Sunday, July 18, 2021

natural gas rigs at 15 mo high as prices hit 30 mo high; global oil shortage at 830,000 bpd; DUC backlog at 7.6 months

natural gas drilling at a 15 month high as prices hit a 30 month high; distillates exports at an 11 month high; global oil shortage at 830,000 barrel per day; DUC backlog at 7.6 months

oil prices finished lower for a second week, after finishing higher the prior six weeks, as rising Covid cases and the likelihood that OPEC would soon add to global supplies weighed on the market...after slipping 0.8% to $74.56 a barrel last week as traders worried that trouble within OPEC would lead to an increase in crude supplies, the contract price of US light sweet crude for August delivery opened higher on Monday on the prospect of tightening oil supplies should OPEC fail to agree, but turned lower on news that virus-related mobility restrictions had been introduced in Japan, South Korea and Vietnam, clouding the demand outlook for oil and settled with a 46 cents loss at $74.10 a barrel....but oil prices rebounded and rose nearly 2% on Tuesday after the International Energy Agency said the market should expect tighter supply for now due to disagreements among major producers over how much additional crude to ship worldwide, and finished $1.15 higher at $75.25 a barrel, the highest front month close since October 2018...however, oil prices slid in off market trading Tuesday evening after the American Petroleum Institute reported that oil inventories rose less than had been expected, and then tumbled on NYMEX on Wednesday to close $2.12 lower at $73.13 a barrel after the EIA confimed a build in fuel inventories, and a potential OPEC+ agreement to increase supply cooled the buying spree that had pushed the price of oil to a 33 month hiigh....oil's price slide continued Thursday on expectations of more crude hitting the market after the expected compromise OPEC deal, and Wednesday's surprisingly poor reading on U.S. fuel demand. with prices falling another $1.48 or 2% to $71.65 a barrel, suddenly at their lowest in nearly a month, with a rising U.S. dollar reducing the appeal of oil & other commodities priced in the currency...oil prices recovered a bit on Friday followiing the pronounced losses earlier in the week, as mixed economic data in the United States pointed to accelerating inflation amid surging consumer spending, with August oil adding 16 cents, or 0.22 percent, to settle at 71.81 dollars a barrel, sapped in volatile trading by expectations of growing supplies just at the time when a rise in coronavirus cases could lead to lockdown restrictions and depressed demand...but even with that modest rebound, oil prices still suffered their worst week in months, with the US benchmark ending down 3.7%, the largest weekly loss for U.S. crude since the week ended April 2nd...

meanwhile, natural gas prices ended the week unchanged as strong export demand offset cooler weather and a bearish storage report..​..​after slipping 0.7% to $3.674 per mmBTU last week as weather forecasts moderated over the major gas consuming regions, the contract price of natural gas for August delivery jumped 7.5 cents, or more than 2%, to a 30 month high of $3.749 per mmBTU on Monday​,​ as global​ natural​ gas prices in excess of $12 per mmBTU offset forecasts for slightly less hot weather and lower air conditioning demand over the next two weeks than had been expected...but natural gas prices slid lower on Tuesday, following forecasts for a pullback in weather-driven demand and lower LNG output in the wake of maintenance work, and ended down 5.3 cents at $3.696 per mmBTU...natural gas prices rebounded early Wednesday, as LNG levels and export demand bounced back, but bearish weather and storage forecasts weighed on afternoon trading ​and the August contract closed 3.6 cents lower at $3.660 per mmBTU....natural gas prices retreated again on Thursday following a relatively robust storage injection and forecasts for tapered cooling demand over the balance of July and settled 4.6 cents lower at $3.614 per mmBTU...but natural gas bounced back on Friday on concern over the potential for paltry levels of supplies ahead of the winter withdrawal season, as prices came full circle and closed 6.0 cents higher at $3.674 per mmBTU, the same price they ended last week at...

the natural gas storage report from the EIA for the week ending July 9th indicated that the amount of natural gas held in underground storage in the US rose by 55 billion cubic feet to 2,629 billion cubic feet by the end of the week, which still left our gas supplies 543 billion cubic feet, or 17.1% below the 3,172 billion cubic feet that were in storage on July 9th of last year, and 189 billion cubic feet, or 6.7% below the five-year average of 2,818 billion cubic feet of natural gas that have been in storage as of the 9th of July in recent years...the 55 billion cubic feet increase in US natural gas in storage this week was above the median forecast for a 46 billion cubic foot addition from a S&P Global Platts survey of analysts, and close to the average addition of 54​ ​billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, but above the 47 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…  

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending July 9th showed that after a sizeble increase in our oil exports, we again needed to withdraw oil from our stored commercial crude supplies for the eighth consecutive week, and for the 24th time in the past thirty-five weeks….our imports of crude oil rose by an average of 347,000 barrels per day to an average of 6,221,000 barrels per day, after falling by an average of 532,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 1,397,000 barrels per day to an average of 4,025,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,196,000 barrels of per day during the week ending July 9th, 1,050,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly 100,000 barrels per day higher at 11,400,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 13,596,000 barrels per day during this reporting week…

meanwhile, US oil refineries reported they were processing 16,093,000 barrels of crude per day during the week ending July 9th, 22,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net ​avarage ​of 1,128,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 1,369,000 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 plugged a (+1,369,000) 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 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….since last week’s EIA fudge factor was at (+418,000) barrels per day, that ​also ​means there was a rounded 950,000 barrel per day balance sheet difference in the crude oil fudge figure from a week ago, thus rendering the week over week supply and demand changes that we have just transcribed meaningless…. 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 wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,361,000 barrels per day last week, which was 0.1% less than the 6,368,000 barrel per day average that we were importing over the same four-week period last year… the 1,128,000 barrel per day net withdrawal from our crude inventories all came from our commercially available stocks of crude oil, while oil stored in our Strategic Petroleum Reserve remained unchanged…over the past four weeks, total US crude inventories have been falling at a 1,192,000 barrel per day clip, just short of the record 1,204,000 barrel per day drop that our inventories had seen during the 4 weeks ending July 2nd...this week’s crude oil production was reported to be 100,000 barrels per day higher at 11,400,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at 11,000,000 barrels per day, while an 4,000 barrel per day decrease in Alaska’s oil production to 434,000 barrels per day had no impact on the rounded national total….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 13.0% below that of our production peak, but 35.3% 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…

meanwhile, US oil refineries were operating at 91.8% of their capacity while using those 16,093,000 barrels of crude per day during the week ending July 9th, down from 92.2% of capacity the prior week, and a bit below normal for summertime operations…while the 16,093,000 barrels per day of oil that were refined this week were 12.5% higher than the 14,309,000 barrels of crude that were being processed daily during the pandemic impacted week ending July 10th of last year, they were still 6.8% below the 17,267,000 barrels of crude that were being processed daily during the week ending July 12th, 2019, when US refineries were operating at a close to summertime normal 94.4% of capacity…

with this week’s decrease in the amount of oil being refined, the gasoline output from our refineries was​ reported to be​ much lower, decreasing by 696,000 barrels per day to 9,858,000 barrels per day during the week ending July 9th, after our gasoline output had increased by 976,000 barrels per day over the prior week…while this week’s gasoline production was 8.4% higher than the 9,095,000 barrels of gasoline that were being produced daily over the same week of last year, it was just fractionally higher than the gasoline production of 9,855,000 barrels per day during the week ending July 12th, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 41,000 barrels per day to 4,926,000 barrels per day, after our distillates output had decreased by 62,000 barrels per day over the prior week…while this week’s distillates output was still 1.4% more than the 4,860,000 barrels of distillates that were being produced daily during the week ending July 10th, 2020, it was 8.1% below the 5,361,000 barrels of distillates that were being produced daily during the week ending July 12th, 2019..

even with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the eleventh time in fifteen weeks, and for the 21st time in thirty-five weeks, rising by 1,038,000 barrels to 236,535,000 barrels during the week ending July 9th, after our gasoline inventories had decreased by 6,075,000 barrels over the prior week...our gasoline supplies increased this week because the amount of gasoline supplied to US users decreased by 760,000 barrels per day to 9,283,000 barrels per day, and because our exports of gasoline fell by 101,000 barrels per day to 747,000 barrels per day, while our imports of gasoline rose by 28,000 barrels per day to 1,044,000 barrels per day…but even after this week’s inventory increase, our gasoline supplies were 4.8% lower than last July 10th's gasoline inventories of 248,535,000 barrels, and about 1% below the five year average of our gasoline supplies for this time of the year…

meanwhile, even with the decrease in our distillates production, our supplies of distillate fuels increased for the fifth time in fourteen weeks and for the 15th time in 30 weeks, rising by 3,657,000 barrels to 142,349,000 barrels during the week ending July 9th, after our distillates supplies had increased by 1,616,000 barrels during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 676,000 barrels per day to 3,164,000 barrels per day, even as our exports of distillates rose by 289,000 barrels per day to an 11 month high of 1,316,000 barrels per day​,​ while our imports of distillates fell by 54,000 barrels per day to 66,000 barrels per day…but even after the inventory increases over the past two weeks, our distillate supplies at the end of the week were still 19.5% below the 176,809,000 barrels of distillates that we had in storage on July 10th, 2020, and still about 4% below the five year average of distillates stocks for this time of the year…

finally, ​after th​is week's big ​jump in our oil exports, our commercial supplies of crude oil in storage fell for thirteeth time in the past twenty-one weeks and for the 28th time in the past year, decreasing by 7,896,000 barrels over the week, from 445,476,000 barrels on July 2nd to 437,580,000 barrels on July 9th, after our crude supplies had decreased by 6,866,000 barrels the prior week….with this week’s decrease, our commercial crude oil inventories fell to about 8% below the most recent five-year average of crude oil supplies for this time of year, but were still about 28% above the average of our crude oil stocks as of the the 2nd weekend of July 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, our commercial crude oil supplies as of this July 9th were 17.7% less than the 531,688,000 barrels of oil we had in commercial storage on July 10th of 2020, and are now 4.0% less than the 455,876,000 barrels of oil that we had in storage on July 12th of 2019, but are still 6.4% more than the 411,084,000 barrels of oil we had in commercial storage on July 13th of 2018…        

OPEC's Monthly Oil Market Report

Thursday of this past week saw the release of OPEC's July Oil Market Report, which covers OPEC & global oil data for June, and hence it gives us a picture of the global oil supply & demand situation for the second month of the modest output easing policy initiated by OPEC and other producers at their early April meeting, which was actually the fourth production quota policy change they've made over the past year, all in response to the pandemic-related slowdown and subsequent recovery...note that we are not reporting on, or considering OPEC's recent disagreement on production quotas for August that has been in the news, just their compliance to their June quotas....and before we start, we want to again 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 check is from the page numbered 49 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...

June 2021 OPEC crude output via secondary sources

As we can see on the bottom line of the above table, OPEC's oil output increased by 586,000 barrels per day to 26,034,000 barrels per day during June, up from their revised May production total of 25,448,000 barrels per day...however, that May output figure was originally reported as 25,463,000 barrels per day, which therefore means that OPEC's May production was revised 15,000 barrels per day lower with this report, and hence OPEC's June production was, in effect, a 571,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official May OPEC output figures as reported a month ago, before this month's revision)... 

From the above table, we can see that a production increase of 425,000 barrels per day from the Saudis was the major factor in OPEC's June output increase; the reason for that increase is that the Saudis had unilaterally committed to cut their own production by a million barrels per day during February, March and then later during April of this year, and that they are now gradually unwinding that voluntary output decrease, having already increased their production by 345,000 barrrel per day in May... recall that last year's original oil producer's agreement was to cut production by 9.7 million barrels per day from an October 2018 baseline for just two months early in the pandemic, during May and June, but that agreement had been extended to include July at a meeting between OPEC and other producers on June 6th....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 and subsequent months, which was thus the agreement that covered OPEC's output for the rest of 2020...the OPEC+ agreement for 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 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 incrimentally adjust their oil production higher over the next three months, which is the agreement which governed OPEC's May's production that you see above...

Hence, to determine if all the OPEC members continued to adhere to the production cuts they had committed to during May, we'll include a copy of the production adjustments table that was provided as a downloadable attachment with the OPEC press release following their April 1st meeting with other oil producers...

May 2021 OPEC production quotas

the above table was included with the press release following the 15th OPEC and non-OPEC Ministerial Meeting on April 1st of this year, and it includes the reference production and expected production levels for the 10 members of OPEC that are expected to make cuts, as well as the same information for the other major oil producers who are party to what the press calls the "OPEC + agreement"....the first column in the above table shows the reference oil production baseline, in thousands of barrel per day, from which each of the oil producers was to cut their production from, a figure which is based on each of the oil producer's October 2018 oil output, ie., a date before last year's and the prior year's output cuts took effect, and coincidently the highest monthly production of the era for most of the producers who are party to these cuts...the remaining columns show the adjustment, or cut, that each is expected to make from that reference production level, and then the oil output allowed for each producer under the April agreement for the months of May, June and July...

OPEC arrived at these figures by repeatedly adjusting the original 23%, or 9.7 million barrel per day cut from the October 2018 baseline first agreed to for May and June 2020, first to a 7.7 million barrel per day 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 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; as you see above, their cut for June was lowered to 4,010,000 barrels per day from the baseline with the latest agreement...note that war torn Libya, and US sanctioned producers Iran and Venzuela, are exempt from the production cuts that the cartel imposes on its other members, and hence the June production of the other ten members remained below the quotas set at the April 1st meeting. ...

the next graphic from this month's report that we'll highlight shows us both OPEC's and worldwide oil production monthly on the same graph, over the period from July 2019 to June 2021, and it comes from page 50 (pdf page 60) of OPEC's July 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....

June 2021 OPEC report global oil supply

Including this month's reported 586,000 barrel per day increase in OPEC's production from what they produced a month earlier, OPEC's preliminary estimate indicates that total global liquids production increased by a rounded 1,100,000 barrels per day to average 94.49 million barrels per day in June, a reported increase which apparently came after May's total global output figure was revised down by 280,000 barrels per day from the 93.67 million barrels per day of global oil output that was estimated for May a month ago, as non-OPEC oil production rose by a rounded 520,000 barrels per day in June after that revision, with with increases in the oil output from the OECD countries accounting for most of the non-OPEC production increase in June...

After that increase in June's global output, the 94.49 million barrels of oil per day that were produced globally during the month were 7.05 million barrels per day, or 8.1% more than the revised 87.44 million barrels of oil per day that were being produced globally in June a year ago, which was second month of the OPEC + agreement to cut global output by 9.7 million barrels per day (see the July 2020 OPEC report (online pdf) for the originally reported June 2020 details)...with this month's increase in OPEC's output, their June oil production of 26,034,000 barrels per day was at 27.6% of what was produced globally during the month, an increase of 0.3% from their 27.3% share of the global total in May....OPEC's June 2020 production was reported at 22,271,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 3,763,000, or 16.9% more barrels per day of oil this June than what they produced a year earlier, when they accounted for 25.8% of global output...

However, even after the sizable increase in 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 demand, as this next table from the OPEC report will show us..

June 2021 OPEC report global oil demand

the above table came from page 26 of the OPEC July Oil Market Report (pdf page 36), and it shows regional and total oil demand estimates in millions of barrels per day for 2020 in the first column, and 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 third column, we've circled in blue the figure that's relevant for June, which is their estimate of global oil demand during the second quarter of 2021... OPEC is estimating that during the 2nd quarter of this year, all oil consuming regions of the globe have been using an average of 95.32 million barrels of oil per day, which is a 60,000 barrels per day upward revision from the 95.26 million barrels of oil per day of demand they were estimating for the second quarter a month ago (note that we have encircled this month's revisions in green), which still reflects quite a bit of coronavirus related demand destruction compared to 2019, when global demand averaged 99.98 million barrels per day....but as OPEC showed us in the oil supply section of this report and the summary supply graph above, OPEC and the rest of the world's oil producers were only producing 94.49 million barrels million barrels per day during June, which would imply that there was a shortage of around 830,000 barrels per day in global oil production in June when compared to the demand estimated for the month...

In addition to figuring June's global oil supply shortfall that's evident in this report, the upward revision of 60,000 barrels per day to second quarter demand that's shown above, combined with the 280,000 barrel per day downward revision to May's global oil supplies that's implied in this report, means that the 1,590,000 barrels per day global oil output shortage we had previously figured for May would now be revised to a shortage of 1,930,000 barrels per addition, the 2,220,000 barrels per day global oil output shortage we had previously figured for April, in light of the 60,000 barrels per day upward revision to second quarter demand, would now be revised to a shortage of 2,280,000 barrels per day...

note that in green we have also circled a downward revision of 130,000 barrels per day to OPEC's previous estimates of first quarter demand....for March, that means that the global oil output surplus of 280,000 barrels per day we had previously figured for March would be revised to a surplus of 410,000 barrels per day... similarly, the downward revision to first quarter demand means that the 930,000 barrels per day global oil output shortage we hadpreviously figured for February would now be revised to a shortage of 800,000 barrels per day, and that the global oil output surplus of 290,000 barrels per day we had previously figured for we had previously figured for January would now be revised to a surplus of 420,000 barrels per day, in light of that 130,000 barrel per day downward revision to first quarter demand...

This Week's Rig Count

The number of drilling rigs active in the US increased for the 37th time out of the past 43 weeks during the week ending July 16th, but it’s still down by 39.0% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US increased by five to 484 rigs this past week, which was also up by 231 rigs from the pandemic hit 253 rigs that were in use as of the July 17th report of 2020, but was still 1,445 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 was up by 2 to 378 oil rigs this week, after it rose by 2 oil rigs the prior week, and it’s also 180 more oil rigs than were running a year ago, while it’s still just 23.6% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was up by 4 to a 15 month high of 104 natural gas rigs, which was also up by 33 natural gas rigs from the 71 natural gas rigs that were drilling during the same week a year ago, but still just 6.5% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….

The Gulf of Mexico rig count was unchanged at 17 rigs this week, with 16 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas….that was five more rigs than the 12 rigs that were drilling in the Gulf a year ago, when 10 Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil in Texas waters….since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig count… in addition to those rigs offshore, we continue to have a rig drilling through an inland body of water in Terrebonne Parish of southern Louisiana, whereas there were no such “inland waters” rigs running a year ago…

The count of active horizontal drilling rigs was up by 1 to 434 horizontal rigs this week, which was also up by 215 rigs from the 215 horizontal rigs that were in use in the US on July 17th of last year, but less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the directional rig count was also up by one to 32 directional rigs this week, and those were up by 9 from the 23 directional rigs that were operating during the same week a year ago….in addition, the vertical rig count was up by 3 to 18 vertical rigs this week, and those were also up by 3 from the 15 vertical rigs that were in use on July 17th of 2020….

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of July 16th, the second column shows the change in the number of working rigs between last week’s count (July 9th) and this week’s (July 16th) count, the third column shows last week’s July 9th 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 17th of July, 2020..

July 16 2021 rig count summary

from the tables above, it's not immediately obvious what happened this week…so checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that two rigs were added in Texas Oil District 8, which is the core Permian Delaware in the westernmost part of the state, while an oil rig was pulled out in Texas Oil District 8A, which encompasses the northern counties of the Permian Midland, and that two more oil rigs were pulled out of Texas Oil District 7C, which includes the southern counties of the Permian Midland...since the Permian basin rig count was up by one, that means that the 2 rigs that were added in Texas Oil District 7B, which could target the farthest east reaches of the Permian Midland, were both apparently Permian rigs...moreover, one of those Permian rig additions this week was a natural gas rig, the first Permian basin gas drilling in 8 weeks...elsewhere in Texas, two rigs were pulled out of Texas Oil District 6, one of which was in the Haynesville shale, which was concurrently replaced by a Haynesville rig in northern Louisiana, leaving the Haynesville shale basin count unchanged....there was also at least one natural gas rig added in Texas Oil District 1, while an oil rig was pulled out in Texas Oil District 2, both of which represent Eagle Ford changes, where the natural gas rig count increased by 2 to three, while the Eagle Ford oil rig count fell by two to the same time, a Granite Wash oil rig was pulled out of Texas Oil District 10, meaning this week's oil rig count in Texas was down by 5, while the state's natural gas rig count rose by three....meanwhile, the Cana Woodford removal from Oklahoma was apparently more than offset by the additon of three rigs in Oklahoma basins not tracked by Baker Hughes, while Wyoming also saw the addition of three rigs in a basin that Baker Hughes doesn't cover; and yet another rig that Baker Hughes doesn't cover was added added in Alaska, probably on the North Slope, the site of all other Alaska oil well drilling..

DUC well report for June

Monday of this past week saw the release of the EIA's Drilling Productivity Report for July, which includes the EIA's June data for drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions....that data showed a decrease in uncompleted wells nationally for the 13th month in a row, as both completions of drilled wells and drilling of new wells increased, but remained below the pre-pandemic levels...for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 269 wells, falling from 6,521 DUC wells in May to 6,252 DUC wells in June, which was also 30.3% fewer DUCs than the 8,965 wells that had been drilled but remained uncompleted as of the end of June of a year ago...this month's DUC decrease occurred as 549 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during June, up from the 533 wells that were drilled in May, while 818 wells were completed and brought into production by fracking, up from the 798 completions seen in May, and up from the pandemic hit 248 completions seen in June of last year, but down by 35.6% from the 1,271 completions of June the June completion rate, the 6,252 drilled but uncompleted wells left at the end of the month represents a 7.6 month backlog of wells that have been drilled but are not yet fracked, down from the 8.4 month DUC well backlog of a month ago, with the understanding that this normally indicative backlog ratio is being skewed by a completion rate that is still more than a third below the pre-pandemic norm...

both oil producing regions and natural gas producing regions saw DUC well decreases in June, while none of the major basins reported DUC well increases....the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico decreased by 123, from 2,598 DUC wells at the end of May to 2,475 DUCs at the end of June, as 253 new wells were drilled into the Permian during June, while 386 wells in the region were the same time, DUC wells in the Niobrara chalk of the Rockies' front range fell by 41, decreasing from 402 at the end of May to 361 DUC wells at the end of June, as 51 wells were drilled into the Niobrara chalk during June, while 92 Niobrara wells were being addition, DUCs in the Eagle Ford of south Texas also decreased by 41, from 1,012 DUC wells at the end of May to 971 DUCs at the end of June, as 56 wells were drilled in the Eagle Ford during June, while 97 already drilled Eagle Ford wells were completed.... at the same time, there was also a decrease of 28 DUC wells in the Bakken of North Dakota, where DUC wells fell from 656 at the end of May to 628 DUCs at the end of June, as 31 wells were drilled into the Bakken during May, while 59 of the drilled wells in the Bakken were being fracked..... meanwhile, the number of uncompleted wells remaining in Oklahoma's Anadarko decreased by 19, falling from 863 at the end of May to 844 DUC wells at the end of June, as 30 wells were drilled into the Anadarko basin during June, while 49 Anadarko wells were being fracked....

among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 17 wells, from 598 DUCs at the end of May to 581 DUCs at the end of June, as 68 wells were drilled into the Marcellus and Utica shales during the month, while 85 of the already drilled wells in the region were fracked....meanwhile, the uncompleted well inventory in the natural gas producing Haynesville shale of the northern Louisiana-Texas border region was unchanged at 392 DUCs, as 50 wells were drilled into the Haynesville during June, while 50 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of June, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 252 wells to 5,279 wells, while the uncompleted well count in the natural gas basins (the Marcellus, the Utica, and the Haynesville) decreased by 17 wells to 973 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...


Ohio rules for oil and gas waste facilities move ahead 8 years later -Ohio Department of Natural Resources has issued a draft of proposed rules that would regulate how the state's oil and gas waste facilities manage radioactive fracking waste.The draft comes after a Dispatch story highlighted there are no rulesfor the waste facilities even though Ohio’s legislature directed ODNR, which regulates the industry, to enact rules in 2013."I think it's good that they're doing this this rulemaking. It's long overdue," said Megan Hunter, a senior attorney at Chicago-based EarthJustice. "But they don't address a lot of the really serious issues presented by these types of facilities."ODNR is accepting comments through Friday. This is the first of three opportunities when Ohioans will have a chance to comment. It's also the third attempt of the agency to get rules passed.The draft, which is 46 pages, proposes standards for where oil and gas waste facilities can be located and how they can operate. As written, it would allow the industry the freedom to have certain records exempted from public inspection if they classify them as infrastructure records. Even though the facilities handle radioactive waste, the draft rules do not require all of the waste facilities to have a radiation protection plan.When hydraulic fracturing or fracking takes place, a mixture of water, sand and chemicals is injected at high pressure thousands of feet below the soil's surface. The shale rock is fractured from the pressure, which then releases the oil and gas. The process generates lots of waste. Companies use their own formulas for the fluid mixture to frack. They don't have to disclose the chemicals it contains because it's considered a trade secret. Some of the thousands of chemicals in the frack waste fluid are radioactive.This week, Physicians for Social Responsibility, a nonprofit coalition of healthcare workers advocating for climate solutions, released the results of a public records request that showed PFAS (the acronym for per- and polyfluorinated alkyl substances), which are man-made long-lasting compounds dubbed “forever chemicals,” may be present in fracking fluids.PFAS can increase the risk of cancer, reduce fertility in women, interfere with hormones, increase cholesterol levels and negatively affect the immune system and development in infants and children, according to the U.S. Centers for Disease Control and Prevention. There also have been studies linking frack waste to severe headaches, asthma symptoms, childhood leukemia, cardiac problems and birth defects, according to the Natural Resources Defense Council.ODNR did not make anyone available for an interview for this story. The agency emailed a statement saying, "The division develops draft rules by using the scientific expertise and experience of our staff—then by engaging stakeholders and welcoming public comments as outlined in the rulemaking process. ... The division looks forward to reviewing comments from any interested party during the current and future public comment periods." "We always try to strike that balance between good, strong regulations and not over-regulating. We think that the waste facility rule in its current form, generally speaking, does," said Matt Hammond, president of the Ohio Oil and Gas Association.

Utica Shale Academy accepts grants to invest in welding lab — A new welding lab will provide students with hands on training at the Utica Shale Academy this school year. On Tuesday, the board of the Utica Shale Academy accepted a $200,000 Equity grant, which the school is combining with another $200,000 Equity grant provided through their partner, Southern Local Schools to purchase all the equipment needed for the new lab. The welding lab will allow Utica Shale Academy students to learn hands on welding skills and gain career path credentials through Lincoln Electric Welding. It will be located downstairs in the Kenneth Hutson Building in Salineville where the school is hoping to relocate in time to welcome most students back to the program this fall. The board also approved a nearly $1,000 per teacher for two instructors to attend a Lincoln Electric Welding virtual training seminar, so those instructors will be ready when the lab is in place. Superintendent Bill Watson said he is in the process of getting all the permits needed to open that building, but is still waiting for American Electric Power to determine what transformer the building will need to provide power to the welding lab equipment and other equipment for the building.

ODA Director Pelanda Being Forced To Choose Sides --In Union County Common Pleas Court Monday, a petition for a writ of mandamus was filed asking the court to order Dorothy Pelanda, Director of the Ohio Department of Agriculture, to use her power as director of the ODA and put a stop to a proposed gas pipeline that would cross protected farm properties in Jerome Township. At issue here is what is called the Columbia Gas Northern Columbus Loop Pipeline, a part of large network of lines which encircles the better part of the Columbus-metro area. A large section has been planned to be laid through Delaware County and Jerome Township in Union County. Columbus Gas did yeoman’s work putting the plans for pipeline together for the Northern Columbus Loop, every last foot having been been mapped out, measured, and marked down. Crews are ready to get to work, ready to install 17 miles of 16- and 24-inch lines that will carry 720 psi of natural gas through the two counties. But a fair part of those 17 miles of pipeline was mapped through three properties in Union County’s Jerome Township, properties that are controlled or owned by Don Bailey Jr., Trustee of the Arno Renner Trust, Charles Renner, and Patrick E. and Whitney Bailey, who are the plaintiffs in the case and are called “Relators” in the court filing.They wanted nothing do with the pipeline and said so. The Relators turned down offers of money from Columbia Gas as recently as June 14, offers which also came with clear warnings of ‘eminent domain’, a frank acknowledgement that Columbia Gas has the political juice to force the granting of the easement and was going to end up with the land for the pipeline one way on another.So the Relators struck first.Represented by David Watkins of Plank Law Firm of Columbus, Mr. Bailey, Mr. and Ms. Bailey and Mr. Renner presented the court Monday a petition for a writ of mandamus to order Director Pelanda to intervene and honor the Deed of Agriculture Easement (Ag Easement) that was issued on the properties in question by the very Ohio Department of Agriculture now headed by Director Pelanda.

Whistleblowers say 'bad seeds' undermine pipeline safety -Two former pipeline inspectors say they were fired for reporting hazards on a volatile liquids pipeline to Royal Dutch Shell PLC’s massive new petrochemical plant northwest of Pittsburgh.The inspectors, Frank Chamberlin and Susan D’Layne Carite, said they warned Shell managers and even federal regulators in 2019 that the anti-corrosion coating was defective on the company’s Falcon pipeline. That could increase the threat of corrosion, a leading cause of pipeline ruptures.A representative of the coating manufacturer told Chamberlin the protective layer was “unacceptable,” and another person on the project told him it peeled from the pipe during installation. Rather than fixing the problem, he says, Shell ordered them off the project and the contractor fired the two inspectors, who live together in a rural part of upstate New York. The couple’s allegations are contained in their whistleblower complaint they filed with the Labor Department.“We did our jobs, and we were harassed, abused, ridiculed, and humiliated then released because we would not follow the bad seeds that are giving the industry a very bad reputation,” Chamberlin wrote in his complaint, obtained by E&E News under the Freedom of Information Act. They said they’d been repeatedly warned they’d be “run off” if they kept pressing safety concerns.The allegations highlight that the inspectors in charge of assuring safety and environmental protection on large pipeline projects are usually paid by the pipeline builders themselves. Critics say that creates a conflict of interest, but pipeline industry officials compare the practice to quality control in other areas of manufacturing.“The system isn’t set up to ensure experienced and accountable inspections,” said Shannon Smith of the FracTracker Alliance, a Pennsylvania-based energy watchdog group that has monitored Shell’s project. Federal pipeline safety regulators from the Pipeline and Hazardous Materials Safety Administration investigated the former inspectors’ allegations, and agency officials say no safety problems were found. They said the coating that peeled was a protective overcoat. But there’s no record that they followed up with the manufacturer.

PUC approves $1 million settlement over Revolution Pipeline explosion in Beaver County in 2018 - Energy Transfer LP will pay a $1 million fine to settle safety violations over a fiery 2018 natural gas pipeline explosion that destroyed a home in Western Pennsylvania.The Pennsylvania Public Utility Commission on Thursday approved a settlement made last December with the Texas company, whose Revolution Pipeline ruptured and exploded after heavy rains caused a landslide in Beaver County. The new 24-inch diameter pipeline was just being brought into service when the failure occurred.The explosion and fire destroyed a nearby home, whose occupants fled without injury, and knocked out a major electrical transmission line. The pipeline has been out of service since the Sept. 10, 2018, incident.Under the settlement, Energy Transfer does not admit it violated the safety regulations alleged by the PUC’s Bureau of Investigation and Enforcement. But in addition to the $1 million payment, Energy Transfer agreed to several conditions that the PUC says go beyond federal safety requirements.The company agreed to conduct five annual inline inspections of the Revolution pipeline through 2025, to walk the entire 40-mile pipeline right of way after heavy rains and to improve how preconstruction geologic research is incorporated into pipeline design and construction.The PUC agreed not to oppose Energy Transfer’s efforts to restart the pipeline.The commission’s order seeks public comment on the proposed settlement. Any modifications to the settlement would allow either party to withdraw from the agreement and pursue litigation.The Revolution Pipeline is operated by ETC Northeast Pipeline LLC, which is separate from Energy Transfer’s former Sunoco Pipeline unit that is building the contentious Mariner East pipeline system. The Mariner East system delivers natural gas liquids like propane from Western Pennsylvania to an export terminal in Marcus Hook, Delaware County.

Weekly Shale Drilling Permits for PA, OH, WV: Jul 5-11 (see embedded documents) - Last week not a whole lot of permit action was goin’ on. Pennsylvania scored only a single (1) new permit. We can’t remember the last time that happened! The PA permit was for a well that will be drilled by EQT in Greene County. Ohio’s Utica got skunked with no new permits. West Virginia rode in to save the day, posting 5 new permits–4 of them for Tug Hill and 1 for Antero Resources.

Physicians Group Uncovers Evidence That ‘Forever Chemicals’ Used Extensively in Fracking Unbeknownst to Public – A new report, released today by Physicians for Social Responsibility (PSR), presents evidence that oil and gas companies including ExxonMobil and Chevron have used per- and polyfluoroalkyl substances (PFAS), and/or substances that can degrade into PFAS, in hydraulic fracturing (“fracking”) for oil and gas in more than 1,200 wells in six U.S. states between 2012 and 2020. The report also notes that, due to the lack of full disclosure concerning chemicals used, PFAS could have been used in additional states and in drilling and other extraction techniques that precede the underground injections known as fracking.PFAS have been linked to cancer, birth defects, pre-eclampsia, and other serious health effects. Toxic in minuscule concentrations, they accumulate inside the human body and do not break down in the environment – hence their nickname, “forever chemicals.”Evidence related to the use of PFAS or PFAS precursors in oil and gas operations has not been previously publicized.The report, Fracking with “Forever Chemicals,” also documents the U.S. Environmental Protection Agency (EPA)’s approval of three chemicals for use in oil and gas drilling and/or fracking, despite EPA’s written observation that the chemicals could degrade into substances similar to PFOA, the most infamous PFAS, highlighted in the 2019 feature film Dark Waters. EPA regulators wrote,EPA has concerns that these degradation products will persist in the environment, could bioaccumulate or biomagnify, and could be toxic (PBT) to people, wild mammals, and birds based on data on analog chemicals, including PFOA and [REDACTED]. One of these chemicals was used commercially for unspecified purposes as recently as 2018, according to EPA records.On Monday, July 12 at noon Eastern time, Physicians for Social Responsibility will host a webinar where report findings will be presented. Representatives of the press will have the opportunity to direct questions to the speakers. “The evidence that people could be unknowingly exposed to these extremely toxic chemicals through oil and gas operations is disturbing,” said Horwitt. “Considering the terrible history of pollution associated with PFAS, EPA and state governments need to move quickly to ensure that the public knows where these chemicals have been used and is protected from their impacts.”

E.P.A. Approved Toxic Chemicals for Fracking a Decade Ago, New Files Show - The compounds can form PFAS, also known as “forever chemicals,” which have been linked to cancer and birth defects. The E.P.A. approvals came despite the agency’s own concerns about toxicity. For much of the past decade, oil companies engaged in drilling and fracking have been allowed to pump into the ground chemicals that, over time, can break down into toxic substances known as PFAS — a class of long-lasting compounds known to pose a threat to people and wildlife — according to internal documents from the Environmental Protection Agency. The E.P.A. in 2011 approved the use of these chemicals, used to ease the flow of oil from the ground, despite the agency’s own grave concerns about their toxicity, according to the documents, which were reviewed by The New York Times. The E.P.A.’s approval of the three chemicals wasn’t previously publicly known. The records, obtained under the Freedom of Information Act by a nonprofit group, Physicians for Social Responsibility, are among the first public indications that PFAS, long-lasting compounds also known as “forever chemicals,” may be present in the fluids used during drilling and hydraulic fracturing, or fracking. In a consent order issued for the three chemicals on Oct. 26, 2011, E.P.A. scientists pointed to preliminary evidence that, under some conditions, the chemicals could “degrade in the environment” into substances akin to PFOA, a kind of PFAS chemical, and could “persist in the environment” and “be toxic to people, wild mammals, and birds.” The E.P.A. scientists recommended additional testing. Those tests were not mandatory and there is no indication that they were carried out. “The E.P.A. identified serious health risks associated with chemicals proposed for use in oil and gas extraction, and yet allowed those chemicals to be used commercially with very lax regulation,” said Dusty Horwitt, researcher at Physicians for Social Responsibility. The documents, dating from the Obama administration, are heavily redacted because the E.P.A. allows companies to invoke trade-secret claims to keep basic information on new chemicals from public release. Even the name of the company that applied for approval is redacted, and the records give only a generic name for the chemicals: fluorinated acrylic alkylamino copolymer. However, an identification number for one of the chemicals issued by the E.P.A. appears in separate E.P.A. data and identifies Chemours, previously Dupont, as the submitter. A separate E.P.A. document shows that a chemical with the same EPA-issued number was first imported for commercial use in November 2011. (Chemours did not exist until 2015, though it would have had the responsibility to report chemicals on behalf of its predecessor, Dupont.)

Pennsylvania Remains Negligent On Radiation Guidance Despite TENORM Study - Public Herald --After nearly two years of revisions, and five years since the release of the state-funded study on Technically Enhanced Naturally Occurring Radioactive Material (TENORM), the Pennsylvania Department of Environmental Protection (DEP) is in the final stage of updating a “technical guidance document” to establish rules for safely handling TENORM from oil and gas waste. Though DEP’s document only makes recommendations based on existing regulation — it does not set new policy — the technical guidance is still important to analyze. This type of document is where the commonwealth reveals under current law how it prioritizes and protects the public from carcinogenic and toxic materials from an industry that is intricately woven into the physical, legal, social and political landscapes. Pennsylvania is the place that’s home to the world’s first commercial oil well and is the second-largest natural gas producing state in the United States, where 75% of the natural gas extracted is exported to other states. So, when it finally starts to speak up about radiation, we better start listening to what they’re saying. As you might imagine, and as Public Herald has uncovered in ten years of investigations, Pennsylvania has a love affair with the oil and gas industry. From buying politicians on both sides of the aisle to the revolving door of staffers who work inside both industry and the government, from open attacks on transparency and protections for the public to converting large swaths of forested public land for industrial use, from ripping prodigious amounts of freshwater out of the state’s water supplies to poisoning drinking water, from DEP being called out by Pennsylvania’s own Auditor and Attorney Generals for prioritizing its relationship with industry more than public health and safety, to unearthing mountains of radioactive waste – the evidence is in Pennsylvania’s actions.Though we certainly did not expect the DEP’s guidance to address all the problems with the industry’s waste, like the dumping of the industry’s radioactive materials into rivers via reclassification loopholes, we remained open to the chance that improvement was possible. But after reviewing DEP’s technical guidance, we lament the continued absence of scientific integrity. Despite a growing body of data that reveals just how ‘hot’ the industry is, or simply the state’s own TENORM study, Pennsylvania remains blasé about the dangers of the radioactive threat of oil and gas waste.The revised technical guidance document is clear. Though DEP reiterates that “there are multiple waste streams that may contain TENORM from [oil and gas] wells, including sediments, drill cuttings, filter socks, hydraulic fracturing flowback water, and other wastes…”, the guidance also states that “DEP may require long-term monitoring of leachate and groundwater” at facilities that handle “large volumes” of TENORM.” It goes on to state that the DEP “may require providing appropriate justification and/or pathway analysis for modeling potential radiation exposure to the public and facility or O&G well site staff…” [Emphasis added.]

Equitrans plans to buy $150M in offsets to reduce methane emissions ** The Canonsburg-based operators of the Mountain Valley Pipeline, Equitrans Midstream Corp., announced Monday it would purchase at least $150 million in carbon offsets over 10 years from a coal mining abatement project with the goal of making MVP carbon neutral for a decade. Equitrans is building and will be the operator of the 303-mile Mountain Valley Pipeline, which will take Marcellus and Utica Shale natural gas from western Pennsylvania from a starting point in northern West Virginia through to a distribution point in Virginia. The pipeline, which has been under construction for several years, could be operational next year but it has been facing opposition from environmentalists and neighbors. It’s a big step for Equitrans and MVP, a joint venture of Equitrans and other owners including utilities. They say it’s one of the first interstate pipelines that will have carbon offsets for its emissions. And, said Equitrans Chief Sustainability Officer Todd Normane, the companies weren’t looking for just any project to offset MVP’s carbon impact. “It took a while before we were able to find the right project,” Normane told the Business Times on Monday afternoon. The centerpiece of the project is a methane abatement project that is being done at a metallurgical coal mine in southwestern Virginia near the West Virginia border and in the same region as MVP is being constructed. The methane abatement project will use a regenerative thermal oxidizer to capture methane and turn it into carbon dioxide and water vapor instead of methane, which is considered a potent greenhouse gas that contributes to climate change. It’s being put into place in two phases with full operation by 2023 and in concert with a subsidiary of NextEra Energy Resources, a partner in MVP. Normane said the project would demonstrably reduce methane emissions — it’s estimated when operational that it will reduce Virginia’s underground coal mine emissions by 25% — and that was a big appeal. So was the location, which is where MVP will be operating, as was the long-term commitment of 10 years. MVP and Equitrans did the carbon offset program, which will be worth between $13 million and $15 million a year, voluntarily.

MVP to Purchase Carbon Offsets, Potentially Pleasing Climate-Conscious FERC - Mountain Valley Pipeline LLC (MVP), the proposed Appalachia-to-Southeast natural gas conduit seeking FERC approval to resume construction following legal and regulatory setbacks, plans to purchase carbon offsets for its first 10 years of operational emissions. Management for the embattled pipeline project, a joint venture (JV) led by Equitrans Midstream Corp., said the move would make MVP one of the nation’s first large-scale interstate natural gas pipelines to achieve carbon neutrality for its operational emissions.“We understand the sensitivities that surround the blending of large-scale infrastructure projects with environmental protection,” Equitrans Midstream CEO Diana Charletta said. “Equitrans Midstream is committed to aggressively pursuing climate change mitigation and adaptation while also balancing the intermediate and increasing need for energy in our country.”The carbon offsets are part of the company’s goal to reach net-zero carbon emissions by 2050, Charletta added.MVP plans to purchase more than $150 million of carbon offsets during the first decade in service. “Through an agreement with a subsidiary of NextEra Energy Resources…these carbon offsets will be sourced through a methane abatement project in Virginia that is expected to be the largest operating coal mine methane abatement project in the world when it reaches full production in 2023,” management said. NextEra Capital Holdings Inc. is a JV partner in MVP. The methane abatement project, which would be at a southwestern Virginia mine near the West Virginia border, is to be built in phases. Construction is expected to be completed in the spring of 2023. The project would make use of an “onsite regenerative thermal oxidizer” to capture methane and convert it to carbon dioxide and water in an effort to reduce climate impacts. The methane abatement project is expected to offset 90% of the greenhouse gas (GHG) emissions from MVP operations through the first decade, with the pipeline planning additional GHG abatement projects in West Virginia, including plans to address abandoned and orphaned gas wells.The announcement comes as MVP awaits final approval from the Federal Energy Regulatory Commission to restart construction on the 303-mile, 2 million Dth/d pipeline. MVP has faced substantial delays since first receiving a certificate from the agency in 2017..

Developer Defends FERC's Approvals Of $468M Project - The developer of a $468 million natural gas pipeline told the D. C. Circuit that federal energy regulators' review of the project was sound and argued project challengers are retreading rejected assertions and that Native American tribes' historic preservation claims aren't properly before the court. Mountain Valley Pipeline LLC, the developer of the Southgate natural gas pipeline project, and Dominion Energy Inc. subsidiary Public Service Company of North Carolina Inc. , which would be the pipeline's primary shipper, told the D. C. Circuit on Monday it should reject a petition for review lodged by a coalition of environmental groups because the Federal Energy Regulatory. .

Colonial Pipeline faces huge fine after massive NC fuel leak - Colonial Pipeline Co. could face daily fines of up to $200,000 per violation if it fails to improve the way it detects leaks in its U.S. pipeline system, after a massive gasoline leak in Huntersville, according to a recent settlement in the case with the U.S. government. The agreement orders Colonial to find and use a better leak detection system across its entire network, citing several newly disclosed leaks over the years. Colonial, meanwhile, faces separate potential action by the state Department of Environmental Quality for the August 2020 leak in Mecklenburg County’s Oehler Nature Preserve, State Sen. Natasha Marcus, D-Mecklenburg, told The Charlotte Observer. Two teenage ATV riders chanced upon and reported the Huntersville leak in August. The spill was among the worst in the state, Michael Regan, then-NCDEQ secretary, said in September. Regan now heads the U.S. Environmental Protection Agency. The company eventually reported that almost 18 times more gasoline leaked from its pipe than its original estimate, according to the June 15 settlement with the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA). An administration spokesman wouldn’t say why the agency didn’t issue a fine for the spill as part the settlement. In an email, he instead pointed the Observer to the agreement, which calls for daily fines of up to $200,000 per violation. But the leak in Mecklenburg’s Oehler Nature Preserve was just the latest of several large spills in Colonial’s pipeline system, the settlement revealed. “Colonial has experienced several other accidents that were not detected by its leak detection system or by Colonial personnel.,” federal officials wrote. Leaks included 309,540 gallons of gasoline near Pelham, Ala., in September 2016; 588 gallons in Gwinnett County, Ga., in February 2016; and 4,000 gallons in Centreville, Va., in September 2015, according to the settlement. The company has until Oct. 15 to show how and by when it will improve its leak detection process, according to the settlement with PHMSA.

Massachusetts cities try new legal path toward banning new fossil fuel hookups | Energy News Network - A year after Massachusetts’ attorney general struck down a suburban town’s attempt to ban new fossil fuel infrastructure, a growing number of municipalities are pursuing new strategies to restrict the use of oil and natural gas in buildings. In the past eight months, the towns of Brookline, Arlington, Lexington, Concord, and Acton have all passed measures asking the state Legislature to allow them to prohibit the installation of fossil fuel infrastructure in new construction and, in some cases, buildings undergoing major renovations. Other municipalities are expected to follow in coming months, as part of a coordinated effort to galvanize statewide action. “We need to rapidly decarbonize,” said Lisa Cunningham of Brookline, a town meeting member and clean energy activist. “And the first thing we need to do is stop making the problem worse.” The movement began in 2019, when Brookline first approved, by an overwhelming majority, a bylaw prohibiting fossil fuel infrastructure in new construction or gut renovations. It was the first such municipal measure passed outside of California. Inspired by the idea, other towns began preparing similar measures. Supporters of these bylaws argue that prohibiting fossil fuel infrastructure right now makes the most logistical and financial sense. Fossil fuel use in buildings will have to be eliminated over the coming decades in order to reach the state’s goal of going carbon-neutral by 2050, they say. Therefore, any natural gas or oil systems installed now would likely have to be replaced with electric alternatives within 10 or 20 years. “Any fossil fuel infrastructure that goes in now is going to have to be torn up,” said Anne Wright, an activist in Arlington who helped push for that town’s bylaw. “So why not save money and put electric infrastructure in there now? That’s the long-term vision and economic argument.”

Massachusetts gas delivery company to pay $850k in settlement for overcharging state for subpar fuel - Diesel Direct, LLC will pay $850,000 in a settlement over the delivery of sub-par gas deliveries to Massachusetts agencies. Massachusetts Attorney General Maura Healey said that the company knowingly delivered nonconforming petroleum diesel fuel to state agencies while charging for higher-priced and more environmentally friendly biodiesel fuel. “By not delivering on the terms of its contracts, this company bilked Massachusetts out of taxpayer dollars and undermined our efforts to reduce harmful emissions,” said Healey. “The company further ignored an important part of its contracts designed to ensure minority, women and veteran-owned businesses have an opportunity to participate in government work. Those who accept taxpayer funding to contract with the state have a duty to operate with integrity and those who don’t will be held accountable.” In addition to paying $850,000, Diesel Direct has agreed not to bid, submit a response to a request for proposal, or otherwise participate in any contract with the state or any state agencies for five years. The issue was brought to Healey’s office by a whistleblower saying that the companies Senior Vice President of Operations Augustine Pesaturo, directed employees to deliver nonconforming petroleum diesel fuel to state agencies, instead of the higher-priced and more environmentally friendly biodiesel blend the agencies ordered. Pesaturo then directed employees to charge state agencies for the higher-priced biodiesel that it did not provide, according to the AG’s office. Healey’s office goes further to say that the company’s Chief Executive Officer William McNamara, Jr., knew about the company’s improper actions, failed to stop the conduct. Diesel Direct’s improper conduct caused state agencies to consume fuel that emitted greater amounts of greenhouse gases and particulate matter into the atmosphere.

Gas leak sends 53 Catskills campers to regional hospitals— A total of 53 people were taken to regional hospitals Thursday after authorities believe a leaky gas pipe sickened youngsters at an all-boys religious camp in the Catskill Mountains.“We sent 53 people to the hospital,” Schoharie County Emergency Services Director Michael Hartzel said of the episode at Camp Oorah for Boys, an Ultra-Orthodox Jewish summer camp located near the now-closed Scotch Valley ski resort.Hartzel said the call initially went to Delaware County, since the closest firehouse, in Stamford, is in that neighboring county. The initial report was that camp officials said that six campers were ill and lapsing in and out of consciousness. It was unclear how many of the 53 people being treated are campers and/or adults.First responders, including ambulances, firefighting and other rescue crews from Jefferson and Stamford, found high levels of carbon monoxide in the building, prompting a call for more medical help and regional assistance.No one was believed to have died. As of late Thursday afternoon, it remained unclear how many campers or camp employees were still in the five hospitals to which they had earlier been rushed.“They all came in around the same time,” said Angie Blair, spokeswoman for the Bassett health care system which operates hospitals in Cooperstown, Cobleskill, Delhi and Oneonta.Another group was taken to a hospital in Margaretville, Hartzel added.When more than five people come in at once, it is considered a mass casualty incident, which triggers procedures for activating the system of multiple hospitals and personnel as needed.“It alerts our emergency and trauma departments for a larger-than-normal influx,” said Blair.All told, 13 ambulances and two fire trucks responded, said Jefferson Assistant Fire Chief Mckay McMullen.

South Portland wins pipeline lawsuit over local clean air rule - - The city has prevailed in the lawsuit brought by the Portland Pipe Line Corp., ending more than six years of federal litigation over a local law that blocks the company from reversing the flow of its World War II-era oil pipeline to bring crude from Canada to Maine.The company gave up the fight Thursday, filing an agreement with the 1st U.S. Circuit Court of Appeals to voluntarily dismiss its appeal of a previous federal court judgment that upheld the city’s Clear Skies Ordinance.Passed by the City Council in 2014, the ordinance prohibits bulk loading of crude oil into marine tanker vessels on the city’s waterfront, and its survival of federal court scrutiny is seen as precedent-setting by many.The dismissal follows the city’s victories in U.S. District Court in Portland and the Maine Supreme Judicial Court, as well as an amicus brief filed by the Biden administration last month supporting the city’s stance that the ordinance doesn’t violate the Constitution, federal laws or foreign policies. Under the terms of the two-page agreement, the company and the city will pay their own court costs, and the company gave up the right to pursue the appeal further in the future. The city has spent $2.8 million fighting the lawsuit, including $174,529 in private donations from residents, organizations and others.

Plans canceled for one of two gas power plants in Charles City; opponents say mystery surrounds fossil fuel interests there - The developer of a proposed natural gas plant in Charles City County said Friday that it is no longer pursuing the project. The move was welcomed by people in the county who say they don’t want more fossil fuel pollution. Opponents say local and state officials haven’t been transparent about the proposal and a plan for a second plant a mile away. The proposed C4GT power plant was backed by private investors and would have brought gas via pipeline to the county to be burned to create electricity. Michigan-based NOVI Energy, the company that wanted the project, announced it is moving on. “NOVI Energy cares deeply about the communities it serves and the affordable, reliable power facilities it helps build,” read a statement from a communications firm representing the company. “After taking feedback from the community and assessing the changing market, NOVI Energy has decided not to pursue the C4GT power plant.” Wanda Roberts, who lives in Charles City and is helping lead opposition to the plants, said the announcement took her breath away. “We were praying and hoping this was going to happen,” she said. “We were told from the very beginning ... that it’s a done deal, there’s nothing anybody can do to stop this plant from coming.” County government officials were already in the process of taking back land where the plant would go, but until Friday the plan appeared to still be on the table.

Chesapeake Energy moves to certify Gulf Coast gas output as RSG by end of 2021 - Chesapeake Energy will work with a pair of environmental groups to certify its Haynesville shale production in Louisiana as responsibly produced by year end, with plans to later do the same with its Appalachia production, as the natural gas industry continues to respond to environmental concerns at home and in global LNG markets. MiQ — a joint venture between RMI and SYSTEMIQ — and Equitable Origin were chosen as the third-party certifiers. MiQ will provide a quantitative assessment of the company's methane emissions and detection practices, while Equitable Origin will certify to a broader qualitative environmental, social, and governance standard. The new initiative will be Chesapeake Energy's second responsibly sourced gas certification project, having previously launched a pilot program with Project Canary in April. The pilot involved installing on-site continuous methane monitoring devices on select Chesapeake well pads in the Marcellus and Haynesville basins, as well as undergoing Trustwell certification. Chesapeake's Haynesville gas production totaled around 532 MMcf/d in the first quarter, according to a May 12 investor presentation. The Haynesville shale basin has seen steady production growth over the past several years, with Platts Analytics data showing year-to-date production volumes of 12.43 Bcf/d, up from 12.03 Bcf/d in 2020 and 11.73 Bcf/d in 2019. Appalachia plans Following its Gulf Coast certification process, Chesapeake aims to complete certification of its Appalachia gas production by Q2 2022. Chesapeake produced 1.26 Bcf/d of gas in Appalachia in Q1, according to the May 12 investor presentation. Appalachia has emerged as the country's dominant basin for RSG certification, likely due to the basin's lower emissions profile. Four out of the top five Pennsylvania gas producers have announced RSG certification efforts for some or all production.

Spire Pipe Closure to Cut Off MU NatGas for Some St. Louis Residents - The people of St. Louis can call and thank the Environmental Defense Fund (EDF) when their natural gas supplies and/or electricity are turned off later this summer because the Spire STL pipeline must shut down. In June MDN brought you the news that three far-left Democrat judges on the U.S. Court of Appeals for the D.C. Circuit overturned a Federal Energy Regulatory Commission (FERC) approval for a long-completed and flowing natural gas pipeline in the St. Louis, MO area that flows Marcellus/Utica gas to residents, businesses, and electric generating plants throughout the region (see Fed Court Overturns Marcellus to St. Louis Pipe – Shutdown Coming?). The parent company of the pipeline is now warning it is in the process of shutting down the pipeline and that could lead to “service disruptions for customers.”Earlier this week we brought you the news that the EDF, the organization that brought the lawsuit shutting down Spire STL, is crowing that this case is the “tipping point” and that EDF believes it can shut down and block even more pipelines across the country (see Radical EDF Brags Spire Pipeline Court Decision is “Tipping Point”). Ever notice that groups like EDF always destroy jobs and the economy, and never, ever create jobs or contribute to the economy? Spire STL connects to and gets M-U gas from the Rockies Express (REX) pipeline. REX between Ohio and Missouri was reversed several years ago to bring our molecules to the Midwest. An important market for our molecules is now directly threatened because of the EDF.

Natural Gas Prices Swing as Traders Track Variables Across Globe — LNG Recap -- Global natural gas prices have turned volatile after a stretch of gains as traders watch variables in key markets from the United States to Asia. In the United States, the Henry Hub prompt contract finally retreated early last week after a nine-day winning streak. However, it spiked again by nearly 10 cents last Thursday (July 8) on a weak storage build before finishing lower to end the week. Traders looked past a tilt toward cooler weather Monday and focused instead on near-term heat and expectations for strong domestic demand and U.S. exports over the balance of summer. That sent gas futures higher. The August contract shed 5 cents Tuesday to finish at $3.696/MMBtu, with similar losses seen across the forward curve.Cameron LNG in Louisiana shut one of its three liquefaction trains for maintenance on Monday, but it was expected back online by Tuesday. Feed gas deliveries dipped to about 10.46 Bcf/d as the week got underway and were hovering near that level on Tuesday. However, nominations to the Cameron terminal were up slightly, according to NGI’s U.S. LNG Export Tracker. The market has also been on a seesaw in Europe. Dutch futures finished last week higher as storage inventories on the continent remain low and Asian liquefied natural gas (LNG) prices remain high enough to lure cargoes away from Europe. Still, prices dipped significantly on Monday in most European markets. Engie EnergyScan analysts said prices were pressured lower by supply rebounding and technical selling. Russian pipeline imports jumped as maintenance on the Yamal system ended, while Norwegian flows also increased as the week started. Statements by Nord Stream 2 AG CEO Matthias Warnig also moved the market lower Monday. He told German newspaper Handelsblatt that both legs of the 5.3 Bcf/d system planned to move gas from Russia to Germany would be online by the end of the year. Testing has already started on the first leg of the project, Warnig reportedly said. Only 2% of construction remains on the second leg. By Tuesday, prices had jumped higher as both the Title Transfer Facility and National Balancing Point contracts gained across the curve. Further volatility is likely this week as the European Commission is slated to unveil a climate policy package on Wednesday aimed at reducing emissions by 55% across the continent by 2030 from 1990 levels. In Asia, meanwhile, spot prices were assessed above $13/MMBtu, down by about $1 from a week ago. Demand still remains strong in the region, but higher prices have sidelined some buyers from the spot market.

U.S. natgas futures hit 30-month high on soaring global prices (Reuters) - U.S. natural gas futures rose 2% to a 30-month high on Monday as rising global gas prices offset forecasts for slightly less hot weather and lower air conditioning demand over the next two weeks than previously expected. Front-month gas futures NGc1 rose 7.5 cents, or 2.0%, to settle at $3.749 per million British thermal units, their highest close since December 2018. U.S. speculators last week boosted their net long futures and options positions on the New York Mercantile and Intercontinental Exchanges for a sixth week in a row to their highest since May 2017 on expectations U.S. exports would reach fresh record highs as global gas prices soar with low stockpiles around the world. The amount of gas in U.S. storage for the winter of 2021-2022 was almost 7% below the five-year (2016-2020) normal for this time of year. Data provider Refinitiv said U.S. output in the Lower 48 states slipped to 91.5 billion cubic feet per day (bcfd) so far in July, due mostly to pipeline problems in West Virginia earlier in the month. That compares with an average of 92.2 bcfd in June and an all-time high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would rise from 91.9 bcfd this week to 94.0 bcfd next week as the weather turns seasonally hotter. Those forecasts, however, were lower than Refinitiv projected on Friday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants averaged 10.9 bcfd so far in July, up from 10.1 bcfd in June but still below the record 11.5 bcfd in April. With European and Asian gas both trading over $12 per mmBtu, analysts said buyers around the world would keep purchasing all the LNG the United States can produce. U.S. pipeline exports to Mexico, meanwhile, averaged 6.5 bcfd so far in July, down from a record 6.8 bcfd in June.

Record Natural Gas Prices Give Power Markets a Jolt – WSJ - A scramble for natural gas is creating pockets of scarcity in the global market, boosting prices for the fuel and for the electricity generated by burning it. Rampant demand in China is sucking in chilled cargoes of gas from the U.S., after a year in which American energy companies throttled back production. A drought in Brazil has added to the competition by curtailing power output from hydroelectric dams.Searing heat in Canada and the Pacific Northwest has also lifted gas demand. Some places are missing out, like Pakistan, where a shortage of gas and the delayed onset of the summer monsoon have prompted power outages. The drought gripping the Western U.S. has climate scientists concerned that the natural cycle of water may be shifting.Europe, in particular, is feeling the pinch. With vessels of liquefied natural gas heading to Asia, buyers on the continent have struggled to replenish tanks and caverns after a long and cold winter. Storage levels are the lowest for this time of year in a decade, said Natasha Fielding, a gas analyst at Argus Media.The price of gas at a trading hub in the Netherlands shot to a record $13.10 per million British thermal units in July, according to S&P Global Platts data going back to 2004. Barring mild temperatures this winter, gas prices are likely to remain elevated globally for at least another year, according to Chris Midgley, head of analytics at the commodities-data firm.“There just isn’t enough [liquefied natural gas] to supply Europe,” Mr. Midgley said. “The LNG, of course predominantly coming out of the U.S., is being pulled into Asia and also into Latin America.”High prices for gas, coal and emission permits—the main input costs for power plants—have fed off each other to send electricity markets skyward too. In Germany, Europe’s largest economy, power prices in July jumped to about €83.67, equivalent to around $99.26, a megawatt-hour, according to Argus. That is close to their highest level in figures dating back to 2000. U.K., Spanish and Italian power prices have shot to record highs.The moves are among the most extreme cases in a broader upswing in energy markets. U.S. crude prices have risen 54% this year to about $75 a barrel and Americans drivers are paying more for gasoline than they have done in almost seven years. Thermal coal hasn’t been as expensive in a decade.For consumers and businesses, it is a painful reminder that energy bills can go up as well as down. The jump is driving a quicker pace of inflation, though central banks say that effect will wash out. Lofty prices are taking the shine off a boom in demand for products made by energy-intensive companies. Profits are being squeezed in industries such as chemicals, pharmaceuticals and automotive companies.

Despite Cooler Forecast Shift, August Natural Gas Futures, Cash Prices Jump as Heat Reigns Out West - Traders looked past a tilt toward cooler weather in new forecasts and focused instead on near-term heat and expectations for both strong domestic demand and U.S. exports over the balance of summer, sending natural gas futures higher on Monday. Natural gas futures bounced back on Thursday, bolstered by an anemic increase in inventories that pointed to a tight supply/demand balance and ignited concerns about adequate storage levels. The August Nymex contract spiked 9.2 cents day/day and settled at $3.688/MMBtu. September jumped 9.3 cents to $3.667. The August Nymex contract gained 7.5 cents from the prior week’s close and settled at $3.749/MMBtu. September natural gas also rose 7.5 cents, reaching $3.732 at the close. The prompt month had finished modestly lower on Friday and closed last week overall essentially flat after a series of rallies in June. NGI’s Spot Gas National Avg. advanced 15.5 cents on Monday to $3.720. NatGasWeather said forecast data over the weekend shifted slightly cooler, with both the domestic and European models showing about five fewer cooling degree days (CDD) early next week. However, the firm added, “It’s still a very warm to hot overall U.S. pattern much of the next 15 days, especially over the western half” of the Lower 48, “as strong upper high pressure continues to bring oppressive heat.” EBW Analytics Group provided a similar assessment. Its analysts noted the loss of CDD but said cooling demand overall is expected to “generally remain elevated for 10 to 14 days.”

August Natural Gas Futures, Cash Prices Retreat Along With Weather, LNG Data - Natural gas futures on Tuesday slid lower, following forecasts for a pullback in weather-driven demand and lower liquefied natural gas (LNG) levels in the wake of maintenance work. The August Nymex contract shed 5.3 cents day/day and settled at $3.696/MMBtu. A day earlier, the prompt month had gained 9.2 cents. September fell 5.0 cents to $3.682 on Tuesday.NGI’s Spot Gas National Avg. fell 10.5 cents to $3.615 as hubs in the West gave back some of the whopping gains made over several recent trading sessions.Bespoke Weather Services said that for a second consecutive day, it made forecast revisions to “the cooler side.“We continue to see a general lack of heat in the pattern compared to what was expected previously, with the 15-day period, along with July as a whole, looking to come in cooler than the five- and 10-year normal,” the firm said Tuesday. “Best heat in the pattern lies from the northern Plains back into the interior West, though even in the West the upcoming heat is nothing like what has been seen out there in previous weeks. There remains a total lack of heat with respect to normal in the southern U.S., especially in Texas.” The East could see modest heat at times over the next two weeks, Bespoke added, “though not as strong as recent heat surges.” In total, the firm projected that July gas-weighted degree days would reach about 350, “which would be the lowest July total since 2015.”

August Natural Gas Futures Fail to Sustain Momentum, Falter a Second Day - Natural Gas Intelligence - Natural gas futures rebounded early Wednesday, as liquefied natural gas (LNG) levels bounced back and reassured markets of robust export demand. Still, bearish tilts in domestic weather outlooks and estimates for a higher storage injection put downward pressure on futures in afternoon trading. The August Nymex contract ultimately fell 3.6 cents day/day and settled at $3.660/MMBtu on Wednesday. The prompt month had shed 5.3 cents a day earlier. The September contract slipped 3.4 cents on Wednesday to $3.648. NGI’s Spot Gas National Avg. moved sideways through most of the day, finishing up 2.0 cents to $3.635. While demand this week is holding strong, bolstered by persistent heat in the West and upper high pressure over large swaths of the East Coast, forecasts called for eased cooling needs next week. NatGasWeather said weather systems would track across the Great Lakes and East this coming weekend and next week, an outlook that cut several cooling degree days (CDD) from earlier forecasts.Both the domestic and European weather models maintained a hotter pattern for the last week of July, the firm said, “although this has been delayed by one to two days in recent data due to cooler trends.” Bespoke Weather Services posted a similar outlook. The forecasts overshadowed data elsewhere that was favorable for gas prices. Production declined for a second day and dipped below 90 Bcf in early estimates Wednesday. That was notably below the 92-93 Bcf highs in recent weeks. LNG feed gas volumes, meanwhile, climbed back above 11 Bcf Wednesday after hovering closer to 10 Bcf for a few days because of maintenance work. Several analysts have projected that LNG levels could steadily exceed 11 Bcf in the second half of the summer – barring surprise maintenance work – and potentially eclipse 12 Bcf to set a new record. Demand for U.S. exports of LNG is running high from both Asia and Europe, following cold winters that depleted stockpiles and several hot weeks to start the summer. Even with recent maintenance work curbing volumes, LNG demand “comparisons have averaged a startling 7.3 Bcf/d higher year-over-year for the past three weeks,” EBW Analytics Group said.

US working natural gas volumes in underground storage increase 55 Bcf: EIA -- US natural gas inventories rose nearly in line with the five-year average for the week ended July 9, doing little to erase the storage deficit, as Henry Hub futures fell slightly. Storage inventories increased 55 Bcf to 2.629 Tcf for the week ended July 9, the US Energy Information Administration reported July 15. The build was more than the 46 Bcf injection an S&P Global Platts survey of analysts expected and just above the five-year average build of 54 Bcf, according to EIA data. Storage volumes now stand 543 Bcf, or 17.1%, below the year-ago level of 3.172 Tcf, and 189 Bcf, or 6.7%, below the five-year average of 2.818 Tcf. The NYMEX Henry Hub August contract dipped 4 cents to $3.62/MMBtu July 15, nearly $2/MMBtu above where the prompt month was valued last year at this time as fundamentals have demonstrated significant change. US dry production is down 700 MMcf/d so far this year, while total demand rose 3.9 Bcf/d year to date, according to Platts Analytics. LNG exports have fueled 3.4 Bcf/d of the rise in demand. Platts Analytics' supply-and-demand model currently forecasts a 38 Bcf injection for the week ending July 16, which would measure only 2 Bcf more than the five-year average, doing little to erase the deficit as the injection season nears the halfway point. Midwest injections have increased by 2.5 Bcf while East injections fell by a similar amount for the week ending July 16. The largest change has come from the Pacific region, where pipeline sample data indicate a possible flip to a net withdrawal, likely the result of sustained, hotter-than-normal weather affecting the West Coast. The current Platts Analytics end-of-season forecast has stocks peaking at 3.5 Tcf, 400 Bcf below last year's storage peak. In response to below-normal volumes in storage, shippers, local distribution companies, and end-users will likely boost injection activity over the next few months to build up adequate supply by the time the heating season arrives in early November. But this might prove difficult in the short term as the US enters the peak demand period of the summer.

August Natural Gas Futures Bounce Back as Inventory Concerns Bubble Up - The August Nymex contract gained 6.0 cents day/day and settled at $3.674/MMBtu. September advanced 5.7 cents to $3.658.NGI’s Spot Gas National Avg., however, fell 13.5 cents to $3.485, as next-day prices dropped in the Northeast ahead of an anticipated cool down.The Energy Information Administration (EIA) on Thursdayreported an injection of 55 Bcf into U.S. natural gas storage for the week ended July 9. The result exceeded expectations for a build in the upper 40s Bcf, and it also eclipsed the year-earlier increase of 47 Bcf and the five-year average 54 Bcf injection.Bearish reads on the EIA print pressured futures on Thursday. Still, the prompt month bounced back Friday as analysts emphasized supply/balance tightness following bouts of record heat and robust cooling demand throughout June.Strong liquefied natural gas (LNG) levels, fueled by Asian and European demand for U.S. exports, continued to help drive the demand side of the equation as well. LNG feed gas volumes hovered near 11 Bcf on Friday, according to NGI data.EIA’s 55 Bcf injection left the market roughly 3 Bcf/d tighter than the five-year average when compared to degree days and normal seasonality, according to Wood Mackenzie analyst Eric Fell. This included an estimated 14 Bcf of demand impacts from the Fourth of July holiday.“Three of the last four weeks have appeared tight by between 3-4 Bcf/d,” Fell said Friday. “These three tight weeks have corresponded with nuclear/renewable generation realizing at or below the prior five-year average, cutting against the trend of growth in nuclear/renewable generation that we have seen over time and in 23 of the 27 weeks in 2021.”

Gas Sellers Reaped $11 Billion Windfall During Texas Freeze - The official autopsy of the great Texas winter blackout of February 2021 quickly established a clear timeline of events: Electric utilities cut off power to customers and distributors as well as natural gas producers, which in turn triggered a negative feedback loop that sunk the state deeper and deeper into frigid darkness. It’s now becoming clear that while millions of Texans endured days of power cuts, the state’s gas producers contributed to fuel shortages, allowing pipelines and traders to profit handsomely off them. Interviews with energy executives and an analysis of public records by Bloomberg News show that natural gas producers in the Permian shale basin began to drastically reduce output days before power companies cut them off. As the flow of gas cratered, everyone scrambled to secure enough supply, sparking one of the wildest price surges in history. Power producers were forced to pay top dollar in the spot market for whatever gas they could find. Soon customers will be saddled with the bill. And it’s a big one: The total comes to about $11.1 billion for a storm that lasted for just five days, according to estimates by BloombergNEF analysts Jade Patterson and Nakul Nair. The cost of gas for power generation alone was about $8.1 billion, or 75 times normal levels. A further $3 billion was spent by utilities providing gas for cooking, heating and fireplaces. The BNEF estimate is based on spot prices at major hubs assessed by S&P Global Platts rather than private contracts, so is likely an upper limit of the total cost. Millions of Texans are now faced with the prospect of paying higher gas prices for years as utilities seek to spread the cost over a decade or more. Texas lawmakers have set aside $10 billion to help natural gas utilities cover their natural gas costs from the storm through low-interest, state-backed bonds. A special legislative session convened Thursday but the agenda did not include any measures to fix the power grid. This week, Governor Greg Abbott appeared to double down on his early assessment that wind and solar were prime culprits of the freeze. Even though gas failed in its role as a reliable backup fuel during the freeze, Abbott pushed regulators in a letter to strengthen incentives for fossil fuel and nuclear generators while increasing “reliability costs” for intermittent renewable power sources. What Abbott didn’t mention was the massive windfall key industry players made during the freeze. Energy Transfer posted its highest quarterly net income on record, more than three times its previous best quarter. This is “the most massive wealth transfer in Texas history,” said Ron Nirenberg, mayor of San Antonio. “Energy market participants took full advantage of the declared disaster, or did not take the appropriate steps to stop the exorbitant and unconscionable prices.”

As Texas electric grid failed, natural gas companies were paid to turn off power: report - The February winter storm that nearly brought the Texas electricity grid to its knees likely stressed the state’s natural gas infrastructure “more than any time in history,” according to the authors ofa new UT Austin report analyzing the power outages and their financial implications. The report includes previously undisclosed data about how the Electric Reliability Council of Texas, the grid’s manager, responded to the unfolding crisis, which led to widespread outages andhundreds of deaths statewide. The report was released just before ERCOT announced its own “roadmap” of 60 proposals to improve the grid. “This isn’t the only time natural gas has constrained electricity generation — it happened in other recent blackouts (1989 and 2011) — but this time was unique,” said Carey King, the assistant director of UT’s Energy Institute and a co-author of the report. “The system was stressed to its absolute maximum capability. One striking revelation from the report involves ERCOT’s Emergency Response Service (ERS) program, which pays enrolled customers to reduce the amount of electricity they are purchasing from the grid or start using backup generators during emergencies. The goal is to decrease ERCOT’s need to start rolling blackouts, according to the agency’s website. UT Austin researchers discovered that 67 electric meters run by natural gas companies were enrolled in the program. In turn, those meters, which were part of the fuel supply chain providing energy to millions of Texans, lost power when the program was activated on Feb. 15.At least five of those meters were later identified as “critical natural gas infrastructure,” including natural gas compressors, processing facilities or other parts of the supply chain, according to Joshua Rhodes, a research associate and co-author.“It seems inconsistent that critical infrastructure should also voluntarily allow themselves to be turned off when they are needed most,” Rhodes said.Natural gas production, storage and distribution facilities played a key role in the electricity crisis by not providing the amount of fuel demanded by power plants during the storm, the report found. That failure led to a dramatic drop in power plant capacity and forced ERCOT to cut power across the state to “avoid a catastrophic failure,” researchers wrote.Researchers attributed those failures in the natural gas system to direct freezing of equipment and failing to inform electric utilities about which parts of their systems were critical and needed power at all times.The outcome was a nearly 85% drop in dry gas production between early February and the winter storm, leading some companies to experience financial windfalls when they could provide scarce gas during the storm.

After explosion kills 14-year-old, Louisiana wants tighter safety rules on oil field tank batteries -Zalee Gail Day-Smith was a talkative, smart 14-year-old from a rural corner of southwest Louisiana who dreamed of going to Harvard University, becoming a lawyer and a judge, and one day making the criminal justice system fairer for more people, her father said. But Day-Smith's dreams were abruptly snuffed out in a tragic explosion and fire on Feb. 28 at an oil tank battery a few hundred feet from her mom's house in the Ragley community between DeRidder and Lake Charles. State Police investigators believe Day-Smith frequently hung out on the Urban Oil and Gas tank battery. She was on top of the first tank that exploded on Feb. 28, throwing her into the air and killing her, a report says. Her death prompted the state Office of Conservation to propose rules that would require tank batteries close to homes, schools, churches and roads to have security fencing, warning signs and other protective measures to keep people from getting onto the flammable, hazardous equipment. The proposed safety changes in Louisiana come nearly 10 years after the U.S. Chemical Safety Board warned that oil batteries in rural areas posed a unique and dangerous attraction for teens and even young adults living among the nation's wide-open spaces. The board recommended warnings and other steps to limit public access. In Louisiana, for instance, the tank batteries are usually set up in far-flung rural areas. They collect the oil and waste salt water, often from a handful of production wells. The Chemical Safety Board found 26 instances between 1983 and 2010 where people were killed in explosions among the more 800,000 oil tank batteries in the nation. In those incidents, 44 people were killed and 25 injured. All of the victims were 25 years old or younger. "They have proven to be a tempting venue for young people looking for a place to gather, and socialize," the CSB wrote in the September 2011 report. "Activities where an ignition source is introduced into the tank, or even the presence of static electricity or lightning, can cause hydrocarbon vapors in the tanks to ignite and explode." The report and its safety recommendations were directed to regulators in Mississippi, Texas and Oklahoma, as well as industry and fire safety groups. They have led to mixed changes to some safety rules, primarily in Mississippi. The state Office of Conservation doesn't currently track oil tank batteries individually and couldn't say how many were in the state. But it's likely thousands based on the nearly 27,000 active oil wells on the state land.

MPCA investigating Enbridge Line 3 nontoxic spill - – The Minnesota Pollution Control Agency is investigating a drilling fluid spill that occurred on the Willow River in Aitkin County at one of Enbridge's construction sites for its new Line 3 oil pipeline. Drilling was halted after the nontoxic spill was discovered early July 6 and "containment and cleanup activities were started," MPCA spokeswoman Cori Rude-Young said Monday. "The MPCA has been in regular communication with the on-site, independent environmental monitors and Enbridge Energy, and we have inspected the site cleanup," she said. The new pipeline will replace the Enbridge's current Line 3, which is deteriorating with age and can now only carry about half of its capacity. It is more than 60% completed. The site where the spill occurred is one of several along the 340-mile route where Enbridge is undertaking horizontal directional drilling to bury its $3 billion pipeline below waterways. The drilling method involves sending a pressurized mud mixture into a tunnel beneath a stream bed before pulling the pipe through. Between 80 and 100 gallons of drilling mud were released, according to the MPCA. "There were no impacts to any aquifers nor were there downstream impacts because environmental control measures were installed at this location," Enbridge spokeswoman Juli Kellner said in a statement. "The drilling operation was immediately shut down, and crews followed the procedure for managing containment and cleanup of material as specified in project permits." The company will need clearance from the MPCA before resuming drilling at the site, which is outside of Palisade in Aitkin County.

State regulators investigate release of drilling fluid into Willow River during Line 3 construction The Minnesota Pollution Control Agency is investigating a spill of drilling fluid into the Willow River in Aitkin County last week during construction on the Line 3 oil pipeline. About 80 to 100 gallons of drilling fluid, or mud, were inadvertently released on July 6 at a construction site near the town of Palisade, Minn., the MPCA said.Enbridge Energy is drilling beneath the Willow River to install a new crude oil pipeline to replace the existing Line 3. It's one of several river crossings along the 340-mile pipeline corridor across northern Minnesota.The MPCA said the drilling mud was a combination of bentonite clay, water and xanthan gum, which it says is not toxic and commonly used as a food additive.Enbridge spokesperson Juli Kellner stated in an email that the company immediately shut down the drilling operation, and crews began containment and cleanup.“There were no impacts to any aquifers nor were there downstream impacts because environmental control measures were installed at this location,” Kellner stated.Environmental groups opposed to the Line 3 project criticized the release, which they call a “frac-out.” They voiced concern that the fine particles in drilling mud could impact aquatic life.The MPCA said it’s been in regular communication with independent environmental monitors on site and has inspected the cleanup. Enbridge must consult with the agency before it an resume drilling at the site. Enbridge says construction on Line 3 is more than halfway complete. It expects the pipeline to be operating by the fourth quarter of this year.

'We're here to ask for help': Tribal leaders urge Walz to block Line 3 - White Earth Nation leadership traveled to the state Capitol Wednesday, calling on Gov. Tim Walz, Lt. Gov. Peggy Flanagan and President Joe Biden to meet with them, government to government, about Enbridge’s Line 3 pipeline. The Capitol rotunda was draped with signs reading “honor the treaties” and echoed with chants of “stop Line 3” from the 100-plus people in attendance. As the new Line 3 nears completion, tribal leaders are increasing pressure on Walz and Biden to block the project. The 337-mile pipeline is more than 60% complete and expected to carry oil by the end of the year. “We’re not here to cause trouble. We’re here to ask for help,” said Ray Auginaush, a White Earth representative. “Remember our generations ahead of us — this is why we’re here today. My great-grandkids are here. That’s who I’m looking out for.” Walz spoke with White Earth Chairman Michael Fairbanks before the rally Wednesday, according to a spokesperson from Walz’s office. They discussed “a commitment to an ongoing government-to-government dialogue,” the spokesperson said. White Earth and Red Lake say the state didn’t sufficiently engage with them as sovereign nations throughout the pipeline permitting and construction process, which the state disputes. Another tribe, the Fond du Lac Band of Lake Superior Chippewa, agreed to let Enbridge build the new pipeline through its land in exchange for compensation and removing the existing Line 3 pipeline there. \ “Government-to-government relations and tribal-state relations are important to the governor and a priority of his administration,” Walz’s spokesperson said. The calls for Walz and Flanagan to act also highlighted a rift in the governor’s office: Walz supports the project, while Flanagan opposes it. Walz, a first-term Democrat-Farmer-Labor governor, announced in 2019 that he would not block the project because he felt doing so would defy the checks and balances between the branches of government. He has publicly said little about the project since.

Line 3 pipeline opponents appeal to Minnesota Supreme Court -- Tribal and environmental groups opposed to Enbridge Energy's Line 3 oil pipeline project asked the Minnesota Supreme Court on Wednesday to overturn a lower court decision affirming the approvals granted by independent regulators that allowed construction to begin last December. The legal move came as protests continue along the route in northern Minnesota. More than 500 protesters have been arrested or issued citations since construction on the Minnesota leg of the project began in December, but they have failed so far to persuade President Joe Biden's administration to stop the project. Meanwhile, opponents have been demanding more transparency about a spill last week of drilling mud into a river that the pipeline will cross. The White Earth Band of Ojibwe, the Red Lake Band of Chippewa, the Sierra Club and Honor the Earth petitioned the state's highest court to hear the case after the Minnesota Court of Appeals last month ruled that the Public Utilities Commission correctly granted Calgary, Alberta-based Enbridge a certificate of need and route permit for the 337-mile (542-kilometer) Minnesota segment of a larger project to replace a crude oil pipeline built in the 1960s that can run at only half capacity. Two other groups — Friends of the Headwaters and Youth Climate Intervenors — made similar but separate filings. The state Commerce Department was part of that earlier appeal but decided not to ask the Supreme Court for further review. One of the central issues in the earlier appeal was the Commerce Department’s contention that Enbridge’s long-range oil demand projections failed to meet the legal requirements. But the appeals panel ruled 2-1 that there was reasonable evidence to support the PUC’s conclusion that the forecasts were adequate. The department said that while the Court of Appeals disagreed with its position, the court’s opinion provided clarity for similar future proceedings. The remaining parties still argue that the PUC failed to demonstrate the need for the oil that Line 3 would transport. And they said in their petition that the appeals court should have considered whether there was enough evidence to back up the PUC's finding that the existing Line 3 poses a real and immediate safety risk. The Commerce Department's involvement had posed a thorny political problem for Democratic Gov. Tim Walz. The Republican-controlled Minnesota Senate expressed its displeasure last summer by firing then-Commerce Commissioner Steve Kelley. And the Senate GOP reaffirmed its readiness to fight the Walz administration on environmental disputes last week when it forced out Minnesota Pollution Control Agency Commissioner Laura Bishop over other matters. The Line 3 replacement would carry Canadian tar sands oil and regular crude from Alberta to Enbridge’s terminal in Superior, Wisconsin. The more than $7 billion project is nearly done except for the Minnesota leg, which is more than 60% complete. Opponents say the heavy oil would accelerate climate change and risk spills in lakes, wetlands and streams where Native Americans harvest wild rice, hunt, fish, and claim treaty rights. But Enbridge says the replacement, made of stronger steel, will better protect the environment while restoring capacity and ensuring reliable deliveries to refineries.

What are the treaties being invoked by Line 3 opponents? Tribal council representatives and members of the White Earth Band of Ojibwe will be gathering at the Minnesota Capitol today to request a “nation-to nation” dialogue with Gov. Tim Walz and President Joe Biden in an effort to stop construction of Enbridge’s Line 3 pipeline. Last Friday, leaders of the tribe gathered in a press conference to raise concerns about the pipeline’s effects on surrounding resources and waters, most notably the treaty-protected wild rice, and said continued efforts to build the pipeline was in violation of the tribe’s treaty rights. As the pipeline nears completion, with the project estimated to be 60% finished as of June, opponents of the pipeline have been advocating for upholding treaty rights as a means to try to halt construction. The White Earth Band is currently suing in federal court, arguing the Army Corps of Engineers can’t issue a permit without tribal approval. Another lawsuit against the Minnesota Pollution Control Agency (MPCA) over a water crossing permit is in the Minnesota Court of Appeals. Meanwhile, in June the Minnesota Court of Appeals reaffirmed state regulators’ key approvals of Line 3 permits, with a three-judge panel ruling 2-1 that the state’s Public Utilities Commission correctly granted a certificate of need to the Canadian oil company. “Manoomin (wild rice) is our most important spiritual, sacred, central part of our culture. This is part of the American Indian Religious Freedoms Act and our rights,” said Frank Bibeau, tribal attorney for the White Earth Band, during the press conference. “Manoomin grows everywhere right now in northern Minnesota. And it’s being starved out from water. It’s being starved out for its nutrients.” During the press conference, Bibeau and Allan Roy, secretary treasure for White Earth, spoke of the 1855 Treaty Authority and others. Here are the relevant treaties and what they mean: A series of 19th-century treaties While the U.S. government signed a series of treaties with the Anishinaabe people, including the Ojibwe, between 1825 and 1867, the most significant are those of 1837, 1854 and 1855. The treaty of 1837 coincided with the collapse of the fur trade, the dominant source of commerce at the time, and the transition to logging as the dominant industry. The treaty is notable for being the first major land cession involving the Ojibwe people, and more importantly specifies the rights of the tribes to gather wild rice, hunt and fish. An estimated 12 million acres of land in central and eastern Minnesota and western Wisconsin was sold to the U.S. government in exchange for payments of $35,000 a year over the course of 20 years.

DNR suspends some water permits for Line 3 construction amid drought - The drought is having an impact on construction of Enbridge's Line 3 pipeline.The Minnesota DNR suspended water permits for dust control, drilling and line testing in some locations where surface water is in low supply.The project has been stop-and-go in Minnesota since work began on the pipeline in December. The DNR will continue to monitor water levels and will allow water use to resume once supplies are back to more sustainable levels.

Susan Rice to sell $2.7M stake in oil pipeline company after project upheld - President Biden’s adviser Susan Rice is being ordered to sell a $2.7 million stake in the oil pipeline company Enbridge — after the Biden administration decided to allow the firm’s Line 3 pipeline project. The Office of Government Ethics ordered Rice to divest from the company on July 9, according to filings first reported by The Daily Poster. Although Biden has broadly taken action against oil pipelines, most notably canceling the Keystone XL oil pipeline, his administration has continued to allow the Line 3 project, which would bring Canadian oil through Minnesota to Wisconsin. Environmental activists oppose the Line 3 project, but the cause has received far less national attention than other pipelines. Last month, Biden administration officials indicated they would not withdraw permission for Line 3 in a major boon for the company. The Office of Government Ethics also ordered Rice, who is director of the Domestic Policy Council, as well as her husband and family trust to divest from smaller holdings that may present a conflict of interest.

Undocumented oilfield workers struggle in New Mexico. Heinrich pushes for energy transition - Pedro Espinoza, an undocumented worker from Mexico, was leaving the Permian Basin for the second time as an operator in the busy oil and gas region. Lower pay and poor conditions, Saucedo said, meant her husband would travel from their home in Hobbs to another prolific oil-producing area thousands of miles north in the Bakken of North DakotaShe said Espinoza left the family and headed north when the Permian Basin last busted in 2016 but was able to return when the industry boomed again a year later. Saucedo said her family is divided not by the boom and bust cycle of the oil and gas industry in the Permian, but rather the treatment he received from his employer as an undocumented laborer. “He came back when there were more jobs available in Hobbs, but then he noticed the big pay difference,” she said in an interview facilitated by a translator. “In North Dakota they pay way more and when he came, he noticed the drop in pay he was getting in Hobbs working the same jobs in the oilfield.” Saucedo expressed concern for worker conditions in New Mexico to Sen. Martin Heinrich during a recent meeting in Roswell where the senator met with members of Somos Un Pueblo Unido – a statewide organization dedicated to racial and worker issues.Aside from a lack of adequate pay, Saucedo said her husband was not provided safety equipment or housing during his time in the Permian, amenities provide to workers in the Bakken.She said she believed this treatment was because of his citizenship status. “This is because companies are choosing to hire undocumented workers and treat them this way,” Saucedo said. “If he was a U.S. citizen, companies wouldn’t be treating him this way.”There are lower standards for undocumented workers in southeast New Mexico because there are more of them, Saucedo said, and companies can hire from a larger pool of undocumented workers.“Lea County is experiencing a lot of Hispanic and Latino people moving to the region,” she said. “They’re hearing about great paying jobs, but they don’t know the dangerous conditions they have to work in. It’s very shocking to people.”

198 oil and gas wells found abandoned near Carlsbad Caverns National Park -Almost 200 oil and gas wells sit abandoned within a 30-mile radius of Carlsbad Caverns National Park.The caverns, which contain a complex system of underground caves, filter local groundwater sources and could be susceptible to contamination from industrial sources like orphaned wells.A study conducted by the National Parks Conservation Association ranked Carlsbad Caverns as the national park or monument with the second-most nearby abandoned wells in New Mexico.Azetc Ruins National Monument in northwest New Mexico was ranked second with 260 abandoned wells within 30 miles of its boundary, and Chaco Culture Historical Park in the same region was third with 44 wells.Manhattan Project National Historical Park near Los Alamos was fourth with seven nearby orphaned wells and Valles Caldera National Preserve just north of Albuquerque was fifth with two wells, per the study.Carlsbad Caverns’ location in southeast New Mexico just outside Carlsbad places it within the oil-rich Permian Basin – New Mexico’s most active oilfield.Aztec Ruins and Chaco Culture in the northwest San Juan Basin are in New Mexico’s other active but less production natural gas field known for one of the densest methane clouds every discovered hovering over the Four Corners region.Nationwide, the study showed there were more than 30,000 orphaned wells within a 30-mile radius of national parks, which could bring pollution in the air and groundwater to the federal public lands.America Fitzpatrick, energy program manager at the Association said the abandoned wells could harm public lands set aside for conservation while also worsening the impacts of climate change.“It is shocking to learn how many orphaned oil and gas wells are leaking dangerous pollutants into the air and water, harming not only our national parks but also local communities,” Fitzpatrick said. “This is an urgent problem that needs to be addressed by Congress to protect parks and public health, and prevent oil and gas companies from skipping town without cleaning up after themselves again in future.”

Antsy Industry Awaits Interior Oil Lease Sale After Court Order -- Oil and gas industry-aligned lawyers say the Interior Department could be held in contempt of court if it doesn’t soon comply with a Louisiana federal judge’s order to restart federal oil and gas leasing. The department paused quarterly oil and gas leasing nationwide in January while it reviewed the leasing program. But Louisiana U.S. District Judge Terry Doughty on June 15 issued a preliminary injunction enjoining and restraining Interior from implementing the pause in Louisiana v. Biden. Interior Secretary Deb Haaland said Tuesday that the department is complying with Doughty’s order and will follow the law, but she declined to say how exactly it’s doing so. If Interior doesn’t conduct a quarterly lease sale soon, “the secretary risks a contempt citation from Judge Doughty,” said John Martin, an oil and gas lawyer and Wyoming-based partner at Holland & Hart LLP. “One would expect that those lease sales would have to go forward forthwith.” Interior Communications Director Melissa Schwartz said Thursday that the department is still reviewing Doughty’s preliminary injunction and declined to comment on whether a lease sale announcement is imminent. Interior needs to resume quarterly lease sales in most Western states where land is available for leasing to comply with the order. But it doesn’t need to “offer all of the lands” that are available, said Mark Squillace, a natural resources law professor at the University of Colorado-Boulder. “I’m expecting that we’re going to see both on shore and offshore lease sales soon,” Martin said. “I do believe that Judge Doughty will be watching those closely.”Some of Interior’s oil and gas activity is moving ahead despite the leasing pause. Interior’s Bureau of Land Management, which is in charge of onshore oil and gas leasing, is actively issuing drilling permits on existing leases nationwide. The pause applies only to new leases. The land bureau approved 616 drilling applications for federal leases nationwide in May—418 of which were in New Mexico, according to its most recent data. It has approved a total of 3,994 drilling applications during FY2021. The bureau’s oil and gas permitting activity shows that its leasing pause hasn’t adversely affected oil and gas production on federal lands, said Bob Abbey, a former land bureau director in the Obama administration.

U.S. drilling approvals increase despite Biden climate pledge - Approvals for companies to drill for oil and gas on U.S. public lands are on pace this year to reach their highest level since George W. Bush was president, underscoring President Biden’s reluctance to more forcefully curb petroleum production in the face of industry and Republican resistance.The Interior Department approved about 2,500 permits to drill on public and tribal lands in the first six months of the year, according to an Associated Press analysis of government data. That includes more than 2,100 drilling approvals since Biden took office Jan. 20.Biden campaigned last year on pledges to end new drilling on federal lands to rein in climate-changing emissions. His pick to oversee those lands, Interior Secretary Deb Haaland, adamantly opposed drilling on federal lands while in Congress and co-sponsored the liberal Green New Deal.But the steps taken by the administration to date on fossil fuels are more modest, including a temporary suspension on new oil and gas leases on federal lands that a judge blocked last month. Further complicating Biden’s climate agenda is a recent rise in gasoline prices to $3 a gallon or more in many parts of the country. Any attempt to limit petroleum production could push gasoline prices even higher and risk souring economic recovery from the pandemic. “He is definitely backing off taking drastic action that would rock the market.... What you’re going to see is U.S. oil production is going to continue to rebound.”Haaland has sought to tamp down Republican concern over potential constraints on the industry. She said during a House Natural Resources Committee hearing last month that there was no “plan right now for a permanent ban.”“Gas and oil production will continue well into the future and we believe that is the reality of our economy and the world we’re living in,” Haaland told Colorado Republican Rep. Doug Lamborn.

Industry Calls the Climate Shots in the Biden Administration --Don’t miss the fact that millions of gallons of poison (“chemicals”) are pumped into the ground in order to force other poisons (methane and fracked oil) out of it. In contrast to the praise Biden is getting from people like Maureen Dowd (the essence of her latest column is “See, Bernie likes Biden and he likes Bernie”), Biden’s actual deeds, especially on climate, are deadly.(The other essence of Dowd’s latest column is, “Continue to hope; Bernie can still save us.” She writes, “Sanders … and Biden have a bond that could have a profound effect on the lives of Americans,” whitewashing Biden with Sanders’ remaining cred. No mention of Sanders’ ultimate powerlessness.)Food And Water Watch (FWW), a group that’s always excellent on climate and environmental issues, has put together a list of Biden’s actions that contradict his promises. It’s an easy read. Taken together, these are deadly indictments.If Biden wanted to fix the increasingly urgent climate problem, he’d be doing that now and we’d be seeing him do it. Instead he fed us nice words when he wanted our vote, then contradicted those words with his constant and ongoing deeds once he gained power. There can be no question that industry calls the shots in his administration. Read and weep. The following is excerpted and adapted from the FWW article. Read it in full for additional detail on each of these points.

The UN needs stricter resolutions to stop fracking - It is quite ironic that the US wants to play a leading role in the fight against climate change, yet the country continues to use harmful and environmentally hazardous fracking to extract shale gas, resulting in emissions of greenhouse gases into the atmosphere and chemicals into water and soil. Proponents of hydraulic fracturing and horizontal drilling are credited with turning unproductive shales into the largest natural gas. Good for business. But protagonists of this dangerous technology of hydraulic fracturing stand accused of putting profits before the environment and humanity. Combating environmental degradation remains one of the UN’s key Millennium Development Goals. Hence initiatives such as the annual World Environment Day during which a conscious effort is made to educate the international community about the wisdom of protecting and preserving our environment. The use of plastic is currently facing extinction. Examples of the negative impact of plastic manufacturing and usage are abound, with images of sea population suffocating on plastic dominating the world stage. Leading global powers such as the US carry on their shoulders the responsibility to take a front role in preserving the environment and indeed our universe. Efforts aimed at fighting climate change have become a collective objective of multilateral organisations. But what is sadly evident is the display of double standards in climate policy of Washington in particular. The international community was left aghast when former US president Donald Trump pulled his country out of the Paris Declaration and prioritised his “America First” foreign policy. Pretty swiftly, though, Trump’s successor President Joe Biden enchanted the world with his decision to return his country to the multilateral institutions where its absence had been felt during Trump’s four years in the Oval Office, particularly with Washington’s crucial monetary contributions and general aid.

Berkshire Hathaway scraps pipeline purchase because of antitrust concerns – CNN - Buffett's Berkshire Hathaway announced Monday it was scrapping plans to buy a big natural gas pipeline for more than $1.7 billion because of antitrust concerns.Oil Giant Dominion Energy (D) already completed the sale of gas transmission assets to Berkshire Hathaway's energy subsidiary in November. But Dominion said the plan to sell its Questar Pipelines business to Buffett's firm was canceled because of "ongoing uncertainty associated with achieving clearance from the Federal Trade Commission" for that part of the deal.Questar operates mainly in Utah, Wyoming and Colorado. So there may have been FTC concerns about overlap with the Berkshire Hatahway Energy subsidiary PacifiCorp, which owns the Rocky Mountain Power energy company that serves customers in Utah, Wyoming and Idaho. Dominion said in November when the initial part of the deal was finalized, it had already received approximately $1.3 billion in cash from Berkshire in anticipation of the full sale being completed. Dominion also said it was planning to transfer about $430 million in Questar debt to Berkshire once the deal closed.Now that the Questar sale is off the table, Dominion said it will begin a competitive process to sell the business to another bidder, adding that it hopes to complete a deal by the end of this year.

Four operators' wells declared abandoned, another's bonds revoked at WOGCC hearing - More than four years after Bearcat Energy filed for bankruptcy, the Wyoming Oil & Gas Conservation Commission on Tuesday voted to require the natural gas operator to forfeit $2.25 million in bonds for the plugging and reclamation of its abandoned wells. Bearcat, which bid close to $1.2 million for approximately 100 Wyoming coal-bed methane wells in 2010, ceased known operations in 2016. It failed to provide nearly $200,000 in additional bonds requested by the commission in 2016 and stopped submitting production reports in 2017, violating commission requirements for well monitoring during bankruptcy. The company filed for chapter 11 bankruptcy — known as “reorganization” bankruptcy — in early 2017. Corporations that successfully undergo this type of bankruptcy often continue to operate throughout the proceedings, retain many of their existing assets and emerge with reduced debt. Wyoming’s regulators prefer to wait to revoke reclamation bonds from oil and gas companies undergoing chapter 11 bankruptcy until they can determine whether the companies will resume operations at idle wells. “Oftentimes, we try to let the dust settle in some of these cases, because something might emerge from bankruptcy, or a purchaser may come and be able to turn these wells back on,” said Micah Christensen, the assistant attorney general representing the commission staff, during the hearing. In Bearcat’s case, the bankruptcy filing was converted last year from chapter 11 to chapter 7 — liquidation — leaving the company with no chance of revival. But another operator is attempting to take over some of the company’s wells prior to its dissolution. “If we give ourselves a window of time where the forfeiture of the bonds takes place, that will probably be the best for all parties, including the state, to make sure that we go forward with an abandonment for these wells that clearly need to be forfeited, but also provide an opportunity for that other operator,” Christensen said. The commission will require Bearcat to surrender up to $2,250,430 in bonds by Oct. 15. But that’s unlikely to cover the full costs of reclamation, according to Lottie Mitchell, an organizer with the Powder River Basin Resource Council.

Goldman Sachs caught in flareup over natural gas pollution in North Dakota -David Solomon’s bid to rebrand Goldman Sachs as environmentally green is going up in flames — courtesy of a bankrupt oil and gas company in North Dakota. That’s the charge from critics — and creditors — who claim that Goldman, as a key lender of debtor-in-possession financing to Nine Point Energy, has failed to curb the driller from flaring natural gas into the atmosphere as part of what looks like hard-knuckle Chapter 11 negotiations. In April, Nine Point flared over 155 million cubic feet of the greenhouse gas from its North Dakota wells. That’s more than two-and-a-half times what they emitted prior to the company’s February bankruptcy filing, and equates to more than 21 million miles driven by passenger vehicles, according to the Environmental Protection Agency. That also amounted to a whopping third of its production — well north of the 9-percent limit allowed by environmental regulators, who cite emissions of carbon dioxide, as well as nitrogen oxides that cause acid rain, ozone and smog. Goldman — whose CEO Solomon pledged in March to detail this year how “climate-risk considerations” figure into the bank’s business strategy — is in a lending group led by Alliance Bernstein that’s poised to take ownership of Nine Point to forgive $250 million in debt. But the deal has hit a snag over a lawsuit from Caliber Midstream, a pipeline company whose contracts to safely transport the gas Nine Point rejected in Chapter 11. Caliber is suing for $150 million in construction costs. Nine Point’s gas flaring provoked a befuddled response from a Caliber attorney at the start of the bankruptcy. Alfredo Perez of white-shoe law firm Weil Gotshal noted that Nine Point was “literally flaring the natural gas that would otherwise come into our system for some reason, in an effort to … put pressure on us, I’m not quite sure exactly why, but it’s part of our theory,” according to a March 17 court transcript.

'Black Snake' tells saga of Dakota Access Pipeline protests - The protest against the Dakota Access Pipeline by the Standing Rock Sioux was one of the most important news stories of 2016 – and rightly so, as it touched on issues related to climate change, fossil fuel dependence, Indigenous rights, and environmental justice. The protest spanned nearly a year, straddled two presidential administrations, and drew thousands to the protest camp site in North Dakota. It caught the world’s attention and starkly illuminated the nation’s long, shameful history of mistreatment of its Indigenous peoples. In “Black Snake: Standing Rock, the Dakota Access Pipeline, and Environmental Justice,” human rights lawyer Katherine Wiltenburg Todrys takes a deep dive into the protest against the oil pipeline, whose proposed route threatened the Standing Rock Sioux’s water source and sacred sites. Although Todrys makes extensive use of sources and documents from both sides of the dispute, there is no doubt that her sympathies lie with the protestors. The Dakota Access Pipeline (DAPL) was a mammoth, $3.8 billion project that would carry up to 570,000 barrels of crude oil from the shale oil fields of the Bakken formation in northwest North Dakota to an oil terminal in south-central Illinois. Dakota Access and its parent company Energy Transfer Partners argued that a pipeline would be safer and more efficient than transporting oil by rail. (Train cars full of oil are known to derail and even explode, but pipelines are also problematic; they’re notorious for producing spills large and small, leaving behind poisoned land and water.)Even with the environmental risks inherent in a pipeline, Dakota Access had little difficulty in securing voluntary easements from property owners along its proposed 1,170-mile route. Little difficulty, that is, until the company had to deal with the Standing Rock Sioux. Despite widespread poverty on the reservation and an unemployment rate of 70 percent, as the author puts it, “the Standing Rock Sioux would not be bought off.”In April 2016, a small group of “water protectors,” many of them teenagers, gathered on land owned by a tribe member and established the Sacred Stone Camp to protest the DAPL, which they called the “black snake,” referring to an ancient Lakota prophecy about a snake that would one day devour the earth. The camp quickly drew Indigenous people from across the country, as well as non-native supporters. Their efforts gained attention through social media campaigns as well as acts of civil disobedience, in which protestors locked themselves to heavy machinery on the construction site and were subsequently arrested. In time, the camp swelled to an eclectic mix of some 10,000 protestors, including representatives of 300 federally recognized tribes, possibly the largest alliance of native tribes in U.S. history. Politicians and celebrities joined in, and the effort caught the attention of the international press and organizations like Amnesty International. The eyes of the world were focused on the Standing Rock Sioux Reservation. In the meantime, work on the pipeline continued. In the fall of 2016, peaceful protestors were met with violent opposition from local law enforcement, which used rubber bullets, water cannons, and attack dogs against them. Videos showing dogs with bloody mouths, similar to images of violent crackdowns during the civil rights movement, went viral and were replayed by major news networks. “The whole world also saw what had happened to the water protectors,” Todrys writes.

Permafrost thaw threatens Alaska's largest oil pipeline - Thawing permafrost is compromising part of the Trans-Alaska Pipeline System, which connects crude oil drilled in the Arctic to tankers in the Port of Valdez, highlighting how a warming climate is reshaping the oil industry in Alaska. While there is no immediate threat of an oil spill, Alyeska Pipeline Service Co., the pipeline operator for TAPS, discovered buckling supports that hold the pipe above ground. Alyeska, a consortium of oil and gas companies, will install underground coolers as a solution “to protect the integrity of TAPS from permafrost degradation” in addition to replacing the supports, according to an update from the Alaska Department of Natural Resources this winter. The finding was first reported by Inside Climate News. State regulators approved driving 100 hundred pipes 50 to 60 feet deep. They will be equipped with passive cooling systems to draw heat away from the ground, according to the state. Alyeska will also use wood chips and other measures as insulation on the surface. “TAPS was designed and built to manage changing environmental conditions, including permafrost zones,” Michelle Egan, a spokesperson for TAPS, said in an email, noting that cooling systems to stabilize the permafrost are not new for the pipeline. “Alyeska has operated TAPS for more than 44 years with commitment and respect for its dynamic environment. As part of that commitment, thermal units and the VSMs are regularly monitored and when needed, Alyeska repairs or reinforces them,” she said. Bill Caram, executive director of the Pipeline Safety Trust, said the pipeline does not appear to be in immediate danger of a severe failure, such as a collapse that could lead to an oil spill. But he said this finding, and the necessary remediation, could be a “harbinger” of things to come as temperatures rise. “The pipeline was designed to handle the dynamic nature of permafrost, but not in a rapid climate change environment,” he said.

‘Wake Up Call’: Rapidly Thawing Permafrost Threatens Trans-Alaska Pipeline - Alaska’s thawing permafrost is undermining the supports that hold up an elevated section of the Trans-Alaska Pipeline, putting in danger the structural integrity of one of the world’s largest oil pipelines.In a worst-case scenario, a rupture of the pipeline would result in an oil spill in a delicate and remote landscape where it would be extremely difficult to clean up.“This is a wake-up call,” said Carl Weimer, of Pipeline Safety Trust, a nonprofit pipeline watchdog group based in Bellingham, Washington. “The implications of this speak to the pipeline’s integrity and the effect climate change is having on pipeline safety in general.”A slope where an 810-foot long section of the pipeline is secured has started to slip due to the melting permafrost, in turn, causing the braces holding this section of the pipeline to twist and bend. According to NBC News, the pipeline supports have been damaged by “slope creep” caused by thawing permafrost, records, and interviews with officials involved with managing the pipeline show.To combat the problem, the Alaska Department of Natural Resources has approved the use of about 100 thermosyphons — tubes that suck heat out of the permafrost – to keep the frozen slope in place and prevent further damage to the pipeline’s support structure.“The proposed project is integral to the protection of the pipeline,” according to the department’s November 2020 analysis.There is some concern in using these cooling tubes – They have never been used as a defensive safeguard once a slope has begun to slide, and the permafrost is already thawing.The Arctic and Alaska are heating twice as fast as the rest of the globe because of global warming. And global warming is driving the thawing of permafrost that the oil industry must keep frozen to maintain the infrastructure that allows it to extract more of the fossil fuels that cause the warming.Permafrost is ground that has remained completely frozen for at least two years straight and is found beneath nearly 85 percent of Alaska. In the last few decades, permafrost temperatures there have warmed as much as 3.5 degrees Fahrenheit.The state’s average temperature is projected to increase 2 to 4 degrees more by the middle of the century, and a study published in the journal Nature Climate Change projects that with every 2-degree increase in temperature, 1.5 million square miles of permafrost could be lost to thawing.

Oil prices are up, but Alaska is America's bottom state for business in 2021 - In a normal summer, Skagway, Alaska, population 1,183, would be teeming with tourists from the cruise ships sailing the Inside Passage. Residents could drive 15 miles up the Yukon Highway into Canada to run their basic errands, or they could hop on a state-run ferry to the next town over, Haines.But this year, the cruise ships have just started running again. Cremata is hoping Skagway will see 100,000 passengers this year; in 2019 they had 1.1 million. The border to Canada remains closed to non-essential traffic, and the ferries, part of the Alaska Marine Highway System, are plagued by budget cuts."Just getting your family down to go see a dentist or doctor, when that becomes burdensome or overly expensive, there's a point where people have just had it and move away," Multiply Skagway's situation by thousands of communities and more than 700,000 Alaskans, and you can begin to understand why The Last Frontier finds itself in last place in CNBC's 2021 America's Top States for Business rankings. It is the sixth bottom-state finish for Alaska in 14 years. The state previously achieved the dubious distinction in the first four years of the study between 2007 and 2010, hitting bottom again in 2018. Alaska met the pandemic with the best-funded public health system in the nation, according to the United Health Foundation, spending $289 per person per year. That is more than three times the national average. Earlier this year, the state was setting the pace for Covid-19 vaccinations, even in its most remote regions. As the national economy struggled to regain its footing, Alaska offered a generally business-friendly regulatory climate — its legal system tilts toward business, and the number of state laws and regulations is manageable. The conservative-leaning Tax Foundation ranks Alaska's tax climate the third-best in the country. So how did Alaska manage to finish No. 50 again in 2021 despite so many advantages going in? In a word: cost.Cost of Doing Business carries the most weight in this year's study. As the recovery builds, states are touting low business costs more than any other factor, according to CNBC's analysis. Alaska is an extremely expensive place to do business.Even Alaska's competitive tax climate, which earns points for relatively low property taxes and no personal income tax, includes a top corporate tax rateof 9.4%, among the highest in the country.

Arctic oil spill cleanup costs could reach $9.4B over 5 years, says risk analyst | CBC News - As global temperatures rise, ice in the Canadian Arctic is melting at an unprecedented rate. This means the Northwest Passage will see more ship traffic — which increases the potential for an oil or fuel spills in the region.A new risk assessment on the consequences of a hypothetical oil spill in the Rankin Inlet region of Nunavut posits that the cleanup and socioeconomic costs of such a disaster could limb to $9.4 billion ($7.5 billion US) in five years under a worst case scenario.The worst case scenario is where no attempt is made to clean up or otherwise mitigate the spill. While non-intervention is unlikely, the report says considering such a worst case situation is "the best scenario to use in making decisions for insurance, resource allocation, and contingency planning."The Arctic can also be a harsh environment which gives only a short window for open-water response to an environmental disaster. As such, a delayed response to a fuel spill in the Arctic is plausible. The study, as part of the GENICE project, also showed that the impacts of an Arctic oil spill would be devastating for Inuit and the environment. "It's a low probability, high consequence event, which means that it happens once in a while, but when it does happen, the consequences are really, really high," To estimate the consequences of a spill, Afenyo and his colleagues simulated the Exxon Valdez oil spill of 1989, in which 11 million gallons of crude oil were spilled into an inlet on the Gulf of Alaska. The simulated spill in their analysis took place in the Rankin Inlet coastal region. Using a "unique" method they developed for this research, the researchers determined that each year, there is a gradual increase in socioeconomic impact — such as damage to flora and fauna, disruption of hunting and negative psychological effects — as well as cost.

Troubled Caribbean refinery seeks bankruptcy as lenders balk at injecting more cash -(Reuters) -The owners of Limetree Bay, a refinery on the U.S. Virgin Islands that was once the largest in the Western Hemisphere, filed for bankruptcy on Monday after lenders balked at putting new cash into a project dogged by environmental violations, cost overruns and regulatory troubles. The St. Croix refinery overhaul was the most expensive effort in nearly a decade to expand refining capacity in the hemisphere. Investors plunged more than $4 billion into the project, aimed at taking advantage of its prime location along shipping routes in the Caribbean. The plan fizzled after construction delays and the COVID-19 pandemic, which slashed demand for fuel worldwide. The refinery finally restarted in February - only to shut three months later when Limetree Bay ran afoul of U.S. environmental regulators who ordered it shut after a series of fires and noxious gas releases. "Severe financial and regulatory constraints have left us no choice but to pursue this path, after careful consideration of all alternatives," Jeff Rinker, Limetree Bay's chief executive, said of the bankruptcy filing in a statement. The U.S. Environmental Protection Agency (EPA) in May ordered the plant to shut temporarily after the gas releases contaminated local drinking water, shut a school and led residents to complain of breathing problems and foul odors. The EPA order, and subsequent investigations by U.S. officials, made investors wary of investing the additional money needed to get the refinery restarted, the company said in court filings.

Investors balk as bankrupt St. Croix refinery needs $1 bln to be viable (Reuters) - The Limetree Bay refinery, which landed in U.S. bankruptcy court on Monday, needs at least $1 billion to finish a massive overhaul to continue as a viable operation, according to bankers, lawyers and restructuring specialists involved in the case, stacking the odds against the Caribbean facility resuming operations. The St. Croix-based facility's owners burned through $4.1 billion to resurrect what was once the largest refinery in the Western Hemisphere, hoping to take advantage of rising global demand. Instead, the refinery only operated for three months before U.S. environmental regulators shut it in May due to foul odors and noxious releases that harmed nearby communities. Limetree filed for Chapter 11 bankruptcy protection with no clear path to restructure some $1.8 billion in debt. It says it needs "at least $150 million" to restart, but restructuring specialists familiar with the operation put that figure at an additional $1 billion. That grim assessment comes from interviews with several Wall Street bankers, lawyers and restructuring specialists involved in the bankruptcy case or closely familiar with it. These sources did not want their names used in this story because they are not authorized to speak publicly about the matter. The facility also now faces the specter of ongoing investigations by the U.S. Environmental Protection Agency and the U.S. Justice Department. Even if Limetree were to restart, it faces several challenges. The refining market is already weak after fuel demand was hit by the coronavirus pandemic, and heavy crude oil favored by Limetree is in short supply due to reduced production out of Mexico and Venezuela, putting its price near three-year highs, which hurts potential margins. The refinery’s oil supplier, BP, is among the largest unpaid trade suppliers to Limetree and has shifted investment to wind and solar from fossil fuels. Limetree also has higher fuel expenses because it burns fuel oil or refinery gases to power operations, according to analysts at Morningstar, compared with U.S. refineries that power themselves with cheaper natural gas. That extra cost is enough to shave $1 to $2 per barrel off refining margins, analysts say.

Oil cleanup complete at historic shipwreck off Vancouver Island-- The Canadian government says the removal of oil from a shipwreck off Vancouver Island is complete after oil was spotted leaking from the wreck in December. On Monday, Fisheries Minister Bernadette Jordan said roughly 60 tonnes of heavy fuel oil and diesel had been removed from the MV Schiedyk, which sunk off Bligh Island in 1968. After oil was seen leaking from the shipwreck in December, federal, provincial and local First Nations began containing the materials. The U.S.-based Resolve Marine Group was contracted tohelp remove the fuel in the spring. Much of the oil was coming from the ship's four fuel tanks after the vessel had sunk to a depth of roughly 122 metres.To remove the fuel, Resolve used drones to drill holes into the fuel tanks, then attached drainage valves and hoses to pump out the oil. Hot water was also injected into the tanks to help liquefy the oil to make it easier to pump, according to the federal government.The oil and water mix was pumped onto a Canadian-registered ship, the Atlantic Condor, where the oil and water was then separated.This pumping technique was used until oil was no longer detected in the fuel tanks, according to the federal government.

Why Russia Is Refusing To Send Europe More Natural Gas - Rising commodity prices have strengthened the economic outlook of resource-rich countries. Russia is taking advantage of this in a major way, with a particular focus on crude oil and natural gas. As Europe’s most important supplier of gas, Gazprom is well-positioned to reap major dividends. However, the state-controlled energy behemoth's lukewarm response to sending additional volumes to Europe could be a sign that the company’s strategy has changed. In 2020, Gazprom’s exports decreased from 199 bcm in 2019 to 170 bcm. The majority of this gas transits through Soviet-era pipelines from Russia to Belarus and Ukraine. Another 55 bcm capacity was added in 2011 with Nord Stream’s completion and will be double to 110 bcm when the heavily contested Nord Stream 2 pipeline starts pumping gas at some point in the next two years.The restart of the European economy has increased demand for commodities and led to substantially higher prices. Although LNG imports have increased over the years, the bulk of the natural gas is still transported through pipelines. Of these exporters, Russia is by far the largest and most influential country due to its sizeable energy industry and excess capacity. Although prices are favorable, Gazprom doesn't seem to be in a hurry to send extra volumes on top of the running contracts with European customers. After an exceptionally cold heating season, European storages are historically low which further boosts demand to prepare for the coming winter. Also, some parts of Europe are experiencing an unusually warm summer leading to higher demand for electricity to run air-conditioners. Under normal circumstances, coal-fired powerplants would fill the gap, but the price of CO2 on Europe’s ETS has doubled to €52 since November. Therefore, natural gas-fired powerplants, which emit almost 50 percent less, are in higher demand.In the past, Gazprom would have quickly ramped up exports to satisfy additional needs with the ultimate goal of increasing market share. However, the Russian company has held off from booking extra transit capacity through Ukraine’s pipeline system. According to Nick Campbell, director at consultancy Inspired Energy, “so far this summer Gazprom has yet to purchase any capacity in the (Ukraine’s) monthly auctions. Therefore, one could see this as a strategy to push Nord Stream 2 to completion.”

Shell Abandons Push for Oil Spill Case to Be Heard in Nigeria -- Royal Dutch Shell Plc has abandoned its final attempt to argue that a major lawsuit brought by thousands of Nigerians over an oil spill in the West African country should be heard in Nigeria rather than the U.K. Shell’s legal team declined to return to England’s High Court with arguments that the five-year-old case would be better heard in Nigeria, according to the parties in the case, conceding that the Nigerian subsidiary will now be joined to claims made in England against the parent company. The U.K. Supreme Court said in a landmark ruling in February that Shell’s parent company could be sued in English courts for the actions of its Nigerian subsidiary. The court, however, left the door open for Shell to argue that it was more appropriate to leave any action against the local unit to Nigerian courts. By including the subsidiary in the U.K. proceedings, more documents about Shell’s work in Nigeria are likely to be made public. The decision follows a pair of recent legal defeats for Shell. A Dutch court in January ordered the company to pay compensation to villagers in the Niger Delta over an oil spill decades ago. In a separate trial in The Hague in May, Shell lost a key case in which it was told to slash emissions by 45% across all its international operations by 2030.

Shell confirms another oil spillage at an oil field in Bayelsa State - Shell Petroleum Development Company of Nigeria (SPDC) has said that there was an oil spillage at its facility in Ekeremor Local Government Area of Bayelsa State. This is as the Nigerian subsidiary of the Anglo-Dutch oil and gas giant noted that the spill clean-up is progressing while the Joint Investigation report is at the conclusion stage. This disclosure is contained in a statement issued by the Media Relations Manager of SPDC, Mr Bamidele Odugbesan, saying that the spill, which discharged a yet to be ascertained volume of crude into the environment, occurred on June 15. According to a report from the News Agency of Nigeria (NAN), Odugbesan dismissed claims by residents that the oil firm was yet to respond to the spill and said that the leak was promptly contained within SPDC’s right of way. Odugbesan in his statement said, “On June 15, a leak was reported at a facility of the Shell Petroleum Development Company of Nigeria Ltd.’s Joint Venture at Opukushi in Ekeremo Local Government Area of Bayelsa. SPDC’s Emergency Response Team was promptly mobilised and it stopped and contained the spill within the SPDC JV right of way. “Spill clean-up is progressing while the Joint Investigation report is being finalised for sign-off by the team comprising representatives of regulatory and relevant government agencies, the community and SPDC.’’ Meanwhile, residents of the host communities have expressed their reservations at the pollution caused by the oil spill and claimed that clean-up was yet to be carried out.

Nigeria loses 21,300 barrels of oil to spill — NOSDRA - Nigeria suffered losses amounting to 21,291.673 barrels of oil, an equivalent of 3,364,084.375 litres, due to spill in 2020, according to the latest data obtained from the National Oil Spill Detection and Response Agency, NOSDRA. This showed a 50 per cent decline, compared to 2019, when 42,076.492 barrels of oil (6,648,085.706 litres) were spilled. NOSDRA, while noting that the spill could be attributed to several factors, explained that the bulk of the spill was caused by sabotage and theft. According to the agency, much of the spill in 2020 was recorded in February, when 6,327 barrels were lost, followed by 4,676 barrels recorded in January, while July took the third position by recording 2,174 barrels. In August, 1,815 barrels of spill were recorded, followed by 1,596 barrels in April, while 1,262 barrels were spilled in June. December, November, October, September, May and March had 846, 572, 401, 321, 235 and 229 barrels of spill, respectively. Interestingly, in 2019, February also recorded the highest spill with 9,148 barrels, followed by June with 6,404 barrels, while January made the third position with 5,559 barrels. November, August, July, October and April had 4,113, 2,620, 1,978, 1,338 and 1,230, barrels, respectively, while September, March, May and December recorded 1,113, 1,015, 993 and 879 barrels, respectively.

Commercial vessel detained following oil spill in Hambantota - A commercial vessel has been detained following an oil spill in Hambantota. The cleanup operation of the minor oil spill at the Hambantota Port has been completed, the port authorities said. The minor oil spill occurred during bunkering at the Hambantota International Port (HIP). The oil has been successfully cleaned up by the Emergency Response Unit of the port. The oil spill occurred at approximately 6 pm on Sunday, 11th of July 2021 whilst a bunkering barge was refueling a commercial vessel that had called at the port. “Minimal chemicals were utilized in the cleaning operation, keeping the environment in mind by using ecofriendly means- including manual oil retrieval was carried out. This method took more time but it’s a more effective and thorough way of cleaning up smaller oil spills,” says Ravi Jayawickreme, CEO of Hambantota International Port Services. Meanwhile, the commercial vessel has been detained until costs incurred are accepted and settled by its owners.

Hydraulic oil spills in Melaka Straits after bulk carrier collides with containership | Hellenic Shipping News - The Panamax bulk carrier Galapagos has spilled hydraulic oil in the Melaka Straits after colliding with the 15,000 Teu mega container ship Zephyr Lumos over the weekend, Malaysia’s maritime authority said July 12. “A team each is onboard the two ships and investigating the matter and, based on the information, there was a thin sheen of oil spill from the hydraulic crane on the Galapagos,” a senior executive at Malaysia’s Marine Department told S&P Global Platts. There has been no spill of bunker fuel, and the hydraulic oil leakage that was within a 50- to 100-meter radius of the ship has mostly evaporated, the executive added. Preliminary investigations show that the 2010-built and Malta-flagged Galapagos experienced a steering gear failure and suddenly turned swiftly after losing control, the senior executive said. The marine gasoil or MGO in the Galapagos has been transferred to another tank space, the marine department said in a statement. The part of the ship that is open as a result of the breach does not store MGO and the oil spilled into the sea is hydraulic oil, the department added. The collision resulted in both ships being dragged together for a short distance before coming to a halt, it said. The Malaysian executive said that the 2021-built, Zodiac Maritime’s UK-flagged Zephyr Lumos was overtaking the Galapagos and, after the Panamax bulk carrier lost control, the container ship hit it on the starboard side from behind. The Zephyr Lumos was asked to anchor outside the traffic separation scheme or TSS in the straits; its destination is Suez from Singapore. The Galapagos is anchored near the collision site; it had been en route to India’s Vizag port. The Straits of Melaka is one of the world’s busiest waterways, with a ship moving through every few minutes and daily cargo movement worth billions of dollars.

Oil Spill After Containership and Bulk Carrier Collide in Strait of Malacca - A containership and a bulk carrier collided early Sunday in the Strait of Malacca, causing major damage and resulting in an oil spill. The Malaysian Coast guard reports that the containership MV Zephyr Lumos and bulk carrier MV Galapagos collided at 14.1 nautical miles southwest of Kuala Sungai just after midnight. The agency said the Galapagos reportedly suffered a rudder failure that resulted in the ship crossing in from of the Zephyr Lumos. Photos published by the Coast Guard show an oil spill from the breached hull of the Galapagos. Zephyr Lumos is a new 2021-built containership registered in the United Kingdom. It measures 366-meters-long and 15,000 TEU capacity. AIS ship tracking shows it is underway from Singapore to the Suez Canal. MV Galapagos, registered in Malta, measures 225-meters-long and is 76,000 DWT. It was built in 2010. AIS shows it is sailing from Gladstone, Australia to Visakhapatnam, India. The cause of the accident is under investigation. Some photos published by the Malaysian Coast Guard are below:

OPEC+ deadlock is bad news for oil producers, consumers and energy transitions, IEA warns— The International Energy Agency on Tuesday warned that world oil markets are likely to remain volatile following a breakdown in talks between OPEC members and their non-OPEC allies, creating a no-win situation. In its latest monthly oil market report, the IEA said energy market participants were closely monitoring the prospect of a deepening supply deficit if a deal was not reached by the Organization of the Petroleum Exporting Countries and its oil-producing allies, a group known as OPEC+. "Oil markets are likely to remain volatile until there is clarity on OPEC+ production policy. And volatility does not help ensure orderly and secure energy transitions — nor is it in the interest of either producers or consumers," the IEA said. OPEC+ abandoned talks last week that would have boosted oil supply. Most delegates tentatively agreed to increase oil production by around 400,000 barrels per day in monthly installments from August until the remaining supply cuts were unwound. This was likely to extend supply cuts through to the end of 2022. The UAE rejected these plans, however, insisting on a higher baseline from which cuts are calculated to better reflect its increased capacity. It means no agreement has been reached on a possible increase in crude production beyond the end of July, leaving oil markets in a state of limbo just as global fuel demand recovers from the ongoing coronavirus crisis. OPEC+, which is dominated by Middle East crude producers, agreed to implement massive crude production cuts last year in an effort to support oil prices when the coronavirus pandemic coincided with a historic fuel demand shock. The energy alliance has since met monthly to try to decide on the next phase of production policy. OPEC+ has not made progress in resolving the dispute between OPEC kingpin Saudi Arabia and the UAE, Reuters reported on Tuesday, citing unnamed OPEC+ sources. It makes the prospect of another policy meeting this week less likely. The IEA said it expects global oil demand to rise by 5.4 million barrels per day this year and by a further 3 million barrels in 2022, largely unchanged from last month's forecast. Meanwhile, the "remote" possibility of a market share battle between producers is hanging over energy markets, the IEA said, warning that higher fuel prices and rising inflation could damage a fragile economic recovery. The uncertainty over the potential global impact of the highly transmissible Covid-19 delta variant was also likely to temper market sentiment in the coming months, the group said.

Oil prices slip as economic worries offset tightening supplies - Crude futures slipped on Monday as concerns over slowing global growth outweighed the prospect of tightening supply after talks among key producers to raise output in coming months stalled. Brent crude for September fell 0.52% to settle at $75.16 per barrel while U.S. West Texas Intermediate crude for August settled at $74.10 a barrel, for a loss of 0.62%. Both benchmarks fell around 1% last week but still hover near highs last reached in October 2018. The spread of coronavirus variants and unequal access to vaccines threaten the global economic recovery, finance chiefs of the G20 large economies warned on Saturday. A Reuters tally of new COVID-19 infections shows them rising in 69 countries, with the daily rate pointing upwards since late-June and now hitting 478,000. "The market has been a bit negative as of late amid the growing sense that the latest OPEC+ impasse could be a precursor to a pump-and-grab scenario, meaning a lot more oil potentially gets put on the market," said Stephen Brennock of oil broker PVM. Oil prices slumped last Tuesday after the Organization of the Petroleum Exporting Countries and their allies, a group known as OPEC+, did not reach an agreement to increase output from August. This was because the United Arab Emirates rejected a proposed eight-month extension to OPEC+ output curbs. The world's top oil exporter Saudi Arabia met full contractual demand for crude oil from five buyers in August, but turned down at least two requests for additional volumes. Front-month WTI crude futures posted their sixth weekly gain last week after a bullish report from the U.S. Energy Information Administration showed U.S. crude and gasoline stocks fell while gasoline demand reached its highest since 2019. In response to higher oil prices, U.S. energy firms added oil and natural gas rigs for a second week in a row, data from Baker Hughes showed.

Oil Prices Settle Lower in Early Week Trading - -- Oil dipped as traders grappled with the demand implications of a Covid-19 resurgence in several regions and slowing economic growth in China. Futures in New York fell 0.6% on Monday. New mobility restrictions have been introduced in parts of Japan, South Korea and Vietnam to curb the spread of the delta variant, clouding the demand outlook for oil. Confirmed Covid-19 cases in the U.S. soared 47% in the week ending Sunday, the largest weekly rise since April 2020. Meanwhile, China’s economic rebound is reported to have slowed. A stronger U.S. dollar also weighed on prices, making commodities priced in the currency less attractive. “As the Covid-19 variant continues to hit Asia hard, which is really the key swing demand center, that’s a big, big negative for the complex,” Rebounding fuel consumption in economies such as the U.S. and China has boosted oil prices this year amid tight global supplies. Now, the spread of the delta variant is threatening the demand recovery, while OPEC+ remains in a stalemate over near-term production. China’s growth eased in the second quarter to 8% from the record gain of 18.3% in the first quarter, according to a Bloomberg poll of economists. Retail sales and industrial production are expected to moderate, too. The delta variant continues to spread around the world. In Europe, officials in the U.K. and France are issuing warnings about new cases and reopenings. Anthony Fauci, the top U.S. infectious disease specialist, said “ideological rigidity” is preventing people from getting Covid-19 shots and voiced frustration at the struggle to boost vaccination rates in parts of the country. West Texas Intermediate for August delivery lost 46 cents to settle at $74.10 a barrel on the New York Mercantile Exchange. Brent for September settlement slid 39 cents to end the session at $75.16 a barrel on the ICE Futures Europe exchange. On the supply side, OPEC and its allies have been unable to agree on an output increase, creating swings in the market and pushing crude to its first weekly loss since May last week. The OPEC+ alliance abandoned meetings last week after a dispute between members over production cuts, and one week later, no deal is in sight.

Oil Rises Nearly 2% As Investors Size Up Tight Market - Oil prices gained almost 2 percent on Tuesday after the International Energy Agency said the market should expect tighter supply for now due to disagreements among major producers over how much additional crude to ship worldwide. The market has been generally stronger as demand has rebounded and the Organization of the Petroleum Exporting Countries and their allies have held millions of barrels of supply from the market. OPEC+, as the group is known, was expected to boost supply, but discussions broke off without an agreement. Brent crude rose $1.33, or 1.8 percent, to settle at $76.49 a barrel, while US West Texas Intermediate crude rose $1.15, or 1.6 percent, to settle at $75.25 a barrel. The Paris-based IEA said global storage drawdowns in the third quarter were set to be the biggest in at least a decade, citing early June stock draws from the United States, Europe and Japan. “You’re still not going to have enough crude oil on the market to avoid a supply deficit by the end of the year. That was definitely a tailwind for the market,” said Bob Yawger, director of energy futures at Mizuho. Oil prices will be volatile, the IEA said, until differences are resolved among members of OPEC+. The group has been unwinding record output curbs agreed last year to cope with the pandemic. But a dispute over policy between Saudi Arabia and the United Arab Emirates put plans to pump more oil on hold. Nuclear talks between world powers and Iran are not likely to resume until after the Islamic Republic installs its new president next month, restricting another potential source of supply. Industry data on US stockpiles on Tuesday showed that oil and gasoline inventories fell last week, according to two market sources, citing American Petroleum Institute figures. Crude stocks fell by 4.1 million barrels for the week ended July 9, the sources said, which would be their eighth consecutive weekly decline. US government data is expected on Wednesday. Still, coronavirus infections are surging in some parts of the world, which could sap demand if outbreaks become more pronounced. The World Health Organization warned the Delta COVID-19 variant was becoming dominant and many countries had yet to receive enough doses of vaccine to secure their health workers.

WTI Slides From 33-Month Highs After Inventory Data - Despite ongoing uncertainty over US-Iran talks (supply increase), Delta variant fears (demand concerns) and Saudi-UAE (OPEC+) malarkey (cartel breakup fears), oil prices managed gains on the day (to 33-month highs) as IEA said global storage drawdowns in the third quarter were set to be the biggest in at least a decade, citing early June stock draws from the United States, Europe and Japan. "You're still not going to have enough crude oil on the market to avoid a supply deficit by the end of the year. That was definitely a tailwind for the market," said Bob Yawger, director of energy futures at Mizuho. Will inventory data provide support for today's rebound? API:

  • Crude -4.079mm (-4.4mm exp)
  • Cushing -1.585mm
  • Gasoline -1.545mm
  • Distillates +3.699mm

Analysts expected an 8th straight week of drawdowns in crude stocks but the draw was smaller than expected and less than the prior week. Gasoline stocks also dropped again but far less than last week. Distillates stocks unexpectedly rose...

OPEC reportedly reaches compromise on oil production after dispute with UAE - The Organization of Petroleum Exporting Countries on Wednesday arrived at a deal after a nearly two-week standoff over its future oil production levels, according to reports by the Wall Street Journal and Reuters. The temporary but unprecedented gridlock that began in early July saw the United Arab Emirates reject a coordinated oil production plan for the group spearheaded by its kingpin, Saudi Arabia.Abu Dhabi had demanded that its own “baseline” for crude production — the maximum volume it’s recognized by OPEC as being able to produce — be raised because this figure then determines the size of production cuts and quotas it must follow as per the group’s output agreements. Members cut the same percentage from their baseline, so having a higher baseline would allow the UAE a greater production quota.The UAE initially called for its baseline to be raised from 3.2 million barrels a day to 3.8 million barrels a day. According to sources cited by the Wall Street Journal, the compromise reached between Saudi Arabia and its smaller neighbor will raise the UAE’s baseline to 3.65 million barrels per day from April 2022. The reports have not been officially confirmed, and OPEC and the Saudi energy ministry did not reply to CNBC requests for comment.The initial agreement supported by most OPEC delegates set out a plan for the group to collectively bring production up to 400,000 barrels of crude per day monthly through to the end of 2022. This would end the remaining limits that were set in the spring of 2020, as economic recovery and growing demand for oil have brought crude prices up to their highest level since late 2018.

UAE Denies Reports That OPEC+ Deal Has Been Reached, Oil Slides - Oil algos are unsure what to make of the latest headlines for now as Bloomberg reports that UAE has resolved its standoff with OPEC and agreed on a new higher baseline production level of 3.65m b/d (versus the UAE's prior 3.16m b/d output level). Additionally, the OPEC+ deal is to be extended until the end of 2022 (vs the original April 2022), according to a source. Reminder, OPEC+ talks were postponed early July after the UAE dissented on OPEC's August proposal, prompting some concerns over the future of OPEC, especially as reports were doing the rounds that the UAE was mulling a unilateral increase in production.. WTI tested up to to $75 and tumbled down to $74 on the headline, then rebounded rapidly back up to test $75 again... Update (1000ET): Not so fast! Reuters is reporting that the UAE Energy Minister has confirmed that no agreement has been reached yet with OPEC+ and that deliberations continue. And that headline removed all the earlier gains from oil prices...

WTI Extends Losses After (Delayed) Inventory Data - After tagging 33-month highs yesterday, oil prices have been chaotic overnight as API inventory data mixed with reports and denials from UAE/OPEC+ over a deal have left WTI lower so far. However, even if a deal is done, timing will remain an issue.“Even if OPEC decides to raise output in August, that crude will not reach refineries until after the August peak-demand period will be over,” Ed Morse, head of commodities research at Citigroup Inc., said in an email.The next $1 one way or the other may be driven by the official inventory data, as industry watchers would consider API’s report of a nearly 5m bbl build in diesel bearish, if the U.S. government confirms it. DOE

  • Crude -7.897mm (-4.4mm exp)
  • Cushing +1.04mm
  • Gasoline -2.489mm
  • Distillates +3.657mm

Expectations for an 8th straight week of crude draws were met with a bigger than expected 7.897mm drop in stocks. US gasoline demand is back at its highest since Oct 2019 and back above its 5y average for this time of year (and last week we saw seasonal demand for petroleum products reach a high in data going back three decades)...

Oil Prices Falter with USA Fuel Build - -- Oil’s rally fizzled as a build in U.S. fuel inventories and a potential OPEC+ agreement to increase supply cooled a buying spree that had pushed the market above $75. Futures in New York fell 2.8%, the most since May. Both gasoline and distillate inventories rose last week, according to a U.S. government report. Meanwhile, Saudi Arabia and the United Arab Emirates were said to resolve the standoff that has prevented OPEC+ from satisfying growing demand for extra barrels. Technical indicators also showed crude close to overbought territory earlier Wednesday, which signals oil may be due for a pullback. With the prospect of more supply from OPEC+ and crude nearing overbought levels, “it’s not surprising to see it down,” said Tariq Zahir, managing member of the global macro program at Tyche Capital Advisors LLC. Economic recovery in countries like the U.S. and China has increased fuel consumption over the course of this year, propelling oil prices forward by more than 50%. Rising demand, especially during the peak summer travel season in the U.S., drew warnings about a deepening supply deficit after OPEC+ talks on a production hike broke down earlier this month. The latest breakthrough proposal involves a higher output quota for the UAE, which said OPEC+ talks are ongoing. It would need to be approved by all OPEC+ members before it can take effect. If the compromise is ratified at a new meeting, it could open the way to higher output, although some members have already locked in most of their supply volumes for August. The 23-nation coalition is aiming to restore supplies in installments of 400,000 barrels a day through to late 2022. The impasse introduced volatility in the market over the last week while near-term supply remained in question. In addition to gasoline, a boom in durable goods is driving demand for naphtha to make plastics as well as diesel to power deliveries. Domestic crude supplies tumbled for the eighth straight week, according to the weekly report. Inventories at the nation’s largest storage hub in Cushing, Oklahoma, fell by 1.6 million barrels.

Oil slides 2% on oversupply fears after OPEC wrangles an agreement - Oil prices dropped more than 2% Wednesday after major global oil producers came to a compromise about supply and after U.S. data showed demand slacked off a bit in the most recent week. Crude prices have surged to highs not seen in nearly three years, but have been choppy lately on worries about a pickup in supply. Brent crude settled down $1.73 a barrel, or 2.26%, at $74.76 a barrel. West Texas Intermediate was off by $2.12, or 2.82%, at $73.13 a barrel. Brent crude’s premium to West Texas Intermediate futures widened to the most since July 6, according to Refinitiv Eikon data. The U.S. benchmark fell more precipitously due to demand concerns. Oil initially dropped after Reuters reported Saudi Arabia and the United Arab Emirates reached a compromise that should unlock an OPEC+ deal to boost global oil supplies as the world recovers from the coronavirus pandemic. The benchmarks fell more after U.S. government data showed implied gasoline demand declining considerably last week. While the U.S. Energy Information Administration said crude stockpiles declined more than expected, in their eighth consecutive draw, the drawdown was overshadowed by lagging gasoline demand. “The significant decline in gasoline and diesel demand has pressured prices, even though crude oil inventories have continued to draw,” U.S. fuel stocks were higher, even as refinery runs eased. Gasoline stocks rose by 1 million barrels, compared with expectations for a 1.8 million-barrel drop. The Organization of the Petroleum Exporting Countries and its allies including Russia, known as OPEC+, had been at loggerheads over increasing supply due to demands from the United Arab Emirates that its contribution to supply cuts be calculated from a higher production level. The agreement should now pave the way for OPEC+ members to extend a deal to curb output until the end of 2022, the sources added, although the UAE energy ministry said in a statement that no deal with OPEC+ on its baseline has been reached and deliberations were continuing. Also adding to a potential supply glut is crude from Iran, . For the market balance, two critical are the timing of a deal between Iran and Western powers, which could lead to increased oil exports, and supply coming from the U.S..

Goldman Sees Oil Price Spiking On UAE/OPEC+ Deal -Oil suffered its biggest drop in 2.5 months today after the EIA reported that in the latest week, gasoline demand in the US unexpectedly tumbled by 760,000 barrels a day from the record 10 million barrels a day a week, to 9.28 million barrels a day to get back to levels in late June. While algos focused on the sharp drop, what they ignored was that the number was largely meaningless, since the reporting week included July 5, a day off for Americans. Additionally, the EIA’s estimate, known as product supplied, is derived from other data rather than being a direct measurement of consumption. Since that method often leads to erratic numbers, some observers prefer to use the 4-week rolling average. That measure was 9.485 million barrels a day, which was about equal to the same week in 2019 None of that mattered, however, as CTAs quickly joined in the selling frenzy and completely erasing the earlier jump on the far more important news of an OPEC+ deal. Just how important was the Reuters report that the UAE and Saudi Arabia are close to reaching a production agreement, one which sees both the higher baseline requested by the UAE (of 3.65 mb/d starting in April 2022) as well as an extension of the output agreement requested by Saudi (through December 2022). Important enough that in a note released late on Wednesday, Goldman said that the deal would remove the low-probability tail risks of potential price war, and "represents $2 to $4/bbl upside risk to our $80/bbl summer and $75/bbl 2022 Brent price forecasts." In the note from Goldman commodity analysts Damien Courvalin and Jeff Currie, the two also write that the expected agreement “as the first of likely four potential bullish supply catalysts over the coming month” that would more than offset higher North American production. Additionally, although some OPEC+ details remain uncertain, like August and September quotas or baselines of other countries, “these are of limited magnitude and importance to the global oil market outlook, which the bank continues to see as supportive of higher oil prices” Piling on the bullish cash, Courvalin writes that an OPEC+ deal that offers a higher baseline for the UAE, as well as an extension of output agreement through December 2022 - such as the one being contemplated - would be bullish relative to Goldman’s base case.

Oil Prices Fall Amid Stronger Greenback and OPEC+ Uncertainty --- Oil slid to a four-week low Thursday as the dollar strengthened and on OPEC+’s signal it may raise output soon. Futures in New York slid 2% on Thursday with a rising U.S. dollar reducing the appeal of commodities priced in the currency. Traders are watching to see whether the OPEC+ alliance sets a date to formalize a deal to hike production after delegates said Wednesday the United Arab Emirates made significant progress in resolving its standoff with Saudi Arabia. In the U.S., an inventory report this week showing expanding fuel supplies and crude production also weighed on prices. “The market is still continuing to assess the fundamentals like what the OPEC+ deal is going to mean,” It “looks like the group is coming to an agreement, but there is lots of uncertainty over how it will be executed.” Crude has rallied nearly 50% this year as economies across the globe reopen and demand returns. Citigroup Inc. said the oil market is expected to be tight in the near-term and should push Brent prices into the mid-$80s, despite any compromise supply deal between the UAE and OPEC+. The Organization of Petroleum Exporting Countries published its first detailed assessment of 2022, in which it forecast that global oil demand will steadily recover to surpass pre-pandemic levels in the second half of next year. However, it also pointed to a lull in the first quarter. West Texas Intermediate for August declined $1.48 to settle at $71.65 a barrel on the New York Mercantile Exchange. The prompt spread ended the session at 27 cents a barrel, the narrowest in four weeks. Brent for September settled $1.29 lower at $73.47 on the ICE Futures Europe exchange. WTI’s prompt timespread weakened to its narrowest level since mid-June with U.S. government data shows domestic crude production is rising. The spread’s backwardation -- indicating tighter supplies -- is fading with output currently at the highest since May 2020. There are also demand concerns with rising Covid-19 cases in Europe and Asia that may lower consumption expectations in the second half of this year.. Meanwhile, Saudi Arabia and the UAE appear to be closing in on an agreement to revise Abu Dhabi’s production quota, it would still need to be ratified by the whole group before they can salvage plans to revive halted supply. Goldman Sachs Group Inc. said an accord would be a “bullish catalyst,” and would help remove the low risk of a potential price war. The two sides haven’t fully resolved their differences and talks are ongoing. There are signs other members of the alliance have been inspired to air their own grievances, with Iraq now seeking a higher baseline for its cuts too.

Oil slumps on OPEC compromise expectations, COVID variant concerns Oil futures fell Thursday, extending a slump that began in the previous session after data showed a rise in U.S. fuel supplies and after reports said the United Arab Emirates and Saudi Arabia reached a compromise that would allow a further relaxation of output curbs beginning next month.Concerns that the spread of the delta coronavirus variant have also contributed to weakness in oil prices as the variant is leading to renewed lockdowns in some countries, particularly in Asia, dulling demand for energy."We do feel the Delta variant is the biggest factor as Asia is having a real issue and Europe is problematic," Tariq Zahir, managing member at Tyche Capital Advisors, told MarketWatch. COVID cases are on the rise in the U.S. again also and this "could hamper oil demand in the days and weeks to come in parts of the country [where] vaccination levels are low," he said. West Texas Intermediate crude for August delivery fell 89 cents, or 1.2%, to $72.24 a barrel on the New York Mercantile Exchange. September Brent crude , the global benchmark, was off 82 cents, or 1.1%, at $73.94 a barrel on ICE Futures Europe.Crude fell sharply Wednesday after reports (link) said the U.A.E. and Saudi Arabia had reached a compromise in their dispute over output cuts. The U.A.E., however, has said no deal has been reached with OPEC+ producers and that talks are ongoing and would need the support of other OPEC countries, according to various news reports (link).A meeting of OPEC and its allies -- known as OPEC+ -- ended earlier this month without an agreement on a proposed easing of output curbs after the U.A.E. insisted it should be allowed to raise the baseline dictating its output, putting it at odds with Saudi Arabia."It is also unclear whether the UAE's higher oil production would be set off against the planned increase in OPEC+ production, which would mean the other countries could raise their output by less, which they would hardly be willing to accept," said Carsten Fritsch, commodity analyst at Commerzbank, in a note."If not, the UAE's increased output would be on top of the intended increase in OPEC+ production, which could ultimately lead to too much oil on the market," he said.Traders will be watching to see if OPEC+ calls a meeting to ratify the reported compromise, said Robert Yawger, executive director of energy futures at Mizuho Securities."All OPEC+ members will need to agree on the increase for it to become official OPEC+ policy. No meeting [means] no agreement," he said.Weekly data from the U.S. Energy Information Administration released Wednesday (link) revealed that domestic crude supplies fell for an eighth week in a row, but implied demand for motor gasoline declined, leading to an increase in supplies of the fuel.In Thursday dealings, August gasoline fell by nearly 1.3% to $2.26 a gallon and August heating oil declined by 1.2% to $2.12 a gallon.Meanwhile, OPEC on Thursday forecast world oil demand to grow by 6 million barrels a day (link) in 2021, unchanged from its June projection, with total demand expected to average 96.6 million barrels a day.

Oil Futures Flat Amid OPEC+ Deal Chatter, Mixed Economic Data - Fading from intra-session highs, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange settled Friday's session little changed as mixed economic data in the United States pointed to accelerated inflation amid surging consumer spending. Renewed strength in the U.S. Dollar Index and risk-off sentiment across equity markets triggered additional pressure on the oil complex. U.S. retail sales -- a measure of purchases at stores, restaurants and online -- gained 0.6% in June, beating market expectations for a modest decrease compared to the previous month, the U.S. Census Bureau reported Friday morning. Last month's surge in consumer spending would have been stronger if it excluded auto sales, which fell 2% from the previous month amid ongoing shortages of the key materials. High retail spending coincides with a faster-than-expected increase in consumer prices, which jumped 5.4% in June from a year earlier following a 5% increase in the prior month. There are growing signs that faster inflation has begun to take a toll on consumer sentiment in July, with University of Michigan's gauge on year-ahead inflation expectations rising to the highest since 2008. Preliminary reading on consumer sentiment, meanwhile, dropped to the lowest since February at 80.8, compared with expectations for a monthly gain to 87.6."Inflation has put added pressure on living standards, especially on lower- and middle-income households, and caused postponement of large discretionary purchases, especially among upper income households," Richard Curtin, director of the survey, said in a statement.U.S. Federal Reserve Chairman Jerome Powell said during his testimony to the Senate Banking Committee on Thursday that inflation has risen to uncomfortably high levels but maintained that rising costs are transitory and tied to the economy's reopening. U.S. Treasury Secretary Janet Yellen warned of several more months of rapid inflation before price pressures finally ease. U.S. equities declined and the dollar index gained modestly against the basket of foreign currencies, pressuring the front-month West Texas Intermediate futures into market-on-close trade. On the session, the NYMEX August WTI contract settled at $71.81 barrel (bbl), up 16 cents from the Thursday's close, and the international crude benchmark Brent for September delivery added 0.12 cents for a $73.59 bbl settlement. Both crude benchmarks declined more than 2.5% on week. NYMEX August ULSD futures settled little changed at $2.1133 gallon, and the front-month NYMEX RBOB contact gained 0.33 cents to $2.2536 gallon.

Oil Has Worst Week in Months; UAE’s OPEC Deal Could Open ‘Can of Worms’ - New York-traded West Texas Intermediate crude, the benchmark for U.S. oil, settled up 35 cents, or 0.5%, at $72 per barrel. For the week though, WTI lost $2.56, or 3.4%. It was the largest weekly loss for U.S. crude since the week ended April 2. London-traded Brent, the global benchmark for oil, rose 12 cents, or 0.2%, to finish the session at $75.55. For the week, Brent lost $1.96, or 2.6%, for its sharpest weekly decline since the week to May 14. OPEC+ - which groups the 13 member Saudi-led Organization of the Petroleum Exporting Countries with 10 other oil producers led by Russia - had initially failed to agree on August production levels after the UAE sought a higher baseline for measuring its output cuts. News reports from the past couple of days, however, suggested that Saudi Arabia and the UAE have reached a compromise, paving the way for OPEC+ producers to end an uncertainty that had bogged down the market and prices for weeks. “All signs indicate that OPEC+ is heading for a potential compromise agreement that will allow the UAE to secure a baseline adjustment,” RBC Capital analysts said in a note. “Other producers will undoubtedly seek similar treatment and potentially prolong the deliberations heading into the August ministerial meeting.” John Kilduff, founding partner at New York energy hedge fund Again Capital, concurred with that view. “This certainly opens a can of worms where OPEC production is concerned,” said Kilduff. “The Iraqis were already talking about wanting their baseline for production increased too.” “Unless the Saudis can point at the new Covid outbreaks from the Delta variant and say ‘hey, we should all keep our production down in order not to lose what we have gained’, I think oil prices will remain under pressure.” On the Covid front, vaccination rates are down and cases are on the rise, exacerbated by the more transmissible Delta variant -- and an expert said earlier this week that the key to winning the race against the spread is getting more Americans vaccinated. "We're losing time here. The Delta variant is spreading, people are dying, we can't actually just wait for things to get more rational," Dr. Francis Collins, director of the National Institutes of Health, said Wednesday. Vaccines have been available to most Americans for months, but still only 48.2% of the country is fully vaccinated, according to the U.S. Centers for Disease Control and Prevention -- and the rate of new vaccinations is on the decline. Meanwhile, case rates have been going up dramatically. In 47 states, the rate of new cases in the past week are at least 10% higher than the previous week, according to data from Johns Hopkins University. Of those, 35 have seen increases of over 50%.

The Conflict Within OPEC Is Far From Over - As expected, OPEC leaders Saudi Arabia and UAE have reached a so-called solution to the current export quota conflict. For two weeks, the global oil market was shocked by the strong position taken by Abu Dhabi’s power brokers, which demanded higher baseline production quota. OPEC sources now have stated that both countries have reached a compromise on production.Even that the first reactions to the so-called agreement which includes a higher base line production level for the UAE are positive, the deal in reality is nothing more than a band aid. Officials in many oil importing nations are hoping that the agreement will help to cool soaring prices.Reuters reports indicate that Riyadh has agreed to Abu Dhabi’s request to have its baseline production level lifted to 3.65 million barrels per day (bpd) when the current pact expires in April 2022, according to the source. The current baseline for the UAE was around 3.17 million bpd. With this gesture, Riyadh looks to keep the current OPEC+ agreement in place, while giving room to Abu Dhabi in order to claim a potential win-win situation. However, the higher production baseline will only be implemented in April 2022, and is a long way from the requested 3.8 million bpd at present. Knowing both sides, the first reactions will be positive, indicating a renewal of the Riyadh-Abu Dhabi-Moscow tandem, showing the market that OPEC is not heading towards a possible breakdown or implosion. It also shows that analysts that were expecting Abu Dhabi to leave OPEC were too quick to draw conclusions. Still, the unease about production quota may persist in the UAE, and the conflict could flare up again at the next OPEC+ meeting. The high-profile clash between Saudi Crown Prince Mohammed bin Salman and Abu Dhabi Crown Prince Mohammed bin Zayed is not over, instead, it’s just been pushed aside for the moment being. For both parties, a more volatile oil (and gas) market is not the goal, as both pursue a stable situation where prices stay at a level that is acceptable for both producers and consumers.OPEC also wants to continue the overall strong cooperation of the last years, as non-OPEC, especially Russia and FSU countries are starting to become unhappy about production and export levels. Russian companies are for sure willing to up the ante, bringing additional volumes to the market to reap the gains at present. Some other OPEC producers, including Iraq are also unhappy about missing out on higher revenues or market share due to OPEC policies. Battling COVID-19’s economic impact, high unemployment, and the ongoing threat of energy-transition polices in the EU and OECD, a growing amount of countries want accelerate the monetization of their hydrocarbon resources. The UAE-Saudi spat is only a sign on the wall of future problems within the cartel. Whatever analysts were stating, MBS and MBZ are maybe competing on lots of issues, but oil and gas are still a binding factor for decision making and cooperation. Saudi Arabia also knows that Abu Dhabi’s continues to invest in increasing its production capacity, which it aims to boost to around 5 million bpd by 2030.

US Waives Sanctions On Frozen Iranian Oil Funds -The United States has decided to temporarily waive sanctions on Iranian oil funds abroad but without returning Tehran's access to its bank accounts in Japan and South Korea. "Allowing these funds to be used to repay exporters in these jurisdictions will make those entities whole with respect to the goods and services they exported to Iran, address a recurring irritant in important bilateral relationships, and decrease Iran's foreign reserves," the waiver, which the Department of State presented to Congress, said, as quoted by Iran's Mehr news agency.This means the government in Tehran will be unable to withdraw the funds but can use them to pay accounts outstanding to South Korean and Japanese exporters. In fact, the money cannot be transferred to Iran at all, the State Department said."The secretary of state previously signed a waiver to allow funds held in restricted Iranian accounts in Japan and Korea to be used to pay back Japanese and Korean companies that exported non-sanctioned items to Iran," a State Department spokesperson said as quoted by Mehr."These repayment transactions can sometimes be time-consuming, and the secretary extended the waivers for another 90 days."The sanction talks between the U.S. and Iran have stalled lately as the government in Iran changed, with the new president known as a hardliner unlike his predecessor Hassan Rouhani who was hailed as a reformer when he came into power.

Russia Warns Pentagon: Don't Deploy Troops In Central Asia Near Afghanistan Amid the continuing full US troop draw down from Afghanistan, which last week President Biden said would be 'complete' by August 31st, the Pentagon has been debating how to maintain a foothold in Central Asia as it increasingly looks like Kabul will come under Taliban threat within a mere months. Last month in an interview with Axios' Jonathan Swan, Pakistan's prime minister Imran Khan slammed the door shut on allowing the CIA or US special forces to conduct cross-border counterterrorism missions against a resurgent Al-Qaeda, ISIS or the Taliban. Given Washington's scrambling to establish other outposts in countries neighboring Afghanistan,Russia is now warning against such an expanded Central Asian US military presence. On Tuesday Russia's foreign ministry put the US on notice, warning that the possibility of a US "permanent military presence" in countries neighboring Afghanistan is "unacceptable". The comments by Russian Deputy Foreign Minister Sergei Ryabkov further stated: "We told the Americans in a direct and straightforward way that it would change a lot of things not only in our perceptions of what’s going on in that important region, but also in our relations with the United States."Crucially Moscow also warned Central Asian countries, especially its allies, against hosting US troops connected to events in Afghanistan."We cautioned them against such steps, and we also have had a frank talk on the subject with our Central Asian allies, neighbors and friends and also other countries in the region that would be directly affected," Ryabkov said further.


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