oil in longest losing streak since 2019; global oil shortage at 2,540,000 barrels per day; DUC well backlog at 7.1 months

oil prices fell every day this week and ended sharply lower, as previously oblivious oil traders realized that we have a pandemic going on...after inching up 16 cents to $68.44 a barrel last week as concerns about a Covid related slowdown were offset by the Senate passage of the infrastructure spending package, the contract price of US light sweet crude for September delivery retreated early Monday following a trio of weaker-than-expected economic reports from China, after earlier sliding more than 1% in Asian trading on concerns that the restrictive measures in place to curb Covid-19 outbreaks would dampen demand for fuel, but recovered from an intraday low of $65.73 to settle $1.15, or 1.7% lower at $67.29 a barrel after sources told Reuters that OPEC and its allies believe the markets do not need more oil than they already plan to produce in the coming months...after briefly moving higher early Tuesday, oil prices again tracked lower on a combination of concerns over slowing global demand growth stemming from sporadic COVID-19 outbreaks in China and elsewhere in southeast Asia leading to renewed restrictions on mobility and closure or reduced operations at key shipping ports, and signs of decelerating economic growth domestically, and finished down 70 cents, or off ​by ​another 1% at $66.59 a barrel​,​ as traders continued to fret over the outlook for demand due to the ongoing spread of the delta variant of Covid-19...oil prices extended their longest losing streak since March late Tuesday​ ​after the API reported a disappointingly small draw from curde supplies, but then pushed higher early Wednesday, as traders awaited the latest crude oil supply data from the US EIA later in the day...but oil prices turned lower even after that data showed there was a bigger-than-expected drawdown in U.S. crude inventories and finished down $1.13 at $65.46 a barrel, on a rising U.S. dollar, as traders remained worried about the outlook for fuel demand as Covid-19 cases surged worldwide....oil prices then opened more than $1 lower on Thursday after the Fed minutes signalled that it would scale back stimulus measures in the coming months and fell from there as the dollar rallied and as the spread of the Delta variant underlined worries about demand, and were down more than 4% at one point before clawing back to settle $1.70 or 2.7% lower at $63.69 a barrel, the lowest ​closing ​price since May and capping the longest losing streek in 18 months...after a higher opening, the relentless drop in oil prices continued on Friday, as traders sold futures in anticipation of weakened fuel demand worldwide due to a surge in Covid-19 cases, as trading in September crude expired with the contract down $1.37, or 2.2%, at $62.32 a barrel, thus finishing the week 8.9% lower in the midst of the longest losing streak since 2019...

meanwhile, natural gas prices were little changed this week as forecasts fluctuated and inventories rose more than had been expected...after falling 6.7% to a three week low of $3.861 per mmBTU last week as forecasts cooled and gas in storage rose more than had been expected, the contract price of natural gas for September delivery rebounded on Monday as forecasts projected hotter weather than had been previously expected and settled 8.5 cents higher at $3.946 mmBTU...but prices reversed on Tuesday and tumbled 10.9 cents to $3.837 per mmBTU, pressured by weaker power burns amid mostly comfortable temperatures in the ​populated ​eastern half of the country....natural gas prices recovered 1.5 cents to settle at $3.852 per mmBTU on Wednesday, boosted by a recovery in exports to Mexico, after trading in a narrow range as traders awaited Thursday's storage data,..prices fell sharply on Thursday following the report of a weekly inventory build that overshot the major surveys, but recovered most of the day's early losses to finish just 2.2 cents lower at $3.830 per mmBTU...September gas prices rebounded on Friday as the weather outlook turned slightly warmer, potentially boosting air conditioning demand, and settled 2.1 cents higher at $3.851 per mmBTU, but still finished the week a penny lower than the prior week's close..

the natural gas storage report from the EIA for the week ending August 13th indicated that the amount of working natural gas held in underground storage in the US rose by 46 billion cubic feet to 2,822 billion cubic feet by the end of the week, which still left our gas supplies 547 billion cubic feet, or 16.2% below the 3,369 billion cubic feet that were in storage on August 13th of last year, and 174 billion cubic feet, or 5.8% below the five-year average of 2,996 billion cubic feet of natural gas that have been in storage as of the 13th of August in recent years...the 46 billion cubic foot increase in US natural gas in working storage this week, which included a reclassification of 4 billion cubic feet of base gas to working gas, was more than the median forecast for a 35 billion cubic foot addition from a S&P Global Platts survey of analysts, and more than the average addition of 42 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​ was​ close to the 45 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 August 13th indicated that after another sizable increase in our oil exports, we needed to withdraw more oil from our stored commercial crude supplies for the eleventh time in thirteen weeks, and for the 27th time in the past thirty-nine weeks….our imports of crude oil fell by an average of 46,000 barrels per day to an average of 6,350,000 barrels per day, after falling by an average of 36,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 768,000 barrels per day to an average of 3,431,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,919,000 barrels of per day during the week ending August 13th, 813,000 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 reportedly increased by 100,000 barrels per day to 11,400,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to total an average of 14,319,000 barrels per day during this reporting week…

meanwhile, US oil refineries reported they were processing 16,006,000 barrels of crude per day during the week ending August 13th, 191,000 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 average of 462,000 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 1,225,000 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 (+1,225,000) 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…but 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 reasonably accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,421,000 barrels per day last week, which was still 14.1% more than the 5,627,000 barrel per day average that we were importing over the same four-week period last year…the 462,000 barrel per day net increase in our crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged….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 EIA"s 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 a 33,000 barrel per day increase in Alaska’s oil production to 428,000 barrels per day had no impact on the rounded national production 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 pre-pandemic 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 92.2% of their capacity while using those 16,006,000 barrels of crude per day during the week ending August 13th, up from 91.8% of capacity the prior week, but still somewhat below normal utilization for summertime operations…while the 16,006,000 barrels per day of oil that were refined this week were 10.5% more barrels than the 14,487,000 barrels of crude that were being processed daily during the pandemic impacted week ending August 14th of last year, they were still 9.6% below the 17,702,000 barrels of crude that were being processed daily during the week ending August 16th, 2019, when US refineries were operating at what was then a normal 95.9% of capacity…

even with this week’s decrease in the amount of oil being refined, the gasoline output from our refineries was a bit higher, increasing by 39,000 barrels per day to 10,000,000 barrels per day during the week ending August 13th, after our gasoline output had decreased by 190,000 barrels per day over the prior week.…this week’s gasoline production was 6.4% higher than the 9,400,000 barrels of gasoline that were being produced daily over the same week of last year, and it was also 1.0% higher than the gasoline production of 9,897,000 barrels per day during the week ending August 16th, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 37,000 barrels per day to 4,848,000 barrels per day, after our distillates output had increased by 8,000 barrels per day over the prior week…even after that decrease, this week’s distillates output was 2.2% more than the 4,742,000 barrels of distillates that were being produced daily during the week ending August 14th, 2020, but 9.2% below the 5,340,000 barrels of distillates that were being produced daily during the week ending August 16th, 2019..

with the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the twelfth time in twenty weeks, and for the 26th time in forty weeks, rising by 696,000 to 228,165,000 barrels during the week ending August 13th, after our gasoline inventories had decreased by 8,945,000 barrels over the prior 3 weeks...our gasoline supplies managed to increase this week because the amount of gasoline supplied to US users decreased by 97,000 barrels per day to 9,333,000 barrels per day, even as our imports of gasoline fell by 182,000 barrels per day to 743,000 barrels per day while our exports of gasoline fell by 95,000 barrels per day to 651,000 barrels per day…even after this week’s inventory increase, our gasoline supplies were 6.4% lower than last August 14th's gasoline inventories of 243,762,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…

meanwhile, with the modest decrease in our distillates production, our supplies of distillate fuels also decreased for the twelfth time in nineteen weeks and for the 16th time in 35 weeks, falling by 2,697,000 barrels to 137,814,000 barrels during the week ending August 13th, after our distillates supplies had increased by 1,767,000 barrels during the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 589,000 barrels per day to 4,323,000 barrels per day, while our exports of distillates fell by 32,000 barrels per day to 1,052,000 barrels per day and our imports of distillates fell by 43,000 barrels per day to 142,000 barrels per day…after twelve inventory decreases over the past nineteen weeks, our distillate supplies at the end of the week were 22.5% below the 177,807,000 barrels of distillates that we had in storage on August 14th, 2020, and about 8% below the five year average of distillates stocks for this time of the year…

finally, with the big increase in our oil exports, our commercial supplies of crude oil in storage fell for the 16th time in the past twenty-six weeks and for the 35th time in the past year, decreasing by 3,233,000 barrels over the week, from 438,777,000 barrels on August 6th to  435,544,000 barrels on August 13th, after our commercial crude supplies had decreased by 448,000 barrels the prior week…after this week’s decrease, our commercial crude oil inventories were about 6% below the most recent five-year average of crude oil supplies for this time of year, but were still around 29% above the average of our crude oil stocks after the second week of August over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated thereafter, our commercial crude oil supplies as of this August 13th were still 15.0% less than the 512,452,000 barrels of oil we had in commercial storage on August 14th of 2020, and 0.5% less than the 437,778,000 barrels of oil that we had in storage on August 16th of 2019, but still 6.7% more than the 408,358,000 barrels of oil we had in commercial storage on August 17th of 2018… 

OPEC's Monthly Oil Market Report

Thursday of last week saw the release of OPEC's August Oil Market Report, which covers OPEC & global oil data for July, and hence it gives us a picture of the global oil supply & demand situation for the third 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 reset they've made over the past year, all in response to the pandemic-related slowdown and subsequent recovery...but before we start in, 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...

As we can see on the bottom line of the above table, OPEC's oil output increased by 637,000 barrels per day to 26,657,000 barrels per day during July, up from their revised June production total of 26,020,000 barrels per day...however, that June output figure was originally reported as 26,034,000 barrels per day,  which therefore means that OPEC's June production was revised 14,000 barrels per day lower with this report, and hence OPEC's July production was, in effect, a 623,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official June 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 497,000 barrels per day from the Saudis was the major factor in OPEC's July 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 unwinding that voluntary output decrease, having previously increased their production by 345,000 barrrel per day in May and by 425,000 barrels per day in June... 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 of last year, but that agreement had been extended to include July 2020 at a meeting between OPEC and other producers on June 6th, 2020....then, in a subsequent meeting in July of last year, OPEC and the other oil producers agreed to ease their deep supply cuts by 2 million barrels per day to 7.7 million barrels per day for August 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 July'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...

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 that they 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 July was lowered to 3,650,000 barrels per day from the baseline with the latest agreement...note that war torn Libya, and US sanctioned producers Iran and Venezuela, are exempt from the production cuts that the cartel imposes on its other members, and hence the 22,495,000 barrel per day production of the other ten members in July remained below the 23,033,000 barrel per day quota for July they 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 August 2019 to July 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....

Including this month's reported 637,000 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 970,000 barrels per day to average 95.69 million barrels per day in July, a reported increase which apparently came after June's total global output figure was revised up by 230,000 barrels per day from the 94.49 million barrels per day of global oil output that was estimated for June a month ago, as non-OPEC oil production rose by a rounded 330,000 barrels per day in July after that revision, with with increases in the oil output from the OECD countries accounting for most of the non-OPEC production increase in July...

After that increase in July's global output, the 95.69 million barrels of oil per day that were produced globally during the month were 6.94 million barrels per day, or 7.8% more than the revised 88.75 million barrels of oil per day that were being produced globally in July a year ago, which was third month of the OPEC + agreement to cut global output by 9.7 million barrels per day (see the August 2020 OPEC report (online pdf) for the originally reported July 2020 details)...with this month's increase in OPEC's output, their July oil production of 26,657,000 barrels per day was at 27.9% of what was produced globally during the month, an increase of 0.4% from their revised 27.5% share of the global total in June....OPEC's July 2020 production was reported at 23,172,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 3,485,000 barrels per day, or 15.0% more barrels per day of oil this July than what they produced a year earlier, when they accounted for 26.1% of global output...

However, even after the sizable increases in OPEC's and global oil output that we've seen in this report, the amount of oil being produced globally during the month fell far short of the expected global demand, as this next table from the OPEC report will show us..

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 fourth column, we've circled in blue the figure that's relevant for July, which is their estimate of global oil demand during the third quarter of 2021... OPEC is estimating that during the ​3rd quarter of this year, all oil consuming regions of the globe will be using an average of 98.23 million barrels of oil per day, which still reflects a bit of coronavirus related demand destruction compared to 2019, when global demand averaged 99.98 million barrels per day and higher during the summer....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 95.69 million barrels million barrels per day during Ju​ly, which would imply that there was a shortage of around 2,540,000 barrels per day in global oil production in July when compared to the demand estimated for the month...

Note that in green we have circled an upward revision of 200,000 barrels per day to OPEC's previous estimates of second quarter demand...so, in addition to figuring July's global oil supply shortfall that's evident in this report, that upward revision of 200,000 barrels per day to second quarter demand, combined with the 230,000 barrel per day upward revision to June's total global supply figure that's implied in this report, means that the 830,000 barrels per day global oil output shortage we had previously figured for June would now be revised to a shortage of 800,000 barrels per day.....in addition, the 1,930,000 barrels per day global oil output shortage we had previously figured for May, in light of the 200,000 barrels per day upward revision to second quarter demand, would now be revised to a shortage of 2,130,000 barrels per day...in like manner,  the 2,280,000 barrels per day global oil output shortage we had previously figured for April would now be revised to a shortage of 2,480,000 barrels per day....note, however, that despite this year's output shortfalls, the quantities of oil produced globally in 2020 still averaged well over 3 million barrels per day more than anyone wanted...

Also note that in green we have also circled a downward revision of 200,000 barrels per day to OPEC's previous estimates of first quarter demand....for March, that means that the global oil output surplus of 410,000 barrels per day we had previously figured for March would now be revised to a surplus of 610,000 barrels per day... similarly, the downward revision to first quarter demand means that the 800,000 barrels per day global oil output shortage we hadpreviously figured for February would now be revised to a shortage of 600,000 barrels per day, and that the global oil output surplus of 420,000 barrels per day​ ​we had previously figured for January would now be revised to a surplus of 620,000 barrels per day, in light of that 200,000 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 41st time out of the past 48 weeks during the week ending August ​20th, but was still down by 36.5% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US increased by three to 503 rigs this past week, which was also up by 249 rigs from the pandemic hit 254 rigs that were in use as of the August 21st report of 2020, but was still 1,426 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 8 to 405 oil rigs this week, after rising by 10 oil rigs the prior week, and it’s now 222 more oil rigs than were running a year ago, but it’s barely over a quarter 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 was down by five to 97 natural gas rigs, which was still up by 28 natural gas rigs from the 69 natural gas rigs that were drilling during the same week a year ago, but still only 6% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….in addition to oil and gas rigs, a horizontal rig that Baker Hughes classifies as "miscellaneous' is still drilling in Kern county California, while a year ago there were no such "miscellaneous' rigs reported to be active...

The Gulf of Mexico rig count was up by one to 14 rigs this week, with all 14 of those rigs now drilling for oil in Louisiana’s offshore waters….that was one more than the 13 rigs that were drilling in the Gulf a year ago, when 10 Gulf rigs were drilling for oil offshore from Louisiana and three were deployed for oil in Texas waters….in addition to those Gulf of Mexico rigs, this week we continue to have a rig drilling for natural gas off the shore of the Kenai peninsula in Alaska, and hence the national offshore rig count is now 15, up from 13 offshore rigs a year ago..

In addition to those rigs offshore, we now have three rigs drilling through inland bodies of water in Louisiana this week. whereas there was only such “inland waters” rigs running a year ago…the new “inland waters” startup is a directional rig targeting oil near the mouth of the Mississippi in Plaquemines Parish, Louisiana; we also continue to have a horizontal rig drilling for oil in the Haynesville shale through a lake in DeSoto parish in the northwestern corner of the state, just south of Shreveport, and another directional rig drilling for oil through an inland body of water in Terrebonne Parish of southern Louisiana...

The count of active horizontal drilling rigs was down by 2 to 454 horizontal rigs this week, which was more than double the 211 horizontal rigs that were in use in the US on August 21st of last year, but was less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the vertical rig count was up by 2 to 19 vertical rigs this week, and those were also up by 6 from the 13 vertical rigs that were operating during the same week a year ago….in addition, the directional rig count was up by three to 30 directional rigs this week, and those were also up by 10 from the 20 directional rigs that that were in use on August 21st 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 August 20th, the second column shows the change in the number of working rigs between last week’s count (August 13th) and this week’s (August 20th) count, the third column shows last week’s August 13th 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 21st of August, 2020...

With the addition of two rigs targeting offshore oil and another inland waters rig targeting oil in Plaquemines​ ​parish, the Louisiana rig count is only up by two because a Haynesville natural gas rig in the northern part of the state was shut down at the same time...an Eagle Ford rig that was shut down had also been targeting natural gas, as ​had been the Marcellus shale rig in West Virginia, and two other natural gas rigs that had been drilling in basins that Baker Hughes doesn't identify, thus accounting for this week's drop of 5 natural gas rigs...the Utica shale rig that was added in Ohio this week was targeting oil in Jefferson county...

meanwhile, the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes shows that one rig was added in Texas Oil District 8, which is the core Permian Delaware, but that ​the ​rig counts in all other Permian districts were unchanged...hence, with the Texas Permian count up by one while national Permian count was up by two, that means that the rig that was added in New Mexico must have been set up to drill in the far west reaches of the Permian Delaware in that state...elsewhere in Texas, we find one rig was added in Texas Oil District 1 and another rigs was added in Texas Oil District 3, while two rigs were pulled out of Texas Oil District 2, and another rig was pulled out of Texas Oil District 4, any or all of which could have been drilling in the Eagle Ford shale, which stretches in a narrow band through the southeastern part of the state...at least one of those removed would have ​been ​the Eagle Ford natural gas rig, while others might account for natural gas rig removals in basins that Baker Hughes doesn't name​, offset by oil rig additions in the same area​...the Texas rig count was still down by one, however, with the removal of a rig that had been drilling​ of oil​ in the state's offshore waters...

other changes nationally include the addition of a Williston basin oil rig in North Dakota, while an oil rig was pulled out of the Williston basin in Montana at the same time, the addition of another oil rig in the Uintah basin in Utah, and the removal of an oil rig from the Cana Woodford of Oklahoma...since Oklahoma's rig count was unchanged, we know there had to be a corresponding oil rig addition in the state in a basin that Baker Hughes doesn't identify...

DUC well report for July

Monday of this past week saw the release of the EIA's Drilling Productivity Report for August, which includes the EIA's July 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 14th 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 258 wells, falling from 6,215 DUC wells in ​June to 5,957 DUC wells in July, which was also 33.3% fewer DUCs than the 8,933 wells that had been drilled but remained uncompleted as of the end of July of a year ago...this month's DUC decrease occurred as 577 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during July, up from the 549 wells that were drilled in June, while 835 wells were completed and brought into production by fracking, up from the 827 completions seen in June, and up from the pandemic hit 298 completions seen in July of last year, but down by 33.5% from the 1,256 completions of Ju​ly​ 2019....at the July completion rate, the 5,957 drilled but uncompleted wells left at the end of the month represents a 7.1 month backlog of wells that have been drilled but are not yet fracked, down from the 7.6 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 a third below the pre-pandemic norm...

both oil producing regions and natural gas producing regions saw DUC well decreases in July, 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 130, from 2,419 DUC wells at the end of June to 2,289 DUCs at the end of July, as 263 new wells were drilled into the Permian during July, while 393 wells in the region were being fracked...in addition, DUCs in the Eagle Ford of south Texas decreased by 44, from 954 DUC wells at the end of June to 910 DUCs at the end of July, as 57 wells were drilled in the Eagle Ford during July, while 101 already drilled Eagle Ford wells were completed.... at the same time, there was also a decrease of 27 DUC wells in the Bakken of North Dakota, where DUC wells fell from 619 at the end of June to 592 DUCs at the end of July, as 32 wells were drilled into the Bakken during June, 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 20, falling from 856 at the end of June to 836  DUC wells at the end of July, as 30 wells were drilled into the Anadarko basin during July, while 50 Anadarko wells were ​completed​.....in addition, DUC wells in the Niobrara chalk of the Rockies' front range fell by 19, decreasing from 373 at the end of June to 354 DUC wells at the end of July, as 77 wells were drilled into the Niobrara chalk during July, while 96 Niobrara 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 16 wells, from 595 DUCs at the end of June to 579 DUCs at the end of July, as 69 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 down by two to 397 DUCs, as 49 wells were drilled into the Haynesville during July, while 51 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of July, 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 4,981 wells, while the uncompleted well count in the natural gas basins (the Marcellus, the Utica, and the Haynesville) decreased by 18 wells to 976 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...

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State says radiation levels good - No worries. That's the response state officials responsible for regulating radioactive waste at Ohio landfills provided after the Register sent a series of questions about concerns they are dangerously mismanaging the job. The questions and answers follow a groundbreaking investigative series by Public Herald, a nonprofit investigative journalism team co-founded by a former Sandusky man and Sandusky High School graduate, Josh Boaz Pribanic. Petroleum industry waste known as TENORM (Technologically Enhanced Naturally Occurring Radioactive Material) is being generated in enormous amounts at shale drilling sites, the series found. The three-part series, "Danger ahead," was published in the Register and other Ohio newspapers starting July 30. It determined that the Ohio EPA, the Ohio Department of Natural Resources and the state health department under Gov. Mike DeWine, don't have the ability to adequately test radiation levels of waste being brought to Ohio. The state is allowing radioactive waste from oil and gas well drilling to be shipped to Ohio for storage at landfills without knowing what the radiation levels of that waste is, whether it is higher than what is allowed, or whether it is safe, or not, according to Public Herald. Public Herald reported the concerns of experts, including Dr. Julie Weatherington-Rice, an earth scientist and adjunct professor for Ohio State University with a Ph.D. in soil science. The minimal testing requirements in Ohio are only getting “weaker and weaker,” according to Weatherington-Rice, which means there is no way to verify what is coming in and out of these facilities. “(Tests) have been watered down and watered down until we have almost no rules at all,” she told Public Herald. The verifiable testing on fracking waste samples of the waste from other storage sites shows evidence that levels are higher than allowable, and at dangerous levels, according to the Public Herald series. The state did not provide records to the Public Herald team, which worked on the series for 15 months, that refutes the concerns about the unknown radiation levels or the lasting and devastating potential impact radioactive waste could have on the environment and ecosystems in the state, including Lake Erie, in the future.

Ferry residents quiz commissioners at town hall — Riverside residents quizzed the Belmont County commissioners Tuesday about a range of subjects from the environment to the economic future and road maintenance during a town hall meeting at the Veterans Memorial Recreation Center. Martins Ferry city leaders and officials, some residents of surrounding communities and environmentalists attended. Sean O’Leary, a researcher for the Ohio River Valley Institute, asked to meet with the commissioners to discuss a model for job creation and economic development. He said his organization has issued a series of reports about the impact of the oil and gas industry, arguing that its impact on jobs, the population and quality of life has been “limited, and in some cases negative.” Members continue to oppose plans for an ethane cracker plant in the Dillies Bottom area along Ohio 7.“You may have reservations and disagreements with the findings that we have. I think we can agree that opportunities to reverse ongoing job loss and population loss and other issues are really important and should at least be examined,” O’Leary said.The commissioners commented on the economic impact of East Ohio Regional Hospital’s reopening and commended Dr. John Johnson for his investment in Martins Ferry.However, Bev Reed of Bridgeport raised concerns that the nearby Austin Master Services fracking waste recycling plant could contaminate the area.The Rev. Michael Ziebarth, pastor of the Greek Orthodox Christian Church of the Life-Giving Fountain in Martins Ferry, voiced concerns about the discovery of per- and polyfluoroakyl substances, or PFAS, in Bridgeport village water last year. He asked if the commissioners and other local leaders could do more to ask that the Ohio Environmental Protection Agency test more often for these and other rare chemicals. “Is that … something that is on your radar?” he asked. “You’d want to make sure this is frequently checked by whoever’s competent to do it.”

Gulfport Changing Utica Approach to Boost Efficiency, Cut Costs After Bankruptcy - After emerging from bankruptcy in May with a new management team, Gulfport Energy Corp. has overhauled its operations with a focus on capital discipline, free cash flow (FCF) generation and investor returns over production growth. The company wiped $1.2 billion of debt from its balance sheet during the restructuring and it’s now focused on sustainability, interim CEO Tim Cutt said during the company’s first earnings call since emerging from bankruptcy. Cutt, who formerly served as CEO of QEP Resources Inc. before it wasacquired by Diamondback Energy Inc., was named chairman. He’s joined at Gulfport by William Buese, QEP’s former CFO, who will assume the same role.“We remain keenly focused on reducing our corporate overhead and as a result we recently flattened our organizational structure by reducing the number of executives and more appropriately sizing the organization for our planned operations.”Gulfport, which operates in the South Central Oklahoma Oil Province (SCOOP) and the Utica Shale in Ohio, where it remains one of the largest producers, also reduced its midstream commitments to 900,000 Dth/d to help improve its cost structure. The company plans to spend up to $310 million on a maintenance program this year to deliver 2021 net production of 975 MMcfe/d-1.0 Bcfe/d. It expects similar programs in the years ahead to generate free cash flow (FCF) of $300 million annually. The company is also changing its operational approach, particularly in the Utica, which continues to account for the bulk of its production. Cutt said the company plans to develop wells in Ohio with wider spacing and complete them with more intense hydraulic fracturing jobs. Utica wells have historically been spaced at 1,000 feet, but Gulfport intends to develop its pads on 1,200-foot spacing with fewer wells. Using more fluid and proppant, along with longer laterals, is expected to boost production efficiency. Cutt, a petroleum engineer, said 1,000-foot spacing and smaller completions are impacting plateau periods and leading to steeper declines in the play.

Residents in a densely-populated Pittsburgh suburb are demanding public hearings on two proposed fracking wells - Residents in two Pittsburgh suburbs are demanding public hearings on a proposal to drill two new fracking wells within a mile of an elementary school. The wells, proposed by Apex Energy, would be within one mile of Level Green Elementary School and within two miles of 12,733 residents in Penn Township and Trafford Borough (about 17 miles east of Pittsburgh). The wells would be near several environmental justice communities, which are defined as, which is defined in Pennsylvania as any census tract where 20% or more of the population lives at or below the federal poverty line, and/or 30% or more of the population identifies as non-white. Environmental justice communities often facedisproportionately high levels of pollution and negative health impacts caused by the overlapping effects of poverty, racism, and pollution. Penn Township and Trafford already experience pollution from a variety of sources, including fracking wells in nearby municipalities, other local industrial plants, andcarcinogenic emissions from the region's remaining steelmaking plants. Fracking wells increase air pollution, produce radioactive waste, and can contaminate drinking water. Research has shown that living near fracking wells increases the risk of premature births, high-risk pregnancies, asthma, migraines, fatigue, nasal and sinus symptoms, skin disorders, and heart failure—all things that raise red flags in an environmental justice community."Public hearings are not usually standard for well pads," Gillian Graber, director of the community advocacy group ProtectPT, told EHN. "They usually only happen when there's a lot of community outcry, but public hearings should be standard for any permit that will impact this number of people." In 2019, Graber and her family participated in an EHN study that looked at toxic exposures in Pennsylvania families who live near fracking wells. Although Gillian, her husband, and their two children currently live five miles from the nearest fracking well, the investigation found evidence of harmful chemicals in their drinking water, air, and urine samples. "This well pad would be less than a half-mile from my house," Graber said. "[EHN's study] made me even more determined than I was before to keep fracking away from my family." While PA DEP has agreed to accept and review public comments regarding the proposed Apex Energy wells in Trafford, they haven't yet responded to ProtectPT's requests for a public hearing. An agency spokesperson told EHN it "is considering the request; however, because Act 13 only allows 30 days to review an oil/gas permit, DEP does not include oil and gas permits in the list of [environmental justice] trigger permits."

First-of-Its-Kind Study Measures Fracking's Impact on Nearby Surface Water Quality -A new study correlates poorer surface water quality with nearby hydraulic fracturing but finds that the impacts aren't major enough to be considered harmful by federal regulators. However, the researchers noted they weren't able to study "potentially more dangerous" substances related to fracking because of a lack of data. While some published studies have already linked groundwater contamination with hydraulic fracking activity, one of the researchers behind the study, Christian Leuz of the University of Chicago, said through a press release that their work was the "first large-sample evidence showing that hydraulic fracturing is related to the quality of nearby surface waters for several U.S. shales."The study, published in the journal Science, found "small but consistent" increases in the concentration of nonbiodegradable salts in watersheds where new hydraulic fracturing activities were taking place."The high salt concentrations were most pronounced at monitoring stations located closer to wells and at stations likely located downstream from wells," the study summary noted, adding that the highest accumulations were "observed within a year from drilling at monitoring stations assigned as downstream from a well and within 15 kilometers [or less than 10 miles] from a well."Researchers studied four salts associated with hydraulic fracturing flowback, or the fluids that bubble up to the surface through a fracking well due to pressure, and a briney wastewater mixture known in the industry as produced water. Three salts were found to have elevated concentrations associated with new hydraulic fracturing: chloride, barium and strontium. A fourth salt was studied — bromide — but evidence correlating its presence to new fracking development was "mixed and not robust."The concentrations identified by the researchers aren't high enough to be considered harmful by the U.S. Environmental Protection Agency, according to a study summary."Our work provides the first large-sample evidence showing that hydraulic fracturing is related to the quality of nearby surface waters for several U.S. shales. Though we estimated very small water impact, one has to consider that most measurements were taken in rivers or streams and that the average fracturing well in our dataset was not particularly close to the monitors in the watershed," explained Leuz through the press release. The researchers warned that the hydraulic fracturing process results in fluids with chemicals "that are potentially more dangerous than salts." However, the researchers weren't "able to look for these chemicals because they're not widely covered by public databases" and lamented the "availability and measurement frequency of water quality data."

Sunoco fined again for Mariner East 2 pipeline violations - The Pennsylvania Department of Environmental Protection fined Sunoco Pipeline’s Mariner East 2 pipeline for violations in four counties.According to the DEP, Sunoco spilled drilling fluids during construction of the pipeline into wetlands in Blair, Cumberland and Juniata counties and a creek in Lebanon County between February and August 2020. Sunoco notified the DEP of 13 “inadvertent returns” that spilled more than 400 gallons of fluid into the waterways.The $85,666 fine was part of a consent assessment of civil penalty signed earlier this month by the DEP, Pennsylvania Fish and Boat Commission and Sunoco.Most of the fine — $84,500 — will be put in the state’s Clean Water Fund. The Blair County, Cumberland County and Juniata County conservation districts will split the rest. Sunoco will also pay the Pennsylvania Fish and Boat Commission $12,424 for civil damages.Sunoco was fined $497,000 earlier this year for spilling drilling fluid into a creek in Lebanon County and failing to notify the DEP of multiple losses of circulation. There were a dozen spills between September and October 2020.The DEP issued a nearly $2 million civil penalty to Sunoco last January for spilling drilling fluids in a central Pennsylvania lake. The Mariner East 2 pipeline is an expansion of the Mariner East pipeline that was converted from a gasoline line to move natural gas liquids from Ohio and the Pittsburgh area to a processor near Philadelphia. It runs more than 300 miles across the southern portion of the state, crossing through 17 counties.

Chesco Government Aims At Pipeline Emergency Response Preparation — Twelve Chester County municipalities have pipelines running through their terrain and into situations potentially hazardous to residents, and in response, Chester County is beginning the process of forming an emergency response plan. At the request of the Chester County Commissioners, the Chester County Department of Emergency Services has prepared a Request for Proposal (RFP) to specialist contractors, for the development of a natural gas liquids (NGL) pipeline hazard-specific addition to the Chester County Emergency Operations Plan. The RFP also calls for the development of tools to better prepare the public for a potential emergency arising from either the Energy Transfer Mariner East Pipeline or the Enterprise Products TEPPCO Pipeline, the Commissioners' Office said on Monday. The pipeline hazard-specific section, which will be of particular value to schools and other vulnerable population facilities, will also be developed and added to the emergency operations plans of the 12 Chester County municipalities in which the Energy Transfer and TEPPCO pipelines traverse. "Chester County's Emergency Services leadership and staff, along with the thousands of police, fire, and emergency medical service personnel throughout the county, have comprehensive emergency operations plans that allow them to quickly respond to disasters, be they natural or man-made," said Chester County Commissioners' Chair Marian Moskowitz. "But the product being carried through the Mariner East and TEPPCO pipelines present us with complex and unusual challenges, should there be a leak, or worse. That is why we are seeking a specialist perspective for this addition to our emergency plans," Moskowitz said. The County's Request for Proposal asks respondents to follow the Federal Emergency Management Agency (FEMA) planning process for the recommended emergency management actions necessary in the event of an incident along the Mainer East or TEPPCO pipelines. The RFP also recommends that consideration be given to using the best practices of the U.S. Nuclear Regulatory Commission's public emergency planning and preparedness for nuclear power plants, the Commissioners' Office explained.

Despite $4 gas, Pa. shale permits drop 52% YOY in July - Shale gas permits issued to Pennsylvania producers in July declined 52% year over year, as the state's largest producers continued to hoard capital, planning fewer wells despite natural gas futures prices rising to $4/MMBtu, the highest in 2.5 years. Four counties, three in the dry gas window of the northeast part of the state, dominated the new permits list, according to the Department of Environmental Protection's database on Aug. 13. All the state's top five producers — EQT Corp., Cabot Oil & Gas Corp. Chesapeake Energy Corp., Range Resources Corp. and Southwestern Energy Co. — had double-digit percentage drops in new permits pulled compared to July 2020, with cuts as large as 85% in EQT's case. One company is breaking with the pack and has roughly doubled the pace of its Pennsylvania shale gas activity: New York's integrated National Fuel Gas Co. National Fuel's faster pace is not a surprise. As far back as November 2020, the New York producer had been telling investors it planned to increase spending and production to capture higher prices and capitalize on new wells and leases acquired from Royal Dutch Shell PLC last year. National Fuel's drilling unit, Seneca Resources Corp., pulled six permits to drill in July in Tioga County where the Utica Shale is stacked underneath the Marcellus Shale. In July, 2020 the company pulled no permits to drill in the state. According to DEP records, National Fuel pulled 33 permits to drill through July of this year, nearly double the 18 permits it pulled in the first half of 2020. EQT President and CEO Toby Rice reiterated that he needs to see futures prices move higher before he unleashes more rigs and drills more wells. "It would require a strip that's got some length to it, probably two to three years out at a gas price that's north of $3," Rice said on a July 29 call to discuss second-quarter earnings.

Methuen firm billed for gas spill, cleanup - — A local trucking company has been fined and is forced to pay for cleaning up a gasoline spill that happened last year. The Massachusetts Department of Environmental Protection announced Friday that P.J. Murphy Transportation must pay more than $60,000 for the spilling of 10,000 gallons of gasoline and 1,000 gallons of diesel fuel at the Brown Circle Rotary in Revere. An announcement from the department explained that on April 17, 2020, the cargo entered a storm drain at the traffic circle and ran into Rumney Marsh, Diamond Creek and Pines River. The company was fined $8,625 by MassDEP and must also pay $52,746 to an environmental trust for damages. “The law in Massachusetts pertaining to the releases of oil and or hazardous materials is quite clear that those who are responsible for spills of this magnitude, should be the first ones to bear the cost it will take to clean it up,” said Eric Worrall, director of MassDEP's Northeast regional office in Wilmington. State officials estimate that an area larger than 15 acres was impacted by the spill, causing injury to the aquatic ecosystem in the surface water, shoreline, and various plants and animal habitats in the area.

Evacuations In Nashua Due To Broken High Pressure Gas Line - - Nashua Fire-Rescue was notified of a gas leak at the corner of Broad Street and Bailey Street. When they arrived they found a crew working on a Liberty utility gas line Wednesday. The gas line was undergoing what the company referred to as "routine maintenance" at about 10:25 a.m. when for an unknown reason gas began to leak. The 6 inch main which also has a 2-inch main branching off was sending gas from the high-pressure line into the air. Nashua Fire Rescue requested additional apparatus to the scene and had Nashua Police shut down Broad Street. Due to the amount of gas leaking Nashua firefighters began to evacuate over 20 houses in the area. Liberty Utilities arrived and attempted to shut down the gas line in several different locations on Broad Street. Several attempts failed at trying to shut down the gas using valves in the street. Backhoes, dump trucks, and additional crews were brought in by the company and several different locations were dug up on Broad Street. At 4:30 p.m.more than five hours after the leak started the high-pressure gas line was shut down according to NFR Deputy Chief Kerrigan. Kerrigan said about 65 homes were affected by the gas leak. Crews were expected to work into the evening on Wednesday to continue the repairs to the pipe and valves.

Cut in rate hike, temporary halt fail to satisfy opponents of North Brooklyn pipeline -- Despite the fact that the state Public Service Commission last week slashed a rate hike that gas provider National Grid planned to charge customers in Brooklyn and nearby areas, a New York City environmental group strongly opposed the increase in general, saying it “continues climate denial and environmental racism.” The group, Sane Energy Project, particularly opposes the PSC’s actions regarding the controversial North Brooklyn Pipeline, even though the state regulators denied funding for the 7-mile structure until National Grid meets metrics, or goals, “on demand-reducing initiatives before seeking cost recovery of this and other infrastructure projects,” subject to review by an independent consultant who would evaluate emissions impacts. “While the Commission’s ruling today will halt construction of the last phase of the North Brooklyn Pipeline, National Grid took advantage of multiple delays in the rate case process to build most of the controversial project,” a statement from Sane Energy Project said. “The Commission today ruled that customers will have to pay for phases 1-4 of the project, which are already built. This financially rewards the utility for putting pipes in the ground over the widespread objections of local community members, local elected officials, the mayor of New York, and Senate Majority Leader Chuck Schumer,” the group continued.

Judge denies request to stop blasting for pipeline construction on Bent Mountain -A judge said Friday that she lacks authority to grant an injunction to stop the blasting of bedrock on Bent Mountain for a natural gas pipeline. Noting that the property owner had already sought action from the Federal Energy Regulatory Commission, U.S. District Judge Elizabeth Dillon said her court is not the proper jurisdiction to resolve the latest dispute over the Mountain Valley Pipeline. Dillon stressed that her ruling was not based on the merits of a request from John Coles Terry III, who maintains that drilling and blasting to clear a trench for the massive pipeline threatens to contaminate his well water and that of others in the Roanoke County community. However, there appeared to be no evidence that drinking water had been impacted. The Virginia Department of Environmental Quality said its investigation of numerous complaints has so far found no water pollution, while casting doubt on assertions that drilling 15-foot holes for explosives had penetrated the aquifer. “Our inspectors have been on scene and have looked into citizens’ concerns,” DEQ Director David Paylor said in a statement. “If we find evidence related to these complaints and any related water supply impacts, we will absolutely take every step necessary to prevent harm to the aquifer.” It is not unusual to encounter ground water while drilling relatively shallow holes in which to place explosives, but that does not impact the much deeper aquifer from which wells draw their water, Mountain Valley contends. After Friday’s hearing, Terry said he has found no discoloration, foul smell or sediment in his well water since blasting began early in the week. However, he said Mountain Valley had yet to reach the portion of his land where construction is most likely to impact his water. Terry also said that more time is needed for a scientific evaluation of his well water, which would include a comparison to samples that were taken before blasting began.M

MVP’s Plans for New Water-Crossing Method Clear Hurdle at FERC - FERC has issued an environmental assessment (EA) for the long-delayed Mountain Valley Pipeline (MVP), signing off on the project’s plans to use a different water crossing method at some locations along its route. MVP filed in February to amend its certificate approval as part of a broader plan to work around a prolonged legal process on its stayed Nationwide Permit 12. MVP has proposed using trenchless methods to cross 136 streams and 47 wetlands that the Federal Energy Regulatory Commission originally authorized as open-cut crossings. FERC said in a favorable EA released Friday that the new technique would not have a significant impact on the human environment as long as MVP adheres to its application and follows the Commission’s recommended mitigation measures. While the project’s new plans are likely to increase construction emissions and noise, the EA concluded that the impacts would be short-term and insignificant. The Commission also determined that the trenchless crossing method would have less of an impact on wetlands and waterbodies than the open-cut technique. Public comments on the EA must be received by Sept. 13. MVP also submitted an application to U.S. Army Corps of Engineers (USACE) as part of its change of plans. Water quality certifications are also pending in both Virginia and West Virginia. The USACE directed the states in June to complete their water quality reviews by the end of the year. Sponsor Equitrans Midstream Corp. said in May that the project’s in-service date would again slip to 2022 pending further regulatory approvals. The 303-mile, 2 Bcf/d MVP would move more Appalachian natural gas to the Southeast.

'It's taken the heart out of the community': Mountain Valley Pipeline cuts through tiny village of Newport - — A shuttered general store, a stately hotel converted to apartments, historic homes, two covered bridges and three churches still stand here — a testament to the village settled more than 250 years ago in the shadow of Sinking Creek Mountain. But among the residents who stayed, there was hope that Newport was on the cusp of a comeback. Then came the Mountain Valley Pipeline. On a recent August afternoon, Donna Pitt of Preserve Giles County looked up at the natural gas pipeline that descends steep mountain walls on both sides of Blue Grass Trail, the main street of Newport. “It’s taken the heart out of the community, is what it’s done,” Pitt said. The buried pipeline avoids cities and towns for much of its 303 miles through West Virginia and the New River and Roanoke valleys, taking a more rural path through forests and fields and finding a way around houses. Small as it is, Newport is the most densely populated community in Southwest Virginia to be impacted by construction. At first, residents opposed to the project believed that it could be stopped, even after 125-foot-wide strips for its right of way were cut out of the wooded slopes around them. “When it was just trees that were cut down, people would say, ‘We can always plant new trees,’” Pitt said. “But when that giant trench came down on top of the town, and in two days they had the pipe buried, people looked up and said, ‘It’s over.’” “That’s reality,” she said of a 42-inch pipe that stops just short of Greenbrier Branch on both sides, waiting as the nearly completed Mountain Valley Pipeline seeks a final set of permits to cross water bodies. “That’s like, ‘Oh, my God.’” Doug Martin remembers what the village was once like. “The old-timers would wake up to church bells and cow bells, but now you get the incessant beeping of trucks backing up” in the pipeline construction zone, he said.

Tribes Drop Fight Against $468M Pipeline At DC Circ. – Law360 -- Two Native American tribes have directly negotiated with the developer of the $468 million Southgate pipeline to ensure the protection of historic and cultural resources during the project's construction and have asked the D. C. Circuit to withdraw from a legal challenge to the pipeline's approvals. The Monacan Indian Nation and Sappony Tribe asked the D. C. Circuit to let them drop out of the challenge to the project on Monday, indicating that their earlier concerns about National Historic Preservation Act violations and the environmental review for the project were no longer pertinent. While no settlement was filed with the court, parties involved. . .

US gas acquisitions signal Gulf coast strategy shift - Chesapeake Energy's $2.2bn bid for Vine Energy is the latest bet by large US natural gas producers on the future of the US Gulf coast market, signaling a shift away from the pipeline-constrained northeast.Chesapeake's planned acquisition of Vine will nearly triple the company's output from the Haynesville shale, a prolific gas-bearing formation underlying east Texas and northern Louisiana. The combined company will have 1.6 Bcf/d (45mn m³) of Haynesville production, all of which may eventually find a home on the nearby Gulf coast, Chesapeake said this week. Those supplies can feed industrial demand and US LNG export terminals. The deal, which should close in the fourth quarter of this year, follows Southwestern Energy's $2.7bn bid for privately held Haynesville producer Indigo Natural Resources. Southwestern, an Appalachian producer, would gain a foothold in the Haynesville, diversifying its assets and increasing its access to Gulf coast markets. That deal was expected to close later this month.Those transactions underscore a renewed interest in the Haynesville as Nymex prompt-month gas prices rebounded from last year's lows and exports of US LNG surged. It also highlights the long-running frustration with regulators in the northeastern US — home to the Marcellus shale, the largest US gas field by volume."The next strategic move for US gas [producers] is on the Gulf coast," said Scott Hanold, an analyst for RBC Capital Markets. The region has more robust pricing, plentiful pipeline capacity and less regulatory friction, he noted.The appetite for natural gas along the US Gulf coast is growing as economic activity rebounds from the depths of the Covid-19 pandemic. The sharp increase in gas prices this year was driven in part by exports of US LNG, most of which leaves from the Gulf.Prompt-month natural gas prices rose above $4/mmBtu this summer, the highest in more than two years, after languishing below $2/mmBtu.US LNG exports hit record highs during the first half of this year as cold weather boosted demand in Asia and Europe and restrictions aimed at slowing the spread of Covid-19 eased.LNG exports averaged 9.6 Bcf/d during the first six months of 2021, up by 42pc from the same period in 2020, according to the US Department of Energy.In contrast, demand for Appalachian gas wanes outside of the winter months because of mild weather. Spot natural gas pries on Columbia Gulf Mainline, an indicator for the price of Haynesville output, so far this month has traded at an average price of $3.78/mmBtu, or about a 20¢/mmBtu premium to gas on Transcontinental Gas' Leidy Line, a bellwether for Marcellus output in northeast Pennsylvania. Prices in the northeast received a boost this summer from low US gas inventories and regional maintenance. Last summer, Columbia Gulf was at a 40¢ /mmBtu premium to the Leidy Line index. Prices for northeast production could face more headwinds from capacity constraints. Chesapeake said this week its ability to grow production there was limited by pipeline availability.

U.S. natgas futures rebound as forecasts project hotter weather (Reuters) - U.S. natural gas futures rebounded from a three-week low on Monday as forecasts projected hotter weather than previously expected, which could increase demand for the fuel to cool homes and businesses. Front-month gas futures NGc1 jumped 8.5 cents, or 2.2%, to settle at $3.946 per million British thermal units (mmBtu), recovering from its lowest level since July 20 earlier in the session. Refinitiv projected average U.S. gas demand, including exports, would rise from 92.2 bcfd this week to 93.6 bcfd next week. "What's really putting price upward pressure on prices is strong LNG exports and lower production," Data provider Refinitiv said gas output in the U.S. Lower 48 states has risen to an average of about 92 billion cubic feet per day (bcfd) so far in August, from 91.6 bcfd in July. That compares with an all-time high of 95.4 bcfd in November 2019. The amount of gas flowing to U.S. LNG export plants is expected to jump to a four-week high of 10.9 bcfd in the next two weeks as several Gulf Coast plants, including Cameron and Sabine in Louisiana and Freeport in Texas, have returned nearly to full service. That compares with an average for LNG feedgas of 10.3 bcfd so far in August, 10.8 bcfd in July and a record 11.5 bcfd in April U.S. pipeline exports to Mexico have slipped to an average of 6.1 bcfd so far in August from 6.6 bcfd in July and a record 6.7 bcfd in June. Data provider Refinitiv said gas output in the U.S. Lower 48 states has risen to an average of about 92 billion cubic feet per day (bcfd) so far in August, from 91.6 bcfd in July. That compares with an all-time high of 95.4 bcfd in November 2019.

Natural Gas Futures Reverse Course, Tumble on Weak Power Burns - Volatility abounded Tuesday as natural gas futures quickly gave back the gains they accumulated at the top of the week. Pressured by weaker power burns, the September Nymex gas futures contract settled at $3.837, off 10.9 cents from Monday’s close. October tumbled 10.9 cents to $3.851. Spot gas prices also continued to fall amid mostly comfortable temperatures in the eastern half of the country. NGI’s Spot Gas National Avg. slid 13.5 cents to $3.815. With long-range weather outlooks not deviating much from prior forecasts, futures traders focused on the impact that current mild weather was having on power burns and cash prices. Bespoke Weather Services said power burns were the weakest they had seen in a while, which is “somewhat of a surprise.” The firm said the decline, something it intends to monitor going forward, indicated that there is more coal in the power generation stack that could take some share away from gas. Production figures continued to fluctuate but generally remained firmly entrenched in the low 90s Bcf/d range. Liquefied natural gas volumes also were stable near 11 Bcf. On the weather front, the latest models cooled a bit but remained in a pattern biased to the warmer side of normal, according to Bespoke. By the end of the month, though, a near-normal outlook is seen for the Lower 48. The forecaster noted that September may be tough to run hotter than normal considering how many hot Septembers have materialized in recent years. It sees the best chance of heat versus normal over the next 10 days mostly in the eastern half of the nation. The warmth would then relocate to the western states in the 11- to 15-day period. Meanwhile, as Tropical Depression Fred moved inland across the Southeast, all eyes were on Tropical Storm Grace. The storm, packing winds near 50 mph as of 2 p.m. ET Tuesday, is forecast to move near or over the Cayman Islands late Tuesday and early Wednesday. Grace then is expected to approach the Yucatan Peninsula of Mexico late Wednesday or early Thursday.

US natural gas volumes in storage increase 46 Bcf following reclassification: EIA -US natural gas volumes in storage increased 46 Bcf, more than the five year-average, following the reclassification of base to working gas in the South Central region, while Henry Hub futures continue to decline. Inventories increased to 2.822 Tcf for the week ended Aug. 13, the US Energy Information Administration reported Aug. 19. The injection was more than the 35 Bcf addition expected by an S&P Global Platts survey of analysts. Responses to the survey ranged from a 25 to 42 Bcf injection. The 46 Bcf build was more the five-year average build of 42 Bcf and last year's 45 Bcf injection in the corresponding week. US storage volumes now stand 547 Bcf, or 16.2%, less than the year-ago level of 3.369 Tcf and 174 Bcf, or 5.8%, less than the five-year average of 2.996 Tcf. The weekly injection would have matched the five-year average, but 4 Bcf of base gas in the South Central storage region was reclassified to working gas. This caused the region to post a 1 Bcf injection rather than a 3 Bcf withdrawal for the week. The reclassification occurred in a non-salt dome storage facility. The Pacific region demonstrated a drawdown for the fifth consecutive week as heat and below-normal hydro generation continues to affect the area. The region's inventory is 16% below the five-year average and 23% less than last year. SoCal Gas, city-gate spot price has retreated from $7.62/MMBtu on Aug. 17 to $4.77 on Aug. 19. PG&E city-gate is at $5.16. The NYMEX Henry Hub September contract dropped 10 cents to $3.75/MMBtu in trading following the release of the weekly storage report. It has fallen by 25 cents since Aug. 16. The winter strip, November through March, averaged $3.87/MMBtu, representing a decline of 23 cents from one week prior. Platts Analytics' supply and demand model currently forecasts a 31 Bcf injection for the week ending Aug. 20, which would measure 13 Bcf less than the five-year average. The last full week in August is expected to add 36 Bcf compared to the five-year average of 53 Bcf. Fundamentals during the week in progress have tightened by roughly 1.2 Bcf/d despite a relatively small increase in total demand. Total supplies are down 900 MMcf/d on the week, with losses split almost evenly between onshore production and Canadian imports. Downstream, total demand is up roughly 300 MMcf/d as a 1.6 Bcf/d slide in power burn demand is being offset by a 1 Bcf/d rebound in LNG feedgas demand and a combined nearly 1 Bcf/d gain in residential-commercial and industrial loads.

Natural Gas Forward Prices Slide Amid Looser Balances, but Appalachian Basis Strengthens -- Loosening balances, evidenced by a weekly inventory build that overshot major surveys, accompanied declines in forward prices for most of the Lower 48 during the Aug. 12-18 trading period, NGI’s Forward Look data show. Nymex September futures experienced some up-and-down action, but on the whole lost ground during the Aug. 12-18 time frame, including a steep 10.9-cent sell-off on Tuesday (Aug. 17). An 8.1-cent decline in September Henry Hub coincided with fixed price front-month discounts at most Lower 48 hubs for the period. [Need natural gas forward curves? NGI offers 70 curves by month going out 10 years (120 data points per curve) as fixed price or basis differentials to the Henry Hub. Learn more.] Meanwhile, forward contracts at hubs in the West and in Appalachia saw both fixed price gains and strengthening basis as they bucked the broader market downtrend. Nymex futures initially seemed poised to add to recent losses Thursday. However, the September contract shrugged off the bearish impact of a net 46 Bcf weekly injection into U.S. gas stocks reported by the Energy Information Administration (EIA). The print, reflecting changes during the week ended Aug. 13, came in above the upper end of survey ranges. Still, price action suggested the build did not catch traders by surprise. At the least, buyers seemed satisfied that discounts leading up to the report had been sufficient to account for the larger print. Shortly after the EIA data crossed trading screens, September was hovering around $3.750. A steady climb from there saw the front month finish back up at $3.830, down 2.2 cents day/day but well off the lows. The print included a reclassification from base gas that resulted in a 4 Bcf increase to working gas in the South Central’s nonsalt facilities. According to Bespoke Weather Services, that put the “real” implied weekly flow at plus 42 Bcf.

U.S. natgas futures rebound as forecasts turn slightly warmer (Reuters) - U.S. natural gas futures gained on Friday as the weather outlook turned slightly warmer, potentially boosting demand for gas used for air conditioning. Front-month gas futures rose 2.1 cents, or 0.5%, to settle at $3.851 per million British thermal units. Prices touched a one-month trough on Thursday, pressured by a weekly storage report that showed a larger-than-expected injection. "I think we'll see an expansion in the storage deficit going into next month and that's a dynamic that should lift us to about $4 and current price gains in face of a bearish storage report points to a fairly firm underpinning," Also, LNG exports should continue to support the market for the rest of 2021. According to data provider Refinitiv, temperatures are expected to be slightly warmer in the next two weeks with 213 cooling degree days (CDDs). That compares with a 30-year average of 171 and 199 in Thursday's forecast. Average U.S. gas demand, including exports, is expected to rise to 95.1 billion cubic feet per day (bcfd) this week from 93.3 in the prior week. Refinitiv also said gas output in the U.S. Lower 48 states has averaged about 92 bcfd so far in August, up from 91.6 bcfd in July. That compares with an all-time high of 95.4 bcfd in November 2019. The amount of gas flowing to U.S. LNG export plants is seen at 10.9 bcfd next week. That compares with an average for LNG feedgas of 10.4 bcfd so far in August, 10.8 bcfd in July and a record 11.5 bcfd in April. With European and Asian \gas prices more than three times higher than the U.S. fuel, analysts expect LNG exports to remain elevated this year.

U.S. Gulf of Mexico oil producers consolidation accelerates - Oil and gas producers in U.S. Gulf of Mexico have consolidated at a faster rate during the pandemic, new government data shows, as crashing prices squeezed out smaller drillers who had been seen as the industry's future. The dominance of the top producers in the Gulf looms large as the industry's technology showcase, the Offshore Technology Conference, officially gets underway in Houston on Monday. The event, which in prior years drew more than 60,000 people and 1,000s of exhibitors, will be smaller this year due to company cutbacks and coronavirus-induced travel restrictions. The pandemic, along with recurring hurricane shut-ins, hastened the demise of some Gulf of Mexico producers. Smaller, private-equity backed firms that pushed into offshore fields last decade have struggled, leading several to exit while others slipped into bankruptcy. "We're only going to see further consolidation," said Colin White, an analyst with consultant Rystad Energy. Private-equity backed producers are being swallowed up by larger firms or are abandoning exploration for safer infrastructure investments, he said. The top 10 producers - led by Royal Dutch Shell, BP Plc and Chevron - this year pumped 86% of the region's 1.6 million barrels per day (bpd), up about 11 percentage points since 2017, data from regulator Bureau of Safety and Environmental Enforcement (BSEE) shows. Two closely-held offshore drillers, Fieldwood Energy and Arena Energy, fell into bankruptcy in 2020 as crude oil prices plummeted. U.S. energy experts forecast output will return to its peak of 1.9 million bpd by 2022.

Offshore oil and gas worker fatalities are underreported by federal safety agency -In the wake of the Deepwater Horizon disaster, the federal government created the Bureau of Safety and Environmental Enforcement, or BSEE, to improve safety and enforce environmental regulations in the offshore oil and gas industry. However, an investigation by Drilled News and Southerly found that the number of offshore worker deaths is being undercounted by the agency. Inconsistent and missing data, as well as loopholes that allow some fatalities to go unreported, make the offshore industry appear safer than it really is. Nearly half of known offshore worker fatalities in the Gulf of Mexico from 2005 to 2019 didn’t fit BSEE’s reporting criteria, according to data provided by the agency in response to a Freedom of Information Act request. On top of that, offshore jobs have been in decline since 2011 despite an increase in the amount of oil being produced offshore, making the jobs that remain more dangerous.Even with this undercount, the most recent data released by the agency in April indicates there were six offshore worker fatalities in 2019—a higher number than they’ve reported in a single year since 2010. But these reports on BSEE’s website, which date back to 2006, don’t match its own raw data. There were three additional deaths among offshore workers not reported by BSEE in 2019, including two in a helicopter crash heading out to a rig and one that law enforcement determined was not work related. The agency does not count offshore fatalities that occur in state waters, or deaths that occur while workers are in transport to offshore facilities. They don’t count deaths that happen on offshore platforms that aren’t work related, either, even though the remoteness of offshore platforms makes it more difficult to seek medical attention and workers often stay on platforms for two weeks at a time. For instance, in April 2021, six men died and seven went missing after a lift boat capsized on its way to an oil and gas lease in the Gulf. They won’t be counted towards the 2021 offshore fatality statistic, a BSEE spokesman said.

E&P Permit Requests Said Focused in Permian, Powder River and Eagle Ford - U.S. drilling permit activity climbed sharply in July, led by the Eagle Ford Shale, Powder River and Permian basins, but the overall numbers are still short from the pre-pandemic days of July 2019, according to Evercore ISI. drilling USA The energy analyst team led by James West uses federal and state data to compile a monthly review of exploration and production (E&P) permit requests across the country. Permitting requests usually precede drilling development by a few months. Based on the latest tally, E&Ps last month requested 81% more permits than in June and 12% more than in July 2020. “The increase was driven by permit growth in the Powder River Basin,” which saw 550 more permits month/month (m/m), or a 1,505% increase, the Evercore team noted. The Permian permit count was 44% higher, with 314 more than in June. Eagle Ford permitting climbed by 204% m/m, or by 188 permits. There were “minor decreases” in the Mississippian Lime, down 11% from June with 18 fewer permits. The Utica Shale’s permit tally fell by 44%, or by 11. The “other smaller plays” were off by 30% or by 54 permits. “The summer increase, however, continues to fall short when compared to July 2019, which was 36% higher than this year’s,” West said. Permitting activity in Wyoming, however, is exploding. Texas is in recovery mode. “Activity in Wyoming reached its highest permit count since November 2019,” up 1,502%, with 631 permit requests m/m. That could signal “a return to 2017-2019 numbers, when the state averaged 1,400 permits per month,” West said. “Texas followed Wyoming in permit count increases,” with 523, or 81% higher than in June. The state’s permit count was the highest monthly count since January 2020. Other states showing increases m/m included West Virginia, up by 189 or 1,112% and New Mexico, up by 72 or 33% higher. Permitting fell in California, however, down by 40 or 43% lower m/m. Pennsylvania’s permit numbers also fell, down by 20 or by 25%. Kentucky saw a 100% shortfall in permitting, down by 19. Kansas was down 13% m/m, with 16 fewer permits. The energy majors led the way in the Permian during July, the Evercore analysts noted. “The month of May experienced a decline in permitting by the majors in the Permian, falling by 84% to only nine permits issued,” the analysts said. June rebounded to 48, growing by 410%. July continued the trend, up 21% m/m to 59. The permit increase in the Permian last month was “driven primarily by ExxonMobil,” up by 30 m/m, and by Royal Dutch Shell plc, which requested 21 permits. “The pair, along with BP plc, are the only majors active in the basin,” as legacy producer Chevron Corp. requested no permits during July.

Most flares from Texas Permian oil drilling lack permits –study - (Reuters) - Oil producers such as Exxon Mobil and Royal Dutch Shell are burning off gas in the largest oil field in the United States without required Texas state permits, the environmental group Earthworks said in a report on Thursday. Energy producers flare gas, an unwanted by-product of oil extraction, when they cannot transport the gas to consumers. Flaring reduces, but doesn't eliminate, methane emissions and contributes to climate change by releasing carbon dioxide into the atmosphere. Texas, the nation's biggest oil producer, has more permissive rules on flaring than other oil-and-gas producing states, and regulators there have opposed additional regulations to limit emissions. The report compared permitting records from Texas regulators with flares witnessed on flights equipped with gas imaging cameras that were conducted by the Environmental Defense Fund. It found that of 227 flares observed, between 69% and 84% were likely unpermitted. Big producers such as Shell, Exxon and Diamondback Energy Inc were among the companies with multiple flares that had no permits, the report said. Shell and Exxon, who did not review the full report ahead of publication, dismissed the topline findings, saying they follow all regulations and work toward ending routine flares. Diamondback did not respond to a request for comment. A Shell spokesperson said it has not "routinely flared in the Permian Basin" since 2018 while Exxon's spokesperson Julie King said its Permian Basin flaring is at a "record low of less than 1%." State regulations allow for unpermitted flaring in some cases, including releases from storage tanks, in the first 10 days after a well's completion, or during equipment maintenance, construction or repair, a spokesperson for the state's oil and gas regulator, the Railroad Commission of Texas (TRC), told Reuters in response to the report. The commission reviewed the report before publication. "A short-term observation of a flare from a flyover and absence of an explicit exception does not necessarily mean the observed flaring is illegal," TRC spokesperson Andrew Keese said.

How West Texas Became Woodstock for Frackers - In the fall of 2017, Sean Mitchell and John Daniel thought it would be fun to invite some of their investment banking clients to Midland so they could see the fracking boom up close. As part of the gathering, Mitchell and Daniel, managing directors at Houston-based Simmons Energy, planned to fire up the smoker and host a barbecue. They expected that about fifty people would show up. But this was the Permian Basin, the hottest oil and gas play in the world, and nothing happens on a small scale. Two hundred and fifty people turned out.It was such a hit that Mitchell and Daniel decided to do it again this past October. But this time the barbecue was refashioned as a cookoff, and attendance more than tripled: eight hundred people came to the Permian Basin Petroleum Museum to sample the wares of 37 oil field service companies vying for a gold cup trophy. Smokers and elaborate trailers circled behind the building in the shadows of historic drilling rigs while guests mingled, listened to live country music, and indulged in beer and cuisine that went far beyond the brisket and ribs that were the focus of the competition—gumbo, barbecued bologna, and pretty much anything that could be wrapped in bacon. CNBC’s Brian Sullivan showed up with a film crew, attendees came from as far away as Montreal, and Cudd Energy Services won the big prize for its succulent brisket. In the span of one year, Mitchell’s small gathering had ballooned into Woodstock for frackers, the people at the forefront of the hydraulic fracturing industry, which has excavated billions of barrels of oil that were once considered inaccessible. “It’s become so important because shale in the Permian Basin is where it’s at,” said Josh Lowrey, the president and CEO of Houston’s Galtway Marketing, who was on his way to check out the brisket at the ValTek trailer. He noted that some of his clients have pulled out of large industry trade shows like the Offshore Technology Conference to attend Mitchell’s barbecue and other Permian-focused gatherings.These are good times in Midland and across the Permian Basin, the most prolific oil field in North America and second in the world behind Saudi Arabia’s massive Ghawar Field. Over the past two years, production from the Permian, which stretches south from Lubbock almost to the Rio Grande and west from San Angelo to New Mexico, has soared from just over 2 million barrels a day to more than 3.6 million.

Gas companies seek more cash from consumers - Texas Gas Service, as well as other utilities throughout Texas that provide natural gas to consumers and businesses, is asking the Texas Railroad Commission to allow it to put a surcharge on customers’ bills in order to pay for natural gas used during Winter Storm Uri. TGS filed its application with the commission to recover costs of the storm on July 30.Consumer advocate Paul Robbins, who has studied documents filed with the commission, has concluded that the gas companies are seeking an order that will allow them to add about $5 a month to customers’ bills for 10 years. Larry Graham, manager of regulatory affairs for TGS, declined to offer an estimate of the cost to consumers.According to an analysis by Bloomberg News, because of Texas’ unregulated market, natural gas producers – as opposed to companies that sell gas to consumers – made $11 billion in just five days during the unprecedented winter storm.Although TGS and the other gas companies that provide gas to consumers each filed a separate request for a hearing on their securitization case, all the cases have been consolidated. More than 50 cities throughout the state have joined a coalition to intervene in the case before the commission. Central Texas cities that have joined the Texas Cities Alliance include West Lake Hills, Taylor, Goliad and Killeen.While Austin is not on the list, city officials confirmed late Monday that Austin has joined in intervening on the matter. Thomas Brocato, the lead attorney representing the alliance of cities, told the Austin Monitor that other cities still have time to join the coalition.Graham insists that the matter before the Railroad Commission is not a “rate case,” but a proceeding to allow securitization financing. As he explained, under Texas House Bill 1520the gas companies will be able to extend the period of time during which they can recover costs associated with Winter Storm Uri.According to documents filed with the commission, charges for natural gas during the winter storm left TGS with about $290 million in debt. Robbins said all told, the companies that provide gas service directly to consumers have more than $3.6 billion in fuel debt that they want to securitize.

U.S. Rep. Henry Cuellar calls for more natural gas spending in $3.5 trillion budget bill -- U.S. Rep. Henry Cuellar said Wednesday he’s looking to steer more federal funding to natural gas-fueled electricity generation in the $3.5 trillion spending bill that’s moving through Congress.As emissions billowed from CPS Energy’s Calaveras gas-fired plant in the background, the Laredo Democrat said at a news conference that Democratic lawmakers’ efforts to expand renewable energy sources in the U.S. shouldn’t hobble the oil and gas industry. Energy companies provide an estimated 347,000 jobs in Texas.“We definitely need to look at clean energy, but you can’t do it to disadvantage or attack oil and gas while it still creates thousands of jobs in our area,” said Cuellar. He represents Congressional District 28, which reaches from Laredo to San Antonio and covers a large swath of the Eagle Ford Shale oil and gas field. “When we do the big reconciliation bill and we look at clean energy, I’m hoping that natural gas can be part of the clean energy,” he said. Cuellar was referring to the budget reconciliation bill that’s being crafted by congressional Democrats. Much of the spending in the bill would go to progressive priorities such as expanding Medicare, extending child-care tax credits and clean-energy initiatives. Cuellar didn’t say how much funding he’d seek in the budget bill to bolster gas-fired power generation.

Research shows gaps in how EPA, oil industry measure methane - -Before EPA and the energy industry can address climate-warming methane emissions from oil and gas production, they’ll have to improve how they track and estimate it.EPA’s method of calculating methane pollution has been widely criticized for underestimating emissions from the oil and gas industry, one of the biggest sources of the potent greenhouse gas (Energywire, Jan. 30, 2020).Today, the agency calculates its inventory of methane emissions by multiplying the number of potentially leaky components — such as valves and thief hatches on well heads and storage tanks — with an estimate of the average emission rate for each part.Some groups have said that such a “bottom-up” approach — where a national estimate of emissions is built by scaling up measurements taken at a small sample size of wells or facilities — leads to an underestimation of emissions. They’ve cited the potential to miss so-called super emitters, or a small number of sources that contribute a large percentage of overall emissions.Studies with a “top-down” approach — using satellites or aircraft to determine total emissions from multiple sites — have found total methane emissions that were double EPA’s estimates. A study published this month in Nature Communications investigates the gap between “top-down” and “bottom-up” approaches. Researchers from Stanford University, the Harrisburg University of Science and Technology, and other institutions say EPA’s “detailed, engineering-based” approach works — but it’s relying on faulty data.EPA is still using equipment counts based on industry self-reporting and a decades-old study, said Arvind Ravikumar, a research associate professor at the University of Texas at Austin and study co-author. While the number of some components hasn’t changed, others have, especially because of the surge in shale drilling in the 2010s.“When the fracking revolution happened, the type of equipment at oil and gas facilities changed,” Ravikumar said. That means today’s equipment could have a different number of components like valves or connectors.The Stanford researchers focused on the bottom-up approach because it’s the method used by EPA when it writes regulations, and it’s widely used by other governments. They examined "component-level measurement data" drawn from previous studies and concluded EPA’s current estimates underreport emissions caused by liquid storage tanks.The liquids frequently have methane and other gases dissolved in them, which can be released during normal operations or when hatches and valves are inadvertently left open.“It’s like opening a beer,” Jeff Rutherford, one of the paper’s authors, said in a news release. “It’s liquid as long as there is high enough pressure, but if you release the pressure, the gas quickly escapes.”

API leads dozen trade groups in suing Interior over pause on new oil, gas leases | S&P Global Platts - A dozen oil, gas and extraction-related industry groups are suing the US Department of the Interior over its nearly seven-month-long pause on new federal oil and gas leases. The groups, led by the American Petroleum Institute, asked a federal court to vacate the pause, claiming that the Biden administration's "leasing moratorium" violated various federal laws, including the Administrative Procedure Act and the Mineral Leasing Act. They also said Interior's leasing pause violated the National Environmental Policy Act because officials did not "take the necessary hard look at the potential environmental impacts before its implementation," according to the Aug. 16 lawsuit filed in the US District Court for the Western District of Louisiana. Interior declined to comment on the new lawsuit. As part of a sweeping executive order on Jan. 27, President Joe Biden issued a pause on new oil and gas leases on federal lands and waters. Interior has since canceled its first- and second-quarter oil and gas lease sales and had not held a third-quarter sale as of the lawsuit's filing, the groups said. The pause drew swift condemnation from the industry and Republican lawmakers in addition to various lawsuits. "Defendants' radical departure from prior policy in implementing the moratorium without a reasoned explanation was arbitrary, capricious, an abuse of discretion, otherwise not in accordance with law, and in excess of their authority," the industry groups said. S&P Global Platts Analytics continues to expect the leasing review to have a muted impact on the US production outlook. It expects Interior to reschedule Gulf of Mexico Lease Sale 257 for sometime in the fourth quarter. "Biden's relatively pragmatic oil policy has balanced a Keystone XL rejection and tougher methane rules with supporting the DAPL pipeline, the Alaska Willow project, and drilling permits on existing federal leases," chief geopolitical analyst Paul Sheldon said in a recent note. But the trade groups said their members are "significantly harmed" by the leasing pause, having "invested millions of dollars in acquiring and exploring federal oil and gas leases in reliance that adjacent tracts needed to complete the development of an oil and gas prospect would be available for lease in scheduled or statutorily mandated lease sales." Such leases are especially important for companies active in deepwater drilling, they said. "If operators cannot obtain access to these additional leases necessary to complete development, their substantial investment is substantially diminished or may be lost entirely," the groups said. Interior officials have responded vaguely to questions about the timeline of the leasing pause and reiterated that the temporary ban on new leasing does not affect existing leases. They have also pointed to a backlog of approved unused drilling permits. In June, a federal judge in Louisiana struck down the leasing pause, pointing to federal laws that require the agency to hold lease sales. Interior Secretary Deb Haaland told federal lawmakers shortly thereafter that Interior was reviewing the decision.

Biden administration appeals federal court decision to block oil, gas leasing pause (Reuters) -The Biden administration on Monday challenged a federal judge's decision in June to block the Interior Department's pause on oil and gas leasing on public lands and waters - a critical piece of its climate change policy - but will proceed with leasing during the appeals process. The Interior Department aims to overturn the decision of Judge Terry Doughty of the U.S. District Court for the Western District of Louisiana, who said Louisiana and a dozen states that sued President Joe Biden's administration established they would suffer injury from the pause on new oil and gas leases. Those states last week sought a court order from the judge to force Interior to hold an offshore lease sale this year. And on Monday, the American Petroleum Institute and 11 other industry groups sued the administration to force them to reinstate lease sales, which had not resumed after the judge's June decision. "The appeal of the preliminary injunction is important and necessary. Together, federal onshore and offshore oil and gas leasing programs are responsible for significant greenhouse gas emissions and growing climate and community impacts," the Interior Department said in a statement. Biden had paused the government's new leases in January as part of a sweeping plan to rein in fossil-fuel extraction on federal land and combat the effects of climate change. The Interior Department said on Monday it will proceed with new leases during the appeals process "consistent with the district court’s injunction during the appeal" and will use "discretion provided under the law to conduct leasing in a manner that takes into account the program’s many deficiencies." The agency acknowledged that its current leasing program and royalty rates do not "adequately incorporate consideration of climate impacts" and the "breadth of the Interior Secretary’s stewardship responsibilities." The agency said it will address the shortcomings through several steps, including completing a report outlining reform recommendations. Interior Secretary Deb Haaland said earlier this year that the highly anticipated report would be released in the “early summer” but it has not yet been published.

Fossil Fuel Leases to Resume on Public Lands While Biden Admin Appeals Court Ruling - Climate groups are expressing deep concern following an Interior Department announcement Monday that the Biden administration will resume oil and gas drilling leases on public lands and waters — a practice President Joe Biden vowed to ban during his 2020 run for the White House — in response to a federal court ruling. While the Biden administration confirmed in its announcement that an appeal has been filed with the 5th Circuit Court of Appeals in a legal battle with the state of Louisiana — which sued the federal government over the pause in the oil and gas leasing program ordered by Biden earlier this year — the Interior Department said leasing would resume while the process plays out."Federal onshore and offshore oil and gas leasing will continue as required by the district court while the government's appeal is pending," the DOI stated.According to Bloomberg, the moves by the administration "mark the beginning of an open-ended analysis of the federal oil, gas and coal leasing programs that could span years — and lead to higher fees as well as new limits on development in sensitive areas."While environmental advocacy groups commended the administration for appealing the lower court ruling —handed down by a Trump-appointed U.S. district court judge in June — they also said the threat of resuming the leasing program on federal lands and for offshore drilling cannot be overstated."Our planet can't afford any more new fossil fuel extraction," said Taylor McKinnon, a senior campaigner with the Center for Biological Diversity, in a statement on Tuesday. "We're out of time. The world's existing oil and gas fields will already push warming past 1.5 degrees Celsius if they're fully developed." Robert Weissman, president of Public Citizen, said in response that with "the climate crisis smacking us in the face at every turn, it's hard to imagine a worse idea than resuming oil and gas drilling on federal lands. As has been documented in long and excruciating detail, oil and gas drillers have trashed public lands and failed to clean up their mess — while siphoning public resources for a relative pittance."As the appeals process plays out, the Biden administration said it will perform a new analysis of the regulatory framework that governs leasing and extraction operations on federal lands as well as hold oil and gas companies to account under existing authorities and guidelines.

Milwaukeeans Protest the Line 3 Pipeline - Several Milwaukeeans recently travelled to Northern Minnesota to protest construction work on Line 3, a thousand-mile pipeline bringing crude oil from Edmonton, Alberta to Superior, Wisconsin. Enbridge Energy says that they are addressing known integrity flaws and improving efficiency. Protestors see this framing as misleading because the construction includes the laying of over 300 miles of new pipeline pumping 760,000 gallons of Canadian tar sands oil through North Dakota, Minnesota and Wisconsin per day. Protestors also see the construction of a new Line 3 as a violation to the Anishinaabe tribe’s treaty rights, a contributor to climate change and a destructive force to the Manoomin (wild rice), a sacred food for a number of local tribes. Amongst the protestors at Red Lake Treaty Camp near Thief River Falls MN, the Red Lake and White Earth Reservation were two Milwaukeeans. Early on Aug. 4, 19 protestors were arrested and one was hospitalized with head injuries at the prayer cam, adding to the nearly 600 protestors who have been arrested during the Line’s construction. Milwaukeean Lelah Allen (aka Buttons) described the movement as being “welcoming” and “palpable.” For Allen, the police presence juxtaposed this atmosphere creating an “adrenaline yo-yo.” “There are actions happening,” she said, “There is police brutality happening, and we are cool and we are making dinner, and we are singing and we are praying and ‘oh there’s more cops’.”

Navy diver who helped after bridge collapse returns awards to protest Line 3 - A U.S. Navy diver who helped efforts to search for bodies in the Mississippi River after the I-35W bridge collapse returned his awards Monday to protest the Line 3 oil pipeline. John Miller, 39, of Monticello, asked Gov. Tim Walz to issue an immediate stay on construction of the pipeline replacement project until lawsuits challenging its approval play out in court. At Minneapolis' Stone Arch Bridge with about three dozen supporters early Monday evening, he lso asked the Minnesota Supreme Court to vote on the related cases before it in a timely manner.Earlier in the day, the Minnesota native returned a commendation ribbon and pendant from the Minnesota Department of Military Affairs and a certificate of commendation from then-Gov. Tim Pawlenty.Miller said he grew up fishing and hunting and wants the pristine lands in northern Minnesota to be left alone for generations to enjoy it."The last time I came back to the Mississippi in distress was to help clean up after a disaster, and this time I come to do everything I can do to help prevent a disaster," he said.Opponents say the new Line 3 will open a new region of Minnesota waterways to oil spill degradation and exacerbate climate change. Enbridge says the new pipeline, which replaces its aging and corroding current Line 3, is a safety enhancement and will restore the full flow of oil.

Justin Vernon's Bon Iver To Headline Line 3 Protest Concert In Duluth Wednesday Grammy award-winning Eau Claire native Justin Vernon and his band Bon Iver will headline a concert in Duluth Wednesday that seeks to raise money to stop construction of Enbridge’s Line 3 oil pipeline in Minnesota.The event is a fundraising concert for the Indigenous environmental nonprofit organization Honor the Earth, which has been leading protests of the Canadian energy firm’s pipeline replacement.Pipeline opponents and health professionals in Wisconsin and Minnesota are calling on President Joe Biden and his administration to stop Line 3, arguing the project conflicts with the administration’s pledges to curb carbon emissions that drive climate change."We need to come together to save our environment, to save our Earth from total annihilation, and that's on its way," Vernon said during a livestream on Monday. "That's what I care about, and I don't really care about anything else."Bon Iver is joining a wide lineup of musicians who will perform as part of the "Water is Life: Stop Line 3" festival at Duluth’s Bayfront Festival Park on Wednesday from noon to 10 p.m. The concert’s line-up includes performances from Lissie, Low’s Alan Sparhawk, David Huckfelt, Mumu Fresh, Larry Long, and Native performers Annie Humphrey, Quiltman, Dorene Day Waubanewquay and Corey Medina.Vernon pointed to a recent report from a United Nations panel on climate change in which more than 200 scientists detailed how changes from past and future emissions will result in irreversible changes to the planet for centuries. The latest report builds on previous studies that humans are causingrapid changes in warming that will lead to more frequent and intense heat waves, rains, drought and other extreme events."I think everyone's feeling the heat, quite literally," said Vernon. "This is just one major fight."

Despite plea for cancellation, Duluth says it can't call off anti-Line 3 concert at city park -A group of local officials along the route of Enbridge's nearly completed Line 3 oil pipeline across northern Minnesota asked the city of Duluth to cancel a fundraising concert planned for next week by pipeline opponents at a city-owned park. But city officials have denied their request, citing the group's First Amendment rights and pointing out that they have received all the necessary permits to host such an event.In an Aug. 5 letter sent by Thief River Falls Mayor Brian Holmer and signed by Grand Rapids Mayor Dale Cristy and Hill City Mayor Sean Lathrop, among other northern Minnesota officials, to Duluth Mayor Emily Larson, Council President Renee Van Nett and Council Vice President Arik Forsman, the officials urged the city to cancel the Aug. 18 "Water is Life: Stop Line 3" concert at Bayfront Festival Park. The letter says the host, Indigenous-led environmental group Honor the Earth, has been organizing and supporting protests along the pipeline route, some of which have led to confrontations with police.Since construction on the 340-mile Minnesota segment began in December, nearly 700 protesters have been arrested along the route as they tried blocking or slowing construction of the pipeline."We write this letter because of our concern for our communities and our first responders," the officials wrote. "We respectfully ask you to help us prevent future avoidable conflicts. On behalf of the people we represent, we strongly request that you rescind Honor the Earth’s permits and not allow this concert to move forward."Duluth Mayor Emily Larson responded the next morning in an email, provided by the city to the News Tribune on Wednesday. She clarified that while Bayfront is city-owned, the Duluth Entertainment Convention Center manages Bayfront."More to your point, however, is your ask to revoke constitutionally protected rights to gather in a public space for an event I may or may not personally agree with. If the group pulls the appropriate permits, follows the rules and pays the rental fees, we do not discriminate," Larson wrote. "This follows the legal advice I’ve been given on this matter."

Physicians join the fight to stop Enbridge's Line 3 pipeline -Medical professionals around the country rallied on Tuesday against the expansion of Enbridge’s Line 3 crude oil pipeline, calling it a threat to human and planetary health.“The health of Minnesotans is at risk,” said Teddie Potter, director of planetary health at the University of Minnesota School of Nursing, addressing a crowd in St. Paul, Minnesota. “Tar sands oil threatens the health and wellness of future generations; we must stop the line.”The events were part of a nationwide day of solidarity against the project from Enbridge, a Canada-based oil and gas company. In cities from Augusta, Maine, to Los Angeles, health professionals united with environmental groups and Indigenous water protectors to express their opposition to the firm’s controversialLine 3 replacement, which is already under construction. If completed, the upgrade would double the pipeline’s capacity, transporting vast amounts of tar sands oil from Edmonton, Canada, to Superior, Wisconsin — traveling over sacred Anishinaabe territory in Minnesota in the process.Enbridge has said the upgrade is needed for safety reasons, to reduce maintenance needs, and to “create fewer disruptions to landowners and the environment.” But opponents from the medical community disagree. According to Health Professionals for a Healthy Climate, or HPHC — the advocacy group that organized Tuesday’s nationwide protests — the project poses both immediate and long-term threats to Minnesota communities and Indigenous peoples, whether from an oil spill or from the pipeline’s contribution to climate change.Vishnu Laalitha Surapaneni, an assistant professor of medicine at the University of Minnesota who helped organize the rally in St. Paul, told Grist she is particularly worried about the pipeline’s potential impact on water quality. “We’re in the Land of 10,000 Lakes,” she explained, using Minnesota’s unofficial nickname. “This is not something that is compatible with healthy water.”In the case of an oil spill, Surapaneni and others have raised concern about the tar sands oil that will be transported through Line 3, a heavy kind of crude oil known as bitumen. To facilitate its flow through pipelines, Enbridge mixes bitumen with a diluent — a proprietary concoction whose specific ingredients are a trade secret. But if Enbridge’s diluent is anything like other companies’, HPHC says it likely contains a mixture of carcinogens such as benzene, toluene, ethyl benzene, and xylene,collectively known as BTEX. Enbridge’s response to Grist’s request for comment did not name the ingredients in its diluent.There may also be threats from spills of drilling fluid, the substance that Enbridge has been using to lay new sections of pipeline into the ground across Minnesota. Already, Enbridge is under investigation by the Minnesota Pollution Control Agency for having spilled drilling fluid 28 times at 12 river crossings. Although Enbridge has said that the drilling fluid is nontoxic and that the spills had “no impacts to any aquifers nor were there downstream impacts,” geologists and environmental experts remain concerned. Spills elsewhere in the country — albeit larger than those in Minnesota — have polluted wetlands and drinking water, and can harm river and wetland ecosystems.

Enbridge's 390,000-bpd pipeline expansion in 'final innings,' lifting hopes for capacity-constrained oilpatch - — Enbridge Inc., North America’s largest pipeline company, has told Canadian oil producers that its long-anticipated, frequently delayed Line 3 pipeline project is nearly complete. Enbridge confirmed last week that it has filed procedural regulatory documents with the Canada Energy Regulator and the U.S. Federal Energy Regulatory Commission to allow for tolling surcharges on the Line 3 pipeline to take effect “within the next 30 to 60 days.” The Calgary-based pipeline giant said in an email the tolls could be effective as of Sept. 15. The date marks the end of a multi-year saga for Enbridge, which has struggled to push its Line 3 replacement pipeline through Minnesota since 2014. The project will replace an aging pipeline and also expand the line’s capacity to ship oil from 370,000 barrels per day to 760,000 bpd. The line, which runs from Alberta to Wisconsin, had been delayed through Minnesota, where it faced legal and regulatory challenges as well as entrenched opposition on the ground that sought to disrupt the $9.3-billion project’s construction schedule. “There will be a further filing to specify the in-service date shortly before the line goes into service once all necessary construction and commissioning activities are complete,” Enbridge spokesperson Jesse Semko said in an email. The pipeline, which will see additional 390,000 bpd Canadian crude to U.S. refineries, comes as the White House urged the Organization of the Petroleum Exporting Countries last week to boost production as gasoline prices in the country soared. Jake Sullivan, Biden’s national security adviser, criticized global oil producers last week, saying, “At a critical moment in the global recovery, this is simply not enough.” Sullivan also said in the statement: “Higher gasoline costs, if left unchecked, risk harming the ongoing global recovery.” Alberta Premier Jason Kenney took the opportunity to slam the Biden administration for seeking more supplies from OPEC countries, after rejecting TC Energy Corp.’s Keystone XL pipeline. “The same US administration that retroactively cancelled Canada’s Keystone XL Pipeline is now pleading with OPEC & Russia to produce & ship more crude oil,” the premier tweeted last week. “This comes just as Vladimir Putin’s Russia has become the 2nd largest exporter of oil to the US.” Canada is the U.S.’s largest source of oil imports, shipping just over 4 million barrels per day of oil on average in May. The project is also critical for Alberta, where oil production has exceeded existing pipeline capacity in recent years, which has led to massive discounts for oilsands crude relative to U.S. blends and a loss of government royalty revenues. “Enbridge’s filing to federal regulators in both Canada and the United States is another step in getting this pipeline operational in the near future, and we are excited to have this project completed and transporting Alberta oil,” Alberta Energy Minister Sonya Savage said in an emailed statement Friday.

Biden Faces Mounting Pressure To Yank Line 3 Oil Pipeline Permits -The White House is facing mounting pressure from Democrats to yank federal permits for Line 3, the controversial oil pipeline under construction in Minnesota. Eight Democratic senators and nearly two dozen House members criticized the Biden administration for allowing pipeline giant Enbridge to continue building Line 3 across wetlands in a letter sent Monday that HuffPost viewed. The lawmakers say President Joe Biden should suspend the Clean Water Act permits the Trump administration had granted until the Army Corps of Engineers completes a more thorough analysis of the potential environmental impacts. “The Trump Administration aggressively expanded fossil fuel infrastructure projects under a new policy of ‘energy dominance’ and severely limited public scrutiny on those projects,” said the letter, which Reps. Pramila Jayapal (D-Wash.) and Ilhan Omar (D-Minn.) and Sen. Jeff Merkley (D-Ore.) led. Carrying out a new assessment, they said, would “ensure a full and significant environmental review that includes assessing the project’s real costs on environment, public health, and climate change and ensuring the public is aware of those costs.” The Army Corps conducted “almost no independent evaluation of the risk of oil spills at the crossings it authorized, despite the fact that the route for Line 3 crosses 227 lakes and rivers, including the headwaters of the Mississippi River and rivers that feed directly into Lake Superior,” the letter said. The lawmakers complained that the Army Corps’s final permitting analysis last November of how the pipeline would affect climate change came down to “a single paragraph in which greenhouse gas emissions from construction and operation of a major tar sands pipeline are dismissed as ‘de minimis.’” They asked instead that the administration examine how the potential for serious drought across the region could “exacerbate the environmental costs of an oil spill.”

North Dakota's oil industry a 'sleeping giant' as production plateaus -Oil production in North Dakota has plateaued. "I would have to characterize the Bakken at this point as a sleeping giant," State Mineral Resources Director Lynn Helms said Friday. "The COVID pandemic kind of put the industry to sleep, and it's struggling somewhat to wake up." North Dakota's oil output from May to June was dead flat at 1.128 million barrels per day both months. Oil production data lags several months, and June figures were released Friday. The state's oil production all year has hovered around the 1.1 million barrel-per-day mark. It's recovered somewhat from last summer's lows amid the coronavirus pandemic, but it's far from the record 1.5 million barrels per day produced in late 2019. North Dakota's natural gas production also is holding steady. June saw 2.983 billion cubic feet of gas per day produced. The oil and gas industry captured 92% of that gas, burning off the rest in flares. The state as a whole is meeting its 91% gas capture target, but regulators are forcing two companies operating on the Fort Berthold Indian Reservation to curtail their production because they cannot meet flaring expectations, Helms said. Gas production is expected to grow, and the state will need to have more pipelines and processing facilities in place within the next two years if it's to continue to keep flaring down, officials say. "It's not going to be an easy feat," North Dakota Pipeline Authority Director Justin Kringstad said. "Things will have to get moving relatively briskly to meet those time frames." Oil production will likely rise more next year, Helms said. Slowly, companies are adding back rigs in North Dakota, as well as crews needed to frack newly drilled wells so that they can start producing oil. Two rigs recently began drilling on the Montana side of the Bakken, which hasn't seen any rigs all year, according to North Dakota officials. One unknown could affect North Dakota's production going forward: How OPEC and Russia respond to calls from the White House to boost oil production. Helms said the state's production could stay flat or drop somewhat if those countries significantly ramp up activity in their oil fields.

Comstock Resources offering U.S. shale oil and gas assets, document shows - Dallas Cowboys owner Jerry Jones’ Comstock Resources oil company is offering to sell properties in North Dakota’s Bakken oilfield, a marketing document seen by Reuters shows, as rising energy prices lift buying and selling in the sector. Crude oil prices are up about 38% year-to-date as economies bounce back and fuel demand recovers from travel restrictions to curb the pandemic. U.S. shale oil companies also are seeking larger scale to drive returns and operational efficiency. A representative for Comstock did not immediately respond to a request for comment. The properties on offer include a non-operated working interest in 436 wellbores. The holdings are valued at about $200 million based on futures pricing, according to the document. The 427 actively producing wells in the portfolio most recently had a six-month average net production of 6,400 barrels of oil equivalent per day, the teaser said. The value of second-quarter deals this year hit $33 billion for more than 40 deals – the highest quarterly value since the second quarter of 2019, consultancy Enverus found. Comstock’s decision to offload its Bakken assets comes as deal activity is rising in the Haynesville shale in Louisiana, where it produces most of its energy. Louisiana rivals Southwestern Energy recently bought Indigo Natural Resources and Chesapeake Energy’s acquired Vine Energy. “High oil prices and a resurgence in Bakken M&A activity may have led to the company’s decision to market its non-operated interests to help fund participation in Haynesville consolidation,”

One-Two Punch Hits ExxonMobil Trucking Plan - - A one-two punch that very few people saw coming is now posing sudden, unexpected, and potentially unanswerable questions about the viability of ExxonMobil’s proposal to transport up to 70 truckloads of crude from its Las Flores Canyon facility on the Gaviota Coast to Phillips 66’s Santa Maria Pump Station outside of Santa Maria. Early the Thursday morning of August 13, Phillips announced its intention to shut down its oil refining operations at the company’s Rodeo refinery located outside San Francisco — the ultimate destination for ExxonMobil’s Las Flores crude — and repurpose that industrial facility into a refinery for fats, greases, soybean oils, and other renewable energy sources. According to a Phillips press release, the company hopes that production can begin as soon as 2024. The same statement reported the company’s intention to shut down the Santa Maria transfer facility, where the Las Flores crude was to have been transferred from trucks into Phillips’s Line 300 pipeline to the Rodeo facility. The Santa Maria facility is scheduled to be shut down in 2023. Errin Briggs, the chief energy planner for the County of Santa Barbara, said Phillips’s decision “pulled the carpet out from underneath us,” referring to both the County Energy Division and ExxonMobil. As to how much warning ExxonMobil got, he added, “No warning.” Phillips 66’s decision goes beyond ExxonMobil. When asked to assess how many other operators along the Gaviota Coast would be affected, Briggs said, “Pretty much every single one of them.” He said the Phillips facility in Santa Maria offers two modes of entry into the pipeline heading north to the Rodeo plant. First, it allows oil trucks to offload into the pipeline, and secondly, it offers oil operators a direct portal into the pipeline itself. He said three oil companies — Freeport-McMoRan, PCEC, and a Sentinel — will find themselves forced to find new accommodations for their oil. The quantity of oil affected is significant; it could be in the ballpark of many thousands barrels a day.

California Building Temporary Gas Plants --- California, a state that has been aggressively weaning its power grid off of fossil fuels, is now working on adding several natural gas-fired plants in an effort to keep the lights on this summer. The California Department of Water Resources is in the process of procuring five temporary gas-fueled generators that have individual capacities of 30 megawatts, said spokesman Ryan Endean. The units will be installed at existing power plants and are expected to be operating by the middle of September. The move comes after California Governor Gavin Newsom declared a state of emergency for the power grid on concern about supply shortages during hot summer evenings when solar production wanes. The order, issued last month, aimed to free up energy supplies and speed up power plant development to help avert blackouts. It also temporarily lifted air-quality rules. Earlier this year, California regulators balked at ordering utilities to add new gas-fired generation after environmental groups said it would run counter to the state’s decarbonization goals. Officials have been scrambling to shore up power resources ever since brief blackouts hit in August 2020 during an extreme heat wave. The situation has become more dire this summer as a historic drought has reduced California’s hydroelectric supplies. The state has been retiring gas plants under a goal to have its grid carbon-neutral by 2045. The California Energy Commission approved on Tuesday licenses for the emergency gas generators for up to five years. “Governor Newsom’s emergency proclamation makes it very clear that all of our energy agencies have to act immediately to achieve energy stability during this emergency as well as accelerating plans for construction, procurement and rapid deployment of new clean-energy and storage projects,” Commissioner Karen Douglas said at the meeting.

How the gas industry got its way at L.A., Long Beach ports - Los Angeles Times -- Diesel truck pollution from the busiest port complex in the United States has fouled the air in nearby neighborhoods in Southern California for decades. So when port officials asked for feedback on cleaning up that pollution, hundreds of people weighed in. Los Angeles and Long Beach officials hoped residents would help them decide whether to require zero-pollution electric trucks or instead promote vehicles powered by natural gas, a fossil fuel. What officials didn’t know was that some of the locals who urged support for natural gas trucks were being paid by a firm hired by the natural gas industry. A joint investigation by The Times and the news outlet Floodlight in partnership with the Guardian found that in 2017 at least 20 locals were organized by Method Campaign Services to push for “near-zero-emission” trucks at the ports. Their comments at public meetings and press conferences bolstered successful industry lobbying for trucks that run on natural gas, which is less polluting than diesel but still contributes to lung-damaging emissions and climate change. San Pedro resident Sholeh Bousheri, who was hired by Method to speak at public hearings, was one of several paid campaigners who said they only learned later that their work was part of a natural gas industry effort. Bousheri said Method led her to believe she’d be “standing up for sustainability” as part of an environmental campaign. She said she pieced together the gas industry’s role when she was paid to hand out pamphlets featuring the logo of Southern California Gas Co., the nation’s largest gas utility. “It didn’t make me feel comfortable. I took a whole ethical step back,” she said. “I was like, ‘Wait, what’s going on?’ Is this something I want to support with you? Is it moral?” Method was being paid at the time by Clean Energy Fuels Corp., which owns natural gas fueling stations and like Southern California Gas has resisted the state’s transition away from fossil fuel infrastructure. Clean Energy paid at least $10,000 to Method in 2017, according to financial disclosures.The total amount spent is unclear, because California only requires public officials to list sources of income of $10,000 or more, not how much money they received. The financial disclosures were filed by Method founder Brian VanRiper’s spouse, Samantha Millman, a member of L.A.’s City Planning Commission. VanRiper declined to answer detailed questions about his firm’s work, saying in an email that it would be “inappropriate for me to discuss any client’s strategy” and directing questions to Clean Energy Fuels.

Big Oil's bid to lure back investors with cash could ultimately fail — The world's largest oil and gas majors are seeking to lure back investors by returning more cash to shareholders. Market participants, particularly those looking to the long term, remain highly skeptical. It comes at a time when oil and gas companies are raking in their highest profits since the onset of the coronavirus pandemic amid a sustained period of stronger commodity prices. A robust showing in the three months through June built on better-than-expected first-quarter earnings and lent further support to the industry's efforts to pay down debt and reward investors. In the U.S., ExxonMobil said late last month that it would back shareholder returns through its dividend and Chevron announced it would resume share buybacks at an annual rate of between $2 billion to $3 billion. In Europe, meanwhile, the U.K.'s BP, France's TotalEnergies, Norway's Equinor, Italy's Eni and Anglo-Dutch oil giant Royal Dutch Shell all announced share buyback programs or increased dividend payouts — or both. It reflects a broader industry trend of energy majors seeking to reassure investors that they have gained a more stable footing amid the ongoing Covid-19 crisis. Share buybacks are designed to boost the firm's stock price, benefiting shareholders. Dividend payments, meanwhile, reflect a token reward to shareholders for their investment. Both are options available to a company seeking to reward investors. These investments are likely to become stranded assets, and investors don't want to be left holding the bag. Ahead of the second-quarter results, energy analysts had warned that Big Oil still faced a host of uncertainties and challenges. Some of these include the remarkable success of shareholder activism in recent months, a "tremendous degree" of ongoing investor skepticism and intensifying pressure to massively reduce fossil fuel use. "Day traders may reap short-term profits, but serious long-term investors have concluded that the old energy of the past — oil and gas extraction, is just that — old, with a sell-by date that is moving closer by the day," Kathy Hipple, finance professor at Bard College in New York, told CNBC via email. "Once institutional investors determine that demand has peaked — which likely has already happened — they will abandon the sector permanently," she added. "Many already have, based on the stock performance of the sector over the past several years."

Energy lenders optimistic about demand but braced for setbacks - Energy lenders are hopeful that the recovery in the oil and gas sector will translate into loan growth, but they’re keeping reserves at elevated levels in case the delta variant once again slows the economy.With fuel consumption on the rise this summer alongside a stronger global economy and increasing travel, oil prices are up about 25% in 2021. Natural gas prices have risen even more — about 60% since the start of the year, according to CME Group — amid scorching summer heat and strong demand for the fuel to power air conditioners in some regions of the country.That's in stark contrast in 2020, when governments around the world limited travel and commerce, choking off demand for oil and curbing businesses’ use of gas. The turnaround this year emboldened bankers to predict increased drilling this fall on top of a recent bump this summer.

Federal judge vacates U.S. approval of ConocoPhillips Alaska drilling project - (Reuters) - A federal judge has thrown out the U.S. government's approval of ConocoPhillips' COP.N Willow oil development in Alaska, according to court documents. In her order, Alaska District Court Judge Sharon Gleason said she was vacating the U.S. Bureau of Land Management's approval of the development in part because the agency failed to include greenhouse gas emissions from foreign oil consumption in its environmental analysis.The order also said the U.S. Fish and Wildlife Service failed to outline specific measures to mitigate the project's impact on polar bears. The Interior Department, which oversees the Bureau of Land Management and Fish and Wildlife Service, would not comment on the ruling.

Federal judge reverses Trump environmental approval for major Alaska oil project - Alaska Public Media --A federal judge has reversed the Trump administration’s environmental approval for ConocoPhillips’ multibillion-dollar proposed Willow development on Alaska’s North Slope, throwing a significant roadblock in front of a project seen by analysts as a needed boost to the state’s flagging oil industry and tax revenue. U.S. District Court Judge Sharon Gleason, in a 110-page ruling on two related lawsuits Wednesday, said the Trump administration’s approval of the project under the National Environmental Policy Act was flawed because it failed to thoroughly analyze potential greenhouse gas pollution, and didn’t sufficiently consider legal protections for Teshekpuk Lake, an important subsistence area on the North Slope.The ruling by Gleason, an appointee of former President Barack Obama, sets aside the project’s approval by the Bureau of Land Management. It also vacates a formal opinion by the U.S. Fish and Wildlife Service that said the project was unlikely to jeopardize polar bears’ continued existence and unlikely to harm their critical habitat.The decision, released Wednesday afternoon, quickly reverberated around Alaska’s political and oil industry circles. In a reflection of Willow’s broad significance, ConocoPhillips, Gov. Mike Dunleavy’s administration and the North Slope Borough had all intervened in the litigation in defense of the federal agencies being sued by nine separate environmental groups.Other major potential Alaska oil developments have endured recent political and financial setbacks: The Biden administration has halted development in the Arctic National Wildlife Refuge, a state government-sponsored LNG pipeline has stalled and another major project on the North Slope, Pikka, is in limbo amid the acquisition of its owner.Willow, located in the National Petroleum Reserve-Alaska, was the “one bright spot in what was otherwise a gloomy world,” said Brad Keithley, a retired Alaska oil and gas attorney and state budget watchdog who tweeted a news story about Gleason’s ruling alongside a “scream” emoji.The project, Keithley noted, has the potential to employ many Alaskans, and federal projections indicate that it could generate as much as $13 billion in taxes and royalties for state government.

Alaska Ruling Shows Big Oil's Uphill Battle - Even the climate-conscious Biden administration supported ConocoPhillips’s $6 billion oil development on Alaska’s Northern Slope, but that couldn’t stop a judge from throwing it in limbo on environmental grounds. U.S. District Judge Sharon Gleason’s decision to rescind the Trump administration’s approval of the project is a “surprise” given that in May the current government defended the project in court, RBC Capital Markets analyst Scott Hanold said in a note Thursday. The setback for ConocoPhillips highlights how difficult it’s become for Western oil producers to seek growth in a world gripped by an unprecedented wave of heat, droughts, floods and wildfires blamed on man-made climate change. Investors, governments, lawmakers and courts are increasingly embracing concerns that in the past had been more typical of environmental activists. In the U.S., oil production has dropped about 13% from a record high of 13.1 million barrels a day before the pandemic, and has only shown signs of slow growth even as demand for crude and prices have come roaring back this year. The federal judge’s ruling comes just days after President Joe Biden called for OPEC to boost crude supplies to keep a lid on oil prices that are making gasoline more expensive for Americans and stoking inflation. Biden’s plea -- recognizing that the long-term clean energy push doesn’t preclude the immediate need for cheap fuel -- triggered speculation the administration may be softer on the oil industry than many had expected. Pro-oil advocates have criticized the government for limiting domestic production for environmental reasons while calling for more supplies from the Middle East and Russia. Just this week, Chevron Corp. Chief Executive Officer Mike Wirth called for “an increase in engagement” from the White House on oil and gas in order to boost U.S. energy security and the economy. But the global race to avert climate disaster is gaining momentum beyond any government’s position. Court battles have long challenged pipeline projects regardless of the White House incumbent. And shareholders have tamed shale’s once insatiable thirst for growth, mostly because of concerns over their balance sheets, but also due to pressure for more environmentally responsible investments. Judge Gleason said Willow’s prior approval failed to adequately protect polar bears and didn’t properly consider the effects on climate change. “We think this ruling greatly increases the likelihood for ConocoPhillips’s Willow project to be materially delayed or permanently shelved,”

Georgian NGOs express concern over oil spill off Russia's Black Sea coast - Democracy & Freedom Watch - Eastern Partnership Civil Society Forum Georgian National Platform, a coalition of more than 200 non-governmental organizations, expresses concern over an oil spill off Russia’s Black Sea coast and calls on the Georgian government to take appropriate measures to prevent the spill from causing major environmental destruction and threatening the Georgian coastline.In the statement issued Wednesday, the GNP says that the Russian government is hiding the true extent of the damage to the environment.“It is disturbing that the Russian Federation continues efforts to hide information. As it turned out later, the spill occurred at the terminal that belongs to the Caspian Pipeline Consortium (CPC) during the loading of a Greek tanker. The contractor at the Black Sea port is Transneft Service, a subsidiary of state-owned Transneft,“ the statement reads.“We call on the Ministry of Foreign Affairs of Georgia and the Ministry of Environmental Protection and Agriculture of Georgia to take control of the issue. It is crucial to use all international tools (under the Convention and the Agreement) to force the Russian Federation to provide transparent and accurate information to the Black Sea countries. It is noteworthy that in the event the oil spill spreads widely, first of all, the waters along Abkhazia will be endangered.“The Russian authorities should also be urged to implement relevant activities to prevent potential environmental disasters that may be caused by disorganized systems and increased oil production.,” the GNP states.The leak occurred in early August six kilometers off the coast of Novorossiysk, a Russian port on the Black Sea. The oil was released during refueling of a Greek tanker. The consortium responsible for the leak initially claimed the area of contamination was only two hundred square meters, about the size of a tennis court. But three days after the leak, the Space Research Institute of the Russian Academy of Sciences said a large oil slick with an area about 85 square kilometers – about the size of Manhattan – was seen in satellite images in the sea near Novorossiysk.

Surface Water Vulnerable to Widespread Pollution From Fracking, a New Study Finds - Fossil fuels don’t just damage the planet by emitting climate-warming greenhouse gases when they are burned. Extracting coal, oil and gas has a huge impact on the surface of the earth, including strip mines the size of cities and offshore oil spills that pollute country-sized swaths of ocean. Years of research has shown how the fracking boom has contaminated groundwater in some areas. But a study published on Thursday in the journal Science suggests there is also a previously undocumented risk to surface water in streams, rivers and lakes.After analyzing 11 years of data, including surface water measurements in 408 watersheds and information about more than 40,000 fracking wells, the researchers found a very small but consistent increase in three salt compounds—barium, chloride and strontium—in watersheds with new wells that were fracked. While concentrations of the three elements were elevated, they remained below the levels considered harmful by the EPA. Such salts are commonly found in water coming from newly fracked wells, making changes in their levels good markers for fracking impacts on surface water, said co-author Christian Leuz, professor of international economics at the University of Chicago. The three economists who did the research specialize in studying the effectiveness of environmental regulations.Though the impact the researchers detected was small, the data came from diluted water in rivers and streams that were often far from wells, Leuz said, so the concentrations could be higher farther upstream and closer to the fracking operations. The findings suggest that the rapid pace of “unconventional oil and gas development,” like fracking, may be outrunning scientists’ ability to monitor its impacts on surface water. “Better and more frequent water measurement is needed to fully understand the surface water impact of unconventional oil and gas development,” As the United States seeks to dial back fossil fuel use, accurate environmental data is important for policy discussions about topics like carbon pricing, as analysts try to present a full accounting of how much fossil fuels cost, said co-author Giovanna Michelon, who researches sustainability accounting at the University of Bristol.The study, she said, was started to determine if regulations requiring companies to disclose the contents of their fracking fluids had an impact on water quality during the fracking boom, when tens of thousands of wells were drilled in Pennsylvania and New York, and through a vast swath of the West, from Oklahoma and Texas through New Mexico, Colorado, Utah, Wyoming, Montana and North Dakota.

DGH overhauls approval processes for oil, gas fields -A self-certified declaration of a commercial oil or gas discovery is all that is now needed by a company to get statutory recognition for a hydrocarbon find after the upstream regulator DGH overhauled approval processes. Following up on its announcement of last month, Directorate General of Hydrocarbons (DGH) released 'Guidance Document' for online submission of various documents. "This document is prepared to guide the E&P (oil and gas exploration and production) contractors for submission of Production Sharing Contract (PSC)," DGH said. It allows self-certified documents for requirements like bank guarantee to the appointment of auditor and relinquishing an area or a commercial oil and gas discovery is made. It limits the requirement of statutory approvals to only extension of contracts, sale of stake and annual accounts. DGH, the government's technical arm overseeing upstream oil and gas production, said procedures and processes for oil and gas blocks awarded under nine bids round of New Exploration Licensing Policy (NELP) and pre-NELP blocks are being simplified and standardised. While state-owned Oil and Natural Gas Corporation (ONGC) and Oil India Ltd (OIL) produce two-third of India's oil and gas from blocks or areas given to them on a nomination basis, the remaining output is from pre-NELP and NELP blocks.The pre-NELP blocks include Panna/Mukta and Tapti oil and gas fields in western offshore and Ravva field in the KG basin. But the biggest of oil and gas discoveries outside of the nomination acreage have happened in the blocks awarded under NELP since 2000. These include Reliance Industries Ltd's eastern offshore KG-D6 block and NEC-25. ONGC too has significant finds in NELP blocks. As many as 37 processes and procedures were required to be followed by a firm exploring oil and gas in a block awarded under NELP or pre-NELP rounds. These have now been cut to just 18, according to DGH.

Shell declares force majeure on Nigerian Forcados crude loadings | S&P Global Platts - Loadings of Nigeria's key crude grade Forcados are on force majeure due to some operational issues at the export terminal, Shell said Aug. 16. Force majeure was declared effective Aug. 13 due to "the curtailment of production and suspension of export operations as a result of some sheen noticed on the water around the loading buoy," Shell Petroleum Development Company of Nigeria Ltd. said in a statement. Forcados is a gasoil-rich sweet crude blend and is one of Nigeria's top export grades. Output has averaged around 200,000 b/d over recent months compared to its full capacity of 250,000 b/d. Nigeria oil output has been hampered by operational and technical problems in the past few months. Key crudes such as Bonny Light, Escravos, Forcados, Qua Iboe have all faced production issues due to operational and technical reasons. Forcados, which relies heavily on oil pipelines, has also faced persistent sabotage in the past few months. S&P Global Platts Analytics expects Nigeria to be one of the largest risks for OPEC+ production growth in end-2021. "We forecast August crude supply to average 1.36 million b/d down from 1.48 million b/d in July and 1.66 million b/d as recently as February," it said in a recent note. "Our outlook for growth to 1.75 million b/d by December faces notable uncertainty, even without rising risks of coordinated attacks on oil infrastructure." Growing threats by militants to renew attacks on oil infrastructure in the restive Niger Delta also pose a huge concern for Africa's largest oil producer. Nigeria has the capacity to produce around 2.2 million-2.3 million b/d of crude and condensate, but production has averaged only around 1.62 million b/d in the first seven months of 2021, according to Platts estimates.

Shell Loses Nigeria Oil License to NNPC - - Royal Dutch Shell Plc’s Nigerian venture lost the right to operate an oil site after a court ruled the company wasn’t entitled to renew a lease first granted in 1989. On Monday, the court of appeals in Nigeria’s capital, Abuja, overturned a 2019 ruling that granted Shell Petroleum Development Co. the right to renew its operating license for the Oil Mineral Lease 11 field. Those rights will transfer to the state-owned Nigerian National Petroleum Corp. “This is a huge victory for the government and people of Nigeria as we now have the impetus to responsibly unlock the oil and gas reserves the block offers for the benefit of all Nigerians,” Mele Kyari, managing director of NNPC, said in a statement. Shell was “disappointed” by the judgment and subsequently filed an appeal, a spokesperson for the company said in a statement. “Though we believe the SPDC JV has fulfilled its obligations under the Petroleum Act for the renewal of OML 11, our preference remains to engage the Nigerian authorities on available options for an amicable resolution of issues around the lease,” the spokesperson said. The decision comes just as Shell agreed to pay a local community $111 million in a decades-old oil spill dispute related to OML 11. Shell faces lawsuits from Nigeria to Europe claiming environmental damages in the Niger Delta. At the same time, the energy giant says it’s in the process of exiting its onshore oil position in Nigeria because that no longer is compatible with the company’s long-term climate strategy. Shell has pumped oil in Nigeria for half a century. Kyari said further legal action by Shell would be “futile” given the company’s “inability to work on the Ogoni region of the block for over 30 years.” An NNPC subsidiary already has taken over the assets, and operations “are in full gear,” according to its statement.

Exxon’s oil drilling gamble off Guyana coast ‘poses major environmental risk’ ExxonMobil’s huge new Guyana project faces charges of a disregard for safety from experts who claim the company has failed to adequately prepare for possible disaster, the Guardian and Floodlight have found.Exxon has been extracting oil from Liza 1, an ultra-deepwater drilling operation, since 2019 – part of an expansive project spanning more than 6m acres off the coast of Guyana that includes 17 additional prospects in the exploration and preparatory phases.By 2025, the company expects to produce 800,000 barrels of oil a day, surpassing estimates for its entire oil and natural gas production in the south-western US Permian basin by 100,000 barrels that year. Guyana would then represent Exxon’s largest single source of fossil fuel production anywhere in the world.But experts claim that Exxon in Guyana appears to be taking advantage of an unprepared government in one of the lowest-income nations in South America, allowing the company to skirt necessary oversight. Worse, they also believe the company’s safety plans are inadequate and dangerous.A top engineer who studies oil industry disasters, as well as a former government regulator, have leveled criticisms at Exxon. They say workers’ lives, public health and Guyana’s oceans and fisheries – which locals rely on heavily– are all at stake. Exxon claims its climate goals are “some of the most aggressive” in the industry, but its operations in Guyana will send more than 2bn metric tons of climate-destroying CO2 into the atmosphere “Exxon is only going to be here for 20 to 25 years,” said Vincent Adams, Guyana’s former environment chief. “When they make all their billions, and they’re ready to pack up and they’re gone, we’ve got to deal with the mess.”

ExxonMobil plans to start gas drilling by end of year -ExxonMobil and Qatar Petroleum plan on drilling for gas in an offshore block towards the end of the year, Energy Minister Natasa Pilidou has said. In an interview with daily Politis, the minister said the two companies planned on drilling an appraisal well in block 10 where natural gas was discovered towards the end of November or early December. “The experts who will take part in the appraisal drill at the Glaucus [Glafcos] well are already in our country and we are in constant contact with the company concerning the procedures that will be followed, both as regards measures against the pandemic, and the plan, the budget, timeframes, etc,” Pilidou said. Based on preliminary interpretation of the well data, the discovery could represent an in-place natural gas resource of approximately 142 billion to 227bn cubic metres, the company said in 2019. Glaucus-1 was the second of a two-well drilling programme in block 10. The first well, Delphyne-1, did not encounter commercial quantities of hydrocarbons. Block 10 is 2,572 square kilometres and ExxonMobil holds 60 per cent interest with Qatar Petroleum owning 40 per cent. Pilidou said the government also expected ENI-Total to start drilling early in 2022. France’s Total and Italy’s ENI are the biggest players in Cyprus’ energy search, holding exploration licences for seven of the 13 blocks. Korea’s Kogas is also a partner in three of those concessions. ENI-Total had notified the government last year that they were postponing their scheduled gas drilling operations for around a year because of the Covid pandemic. Eni and Total had been scheduled to start drilling in block 6 and two other blocks. In February 2018, the companies announced a gas discovery in the Calypso 1 well located in block 6 which was described as “a promising discovery and detailed sampling on fluids and rocks has confirmed that the Zohr (Egypt) play extends into the exclusive economic waters of Cyprus”.

Oil Drilling Activity To Jump In Guyana, Suriname - Guyana and Suriname, the new stars on the oil map, are expecting more exploration drilling over the next two years after a string of discoveries revealed the potential of the Guyana-Suriname Basin.Reuters reports that the two small South American countries attracted the most attention at the recent Offshore Technology Conference in Houston this week, eclipsing even the Gulf of Mexico.Upstream Online reported this week the Guyana-Suriname Basin could see 10 drilling rigs in 2022 as exploration in the area accelerates. Exxon already has six drillships in Guyana waters, and TotalEnergies has deployed two in Suriname waters. The report notes that 15 companies in total hold drilling rights to acreage in the basin.“We have unlocked more than 9 billion barrels of oil equivalent in Guyana, and it appears TotalEnergies has discovered another 2 billion boe in Suriname,” Tim Chisholm, exploration VP at Hess, Exxon’s partner in Guyana, said at the Offshore Technology Conference, as quoted by Upstream.TotalEnergies, which partners with Apache Corp., has made five significant discoveries since last year and is planning to deploy a floating production storage and offloading vessel in Suriname later this decade.Guyana expects its oil production from already made discoveries in the Stabroek Block, operated by Exxon and Hess, to reach close to 1 million bpd by 2025 or 2026, the country’s natural resources minister, Vickram Bharrat, told Reuters. That would be up from 125,000 bpd at the moment.This production comes from the Liza well drilled by Exxon and Hess but will next year rise to 220,000 bpd with the addition of a second FPSO on the site. With oil prospects so bright, Guyana’s government is seeking better royalties and other contract terms, Reuters reported earlier this week. The country plans to form an energy regulator by the end of this year and complete the revision of its production-sharing agreement that will apply to future partners.

NYK Sends Team to Clean Up Crimson Polaris Oil Spill -- NYK, charterer of the Crimson Polaris, says it will send a team to assist with the clean-up of an oil spill that has resulted from the wreck.As we have reported, the dedicated wood chip carrier Crimson Polaris broke up after briefly running aground in heavy weather off the coast of Port of Hachinohe back on August 11. The ship was reported to be carrying 1,550 metric tons of heavy fuel oil and about 130 metric of diesel oil at the time of the accident. It’s unclear how much oil has spilled.NYK said previously the crack in the hull initially occurred between the No. 5 cargo hold and the No. 6 cargo hold. The bow is floating and held by an anchor. The stern, which was believed to be aground, has since rolled over.An update from NYK on Wednesday said the company has now dispatched 10 employees to perform cleaning work of oil and cargo that has washed ashore.“From the standpoint of being involved in this accident as a charterer, we have decided to first recruit workers to clean the cargo washed ashore on the beach and dispatch them to the site,” NYK said in an update, translated using Google. “The number of people in the first team will be 10, and we plan to dispatch them for one night and two days, and then continue to dispatch the second and third teams.”The wreck is located about 4 kilometers offshore Hachinohe, on the northeast coast of Japan’s Honshu island.All crew members were rescued from the vessel prior to the ship breaking up.NYK said earlier that salvors were considering a plan to tow the separated hull to an unspecified location, but environmental protection was the priority. It’s not clear if those plans remain in place or have changed.

Production Slumps By 40% At India’s Biggest Oil, Gas Deposit - Oil and gas production from India’s northwestern state of Rajasthan—home to the country’s single biggest oil and gas deposit—has slumped by 40 percent over the past two years, mostly due to the pandemic and its effect on oil demand and prices, officials told Hindustan Times on Friday.Alongside with lower production of oil and gas, the state of Rajasthan saw its revenues from hydrocarbon production decline last year.The area around Barmer is the biggest source of domestic oil and natural gas for India after crude oil and coal were discovered there in 2004.Despite the COVID-induced slump, Indian companies haven’t given up on investment in new production in the Barmer area. State-controlled Oil India, for example, will be investing in oil and natural gas exploration, an official told Hindustan Times. “And upon commencement of production, the state will generate revenue at the rate of 12.5% on mineral oil and 10% on natural gas production,” the official added.Meanwhile, India’s fuel demand is recovering from the COVID wave in the spring, and as of mid-August, it was holding up despite the gloomier demand picture in the rest of Asia.India’s fuel consumption recovery was a rare bright data point in the first half of August, while China, Japan, and Southeast Asia are struggling to contain a COVID resurgence with lockdowns and emergency measures that threaten to reduce immediate refined product demand. India’s gasoline sales rose by 3.7 percent in the first two weeks of August compared to the same period of the pre-pandemic 2019, Bloomberg reported on Tuesday, citing preliminary data from the three largest fuel retailers in the country. Sales of diesel—the most used fuel in India—were down by 8 percent compared to 2019, but still higher than in July 2021, when diesel consumption had declined by 11 percent, according to the data obtained by Bloomberg.

Oman close to finishing Ras Markaz oil storage center outside Strait of Hormuz: report - Oman is putting the finishing touches on an crude storage center outside the Strait of Hormuz, the Duqm Special Economic Zone said in a Aug. 15 tweet, that can eventually hold more than 200 million barrels as the Gulf state seeks to attract international oil companies to park their cargoes in the country. Ras Markaz Oil Storage Park will have an initial capacity to hold 25 million barrels starting in Q1 2022, Salim al Hashmi, project general manager at developer Oman Tank Terminal Co., told the zone's Duqm Economist Magazine in its quarterly issue published in July. Ras Markaz Oil Storage Park will receive oil by sea through ships that will pump oil to the facility through pipelines extending to 7 km at sea and 3.5 km on land and in the future the facility may be connected to Oman's oil fields, Ard Van Hoof, CEO of Oman Tank Terminal Co., told the magazine. Oman currently exports its crude via the Mina al Fahal terminal in the Persian Gulf, but having a second export facility at Ras Markaz can help the country deal with surplus production, according to the article The storage park also can be a source of oil from Duqm refinery, which is connected to the facility with an 80-km long pipeline and eight tanks built to store the refinery's oil, the article added. The 230,000 b/d Duqm refinery is a is a 50-50 joint venture owned by Oman's OQ and Kuwait Petroleum International (Q8), called Duqm Refinery and Petrochemical Industries Co. (OQ8). The refinery has been under construction since 2018, and is expected to start up in 2022. Once operational, Duqm refinery will receive 65% of its crude volume from Kuwait, and the remaining 35% will be Omani crude, with both grades stored at Ras Markaz. The Duqm special economic zone and port is the site of several energy infrastructure projects under development and construction. Plans to build a pipeline network, bunker terminal facility and petrochemicals plant at Duqm are also underway.

Iran’s oil output falls to 40-year low in 2020 – Iran’s crude oil production fell to the lowest in 40 years, according to an updated analysis by the U.S. Energy Information Administration. At less than 2 million bpd, the EIA said the country’s oil output was affected by both the pandemic, which decimated demand for oil, and U.S. sanctions targeting specifically the Iranian oil industry. Before the U.S. withdrawal from the Iran nuclear deal and the snap-back of sanctions, Iran was pumping around 2.6 million barrels daily and exporting some 2.5 million bpd, the EIA also said. Still, at less than one million bpd, the decline in production is a far cry from the Trump administration’s target of bringing Iran’s oil output and exports to zero to force Tehran to return to the nuclear negotiating table. Speaking of the nuclear negotiations, a report by the Financial Times had suggested that not all hope was lost for a deal. Citing Iranian sources, the daily reported that Tehran’s new top diplomat, despite being a hardliner and openly distrustful of the West, could end up clinching the deal his predecessor couldn’t. “Under Amirabdollahian, we will not see more radicalism, rather more co-ordination between the diplomatic and military fields,” once source told the FT. “You no longer have the kind of friction between the government and the deep states that proved to be a serious impediment for his predecessor’s initiatives,” explained another. Tehran also named the new oil minister last week: Javad Owji, a former deputy to outgoing Bijan Zanganeh and a senior executive in state-owned energy firms. As Zanganeh said last month, his successor’s main job would be to boost oil exports. The outgoing minister said recently that Iran had lost some $120 billion in oil revenues from U.S. sanctions, taking an export hit of 2 billion barrels since the United States withdrew from the nuclear deal.

Iran’s Huge Caspian Gas Find Is A Geopolitical Gamechanger - Iran last week revealed a huge new gas deposit located in the Iranian sector of the Caspian Sea. The ‘Chalous’ structure is to be developed with the intention of forming a new gas hub in northern Iran to complement the southern gas hub centred on the massive South Pars field.The principal named developer of the Chalous site is Iran’s Khazar Exploration and Production Company (KEPCO) but technical and financial assistance will also come from Russia and China. If the initial estimates of the gas reserves held in the Chalous deposit are correct then Iranian gas will be able to supply at least 20 percent of Europe’s gas needs. However, the size, price, and destination of this gas will be co-ordinated with Russia, adding to the energy power that Moscow has over Europe, already a key matter of contention between Europe and its NATO partner, the U.S. According to KEPCO’s chief executive officer, Ali Osouli, the Chalous structure is estimated to hold gas reserves equivalent to a quarter of the supergiant South Pars gas field, or around 11 of its phases. South Pars has an estimated 14.2 trillion cubic metres (Tcm) of gas reserves in place plus 18 billion barrels of gas condensate and already accounts for around 40 percent of Iran’s total estimated 33.8 tcm of gas reserves and about 80 percent of its gas production. The 3,700-square kilometre (sq.km) South Pars site is part of the 9,700-square km basin shared with Qatar (in the form of the 6,000-square km North Dome) but the Chalous structure lies squarely within Iran’s sector of the Caspian Sea. This has not so far been affected by the recent disputes between the five littoral states that share oil, gas, and other rights in it: Russia, Iran, Kazakhstan, Turkmenistan and Azerbaijan.These disputes – exclusively covered and analysed by OilPrice.com – centered around the official designation of the Caspian as either a ‘sea’ or a ‘lake’ in early 2019, which was crucial in determining how all of the Caspian’s oil and gas resources would be divided up between the five states. The wider Caspian basins area, including both onshore and offshore fields, is conservatively estimated to have around 48 billion barrels of oil and 292 trillion cubic feet of natural gas in proven and probable reserves. Suffice it to say that, over and above the finer points involved that are covered in the article linked above, Russia contrived to have the Caspian re-designated as a sea, not a lake, which fundamentally altered the previously agreed split of revenues from it among the partners. In this process, Iran’s share was slashed from the 50-50 split with the USSR that it had enjoyed as from the original agreement made in 1921 (on ‘fishing rights’) and amended in 1924 to include ‘any and all resources recovered’ to just 11.875 percent. This meant that Iran will lose at least US$3.2 trillion in revenues from the lost value of energy products across the shared assets of the Caspian Sea resource going forward.The reason why Iran accepted this appalling re-ordering of shares in the spoils of the Caspian Sea was that at the time it was in the throes of negotiating the game-changing 25-year deal with China that included a major corollary deal with Russia. This deal with Russia was a legal necessity to the 25-year agreement with China – allowing for Russian as well as Chinese planes and ships to use the dual-use sites across Iran, for example – and was added into the existing multi-layered 10 year deals that Iran had been signing with Russia to that point. It is apposite to note that Iran’s ambassador to Moscow, Kazem Jalali, said last month that this usual 10-year deal had now been superseded by a 20-year deal with Russia that covers political, security, military, defence and economic cooperation. Given these developments, then, Tehran felt in no position to start playing tough with the Kremlin in the negotiations over its share in the Caspian Sea resource.

Oil Futures Fall as Traders Watch Tropical Storm Fred, China's Data - - Nearby delivery month oil futures on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange retreated early Monday, sending the U.S. crude benchmark as much as 1.5% lower following a trio of weaker-than-expected economic data from China, pointing to a broad-based slowdown in the world's second largest economy, while domestically traders monitor the path of Tropical Storm Fred with expectations for heavy flooding and storm surge along the coast of Florida's Panhandle and Big Bend area to disrupt gasoline demand. At the beginning of the new trading week, oil and equity futures dropped sharply amid signs of an economic slowdown in China, with last month's retail sales, industrial production and fixed asset investment falling far short of expectations. Retail sales, a key measurement of consumer spending in the world's second largest economy, fell 0.13% in July, down from the 0.48% increase in June, and below the projection for 11.5% annualized growth. Industrial production, a gauge of activity in the manufacturing, mining and utilities sectors, grew by 6.4% in July from a year earlier after an 8.3% rise in June. July's figure was below the median forecast for a rise of 7.9%. "Given the combined impact of sporadic local outbreaks of COVID-19 and natural disasters on the economy of some regions, the economic recovery is still unstable and uneven," Faced with growing outbreaks, Chinese health officials tightened restrictions on mobility and businesses in several metropolitan areas, suspending airfare and rail service. Last week, China closed the key port of Ningbo-Zhoushan, the world's largest shipping port by cargo tonnage, after a single case of COVID-19 infection sparked fears of an outbreak. The abrupt closure will further disrupt already strained supply chains, while raising shipping costs to the ports of North America and European Union ahead of the peak holiday season.At the start of July, Goldman Sachs trimmed its forecast for China's growth to 2.3% from 5.8% for the third quarter, while also cutting its full-year forecast to 8.3% from 8.6%.Domestically, Tropical Storm Fred is expected to impact the Gulf of Mexico over the next 48 hours with heavy rains and winds in excess of 50 knots, while also bringing dangerous storm surge along the coast of Florida's Panhandle and Big Bend area. As of Monday morning, most of the schools and all outdoor events across the region have been closed. Fred had been downgraded but regained its tropical storm status Sunday morning over the Gulf of Mexico and is forecast to gradually increase in strength as it tracks through the warm waters of the gulf Monday. The development is bearish for regional gasoline demand, with seasonal decline in consumption seen steeper this year due to the lack of commute to work and rising tally of COVID-19 infections. The U.S. Energy Information Administration forecasts gasoline consumption won't return to pre-pandemic levels even next year, averaging about 9 million barrels per day (bpd), some 300,000 bpd below 2019-levels.

Oil settles lower, pares losses despite weak economic data - (Reuters) -Oil prices settled lower on Monday, paring steep losses on weak Chinese economic data after sources told Reuters that OPEC and its allies believe the markets do not need more oil than they plan to release in the coming months. Brent crude settled down $1.08, or 1.5%, at $69.51 a barrel after earlier falling to $68.14. U.S. oil fell by $1.15, or 1.7%, to $67.29 after reaching lows of $65.73. The market had dropped more than 3% earlier in the session after data showed Chinese factory output and retail sales growth slowed sharply in July, missing expectations, as flooding and fresh outbreaks of COVID-19 disrupted business activity. Crude oil processing in China, the world's biggest oil importer, last month also fell to its lowest level on a daily basis since May 2020 as independent refiners cut production in the face of tighter quotas, elevated inventories and falling profits. However, prices rebounded slightly after sources from OPEC+, which comprises the Organization of the Petroleum Exporting Countries and its allies, said there was no need to release more oil despite U.S. pressure to add supplies to check an oil price rise. OPEC+ agreed in July to boost output by 400,000 barrels per day a month starting in August until its current oil output reductions of 5.8 million bpd are fully phased out. Two of the OPEC+ sources said the latest data from OPEC and from the West’s energy watchdog - the International Energy Agency (IEA) - also indicated there was no need for extra oil. {OPEC/M] The IEA last week said that rising demand for crude oil reversed course in July and was expected to increase at a slower rate over the rest of 2021 because of surging COVID-19 infections from the Delta variant. U.S. oil output from seven major shale formations is expected to rise by about 49,000 barrels per day (bpd) in September, led by growth in the Permian, according to the Energy Information Administration's monthly drilling productivity report on Monday. Money managers reduced their net-long U.S. crude futures and options holdings in the week to Aug. 10, the U.S. Commodity Futures Trading Commission (CFTC) said on Friday. Speculators also cut their futures and options positions in New York and London by 21,777 contracts to 283,601 over the period, the CFTC said. "With COVID cases rising, the demand outlook is looking unclear, so traders are increasingly wary about hedging and locking in prices,"

Oil Futures Soften as China's Slowdown Fuels Growth Worry -- Nearby delivery month oil futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange extended losses into the fourth consecutive session early Tuesday, sending U.S. crude benchmark below $67 per barrel (bbl) on a combination of concerns over slowing global demand growth stemming from sporadic COVID-19 outbreaks in China and elsewhere in southeast Asia that have led to renewed restrictions on mobility and closure or reduced operations at key shipping ports, and signs of decelerating economic growth domestically. China's refinery output in July fell to the lowest since May 2020 at 13.9 million barrels per day (bpd) or 0.9% below the same month last year, according to the data released from the National Bureau of Statistics. That was the first year-on-year decline since March last year when coronavirus hammered Chinese fuel demand. A government crackdown on independent plants, also known as teapot refineries, combined with a growing number of COVID-19 outbreaks in several of China's major industrial hubs led to a sharp decline in refinery output last month. The world's second largest economy also lost steam in the third quarter, with last month's retail sales, industrial production and fixed asset investment falling far short of expectations. Retail sales, a key measurement of consumer spending fell 0.13% in July, down from the 0.48% increase in June, and below a projection for 11.5% annualized growth. Industrial production, a gauge of activity in the manufacturing, mining and utilities sectors, grew by 6.4% in July from a year earlier after an 8.3% rise in June.Domestically, a sharp fall in consumer sentiment this month, joined with slowing manufacturing output and expectations for July's retail sales to fall after several months of strong readings have investors questioning the pace of second half growth as well as the timing of the Federal Reserve's plans to taper its monthly bond purchases. Fed Chairman Jerome Powell could shed some light on that issue during today's virtual Town Hall meeting at 1:30 p.m. ET ahead of central bank's symposium in Jackson Hole, Wyoming, later this month.Oil traders are also monitoring the impact to gasoline demand in Florida and other Atlantic Coast states following flash flooding brought about by Tropical Depression Fred. Tropical Storm Fred made landfall late afternoon Monday and is expected to dissipate in the mid-Atlantic states over the next 24 hours. As Fred was downgraded, however, a tornado watch was issued for much of central and north Georgia on Tuesday.The development is bearish for regional gasoline demand, with seasonal decline in consumption already seen steeper this year due to the lack of commuting to work and the rising tally of COVID-19 infections. The U.S. Energy Information Administration forecasts gasoline consumption won't return to pre-pandemic levels even next year, averaging about 9 million bpd, some 300,000 bpd below the 9.309 million bpd 2019 average.

Oil prices stretch losing streak to a 4th session as demand worries prevail - Oil futures stretched their streak of losses to a fourth session on Tuesday as investors continued to fret over the outlook for demand due to the ongoing spread of the delta variant of the coronavirus that causes COVID-19. "The fundamental outlook for oil is mixed as in the immediate term," analysts at Sevens Report Research wrote in Tuesday's newsletter. Delta fears are weighing on demand expectations but in the medium term, a "global supply deficit is expected to last through year-end." Looking further down the road, sharp increases in 2022 production by the Organization of the Petroleum Exporting Countries and their allies, together known as OPEC+, are "expected to swing the market back into a surplus," the analysts wrote. West Texas Intermediate crude for September delivery lost 70 cents, or 1%, to settle at $66.59 a barrel on the New York Mercantile Exchange. That was the lowest front-month contract finish since Aug. 9, according to Dow Jones Market Data. October Brent crude , the global benchmark, fell 48 cents, or 0.7%, at $69.03 a barrel on ICE Futures Europe, the lowest finish since July 19. New Zealand took drastic action Tuesday, with the government putting the entire nation into a strict lockdown (link) for at least three days after finding a single case of coronavirus infection in the community. The continued spread of the virus is being blamed for renewed congestion at ports in China (link), adding to worries about further lockdowns and the potential for a slowdown in economic activity around the world. Analysts Goldman Sachs believe that the delta variant wave hit to oil demand will remain "transient," with "structural supply underinvestment increasingly clear," according to a research note dated Monday. They expect the oil market deficit to persist through year-end, "eventually requiring a sharp increase in OPEC output and a further rebound in shale activity, which will necessitate higher prices." Oil traders await weekly data on U.S. petroleum supplies from the Energy Information Administration Wednesday morning. On average, analysts expect the government report to show a 3.1 million-barrel decline in domestic crude inventories for the week ended Aug. 13, according to a survey conducted by S&P Global Platts. They also forecast a fall of 2.3 million barrels for gasoline stockpiles and an increase of 700,000 barrels for distillate supplies. On Nymex Tuesday, September gasoline shed 1.6% to $2.17 a gallon and September heating oil lost 0.6% to $2.04 a gallon. September natural gas settled at $3.84 per million British thermal units, down 2.8%, after tacking on 2.2% on Monday.

Oil Extends Longest Losing Streak Since March After Disappointingly Small Crude Draw - Oil prices fell for the fourth day in a row - its longest losing streak since March - as a strong dollar and dismal US economic data following weak China data (combined with the ongoing spread of Delta around the world) prompted growth scares everywhere.“Poor data coming out of China is ground zero for reignited global concern surrounding Covid-19,”says Phil Flynn, senior market analyst at Price Futures Group.“Although indicators in the U.S. shows a better situation than China, as the second largest economy, what happens in the region has huge market impact.”Additionally, U.S. gasoline demand falls for third-straight week, dropping less than 1% to 9.423m b/d in the week ended Aug. 13, Descartes Labs says in survey based on movements of cellular devices.Algos will be desperately hoping for a bullish surprise from tonight's inventory data. API:

• Crude -1.163mm (-3.1mm exp)
• Cushing -1.735mm
• Gasoline -1.1979mm
• Distillates +502k

After the prior week's disappointingly small crude draw, analysts expected a sizable drop in inventories but they weredisappointed once again when API reported a mere 1.163mm draw (vs 3.1mm exp)...

WTI Tumbles Into Red After Surprise Gasoline Build, Production Increase - Oil prices rollercoastered overnight, after a 4-day losing streak (the longest since March), rebounding after a dip following API's reported smaller than expected crude draw, and now fading back into the red ahead of the official inventory data (as early dollar weakness turned to strength).The International Energy Agency last week said it expects oil demand to fall by more than half a million barrels per day in the second half of this year, even as OPEC+ continues with plans to add 400,000 bpd of additional supply monthly as the end of the U.S. driving season approaches, lowering the call for gasoline and raising concern over prices going forward."We doubt that all the negative factors are fully priced in, and think prices had overshot their fundamental values in the past anyway. Thus, the selling pressure is likely to continue for a while yet, and with the potential breakdown of key support levels, we may see increased technical selling activity too. As a result, oil prices could fall more abruptly going forward," Victor Argonov, senior analyst at International Fintech EXANTE, said in a note. Will the official data ignite the momentum for the algos? DOE

• Crude -3.23mm (-3.1mm exp)
• Cushing -980k
• Gasoline +696k
• Distillates -2.697mm

Official inventory data shows a notably bigger than expected crude draw last week (-3.23mm vs API's reported 1.163mm draw), Gasoline stocks rose but Distillates drewdown...US crude production rose modestly last week, but continues to behave itself, despite still high prices and rising rig counts. Still, US crude production is at its highest since May 2020...

Oil slides as COVID-19 surge, firmer dollar overshadow U.S. crude drawdown - Oil prices fell about 1% on Wednesday after four straight days of declines, as investors remain worried about the outlook for fuel demand as COVID-19 cases surge worldwide and on rising strength in the U.S. dollar. Brent crude settled 80 cents, or 1.16%, lower at $68.23 per barrel. U.S. WTI crude oil lost $1.13, or 1.7%, to settle at $65.46 per barrel. The U.S. dollar index was up 0.1%, hitting its highest level since April. Crude prices often move inversely to the dollar because the commodity is priced in dollars; when the U.S. currency rallies, it makes oil more expensive for foreign buyers. Oil markets have experienced several days of weakness due to the rise in infections caused by the Delta variant of the coronavirus both in the United States and worldwide. Several countries have re-introduced travel restrictions and air traffic has softened in recent weeks. The market was helped by a bigger-than-expected drawdown in U.S. crude inventories, which fell 3.2 million barrels last week to 435.5 million barrels, their lowest since January 2020. Gasoline stocks, however, rose modestly, which kept the market from moving up given ongoing worries about coronavirus. "The market is being dragged down on a disappointing gasoline inventory build as we make our way into the Labor Day weekend," said Andy Lipow, president of Lipow Oil Associates in Houston, Texas, referring to the Sept. 6 U.S. holiday. The four-week average of overall U.S. product supplied to the market - a measure of demand - was 20.8 million barrels per day, in line with pre-coronavirus levels from 2019. Gasoline product supplied was 9.5 million bpd, just 1% below 2019 levels. U.S. fuel demand has steadily increased throughout the year as consumers have resumed activities with vaccination rates going up.

WTI, Brent Plunge to 5-Mo Low on Delta Risk, Fed Tapering - Nearby delivery month oil futures on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange fell sharply early Thursday, sending the U.S. crude benchmark below $63 bbl as investors fled to safety on concerns the Federal Reserve would begin tapering its purchase of bonds just as a resurgence in coronavirus infections linked to the spread of highly infections Delta variant looks set to stall a global economic recovery. U.S. Dollar Index jumped to a nine-month high at 93.515 in overnight trading after minutes from July's Federal Open Market Committee meeting released Wednesday afternoon show policymakers are set to start tapering asset purchases within months. The Federal Reserve currently makes $120 billion in monthly purchases of Treasuries and mortgage-backed securities. The minutes also show a split among participants on when to begin the tapering and the appropriate process to do so."Several participants" said aggressive monetary policy was still needed to fix the damage done to the labor market by the pandemic and felt ongoing bond purchases helped that process. "A few" countered that Fed policy had little left to contribute to a process driven by private business and household decisions. "Several" others said the condition of labor markets prior to the pandemic "may not be the right benchmark" given lasting changes to the economy. "No decision regarding future adjustments to asset purchases were made at this meeting," read the minutes. Since FOMC held its last discussion, however, U.S. labor market added 943,000 new jobs in July and the unemployment rate fell to 5.4% -- a new pandemic era low, revealed the Bureau of Labor Statistics Report. It was the biggest job gain since August last year, when more than one million positions were filled. Some economists suggest the torrid pace of employment last month moved the Federal Reserve closer to its goal of rolling back its quantitative easing program. A stronger greenback weighed on all dollar-denominated commodities this morning, making them more expensive to holders of other currencies. NYMEX September West Texas Intermediate futures fell by another 3.8% overnight to under $63 ahead of the contract's expiration Friday afternoon. Next-month delivery October WTI futures narrowed its discount to $0.17. International crude benchmark for October delivery moved down $2.25 to $65.98 bbl. NYMEX September ULSD contact plunged 6.14 cents to $1.9598 gallon and NYMEX September RBOB futures declined to $2.0894 gallon.Further weighing on the petroleum complex, domestic demand for gasoline showed no marked improvement over the past few weeks, stalling around 9.3 million barrels per day (bpd) with only few weeks left in the summer driving season. The lack of work commuting, retreating consumer spending, and a resurgent pandemic among other factors continue to weigh on domestic gasoline consumption. Accelerating coronavirus infections tied to a highly transmissible Delta variant are weighing on consumer sentiment, spending and the outlook for the economy. The seven-day moving average for daily infections moved above 100,000 cases in mid-August to 114,190, up 18.4% from the prior week, according to data from the Centers for Disease Control and Prevention.

Oil Prices Fall to Lowest Point Since May on Stronger Dollar – WSJ - Oil prices fell Thursday to their lowest level in about three months after the U.S. dollar strengthened on concern that the global economic recovery might slow and the Federal Reserve’s signals that it will scale back stimulus measures.Brent crude oil, the international benchmark in energy markets, dropped 2.6% to $66.45 a barrel. West Texas Intermediate futures, a key U.S. gauge, declined 2.7% to $63.69 a barrel. Both benchmarks ended at their lowest daily close since May.The dollar’s advance to its strongest level since early November added to recent worries in energy markets. Investors had already grown increasingly nervous in recent days that rising Covid-19 cases are threatening to hobble the global recovery and could sap demand for oil in major economies like China.A stronger dollar tends to put pressure on commodities denominated in the U.S. currency—such as oil and industrial metals like copper—which become more expensive for other currency holders.The ICE Dollar Index, which tracks the greenback against a basket of currencies, gained 0.44% Thursday. “It’s a very nervous market, and that will probably continue until we get some clarity at Jackson Hole next week,” “There is mostly a worry that strength in demand for oil has suddenly faded quite fast out of China, where economic data has been showing softness. And there’s soft mobility in the U.S. as we head into the autumn.”Minutes released Wednesday from the Federal Reserve’s recent meeting showed that policy makers are increasingly in agreement about tapering the central bank’s asset purchases in the months ahead. That has added to bets that the Fed may also raise interest rates sooner than anticipated, making U.S. Treasurys more attractive than government bonds from Germany and Japan that offer subzero yields.U.S. copper futures dropped 1.9% to $4.0385 a pound, the lowest settlement since mid April. Prices for the metal—which are sensitive to the health of the world economy because of copper’s uses in construction and manufacturing—have fallen more than 15% from the all-time high they reached in May.Investors’ appetite for risky assets such as stocks also ebbed as they assessed the growing threat posed by renewed lockdown measures, with many countries struggling to curb the spread of the Delta variant of coronavirus.Shares in major energy companies also took a hit. BP PLC dropped nearly 5% in London, whileTotalEnergies SE shares retreated more than 3% in Paris. Royal Dutch Shell PLC shares slid more than 4% in Amsterdam. In the U.S., Exxon Mobil Corp. and Chevron Corp. also declined.Industrial production data from China earlier this week undershot expectations, and other figures showed that Chinese refiners processed the least crude in 14 months, according to Warren Patterson, head of commodity strategy at Dutch bank ING. Separately, while Energy Information Administration figures released Wednesday showed that U.S. crude inventories fell twice as sharply in the most recent reporting week, gasoline stocks unexpectedly rose.“It appears that gasoline demand has peaked,” “Though the summer driving season still has three weeks to go, it is already clear that it will not meet the high expectations.”

Oil falls for a sixth straight day, sinks to the lowest level since May on fears of slowing growth Oil dropped for a sixth-straight session on Thursday, falling to the lowest level since May as demand fears and comments from the Federal Reserve that it will suspend its bond-buying program sent prices tumbling. Crude came under pressure amid weakness in the commodities market and equities more generally. West Texas Intermediate crude futures for September delivery slid 2.7% to settle at $63.69, its lowest level since May 21. At one point during the session the more actively traded contract for October delivery dipped more than 4%, touching a session low of $62.41. International benchmark Brent crude declined 2.61% to $66.45 per barrel. Both WTI and Brent registered their longest daily losing streak since February 2020. The dollar advanced Thursday after minutes from the Federal Reserve's July meeting indicated plans to pull back the pace of their monthly bond purchases. A strong dollar can pressure oil since it makes the commodity more expensive for foreign buyers. Weak data out of China has also pressured crude in recent sessions after data released Monday showed the economy slowed more than expected in July. Additionally, the country's refinery output fell to the lowest level in 14 months. "Concerns about demand due to the global spread of the Delta variant are continuing to preclude any higher prices," analysts at Commerzbank wrote in a recent note to clients. Data from the U.S. Energy Information Administration released Wednesday showed a surprise build in gasoline stocks, which sparked fears of a weaker-than-expected end to the summer driving season. "Though the summer driving season still has three weeks to go, it is already clear that it will not meet the high expectations," Commerzbank added. Oil staged a blistering comeback during the first half of the year as demand returned and producers kept supply in check. But the momentum began to stall in July as the delta variant spread. WTI is now down 18% from its recent high of $76.98 from July 6. "There are still too many question marks over the crude demand outlook over the next few months and that will weigh on crude prices," said Ed Moya, senior market analyst at Oanda. "After the release of the Fed's Minutes, risk aversion prevailed and oil prices returned back to session lows," he added.

WTI Expires at 3-Month Low as Delta Halts Demand Growth Rate -- Crude and refined products futures on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange finished a volatile trading week with sharp losses, sending West Texas Intermediate September below $63 barrel (bbl) at expiration Friday afternoon, as traders reassess prospects for a delayed recovery in global oil demand this year, hammered by the aggressive spread of COVID-19 infections and rising inflation across major oil consuming economies.Further weighing on the oil complex, Bakers Hughes reported Friday afternoon the number of active oil rigs in the United States increased for the third consecutive week through Friday to the highest level since April 2020 at 405. The number of oil-directed rigs is now 222 higher compared to a year ago, with a dozen rigs added in August so far. More evidence of rising crude production was found in data released Wednesday by the Energy Information Administration showing domestic operators added 100,000 barrels per day (bpd) of crude output during the week ended Aug. 13 for an 11.4 million daily output rate -- the highest since May 2020. In its latest Short-Term Energy Outlook, EIA forecasts output would average around 11.1 million bpd for the remainder of the year before hitting 11.8 million bpd by the end of 2022.Globally, the Organization of the Petroleum Exporting Countries together with Russia-led partners, known as OPEC+, began increasing crude production 400,000 bpd a month in August after members reached consensus to gradually unwind agreed to production cuts made during the depth of the pandemic in the second quarter 2020. OPEC+ production cuts totaled 5.759 million bpd in July, with monthly increases set to continue through December 2022 or until all cut output is restored. Compliance among OPEC members eased to 116% last month from June's 120% compliance rate, according to private surveys, while their non-OPEC counterparts scored a compliance rate of 97% in July. Reduced OPEC compliance was mostly driven by Saudi Arabia, with the kingdom restoring the remaining 400,000 bpd of an additional unilateral cut of 1 million bpd above its quota in the first quarter last month.Rising global oil production is met with concerns over flagging oil demand in major Asian and Western economies, prompting several investment banks to downgrade their growth forecasts for the third quarter. Goldman Sachs this week slashed its third quarter U.S. gross domestic product outlook from 9.8% to 5.5%, noting the "impact of the Delta variant on growth and inflation is proving to be somewhat larger than we expected. Spending on dining, travel, ... is likely to decline in August, though we expect the drop to be modest and brief," they wrote in a note.

Oil Extended Losing Streak Friday to Seven Days, Longest since 2019 | Rigzone --Oil capped the week with the longest losing streak since 2019 as the dollar strengthened after the Federal Reserve signaled it will start tapering stimulus and the virus resurgence raises doubts about demand growth. West Texas Intermediate futures ended the session 2.2% lower, tumbling for a seventh day and extending the week’s decline to 8.9%. Other raw materials including copper and iron ore fell on Thursday following the Fed’s signal. The Bloomberg Dollar Spot Index has risen every day this week, making commodities priced in the currency less appealing. The pandemic remains a threat to energy demand, especially across Asia, with key importer China restricting mobility to combat an outbreak. “It’s an exceptionally rare event for oil to fall for such an extended period,” said Thomas Finlon, chief operating officer at Brownsville LLC, a trading and logistics firm in Houston. “External factors including the ongoing effects of the delta variants’ growth and the behavior coming out of the federal reserve, is proving surprisingly significant to investors.” Crude’s weakness comes amid fading expectations for further large inventory draws in the coming months. Bank of America said prices will probably be range-bound in the second half of the year with more steep drops in stockpiles unlikely. The price plunge may force the Organization of Petroleum Exporting Countries and its allies to pause their next planned production increase, according to Citigroup Inc. “We have now priced down to a level reflecting more sideways inventories, with demand pain from Covid-19 together with more from OPEC+ on supply,” said Bjarne Schieldrop, chief commodities analyst at SEB AB. “But OPEC+ should be in fairly good control of the market still.” The pandemic continues to disrupt plans to restart economic activity, crimping mobility and demand for fuels. In Australia, Sydney’s two-month long lockdown will be extended until at least the end of September. In the U.S., more companies announced plans to keep workers at home as the virus spreads. Brent crude is also sinking. The international benchmark is headed for its longest run of losses in more than three years and close to falling below $65 a barrel for the first time since May. Prices: WTI for September delivery, which expires Friday, fell $1.37 to settle at $62.32 a barrel in New York. Brent for October settlement declined $1.27 to end session at $65.18 a barrel. Despite lower headline prices and the commodity being unable to shake investors’ risk averse mood as of late, Brent’s nearest timespread widened to 44 cents, an indicator of long term bullishness. The number of people in the U.S. getting a first dose of a Covid-19 vaccine has risen to almost half a million a day, a level last seen at the end of May, as the overall vaccination rate in the U.S has increased to 60%.

Saudi Aramco aims to raise at least $17 billion from gas pipeline: Sources - Saudi Aramco is looking to raise at least $17 billion from the sale of a significant minority stake in its gas pipelines, higher than the $12.4 billion raised from its oil pipeline deal, sources familiar with the matter said on Monday. Potential bidders including North American private equity and infrastructure funds, as well as state-backed funds in China and South Korea have been approached by Aramco through its advisors before a formal sale process kicks off in the next few weeks, they said. The deal size may include $3.5 billion of equity and the remainder will be funded by bank debt, one source said, while another source said the transaction size could top $20 billion. Saudi Arabia is the world's sixth largest gas market,according to Aramco, whose Master Gas System (MGS) derives valuefrom a range of gas deposits and helps deliver it to consumers. "The gas deal is about the long-term view of gas utilisation and consumption in Saudi Arabia," said one source familiar with deal, explaining why the gas deal may generate higher proceeds. The source said many industries will shift to gas under the economic Vision 2030, meaning domestic gas demand will rise. Aramco is working with JPMorgan and Goldman Sachs on the deal to tap potential buyers, sources have said. The companies tapped include the ones who took part in the stake sale process for Abu Dhabi National Oil Co's gas pipelines, which was bought by a consortium of investors including Global Infrastructure Partners (GIP), Brookfield, Singapore sovereign wealth fund GIC and European gas infrastructure owner and operator SNAM.

Iranian oil shipment to Lebanon poses new challenge for Israel - Israel News - Haaretz.com - This new unsupervised axis through the Suez Canal will be perceived as a Hezbollah accomplishment testing both Israel and Egypt. The Israeli army’s love affair with psyops blurs ethical lines

Taliban to Take Power in Afghanistan, Country's President Flees - The Taliban is set to retake power in Afghanistan 20 years after being ousted by US-led forces, with the president fleeing the country by plane and the militant group taking control of the presidential palace in Kabul after a rapid offensive.The Taliban will declare the Islamic Emirate of Afghanistan from the palace, a Taliban official announced on Sunday.The official spoke under the condition of anonymity because he was not authorized to speak to the press, according to the Associated Press.President Ashraf Ghani boarded a plane and left Afghanistan for Tajikistan on Sunday, a senior interior ministry official told Reuters. The president's office told the news agency it "cannot say anything about Ashraf Ghani's movement for security reasons."Tolo TV also confirmed that Ghani has gone into exile.The Taliban has advanced rapidly through Afghanistan over the past few weeks as NATO troops and American forces left the South Asian country two decades after the US invaded to hunt down Osama bin Laden following the 9/11 terrorist attacks on New York and Washington D.C. A series of smaller towns and cities systematically fell to the militant group as it overran US-trained forces. As Afghan troops have surrendered, the Taliban has seized weapons provided by the US, forcing the US to carry out strikes on captured military equipment to stop the Taliban from turning it on the Afghan forces.US Secretary of State Antony Blinken said on Sunday that US embassy staff in Kabul are leaving the facility and moving to the airport. But a security alert released Sunday by the US Embassy in Kabul said the situation in the capital city is "changing quickly including at the airport. There are reports of the airport taking fire; therefore we are instructing U.S. citizens to shelter in place."President Joe Biden was slammed by GOP leaders for his silence during early Sunday developments emerging from Afghanistan. The White House eventually said in an afternoon statement that Biden and Vice President Kamala Harris had met with national security officials in the morning "to hear updates on the draw down of our civilian personnel in Afghanistan, evacuations of SIV (Special Immigrant Visa) applicants and other Afghan allies, and the ongoing security situation in Kabul."

Taliban declare 'amnesty,' call on women to join government --The Taliban on Tuesday said they would grant amnesty for all Afghans and called on women to join government offices, an apparent move to gain support from local populations who remain fearful of a return to the restrictive laws against women and girls from the Taliban’s rule more than two decades ago. Enamullah Samangani, a member of the Taliban’s cultural commission, explained that the “Islamic Emirate of Afghanistan with full dignity and honesty has announced a complete amnesty for all Afghanistan, especially those who were with the opposition or supported the occupiers for years and recently,” according to The Associated Press. The Taliban official also said that women have been the “the main victims of the more than 40 years of crisis in Afghanistan” and that the insurgent group "doesn’t want the women to be the victims anymore.” “The Islamic Emirate of Afghanistan is ready to provide women with environment to work and study, and the presence of women in different [government] structures according to Islamic law and in accordance with our cultural values,” he added, the AP reported. The remarks are the first comments revealing how the Taliban intends to govern since the group’s rapid takeover of Afghanistan, culminating in Sunday’s fall of Kabul. The takeover, which came just two weeks before the U.S. was set to officially withdraw the remainder of its troops from Afghanistan, has led to widespread concerns among human rights groups and local populations that the expanded rights women and girls have gained in the country over the past 20 years could be quickly turned back under a new Taliban regime. The group previously governed under an extreme interpretation of Islamic law and prohibited women and girls from going to school, working or leaving their homes unless they were accompanied by a man. Women were also required to cover most of their bodies, including their faces, and were not allowed to drive. CNN’s Clarissa Ward reported Monday that women had already begun dressing more conservatively while walking outside their homes in Kabul.

Iran closes border to fleeing Afghans -- Iran closed its border to Afghanistan on Wednesday, as thousands of Afghan nationals seek to flee the country following the Taliban’s takeover. Hossein Qasemi, the director of the Iranian interior ministry’s office for border affairs, told the state-run Mizan news agency that authorities instructed Iran’s three provinces that border Afghanistan to deny Afghan nationals entry into Iran because of recent developments in the country and “coronavirus restrictions,” according to the BBC. The news comes after Qasemi reportedly said Iran was establishing refugee camps on its border with Afghanistan in the expectation of a surge of people fleeing from the Taliban. Thousands of Afghan citizens are scrambling to leave the country after the Taliban seized control of the capital city of Kabul this weekend, effectively toppling the government and unleashing chaos in the region. The U.S. has thus far evacuated more than 3,200 people from Afghanistan, 1,100 of whom were removed Tuesday, according to the CNN. The Taliban has vowed to rule peacefully in Afghanistan, but many are still skeptical of how the insurgent group will govern in the region, especially when it comes to women. Hundreds of Afghan service members have fled to Uzbekistan on dozens of U.S.-supplied planes and helicopters since the weekend. The Pentagon on Tuesday said it is aiming to have one flight leave from Kabul per hour within the next day, which would allow the military to extract between 5,000 and 9,000 people from Afghanistan a day.

Ex-Afghan President Ashraf Ghani Reportedly Fled Country With $169 Million, Emerges In UAE - It's now well known that ex-Afghan President Ashraf Ghani had fled his country on Sunday while claiming it would "avert bloodshed". His rapid exit, initially said to have been toward Tajikistan, ensured the lighting fast Taliban takeover of Kabul - also as the Pentagon scrambled to initiate the still ongoing evacuation of US diplomats and all American citizens. On Monday it emerged via Russian embassy eyewitnesses and reports that Ghani had stuffed multiple cars and a helicopter full of cash upon departure, even leaving some of it on the airport tarmac as not all of it could be physically carried, apparently. It's now emerging that he and his aides may have escaped with a whopping $169 million, according to new statements from the Afghan ambassador in Tajikistan, as reported in BBC. Further the United Arab Emirates is now confirming that he's reappeared in the UAE. "The UAE Ministry of Foreign Affairs and International Cooperation can confirm that the UAE has welcomed President Ashraf Ghani and his family into the country on humanitarian grounds," according to a Wednesday foreign ministry statement. Since he fled Sunday, there had been no official word on his whereabouts, though previously there was speculation that Tajikistan may have denied him entry, which may have initially diverted Ghani to Oman. Ghani has a lot to answer for: not only did he loot Afghanistan's coffers (and the US taxpayer by extensions), but his fleeing may have collapsed a major transitional or possible 'power sharing' deal that was in the works, which perhaps would have also avoided the horrific scenes from Kabul international airport on Monday that resulted in at least seven deaths.

Pepe Escobar: The 'New Great Game' In Eurasia Has Just Been Reloaded - In the end, the Saigon moment happened faster than any Western intel “expert” expected. This is one for the annals: four frantic days that wrapped up the most astonishing guerrilla blitzkrieg of recent times. Afghan-style: lots of persuasion, lots of tribal deals, zero columns of tanks, minimal loss of blood. August 12 set the scene, with the nearly simultaneous capture of Ghazni, Kandahar and Herat. On August 13, the Taliban were only 50 kilometers from Kabul. August 14 started with the siege of Maidan Shahr, the gateway to Kabul. Ismail Khan, the legendary elder Lion of Herat, struck a self-preservation deal and was sent by the Taliban as a top-flight messenger to Kabul: President Ashraf Ghani should step out, or else. Still on Saturday, the Taliban took Jalalabad – and isolated Kabul from the east, all the way to the Afgan-Pakistan border in Torkham, gateway to the Khyber Pass. By Saturday night, Marshal Dostum was fleeing with a bunch of military to Uzbekistan via the Friendship Bridge in Termez; only a few were allowed in. The Taliban duly took over Dostum’s Tony Montana-style palace. By early morning on August 15, all that was left for the Kabul administration was the Panjshir valley – high in the mountains, a naturally protected fortress – and scattered Hazaras: there’s nothing there in those beautiful central lands, except Bamiyan. In the end, there was no Battle for Kabul. Thousands of Taliban were already inside Kabul – once again the classic sleeper-cell playbook. The bulk of their forces remained in the outskirts. An official Taliban proclamation ordered them not to enter the city, which should be captured without a fight, to prevent civilian casualties. The Taliban did advance from the west, but “advancing,” in context, meant connecting to the sleeper cells in Kabul, which by then were fully active. Tactically, Kabul was encircled in an “anaconda” move, as defined by a Taliban commander: squeezed from north, south and west and, with the capture of Jalalabad, cut off from the east. At some point last week, high-level intel must have whispered to the Taliban command that the Americans would be coming to “evacuate.” It could have been Pakistan intelligence, even Turkish intelligence, with Erdogan playing his characteristic NATO double game. The American rescue cavalry not only came late, but was caught in a bind as they could not possibly bomb their own assets inside Kabul. The horrible timing was compounded when the Bagram military base – the NATO Valhalla in Afghanistan for nearly 20 years – was finally captured by the Taliban. That led the US and NATO to literally beg the Taliban to let them evacuate everything in sight from Kabul – by air, in haste, at the Taliban’s mercy. A geopolitical development that evokes suspension of disbelief.