US oil prices hit a 4 month low; US distillates supply is at a 25 week low; global oil supply was 1,680,000 barrels per day short of global demand in October, as OPEC's output was 490,000 barrels per day below their reduced target..
US oil prices were down for a fourth straight week and tumbled on Thursday to a 4 month low before rebounding Friday to cut the loss....after falling 4.1% to settle at $77.17 a barrel last week following softer-than-expected economic data out of China and the US, and threats of more rate hikes from central bankers, the contract price for the benchmark US light sweet crude for December delivery rebounded on Monday to settle $1.09 higher at $78.26 a barrel after OPEC's monthly market report countered concerns over declining demand in the U.S. and China...oil prices rallied again early Tuesday after the IEA increased its demand growth forecasts and the U.S. dollar fell on data showing inflation was slowing but ended the day's trading unchanged as traders positioned ahead of the release of two weeks of oil data from the U.S. EIA ...oil prices erased the week's gains on Wednesday, settling $1.60 lower at 76.66 a barrel, following the EIA's report of a larger than expected build in U.S. crude stocks, and then nosedived 5% on Thursday following reports of a Chinese refinery slowdown and on record US oil production amid rising supplies and settled $3.76 lower at a four-month low of $72.90 a barrel....however, oil prices retraced most of their losses on Friday, rallying 4% as the U.S. dollar index pulled back and traders looked ahead to next week's meeting among OPEC+ ministers and the potential for deeper production cuts, and settled $2.99 higher at $75.89 a barrel, but still posted a 1.7% loss for the week...
natural gas prices finished the week 2.4% lower at $2.960 per mmBTU, after tumbling nearly 14% to $3.033 last week, on record production, mild weather and a big addition of gas to storage in spite of the beginning of the usual heating season...The EIA's natural gas storage report for the week ending November 10th indicated that the amount of working natural gas held in underground storage in the US increased by 60 billion cubic feet to 3,833 billion cubic feet by the end of the week, after natural gas supplies had decreased 6 billion cubic feet the prior week in the season's first withdrawal, which left our natural gas supplies 198 billion cubic feet, or 5.4% above the 3,635 billion cubic feet that were in storage on November 10th of last year, and 203 billion cubic feet, or 5.6% more than the five-year average of 3,630 billion cubic feet of natural gas that were in working storage as of the 10th of November over the most recent five years…the 60 billion cubic foot injection into US natural gas working storage for the cited week was quite a bit more than the average 40 billion cubic feet addition to supplies that was expected by industry analysts surveyed by Reuters, and was much more than the average 20 billion cubic feet addition to natural gas storage that has been typical for the same Autumn week over the past 5 years, but was a bit less than the 66 billion cubic feet that were added to natural gas storage during the corresponding warm November week of 2022…
The Latest US Oil Supply and Disposition Data from the EIA
Note: Since last week's oil data was not published while the EIA was undergoing a systems upgrade, this week's statistics include two weeks of new data....hence, we will try to include as many of the key stats from last week as possible with this week's synopsis, without allowing it to get too cumbersome...also note that with the systems upgrade, the U.S. Petroleum Balance Sheet now includes three new lines: line 4) Transfers to Crude Oil Supply, which includes 5) Alaskan NGL production and 6) "Natural Gasoline, Condensate, and Unfinished Oils"...presumably, those liquids which have been included but in our oil supplies weekly should account for the large "unaccounted for crude oil" entry we've complained about for years...however, as of this week, they don't...
At any rate, the US oil data from the US Energy Information Administration for the week ending November 10th indicated that even after an increase in our oil exports and a drop in the amount of oil supplies that the EIA could not account for, we again had surplus oil to add to our stored commercial crude supplies, for the seventh time in eighteen weeks, and for the 25th time in the past 47 weeks ...Our imports of crude oil fell by an average of 21,000 barrels per day to average 6,373,000 barrels per day, after falling by an average of 31,000 barrels per day the prior week, while our exports of crude oil rose by 364,000 barrels per day to average 4,889,000 barrels per day, after falling by an average of 372,000 barrels per day the prior week, which combined meant that the net of our trade in oil worked out to a net import average of 1,484,000 barrels of oil per day during the week ending November 10th, 385,000 fewer barrels per day than the net of our imports minus our exports during the prior week. .Over the same period, transfers to our oil supply from Alaskan gas liquids, natural gasoline, condensate, and unfinished oils averaged 715,000 barrels per day, while at the same time, production of crude from US wells remained at its all time high of 13,200,000 barrels per day for the sixth straight week, and hence our daily supply of oil from the net of our international trade in oil, from transfers, and from domestic well production appears to have averaged a total of 15,399,000 barrels per day during the November 10th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,399,000 barrels of crude per day during the week ending November 10th, an average of 164,000 more barrels per day than the amount of oil that our refineries were processing during the prior week, while over the same period the EIA’s surveys indicated that a rounded average of 513,000 barrels of oil per day were being added to the supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures provided by the EIA for the week ending November 10th appear to indicate that our total working supply of oil from net imports, from transfers, and from oilfield production was 512,000 barrels per day less than what was added to storage plus our oil refineries reported they used during the week. To account for that difference between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a [ +512,000 ] barrel per day figure onto what is now line 16 of the weekly U.S. Petroleum Balance Sheet in order to make the reported data for the supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there was an error in the week’s oil supply & demand figures that we have just transcribed.....Moreover, since 2,147,000 barrels of oil per day were unaccounted for in last week’s data, that means there was a 1,635,000 barrel per day difference between this week's oil balance sheet error and the EIA's much larger crude oil balance sheet error from a week ago, and hence the changes to supply and demand from that week to this one that are indicated by this week's report are off by that much, and therefore nonsense...however, since most oil traders react to these weekly EIA reports as if they were accurate, and since these weekly figures therefore often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably reliable 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)….(NB: there is also an aging twitter thread from an EIA administrator addressing these errors, and what they had hoped to do about it)
This week's 513,000 barrel per day increase in our overall crude oil inventories was all added to our commercially available stocks of crude oil, after 1,981,000 barrels per day were added to our commercial crude supplies the prior week, while the amount of oil in our Strategic Petroleum Reserve remained unchanged both weeks. Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to 6,488,000 barrels per day last week, which was 2.8% more than the 6,310,000 barrel per day average that we were importing over the same four-week period last year. This week’s crude oil production was reported to be unchanged at an all time high of 13,200,000 barrels per day for the sixth consecutive week because the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 12,800,000 barrels per day, while Alaska’s oil production was 4,000 barrels per day lower at 433,000 barrels per day but still added the same 400,000 barrels per day to the EIA's rounded national total as it did last week...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure is now 0.8% above that of our pre-pandemic production peak, and 36.1% above the pandemic low of 9,700,000 barrels per day that US oil production had fallen to during the third week of February of 2021.
US oil refineries were operating at 86.1% of their capacity while processing those 15,399,000 barrels of crude per day during the week ending November 10th, up from their ten month low utilization rate of 85.2% last week, with such low utilization rates not uncommon during the Fall, when refineries are undergoing seasonal maintenance as they changeover to produce winter blends of fuel.. however, the 15,399,000 barrels per day of oil that were refined this week were still 4.7% less than the 16,152,000 barrels of crude that were being processed daily during week ending November 11th of 2022, and 3.2% less than the 15,916,000 barrels that were being refined during the prepandemic week ending November 8th, 2019, when our refinery utilization rate was at 87.8%..
Even with the increase in the amount of oil being refined this week, the gasoline output from our refineries was much lower, decreasing by 813,000 barrels per day to 9,415,000 barrels per day during the week ending November 10th, after our refineries' gasoline output had increased by 734,000 barrels per day during the prior week. This week’s gasoline production was 3.0% less than the 9,789,000 barrels of gasoline that were being produced daily over the same week of last year, and 6.7% less than the gasoline production of 10,173,000 barrels per day during the prepandemic week ending November 8th, 2019. At the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 53,000 barrels per day to 4,753,000 barrels per day, after our distillates output had increased by 120,000 barrels per day during the prior week. But even with those increases, our distillates output was 6.7% less than the 5,097,000 barrels of distillates that were being produced daily during the week ending November 11th of 2022, and 5.7% less than the 5,03,000 barrels of distillates that were being produced daily during the week ending November 8th, 2019..
With this week's big decrease in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the 26th time in thirty-eight weeks, decreasing by 1,540,000 barrels to 215,670,000 barrels during the week ending November 10th, after our gasoline inventories had decreased by 6,312,000 barrels during the prior week. Our gasoline supplies fell by less this week because the amount of gasoline supplied to US users fell by 543,000 barrels per day to 8,949,000 barrels per day (after rising by 795,000 barrels per day the prior week), while our exports of gasoline fell by 49,000 barrels per day to 933,000 barrels per day, and while our imports of gasoline fell by 190,000 barrels per day to 514,000 barrels per day.…Even after twenty-six gasoline inventory decreases over the past thirty-eight weeks, our gasoline supplies were still 3.7% above than last November 11th's gasoline inventories of 207,940,000 barrels, and only 1% below the five year average of our gasoline supplies for this time of the year…
Even with this week's increase in our distillates production, our supplies of distillate fuels fell for the twenty-second time in thirty-six weeks, decreasing by 1,422,000 barrels to a 25 week low of 106,579,000 barrels over the week ending November 10th, after our distillates supplies had decreased by 3.294,000 barrels during the prior week. Our distillates supplies fell by less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 189,000 barrels per day to 4,109,000 barrels per day, and because our exports of distillates fell by 88,000 barrels per day to 1,000,000 barrels per day, while our imports of distillates fell by 64,000 barrels per day to 152,000 barrels per day....With 22 inventory decreases over the past thirty-six weeks, our distillates supplies at the end of the week were 0.7% below the 107,383,000 barrels of distillates that we had in storage on November 11th of 2022, and about 13% below the five year average of our distillates inventories for this time of the year...
Finally, even with our oil exports higher, our commercial supplies of crude oil in storage rose for the 12th time in twenty-six weeks and for the 27th time in the past year, increasing by 3,592,000 barrels over the week, from 435,762,000 barrels on November 4th to 439,354,000 barrels on November 11th, after our commercial crude supplies had increased by 13,869,000 barrels over the prior week. .Even with those increases, our commercial crude oil inventories were still about 2% below the most recent five-year average of commercial oil supplies for this time of year, but were still about 28% above the average of our available crude oil stocks as of the 2nd weekend of November over the 5 years at the beginning of the past decade, with the big difference between those comparisons arising because it wasn’t until early 2015 that our oil inventories had first topped 400 million barrels. After our commercial crude oil inventories had jumped to record highs during the Covid lockdowns of the Spring of 2020, then jumped again after February 2021's winter storm Uri froze off US Gulf Coast refining, but then fell in the wake of the Ukraine war, only to jump again following the Christmas 2022 refinery freeze offs, our commercial crude supplies as of this November 10th were 0.9% more than the 435,355,000 barrels of oil in commercial storage on November 11th of 2022, and 1.5% more than the 433,003 ,000 barrels of oil that we still had in storage on November 12th of 2021, but 10.2% less than the 489,475,000 barrels of oil we had in commercial storage on November 13th of 2020, after early pandemic precautions had left a lot of oil unused…
OPEC's Report on Global Oil for October
Monday of this past week saw the release of OPEC's November Oil Market Report, which includes the details on OPEC's & global oil data for October, and hence it gives us a picture of the global oil supply & demand situation as Chinese demand remained sluggish after their first half recovery from the country's restrictive Covid policy, while oil supplies were impacted by an ongoing unilateral million barrel per day production cut by the Saudis and an additional 300,000 million barrel per day supply cut by Russia...October was also the tenth month that OPEC and aligned oil producers were operating under a 2 million barrel per day production cut, meant to take roughly 2% of global oil supplies off the market, in response to a perceived global surplus and related lower prices of a year ago, and the fifrth month of a Saudi led cut of an additional 1.16 million barrels per day, which, when combined with a unilateral 500,000 million barrel per day Russian cut, was intended to take an additional 1.66 million barrels per day off the market for the rest of this year...all told, then, the members of the cartel have committed to holding 4.66 million barrels per day, or roughly 4.6% of global supplies, off the market ...
The first table from this month's report that we'll review is from the page numbered 49 of the 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 has been using an average of production estimates by as many as eight "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), the industry newsletter Petroleum Intelligence Weekly, the energy consultancy Wood Mackenzie and the research and intelligence firm Rystad Energy, 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 in the bottom right hand corner of the above table, OPEC's oil output increased by 80,000 barrels per day to 27,900,000 barrels per day during October, up from their revised September production total that averaged 27,820,000 barrels per day....however, that September OPEC output figure was originally reported as 27,775,000 barrels per day, which therefore means that OPEC's September production was revised 45,000 barrels per day higher with this report, and hence OPEC's October production was, in effect, 125,000 barrels per day more than the previously reported OPEC production figure (for your reference, here is a copy of the table of the official August OPEC output figures as reported a month ago, before this month's revision)...
since the increase in OPEC production in October was led by a 51,000 barrel per day increase by Angola and a 46,000 barrel per day increase by Iran, it remains in line with their previously announced cuts, since Iran is exempt from those cuts while Angola had been underproducting by hundreds of thousands of barrels per day...production from Kuwait, which has been producing above their assigned quota, was down by 26,000 barrel per day, while production from the Emirates, another overproducer, rose by 16,000 barrels per day...
the additional million barrel per day output cut the Saudis first implemented in July and recently extended to the end of this year was the latest in a series of oil supply cuts imposed by the OPEC+ cartel over the past year, beginning with a 2 million barrel per day production cut that the joint agreement imposed on all producers in October 2022...following that, six OPEC oil producers, led by the Saudis, and two other oil producers aligned with OPEC+, came to an agreement at the beginning of April to further reduce their combined production by an additional 1.16 million barrels per day beginning in May, over and above the formal OPEC cuts...in addition, Russia agreed to extend their ongoing 500,000 barrels per day cut for the rest of the year for a total cut of 1.66 million barrels per day from those nine producers...production cuts for OPEC members under that agreement included 500,000 barrels per day (bpd) from the Saudis, 211,000 bpd from Iraq, 140,000 bpd from the Emirates, 128,000 bpd from Kuwait, 48,000 barrels per day from Algeria, and 8,000 barrels per day from Gabon...four months ago, our initial assessment was that only the Saudis managed to hit the additional production cut target in May, and only Algeria joined them in June, indeed, most of the others who announced cuts in April increased their production over the June through September period, rather than cutting it, and it appears that's also been the case in October....hence, the net production reduction remains less than half of what had been committed to by the parties to that April 2nd agreement..
furthermore, OPEC and other aligned oil producers had previously agreed to reduce production by 2,000,000 barrels per day beginning last November, so the net 917,000 barrels per day OPEC ex-Saudi Arabia have cut since then is also short of that...however, OPEC's production was already running 1,585,000 barrels per day below what they were expected to produce when that policy was initiated in October of last year, so the 27,900,000 barrels per day OPEC produced in Octobr still leaves them short of what they were expected to produce during the month, as we'll see in the next table...
The above table was originally included as a downloadable attachment to the press release following the 33rd OPEC and non-OPEC Ministerial Meeting on October 5th, 2022, which set OPEC's and other aligned oil producers' production quotas for November 2022 and the following months through the end of 2023, and the quotas shown above were reaffirmed by the cartel for 2023 in during the 34th OPEC and non-OPEC Ministerial Meeting on December 4th, 2022....the first column above, labeled "August 2022 required production", actually matches the October 2018 baseline production level on which OPEC and aligned producers have based all of their quotas since the onset of the pandemic, and the "Voluntary adjustment" is the production cut each country is expected to make from that benchmark level to achieve a 2 million barrel per day cut for the cartel as a whole, leaving each country with a "Voluntary Production" level they're expected to hit each month during 2023, whether they've been able to produce that much recently or not....since war torn Libya and US sanctioned producers Iran and Venezuela have been exempt from the production cuts imposed by the joint agreement that has governed the output of the other OPEC producers since May 2020, they are not shown on the above list, and OPEC's quota excluding them is aggregated under the total listed for the 'OPEC 10', which you can see was expected to be at 25,416,000 barrels per day from November 2022 through December 2023...
with the April 2nd agreement, six members of OPEC agreed to further reduce their production by 1,035.000 starting in May and through the end of the year....thus the voluntary production level for the OPEC 10 would have been reduced to 24,381,000 through December....subtracting the one million barrel per day cut from the Saudi's production initiated in July from that would leave OPEC's 'voluntary production' level at 23,381,000 barrels for the month of October....therefore, the 22,891,000 barrels those 10 OPEC members actually produced in September were 490,000 barrels per day short of what they were expected to produce during the month, with Nigeria and Angola still accounting for the majority of this month's production shortfall...
The next graphic from this month's report that we'll look at shows us both OPEC's and worldwide oil production monthly on the same graph, over the period from November 2021 thru October 2023, and it comes from page 50 (pdf page 60) of OPEC's November Oil Market Report....on this graph, the sky blue bars represent OPEC's monthly oil production in millions of barrels per day as shown on the left scale, while the purple line graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale....
After this month's 80,000 barrel per day increase in OPEC's production from their revised production of a month earlier, OPEC's preliminary estimate is that total global liquids production increased by a rounded average of 300,000 to an average of 101.6 million barrels per day in October, after September's total global output figure was apparently revised up by 700,000 barrels per day from the 100.6 million barrels per day of global oil output that was reported for September a month ago, as non-OPEC oil production rose by a rounded 200,000 barrels per day in October after that revision, with most of October’s non-OPEC production increase due to greater oil output from by Norway and OECD Americas, which more than offset lower production from Russia and Brazil...
After that 300,000 barrel per day increase in October's global output, the 101.60 million barrels of oil per day that were produced globally during the month were only 100,000 barrels per day, or 0.1% more than the revised 101.50 million barrels per day that were being produced globally in October a year ago, when OPEC was operating with an inconsequential 100,000 million barrel per day production cut, after their pandemic era out reductions had unwound that September... (see the November 2022 OPEC report for the originally reported October 2022 details)...since this month's increase in OPEC's output was in line with the global increase, their October oil production of 27,900,000 barrels per day amounted to 27.5% of what was produced globally during the month, same as their revised 27.5% share of the global total in September....OPEC's October 2022 production was originally reported at 29,494,000 barrels per day ,which means that the 13 OPEC members who were part of OPEC last year produced 1,594,000 barrels per day, or 5.4% fewer barrels per day of oil this October than what they produced last October, when they accounted for 29.1% of a similar global output total...
Even with the increase in global oil output in October and the big aforementioned upward revision to September's production, the amount of oil being produced globally during the month again fell short of the expected global demand, as this next table from the OPEC report will show us...
The above table came from page 27 of the November Oil Market Report (pdf page 37), and it shows regional and total oil demand estimates in millions of barrels per day for 2022 in the first column, and then OPEC's estimate of oil demand by region and globally, quarterly over 2023 over the rest of the table…on the "Total world" line in the fifth column, we've circled in blue the figure that's relevant for October, which is their estimate of global oil demand during the fourth quarter of 2023….OPEC is estimating that during the 4th quarter of this year, all oil consuming regions of the globe will be using an average of 103.28 million barrels of oil per day, which was revised a rounded 150,000 barrels of oil per day higher from the 103.13 million barrels per day they estimated for the fourth quarter a month ago (we've circled this month's revisions in green)....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 101.60 million barrels per day during October, which would imply that there was a shortage of around 1,680,000 barrels per day of global oil production during October, when compared to the demand estimated for the month...
in addition to figuring that October oil shortage implied by this report, the upward revision of 700,000 barrels per day to September's global oil output that's implied the data in this month's report, combined with the 60,000 barrels per day downward revision to 3rd quarter demand that we've circled in green above, means that the 1,570,000 barrels per day global oil output shortage we had previously figured for September would now be revised to a shortage of 810,000 barrels per day....in like manner, the 60,000 barrels per day downward revision to 3rd quarter demand means that the shortage of 1,360,000 barrels per day we had previously figured for August would now be revised to a shortage of 1,300,000 barrels per day, and that the shortage of 1,480,000 barrels per day barrels per day we had previously figured for July would have to be revised to a shortage of 1,420,000 barrels per day...
Note that in green we have circled an upward revision of 130,000 barrels per day to OPEC's previous estimate for second quarter demand...so, based on that upward revision to demand, our previous estimate of a shortage of 450,000 barrels per day in June would now be revised to a shortage of 580,000 barrels per day...in addition, the 750,000 barrels per day global oil output shortage we had previously figured for May would now be revised to a shortage of 880,000 barrels per day...meanwhile, the global shortage of 130,000 barrels per day we had previously figured for April would now be revised to a shortage of 260,000 barrels per day, in light of that 130,000 barrel per upward revision to 2nd quarter demand....
Also note that in green we have encircled a downward revision of 10,000 barrels per day to OPEC's previous estimates of first quarter demand...for March, that means that the 200,000 barrels per day global oil output surplus we had previously figured for March would be revised to a surplus of 210,000 barrels per day.. similarly, the downward revision to first quarter demand means that the global oil surplus of 500,000 barrels per day we had previously figured for February would now be revised to a surplus of 510,000 barrels per day, while the 250,000 barrels per day global oil output shortage we had previously figured for January would now be revised to a shortage of 240,000 barrels per day, in light of the 10,000 barrel per day downward revision to first quarter demand...
Also note that in orange we've also circled an upward revision of 30,000 barrels per day to 2022's demand, which also means that the supply shortfalls that we previously reported for last year would have to be revised....while we're not inclined to go back and recompute supply & demand for the months of 2022, we have those totals for each month of last year accompanying our review of OPEC's January 2023 report, should anyone want to review how 2022's oil supply & demand shook out..
This Week's Rig Count
in lieu of details on the rig count, we are again just including below a screenshot of the rig count summary pdf from Baker Hughes...in the table below, the first column shows the active rig count as of November 17th, the second column shows the change in the number of working rigs between last week’s count (November 10th) and this week’s (November 17th) count, the third column shows last week’s November 10th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 18th of November, 2022...
in addition to the removal of one natural gas rig that had been drilling in Ohio's Utica shale, there's been quite a bit of repositioning of those rigs that are still drilling; over the week ending November 17th, 2 rigs were pulled out of Belmont county, and rigs were also removed from Monroe and Columbiana counties as well; at the same time, 2 more rigs began drilling in Guernsey county, and another rig was added to Jefferson county at the same time...the key details on Ohio’s Utica shale rigs as they stand as of Friday from Baker Hughes's North America Rotary Rig Count Pivot Table (xls) are included below...
- MONROE – Horizontal >15k
- MONROE – Horizontal >15k
- NOBLE – Horizontal 5k-10k
- NOBLE – Horizontal >15k
- TUSCARAWAS – Horizontal >15k
- JEFFERSON – Horizontal >15k
- JEFFERSON – Horizontal >15k
- GUERNSEY – Horizontal >15k
- GUERNSEY – Horizontal >15k
- GUERNSEY – Horizontal >15k
- CARROLL - Horizontal >15k
- BELMONT – Directional >15k
Ohio Justices Urged To Adopt Broad Utica Shale View – Law360 --- Gulfport Energy and Ohio oil and gas rights owner Tera LLC sparred before the Buckeye State Supreme Court on Tuesday, with the former telling the justices that a state appellate court rendered the language of the parties' oil and gas lease contracts "superfluous" by containing its drilling rights to the Utica Shale. . .
- Justices pondered what’s included in Utica Shale formation
- Drilling industry has expressed keen interest in case
A closely-watched case centering on a multimillion-dollar hydraulic fracturing deal in Ohio turns on how eight words in a drilling contract are interpreted, attorneys on both sides of a contract dispute told the state Supreme Court Tuesday.Gulfport Energy Corp. and a subsidiary of Rice Energy Inc. say the phrase “the formation commonly known as the Utica Shale”—which appears in a contract reached with a landowner in rural Belmont County, along the Ohio-West Virginia border—was known to include the Point Pleasant formation below Utica’s base. This gives the companies permission to conduct drilling for hydraulic fracturing, commonly known as “fracking,” ...
MWCD Makes Historic Economic Impact Across the Region -— The Muskingum Watershed Conservancy District (MWCD) announced a plan to address major upgrades and deferred maintenance needs at recreational facilities and marinas in 2014. The plan, which was enabled by revenues from Utica shale leases, has bolstered the region’s economy by nearly $1 billion through the MWCD’s investment of $221.9 million. It has also supported 2,606 jobs, paying out nearly $300 million in wages and benefits since its inception nine years ago.The economic benefits were calculated as part of a comprehensive analysis of the benefits of MWCD’s oil and gas revenue done by Cleveland State University and released publicly today.“MWCD is excited to work with Cleveland State University to show the historic levels of investments made from taking the bold step to allow oil and gas development on our lands,” said Craig Butler, MWCD Executive Director. “Through careful planning, analysis, and through a comprehensive lease and program, MWCD is leading the way and showing how we can have nearly $1 billion of economic impact, all while offering the best camping, fishing and overall recreation opportunities in Ohio. I am proud of decision by the Board of Directors and staff made in 2011 and very proud that we have been able to invest and support the region through these investments.”As the Cleveland State analysis underscores, increases in oil and gas revenues associated with Utica Shale development have generated revenue for MWCD that has enabled it to bring economic benefits to the conservancy district’s 18-county service area, including job creation, increased state and local tax revenue, and growth in related industries such as transportation and infrastructure. This development has also enabled MWCD to greatly expand its services so that it now provides some of the best recreational opportunities anywhere in Ohio. It has, for example, upgraded cabins, campgrounds, docks, playgrounds, picnic shelters, shower houses, trails, and wastewater utilities infrastructure to a level of quality rarely found in public parks and campgrounds anywhere in the country.The Cleveland State analysis includes MWCD’s investments through 2022 but does not include nearly $15M in project funding in 2023, and $30M budgeted for 2024. In addition, MWCD leased more than 7,300 acres in Harrison County in 2022. Spending resulting from this lease agreement is not reflected in this study either, although these revenues will catalyze further economic impact through capital improvements and ongoing operations for many years to come. With the addition of these additional significant investments, the economic benefits of MWCD’s oil and gas revenue are even greater. To review the Economic Impact Study, visit http://www.mwcd.org/EconomicImpact
Conservation District Brings $1 Billion to Ohio Region Thanks to Utica Shale Revenues - Energy In Depth - Natural gas and oil development in the Muskingum Watershed Conservancy District (MWCD) has brought $1 billion of economic impact to the region, according to a new analysis by Cleveland State University. The historic partnership has also supported 2,606 jobs totaling nearly $300 million in wages and benefits over the past nine years, while bringing increases in state and local tax revenue and growth in related industries such as transportation, tourism, and infrastructure. MWCD Executive Director Craig Butler called the decision to allow energy development on state lands – all while protecting and preserving Ohio’s lands – a “bold step:” “Through careful planning, analysis, and through a comprehensive lease and program, MWCD is leading the way and showing how we can have nearly $1 billion of economic impact, all while offering the best camping, fishing and overall recreation opportunities in Ohio. I am proud of decision by the Board of Directors and staff made in 2011 and very proud that we have been able to invest and support the region through these investments.” EID has discussed the many benefits stemming from oil and gas development in the MWCD. Thanks to revenues from Utica Shale leases, MWCD has invested more than $220 million in upgrades to its facilities. This includes efforts to build new campgrounds, renovate aging spaces, add new playgrounds, sports courts, trails, shower houses and wastewater utilities infrastructure the District calls “a level of quality rarely found in public parks and campgrounds anywhere in the country.” Likely in response to these upgraded recreational facilities, in 2021 MWCD saw a record-breaking 5 million-plus visitors, and forecasts that even more tourists will continue to visit its district. Given the success of MWCD’s Master Plan, the district recently signed its largest oil and natural gas lease to date to develop 7,300 acres of land in the Utica Shale basin. The five-year contract will result in around 15 wells, with the possibility to add additional wells in an optional three-year extension. However, MWCD and oil and gas operators take great care to ensure that the wells are no hindrance to parkgoers. In a video highlighting these standards, Brad Janseen, Chief of Natural Resources and Land Management, says:“We work with the operators to do things like sound walls for sound proofing and buffering. We do surveys before a rig even gets on the pad.”Additionally, the new analysis highlights the many conservation efforts MWCD has been able to achieve, thanks to oil and gas revenues: MWCD’s partnership with oil and gas operators while maintaining strict stewardship over Ohio’s lands is a prime case study in responsible development and comes the same week that the Ohio Oil & Gas Land Management (OGLM) Commission meets to finally determine the fate of energy development underneath state lands. This decision has been more than a decade in the making, after continued obstruction from activists, as EID has repeatedly discussed. The bold and historic partnership between the Muskingum Watershed Conservancy District and oil and natural gas operators has been a $1 billion economic machine for the region. The partnership is proof point that conservation, sustainability, and oil and gas are not mutually exclusive – but in fact, can all work together for the benefit of the state and our beautiful Ohio lands.
Muskingum Watershed Generated $1B in Econ Impact from Utica Drilling --Marcellus Drilling News - For more than a decade, MDN has brought you stories about shale development on and under land controlled by the Muskingum Watershed Conservancy District (MWCD), an agency formed in 1933 to help control flooding and promote water conservation in the Muskingum River watershed area of Ohio, an area that covers 8,000 square miles (see our Muskingum Watershed stories here). Over the years, MWCD has leased tens of thousands of acres for Utica Shale drilling and cut deals to sell water to drillers for fracking. According to a new study from Cleveland State University, the MWCD’s aggressive leasing for Utica drilling has brought more than $1 billion in economic stimulus to the region. And not one penny is government (your) money! It’s all private money being injected into the Buckeye State.
Ohio opens Salt Fork State Park and two wildlife areas to fracking for gas – The Oil and Gas Land Management Commission opened parcels of land underneath Salt Fork State Park and two other state-owned wildlife areas to oil and gas development, in the face of roaring chants from a room full of approximately 100 protesters during the hearing. The commissioners granted seven of the 10 requests for tracts spanning thousands of acres at Salt Fork in Guernsey County, plus smaller swaths of Valley Run Wildlife Area in Carroll County and Zepernick Run Wildlife Area in Columbiana County. The commissioners rejected a request to frack under Wolf Run State Park. Their rationale for the latter decision could not be heard over the thunder of chants like “don’t frack our futures.” At one point, a woman dressed as Milburn Pennybags (as seen on the cover of Monopoly board games) threw a handfull of faux gold coins in the air just in front of the commissioners. At one point, activists effectively hijacked the meeting. Roughly a dozen or so stood in front of the commissioners holding a “NO FRACKING OUR OHIO PUBLIC LANDS” sign, obstructing view of commissioners. Chants and a sing-along forced a roughly 15-minute recess. The commission eventually returned to the hearing room and approved various land nominations, ignoring the chants breaking out just a few feet in front of them. After the meeting, Ryan Richardson, who chairs the commission as a representative of the Ohio Department of Natural Resources, which owns state park lands, quickly exited the hearing room and declined interview requests. Wednesday’s vote sends the parcels out for a bidding process, from which the OGLMC is to select the “highest and best” offer. The state can post the bid as soon as January, according to ODNR spokesman Andy Chow. From then, bidders have 30 days to make an offer. Only once a bid is selected will the state reveal the companies interested in the land and the terms of their offers. Republicans at the Ohio Statehouse created the land leasing program in 2011. However, the OGLMC under Gov. John Kasich and DeWine failed to roll out rules to administer and implement it. It took a new state law passed late last year, which also dubiously expanded the legal definition of “green energy” to include natural gas, to effectively force-start the state leasing program into existence. Randi Pokladnik, a retired research chemist affiliated with the grassroots Save Our Parks, said Wednesday’s outbursts were a foreseeable reaction to people who don’t want fracking, and must now shoulder the burden of its environmental and health consequences, going unheard. “For the people that live in Southeast Ohio, like we do in Harrison County and Guernsey County around these parks, that’s just going to make things all the worse for them,” she said. “They’re already subjugated to it on it private land. Now it’s public land.” The industry interest is unmistakable: this year, 98 individuals have registered to lobby the OGLMC on behalf of the likes of Marathon, Shell, BP, Encino Energy, Columbia Gas, EQT Corp., Gulfport Energy, TC Energy, Ascent Resources, Calpine Energy Solutions, Vistra Corp. and others. Before the new legal system took form, Encino offered the state as much as nearly $2 billion over 15 years for rights to drill under Salt Fork. The commissioners took the perhaps unexpected step of rejecting a nomination to frack 2,100 acres of Wolf Run State Park in Noble County. This amounted to the only instance of a wholesale rejection to frack a given protected area. The decision comes after Kara Herrnstein, special counsel for Ohio State University, wrote a letterMonday seeking the rejection of the Wolf Run nomination. She said of the 2,100 acres, OSU owns 770 of them, including the Eastern Agricultural Research Station. The OGLMC, she alleged, failed to identify OSU as the owner of its land and notify the public of as much, as it’s required to do. She said the school uses the land for academic research that requires removal of “external variables” and maintaining precisely controlled land conditions. The commissioners previously met in September with the intention of deciding on the 10 different land nominations to drill under state parks and wildlife areas that have been on their desks all summer. Theypunted on the decision at the time, however, citing a need for more stakeholder input. They did so in the face of a similar room of dozens of angry environmentalists urging rejection, citing a need to protect state lands from development. In the weeks before the hearing, Cleveland.com and the Plain Dealer published articles about more than 100 Ohioans saying their names were used without their knowing consent on letters submitted to the OGLMC urging them to support fracking Salt Fork State Park. Commissioners are required by law to consider the public comments they receive.Attorney General Dave Yost, shortly after publication, announced an investigation into the matter but has declined to provide updates on it. House Minority Leader Allison Russo, a Columbus-area Democrat, pressed him for more details in a public letter sent Tuesday.“A thorough investigation is imperative so Ohioans have confidence that any state process meant to include public input is, in fact, functioning to reflect public opinion and not another conduit for public corruption,” she said. “Identity theft in Ohio is a serious crime, and I look forward to the Attorney General improving public confidence in our state agencies and ensuring criminal activity does not permeate our state approval processes.” In both 2011 and 2022, the laws creating and implementing the system for fracking state parks were passed almost exclusively with Republican support. Gov. Mike DeWine, who signed the more recent legislation into law, declined to comment. Speaking to reporters Wednesday, Senate President Matt Huffman, a Lima Republican, said before the Senate spearheaded the 2022 law change, Ohio effectively couldn’t frack under parks, despite state law, because the state’s governors weren’t on board. He praised the day’s votes, but said fracking should go forward in an “environmentally sensitive way” for plants and other wildlife. “The state can derive a lot of revenue from those,” he said. “Revenue, on this side, means perhaps lower taxes, or just as likely, other benefits to the public, whether it’s fixing up state lodges, whether it’s more money for public schools.”A lawsuit filed by the Ohio Environmental Council, Sierra Club, and others seeking to overturn Ohio’s land leasing law also remains in process. The suit alleges lawmakers failed to heed constitutional rules that limit bills to one subject and require readings of bills over multiple days. A judge declined to freeze the law as the case proceeds, and it awaits trial.Meg Edwards, 24, who joined the protesters in obstructing the ongoing meeting, said after the meeting that the issue isn’t settled yet.“The fight isn’t over until drills are in the ground,” she said.
Ohio commission approves fracking in state parks and wildlife areas despite fraud investigation (AP) — Some state parks can be fracked in Ohio, a decision made by a government commission Wednesday despite an ongoing investigation into oil and gas companies claiming possible fraudulent support. During a raucous meeting attended by many fracking opponents, the Ohio Oil and Gas Land Management Commission OK'd several parcels for fracking by outside entities — all of them owned by the Ohio Department of Natural Resources and the Ohio Department of Transportation — that include state parks and designated wildlife areas. Under state law, the identities of those who nominated the land for oil and gas drilling are confidential. The vote took place during a tense public meeting at which anti-fracking protesters held up signs that read “DENY” and “Save Our Parks.” Advocates accused the state board members of lacking transparency, upholding the interests of corporate greed and poisoning future generations. Some threw money in front of the commissioners and shouted them out of the state meeting, while others sang protest songs in and chanted “Don't frack our futures," and “Shame.” A member of Save Ohio Parks, Cathy Cowan Becker, said opponents were disappointed by the vote but vowed to continue to show up to meetings. “At a time when the science is telling us we have to stop all the oil and gas, instead we're doing this in our parks,” Cowan Becker said. “We're rightfully really angry about this.” The decision is the first of its kind in Ohio, although laws allowing fracking have been on the books since 2011. Legislation under then-Gov. John Kasich, a former Republican presidential candidate, called for a state board to allow state-owned land to be “leased for the exploration for and development and production of oil or natural gas." But the formation of the commission was not formalized during the Kasich administration. In fact, its first meeting did not occur until December of 2022, after current GOP Gov. Mike DeWine signed a bill similar to the 2011 legislation. Commission chair Ryan Richardson emphasized in a previous commission meeting that according to the language in the nominated leases, no surface areas of the parks would be disturbed by oil and gas drilling as it would occur underground. However, most of the meeting Wednesday was nearly impossible to hear over the boos and chants of environmental advocates in the room. A spokesperson for Richardson said she would respond to reporters' questions later Wednesday. Oil and gas fracking is often a polarizing topic, but ongoing accusations of fraudulent support have added even more tension to the vote. A Cleveland.com investigation in September found that over a hundred Ohio residents said their names were attached to form letters sent to the commission in a public comment period without their knowledge — all of them urging state parks allow fracking.Those names included a 9-year-old girl and a blind woman. The form letter, which appears over 1,000 times in the public comment database, urges Ohio to “responsibly” lease rights to minerals under Salt Fork State Park, among other areas.
Ohio Finally Opens Energy Development Under State Lands - After more than a decade in the making, the Ohio Oil and Gas Land Management Commission (OGLM) voted today to allow for the safe development of oil and natural gas resources under the surface of state-owned lands and parks. This is a win for landowners and their right to develop private minerals close to and adjacent to Ohio state lands, as well as a massive economic win for Eastern Ohio, the entire state, and Ohio taxpayers. The opened parcels include land underneath Salt Fork State Park in Guernsey County, Valley Run Wildlife Area in Carroll County, and Zepernick Wildlife Area in Columbiana County. Bids will be accepted starting in January, and companies are already showing they are ready to invest in the state, helping to create local jobs and develop crucial energy resources. For example, EID has discussed before that a proposed lease to access natural gas and oil beneath Salt Fork State Park would have generated $1.8 billion in estimated royalties and lease bonus payments. This highlights the economic value deals like this will have for Ohio landowners, taxpayers, and parkgoers alike. Today’s OGLM vote proceeded despite the many interruptions and outbursts from protestors who repeatedly disrupted the meeting.Cleveland.com described these outbursts: “At one point, activists effectively hijacked the meeting. Roughly a dozen or so stood in front of the commissioners holding a “NO FRACKING OUR OHIO PUBLIC LANDS” sign, obstructing view of commissioners. Chants and a sing-along forced a roughly 15-minute recess.” This is no surprise: EID has repeatedly discussed the continued obstruction from activists and debunked their claims that oil and gas development harms Ohio lands. To the contrary, oil and gas development can actually boost Ohio’s conservation efforts as evidenced by the “bold” partnership between the Muskingum Watershed Conservancy District (MWCD) and oil and gas producers. A new analysis just this week shows that energy development in the MWCD has brought $1 billion of economic impact to the region and made it a record-setting site for tourism due to facility upgrades made possible by Utica Shale revenues. The energy development has also supported 2,606 jobs totaling nearly $300 million in wages and benefits, while bringing increases in state and local tax revenue and growth in related industries such as transportation and infrastructure – all while promoting and protecting Ohio’s lands. Bottom Line: Today’s vote is a win for landowners, a win for taxpayers, and importantly – with over a decade of evidence showing the safe and responsible development of Ohio’s natural resources and oil and gas partnerships actually increasing sustainability efforts – it’s a win for Ohio’s lands too.
OGLMC Votes to Allow Fracking Under Ohio's Salt Fork State Park | Marcellus Drilling News - Yesterday, the Ohio Oil & Gas Land Management Commission (OGLMC) met in a public forum and voted to allow shale drilling under (not on top of) three different state-owned tracts of land: all 20,000 acres of Salt Fork State Park in Guernsey County, more than 300 acres of Valley Run Wildlife Area in Carroll County, and 66 acres of the Zepernick Wildlife Area in Columbiana County. In addition, commissioners voted against shale drilling under Wolf Run State Park. Approximately 100 anti-fossil fuel zealots were on hand at the meeting and nearly made the votes impossible with their prancing, chanting, and singing. They made horses rear ends of themselves by making the meeting miserable for everyone else.
Ohio Extends Time to Build 2nd Utica-Fired Elec Plant Near Toledo --In December 2017, MDN told you about a second proposed natural gas-fired power plant planned by CME Energy for Oregon (Lucas County), Ohio (see Ohio Approves 2nd Oregon Utica-Fired Elec Plant (Near Toledo)). The first plant was called the Oregon Clean Energy Center. The second plant project was named Clean Energy Future – Oregon. The second plant is bigger than the first, targeted to generate 955 megawatts of power. At that time (in 2017), CME was in the permitting process for the second plant, with plans to have it built and online in 2020. Fast forward to today. The plant was never built but is still being planned.
Enbridge, EDF Energy Form Solar Project JV in Ohio -Enbridge said Wednesday that it has signed an agreement to form a joint venture with EDF Renewables to build and operate a solar project in Ohio.The Canadian energy infrastructure company said the definitive agreement is for a 50% interest in a JV with EDF Renewables for the Fox Squirrel solar project in Madison County.The project is expected to be constructed in three phases. Initially, it is seen generating about 150 megawatts of solar energy, and would ultimately deliver up to 577 megawatts of renewable energy to the grid by the end of next year.Enbridge plans to invest $149 million in the first phase and plans to reach a final investment decision in the following phases throughout next year.The company said the project has 20-year fixed-price power purchase agreements with a strong investment grade counterparty for the full generation capacity.
Invenergy’s natural gas powerplant outside Pittsburgh nixed - Another proposed natural gas power plant has been called off in Western Pennsylvania, this one after eight years of development, permitting and opposition. Chicago-based Invenergy, which was developing the Allegheny Energy Center project in Elizabeth Township, surrendered its installation permit last week and withdrew its application to connect to the regional grid. Invenergy cited “current market conditions” in a one-sentence statement about its decision and declined to elaborate further.But environmental groups that have fought the project from its zoning variance requests at the local level to its air permit applications with the Allegheny County Health Department celebrated their role in scuttling the plant, just as they did with the $1 billion proposed Renovo Energy Center in Clinton County that was canceled in April after eight years of permitting and development. The same groups, including PennFuture and the Clear Air Council, said strong community advocacy also ended the prospects of a natural gas plant that was proposed in Robinson Township. That initiative let its environmental permit expire in 2021 and never reapplied.“Allegheny Energy Center’s demise marks the end of giant new fossil-fueled power plants in Pennsylvania,” said Joseph Minott, executive director and chief counsel for the Clean Air Council. “Instead of locking us into decades of fossil fuel use and fueling the climate crisis, Pennsylvania can invest in wind and solar, which are safer, cheaper, and guarantee our energy independence far into the future.”Invenergy’s 639-megawatt power plant, if built, would have made enough electricity to power roughly half a million homes. It also would have been a significant emitter of nitrogen oxides, volatile organic compounds, ammonia and air pollutants.The project had been through several iterations since Invenergy first proposed it as a 550 megawatt gas plant in 2016 on the site of an industrial dump along the Youghiogheny River.It was met with opposition from residents and environmental groups, who argued it would be a major source of pollution and a visual blight on the area. Invenergy moved the project to another area of Elizabeth Township to tackle some of these challenges. In 2021, environmental groups challenged the project’s air permit and the case had advanced to trial. Then, after some witnesses had already testified, Invenergy asked to pause the proceedings, according to the groups’ account on Monday.Angela Kilbert, a senior attorney with PennFuture, declared Invenergy’s retreat a “victory for Allegheny County.”“We will continue to fight to protect the health of our communities from the harmful air pollution impacts imposed by fossil fuel facilities like this one,” she said in a statement.It’s not clear exactly what pushed Invenergy to abandon the effort now.The development of the Marcellus and Utica shales in Appalachia shuffled the dynamics of the regional power grid, which is operated by PJM Interconnection and includes Pennsylvania and 12 other states. With a new source of cheap and plentiful fuel, developers proposed to build gas power plants to soak up the new supply. Many of them never materialized.
22 New Shale Well Permits Issued for PA-OH-WV Nov 6 – 12 - New shale permits issued for Nov 6 – 12 in the Marcellus/Utica slipped but still turned in a respectable number. There were 22 new permits issued last week, versus 37 issued the week before. Last week’s permit tally included 6 new permits in Pennsylvania, 16 new permits in Ohio, and no new permits in West Virginia. Hilcorp Energy was the winner of most permits issued, with 12 new permits issued for a single well pad in Columbiana County, OH. BRADFORD COUNTY | CHESAPEAKE ENERGY | COLUMBIANA COUNTY | COTERRA ENERGY (CABOT O&G) | ENERGY COMPANIES | GULFPORT ENERGY | HARRISON COUNTY| HILCORP ENERGY | MONROE COUNTY | SOUTHWESTERN ENERGY | SUSQUEHANNA COUNTY |
New Study Finds Overwhelming Evidence of Harms From Fracking - The negative impacts of hydraulic fracturing on public health, the environment, and the climate are “intractable and not fixable,” according to a newly published report. Hydraulic fracturing, or “fracking,” along with advances in horizontal drilling, ushered in an enormous oil and gas production boom beginning about 15 years ago, leading to the U.S. becoming the largest oil and gas producer in the world. But the scientific literature on its impacts has grown larger with each passing year, shedding light on the vast human and environmental toll left in the industry’s wake. The fracking boom really began to take off in Pennsylvania in the late 2000s and early 2010s. Sandra Steingraber, a scientist and co-founder of Concerned Health Professionals of New York, a group of health professionals and scientists concerned about fracking, began scouring the scientific literature on the drilling practice. Fracking involves the use and release of toxic chemicals and contaminants into the air and water, through multiple stages of the drilling process. That pollution finds its way to people who live nearby. In addition, vast quantities of carbon and methane pollution are released into the atmosphere. In those early days, the science was playing catchup to a fracking boom that was already advancing at full speed. “At the time, there were really 65 studies in the peer-reviewed literature. I remember there was a time where I had them all sort of memorized,” Steingraber told Gas Outlook. Concerned Health Professionals of New York compiled all the literature into a “fracking compendium,” as they called it. Steingraber travelled around to speak to rural New York communities who were slated to be targeted by gas companies if the state moratorium was lifted. But in late 2014, New York announced that it was permanently banning fracking, with state officials citing “significant public health risks.” “It was like hearing our own study read back to us,” Steingraber told Gas Outlook. “They did in fact look at a lot of the same research we did, and came to the same conclusions.” But even then, the scientific evidence on the dangers of fracking was only beginning to be understood. The evidence began as a trickle, but quickly turned into an avalanche as scientists began to study the industry. “The second edition of the compendium had 150 studies and then it went to 400 studies for the third edition in 2014,” Steingraber said. “2014 was a year of just so many publications that I could hardly keep track anymore.” The latest version, the 9th edition, released in October, has nearly 2,500 studies showing evidence of harm from fracking. In the past decade, the science has been used by researchers, scientists and activists from all over the world. Steingraber has been in touch and worked with people in Ireland, Argentina, Mexico, South Africa, and Scotland, among other places. Taken together, the report finds that the health, environmental, and climate impacts of fracking are so profound, that there is “no evidence that fracking can be practiced in a manner that does not threaten human health directly or without imperiling climate stability upon which human health depends.” At a press conference on November 8, discussing the findings, Steingraber said that the problems with fracking are “intractable and are not fixable through any regulatory framework.” “Fracking resembles lead paint or indoor smoking — no rules or regulations can make these practices safe.”
Risks of Fracking Are “Real and Growing,” Report Warns -The human and environmental health risks associated with hydraulic fracturing, commonly known as fracking, are “real and growing,” according to a new report synthesizing nearly a decade of research.The Fracking Science Compendium, ninth edition was released in October by Concerned Health Professionals of New York and Physicians for Social Responsibility, and adds to evidence of numerous problems posed by natural gas extraction through fracking and fracking-associated infrastructure, from pipelines and compressor stations to appliances such as gas furnaces and stoves. The report compiles data and conclusions from thousands of studies, including peer-reviewed papers, investigative media reports and government documents.“Our examination uncovered no evidence that fracking can be practiced in a manner that does not threaten human health directly or without imperiling climate stability upon which human health depends,” the report states.For years, scientists have warned that living in close proximity to a fracking operation elevates one’s risk of developing various diseases or health impairments, and the science substantiating these exposure-based outcomes has only gotten more robust over the years.“This rapidly growing body of hundreds of studies supports the conclusion that fracking causes a variety of adverse health effects in fetuses, infants, children, and adults,” Dr. Ted Schettler, a retired physician and public health expert and science director of the Science and Environmental Health Network, said in a webinar held this week to discuss the report results.Schettler said several studies have found that children living near fracking sites are more likely to be diagnosed with cancer. One recent study for example found that children whose birth residence was within 2 kilometers of a fracking well were 2 to 3 times more likely to be diagnosed with acute lymphoblastic leukemia between the ages of 2 and 7 than children living further away.Exposure to fracking and associated infrastructure has also been linked to preterm birth, reduced birth weight and birth defects, increases in asthma attacks and respiratory diseases, cancers, heart attacks and heart failure, and premature death, among other adverse outcomes. Fracking inherently uses and generates toxic chemicals, many of which are not required to be disclosed, and these toxins contaminate air, water, and soil. Benzene and formaldehyde, fine particles, nitrogen oxides, and chlorine are among some the chemicals that have been detected at drill sites.Additionally, hazardous air pollution is infiltrating residential homes that are equipped with gas heating and appliances. Research shows that using gas stoves, especially in the absence of adequate ventilation, increases exposure to harmful chemicals such as nitrogen oxides, carbon monoxide, and benzene. About 1 in 8 cases of pediatric asthma in the US is attributable to exposure to indoor air pollution from gas stoves.Kathy Nolan, a pediatrician and president of the New York chapter of Physicians for Social Responsibility, said people should replace gas stoves in their homes as a preventative health measure, similar to quitting smoking or prohibiting smoking indoors.“We have to wean ourselves off of natural gas,” she said.Transitioning away from gas is also necessary from a climate standpoint. Contrary to the narrative that gas is a cleaner substitute for coal or is a “bridge fuel” to renewable energy, more evidence is emerging indicating that this fossil fuel has a larger greenhouse gas footprint than was previously understood. The main reason for this is that natural gas is almost entirely composed of methane, which is itself a powerful greenhouse gas that is roughly 86 times more potent than carbon dioxide over a 20-year timeframe. In fact, scientists estimate about 40% of current warming stems from atmospheric methane buildup. “Shale gas has a greenhouse gas footprint that is certainly as big as that of coal,” said Robert Howarth, a professor of ecology and environmental biology at Cornell University. In a paper just submitted for peer review, Howarth analyzed the emissions associated with LNG export operations, which involves supercooling gas to liquefy it and then transporting it on giant tankers. His analysis shows that LNG carried by older-style tankers amounts to a greenhouse gas footprint that is roughly 2.5 to 3 times worse than simply burning coal, and even with the newest tankers it is still almost 25% worse than coal. “The science is quite clear. Liquified natural gas is a terrible idea from a climate standpoint,” Howarth said. This new analysis comes at a critical time when the US is rapidly expanding its LNG export capacity, driven at least in part by energy security concerns and energy policy decisions stemming from Russia’s invasion of Ukraine. The US currently has eight existing LNG export terminals with five more under construction and 17 others planned, 11 of which have received federal approval. Already the world’s number one exporter of natural gas and of liquified natural gas, the US is set to double its LNG export capacity over the next five years. “When it comes to fracked gas, the United States is the fentanyl dealer to the planet,” biologist and senior scientist at the Science and Environmental Health Network Sandra Steingraber said during the briefing webinar. Steingraber, who has been an instrumental contributor to the Compendium since its inception and referred to it as her life’s “most meaningful work,” emphasized that the detrimental impacts of this industry cannot be mitigated through existing regulations or controls. “The problems with fracking, both for our health and for our climate, are intractable and are not fixable through any regulatory framework,” she said. “In this, fracking resembles lead paint or indoor smoking. No rules or regulations can make these practices safe.” The only meaningful solution, the Compendium contends, is a comprehensive ban on fracking.
WhiteHawk Expands Marcellus Shale Assets to Boost Natural Gas Production WhiteHawk Energy, LLC announced a significant acquisition of additional Marcellus Shale natural gas mineral and royalty assets, marking a major boost to its portfolio. The total purchase price for the assets amounted to $54.0 million, allowing WhiteHawk to increase its mineral and royalty ownership in its existing 475,000 gross acre position by 100%. This acquisition doubles WhiteHawk’s Marcellus Shale assets and strengthens its position in Washington and Greene counties, Pennsylvania, which are known for their high-quality natural gas reserves. The newly acquired assets possess the ideal mineral and royalty attributes, including diversified acreage positions in well-established basins. These assets are operated by some of the best-in-class companies, generating significant cash flow with minimal additional capital expenditures. WhiteHawk’s Chief Executive Officer, Daniel C. Herz, expressed satisfaction with the initial Marcellus Assets acquired in 2022, highlighting their excellent performance and the opportunity to expand ownership under the world’s top natural gas operators. With this acquisition, WhiteHawk’s Marcellus Assets now cover approximately 475,000 gross unit acres, hosting more than 1,315 horizontal shale wells. Furthermore, the company owns mineral and royalty interests in 72 wells-in-progress, 64 permitted wells, and nearly 900 undeveloped Marcellus locations, with additional potential from the underlying Utica Shale. Notably, approximately 95% of production, cash flow, and present value associated with the Marcellus Assets are operated by EQT Corporation, Range Resources Corporation, and CNX Resources Corporation. This strategic move follows WhiteHawk’s earlier acquisition of natural gas mineral and royalty assets in the Haynesville Shale, resulting in ownership in approximately 850,000 gross unit acres across the two core operating areas. The company continues to expand its interests, specifically in the Marcellus and Haynesville Shales, to tap into the immense potential of these top-tier natural gas resource plays.
NY Fracking Ban Under Attack: Texas Corporation Proposes Carbon Capture Drilling Scam - According to media reports, a newly formed Texas corporation intends to drill thousands of new gas wells in the Southern Tier, by injecting carbon dioxide into fracking wells to escape regulation under New York’s nation-leading ban on fracking.Food & Water Watch research has found that direct air carbon capture is resource and energy intensive, prohibitively expensive, and a risk to human health. Using that carbon dioxide to extract methane, a potent greenhouse gas would further exacerbate these concerns. Food & Water Watch Northeast Region Director Alex Beauchamp issued the following statement:“After almost ten years of relief from the destructive fracking industry, fossil fuel profiteers have once again come knocking in New York. Southern Tier Corporations’ proposal to drill thousands of new gas wells is explicitly against the intention of New York’s nation-leading fracking ban. What’s more, the corporation’s proposal to use proven-to-fail carbon capture technology to skirt state regulation is absurd and dangerous for our climate and communities.“Direct air capture is expensive, unproven and will ultimately make almost no difference in reducing climate-warming pollution. Whether extracted with precious water supplies or energy-intensive sci-fi technology, methane gas has no place in New York’s future. Governor Hochul must come out early against Southern Tier Corporation’s carbon capture fracking scam.”
EIA Nov DPR: Another Big Drop in Shale Gas in M-U, Haynesville | Marcellus Drilling News - The latest monthly U.S. Energy Information Administration (EIA) Drilling Productivity Report (DPR) for November, issued yesterday (below), shows EIA believes shale gas production across the seven major plays tracked in the monthly DPR for December will *decrease* production from the prior month of November — by a significant quantity. This is the fifth month in a row that EIA has predicted shale gas production will decrease for the combined seven plays. EIA says combined natgas production will slide by 299 MMcf/d (million cubic feet per day) — nearly one-third of a billion cubic feet per day (Bcf/d). The Marcellus/Utica, called “Appalachia” in the report, is predicted to decrease by a massive 189 MMcf/d in December compared with November, the biggest decrease in gas production for any of the seven plays.
Mountain Valley Pipeline partner charged in Pennsylvania natural gas explosion -The company that is leading construction of the Mountain Valley Pipeline was charged this week with failing to fix a natural gas leak that caused an explosion of an occupied house in Pennsylvania. A grand jury recommended criminal charges against Equitrans Midstream Corp. for failing to properly maintain a storage well beneath the home, according to state Attorney General Michelle Henry. Three occupants of the Greene County house, a couple and their 4-year-old son, suffered serious burns but were able to escape after the Oct. 31, 2018, explosion. “Pennsylvanians have a right to feel safe in their homes, without concern for large corporations creating environmental hazards,” Henry said in a news release this week. Prosecutors allege that Equitrans was aware that a storage well below the house had been deteriorating and leaking gas for years, resulting in methane contamination. After the gas migrated up into the home through its water supply, an explosion happened when resident Cody White turned on the stove to cook a meal for his child, according to the attorney general’s news release. White, his girlfriend and their son were knocked down by flaming debris, but were able to make it out of the house before it was destroyed by the blast and subsequent fire. Equitrans is the owner and operator of the Pratt Storage Field, directly underneath the White home. Storage fields allow companies to hold large supplies of gas, after it is extracted, so they have quick access to it during times of high demand. The Pittsburgh-region based company is also the lead partner in a joint venture building a 303-mile pipeline that passes through Southwest Virginia, where resistance has run high during more than five years of legal battles. Opponents fear that during long delays in construction, a protective coating designed to guard the pipe from corrosion has been damaged by prolonged exposure to sunlight. That could weaken the pipe, they say, and cause it to rupture and to explode once the line is buried and carrying gas under high pressure. “This news [of the Pennsylvania explosion] is further confirmation that Equitrans and the pipeline they’re backing, MVP, are dangerous actors,” the Protect Our Water, Heritage, Rights coalition, one of the groups fighting the pipeline, said in a statement Friday. POWHR raised similar arguments in August, after an investigation showed that corrosion of a well joint caused a leak at another storage facility in Pennsylvania. It took nearly two weeks for Equitrans to stop the leak, which spewed about 1 billion cubic feet of greenhouse gas into the atmosphere. Mountain Valley spokeswoman Natalie Cox said the company denies the attorney general’s allegations – and rebuts any connection between the incidents in Pennsylvania and the pipeline being built in West Virginia and Virginia. “It is no surprise that special-interest activist groups that have steadfastly opposed the MVP project for years are continuing to find ways to promote their own agendas over national and regional public interests,” Cox wrote in an email Friday. “Regardless,” the email continued, “it is important to note that vertical storage wells are vastly different from natural gas transmission lines, including in construction, operations, and materials, such as coatings.” Concerns about the coating were recently raised by the U.S. Pipeline and Hazardous Materials Safety Administration. In August, PHMSA found that conditions may exist that “pose a pipeline integrity risk to public safety, property or the environment.” A consent agreement reached between the government and Mountain Valley in early October calls for additional inspections of pipes and an independent, third-party review of a process to test the steel pipes and, where needed, to reapply the protective coating. The 12-page consent agreement has been posted to PHMSA’s website, but so far various audit reports and written remedial actions that it requires have not been shared with the public. “While we appreciate PHMSA’s use of an electronic reading room, it appears that the MVP file has not been updated in several months,” the Sierra Club said in a recent letter to the agency. “PHMSA should make available to the public all information and data on safety of the MVP as soon as it becomes available.” A spokesperson for the agency said Friday it is working to increase transparency, “within the letter of the laws established by Congress.” While consent agreements and some enforcement data are currently available online, additional documents may be released later to the public, the spokesperson wrote in an email. After repeated lulls in construction since it began in 2018, Mountain Valley now says it expects to have the pipeline completed by early next year. As for the charges in Pennsylvania, the company said it shared information with the grand jury that it says showed its operation of the gas storage field did not cause the explosion. The charges, brought under Pennsylvania’s Clean Streams Law, allege failures to properly maintain a storage well and to conduct an investigation after the explosion. “We deny the Attorney General’s allegations, which were riddled with inaccuracies,” Cox wrote in the email. “We respect the judicial process and look forward to vindication in court.”
Advocates press Wisconsin regulators to reconsider gas plant --A social worker by training, Jenny Van Sickle sought office to fight for things like mental health resources and accessible childcare. The nuances of a massive power plant proposal were beyond her expertise, and like other civic leaders, she was open to promises that it would provide jobs, a bridge to clean energy and grid reliability. Heavy industry was nothing new in the port town; an Enbridge Energy oil terminal is also located in the neighborhood. In 2019, the council unanimously passed a resolution supporting the project. But the more Van Sickle learned, the more she had doubts about the plant. She began asking more questions and felt like she was getting “misinformation and disinformation” from its developers — Dairyland Power Cooperative and Minnesota Power. She was especially concerned to learn that the proposal included the possibility of burning heavily polluting diesel if natural gas wasn’t available. “When you finally build up the courage to talk about it, it’s like a dam breaking,” she recounted, and other residents also began to share their fears.Now, Van Sickle devotes much of her life to opposing the $700 million power plant, which received crucial approval from the state Public Service Commission in January 2020 and is scheduled to go online by 2027 — if it receives permits still needed from agencies including the Wisconsin Department of Natural Resources and U.S. Army Corps of Engineers. Construction could reportedly start next year.Meanwhile, the Sierra Club and Clean Wisconsin are demanding the Public Service Commission reconsider and reopen the process around the crucial certificate of public convenience and necessity that was issued in January 2020.That’s because two major factors have changed since the commission granted the certificate.Wisconsin utilities have launched plans to install 480 MW of battery storage by 2025. That’s enough storage to work in tandem with renewables to provide reliable power, advocates argue. And the Inflation Reduction Act offers direct-pay incentives for renewables, replacing tax credits and making renewable development much more financially viable for nonprofit entities, including rural electric cooperatives like Dairyland, that don’t pay taxes. Clean Wisconsin and Sierra Club filed a lawsuit challenging the Public Service Commission’s certificate. A district court backed the commission, and they are now awaiting an appellate court decision. Clean Wisconsin staff attorney Brett Korte noted that the Public Service Commission has the authority to reopen a case when it chooses. One of the three public service commissioners, Rebecca Valcq, argued against granting the certificate. Her dissent cited environmental impacts including erosion and the effect on wetlands, and she questioned the availability of water — to be drawn from an aquifer — to cool the plant. She also stated the plant was not needed for a reliable electric supply. Advocates are hopeful the commission would decide differently if the case is reopened.
TC Energy, Williams Each Fetch Final Approvals for Natural Gas Expansion - Columbia Gas Transmission LLC (TCO) and Transcontinental Gas Pipe Line Co. LLC (Transco) each gained FERC approval on three projects designed to boost natural gas deliveries to the Southeast and East Coast. Transco’s Southeast Energy Connector (SEC) would increase firm transportation supply by 150,000 Dth/d from Mississippi and Alabama to an existing power generation facility in Shelby County, AL. Supply would be delivered to Southern Company subsidiary Alabama Power Co.’s Ernest C. Gaston Electric Generating Plant. All but one unit, which would be transitioned from coal to natural gas by 2028, are slated for retirement. Three Federal Energy Regulatory Commission members voted for the certificate (No. CP22-501-000). Commissioner James Danly did not participate,
NextDecade Targets 2024 to Sanction Rio Grande LNG Expansion - As construction of the first phase gets underway in South Texas near the Mexico border, NextDecade Corp. is looking to finalize plans by mid-2024 to expand its Rio Grande LNG export project. The Houston-based firm broke ground in Brownsville on the first three trains of the facility last month, which could add 17.6 million metric tons/year (mmty) of export capacity to the global market by 2027. NextDecade reached a final investment decision (FID) on Rio Grande LNG in July after securing $18.4 billion in financing, making it one of the most expensive U.S. greenfield energy projects to date. In a third quarter business update, the firm noted that it had already started the process of front-end engineering and design (FEED) and securing engineering procurement and construction...
US natgas prices fall 4% on big storage build, record output (Reuters) - U.S. natural gas futures fell about 4% on Thursday on a bigger-than-expected weekly storage build and on record output that should enable utilities to keep injecting gas into storage through at least late November. Utilities usually start pulling gas out of storage to meet heating demand in mid-November. The U.S. Energy Information Administration (EIA) said utilities added 60 billion cubic feet (bcf) of gas into storage during the week ended Nov. 10 after pulling 6 bcf out of storage during the week ended Nov. 3. The withdrawal during the colder-than-normal week ended Nov. 3 was the first withdrawal of the 2023-2024 winter season. The injection during the week ended Nov. 10 was bigger than the 40-bcf build analysts forecast in a Reuters poll and compares with an increase of 66 bcf in the same week last year and a five-year (2018-2022) average increase of 20 bcf. Analysts said utilities were able to add gas into storage during the week ended Nov. 10 because mild weather limited heating demand. Looking ahead, analysts said record output would likely allow utilities to keep injecting gas into storage during the weeks ended Nov. 17 and Nov. 24 if output remains at record highs. EIA did not release its weekly gas storage report last week due to a planned systems upgrade. Front-month gas futures for December delivery on the New York Mercantile Exchange fell 12.8 cents, or 4.0%, to settle at $3.062 per million British thermal units (mmBtu). In a sign that some in the market were giving up on the possibility of higher prices from extreme cold weather later this winter, the premium of futures for January over December NGZ23-F24 fell to just 17 cents per mmBtu on Wednesday, its lowest since November 2022. Based on current futures, the gas market may have already hit its highest price this winter in early November when the front-month closed at $3.52 per mmBtu on Nov. 3. It is actually not that unusual for the highest price of the winter to occur in November. In fact four of the highest prices seen during the heating season over the past five years occurred during November rather than January, which is traditionally the coldest month of the year. Traders noted that is because the anticipation of extreme cold is usually worse than the actual weather itself. The highest winter prices were $7.31 per mmBtu on Nov. 23, 2022, during the winter of 2022-2023; $6.27 on Jan. 27, 2022, during the winter of 2021-2022; $3.24 on Nov. 2, 2020, during the winter of 2020-2021; $2.86 on Nov. 5, 2019 during the winter of 2019-2020; and $4.84 on Nov. 14, 2018, during the winter of 2018-2019. Financial firm LSEG said average gas output in the Lower 48 U.S. states rose to 107.2 billion cubic feet per day (bcfd) so far in November, up from a record 104.2 bcfd in October. Over the past four days, however, output was on track to drop by about 2.4 bcfd to a preliminary one-week low of 106.1 bcfd on Thursday. Meteorologists projected the weather would remain warmer than normal through Nov. 21 before turning close to colder than normal from Nov. 22-Dec. 1. With colder weather coming, LSEG forecast U.S. gas demand in the Lower 48 states, including exports, would rise from 112.2 bcfd this week to 113.8 bcfd next week. The forecast for this week was higher than Refinitiv's outlook on Wednesday. Gas flows to the seven big U.S. liquefied natural gas (LNG) export plants rose to an average of 14.2 bcfd so far in November, up from 13.7 bcfd in October and a monthly record of 14.0 bcfd in April.
Court dismisses effort to restrict Gulf drilling over endangered whale - A federal appeals court has dismissed an effort from environmental groups to prevent an oil rights drilling auction from proceeding without protections for an endangered species of whale. Instead, the 5th Circuit Court of Appeals ruled the Biden administration will have 37 days to carry out the auction for rights to drill in the Gulf of Mexico. The litigation stems from action by the Biden administration that would have put stipulations on an upcoming oil and gas lease sale auction in the Gulf as part of an effort to protect the Rice’s Whale. The administration said in August that it would shrink the sale and restrict ship activity in order to protect the whale, of which there are believed to be fewer than 100 remaining. Chevron, the state of Louisiana and an oil and gas lobbying group sued over that action, and a lower court ruled in their favor, saying that the Biden administration needed to move ahead with the sale in just a few days. Both the Biden administration and environmental groups appealed the lower court’s move, with the Biden administration asking for more time while environmentalists wanted the restrictions that aimed to protect the whale. The administration got more time, as it will now have 37 days to carry out the sale. However, judges Edith Brown Clement, Catharina Haynes and Andrew Oldham, who are Bush and Trump appointees, dismissed the environmental groups’ challenge. They found that the groups did not have standing in the case because they did not show that they will suffer “certainly impending” injury or that any such issues would likely be resolved by the court.
World's first (nearly) zero-emission gas plant delayed until 2027 - Supply chain challenges will delay the world’s first utility-scale gas plant with carbon capture, Net Power executives announced Tuesday.The clean energy technology company unveiled plans last November to build the natural gas plant in Texas’ Ector County, with expectations that the facility would be online in 2026. Project Permian would generate electricity with nearly zero emissions, according to Net Power.But on an earnings call Tuesday, Net Power President Brian Allen told investors that the date has slipped to “sometime between the second half of 2027 and first half of 2028.”“We believe this updated schedule will allow us to accomplish safe, clean and reliable operations and enable this project to serve as the catalyst for all future NET Power plant deployments,” said Allen, who is also the company’s chief operating officer.Allen attributed the delay to “global energy supply chain” challenges, which he said had caused “extensive lead times across critical components.” The company previously adjusted the cost of the project to approximately $1 billion, up from an initial price tag of between $750 and $950 million.Net Power’s technology produces electricity by combusting natural gas with pure oxygen, creating water and carbon dioxide — most of which is recirculated back into its power generation system. Excess high-purity CO2 can then be sold to industry or sequestered underground, according to Net Power. The company plans to use Occidental Petroleum’s existing infrastructure near Odessa, Texas, to move trapped CO2 to a permanent storage location.Occidental is a major supporter of Net Power, investing at least $350 million in the startup since it was founded in 2010.On an earnings call in May, Occidental CEO Vicki Hollub said Net Power’s technology is “really the only source of emission-free power technology that uses hydrocarbon gases.” Net Power’s plant will provide power for Occidental’s oil and gas operations, Hollub said, and “then in the future, it will be one of the emission-free power sources that we use for our direct air capture units.”Will Fitzgerald, an Occidental spokesperson, said Project Permian would not be used for Stratos, the direct air capture facility that’s under construction outside of Odessa. Occidental has entered into an agreement with Origis Energy to provide zero-emission solar power for Stratos, he said.“We intend to power DAC plants with zero or very low-emissions power and anticipate a variety of sources will be needed including wind, solar and potentially other types depending on location and technology development in the coming years,” Fitzgerald said in an email Tuesday.
Barnett Bonanza Is Coming | Rigzone --The Barnett bonanza is coming. That’s what Enverus Intelligence Research (EIR), a subsidiary of Enverus, stated in a release sent to Rigzone recently, which highlighted that the company had published a new report examining various exploration and production companies testing the Barnett Formation in the Midland Basin, “including economic and productivity outcomes”. The release pointed out that, according to a new analysis from EIR, “recent wells targeting the Barnett interval in the Midland Basin show higher oil recoveries and lower breakevens than other secondary zones”. Barnett wells drilled in the core of the Midland Basin average slightly higher oil rates than those drilled near its edges, EIR stated in the release, adding that “vertical separation of more than 1,000 feet from the Wolfcamp D makes the Barnett a true inventory expansion opportunity for operators with deep drilling rights regardless of previous shallower development”. “Sometimes the best place to find new oil is in already-producing areas, which neatly describes what’s happening in the Midland Basin in Texas,” Emily Head, A Senior Associate at EIR and the author of the report, said in the release. “The Barnett formation is buried about 1,000 feet deeper than the Wolfcamp, a prolific oil-producing zone,” Head added. “This separation means companies owning deep drilling rights in the area can expand their inventories of well locations that break even below $50 per barrel, an important metric for many investors,” Head went on to state. The U.S. Energy Information Administration’s (EIA) latest short term energy outlook (STEO), which was released earlier this month, projects that the West Texas Intermediate (WTI) spot price will average $79.41 per barrel in 2023 and $89.24 per barrel in 2024. The EIA’s latest STEO sees the Brent spot price averaging $83.99 per barrel this year and $93.24 per barrel next year. In 2022, the WTI spot price averaged 94.91 per barrel and the Brent spot price averaged $100.94 per barrel, the EIA’s November STEO showed. In another release sent to Rigzone last week, EIR Director Al Salazar noted that EIR expects Brent prices “to trade in the high-$80s – low-$90s into 2024, due to OPEC intervention”. “The Saudis wish to take the cyclicality out of the market,”
Researchers warn that changes in the Permian Basin surface due to oil and gas industry activities are leading to increasing number of geohazards | NM Political Report - A new study published this month examines how the petrochemical industry in the Permian Basin has deformed the landscape by causing some areas to sink while other areas rise.While the changes may not be easily noticeable, especially in sparsely populated areas like the Permian Basin, researchers say they can damage infrastructure. The study by researchers from Southern Methodist University was published in the August edition of the International Journal of Applied Earth Observation and Geoinformation.In their investigation, the researchers from Southern Methodist University sought to map the surface deformation across the Permian Basin and to quantify the relationship between oil and gas operations and the changes to the surface.They found, on average, the ground in the Permian Basin is subsiding at a rate of three to four centimeters annually, though there are several pockets with larger rates of subsidence.The researchers write in the study that, over the past few decades, the increase in oil and gas extraction has “contributed to the alarming increase in geohazards, sometimes permanently altering the local ecosystem, and is a growing concern for communities and policymakers worldwide.” They say it is important to understand “the dynamics of geohazards at various stages in production.”The Permian Basin is an important area to study because about 40 percent of the oil production in the United States occurs there.Dr. Zhong Lu, a professor at Southern Methodist University who has been studying land deformation in the region, said under normal conditions, the landscape would not experience what is known as subsidence, or sinking of the surface ground due to changes in subsurface conditions.“The Permian Basin, along with the rest of the US mid-continent, has long been considered geologically stable with no large-scale tectonic movement, volcanism, or seismic activities. Thus, natural geohazards are relatively uncommon,” Lu said.But, approximately 100 years of extractive industry in the Permian Basin has changed that.Now the basin is experiencing sinkholes, subsidence and uplifts as a direct consequence of the oil and gas activities. These changes in the landscape do not occur at a uniform rate. That means a plot of level ground may change so that one area is higher than an adjacent area. This can have various effects on infrastructure, architecture and even water sources. Uneven changes in the surface can damage pipelines or even disrupt flow within those pipelines, he said. In Pecos, Texas, and other Permian Basin communities, residents have seen their homes and businesses damaged by the changing lands. As many of the abandoned oil wells are more than 50 years old, cracks can form in the cement and corrosion can take place in the oil pipes. These can result in wastewater leaking from a previously sealed and isolated formation into the groundwater or even onto the surface, he said.Karanam said the oil and gas activities also increase the seismic activity in the basin and can induce the formation of sinkholes.It’s not new news that the Permian Basin’s oil fields have a sinkhole problem. In 2020, Undark published a story about the sinkholes in New Mexico’s Permian Basin. But the research that the team at Southern Methodist University is conducting provides a better understanding of how the oil and gas industry in the Permian Basin is changing the landscape and at what rates.
Colorado schools near fracking sites could get funding, but there are concerns — Christa Burke and Monica Aldridge have been friends since they moved to Aurora’s Southshore neighborhood just one day apart two years ago.Their families wanted a quiet community with access to nature and great schools.“We moved into this neighborhood, in particular, because it's part of the Cherry Creek School District, which is known for its excellence. And so, we were very excited,” said Burke, who has two sons in middle and high school."This neighborhood is full of young families with young children," said Aldridge, whose three children also go to the local schools. But soon after buying their new homes, she said they got “a surprise, and not a happy one.” Just east of their neighborhood, beyond the Aurora Reservoir, the oil and gas company Civitas is proposing to drill more than 170 wells.“They're going to do fracking very close by with young children,” Aldridge said.Burke, Aldridge and many of their neighbors are pushing back against the planned fracking through a grassroots group called Save the Aurora Reservoir.“Most of the neighborhood was unhappy, and our fears related really to the health impacts of fracking near homes and schools,” Burke said. "We have at least three elementary schools, two middle schools and a high school that are all within the map where the [horizontal drilling from the] wells will go underneath.”Altitude Elementary School, Fox Ridge Middle School and Cherokee Trail High School are among the schools nearby the proposed oil and gas operations on Lowry Ranch east of the Aurora Reservoir. If Colorado’s oversight agency, the Energy and Carbon Management Commission, and Arapahoe County approve the proposed fracking, the operator will drill the wells at the Lowry Ranch, sprawling grasslands owned by Colorado’s State Land Board.Kristin Kemp, a spokesperson for the land board, told Denver7 this summer that Colorado owns the Lowry Ranch land and minerals, and rents it out to companies, including oil and gas producers.Civitas is already operating several wells on the Lowry Ranch, since the company acquired an existing lease from the energy giant ConocoPhillips in 2020. Civitas hopes to incorporate those wells into its larger proposed project for the ranch.“It's been leased here for oil and gas development for almost 100 years already,” Kemp said. “The rent we collect helps fund public schools.”Civitas's subsidiary Crestone Peak Resources is already operating wells on the Lowry Ranch aquired from ConocoPhillips.The State Land Board has collected $1.5 billion for public schools from oil and gas operations over the last 15 years.Civitas estimates its proposed fracking on the Lowry Ranch could generate about $640 million for public schools in the first 15 years of operations, including both royalties paid to the State Land Board and property tax revenues, according to a statement provided to Denver7. Civitas also estimates the Lowry Ranch operations could help fund Arapahoe County more broadly with more than $400 million in public revenues."It's wonderful to have more money for schools, it is very necessary. But this might not be the best way to do it,” Aldridge said.Her neighbor Burke agrees.“I don't think … the benefits that come from funding for the schools outweigh the costs of our children's health. It doesn't cover the health care costs that come along with chronic illnesses like asthma or childhood cancer,” she said.
EIA Cuts WTI Oil Price Forecasts - The U.S. Energy Information Administration (EIA) lowered its West Texas Intermediate (WTI) oil price forecast for 2023 and 2024 in its November short term energy outlook (STEO), which was released recently. According to the November STEO, the EIA now projects that the WTI spot price will average $79.41 per barrel this year and $89.24 per barrel next year. The latest STEO sees the average WTI spot price coming in at $85.93 per barrel in the fourth quarter of 2023, $89.64 per barrel in the first quarter of 2024, $90.34 per barrel in the second quarter, $89 per barrel in the third quarter, and $88 per barrel in the fourth quarter. In its previous STEO, which was released in October, the EIA projected that the WTI spot price would average $79.59 per barrel in 2023 and $90.91 per barrel in 2024. That STEO saw the average WTI spot price coming in at $86.65 per barrel in the fourth quarter of this year, $90.64 per barrel in the first quarter of 2024, $92 per barrel in the second quarter, $91 per barrel in the third quarter, and $90 per barrel in the fourth quarter. The EIA’s November STEO highlighted that the WTI spot price averaged $94.91 per barrel in 2022. In the first quarter of 2023, the WTI spot price averaged $75.96 per barrel, and in the second and third quarters, it averaged $73.49 per barrel and $82.25 per barrel, respectively, according to the STEO. A report sent to Rigzone on November 14 showed that Standard Chartered projected that the NYMEX WTI price will average $95 per barrel in 2024, $106 per barrel in 2025, and $125 per barrel in 2026. This report revealed that Standard Chartered saw the NYMEX WTI price averaging $89 per barrel in the first quarter of 2024, $91 per barrel in the second quarter, $95 per barrel in the third quarter, $103 per barrel in the fourth quarter, and $104 per barrel in the first quarter of 2025. Standard Chartered had exactly the same quarterly and yearly NYMEX WTI price projections in a separate report sent to Rigzone on October 10. That report also showed that the company saw the NYMEX WTI price averaging $91 per barrel in the fourth quarter of 2023. In a report sent to Rigzone on September 26, Standard Chartered projected that the NYMEX WTI price would average $88 per barrel in 2023. That report also showed that the company forecast that the NYMEX WTI price would come in at $91 per barrel in the fourth quarter of 2023, $89 per barrel in the first quarter of next year, $91 per barrel in the second quarter, $95 per barrel in the third quarter, $103 per barrel in the fourth quarter, $95 per barrel overall in 2024, and $106 per barrel overall in 2025. In a report sent to Rigzone on November 3, BMI, a Fitch Solutions company, revealed that it sees the WTI crude price averaging $79 per barrel in 2023 and $82 per barrel in 2024. When executives from 146 oil and gas firms were asked what they expected the WTI crude oil price to be at the end of the year as part of the latest Dallas Fed Energy Survey, which was released in September, they gave an average response of $87.91 per barrel. The low forecast came in at $70 per barrel, the high forecast came in at $120 per barrel, and the price of WTI during the survey was $90.29 per barrel, the survey highlighted. The next Dallas Fed Energy Survey is currently scheduled to be released on December 20
The Willow effect: Are even more Arctic oil projects on the way? -The massive Willow oil project on Alaska’s North Slope is all but certain to be built now that a federal judge has ruled against environmental groups hoping to halt the development. While it’s set to be Alaska’s biggest new oil field in decades, it very well may not be the last: Willow could give ConocoPhillips and other oil companies cheaper access to vast, untapped reserves beneath the tundra.U.S. District Judge Sharon Gleason denied a challenge last week to the $7.5 billion project — a large expansion of ConocoPhillips’ sprawling network of oil rigs, roads, and pipelines — which the Biden administration controversially approved in March. The federal government estimates burning all the oil that Conoco hopes to extract from Willow would emit about 240 million metric tons of carbon dioxide.The judge’s ruling paves the way for Conoco to drill through permafrost and slurp up 600 million barrels of oil in the northeastern corner of the National Petroleum Reserve in Alaska, an Indiana-sized swath of mostly undeveloped tundra in the western Arctic. But that’s not all. As the company moves ahead with construction of the new oil field, it’s looking to gain access to millions, perhaps billions, more barrels farther west and southwest in the reserve beneath the wild tussocks, sloughs, and lakes where caribou and migratory birds abound.“It’s not only itself a huge project,” said Erik Grafe, an attorney at Earthjustice, which represents the environmental groups that sued to stop the project. “It’s designed to be a hub for future development and that’s itself an even bigger problem.” Conoco told investors two years ago that Willow could be “the next great Alaska hub” for Arctic oil. The company leases a total of 1.1 million acres in the federal petroleum reserve, sitting on an estimated 3 billion barrels of oil. Other companies lease another1.4 million acres combined. Many of those leases lie outside of the roughly 13 million acres where the Biden administration plans to restrict drilling.Just last month Conoco proposed seismic surveys on about 272,000 acres of frozen earth, including an area west of the Willow site, deeper into the national oil reserve. The company initially said the surveys were intended to “determine the most efficient development” at Willow and “to identify potential future development areas” on Conoco’s leases. But the company later amended the proposal, reducing the survey area to some 160,000 acres and cutting the mention of its intention to identify future development areas. (Conoco has said the surveys are intended “exclusively” to support Willow.)Conoco has also drilled two exploratory wells a dozen miles west of Willow — in an area named “West Willow.” The several miles of new roads and pipelines that the company plans to build at Willow could significantly lower the cost of tapping into the estimated 75 million barrels of crude beneath West Willow. That oil “seems like the obvious next target,” Grafe said. “Willow puts in processing facilities, central operating facilities, pipelines, roads. Once that’s in place, it’s a lot cheaper for Conoco and maybe others to develop their leases and tie into that infrastructure.” Earthjustice plans to appeal Gleason’s ruling.
North America Poised to Double LNG Export Capacity by 2027: EIA - New projects are set to grow North America’s liquefied natural gas (LNG) export capacity to 24.3 billion cubic feet per day (Bcfpd) by 2027 led by expansion in the U.S., according to the Energy Information Administration (EIA). That is more than double the current capacity of 11.4 Bcfpd. “By the end of 2027, we estimate LNG export capacity will grow by 1.1 Bcf/d in Mexico, 2.1 Bcf/d in Canada, and 9.7 Bcf/d in the United States from a total of 10 new projects across the three countries”, the U.S. EIA said in a report Monday. Of the 10 projects expected to be put onstream by 2027, five are under development in the U.S., three in Mexico and two in Canada. Exxon Mobil Corp. and QatarEnergy expect to partially start up the three-train Golden Pass project in Texas by next year, before full operation by 2025. Plaquemines LNG, a two-phase project by Venture Global LNG Inc. in Louisiana, expects to be online 2024, with the second phase planned to come into service 2025. Cheniere Energy Inc.’s Corpus Christi project in Texas, already operating with three trains, expects to startup another facility 2025. TotalEnergies SE and NextDecade Corp. target to commission Rio Grande LNG in Texas 2027. Sempra Energy’s Port Arthur LNG, also in Texas, is planned to start up 2027. In Canada, Shell PLC and partners target to put LNG Canada, on the west coast, into service 2025. British Columbia’s Woodfibre LNG is planned to be put onstream 2027 by Pacific Energy Corp. Ltd. and Enbridge Inc. In Mexico, Fast LNG Altamira, a partnership between New Fortress Energy Inc. and state-owned CFE, expects to begin service December 2023 at its offshore unit and 2025 at its two onshore units. Sempra Energy and co-venturers plan to start exporting from Energia Costa Azul LNG, already operating as an import facility, in 2025. Fast LNG Lakach, another New Fortress project in partnership with state-owned Petroleos Mexicanos, is planned for startup 2026. In an earlier report the EIA said 55 countries are set to have LNG terminals by the end of next year with a combined regasification capacity of 163 Bcfpd. The projected capacity is an expansion of 16 percent or 23 Bcfpd compared to 2022 with seven nations having their first import terminals, it said basing the forecasts on data by the International Group of LNG Importers and trade press. In the first seven months of 2023 three countries started importing LNG for the first time: Germany, the Philippines and Vietnam, the EIA noted. "By the end of next year, we expect Antigua, Australia, Cyprus, and Nicaragua to start importing LNG", it said in the report August 30. "Several more countries are in advanced stages of developing LNG import capacity." The EIA sees Asia as the growth leader in global regasification capacity in 2023 and 2024 accounting for 52 percent or 11.9 Bcfpd. Europe would comprise 30 percent or 8.6 Bcfpd and the rest of the globe 10 percent or 2.3 Bcfpd. China is expected to host the bulk of the Asian expansion, at 8.5 Bcfpd. "China was the country that had the most LNG imports in 2021, but its LNG imports declined in 2022, mainly because of the COVID-19-related economic slowdown", the EIA said. Meanwhile India expects 1.3 Bcf/d of capacity added by the end of this year through the Dhamra LNG and Chhara LNG projects. In new markets the Philippines and Vietnam, additions of 1.1 Bcfpd in 2023 and 0.1 Bcfpd by the end of 2024 are expected respectively. In Europe, lower natural gas imports by pipeline from Russia would drive regasification capacity growth by one-third by the end of 2024 compared to 2022, the EIA said. "Germany began importing LNG this year as operators fast-tracked construction of regasification capacity by using Floating Storage and Regasification Units", with three terminals put into operation and three more under construction for an expected startup by the end of 2023, it said. The report put Germany's active and under-development capacity at up to 3.7 Bcfpd. "Eleven other [European] countries will each add between 0.1 Bcf/d and 0.7 Bcf/d of new or expanded regasification capacity for a combined 4.9 Bcf/d of additions", it added. "Cyprus is also expected to start importing LNG in 2024." In the Americas, Brazil is projected to add 1.8 Bcfpd in regasification capacity this year, while Nicaragua and Antigua and Barbuda will together add 0.1 Bcfpd as first-time LNG importers. Elsewhere, "Australia, although also one of the world’s three largest LNG exporters, will add 0.3 Bcf/d of regasification capacity through a new offshore terminal on its eastern coast", the EIA said.
BC Energy Export Terminal One Step Closer to FID - The Ridley Energy Export Facility (REEF) project in British Columbia, spearheaded by a joint venture of AltaGas Ltd and Royal Vopak, is nearing a final investment decision (FID) as site clearing work will begin in the coming weeks. REEF, located on Ridley Island, is planned to be a large-scale coastal terminal that will have the capability to export liquified petroleum gases (LPGs), methanol, and other bulk liquids. Following a five-year environmental preparation and review process, the project FID is expected in the first half of 2024, AltaGas and Vopak said in a joint news release Tuesday. The site clearing work will include logging, clearing, and drainage activities. REEF has been granted key Federal and Provincial permits to construct storage tanks, a new dedicated jetty, and rail and other ancillary infrastructure, according to the release. The project will be developed on a 190-acre (77-hectare) site on lands administered by the Prince Rupert Port Authority (PRPA), where the joint venture has executed a long-term lease. The project will operate under AltaGas and Vopak's existing exclusive rights granted by the PRPA to develop LPG, methanol, and other bulk liquid exports on Ridley Island. REEF has made “strong advancements across critical workstreams” required to reach a positive FID, including commercial, engineering, and partnership agreements, the joint venture said, adding that it will be positioned to award several contracts in the first half of 2024. In October, AltaGas entered into a five-year transportation agreement with Canadian National Railway Company, which provides the joint venture and its customers with cost and service predictability for Ridley Island Propane Export Terminal and the REEF expansion project, according to the release. The joint venture said it would have the option to progress evaluation work on fuels of the future, such as hydrogen, “which has growing customer interest in Asia, particularly Japan and South Korea”. Vopak is one of the “preeminent third-party hydrogen storage platforms globally, operating multiple terminals across several countries”, the release noted. The joint venture highlighted the advantages when the REEF project is completed, claiming that it will take only ten shipping days for Canada’s energy products to reach the “fastest growing demand markets in Northeast Asia”. It added that REEF would have an approximate 60 percent base time savings over the U.S. Gulf Coast, which requires a minimum 25-day shipping time to Northeast Asia, and approximately 45 percent base time savings over the Arabian Gulf, which requires a minimum 18-day shipping time. The geographical advantage expands when there is significant congestion in the Panama Canal or when other global shipping pinch points experience disruptions, the joint venture added. AltaGas is a North American infrastructure company operating a diversified Utilities and Midstream business. Its Midstream business includes global market access for North American LPGs, which provides North American producers and aggregators with the best netbacks for LPGs while delivering diversity of supply and stronger energy security to its downstream customers in Asia. Rotterdam-based Royal Vopak is an independent tank storage company that also aims to develop infrastructure solutions for new vital products, focusing on zero- and low-carbon hydrogen, ammonia, carbon dioxide, long-duration energy storage, and sustainable feedstocks.
Aspiring LNG Exporter Mexico Pacific Touts Chihuahua Natural Gas Pipeline Agreement - Mexico Pacific Ltd. LLC has reached an agreement with the government of Chihuahua state to advance the proposed 2.8 Bcf/d Sierra Madre natural gas pipeline. ExportsSierra Madre would supply Permian Basin gas from the U.S. border across the states of Chihuahua and Sonora to Mexico Pacific’s proposed Saguaro Energía LNG export terminal envisioned for Puerto Libertad on the Sonoran coast. Under the agreement, “the government of Chihuahua will continue to pave an efficient path for the commencement of construction of this historic project in the coming months, marking yet another significant milestone in the progression of energy infrastructure for the state,” Mexico Pacific said. Mexico Pacific has yet to reach a final investment decision (FID) on Saguaro Energía.
Policy Concerns or No, Mexico Natural Gas Imports to Keep Growing, Experts Say - -- Mexico’s pipeline imports of U.S. natural gas should continue rising over the coming years even in the most conservative demand scenarios, experts agreed at the US-Mexico Natural Gas Forum. The power sector is driving demand growth currently, a trend that is likely to continue in the immediate term as state power company Comisión Federal de Electricidad (CFE) expands its fleet of combined-cycle gas turbine plants, energy consultant Guillermo Turrent told the gathering held Nov. 13-15 in San Antonio, TX. Turrent, who is the general manager of Energy and Infrastructure Advisors, highlighted that CFE imports 100% of its gas supply, and company gas imports peaked around 5 Bcf/d last summer.
Pemex Ordered to Provide Weekly Spending Update --Petroleos Mexicanos has been ordered to provide weekly updates on its spending to the head of the country’s tax authority, an effort by Mexican President Andres Manuel Lopez Obrador to rein in excesses at the state-owned oil producer. The president imposed the condition last month amid growing tensions between Pemex and the Finance Ministry, according to people familiar with the matter. Ministry officials have grown increasingly frustrated with the company’s ever-expanding bill to cover its debt payments and fund its expansion into refining and exploration, said the people, who asked not to be identified discussing internal moves. Finance officials are worried about growing expenses that will weigh on the next administration and Mexico’s credit rating, the people said, leading the president to call for the requirement of supervision as a condition for support, the people said. Most recently, the Finance Ministry provided 145 billion pesos ($8.2 billion) of additional funds in the 2024 budget while also lowering a profit-sharing duty, which lawmakers then cut even further. That comes after some $77 billion in cash and tax breaks the company has received during Lopez Obrador’s administration, which have failed to reverse losses. Pemex’s debt reached $106 billion last month, according to Chief Executive Officer Octavio Romero, making the company the most indebted oil producer in the world. Since the reviews by tax officials began, the company has yet to show signs of improvement amid a pile of unpaid suppliers, said one of the people. Spokespeople for Pemex, the tax authority SAT, and the president didn’t immediately reply to a request for comment. Despite Lopez Obrador’s support this year, Pemex bonds show investors remain concerned, with yields on longer-dated bonds up around 100 basis points since June, said George Ordonez, a strategist at BBVA. Money managers are also wary of whether the next administration—which will be elected next year— can, or will, be able to provide the same level of support as Lopez Obrador, he added. “The piecemeal approach to meeting debt obligations has also proven worrisome,” Ordonez said.
Europe Gas Prices Fall on Strong Supply - -- European natural gas eased on Tuesday with the market so brimming with supplies that even the potential shutdown of an LNG plant in Texas isn’t worrying traders for now. Benchmark futures fell as much as 2.4% on Tuesday, after a modest increase late Monday after news of the issues at the Freeport LNG export plant. Storage tanks that are more than 99% full, and mild weather, are helping reduce price sensitivity. Unseasonably mild weather is expected to extend across much of continental Europe well into late November reducing heating demand, according to forecaster Maxar Technologies Inc. In parts of the UK, storm Debi has triggered weather warnings as it brings strong winds, which have boosted renewable generation in the country, further cutting gas use in the power sector. Europe’s energy supplies are on far more stable footing than they were at the peak of last year’s energy crisis, even as withdrawals from gas inventories have now started. Storage has reached maximum levels earlier than usual in the season. Global supply balances remain tight and prolonged supply disruptions or a recovery in industrial demand could tilt the fragile balance. So far this year, extended maintenance in Norway, LNG worker strikes in Australia and the Middle East war have prompted sharp intraday price swings. Dutch front-month futures, Europe’s gas benchmark, fell 1.37% to €47.22 a megawatt-hour at 9:15 am in Amsterdam. The equivalent UK contract also dropped.
Spanish LNG imports, reloads drop in October - Spanish liquefied natural gas imports and reloads dropped in October compared to the same month last year, according to LNG terminal operator Enagas.LNG imports decreased by 8 percent to about 21.8 TWh in October and accounted for 67.6 percent of the total gas imports. In September, LNG imports reached some 19.2 TWh.Including pipeline imports from Algeria, France, and Portugal, gas imports to Spain reached about 33.8 TWh last month, a drop from some 36.9 TWh in October last year, Enagas said in its monthly report.Moreover, national gas demand in October dropped by 10.6 percent year-on-year to some 25 TWh.Demand for power generation declined by 42 percent year-on-year to about 8.3 TWh last month, while conventional demand rose by 22.3 percent to 16.7 TWh, the LNG terminal operator said.The firm previously said that August of this year marked the first time in its history that Spain has managed to fill 100 percent of its underground storage facilities.Storage facilities were also full in October, according to Enagas.Enagas operates a large network of gas pipelines and has four LNG import plants in Barcelona, Huelva, Cartagena, and Gijon.It also owns 50 percent of the BBG regasification plant in Bilbao and 72.5 percent of the Sagunto plant, while Reganosa operates the Mugardos plant.
Israel’s Natural Gas Flow To Egypt To Return To Normal Next Week -Natural gas supply from Israel to Egypt is expected to return early next week to normal levels after an Israeli gas field resumed production suspended in the wake of the Hamas attack in early October, Bloombergreported on Tuesday, quoting a source with knowledge of Egypt’s gas import levels.Low Israeli gas supplies to Egypt also mean low or none Egyptian LNG exports to Europe, which rely on a growing number of cargoes to replace the pipeline gas supply from Russia, most of which was cut off last year after the Russian invasion of Ukraine. In Israel, gas production from the offshore Tamar field has resumed, a month after it was suspended in the wake of the Hamas attacks on southern Israel. The Tamar field is one of the two massive offshore gas fields that put Israel on the global gas map when they were discovered. The field last year produced 10.25 billion cubic meters, up by 18% in 2021. It is operated by Chevron, which also operates the other major gas field in the country, Leviathan.After the resumption of gas production at Tamar, gas flows from Israel to Egypt are set to nearly double and return to the pre-war levels by early next week, according to Bloomberg’s source. Egypt’s gas imports from Israel are set to return to the pre-war level of 800 million cubic feet a day early next week, compared to only 250 million cubic feet per day in early November, the anonymous source told Bloomberg.Export flows of gas from southern Israel to Egypt through the offshore EMG pipeline are also likely to restart this week, sources told Bloomberg on Monday. Supplies from Israel to Egypt via EMG were suspended following the shutdown of the Tamar field, although some of those exports were re-routed through Jordan. Higher Egyptian gas imports and eased concerns about production disruption in the Eastern Mediterranean are good news for Europe, which could hope for some LNG from Egypt this winter, barring an escalation and other field shut-ins.
EU settles on methane limits for fossil fuels imports - The European parliament and EU states have agreed methane greenhouse gas (GHG) intensity thresholds, and penalties, for oil, coal and gas importers. Petrochemicals escape the new rules. With a view to the upcoming UN Cop 28 climate talks in Dubai, parliament's chief lawmaker for methane regulation, Jutta Paulus, said it was "high time" to deliver on the global methane pledge. "Not all fossil fuel exporting countries will appreciate it. But the US will appreciate the EU restricting imports to those countries that act on methane emissions," Paulus told Argus. The text agreed between negotiators has to be formally adopted by parliament and by EU ministers. The regulation would then apply directly in the 27 EU states on publication in the bloc's official journal. Oil, gas and coal importers would, from 1 January 2027, have to demonstrate equivalent monitoring, reporting and verification requirements at production level. And the European Commission would, within three years, have to propose delegated legislation setting methane intensity classes for producers' and companies' crude, natural gas and coal sold in the EU. Individual EU states retain the right to set penalties. Parliament failed to have a provision for closing the EU market to non-compliant producers. "On imports, I'm not so much worried about loopholes," said Paulus. "I'm more worried about a very very long timeline [till 2030]. The measures on imports will come pretty late and will not have an effect until at least 2028 when we have equivalency on monitoring, reporting and verification [of methane emissions]." The regulation obliges oil and gas operators in the EU to detect and repair methane leaks, and to submit a methane-leak detection and repair programme to national authorities within nine months from the regulations' entry into force. A first leak-detection and repair survey of existing sites would have to take place within 12 months. There are strengthened repair obligations and general bans on venting and flaring methane from drainage stations and ventilation shafts. For coal, EU countries have to measure and report methane emissions from operating underground and surface mines. For mines closed or abandoned in the past 70 years, countries have to draw up public inventories and measure emissions, except for mines flooded for more than 10 years. Coal mine flaring is banned from 1 January 2025 and venting from 1 January 2027, if those mines emit over 5t of methane per kilotonne of coal mined. Venting and flaring is banned from closed and abandoned mines from 1 January 2030. Paulus regretted a "no go" from EU member states and commission for including methane emissions from the petrochemicals sector. But she said the commission will make sure that updated implementing rules to the bloc's Industrial Emissions directive, so-called Best Available Techniques (BAT), will be amended to include petrochemicals in 2030. "The rules will be copy-pasted from the methane regulation," she said. Paulus noted inclusion of an overarching methane target cut in the regulation would have excluded emissions from agriculture and waste, which the European Environment Agency (EEA) notes as responsible respectively for 53pc and 26pc of EU methane emissions compared with the energy sector's 19pc.
Gazprom to ship 40.5 mcm of gas to Europe via Ukraine on Monday - Russia's Gazprom said it would ship 40.5 million cubic metres of gas to Europe via Ukraine on Monday, a slightly lower volume than in recent days.
Russian crude exports are rising despite pledge to cut, helping keep oil prices in check -Russia may be helping fuel the steady decline of global oil prices, despite Moscow's commitment to limit its exports.Crude oil shipments from the OPEC+ member's western port have risen since September, according to E.A. Gibson Shipbrokers data cited by the Wall Street Journal reported.That coincided with a nearly 13% slide in Brent crude.The international benchmark now trades at around $82 a barrel, despite earlier forecasts that it could reach $100.And even the latest report from OPEC on Monday also appeared to acknowledge the increase in crude flows. While it said refined product exports are down, the oil cartel noted seaborne crude shipments out of Russia rose.Russia has vowed to curb crude exports by 300,000 barrels per day, in a deal reached with OPEC-leader Saudi Arabia.But October's seaborne outflows totalled 3.54 million barrels per day, surpassing the limit by about 300,000 barrels per day, according to Rystad Energy. It added that as refinery activity in Russia rebounds, less crude oil will likely be exported.As global benchmark oil prices fall, Russia's Urals crude is also trending lower. Last week, it traded at $66.19, according to data cited by Bloomberg, closer to the $60-per-barrel price cap imposed by the West late last year for Moscow's invasion of Ukraine.
US To Sanction Shippers of Russian Oil Over Price Cap Violations - On Thursday, the US Treasury Department imposed a set of new sanctions on ships and companies accused of using American service providers to ship Russian crude oil above the $60 price cap. The cap, imposed by the US and the Group of Seven (G7) nations in late 2022, was meant to deprive the Kremlin of funds for its war effort, but that strategy has failed.Three firms based in the United Arab Emirates and three ships wereblacklisted from transferring oil and other products with US service providers. Last month, the Treasury issued its first sanctions over violations of the Russian oil price cap and notified shipping management firms in more than 30 countries that Washington is seeking information regarding 100 vessels it believes are dodging sanctions.“We are committed to maintaining market stability in spite of Russia’s war against Ukraine, while cutting into the profits the Kremlin is using to fund its illegal war and remaining unyielding in our pursuit of those facilitating evasion of the price cap,” boasted Wally Adeymo, the deputy secretary of the Treasury. It’s been almost a year since the price cap was implemented and Moscow has seen an “almost complete export volume recovery” in oil, Chris Weafer, the chief executive officer of strategic consultants Marco-Advisory Ltd,told Newsweek.He continued, highlighting that Russia shipped 3.5 million barrels of crude per day last month via tankers, along with 1.2 million barrels through the East Siberia pipeline. In August, Russia was selling oil at an average price of $74 per barrel. Weafer also notes Russia has seen further gains as a result of the Brent crude price increasing from $70 to $95 per barrel between July and September.In response to the sanctions and the price cap, the Kremlin continued looking east and selling its oil to non-sanctioning countries. Last year, Moscow became the top crude supplier to India and China. Russia has also been using a “shadow fleet” of vessels to circumvent the Western economic penalties.Weafer says Washington and the G7 expected to be dealing with the “old tanker market structure… [assuming Russia would be using a] few very big tanker operators with large fleets that would have been easy to monitor and enforce.”However, he says, “what has emerged is a greatly dispersed fleet ownership with the flexibility to disappear and reappear with a new name faster than the G7/EU can catch them.”At any rate, Washington and NATO’s proxy war with Russia in Ukraine has been a disaster. As EUROCOM chief General Christopher Cavoli explained to Congress earlier this year, Russia’s navy and air force have taken negligible losses and its ground forces are “bigger today” than when the war began. The Pentagon is depleting its own weapons stocks to support Kyiv’s failing war effort, while Russia’s capacity to produce armor and ammo hasoutstripped the entire NATO alliance.Ukraine has lost 20% of its country, the Kremlin gained more territory than Kyiv this year, and Ukrainian forces are estimated to have suffered tens of thousands of casualties during recent months. Despite all this, the White House is still seeking roughly $60 billion from Congress to continue funding the war through next year’s presidential election. In September Russia’s Finance Ministry published a document explaining that Moscow will ramp up defense spending by 68% to 10.8 trillion rubles ($111.15 billion) next year.
Disclosed Oil and Gas Contract Value Drops in Q3 -The oil and gas industry’s overall disclosed contract value witnessed a quarter on quarter decrease of 26 percent in the third quarter. That’s what GlobalData noted in a release sent to Rigzone this week, which outlined that the company’s latest report showed that overall contract value decreased from $57.4 billion in the second quarter to $42.6 billion in the third quarter. Contract volume also saw a drop from 1,425 in the second quarter to 1,128 in the third quarter, GlobalData stated in the release. According to a chart included in the release, which showed oil and gas industry contracts by scope in the third quarter, there were 663 contracts during the period with an operations and maintenance scope. There were 165 deals with a procurement scope, 147 contracts with multiple scopes, 88 contracts with a design and engineering scope, 61 contracts with a construction scope, and four contracts with an installation scope in the third quarter, the chart revealed. In the release, GlobalData highlighted that HD Hyundai Heavy Industries’ agreement with QatarEnergy for the construction of 17 LNG carriers and the National Petroleum Construction Co/Tecnicas Reunidas consortium’s contract from ADNOC Gas for the expansion of gas processing infrastructure at the Habshan complex were “some of the notable contracts during the quarter”. The company pointed out that McDermott International’s contract from Qatargas Operating Company for Engineering, Procurement, Construction, and Installation services for the North Field Production Sustainability COMP1 project “is the other major contract in the quarter”. “The ongoing geopolitical tensions and the unpredictable fluctuations in crude oil prices are significantly dampening the overall sentiment within the oil and gas sector,” Pritam Kad, an oil and gas analyst GlobalData, said in the release. “This is translating into a notable slowdown in projects/contracts activity reflecting a cautious approach among key stakeholders,” Kad added. In a separate release sent to Rigzone back in August, GlobalData revealed that the overall oil and gas industry’s disclosed contract value jumped 60 percent in the second quarter, “mainly driven by a mega contract for Qatar’s North Field South LNG project”. The company’s latest report at the time showed that overall contract value increased from $35.4 billion in the first quarter to $56.7 billion in the second quarter, that release outlined. Contract volume dropped from 1,625 in the first quarter of 2023 to 1,256 in the second quarter, the release pointed out.
China independent refineries see govt raising fuel oil import quota: sources - China's small independent refineries expect the government to raise the fuel oil import allowance for 2023 to allow them to bring in more barrels as an alternative feedstock for the remainder of the year, refining sources told S&P Global Commodity Insights Nov. 14. There has been widespread talk that the government would likely raise the 2023 fuel oil import allowance by 3 million mt for non-state-owned enterprises as the quotas are running out under the annual limit of 16.2 million mt set at the beginning of the year. The annual limits have been kept stable for several years as the fuel oil quotas were more than sufficient either due to slow refining demand or abundant crude oil imports. Unlike quotas for importing crude oil or exporting oil products, which are allocated to each oil firm, refineries or oil companies are required to apply for the fuel quota cargo by cargo until the annual limit is reached, in a first-come-first-served manner. But this year, due to the combination of competitive prices of Russian fuel oil, strong refining margins in the first half of the year and tight crude import quota availability, small independent refineries had almost used up the 16.2 million mt fuel oil import quotas as of the end of October, according the refining sources. China imported 17.38 million mt of fuel oil in the first nine months of 2023, more than double the 7.65 million mt in the same period last year, according to customs data. The imports include barrels saved in bonded warehouses, which do not consume fuel oil import quotas. Some small independent refineries have paid about Yuan 10/mt ($1.37/mt) to procure imported fuel oil via state-run trading houses by using their import quotas for state-run enterprises, the sources said. "The shortage of fuel oil quotas has not had much impact on the volume of fuel oil, but the cost is higher," a source at a Dongying-based independent refinery said. A Shandong-based analyst said: "Some independent refineries will likely take this chance to import a few more cargoes of fuel oil, but the supply seems to be a bit tight, capping imports." The Dongying-based refinery source said the import cost of Russian M100 fuel oil was "slightly lower than the cost of some crudes, making it attractive as a feedstock." A trade sources said fuel oil had become "a bit economic as the price basis of MOPS has come off more than that of ICE Brent, which made it possible for independent refineries to replenish the barrels as a feedstock." Russian M100 fuel oil was offered at a premium of around $70-$75/mt against the MOPS 380 CST HSFO assessment, which was up from deals done at around $65-$70/mt last week, sources said. Some trading sources also said the tight crude import quota availability was the main reason behind the growing appetite of independent refineries for imported fuel oil, sources said.
Iran's Booming Oil Exports Threatened By Looming Gas Shortages | Iran International - A senior Iranian oil industry official has warned of the detrimental effects of the country’s gas shortages on its oil production. Erfan Afazeli, the chairman of the Iranian Federation of Petroleum Industry, explained to ILNA that Iran needs to inject gas to its oil reservoirs to maintain the production flow, warning if not, “it will result in significant damage." He said the necessary measures would help maintain or increase the pressure within the oil reservoir to push the oil towards the extraction wells; and would enhance oil recovery for the oil that would otherwise be left behind, known as Enhanced Oil Recovery (EOR). The process is essential for maximizing the extraction of oil from a field. “Currently, our oil recovery factor is less than 20 percent,” he said, claiming that “every one percent increase in the oil recovery factor from oil fields will result in nearly one billion barrels of extra production. Therefore, in the event of the inability to inject gas, the amount of damage is unpredictable.” Iran’s Oil Minister Javad Owji claimed earlier in the month that the country is producing 3.4 million barrels per day (mb/d) of crude oil, about 1.2 mb/d more than in mid-2021. Stressing the significance of gas injection for both maintaining current production levels and increasing future production, Afazeli said that Iran’s enhanced oil recovery projects are not implemented due to a lack of know-how and insufficient capital. “Firstly, we lack the necessary technology for enhanced oil recovery. Secondly, and more importantly, we lack the capital required for these projects,” he said. He bemoaned the fact that currently a significant portion of the produced gas is wasted in the residential sector due to the absence of consumption optimization. Afazeli referred to North Pars Gas Field -- one of the biggest independent gas fields of the world located some 120 kilometers southeast of Bushehr province in water depths of 2 to 30 meters in the Persian Gulf. The field has the potential for increased gas extraction and injection. “For instance, with an investment of approximately $4 billion, North Pars can be brought into operation to extract and inject gas," he said. He warned that “without gas injection and pressure maintenance in the coming years, Iran will face a daily decrease of around 20 to 25 million cubic meters in gas production.” While he said current production and extraction is 600 million cubic meters of gas per day from South Pars, he warned that "it is certain that there will be a decline in production starting in a few years”. He suggested that to enhance recovery in oil and gas fields, "we need an investment of $80 billion, and this capital is contingent on cooperation with the world,” referring to the regime's economic and political isolation on the global stage. His remarks came as a confirmation to an Iran International article which warned that without re-injecting natural gas into oil deposits, some fields might become unproductive, leading to substantial economic losses for the country's oil sector.
India asks OPEC to ensure oil market stability - India, the world's third largest oil consumer, has asked oil producers cartelOPEC to maintain and ensure market stability for the benefit of consumres, producers and global economy. Oil Minister Hardeep Singh Puri said this at the 6th India-OPEC Energy Dialogue that took place on November 9 in Vienna, an official press statement said on Monday.The meeting was co-chaired by OPEC secretary general Haitham Al Ghais and Puri."The open and candid discussions at the meeting focused on key issues related to oil and energy markets with a specific emphasis on ensuring availability, affordability and sustainability, which are necessary in ensuring the stability of energy markets. The two sides discussed the short, medium and long-term outlooks for the industry and recognized the important role of India in global economic growth and energy demand," the statement said.At the meeting, Puri highlighted that as the third-largest energy consumer, crude oil importer and the fourth-largest global refiner, close ties between India and OPEC are not only essential but also natural."He added that as India remains on a trajectory of stable and robust economic growth, fostering deeper collaboration for the mutual benefit of both parties has the potential to contribute significantly to the long-term prosperity and stability of the global oil markets," the statement said. "In this context, he called on OPEC to continue playing its key role in maintaining and ensuring market stability for the benefits of consumers, producers and global economy."
Opec upgrades 2023 oil demand growth forecast -Opec upgraded its oil demand growth forecast for 2023 and said "exaggerated negative sentiments" explain the recent slide in oil prices. In its Monthly Oil Market Report (MOMR), published today, Opec revised up its 2023 oil demand growth forecast by 20,000 b/d from last month to 2.46mn b/d. This was mainly driven by third and fourth quarter upgrades to China's oil demand growth, which Opec now sees at 1.14mn b/d in 2023, up by 70,000 b/d. "Recent data confirm robust major global growth trends and healthy oil market fundamentals," it said. Opec said China's crude imports increasing to 11.4mn b/d in October and remained on track to reach a record this year, "despite the overblown negative sentiment" regarding the country's oil demand. It said India's crude imports will pick up in the fourth quarter to reach a record high this year. Opec revised up its fourth quarter global oil demand forecast by 150,000 b/d compared with last month, to 103.28mn b/d. It kept its 2024 oil demand growth forecast unchanged at 2.25mn b/d. The group said the recent fall in oil prices was "mainly driven by financial market speculators" that "sharply reduced their net long positions over the month of October, compared to the late September." Front month Ice Brent has been on a downward spiral in the past few weeks, falling from around $93/bl in mid-October to around $82/bl as of midday London time today. The group increased its non-Opec liquids supply growth forecast for this year by 100,000 b/d and once again upgraded its supply forecast for Russia. It now sees non-Opec liquids supply rising by 1.78mn b/d this year, compared with a 1.68mn b/d increase in last month's forecast. The revision was mainly driven by upgrades to Russian, US and Brazilian supply, partly offset by downward revisions from Canada and Norway. Opec expects sanctions-hit Russia to produce 10.61mn b/d of liquids in 2023, 80,000 b/d more than in last month's projection. It forecasts Russian supply will remain at 10.61mn b/d next year. Opec's call on its members' crude was revised down by 50,000 b/d in 2023 and 2024 to 29.08mn b/d and 29.88mn b/d, respectively. The group produced 27.9mn b/d of crude last month, up by 80,000 b/d from September, according to an average of secondary sources that includes Argus.
Oil Rebounds After OPEC Lifts Global Oil Demand Outlook -- Oil futures moved higher on Monday at the start of a new trading week. Investors looked past Moody Investors Service's U.S. credit rating downgrade ahead of another deadline to reach a debt ceiling agreement on Capitol Hill to instead focus on the outlook for fuel demand following upbeat projections from the Organization of the Petroleum Exporting Countries. Saudi-led OPEC dismissed an "exaggerated negative sentiment" on the oil markets, blaming the recent decline in oil prices on speculators and hedge fund managers. Oil prices have declined in each of the past three weeks, sending the international crude benchmark Brent contract below the $80-a- barrel (bbl) mark on Nov. 9 for the first time since mid-summer. In its Monthly Oil Market Report released Monday morning, OPEC asserts physical market fundamentals are "strong and supportive" due to solid demand growth in China and India -- Asia's two largest oil consuming nations. "Despite the overblown negative sentiment in the market regarding China's oil demand performance, and global oil market in general, the latest data shows Chinese crude imports increasing to 11.4 million barrels per day (bpd) in October and remaining on track to reach a new annual record high for this year," according to OPEC's MOMR. As such, OPEC lifted its global oil demand growth outlook to 2.5 million bpd this year, up from 2.44 million bpd in the previous month's outlook. OPEC said despite healthy and supportive market fundamentals, financial market speculators have sharply reduced their net long positions over the month of October compared to late September, particularly in NYMEX West Texas Intermediate futures and options contracts. The producer group pointed to data that showed hedge funds and other money managers sold an equivalent of 161 million bbl and 43 million bbl of NYMEX WTI and ICE Brent futures and options contracts, respectively. In total, they have sold an equivalent of more than 200 million bbl of oil since late September, reducing their bullish positions by 37%. In broader markets, investors seemed to shrug off Moody's weekend downgrade for the outlook on U.S. credit rating, with the agency lowering the credit rating from stable to negative ahead of a potential federal government shutdown on Friday, Nov. 17. The key drivers for the outlook change are the downside risks to U.S. fiscal strength and high interest rates that are expected to sustain large fiscal deficits in the near-term, which, in turn, will significantly weaken debt affordability for the U.S. government. "Continued political polarization within U.S. Congress raises the risk that successive governments will not be able to reach consensus on a fiscal plan to slow the decline in debt affordability," said Moody's. The credit rating agency maintained however U.S. long-term and foreign-currency country ceilings at a AAA rating, citing the central roles of the U.S. dollar and Treasury bond market in the global financial system among other factors. At settlement, NYMEX December WTI futures added $1.09 to $78.26 bbl, with January WTI closing the session with a $0.07 bbl discount against the front-month contract. ICE January Brent futures settled the session $1.09 higher at $82.52 bbl, while the next month February contract expanded the discount to the prompt month to $0.33 bbl. NYMEX December RBOB futures rallied to $2.2359 gallon, up $0.0464, and NYMEX December ULSD futures advanced $0.0962 to $2.8393 gallon.
The Oil Market on Wednesday Erased Some of its Recent Gains Following the Larger Than Expected Builds in U.S. Crude Stocks - The oil market on Wednesday erased some of its recent gains following the larger than expected builds in U.S. crude stocks. The oil market traded to a high of $78.77 in overnight trading amid the news that China’s economic activity grew in October as industrial output increased at a faster pace and retail sales growth surpassed expectations. However, weighing on demand was a decline in China’s refinery throughput in October amid weakening industrial fuel demand. The crude market erased its gains ahead of the release of the EIA’s petroleum stock report on Wednesday morning. It extended its losses to $1.95 as it sold off to a low of $76.31 on the close following the release of the inventory report, which showed a build of 3.6 million barrels in the week ending November 10th while U.S. domestic production remained at a record 13.2 million bpd. The December WTI contract settled down $1.60 to $76.66 and the January Brent contract settled down $1.29 at $81.18. Meanwhile, the product markets ended the session in mixed territory, with the heating oil market settling up 3.16 cents at $2.8687 and the RB market settling down 2.1 cents at $2.2018. The EIA reported that total U.S. crude oil inventories in the week ending November 10th increased by 3.6 million barrels. It reported that East Coast crude stocks increased by 800,000 barrels to 9.5 million barrels, the highest level since November 2021. The Financial Times reported that Denmark will be tasked with inspecting and potentially blocking tankers carrying Russian oil through its waters under new European Union plans. The FT said that Denmark would target tankers carrying Russian oil that did not have Western insurance, a step that would hit Russian oil export income hard while impacting Russian oil production and refinery business. In response to the report, the Kremlin said it was necessary to caution everyone that the rules of international commercial shipping needed to be observed after the Financial Times reported that Denmark could block Russian oil from reaching world markets. Kremlin spokesman Dmitry Peskov said that he had no information about such a move. When asked if Russia might escort tankers with Russian oil if Denmark moved ahead with the alleged plan, he said that Russia did not make such grave decisions based on newspaper reports. A spokeswoman for the Russian Foreign Ministry, Maria Zakharova, said that all vessels, including Russian ones, has free passage through the Baltic Sea and said that any attempt to violate international law on the free movement of shipping was dangerous. Amrita Sen, co-founder of consultancy Energy Aspects, said Saudi Arabia is expected to extend its additional voluntary supply cuts to at least the first quarter, if not the first half of 2024. She said current oil prices are not low enough to push OPEC+ to deepen supply cuts in 2024. The next OPEC+ ministerial meeting is scheduled for November 26th to discuss market outlook. IIR Energy said U.S. oil refiners are expected to shut in 787,000 bpd of capacity in the week ending November 17th, increasing available refining capacity by 602,000 bpd. It reported that offline capacity is expected to fall to 264,000 bpd in the week ending November 24th.
Chinese Refinery Slowdown, US Output Surge Drive Global Oil Prices Down 5% -Global oil prices fell by nearly 5% Thursday, continuing a nearly two month decline amid rising U.S. oil supply and sluggish Chinese refinery output.U.S. West Texas Intermediate crude (WTI) prices were down by 4.75% as of 12:40 PM (EST) on Thursday, at $73.02 per barrel.WTI prices were $93.68 per barrel at the close of business on Sept. 27; current prices reflect a 22% decline over that seven-week period.The UK-origin Brent crude index was down by 4.80% Thursday ($77.28 per barrel), marking a 18% decline since its Sept. 27 peak.Despite prior projections of persistently high prices in the wake of OPEC+ production cuts and the outbreak of the Israel-Hamas War, global crude oil prices have followed a downward trajectory in response to increased oil output from non-OPEC+ members and news of slowing consumption in China.U.S. crude oil stockpiles rose by 3.6 million barrels in the week leading up to Nov. 10, the Energy Information Agency disclosed Wednesday, doubling experts' estimated predictions.The U.S. has produced record levels of crude oil in 2023, according to official data. Nationwide oil production topped 13 million barrels per day in October for the first time ever.The U.S. is the world's largest producer of crude oil and natural gas, with a total annual oil output comparable to that of the next largest producers, Russia and Saudi Arabia, combined.Slowing oil prices are likely to provide a further inflationary cushion; U.S. consumer prices were unchanged in October, the Department of Labor's Bureau of Labor Statistics reported Tuesday.
Oil Sinks Into Bear Market as Robust Supply Pressures OPEC+ -- Oil headed for a fourth weekly loss after sinking into a bear market as signs of healthy supplies and rising stockpiles offset attempts by OPEC+ leaders Saudi Arabia and Russia to keep declines in check. West Texas Intermediate traded near $73 a barrel after dropping more than 20% from a high in September. Global benchmark Brent plunged almost 5% on Thursday. The declines followed a build in US crude inventories, and were likely amplified by automated selling programs. Crude’s run of four straight weekly declines — the longest losing streak since May — has come despite collective and voluntary supply cuts by the Organization of Petroleum Exporting Countries and its allies. The losses have also been abetted by the evaporation of an Israel-Hamas war risk premium as fears the conflict would expand and disrupt oil supplies have so far not eventuated. The International Energy Agency said earlier this week that production growth means the global market won’t be as tight as had been expected this quarter, adding pressure on OPEC+ ahead of a meeting on its supply policy on Nov. 26. “We believe that OPEC will ensure that Brent oil prices end up in a $80-to-$100 range in 2024 by ensuring a moderate deficit and leveraging its pricing power,” Goldman Sachs Group Inc. analysts including Daan Struyven said in a note. The latest selloff was driven by non-OPEC supply topping expectations, they said. Data midweek showed nationwide US crude stockpiles expanded for a fourth week to hit the highest level since August. Some of that increase came at the key hub in Cushing, Oklahoma, where holdings expanded by more than 8%. There have also been some clouds on the demand horizon. Figures from China, the world’s largest importer of crude, showed that refiners cut daily processing rates in October as apparent oil demand fell from a month earlier. Meanwhile, US unemployment benefits rose to the highest level in almost two years, signaling a slowdown in the world’s biggest crude consumer. “The string of weak macro data, coupled with rising US crude stockpiles, triggered the sell-down in oil,” said Han Zhong Liang, investment strategist at Standard Chartered Plc. WTI prices are likely to be sluggish on the back of a slowing global economy, he added. Pricing patterns along the futures curve point to looser conditions. The spread between Brent’s two nearest contracts was 5 cents a barrel in contango — where near-term prices are below longer-dated ones — compared with more than $1 a barrel in backwardation a month ago.
Oil Futures Rebound After Selloff, Still Post 4th Weekly Loss -- After Thursday's steep selloff sent oil futures into a bear market, West Texas Intermediate and Brent crude retraced most of the losses on Friday, rallying 4% as the U.S. dollar index pulled back and traders looked ahead to the meeting among OPEC+ ministers that could deliver deeper production cuts to their supply accord. Despite Friday's rebound, the oil complex failed to break a four-week losing streak, with both WTI and Brent contracts falling more than 20% since their September highs. In technical terms, the oil market has entered a bear market. A combination of rising inventories in the United States, lower refinery runs in China and production gains outside of OPEC+ prompted investors to broadly reassess fundamentals in the physical oil market. Furthermore, the unwinding of geopolitical risk premium tied to the Oct. 7 surprise attack by Hamas on Israeli civilians added to bearish sentiment. This week's Energy Information Administration inventory report exacerbated the collapse of oil prices on Thursday, revealing commercial crude oil inventories in the U.S. increased by a massive 19.6 million barrels (bbl) in the four weeks ending Nov. 10. Domestic oil production, meanwhile, remained at a record high 13.2 million barrels per day (bpd). Faced with these headwinds, OPEC+ ministers are reportedly considering deeper production cuts when the group meets on Nov. 26, according to a Reuters report citing sources close to negotiations. Saudi Arabia, Russia and other OPEC+ producers have already pledged to extend a total of 3.66 million bpd in production cuts through the end of 2024. Additionally, Russia, and Saudi Arabia, the group's two largest producers, agreed to a voluntary 1.3 million bpd in production and export reductions through year's end. One OPEC+ source cited in the Reuters report said the existing curbs might not be sufficient to backstop volatility in the market and that the group would likely analyze if deeper cuts could be implemented. On the macroeconomic front, the number of Americans filing for initial unemployment claims jumped to a three-month-high 231,000 in the most recent week after rising for each but one of the past five weeks, according to data released Thursday from the U.S. Labor Department. Continued jobless claims, a proxy for the number of Americans receiving unemployment benefits on a recurring basis rose to a two-year-high 1.87 million in a clear sign of a growing slack in the labor market. Combined with moderation in consumer spending, a softer labor market doesn't bode well for U.S. gasoline demand heading into the holiday season. The most recent data from the U.S. Energy Information Administration showed gasoline demand nosedived 544,000 bpd for the first week of November to 8.949 million bpd, 103,000 bpd or 1.2% below last year's level. At settlement, NYMEX December WTI futures rebounded $2.99 to $75.89 bbl, with January WTI holding its premium against the front-month contract at $0.15. Lending support to the WTI contract, the U.S. dollar retreated 0.42% against a basket of foreign currencies to 103.795. ICE January Brent futures jumped $3.19 to $80.16 bbl and the next month's February contract settled the session at $80.50 bbl. NYMEX December RBOB futures added $0.0834 to $2.1845 gallon and NYMEX December ULSD futures gained $0.0223 to $2.7725 gallon.
US Official Says Up To Seven Killed in Latest US Airstrike in Eastern Syria - A US official told Reuters on Tuesday that up to seven people were killed in the US airstrikes in eastern Syria on Sunday that targeted Shia militias.If confirmed, the casualties are the first known deaths since the Biden administration began launching airstrikes in eastern Syria as US troops in the region have come under a spate of attacks due to US support of Israel’s onslaught on Gaza.The Pentagon said Tuesday that it’s still assessing the aftermath of the airstrikes. “We are aware that there were IRGC-affiliated members in the proximity of the facilities that were struck by our aircraft. But I don’t have more on casualty numbers or anything else to read out,” said Pentagon spokeswoman Sabrina Singh.Secretary of Defense Lloyd Austin said the strikes targeted facilities “used by Iran’s Islamic Revolutionary Guard Corps (IRGC) and Iran-affiliated groups” at two sites in eastern Syria’s Deir Ezzor province.The US official speaking to Reuters did not share any details about the people who were killed. The UK-based Syrian Observatory for Human Rights previously said that eight people were killed in the strikes and described them as “pro-Iran fighters,” including at least one Syrian and Iraqi nationals, but the SOHR report has not been confirmed.Attacks on US bases in Iraq and Syria have continued since the airstrikes were launched on Sunday, as Shia militia leaders have warned they’re not backing down until there’s a durable ceasefire in Gaza.The Pentagon said on Tuesday that the total number of attacks on US bases in Syria and Iraq since October 17 has climbed to 56. At least 59 US troops have been injured, including 32 listed with “non-serious” injuries and 27 suffering from traumatic brain injuries.
Israel Will Ignore UN Security Council Resolution Calling for Pause in Fighting in Gaza - The UN Security Council passed a resolution on Wednesday that called for a temporary pause to the fighting in Gaza. Tel Aviv said the call for a short peace was a decision “disconnected from reality and holds no significance.”The resolution passed the UN’s most powerful body in a vote of 12-0. The US and UK did not vote for the motion because it did not condemn Hamas. Russia abstained over concerns that the resolution did not make a strong enough call for peace. Moscow’s representative said Washington is responsible for removing the word “ceasefire” from the text.The resolution called for “urgent and extended humanitarian pauses” in Gaza to allow aid to reach Palestinian civilians and for “the immediate and unconditional release of all hostages held by Hamas and other groups, especially children, as well as ensuring immediate humanitarian access.” The AP reports the language in the resolution was watered down.In response to the Security Council passing its first resolution on the war in Gaza, Tel Aviv said it would ignore the call for a humanitarian pause. “The decision is disconnected from reality and holds no significance,” Israel’s ambassador to the UN, Gilad Erdan, said. “Israel already operates in Gaza according to international law, while Hamas terrorists will ignore the decision and certainly not act in accordance with it. Israel will continue its actions until the destruction of Hamas and the return of the kidnapped.”Tel Aviv has resisted all calls or agreements even to pause its onslaught against Gaza. VICE News reports Prime Minister Benjamin Netanyahu rejected a hostage agreement because he wanted to free the captives using the Israeli military. “It’s clear the Israelis wanted a ground offensive underway before considering this proposal, which has been on the table since the first days of the conflict,” a regional diplomat said.A NATO official told the outlet, “Netanyahu can now look at the Israeli public and tell them his firm action with the ground offensive is what freed some hostages.” The source added, “[Netanyahu] sees a short-term political gain to arguing the offensive forced Hamas into concessions but he doesn’t seem to fear explaining how hostages might have died in air strikes while the same deal was available.”The New York Times reported on Wednesday that Tel Aviv raided the al-Shifa Hospital, the largest and most modern medical facility in Gaza, to pressure Hamas into accepting an agreement on Israeli terms. Tel Aviv has been pushing for a hostage release that includes as short a pause to fighting as possible.Israeli War Cabinet Minister Benny Gantz says even if Tel Aviv agrees to a short pause to military operations in Gaza, it plans to settle the war with its military. “Even if we are required to pause fighting in order to return our hostages, there will be no stopping the combat and the war until we achieve our goals,” he said.
Israel's Other War: Ethnic Cleansing in the South Caucasus - – Over the past month, legacy and social media have been saturated with reports of the Netanyahu regime’s war on Gaza, which is being met with growing calls from the international community to invoke the 1948 Convention on the Prevention and Punishment of the Crime of Genocide.Less known, however, is the role the Israeli government has played in another genocide that took place in West Asia only a month and a half ago. This genocide, little noted in the Western press, involved the ancient Christian community of Armenians in Nagorno-Karabakh, known within Armenia as the Republic of Artsakh, that was ethnically cleansed by the Ilham Aliyev, the Shia dictator of Azerbaijan, in late September and early October. The muted response to Azerbaijan’s crime might plausibly be chalked up to the strength of its well-funded and influential lobby in Washington which profits off of the oil and gas revenue generated by SOCAR, the State Oil Company of the Azerbaijan Republic. SOCAR has links to the Podesta Group (co-founder John Podesta currently serves as a senior adviser to President Biden), lobbying powerhouse BGR Government Affairs, LLC, as well as numerous think tanks and academics associated with, among others, The Johns Hopkins University School of Advanced International Studies (SAIS) and the American Foreign Policy Council.Yet another reason for the subdued response by Washington is the well documented ‘special relationship’ between the 51st US state, Israel, and Azerbaijan. A discussion I had last week with the Armenian academic Dr. Benyamin Poghosyan, who serves as Chairman of the Center for Political and Economic Strategic Studies and Senior Research Fellow on Foreign Policy at the Applied Policy Research Institute (APRI) of Armenia, shed some light on the role the Israeli government and its defense industry has played in enabling Azerbaijan – and why.The relationship between the two countries began to deepen around 15 years ago when Azerbaijan, flush with revenue from its oil and gas deposits in the Caspian basin, began looking to purchase advanced weapons systems.According to Poghosyan, “as late as September 2023, just before the most recent Azerbaijani attackseveral cargo planes went to Israel and came back to Azerbaijan full of weapons. And there is even information that Israel continued to supply weapons to Azerbaijan even after October 7th.”The AP reports that it is estimated that Israel has supplied Azerbaijan with “nearly 70% of its arsenal between 2016 and 2020.”And just this week it was reported that Azerbaijan inked a $1.2 billion dollar deal with Israel Aerospace Industries to purchase the Barak MX air defense system, described as “a modular air defense system… designed to address missile and aircraft threats.”According to Poghosyan, Azerbaijan has agreed “to allow Israel to use their territory for anti-Iranian activities. And we are speaking about covert activities, foreign intelligence… Azerbaijan gave the green light to Israeli special services, especially its foreign intelligence service, to do whatever they want in Azerbaijan. Of course now they have access to that security zone around Nagorno-Karabakh, which borders Iran.”Poghosyan notes that in recent years (in the aftermath of its earlier attempt to subjugate Nagorno Karabakh in 2020) Azerbaijan constructed two airports in the territory it gained around Nagorno Karabakh. “They are,” says Poghosyan “supposedly civilian airports, yet they are located very close to Azerbaijani-Iranian border – a distance of 30, 40 kilometers from the border. There are a lot of reports that Israeli military intelligence or foreign intelligence operatives are using these airports for operations against Iran.”Israel’s role in assisting Azerbaijan’s ethnic cleansing of Nagorno-Karabakh is well known inside Israel, which it must be said, conducts a far more robust debate over Israel’s foreign policy than is allowed here in the United States.The estimable Israeli newspaper Haaretz recently editorialized that Israel has, in their words, “its fingerprints” all over Azerbaijan’s ethnic cleansing in Nagorno-Karabakh. Haaretz also contends that “Israel hasn’t just supplied Azerbaijan with arms. It has also helped it distort history” by its refusal to recognize the Armenian genocide, which the Israeli regime merely defines as a “tragedy.”