US natural gas supplies back to pre-winter average on Freeport outage; US oil supplies at a 21½ year low, Strategic Petroleum Reserve at a 38½ year low, oil + oil products supplies at an 18 year low; global oil supply & demand nearly balanced in October, even with OPEC's production 1,585,000 barrels per day short of quota..
US oil prices finished lower again this week as Covid cases in Beijing rose to record highs and the Fed signaled interest rates could go much higher, assuring a deeper recession... after falling 3.9% to $88.96 a barrel last week as a widening Covid outbreak in China and subsequent lockdowns drove global prices lower, the contract price for the benchmark US light sweet crude for December delivery fell more than $1 in Asian trade on Monday, dragged down by a firmer US dollar and a weekend surge in coronavirus cases in China, the world's largest crude importer, and then dropped 3.7% to a session-low $85.65 a barrel in New York after the dollar strengthened further following comments by several Fed officials that it's way too soon to claim any victory over inflation, before settling down $3.09 on the day at $85.87 a barrel, with prices further hit by reports suggesting Russian crude oil exports were holding steady ahead of a European embargo on seaborne oil shipments, after OPEC had lowered its global demand forecast for this year and next...oil prices tumbled another 2% in overseas markets early Tuesday after the IEA also forecast weakening demand growth next year and as traders fretted about a weakening demand outlook. but then jumped following unconfirmed reports that Russian missiles had hit Poland overnight, and settled $1.05 higher at $86.92 a barrel after news broke that oil supplies to Hungary via the Druzhba pipeline had been temporarily suspended due to a fall in pressure...crude prices continued higher on Wednesday morning after a bomb-carrying drone struck an oil tanker owned by an Israeli billionaire off the Omani coast, but turned lower as Covid cases in China continued to climb, outweighing supply concerns, and settled $1.33 or 1.5% lower at $85.59 a barrel after Russian oil shipments via the Druzhba pipeline to Hungary restarted and as rising COVID-19 cases in China weighed on sentiment....oil prices fell for a second day in early Asian trade on Thursday, as concerns over geopolitical tensions eased and rising numbers of Covid-19 cases in China added to demand worries, and then slid more than 4% to $81.64 a barrel during the US session as traders recalibrated their bets for a deeper recession next year after the dollar rallied when Fed officials signaled interest rates could go much higher than had been priced in by markets....oil prices moved lower again early Friday and were trading at the lowest level since September after European Central Bank President Christine Lagarde said recession alone might not be enough to bring down consumer prices and finished the session down $1.56, or 1.9% at $80.08 a barrel, on concerns about weakened demand in China and further increases to U.S. interest rates, and thus finished the week 10.0% lower dropping the most in a week since April, as the full weight of languishing Chinese demand and more economic tightening radically shifted the market’s sentiment...
Natural gas prices, on the other hand, finished higher for the third time in four weeks, on colder forecasts and an end to the storage injection season.....after falling 8.1% to $5.879 per mmBTU last week after a Twitter spoof reporting a delay in Freeport LNG's reopening led to a 9% drop in prices on Friday, the contract price of US natural gas for December delivery jumped more than 5.5% to open at $6.277 per mmBTU on Monday after Freeport dismissed last week's twitter claims, but tumbled to show losses after Bloomberg reported that Freeport LNG had told customers that its reopening would be delayed, but recovered to close 5.4 cents higher at $5.933 per mmBTU as the weather shifted substantially colder, driving heating demand and offsetting festering concerns about Freeport's relaunch...natural gas prices moved up almost 2% on Tuesday to settle 10.1 cents higher at $6.034 per mmBTU, on forecasts for colder weather and more heating demand next week than previous estimates, even as doubts about the timing of the Freeport LNG export terminal’s return, which had been slated for this month, continued to simmer...but the December contract opened 17 cents lower on Wednesday, with warming forecasts and the delay of the Freeport LNG reopening contributing to the overnight retreat, but reversed on a colder midday forecast to settle 16.6 cents, or 2.8% higher at $6.200 per mmBTU....prices were up a fourth consecutive day on Thursday, rising 16.9 cents to $6.369 per mmBTU, on cold weather and mounting heating demand that pointed to steep storage withdrawals following what analysts expected was the last reported injection of the year...but natural gas prices tumbled more than 5% early Friday after Freeport LNG said it was now targeting a mid-December restart for its export plant, but recovered to finish just 6.6 cents lower at $6.303 per mmBTU, as forecasts “held very strong national demand” leading up to Thanksgiving but pointed to a return to seasonal levels and “a little lighter-than-normal” demand for several days at the end of the month...but natural gas prices still finished 7.2% higher on the week, despite the delay of the Freeport export plant reopening, which would leave roughly 2% more natural gas for stateside domestic use until that time...
The EIA's natural gas storage report for the week ending November 11th indicated that the amount of working natural gas held in underground storage in the US rose by 64 billion cubic feet to 3,644 billion cubic feet by the end of the week, which means our gas supplies were now 4 billion cubic feet, or 0.1% more than the 3,640 billion cubic feet that were in storage on November 11th of last year, while still 7 billion cubic feet, or 0.2% below the five-year average of 3,656 billion cubic feet of natural gas that were in storage as of the 11th of November over the most recent five years....the 64 billion cubic foot injection into US natural gas working storage for the cited week was close to the average forecast for an injection of 63 billion cubic feet from a Reuters poll of analysts, but it was much more than the 23 billion cubic feet that were added to natural gas storage during the corresponding week of 2021, and contrasts with the 5 billion cubic feet of natural gas that have typically been withdraw from our natural gas storage during the same week over the past 5 years...
you might note that we're now heading into winter with our natural gas supplies close to the average pre-winter high, after concerns arose almost weekly since early summer that we might go into winter with inadequate supplies and possible spot shortages....to show how we recovered to normal levels so quickly, we'll include a copy of an interactive graphic from the EIA's natural gas storage dashboard below...
the above graphic shows, as a series of blue dots, the change in the amount of natural gas we had in storage each week since the beginning of this year, with weeks when we added natural gas to storage indicated by a blue dot above the zero line, and weeks when we pulled natural gas out of storage indicated by a blue dot below the zero line...shown in the background to that, there are dark grey diamonds indicating the 5 year average of the amount added or pulled out of storage in the same week, and in light grey bars behind that, the range of changes for each date over the prior five years...to illustrate what each entry shows, i have positioned my cursor over the current week, November 11, so that its data appears in a box on the graph...
as you can see on the graphic, eight of the past nine weeks saw an addition of natural gas to storage that exceeded the 5 prior years of historical data for each given week...two of those weeks, for September 30 and October 7th, represent 5 year highs for any date, and the largest autumn additions to storage on record...before that 9 week run of exceptional storage builds, we were reporting that our natural gas supplies were "354 billion cubic feet, or 11.3% below the five-year average of 3,125 billion cubic feet of natural gas that were in storage as of the 9th of September" so we have since eliminated 347 billion cubic feet of our deficit to the 5 year average over that nine weeks, and we're now only 0.2% below that running 5 year average for this time of year....
while our mild autumn weather certainly contributed to those above normal storage additions, as large parts of the country were experiencing weeks of weather without much demand for either heating or cooling, the largest single factor that allowed us to rebuild our natural gas inventories before winter was June 8th fire and explosion and subsequent shutdown of the Freeport liquefaction and export facility in Texas...that LNG plant had been processing up to 2.1 billion cubic feet of gas a day for export, and once it was shut down, that gas became available for domestic use, and that's what enabled us to rebuild our natural gas supplies before winter...if Freeport had been operating and exporting the LNG equivalent of 2.1 billion cubic feet of gas a day since June 8, it would have sent the equivalent of 349.5 billion cubic feet of natural gas overseas by now, and we'd be heading into winter with our supplies nearly 10% below normal...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending November 11th indicated that after a big drop in our oil imports and a modest increase in our oil exports, we needed to pull oil out of our stored commercial crude supplies for the 8th time in 14 weeks, and for the 16th time in the past 30 weeks. despite another big release of oil from the Strategic Petroleum Reserve....Our imports of crude oil fell by an average of 895,000 barrels per day to average 5,559,000 barrels per day, after rising by an average of 249,000 barrels per day during the prior week, while our exports of crude oil rose by 341,000 barrels per day to 3,862,000 barrels per day, which together meant that the net of our trade in oil worked out to an import average of 1,697,000 barrels of oil per day during the week ending November 11th, 1,236,000 fewer barrels per day than the net of our imports minus our exports during the prior week. Over the same period, production of crude from US wells was reportedly unchanged at 12,100,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have averaged a total of 13,797,000 barrels per day during the November 11th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 16,152,000 barrels of crude per day during the week ending November 11th, an average of 63,000 more barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net average of 1,357,000 barrels of oil per day were being pulled out of the various supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures from the EIA for the week ending November 11th appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 997,000 barrels per day less than what our oil refineries reported they used during the week. To account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+997,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet in order to make the reported data for the daily 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 must have been an omission or error of that magnitude in this week’s oil supply & demand figures that we have just transcribed....however, since most everyone treats these weekly EIA reports as gospel, and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
This week's 1,357,000 barrel per day decrease in our overall crude oil inventories left our oil supplies at 827,474,000 barrels at the end of the week, which was our lowest total oil inventory level since March 23rd, 2001, and therefore at a 21 1/2 year low...Our oil inventories decreased this week as an average of 771,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 586,000 barrels per day of oil were being pulled out of our Strategic Petroleum Reserve. That draw on the SPR was an extension of the emergency withdrawal under Biden's "Plan to Respond to Putin’s Price Hike at the Pump" (sic), that was originally intended to supply 1,000,000 barrels of oil per day to commercial interests over a six month period from its inception to the midterm elections in November, in the hope of keeping gasoline and diesel fuel prices from rising over that time....The SPR withdrawals under that program have been fluctuating in recent weeks because the administration has since been attempting to use the Strategic Petroleum Reserve to manipulate prices on a weekly basis; furthermore, Biden recently announced another 15,000,000 barrel release from the Strategic Petroleum Reserve to run thru December, while simultaneously announcing he'd buy crude to replenish the SPR if oil prices fall to or below the $67-72 a barrel range, effectively putting a floor under oil at that price.....Including the administration's initial 50,000,000 million barrel SPR release earlier this year, their subsequent 30,000,000 barrel release, and other withdrawals from the Strategic Petroleum Reserve under recent release programs, a total of 259,930,000 barrels of oil have now been removed from the Strategic Petroleum Reserve over the past 28 months, and as a result the 392,119,000 barrels of oil that still remain in our Strategic Petroleum Reserve is now the lowest since March 30, 1984, or at a new 38 1/2 year low, as repeated tapping of our emergency supplies for non-emergencies or to pay for other programs had already drained those supplies considerably over the past dozen years, even before the Biden administration's SPR releases. The total 180,000,000 barrel drawdown of the current release program, now scheduled to run through December, will remove almost a third of what remained in the SPR when the program started, and leave us with what would be less than a 20 day supply of oil at the current consumption rate...
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,100,000 barrels per day last week, which was 1.3% less than the 6,181,000 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 12,100,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,700,000 barrels per day, while Alaska’s oil production was 2,000 barrels per day higher at 448,000 barrels per day but had no impact on the rounded national total. 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 was still 7.6% below that of our pre-pandemic production peak, but was 24.7% 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 92.9% of their capacity while using those 16,152,000 barrels of crude per day during the week ending November11th, up from their 92.1% utilization rate during the prior week, and above their historical utilization rate range for this time of year... The 16,152,000 barrels per day of oil that were refined this week were 4.9% more than the 15,397,000 barrels of crude that were being processed daily during week ending November 12th of 2021, but 1.7% less than the 16,435,000 barrels that were being refined during the prepandemic week ending November 15th, 2019, when our refinery utilization was at 89.5%, within the normal range for mid November...
With the increase in the amount of oil being refined this week, the gasoline output from our refineries was also a bit higher, increasing by 35,000 barrels per day to 9,789,000 barrels per day during the week ending November 11th, after our gasoline output had increased by 274,000 barrels per day during the prior week. But this week’s gasoline production was still 1.3% less than the 9,922,000 barrels of gasoline that were being produced daily over the same week of last year, and 2.6% below the gasoline production of 10,053,000 barrels per day during the week ending November 15th, 2019. ON the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 107,000 barrels per day to 5,097,000 barrels per day, after our distillates output had increased by 87,000 barrels per day during the prior week. Even with that decrease, our distillates output was 5.3% more than the 4,842,000 barrels of distillates that were being produced daily during the week ending November 12th of 2021, and just 0.5% less than the 5,124,000 barrels of distillates that were being produced daily during the week ending November 15th 2019...
With the increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 4th time in 14 weeks; and by the most since mid-July, increasing by 2,207,000 barrels to 207,940,000 barrels during the week ending November 11th, after our gasoline inventories had decreased by 900,000 barrels to an 8 year low during the prior week. Our gasoline supplies rose this week because the amount of gasoline supplied to US users fell by 269,000 barrels per day to 8,742,000 barrels per day, and because our imports of gasoline rose by 83,000 barrels per day to 572,000 barrels per day, and because our exports of gasoline fell by 65,000 barrels per day to 927,000 barrels per day. But after 31 gasoline inventory drawdowns over the past 41 weeks, our gasoline supplies were 1.9% lower than last November 12th's gasoline inventories of 211,996,000 barrels, and about 5% below the five year average of our gasoline supplies for this time of the year…
Meanwhile, even with the decrease in our distillates production, our supplies of distillate fuels increased for the 10th time in 15 weeks and for the 24th time in the past year, rising by 1,120,000 barrels to 107,383,000 barrels during the week ending November 11th, after our distillates supplies had decreased by 521,000 barrels during the prior week. Our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, decreased by 298,000 barrels per day to 3,863,000 barrels per day, and because our exports of distillates fell by 263,000 barrels per day to 1,183,000 barrels per day, while our imports of distillates fell by 218,000 barrels per day to 110,000 barrels per day.. But after fifty-two mostly larger inventory withdrawals over the past eighty-one weeks, our distillate supplies at the end of the week were were 13.2% below the 123,685,000 barrels of distillates that we had in storage on November 12th of 2021, and about 15% below the five year average of distillates inventories for this time of the year...
Meanwhile, after the decrease in our oil imports and the increase in our oil exports, our commercial supplies of crude oil in storage fell for the 10th time in 18 weeks and for the 31st time in the past year, decreasing by 5,400,000 barrels over the week, from 440,755,000 barrels on November 4th to 435,355,000 barrels on November 11th, after our commercial crude supplies had increased by 3,115,000 barrels over the prior week. After this week's decrease, our commercial crude oil inventories fell to around 4% below the most recent five-year average of crude oil supplies for this time of year, but were still almost 38% more than the average of our crude oil stocks as of the first weekend of November over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels. And after our commercial crude oil inventories had jumped to record highs during the Covid lockdowns of the Spring of 2020, and then jumped again after February 2021's winter storm Uri froze off US Gulf Coast refining, our commercial crude supplies as of this November 11th were 0.5% more than the 433,003,000 barrels of oil we had in commercial storage on November 12th of 2021, while 11.1% less than the 489,475,000 barrels of oil that we had in storage on November 13th of 2020, and 3.3% less than the 450,380,000 barrels of oil we had in commercial storage on November 15th of 2019…
Finally, with our inventories of crude oil and our supplies of all products made from oil near multi-year lows over the most recent months, we are also continuing to watch the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR. Despite the modest gasoline and distillates inventory increases we've already noted for this week, the EIA's data shows that the total of our oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and thus including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 10,640,000 barrels this week, from 1,619,505,000 barrels on November 4th to 1,608,865,000 barrels on November 11th, after our total inventories had decreased by 4,386,000 barrels during the prior week. This week's decrease left our total liquids inventories down by 179,548,000 barrels over the first 45 weeks of this year, and at the lowest level since June 25th, 2004, or at a new 18 year low...
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 during a period when oil supplies from Russia continued to be constrained by Western sanctions, while demand was constrained due to the zero-COVID-19 policy in China and due to a strong dollar, which made oil more expensive for other countries...October was also the second month after OPEC and aligned oil producers had completely unwound the production cuts put in place to offset the demand destruction caused by the Covid pandemic, and they agreed to decrease their monthly output by an inconsequential 100,000 barrels per day, reversing September's token increase, and leaving the OPEC+ quota back at the benchmark level on which all Covid production cuts were based....as of August's final Covid recovery production increase, the cartel's output should have been restored to the level it was at before the Covid-related production cuts began, but as we've noted in the past, they are still far short of their quota, and remained so with this report.....also note that with the course and impact of the Ukraine war and the future course of the Covid pandemic largely unknown, the demand projections made in this report will have a much greater degree of uncertainty than they would have during normal, more stable times...
The first table from this month's report that we'll review is from the page numbered 47 of this month's report (pdf page 57), 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 used an average of production estimates by six or more "secondary sources", namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thereby avert any potential disputes that could arise if each member reported their own figures....since the June report, the consultancy Wood Mackenzie and the research and intelligence firm Rystad Energy were also added to OPEC's secondary sources.....
As we can see on the bottom line of the above table, OPEC's oil output decreased by 210,000 barrels per day to 29,494,000 barrels per day during October, down from their revised September production total that averaged 29,704,000 barrels per day....however, that September output figure was originally reported as 29,767,000 barrels per day, which therefore means that OPEC's August production was revised 63,000 barrels per day lower with this report, and hence OPEC's October production was, in effect, 273,000 barrels per day lower 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)...
while OPEC and other aligned oil producers had agreed to reduce production by 100,000 barrels per day during October, the 210,000 barrels per day we see above obviously exceeds that by quite a bit, and was largely due to to the 149,000 barrels per day drop in the the Saudis' oil production, without that, the 61,000 barrel per day decrease in production from the rest of the cartel come pretty close to their 64,000 barrel per day share of the 100,000 barrels per day output cut prescribed by their agreement with Russia and other producers...nonetheless, several other OPEC members also continued to be well short of what they were expected to produce, as we'll see in the next table...
The adjacent table was originally included as a downloadable attachment to the press release following the 32nd OPEC and non-OPEC Ministerial Meeting on September 5th, 2022, which set OPEC's and other aligned oil producers' production quotas for October... 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, they are not shown in this 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 26,689,000 barrels per day in October....therefore, the 25,104,000 barrels those 10 OPEC members actually produced in October were 1,585,000 barrels per day short of what they were expected to produce during the month, with Nigeria and Angola accounting for a large part of this month's shortfall, while only the UAE and Gabon were able to produce what was expected of them...
+ + +
Recall that the original 2020 oil producer's agreement was to jointly cut their oil production by 23%, or by 9.7 million barrels per day, from an October 2018 baseline for just two months early in the pandemic, during May and June of 2020, but that initial 9.7 million bpd production cut agreement was extended to include July 2020 at a meeting between OPEC and other producers on June 6th, 2020....then, in a subsequent meeting in early July of that year, OPEC and the other oil producers agreed to reduce their supply cuts by 2 million barrels per day to 7.7 million barrels per day for August 2020 and subsequent months, which thus became the agreement that governed OPEC's output for the rest of 2020...the OPEC+ agreement for their January 2021 production, which was later extended to include February, March and April's output, was to further ease their supply cuts by 500,000 barrels per day to a reduction of 7.2 million barrels per day from that original October 2018 baseline...then, during a meeting on April 1st of last year, OPEC and the other oil producers that are aligned with them agreed to incrementally adjust their oil production higher each month for the following three months by a pre-set amount for each country, thus extending their joint output cut agreement through July 2021....production levels for August and the following months of last year were to be determined by a July 1st OPEC meeting, but that meeting was adjourned on July 2nd due to a dispute between the UAE and the Saudis over the 2018 reference production levels on which the cuts are based, and a subsequent attempt to restart that meeting on July 5th was called off....so it wasn't until July 18th 2021 that a tentative compromise addressing August 2021's output quotas was worked out, allowing oil producers in aggregate to increase their production by 400,000 barrels per day in August, and again by that amount in each of the following months, and also to boost reference production levels for the UAE, the Saudis, Iraq and Kuwait beginning in April 2022, and which made the cartel's effective monthly production increase 432,000 barrels per day after that time....OPEC and other producers then agreed to increase their production in January 2022 by a further 400,000 barrels per day in a meeting concluded on the 2nd of December, 2021, and reaffirmed their intention to continue that policy with another 400,000 barrel per day increase in February at a meeting concluded January 4, 2022...subsequent monthly meetings from February through May served to step up their production by 400,000 barrels per day each month......however, in a meeting held on June 2nd, they agreed to bring forward the 432,000 barrel per day increase they had already scheduled for September, with that increase to be split evenly between July and August...hence, the production quota increase for both July and August was set at 648,000 barrels per day, which would have left each member's production back at the October 2018 baseline...hence, after September's 100,000 barrels per day increase from that level and October's 100,000 barrels per day decrease, OPEC's quota would be back at that October 2018 baseline, which had been their record month prior to the pandemic, and which still stands as the record, as they've been unable to match it since..
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 2020 to October 2022, and it comes from page 48 (pdf page 58) of OPEC's November Oil Market Report....on this graph, the cerulean blue bars represent OPEC's monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale....
Even with this month's 210,000 barrel per day decrease in OPEC's production from their revised production of a month earlier, OPEC's preliminary estimate is that total global liquids production still increased by a rounded 700,000 barrels per day to average 101.50 million barrels per day in October, a reported increase which came after September's total global output figure was apparently revised down by 680,000 barrels per day from the 101.48 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 900,000 barrels per day in October after that big downward revision, with most of October's production growth coming from Eurasia ex-Russia, Asia ex-China and India, and the OECD Europe, which were partially offset by production declines in Latin America...
After that 700,000 barrel per day increase in October's global output, the 101.50 million barrels of oil per day that were produced globally during the month were 4.10 million barrels per day, or 4.2% more than the revised 97.40 million barrels per day that were being produced globally in October a year ago, which was the third month of the monthly 400 million barrel per day production increases that OPEC and their allied producers initiated as the fourth policy reset in response to the global demand recovery following the early pandemic lockdowns (see the November 2021 OPEC report (online pdf) for the originally reported October 2021 details)...since this month's decrease in OPEC's output contrasts to the global increase, their October oil production of 29,494,000 barrels per day amounted to 29.1% of what was produced globally during the month, down from their revised 29.5% share of the global total in September, which had originally been reported at 29.3%, before this month's large downward revision to global totals for that month....OPEC's October 2021 production was originally reported at 27,453,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 2,041,000 barrels per day, or 7..4% more barrels per day of oil this October than what they produced last October, when they accounted for 28.1% of a smaller global output total...
With the decrease in OPEC's output and the downward revision to global oil output that we've seen in this report, the amount of oil being produced globally during the month was a little short of the expected global demand, as this next table from the OPEC report will show us....
The above table came from page 25 of the November Oil Market Report (pdf page 35), and it shows regional and total oil demand estimates in millions of barrels per day for 2021 in the first column, and then OPEC's estimate of oil demand by region and globally quarterly over 2022 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 2022....OPEC is estimating that during the 3rd quarter of this year, all oil consuming regions of the globe will be using an average of 101.25 million barrels of oil per day, which is a rounded downward revision of 390,000 barrels per day from their estimate 101.64 million barrels per day for 4th quarter demand of a month ago (that revision is circled 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 producing 101.50 million barrels per day during October, which would imply that there was a modest surplus of around 250,000 barrels per day of global oil production in October, when compared to the demand estimated for the month...
in addition to figuring that October oil shortage implied by this report, the downward revision of 680,000 barrels per day to September's global oil output that's implied the data in this month's report, slightly offset by the 20,000 barrels per day downward revision to 3rd quarter demand that we've circled in green above, means that the 2,150,000 barrels per day global oil output surplus we had previously figured for September would now be revised to a surplus of 1,490,000 barrels per day....in like manner, the 20,000 barrels per day downward revision to 3rd quarter demand means that the surplus of 1,210,000 barrels per day we had previously figured for August would now be revised to a surplus of 1,230,000 barrels per day, and that the surplus of 660,000 barrels per day barrels per day we had previously figured for July would have to be revised to a surplus of 680,000 barrels per day...
Note that in green we have also circled an upward revision of 20,000 barrels per day to OPEC's previous estimates of second quarter demand...based on that upward revision to demand, our previous estimate that there was a surplus of 570,000 barrels per day in June would now be revised to a 550,000 barrels per day surplus, while the oil shortage of 160,000 barrels per day that we had previously figured for May would have to be revised to a shortage of 180,000 barrels per day, and finally, that the 560,000 barrels per day global oil output surplus we had previously figured for April would have to be revised to a surplus of 540,000 barrels per day...
This Week's Rig Count
The number of drilling rigs running in the US rose for the ninth time in sixteen weeks, and for the 90th time over the past 112 weeks during the week ending during the week ending November 18th, but they're still 1.4% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by 3 rigs to 782 rigs this past week, which was also 219 more rigs than the 563 rigs that were in use as of the November 19th report of 2021, but was 1,147 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global market with oil in an attempt to put US shale out of business….
The number of rigs drilling for oil increased by 1 to 623 oil rigs during the past week, after the number of rigs targeting oil had increased by 9 during the prior week, and there are now 162 more oil rigs active now than were running a year ago, even as they amount to just 38.7% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 8.8% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 2 to 157 natural gas rigs, which was also up by 55 natural gas rigs from the 102 natural gas rigs that were drilling during the same week a year ago, even as they were only 9.8% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….
Other than those rigs targeting oil and natural gas, Baker Hughes also reports that two "miscellaneous" rigs continued drilling this week: one of those was a directional rig drilling to between 5,000 and 10,000 feet on the big island of Hawaii, while the other was a directional rig drilling to between 5,000 and 10,000 feet into a formation in Lake county California that Baker Hughes doesn't track....While we have seen no details on either of those, in the past we've identified various "miscellaneous" rigs as being exploratory, for carbon dioxide storage, and for utility scale geothermal projects...a year ago, there were were also two such "miscellaneous" rigs running...
The offshore rig count in the Gulf of Mexico was unchanged at 16 rigs this week, with 14 Gulf rigs drilling for oil in Louisiana's offshore waters, and two rigs drilling for oil offshore from Texas....the Gulf rig count is up by 1 from the 15 Gulf rigs running a year ago, when 13 of the Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil offshore from Texas...in addition to rigs drilling in the Gulf, we still have an offshore directional rig drilling to between 5,000 and 10,000 feet for natural gas in the Cook Inlet of Alaska, while a year ago, drilling offshore from Alaska had already shut down for the winter...
In addition to rigs running offshore, there are still three water based rigs drilling through inland bodies of water this week; those include a directional rig drilling for oil to between 10,000 and 15,000 feet, inland in St Mary Parish, Louisiana, a directional rig drilling for oil at a depth greater than 15,000 feet in Terrebonne Parish, Louisiana; and a directional rig drilling for oil to between 5,000 and 10,000 feet, inland in Lafourche Parish, Louisiana....the directional rig that had been set up to drill for oil in the Haynesville shale at a depth greater than 15,000 feet from a lake in DeSoto Parish, Louisiana last week appears to have been shut down this week...a year ago, there were only two rigs drilling on inland waters...
The count of active horizontal drilling rigs was up by 3 to 714 horizontal rigs this week, which was also 208 more rigs than the 506 horizontal rigs that were in use in the US on November 19th of last year, but just 52.0% of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....at the same time, the vertical rig count was up by one to 23 vertical rigs this week, which was also up by one from the 22 vertical rigs that were operating during the same week a year ago…on the other hand, the directional rig count was down by one to 45directional rigs this week, but those were still up by 10 from the 35 directional rigs that were in use on November 19th of 2021….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of November 18th, the second column shows the change in the number of working rigs between last week’s count (November 11th) and this week’s (November 18th) count, the third column shows last week’s November 11th 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 19th of November, 2021...
to determine what happened in New Mexico,.we start by checking the Rigs by State file at Baker Hughes for the changes in the Texas Permian...there we find that there were three rigs added in Texas Oil District 8, which is the core Permian Delaware, but that there was a rig pulled out of Texas Oil District 8A, which includes the counties overlying the northern Permian Midland, thus netting a two rig increase in the Texas Permian...since the national Permian basin count was down by one, we can thus conclude that all three rigs pulled out of New Mexico had been drilling in the far western Permian Delaware, in the southwest corner of that state...meanwhile, one of those Texas District 8 additions was targeting natural gas, since the Permian basin gas rig count rose from three to four at the same time..
elsewhere in Texas, there were two rigs pulled out of Texas Oil District 1, but there was a rig added in Texas Oil District 2, and there was another rig added in Texas Oil District 4; those could have all been offsetting changes in the Eagle Ford shale, where the rig count and oil & gas mix remained unchanged...there was also a rig pulled out of Texas Oil District 6, which apparently was a rig removed from the Haynesville shale, since the inland waters oil rig that had been drilling in the Haynesville in DeSoto Parish Louisiana was replaced by a natural gas rig in the Haynesville shale in the same region of Louisiana, and since the Haynesville shale natural gas rig count was unchanged at 70.. ..there was also a rig added in Texas Oil District 10, which was most likely targeting a basin that Baker Hughes doesn't track, since the Granite Wash of that district shows a net decrease...on the other hand, if that Granite Wash rig had come out of Oklahoma, it would have also had to have been offset by a rig addition elsewhere in the state not shown by Baker Hughes, since the Oklahoma count was up by two after the oil rig additions in the Cana Woodford and the Mississippian shale and the oil rig removal from the Arkoma Woodford...meanwhile, the rig added in the Williston basin was in Montana, which now accounts for four of the Bakken rigs, while the rig added in Utah was targetting natural gas in the Uintah basin, which now has four natural gas rigs and nine oil rigs not tracked by and just listed as "other" by Baker Hughes...
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Shale Permit Activity on the Rise in Columbiana County - Houston-based Hilcorp Energy Co. has received a dozen permits to drill new horizontal wells in the Utica-Point Pleasant formation in Columbiana County, records show. The 12 permits, issued on Nov. 1, are for new wells at the Scheel pad in Elk Run Township, according to the latest data from the Ohio Department of Natural Resources. Hilcorp has been awarded 37 permits to drill new wells in the Point Pleasant formation so far this year in Columbiana County, according to ODNR. It has also received seven permits to deepen existing wells in the county. Overall oil and gas production from shale formations is on the rise across the country, according to the latest data from the U.S. Energy Information Administration. According to EIA’s Drilling Productivity Report dated Oct. 17, oil production is projected to increase by 104,000 barrels per day to 9.105 million barrels in November across the country’s seven shale formations. Natural gas production is also expected to jump by 554 million cubic feet per day to 95.085 billion cubic feet per day. In Appalachia, which includes the Utica/Point Pleasant in eastern Ohio and the Marcellus shale in Pennsylvania and West Virginia, oil production is expected to increase by 2,000 barrels per day to 122,000 barrels daily. Natural gas production is also on the rise, EIA data show. In November, natural gas wells in Appalachia are expected to increase output by 89 million cubic feet per day to 35.666 billion cubic feet per day, the agency reported. The Appalachian region continues to be the largest natural gas-producing shale play in the country.
Natural gas prices mean high heating bills, but relief is available – WOUB — Despite record natural gas production, gas prices are expected to remain high for the foreseeable future, meaning higher heating bills for families throughout southeastern Ohio. Monthly U.S. natural gas production reached an all-time high of 2.89 trillion cubic feet in 2022, exceeding the pre-pandemic record of 2.82 trillion cubic feet. However, this increase in production comes at a time when the global demand for natural gas has increased dramatically because of Russia’s invasion of Ukraine and subsequent economic sanctions and wartime disruptions. Russia is the world’s second-largest producer of natural gas and the primary provider of natural gas to Western Europe. To meet global demand at a time of decreased global production, U.S. producers of natural gas have been exporting more liquified natural gas abroad, pushing U.S. exports to record highs. On top of increased demand, U.S. natural gas storage balances are lower than in previous years. “We’ve seen lower production growth and storage demand, coupled with an increased demand for liquified natural gas,” said Erica Chronaberry, a spokesperson for Columbia Natural Gas of Ohio. Columbia Natural Gas operates a network of pipelines distributing natural gas from producers in Ohio, Pennsylvania and West Virginia to consumers throughout Ohio. Columbia’s pipelines are also linked to gas producers in Texas and Louisiana through the Texas Eastern Transmission Pipeline. Chronaberry said while natural gas production has been increasing since mid-August, it remained relatively steady up to that point. Chronaberry also said that Ohio has a high demand for natural gas because of the number of factories located in the state. Many coal-fired power plants in Ohio have converted to natural gas, further increasing demand. “The customers with the highest demand for natural gas are usually large industrial customers,” said Chronaberry. “Ohio is home to many manufacturers with high energy demands.” While natural gas prices in Ohio have been rising, they are expected to remain below the national average. In fact, according to Chronaberry, the price of gas in the Midwest is generally lower than both the Gulf Coast and the Northeast. This is partially due to extensive natural gas production in southeastern Ohio. While production has increased in recent years because of fracking, southeastern Ohio has been producing oil and gas since 1860 when the first oil wells were drilled in Washington County.Higher natural gas prices mean increased heating and energy bills heading into winter, when residential consumption is typically at its highest. Chronaberry said there are many small things consumers can do to keep their costs down.
EOG again seeks to build on its oil and gas inventory organically, this time in the Utica. - EOG has become one of the top performing U.S. producers through a contrarian strategy of growth through organic exploration, which — if done successfully — adds reserves, lowers finding-and-development costs, and reduces the overall cost basis of the company. Beginning in 2016, EOG established a benchmark for high-grading its portfolio, targeting investment and development of “premium” reserves that provided a minimum 30% return at $40/bbl oil, $16/bbl NGLs, and $2.50/Mcf gas prices. The company concentrated on allocating funds to boost its premium inventory in its current core areas: the Delaware Basin, the Eagle Ford Shale, the Bakken/Three Forks play, the Denver-Julesburg and Powder River basins, and the Anadarko Basin’s Woodford oil play. Successes include the doubling of its reserve estimates and premium locations by successful exploration in the Mowry, Niobrara, and Turner Sand formations in the northern Powder River. Most notably, EOG has devoted a significant portion of its annual investment to exploration in what it calls the “sleepy” — or underappreciated or neglected — portions of major U.S. unconventional basins. The first major discovery was in South Texas. The company had been drilling oil-focused wells in the Austin Chalk in South Texas, but in 2018 began investigating dry gas Austin Chalk potential in Webb County, along the Mexico border. In November 2020, EOG announced the new Dorado natural gas play, estimating a massive 21 Tcf in recoverable resources from stacked pay zones in the Austin Chalk and Upper and Lower Eagle Ford in what it hailed as “the lowest cost U.S. natural gas play.” The 163,000-net-acre position, which EOG had assembled through legacy assets, organic leasing, trades, and bolt-on acquisitions, had a development breakeven of less than $1.25/Mcf and offered easy access to growing demand from Gulf Coast LNG export facilities and from Mexico. Best of all, the play easily met what EOG is calling its new “double-premium” investment criteria, which it says is the “most stringent investment hurdle rate in the industry”: a minimum 60% return at $40/bbl oil, $16/bbl weighted average NGLs, and $2.50/Mcf gas prices — each of which is less than half of today’s prices.Year-to-date 2022 results demonstrated that focusing capital investment on “double-premium” locations significantly boosted cash flow generation, from $5.5 billion in 2021 to an estimated $7.6 billion in 2022. EOG is allocating 67% of its free cash flow, or $5.1 billion, to return to shareholders as regular or special dividends. The remaining cash is being used to strengthen EOG’s fortress-like balance sheet (0.2x net debt to Adjusted EBITDA leverage ratio) and for low-cost property bolt-on acquisitions, which augmented a development program that replaced 170% of the “double-premium” wells drilled in 2021.Along with those Q3 2022 financial results, EOG unveiled its eighth and perhaps most surprisingly new “double-premium” exploration play. As shown in Figure 1 below, the company said it had stealthily accumulated 395,000 net acres in the volatile oil window of the Utica Shale in southeastern Ohio — just west and north of West Virginia’s panhandle.The Utica Shale is a massive formation that covers 170,000 square miles over portions of eight U.S. states. It underlies the Marcellus Shale at depths reaching 14,000 feet on the eastern side, including Pennsylvania, but thins to 2,000-8,000 feet moving west across Ohio. Cited as the fourth-largest U.S. natural gas resource by the EIA, the Utica also has volatile oil, another word for condensate, (light-green area in Figure 1) and black oil (dark-green area in Figure 1) windows as it thins in Ohio. Development of the Utica began in 2011, shortly after the onset of the Shale Revolution, with the rig count rising to 50 in late 2014. But the rig count subsequently plunged to 10 in 2016 on the crash in commodity prices, rebounded to 30 in 2017, then cratered at four after the onset of the pandemic before recovering to its current 10, primarily located in the eastern dry gas window.
Shell commissions Pennsylvania petrochemical complex - Shell PLC subsidiary Shell Chemical Appalachia LLC has officially started operations at its long-planned Shell Polymers Monaca (SPM) petrochemical complex atop a 386-acre site just southwest of Monaca, Pa., along the Ohio River in Potter and Center Townships, Beaver County, 30 miles northwest of Pittsburgh (OGJ, Nov. 1, 2021). Commencing operation as of Nov. 15, SPM will produce about 1.6 million tonnes/year (tpy) of polyethylene upon ramping up to its full nameplate capacity, which is scheduled to occur by second-half 2023, Shell said in a release.First proposed as a potential investment project in 2012, Shell began construction on SPM in April 2017 following the operator’s final investment decision (FID) to move forward with the development in June 2016 (OGJ Online, Nov. 8, 2017; Mar. 15, 2012).Upon announcing official commercial operation, Shell confirmed SPM contracted at FID for most of the complex’s required natural gas feedstock from regional gas operators in nearby Utica and Marcellus basins.While details regarding SPM’s feedstock supply agreements were not revealed, Shell previously said the Monaca complex will receive the entirety of its regionally-sourced ethane feedstock via Shell Pipeline Co. LP’s Falcon ethane pipeline system (FEPS), a 97-mile common carrier ethane pipeline that—stretching across southwestern Pennsylvania, West Virginia, and eastern Ohio—connects Monaca with three major ethane source points in the rich-gas portions of the Marcellus and Utica shale reservoirs: Houston, Pa.; Scio, Ohio; and Cadiz, Ohio (OGJ Online, Aug. 1, 2022).Designed to produce ethylene, high-density polyethylene (HDPE), and linear low-density polyethylene (LLDPE) from Marcellus and Utica shale ethane, Shell’s Monaca site houses a dual 1.5-million tpy ethylene and 1.6-million tpy polyethylene complex, which features seven tail gas and natural gas-fired ethane cracking furnaces with a heat input rating of 620 MMbtu each to support the ethane cracker and three polyethylene units.The complex’s two gas-phase polyethylene manufacturing lines each are equipped to produce 550,000 tpy of either HDPE or LLDPE-grade pellets, while a third manufacturing line outfitted with INEOS AG’s slurry-loop reactor polyethylene technology will produce 500,000 tpy of HDPE pellets. Alongside installations for steam generation, storage, logistics, cooling water, and wastewater treatment, the complex also houses a 250-Mw cogeneration power unit that uses natural gas and steam to meet the site’s full electricity requirement, according to project documents.Shell said SPM comes as part of its Powering Progress strategy to reduce the production of traditional fuels and accelerate the operator’s transition by 2050 to net-zero emissions. A cornerstone of the strategy includes the operator’s plan to consolidate its global refinery footprint to five core energy and chemicals parks that maximize integration benefits of conventional fuels and chemicals production while also offering new low-carbon fuels and performance chemicals (OGJ Online, Sept. 6, 2022; Jan. 21, 2022).
Shell Ramps Up Pennsylvania Petrochemical Project, Fueled by Marcellus and Utica Natural Gas - Shell plc’s long awaited Pennsylvania petrochemical project, the first major polyethylene manufacturing complex fueled by natural gas liquids in the Northeast, has begun operations, with designed output of 1.6 million metric tons/year. The Shell Polymers Monaca (SPM) facility by subsidiary Shell Chemical Appalachia LLC is northwest of Pittsburgh, adjacent to the Ohio River on 384 acres in Beaver County. Main construction began in April 2017. SPM’s polyethylene and ethylene would be produced using ethane feedstock sourced from the prolific Marcellus and Utica shales. Full production is expected by the second half of 2023.“Building this world-class facility is a fantastic achievement and one the team can be proud of; it’s a showcase of Shell’s project delivery expertise,” said Shell Downstream director Huibert Vigeveno. “With great market access, innovative offers and connected infrastructure, Shell Polymers Monaca is well positioned and ready to serve customers with high quality, competitive products.”SPM is within a 700-mile radius of 70% of the U.S. polyethylene market, Shell noted“The advantages of proximity are not limited to production,” executives said. “SPM also offers customers shorter supply chains, which translates to increased flexibility and access to polyethylene pellets that can be used in a wide variety of products such as common household goods, consumer and food packaging, as well as industrial and utility products.”The ramp up “represents an important step in growing Shell’s chemicals business as part of its Powering Progress strategy,” the London-based supermajor noted. The company is using “value chains” closer to end-use customers and using advantaged feedstocks, while reducing exposure over time to commodity chemicals.“In delivering this facility, we’ve had a strong and innovative safety focus,” Vigeveno said. Shell has “invested in the community through employment and education, and helped repair and improve the local environment by remediating a brownfield site. These commitments are core to Shell’s Powering Progress strategy today and will remain so in the years to come.”
It's Happening: Shell Ethane Cracker Plant Commences Operations - The Shell Polymers Monaca (SPM) petrochemical refinery in western Pennsylvania, became fully operational this week, marking it as the first major polyethylene manufacturing complex in the Northeast. Shell Downstream Director Huibert Vigeveno heralded the project:“Building this world-class facility is a fantastic achievement and one the team can be proud of; it’s a showcase of Shell’s project delivery expertise. With great market access, innovative offers and connected infrastructure, Shell Polymers Monaca is well positioned and ready to serve customers with high-quality, competitive products.”First announced in 2012, the facility has been under construction since 2017. After a decade of careful planning and construction, the plant will now convert natural gas into ethylene for important consumer products, with a designed output of 1.6 million tonnes annually.Notably, the plant uses natural gas feedstock from the nearby energy-rich Marcellus and Utica shales, highlighting the economic and consumer benefits of natural gas to power ancillary industries like the SPM.In a press release, Shell highlighted these benefits:“SPM contracted most of its natural gas feedstock at Final Investment Decision from the nearby Utica and Marcellus basins. The advantages of proximity are not limited to production; SPM also offers customers shorter supply chains, which translates to increased flexibility and access to polyethylene pellets that can be used in a wide variety of products such as common household goods, consumer and food packaging, as well as industrial and utility products.”Appalachia is seeing a resurgence of industry investment due to its abundant supply of natural gas and skilled workforce. This project is just one of many examples showing how Appalachia is growing and prospering, a topic Energy in Depth has previously explored.Shell’s cracker plant brought new growth and jobs to the region through construction – 6,000 construction workers built the new facility – and will have 600 permanent employees to operate and maintain the facility with an expected several thousand more jobs from the private industry and public services created to help support this facility.According to analysis from Robert Morris University’s School of Business, the SPM will produce between $260 and $846 million in annual economic activity through wages, benefits, and related spending within Beaver County. The state will also collect $23 million annually in state income tax from the SPM, and over 40 years, it is projected to produce more than $81 billion in economic activity across the Keystone State.
Gasoline spill displaces about 1,000 people in Bethlehem, Pa. About 1,000 people have been evacuated in Bethlehem, Penn., after a gasoline tanker overturned Thursday morning. The tanker spilled about 6,000 gallons of gasoline after it crashed around 2:30 a.m. ET at W. Union Boulevard and Paul Avenue, according to WFMZ. Officers evacuated everyone within a 1,000-meter radius of the spill, which included about 400 homes. American Red Cross of Greater Pennsylvania is responding to the "significant fuel oil spill affecting hundreds of homes." "Currently, we are providing canteen services to responders, mobilizing shelter teams to support the evacuation site, and coordinating with local officials to determine community needs and next steps," American Red Cross wrote on Twitter. Some people have been allowed to return to their homes as of 11:00 a.m., according to CBS Philadelphia. "We will delay the opening of school for two hours to ensure that our building is ready to function normally for students and staff while also serving our community's needs," the district wrote to its website. Some people have been allowed to return to their homes as of 11:00 a.m., according to CBS Philadelphia. The driver of the truck was taken to the hospital, but their condition has not been made public, according to 6ABC. Bethlehem police said top concerns are a fire or explosion, WFMZ reported. Gasoline is a highly flammable liquid that is toxic to people when they are exposed in large amounts for a long period of time. Standard protocol for fuel spills include evacuating personnel from the immediate area, notifying the cleanup response team, extinguishing or disconnecting all ignition sources, and contacting the fire department if the spill is flammable.
As Evidence Mounts, New Concerns About Fracking and Health - Yale E360 - Almost 20 years after the adoption of hydraulic fracturing began to supercharge U.S. production of oil and gas, there’s growing evidence of a correlation between the industry’s activities and an array of health problems ranging from childhood cancer and the premature death of elderly people to respiratory issues and endocrine disruption. While the oil and gas industry insists its processes are safe, and regulators have set rules designed to prevent the contamination of air and water by “fracking” technology, advocates for stricter limits on the practice, or even an outright ban, point to an increasing number of studies suggesting that fracking poses a threat to public health. A paper by the Yale School of Public Health this summer showed that children living near Pennsylvania wells that use fracking to harvest natural gas are two to three times more likely to contract a form of childhood leukemia than their peers who live farther away. That followed a Harvard study in January that found elderly people living near or downwind from gas pads have a higher risk of premature death than seniors who don’t live in that proximity. In April, the nonprofit Physicians for Social Responsibility and Concerned Health Professionals of New York, which consists of health professionals, scientists, and medical organizations, published its most recent compendium of investigations into risks and harms linked with fracking. Since 2014, the compendium has tallied 2,239 peer-reviewed papers that found evidence of harm, with nearly 1,000 of those papers published since 2018. More than 17.6 million people in the U.S. now live within a mile of a fracked oil or gas well. “The risks and harms of fracking for public health and the climate are real and growing,” said the authors of the compilation. “Despite the continuing challenges of exposure assessments, the results of recent studies confirm and extend the validity of earlier findings.” According to the 577-page document, 79 percent of U.S. natural gas and 65 percent of crude oil is now produced by fracking, with more than 17.6 million people living within a mile of a fracked oil or gas well. The result, says the report, is a public health crisis. U.S. energy companies have been under fire from environmentalists and public health advocates since the mid-2000s, when the U.S. fracking boom got underway. The opposition goes beyond concerns that emissions from natural gas contribute to climate change. Critics say that the cocktails of chemicals injected a mile or more underground to crack open gas-bearing fissures in shale threaten groundwater supplies — including drinking water — and that diesel fumes from trucks and generators on well pads erode air quality. Commonly reported health effects that are increasingly linked to fracking include some cancers, low birth weight, disruptions to the endocrine system, nose bleeds, headaches, nausea, and weight gain.
Pipeline's path through the Jefferson National Forest to get another look -- For the third time in six years, the U.S. Forest Service will study the environmental impact of burrowing a large natural gas pipeline through a 3.5-mile stretch of the Jefferson National Forest. The latest evaluation comes after a federal appeals court rejected two earlier approvals for the Mountain Valley Pipeline. Both times, in 2018 and again earlier this year, the 4th U.S. Circuit Court of Appeals ruled that the Forest Service did not adequately address the erosion and sedimentation to be caused by clearing land and digging a trench for a buried pipe that will traverse steep slopes through federal woodlands in Giles and Montgomery counties. A draft environmental impact statement will be completed by January, the service said Thursday. That will be followed by a 45-day public comment period, with final action expected by summer 2023. Mountain Valley said the timeline aligns with its plans to complete the long-delayed, $6.6 billion project by the end of next year. “Mountain Valley believes that the few items referenced in the Fourth Circuit’s remand issued in January 2022 can be addressed within the timeframe outlined by the agency,” spokeswoman Natalie Cox wrote in an email. “With total project work roughly 94% complete, Mountain Valley looks forward to safely and responsibly completing this critical infrastructure project to serve the growing demand for affordable, reliable energy.” Opponents argue that the pipeline is closer to halfway finished. Mountain Valley must also apply for a new assessment of its impact to endangered species from the U.S. Fish and Wildlife Service. The Fourth Circuit has also raised questions about a permit for the pipeline to cross streams and wetlands, which is now in a third round of litigation from environmental groups. Currently, 10 other natural gas pipelines bisect the George Washington and Jefferson National Forests, which encompass 1.8 million acres in the Appalachian Mountains of Virginia, West Virginia and Kentucky. But Mountain Valley would be the largest, and is the only interstate pipeline that falls under the regulation of the Federal Energy Regulatory Commission. After entering in national forest in Monroe County, West Virginia, the pipeline will be buried beneath the Appalachian Trail and then run southeast through the New River and Roanoke valleys. “As a federal land management agency with a multiple-use mission, the Forest Service considers authorization of many different types of uses on National Forest System lands,” Joby Timm, supervisor for the Jefferson National Forest, said in statement Thursday. “Our mission is caring for the land and serving people.” Opponents — from national environmental giants such as the Sierra Club to local community groups — have contested more than a dozen state and federal permits issued to Mountain Valley. They contend that constructing a 42-inch diameter steel pipe along mountainsides and through streams and wetlands is a recipe for disaster. Mountain Valley has been cited nearly 500 times for violating regulations meant to control muddy runoff in Virginia and West Virginia, where the 303-mile pipeline starts. In rejecting the latest permit from the Forest Service and the U.S. Bureau of Land Management, the Fourth Circuit ruled that the agencies “erroneously failed to account for real-world data suggesting increased sedimentation along the pipeline route.”
Lawmakers back to deal-making on permitting, spending - Lawmakers are intensifying negotiations on a spending package and permitting reform ahead of a busy rush to the finish line in December.Senate Energy and Natural Resources Chair Joe Manchin (D-W.Va.) said “good conversations” continued over the recess on permitting. The White House has also voiced support for a bill in the lame-duck session (E&E News PM, Nov. 11).“We’re working every way we can,” Manchin said as Congress returned to work Monday. “This needs to be passed.”Manchin and other lawmakers want to streamline the approval process for both fossil fuel and renewable energy projects and want the compromise legislation to ride on the National Defense Authorization Act, which already includes an array of energy and environmental provisions.Lawmakers, for example, are poised to use the must-pass defense bill to approve the latest water projects authorization bill, the Water Resources Development Act, or WRDA.But the politics around permitting reform remain tricky. Changing the current system faces stiff opposition from House progressives wary of making any changes to the National Environmental Policy Act or approving the contentious Mountain Valley pipeline project.And many Republicans have resisted Manchin’s permitting proposals, arguing reform legislation should be more aggressive. The GOP has also resisted joining a deal that Manchin hatched with Democratic leaders in exchange for his support of the Inflation Reduction Act.Rep. Jared Huffman (D-Calif.), one of the progressive permitting reform opponents, said it’s “hard to say” whether the permitting push would have enough votes in the House as an attachment to the NDAA.“The NDAA is already going to be combined with WRDA,” Huffman said. “You’ve got to put a pretty complicated algorithm together for that.”Sen. Martin Heinrich (D-N.M.), who has supported permitting reform as a means to build out clean energy, said it’s “too early to tell” if the effort will pan out.“It’s one of those interesting places where it’s not the substance that has tripped all this up,” Heinrich said in an interview Monday. “So that makes it harder, for me at least, to sort of game out what the odds are.”The Senate launched debate on its version of the NDAA last month but set aside the effort to deal with nominations and gay marriage. The chambers may end up crafting a final defense bill behind closed doors.
Defense negotiators resist adding permitting to NDAA - Leaders of the House and Senate Armed Services committees were pessimistic Tuesday about Sen. Joe Manchin’s permitting reform package ending up in the annual defense authorization package.“Zero chance,” House Armed Services ranking member Mike Rogers (R-Ala.) said about the prospects of the West Virginia Democrat’s permitting reform push being in the fiscal 2023 National Defense Authorization Act. “We’re doing everything we can to keep anything controversial out of this bill.”The House already passed its version of the NDAA, but the Senate has opted to address other priorities, including nominees. Negotiators are instead trying to craft a final package behind closed doors“The approach is to try and work this out between the four leaders of the committees, Democrat, Republican, House and Senate, and then the top leadership and get a bill we can all agree on,” said Senate Majority Leader Chuck Schumer (D-N.Y.). “We think we’ll get more done that way.”Even though Schumer supports permitting reform, the defense bill strategy could hurt Manchin’s cause, with top negotiators reluctant to include anything controversial that might jeopardize the bill’s passage before the end of the year. The NDAA has passed Congress every year for 62 years straight.“My focus is to get the NDAA done,” said Senate Armed Services ranking member Jim Inhofe (R-Okla.). “I am not optimistic” that permitting reform will be included.Whether or not permitting reform is included in the NDAA could ultimately be up to Schumer. House Armed Services Chair Adam Smith (D-Wash.) previously said the Democratic leadership would make the call on such a pivotal issue (E&E Daily, Sept. 21)Schumer said Tuesday, “As you saw when we tried it last time, there weren’t enough Republican votes. I’m working with Senator Manchin to see what we can get done next.”Senate Armed Services Chair Jack Reed (D-R.I.) said including the permitting package “hasn’t been suggested ” so far in NDAA negotiations.
TC Energy Looking to Expand Haynesville to Gulf Coast LNG Corridor - TC Energy Corp. is working to connect more natural gas supply from the Haynesville Shale and Western Canadian Sedimentary Basin (WCSB) with LNG export demand, management said last week. CEO François Poirier hosted a call on Wednesday (Nov. 9) to discuss the Calgary-based pipeline juggernaut’s third quarter earnings. Poirier and his team highlighted the $400 million Gillis Access project in Louisiana, which the company sanctioned during the quarter. The 1.5 Bcf/d header system “will connect growing supply from the Haynesville basin to Louisiana markets including the rapidly expanding” Louisiana liquefied natural gas export market, management said. TC is aiming for the project to enter service in summer 2024. “Essentially, the project is a header system that can be further expanded over time within the state of Louisiana, that will ultimately connect the Haynesville supplies that are going to show up at a point called Gillis to serve downstream LNG, industrial and other markets within the state,” said Vice President Stanley Chapman, who oversees U.S. and Mexico natural gas pipelines. Chapman said with Gillis project and the other projects in service on the drawing board, “we’re going to increase the flowing LNG feed gas that we have from about 3 Bcf today, which is roughly a 30% market share, to over 6 Bcf or 35% market share in 2025. “So we see continued opportunities in a target-rich environment to continue to expand our best-in-class footprint, particularly across the state of Louisiana to serve LNG loads, particularly important as energy security and energy reliability becomes a forward theme with respect to world energy demand.” The third quarter also saw the start up of the Louisiana XPress natural gas pipeline, which has increased TC’s market share from 25% to about 30% of volumes destined for export from third-party LNG facilities. The start of commercial service on Louisiana Xpress, along with expansions and upgrades to TC’s ANR Pipeline Co. system, added about 1 Bcf/d of U.S. gas capacity during 3Q2022. In Canada, the company is “laser focused” on completing the Coastal GasLink pipeline by the end of 2023, said TC’s Bevin Wirzba, executive vice president who oversees Canadian natural gas and liquids pipelines. Coastal GasLink is meant to transport WCSB gas to the LNG Canada export terminal planned for British Columbia’s west coast. TC also expects “to announce and close C$5 billion plus of asset divestitures within 2023,” Poirier told analysts. He declined to go into specifics on which assets the firm is planning to offload. Poirier touted high utilization rates across the firm’s North American gas pipeline network. He added that the company remains “opportunity rich,” citing a $34 billion portfolio of fully sanctioned, secured capital projects under development. TC is now targeting full-year 2022 capital spending of about $9.5 billion, and expects to sanction about $5 billion of projects per year throughout the decade, Poirier said.
Summary of FERC Meeting Agenda for November 2022 - Below are summaries of the agenda items for the Federal Energy Regulatory Commission's November 17, 2022 open meeting, pursuant to the sunshine notice released on November 10, 2022. (includes details on several dozen pending projects)
Race Is On to Be Next Big USA Supplier of LNG to Europe - It’s been eight months since Russia invaded Ukraine, sending global commodity prices soaring and forcing energy-ravenous countries into a mad competitive dash to secure new fuel sources ahead of winter. While the US filled some of the supply gap by exporting huge quantities of liquefied natural gas from its seven plants, global markets are going to have to wait at least two more years before any new LNG supplies from the US come online. Three large-scale projects requiring more than $30 billion of financing are now under construction in Texas and Louisiana, yet none will be ready next year. Two of the projects, Golden Pass LNG near Port Arthur, Texas, and the first phase of Plaquemines LNG, along the Mississippi River about 25 miles south of New Orleans, are expected to begin production in 2024, setting up a race to see which will be the eighth US export terminal. The third project, by Cheniere Energy, the US’s largest LNG exporter, will expand an existing plant in Corpus Christi and won’t begin production until late 2025. Natural gas traders, government officials and industry observers will spend the next few years watching the projects for any signs of delay or movements ahead of schedule. Golden Pass is a joint venture between industry titans Qatar Energy and Exxon Mobil. It began construction in May 2019. Plaquemines, a project by the closely held Virginia-based developer, Venture Global LNG, quietly started construction in August 2021. Venture Global pulled off a near-miracle in January 2022 when it began production at its first LNG plant, Calcasieu Pass in Cameron, Louisiana, in a record 29 months after securing financing. Many wonder if it can repeat or beat that success with Plaquemines. Using regulatory filings and satellite images, Michael Webber, co-founder and managing partner of New York consulting firm Webber Research, said the race is a “dead heat” but that Venture Global’s construction approach gives it an edge. It’s using a modular process in which sections of the plant are built offsite and shipped to Plaquemines, where they are dropped into place, akin to snapping Lego blocks together. Golden Pass, on the other hand, is using the traditional approach by building everything onsite. Natural gas is a plentiful fuel that, when burned, emits less carbon dioxide than oil and coal. And in its super-chilled form, it’s easy to store and transport on ocean-faring tankers. Seeking to stay warm this winter and keep manufacturers humming, European nations have been paying a premium for those cargoes. The US began exporting LNG in force in 2016 and now has seven plants that can ship the fuel overseas. One of those terminals, Freeport LNG in Quintana, Texas, remains shuttered following a June 8 fire. Once Freeport is back in full service, possibly at the end of the year, the seven plants will be able to export a combined 13.9 billion cubic feet of natural gas per day, figures from the Energy Information Administration show. At the end of 2019, the US’s peak capacity sat at 11.6 billion cubic feet per day. Adding more capacity is a Herculean financial, engineering and environmental feat. The multi-story plants occupy hundreds of acres of land and have miles of winding pipes that move natural gas, which must be cleaned of contaminants and then cooled to -260 degrees Fahrenheit. At that point, it becomes a liquid that can be stored in giant insulated tanks large enough to fit a cargo plane. An LNG plant “has a lot of moving parts and a lot of these moving parts have never moved together before,” Golden Pass LNG Chief Commercial Officer Jeff Hammad said Oct. 13 at the Gulf Coast Energy Forum in New Orleans. “It’s big and expensive. It’s technically complex. And it takes a long time to plan and execute.” Here is the status of the US’s major LNG projects:
U.S. Greenlights Commonwealth LNG Project - The Commonwealth LNG project received the unanimous approval of energy regulators this week despite concern expressed by Democrats about its carbon footprint.Per its website, the project will have a capacity of 8.4 million tons of liquefied natural gas annually and should begin operation in 2027. Located on the Louisiana Gulf Coast, the facility will also include six 50,000-cu m storage tanks and the capacity to accommodate vessels up to 216,000 cu m.The facility will receive feed gas via an interconnector to “two major pipeline systems with significant excess transportation capacity.”Commonwealth already has a long-term offtake commitment from Woodside Energy Trading, a subsidiary of the Australian energy major, which will see the trading company buy LNG from the Commonwealth facility over a 20-year period.The deal is for 2.5 million tons of liquefied natural gas annually, with the first shipments scheduled for the middle of 2026. The initial contracted volume is 2 million tons, with an option for an additional 500,000 tons.“The agreements secure for Woodside low-cost LNG volumes in the Atlantic Basin in a period of expected strong demand as Europe seeks alternatives to Russian pipeline gas,” said Woodside’s chief executive, Meg O’Neill, in comments on the deal announced in September.Reuters noted in a report on the approval news that this is the first new LNG project to earn the approval of the Federal Energy Regulatory Commission in the last two years.The chairman of the commission, however, voiced concern about the emissions footprint of the facility, which will generate an estimated 3.5 million tons of carbon dioxide annually. “I still am at a loss as to why we don’t at least assess the significance of the greenhouse gas emissions in terms of making our determination ... and I think it is something we need to grapple with as we move forward,” Rich Glick said.
Fatigue contributed to Texas LNG explosion, probe says - Employee fatigue from understaffing played a role in the explosion that has closed one of the largest U.S. natural gas export terminals since June, according to an investigative report made public Tuesday.Operators at Freeport LNG generally worked 12-hour shifts, and nearly three-quarters had worked at least 20 percent more than their scheduled hours in the first half of 2022, according to the report done for the company by the consulting company IFO Group. It deemed fatigue a “probable contributing factor” to the incident.“Fatigue can increase errors, delay responses, and cloud decision-making,” the report said. It added that operators often worked overtime shifts on their days off and noted problems with the plant’s warning systems. Freeport LNG officials had predicted the facility would reopen by early to mid-November. But a Pipeline and Hazardous Materials Safety Administration official said Tuesday the company hasn’t requested permission to restart.Analysts at multiple research and banking firms have said a November start-up appears unlikely. Company officials aren’t providing information about the timeline.“When we have an update to communicate it will be provided accordingly,” Freeport LNG spokesperson Heather Browne said in an email.The results of the investigation are important in part because PHMSA is trying to update its 42-year-old safety rules for the rapidly growing industry (Energywire, June 28). PHMSA sent a proposal to leadership at the Department of Transportation, its parent agency, in September. It could go to the White House by the end of November.The heavily redacted investigative report was released under the Freedom of Information Act (FOIA). It attributed the Freeport fire and explosion to human error and said company officials were aware of problems days beforehand. E&E News previously reported on similar issues raised by a different investigatory report (Energywire, Nov. 1). Freeport LNG hired the Houston-based IFO Group to investigate the cause of the explosion under the terms of an agreement with PHMSA. The terminal cannot reopen without the approval of the agency and other regulators. IFO investigators told officials of Brazoria County, where Freeport is located, that managers didn’t stop operations at the terminal because of “hubris” — they didn’t want to acknowledge there was a problem at the plant. In response to the IFO report, the company said it planned to expand its workforce by more than 30 percent and committed to other recommended changes. The explosion took nearly 20 percent of the country’s liquefied natural gas export capacity offline, hindering a crucial aspect of the Biden administration’s support for Ukraine.“Freeport was clearly putting profits ahead of safety by keeping a plant running at full steam when its staff was worn thin due to overwork,” said Clark Williams-Derry, an energy finance analyst at the Institute for Energy Economics and Financial Analysis, which advocates accelerating a transition to sustainable energy. “LNG is explosive, and safety can’t be an afterthought.”
US NatGas Tumbles On Bloomberg Report That Freeport LNG May Extend Plant Outage - On Monday morning, US natural gas futures jumped more than 5.5% to as high as $6.25/mmbtu on Freeport dismissing reopening claims. The Texas terminal has been shuttered since June due to an explosion, with a reopening timeframe around mid-November. Any such reopening would boost NatGas prices because the liquefaction plant serves as a major export facility, serving European customers. Now Bloomberg reports Freeport LNG told customers that outages at its Texas terminal, which has been closed since June and was scheduled to reopen by mid-November, could be delayed further. People with direct knowledge of the situation said LNG shipments for November and December are likely to be canceled as maintenance work continues on the liquefaction plant. Also, regulatory approvals could prolong the start date.This comes as heating demand is set to surge across the Northern Hemisphere. The LNG exfor 15% of all US LNG exports, most of which were sent to Europe. Freeport said last week it was set to resume operations this month, though reliable timelines from the company port facility in Freeport, Texas, accounted have been hard to get, according to the people. Last Friday, US natural gas prices plunged after rumors circulated on social media about possible restart delays at Freeport. Then the company denied Twitter rumors late Friday which sent US Natgas prices higher early Monday to only plunge again, with now Bloomberg reporting possible restart delays. This is more bad news for Europe as the energy-stricken continent has to search elsewhere for LNG shipments. On the flip side, more NatGas will be injected into US storage ahead of winter. Freeport LNG, a major liquefied natural gas exporter in Texas, rejected claims made on social media last Friday that its terminal would be closed for an extended period. US natural gas futures plunged as much as 7.4% on Friday as someone operating a Twitter account, identifying as a trader, said "cracked pipes" were discovered at the terminal, potentially delaying the company's plans to restart exports by mid-month. The tweet was immediately deleted.
U.S. Natural Gas Prices Swing as Uncertainty Over Freeport LNG Restart Continues – U.S. natural gas futures swung on Monday as the market continued to weigh conflicting information about when Freeport LNG might return to service. While Henry Hub ultimately finished higher, a rally earlier in the day fizzled after Bloomberg cited anonymous sources who said the terminal would likely cancel shipments scheduled for November and December. The contract seemed poised for a strong recovery from Friday’s losses, when unverified rumors on social media about further delays to Freeport’s restart stirred the market. The liquefied natural gas operator responded last Friday to what it called “false information circulated today about the restart of Freeport LNG’s liquefaction facility.” Freeport said it had not made any public statements on the timing of its highly anticipated return to service. The company warned that “any Tweets and/or posts on Freeport LNG-branded letterhead that may have been obtained or published, are reporting false information and are not legitimate.” Freeport did not comment about the Bloomberg report. It continues to work toward a restart, but the mid-November timeline that it had previously targeted is clearly slipping away. The facility has not submitted a remedial work plan or a request to restart to federal regulators, which is required before operations can resume. The outage has moved the U.S. and global gas markets since it began over the summer given the facility’s domestic demand and international supply impacts. The December Henry Hub contract finished 5.4 cents higher at $5.933/MMBtu on Monday. Freeport has been offline since a June explosion near its storage tanks forced the plant to shut down. It has been targeting a mid-November start-up that calls for it ramping toward 2 Bcf/d of production, or about 85% of its capacity. Full service isn’t expected to resume until March, when a second loading dock returns to operations.
December Natural Gas Futures, Cash Prices Rally as Winter Chill Offsets Freeport Confusion -Natural gas futures recovered Monday as weather shifted substantially colder, driving heating demand and offsetting festering concerns about the relaunch of a key export facility. The December Nymex gas futures contract settled at $5.933/MMBtu, up 5.4 cents day/day. January gained 3.6 cents to $6.299. NGI’s Spot Gas National Avg. jumped $1.415 to $6.340, with prices surging in the nation’s midsection and the East along with advancing cold. The front month contract shed 36.0 cents to settle at $5.879 on Friday. This followed unsubstantiated rumors that the Freeport LNG facility in Texas, offline since June following a fire, would not reopen until 2023 – much later than its mid-November goal. The liquefied natural gas operator put out a statement responding to “false information circulated” about “the restart of Freeport LNG’s liquefaction facility.” Freeport said it had not made any public statements on the timing of the highly anticipated return to service for the 2 Bcf/d export terminal, seemingly leaving a potential November relaunch on the table. The company warned that “any Tweets and/or posts on Freeport LNG branded letterhead that may have been obtained or published, are reporting false information and are not legitimate.” Futures popped more than 30 cents in morning trading Monday as traders shrugged off the conflicting Freeport news and focused instead on intensifying cold in the central United States that had spread east over the weekend. Wintry conditions were forecast to settle across much of the Lower 48 in the current week and deeper into November, NatGasWeather said. However, the gains were curbed after a midday Bloomberg News report, citing anonymous sources, said Freeport had told LNG buyers it would likely cancel shipments slated for this month and December because repair work and efforts to secure regulatory approvals are ongoing. The company, however, had not provided an official update to its timeline as of the December contract’s settlement on Monday. “Nat gas market participants have been frustrated by the lack of transparency from Freeport regarding when they will resume operations since it’s keeping nearly 2 Bcf/d in the U.S. instead of it being exported overseas,” NatGasWeather said. “Many still believe Freeport LNG won’t resume operations by their stated date and will be delayed into December due to the lengthy federal process to ensure the facility is safe. “We must expect more fallout early this week” from “confusing and conflicting Freeport news. But what’s likely to matter more” is colder weather “for the coming 15 days.” Both the American and European weather models showed widespread freezing conditions through this week and into next before returning to seasonal norms around the Thanksgiving holiday, NatGasWeather added.
U.S. natgas up 2% on colder forecasts; Freeport LNG delay (Reuters) - U.S. natural gas futures gained about 2% on Tuesday on forecasts for colder weather and more heating demand next week than previous estimates, but expectations that Freeport LNG will delay the restart of its liquefied natural gas (LNG) export plant in Texas clouded the outlook. Freeport LNG, as of Monday afternoon, had not submitted a request to resume service to the Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). Many analysts believe that means the plant will not return until December at the earliest. Global gas markets have been extremely focused on Freeport news this month, with U.S. futures gaining or losing more than 5% in seven of the past 10 days. Some people have created fake news releases on Freeport letterhead and posted unfounded tweets about pipe cracks to sway the market up or down. Some traders have called on the U.S. Commodities Futures Trading Commission (CFTC) to investigate the flood of misinformation. Until late last week, Freeport had said repeatedly that the plant, which shut after an explosion on June 8, was on track to return to service in November. The company, however, did not mention a November restart, or any restart date, in comments made on Friday or Monday. "Speculating on Freeport's restart timeline is a loser's game, but resuming output by year-end would provide the boost in demand that bullish market participants have been anticipating, resulting in an upside catalyst for prices," Ade Allen, an analyst at energy research firm Rystad Energy, said in a note. Once the 2.1-billion cubic feet per day (bcfd) Freeport facility returns to service, U.S. gas prices should rise due to increased demand from LNG export plants. On the flip side, the delay in Freeport's return means less gas available for Europe to import, a factor which helped prices there spike around 7% on Tuesday. Europe needs U.S. gas because it is not getting as much Russian fuel as usual after imposing sanctions on Moscow for Russia's invasion of Ukraine. A couple of vessels were waiting to pick up LNG from Freeport, according to Refinitiv data. Prism Diversity and Prism Courage were offshore from the plant, while LNG Rosenrot and Prism Agility were expected to arrive in late November. But one vessel, Prism Brilliance, which had been waiting outside the Freeport plant, seems to have given up on Freeport and was now sitting outside of Corpus Christi where Cheniere Energy Inc has an LNG export plant. Front-month gas futures rose 10.1 cents, or 1.7%, to settle at $6.034 per million British thermal units (mmBtu). Gas futures are up about 63% so far this year as much higher global gas prices feed demand for U.S. exports due to supply disruptions and sanctions linked to Russia's invasion of Ukraine. Gas was trading at $37 per mmBtu at the Dutch Title Transfer Facility (TTF) in Europe and $27 at the Japan Korea Marker (JKM) in Asia.
U.S. natgas futures gain 3% on colder midday weather forecast (Reuters) - U.S. natural gas futures closed about 3% higher on Wednesday, reversing earlier losses as colder midday weather forecasts outweighed news a few liquefied natural gas (LNG) vessels turned away from the Freeport export plant in Texas in recent days and expectations its restart will be delayed. Federal pipeline safety regulators released a heavily redacted consultant's report blaming inadequate operating and testing procedures, human error and fatigue for the June 8 explosion that shut the Freeport plant. Sources familiar with Freeport LNG's filing said the company had not yet submitted a request to resume service to the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). Many analysts said that means the plant will not return to service until December at the earliest. Until late last week, Freeport had said repeatedly the plant remained on track to return to service in November. In comments made in recent days, however, the company did not mention a restart date. Once the 2.1 billion-cubic-feet-per-day (bcfd) Freeport facility restarts, U.S. gas prices will likely rise due to increased demand from the country's LNG export plants. Until the facility restarts, less U.S. gas will be available to export to Europe, where prices have spiked around 17% this week. Europe needs U.S. gas because Russia has slashed its gas exports there after several European countries imposed sanctions on Moscow for its invasion of Ukraine. Worries about a possible U.S. railroad strike have underpinned gas prices because a rail strike would threaten coal deliveries to U.S. utilities, forcing generators to burn more gas. A third U.S. rail union voted this week to reject a tentative national contract reached in September, but expects to continue negotiating to reach a deal. Front-month gas futures rose 16.6 cents, or 2.8%, to settle at $6.200 per million British thermal units (mmBtu). Gas futures were up about 66% so far this year as much higher global gas prices feed demand for U.S. exports due to supply disruptions and sanctions linked to Russia's invasion of Ukraine. Gas was trading at $35 per mmBtu at the Dutch Title Transfer Facility (TTF) in Europe and $26 at the Japan Korea Marker (JKM) in Asia. Data provider Refinitiv said average gas output in the U.S. Lower 48 states slid to 99.2 bcfd so far in November, down from a record 99.4 bcfd in October. With much colder weather coming, Refinitiv projected average U.S. gas demand, including exports, would jump from 122.6 bcfd this week to 126.6 bcfd next week. The forecast for this week was higher than Refinitiv's outlook on Tuesday, while its forecast for next week was lower. The average amount of gas flowing to U.S. LNG export plants rose to 11.8 bcfd so far in November, up from 11.3 bcfd in October.
U.S. natural gas futures gain 3% on cold forecasts (Reuters) - U.S. natural gas futures rose about 3% to a one-week high on Thursday on forecasts for much colder weather and higher heating demand over the next week or so. "Natural gas has caught a bid on the back of a big change in the weather, with forecast(s) below average for much of the (Lower) 48 states," . Meteorologists at AccuWeather said a foot of snow had already fallen in Buffalo, New York, with another three to four feet expected in parts of Upstate New York over the next few days. U.S. gas prices increased despite forecasts for warmer weather and lower heating demand in two weeks than previously expected and a federal storage report showing an expected storage build that was much bigger than usual last week when the weather was still mild and heating demand low. The U.S. Energy Information Administration (EIA) said utilities added 64 billion cubic feet (bcf) of gas to storage during the week ended Nov. 11. That was close to the 63-bcf build analysts forecast in a Reuters poll and compares with an increase of 23 bcf in the same week last year and a five-year (2017-2021) average decline of 5 bcf. Traders noted utilities started pulling gas out of storage during the cold weather this week. Some traders said they were surprised U.S. gas prices rose for a fourth day in a row despite widespread expectations Freeport LNG will delay the restart of its liquefied natural gas (LNG) export plant in Texas to December or later. In recent days, a couple of LNG vessels that were either heading for Freeport (LNG Rosenrot) or had waited outside the plant (Prism Brilliance) have moved on to other ports. LNG Rosenrot is now headed for Gibraltar, while Prism Brilliance is sitting outside Corpus Christi in Texas where Cheniere Energy Inc has an LNG export plant, ship tracking data from Refinitiv showed. Until late last week, Freeport LNG had said repeatedly the plant remained on track to return to service in November. In comments made in recent days, however, the company did not mention a restart date. Front-month gas futures rose 16.9 cents, or 2.7%, to settle at $6.369 per million British thermal units (mmBtu), their highest close since Nov. 7. That also put the front-month up for a fourth day in a row for the first time since September. Gas futures are up about 57% so far this year as much higher global gas prices feed demand for U.S. exports due to supply disruptions and sanctions linked to Russia's invasion of Ukraine. Gas was trading at $33 per mmBtu at the Dutch Title Transfer Facility (TTF) in Europe and $26 at the Japan Korea Marker (JKM) in Asia. Once the 2.1 billion-cubic-feet-per-day (bcfd) Freeport facility restarts, analysts expect U.S. gas prices to rise due to increased demand from the country's LNG export plants.
Natural Gas Futures Snap Win Streak Amid Freeport LNG Delays, Weather Shift; Spot Prices Advance - Natural gas futures faltered Friday, ending a four-day win streak built on impressive cold blasts. Traders took profits after the run-up and shifted their attention to the delayed relaunch of a critical export terminal and the potential for milder weather late in November. The December Nymex gas futures contract settled at $6.303/MMBtu, down 6.6 cents day/day. January slipped 2.8 cents to $6.716. NGI’s Spot Gas National Avg., however, gained 14.0 cents to $6.685 amid freezing conditions and powerful snowstorms in the Northeast.NatGasWeather said that, while bitter cold and snow were expected to pepper the central and eastern United States through the weekend and into the week ahead, both the American and European weather models dropped forecast demand Friday and showed less cold over the northern part of the country during the last week of November.Forecasts “held very strong national demand” leading up to Thanksgiving but pointed to a return to seasonal levels and “a little lighter-than-normal” demand for several days at the end of the month.Looking further out, recently released longer-range forecasting “suggested a seasonal to slightly bearish pattern should be favored to start December,” NatGasWeather said. Meanwhile, the Freeport LNG export plant in Texas, forced offline in June following a fire, provided a long-awaited update after missing its target to return to service by mid-November amid ongoing repairs and work to secure regulatory approvals.Management of the liquefied natural gas facility said in a statement reconstruction work necessary to commence initial operations, including utilization of all three liquefaction trains and two LNG storage tanks, was about 90% complete. The company expects to complete repairs by the end of this month and updated the targeted relaunch to mid-December.“We are committed to moving forward with an uncompromising safety focus and enhanced operational processes that will enable us to chart a safe, sustainable path forward to serve our customers and the broader LNG market as a whole,” said Freeport CEO Michael Smith.The update, anticipated for several days, followed comments from Osaka Gas Co. President Masataka Fujiwara, who reportedly said early Friday in Japan that it was “highly likely” the Freeport facility would not reopen this month, according to Bloomberg. Osaka Gas owns a stake in one liquefaction train and contracted about 15% of the facility’s fuel.Freeport anticipates ramping up to 2 Bcf/d of production capacity by January, though full restoration to 2.38 Bcf/d may not happen until March, as the plant brings back each of its three trains in sequential order.The news of ongoing delays is important for natural gas markets because Freeport accounts for about 15% of American export capacity. With it out of commission, it limits U.S. suppliers’ ability to meet robust demand from Europe and parts of Asia for the super-chilled fuel.“The market continues to ping pong amid the latest” Freeport news, said EBW Analytics Group’s Eli Rubin, senior analyst.
U.S. Diesel Inventories Hit Historic Lows At The Worst Possible Time - U.S. distillate stocks, which include diesel and heating oil, have slumped to their lowest level for this time of the year since 1951, just as the heating season starts and the EU embargo on Russian oil product imports kicks in in February.Despite a small build in America’s distillate inventories last week, the levels are still at their lowest level since 1951, according to Financial Times estimates.The historically low stocks have pushed diesel prices much higher than the smaller rises in gasoline and crude oil this year. Since diesel is the primary fuel of the economy and long-haul transportation, the high diesel prices continue to fuel inflation.In the week ending November 11, distillate fuel inventories increased by 1.1 million barrels and are about 15% below the five-year average for this time of year, the EIA said in its weekly inventory report on Wednesday. At 107.4 million barrels, those stocks are the lowest ever seen for this season of the year.“The bulk of the increase in distillate stocks was on the US East Coast. And while this is helpful, stocks in the region are still at their lowest levels on record for this time of year,” ING strategistssaid on Thursday, commenting on the EIA inventory data.Very low diesel stockpiles and lower refining capacity since the pandemic have driven diesel prices in the United States higher to the point of reaching a record-high premium over gasoline and crude oil.Going forward, the supply of diesel in the U.S. and globally is set to tighten even further with the EU embargoes on imports of Russian crude and products, starting in December and February, respectively.“The competition for non-Russian diesel barrels will be fierce, with EU countries having to bid cargoes from the US, Middle East and India away from their traditional buyers,” International Energy Agency (IEA) said in its monthly report earlier this week. “Increased refinery capacity will eventually help ease diesel tensions. However, until then, if prices go too high, further demand destruction may be inevitable for the market imbalances to clear,” said the agency, which sees stubbornly high diesel prices fueling inflation as well as slowing economies leading to a slight decline in global diesel demand in 2023.
Why U.S. Diesel Exports Haven’t Dried Up During A Domestic Shortage - Following my recent article — Why The U.S. Has A Diesel Shortage — one reader pointed out that I omitted one factor from my analysis. Even as the U.S. grapples with one of the worst diesel shortages on record, U.S. companies are exporting more than a million barrels of distillates a day.That’s a fair point, but it isn’t a new development. U.S. companies have beenexporting more than a million barrels a day of distillates for about a decade. The obvious question, then, is why this is being done.The short and simple answer is that companies are doing it because they can, and because they are making more money doing this than selling it in the U.S. Consumers may complain, but ultimately these companies are trying to make as much money as they can, and that means selling products to the highest bidders.A U.S. Gulf Coast refiner who wishes to ship distillates to the East Coast must abide by the Jones Act, which requires any cargo shipped between U.S. ports to be carried by U.S. ships, with American crews. This can drive up costs, and make it more economical for that Gulf Coast refiner to export to Europe or South America.Another important point to note is that sometimes distillates are exported because the product doesn’t meet U.S. standards.For example, in 2006 EPA began to phase-in more regulations to lower the amount of sulfur in diesel fuel to 15 parts per million (PPM). This required costly investments by refiners to comply, but some refiners chose to continue making high-sulfur diesel and to export that to countries with less stringent regulations. That practice continues today and explains some of the exports.That is ultimately a business decision for each company, although it’s understandable that consumers would be upset by such decisions.The other obvious question — which I am often asked — is why don’t we ban companies from exporting fuel during a fuel crisis? That’s ultimately a political question. Would the crisis be eased if such a ban were in place? It’s hard to argue that it wouldn’t, but it would exacerbate the crisis elsewhere.Europe is already grappling with a fuel crisis due to the situation in Ukraine. They are relying on U.S. exports to help ease their fuel burdens headed into winter. An American consumer may say that this isn’t our problem, but this isn’t being done for altruistic reasons. Some countries are in worse shape than the U.S. with respect to fuel supplies, and they are willing to pay more to obtain them. That, in a nutshell, is why companies are exporting diesel during a diesel shortage.
The Mississippi, She's A-goin' Dry - Low Water Levels Pinch Midwest Condensate Takeaway - Infrastructure constraints in the energy sector come in all shapes and sizes, and don’t think for a second that they only involve pipelines. For many producers of crude oil, refined products and other liquids, the Mississippi River is a critically important conduit for barging commodities to market. Lately though, water levels on sections of the river have been near historic lows, reducing both the volume of liquids that each barge can carry and the number of barges the Mississippi can handle. Among other things, the low water situation has been putting a squeeze on condensate producers in the “wet” Marcellus/Utica, who depend on barges to transport a significant portion of their superlight crude oil down the Ohio and Mississippi rivers to refineries and for blending into Light Louisiana Sweet (LLS). In today’s RBN blog, we discuss the situation. The rapid run-up in U.S. crude oil, natural gas and NGL production through the 2010s put enormous pressure on the nation’s energy-related infrastructure. In what seemed like a flash, the Bakken in western North Dakota became a leading crude oil play, spurring the development of crude-by-rail terminals and takeaway pipelines. In the Marcellus/Utica, production growth made the Northeast self-sufficient in natural gas and resulted in a slew of pipeline reversals, expansions and greenfield projects to enable gas to flow west and south. And over the past five years or so, we’ve chronicled a phenomenal build-out of infrastructure within and out of the Permian, most of it designed to gather and process hydrocarbons in West Texas and southeastern New Mexico, and transport them to end-users and export markets along the Gulf Coast. One of the most impressive — and comprehensive — infrastructure projects of the Shale Era was MPLX’s development of a condensate and NGL “purity product” pipeline-and-storage network in the Midwest. RBN estimates that the network now transports more than 30% of the condensate produced in the liquids-rich Marcellus/Utica play; the pipes also move much of the natural gasoline produced there and, more recently, a portion of the play’s isobutane as well. As important as this network is, however, Marcellus/Utica producers also depend on other means of transport to get these liquids to market, especially barges moving condensate down the Ohio and the Mississippi.
Plaquemines oil terminal could reduce land-building sediment for Mid-Barataria diversion -- Docking facilities planned for a proposed 20-million-barrel crude oil export storage terminal – and the oversized ocean-going vessels and barges that would be berthed there – could reduce the land-building ability of the state’s proposed $1.4 billion Mid-Barataria Sediment Diversion, just downstream, by as much as 15 percent.That’s the warning raised by Bruce Lelong, a project leader withAECOM, the state contractor overseeing engineering and design of the diversion for the state Coastal Protection and Restoration Authority, in an Aug. 30 email sent to the company’s subcontractors.“I expect it will have significant and potentially adverse impacts to MBSD,” he wrote, using the initials of the diversion project and citing a 2012 study completed by the Water Institute of the Gulf for the Coastal Protection and Restoration Authority about an earlier plan by RAM Terminals to build a coal export facility on the same property.The study was written by Ehab Meselhe, lead scientist with the Water Institute, and three researchers with ARCADIS. They concluded that a Mississippi River docking facility just upriver from the proposed diversion site actually would reduce the amount of sediment captured by the diversion by as much as 17 percent.That reduction was based on modeling assuming an ocean-going vessel with a draft of minus 40 feet and a large barge were berthed at the facility. In his email, Lelong said the new oil terminal project proposed berths for multiple larger “post-Panamax” ships, which have drafts of as much as minus 50 feet, plus barges.The oil terminal is being proposed by the Plaquemines Port and Harbor District, Tallgrass Energy LP, and Drexel Hamilton, a Philadelphia-based investment firm, and would be operated by Tallgrass. The Plaquemines Parish Council has approved the issuance of up to $650 million in revenue bonds to underwrite Drexel Hamilton’s recently created Plaquemines Liquids Terminal LLC.The port authority has been attempting to develop the Myrtle Grove property adjacent to the state diversion site and just below the Phillips 66 Alliance refinery since the cancellation of a proposal by RAM Terminals LLC to build a coal export terminal there.The state Department of Natural Resources issued a permit for the RAM facility in 2013, but a Plaquemines Parish judge threw out the permit, saying the state hadn’t considered alternative sites. In April 2016, the state issued a second permit, but it was put on hold when officials asked for information about potential impacts on the diversion. The RAM project’s federal and state permit applications expired in December 2017.The oil terminal’s efforts to receive a permit from state officials has been delayed by repeated requests from the state Coastal Protection and Restoration Authority for information on how the terminal might affect the diversion. Authority officials are concerned about the terminal’s potential to reduce the amount of sediment captured by the diversion, and about any oil or chemical spill at the terminal could move through the diversion into Barataria Bay.
Shell's Zydeco oil pipeline running at reduced capacity -(Reuters) -Shell Pipeline Co.'s Zydeco oil pipeline from Houston to Port Neches, Texas, is operating at reduced capacity due to project work at Port Neches, and is expected to remain at reduced capacity until mid to late December, the company said on Thursday.The Zydeco pipeline systemalleviates transportation bottlenecks of crude arriving in Houston from the Eagle Ford, Permian and Bakken regions, according to Shell Midstream Partners' website. The system connects severalcrude oil pipelines in Houston and Port Neches, and spans over 350 miles(563.27 km), with a mainline capacity of 375,000 barrels per day.The capacity reduction of the line from Houston to Port Neches sent some U.S. physical crude oil grades surging, dealers said, with Light Louisiana Sweet crudeWTC-LLS this week firming to $6 a barrel above U.S. crude oil futures CLc1, its strongest in more than two years. At a 50-cent differential, Mars Sour crude WTC-MRS was at its strongest since April, Refinitiv Eikon data show.
U.S. Permian oil production due to rise in Dec to record -EIA -(Reuters) - Oil output in the Permian in Texas and New Mexico, the biggest U.S. shale oil basin, is due to rise by about 39,000 barrels per day (bpd) to a record 5.499 million bpd in December, the U.S. Energy Information Administration (EIA) said in its productivity report on Monday. U.S. crude oil output is due to rise by about 91,000 bpd to 9.191 million bpd in December, its highest since March 2020, the EIA projected. In the Bakken in North Dakota and Montana, the EIA forecast oil output will rise 19,000 bpd to 1.201 million bpd in December, the most since November 2020. In the Eagle Ford in South Texas, output will rise 14,000 bpd to 1.237 million bpd in December, its highest since April 2020.
U.S. Permian oil output to hit record in December, but gains are slow - Oil output in the Permian Basin is set to hit another record of5.499 million barrels per day in December, but production is rising very slowly in the biggest U.S. shale oil basin even though U.S. prices have surged in 2022. Overall US crude oil output in shale regions is due to rise by a mere 91,000 bpd to 9.191 million bpd in December, the highest since March 2020, the US Energy Information Administration (EIA) said in its monthly productivity report on Monday. Natural gas production is also expected to reach a record. Shale executives have been more bullish on gas output than crude because of the growing global need for US gas and oil producers' desire to maintain capital discipline. In addition, aging shale regions are showing weaker per-well output. Productivity in the biggest oil and gas basins has declined every month since hitting records of new oil well production per rig of 1,545 bpd in December 2020 in the Permian and new gas well production per rig of 33.3 million cubic feet per day (mmcfd) in March 2021 in Appalachia. The EIA expects new oil well production per rig will drop to 1,049 bpd in the Permian and new gas well production per rig will drop to 26.1 mmcfd in Appalachia, both of which are the lowest since July 2020. In the Bakken in North Dakota and Montana, the EIA forecast oil output will rise 19,000 bpd to 1.201 million bpd in December, the most since November 2020. In the Eagle Ford in South Texas, output will rise 14,000 bpd to 1.237 million bpd in December, its highest since April 2020. Total natural gas output in the big shale basins will increase 0.6 billion cubic feet per day (bcfd) to a record 95.7 bcfd in December, the EIA forecast. In the biggest shale gas basin, Appalachia in Pennsylvania, Ohio and West Virginia, output will rise to 35.6 bcfd in December, the highest since hitting a record 36.0 bcfd in December 2021. Gas output in the Permian and the Haynesville in Texas, Louisiana and Arkansas will rise to record highs of 21.3 bcfd and 16.3 bcfd in December, respectively. EIA said producers drilled 984 wells in October, the most since March 2020. Total drilled-but-uncompleted (DUC) wells rose by eight to 4,408 in October, the first monthly increase since June 2020.
5.4 magnitude earthquake hits western Texas, southern New Mexico - The magnitude 5.4 earthquake that rattled western Texas and southern New Mexico on Wednesday occurred in a "seismically active" region that has seen more than 100 earthquakes over magnitude 2.5 since 2018, the U.S. Geological Survey said Thursday. The latest earthquake occurred about 24 miles southwest of Mentone, Texas, the USGS reported. The earthquake occurred around 3:30 p.m. local time.The largest earthquake in the region prior to Wednesday's occurrence was a magnitude 5 earthquake on March 26, 2020, that struck about 6.21 miles north of the most recent earthquake.No injuries or deaths were reported from the latest activity, but the earthquake forced the closing of the historic Robert B. Green historical building in San Antonio, which now houses a University Health administrative building, the hospital system said Thursday. University Health said the 100-year-old building was deemed unsafe and its administrative offices have been moved elsewhere. Data from the USGS said the earthquake was felt as far east as Dallas and Austin and as far north as Roswell, New Mexico.The San Antonio Police Department said residents in high-rise buildings in the city's downtown reported shaking from the earthquake Wednesday, ABC affiliate KSAT reported.
Human-induced M5.3 earthquake, series of aftershocks hit western Texas, U.S. - A shallow earthquake, registered by the USGS as M5.3, hit western Texas at 21:32 UTC on November 16, 2022. The agency is reporting a depth of 8.3 km (5.1 miles). The quake was followed by a series of aftershocks, with magnitudes ranging from 2.6 to 4.1. The epicenter was located 39.2 km (24.3 miles) WSW of Mentone (population 19), Texas, and 90 km (56 miles) SSE of Carlsbad (population 28 957), New Mexico. According to the USGS PAGER, 397 000 people are estimated to have felt light shaking. A Green alert was issued for shaking-related fatalities and economic losses. There is a low likelihood of casualties and damage. Overall, the population in this region resides in structures that are resistant to earthquake shaking, though vulnerable structures exist. The predominant vulnerable building types are unreinforced brick masonry and reinforced masonry construction. Light damage was reported in the region. The largest known earthquake to hit Texas was M6.0 in the town of Valentine, near Marfa, in 1931. The quake occurred in the same area where a human-induced M5.0 earthquake hit on March 26, 2022. This was the third-largest earthquake recorded in Texas and the largest earthquake in the Central and Eastern United States since the three M5.0 – 5.8 induced events in Oklahoma in 2016. “Using multistation waveform template matching, we detect 3 940 earthquakes in the sequence with the first event in the area occurring in May 2018… We find that the sequence was most likely induced by nearby wastewater disposal operations, and seismicity rates in the region surrounding the M5.0 will likely continue to increase in the future if disposal operations continue unaltered.”“This area of western Texas was historically very quiet, but has had 375 M≥3 quakes beginning in 2019,” said Dr. Lucy Jones — one of the world’s most recognizable seismologists.2 “This is the type of pattern that suggests the quakes are induced by pumping fluids into the ground. This is not too big to be induced.” As is the case elsewhere in the world, there is evidence that some central and eastern North America earthquakes have been triggered or caused by human activities that have altered the stress conditions in the earth’s crust sufficiently to induce faulting.3 Activities that have induced felt earthquakes in some geologic environments have included the impoundment of water behind dams, injection of fluid into the earth’s crust, extraction of fluid or gas, and removal of rock in mining or quarrying operations. In much of eastern and central North America, the number of earthquakes suspected of having been induced is much smaller than the number of natural earthquakes, but in some regions, such as the south-central states of the U.S., a significant majority of recent earthquakes are thought by many seismologists to have been human-induced. Even within areas with many human-induced earthquakes, however, the activity that seems to induce seismicity at one location may be taking place at many other locations without inducing felt earthquakes. In addition, regions with frequent induced earthquakes may also be subject to damaging earthquakes that would have occurred independently of human activity. Making a strong scientific case for a causative link between a particular human activity and a particular sequence of earthquakes typically involves special studies devoted specifically to the question. Such investigations usually address the process by which the suspected triggering activity might have significantly altered stresses in the bedrock at the earthquake source, and they commonly address the ways in which the characteristics of the suspected human-triggered earthquakes differ from the characteristics of natural earthquakes in the region.
Texas Oil and Gas Agency Investigating 5.4 Magnitude Earthquake in West Texas, the Largest in Three Decades - Inspectors for the Texas Railroad Commission are investigating a 5.4 magnitude earthquake that was recorded west of Pecos near the border of Reeves and Culberson counties on Wednesday, the agency said.The earthquake, confirmed by the U.S. Geological Survey, was the largest recorded in the state since 1995 and the third-largest in Texas history, according to the USGS National Earthquake Information Center. The largest quake in Texas history was 5.8 magnitude recorded in 1931 southwest of Valentine, according to the USGS National Earthquake Information Center.“It felt like a truck hit the house,” It was the biggest Texas quake in nearly three decades, but far from the only one. Shifflett has weathered the damage from smaller earthquakes for years. One, around 2016, left a broad bulge on his 2,000 acres, cracking pipes and ruining his gravity-run irrigation system, he said.The quake could be felt as far away as Carlsbad, New Mexico, and El Paso, and it forced University Health, the Bexar County Hospital District, to vacate a historic downtown San Antonio hospital building after structural engineers declared it unsafe. The more than 100-year-old building was once known as the most modern hospital of its kind in the Southwest.Most of the building’s clinical services were moved to a new building about a decade ago, but some administrative services were still housed in the historic location. Those offices have now been moved to a different space, according to a University Health statement.The number of earthquakes recorded in Texas has spiked in recent years, particularly in West Texas’ Permian Basin, the most productive oil and gas region in the state. Scientific studies have linked the seismic activity to the disposal of contaminated, salty water deep underground — a common practice by oil companies at the end of the hydraulic fracturing process that can awaken dormant fault lines.Between three and six barrels of salty, polluted water also come up to the surface with every barrel of oil during the fracking process — ancient water that was trapped underground by rock formations.Years of pumping hundreds of millions of gallons of contaminated water per day underground in Texas has coincided with more frequent and more powerful earthquakes in the state: An analysis by The Texas Tribune found that the number of earthquakes of 3.0 magnitude and greater had doubled in 2021 from the previous year.
West Texas earthquake damages historic building on University Health campus - A strong earthquake in West Texas on Wednesday that was felt hundreds of miles away from the epicenter has damaged the Robert B. Green historical building in downtown San Antonio, according to a University Health news release.Officials said Thursday that structural engineers determined the downtown building owned by the public health system was unsafe and have closed off the building.The magnitude 5.3 quake near the New Mexico border in Mentone was caused by oil and gas extraction, according to the U.S. Geological Survey. “Over the past few months, the frequency of these quakes has been going up,” said Randy Baldwin, a geophysicist with the USGS. “We've seen an increase since about 2015, and it’s been related to the extraction industries out in the area.” The quake appears to be one of the largest in Texas history. The largest known earthquake to ever hit Texas was a 6.0 magnitude quake in the town of Valentine, near Marfa, in 1931. Wednesday's earthquake occurred at a depth of about 6 miles, according to the USGS. Mentone is a tiny rural town about 77 miles west of Odessa and over 350 miles from San Antonio. The quake was strong enough to be felt in San Antonio and as far north as Dallas, areas where these types of events are rare. Built in 1917, the hospital building is named for former Bexar County Judge Robert B. Green and was designed by prominent architect Atlee B. Ayres. The building, once lauded as “one of the best and modern institutions of its kind in the Southwest,” appears to be the only San Antonio structure damaged by Wednesday’s earthquake. The vast majority of the building's clinical services were moved in 2013 to the newer Robert B. Green building next door. The new structure appears to be undamaged by the earthquake. Had the earthquake occurred closer to a city, the damage could have potentially been more severe, Baldwin said. The epicenter was close to the same area where a 5.0 earthquake hit in March 2020, and a number of 4.0 magnitude earthquakes have been reported in the area in the last few months, Baldwin said. “These are induced earthquakes out here,” he said. “They are related to the oil and gas industries. Because the amount of production has increased, there has been a corresponding increase in the rates of wastewater injection wells in the area. So those factors go hand in hand.” More than 200 earthquakes of 3.0 magnitude or greater struck Texas in 2021, more than double the 98 recorded in 2020, according to a Texas Tribune report.The Tribune reported that the record-setting seismic activity is largely concentrated in West Texas’ Permian Basin, the most productive oil and gas region in the state. Most induced earthquakes are not directly caused by hydraulic fracking, according to the USGS. The recent increase in earthquakes in the central United States is primarily caused by the disposal of waste fluids that are a byproduct of oil production. Wastewater disposal wells typically operate for longer durations and inject much more fluid than what is injected during the hydraulic fracturing process, making them more likely to cause earthquakes.
Far West Texas deals with 40 quakes in less than 24 hours - The area west of Mentone in Reeves County was shaken Wednesday and Thursday with 40 earthquakes reported in less than 24 hours.The biggest quake of them all was the 5.4-magnitude quake that was felt as far as Midland, San Antonio and Ciudad Jaurez, according to reports including one from the Associated Press. It was the third strongest earthquake in the state’s history.The series of tremors, specifically the 5.4-magnitude quake, was enough for the Railroad Commission to announce it was deploying inspectors to Reeves County. The strongest of all the tremors on Wednesday was the strongest recorded in the lower 48 states this calendar year.“The agency is monitoring seismic data from the United States Geological Survey, the TexNET Seismic Monitoring Program and private operator monitoring stations and will take any actions necessary to protect public safety and the environment,” the Railroad Commission stated in a news release on Thursday. “RRC inspectors are examining disposal activity at injection wells in the area, and staff is also reviewing permit requirements and operators’ seismic response plans in the Northern Culberson-Reeves Seismic Response Area (SRA).”The quakes took place in relatively the same area west-southwest of Mentone. The first quake, the 5.4-magnitude earthquake, took place 25.5 miles west-southwest of Mentone around 3:32 p.m. Thirty-one quakes ranging from 1.9-4.1 in magnitude were reported between 3:39 and 7:49 p.m., according to the USGS. At 9:54 p.m. the quakes returned ranging from 2.1-3.8 in magnitude.The last seven earthquakes, including the five that took place Thursday through 3 p.m., were less than magnitude 3.0, according toearthquaketrack.com. The same site showed 42 quakes had taken place within the last 24 hours of the 5.4-magnitude quake. It also showed 70 quakes within the last seven days, 199 in the past 30 days and 1,668 in the past 365 days,TexNet, the Texas state earthquake monitoring network, stated the following about the seismic activity:“We are still investigating the data associated with these seismic events,” said Scott W. Tinker, the State Geologist of Texas, and the director of the Bureau of Economic Geology. “Our first concern, of course, is for any people who might have been affected by these earthquakes. The professional scientists on the TexNet team, led by Alexandros Savvaidis, are working diligently to analyze the data that we have received from the TexNet network of monitoring stations.”The Associated Press reported Thursday that State Rep. Eddie Morales, Jr., whose district includes Mentone, said he spoke with local authorities and there were no reported injuries. He said via Twitter that state officials will be “inspecting roads, bridges and other infrastructure as a precaution.”
EPA Announces More Stringent Methane Measures - The U.S. Environmental Protection Agency (EPA) has announced that it is strengthening its proposed standards to cut methane and other air pollution. If finalized, the standards will protect workers and communities, maintain and create high-quality, union-friendly jobs, and promote U.S. innovation and manufacturing of critical new technologies, all while delivering significant economic benefits through increased recovery of wasted gas, the EPA noted. The updates, which supplement proposed standards the EPA released back in November 2021, reflect input and feedback from a broad range of stakeholders, and nearly half a million public comments, according to the EPA. The organization said the updates would provide more comprehensive requirements to reduce pollution, “including from hundreds of thousands of existing oil and gas sources nationwide”. “We’re listening to public feedback and strengthening our proposed oil and gas industry standards, which will enable innovative new technology to flourish while protecting people and the planet. Our stronger standards will work hand in hand with the historic level of resources from the Inflation Reduction Act to protect our most vulnerable communities and to put us on a path to achieve President Biden’s ambitious climate goals,” EPA Administrator Michael S. Regan said in an EPA statement. In response to the EPA’s supplemental proposed methane rule, the American Petroleum Institute’s (API) Senior Vice President of Policy, Economics and Regulatory Affairs, Frank Macchiarola, said, “API looks forward to reviewing the proposed rule in its entirety and will continue to work with EPA in support of a final rule that is cost-effective, promotes innovation, and creates the regulatory certainty needed for long-term planning”. “Federal regulation of methane crafted to build on industry’s progress can help accelerate emissions reductions while developing reliable American energy. API’s member companies are continuously advancing and deploying new technology to improve methane detection and reduction, and we support efforts to promote this innovation rather than inhibiting it with overly prescriptive red tape,” Macchiarola added. “Our industry is taking action, and as a result, methane emissions relative to production fell 60 percent from 2011 to 2020. Industry-led initiatives like The Environmental Partnership are helping to continue that progress with the goal of further reducing methane emissions in every major U.S. basin,” he continued. Also commenting on the supplemental proposed methane rule, the American Exploration and Production Council (AXPC) said, “our industry is committed to working with EPA on the federal regulation of methane, in a manner that creates regulatory certainty and allows for domestic producers to provide America and the world with affordable and reliable energy”. “While we are still digesting the full proposal, at the onset we appreciate EPA’s inclusion of many of the recommendations we made for needed changes and clarifications for upstream. We still have concerns that should be addressed to make key provisions truly workable, but we will continue to work with EPA on meaningful solutions,” AXPC added.
FOCUS-In Colorado, oil firms fix leaky wells ahead of new rules - (Reuters) - Northern Colorado's biggest oil producing region is emerging as a test case for energy companies hoping to tackle the industry's most pressing regulatory and environmental problems: capping old wells that leak climate-warming methane and other emissions. In this farming community, oil giant Chevron Corp is sending crews as part of a state-wide push to seal leaks. Once wells are plugged with cement and equipment is removed, workers restore the land to its original state. Colorado, the fifth largest U.S. oil-producing state, has been in the forefront of anti-drilling sentiment spreading across the country. Voters have set limits to operations near homes and schools, banned routine burning of unwanted gas, and imposed restrictions on fracking chemicals. Chevron Corp is running 16 "workover rigs" that do well removal. It plans to deconstruct and plug some 500 old wells in Colorado each year. That work, along with new equipment to clean oil operations, will reduce greenhouse emissions by about 100,000 U.S tons a year, the company said, roughly the same as 21,7000 cars. Since 2016, Chevron has removed 3,400 wells in the state and aims to do another 2,200 over the coming years, part of its effort to make oilfields more green. Companies are also employing electric- instead of diesel-powered rigs, eliminating routine flaring and piping production instead of using heavy trucks. "We've got lower emissions, we have lower ground disturbance. So this is just part of that evolution of what we're doing out here," said Hodge Walker, vice president of Chevron's Rockies Business unit. Critics say these initiatives are "green-washing" that encourage more fossil fuel production that leads to more emissions. Plugging old wells could also become big business for energy and service firms given the sheer number of abandoned wells and $1.15 billion in federal funding being made available to states to seal them. In parts of Ohio, West Virginia, and Pennsylvania, natural gas producer Diversified Energy turned its in-house well-plugging unit into a for-profit business. It also removed some 90 of its own at a cost of about $21,000 each in the first half of 2022. It now aims to cap 200 of its own wells per year. But now, he sees a sizeable business from state and federal monies directed to stopping methane leaks. The operation will have 15 rigs and has already won contracts from West Virginia and Ohio to plug orphaned wells that have no identified owners and can leak methane. Environmentalists say the efforts are overdue. "We learn to clean up our own messes in kindergarten. This isn't something that deserves applause, it should be expected," said Anne Lee Foster, a Colorado environmental activist. She said Colorado taxpayers have spent about $5 million a year since 2018 to subsidize the cleaning up of abandoned wells. On a sunny October day, a Chevron crew in Kersey was mid-way through removing a well drilled in 1992 on 78-year-old Bill Klein's farmland. The well, called the Patriot 16-12, is a vertical well that pre-dates the shale oil revolution where new drilling techniques helped propel the U.S. into a world-leading oil and gas producer. "I've never had any problem with the oil companies," says Klein, who for 57 years has owned land around where Patriot 16-12 operated and has collected royalties from oil and gas drilling. He plans to re-farm the land once the wells are safely plugged. That does not mean the oil industry is walking away from Kersey. Several hundred feet from Chevron's plugging work, PDC Energy Inc. is drilling a new, horizontal well, which can span over 2 miles underground. PDC Energy and Chevron regularly share drilling plans to avoid potential collisions that could provide a way for methane to reach the surface.
Colorado air regulators vastly underestimated ozone pollution from some oil and gas operations due to a data error - Colorado air regulators withdrew large parts of a draft plan to cut ozone pollution Friday, acknowledging that it underestimated emissions coming from some oil and gas drilling and hydraulic fracturing operations. The admission, detailed in a notice sent to state air commissioners, sends regulators back to the drawing board as they attempt to bring Front Range air quality into compliance with federal health standards. It also invites new scrutiny onto the state's oil and gas industry, which the state already recognized as the region's largest source of local ozone ingredients — even before they acknowledged the latest data error. Environmental groups praised the latest decision. After criticizing an initial ozone plan released in June, they now see an opportunity to push for new air quality regulations, including rules to limit fracking operations during the summertime ozone season or requiring cleaner, electric drilling rigs. "They're not trying to cover up their mistakes, but actually owning them and acknowledging some hard decisions need to be made," said Jeremy Nichols, the climate program director for WildEarth Guardians, an environmental advocacy group. Colorado air regulators now plan to rewrite large parts of the state's ozone plan before submitting it to federal regulators next year. Lorena Gonzalez, who leads the climate campaign with Conservation Colorado, said the move is appropriate amid what's become an "ozone crisis" on the Front Range. "Chronically high ozone levels put the public at risk, so it really is time we get this situation figured out," Gonzalez said. The pollutant is a well-studied lung irritant linked to many health problems, including asthma, lower birth weights and premature death. Ground-level ozone usually isn't emitted directly into the atmosphere from tailpipes and smokestacks. It comes from a range of sources — cars, factories, wildfires, oil and gas operations — that emit nitrogen dioxide and hydrocarbons into the air. Those "primary pollutants" react in the atmosphere amid heat and sunlight to produce ozone. On the Front Range, most ozone pollution comes from out-of-state "background" pollution, but local sources are responsible for pushing concentrations above federal health standards. Estimates in the state's latest ozone plan show the oil and gas industry is the largest single source of local ozone ingredients followed by cars and other vehicles. The federal government has demanded the state take immediate action. In September, the U.S. Environmental Protection Agency reclassified a nine-county area stretching from Fort Collins to Castle Rock as a "severe" ozone violator under its 75-parts-per-billion health standard. The agency also maintains a 70-parts-per-billion standard, which it adopted in 2015 to acknowledge growing concern from medical experts about ozone exposure. It named the region a "moderate" violator under the tougher threshold. A plan to bring the region into compliance fell to the Regional Air Quality Council, the lead air quality planning agency for metro Denver. It released a draft of the plan in August before submitting it to the Colorado Air Pollution Control Division.
Groups petition to keep taxpayers from cleaning oil and gas messes – WyoFile - Conservation and taxpayer advocacy groups filed a petition Wednesday asking the Interior Department and U.S. Bureau of Land Management to make good on promises to reform reclamation bonding requirements that help ensure the cleanup of oil and natural gas production facilities. Current minimum federal bond requirements are not nearly enough to cover the actual cost of cleanup to protect human health and the environment, leaving local residents to suffer the consequences and taxpayers to foot the bill, according to the groups. The Inflation Reduction Act includes $4.7 billion to clean up abandoned oil and gas facilities — a gift to the oil and gas industry that should not continue with future development, they say. “Taxpayers should simply not be on the hook for dealing with these messes,” Natural Resources Defense Council Senior Policy Advocate Josh Axelrod said in a prepared statement. The petition filed by NRDC, Western Organization of Resource Councils and Taxpayers for Common Sense asks the federal agencies to “promulgate rules to ensure oil and gas companies — not the public and taxpayers — are the responsible parties to plug and reclaim all federal oil and gas wells,” the groups stated in the petition. “Taxpayers have bailed out the richest industry on Earth with over $4 billion in taxpayer monies allocated to pay for the plugging and reclamation of orphaned and idle oil and gas wells,” Powder River Basin Resource Council former Executive Director Jill Morrison told reporters at a live-streamed press conference Wednesday. “These are wells that have given the industry billions of dollars in profits, and a lot of it from public minerals.” Reforming the program with higher bond amounts and more stringent reclamation standards is especially important in Wyoming, Morrison said, because most oil and gas production in the state takes place on federal lands and minerals. Wyoming is also the largest target for federal onshore oil and gas lease sales, including a pending sale offering up to 251,000 acres — 392 square miles — in 2023. Despite the industry’s legacy of abandoned facilities, full reclamation — on the operator’s own dime — is the industry standard, Petroleum Association of Wyoming Vice President Ryan McConnaughey told WyoFile. Large operators could meet higher bond amounts, he said, but it would add to the cost of production — and it would inhibit the ability of medium- and small-sized companies to operate in Wyoming. “This is another opportunity for groups who don’t want to see oil and gas drilled in Wyoming to add more costs,” McConnaughey said.
Cleanup underway at Tanzanite Park in Sacramento for diesel spill— Crews are working to clean up a diesel spill at a park in the North Natomas area of Sacramento. The spill happened at Tanzanite Park, near Interstate 80 and Interstate 5. The park is shut down during the cleanup. A report from the Office of Emergency Services shows a 10,000-gallon tank had a "malfunction," and the diesel was released onto the concrete loading dock and into a storm drain. "It came from a storage tank up slope, up stream that had a 10,000 gallon capacity," said Ryan Hanson with the Department of Fish and Wildlife. "We don't have the exact number yet but several thousand gallons has been reported to us as missing." The Office of Spill Prevention and Response is leading the cleanup efforts which began at sunrise Tuesday. The spill originated about a mile north of the park at the Centene Corporation on East Commerce Way. The property management company, Hines, said the spill happened on the loading dock and it's working with the state to help clean up the storm drains and lake. In a statement, Hines said, "At this time, a team is working diligently to clear and clean the storm drains on the property and address areas potentially affected by the storm drains. In doing so, we are working closely with the County, the California Department of Fish and Wildlife, and the Office of Emergency Management to resolve these issues. We will provide updates as the work proceeds under proper regulatory oversight.” The source of the leak has been stopped. Wildlife care specialists with the Oiled Wildlife Care Network of Cordelia are on the scene and have already rescued at least two birds that are being treated at the San Francisco Wildlife Care and Education Center. The specialists are walking along the banks and park looking for other birds and wildlife affected by the spill. "It affects their feathers primarily which impacts their ability to thermos regulate so they preen a lot which means they are ingesting oil while they are cleaning their feathers," said Greg McGowan with the wildlife branch of the Office of Spill Prevention and Response. Neighbors said the park is usually filled with gaggle of geese and migratory mallards and other birds. There are also turtles and beavers that live around the lake. "We will continue to do reconnaissance, looking for birds, looking for behavior that is abnormal and other wildlife in the pond," McGowan said. The Office of Health Hazard and Assessment will test water samples to see if there is any danger to the fish in the lake. The Sacramento Fire Department is testing the air quality in the area because the spill happened near a neighborhood. Crews will continue the cleanup Wednesday morning.
Natomas-area park still closed after large diesel spill - CBS Sacramento - A Natomas park is still shut down on Thursday following a diesel spill that polluted a nearby pond. The spill happened at a business about a mile from Tanzanite Park. Neighbors living near the park first reported the oil spill over the weekend, but it wasn't until Monday when the property management company reported the spill to emergency services.The tank containing more than 10,000 gallons of diesel belonged to the Natomas Development Partners on East Commerce Way.According to the incident report, an oil tank malfunction caused the diesel to release onto a concrete loading dock and into the storm drain.The Oiled Wildlife Care Network is on site monitoring wildlife in the area and making sure they don't go into t he pond. Their numbers show that a total of 18 birds have been recovered from the spill, with 3 of those animals having died.
California's climate plan calls for no new gas power plants - California regulators announced initiatives Wednesday to speed up the state’s clean-energy transition by cutting demand for fossil fuels by the end of the decade, including ending the construction of new gas-burning power plants — moves that would help combat climate change but could put the state at higher risk of power blackouts.The proposal, which goes before the California Air Resources Board for a vote next month, lays out how the state could reach its goal of carbon neutrality by 2045, one of the most ambitious timelines in the nation. While it does not have the force of a legal ban on new gas power plants, its approval would make clear to other state agencies, including the California Public Utilities Commission, the state’s current policy.If California follows through on the proposal, planet-warming emissions are expected to fall 85 percent below 1990 levels by 2045. California would also blow past its interim target, which requires that emissions fall by 40 percent by 2030. The new plan anticipates a cut of 48 percent by the end of the decade.“The climate is changing before our eyes. We need to take action to reduce the worst impacts of a changing climate and there is only one way to do that, break forever our dependence on fossil fuels,” said Liane Randolph, chair of the air board. Yet she cautioned that reaching the state’s targets would be a challenge. The plan “calls for a build-out of renewable energy resources at a rate we have never seen before in this state,” she said.Gov. Gavin Newsom praised the proposal. “It’s the most ambitious set of climate goals of any jurisdiction in the world, and if adopted, it’ll spur an economic transformation akin to the industrial revolution,” he said in a statement following the plan’s release.Some environmental advocates were less impressed. Catherine Garoupa White, executive director of the Central Valley Air Quality Coalition, said that while board staff had made changes to the plan in response to pressure from advocates, it remained overly reliant on technological advances to curb emissions and was not as aggressive as she and others had hoped.“It’s important to keep in mind that this document is just a plan, and there is currently no enforcement strategy for ensuring any of these changes happen in the real world,” she said.Though an earlier proposal would have allowed the state to expand its use of gas, regulators said they ultimately struck this part at the urging of climate advocates speaking on behalf of disadvantaged neighborhoods near oil refineries and gas plants.California’s aspirations of transitioning rapidly to clean energy have been frustrated by the continuing threat of rolling blackouts, especially on hot summer nights when air conditioners are buzzing and the state can’t tap power from solar farms. To keep power flowing, the state has added giant new battery systems that can store the extra energy produced by solar panels during the day.
House Republicans prepare big energy package for 2023 - House Republican leaders said Thursday the party is preparing an energy and environment package that could emerge in January as one of the first pieces of major legislation passed by the GOP-controlled chamber. Largely based on legislation already put forward by the top Republican on the Energy and Commerce Committee, Cathy McMorris Rodgers of Washington, and the Natural Resources Committee’s top Republican, Bruce Westerman of Arkansas, the package would seek to unleash domestic fossil fuel production along with critical mineral mining. The package will follow an edict from Minority Leader Kevin McCarthy (R-Calif.), who has indicated on multiple occasions that energy policies to help attain American “energy independence” and lowering energy prices would be among the House’s first priorities. “We need to return to American energy independence and bring down gas prices, and that’s unleashing American energy,” McMorris Rodgers told reporters yesterday. McMorris Rodgers confirmed discussions are underway to fine-tune what the package will contain. She said that the foundation would likely come from the “American Energy Independence From Russia Act,” H.R. 6858, and “Securing America’s Mineral Supply Chains Act,” H.R. 8991. Introduced in the immediate aftermath of the Russian invasion of Ukraine, the first of the bills would offer a host of policies that would undercut Biden administration energy decisions, including a restoration of the approval of the Keystone XL pipeline, directions to offer public lands for fossil fuel production and efforts to streamline liquefied natural gas exports, among other areas. The bill reads as a list of Republican gripes against the alleged slow-walking of fossil fuel project approvals by the Biden administration. Republicans have attempted to press Democrats to back the bill on multiple occasions this year using parliamentary tactics. Each attempt was rebuffed on party lines. The critical mineral portion of the package emerged later this year as Republicans headed into the midterm elections. Republicans said the bill would help unleash hardrock mining to help address a rash of critical minerals supply woes that have helped increase the cost of energy. The bill would look to streamline permit approvals for critical mineral mining and includes provisions that would limit the Biden administration from restricting lease withdrawals and mineral mining on existing federal land grants without an act of Congress.
5 energy, environment issues in bull's-eye for House GOP - Republicans clinched a narrow House majority Wednesday night, and executive agencies are now bracing for a flood of GOP-led oversight inquiries into Biden administration energy and environment decisionmaking. Republican lawmakers have made clear which policies and people they want investigated. For nearly two years, GOP committee chairs have fired off dozens of letters to agencies seeking information. Republicans will now have subpoena power to demand cooperation. “We will devote the resources necessary for this House to go toe-to-toe with the Executive branch, especially as it pertains to oversight and holding the Biden administration accountable for its mismanagement of our country,” Republican leader Kevin McCarthy (R-Calif.) said in a Dear Colleague letter last week announcing his bid for speaker of the House. Over the summer, GOP lawmakers on both the Natural Resources and Energy & Commerce committees offered a preview of their 2023 efforts. Using a procedural tactic known as a “resolution of inquiry,” they forced failed votes on Republican-led efforts seeking documents and communications on a host of administration actions. Those actions included domestic fossil fuel production, public lands leasing, energy reliability and energy costs, among other areas. Republicans have hammered Democrats on gasoline prices over the past year and during campaign season. Their main argument: The Biden administration is actively undercutting domestic oil and gas production. They have criticized the cancellation of the Keystone XL pipeline, the pace of permitting for new oil and gas leases on federal lands, and the formation of the new five-year offshore leasing program. Thus far, Republicans have been met with indifference from the administration. They’re looking to change that. “We’ve sent a lot of letters over to the administration that have gone unanswered,” House Natural Resources ranking member Bruce Westerman (R-Ark.) said earlier this summer. Oversight Committee Republicans released their own report last week, in which they allege the Biden administration has not done enough to support the development of domestic oil and gas. “Democrats have weaponized their unchecked power to wage a war against American-made energy production and push radical, far-left Green New Deal policies that jeopardize Americans’ ability to power their homes,” ranking member James Comer (R-Ky.) said in a statement. In the lead-up to the election, Republicans have criticized the administration’s depletion of the Strategic Petroleum Reserve to bolster global supplies, arguing that the move to lower prices has endangered national security (Energywire, Oct. 24). Energy and Commerce Subcommittee on Oversight ranking member Morgan Griffith (R-Va.) indicated his subcommittee was unlikely to focus much on the producer side of the equation as Democrats have for much of 2022. Instead, he says he wants to investigate what he sees as an overemphasis on renewable energy research and development at the Department of Energy at the expense of fossil fuels.
Significant back-to-back earthquakes in northern B.C. 'very likely' caused by fracking: federal expert - Two significant earthquakes within a week in northeast B.C. were probably triggered by hydraulic fracturing, or fracking, according to preliminary information from federal scientists. On Nov. 11, Earthquakes Canada reported a 4.7-magnitude earthquake, 132 kilometres northwest of Fort St. John. That was followed four days later by a 4.6-magnitude quake recorded just a kilometre away from the first seismic event. "There is an active hydraulic fracturing operation nearby," said Prof. Honn Kao, a research scientist with the Geological Survey of Canada. "The likelihood of these two events being induced by industry is very high." Earthquakes Canada said while the tremors were "lightly felt in the surrounding area," there were no reports of damage. Fracking involves injecting fluids into a deep well under high pressure to fracture tight rock formations and release the natural gas inside. According to the B.C. Oil and Gas Commission (BCOGC), the province's energy regulator, fracking in B.C. takes place deeper underground than it does in other areas of the world — sometimes more than four kilometres beneath the surface. In an email to CBC News, the BCOGC said all drilling in the Montney formation near Fort St John B.C., "has or will eventually involve hydraulic fracturing operations." According to information on the BCOGC's website, "microseismic events" occur when fluid fractures the rock. "In some cases, where there is a susceptible pre-existing fault, slippage on the fault plane can occur," it says.
EPA orders troubled St. Croix refinery to obtain new permit - The Washington Post The Environmental Protection Agency said Thursday it will require an idled refinery in the U.S. Virgin Islands that rained oil onto nearby homes to obtain a new air pollution permit before restarting operations. The move, which comes after EPA inspectors found the plant could release “extremely hazardous substances” affecting disadvantaged residents in St. Croix, escalates the agency’s crackdown on the plant and could establish a precedent for how the Biden administration treatscommunities suffering from high pollution levels.“EPA has been laser-focused on protecting public health and the safety of communities who have unjustly borne the burden of pollution,” EPA Administrator Michael Regan said on a call with reporters. “We’ve made environmental justice and equity a centerpiece of our agenda and have embedded these issues into EPA’s DNA.” The refinery’s owners must apply for a permit under the Clean Air Act that would require them to conduct detailed air-quality analyses, the agency said in a statement, and use the best available technology for air pollution control. The move would probably result in “significant reductions” of several harmful pollutants, including sulfur dioxide, carbon monoxide and particulate matter, the agency said. The idled plant in St. Croix, formerly known as the Limetree Bay refinery, experienced multiple accidents over the course of last year that spewed noxious fumes and showered oil droplets onto surrounding homes, sending some residents to emergency rooms. In September, the EPA inspected the refinery and found “significant corrosion” of equipment including valves, pipes and pressure relief devices. Inspectors concluded that the plant poses the risk of a fire, explosion or other “catastrophic” releases of “extremely hazardous substances,” the agency said in a report released last month. A refinery rained oil on thousands of St. Croix homes. Now it could reopen. Local residents have questioned why federal officials have not done more to protect the health and safety of this Caribbean island’s predominantly Black and Brown population. “Since 2019, St. Croix Foundation and our nonprofit partners have been on a lonely advocacy journey trying to compel policymakers to consider alternatives to this ‘ticking time bomb’ on our shores — to no avail,” Deanna James, president of the St. Croix Foundation for Community Development, said in an email last month.
Gulf of Mexico an Area of Increasing Instability -The Gulf of Mexico continues to be an area of increasing instability, according to Dryad Global, which made the statement in its latest Maritime Security Threat Advisory (MSTA). In the MSTA, Dryad revealed that reporting had indicated that an OSV had been boarded and robbed offshore Campeche. Reporting had also indicated that a spate of three incidents involving attacks on fishing vessels had occurred in the Gulf of Mexico, “resulting in the theft of outboard motors and other properties”, Dryad highlighted in the MSTA. Dryad’s latest MSTA rates Mexico’s risk rating as “substantial” and the country’s Dos Bocas port terminal risk rating as “moderate”. These risk ratings were identical in Dryad Global’s previous MSTA, which was released last week. Countries with the highest risk rating in the latest MSTA include Ukraine, Yemen, and Syria. At the time of writing, a U.S. State Department map warns travelers to exercise increased caution at every Mexican state bordering the Gulf of Mexico, except Taumalipas, which has a do not travel warning, and Yucatan and Campeche, which have an “exercise normal precautions” advisory. Back in September, Dryad’s Global Chief Executive Officer, Corey Ranslem, revealed to Rigzone that the most dangerous offshore region for oil and gas, in terms of rig work, was the Bay of Campeche in the Gulf of Mexico. “We have seen the number and types of attacks increase over the past year along with the level of violence. Assailants are now armed and are increasing the number of attacks against oil rigs in this region,” Ranslem told Rigzone. A Dryad MSTA released in August outlined that the Gulf of Mexico was in the midst of a pirate problem. “There has been an increase in the cadence of incidents in the Gulf of Mexico,” the MSTA stated at the time. “Since 22 May 2022, there have been six maritime events just within the Bay of Campeche. Three supply vessels have been attacked, and three oil platforms,” the MSTA added.
Climate emergency council faces environmental pressure before fracking decision is made - A Conservative-led council which declared a climate emergency this summer has faced intense pressure from opposition councillors to reconsider how its environmental actions are managed before postponing a decision on whether fracking is appropriate in the area. A full meeting of North Yorkshire County Council saw a North Yorkshire Climate Coalition, which includes 18 environmental groups based from Selby to Stokesley, calling on the authority to move “further and faster” over environmental issues, and drop party politics to introduce measures more rapidly. The coalition pressed the council to address the twin climate and ecological emergencies and to harness “huge economic opportunities” during a transition to a cleaner, greener economy. The meeting was told that the authority’s leader, Councillor Carl Les, had this week called for people to support the Yorkshire and Humber Climate Change Commission move to declare an ecological emergency, before his Conservative group voted to stop the creation of a biodiversity crisis working group at the council. Councillor Greg White, executive member for climate change and customer engagement, said the authority did not want to judged on what it said, but rather its actions, and that its plan for cutting carbon was “bold”. Coun White added while the council was working to introduce carbon-cutting measures it also needed to focus on its main purpose, which was to provide much-needed services. Nevertheless, opposition councillors insisted more action and a greater focus was needed. The administration then faced numerous questions from opposition members over its environmental actions, ranging from public transport to buying zero carbon electricity, and from installing air source heat pumps to offloading pension fund investments in fossil fuels.
Tories under pressure to make fracking ban ‘U-turn proof’ -Conservative MPs are being urged to formally pledge that they will never vote for fracking, following months of uncertainty in which successive Tory administrations have flip-flopped over going ahead with drilling operations across the country. The Liberal Democrats have secured a debate in Westminster Hall on Tuesday opposing any fracking in England without the support of local communities. The move is intended to make the current moratorium on fracking, recently reinstated by Rishi Sunak, "U-turn proof". The Conservatives backed a "fracking revolution" in their 2017 manifesto – the only party to support the practice – when Theresa May was prime minister, but amid national outcry, this was dropped in 2019 under Boris Johnson. When Liz Truss and Mr Sunak campaigned against one another to succeed Mr Johnson as prime minister earlier this year they both said they would U-turn on the manifesto pledge and support fracking if local communities supported it. Following her victory over Mr Sunak, Ms Truss’s energy secretary Jacob Rees-Mogg lifted the ban on fracking and reportedly began examining ways to reduce environmental and public scrutiny of such drilling projects. The row escalated after the Labour Party tabled a vote on whether to outlaw fracking, and Ms Truss ordered MPs to vote with her administration on the fraught issue, effectively telling her MPs to vote against a key 2019 manifesto pledge. Amid farcical scenes in the House of Commons, a Tory revolt ultimately brought down the curtain on Ms Truss’s disastrous premiership. In total, 326 Conservative MPs voted against a ban, defeating Labour’s motion, but many had felt compelled to vote along party lines, despite their stated opposition to fracking. After Ms Truss’s record-short stint as prime minister, Mr Sunak then U-turned again, to reinstate the 2019 moratorium. Liberal Democrat Levelling Up spokesperson Helen Morgan, who secured Tuesday’s debate, told The Independent: “Conservative MPs have lurched to different positions on fracking from month to month. Who knows what they will do next?
North Sea Can Fuel UK For 30 Years, But More Investment Is Needed - The waters off the coast of the UK still contain oil and gas reserves equivalent to 15 billion barrels of oil equivalent, enough to fuel the UK for 30 years, but more investment in exploration is needed to slow down the decline in production. OEUK said that just four exploration wells had been drilled this year compared to 16 in 2019, the most recent pre-pandemic year comparison. The Exploration Insight report published by Offshore Energies UK shows how the offshore energy industry is balancing the UK’s continuing demand for energy while supporting the transition to a low-carbon energy economy through its commitment to deliver net zero emissions by 2050. The Insight report assesses oil and gas exploration over the past ten years, explores the potential for future developments, and considers how the 33rd offshore licensing round will impact exploration while reflecting on opportunities for the expanding sector to support the UK’s climate goals through the development of critical carbon capture and storage facilities. “Our new report shows why ongoing exploration in our waters is critical to ensuring reliable supplies of domestically produced energy which also adds value to the UK economy. The UK Continental Shelf is a mature basin, with North Sea oil and gas production peaking in 2000 so careful management of the remaining resources is vital to avoid rapidly increasing reliance on imports. Supporting this industry and its exploration activities is essential to the UK delivering a homegrown transition to cleaner energies, retaining the benefits in taxes paid, jobs supported, and our wider economic contribution,” Mark Wilson, OEUK’s HSE and Operations Director, said. However, the ongoing uncertainty and continuous changes to the fiscal regime will drive investment out of the UK and encourage some companies to leave the basin. In such conditions, companies are unable to plan the future long-term investments we need to support energy security and our net-zero commitments. “Low levels of exploration mean on a ten-year average; we are replacing only 10 percent of the reserves we need to sustain the production levels that can help to keep the UK energy secure and power its energy transition. We need to ensure that the UK government’s British Energy Security Strategy made clear the need to support the production of North Sea oil and gas, alongside the deployment of offshore wind, solar, and hydrogen, which continues to be the focus of the new Prime Minister and his government. It was good to see the importance of oil and gas to the transition to a low carbon economy and energy security recognized with the launch of the 33rd licensing round following the completion of the new climate compatibility checkpoint.” “Our new report shows why ongoing exploration in our waters is critical to ensuring reliable supplies of domestically produced energy which also adds value to the UK economy. The UK Continental Shelf is a mature basin, with North Sea oil and gas production peaking in 2000 so careful management of the remaining resources is vital to avoid rapidly increasing reliance on imports. Supporting this industry and its exploration activities is essential to the UK delivering a homegrown transition to cleaner energies, retaining the benefits in taxes paid, jobs supported, and our wider economic contribution,” Wilson added
Diesel Price Sees Third Biggest Monthly Increase on Record -UK motoring services company RAC has revealed that the average price of diesel saw its third biggest monthly increase on record in October. The average price of the commodity rose from 180.37pence ($2.15) to 190.51p ($2.27), RAC highlighted, adding that the rise added more than GBP 5 ($5.96) to a tank. The rise ranked third behind an increase of 22p ($0.26) in March this year and an increase of 16p ($0.19) in June this year, RAC outlined. “After three months of falling pump prices October was a severe shock to the system for drivers with the unwelcome return of some scary numbers on forecourt totems,” RAC fuel spokesman Simon Williams said in a company statement. “Those with diesel vehicles suffered most with 10p ($0.12) being added to the cost of a liter in what was the third worst monthly increase on record, but petrol car drivers also saw a 4p-a-litre ($0.05) increase across the country,” Williams added. The RAC spokesman noted that OPEC+’s decision to cut supply by two million barrels a day had “cost drivers dear” and said “the fear now, particularly for diesel drivers, is whether the average price of a liter is heading back to that record of 199.09p ($2.37) which made a full tank cost more than GBP 109 ($129.97)”. According to RAC’s fuel watch tool, the latest UK average diesel price is 188.72p ($2.25) per liter. This price “should fall sharply”, however, according to the tool, which was last updated on November 15. A chart posted on RAC’s website, which includes data spanning back to January 2013, shows that the average UK diesel pump price, including VAT, rose sharply from February to July this year, before dropping from July to October then rising again to November. The lowest recorded average price, according to the chart, was seen in February 2016 at 100.19p ($1.19).
IEA Says Diesel Demand Destruction Starting to Look Inevitable - Unprecedented diesel prices mean that demand destruction for the fuel is probable, the International Energy Agency said. Both the outright price of the fuel and its trading level relative to crude oil rose to records in October, jumping 70% and 425% respectively year-on-year, the Paris-based adviser said in its monthly report on the state of the oil market. With economic growth showing signs of weakening in the face of high inflation and energy costs, those high prices could well prove self-defeating, the agency said. “This increasingly ominous global outlook, along with very high prices, is set to significantly curtail diesel demand in 2023,” the IEA said. The IEA forecast that global growth in diesel and gasoil will ease from 1.5 million barrels a day in 2021, to 400,000 in this year. In 2023, consumption will post a small decline “under the weight of persistently high prices, a slowing economy and despite increased gas-to-oil switching.” Even before Russia invaded Ukraine, diesel markets were in deficit because of a combination of halted refineries during Covid and then resurgent demand as countries dealt with the pandemic, the adviser to oil consuming nations said. The war has led to the European Union announcing a ban on the purchase of Russian diesel that enters into force in February but is already an intense focal point for the market. Russia remains the continent’s biggest external supplier and Europe is likewise the top buyer from Moscow, creating uncertainty how global flows will be affected once the prohibition begins. “The competition for non-Russian diesel barrels will be fierce, with EU countries having to bid cargoes from the US, Middle East and India away from their traditional buyers,” the IEA said. “Increased refinery capacity will eventually help ease diesel tensions. However, until then, if prices go too high, further demand destruction may be inevitable for the market imbalances to clear.”
EUROPE GAS-Prices mixed on colder weather outlook, strong LNG flows - British and Dutch wholesale prompt gas prices were mixed on Monday with strong demand due to outages and colder weather partly offset by high liquefied natural gas (LNG) supply. The Dutch day-ahead contract rose by 31 euros to 99.75 euros per megawatt hour (MWh) by 1013 GMT, while the December contract was up 7.7 euros at 106.5 euros/MWh, according to Refinitiv Eikon data. “The way is up for today with all the planned and unplanned outages, consumption is higher and its getting colder,” a European gas trader said. Equinor’s Aasgard B oil and gas processing platform was shut and partly evacuated late Sunday following a fire in a transformer, causing a production outage. The shutdown resulted in an outage of gas production amounting to 19.8 million cubic metres (mcm) per day with “uncertain duration and capacity consequence”, Aasgard’s pipeline operator Gassco said in a regulatory filing. Norwegian gas nominations to Europe dropped to 304 mcm on Monday from 312 mcm the previous day. In the British gas market the day-ahead contract was down 22 pence at 77 pence per therm. In Britain, peak wind generation is forecast at 8.13 gigawatts (GW) on Monday but will rise to almost 16 (GW) on Tuesday, Elexon data showed. Strong wind power output curbs demand from gas-fired power plants. Maintenance at the Interconnector UK pipeline connecting Britain with Belgium from Tuesday also reduces Britain’s ability to pump any excess gas to the continent. The British December gas contract was up 9.5 p at 238 p/therm, Refinitiv Eikon data showed. An adjustment to the weather forecast towards colder temperatures well below seasonal norms by the end week is also supporting the uptrend. However, LNG cargoes to north-west Europe, particularly Britain, remain strong, putting some pressure on prices. In the European carbon market, the benchmark contract CFI2Zc1 was down 0.62 euro at 75.22 euros a tonne.
Germany inaugurates first new LNG terminal - The German government inaugurated its first floating terminal on Tuesday (15 November), built in record time and intended to receive liquefied natural gas as part of Berlin’s plan to replace Russian gas, with the first regasification ship set to dock in mid-December. Following Russia’s attack on Ukraine, a halt in the supply of gas from Gazprom, and the subsequent destruction of the Nord Stream 1 pipeline, Germany is missing about 50 billion cubic meters (bcm) of gas in yearly deliveries. Hastily constructed infrastructure to facilitate the import of LNG is Berlin’s way out. LNG is supercooled and highly pressurised gas, turned into a liquid state fit for long-haul transport. Turning it back into gas requires specialised equipment – so-called regasification units. On Tuesday, Olaf Lies, the economy minister of the German state of Lower Saxony, toured the port of Wilhelmshaven. After six months, construction of the infrastructure to support an inbound floating LNG terminal (FSRU) – a pier, pipelines, and electricity lines – was completed. “Germany is looking to Wilhelmshaven today. The new LNG terminal is a big step towards a secure energy supply,” highlighted Lies, noting the early decision to focus on Wilhelmshaven and existing port infrastructure as the key drivers of speed, thanking “all planners, experts and construction companies involved.” The completion in 194 days represented an unprecedented pace of construction in Germany, made possible by permitting exceptions and forgoing environmental impact assessments. These FSRUs are essentially LNG tankers that can regasify LNG instead of merely transporting it. In mid-December, the ship Hoegh Esperanza, built in 2018, is set to arrive. It was previously on three-year deployment in the Chinese port of Tianjin. A subsequent deployment in Australia had been cancelled on grounds of environmental concerns. The FSRU, which is more than 280 metres long and 46 metres wide, can regasify a minimum of 5 bcm of LNG annually, with a maximum capacity of 7.5 bcm. It will feed the gas into the German gas grid through a pipeline with an annual capacity of 10 bcm. A second FSRU is expected in late December, followed by another three next year. In total, the German government hopes to replace 50 to 60% of Russian gas through LNG in 2023. Environmental groups, who were largely left out of the construction process, have voiced concerns about pollution. Uniper, the ailing gas giant and operator of the infrastructure, is expected to clean its facilities using Chlorine, which will then be vented into the sea. “A creeping chemical accident looms in Wilhelmshaven and at the other LNG sites,” explained Sascha Müller-Kraenner, CEO of Environmental Action Germany (DUH). “According to the application documents, Uniper wants to discharge ten times as much biocide into the North Sea with its LNG terminal vessel as … was previously deemed acceptable at a comparable location,” he added. They are in part backed by the new government in Lower Saxony, where the Greens are the junior partner and in charge of the environment ministry.
Mozambique ships gas to Europe for first time -Mozambique has started exporting Liquefied Natural Gas (LNG) for the first time, in a move the country’s President Filipe Nyusi has described as historic. The gas has been produced at an off-shore plant run by Italian energy firm Eni, but British oil giant BP has the purchasing rights over it. The gas left in a British cargo ship for Europe, but its final destination is unclear. The shipment comes at a time when Europe is looking for alternative sources of gas, as it tries to reduce its reliance on Russia. Mozambique hopes to become one of the world's biggest exporters of natural gas, following its discovery in the northern Cabo Delgado province in 2010. But its efforts have been hampered by a five-year-long Islamist insurgency that has killed more than 4,000 people and left hundreds of thousands homeless in the province. The Government believes the discovery of gas will boost the economy, but President Nyusi said Mozambique would continue to focus on "traditional activities", such as agriculture, fishing, tourism, to achieve development.
Eni Ships First LNG Shipment From Coral FLNG -The first shipment of liquefied natural gas (LNG) produced from the Coral gas field in the ultra-deep waters of the Rovuma Basin has just departed from Coral Sul Floating Liquefied Natural Gas (FLNG) facility. Italian oil and gas major Eni, the delegated operator of the Coral South project on behalf of its Area 4 Partners, said that Coral South was a landmark project for the industry and firmly placed Mozambique on the global LNG stage. The project, sanctioned in 2017, comes on stream after just 5 years, in line with the initial budget and schedule, despite the disruptions caused by the Covid pandemic. According to the company, this result was made possible thanks to Eni’s distinctive phased and parallelized approach, very effective execution planning, strong commitment by all partners, and the unwavering support of the Government of Mozambique. Coral Sul FLNG has a gas liquefaction capacity of 3.4 million tons per year and will produce LNG from the 450 billion cubic meters of gas of the Coral reservoir. “The first shipment of LNG from Coral South project, and from Mozambique, is a new and significant step forward in Eni’s strategy to leverage gas as a source that can contribute in a significant way to Europe’s energy security, also through the increasing diversification of supplies, while also supporting a just and sustainable transition. We will continue to work with our partners to ensure timely valorization of Mozambique’s vast gas resources,” Eni CEO Claudio Descalzi said. As for Area 4, it is operated by Mozambique Rovuma Venture, an incorporated joint venture owned by Eni, ExxonMobil, and CNPC, which holds a 70 percent interest in Area 4 exploration and production concession contract. In addition to the joint venture, the other shareholders in Area 4 are Galp, KOGAS, and ENH, each with a 10 percent participation interest. Eni is the Delegated Operator for the Coral South project and all Upstream activities in Area 4.
Eni Starts Up Production From Oil Field Onshore Algeria - Italian oil company Eni announces the start-up of the HDLE/HDLS oil field, in Zemlet el Arbi concession in the Berkine North Basin, onshore Algeria, only six months after its discovery in March. Eni said that the HDLE/HDLS field was currently producing 10,000 barrels of oil per day (bod). Production ramp-up will be achieved through an accelerated development plan which envisages the drilling of new wells in 2023. This achievement, reached in partnership with Sonatrach and in cooperation with the local authorities, was made possible by Eni’s distinctive upstream business model, based on the parallelization of project activities. HDLE/HDLS fast track development, in addition to the recent Berkine South start-up, will contribute towards exceeding 120,000 boed of equity production in Algeria in 2023, strengthening the role of Eni as the main international energy company operating in the country.
Slovenia to sign three-year gas contract with Algeria’s Sonatrach - Slovenia’s gas supplier Geoplin will sign a natural gas supply contract with Algeria’s state-owned energy company Sonatrach on Tuesday, the Slovenian Press Agency (STA) reported. The three-year contract includes the purchase of about 300 million cubic metres of natural gas per year, which is about a third of Slovenia's current annual consumption, STA said. The Algerian gas will be transported to Slovenia via a pipeline running through Tunisia and Italy. Europe is in the midst of its worst energy crisis after Russia, the region’s biggest natural gas supplier, curtailed exports sharply in response to EU sanctions over its military offensive in Ukraine. Russia supplies most of Slovenia’s natural gas, which accounts for 12 per cent of overall energy mix. The EU member state relies mostly on hydroelectric, thermal and nuclear power sources to meet its electricity requirements. In 2018, Geoplin signed a five-year natural gas supply contract with Gazprom to import 600 mcm of Russian natural gas per year. However, Russia’s invasion of Ukraine has forced Slovenia to reconsider its energy policy and seek alternate sources such as liquefied natural gas (LNG). Algeria, a member of Opec, relies heavily on oil and gas, which accounted for 19 per cent of GDP, 93 per cent of product exports, and 38 per cent of budget revenue between 2016 and 2021, the World Bank said. Algeria is Africa's biggest gas exporter and supplies about 11 per cent of the natural gas consumed in Europe.
Military Drills in Gas-Rich Algeria Put Focus on Russian Ties -Algeria and Russia began their first joint military exercises on Algerian soil amid Western concerns over Moscow’s deepening ties with the North African nation that’s a key energy supplier for Europe. The Desert Shield anti-terrorism training began Wednesday in the sparsely-populated Bechar province, near Algeria’s border with long-time rival Morocco, the Russian state news service Sputnik reported. An OPEC member on the Mediterranean, Algeria has been thrust into the limelight of international diplomacy this year as Russia’s invasion of Ukraine sends Europe scouring the region for replacement natural gas and oil. French, Spanish and Italian leaders have visited Algiers several times this year to secure or boost shipments. But as Algeria bolsters its links with Europe it’s also intensifying cooperation with Russia. About 80 soldiers from each country are participating in the drills that’ll last until Nov. 28. It follows similar training in Russia last year, and come a month after joint naval maneuvers in the Mediterranean. Algeria sells the vast bulk of its oil and gas to Europe and before the war was its biggest supplier after Russia and Norway. At the same time, Russia is Algeria’s biggest arms supplier, with defense ties that go back to the era of the Soviet Union. The Arab nation gets close to 80% of its weapons imports from Russia and is the third-biggest buyer of such arms after India and China, according to the Moscow-based Centre for Analysis of Strategies and Technologies, which conducts research on the defense industry. Algeria is considering signing a new long-term arms deal with Russia worth as much as $17 billion for the purchase of submarines, Su-57 stealth fighters and other warplanes and advanced air-defense systems including the S-400, Russian state channel RT reported Oct. 31. Russian Arms The 10-year contract may be finalized during a visit to Moscow in December by Algerian President Abdelmadjid Tebboune, it said, citing Africa Intelligence, a newsletter published from Paris. The current tensions “are only pushing us closer together,” said Elena Suponina, a Moscow-based Middle East expert, referring to Algeria and Russia. “Algeria is refusing to adopt an anti-Russian stance.” The US and Morocco earlier this year staged part of their regular African Lion military drills close to the Algerian border. Aligning itself with countries such as Cuba and China, Algeria abstained twice this year from voting on UN resolutions condemning the war in Ukraine and the annexation of parts of its territory. In turn, Russia has opted for a neutral stance regarding the dispute over Western Sahara -- a former Spanish colony that Morocco claims in a stand off with the Algeria-supported Polisario Front. Republican Senator Marco Rubio and a bi-partisan group of US lawmakers in September urged the Biden administration to impose sanctions against Algeria over the Russian arms purchases. Russia says the military exercises with Algeria are “routine” and are “not aimed against any third country,” according to a Foreign Ministry statement in September. S
Poland Takes Control of Gazprom's Local Gas Pipeline Assets -
- State to manage Russian company’s stake in section of Yamal
- Gazprom held 48% of company that owns Polish stretch of link
Poland introduced compulsory administration over Gazprom PJSC’s stake in the company that owns the local part of the Yamal-Europe gas pipeline, tightening the government’s grip over Russian assets in the country. The Development Ministry is taking over the Russian exporter’s share in EuRoPol Gaz SA, it said on the website. Gazprom held 48% of the firm, with Polish state companies owning the remainder. The “temporary” measure was necessary to facilitate decision-making at the company, according to the ministry.
Nigeria To Build Its First-Ever Floating LNG Unit -UTM Floating LNG Limited, JGC, Technip Energies, and KBR have signed a Front-End Engineering Design (FEED) contract for the development of Nigeria’s first FLNG facility. With the signed contract, the development of the FLNG facility in block OML 204 offshore Nigeria will kick off. According to Chief Timipre Sylva, the Nigerian Minister of Petroleum Resources, with factors such as a lack of investment, transportation and export infrastructure, and technological challenges disrupting Nigeria from maximizing its gas industry, the FLNG project is a step forward in the right direction for the west African country to develop, exploit and monetize its over 209 trillion cubic feet of proven gas resources and a potential upside of 600 tcf of gas. “Given the large resources that may be developed and used for commercial purposes, we have already proclaimed that gas is our transition fuel and a destination fuel, and we anticipate that it will be a major component of our energy mix by the year 2060. As a developing nation, we believe that affordable, accessible, and reliable energy will continue to be essential to sustaining and powering our growing economy and lifting millions out of poverty. As a government, we know our action is essential to enable the evolution of the energy system. We believe innovation, technology, and policy will be the key drivers of change” “We are aware that the number of offshore gas finds has surged in recent years around the world, with LNG and FLNG becoming even more important in terms of satisfying the world's future energy needs. According to market research analysts, the FLNG market is estimated to increase at a compound annual growth rate of 27.14%, reaching $88.99 billion by 2024. The UTM offshore FLNG project is therefore timely and will lead towards a faster-moving, more diverse, and more flexible global LNG industry,” Sylva said. The minister also highlighted the importance of collaborative partnership, commending the “African Export-Import Bank, under the leadership of its President and Chairman, Benedict Okey Oramah, for orchestrating the signing of the Memorandum of Understanding with UTM Offshore to raise $5 billion for the development of Nigeria’s first FLNG project.”
Petronas Confirms Fire at Gas Pipeline -Petronas has confirmed that a “fire incident” occurred at the Sabah-Sarawak Gas Pipeline (SSGP) near KP 132, nearby Lawas, Sarawak, on Wednesday afternoon. The incident is believed to have involved a third-party contractor performing work unrelated to SSGP operations nearby the pipeline’s Right-of-Way (ROW) area, Petronas said in a company statement. Petronas noted that a police report had been lodged with regard to the incident and stated that an investigation will commence “in earnest”. “Petronas’ emergency response team has been mobilized to the area,” Petronas said. “The company will work closely with all the relevant authorities to take the necessary action and preventive measures to contain the situation and safeguard the safety of the surrounding community and environment,” Petronas added. Last month, Petronas revealed that it had declared force majeure on gas supply to MLNG Dua due to a pipeline leak caused by soil movement at the vicinity of KP201, SSGP, which the company said occurred on September 21. Petronas noted at the time that it was conducting a comprehensive evaluation of the SSGP to ensure the integrity and safety of the pipeline. The SSGP is a 318 mile, 36-inch pipeline with a capacity of 750 million cubic feet per day, which links the gas fields in Sabah to the MLNG export complex at Bintulu, global energy research company Wood Mackenzie highlights on its website. Petronas describes its LNG complex at Bintulu as the “bedrock” of its operations and “one of the world’s largest LNG facilities in a single location”. To date, Petronas has delivered over 12,000 LNG cargoes across the world from its portfolio of global LNG assets, according to the company’s website. Petronas describes itself as Malaysia’s fully integrated energy provider. The company is involved in a variety of energy related activities, including exploration, production, refining, chemicals, marketing and trading.
Pakistan ‘Has No Option But To Ration’ Natural Gas Supply This Winter - Pakistan has no other option but to ration natural gas supply this winter, with gas provided three times a day for cooking to households, amid acute shortages and a forex crisis in the world’s fifth most populous country, an official from the petroleum ministry told a Parliament panel this week. The energy crisis in Pakistan has deepened this year, and now, natural gas supplies will be very limited for households, according to officials.“There would be no gas supply (to household consumers) for 16 hours” a day, Muhammad Mahmood told the Parliament’s Standing Committee on Petroleum, as carried by the local outlet Dawn. Pakistani households will have gas available for three hours in the morning, two hours in the afternoon, and three hours in the evening, Mahmood added.Pakistan—whose population is the fifth largest in the world after China, India, the United States, and Indonesia—has been experiencing an energy crisis as the country cannot afford to import a lot of energy products at the current high prices. The stronger U.S. dollar and the sky-high LNG prices have worsened the country’s finances, with foreign exchange reserves down in October to their lowest level in three years.In April, soaring prices of LNG and coal on the international markets left Pakistan with having to cut electricity supply to households and industry as the country, in a deep political and economic crisis, could not afford to buy more of the expensive fossil fuels.This year, Europe has been outbidding Asian customers for LNG supply as it has scrambled to secure gas supply with very low pipeline imports from Russia. High spot rates for LNG have discouraged many buyers and users of the super-chilled fuel in Asia, including in India, Pakistan, and Bangladesh. Meanwhile, industry customers across South Asia have turned to fuel oil because of the high prices of natural gas. In Pakistan, oil-fired power generation has surged five-fold this year,
Trump's former Treasury secretary calls Russian oil price cap ‘most ridiculous idea I’ve ever heard’ - Former U.S. Treasury Secretary Steve Mnuchin described the G-7's plan for a price cap on Russian oil as "ridiculous."Speaking to CNBC's Hadley Gamble during a panel at the Milken Institute's Middle East and Africa Summit, Mnuchin said the idea was "not only not feasible, I think it's the most ridiculous idea I've ever heard."He added that while there were no certainties, sanctions on Russia and Russian officials — which the U.S. and other nations have continued to roll out since Russia's unprovoked invasion of Ukraine — could have had an impact before the war started rather than after."Sanctions would have had a big impact back then. I think the problem now is that there's limited options ... there's parts of the world that are now buying Russian oil outside of U.S. sanctions," he said."But look, a price cap, the market is going to set the price. So if you put sanctions on at higher prices, in a way you're just making the situation worse, in my opinion."The Group of Seven nations — the U.S., Canada, France, Germany, Italy, Japan and the U.K. — along with Australia, have reportedly agreed to set a fixed price cap on Russian oil from Dec. 5, but the level has not been announced.The plan, which has been under discussion for several months, involves a ban on the provision of certain services, such as maritime routes, insurance and financing, to buyers of Russian oil unless it is sold at or below the cap.It is intended to limit the Kremlin's ability to fund the war in Ukraine while also protecting consumers and households from sky-high energy prices. New sanctions are also due in early December that will end all Russian crude oil deliveries to the EU by sea, ahead of a ban on all Russian refined products in 2023.As Europe seeks to wean itself off Russian oil and gas, Moscow has ramped up its sale of oil to countries including China and India.Energy analysts sayit will be vital to get those countries' cooperation for any price cap to be effective, but it remains unclear how they will react to any final announcement.Current U.S. Treasury Secretary Janet Yellen said last week India would still be able to buy oil from Russia at any price so long as it avoided the Western sanctions, and that this scenario would still dampen global oil prices and curb Russian oil revenues.Mnuchin served for the full term of President Donald Trump and now works in private equity investing.At the Milken Institute panel, he said getting Russian President Vladimir Putin and Ukrainian President Volodymyr Zelenskyy to the negotiating table was "long overdue" and that a best-case scenario in the near term may be a pause in fighting.Ukraine has previously said it will only enter talks following the "restoration of Ukraine's territorial integrity."
IEA Sees Russia Oil Output Nosediving - Russia may struggle to find new markets for its oil once a European import ban kicks in, potentially pushing the nation’s average output below 10 million barrels a day next year, according to the International Energy Agency. Russia has redirected more than a million barrels a day to India, China and Turkey since many of its traditional customers fell away following the invasion of Ukraine, the agency said Tuesday. Yet flows to those countries have steadied recently, raising speculation they may not be able to ramp up imports further. Should their purchases remain stable, the rest of the world would need to triple Russian imports to around 3.3 million barrels a day by February, the IEA said in a report. “We do not think this is feasible,” it said, predicting Russia may lose close to 2 million barrels a day of output by the end of March, compared with prewar levels, and pump an average of just 9.6 million barrels a day next year. Russia’s production in January through October averaged about 10.7 million barrels a day, according to Bloomberg calculations based on media reports and data from the Energy Ministry’s CDU-TEK unit. The European Union is set to ban imports of most Russian crude on Dec. 5 and refined products from Feb. 5. The move will not only create production risks for Russia, but exacerbate a supply headache for the region as alternative fuel sources may not be enough to fill the gap. The bloc will also prohibit EU-flagged tankers from shipping Russian cargoes and ban the provision of maritime services, including insurance, to third-party vessels involved in the trade. That may further hamper the redirection of Russian crude flows away from Europe. Buyers and sellers of the barrels are set to expand their use of “shadow trade, including high-sea transshipments using ‘dark’ tankers,” the IEA said. Based on October data, the Kremlin will need to find new markets for roughly 1.5 million barrels a day of crude and 1 million barrels of oil products, according to the IEA.
Russia allows Japan to keep stake in Sakhalin-1 oil and gas project -The Russian government has decided to allow Japan to maintain its stake in the Sakhalin-1 oil and gas development project in Russia’s Far East, the Japanese government said Tuesday. “The decision is very significant for stable energy supplies to our country over the medium to long term,” Chief Cabinet Secretary Hirokazu Matsuno told reporters.
Azerbaijan Exports 21.9M Tons Of Oil In Jan-Oct 2022 -Azerbaijan exported 21.9 million tons of oil from January to October 2022, Azernews reports, citing Energy Minister Parviz Shahbazov. According to the operational data, 27.2 million tons of oil were extracted in the country in the first 10 months of 2022, he added. Moreover, the minister noted that 38.4 billion cubic meters of gas were produced during this period, adding that 18.2 billion cubic meters of this volume were exported, which is an increase of 7.3 percent. ‘According to operational data for the 10 months of this year, 21.9 out of 27.2 million tons of extracted #oil was #exported. Compared to the same period last year, 18.2 out of the 38.4 bcm #gas produced with an increase of 7.3% was #exported,’ he . In 2021, Azerbaijan exported 27.1 million tons of oil worth $13.2 billion. The top five countries in terms of oil imports from Azerbaijan were Italy, Israel, Croatia, Germany, and Portugal. In addition, Azerbaijan produced 34.6 million tons of crude oil in 2021. The slight increase in oil production last year was primarily due to the gradual elimination of voluntary oil output cuts under the OPEC+deal.
Nigeria’s October Oil Production Increases Marginally, Hits 1.014m bpd – - Nigeria struggled to exceed the 1 million barrels per day oil production mark in October, a ‘feat’ it hadn’t achieved in the last two months. The Nigerian Upstream Petroleum Regulatory Commission (NUPRC) data obtained by THISDAY indicated that Nigeria drilled 1.014 million barrels per day for the month under review, exceeding production for August which was 972,394 bpd and September’s pegged at 937,766 bpd. In all, the country produced 31.449 million barrels of oil in October as opposed to 28.132 million in September and 30.144 million barrels in August. The month also saw the production of 6.692 million barrels volume of condensate, raising total production to 38.1 million barrels for last month. Bonny appeared to have resumed production, rising from 167,582 barrels in September to 1.616 million barrels for the month. Brass also rose from 172,814 barrels to 358,671 barrels in the month of October. Qua Iboe continued to hold forth with 4.984 million barrels as against 4.97 million in September, while Forcados increased output massively from 134,437 barrels to 2.519 million barrels for the month.
Suspected oil spill on the Whanganui River - Work is underway to contain a suspected diesel spill on the Whanganui River. Horizons Regional Council’s emergency management manager Ian Lowe said the spill was reported Thursday morning via the council’s pollution hotline and emergency management staff immediately went to the site in the lower reaches of the river to assess the situation. “We can see what appears to be diesel over a large area of water between the rivermouth and boat ramp,” Lowe said. The incident was reported by contractors at the North Mole site who suspected diesel coming past their site when they arrived this morning. At this point the source of the spill is unknown, Lowe said. “However, we can confirm it is not as a result of river management work underway for the Te Pūwaha port revitalisation project at the North Mole.” He said at this stage they did not believe the spill to be linked to any boats in the port either. “We are mobilising equipment and more staff from Palmerston North to assist with the response. This will include a boat to assess the extent of the spill and possible source.” Lowe said the first priority was to contain the spill and remove as much as possible from the awa. “We will put inflatable booms out to stop the diesel from spreading out further and use absorbent pads to soak up what we can.” He said there was an incoming tide which they would use to their advantage for containment of the spill. “While we will do our best, it’s unlikely that we will be able to absorb all the diesel and expect any elusive patches will evaporate over time. “People are likely to see lingering effects of the spill and Horizons will be monitoring the situation over the next few days alongside and under the leadership of hapū,” Lowe said. “Our compliance team are also working to determine the source of the spill.” Lowe said people in the port vicinity would see staff undertaking the work most of Thursday and local iwi have been notified of the event.
Global Oil Inventories Hit Lowest Level Since 2004 - The lowest oil inventories in developed economies since 2004 are set to combine with the upcoming EU embargo on Russian oil imports to further tighten the oil market and the already “exceptionally tight” diesel markets, the International Energy Agency (IEA) said on Tuesday.“Oil markets remain finely balanced going into the winter months, with OECD stocks trending at the lowest levels since 2004,” the IEA said in its closely-watched Oil Market Report (OMR) for November published today.“The approaching EU embargoes on Russian crude and oil product imports and a ban on maritime services will add further pressure on global oil balances, and, in particular, on already exceptionally tight diesel markets. A proposed oil price cap may help alleviate tensions, yet a myriad of uncertainties and logistical challenges remain,” said the international agency. According to the IEA, global observed inventories fell by 14.2 million barrels in September as OECD and non-OECD stocks plunged by 45.5 million barrels and 19.3 million barrels, respectively. The decline in stocks, however, was partially offset by a surge in stocks of oil on floating storage of 50.6 million barrels, the IEA said. OECD industry oil stocks fell by 8 million barrels, while government stocks drew by 37.4 million barrels in September. OECD total oil stocks fell below 4 billion barrels for the first time since 2004, per IEA estimates.Those low inventory levels and the embargo on EU imports of Russian crude oil and products as of December 5 and February 5, respectively, will disturb the currently finely balanced market, the agency says.However, the very tight diesel market and high prices will lead to additional demand destruction next year. The IEA raised its global oil demand growth estimate by nearly 200,000 barrels per day (bpd) to 2.1 million bpd for this year, but slightly cut the 2023 demand growth estimate to 1.6 million bpd from 1.7 million bpd growth expected in the October report.
Crude Demand Must Fall Two-Thirds For Climate Scenarios To Work -It is obvious that crude must decarbonize. But COP27 is a reminder that oil consumption must first fall if the world is to achieve net zero. Wood Mackenzie said that in its accelerated energy transition 1.5 °C scenario, demand must fall by two-thirds from 100 million bpd today to 35 million bpd in 2050. Crude oil’s centrality to the global economy has been reinforced in the energy crisis of 2022. Oil demand has recovered strongly from the Covid-induced dip and, despite an economic slowdown, could reach record highs next year. In the meantime, pressure on the upstream and refining sectors to decarbonize the crude oil value chain is mounting. Alan Gelder and Sushant Gupta of our Refining team took me through their latest analysis. The sector is responsible for one-third of global emissions. Around 70% of these are Scope 3, released into the atmosphere on combustion at the point of consumption, mainly in transportation, heating, or industry. The other 30%, Scope 1& 2, are split almost evenly between upstream production and refining. Emissions must start falling soon, and precipitously if the world is to get onto a 1.5 °C pathway. There is a broad range of carbon intensities across the numerous different crudes. Including the cost of carbon will change ‘traditional’ price differentials that today are determined mainly by the crude’s gravity (API) and sulfur content. For refiners, carbon intensity will not only change the economics of selecting crudes as feedstocks but how they tackle reducing emissions from refining. Most upstream emissions are produced by powering operations (70%); the rest comprise non-combustion emissions from methane losses, flaring gas, and venting CO2. Upstream carbon intensity for crudes ranges from 10 tons to 70 tons of CO2 equivalent (CO2e) per 1000 bbls of crude produced. Arab Light is at the low end, Brent roughly in the middle, and Basrah Heavy among the highest. Refining emissions intensities are a similar order of magnitude, from 20 tons to 100 tons of CO2e per 1000 bbls of crude processed, the range a function of crude feedstock and the configuration of the refinery processing it. More complex refineries have the higher processing capability to produce higher-value products so tend to produce more emissions. Likewise, sites with deep integration with chemicals are more energy-intensive and produce higher emissions. Product end-use emissions range from 250 to 450 tons of CO2e per 1000 bbls of crude. Refineries integrated with petrochemicals tend towards the lower end because plastics are not combusted on consumption.In Europe, refiners already pay a carbon price on a portion of emissions that arise from crude processing through the EU emissions trading scheme. As upstream carbon intensity becomes an independent, reported variable, the roll-out of carbon pricing in other fiscal regimes will lead to a widening of differentials between lower and higher emission-intensive crudes. The differentials will change with the level of the carbon price. Woodmac estimates that at $100/ton of CO2, the Brent-Dubai differential could double to $4/bbl, assuming the refiner pays all upstream and refinery processing emissions. Arab Light’s low upstream emissions are a significant advantage and its typical discount to Brent could be eliminated.
Exxon Mobil Makes First Oil Discovery In Angola In 20 Years - Over the past five years, the United States’ largest independent oil and gas company, Exxon Mobil (NYSE: XOM), has mostly focused its exploratory activities in South America. Last month, the oil major announced that it had made two new discoveries at the Sailfin-1 and Yarrow-1 wells in the Stabroek block offshore Guyana, potentially adding more barrels to one of the most closely watched new oil discoveries. ExxonMobil has now made more than 30 discoveries on the block since 2015, and has ramped up offshore development and production at a pace that far exceeds the industry average. In contrast, Exxon’s exploits in Africa have been few and far between, with its last discovery on the continent coming nearly two decades ago. But Exxon has now announced that it has, together with its partners, discovered hydrocarbons in Block 15 off Angola in the Bavuca South prospect. This was the block’s 18th discovery, but the first since 2003. According to Exxon, the Valaris DS-9 drillship drilled the Bavuca South-1 well 365 km northwest from the coast at Luanda in 1,100 m (3,608 ft) of water, encountering 30 m (98 ft) of good-quality, hydrocarbon-bearing sandstone. Exxon owns a 36% interest in the block, with BP Exploration Angola (24%), ENI Angola Exploration (18%), Equinor Angola Block 15 (12%) and Sonangol P&P(10%) being its partners.The last big fossil fuel discovery on the continent dates back to 2010 after Texas-based Anadarko Corp. (now a subsidiary of Occidental Petroleum Corp.) and Italian energy giant Eni S.p.A. (NYSE: E) discovered approximately 180 trillion cubic feet of natural gas reserves, equivalent to ~29 billion barrels of oil, in Mozambique’s supergiant offshore basin of Rovuma, immediately catapulting the South African nation to a potential global LNG superpower. As you might expect, there was a stampede by oil and gas majors including ExxonMobil,TotalEnergies (NYSE: TTE), Shell (NYSE: SHEL), and China National Petroleum Corp. (NYSE: SNP)) coming in to stake their claims. Unfortunately, widespread terrorism and the growing menace of piracy have constantly held back progress with Mozambique fast joining the league of African nations grappling with a ‘resource curse.’ The security crisis in the northern region of Cabo Delgado had displaced hundreds of thousands of people, created a humanitarian crisis and even forced TotalEnergies to declare force majeure on its massive natural gas investment in the country.But the tides have now turned, and Mozambique has managed to get its act together just in time. The country is nowpoised to ship its first cargo of liquefied natural gas (LNG) overseas in November at a time when Europe is desperately trying to cut energy ties with Russia. Experts have estimated that Mozambique can earn in excess of $100B from its natural gas assets over the next 30 years.
China looks to ocean resources for energy needs, international cooperation - Offshore areas of China will become a major energy growth driver in the country for years to come, especially in the oil and gas sector, in which its increment will come mostly from offshore resources in China, analysts said. China's offshore crude increment last year accounted for a record high of more than 80 percent of the country's total growth volume, while the exploitation of offshore natural gas resources is also steadily advancing toward ultra-deep waters, said the Energy Economics Institute under the China National Offshore Oil Corp (CNOOC), the country's largest offshore driller. The institute believes that China's offshore oil and gas output will continue increasing this year. Offshore crude output will rise 5.4 percent to 57.6 million metric tons, accounting for around 80 percent of the country's total crude increment. Offshore natural gas production will exceed 20 billion cubic meters, up 6.7 percent year-on-year and making up around 12 percent of the country's gas increment, it said. CNOOC expects its oil and gas production to rise more than 6 percent each year during the 2022-24 period, while its continuous upstream investment and production commitment will also play a critical role in China's energy supply security, Li said. CNOOC accounted for more than half of China's total oil and gas output growth in 2021, while the driller is also seeking to use its engineering prowess to become a major player in offshore wind power projects, she said. The company said earlier that it would further take advantage of the company's offshore advantages while laying out the new energy industry to enhance its position as the country's top offshore oil and gas driller. CNOOC's offshore oil and gas production projects are ranked tops in the world, according to the China Offshore Energy Report drafted by the institute this year.
India Is Bright Spot for World Oil Demand - Petroleum demand in the world’s third-largest oil consumer has been growing faster than anywhere else in 2022, rising by more than 400,000 barrels a day. That’s equivalent to more than 20% of the total global increase. The country’s vigorous appetite for oil was clear early in the year, but what’s impressive is that it has remained robust in recent months just as consumption growth slowed elsewhere. Three factors help to explain that resilience. First, a fast-growing economy: India is set to post the second-strongest expansion among the Group of 20 this year, behind only oil-rich Saudi Arabia and well ahead of China. Second, New Delhi has capped retail fuel prices, insulating the public from the impact of $100-plus oil on the wholesale market. And third, the government has turned to Russia for petroleum, benefiting from the discounts offered by Moscow — at times as much as $20 a barrel — to keep its oil sales flowing. If current trends continue, India’s consumption will average at least 5.2 million barrels a day in 2022, surpassing the previous annual record, which was set in 2019 before the onset of the pandemic at 5 million barrels a day. To put that into context, current demand tops that of Germany, France and the UK combined. And there’s no peak in sight. Although Indian oil-use growth will slow next year, it’s likely to remain steep by historical standards at 200,000 barrels a day, with the country consuming an average of 5.4 million barrels a day. But there are risks. While current momentum suggests demand will remain healthy, the outlook is clouded by China’s economic slowdown and interest-rate hikes by India’s central bank in an effort to shore up the rupee.
OPEC Cuts Oil Demand Growth Estimates Yet Again - Significant global economic uncertainties in the coming months made OPEC cut on Monday its estimate of global oil demand growth for this year and next, in the fifth reduction of consumption forecasts since April.OPEC revised down each of its 2022 and 2023 oil demand growth forecasts by 100,000 barrels per day (bpd) from last month’s estimates due to China’s still-strict Covid policy and economic challenges in Europe, the organization said in its Monthly Oil Market Report (MOMR) out on Monday. “The significant uncertainty regarding the global economy, accompanied by fears of a global recession contributes to the downside risk for lowering global oil demand growth. In addition, China’s strict adherence to the ‘zero COVID-19 policy’ adds to this uncertainty, making the country’s recovery path even more unpredictable,” OPEC said. In October, a week after announcing a 2-million-bpd headline cut to its collective oil production target, OPEC slashed its global oil demand growth estimates for both 2022 and 2023. Those estimates are now further revised down by 100,000 bpd each.OPEC now sees global oil demand growth at 2.5 million bpd in 2022 after slashing the fourth-quarter demand projections by nearly 400,000 bpd.Global oil demand is projected to average 99.6 million bpd this year, with developed economies in the Americas seeing the highest rise in demand, led by the U.S. on the back of recovering gasoline and diesel demand, the cartel said. Light distillates are also projected to support demand growth this year, OPEC added.For 2023, OPEC now sees oil demand growth at 2.2 million bpd, down by 100,000 bpd from the growth expected in the October report. World oil demand is set to average 101.8 million bpd, “supported by expected geopolitical improvements and the containment of COVID-19 in China,” according to OPEC. Next year, U.S. demand is expected to exceed 2019 levels, thanks to a recovery in transportation fuels and light distillate demand. However, OECD Europe and the Asia Pacific are not expected to rise above 2019 consumption levels, the cartel said.“While risks are skewed to the downside, there exists some upside potential for the global economic growth forecast. This may come from a variety of sources. Predominantly, inflation could be positively impacted by any resolution of the geopolitical situation in Eastern Europe, allowing for less hawkish monetary policies,” OPEC noted.
OPEC Oil Production Fell In October As Members Missed Targets - OPEC’s crude oil production dropped by 210,000 barrels per day (bpd) in October compared to the previous month after the cartel and the wider OPEC+ group reversed the small output increase in September.The crude oil production of all 13 OPEC members, including those exempt from the OPEC+ pact - Venezuela, Iran, and Libya - averaged 29.49 million bpd in October, according to secondary sources in the organization’s closely-watched Monthly Oil Market Report (MOMR) published on Monday.Saudi Arabia, the de facto leader of OPEC and its top producer, saw its production decline by 149,000 bpd to average 10.838 million bpd last month, as OPEC+ decided in early September to reverse a 100,000 bpd increase in target oil production, which was only intended for the month of September. Saudi Arabia’s production dropped the most among OPEC members and was below the targeted production level of 11.004 million bpd per the schedule the OPEC+ meeting had adopted. The Kingdom self-reported higher production for October than secondary sources’ estimates, at 10.957 million bpd, down by 84,000 bpd compared to September.Production in Angola saw the second-steepest drop in OPEC producers in October, but it wasn’t the result of a conscious reduction since the African producer has been lagging behind its quota for many months. Angola’s crude oil production fell by 78,000 bpd to 1.067 million bpd in October, according to OPEC’s secondary sources. Angola’s target, however, is much higher, at 1.525 million bpd, meaning that the country was nearly 500,000 bpd below target. Over the coming months, OPEC’s production is set to decline further after the OPEC+ alliance decided to reduce its collective target by 2 million bpd for November. Although the actual cut is expected to be around half that number, at 1.1 million bpd, it still is the biggest cut since the record production reduction announced in April 2020 when oil demand plunged at the start of the pandemic.
USA EIA Raises Oil Price Forecast -The U.S. Energy Information Administration (EIA) slightly raised its Brent oil price forecast for both 2022 and 2023, the organization’s latest short term energy outlook (STEO) has revealed. The EIA now sees the Brent crude oil spot price averaging $102.13 per barrel this year and $95.33 per barrel next year, according to its November STEO. In its October STEO, the EIA projected that the Brent spot average would come in at $102.09 per barrel in 2022 and $94.58 per barrel in 2023. Despite the increase in the EIA’s Brent forecast values in November, the figures are still down on September’s projections. In its September STEO, the EIA expected the Brent spot average to hit $104.21 per barrel this year and $96.91 per barrel next year. “Growth in OPEC and non-OPEC oil production, most notably production in the United States, keeps the Brent crude oil price in our forecast lower on an annual average basis in 2023 than in 2022,” the EIA noted in its latest STEO. “However, we expect the Brent crude oil price will begin rising in 2H23,” the EIA added in the STEO. In its November STEO, the EIA warned that weakening global economic conditions, which it said could limit oil demand growth, “create the potential for oil prices to end up lower than our forecast”. The organization also noted that higher than forecast oil prices could stem from supply disruptions resulting from the EU’s impending bans on the seaborne import of crude oil and petroleum products from Russia. The EIA expects U.S. crude oil production to average 11.83 million barrels per day in 2022, before rising to 12.31 million barrels per day in 2023, according to its November STEO. In its October STEO, the EIA expected U.S. crude oil output to come in at 11.75 million barrels per day in 2022 and 12.36 million barrels per day in 2023. U.S. crude oil production was 11.25 million barrels per day in 2021, the EIA highlighted in its latest STEO.
Oil prices fall $1 on surging Covid cases in China, firmer US dollar - Oil prices fell on Monday, dragged down by a firmer US dollar while surging coronavirus cases in China dashed hopes of a swift reopening of the economy for the world's biggest crude importer. Brent crude futures were down $1.01, or 1.1%, at $94.98 a barrel by 1030 GMT after gaining 1.1% on Friday. WTI crude futures fell $1.11, or 1.3%, to $87.85 after advancing 2.9% on Friday. "US dollar strength appears to be weighing on oil and the broader commodities complex this afternoon," said Warren Patterson, head of commodities strategy at ING. "There probably is also an element where the market got a bit ahead of itself on Friday following an easing in China's Covid-related quarantine measures." Commodities prices rallied on Friday after China's National Health Commission adjusted its Covid prevention and control measures to shorten quarantine times for close contacts of cases and inbound travelers. But Covid-19 cases climbed in China over the weekend, with Beijing and other big cities on Monday reporting record infections. China's demand for oil from top exporter Saudi Arabia also remained weak, with several refiners having asked to lift less crude in December. Separately, US Treasury Secretary Janet Yellen on Friday said that India can continue buying as much Russian oil as it wants, including at prices above a G7-imposed price cap mechanism, if it steers clear of Western insurance, finance and maritime services bound by the cap. Also weighing on oil was dollar strength after comments from US Federal Reserve Governor Christopher Waller, who said on Sunday that the Fed could consider slowing the pace of rate increases at its next meeting, but that should not be seen as a softening in its commitment to lower inflation. "This leans towards the sticky inflation or recession narrative, which is negative for oil and other risk markets,"
Crudes Decline sharply on Russian Oil Exports, Firmer USD - West Texas Intermediate futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange fell 3% or more on Monday. The losses came on a stronger U.S. dollar index and reports suggesting Russian crude oil exports are holding steady ahead of a European embargo on seaborne oil shipments from Russian ports, with Asian buyers lifting increased volumes of displaced Russian oil. Russian crude oil exports rose to 3.25 million barrels per day (bpd) for the first two weeks of November, which is roughly the same rate Russia exported in the weeks prior to President Vladimir Putin's invasion of Ukraine on Feb. 24. Two-thirds of the crude loaded at Russian ports are now heading to Asian markets, according to private data published this morning, with India and China emerging as top buyers of Russian oil followed by Turkey and the United Arab Emirates. In comparison, Russia's seaborne oil exports to European countries dropped to just 700,000 bpd in the four-week period ending Friday, Nov. 11. Additionally, crude loadings out of Russian ports that are yet to show their destination rose to a record 2.39 million bpd on a four-week average basis. This might suggest the so called "shadow trade" in Russian crude tankers is gaining traction ahead of a European embargo on Russian oil flow that is set to take effect Dec. 5. Earlier this month, reports emerged suggesting G7 countries reached an agreement to enforce a fixed price on Russian oil exports but only at the point of first sale on land, meaning the resale of the same oil at sea won't be subject to the regulation. The measure will also bar European tankers from hauling Russian crude and prohibit the provision of insurance, brokerage and other maritime services unless oil loaded to those vessels was purchased at a price below a yet-to-be-agreed-upon cap. So far this year, Russian crude production held steady at 10.86 million bpd, according to OPEC's Monthly Oil Market Report released this morning, which is 0.5% higher compared to 2021 levels. Further details of the report showed Saudi Arabia's oil production slid 149,000 bpd last month to 10.838 million bpd, the kingdom's lowest output rate since July, and below its 11.004 million bpd production quota agreed to on Sept. 5. OPEC's oil production dropped by 210,000 bpd to a three-month low 29.494 million bpd. OPEC downgraded worldwide oil consumption by 100,000 bpd this year for annual growth of 2.5 million bpd. Oil demand in countries that are part of the Organization for Economic Cooperation and Development is estimated to increase by around 1.3 million bpd, while non-OECD oil demand is seen growing by about 1.3 million bpd. Global oil demand in the third and fourth quarters was revised lower due to China's zero-COVID policy along with geopolitical uncertainties in Europe. For 2023, global oil demand growth forecast was also revised down by 100,000 bpd from the previous assessment to now stand at 2.2 million bpd. OECD oil demand growth is expected to grow by 300,000 bpd and the non-OECD by 1.9 million bpd. In outside markets, U.S. dollar index extended gains into afternoon trading Monday, strengthening 3.5% against a basket of foreign currencies to settle at 106.531, further pressuring front-month WTI. NYMEX WTI for December delivery declined $3.09 per barrel (bbl) to $85.87 per bbl, and international crude benchmark ICE Brent fell to $93.14 bbl, down $2.85 on the session. NYMEX December RBOB futures declined 8.11 cents to $2.5285 per gallon, and December ULSD futures retreated 1.13 cents to $3.5440 per gallon.
Monday's Decline Was Driven Largely by a Stronger Dollar - WTI oil prices dropped 3.7% to a session-low $85.65 a barrel, while Brent dropped 3.4% to session low of $92.73. Monday's decline was driven largely by a stronger dollar and a return of worries about inflation and a drop in oil demand as the number of coronavirus cases in China continue to surge. Data last week showed a slight easing of inflationary price-pressures in October that quickly triggered risk appetite in financial markets. But several Fed officials quickly jumped in to say it's way too soon to claim any victory over inflation. Meanwhile, the Organization of the Petroleum Exporting Countries cut its forecast for global oil demand growth this year and next, citing economic headwinds. December WTI lost $3.09 per barrel, or 3.47% to $85.87, the largest one day dollar and percentage decline since Friday, Oct. 14, 2022, snapping a two session winning streak. January delivery lost $2.85 per barrel, or 2.97% to $93.14, its largest one day dollar and percentage decline since Friday, Oct. 14, 2022. RBOB Gasoline for December delivery lost 8.11 cents per gallon, or 3.11% to $2.5285, while December heating oil fell 1.13 cents per gallon, or 0.32% to $3.5440. OPEC cut its forecast for 2022 global oil demand growth for a fifth time since April and also cut next year's figure, citing increasing economic challenges including high inflation and rising interest rates. In its monthly report, OPEC estimated that oil demand in 2022 will increase by 2.55 million bpd or 2.6%, down 100,000 bpd from the previous forecast. OPEC said "The world economy has entered a period of significant uncertainty and rising challenges in the fourth quarter of 2022." Next year, OPEC expects oil demand to increase by 2.24 million bpd, also 100,000 bpd lower than previously forecast. Despite commenting on the rising challenges, OPEC left its 2022 and 2023 global economic growth forecasts steady and said while risks were skewed to the downside, there was also upside potential. OPEC said that in the second and third quarters of this year, global oil supply outpaced total oil demand by 200,000 bpd and 1.1 million bpd, respectively, having been in a deficit of 300,000 bpd in the first quarter. The report said that OPEC output fell by 210,000 bpd in October to 29.49 million bpd, more than the pledged OPEC+ reduction, led by a 149,000 bpd cut by Saudi Arabia. Genscape reported that crude oil stocks held in Cushing, Oklahoma as of Friday, November 11th fell by 1,357,864 barrels on the week and by 392,043 barrels from Tuesday, November 8th to 28,766,653 barrels. European gasoline flows to West Africa are estimated to be starting November at a slower pace, after reaching an eight-month high in October. Total November export volumes across the U.S. and West Africa arbitrage routes are tracking at 575,000 tons so far. IIR Energy reported that U.S. oil refiners are expected to shut in about 392,000 bpd of capacity in the week ending November 18th, increasing available refining capacity by 171,000 bpd. Offline capacity is expected to fall to 267,000 bpd in the week ending November 25th.
Oil Prices Tumble As Demand Concerns Weigh -- Oil prices fell around 2 percent on Tuesday as investors fretted about a weakening demand outlook.Benchmark Brent crude futures fell 1.7 percent to $91.59 a barrel while WTI crude futures were down 2.1 percent at $84.09.OPEC on Monday cut its forecast for global oil demand growth this year by 100,000 barrels a day to 2.55 million barrels per day, citing mounting economic challenges including high inflation and rising interest rates.China's factory output grew more slowly than expected in October, retail sales unexpectedly fell for the first time since May and property investment saw its biggest drop in 32 months, suggesting the world's second-largest economy is losing momentum as a result of protracted COVID-19 curbs and a property downturn.Elsewhere, data showed Japan's economy unexpectedly shrank for the first time in a year in the third quarter.Surging coronavirus cases in China also dashed hopes of a swift reopening of the world's second-largest economy.The southern Chinese city of Guangzhou has the biggest caseload, with new daily infections of Covid-19 exceeding 5,000 for the first time and fuelling speculation that localised lockdowns could widen.
Oil Futures Jump on Reports Russian Missiles Strike Poland -- West Texas Intermediate futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange reversed losses and advanced more than 1% on Tuesday following unconfirmed reports Russian missiles crossed into Poland overnight, a member of the North Atlantic Treaty Organization, killing two people in a town near the Ukrainian border. The attack, if confirmed, could trigger NATO's Article 5 provision, calling on all of the treaty's members to attack Russia in response to an unprovoked aggression. According to Article 5, an attack against one NATO member is considered an attack against all allies. It is not immediately clear if the two rockets that landed in the border town of Przewodów was a result of Russia's mass bombardment of Ukrainian cities earlier today, with over 100 rockets launched, or was a deliberate attack on Poland itself. Poland's Prime Minister, Mateusz Morawiecki, has convened the Committee of the Council of Ministers for National Security and Defense Affairs "as a matter of urgency," government spokesman Piotr Müller confirmed, with local media outlets claiming this is likely the result of the explosions on its eastern border. Russia's Ministry of Defense moments ago claimed reports of Russian missiles landing in Poland are a "deliberate provocation" from Polish media. The Ministry added, "No strikes were made against targets near the Ukrainian-Polish state border by Russian weapons. The fragments published in a hot pursuit by the Polish media from the scene in the village of Przewodow have nothing to do with Russian weapons." The situation remains fluid. Earlier this morning, the oil complex came under selling pressures after International Energy Agency revised lower its demand expectations for the remainder of the year, citing, in part, geopolitical tensions in Ukraine. For refined products, in particular, demand growth is forecasted to ease from 1.5 million bpd in 2021 to 400,000 bpd in 2022 before posting a small decline in 2023 under the weight of persistently high prices and slowing economies. The Paris-based agency estimates oil flow from Russian ports rose by 165,000 bpd in October to 7.7 million bpd as shipments to the European Union, China, and India held up well into last month. At settlement, NYMEX WTI for December delivery advanced $1.05 bbl to $86.92 bbl, and international crude benchmark ICE Brent rallied to $93.86 bbl, up $0.72. NYMEX December RBOB futures declined 1.24 cents to $2.5161 gallon, and December ULSD futures advanced 9.73 cents to $3.6413 gallon.
Oil prices settle higher amid supply disruption on Druzhba pipeline - Oil prices rose on Tuesday and settled higher after news that oil supply to Hungary via the Druzhba oil pipeline has been temporarily suspended due to a fall in pressure. Brent crude futures rose 72 cents to settle at $93.86 a barrel, while U.S. West Texas Intermediate crude rose $1.05 to $86.92. Russia's state-owned pipeline monopoly Transneft has been notified by Ukraine of the pipeline disruption, the RIA news agency quoted Transneft as saying on Tuesday. The United States said it was investigating unconfirmed reports that stray Russian missiles caused an explosion that killed two people in a Polish village near the border with Ukraine. A European Union ban on seaborne Russian crude, set to start on Dec. 5, means that 1.4 million barrels per day (bpd) must be replaced, the International Energy Agency said on Tuesday. "When you look at what we saw from the IEA about global oil inventories, that should be very bullish," said Phil Flynn, an analyst at Price Futures Group. Adding support to oil prices, U.S. producer prices increased less than expected in October, more evidence inflation was starting to ease, which could allow the Federal Reserve to slow its aggressive interest rate hikes. Wall Street indexes rose after the data, while the U.S. dollar index fell, making greenback-denominated oil less expensive for other currency holders. "The inflation data was positive in a way. Stocks took off from that and it looks like we're getting dragged higher now," "We're still in that inverse dollar effect here." The IEA forecast that a gloomy economic outlook will put global oil use on track to contract by nearly a quarter million bpd in the fourth quarter of 2022 year on year, with demand growth slowing to 1.6 million bpd in 2023 from 2.1 million bpd this year. U.S. crude stocks fell by about 5.8 million barrels for the week ended Nov. 11, according to market sources citing American Petroleum Institute figures on Tuesday. Gasoline inventories rose by about 1.7 million barrels, while distillate stocks rose by about 850,000 barrels. [API/S] U.S. government data on inventories is due Wednesday. In China, COVID cases rose further, including in the capital Beijing, and the country's factory output growth slowed. Investment bank JPMorgan cut its quarterly and full-year forecasts for economic growth in China. The Organization of the Petroleum Exporting Countries (OPEC) cut its 2022 global oil demand growth forecast for a fifth time since April, citing mounting economic challenges including high inflation and rising interest rates.
Crude Prices Jump After Israeli Tanker Hit By Iranian Drone Off Oman Coast - Crude prices are higher Wednesday morning after a bomb-carrying drone on Tuesday evening struck an oil tanker owned by an Israeli billionaire, The Associated Press reported.The Liberian-flagged oil tanker Pacific Zircon was approximately 150 miles off the Omani coast at 730 pm local time when a "projectile" hit the vessel, a Mideast-based defense official told AP. AP said the United Kingdom Maritime Trade Operations was notified about the attack and is monitoring shipping lanes in the region. "We are aware of an incident and it's being investigated at this time," UKMTO said. Also, the commander of the US Navy's Fifth Fleet, Timothy Hawkins, was briefed on the incident, according to Reuters. Brent crude prices, which were down before the news, jumped and traded above $94 a barrel.In a statement, Pacific Zircon's owner Eastern Pacific Shipping, which Israeli billionaire Idan Ofer owns, said the vessel was hauling diesel when it was "hit by a projectile ... there were no reports of injuries or pollution." "All crew are safe and accounted for. There is some minor damage to the vessel's hull but no spillage of cargo or water ingress," the Singapore- based Eastern Pacific said. Bloomberg cited a report via the Israeli Public Broadcasting Company (KAN) that said unidentified Israeli officials pointed the finger at Iran for the drone attack. Tracking data shows the vessel is off the Omani coast.
WTI Extends Losses Despite Crude Draw As Product Stocks Build - Despite a surprisingly large crude draw, oil prices are lower this morning as a pipeline carrying Russian oil to Europe was reported to have restarted after being offline during a turbulent 24 hours.Prices dropped as a section of the Druzhba oil pipeline, Europe’s largest crude oil conduit, was reported to have restarted after a disruption to its power supply.Oil has experienced a renewed bout of volatility amidst a renewed injection of geopolitical risk. An oil tanker linked to an Israeli billionaire was hit by a projectile about 150 miles (241 kilometers) off the coast of Oman, according to a statement from its owner. Yesterday, a rocket hit a Polish village near the Ukrainian border. The incident was unlikely to have been an intentional attack, the Polish president said.“Geopolitical risk premia only hold if they trigger supply disruptions,” An "uptick in geopolitical risk" helped drive oil prices higher late Tuesday, following news of a missile strike in Poland, said Stephen Innes, managing partner at SPI Asset Management, in a market update.With "crude oil at the epicentre of Eastern European risk oil," traders had little choice but to "graduate what-if scenarios hedging the potential risk to global oil supplies" if a smouldering powder keg ignites, he said.Additionally, prices fell as China's COVID-19 cases continue to rise, suggesting more lockdowns ahead of the holiday and flu season API:
- Crude -5.835mm (-400k exp)
- Cushing -842k
- Gasoline +1.69mm (+300k)
- Distillates +850k (-500k exp)
DOE:
- Crude -5.4mm - biggest draw since August
- Cushing -1.62mm - biggest draw since May
- Gasoline +2.21mm - biggest build since July
- Distillates +1.12mm - biggest build since Sept
Official EIA data confirmed last night's big crude draw reported by API (-5.40mm barrels) and on the products side the official data showed larger than expected builds... Graphics Source: Bloomberg Adding the 4.1mm drain from SPR (now at its lowest since March 1984)... ...,overall crude stocks fall by almost 10mm barrels...
U.S. Crude Oil Stockpiles Fell by 5.4 Million Barrels - U.S. crude oil stockpiles fell by 5.4 million barrels, to 435.4 million barrels for the week ending November 11, as refinery activity accelerated, according to the Wednesday release by the Energy Information Administration. Analysts were expecting a decline of 500,000 barrels. The surprising decline in crude inventories was caused by the significant decline in U.S. crude oil imports. Oil futures were trading lower as Russian oil shipments via the Druzhba pipeline to Hungary restarted and rising COVID-19 cases in China weighed on sentiment however, loses were slightly reduced after the release of the EIA report. WTI December delivery lost $1.33 per barrel, or 1.53% to $85.59. This is the lowest settlement for a front month contract since October 25. Brent Crude for January delivery lost $1.00 per barrel, or 1.07% to $92.86, the lowest settlement for a front month contract since November 9. RBOB Gasoline for December delivery lost 0.81 cent per gallon, or 0.32% to $2.5080; down for three consecutive sessions and down 10.16 cents or 3.89% over the last three sessions. ULSD for December delivery lost 2.77 cents per gallon, or 0.76% to $3.6136, the largest one day dollar and percentage decline since Thursday, Nov. 10, 2022. ULSD was down seven of the past eight sessions At the moment, various geopolitical situations are influencing oil markets, among which include increased and persistent tensions between Russia and Ukraine, weak Chinese The EIA said U.S. commercial crude oil imports fell by 895,000 bpd in the latest week to 5.6 million bpd, the lowest level since May 2021. In the U.S. Gulf Coast region, crude oil imports fell by 257,000 bpd last week to 879,000 bpd, the lowest level since December 2021. U.S. crude stocks in the SPR fell by 5.4 million barrels to 435.4 million barrels, the lowest level since March 1984.OPEC Secretary General, Haitham al-Ghais, said that the organization is ready to intervene for the benefit of oil markets. He also said that OPEC is aware, cautious and monitoring economic developments worldwide.Hungarian Foreign Minister, Peter Szijjarto, said Russian oil shipments via the Druzhba pipeline to Hungary have restarted, adding that the pipeline was still operating with low pressure after a temporary shutdown on Tuesday. Oil supply to parts of Eastern and Central Europe via a section of the Druzhba pipeline were temporarily suspended on Tuesday for technical reasons. Barclays forecast Brent oil prices in the fourth quarter at $93/barrel and WTI prices at $86/barrel. It sees Brent oil prices and WTI prices at $92/barrel and $86/barrel in the first quarter of 2023, respectively and sees Brent oil prices at $103/barrel in the fourth quarter of 2023 and WTI prices at $99/barrel. Petro-Logistics said crude oil exports by OPEC have fallen significantly so far this month, suggesting members are delivering on their share of the output cut agreed by the group and its allies.
Oil falls amid easing geopolitical tensions, China's Covid concerns -Oil prices fell for a second day in early Asian trade on Thursday as concerns over geopoliticaltensions eased and rising numbers of Covid-19 cases in China added to demand worries in the world's largest crude importer. Brent crude futures dropped by 62 cents, or 0.7 per cent,to $92.24 a barrel by 0110GMT. US West Texas Intermediate (WTI) crude futures fell 65 cents, or 0.8 per cent,to $84.94 a barrel. Brent dropped by 1.1 per cent andWTI declined by 1.5 per cent on Wednesday axer Russian oil shipments via theDruzhba pipeline to Hungary restarted. "Crude oil fell axer NATOcleared Russia's missile attack on Poland, while demand concerns (are) back to trader's focus amid ongoing China's Covid curbs and gloomy global economic outlooks," Poland and military alliance NATOsaid on Wednesday that a missile which crashed inside Poland was probably a stray fired by Ukraine's air defences and not a Russian strike, easing fears of the war between Russian andUkraine spilling across the border. Oil prices eased despite a larger-than-expected draw in crude oil stockpiles in theUnited States, added Teng. Crude stocks in theUS,the world's biggest oil consumer, fell by 5.4 million barrels in the week endedNov. 11 to 435.4 million barrels,the Energy Information Administration said on Wednesday, compared with expectations in a Reuters poll for a 440,000- barrel drop. However, inventories of gasoline and distillate fuels both rose by more than expectations. More oil is set to flow to theUS as TC Energy lixed a force majeure on its 622,000-barrel-per-day Keystone pipeline that supplies the Midwest andGulf Coast that had reduced shipments by 7 per cent. Sustained concerns of demand weakness in China are also "keeping markets grounded," as it continues to report more Covid cases in major cities. "With Covid cases in China continuing to rise, especially as we move towards flu season,traders are lex with little option to recalibrate positions reflecting the possibility of more lockdowns in heavily populated centers that hurt oil demand exponentially more than other areas of the economy," China's Covid caseload is small compared with the rest of the world, but it maintains stringent policies to quash out cases before they further spread. TheNationalHealth Commission reported 23,276 new Covid-19 infections onNov. 16, of which over 20,000 were asymptomatic
WTI Slides 4% on Fed's Hawkish Rhetoric, USD Gains (DTN) -- Oil futures nearest delivery on the New York Mercantile Exchange and the Brent contract on the Intercontinental Exchange settled Thursday's session sharply lower, with West Texas Intermediate sliding below $82 barrel (bbl) on the spot continuation chart as investors recalibrated bets for a deeper recession next year after Fed officials signaled interest rates could go much higher than currently priced in by markets. St. Louis Federal Reserve President James Bullard said on Thursday the central bank might need to raise the federal funds rate to 5% to 7% range in order to bring down inflation. The federal funds rate currently stand between 3.75% and 4%. "The policy rate is not even yet in a zone that might be considered sufficiently restrictive. Monetary tightening has had limited effect on prices so far," he added. For context, officials in September projected rates increasing to around 4.6% in 2023. Those projections will be updated at the Federal Open Market Committee meeting Dec. 13-14. Bullard was not the only Federal Reserve official who struck a hawkish tone this week. Federal Reserve Governor Christopher Waller said on Wednesday in his view the central bank's policy is barely restrictive, adding, "We have a long way to go in terms of raising interest rates." Waller further added it was too soon to conclude that inflation had peaked or that the central bank would be able to end its rate increases early next year. He pointed to the summer months last year when inflation pressures appeared to be easing but later reaccelerated. Inflation in October moderated to 0.4% from 0.6% monthly gain seen over the previous month, which has brought an annualized increase in consumer prices to 7.7%. U.S. retail sales, meanwhile, surprised in October with a 1.3% gain after an unchanged reading in September, according to data from Commerce Department. Some economists suggest the jump in October retail sales could be a sign of an early holiday shopping season. Underlying Thursday's losses in the oil complex are also reports of a partial return of Russian oil flows through Druzhba network -- a key pipeline that delivers Russian oil to landlocked countries in Central and Eastern Europe. Hungary's oil and gas company MOL confirmed that oil flows through the Druzhba pipeline resumed on Wednesday afternoon after a brief power cut on the Ukrainian side. On Tuesday, Ukraine notified European partners that it had suspended oil pumping via Druzhba pipeline in direction of Hungary due to an unidentified technical reason. In financial markets, the U.S. Dollar Index regained ground against a basket of foreign currencies to settle at 106.610 as investors digest recent comments from Fed officials that point to more rate hikes in coming months. NYMEX December West Texas Intermediate futures ended the session $3.95 lower at $81.64 bbl, and January Brent futures on ICE declined $3.08 to $89.78 bbl. December NYMEX RBOB futures fell 5.33 cents to $2.4547 gallon, with December ULSD futures 8.88 cents lower at $3.5248 gallon.
WTI at 2-Month Low as Traders See Hawkish Fed, Recession Risk - Oil futures moved mixed in early trade Friday, with all petroleum contracts heading for weekly losses as investors reprice the risk of a deeper recession next year amid increasingly hawkish central banks. International crude benchmark Brent contract fell below $90 barrel (bbl) for the first time in six weeks and West Texas Intermediate is trading at the lowest level since September after European Central Bank President Christine Lagarde said recession alone might not be enough to bring down consumer prices. "Interest rates remain the most effective tool for shaping our policy stance. We expect to raise them further to the levels needed to ensure that inflation returns to our 2% medium-term target in a timely manner," Lagarde furthered. Markets broadly expect the ECB will increase its key interest rate by 0.5% next month to 2% after lifting the benchmark rate by 0.75% at its two previous meetings. In the United States, St. Louis Federal Reserve President James Bullard sent shockwaves through markets on Thursday after he suggested the federal funds rate might go as high as 7% to tame inflation. The Federal Reserve is currently targeting the key overnight borrowing rate between 3.75% and 4%. "Monetary tightening so far has had a limited effect on prices. Based on this analysis, rates must stand at the minimum of 5% and 5.25%. That would at least get us in the (restrictive) zone," said Bullard. In September, central bank officials projected the federal funds rate rising to around 4.6% in 2023, with the projection almost certainly to be updated at the next Federal Open Market Committee meeting on Dec. 13-14. Current market consensus sees a 0.5% rate hike in December, but a higher terminal rate at some point next year and a greater risk to the economic outlook. Bloomberg poll shows 100% of economists expect some sort of recession next year whether it is a mild or a severe one. Geopolitical uncertainty tied to ongoing fighting in Ukraine lifted prices earlier this week after reports emerged suggesting Russian oil flows through Druzhba pipeline were halted due to an unidentified "technical reason." The Druzhba pipeline network is a key conduit that delivers Russian oil to landlocked countries in Central and Eastern Europe. In financial markets, the U.S. Dollar Index slipped 0.2% against a basket of foreign currencies to trade near 106.560 as investors continued to reprice risk of recession next year. NYMEX December West Texas Intermediate futures is down more than $1.50 near $80 bbl, and January Brent futures on ICE declined a $1.60 to near $88.15 bbl. December RBOB futures on NYMEX were down more than $0.01 to $2.4425 gallon, with December ULSD futures $0.022 lower at $3.5028 gallon.
Oil Slides 2%, Posts Second Weekly Decline as Supply Fears Recede (Reuters) -Oil dropped by about 2% on Friday, logging a second weekly decline, due to concern about weakened demand in China and further increases to U.S. interest rates. Brent crude settled at $87.62 a barrel, falling $2.16, or 2.4%. U.S. West Texas Intermediate (WTI) crude settled at $80.08 a barrel, losing $1.56, or 1.9%. Both benchmarks posted weekly losses, with Brent down about 9% and WTI roughly 10%. A stronger U.S. dollar, which makes oil more expensive to non-American buyers, pushed down crude prices. The market structure of both oil benchmarks shifted in ways that reflect dwindling supply concerns. Crude came close to record highs earlier this year as Russia's invasion of Ukraine added to those worries. In addition, the front-month futures contract soared to a gigantic premium over later-dated contracts, a signal that people were worried about the immediate availability of oil and were willing to pay handsomely to secure supply. Those supply concerns are waning. The current WTI contract is now trading at a discount to the second month, a structure known as contango, for the first time since 2021, Refinitiv Eikon data showed. This condition will also benefit those looking to put more oil in inventories for later, especially with stocks still at low levels. "The deeper the contango, the more likely the market will put those barrels in storage," Brent was still in the opposite structure, backwardation, though the premium of nearby Brent over barrels loading in six months fell as low as $3 a barrel, the lowest since April. China, which sources say is looking to slow crude imports from some sources, has seen a rise in COVID-19 cases while hopes for less aggressive U.S. rate hikes have been dented by remarks from some Federal Reserve officials. "The situation in China with COVID continues to haunt this market," "So much optimism gets priced in to the market as soon as they try to say that they're going to reopen, but then the reality on the ground is just completely opposite of that hopeful analysis." As the European Union's ban on Russian crude looms on Dec. 5, the prospect of more barrels from Russia pressuring the spot crude oil market also weighed on futures prices. Recession concerns have dominated this week even with a tightening of supply by the Organization of the Petroleum Exporting Countries (OPEC) and its allies, together known as OPEC+. "On the demand side, there are concerns about an economic slowdown," . "The path of least resistance seems skewed to the downside." The Fed is expected to raise rates by a smaller 50 basis points (bps) at its Dec. 13-14 policy meeting after four consecutive hikes of 75 bps, a Reuters poll showed.
Oil Slumps 10% This Week as Oversupply Fears Send Bulls to Exits - Oil dropped the most in a week since April as the full weight of languishing Chinese demand and more economic tightening radically shifted the market’s sentiment. West Texas Intermediate fell 1.9% to settle just over $80 a barrel. US futures fell 10% this week, the most since Biden ordered a historic discharge of crude from the Strategic Reserves in April. Swelling Covid cases in China and aggressive monetary tightening by central banks have combined to erase all the gains earned last month when OPEC and its partners slashed production by 2 million barrels a day. Pullbacks were evident along most of the oil-trading complex. On Friday, the US prompt-spread flipped into contango, a structure that signals oversupply, for the first time since last year. Meanwhile, a deteriorating market for physical barrels has also weighed on prices as demand for winter-delivery cargoes has weakened. The collapsing gauges of market health sent bulls running for the exits. Hedge funds slashed bullish bets for Brent crude the most in four months. Money managers’ net-long positions on the international benchmark fell around 30,000 contracts, according to data from the U.S. Commodity Futures Trading Commission released Friday. Crude is trading below several key moving averages, sparking so-called technical-based selling. A further collapse in the market’s structure on Friday added to the selling. WTI for December delivery lost $1.56 to settle at $80.08 a barrel in New York. Brent for January fell $2.16 to settle at $87.62 a barrel. Coronavirus cases in China have climbed to near their highest level of the pandemic, as authorities signal they’re preparing for even more infections. The increases will likely prove a test for any loosening of the country’s Covid rules.
USA Lays Blame for Tanker Attack -U.S. Central Command has stated that an Iranian-made unmanned aerial vehicle conducted a one-way attack against the Pacific Zircon tanker. Exploitation of the debris that hit the vessel reveals that it was a Shahed-series one-way attack drone, U.S. CentCom noted, adding that a multilateral operation led by the British Royal Navy’s HMS Lancaster - including two U.S. Navy vessels, guided-missile destroyer USS The Sullivans (DDG 68), patrol coastal ship USS Chinook (PC 9), and a U.S. Navy P-8 Poseidon patrol craft - responded to the scene. “This unmanned aerial vehicle attack against a civilian vessel in this critical maritime strait demonstrates, once again, the destabilizing nature of Iranian malign activity in the region” General Michael ‘Erik’ Kurilla, the commander of U.S. Central Command, said in a government statement. In a statement posted on the White House website, U.S. National Security Advisor Jake Sullivan said, “upon review of the available information, we are confident that Iran likely conducted this attack using a UAV, a lethal capability it is increasingly employing directly and via its proxies throughout the Middle East and proliferating to Russia for use in Ukraine.” “There is no justification for this attack, which is the latest in a pattern of such actions and broader destabilizing activities. This action further threatens freedom of navigation through this crucial waterway, international shipping and commerce, and the lives of those on the vessels involved,” he added in the statement. “As President Biden emphasized during his visit to the Middle East region, the United States is committed to supporting the free flow of commerce through its vital waterways,” Sullivan continued. In the wake of the MV Pacific Zircon incident, Aljazeera reported that Iran’s Nournews, which Aljazeera highlighted is affiliated with the country’s top security body, blamed Israel for the attack. An Israeli official speaking anonymously to Reuters said that Iran was behind the attack, Aljazeera noted.
U.S. moves to shield Saudi crown prince in Khashoggi killing - The Biden administration declared Thursday that the high office held by Saudi Arabia’s crown prince should shield him from lawsuits for his role in the killing of a U.S.-based journalist, a turnaround from Joe Biden’s passionate campaign trail denunciations of Prince Mohammed bin Salman over the brutal slaying. The administration said the prince’s official standing should give him immunity in the lawsuit filed by the fiancée of slain Washington Post columnist Jamal Khashoggi and by the rights group he founded, Democracy for the Arab World Now. The request is non-binding and a judge will ultimately decide whether to grant immunity. But it is bound to anger human rights activists and many U.S. lawmakers, coming as Saudi Arabia has stepped up imprisonment and other retaliation against peaceful critics at home and abroad and has cut oil production, a move seen as undercutting efforts by the U.S. and its allies to punish Russia for its war against Ukraine. The State Department on Thursday called the administration’s decision to try to protect the Saudi crown prince from U.S. courts in Khashoggi’s killing “purely a legal determination.” And despite backing up the crown prince in his bid to block the lawsuit against him, the State Department “takes no view on the merits of the present suit and reiterates its unequivocal condemnation of the heinous murder of Jamal Khashoggi,” the administration’s court filing late Thursday said. Saudi officials killed Khashoggi at the Saudi consulate in Istanbul. They are believed to have dismembered him, although his remains have never been found. The U.S. intelligence community concluded Saudi Arabia’s crown prince had approved the killing of the widely known and respected journalist, who had written critically of Prince Mohammed’s harsh ways of silencing of those he considered rivals or critics. The Biden administration statement Thursday noted visa restrictions and other penalties that it had meted out to lower-ranking Saudi officials in the death. Biden as a candidate vowed to make a “pariah” out of Saudi rulers over the 2018 killing of Khashoggi.
Iran Court Issues First Protest-Related Death Sentence - Anti-government protests have continued raging in Iran since they started in mid-September, following the death in police custody of 22-year-old Mahsa Amini for alleged non-compliance with the country's strict Islamic dress code. The protests have at times gotten violent, with buildings across various cities burned down, and also with live fire used by security services to quell the unrest. Last week hardliners in parliament demanded that authorities take a harsher stance in order to finally halt the so-called "anti-hijab" demonstrations.A majority of the members of Iran’s parliament last week formally requested that the judiciary "deal decisively with the perpetrators of these crimes [the protests] and with all those who assisted in the crimes and provoked rioters."This as the death toll has grown into the hundreds - though the government says the police and security services side has suffered scores of casualties. The BBC reports that "At least 326 protesters, including 43 children and 25 women, have been killed in a violent crackdown by security forces, according to Iran Human Rights."But it seems the judiciary has taken the criticism from parliament to heart, as it has handed down its first execution sentence for alleged protest-related crimes. According to Al Jazeera: The Iranian judiciary said late on Sunday that an unnamed individual has been sentenced to execution for “setting fire to a government center, disturbing public order and collusion for committing crimes against national security” in addition to “moharebeh” (waging war against God) and “corruption on Earth”.Five more unnamed people, who authorities described as “rioters” – a word the government uses to describe the ongoing protests and those participating in them – were handed between five and 10 years in prison on national security-related charges.More such extreme penalties are expected, given that Tehran officials have long accused the protest movement of being fueled by Iran's enemies such as Israeli and US intelligence, hence the charge of "collusion for committing crimes against national security." John Bolton, who spearheaded Trump’s policies towards Iran for years, insists to BBC Persian that Iranian protesters are armed. He adds that he’s seen images of Kurdish forces that have been trained & armed in Iraq & says they are making a big difference in the current protests. https://t.co/69rxcm5Y2c President Biden and the White House have spurred on the protests, saying that the US stands on the "side of the Iranian people".Early this month at a Democratic campaign event in California, Biden said, "Don’t worry, we’re gonna free Iran. They’re gonna free themselves pretty soon." Iranian officials have meanwhile taken these and similar statements as evidence of an externally driven regime change operation.
US to send over 100 unmanned vessels to Persian Gulf despite stern warnings from Iran -- The commander of United States Central Command (CENTCOM) says a US-led task force will deploy over 100 unmanned vessels in the Persian Gulf region's strategic waters, in spite of stern warnings from Tehran against such deployments. General Michael Kurilla said on Saturday that the deployment will be completed by next year, claiming that it aims to stave off maritime threats. “By this time next year, Task Force 59 will bring together a fleet of over 100 unmanned surface and subsurface vessels operating together, communicating together and providing maritime domain awareness,” said Kurilla, who was sanctioned by the Islamic Republic last month for supporting terrorism and inciting violence against the Iranian nation during the recent riots. Task Force 59 was created in Bahrain in September 2021 to integrate unmanned systems and artificial intelligence into the Pentagon's Middle East operations, after a series of drone attacks blamed on Iran. Iranian Foreign Minister Hossein Amir-Abdollahian said earlier in the day that the pervasive presence of unmanned vessels by extra-regional countries has doubled the region's problems. Iranian Navy Commander Rear Admiral Shahram Irani says the country’s destroyers will be equipped with the indigenous Abu Mahdi naval cruise missiles. "We consider the presence of [extra-regional] forces in the region to be a threat to the peace and stability of the region, and we believe that they have become a threat to the Persian Gulf region and the Oman Sea, as well as energy security in the region," Amir-Abdollahian said at a joint press conference with his Omani counterpart Sayyid Badr Albusaidi in Tehran. He added the Islamic Republic believes that regional countries are capable of preserving the peace and security of the region by themselves. Top Iranian officials and commanders have repeatedly warned against the presence of foreign forces in the region, saying Tehran deems such presence to becontradictory to regional peace, stability, and cooperation. . Meanwhile, Kurilla also said that in addition to the unmanned vessels, the US is “building an experimentation program here in the Middle East to beat adversary drones with our partners.” He was apparently referring to Iranian drones, which he claimed to be "the greatest technological threat to regional security."
Iran and Russia reach deal to produce unmanned weaponized aircraft: report - Iran and Russia have finalized an agreement to build hundreds of weaponized drones in Russian territory as the war in Ukraine approaches the nine-month mark, according to The Washington Post. The Post reported on Saturday that Russian and Iranian officials reached the deal earlier this month and the countries are transferring designs and components of the drones to allow production to start potentially within months, based on interviews with three officials familiar with the matter. Iran is officially neutral in the conflict between Russia and Ukraine but has faced international criticism after intelligence reports revealed that Russia has been using Iranian-made drones to attack Ukrainian military and civilian targets. Tehran initially denied the reports but admitted earlier in November that it gave a “limited” number of drones to Russia, saying that it did so before the war began and it does not know how they were being used. The officials told the Post that Russia could significantly increase its stockpile of weapons through the deal by acquiring its own assembly line to make the drones, as production would occur in Russia. Multiple members of NATO, including the United States, have reviewed intelligence on the agreement, the Post reported.Moscow has sent more than 400 drones to Ukraine, often to strike civilian infrastructure, since August, according to the outlet, which cited intelligence officials. Russia sent a barrage of missiles to a variety of targets throughout Ukraine earlier this week, primarily targeting the country’s electrical infrastructure, after Russian forces withdrew from the city of Kherson, the only regional capital they had captured since their full-scale invasion began in February. ‘
Russia, India, China, Iran: The Quad that Really Matters - By Pepe Escobar - Southeast Asia is right at the center of international relations for a whole week viz a viz three consecutive summits: Association of South East Asian Nations (ASEAN) summit in Phnom Penh, the Group of Twenty (G20) summit in Bali, and the Asia-Pacific Economic Cooperation (APEC) summit in Bangkok. Eighteen nations accounting for roughly half of the global economy represented at the first in-person ASEAN summit since the Covid-19 pandemic in Cambodia: the ASEAN 10, Japan, South Korea, China, India, US, Russia, Australia, and New Zealand. With characteristic Asian politeness, the summit chair, Cambodian Prime Minister Hun Sen (or “Colombian”, according to the so-called “leader of the free world”), said the plenary meeting was somewhat heated, but the atmosphere was not tense: "Leaders talked in a mature way, no one left." It was up to Russian Foreign Minister Sergey Lavrov to express what was really significant at the end of the summit. While praising the “inclusive, open, equal structure of security and cooperation at ASEAN”, Lavrov stressed how Europe and NATO “want to militarize the region in order to contain Russia and China’s interests in the Indo-Pacific.” A manifestation of this policy is how “AUKUS is openly aiming at confrontation in the South China Sea," he said. Lavrov also stressed how the West, via the NATO military alliance, is accepting ASEAN “only nominally” while promoting a completely “unclear” agenda. What’s clear though is how NATO “has moved towards Russian borders several times and now declared at the Madrid summit that they have taken global responsibility.” This leads us to the clincher: “NATO is moving their line of defense to the South China Sea.” And, Lavrov added, Beijing holds the same assessment. Here, concisely, is the open “secret” of our current geopolitical incandescence. Washington’s number one priority is the containment of China. That implies blocking the EU from getting closer to the key Eurasia drivers - China, Russia, and Iran – engaged in building the world’s largest free trade/connectivity environment. Adding to the decades-long hybrid war against Iran, the infinite weaponizing of the Ukrainian black hole fits into the initial stages of the battle. For the Empire, Iran cannot profit from becoming a provider of cheap, quality energy to the EU. And in parallel, Russia must be cut off from the EU. The next step is to force the EU to cut itself off from China. All that fits into the wildest, warped Straussian/neo-con wet dreams: to attack China, by emboldening Taiwan, first Russia must be weakened, via the instrumentalization (and destruction) of Ukraine. And all along the scenario, Europe simply has no agency. Real life across key Eurasia nodes reveals a completely different picture. Take the relaxed get-together in Tehran between Russia's top security official Nikolai Patrushev and his Iranian counterpart Ali Shamkhani last week. They discussed not only security matters but also serious business – as in turbo-charged trade. The National Iranian Oil Company (NIOC) will sign a $40 billion deal next month with Gazprom, bypassing US sanctions, and encompassing the development of two gas fields and six oilfields, swaps in natural gas and oil products, LNG projects, and the construction of gas pipelines. Immediately after the Patrushev-Shamkhani meeting, President Putin called President Ebrahim Raeisi to keep up the “interaction in politics, trade and the economy, including transport and logistics," according to the Kremlin. Iranian president reportedly more than “welcomed” the “strengthening” of Moscow-Tehran ties. Patrushev unequivocally supported Tehran over the latest color revolution adventure perpetrated under the framework of the Empire’s endless hybrid war. Iran and the EAEU are negotiating a Free Trade Agreement (FTA) in parallel to the swap deals with Russian oil. Soon, SWIFT may be completely bypassed. The whole Global South is watching. Simultaneous to Putin’s phone call, Turkiye’s Recep Tayyip Erdogan - conducting his own diplomatic overdrive, and just back from a summit of Turkic nations in Samarkand – stressed that the US and the collective West are attacking Russia “almost without limits”. Erdogan made it clear that Russia is a “powerful” state and commended its “great resistance”. The response came exactly 24 hours later. Turkish intelligence cut to the chase, pointing out that the terrorist bombing in the perpetually busy Istiklal pedestrian street in Istanbul was designed in Kobane in northern Syria, which essentially responds to the US. That constitutes a de-facto act of war and may unleash serious consequences, including a profound revision of Turkiye’s presence inside NATO.
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