Sunday, December 18, 2022

global oil surplus at 390,000 barrels per day​ in November​, in spite of OPEC’s ​938,000 barrel per day shortfall

global oil production​ exceeded demand by​ 390,000 barrels per day​ in November​; despite OPEC production that  was ​938,000 barrels per day short ​of their ​​reduced quota; US Strategic Petroleum Reserve was at a new 38½ year low

oil prices partly recovered from last week's drop to a 12 month low after an oil leak shut down the Keystone pipeline supplying diluted Canadian bitumen​, a replacement for Russian Urals,​ to US refineries...after falling 11.2% to $71.02 a barrel last week after the EU banned seaborne imports of Russian crude and a G7 price cap on Russian oil kicked in, the contract price for the benchmark US light sweet crude for January delivery rose more than 1% in early Asian trade on Monday as the Keystone pipeline bringing Canadian crude to remained closed while Russian President Putin threatened to cut production in response to the G7 price cap on Russian oil, but slipped in early trading on the NYMEX as traders balanced concerns over the health of the global economy in the coming year against falling supplies from OPEC+ nations, before rallying to close $2​.​15 or 3% higher at $73.17 a barrel​,​ as traders swooped in to buy oil at the lowest price of th​e year....oil prices rose sharply early Tuesday to extend Monday's gains amid signs of further easing of China's COVID restrictions, and continued to rally on a steep drop in the US dollar following a CPI report that showed US consumer prices in November rose at the slowest pace since December 2021, solidifying the case for less-aggressive interest rate increases from the Fed, and settled $2​.22 higher at a one week high of $75.39 a barrel as the Keystone pipeline remained shut amid what could potentially be one of the coldest of cold snaps in decades...however, oil prices slid after the market closed ​Tuesday ​after the API reported a surprisingly big build in crude supplies and opened lower Wednesday, and ​then ​tumbled further in early trading after the EPI reported an even more massive crude build, but then reversed and rallied to their highest level in just over a week, supported by the International Energy Agency’s forecasts for stronger demand growth this year and next, and settled $1.89 higher at $77.28 a barrrel, as traders looked beyond the big weekly build in U.S. crude inventories to focus instead on the shutdown of ​the ​Keystone pipeline, which is vital to refiners on the country’s coasts...oil prices steadied on Thursday, after TC Energy restarted a section of the Keystone pipeline and the dollar advanced, and then slid about 2% as traders worried about the fuel demand outlook due to a stronger dollar and further interest rate hikes by global central banks and settled ​$​1​.17 lower at $76.11 a barrel after softer-than-expected economic data in the United States, China, and Eurozone brought demand concerns back into focus, while traders weighed the impacts of higher borrowing costs next year....oil prices moved lower in early trading on Friday as a bumpy reopening out of China saw the Omicron virus burning through its large cities, with hospital capacity in Beijing and Hong Kong unable to handle the developing crisis, and erased the gains from earlier in the week in sliding by more than 3% as central bankers said much more need​ed to be done to curb inflation​, despite the less aggressive hike rates this week​​​​​​, but trimmed those losses after U.S. Department of Energy announced it would start repurchasing crude oil for the Strategic Petroleum Reserve​, in order​ to replenish our emergency stockpiles, and settled the Friday session $1.82 lower at $74.29 a barrel, but still held on to a gain of 4.6% on the week, even as oil’s comeback rally after its worst week since March had been snuffed out by renewed fears of recession and higher-for-longer interest rates in the U.S. and Europe...

Meanwhile, natural gas prices finished higher for the first time in 3 weeks after a​ quite​ volatile week of trading, on the potential for much colder weather for the rest of December... after ending 0.6% lower at $6.245 per mmBTU last week on a delay in the restart of the Freeport ​LNG ​export terminal, the contract price of US natural gas for January delivery opened 63 cents or 10% higher on Monday, on colder December forecasts that included the possibility of even more frigid air moving in from Canada, but pulled back as the day drew on and settled 34.2 cents higher at $6.587 per mmBTU, supported by a jump in European gas prices that should keep U.S. LNG exports near record highs.....natural gas prices jumped another 5% on the late December cold forecasts Tuesday, and reached an intraday high at $7.105 per mmBTU, but again pulled back to settle ​just ​34.8 cents higher at $6.935/MMBtu, as warmer trends in the weather models took a hatchet to the early gains...natural gas prices opened 30 cents lower on those weaker weather forecasts Wednesday, and finished down 50.5 cents or 7.3% at $6.430 per mmBTU on expectations for less chilly weather than had been anticipated come late December...however, natural gas prices reversed and jumped 54.0 cents, or 8.4%, to settle at a two-week high of $6.970 per mmBTU on Thursday, on a bigger than expected storage draw, an increase in gas flows to LNG export plants, and a drop in output as extreme cold from North Dakota to Texas caused oil and gas wells to freeze....natural gas futures floundered on Friday amid hints in weather models that Arctic cold blasts, while intense, might not endure as long as earlier forecasts suggested, and settled 37.0 cents lower at $6.600 per mmBTU on the day, but still finished 5.7% higher on the week...

The EIA's natural gas storage report for the week ending December 9th indicated that the amount of working natural gas held in underground storage in the US fell by 50 billion cubic feet to 3,412 billion cubic feet by the end of the week, which meant our gas supplies were 18 billion cubic feet, or ​​0.5% less than the 3,430 billion cubic feet that were in storage on December 9th of last year, and 15 billion cubic feet, or ​just ​0.4% below the five-year average of 3,427 billion cubic feet of natural gas that were in storage as of the 9th of December over the most recent five years....the 50 billion cubic foot withdrawal from US natural gas working storage for the cited week was more than the average forecast for an 45 billion cubic feet withdrawal by a Reuters poll of analysts, but much less than the 83 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2021, and also much less than the average 93 billion cubic feet of natural gas that have typically been withdrawn from our natural gas storage during the same ​winter ​week over the past 5 years...

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending December 9th indicated that after a sizable increase in our oil imports, an increase in the amount of oil released from the SPR, a drop in the amount of oil we were refining, and a near record increase in the amount of oil supplies that could not be accounted for, we had oil left to add to our stored commercial crude supplies for the first time in five weeks and for the 15th time in the past 34 weeks, despite a big increase in our oil exports....Our imports of crude oil rose by an average of 855,000 barrels per day to average 6,867,000 barrels per day, after falling by an average of 24,000 barrels per day during the prior week, while our exports of crude oil rose by 886,000 barrels per day to average 4,316,000 barrels per day, which together meant that the net of our trade in oil worked out to an import average of 2,551,000 barrels of oil per day during the week ending December 9th, 31,000 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 reported​ as being 100,000 barrels per day lower 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 14,651,000 barrels per day during the December 9th reporting week…

Meanwhile, US oil refineries reported they were processing an average of 16,126,000 barrels of crude per day during the week ending December 9th, an average of 459,000 fewer barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net average of 783,000 barrels of oil per day were being added to the supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures from the EIA for the week ending December 9th appear to indicate that our total working supply of oil from net imports and from oilfield production was 2,259,000 barrels per day less than what was added to storage plus our oil refineries reported they used during the week. To account for that big, inexplicable disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+2,259,000) 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....moreover, since last week’s EIA fudge factor was at (+762,000) barrels per day, that means there was a 1,497,000 barrel per day difference between this week's balance sheet error and the EIA's crude oil balance sheet error from a week ago, and hence the changes to supply and demand from that week to this one that are indicated by this week's report are off by that much, rendering those comparisons completely meaningless....however, since most everyone treats these weekly EIA reports as gospel, and since these figures often drive oil pricing, and hence decisions to drill or complete 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 ​7​83 ,000 barrel per day ​increase in our overall crude oil inventories came as an average of 1,462,000 barrels per day were being added to our commercially available stocks of crude oil, while 678,000 barrels per day of oil were being pulled out of our Strategic Petroleum Reserve.  That draw on the SPR, the largest since October 7th, 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 had been fluctuating in recent weeks because the administration has also 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 273,878,000 barrels of oil have now been removed from the Strategic Petroleum Reserve over the past 28 months, and as a result the 382,271,000 barrels of oil that still remain in our Strategic Petroleum Reserve is now the lowest since January 6th, 1984, or nearly a 39 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 ​rose to an average of 6,​495​,000 barrels per day last week, which was ​0.1% less than the 6,​502​,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 100,000 barrels per day lower at 12,100,000 barrels per day​,​ even though the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,700,000 barrels per day​,​ because Alaska’s oil production was 7,000 barrels per day lower at 443,000 barrels per day and subtracted 100,000 barrels per day from the rounded national total​ ​​(EIA math).​ 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 92.2% of their capacity while using those 16,126,000 barrels of crude per day during the week ending December 9th, down from their 95.5% utilization rate during the prior week, but still on the high side of normal utilization ​in ​earl​y​ December...The 16,126,000 barrels per day of oil that were refined this week were still 2.9% more than the 15,670,000 barrels of crude that were being processed daily during week ending December 10th of 2021, while 2.6% less than the 16,562,000 barrels that were being refined during the prepandemic week ending December 13th, 2019, when our refinery utilization was at 90.6%, within the normal utilization range for early December ...

Even with the decrease in the amount of oil being refined this week, gasoline output from our refineries was somewhat higher, increasing by 129,000 barrels per day to 9,194,000 barrels per day during the week ending  December 9th, after our gasoline output had decreased by 295,000 barrels per day during the prior week. This week’s gasoline production was still 8.4% less than the 10,042,000 barrels of gasoline that were being produced daily over the same week of last year, and 6.6% below the gasoline production of 9,840,000 barrels per day during the prepandemic week ending December 13th, 2019.  On the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 164,000 barrels per day to 5,168,000 barrels per day, after our distillates output had increased by 21,000 barrels per day during the prior week.  But even with that decrease, our distillates output was still 7.4% more than the 4,812,000 barrels of distillates that were being produced daily during the week ending December 10th of 2021, and 1.9% more than the 5,072,000 barrels of distillates that were being produced daily during the week ending December 13th 2019...

With the increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 5th week in a row and for the 8th time in 18 weeks, increasing by 4,496,000 barrels to 213,768,000 barrels during the week ending December 9th, after our gasoline inventories had increased by 5,319,000 barrels during the prior week. Our gasoline supplies rose again this week as the amount of gasoline supplied to US users fell by 103,000 barrels per day to 8,255,000 barrels per day, and as our exports of gasoline rose by 191,000 barrels per day to 1,203,000 barrels per day​,​ while our imports of gasoline rose by 271,000 barrels per day to 790,000 barrels per day.   After 31 gasoline inventory drawdowns over the past 45 weeks, our gasoline supplies were still 2.3% more than last December 10th's gasoline inventories of 218,585,000 barrels, but about 3% below the five year average of our gasoline supplies for this time of the year…

Even with the decrease in our distillates production, our supplies of distillate fuels increased for the 14th time in 19 weeks, and for the 26th time over the past year, rising by 1,364,000 barrels to 120,171,000 barrels during the week ending December 9th, after our distillates supplies had increased by 6,159,000 barrels during the prior week. Our distillates supplies rose by less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, increased by 218,000 barrels per day to 3,768,000 barrels per day, and because our imports of distillates fell by 95,000 barrels per day to 277,000 barrels per day, and because our exports of distillates rose by 209,000 barrels per day to 1,483,000 barrels per day... But after fifty-two inventory withdrawals over the past eighty-five weeks, our distillate supplies at the end of the week were were still 2.9% below the 123,758,000 barrels of distillates that we had in storage on December 10th of 2021, and about 8% below the five year average of distillates inventories for this time of the year...

Meanwhile, after a big increase in our oil imports, a big release from the SPR, and a slowdown in refining, our commercial supplies of crude oil in storage rose for the 7th time in 18 weeks and for the 21st time in the past year, increasing by 10,231,000 barrels over the week, from 413,898,000 barrels on December 2nd to 424,129,000 barrels on December 9th, after our commercial crude supplies had decreased by 5,194,000 barrels over the prior week. After this week's increase, our commercial crude oil inventories rose to around 6% below the most recent five-year average of crude oil supplies for this time of year, and were around 26% more than the average of our crude oil stocks as of the second weekend of December over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels. 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 December 9th were 1.0% less than the 428,286,000 barrels of oil we had in commercial storage on December 10th of 2021, and 15.2% less than the 500,096,000 barrels of oil that we had in storage on December 11th of 2020, and 5.1% less than the 446,833,000 barrels of oil we had in commercial storage on December 13th 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....after the big crude, gasoline, distillates inventory increases we've already noted for this week, 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, rose by 9,231,000 barrels this week, from 1,604,208,000 barrels on December 2nd to 1,613,439,000 barrels on December 9th, after our total inventories had increased by 3,776,000 barrels during the prior week. This week's increase still left our total petroleum liquids inventories down by 174,225,000 barrels over the first 49 weeks of this year, and about 0.8% from a new 18 year low...

OPEC's Report on Global Oil for November

Tuesday of this past week saw the release of OPEC's December Oil Market Report, which includes the details on OPEC's & global oil data for November, and hence it gives us a picture of the global oil supply & demand situation during a period when demand for oil was constrained by lockdowns in Beijing and other ​big ​cities in China, while oil supplies from Russia continued to be constrained by Western sanctions, even as some buyers of Russian crude ​had ​stepped up their purchases in advance of December's European Union ban of Russian oil imports by sea and the G7 price caps....November was also the first month after OPEC and aligned oil producers had imposed a new 2 million barrel per day production cut on the cartel, taking roughly 2% of global oil supply off the market... 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 48 of this month's report (pdf page 60), 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 744,000 barrels per day to 28,826,000 barrels per day during November, down from their revised October production total that averaged 29,570,000 barrels per day....however, that October output figure was originally reported as 29,494,000 barrels per day, which therefore means that OPEC's October production was revised 76,000 barrels per day higher with this report, and hence OPEC's November production was, in effect, only 668,000 barrels per day lower than the previously reported OPEC production figure (for your reference, here is a copy of the table of the official October OPEC output figures as reported a month ago, before this month's revision)...

while OPEC and other aligned oil producers agreed to reduce production by 2,000,000 barrels per day during November, and while the 744,000 barrels per day production cut we see above obviously is short of that, OPEC's production was already running 1,585,000 barrels per day short of what they were expected to produce during October, so the November production cut​ still​ leaves them far short of what they were expected to produce during the month, as we'll see in the next table...

The above table was originally included as a downloadable attachment to the press release following the 32nd OPEC and non-OPEC Ministerial Meeting on October 5th, 2022, which set OPEC's and other aligned oil producers' production quotas for November​ and the following months through 2023​.. 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 25,416,000 barrels per day in November...therefore, the 24,478,000 barrels those 10 OPEC members actually produced in November were 938,000 barrels per day short of what they were expected to produce during the month, with Nigeria and Angola accounting for the majority of this month's shortfall...

The next graphic from this month's report that we'll look at shows us both OPEC's and worldwide oil production monthly on the same graph, over the period from December 2020 to  November 2022, and it comes from page 49 (pdf page 61) of OPEC's December 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 744,000 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 43,000 barrels per day to average 101.50 million barrels per day in November, a reported increase which came after October's total global output figure was apparently revised down by 43,000 barrels per day from the 101.50 million barrels per day of global oil output that was reported for October a month ago, as non-OPEC oil production rose by a rounded 800,000 barrels per day in October after that downward revision, with most of ​November'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 43,000 barrel per day increase in November's global output, the 101.50 million barrels of oil per day that were produced globally during the month were 3.64 million barrels per day, or 3.7% more than the revised 97.86 million barrels per day that were being produced globally in November a year ago, which was the fourth 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 December 2021 OPEC report (online pdf) for the originally reported November 2021 details)...since this month's ​bg ​decrease in OPEC's output contrasts to the ​modest ​global increase, their November oil production of 28,826,000 barrels per day amounted to 28.4% of what was produced globally during the month, down from their 29.1% share of the global total in October....OPEC's November 2021 production was originally reported at 27,717,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year ​still ​produced 1,109,000 barrels per day, or 4.0% more barrels per day of oil this November than what they produced last November, when they accounted for 28.2% of a smaller global output total...

Even with the big decrease in OPEC's output and the ​small ​increase​ in other global oil output that we've seen in this report, the amount of oil being produced globally during the month was ​still in excess of  the expected global demand, as this next table from the OPEC report will show us....

The above table came from page 26 of the November Oil Market Report (pdf page 38), 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 ​November, which is their estimate of global oil demand during the fourth quarter of 2022....OPEC is estimating that during the 4th quarter of this year, all oil consuming regions of the globe have been using an average of 101.11 million barrels of oil per day, which is a rounded downward revision of 140,000 barrels per day from their estimate 101.25  million barrels per day for 4th quarter demand of a month ago (revisions are 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 ​November, which would imply that there was surplus of around 390,000 barrels per day of global oil production in November, when compared to the demand estimated for the month...

in addition to figuring th​e November oil s​urplus implied by this report, the downward revision of 43,000 barrels per day to October's global oil output that's implied in this report​, ​combined with the 140,000 barrel per day downward revision to 4th quarter demand, means that the 250,000 barrels per day global oil output surplus we had previously figured for October would now be revised to surplus of ​347,000 barrels per day....

Note on the table above that we've highlighted in green an upward revision of 220,000 barrels per day to the third quarter's demand....that means that the 1,490,000 barrels per day global oil output surplus we had previously figured for September would now be revised to a surplus of 1,270,000 barrels per like manner, 220,000 barrels per day upward revision to 3rd quarter demand means that the surplus of 1,230,000 barrels per day we had previously figured for August would now be revised to a surplus of 1,010,000 barrels per day, and that the surplus of 680,000 barrels per day barrels per day we had previously figured for July would have to be revised to a surplus of 460,000 barrels per day... 

Note that in green we have also circled a downward revision of 140,000 barrels per day to OPEC's previous estimates of second quarter demand...based on that downward revision to demand, our previous estimate that there was a surplus of 550,000 barrels per day in June would now be revised to a 690,000 barrels per day surplus, while the oil shortage of 180,000 barrels per day that we had previously figured for May would have to be revised to a shortage of ​just ​40,000 barrels per day, and finally, that the 540,000 barrels per day global oil output surplus we had previously figured for April would have to be revised to a surplus of 680,000 barrels per day...

Also note that in green that we have circled a small downward revision of 10,000 barrels per day to OPEC's previous estimate of first quarter demand, during a period when supply and demand seemed to be closer to being in balance.....​so ​for March, that means that the global oil output surplus of 140,000 barrels per day we had previously figured for March would be revised to a surplus of 150,000 barrels per day, and that the 80,000 barrels per day global oil output shortage we had previously figured for February would now be revised to a shortage of 70,000 barrels per day, and that the global oil output shortage of 830,000 barrels per day we had previously figured for January would now be revised to a shortage of 820,000 barrels per day, in light of that 10,000 barrel per day downward revision to first quarter demand...

You might also note that we have also circled a 20,000 barrel per day downward revision to 2021's demand​,​ circled in orange....while we're not inclined to go back and recompute the figures for each month of last year in light of that revision, we do have an adequate running total for last year ​supply shortfall ​from our prior reports such that we can estimate an aggregate revision for the year​ as a whole​ of the September revision to 2021's demand, we had figured there had an oil shortage for last year of 577,915,000 barrels, or an average of 1,583,329 barrels per day​, (computed to an accuracy far greater than the data availble allows)​....thus the 20,000 barrel per day downward revision to 2021 demand still leaves an oil shortage for last year of 570,615,085 barrels, or an average of 1,563,329 barrels per day...​.​we were never close to running out, however, because the quantities of oil being produced globally during the pandemic of 2020 still averaged over 1.1 trillion barrels, or over 3 million barrels per day more than anyone wanted...

This Week's Rig Count

The number of drilling rigs active in the US decreased for the 9th time over the past 20 weeks during the week ending December 16th, but even ​with 92 weekly increases over the past 116 weeks, active rigs are still 2.1% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US decreased by 4 rigs to 776 rigs over the past week, which was still 197 more rigs than the 579 rigs that were in use as of the December 17th report of 2021, but was 1,153 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 decreased by 5 to 620 oil rigs during the past week, after the number of rigs targeting oil had decreased by 2 during the prior week, but there are still 145 more oil rigs active now than were running a year ago, even as they amount to just 38.5% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 9.2% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 1 to 154 natural gas rigs, which was also up by 50 natural gas rigs from the 104 natural gas rigs that were drilling during the same week a year ago, even as they were only 9.6% 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 haven't seen any details on either of those wells, in the past we've identified various "miscellaneous" rig activity as being for exploration, for carbon dioxide storage, and for utility scale geothermal projects...a year ago, there were were no such "miscellaneous" rigs running...

The offshore rig count in the Gulf of Mexico was down by 3 to 15 rigs this week, with 14 rigs still drilling in Louisiana's offshore waters, and only one rig still drilling for oil offshore from Texas....the Gulf rig count now matches 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...since there are not any rigs drilling off our other coasts, the Gulf rig count equals the national offshore count..

In addition to rigs running offshore, there are still two water based rigs drilling through inland bodies of water this week; those include 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 ...a year ago, there was just one such rig drilling on inland waters...

The count of active horizontal drilling rigs was down by 1 to 707 horizontal rigs this week, which was still 186 more rigs than the 521 horizontal rigs that were in use in the US on December 17th of last year, but just over half of the record 1,374 horizontal rigs that were drilling on November 21st of addition, the directional rig count was down by three to 43 directional rigs this week, while those were still up by 11 from the 32 directional rigs that were operating during the same week a year ago…on the other hand, the vertical rig count was unchanged at 26 vertical rigs this week, which was also unchanged from the 26 vertical rigs that were in use on December 17th 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 December 16th, the second column shows the change in the number of working rigs between last week’s count (December 9th) and this week’s (December 16th) count, the third column shows last week’s December 9th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 17th of December, 2021...

checking the Rigs by State file at Baker Hughes for the changes in the Texas Permian, we find that there was a rig pulled out of Texas Oil District 8, which overlies the core Permian Delaware, while rig counts in other districts in the Texas Permian were unchanged...since the national Permian basin count was unchanged, we can thus conclude that the rig added in New Mexico was set up to drill in the far western Permian Delaware, in the southwest corner of that state...that switch also facilitated the reduction of the Permian natural gas rig count to three, all of which are in Texas​, and an increase to 347 Permian oil rigs​...elsewhere in Texas, there was a rig pulled out of Texas Oil District 1, which would account for the Eagle Ford oil rig decrease, while there were was a rig added in Texas Oil District 3, apparently in a basin that Baker Hughes doesn't track.... there was also a rig pulled out of Texas Oil District 6, which had been drilling for natural gas in the Haynesville shale, and there was also a rig removed from the state's offshore waters....more than offsetting that Texas Haynesville shale loss, there were four natural gas rigs added in the Haynesville in northwest Louisiana, while Louisiana​ ​saw two rigs removed from the state's offshore waters​ at the same time​...

elsewhere, the rig removed from Colorado had been drilling in the DJ Niobrara chalk, the rig pulled out of North Dakota had been drilling in the Bakken shale of the Williston basin, the rig removed from Oklahoma apparently had been drilling in a basin not tracked by Baker Hughes​, and the two rigs pulled out of Wyoming ​also ​had been drilling in a basin or basins not tracked by Baker Hughes....since our other data shows three natural gas rigs added in the Haynesville and one pulled out of the Permian, it appears one of those rigs that had been drilling in a basin not tracked by Baker Hughes ​had been drilling for natural gas...lastly, the​ oil​ rig added in Alaska was added to the eight that already had been drilling on the North Slope...


DeWine should veto drilling threat to state parks falsely labeled 'green energy' - Ohio Capital Journal -- Ohioans love their state parks. I’ve been to seven this year. Had lots of company. The log of daily visitors is surging at the parks. Overnight stays jumped 26.5% from 2017 to 2021. Try booking a campsite or cabin in the summer — or fall. Everybody wants one. The lure of solitude and escape in the natural beauty of Ohio state parks is potent and getting more so.But so is the lure for expanded fracking and oil and gas development in our treasured state oases after state lawmakers slipped an early Christmas present to the fossil fuel industry in a totally unrelated bill about food safety and poultry sales. In the dark of the night, Ohio Senate Republicans quietly added two amendments to House Bill 507 that would clear the way for industrialized polluters to camp out in our state parks.Without any public notice or input, GOP legislators did their friends in the Ohio Oil and Gas Association a solid with provisions forcing Ohio to grant lease applications for more natural gas drilling on public lands and state parks. The prerogative of a state agency to nix approval of fracking operations on state land was slyly tweaked into a requirement to give the go-ahead for drilling applicants casing a state park near you.Adding insult to (CO2, methane, and toxic waste) injury, the Ohio Senate also tucked an Orwellian twist in the House legislation that would reclassify natural gas as “green energy” — a legal definition scientifically reserved for renewable energy generated from natural sources such as solar, wind, water. Natural gas is no such thing.But the Republican fossil fuel cabal in the state senate surreptitiously broadened that legal meaning to include not only natural gas (which is mainly methane, a strong greenhouse gas) but any source of energy that “is more sustainable and reliable relative to some fossil fuels.”Sounds vague enough to greenlight a whole bunch of drilling rigs leaking large quantities of methane emissions that pollute the air along with diesel fumes from massive truck transportation and machinery operations and accumulate an enormous amount of wastewater with the potential to contaminate groundwater or cause earthquakes in surrounding areas. The rich and powerful fossil fuel industry wins again. Political payoff at the public expense. Ground Zero in Ohio for greedy oil and gas titans is the state’s largest park nestled in the heart of rural Guernsey County. Fracking for the potentially abundant deposits of Marcellus and Utica shale that lie beneath Salt Fork State Park has long been a goal of energy companies eager to tap into a possible gold mine of natural gas.The oil industry wants to turn the natural landscape and wonder of Salt Fork into an industrialized zone of well pads, new access roads, pipelines, and other fracking infrastructure that destroys the otherwise lush playground of 17,229 acres.

Ohio’s ‘Frackgate’ controversy predicted backlash to drilling under state parks -- Barkcamp State Park is among the few places where visitors can experience Ohio’s forests as they existed before European settlement. Once the site of a historic logging camp, today it’s a destination for camping, fishing and other outdoor recreation. It’s also a place that could see new pressure for oil and gas development if Ohio lawmakers approve lame-duck legislation this month that would remove barriers to drilling under public lands. Neither supporters nor critics have singled out specific parks that could be of interest to the industry, but a planning document from a previous governor’s administration reveals at least three areas where oil and gas extraction might occur. They include Barkcamp, as well as Wolf Run State Park and Suncreek Fish State Forest. That document — a strategic communications plan developed by members of the Kasich administration and Ohio Department of Natural Resources in 2012 — ignited a political controversy known as Frackgate after it became public two years later. It also predicted the backlash that would be likely to follow any proposal to drill under state parks.“Vocal opponents of this initiative will react emotionally, communicate aggressively to the news media and online, and attempt to cast it as unprecedented and risky state policy,” the communication plan said. Ohio law for more than a decade has said an agency “may” lease land for oil and gas drilling. House Bill 507,, which passed the Ohio Senate last week without any public testimony on its last-minute amendments, would change that to say the agency “shall” lease the land “in good faith.” If the bill becomes law, “the state agency essentially has to — must — lease the land when the oil and gas company shows up at the door and demands the lease,” said attorney Nathan Johnson, director of public lands for the Ohio Environmental Council. In his view, the amendment would give free rein to oil and gas companies, with few safeguards for competing public interests or the environment.The same legislation would also declare natural gas to be “green energy.”   A 2011 law created an oil and gas leasing commission and outlined a framework for it to decide whether to grant permits for drilling and to enter into leases through a competitive bidding process. Lawmakers passed the bill, and Gov. John Kasich signed it roughly a year before another law opened the state to widespread fracking and horizontal drilling.By the summer of 2012, members of the Kasich administration, Ohio Department of Natural Resources and others put together the strategic communications plan before potentially moving ahead with drilling at Barkcamp, Wolf Run and Sunfish Creek. All three are located in counties that are among Ohio’s top seven oil and gas producers.The communications plan became public in early 2014 and resulted in outcry from the Sierra Club, the Ohio Environmental Council, ProgressOhio and other groups. Days later, Kasich said he had changed his position about drilling on state public lands. A pro-industry newsletter predicted “Frackgate” would remain an issue in Ohio for a while.

Ohio ‘green’ natural gas bill motivated by ESG investing concerns - The author of an Ohio amendment that would classify natural gas as “green energy” said he hopes the legislation can help companies meet ESG investing standards.ESG refers to environmental, social and governance practices. ESG investing generally limits financing choices to companies or funds that meet certain criteria for those categories. The practice has been around for decades but recently has become a political boogeyman for conservatives who denounce it as “woke capitalism.”  Ohio state Sen. Mark Romanchuck, a Republican from Ontario, told the Energy News Network he hopes having the “green energy” language in Ohio law might help large users of natural gas meet ESG standards.“I don’t know if it will work,” Romanchuk added. Romanchuk said he doesn’t think there is “anything magical” about using the word “green,” and there is uncertainty about its potential legal impact. Unlike an earlier version, the amendment to House Bill 507 specifically says it would not allow natural gas projects to qualify for renewable energy credits.That hasn’t quelled criticism from climate and clean energy advocates, who say the vague legislation — approved by the state Senate last Wednesday without any public testimony — could have wider implications for the way natural gas is marketed and regulated in the state.   “In terms of how the ‘green energy’ amendment might impact regulatory decisions and investments, I think everyone is still trying to fully understand that,” said Neil Waggoner, who leads the Sierra Club’s Beyond Coal campaign in Ohio. The Senate moved “quickly and foolishly,” he said, in a way that prevented opponents from offering any testimony on the proposal.The Ohio Senate Agriculture and Natural Resources Committee last Tuesday tacked the proposal and other amendments onto an unrelated bill about rules for poultry farmers regarding baby chicks. Now, along with the “green energy” provision, the bill includes provisions that would require state agencies to open parks and other public lands to oil and gas drilling, plus other amendments.  The bill version passed by the Senate states: “‘Green energy’ includes energy generated by using natural gas as a resource.” It also defines green energy as an energy source that either releases reduced air pollutants or “is more sustainable and reliable relative to some fossil fuels.”

Ohio House Declares Natural Gas 'Green' Energy | RTO Insider - Ohio lawmakers, dominated by Republican majorities, OK'd legislation declaring green energy “includes energy generated by using natural gas as a resource.”

Ohio Legislature Opens Door for E&P on State Lands, Stamps 'Green Energy' Label on Natural Gas -- A bill qualifying natural gas as green energy and allowing state agencies to lease land to develop oil and gas has passed the Ohio legislature and was awaiting a signature from Republican Gov. Mike DeWine.  Under current Ohio law, state agencies are not automatically required to lease land for oil and gas exploration and production (E&P) activities.    Ohio Oil and Gas Association President Rob Brundrett told NGI that “Ohio’s had the law on the books that you’re able to lease state lands for over a decade, and one of the things that was supposed to happen during this time period was the Oil and Gas Land Management Commission was to provide a rule framework for that to happen.”In September 2021, the legislature adopted Section 155.34 to state code, requiring the Ohio Department of Natural Resources’ Oil and Gas Land Management Commission to establish a standard lease form by which state agencies could enter into contracts with E&Ps. The commission had not adopted a framework within the 120-day timeframe set in Section 155.34.  “There’s been starts and stops over the last decade…The commission met last December, but then it hadn’t met again until this December,” Brundrett said. At its latest meeting, however, the commission adopted a draft standard lease form as required by Section 155.34. The form is now available for public comment through Jan. 13.  “There’s another meeting scheduled tentatively in February, so we’re hopeful that by the springtime we’ll have a framework that will be able to go through the rules process and get put in place in 2023.”In the meantime, the Ohio Senate added Section 155.33 to House Bill (HB) 507, “kind of like a stopgap,” Brundrett said. HB 507 was initially introduced and later passed the state’s House as legislation solely dealing with agriculture. Section 155.33 alters Ohio’s Revised Code so that state agencies no longer “may,” but “shall lease, in good faith, a formation within a parcel of land” for oil and gas development.  “The amendment (HB 507) is basically kind of like the stopgap,” Brundrett said. “…Over the last decade, there’s been issues that come up where a company is trying to put a drill package together that has partial state lands in it, and so they want to be able to try and negotiate that lease because it’s faster to do it that way…“So this amendment sort of creates that process to do it until the rules are promulgated from the land commission. Once the Oil and Gas Land Management Commission rules are finalized, then the law will revert to those rules and the law change will basically be moot at that point,” Brundrett said.

Report: Nearly $100 Billion Invested for Ohio Shale   --– Ohio’s shale gas industry has led the nation in growth for the past four years due to large Utica and Marcellus shale deposits, according to a new report released Friday by JobsOhio and Cleveland State University.The Ohio Shale Investment Report shows that the natural gas and oil industry has put nearly $100 billion in investments into the state. An investment of $2.5 billion was invested between last July and December alone, the report found.“Our natural gas and oil energy industry is something Ohioans can be proud of,” said George Brown, executive director of Ohio Oil Gas Energy Education Program. “This report shows not only all the work the men and women of this industry are doing, but the immense benefits that are brought to communities across Ohio.”The JobsOhio/CSU studies have been taking place since 2011, analyzing the natural gas and oil industry’s investments in relation to Utica Shale formation.Since the beginning of the series of study, an estimated $97.8 billion has been invested in the state of Ohio through December 2021.Other report highlights:

  • Total estimated royalties spent on Ohio properties during the second half of 2021 were nearly $1.2 billion (14% higher than the first half of the year)
  • 86 new wells were listed by the Ohio Department of Natural Resources as “drilled,” “drilling” or “producing” during the second half of 2021 (16.2% higher than the first half of the year)
  • Ascent Resources and Encino Acquisition Partners Ohio were the top producers during the time period in the state

“The cumulative investment in shale gas development over time has brought thousands of jobs to hard-working Ohioans and affordable energy to residential and industrial consumers,” said J.P. Nauseef, JobsOhio president and CEO. “Ohio has the resources, the regulatory environment, the talent, and the central location to continue to evolve as an international player in shale-related productivity.”Ohio Oil & Gas Energy Education Program said it is important to acknowledge the potential in Ohio as the current energy crisis continues. The organization believes Utica shale can both provide the nation with better energy opportunities and be used as an economic tool. The full report can be accessed here.

New EPA Rules on Methane Could Be a Win for Ohio's Economy -- The Environmental Protection Agency has released rules which would for the first time require regular inspections of all methane-emitting oil and gas production sites throughout the country. Groups backing the new rules said they will also pave the way for more jobs in Ohio's the natural gas industry.The rules are an update to standards the Biden administration released last year.Sarah Spence, executive director of the Ohio Conservative Energy Forum, said in addition to cleaner air, the changes could mean more employment in the methane-capture business, particularly in the state's Utica Shale region."We're already headquarters for two manufacturing firms and five service firms that deal in methane mitigation," Spence pointed out. "I think these rules will allow those companies to grow and to hire more Ohioans to work for them in those areas." In 2014, Ohio implemented laws requiring oil and gas operators to check for and fix equipment leaks to reduce air pollution. The nation's oil and gas industry emits at least 13 million metric tons of methane a year, according to research from the Environmental Defense Fund. Energy developers have said methane-capture equipment is costly, especially for smaller producers. Isaac Brown, executive director of the Center for Methane Emission Solutions, noted there is a burgeoning market for companies to provide technologies to help oil and gas companies address emissions."Jobs can be created to help companies comply with these rules," Brown emphasized. "Because these rules will result in more product being saved that can be brought to market, producers can also actually see their profits increase."

How EOG's Move into Ohio Utica Shale Will Affect Midstream | Marcellus Drilling News -- In 2020, EOG Resources, one of the largest oil and gas drillers in the U.S. (with international operations in Trinidad and China), sold *all* of its Marcellus assets, which were located in Bradford County, PA, to Tilden Resources for $130 million (see EOG Resources Sells Marcellus Assets for $130M, Exits Basin). EOG left the M-U building, so to speak. But the company couldn’t stay away. In November, we told you that EOG admitted to stealthily amassing 395,000 net acres in the Ohio Utica for very little money (see EOG Resources Accumulates 395K Acres in Ohio Utica for Under $500M). EOG calls its new position the “Ohio Utica combo play.” We later told you what the company means by that phrase (see EOG Resources has “Double Premium” Plans for Ohio Utica). Today we tackle the topic of how EOG’s Utica combo play will affect the midstream in Ohio.

We're not being protected from toxic brine - The Steubenville Herald-Star – Randi Pokladnik - Since fracking first appeared in the Appalachian counties of Southeastern Ohio, residents have witnessed the green rolling hills become an industrial landscape. Today, fracking wells, compressor stations and pipelines are now a major part of that landscape. The rural roads are now congested with dangerous truck traffic. Local residents must dodge semi-trucks carrying sand and chemicals to fracking well pads and brine tankers transporting produced fluids away from the sites to Class II injection wells.  Those produced fluids are innocuously referred to as brine even though the oil and gas industry as well as regulators know this fluid is much more than just a mixture of halide salts. This waste contains flowback water — a chemical cocktail of benzene, arsenic, formaldehyde, lead, mercury, PFAS and many other proprietary chemicals. The liquid waste also contains toxic metals, radioactive materials and brine resulting from contact with the ancient rock formation that is being fracked. According to a 2018 study out of Dartmouth College, in just hours, radioactive Radium 226 and Radium 228 can be leached out of the rock and into the saline solution. As the waste is pulled to the surface to be disposed of, the water-soluble radioactive isotopes hitch a ride as well.   During a June public meeting with Ohio’s Department of Natural Resources, the risks of transporting this toxic fluid on our state, county and township roads was questioned. The response of ODNR was to deflect the responsibility on to Ohio’s Department of Transportation.  […] In 1983, an agreement between Ohio and U.S. EPA gave Ohio authority over the oil and gas waste disposal program.  Sadly, the state has shown time and time again it cannot carry out these responsibilities, failing to protect the citizens of the state from this toxic brew. These failures include: A poor enforcement record, incidents of wastes migrating from the injection formation and unlawful waste disposal.  The well disposal program excludes citizens from participating in permit decisions. Low-income Appalachian Ohioans are being disproportionately affected as the majority of disposal wells are located in their communities. “More than 18 billion gallons of waste fluid from oil and gas is generated annually in the USA” according to the American Petroleum Institute.  Horizontal unconventional wells can contain water soluble Radium-226 in concentrations ranging from 40 to 26,000 pCi/L. The safe drinking water standard for Ra-226 and Ra-228 is 5 pCi/L. This toxic radioactive waste is being pushed down injection wells in Ohio. In addition, much of the waste injected into Ohio’s Class II wells comes from neighboring states, including Pennsylvania and West Virginia.  Recently, the Buckeye Environmental Network, the Sierra Club, Earthjustice and several frontline grassroot groups, petitioned the United States Environmental Protection Agency to rescind the primacy granted to ODNR’s Division of Oil and Gas Resources Management for permitting and monitoring Class II injection wells in the state of Ohio. This is because the ODNR has failed to meet the basic requirements under the Safe Drinking Water Act and failed to carry out its environmental justice obligations under federal law and Executive orders.

Natural Gas the Answer to Reducing Emissions, Argues CNX in 'Appalachia First' Plan - Natural gas should be viewed not as a bridge fuel, but as a catalyst to the energy transition domestically and abroad, according to the new “Appalachia First” vision unveiled by CNX Resources Corp. The Pittsburgh-based firm, which produced 1.67 Bcfe/d from the Marcellus and Utica shales during the third quarter of 2022, is arguing against a renewables-focused strategy for the region. “The nation and world are waking up to stark energy realities: energy scarcity, deterioration of our power grid and energy inflation stoking wider inflation,” said CEO Nick Deluliis. “Policy often relies too heavily on applications such as wind, solar and electric vehicles that can present large life cycle carbon footprints, require supply chains stretching thousands of miles, are costly and face serious challenges when scaling in regions like Appalachia. [Actionable Insight: Did you know that NGI is one of only two Price Reporting Agencies that include trade data from the Intercontinental Exchange? Find out more.] “If we don’t get energy and climate policies right, our economic competitiveness will be stifled, the environment will be worse off, and we will end up enabling our adversaries to wage war and forcing leaders to negotiate energy supplies from dictators and despots.” He cited that natural gas has driven a 40% reduction in Pennsylvania’s electricity-related carbon emissions since 2005, and that gas’ share of the PJM Interconnection LLC electricity mix grew from 14% to 38% between 2011 and 2021. Over the same span, the combined contribution from wind and solar grew from about 1% to just under 4%. “There is a better, simpler and more logical way,” Deluliis said. “Appalachia can be the launchpad to a more efficient and sustainable future catalyzed by lower carbon intensity natural gas. This proud region and its people should be the solution to deliver reliable and affordable energy – our region’s abundant energy resources can and must be used more effectively to prioritize the improvement of the human condition, the environment, the nation and the world.” This approach, Deluliis said, represents “a clear roadmap to transform key sectors of our economy and workforce while also changing the world for the better.” According to CNX, Appalachia should leverage its immense gas reserves to bolster the region’s economy while reducing emissions. Appalachia has the potential to “transform the sectors of aviation, plastics, rail, cargo, mass transit, trucking, and fleet and passenger vehicles by displacing higher-carbon fuels with locally produced natural gas,” the company said.

US Gas Leak at Equitrans Well in Pennsylvania Adds Climate Pressure - While diplomats in Sharm El-Sheikh were hammering out a historic agreement last month to help developing nations cope with the crippling consequences of a warmer planet, one of the biggest US climate disasters in recent years was unfolding in a rural corner of Pennsylvania. A leak from a 1 5/8-inch (4.1 centimeter) vent on a natural gas storage well operated by Equitrans Midstream Corp. was discovered on Nov. 6 and lasted for 13 days, allowing more than 1 billion cubic feet to escape. Methane, the primary component of natural gas, has a devastating impact on the climate if released directly into the atmosphere, where it has more than 80 times the warming power of carbon dioxide in its first two decades. That single Equitrans release effectively erased emissions gains from about half of the 656,000 electric vehicles sold in the US last year. The incident is one of the biggest blows to the credibility of the US gas industry since the Aliso Canyon leak that began in late 2015 in California and lasted more than 100 days. The magnitude of the Equitrans release, and the operator’s inability to halt it quickly, intensifies scrutiny on an industry the International Energy Agency has said must do more to curb deliberate and accidental releases if it wants to play an active role in the energy transition. Leaks are one of the main climate risks facing gas suppliers, and a new generation of multispectral satellites has made it easier to spot major emissions, leading to a greater understanding of just how pervasive they are. Bloomberg News has used satellite observations since July 2020 to identify about 70 methane releases linked to the energy and waste sectors from Argentina to Turkmenistan, including almost two dozen in the United States. The coverage has triggered government investigations in the US and Bangladesh, but most methane releases worldwide still go unreported. “The fact that massive releases are persisting even in regions where they're properly quantified speaks to the scope of the challenge,” said Antoine Vagneur-Jones, head of trade and supply chains at research company BloombergNEF.

A century-old law poses problems for New England’s energy supply this winter and there’s a push to find a way around it - — A century-old federal law designed to protect the US maritime industry is having a chilling effect in New England in the wake of the Ukraine war, helping drive up home heating oil prices and threatening to cause supply shortages that could become severe enough to trigger rolling blackouts if this winter is much colder than usual. Known as the Jones Act, the law requires that any goods transported between US ports be carried on domestically built and owned ships manned by American crews. That means foreign tankers can bring shipments to Boston from abroad but not from the Gulf Coast. And since the war has strained global shipping capacity, those stringent requirements are becoming a significant obstacle to delivering heating oil and liquefied natural gas to New England because there is only a small fleet of US commercial vessels available and limited ability to bring in the fuels by pipeline.“If it gets cold, the lights are going to go out,” predicted Sean Cota, head of NEFI, a Massachusetts-based organization of independent heating oil dealers in the region. “There’s no way you can move enough energy via pipeline, trains, and trucks to make up what would be needed in vessels if it’s cold.”Cota and other industry officials, including Joe Nolan, chief executive of Eversource, New England’s largest utility, joined all six New England governors in calling for President Biden to temporarily suspend the Jones Act. Doing that, they argue, would allow foreign tankers to carry shipments from Gulf Coast facilities to ports in Boston and the Northeast.But the Biden administration has been noncommittal and would have a tough time helping because of the red tape required for any exemptions. For one, a waiver must be “in the interest of national defense.” Moreover, recent changes now require a waiver for each shipment, which requires complicated assessments of the individual circumstance, rather than a blanket exemption that could extend to a sustained number of deliveries.

Natural gas project including pipeline between Springfield, Longmeadow up for public comment - A virtual public comment session is being held Wednesday evening on a natural gas project, which includes a new pipeline between Longmeadow and Springfield, Massachusetts. The state's Energy Facilities Siting Board is reviewing the proposal by the utility company Eversource. It calls for a new gas delivery station in Longmeadow and the pipeline, which would run from that facility to another in Springfield. The company said the project is needed to back up an existing pipeline, which is more than 70 years old. Naia Tenerowicz is an organizer with the Springfield Climate Justice Coalition. She said the organization has many concerns about the project, including what the possible leak of chemicals from natural gas could do to the environment. "Methane is an extremely potent greenhouse gas,” Tenerowicz said. “This is going to increase the amount of greenhouse gas emissions that we'll have in Springfield, which will worsen the climate crisis." Eversource spokesperson Priscilla Ress said alternative sources of energy are not ready yet to handle the load if something were to happen to the current natural gas supply. "We see clean energy as absolutely...that is the future, but in the meantime, we have a mission to make sure that we are serving our customers and making sure that they have a reliable source of energy," Ress said. The siting board will also take written comments on the proposal through Jan. 2, but some have already been coming in. State Sen. Adam Gomez, of Springfield, wrote to the board to express his opposition. "I continue to remain opposed to the pipeline in which the Eversource Project would degrade air quality, increase the risk of fires and explosions in the community, contribute to detrimental climate change, and increase our reliance on fossil fuels," Gomez wrote.

Senate to vote on Manchin's permitting overhaul -  Sen. Joe Manchin will get a floor vote on his environmental permitting overhaul, Senate Majority Leader Chuck Schumer told reporters Tuesday. It’s a move that will roil environmental groups, but the bill has a shaky outlook on the floor, with an unusual partnership of progressives and Republicans ready to oppose it. Manchin’s legislation will be considered as an amendment to the annual National Defense Authorization Act. It’s an attempt to uphold a bargain the West Virginia Democrat made with leadership to vote on his reform of permitting laws for energy projects in exchange for supporting the Inflation Reduction Act in August. “We’re gonna vote on that amendment. As you know, Republicans have blocked it in the House, even though permitting reform is something that they’ve always supported in the past,” Schumer (D-N.Y.) said. “So I hope they’ll help us.” Some Senate Republicans have already said they would support Manchin’s bill, but others are maintaining their opposition. Sens. John Cornyn (R-Texas) and Jim Inhofe (R-Okla.), ranking member of the Armed Services Committee, both indicated Tuesday they would vote against the amendment. Manchin’s proposal would make it easier to permit energy projects across the board, including fossil fuels and renewables. It would also authorize the Mountain Valley pipeline, a contentious project that has long been a top priority for Manchin and other West Virginia lawmakers. But he’s had trouble building a coalition to support it. Progressives are furious that Democrats would consider legislation to speed permits for fossil fuel projects, while Republicans oppose Manchin’s attempt to give the federal government more power over transmission permitting.

West Virginia gas pipeline permitting battle not over in Congress --— Efforts to complete a big natural gas pipeline in West Virginia and Virginia have been dealt another setback. Efforts to get this item in the National Defense Bill failed Thursday night, but senators fight on. National Defense Bill nears passage; includes benefits to West Virginia At issue is a bill in Congress to speed up the permitting process for energy projects. In this case, that could fast-track the completion of the Mountain Valley Pipeline, which runs from northern West Virginia to southeast of Roanoke, and eventually into North Carolina. Supporters say it will offer enormous amounts of natural gas to fuel this country, and sell to our allies overseas. “Part of that is what they call energy security, energy independence. you cannot be a superpower in the world if you do not have energy independence. And you can’t be secured if you don’t have energy independence,” said Sen. Joe Manchin (D) West Virginia. “I don’t think it’s dead in other words. I think it’s something we will have to come back to, time and again until we are successful,” said Sen. Shelley Moore Capito (R) West Virginia. Senators could add another amendment to the overall spending bill, to include the pipeline permitting, before a final vote next week. A similar amendment failed in the Senate Thursday night. Many environmentalists oppose the measure out of concerns over air and water pollution. Last week, the controversial Keystone Pipeline had a leak in Kansas, that dumped thousands of barrels of oil in that state. The temporary spending bill to keep the government open only lasts for one week. So you can expect this pipeline measure may be added to the entire spending bill when it comes up for a final vote next week.

US FERC to act on backstop transmission siting, long-running gas pipeline disputes - The US Federal Energy Regulatory Commission is poised to act on transmission siting, key pipeline rate disputes, and two important natural gas pipeline certificates at its last meeting of the year Dec. 15, potentially Democrat Richard Glick's final session as chairman. Glick's nomination to serve a second five-year term has been stalled by US Senator Joe Manchin, Democrat-West Virginia, who announced in November that he is not "not comfortable" holding a confirmation hearing for US President Joe Biden's pick to continue helming the commission. Glick must leave FERC if he is not confirmed before the 117th Congress adjourns. As FERC chairman, Glick has launched multiple important rulemakings designed to speed the expansion of the US electric transmission system. Momentum in those proceedings could slow next year with FERC evenly divided along a 2-2 partisan split. Glick has sought buy-in from state utility regulators who play a central role in the siting and permitting of power lines needed to accommodate more renewable energy. Meanwhile, the US Congress clarified in the 2021 Infrastructure Investment and Jobs Act that FERC has backstop siting authority when states either fail to act on or deny applications for transmission projects sited in national-interest corridors designated by the US Department of Energy. The legal status of FERC's backstop siting authority on transmission has remained in limbo since the US Court of Appeals for the 4th Circuit ruled in 2009 that the commission read too much into its authority granted under the Energy Policy Act of 2005. Glick has stressed that FERC's members do not want to use the commission's backstop siting authority if that can be avoided. Nevertheless, the commission listed what appears to be a proposed update (RM22-7) to its backstop siting regulations as the first item on its Dec. 15 meeting agenda. The agenda notice indicates that the regulations would apply to developers who petition FERC to exercise its backstop siting authority, a step that no party has taken since the 4th Circuit ruling. FERC is also poised to act on a complaint (EL22-34) filed by the Office of Ohio Consumers' Counsel against efforts by the American Electric Power Service, American Transmission Systems, and Duke Energy Ohio to receive a 50-basis point return on equity for participating in a FERC-jurisdictional regional transmission organization.

Energy Transfer Cleared to Start Service on Gulf Run Pipeline in Louisiana - Federal regulators have cleared Energy Transfer LP (ET) to start service on the 1.65 Bcf/d Gulf Run natural gas pipeline system in Louisiana, opening a path to meet increasing demand along the Gulf Coast and in international markets. The project is underpinned by a 1.1 Bcf/d commitment from anchor shipper Golden Pass LNG, which is under construction on the Texas coast. FERC, which authorized the project last year, approved ET’s request to start service. The 42-inch, 135-mile system will receive natural gas from ET’s intrastate and interstate pipeline network, including production from the Haynesville, Marcellus, Utica and Barnett shales and the Permian Basin. Gulf Run consists of two zones, one connecting the Carthage Hub to the Perryville markets, and another that extends south to connect with Golden Pass and ET’s Trunkline system. The Zone 1 segment has bi-directional flow capabilities, allowing it to deliver significant volumes to Perryville as well as Golden Pass and the Trunkline system. The Golden Pass liquefied natural gas terminal remains on track to start production in 2024, when the first of three liquefaction trains is expected to start ramping up. It is scheduled to enter full service sometime around 2025. The project is a joint venture of QatarEnergy and ExxonMobil. Along with Venture Global LNG Inc.’s Plaquemines LNG export project, which was sanctioned this year and is expected to come online in 2025, Golden Pass would boost peak U.S. export capacity to more than 18 Bcf/d from current peak capacity of about 14 Bcf/d.

Energy Transfer Announces Gulf Run Transmission Is In Service  -- Dallas-based Energy Transfer LP today announced its subsidiary, Gulf Run Transmission LLC has received FERC approval to place the Gulf Run pipeline in service delivering domestically produced natural gas from key U.S. producing regions to meet the rapidly growing demand along the Gulf Coast and international markets. The newly constructed 135-mile, 42-inch natural gas pipeline in Louisiana has a capacity of 1.65 Bcf/day, with potential growth opportunities. Gulf Run receives natural gas from Energy Transfer’s extensive intrastate and interstate pipeline network, including production directly from the Haynesville Shale. Volumes originating from all the major natural gas basins in the U.S. have access to the pipeline, including the Permian Basin, the Barnett Shale, the Marcellus and Utica shales, East Texas, the Arkoma and the Anadarko basins. The pipeline consists of two zones. Zone 1 connects the Carthage Hub to the Perryville markets and Zone 2 extends south and connects to Golden Pass Pipeline and to Energy Transfer’s Trunkline system. The Zone 1 segment has bi-directional flow capabilities, providing the ability to deliver significant volumes to Perryville as well as to the Golden Pass and Trunkline systems. Energy Transfer owns and operates approximately 120,000 miles of pipeline and related infrastructure across 41 states transporting natural gas, crude oil, natural gas liquids and refined products. Energy Transfer operates more than 8,800 miles of pipeline in Louisiana. Energy Transfer LP (NYSE: ET) owns and operates one of the largest and most diversified portfolios of energy assets in the United States, with a strategic footprint in all of the major U.S. production basins. Energy Transfer is a publicly traded limited partnership with core operations that include complementary natural gas midstream, intrastate and interstate transportation and storage assets; crude oil, natural gas liquids (“NGL”) and refined product transportation and terminalling assets; and NGL fractionation. Energy Transfer also owns Lake Charles LNG Company, as well as the general partner interests, the incentive distribution rights and 28.5 million common units of Sunoco, and the general partner interests and 46.1 million common units of USA Compression Partners, LP

Here's where Louisiana's LNG facilities will be located Liquefied natural gas is a booming industry in Louisiana, and it’s only set to grow in the coming years. Three of the nation’s seven LNG export terminals are already in operation here, and 10 more new facilities are scheduled to be open by the end of the decade, if all goes to plan. Another one is in the works but doesn't have an announced timeline yet. The new projects are in various stages. Some are under construction, while others are still awaiting federal or state permits. Others have received their permits but have yet to move forward as their parent companies wait to make a final investment decision. The projects are underway amid high demand for LNG worldwide. Industry supporters say it's the best way to transition from dirtier fuel sources like coal and to wean Europe off Russian natural gas following the country's war in Ukraine. However, environmental advocates say natural gas is still a fossil fuel that spews out far too many emissions to be considered a clean energy source. Here is a map of Louisiana’s existing and proposed LNG facilities and where they will be located should they come to fruition as expected.

New natural gas storage facility coming to Spindletop Beaumont -— A new natural gas storage facility is coming to Spindletop in Beaumont, allowing for more jobs and economic growth in Southeast Texas. Caliche Development Partners bought the Golden Triangle storage facility in November and they're hoping to expand their operations. At this moment, the facility has two salt caverns that store natural gas, but the dome can hold up to nine caverns. In 1901, Spindletop changed Beaumont forever. "Beaumont is the cradle of the oil and gas industry here in our state and because of that, there's a tremendous amount of infrastructure here," said CEO of Caliche Development Partners, David Marchese. "This is the top of the facility. Underneath this wellhead about 2,000 feet underground is a formation the size of the Empire State Building," Marchese said. The cylinder-shaped formation stores natural gas, which is usually stored underground. Darrell Hall, Vice President of Operations with Caliche, has worked on the Spindletop dome for 15 years. "A lot of new businesses have come on. Caliche came in, they brought a lot of excitement to the dome and went from mostly all natural gas or gas liquids to our storage to to liquid storage," Hall said. Under the new management, the facility is also expected to expand.

January NYMEX Natural Gas Futures Contract Closed at $6.587 on Monday, December 12th - Monday, December 12th saw the January NYMEX Natural Gas Futures Contract open at $6.874, nearly sixty-three cents above Friday’s closing price of $6.245. Moving higher prior to the open and recording a near two-week intraday high of $6.934 out of the gate, weekend forecasts all but solidified the end of month bullish forecasts while adding the possibility of frigid air moving in from Canada. Pulling back as the day drew on, crossing midday at $6.848 and marking the intraday low of $6.521 at 2:15PM, January closed higher on Monday at $6.587. As of 7:10AM EST this morning in Globex, WTI Crude was up 19 cents; Natural Gas was up 17 cents; Heating Oil was up three cents; and Gasoline was up one cent.

Natural Gas Futures Rally, but Warmer Weather Models Trim Early Gains; PG&E Cash Hits $75 - After five straight days in positive territory, natural gas bulls may struggle to keep momentum going amid continued weather model volatility. Though they managed to eke out another substantial price increase on Tuesday, warmer trends in the weather models took a hatchet to early gains. The Nymex January gas futures contract reached a $7.105 intraday high but eventually settled at $6.935/MMBtu, up 34.8 cents on the day.Spot gas prices also moved up sharply on Tuesday, with ongoing chilly weather and supply constraints fueling a surge to $75.00 in Northern California. NGI’s Spot Gas National Avg. jumped $2.365 to $14.000. After pummeling the West Coast, a major winter storm is expected to dump more than two feet of snow in parts of the central United States this week. The accompanying spike in heating demand has kept traders on edge awaiting clarity on additional cold blasts expected to blanket the Lower 48 beginning next week. So far, the models have been choppy, trending colder or warmer daily.As of midday Tuesday, the Global Forecast System model remained the coldest, but it shed a handful of heating degree days (HDD) to align better with the European model, according to NatGasWeather. The forecaster said the first in a series of frigid blasts is expected to sweep across the United States this weekend. Overnight lows could plunge more than 10 degrees below zero across the northern half of the country and into the upper teens in Texas and the South.  While this would likely result in strong national demand, NatGasWeather pointed out that the data are not not quite as cold as they had been. That said, the models remained impressively cold with an Arctic blast hitting the Lower 48 next Wednesday through Christmas Day (Dec. 21-25), that would send overnight temperatures in the Midwest and Plains more than 20 degrees below zero. The firm cautioned, though, that trends once viewed as bullish late in the 15-day outlook have had the tendency to warm as they roll into the front of the forecast. As such, the system needs close monitoring since there’s potential the Arctic front advances deep into the southern United States, particularly Texas, NatGasWeather said. The forecaster noted that grid stability in the Electric Reliability Council of Texas (ERCOT) could be in play given the crippling cold. Meanwhile, Mobius Risk Group said HDDs are expected to be more than 60 higher than the 30-year norm — not to mention more than 140 higher than a year ago. As such, there is a strong possibility that 2022 will end with less than 3 Tcf in storage. Of course, the market also continues to look for clues as to when Freeport LNG may return. The liquefied natural gas exporter has targeted late December for a restart of its terminal on the upper Texas coast.  On Tuesday, it stuck to that timeline even after FERC sent a 16-page letter asking it to address dozens of issues before operations can resume. The Federal Energy Regulatory Commission sent two separate documents requesting information on 64 questions, only one of which was made available to the public because of security reasons.

U.S. natural gas futures decline by 7% - On Wednesday, U.S. natural gas futures fell by roughly 7% as a result of expectations for less chilly weather than had been anticipated in late December and after failing to overcome significant technical price resistance for the third straight day. Meanwhile, as freezing weather and snowfall cover portions of California and gas pipeline failures and limits restrict supplies into the region, U.S. West Coast power and gas prices have almost tripled over the previous few weeks and were on track to record multiyear annual highs. Even though production was on course to reach a two-month low due to extreme weather from North Dakota to Texas, futures prices dropped as some oil and gas wells froze. In the upcoming weeks, the cold weather should require utilities to draw more gas from storage than typical. Gas stockpiles were roughly 1.6% below the seasonal average for the previous five years (2017–2021). Front-month gas futures ended the day at $6.430 per million British thermal units, down 50.5 cents or 7.3%. (mmBtu). For the third day in a row this week, the market made an attempt to push the contract over the 200-day moving average but was unsuccessful. At the Dutch Title Transfer Facility (TTF) in Europe and the Japan Korea Marker (JKM) in Asia, gas was trading for $41 and $33, respectively, per mmBtu (JKMc1). Average gas output in the Lower 48 States of the United States has increased to 99.7 bcfd so far in December, up from a monthly record of 99.5 bcfd in November, according to data source Refinitiv. On a daily basis, however, production was expected to decrease by 2.3 bcfd to a preliminary two-month low of 97.3 bcfd on Wednesday due to well freeze-offs brought on by frigid weather that has blanketed sections of Texas, Oklahoma, and North Dakota. The daily output would have decreased by the most since mid-October.

U.S. natgas jumps 8% as LNG exports rise, some wells shut due to cold | (Reuters) - U.S. natural gas futures jumped about 8% to a two-week high on Thursday in a volatile week of trade on a bigger than expected storage draw, an increase in gas flows to liquefied natural gas (LNG) export plants and a drop in output as extreme cold from North Dakota to Texas caused oil and gas wells to freeze. Prices spiked despite forecasts for milder weather and lower heating demand in late December. The U.S. Energy Information Administration (EIA) said utilities pulled 50 billion cubic feet (bcf) of gas from storage during the week ended Dec. 9, exceeding the 45-bcf decline analysts forecast in a Reuters poll and compared with a decrease of 83 bcf in the same week last year and a five-year (2017-2021) average decline of 93 bcf. Last week's decrease cut stockpiles to 3.412 trillion cubic feet (tcf), or 0.4% below the five-year average of 3.427 tcf for this time of year. Traders said the biggest uncertainty for the market remains when Freeport LNG will restart its LNG export plant in Texas. Despite the Freeport shutdown, the amount of gas flowing to U.S. LNG export plants hit 13.0 bcfd on Thursday, the most since June 4 - four days before Freeport shut. That is because the nation's six other big export plants were operating near full capacity. In a volatile week of trade, front-month gas futures for January delivery on the New York Mercantile Exchange rose 54.0 cents, or 8.4%, to settle at $6.970 per million British thermal units (mmBtu), their highest close since Nov. 29. So far this week, gas prices have jumped over 5% on Monday and Tuesday and dropped over 7% on Wednesday. Gas futures were up about 84% so far this year as much higher global prices feed demand for U.S. exports due to supply disruptions and sanctions linked to Russia's war in Ukraine. Gas was trading at $42 per mmBtu at the Dutch Title Transfer Facility (TTF) in Europe and $33 at the Japan Korea Marker (JKM) in Asia. Data provider Refinitiv said average gas output in the U.S. Lower 48 states rose to 99.6 bcfd so far in December, up from a monthly record of 99.5 bcfd in November. On a daily basis, however, output was on track to drop about 3.4 bcfd over the past three days to a preliminary two-month low of 97.2 bcfd on Thursday as freezing weather blankets parts of Texas, Oklahoma and North Dakota, causing well f

Bone-Chilling Cold Takes Toll on Production, Driving Weekly Natural Gas Prices Higher - Natural gas prices exploded higher during the Dec. 12-16 trading period amid the first intimidating cold blast to hit the Lower 48 since the start of winter. With production curtailments to boot because of wellhead freeze-offs, NGI’s Spot Gas National Avg. jumped $4.070 to $11.645.  Natural gas futures ended the week in positive territory – barely – as wild swings occurred throughout the week with seemingly every run of the weather models. At Friday’s close, the January Nymex gas futures contract settled at $6.600, up only 1.3 cents from Monday’s settlement. Notably, the prompt month had surged as high as $7.105 earlier in the week. With frigid air penetrating the West Coast resulting in continued solid gas demand, massive price spikes continued throughout the region during the Dec. 12-16 trading week. The price gains are significant since they are on top of what were record levels the prior week. PG&E Citygate, in the northern part of California, led the way as prices hit a fresh high of $75.00 on Tuesday. Cash prices experienced swings in both directions in the days since, ultimately averaging $8.980 higher week/week at $35.890. Prices also were strong in Southern California, where the SoCal Border Avg. picked up $10.495 on the week to average $37.050. The rally extended across the Desert Southwest and into the Rockies as markets throughout the western United States competed for limited supplies. As previously detailed by NGI, significant cold has slammed the region this winter. Bitter temperatures along with heavy snowfalls, gusty winds and widespread rain have fueled heating loads much earlier in the year than normal. Importantly, Pacific Gas & Electric Corp. (PG&E) in the summer of 2021 reclassified 51 Bcf of storage inventories to cushion gas, rather than working gas. Without replenishing those stocks, utilities have few molecules they can call on to meet heightened demand. But that doesn’t mean they won’t pull on what is available. Meanwhile, there’s also a shortfall of pipeline capacity to move gas from the Permian Basin and the Rockies westward toward California and the Pacific Northwest. Against that backdrop, El Paso Natural Gas – the primary conduit for moving Permian gas west – has often restricted gas flows because of maintenance. The pipeline also has had a standing 600 MMcf/d curtailment in place since an explosion last year. “The bottom line: pipeline explosions and the related extended forces majeure, not to mention old-fashioned bottlenecks, have eroded what flexibility was left,” said RBN Energy LLC’s Sheetal Nasta, managing editor. Given that all it’s taken for West Coast prices to soar to such historic heights was a little cold weather and upstream gas limitations, gas supply constraints out West are getting worse, according to Nasta. “It’s likely the market will continue to see constraint-driven pricing during high-demand periods and during frequent outages as legacy infrastructure ages, at least until there is some relief in the way of incremental pipeline capacity.”

Coast Guard Monitors Oil Spill Response Near Lake Charles, Louisiana -  The Coast Guard is monitoring the response to an oil spill in the vicinity of Calcasieu Point Landing near Lake Charles, Louisiana, Wednesday. Coast Guard Marine Safety Unit Lake Charles pollution responders received a report at approximately 8:15 a.m. Monday of an unknown quantity of oil in the water in an industrial canal north of Choupique Island. Coast Guard pollution responders dispatched to the location alongside representatives from the Louisiana Department of Wildlife and Fisheries (LDWF), the Calcasieu Parish Sheriff’s Office Marine Division, the Louisiana Department of Environmental Quality (LDEQ), and the Lake Charles Fire Department. On-scene investigators ascertained that the discharge escaped from the secondary containment at Martin Energy Services. Personnel from Martin Energy Services secured the source of the spill and estimated that approximately 3,500 gallons of used lubricant oil entered the water. The oil spill response organization hired by Martin Energy Services, OMI Environmental Solutions, placed over 2,000 feet of boom and contained the oil spill along the banks of the Lake Charles Industrial Canal. LDWF personnel rescued seven oiled pelicans from the site of the spill. Environmental assessments are still ongoing. The Coast Guard temporarily halted traffic along the Intracoastal Waterway during the initial assessment and cleanup; however, the Intracoastal Waterway is not impacted and has since been reopened to marine traffic.

Oil Wells Creeping into Texas Cities Herald Shale Era Twilight - Each morning when Michael Quinn pulls into the parking lot of the luxury apartment complex he manages in West Texas, an unsightly vision blots the horizon: a 24-foot-high insulated wall. The barrier, covered in a sand-colored tarp, is designed to muffle noise from an oil-well site across the road. The wall, and an accompanying surge in urban drilling, is the latest sign that America’s shale fields are reaching middle age. An uptick in drilling within the city limits signals that the very best rock in one of the world’s most prolific oil fields has already been tapped. In the shale boom’s early days, with so much crude-soaked land up for grabs elsewhere in the Permian Basin, there was little reason to deal with the red tape needed to bore underneath populated areas. But with over two-thirds of the Permian’s premium land now drilled, producers are seeking more permits than ever to burrow beneath Midland and its 130,000 residents. Observers have long been predicting shale’s demise or heralding its rebirth. But this time is different: After years of honing their craft to boost output, producers in the Permian’s two main zones are pumping less oil per foot drilled in each new well, not more. Output guidance from Exxon Mobil Corp., Chevron Corp. and Devon Energy Corp. has shown that US shale growth is coming in at the low end of expectations. Analysts say the Permian could reach a production plateau within five years. That’s a problem that reaches far beyond Texas. US shale, led by the Permian, has provided 90% of global oil output growth in the past decade, according to research firm Enverus. It made the US the biggest producer ahead of Saudi Arabia. A shale slowdown means the world can no longer rely on the US to be its swing oil supplier, capable of ramping up or down quickly to temper a volatile market. It complicates the Biden administration’s efforts to tame pump prices, and it hands more power back to OPEC as Russia’s invasion of Ukraine upends oil and gas supply. US shale’s spectacular growth — adding more crude to global markets from 2012 to 2020 than the entire current production of Iraq and Iran combined — had become a thorn in the eye of OPEC, which saw its market dominance threatened like never before. But US output tumbled at the start of the Covid-19 pandemic and is still about 1 million barrels a day below the record 13 million reached in early 2020. Next year, growth is likely to be around 560,000 barrels a day, according to Enverus. That’s despite crude prices averaging more than $90 a barrel this year, far above what producers need to break even. Skyrocketing costs for labor and equipment, as well as pressure to return more cash to shareholders, are partly to blame for drillers’ restraint. Rising interest rates, meanwhile, likely herald the end of cheap money for shale producers looking to finance even modest growth plans. But a new, more troubling trend has emerged in recent weeks: The rock itself is yielding less oil. Wells drilled this year produced between 8% and 13% less oil per lateral foot than a year earlier, according to BloombergNEF, the first major reversal after a decade of productivity gains. Pioneer Natural Resources Co., one of the biggest Permian operators, recently overhauled its drilling plan after executives were “not satisfied” with its well performance this year. Laredo Petroleum Inc. said some of its production was hurt by interference from other wells nearby. A higher proportion of drilling is now done by private companies, which aren’t beholden to shareholder pressure to boost buybacks and dividends. But that’s contributing to lower productivity, Private producers tend to have less-desirable acreage, he said. Some public and private companies are using a method known as multi-zone development, which means they’re drilling several layers of shale at once to improve efficiency, but in doing they’re also tapping their less-productive rock. BMO estimates that most of the top-tier land has already been developed in the Permian and in the Bakken of North Dakota, the top-producing shale regions. That leaves explorers with a lower inventory of the most valuable yet-to-be-drilled sites. “We’re going to run out of inventory in the next four to six years,” “We probably saw it earlier in other shales, which is why we left those other shales and moved so much activity into the Permian. It’s now rearing its ugly head in the Permian.”

Fourth Strongest Quake In Texas History Rattles Nation's Largest Fracking Region - A magnitude 5.4 earthquake rattled parts of the Permian basin on Friday. The area is the largest oil-producing region in the US, located in West Texas -- and has more fracking operations than anywhere in the world. The US Geological Survey said the quake struck northwest of Midland around 5:35 pm local time, and three minutes later, a tremor of magnitude 3.3 followed. It's the second time in 30 days that a sizeable quake has hit the West Texas region. The last was Nov. 16, when a 5.3-magnitude earthquake hit the area. "I thought it was the wind until I realized the wind wouldn't be making the light fixtures sway. Midland will get tremors that are rarely even felt but that was a full blown earthquake," someone in West Texas tweeted. On Friday evening, the National Weather Service's Midland tweeted: "We just felt an earthquake here at the office! While we don't actively monitor or track earthquakes ... but this would be the 4th strongest earthquake in Texas state history!" Earthquakes have been linked to fracking operations. Latest data via Bloomberg shows shale oil production in Permian Basin has jumped to a record high.

The U.S. Shale Boom Is Officially Over- The days of explosive growth in U.S. shale oil production are over. American oil production is rising, but at a much slower pace than it did before the 2020 crash, and at lower rates than expected a few months ago. The new priorities of the shale patch – capital discipline and a focus on returns to shareholders and debt repayments – have coupled with supply chain constraints and cost inflation to drag down U.S. oil production growth. The Biden Administration’s mixed signals to the American oil and gas industry are not motivating U.S. producers, either. Many are reluctant to commit to spending more on drilling when there isn’t any medium-to-long-term vision of how the U.S. oil and gas resources could be used to boost America’s energy security and help Western allies who depend on imports. This year, the U.S. Energy Information Administration (EIA) and various analysts have been downgrading their forecasts of crude oil production for 2022 and 2023. Although the EIA still expects output to set a new annual average record next year, it has significantly revised down its projections since the start of this year.Oil firm executives, for their part, say the U.S. Administration’s policies and anti-oil rhetoric, inflation, contractor time delays, and regulatory uncertainty are negatively impacting drilling and production planning.The EIA expects U.S. crude oil production to average 11.7 million barrels per day (bpd) in 2022 and 12.4 million bpd in 2023, which would surpass the record high set in 2019, per the November Short-Term Energy Outlook. Despite the expectation of a record output next year, the EIA has downgraded the numbers several times in 2022 so far. The latest cut is a massive 21% reduction in the growth estimate, according to calculations by Reuters.In the October forecast, the EIA had already downgraded the average production estimate for 2023 to 12.4 million bpd from the September forecast of 12.6 million bpd.“Lower crude oil production in the forecast reflects lower crude oil prices in 4Q22 than we previously expected,” the administration said in October.Weeks before the Russian invasion of Ukraine, which upended global energy markets, Enverus Intelligence Research expected U.S. oil production growth to accelerate in 2022 above around 900,000 bpd.However, inflation and supply-chain delays from the second quarter onwards have materially worsened the outlook on U.S. crude oil production growth. Enverus Intelligence Research (EIR) cut this month its forecast for U.S. production growth, due to “the headwinds created by oilfield services limitations, the risk of recession and reduced performance from wells drilled recently in the Permian Basin.” Therefore, the Lower 48 oil production forecast has been significantly downgraded and EIR now expects growth of around 450,000 bpd exit-to-exit in 2022 and 560,000 bpd growth for 2023.

With U.S. shale oil boom over, can world production climb?  -- Prior to the pandemic-induced downturn in world oil production, U.S. oil production growth was responsible for 98 percent of the increase in world production in 2018. Almost all of that growth resulted from rapid increases in shale oil production which accounted for 64 percent of U.S. production.   Fast forward to today when has declared that "The U.S. Shale Boom Is Officially Over." The reasons cited mostly have to do with management "discipline" regarding capital expenditure in favor of shareholder payouts and complaints about "anti-oil rhetoric" and "regulatory uncertainty." But there might just be another reason for the slowdown in shale oil production in the United States: There isn't as much accessible and economical shale oil underground as advertised. Earth scientist David Hughes laid out his case for this view in his "Shale Reality Check 2021." (For a summary of Hughes' report, see my piece from December 2021 entitled, "U.S. shale oil and gas forecast: Too good to be true?")  There may be other sources of oil worldwide that will somehow make up for the significantly lower growth in U.S. shale oil production. But no other source seems set to provide the kind of growth U.S. shale oil provided, that is, 73.2 percent of the global increase in oil production from 2008 through 2018. The world has actually been getting along with less oil for some time now. World oil production proper (crude oil including lease condensate) peaked on a monthly basis in November 2018 at 84.58 million barrels per day (mbpd). In August 2022 production was 81.44 mbpd. That's after a pandemic-induced shock that saw production fall to 70.28 mbpd in June 2020. Neither the U.S. shale oil companies nor OPEC seem ready to increase production significantly (assuming that they can). Russia, among the world's top three producers, is under heavy sanction and may not be able to produce more oil for export anytime soon. (Again, it is not certain that Russia can significantly increase production. Except for the pandemic-induced drop Russia has long been on a production plateau of between 10 and 11 mbpd.) No doubt some new oil savior will be announced soon whether credible or not. In the meantime, the world economy will be faced with limited oil supplies that do not simply grow to meet our fantasies of what we want. The result will be high prices, that is, higher than has been historically the case. A recession won't change this dynamic and, in fact, may reinforce it as oil companies are likely to reduce drilling activity when demand for oil slumps. That will make it doubly difficult for those companies to supply growing demand coming out of the next recession. This is the way things might very well be for a long time if not indefinitely. Many of us who foresaw this day said that we would only see peak world oil production in the rearview mirror. It may take a few more years to determine if November 2018 marked the all-time peak.

U.S. shale oil output to keep growing, at snail's pace – EIA (Reuters) - Oil output from the Permian shale basin in January is set to touch a record 5.6 million barrels per day (bpd), the U.S. forecast on Monday, but the increase is a third of September's pace. Output in the biggest US shale oil basin is set to rise by about 37,000 bpd, the smallest gain in seven months based on projections from the US Energy Information Administration (EIA) in its monthly drilling productivity report.Gains slowed as some of the largest firms are warning of overworked oilfields and less productive new wells. Overall U.S. output is forecast to reach a record 9.32 million bpd in January, according to the EIA, up only 94,500 bpd over the prior month. In August, the month-over-month increase was 207,500 bpd. Legacy oil production change, which excludes output from new wells, will show steeper declines in all major shale producing regions in January. Production from new wells, defined as one that began producing for the first time in the previous month, also is expected to fall. In the Bakken region of North Dakota and Montana, the EIA forecast oil output next month will rise 21,000 bpd to 1.22 million bpd, the largest total since November 2020. In the Eagle Ford shale in South Texas, output will rise 10,000 bpd to 1.24 million bpd in January, its highest total volume since April 2020. Natural gas production also is expected to grow by 535 million cubic feet per day to a record 96.28 billion cubic feet of gas per day. U.S. gas production is rising sharply amid growing global need for the fuel. In the biggest shale gas basin, Appalachia in Pennsylvania, Ohio and West Virginia, January output will rise to 35.53 bcfd, the highest since hitting a record 36 bcfd in December 2021. Gas output in the Permian and the Haynesville field in Texas, Louisiana and Arkansas will rise to record highs of 21.39 bcfd and 16.41 bcfd in January, respectively. EIA said producers drilled 1,005 wells in November, the most since March 2020. Total drilled-but-uncompleted (DUC) wells rose by 22 to 4,443 in November, the first monthly increase since June 2020.

Regulators order Keystone Pipeline to investigate after 14,000 barrels spill in Kansas - Kansas Reflector --— Federal regulators have ordered operators to temporarily shut down part of the Keystone Pipeline in northern Kansas after it spilled 14,000 barrels of crude oil. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration issued a corrective action order, its strictest enforcement, Thursday evening. It orders the pipeline’s operators to conduct an investigation before they can resume operations.  In a statement Friday, TC Energy, which owns the 2,687-mile Keystone Pipeline, said it had been working closely with regulators, local officials, landowners, tribal nations and the community at-large. The spill occurred close to Washington, Kansas, near the Nebraska border, dumping oil into Mill Creek. Environmental Protection Agency coordinators were dispatched to the scene Thursday along with state and local crews. TC Energy said in a news release Thursday evening that the segment of Mill Creek where the oil spilled had been isolated to prevent it from flowing downstream. The EPA said Friday the oil was contained within three miles of the pipeline burst and no drinking water had been impacted. Zack Pistora, a lobbyist for the Sierra Club in Kansas, said it was a “shame that this has happened once again on the Keystone Pipeline.” “It’s a shame because Mill Creek will probably never be the same,” Pistora said. The corrective action order says TC Energy must determine the root cause of the failure that caused the oil spill Wednesday, review 10 years of inspections and create a remedial work plan that assesses the risk of spills at other points along the pipeline.

Kansas oil spill is Keystone pipeline's biggest ever, according to federal data - — A ruptured pipe dumped enough oil this week into a northeastern Kansas creek to nearly fill an Olympic-sized swimming pool, becoming the largest onshore crude pipeline spill in nine years and surpassing all the previous ones on the same pipeline system combined, according to federal data.The Keystone pipeline spill in a creek running through rural pastureland in Washington County, Kansas, about 150 miles northwest of Kansas City, also was the biggest in the system's history, according to U.S. Department of Transportation data. The operator, Canada-based TC Energy, said the pipeline that runs from Canada to Oklahoma lost about 14,000 barrels, or 588,000 gallons. The spill raised questions for environmentalists and safety advocates about whether TC Energy should keep a federal government permit that has allowed the pressure inside parts of its Keystone system — including the stretch through Kansas — to exceed the typical maximum permitted levels. With Congress facing a potential debate on reauthorizing regulatory programs, the chair of a House subcommittee on pipeline safety took note of the spill Friday. A U.S. Government Accountability Office report last year said there had been 22 previous spills along the Keystone system since it began operating in 2010, most of them on TC Energy property and fewer than 20 barrels. The total from those 22 events was a little less than 12,000 barrels, the report said.TC Energy and the U.S. Environmental Protection Agency said the spill has been contained. The EPA said the company built an earthen dam across the creek about 4 miles downstream from the pipeline rupture to prevent the oil from moving into larger waterways.  Randy Hubbard, the county's emergency management director, said the oil traveled only about a quarter mile and there didn't appear to be any wildlife deaths.The company said it is doing around-the-clock air-quality checks and other environmental monitoring. It also was using multiple trucks that amount to giant wet vacuums to suck up the oil.Past Keystone spills have led to outages that lasted about two weeks, and the company said it still is evaluating when it can reopen the system.

UPDATED: Keystone pipeline system remains offline due to 14,000-barrel oil spill into creek | Upstream OnlineCanadian pipeline owner and operator TC Energy has shut down its 622,000 barrels per day Keystone Pipeline System and is responding to an oil spill into a Kansas creek. TC Energy estimated 14,000 barrels of oil has been spilled from the pipeline system in the latest incident. That volume is larger than the total 11,975 barrels of oil that had been released from Keystone in prior spills since 2010, according to a US Government Accountability Office report published in July 2021. . The emergency shutdown of the line happened around 20.00 local time on 7 December after alarms were triggered and pressure dropped in the system, the company said. “We have shut down the Keystone Pipeline System and mobilised people and equipment in response to a confirmed release of oil into a creek in Washington County, Kansas, approximately 20 miles [32 kilometres] south of Steele City, Nebraska.” “The system remains shut down as our crews actively respond and work to contain and recover the oil,”  The affected segment has been isolated and we have contained downstream migration of the release, the company added. The US Environmental Protection Agency (EPA) said TC Energy reported the discharge of crude oil from its pipeline early on the morning of 8 December. The EPA said surface water at Mill Creek had been impacted, adding “at this time, there are no known impacts to drinking water wells or the public”. Agency on-scene co-ordinators, state and local responders were on the scene along with a TC Energy response crew, the EPA said. Bloomberg and Reuters quoted unnamed sources as saying TC had declared force majeure over the outage. TC Energy’s statement said it is working to make appropriate notifications, including to its customers and regulators. It is not clear when the company will reopen the line, but it said its current primary focus is the health and safety of onsite staff and personnel, the surrounding community and mitigating risk to the environment.

TC Energy says has not found cause of Keystone oil pipeline leak – Canada’s TC Energy said on Sunday it has not yet determined the cause of the Keystone oil pipeline leak last week in the United States, while also not giving a timeline as to when the pipeline will resume operation. TC shut the pipeline after more than 14,000 barrels of crude oil spilled into a creek in Kansas on Wednesday, making it one of the largest U.S. crude spills in nearly a decade. “Our teams continue to actively investigate the cause of the incident. We have not confirmed a timeline for re-start and will only resume service when it is safe to do so, and with the approval of the regulator,” TC said in an update posted to its website. The pipeline operator said that it has more than 250 people working on the leak, including third-party environmental specialists, adding that it is continuously monitoring air quality and presently there are no indications of adverse health or public concerns. Crews are also preparing for rain forecast to begin on Monday, TC said. The 622,000 barrel-per-day Keystone line is a critical artery shipping heavy Canadian crude from Alberta to refiners in the U.S. Midwest and the Gulf Coast. Keystone’s shutdown will hamper deliveries of Canadian crude both to the U.S. storage hub in Cushing, Oklahoma and to the Gulf, where it is processed by refiners or exported.

Keystone pipeline has now leaked more oil in the US than any other since 2010: report -- On the heels of another spill last week, the massive Keystone pipeline has now leaked more oil than any other pipeline since 2010, according to a new report from Bloomberg.With more than 26,000 barrels of crude oil spilled in the last 12 years, the hazardous liquid pipeline system has come under controversy after some two dozen accidents and takes the top spot for most spillage in the last 12 years, Bloomberg reported. Keystone leaked an estimated 14,000 barrels into a creek in northeastern Kansas last week, spurring TC Energy to shut down the massive vein while the company tries to contain the oil and recoup what was lost. The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration has issued a corrective order to operator TC Energy, requiring the company address the current Keystone leak, develop and submit “restart plan” to resume operations for approval, and submit quarterly reports moving forward. The 2,687-mile hazardous liquid pipeline runs from Hardisty, Alberta, in Canada through the Midwest U.S. to Port Arthur, Texas. According to data from the Government Accountability Office (GAO) last year, Keystone has carried more than 3 billion barrels across the U.S. since 2010, but “the severity of its spills has worsened in recent years.” The pipeline saw 22 accidents from 2010 to 2020, which isn’t unlike other pipelines — but six of those met agency criteria for an incident “impacting people or the environment,” according to the GAO.

The Keystone Pipeline has had at least 3 significant spills in the last 5 years. Here's what to know. - A small Kansas county became a site of a significant pipeline failure last week as the Keystone Pipeline leaked an estimated 14,000 barrels of crude oil into a creek — the largest spill in its history. Now, officials are scrambling to clean up the mess made by the system, which stretches more than 2,600 miles from Canada to the U.S. And it isn't the first time they've had to do so.  The Keystone Pipeline has had nearly two dozen accidents since it went into service in 2010, according to a report from the U.S. Government Accountability Office, a history similar to other oil pipelines. There are dozens of "significant" oil pipeline incidents every year in the U.S., according to the Pipeline and Hazardous Materials Safety Administration, costing more than $3 billion and leading to the deaths of six people since 2002. More than 719,000 barrels of crude oil have been lost in that time, with each barrel being about 42 gallons. It's not uncommon for smaller-scale oil pipeline breaches to occur in the U.S. But what makes the Keystone Pipeline different, the GAO said, is that its incidents have only gotten worse.While most of the 22 accidents at the pipeline over the past 12 years resulted in fewer than 50 barrels of oil being released each time, four incidents stand out. In two separate instances in two different states, 400 barrels, or more than 16,000 gallons, of oil spilled out of the pipeline – in Ludden, North Dakota, in 2011 and in Freeman, South Dakota, in 2016.Then in the past five years, the pipeline has had two larger accidents, aside from the most recent one, that pushed the pipeline's performance below nationwide averages. Before last week, there were two – one in 2017 and the other in 2019 – that were big enough to affect people or the environment, according to the hazardous materials administration's standards.  The Keystone Pipeline was shut down mid-November 2017 after it leaked an initial estimate of 210,000 gallons of crude oil in Amherst, South Dakota, according to the GAO. It was one of the largest on-shore oil spill in the nation since 2010, according to the Associated Press, and months later, it was determined to be nearly twice as big as originally thought.  A spokesperson for TransCanada Corp., the owner of the pipeline now called TC Energy, said five months after the fact that the pipeline had actually spilled about 407,000 gallons of crude oil into surrounding farmland, with the GAO saying last year that 6,592 barrels of oil were released. Despite taking months to clean up, the pipeline resumed 12 days after the leak began.   Not even two years later, a tiny town of fewer than 200 people became the site of another massive leak nearby. The pipeline sprung a leak near Edinburg, North Dakota, in October 2019, forcing the pipeline to halt the transport of oil. While state regulators initially expected the leak to affect about 22,500 square feet, they later determined it was almost 10 times bigger than that – 209,100 square feet, according to the AP.  According to the GAO, 4,515 barrels of oil were released in the incident, with officials telling the AP that an estimated 383,000 gallons of oil had been leaked. The latest major incident started last week, when TC Energy officials announced on Dec. 8 that an estimated 14,000 barrels had been spilled in Washington County, Kansas — more than all the crude oil pipeline spills in 2021 combined, according to federal data. With each barrel being 42 gallons, that would come out to more than half a million gallons of crude oil seeping into the surrounding area.

As pipeline operator searches for cause of Kansas oil spill, residents await cleanup - The operator of a pipeline system that spilled thousands of barrels of crude oil into a north-central Kansas creek last week has said it is still unclear what caused the incident, the largest in the history of the Keystone pipeline. The pipeline failure, which occurred in Washington County on Wednesday night, caused over 14,000 barrels of crude oil to flow into Mill Creek, equivalent to over 500,000 gallons or about the size of a water tower. The Pipeline and Hazardous Materials Safety Administration of the U.S. Transportation Department ordered TC Energy — which operates the pipeline over its 2,700 mile run from Alberta, Canada, to Oklahoma — to shut down the 96-mile segment that includes Washington County. In the USDOT order dated Dec. 8 and signed by Alan Mayberry, an associate administrator for pipeline safety, the agency mandates TC Energy take the segment offline until it takes action to address public health and environmental concerns. That includes a submitted analysis of what went wrong, testing and a plan for how to restart operations. Given the unknown nature of what went wrong and those issues which "may have caused the failure remain present in the pipeline and could lead to additional failures," Mayberry wrote that continuing to operate the portion of the pipeline "without corrective measures is or would be hazardous to life, property, or the environment, and that failure to issue this Order expeditiously would result in the likelihood of serious harm." In a statement released over the weekend, TC Energy said it had a crew of 250 specialists on the scene and that continuous air monitoring was underway. The company said there is presently "no indication of adverse health or public concerns" and the Environmental Protection Agency said Friday that drinking water had not been contaminated as part of the spill.

Company starting to recover oil from Kansas pipeline spill - (AP) — The company operating a pipeline that spilled about 14,000 bathtubs’ worth of oil into a Kansas creek during a test for potential problems is recovering at least a small portion of the crude. The U.S. Environmental Protection Agency said Tuesday that Canada-based TC Energy has recovered 2,598 barrels of oil mixed with water from the 14,000-barrel spill on a creek running through rural pastureland in Washington County, Kansas, about 150 miles (240 kilometers) northwest of Kansas City. Each barrel is enough to fill a household bathtub. Last week’s rupture in Kansas forced the company to shut down the Keystone system, and it hasn’t said when it will come back online. The company said it is working around-the-clock to suck up spilled oil using trucks equipped with what essentially are large wet vacuums. No one was evacuated, and officials said no drinking water was affected. The company has promised to fully comply with demands from regulators and to work until it has “fully remediated the site.” Concerns that spills could pollute waterways spurred opposition to plans by TC Energy to build another crude oil pipeline in the same system, the 1,200-mile (1,900-kilometer) Keystone XL, across Montana, South Dakota and Nebraska. President Joe Biden’s cancelation of a permit for the project led the company to pull the plug last year. Last week’s spill was the largest on the Keystone system since it began operating in 2010 and the largest onshore spill since a Tesoro Corp. pipeline rupture in North Dakota leaked 20,600 barrels in September 2013, according to U.S. Department of Transportation data. The agency’s pipeline safety arm last week ordered TC Energy to take corrective action. The order said TC Energy was running an in-line inspection using a device inside the pipeline that was some 80 miles (129 kilometers) past where the pipeline ruptured. Such devices are designed to fit tightly inside and are known as “pigs” because early wooden ones squeaked as they went through. Three university petroleum engineering instructors who reviewed the regulators’ order ahead of Associated Press interviews pointed out the testing, which federal guidelines call for doing at least once every five years.

No timeline for Keystone crude pipeline restart as TC Energy continues cleanup -- The US Pipeline and Hazardous Materials Safety Administration has not set any timeline for restart of the shutdown Keystone pipeline, spokesperson Darius Kirkwood said Dec. 13, even as the operator TC Energy continues with cleanup activities and puts more resources on the ground. PHMSA also does not have any timeline for completing the investigation it is carrying out into the 36-inch pipeline leak, Kirkwood said in an email. TC Energy continues with response and remediation efforts at the Keystone Pipeline System and has so far recovered 2,598 barrels of crude oil and water, it said late Dec. 12, adding vacuum trucks and multiple booms are set up downstream of the release point to contain the oil from moving downstream. Oil has not breached the containment area and "we now have over 300 individuals on site, including third-party experts, to support containment and incident response," TC Energy said in its Dec. 12 update. In its corrective action order issued Dec. 8, PHMSA said crude leaked following a "failure" in the Keystone pipeline nearly three miles east of Washington in Kansas. Neither PHMSA nor TC Energy has so far divulged the cause of the leak into the Dec. 7 incident that resulted in some 14,000 barrels of crude being spilled.

Keystone pipeline break spilled diluted bitumen, complicating cleanup (Reuters) - The oil spilled from TC Energy Corp's (TRP.TO) ruptured Keystone pipeline was diluted bitumen, the U.S. Environmental Protection Agency (EPA) said on Thursday, adding complications to the cleanup. The 622,000 barrels per day (bpd) pipeline was shut last week after it spilled 14,000 barrels of oil in rural Kansas, including into a creek. Bitumen tends to sink in water, making it harder to collect than oils that float. The parts of the pipeline carrying oil from Alberta, Canada, to refineries in Illinois opened on Wednesday at reduced capacity. The ruptured portion that extends from south of Steele City, Nebraska, to a storage hub in Cushing, Oklahoma, remains closed. Bitumen from Canada's oil sands is a dense, thick form of oil that shippers dilute with lighter oils so it can move through pipelines. The resulting product is called dilbit for short.

Company reopens most of pipeline following Kansas oil spill - (AP) — The operator of a pipeline with the largest onshore crude oil spill in nine years has reopened all of it except for the stretch in Kansas and northern Oklahoma that includes the site of the rupture. Canada-based T.C. Energy said in a statement Wednesday night that its Keystone system has restarted operations from Canada to southern Nebraska and from there to south-central Illinois. It also is operating the pipeline from northern Oklahoma to the Gulf Coast. The Dec. 7 spill forced the company to shut down the Keystone system and dumped about 14,000 barrels of heavy crude oil into a northeastern Kansas creek running through rural pastureland in Washington County, about 150 miles (240 kilometers) northwest of Kansas City. Each barrel is 42 gallons, the size of a household bathtub. “The affected segment of the Keystone Pipeline System remains safely isolated as investigation, recovery, repair and remediation continues to advance,” the company said in a statement. “This segment will not be restarted until it is safe to do so.” Last week’s spill was the largest on the 2,700-mile (4,345-kilometer) Keystone system since it began operating in 2010 and the largest onshore spill since a Tesoro Corp. pipeline rupture in North Dakota leaked 20,600 barrels in September 2013, according to U.S. Department of Transportation data. The crude carried by the pipeline is extracted from tar sands in western Canada, can sink in water and can be harder to clean up than more conventional crude oil, according to experts and environmentalists. A 2016 National Academies of Sciences studysaid the tar sands oil has an “exceptionally high density” compared with other crude oils that can “pose particular challenges when they reach water bodies.” Company and officials have said no drinking water supplies were affected, the oil didn't reach larger waterways and no one was evacuated. But the U.S. Environmental Protection Agency said Friday that four dead animals and 71 dead fish had been recovered.

Ecology fines barge company for oil spill in Salish Sea -A barge company that spilled fuel into the Salish Sea has been fined $38,500, the Washington State Department of Ecology announced Wednesday, Dec. 14. The barge, carrying 1.55 million gallons of high-sulfur fuel oil, marine gas oil and ultra-low sulfur diesel, spilled an unknown amount of fuel due to open hatches during high-seas transport, according to a news release from Ecology. The barge, operated by Olympic Tug & Barge, Inc., a subsidiary of Centerline Logistics, was being transported from the Parkland Refinery in Vancouver, B.C., to Commencement Bay in Tacoma, Feb. 7, 2021. When it arrived in Commencement Bay, tug crews noticed fuel had “splashed out” of the tanks and was in the water. The company was fined for spilling oil in water and negligence, as it had either failed to close the two of the hatches before departure, or were unaware the hatches had opened during transport, the news release said. There are no reported signs of damage to the natural environment in the Salish Sea, and 267 gallons of oil were recovered from the vessel’s deck.

Safety concerns preceded oil well blowout -- The idle oil well that blew out Dec. 2 north of California Avenue, badly injuring a Bakersfield oil field worker, twice prompted safety concerns earlier this year — first as part of a cluster of bores whose elevated pressure readings led to an emergency work order in May, then again after a rupture boomed at the site in June. State regulators warned the well's owner in April about excessive pressure at seven of its facilities in the Fruitvale Oil Field, later characterizing them as presenting "an immediate danger to the surrounding area," including homes, parks, commercial centers and an elementary school. Bakersfield-based owner E&B Natural Resources Management Corp. resisted the state order to cap the well, telling regulators it was addressing the situation and intended to reactivate the facility after idling it in September 2015. The company later agreed to permanently plug it and the others. Remedial work was underway at the well, located just west of Easton Drive in a dirt lot behind a police training facility, when authorities say a sudden release of high pressure at about 8:30 a.m. hurtled Leonardo Andrade, an employee of Bakersfield oil field contractor MMI Services Inc. Andrade's wife has said he suffered internal bleeding and severe leg injuries. Cal/OSHA has since opened investigations of the two companies, both of which were the target of fines by the agency last year for alleged safety problems after separate oil field accidents. The penalties remain under appeal. Little investigation was done after a smaller accident at the same well shortly before 8 a.m. on June 24. According to the Bakersfield Police Department, at least two callers reported a loud bang, with one telling of light smoke at the lot. Responders with the Bakersfield Fire Department concluded the boom resulted from a "mechanical malfunction" in which a pressurized rubber line running from an oil rig at the site suddenly burst. No one was reported hurt. The agency said it did not know what company was performing the natural gas release at the well. The well had been included in E&B's state-mandated plan for managing and capping idle wells. The company told regulators last spring it plugged wells it owns in the same oil field in 2019 and 2021, and that it was planning to properly abandon two more by the end of this year.

Biden May Soon Approve Huge Alaska Oil Drilling Project --When Joe Biden was a candidate to be his party’s nominee for President, he ran as one of the biggest foes of fossil fuels ever to make a credible run for the White House. He pledged to eliminate net carbon emissions by 2050, ween the country off dirty sources of energy and “end fossil fuel.” He canceled the high-profile Keystone XL pipeline, took millions of acres of possible drilling off the table by scrapping leases to oil and gas companies, and banned imports of Russian oil. He even threatened oil firms with a windfall tax and likened them to war profiteers.Environmental groups went gaga over his rhetoric and action alike, buoying his political alliances and giving climate change activists heart after years of broken promises.And yet, a unique alignment of political and geological confluences may spur Biden in the coming days to do something that will leave those same green allies seeing red.Biden’s administration is nearing a final decision on a potentially game-changing oil and gas project that has now been under consideration across five presidencies. The proposed Willow project in the northeast section of the National Petroleum Reserve-Alaska would produce 180,000 barrels of oil each day, create $10 billion in tax and royalty revenues, and create 2,000 construction jobs and 300 permanent ones. The massive project would require as many as five drilling sites, a processing facility, 50 miles of new roads, seven bridges, and an airstrip. Local groups, including those representing Alaska Natives, as well as labor unions and the state’s congressional delegation, have all championed the project as a source of good union jobs and money for Alaska’s North Slope. But environmental groups and some Native American groups from the Lower 48 oppose the ConocoPhillips project, citing an Interior Department analysis that estimates it would emit at least 278 million metric tons of carbon dioxide over its lifetime and during construction. It also would endanger the local wildlife like polar bears. On Thursday, a coalition of environmental groups—represented by a PR firm with deep ties to the Biden Administration—plans to rally at Lafayette Square across from the White House before delivering another 90,000 comments in opposition to the proposal, which they liken to 76 coal plants running for a year. (Industry groups heartily reject this comparison, noting it compares a lifetime of direct and indirect emissions from Willow with one coal plant’s annual emissions.)

Coast Guard identifies oil spill south of Prince Rupert - Oil is leaking again from the sunken United States Army Transport (USAT) Brigadier General M.G. Zalinski vessel in Grenville Channel, about 100 kilometres south of Prince Rupert, the Canadian Coast Guard (CCG) stated on Dec. 1. Guardians noticed a “small amount” of oil on the water near the wreck site this September and October, the coast guard stated. They completed an assessment of the site and found three leaks releasing slow but consistent drops of oil into the marine environment. The CCG is working with Gitga’at and Gitxaala First Nations who have created an Emergency Coordination Centre with Fisheries and Oceans Canada (DFO) along side the Ministry of Environment and Climate Change to address the spill, a social media post stated. The wreck is in a difficult location on the edge of a rocky shelf with challenging currents, tides and weather patterns. The ship itself is also badly deteriorating in some areas. These factors create a safety risk to the coast guard that they must consider in their plans to respond to the incident, a spokesperson wrote. “While the current amount of marine pollution upwelling from the shipwreck is minimal, it is possible the amount could increase. The Canadian Coast Guard is taking action now to assess and contain the immediate threats posed by the wreck to prevent long-term damage to the environment.” The Zalinski ran aground and sunk in Grenville Channel in 1946 while travelling from Seattle to Alaska. The vessel lies upside down in 27 metres of water and has had multiple small oil leaks.

Cleanup continues at oil spill site near Meadowbank Mine- Monitoring efforts continue at the site of an oil spill that occurred more than a week ago near Meadowbank Mine, according to a spokesperson for the federal Department of Crown-Indigenous Relations and Northern Affairs Canada. “There is no indication that fuel has entered any freshwater body or exited the immediate spill area,” Vincent Gauthier told Nunatsiaq News on Thursday, adding that a water resource officer has been to the site of the spill. On Nov. 28, a tanker truck rollover led to the spill onto an all-weather road near the gold mining complex owned by Agnico Eagle Mines Ltd. Meadowbank is located about 110 kilometres by road from Baker Lake. The company originally estimated it to be 20,000 litres in size, but the federal government has provided a revised estimate of about 29,000 litres. That’s enough oil to fill the 40-litre tanks of 725 passenger cars. Agnico Eagle stated on Nov. 29 that the driver was not injured and the company had started an investigation into the incident. Kivalliq Inuit Association released its own statement Dec. 1, advising that trenches have been dug in an effort to contain the spill. It noted the spill has spread approximately 30 metres beyond the road, and that the closest body of water is 600 metres away. The remaining fuel was pumped into another tanker.

European Gas Storage Still On Target Despite Cold Weather - Increased month-on-month heating demand in Europe due to colder temperatures did not hurt the continent as both businesses and households changed their behavior. Wood Mackenzie said that colder temperatures across Europe have increased month-on-month heating demand by 20% in December, but a behavioral change in households and services means the amount of gas used in these sectors is 16% lower than previous average consumption patterns for similar temperatures. Despite the recent cold weather, Europe is still on track to end this winter with gas storage levels at 38% and looks set to meet the 2023 European Union target of having inventories up to 90% by November next year. “Gas demand has decreased by 10% in 2022, equivalent to 50 bcm. In 2023, gas demand will continue falling, albeit at a slower rate year-on-year, under normal weather conditions. Demand in the residential sector will reduce by 12% compared to the five-year average, however, it will be like levels in 2022 as this was a relatively warm year. Demand in the industrial sector will reduce by an additional 7%. Gas demand in the power sector will fall by 4% as renewable build-out continues to grow and despite nuclear and hydro output remaining weak,” Penny Leake, Wood Mackenzie research analyst for European gas, said. “From April to October 2023, there will be up to 25 billion cubic meters less Russian gas. But with storage levels reaching 38% at the end of this winter, Europe’s requirement to refill storage levels next summer will fall by 19 bcm compared to the corresponding period of 2022. This, combined with 9 bcm additional LNG imports, will help hit the 90% gas storage capacity target set by the EU.” “The EU and UK combined are projected to import 164 bcm of LNG in 2023, a record high, and 13 bcm more than 2022. This will be supported by accelerated regasification capacity projects that are currently underway and will help Europe’s storage levels refill by next summer,” Leake added. “Prices will need to remain high to keep demand low and to attract LNG. However, if Europe’s storage levels reach 38% by March as forecasted, there is a downside risk to the current forward curve, which is trading at $40/million British thermal units (mmbtu). Part of this reduction will also be facilitated by increased regasification capacity in the Netherlands and Germany, helping reduce bottlenecks from gas piped flows from the UK to the continent, helping TTF ease to levels closer to NBP and DES LNG prices,”

Kremlin: No decision yet on repair of Nord Stream gas pipelines ---  (Reuters) – Kremlin spokesman Dmitry Peskov said on Thursday that no decision had been made yet on whether to go ahead with a repair of the undersea Nord Stream gas pipelines that were damaged by explosions in September. He was commenting on Canada’s plans to revoke a sanctions waiver that allowed turbines for Nord Stream 1, Russia’s biggest gas pipeline to Europe, to be repaired in Montreal and returned to Germany. “Only repairs can affect Nord Stream now. Or launching the only surviving line of Nord Stream 2,” Peskov told reporters. “The repair has yet to come to fruition. No decisions were made in this regard.” He said Russia was not aware of the results of investigations into the pipeline blasts by Sweden and Denmark. Moscow, without providing evidence, has blamed the explosions on Western sabotage. “We do not know anything about the results of the investigation yet. We do not know to what extent the countries in whose economic zone this sabotage took place will still insist on getting to the bottom of the truth,” Peskov said. Peskov added there was no decision on whether to start gas exports via the intact part of the Nord Stream 2 line. Construction of Nord Stream 2, designed to carry Russian gas to Germany, was completed in September 2021, but was never put into operation after Berlin shelved certification just days before Moscow sent its troops into Ukraine in February.

China Sees $10 Billion In LNG Tanker Orders In 2022 Three of China’s shipyards won almost a third of this year’s orders to make new LNG carriers, Reuters said on Monday. China’s shipyards—only one of which has experience building new LNG tankers—are getting a significant piece of the pie for new LNG carriers, which hit a record this year at 163 orders. The orders that China’s shipyards are seeing tripled this year, to 45, and some of China’s shipmakers that only recently became certified to build the LNG tankers, are even seeing foreign orders for the first time ever. China’s LNG tanker orders this year are valued at nearly $10 billion—about five times the order value of last year, Clarksons Research showed, cited by Reuters. South Korean shipyards usually get a large share of the LNG tanker orders, but they are already at capacity as they try to service Qatar’s North Field expansion. This has created a backlog for South Korean shipyards, and has increased costs to build LNG tankers. The end result is that even foreign buyers who look favorably on South Korea’s ability to design and build LNG tankers free from problems are now giving a serious look at China—even for companies that have zero experience with the intricacies of LNG shipbuilding. “As more Chinese gas traders engage local shipyards, they will be forced to climb the learning curve and eventually grow the whole industry,” Li Yao, founder of Beijing-based consultancy SIA Energy, told Reuters. As of late November, Chinese shipyards had orders for 66 LNG tankers, bringing its total to 21% of all global LNG tanker orders, worth some $60 billion. LNG tankers are notoriously difficult to build, and typically take more than two years to complete.

Why Supertanker Rates Are Suddenly Crashing - Earlier in the year, supertanker freight rates hit record levels as traders scrambled to park crude in storage to take advantage of a record gap between spot and future prices shortly after Russia invaded Ukraine. Freight rates for very large crude-oil carriers (VLCC) along the Middle East Gulf to China route reached as high as $180,000 a day while VLCC time charter rates for floating storage jumped to as much as $120,000 per day. But the situation has now reversed with supertanker rates plunging sharply. According to Bloomberg, ships capable of hauling 2 million barrels of crude are now earning about $38,000 a day, down 62% from just weeks ago after OPEC+ cut production and reduced releases from US reserves lowered seaborne volumes, Bloomberg reports.“Clearly OPEC+ cuts and waning SPR releases would both be short-term volume headwinds. They cut production from the first of November and you would expect some lag, and we are seeing activity in the Middle East cooling off somewhat. That’s the simple explanation,”Lars Bastian Ostereng, an analyst at Arctic Securities has told Bloomberg. Lower freight rates are encouraging some crude to travel longer distances. For instance, Bloomberg has reported that a South Korean refiner bought 2 million barrels of U.S. crude for March arrival. Meanwhile, offers for long-haul U.S. cargoes for delivery to Asia have declined partly due to lower shipping costs. But things could not be more different in the natural gas arena.  Demand for LNG floating storage and regasification units (LNG-FSRUs) has increased sharply this year, with Europe facing an energy supply squeeze as Russia has progressively cut pipeline gas flows. Demand for LNG imports has intensified after the ruptures on the key Nord Stream pipeline system quashed any prospect of Russia turning its gas taps back on. This has forced dozens of countries in Europe to turn to FSRUs or floating LNG terminals, which are essentially mobile terminals that unload the super-chilled fuel and pipe it into onshore networks. Currently, there are 48 FSRUs in operation globally, with Rystad Energy revealing that all but six of them are locked into term charters.According to energy think-tank Ember, the EU has lined up plans for as many as 19 new FSRU projects at an estimated cost of €9.5bn.

Uzbekistan halts gas exports to China as winter demand spikes Authorities in Uzbekistan have ordered state-run gas producer Uzbekneftegaz and Russia's Lukoil, the second-largest gas producer in the country, to temporarily halt exports of natural gas to China as the country deals with a wave of blackouts and disruptions to local gas networks. Speaking earlier this week in the capital Tashkent, Bekhzot Narmatov, the executive chairman of gas pipeline operator and distributor Uztransgaz, said producers have been asked to redirect gas supplies originally destined for export to the domestic distribution network. Gas consumption has been much higher than expected because of a prolonged spell of subzero temperatures, Narmatov said, with authorities even stopping the sale of natural gas as motor fuel to drivers to free some gas for other sectors of the country’s economy. Gas exports were already expected to decline sharply this year against 2021, as the commissioning of a major gas-to-liquids plant and the construction of gas-fired power and heat stations drove up domestic demand, he said. Uzbekistan’s Energy Ministry earlier forecast exports of about 3.3 billion cubic metres of gas in 2022.

Crude production starts at Johan Sverdrup phase 2 |-- Norwegian state-controlled Equinor has started production from the second phase of its giant Johan Sverdrup field in the country's North Sea, as planned. The entire field is now on stream, Equinor said today, reiterating that at plateau it will produce 720,000 b/d, with an aim to boost output to 755,000 b/d. The 440,000 b/d phase 1 came on stream in October 2019. Johan Sverdrup has 2.7bn bl of oil equivalent (boe) in recoverable volumes, according to Equinor, which operates the field with a 42.6pc stake. Lundin Energy holds 20pc, state-owned Petoro 17.4pc, independent Aker BP 11.6pc and TotalEnergies has 8.4pc. "Johan Sverdrup accounts for large and important energy deliveries, and in the current market situation, most of the volumes will go to Europe," said Equinor's executive vice president for projects, drilling and procurement Geir Tungesvik. Freight programmes for December showed the start-up of Johan Sverdrup phase 2 boosting North Sea crude loadings to their highest in more than a year. Loadings from the field were scheduled up by 9pc on the month at 640,000 b/d. Crude from Johan Sverdrup is transported by pipeline to Mongstad, and its gas goes to Norway's 97.6mn m³/d Karsto processing plant. The entire field development has a breakeven price of less than $15/bl, Equinor said. The firm expects CO2 emissions of 0.67kg/bl throughout the life of the field, as five platforms receive power from shore. Equinor said this will help to reduce CO2 emissions by 1.2mn t/yr, which equates to 2.5pc of Norway's annual emissions. Electrification is an important measure to develop the Norwegian continental shelf (NCS) towards net zero greenhouse gas emissions by 2050, said Marianne M. Bjelland, Equinor's vice president, exploration and production for the Johan Sverdrup and Martin Linge areas.

Europe Diesel Stockpiles Set to Swell - Stockpiles of diesel-type fuel in northwest Europe are set to rise — though by slightly less than previously expected — ahead of an upcoming ban on Russian supplies. Inventories will reach 215 million barrels before plunging early next year to their lowest in data going back to 2011, according to a forecast from Wood Mackenzie Ltd. European Union sanctions will all but cut off seaborne deliveries from Russia — currently the bloc’s single biggest external supplier — from early February. The increases in December and January are smaller than previously forecast, due to a downward revision to this month’s refinery processing because of deteriorating margins. While it’s normal for Europe’s diesel stockpiles to rise during winter, the upcoming EU sanctions make this season’s builds particularly important. Once Russian barrels are gone, the bloc will have to find more fuel from other sources. Stockpiles offer a useful buffer as new supply chains develop. The economics of importing diesel from east of Egypt’s Suez Canal have improved, helped by weaker Asian prices, according to James Burleigh, principal analyst at Wood Mackenzie. March is currently forecast to be the tightest month because it follows both the embargo on Russia and northwest Europe’s seasonal demand peak, he said. “After that, the tightness will ease as trade flows re-balance and demand wanes into the summer months.” Refinery processing in northwest Europe rose to 6.1 million barrels a day in November, though was limited by the delayed return of some French plants after strike action and the shutdown of crude distillation units at BP Plc’s giant Rotterdam refinery. It’s forecast to reach 6.16 million barrels a day this month.

Europe Imports Huge Amounts of Diesel | Rigzone Europe is bringing in diesel cargoes from around the world at close to a record pace ahead of the coming ban on shipments from its biggest external supplier. In the first 10 days of this month, the UK and European Union imported more than 16 million barrels of diesel-type fuel via ship — a rate that, if continued, would make December’s total the second-highest since at least the start of 2016, according to data provided by Vortexa Ltd. and compiled by Bloomberg. Europe is structurally short of diesel and has long relied on others for imports. With much of December’s arrivals coming from Asia and the Middle East, the shipments provide a glimpse into how the region might get by after EU sanctions banning seaborne deliveries from Russia take hold in February. Close to half of December’s diesel imports so far — about the same ratio as November’s — came from Russian shipping facilities. That means the EU still has a long way to go before it completely weans itself off the country’s fuel. It remains to be seen whether early December’s staggering level of imports will be maintained. Forward-looking data from Vortexa currently puts average arrivals for Dec. 1-15 at about 1.8 million barrels a day. If that were to continue through year’s end, the final month of 2022 would see the highest deliveries since at least 2016 — surpassing the October surge, when strikes at French refineries led to an import jump. The overwhelming majority of non-Russian deliveries of diesel-type fuel into the UK and EU are coming from the Middle East and Asia — including Saudi Arabia, the United Arab Emirates and India. More are en route, including a supertanker that recently loaded at least some diesel in the Middle East and now is sailing for Rotterdam. Russia’s primary non-EU diesel buyer is Turkey, which also is an exporter. Turkey potentially could function as a middleman, importing Russian diesel for domestic consumption and exporting product made in its own refineries to Europe, according to consultancy Facts Global Energy. The majority of diesel exports from Russian facilities still flow to the EU, much of it to the Amsterdam-Rotterdam-Antwerp area, northwest Europe’s oil trading hub. December is the last month that traders of ICE Gasoil — Europe’s main diesel futures market — will be allowed to deliver physical Russian fuel into storage locations in the ARA region through these contracts. That potentially creates an incentive for anyone looking to sell Russian barrels this way to get it done quickly. Not all Russia-made fuel is always exported from the country’s ports — some can be shipped via other countries, and that isn’t included in the statistics used here.

India imports record 1.7 m b/d of Russian crude in November - India imported a record 1.7 million barrels per day (b/d) of crude oil from Russia in November with inbound shipments surging to a record high ahead of the European Union’s (EU) December 5 import ban and the G7 price cap, S&P Global Commodity Insights said on Monday. “While Russian crude flows to the EU slumped 308,000 b/d to average a record low of 464,000 b/d in the month (November 2022), Indian refiners stepped up their buying of Russian oil by 272,000 b/d to a record 1.17 million b/d,” S&P said. According to S&P Global Commodities at Sea data, the seaborne exports of crude oil from Russia averaged at 3.07 million b/d in November with China and India accounting for 68 per cent of the share, which is higher than the share of the two Asian countries in October. In October, Russia seaborne exports of the key commodity averaged at 3.09 million b/d with both the Asian energy guzzlers accounting for 58 per cent of the share. A senior official from an oil marketing company (OMC) said refiners have contracted high volumes in anticipation of the disruptions due to the price cap and sanctions. Besides, many are taking advantage of the January 19 window.

US Heavy-Handedness Forges Russia-Iran-India Ties - India already rebuffed US pressure to cut ties with Russia. Now it appears ready to at least partially ignore US sanctions on Iran. Back in 2017, India got roughly 11 percent of its oil from Iran, and the two countries were steadily increasing economic ties. Then the Trump administration slapped sanctions back on Iran, and New Delhi caved to US pressure to halt oil imports and other cooperation. That could soon change. According to The Cradle:  Faced with a burgeoning demand for oil and gas amid the global energy crisis and recent oil cuts by the OPEC+, India now looks poised to resume oil imports from Iran, defying US sanctions, The Cradle learned from sources in Tehran and New Delhi.Interestingly, India’s petroleum minister Hardeep Puri hinted at it during his visit to Washington in October, saying New Delhi will buy oil from wherever it has to. Russia, as we know, is already shipping oil to India, despite strong US pressures.It remains to be seen if India goes through with the plan, especially considering Washington’s warning shot in September when the US sanctioned Mumbai-based Tibalaji Petrochem Private Limited for shipping Iranian petrochemical products to China (reportedly the first Indian company sanctioned by the US for dealing with Iran). US sanctions on Iran’s oil exports deprive India of cheap Iranian oil,  forcing it to look elsewhere, including buying more expensive US energy exports. India is now the largest oil export destination for the US. Still, New Delhi likely isn’t in a big rush, as it has already emerged as a big winner from the US proxy war against Russia in Ukraine as India is indispensable to both the US and Russia. Washington needs New Delhi to help control China’s rise and Moscow needs it as an outlet due to western sanctions. For months now India has been getting Russian oil at a discount and selling some to the EU at substantial profits. According to Michael Tran, global energy strategist at RBC Capital Markets:  India is buying record amounts of severely discounted Russian crude, running its refiners above nameplate capacity, and capturing the economic rent of sky-high crack spreads and exporting gasoline and diesel to Europe. In short, the EU policy of tightening the screws on Russia is a policy win, but the unintended consequence is that Europe is effectively importing inflation to its own citizens. This is not only an economic boon for India, but it also serves as an accelerator for India’s place in the new geopolitically rewritten oil trade map. What we mean is that the EU policy effectively makes India an increasingly vital energy source for Europe.    Indian-Russian integration is likely to accelerate despite US pressure and Ukraine throwing fits. Fuelled by a surge in import of oil and fertilizers, India’s bilateral trade with Russia has soared to an all-time high of $18.2 billion over the April-August period of this financial year, according to the latest data available with the Department of Commerce. That makes Russia India’s seventh biggest trading partner — up from its 25th position last year. The US, China, UAE, Saudi Arabia, Iraq, and Indonesia remain ahead of Russia. The increased trade with Russia is a primary driver bringing New Delhi and Tehran closer together – largely a result of US efforts to sever Europe from Russia. According to Reuters, at the end of November Moscow sent India a list of more than 500 products it wants India exporting to Russia, “including parts for cars, aircraft and trains.” The report added:  Indian imports from Russia have grown nearly five times to $29 billion between Feb. 24 and Nov. 20 compared with $6 billion in the same period a year ago. Exports, meanwhile, have fallen to $1.9 billion from $2.4 billion, the source said. India is hoping to boost its exports to nearly $10 billion over coming months with Russia’s list of requests, according to the government source.

Flood of Russian Crude Heads to Asia After EU Ban Kicks In - Almost 90% of Russia’s seaborne crude headed to Asia in the week to Dec. 9. Russia has all but ceased to be a supplier of crude oil to Europe. A European Union ban on imports of Russian crude by sea came into force on Dec. 5, effectively closing off its closest oil market, which took roughly half the country’s supplies at the start of the year. With the exception of a small volume delivered to Bulgaria, seaborne flows of Russian crude to the bloc have halted.

Chinese oil demand faces bumpy road to recovery as Covid curbs ease -Oil demand in China is expected to pick up as the world’s largest crude importer pivots away from its strict Covid Zero policy, although analysts caution that it may take time for gains to kick in. Energy Aspects Ltd. boosted its first-quarter outlook by 260,000 barrels a day, according to a Dec. 12 note from analysts including Jianan Sun. The revision centers on gasoline and jet fuel as mobility increases, with the latter expected to rise to about 750,000 barrels a day from a low base of 450,000 barrels. Increased energy consumption in Asia’s biggest economy following the abrupt shift in policy may help to support futures prices that are on course for a back-to-back quarterly drop, with global benchmark Brent well down from the peak seen after Russia’s invasion of Ukraine. Nevertheless, a potential surge in infections in China as curbs are lifted could make for near-term disruption. “People’s will to go out may still be conservative in the next one or two months as most cities have yet to see big outbreaks,” Zhang Xiao, an analyst at OilChem, told a webinar, adding that gasoline usage may actually drop near term as people opt to stay home to avoid infection or to recover “The market will wait at least till March to see a recovery in gasoline demand.” China’s shift comes at a complex time in energy markets. The Organization of Petroleum Exporting Countries and its allies recently opted to slash supply as global growth slows, traders are tracking the impact of the Group of Seven’s price cap on Russian oil exports, and central banks are still battling inflation. The International Energy Agency, which advises major economies, bolstered its forecasts for global demand in 2023 by 300,000 barrels a day, citing factors including surprising resilience in China. Usage will grow by 1.7 million barrels a day next year to average 101.6 million a day, it said in a report this week. There’s also guarded optimism from Vitol Group, the world’s biggest independent oil trader. Demand in China may recover as early as the second quarter, according to Mike Muller, head of Asia, who said this week there will probably be a “Nike-swoosh or J-shaped” rebound in transport-fuel usage

Number of oil tankers waiting to pass through Istanbul strait falls to 13 The recent buildup in traffic in the Black Sea eased on Monday, as the number of tankers waiting to pass through Istanbul’s Bosporus on the way to the Mediterranean fell to 13 from 17 a day earlier, a shipping agency said. In a new measure that has been in force since the start of this month, Türkiye is requiring vessels to provide proof they have insurance in place for all circumstances covering the duration of their transit through its straits or when docking at Turkish ports. Five tankers were scheduled to go through the Bosporus southbound on Monday, the Tribeca shipping agency said. The number of ships waiting in the Black Sea to pass through the strait had stood at 20 on Friday. The average waiting time for tankers decreased to 2.8 days from 4.2 days a day earlier, the Tribeca data indicated. The average waiting time peaked at above six days last week. Türkiye’s maritime authority said it would continue to keep out of its waters oil tankers that lacked appropriate insurance letters. On Sunday, the authority said four tankers, carrying some 475,000 tons of oil, had provided the necessary insurance letters according to regulations, facilitating their passage through the strait on Monday. In a statement, the authority also said it removed five oil tankers from the country’s territorial waters via the Dardanelles, further south than the Bosporus, as they could not provide confirmation letters for their insurance. At the Dardanelles, two tankers were scheduled to pass through southbound on Monday, while seven tankers were waiting to be scheduled, Tribeca said. The Transport and Infrastructure Ministry’s Directorate General for Maritime Affairs last week said the insurance checks on ships in its waters were a “routine procedure” and stressed it was unacceptable to pressure Türkiye over the measure. The regulation came into effect before the G-7, the European Union and Australia agreed to bar shipping service providers like insurers from helping export Russian oil unless it is sold at an enforced low price, or cap, to deprive Moscow of wartime revenue.

Russia Claims Price Cap Won’t Seriously Hit Its Oil Production | Russia’s oil production will not fall off a cliff now that the EU-G7 price cap on Russian crude has come into effect, Russia’s First Deputy Energy Minister Pavel Sorokin said on Thursday. “Most markets are available for our oil based on adequate market principles, while any fluctuations in oil production that may occur, are not critical and will not exceed those registered in the spring,” Sorokin told reporters in Moscow today, as carried by Russian news agency TASS. Russian oil output dipped in the spring immediately after the Russian invasion of Ukraine, but later stabilized by June. Still, Russia is estimated to have been around 1 million barrels per day (bpd) below its OPEC+ oil production quota since then. Analysts expect a further decline in Russian output due to various hurdles for its exports now that the $60 a barrel price cap is in place. Russia’s central bank has said that the price cap could result in another shock to the Russian economy. Commenting on this, Sorokin said, “It should be noted here that the analysis presented in the publication contained a remark saying that the opinion of experts may not coincide with the regulator’s view.” “Overall, we do not share the opinion that the introduction of a price cap is an event that will lead to major consequences for the Russian economy,” he added. Earlier this week, Deputy Prime Minister Alexander Novak – who is in charge of Russia’s oil policy and attends the OPEC+ meetings –– said that Russia may have to reduce its oil production due to uncertainties, but noted that the “decline will not be very significant.” As of October, Russia had yet to find markets for an additional 1.1 million bpd of crude and 1 million bpd of diesel, naphtha, and fuel oil which will be banned in Europe by early February, the International Energy Agency (IEA) said in its Oil Market Report in November. “For crude oil, no significant buying from Russia outside China, India, and Türkiye has appeared despite massive discounts. A further rerouting of trade should help ease pressures but a shortage of tankers is a major concern, especially for ice-class vessels required to load out of Baltic ports during winter,” the agency added.

Russia Price Cap Impact Not Clear Yet -- Saudi Arabia’s Energy Minister Prince Abdulaziz bin Salman said the impact of European sanctions on Russian crude oil and the cap that the Group of Seven nations has imposed on the price of Russian barrels is not clear yet. “In terms of sanctions and price caps, these have not yielded clear results yet,” the prince told a forum in Riyadh on Sunday, held following the country’s 2023 budget announcements last week. “Some of these measures were only implemented on Dec. 5 and we can now see the state of uncertainty in the implementation. There are many measures that have not been verified and it will continue to change or be modified in line with the political requirements.” The G-7 last week slapped a price ceiling on Moscow’s oil exports, a move that Washington insists is purely about Russia: keeping its oil flowing while starving it of funds for the war in Ukraine. Introduced in tandem with a European Union ban on seaborne Russian crude, any nations still buying must pay $60 a barrel or less, or lose access to key shipping services supplied by EU and G-7 firms. OPEC+ — a 23-nation coalition that is led by Saudi Arabia and Russia — met to discuss policy earlier this month and agreed to hold output steady, having decided in October to cut supply by two million barrels a day in a move that angered the US. Oil soared after Russia sent troops into Ukraine in February, with benchmark Brent topping $127 a barrel. But it’s since slumped below $80 as slowing economic growth in the US and Europe, and lingering coronavirus curbs in China, stoke demand concerns. Adding to that weakness is a view among traders that the price cap was set high enough to ensure Russia won’t need to rein in output. Despite this, Russian president Vladimir Putin said his country may cut its oil production in response to the price cap and that a decision on Russia’s response will be made within the next several days, according to comments broadcast on state Rossiya 24 TV on Dec. 9. Asked about the threat to cut oil production by Russia, the prince told reporters today: “I’ll believe it when I see it.” Russia’s response to the price cap also adds another layer to the uncertainty surrounding the actual impact the measures could have on global markets, the Saudi energy minister told the forum. “What will the reaction be, what they can possibly do and whether it will be similar to what has been done with gas, will the practices when it comes to crude oil be similar or different, is also mysterious,” he said. “These tools were created for political purposes and it is not clear yet whether they can achieve these political purposes.“ Other uncertainties on the global economy as we walk into 2023 include the impact on the Chinese economy from easing Covid restrictions and central banks’ actions to tame inflation. “The central banks now are controlled by the tendencies to curb inflation no matter the costs – these will have negative impacts on the growth of global economies.” he said. The OPEC+ alliance decision to cut production by two million barrels a day on Oct. 5 was proven to be the correct one when recent developments are taken into consideration, he said, adding that the alliance will continue to focus on stability in the year ahead.

Price Cap Will Take a Few Months for Traders to Understand -The price cap is a new mechanism that traders did not properly price in, and the new paradigm surrounding Russia’s ability to move crude on the market will take a few months for traders themselves to understand. That’s according to Louise Dickson, a senior analyst at Rystad Energy, who made the comment in a statement sent to Rigzone. In the statement, Dickson highlighted that the oil market has been subject to many “artificial forces” over the past three years, such as “extreme OPEC+ quotas, unbounded stimulus, and unprecedented inventory releases”. “In terms of price we seem to be at an inflection point,” Dickson told Rigzone. “$75 per barrel oil has upside pressure if Russia retaliates with production cuts, but likely has more downside spin as the murky macro backdrop of 1Q23 unfolds,” Dickson added. “It is still our belief that oil demand will swing back in 2023, spurred first and foremost by the re-opening of China, both in terms of oil consumption and in terms of easing of supply chain inflationary triggers,” the Rystad analyst continued. Dickson noted in the statement that the futures curve has been undergoing “significant flattening” over the past few months and said “the flip towards contango was inevitable as we approached 1Q23, a shoulder season for oil demand coupled with what we forecast to be the worst of the recession impact”. At the time of writing, the price of Brent crude oil is trading at $75.66 per barrel. Brent’s highest 2022 close, so far, was seen on March 8 at $127.98 per barrel, and its lowest 2022 close, so far, was seen on December 9 at $76.01 per barrel. On December 3, the European Council decided to set an oil price cap for crude oil and petroleum oils, and oils obtained from bituminous minerals, which originate in or are exported from Russia, at $60 per barrel. The cap, which became applicable as of December 5, will limit price surges driven by extraordinary market conditions and drastically reduce the revenues Russia has earned from oil, the council noted. On October 6, the council adopted a decision prohibiting the maritime transport of Russian crude oil, also as of December 5, and petroleum products, as of February 5, 2023, to third countries, and the related provision of technical assistance, brokering services or financing or financial assistance.

Russia Sets Up Oil Transfer Site in Baltic Sea - Russia has set up a site in the Baltic Sea to allow it to transfer refined fuels from one vessel onto another in a bid to help it overcome a stretched tanker market before the onset of European Union sanctions. The site, near the port of Ust-Luga, will allow ship-to-ship transfers of fuels, including diesel, according to a statement at the website of Rosmorport, the nation’s agency regulating and providing maritime services in the country’s seaports. Its establishment was ordered by Russia’s Transport Ministry in September. The International Energy Agency said in its Oil Market Report on Wednesday that the strategy will allow smaller tankers to discharge onto bigger ones that can then carry the fuels further afield. Historically, most of Russia’s diesel from the port of Primorsk — the country’s main Baltic exporting facility — has gone to Europe in cargo sizes of about 30,000 tons. But with the EU banning seaborne imports from early February, bigger tankers, more suited to long-distance trading, will likely be required. The ship-to-ship, or STS, site will allow for those cargo accumulations. It’s not clear how much the approach will also help Russia to deal with a possible shortage of tankers that are built for icy conditions. Ust-Luga usually declares ice conditions later than Primorsk, according to Richard Matthews, head of research at E.A. Gibson Shipbrokers Ltd. This means that, for a while, ice-class tankers will potentially be able shuttle fuel from the most difficult ports to nearby Ust-Luga for an STS transfer, rather than carrying it all the way to its final destination. Still, Ust-Luga can experience ice in winter. And with more Russian cargoes being shipped over longer distances — for both crude and refined fuels — the pressure on ice-suitable ships will mount unless a solution is found.

Rosneft reports $889m loss from assets ‘transfer’ in Germany - Russia’s oil giant Rosneft said Wednesday its profit over the past nine months had been badly hit by the seizure of its German-based refineries by Berlin. “In 3Q 2022, the most significant negative impact on income came from the transfer of the company’s assets in Germany... which resulted in the recognition of an additional loss of 56 billion rubles (around $889 million),” Rosneft said in a statement. Between July and September, the company “continued to be negatively affected by external factors and illegal restrictions”, including the transfer of assets in Germany, Rosneft chief executive Igor Sechin said in the statement. Berlin in September took control of Rosneft’s German subsidiaries, which account for about 12 percent of oil refining capacity in the country, and placed them under the trusteeship of the Federal Network Agency. Germany has also pledged to end Russian oil imports by the end of the year as Europe seeks to wean itself off Russian energy supplies since the start of the Ukraine offensive. But Rosneft said it had increased its deliveries to Asia by a third and “fully compensated for the decline in supplies to European buyers”. Despite the heavy loss, Rosneft’s ruble revenue in the first nine months of 2022 increased by 15.7 percent year-on-year to the equivalent of $102.3 billion.

Russian court asked to offer Shell an exit route from Salym joint venture --  Russian state-controlled oil producer Gazprom Neft is reportedly seeking an orderly exit for Shell from their Salym joint venture in West Siberia.According to an arbitration court filing in Moscow released into the public domain earlier this week, Gazprom Neft subsidiary GPN Salymskiye Proyekty has requested that the court amend an earlier ruling and permit Shell to take full control of its 50% stake in Salym Petroleum Development (SPD).SPD operates a group of three Salym oilfields in West Siberia’s Yamal-Nenets region and holds an exploration and development licence for a prospective block in the same region.GPN Salymskiye Proyekty earlier this year obtained a court order that imposed restrictions on Shell’s shareholder rights to sell or otherwise manage or dispose of its stake in SPD.The company had accused Shell of attempting to undermine the financial stability of the joint venture and disrupt its normal operations by refusing to lift oil cargoes held under its equity interest in SPD.GPN Salymskiye Proyekty now wants the court to grant Shell permission to pass its shareholding in the venture to another subsidiary of the Russian oil producer, GPN Middle East Projects, after the UK supermajor regains its shareholder rights.

ExxonMobil lets contract for Uaru development offshore Guyana -ExxonMobil has let a subsea contract to Saipem SPA for Uaru oil field development in Stabroek block, offshore Guyana, the service provider said in a release Dec. 15 (OGJ Online, Apr. 27, 2021). The contract includes design, fabrication, and installation of subsea structures, risers, flowlines, and umbilicals for a large subsea production installation. Saipem was previously awarded four subsea contracts by ExxonMobil Guyana for prior developments in Liza Phase 1 and 2, Payara, and Yellowtail, and will perform operations by using its vessels, including FDS2 and Constellation. Uaru, in the eastern portion of the block at a water depth of around 2,000 m, will target 1.319 billion boe and is expected to come online end-2026 (OGJ Online, Oct. 26, 2022). ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator of the 6.6-million-acre Stabroek block with 45% interest. Hess Guyana Exploration Ltd. holds 30% and CNOOC Petroleum Guyana Ltd. holds 25%.

Saipem Wins $1.2 Billion In Offshore Deals -  Italian contractor Saipem has been awarded new contracts in Guyana and Egypt for a total amount of approximately $1.2 billion. The first contract has been awarded by ExxonMobil Guyana, subject to government approvals, for the UARU oil field development project, located in the Stabroek block offshore Guyana at a water depth of around 2,000 meters. Saipem said that the contract scope includes the design, fabrication, and installation of subsea structures, risers, flowlines, and umbilicals for a large subsea production facility. The company, which was previously awarded other four subsea contracts by ExxonMobil Guyana for prior developments in the same area, namely Liza Phase 1 and 2, Payara, and Yellowtail, will perform the operations by using its vessels, including FDS2 and Constellation. Subject to the necessary government approvals, project sanction by ExxonMobil Guyana and its Stabroek block coventurers, and authorization to proceed with the final phase, the award will allow Saipem to start some limited activities, namely detailed engineering, and procurement. It is worth noting that ExxonMobil made more than 30 discoveries on the Stabroek block since 2015, and it has ramped up offshore development and production at a pace that far exceeds the industry average. ExxonMobil’s first two sanctioned offshore Guyana projects, Liza Phase 1 and Liza Phase 2, are now producing above design capacity and achieved an average of nearly 360,000 barrels of oil per day in the third quarter. A third project, Payara, is expected to start up by the end of 2023, and a fourth project, Yellowtail, is expected to start up in 2025. Environmental authorization for Uaru is underway. By the end of the decade, ExxonMobil expects Guyana’s oil production capacity to be more than one million barrels a day. The second contract awarded to Saipem was given by Petrobel for the transportation, installation, and pre-commissioning of 170 kilometers of umbilicals for the Zohr Field. The umbilicals will be installed between the central control platform and the subsea field, connecting to the existing subsea production systems. The offshore campaign is planned to start during the third quarter of 2023. The Zohr field is believed to be the largest-ever gas discovery in Egypt and the Mediterranean. In August 2019, production from the field reached more than 2.7 billion cubic feet of gas per day, roughly five months ahead of the development plan.

Nigeria's oil output rose to 1.185 mln barrels per day in November - (Reuters) - Nigeria’s oil production rose to 1.185 million barrels per day (bpd) in November from 1.014 million barrels in October, figures from the country’s petroleum regulator showed. Oil production fell to less than 1 million barrels a day (bpd) in August, the lowest in years due to increased crude oil theft and vandalism of pipelines, forcing some companies to curtail or stop production. Timipre Sylva, minister of state for petroleum resources, said Nigeria is working to meet its OPEC oil production quota of 1.8 million barrels per day by the end of May next year.

‘Nigeria Local Content Law Growing Indigenous Oil Industry Capacity’  - Chairman of Independent Petroleum Producers Group (IPPG), Mr. Abdulrazaq Isa, has stated that the 27-member indigenous oil and gas exploration and production group is a product of the Nigerian Content policy of the Federal Government which is a clear testimony that the policy has recorded huge success. “The emergence of the strong indigenous Exploration and Production companies is a testament to the successful local content policy. There is no better or clearer way to demonstrate that Nigerian Content is working”, said Isa during his speech at the opening ceremony of the 11th Practical Nigerian Content Forum (PNC) which took place in Uyo, Akwa Ibom State recently. The IPPG Chairman said that Government’s effort in deepening local content in the Nigerian oil and gas industry is paying dividends and it is imperative that the effort is sustained and greater focus placed on bridging the capacity gap and addressing funding challenges. “Nigerian-owned companies are beginning to play more active roles across the industry. Indigenous companies are now penetrating areas that were once solely dominated by foreign players’, Isa said. He reaffirmed IPPG’s commitment to full compliance with the provisions of the Nigerian Oil and Gas Industry Content Development (NOGIC) Act adding that the group will continue to partner with the Nigerian Content Development and Monitoring Board (NCDMB), as it aims to strengthen in-country capacity and increase Nigerian Content, and all relevant stakeholders for the benefit of the industry as well as Nigeria. The IPPG states that the theme of the conference – “Deepening Nigerian Content Opportunities in the Decade of Gas” underscores the importance of re-positioning Nigeria’s oil and gas industry in the face of the ongoing global energy transition as well as divestment of assets by the International Oil Companies (IOCs) in Nigeria.

Nigeria loses $680m to gas flaring yearly -- Ahead of the 2023 general elections, stakeholders in the oil and gas industry have urged Nigerians to identify and vote candidates who are environment-conscious and have the political will to enact laws that will mitigate the effect of gas flaring in the country. The stakeholders made the call following a revelation that the country was losing about $680m to the menace annually. They spoke at a political dialogue themed “Accountability for Gas Flared and Clean Energy Advocacy Project,” organised by the Centre for Transparency Advocacy, in conjunction with other cluster organisations, and sponsored by United States Agency for International Development (USAID), The Project Monitoring Officer of Murna Foundation, Bashir Mukthar, in his remarks said that the country loses $680m annually in penalty fees to International Oil Companies (IOCs), due to discrepancy in the reported volume of gas flared declared. Mukthar attributed this to lack of adequate technology to track the exact volume of gas being flared, as the Nigeria Extractive Industry Transparency Initiative (NEITI) has to rely on figures provided by the IOCs, who usually under-declare in order to evade payment of adequate penalty fees. ICD’s Programme Manager, Ufuoma Asheshe, described gas flaring as the burning of natural gas associated with oil extraction. She said that CSOs must engage Ministries Departments and Agencies (MDAs) to prevail on politicians to see how they could include in their agenda, efforts to tackle gas flaring in the country when elected. “There must be political will on the part of our leaders to tackle gas flaring,”Asheshe said. While decrying the effect of gas flaring, Asheshe said that reports indicated that Nigeria was one of the top seven gas-flaring countries in the world. She added: “Nigeria is a major gas flarer/global Green House Gas Emission. Only in 2018 and 2019, Nigeria lost $680m to gas flaring.

Israel Opens Bids For Offshore Gas Explorations In North - The Israeli Ministry of Energy on Tuesday launched a bid round to provide licenses for offshore natural gas explorations in northern Israel, trend reports citing xinhua . The area offered for bidding includes 20 exploration blocks in four zones, totaling 5,888 square kilometers, much larger in size than the nearby active gas fields Leviathan and Tamar, the ministry said in a statement. The bid round was launched amid the global energy crisis and many countries' strategy of diversifying natural gas supply, and the increasing recognition of the importance of natural gas in enabling renewables, the statement said. The purposes are mainly to increase the certainty of natural gas supply to Israel, expand competition between suppliers, reduce consumer prices, and connect more industrial plants with natural gas, it said. The working period for the blocks offered includes two drill-or-drop decision points after three and five years, and it may be extended up to seven years from the date of the award.

‘He got hit over the head with a pipe’: Qatar offshore attack survivor’s family tell of ‘complete shock’ after murder -- The father of an offshore worker who survived a deadly attack in Qatar has spoken of his relief to have his son back in Scotland. Chris Begley, 38, has returned home after being released from a Middle Eastern hospital, following the violent incident onboard the Seafox Burj platform. He was bludgeoned over the head with a weapon – possibly a pipe – before fellow workers restrained his alleged attacker. Another man, who has not been named, was found dead in the room. A third man, believed to be from the north-east, has been detained and is currently being questioned by Qatari police over the alleged murder on Monday. All three men were contractors for Film-Ocean Ltd, based at the Balmacassie Commercial Park in Ellon. Details of the circumstances surrounding the death have not been released, however unconfirmed accounts have spread rapidly across social media and via WhatsApp. They claim the three men, all reportedly Scots, had been sharing a room onboard the Seafox Burj. It’s claimed a body was discovered in the sleeping quarters. Mr Begley’s father Dennis, 64, said: “They all work together. There’s been no animosity between any of them. This seems to be completely random. “There wasn’t any bad feeling among them or anything like that. That’s why it’s pretty bizarre. There was no indication of any problem or anything within them. “There certainly wasn’t any ill feeling among any of them so I don’t know what’s happened.”

Saudi Arabia to build $11bn petrochemical complex with France’s Total -- Saudi Arabia’s state-owned oil company Aramco will join forces with French supermajor oil company TotalEnergies to build a new petrochemicals complex valued at $11 billion, to start operations in 2027. According to a statement released by the French oil giant on 15 December, construction on the Amiral complex is scheduled to begin in the first quarter of 2023. It will be owned and operated jointly by Aramco and TotalEnergies.The Amiral complex will be integrated into the existing Saudi Arabia Total Refining and Petrochemical (SATORP) refinery located on the kingdom’s eastern coast, allowing it to convert off-gases and naphtha, as well as ethane and natural gasoline, into higher-value chemicals. Last year, Aramco and TotalEnergies launched a joint project to “significantly upgrade” a network of 270 service stations across the kingdom. The French supermajor is looking to cement its foothold in West Asia.France has been leading the charge to secure energy resources from the Gulf, hoping to avert a major disaster after the EU lost access to Russian oil and gas in the wake of a wide range of western sanctions imposed on the Kremlin. In July, French President Emmanuel Macron rolled out the red carpet for Saudi Crown Prince Mohammed bin Salman (MbS). After their meeting, the Elysee Palace issued a statement saying Macron  “underlined the importance of continuing the ongoing coordination with Saudi Arabia with regards to the diversification of energy supplies for European countries.” Earlier that same month, Macron signed a strategic partnership agreement with the UAE for fuel and gas supplies, as Paris moves to reduce its dependency on Russian gas, which accounted for about 17 percent of its supplies before the war in Ukraine. As part of its bid to secure energy resources back home, France has also been bolstering its armed presence in war-torn Yemen.

Xi of Arabia and the petroyuan drive - By Pepe Escobar - Xi Jinping has made an offer difficult for the Arabian Peninsula to ignore: China will be guaranteed buyers of your oil and gas, but we will pay in yuan… It would be so tempting to qualify Chinese President Xi Jinping landing in Riyadh a week ago, welcomed with royal pomp and circumstance, as Xi of Arabia proclaiming the dawn of the petroyuan era.  But it’s more complicated than that. As much as the seismic shift implied by the petroyuan move applies, Chinese diplomacy is way too sophisticated to engage in direct confrontation, especially with a wounded, ferocious Empire. So there’s way more going here than meets the (Eurasian) eye.  Xi of Arabia’s announcement was a prodigy of finesse: it was packaged as the internationalization of the yuan. From now on, Xi said, China will use the yuan for oil trade, through the Shanghai Petroleum and National Gas Exchange, and invited the Persian Gulf monarchies to get on board. Nearly 80 percent of trade in the global oil market continues to be priced in US dollars. Ostensibly, Xi of Arabia, and his large Chinese delegation of officials and business leaders, met with the leaders of the Gulf Cooperation Council (GCC) to promote increased trade. Beijing promised to “import crude oil in a consistent manner and in large quantities from the GCC.” And the same goes for natural gas.China has been the largest importer of crude on the planet for five years now – half of it from the Arabian peninsula, and more than a quarter from Saudi Arabia. So it’s no wonder that the prelude for Xi of Arabia’s lavish welcome in Riyadh was a special op-ed expanding the trading scope, and praising increased strategic/commercial partnerships across the GCC, complete with “5G communications, new energy, space and digital economy.” Foreign Minister Wang Yi doubled down on the “strategic choice” of China and wider Arabia. Over $30 billion in trade deals were duly signed – quite a few significantly connected to China’s ambitious Belt and Road Initiative (BRI) projects.And that brings us to the two key connections established by Xi of Arabia: the BRI and the Shanghai Cooperation Organization (SCO).  BRI will get a serious boost by Beijing in 2023, with the return of the Belt and Road Forum. The first two bi-annual forums took place in 2017 and 2019. Nothing happened in 2021 because of China’s strict zero-Covid policy, now abandoned for all practical purposes. BRI not only embodies a complex, multi-track trans-Eurasian trade/connectivity drive but it is the overarching Chinese foreign policy concept at least until the mid-21st century. So the 2023 forum is expected to bring to the forefront a series of new and redesigned projects adapted to a post-Covid and debt-distressed world, and most of all to the loaded Atlanticism vs. Eurasianism geopolitical and geoeconomic sphere.Also significantly, Xi of Arabia in December followed Xi of Samarkand in September – his first post-Covid overseas trip, for the SCO summit in which Iran officially joined as a full member. China and Iran in 2021 clinched a 25-year strategic partnership deal worth a potential $400 billion in investments. That’s the other node of China’s two-pronged West Asia strategy.The nine permanent SCO members now represent 40 percent of the world’s population. One of their key decisions in Samarkand was to increase bilateral trade, and overall trade, in their own currencies.

Gulf producers lead on OPEC+ cuts, Saudi crude output at 6-month low: Platts survey - The OPEC+ oil producer alliance shrank crude output by 700,000 b/d in November, the steepest monthly decrease since April when Russian production plunged due to sanctions, the latest Platts survey by S&P Global Commodity Insights showed. OPEC’s 13 countries produced 28.87 million b/d, a fall of 850,000 b/d from October, while Russia and eight other allies pumped 13.70 million b/d, up 150,000 b/d. The overall decrease came as the alliance began implementing its 2 million b/d cut to quotas to counter economic headwinds. But with many members, including Russia, vastly underperforming their targets already, the actual physical cuts were always likely to be far less. The gap between the group’s quotas and actual production remained fairly wide at 1.89 million b/d in November, the survey showed. But this is a huge improvement compared with October, when the shortfall reached 3.273 million b/d. Iran, Libya and Venezuela are exempt from quotas under the OPEC+ agreement. In total, only 14 of the 22 countries in the coalition actually reduced production last month, the survey found. Gulf producers Saudi Arabia, the UAE, Kuwait and Iraq led the way, with all of them carrying out hefty cuts, as demand concerns have led to a very bearish sentiment in the oil markets. These four producers cut a cumulative total of 780,000 b/d last month, accounting for almost all of the group’s supply reduction. Saudi Arabia cut output by a weighty 440,000 b/d, averaging 10.46 million b/d last month, its lowest since May. The kingdom significantly reduced exports and also drew steadily from its crude inventories, survey panelists said. Saudi energy minister Prince Abdulaziz bin Salman has reiterated that the group of major oil producers is focused on maintaining current quotas through end-2023 but remains ready to intervene if needed. The UAE also saw a sharp fall in its exports, with production slumping 130,000 b/d last month, while Kuwait trimmed output by 120,000 b/d, the survey found. Iraqi crude output fell 90,000 b/d to 4.49 million b/d in November as exports from the federal region and also from the semiautonomous Kurdistan region dipped. OPEC’s second-largest producer also drew from its crude inventories, survey panelists said.

OPEC Production Fell In November, But 3 Members Actually Boosted Output -  OPEC’s crude oil production fell by an average of 744,000 barrels per day, according to OPEC’s Monthly Oil Market Report released on Tuesday. Saudi Arabia’s November production fell by the most among its members, by 404,000 bpd, to 10.474 million bpd—Saudi Arabia’s lowest monthly average since May 2022. Other significant production decreases were realized by the United Arab Emirates, which saw a decrease of 149,000 bpd in November, landing at 3.037 million bpd; Kuwait, which saw a dip of 121,000 bpd to 2.685 million bpd; and Iraq with a loss of 117,000 bpd to 4.465 million bpd. Overall, OPEC’s average production for November fell to 28.826 million bpd—the lowest average production level since June. While the overall production was significantly lower for November and largely in line with OPEC’s plan to reduce output in response to market conditions, a handful of members increased their production. Libya’s production also decreased by 32,000 bpd, to 1.133 million bpd. Earlier this week, Libya’s oil minister said its oil production was 1.2 million bpd. “We hope to return to 2010 levels, which was 1.6 million bpd, within two or three years,” Oil Minister Mohamed Oun told reporters on Monday. Libya lifted its force majeure on oil and gas last exploration last week in hopes of luring foreign oil companies back into the country that has seen significant unrest in recent years. Angola, Gabon, and Nigeria went the other way, increasing their production by a collective 132,000 bpd. While OPEC saw its overall crude production fall, non-OPEC liquids production, according to OPEC’s latest report, increased month on month in November by 800,000 bpd to 72.7 million bpd. This figure is also 2.1 million bpd higher than the same month last year. This means that OPEC’s share of crude oil in the global production mix slipped by 0.7%, to 28.4% in November from the month prior.

Column-Investors Abandon Bullish Oil Positions As Recession Nears: Kemp - Portfolio investors were heavy sellers of petroleum for the fourth week running as the smooth introduction of the Russia price cap brought the weakness of the economy and oil demand into sharper focus. Hedge funds and other money managers sold the equivalent of 30 million barrels in the six most important petroleum-related futures and options contracts over the seven days ending on Dec. 6. Fund sales have totalled 221 million barrels over the four most recent weeks, according to position records published by ICE Futures Europe and the U.S. Commodity Futures Trading Commission. The combined position has been cut to just 358 million barrels (12th percentile for all weeks since 2013) down from 579 million barrels (47th percentile) on Nov. 8. Crude positions have already been hit hard, limiting the scope for further selling, but liquidation spread to refined products, especially the middle distillates that are the key industrial and transport fuels. Fund managers sold NYMEX and ICE WTI (-5 million barrels), Brent (-4 million), U.S. gasoline (-5 million), U.S. diesel (-11 million) and European gas oil (-5 million). As a result, the net position in Brent fell to just 95 million barrels (5th percentile), the lowest since the first and second waves of the coronavirus epidemic were ranging in 2020. But that weakness is now spilling over into middle distillates, until recently the strongest part of the market because of the low level of inventories. The net position in U.S. diesel and European gas oil was cut to 49 million barrels (41st percentile) from 75 million barrels (62nd percentile) on Nov. 8. Bullish long positions outnumbered bearish short ones by a ratio of 2.92:1 (52nd percentile) down from 5.40:1 (81st percentile) four weeks earlier. U.S. distillate fuel oil inventories remain below the pre-pandemic seasonal average but the deficit has narrowed sharply over the last eight weeks, taking much of the heat out of the market. Slowing manufacturing growth, rising interest rates, conflict between Russia and Ukraine, sanctions and persistent inflation have created a poisonous cocktail for oil consumption and distillates. The extremely low level of hedge fund positions in crude has created upside price risk if and when managers attempt to rebuild bullish positions. But until some of the negative factors weighing on consumption are resolved, many managers are likely to remain cautious about re-entering the market.

Analysts Explain Plunge in Oil Positioning Index Standard Chartered’s crude oil positioning index has fallen for four consecutive weeks, according to a new report from the company, but its analysts think very little of the fall is due to the active opening of new short positions, the report revealed. “It is primarily due to the closing out of existing longs,” Standard Chartered analysts stated in the report. “It does not appear to us that speculators have been adopting a new and far more bearish narrative or specific negative views about oil market fundamentals. Instead, we see the plunge in the index as reflecting the final abandonment of a series of hypotheses that had encouraged speculative longs,” the analysts added. “These range from a tightening of the market due to pent-up demand and a lack of spare output capacity through to imminent supply gaps when EU sanctions on Russian crude oil became effective, in the interim passing through background noise on super-cycles, predictions of $380 per barrel oil and a series of incorrect views about OPEC policy,” the analysts continued. In the report, the analysts noted that they think the closing out of longs is largely due to the abandonment of the latest of these views and added that “in addition, many traders are now cutting back on risky positions before year-end”. “For the first time in 2022 no new focal point has emerged to seamlessly continue what has been the dominant ‘rolling-crisis’ narrative, leaving crude oil prices prey to more top-down, macro-led concerns and the associated correction in prices,” the analysts stated. Last week, analysts at Standard Chartered highlighted in a separate report that speculative positioning in oil was as bearish as during the early weeks of the pandemic. “The crude oil index stands at -70.3, the lowest since mid-April 2020, about a week before WTI prices settled at a negative price. The index has fallen by 57.4 over the past three weeks; this is the largest three-week fall since February 2020, just before the temporary collapse of the OPEC+ agreement,” the analysts stated in that report. In its most recent report, Standard Chartered analysts revealed that their crude oil money-manager positioning index had fallen 2.7 week on week to a 31-month low of -73.0. At the time of writing, the price of Brent crude oil stood at $81.58 per barrel. Brent was trading at more than $98 per barrel last month.

Oil prices are bouncing higher at the start of the week's trading -  Oil prices rose more than 1% in early Asian trade on Monday as a major pipeline carrying crude oil between Canada and the United States remained closed as Russian President Vladimir Putin threatened to cut production in response to the West imposing a cap on Russian oil export prices. Brent crude futures were up 83 cents, or 1.1%, to $76.93 a barrel by 00:20 GMT. US West Texas Intermediate crude was at $71.92 a barrel, in up 90 cents, or 1.3%. Canadian company TC Energy said on Sunday it had not yet determined the cause of the Keystone pipeline oil spill last week in the United States, without providing a timetable for when the pipeline will resume operations. The Keystone Line, with a production capacity of 622,000 barrels per day, is a major thoroughfare for transporting Canadian heavy crude from Alberta to refineries in the US Midwest and Gulf Coast and for export. Meanwhile, Putin said on Friday that his country, the world’s biggest energy exporter, could reduce its oil production and would refuse to sell oil to any country that imposes a price ceiling on Russia agreed by the G7 countries . ANZ Group analysts said in a note that although the uncertainty surrounding the EU sanctions on Russian oil and the associated price cap keeps price volatility high, the sanctions have had little impact on global markets so far. Last week, Brent and WTI crude saw their biggest weekly losses in months, hitting their lowest levels since December 2021 on concerns about the global recession and the impact on oil demand.

Oil Wavers as Economic Headwinds Counter Supply Risks - Crude and gasoline futures nearest delivery slipped early Monday as investors balanced concerns over the health of the global economy next year, clouded by inflation headwinds in the United States and Eurozone, against falling supplies from OPEC+ nations as Russia threatens to cut production in response to the G7's price cap on its oil. Russian President Vladimir Putin threatened to cut the country's oil production "as much as needed" in response to a G7 plan to deny insurance and other maritime services to Russian oil shipments unless the oil is being sold at or below a $60-barrel (bbl) ceiling that took effect last week. Putin's comments were his first indication of the Kremlin's response to EU sanctions and the associated oil price cap. Russian crude oil exports in early December remained as high as at any other point this year, according to private shipping data, with any drop due to the sanctions expected to be visible only later in the first quarter 2023. Even then, analysts forecast Russian oil production unlikely to decline by more than 1 million barrels per day (bpd) compared to earlier calls for 3 million bpd. Putin acknowledged that for now Russia is relatively insulated from the price cap because "the ceiling they have suggested is in line with the prices we are selling it today." Russian crude benchmark Urals is currently trading $27 bbl below the global benchmark Brent that fell Monday morning to $75.30 bbl. Oil futures traded modestly higher overnight after a private survey found OPEC+ production fell by 700,000 bpd in November -- the sharpest drop since April 2020. In financial markets, the U.S. dollar was mostly unchanged against a basket of global currencies and equity futures on Wall Street rose slightly Monday morning, with investors squarely focusing on the U.S. Consumer Price Index report due out Tuesday morning and the Federal Reserve meeting that concludes with a final rate decision of the year on Wednesday. Near 7:30 a.m. EST, January West Texas Intermediate futures slipped $0.30 to $70.75 bbl, February Brent futures on ICE falling $0.50 to $75.58 bbl. NYMEX January RBOB futures decline $0.0213 to $2.0348 gallon and January ULSD futures gained $0.0170 to $2.8107 gallon.

Oil Rises as Traders Scoop up Bargains -   Traders swooped in to buy oil at the lowest price this year, as markets digested the fact that a key North American crude pipeline remains shut with no timeline for reopening. West Texas Intermediate rose 3% to settle above $73 a barrel. Oil rallied Monday after prices plunged 11% last week to settle at the lowest price in 2022. Last week, crude closed below its nine-day relative strength index for three days, breaching a technical indicator that suggests oil is oversold and presents a good buying opportunity for some traders. Meanwhile, TC Energy Corp. is continuing recovery efforts at its shuttered Keystone pipeline, that links fields in Canada to refiners on the US Gulf Coast. A date for a restart hasn’t yet been set, according to a statement on Sunday. Refined products also recovered this morning, with gasoline futures rising 1.2% after touching a new low for the year overnight. Crude is on track for its first back-to-back quarterly decline since mid-2019 as the demand outlook sours and thin liquidity exacerbates price swings into the year-end. December was expected to be a rocky month with sanctions on Russian oil shipments taking effect, but the weakening demand outlook — led by risks to global growth — has weighed on prices. As the oil market has softened in recent days, both Brent and WTI have at times traded in contango. The bearish market structure indicates plentiful crude supply over the short term. Russia’s ability to export crude oil without as many disruptions as traders anticipated has left markets softer, Francisco Blanch, head of commodity and derivatives research at Bank of America said in a Bloomberg Television interview. “We have a bit of a soft patch right here; contango is happening but it is very front-loaded,” said Blanch. “You have a modest surplus you need to adjust for, and that’s exactly what the market has done.” Prices: WTI for January delivery rose $2.15 to settle at $73.17 a barrel in New York. Brent for February settlement rose $1.89 to settle at $77.99 a barrel. Following the imposition of the price cap on Russian crude and related curbs, a backlog of tankers waiting to haul oil through Turkey’s vital shipping straits built up amid a dispute over insurance cover. That now appears to be clearing, with a port agent tally on Sunday showing 19 tankers waiting to pass through the Bosphorus and Dardanelles straits, down from a total of 27 on Saturday.

Oil up $2/bbl on supply risks amid ongoing Keystone outage (Reuters) -Oil prices settled up about $2 a barrel on Monday on supply jitters, as a key pipeline supplying the United States closed and Russia threatened a production cut even as China's loosening COVID-19 restrictions bolstered the fuel demand outlook. Brent crude futures settled at $77.99 a barrel, gaining $1.89 or 2.5%. U.S. West Texas Intermediate crude settled at $73.17 a barrel, rising $2.15, or 3%. Last week, Brent and WTI fell to their lowest since December 2021 as investors worried a possible global recession could hurt oil demand. The potential of a prolonged outage of TC Energy Corp's Canada-to-U.S. Keystone crude oil pipeline helped turn prices around. "Keystone Pipeline repair appears to be taking longer than expected (and) upping the possibility of further stock draws at Cushing," Traders worried about how long it would take to clean up and restart the Keystone oil pipeline after more than 14,000 barrels of oil leaked last week, the largest U.S. crude oil spill in nearly a decade. TC Energy shut the pipeline after the spill was discovered late last Wednesday in Kansas. The company told officials in Washington County, Kansas, that they have not yet determined the cause or timeline for a restart. Officials were excavating around the 622,000 barrel-per-day Keystone line, a critical passageway for heavy Canadian crude shipped to U.S. refiners and to the Gulf Coast for export. The outage is expected to shrink supplies at the Cushing, Oklahoma storage hub, and delivery point for benchmark U.S. crude oil futures. Seven analysts polled by Reuters estimated, on average, that overall crude inventories dropped by about 3.9 million barrels in the week to Dec. 9, a preliminary Reuters poll showed. Bank of America Global research said Brent could rebound past $90 per barrel on the back of a dovish pivot in the U.S. Federal Reserve's monetary policy and a "successful" economic reopening by China.

Oil Updates — Crude prices rise on US supply concerns; Libyan oil production at 1.2m bpd | Arab News - Oil prices rose for a second day on Tuesday as a key pipeline supplying the US, the world’s biggest crude consumer, remained shut and on expectations loosening COVID restrictions in China, the second-biggest user globally, will boost demand. Brent crude futures rose $1.03, or 1.32 percent, to $79.02 per barrel by 08.10 a.m. Saudi time, while US West Texas Intermediate crude futures gained 96 cents, or 1.31 percent, to $74.31. The closure of TC Energy Corp.’s Keystone Pipeline, which ships about 620,000 barrels per day of Canadian crude from Alberta to the US, has tightened supplies and raised the prospect that inventories at the Cushing, Oklahoma, storage hub will decline. Cushing is also the delivery point for the WTI crude futures contract. Keystone has remained shut since a 14,000-barrel leak in the US state of Kansas reported on Dec. 7. TC Energy has not released a timeline for a restart of the line, which carries crude to refineries in the Midwest and Gulf Coast. Libya is producing about 1.2 million barrels per day of oil, Oil Minister Mohamed Oun told reporters on the sidelines of a meeting organized by the Organization of Arab Petroleum Exporting Countries. “We hope to return to 2010 levels, which was 1.6 million bpd, within two or three years,” he added. He added that he hoped that Libya’s decision to lift force majeure on oil and gas exploration, which was announced last week, would encourage foreign oil companies to return to the country. Meanwhile, figures from Nigeria’s petroleum regulator suggested that the country’s oil production rose to 1.185 million bpd in November from 1.014 million barrels in October. . A European Commission plan for a gas price cap risks reducing liquidity in Europe’s gas market, posing a threat to how it functions, the head of trading at Norwegian oil company Equinor told Reuters, but its own gas deliveries will not be affected. The aim of the cap is to shield European consumers from the surge in energy prices they have faced since Russia invaded Ukraine, and which has helped to fuel inflation. For Equinor, the biggest concern is what happens to the liquidity in the gas market, Helge Haugane, Equinor’s head of gas and power trading, said in an interview.

Pipeline to the U.S. Remained Shut Amid What Potentially Could Be One of the Coldest Cold Snaps - Oil futures rose on Tuesday, as an important pipeline to the U.S. remained shut amid what potentially could be one of the coldest of cold snaps in decades. This, along with Russia suggesting it might cut production and a cooler than expected U.S. inflation reading pressured the U.S. dollar, which in turn provided support to oil priced in dollars. Oil prices are still down about 15% over the past month and are near the levels from the start of the year, before Russia’s invasion of Ukraine sent prices soaring.  Rising interest rates and an economic slowdown in China as it copes with renewed COVID outbreaks continue to weigh on the market.  January WTI rose $2.22, or 3%, to settle at $75.39 a barrel.  Brent Crude for February delivery gained $2.69 per barrel, or 3.45% to $80.68. RBOB Gasoline for January delivery gained 7.99 cents per gallon, or 3.84% to $2.1609, while ULSD for January delivery gained 12.37 cents per gallon, or 4.17% to $3.0922.  US crude oil prices are now 6.7% higher since the week began, marking one of the largest two-day gains of the year. The price-surge follows a six-session streak of declines through Friday, when WTI crude closed at $71.02 a barrel, the lowest closing price since Dec. 20. Part of the reason for this week's rebound in oil prices is a weaker dollar. Crude prices often move inversely to sharp swings in US currency because oil is bought and sold in dollars.   OPEC stuck to its forecasts for global oil demand growth in 2022 and 2023 after several downgrades, saying that while economic slowdown was "quite evident" there was potential upside such as from a relaxation of China's zero-COVID policy. In its monthly report, OPEC said oil demand in 2023 will increase by 2.25 million bpd or about 2.3% after growth of 2.55 million bpd in 2022. Both forecasts were unchanged from last month. While keeping the annual demand growth forecasts steady, OPEC cut the absolute demand forecasts in the fourth quarter of 2022 and the first quarter of 2023. The report also showed that OPEC's production fell in November after the wider OPEC+ alliance pledged steep output cuts to support the market amid the worsening economic outlook and weakening prices. OPEC said its oil output in November fell by 744,000 bpd to 28.83 million bpd. Officials said cleanup of the biggest U.S. oil spill in nearly a decade will take at least weeks to complete following a meeting with Keystone pipeline owner TC Energy Corp on Monday. TC closed the pipeline after the spill of roughly 14,000 barrels of crude was discovered in a creek last Wednesday in Washington County in Kansas. There is still no official timeline for a restart of the 622,000 bpd pipeline, which will need approval from regulators.

WTI Slides After Big Surprise Crude Build - Oil prices extended yesterday's gains today, ending at their highest in a week,  as colder weather forecasts in the US boosted prospects for energy demand, and a soft CPI print sent the dollar notably lower (and raised optimism among some that a soft landing was still possible).Compounding bullish sentiment, China’s ambassador to the US said the country will continue relaxing its pandemic curbs and will welcome more international travelers soon, lifting demand prospects in the world’s top oil importer.  Additionally, OPEC urged “vigilance and caution” on its members as it reduced estimates for the amount of crude the group will need to pump in the coming months.“As the year 2022 draws to a close, the recent global economic growth slowdown with all its far-reaching implications is becoming quite evident,” OPEC’s Vienna-based research department said in its monthly report.“The year 2023 is expected to remain surrounded by many uncertainties, mandating vigilance and caution.”  The last few weeks have seen notably consistent product builds and crude draws and all eyes are on the API data tonight for signs of a product demand picking up. API

  • Crude +7.819mm (-3.913mm exp) - biggest build since 10/7
  • Cushing +640k
  • Gasoline +877k
  • Distillates +3.9mm

After four weeks of sizable draws, the last week saw an unexpectedly large crude inventory build. Products also yet another weekly build...

WTI Tumbles After Massive Crude Build - -  Oil prices extended gains this morning, despite the across-the-board builds reported by API last night, following comments from the IEA cautioning that prices could rally next year amid a tightening market  “Positioning is now much less distorted than it has been for a while, and hence, perhaps for the first time in six months, short-term risk-reward is now skewed toward higher prices,” Standard Chartered analysts including Emily Ashford wrote in a report. Given the big builds reported by API, all eyes will be on the official data now (especially considering the massive SPR draw last week) as inventories have slipped.  DOE

  • Crude +10.23mm  (-3.913mm exp) - biggest build since March 2021
  • Cushing +426k
  • Gasoline +4.496mm
  • Distillates +1.364mm

API reported builds across the board last night (after 4 straight weeks of sizable draws) and official DOE data confirmed it with a massive 10.23mm barrel build in crude stocks. Additionally there were builds at Cushing and in products...  Total US Crude stocks (ex-SPR) rebounded from their lowest since March (and near the lowest since 2018), but given the collapse in the SPR, total inventories must be near record lows.SPR released 4.7 million barrels (~675,000 b/d). That's the largest weekly release since early October. It puts the SPR at just 382.3 million barrels, the lowest since January 1984...

Oil up third day in row, boosted by U.S. pipeline outage, cold and Fed   - Oil prices rose for a third day in a row as traders looked beyond a big weekly build in U.S. crude inventories to focus instead on the shutdown of Canadian pipeline Keystone, which is vital to refiners in the country’s West Coast. Expectations that the Federal Reserve will start its long-awaited pivot on monetary tightening by slowing rate hikes for the first time since March also boosted sentiment in oil, as it did in other risk assets. Adding to the market’s upside were stronger demand outlooks for oil from producer group OPEC+ as well as the International Energy Agency, which oversees the interest of consumers, A rise in road and air traffic in China after a reopening of cities placed under coronavirus lockdowns also contributed to the fervor of an oil market emerging from its sharpest weekly loss in nine months. The result was a rally of 3% or more in U.K.-origin Brent oil and U.S. West Texas Intermediate, or WTI, crude for a second day in a row. That set the two benchmarks up about 8% on the week, after last week’s plunge of almost 12%. Brent crude settled up $2.02, or 2.5%, at $82.70. It rose about 6% in the past two sessions. The global crude benchmark fell $9.47, or 11% last week, hitting a low of $75.14 — a bottom not seen since Dec 23, 2021. WTI for delivery in January settled up $1.89, or 2.5%, at $77.28. Like Brent, WTI rose a cumulative 6% in the past two sessions. The U.S. crude benchmark ended last week down $9.28, or 11%, making it its worst week since the week ended March 25. WTI’s session low for last week was $70.11 — a bottom not seen since Dec 21, 2021. This week’s rally in oil came amid the closure of the 622,000 barrel-per-day Keystone pipeline carrying Canadian heavy crude to the U.S. Gulf Coast of Mexico. Canada's TC Energy shut the pipeline on Wednesday after it was found to have leaked more than 14,000 barrels of oil in Kansas last week, in the largest U.S. oil spill in nearly a decade. No timeline has been given on how long it would take to clean up and restart the pipeline. Risk appetite in oil got a further boost as traders expected the Fed to announce later on Wednesday an increase of 50 basis points for the central bank’s December rate decision — after four back-to-back jumbo hikes of 75 basis points from June through November. On the demand outlook front, producer group OPEC+ said it expects oil demand to grow by 2.25 million barrels per day (bpd) over next year to 101.8M bpd, with potential upside from China, the world's top importer. Paris-based oil consumers’ alliance IEA said it saw Chinese oil demand recovering next year after a 400,000 bpd contraction in 2022. The alliance raised its 2023 oil demand growth estimate to 1.7M bpd for a total of 101.6M bpd. On the U.S. oil inventory front, crude stockpiles rose for the first time in five weeks as refiners slowed work last week after massively turning out fuel products ahead of the winter, data from the Energy Information Administration, or EIA, showed. Crude inventories rose by 10.231M barrels during the week ended December 9, the EIA said in its Weekly Petroleum Status Report, after a cumulative draw of 26.86M barrels over five previous weeks. Refineries operated at 92.2% of their operable capacity last week, versus 95.5% in the previous week to December 2, the EIA said. Gasoline stockpiles rose by 4.496M barrels during the week to December 9, after a 5.32-million-barrel build the previous week. Gasoline is the top automobile fuel in the United States. Inventories of distillates, meanwhile, rose by 1.364M barrels last week, compared with the rise of 6.159M the week before. Distillates are refined into diesel for trucks, buses, trains and ships as well as fuel for jets. Supply of finished motor gasoline in the marketplace was at 8.255M barrels per day last week, down by 103,000 barrels per day. Distillate fuel oil, meanwhile, saw a rise of 218,000 barrels per day to 3.768M barrels per day. Kerosene-type jet fuel saw a build of 377,000 barrels per day, to reach 1.386M barrels daily.

Oil Steadies on Partial Restart of Keystone, USD Advance  -- Oil futures flipped between modest gains and losses early Thursday as investors parsed through Federal Reserve Chairman Jerome Powell's hawkish comments as the central bank doubles down in its fight against inflation, lifting the U.S. dollar index off a seven-month low in overnight trade, while a partial restart of the shuttered Keystone pipeline that was halted last week due to a leak further pressured the oil complex. TC Energy said late Wednesday that it has restarted operations on sections of the pipeline that were unaffected by the line rupture, including the lines that extend from Alberta, Canada to Steele City, Nebraska, and from Steele City to the refining center in Illinois at Wood River and Patoka. A segment of the pipeline that brings oil from Steele City to the Cushing, Oklahoma storage hub and further south to the Texas refining center won't be restarted until it is safe to do so, and after the company receives approval from federal regulators. The company said it continues to investigate the spill. The 610,000-bpd Keystone pipeline was shut down Dec. 7 after a leak was detected in Kansas, leading to a spill of 14,000 bbl into a nearby creek, which has already become the largest onshore U.S. oil spill in over a decade. A weeklong shutdown of the Keystone pipeline limited the flow of heavy crude oil to Gulf Coast refiners, which need a steady diet of heavy crude to offset the light oil from the Permian to produce middle-of-the-barrel distillate fuel. U.S. Energy Information in its inventory report released Wednesday said refiners in the Gulf Coast cut utilization capacity by 3% during the week-ended Dec. 9. The disruption has yet to show an impact on inventory levels at the Cushing hub, with EIA reporting a 426,000 bbl build last week that lifted stocks there to 24.4 million bbl. Commercial crude oil inventories last week jumped 10.2 million bbl during the week-ended Dec. 9, contrary to expectations for a 3.1 million bbl drawdown. The supersized build was, in part, realized on the back of a 4.7 million bbl transfer of crude oil from the nation's Strategic Petroleum Reserve to the commercial side. In financial markets, the U.S. dollar clawed back some of Wednesday's losses against a basket of foreign currencies to trade 0.58% higher at 104.345, further pressuring the front-month West Texas Intermediate contract. Greenback's move higher follows the Federal Open Market Committee's announcement of a 0.5% increase in the federal funds rate at the conclusion of its Wednesday meeting, in line with market expectations and a stepdown from the 0.75% rate hikes from the previous four meetings. However, the focus remained with FOMC's economic projections that showed a rather bleak outlook for the economy next year, with GDP growth expected to expand by just 0.5%, down from their 1.2% growth outlook in September. FOMC expects the national unemployment rate to rise to 4.6% next year compared with a 3.7% jobless rate in November. For context, that would translate into 1.6 million Americans losing their jobs next year. What's more hawkish, median projections for the peak federal funds rate is now seen ending 2023 at 5.1%, up from 4.6% in September's projections. The federal funds rate is now in a 4.25% to 4.5% target range, meaning the central bank is projecting to lift the key overnight borrowing rate by another 0.75% over the course of 2023. On an annualized basis, inflation was still above 7% in November -- more than three times greater than the Fed's goal. Near 7:30 AM ET, January WTI futures traded little changed at $77.30 bbl, and February Brent futures on ICE were also near unchanged at $82.70 bbl. NYMEX January RBOB futures slipped $0.0136 to $2.2444 gallon and January ULSD futures declined $0.0454 to $3.2313 gallon.

Oil prices slid 2% as dollar firms and central banks hike interest rates - Oil prices slid about 2% on Thursday as traders worried about the fuel demand outlook due to a stronger dollar and further interest rate hikes by global central banks. After rising for three straight days, Brent futures fell $1.49, or 1.8%, to settle at $81.21 a barrel, while U.S. West Texas Intermediate (WTI) crude fell $1.17, or 1.5%, to settle at $76.11. "Crude prices edged lower as ... global recession risks increased after a wave of central banks delivered another strong round of tightening. Oil’s recent rally (ran) out of steam as risk aversion runs wild," said Edward Moya, senior market analyst at data and analytics firm OANDA. Federal Reserve Chair Jerome Powell said on Wednesday the U.S. central bank will raise interest rates further next year, even as the economy slips toward a possible recession. On Thursday, the Bank of England and the European Central Bank raised interest rates to fight inflation. U.S. stock indexes fell sharply as the Federal Reserve's guidance for protracted policy tightening quelled hopes the rate-hike cycle would end anytime soon. "The oil price is under pressure today as the Fed's hawkish guidance for its monetary policy sparked renewed concerns about economic growth, lifting the U.S. dollar and sending commodity prices down," said CMC Markets analyst Tina Teng. A stronger U.S. dollar makes oil more expensive for those using other currencies. U.S. retail sales fell more than expected in November, but consumer spending remains supported by a tight labor market, with the number of Americans filing for unemployment benefits decreasing by the most in five months last week. In China, the world's second biggest economy, lost more steam in November as factory output slowed and retail sales extended declines, the worst readings in six months, hobbled by surging COVID-19 cases and widespread virus curbs. Also pressuring oil prices, Canada's TC Energy said it was resuming operations in a section of its Keystone pipeline, a week after a leak of more than 14,000 barrels of oil in Kansas triggered a shutdown.

Oil Prices Tank 3% As Contract Rollover Nears -- Oil prices slid by 3% early on Friday, erasing the gains from earlier this week, as the contracts are set for rollover and central banks say much needs to be done to curb inflation despite the less aggressive hike rates this week. As of 9:37 a.m. ET on Friday, the front-month U.S. benchmark contract WTI Crude was trading down 3.35% at $73.45. The international benchmark, Brent Crude, was down 3.42% on the day to $78.42, slipping below $80 per barrel again after having reached $82 per barrel earlier this week. Brent at $78 per barrel is the lowest level in a year, lower than before the Russian invasion of Ukraine. Inventory builds across the board in the United States also weighed on oil prices this week, as well as the policy statements from the Fed and other major central banks such as the European Central Bank (EBC) and the Bank of England, which said the taming of the inflation – which may have already peaked – needs continued monetary policy tightening and the rates at the end of the tightening cycle could end up higher than initially estimated.The Fed raised by half a percentage point the federal funds rate on Thursday, ending the several consecutive 0.75 percentage point increases, for now. The Bank of England and the ECB also raised rates by 0.50 percentage points, with the UK rate hike being the ninth consecutive increase since December 2021.The ECB said on Thursday that “interest rates will still have to rise significantly at a steady pace to reach levels that are sufficiently restrictive to ensure a timely return of inflation to the 2% medium-term target.” Oil reversed some of the strong gains seen earlier in the week, “after the Fed’s hawkish tilt was followed by a slew of other G10 central banks, especially the ECB which highlighted the struggle to get inflation under control,” Saxo Bank said on Friday. “Given the current focus on recession potentially hurting demand, a supply side struggle may not positively impact prices until the second quarter, and with that in mind, the price of Brent may settle into a range below $90 until then,” the bank’s strategy team added.

Oil Trims Losses after DOE Announces Start to SPR Refill  -- Oil fell more than 2% on Friday, although all petroleum contracts moved off intrasession lows after U.S. Department of Energy announced it would start repurchasing crude oil for the Strategic Petroleum Reserve to replenish emergency stockpiles after a yearlong sales program aimed at stabilizing oil prices. "This repurchase is an opportunity to secure a good deal for American taxpayers by repurchasing oil at a lower price than the $96 per barrel average price it was sold for, as well as to strengthen energy security," said DOE in a statement released Friday. The initial buy-back would begin with a bid for 3 million bbl to be delivered in February to the SPR storage facility in Beaumont, Texas, with no decision yet announced for additional purchases. In October, the Biden administration announced a plan to replenish the SPR using fixed-price forward purchases of crude oil compared to conventional contracts that DOE said exposes producers to volatile crude prices. The program intends to repurchase crude oil for the SPR when the price of West Texas Intermediate is at or below about $67 to $72 bbl. Initial repurchases were intended for delivery in 2024 or 2025. President Joe Biden in March approved emergency sales from the SPR of 180 million bbl of crude after Russia's invasion of Ukraine led to the price of global benchmark Brent to jump above $130 bbl. DOE said it sold that oil for an average of $96.25 bbl. In reaction to the announcement, West Texas Intermediate for January delivery trimmed earlier losses to settle the session at $74.29 bbl, down $1.82 bbl, and international crude benchmark February Brent fell $1.49 bbl for a $79.04 bbl settlement. NYMEX January RBOB futures declined $0.0345 to $2.1323 gallon and January ULSD futures nosedived $0.1635 to a $3.1199 gallon settlement. Underlying Friday's lower settlements are reports of a steep economic contraction in China after an unprecedented wave of COVID cases pushed its healthcare system to the brink of collapse. Authorities are actively discouraging people from seeking help at a hospital. This has led to panic buying from everyday painkillers to simple grocery items as citizens are resorting to at-home medications. Anecdotal reports show megacities like Beijing and Hong Kong have turned into ghost towns as most residents fell sick or are simply scared to catch the virus. On Dec. 7, authorities in Beijing suddenly lifted all COVID controls in favor of a "let it rip" approach, surprising traders and experts alike. Some studies suggest nearly one million people will die in the coming months because of Beijing's sharp policy U-turn. In the immediate term, the surge in COVID cases will likely lead to a bumpy reopening for China's economy, now mired with a "stop and go" approach the West faced a year ago when Omicron cases surged before eventually leveling off in the spring. As a result, China's economic activity in the first quarter of 2023 is likely to be underwhelming. Analysts estimate that China's demand is lagging somewhere between 700,0000 bpd and 1 million bpd below its pre-pandemic norms.

Oil rally stalls after 4% weekly gain on Keystone closure and SPR repurchase - Blame it on the central banks, but oil’s comeback rally after its worst week since March has been snuffed out by renewed fears of recession and higher-for-longer interest rates in the U.S. to Europe — despite this week’s support from the shutdown of Canadian oil pipeline Keystone, which supplies crude to refineries in the United States U.S. West Texas Intermediate crude for delivery in January settled Friday’s trade down $1.82, or 2.4%, at $74.29 per barrel. Earlier, WTI, as it is known, hit an intraday low of $73.33. For the week, it rose 4% after a 11% drop last week, like Brent. The U.S. crude benchmark fell to as low as $70.11 a week ago — hitting a bottom not seen since Dec 21, 2021. U.K. origin Brent crude for delivery in February settled down $2.17, or 2.7%, at $79.04 per barrel. Earlier, Brent hit a session low of $78.30. For the week though, the global crude benchmark was up 4% after the 11% slump in the week prior that took a barrel of Brent to as low as $75.14 — a bottom not seen since Dec 23, 2021. Recession fears aside, weighing on oil Friday were fears that China’s coronavirus contagion could get out of hand again amid reports of rising fatalities in the world’s largest oil importer. “If COVID spreads freely and many people cannot get care, we estimate that in the coming months 1.5 million Chinese people will die from the virus,” The Economist said. On the positive side, there was just modest support for the market on Friday from news that the Biden administration will start refilling the heavily drawn-down U.S. Strategic Petroleum Reserve, or SPR, from February with an initial purchase of 3M barrels. The administration has drawn down some 200M barrels from the SPR over the past year, sending inventories in the reserve to 38-year lows, as it attempted to bridge a global supply deficit in crude caused by Russia’s invasion of Ukraine and consequent sanctions on Moscow. Reliance on the SPR accelerated after the White House approved a 180M-barrel draw over a six-month period beginning in May. Brent crude hit 14-year highs of almost $140 a barrel in early March, just after the Ukraine invasion, while U.S. pump prices of gasoline hit record highs of $5 per gallon by June. As of Friday, Brent was trading under $75 per barrel while gasoline at U.S. pumps averaged $3.18 per gallon, according to the American Automobile Association — although some areas in the United States with refineries in their proximity had gasoline at under $3 a gallon due to cheaper costs of transporting the fuel. News of the SPR’s refilling, which oil bulls had widely anticipated to re-energize oil prices, came amid a renewed hawkish tone by the Federal Reserve, the European Central Bank and the Bank of England that dampened risk appetite across markets. The stance by the global central banks reignited fears that a recession might be inevitable for the U.S. economy and accelerate the one already happening in Europe. The positive tone in oil was also offset somewhat on Friday by a Biden administration official saying the SPR would also loan out 2 million barrels to domestic energy companies to relieve any supply shortage caused by the Keystone pipeline’s closure. The 622,000 barrel-per-day Keystone pipeline is a critical artery shipping heavy Canadian crude from Alberta to U.S. refiners in the Midwest and the Gulf Coast. It has been closed for a week now, after causing what officials say is the largest U.S. oil spill in a decade. Under the SPR loan arrangement reported Friday, companies will immediately receive an x-amount of barrels from the reserve to resolve the supply crunch emanating from the Keystone crisis and return them much later, at a mutually-agreed time. “It’s a smart hedge, if you ask me,” “Instead of announcing a massive purchase that would take care of the entire 180 million barrels that were drawn down the last six months, the administration chose to just begin with a 3 million barrel purchase. The positive impact on the market will be minimal, just as U.S. consumers at the pump would have liked.”

MENA oil exporters set for fiscal surplus in 2023: report - Credit metrics in oil-exporting sovereigns in the Middle East and North Africa (MENA) will be supported by another year of fiscal and external surpluses in most cases, based on Fitch Ratings’ assumption that Brent crude oil averages $85 a barrel and that production levels broadly stabilise, Fitch Ratings said. MENA oil exporters’ growth will be much weaker in 2023 as oil output stabilises, following a sharp rebound in 2022 when Opec+ countries unwound Covid-19 pandemic-era cuts for much of the year, before a new much smaller cut in November, it said. Slower global growth in 2023 could prompt further Opec+ cuts if the oil market shifts decisively into surplus, but concerns persist about potentially tight supply, including related to Russia, Fitch Ratings said. Gulf Cooperation Council (GCC) non-oil growth will retain some momentum but will slow, from 4.5% on average to 3%, given spillovers from oil prices, higher interest rates and weaker global growth; some post-pandemic gains in 2022 will also fade in 2023. In MENA non-oil economies, credit fundamentals in many countries face risks from high debt burdens and tight external financing conditions amid higher global interest rates; domestic interest rates will also remain high given inflation trends, it said. Growth is likely to be weaker in most cases, affected by lacklustre global trade, higher interest rates, limited fiscal space and risks to particular sectors, including tourism. Multilateral and bilateral financial support is an important mitigant in some countries, alongside some progress with economic and fiscal reforms, the agency said. Fitch Ratings said it added two Positive Outlooks in 2022, for Ras Al Khaimah and Saudi Arabia. Of the 15 MENA sovereigns that Fitch rates, only Egypt is on Negative Outlook, while Lebanon and Tunisia do not have outlooks as Fitch typically does not assign outlooks to sovereigns with a rating of 'CCC+' or below. Lebanon remains in default. Tunisia is rated ‘CCC+’, upgraded in December from ‘CCC’.

Iran publicly hangs second anti-government protester after show trial - In a gruesome attempt to intimidate the populace, Iranian authorities executed an anti-government protester early Monday morning—the second such execution in four days—and publicly circulated photos of his corpse hanging from a construction crane. Twenty-three-year-old Majidreza Rahnavard was hanged “in the presence of a group of Mashadi citizens,” reported the Islamic Republic judiciary’s own Mizan news agency. A court in the northeastern city of Mashhad had convicted Rahnavard of stabbing and killing two Basij security officers and wounding four others in an incident it termed a “terrorist attack.” According to the Oslo-based group Iran Human Rights, Rahnavard “was sentenced to death based on coerced confessions after a grossly unfair process and a show trial.” He was hanged just 23 days after his arrest. Four days earlier, Mohsen Shekari became the first person to be executed for his role in a three-month-long wave of protests that has been the target of ruthless state repression and punctuated by violent clashes between some protesters and security forces. Shekari, also just 23, paid with his life for what an Iranian court said were the crimes of participating in the blocking of a Tehran street and stabbing a Basij security guard, who survived the attack and required just 13 stitches. While the authorities claimed Shekari had confessed, his relatives said he was not allowed legal representation, his trial was held in a closed court, his face showed signs of bruising and his body had not been released. In neither case did the Islamic Republic authorities link their two victims, at least publicly, to the “outside entities,” meaning US imperialism, Israel, and the Saudi absolutist monarchy, which they accuse of fomenting the protests. .

Iranian forces shooting at faces and genitals of female protesters, medics say - Iranian security forces are targeting women at anti-regime protests with shotgun fire to their faces, breasts and genitals, according to interviews with medics across the country. Doctors and nurses – treating demonstrators in secret to avoid arrest – said they first observed the practice after noticing that women often arrived with different wounds to men, who more commonly had shotgun pellets in their legs, buttocks and backs. While an internet blackout has hidden much of the bloody crackdown on protesters, photos provided by medics to the Guardian showed devastating wounds all over their bodies from so-called birdshot pellets, which security forces have fired on people at close range. Some of the photos showed people with dozens of tiny “shot” balls lodged deep in their flesh. The Guardian has spoken to 10 medical professionals who warned about the seriousness of the injuries that could leave hundreds of young Iranians with permanent damage. Shots to the eyes of women, men and children were particularly common, they said. One physician from the central Isfahan province said he believed the authorities were targeting men and women in different ways “because they wanted to destroy the beauty of these women”. “I treated a woman in her early 20s, who was shot in her genitals by two pellets. Ten other pellets were lodged in her inner thigh. These 10 pellets were easily removed, but those two pellets were a challenge, because they were wedged in between her urethra and vaginal opening,” the physician said. “There was a serious risk of vaginal infection, so I asked her to go to a trusted gynaecologist. She said she was protesting when a group of about 10 security agents circled around and shot her in her genitals and thighs.” Traumatised by his experience, the physician – who like all medical professionals cited in this article spoke on condition of anonymity for fear of reprisals – said he had a hard time dealing with the stress and pain he witnessed. “She could have been my own daughter.” Some of the other medical professionals accused security forces, including the feared pro-regime Basij militia, of ignoring riot control practices, such as firing weapons at feet and legs to avoid damaging vital organs. One doctor from Karaj, a city near Tehran, said security forces “shoot at the faces and private body parts of women because they have an inferiority complex. And they want to get rid of their sexual complexes by hurting these young people.” The ministry of foreign affairs was approached to comment on the allegations made by the medics but has yet to respond.

Russia using more Iranian-made drones in attacks on Ukraine infrastructure: think tank --Russia is deploying a “significantly higher number” of Iranian-made drones to attack critical infrastructure in Ukraine than it did in previous weeks, according to an updated analysis from the Institute for the Study of War (ISW). Ukraine’s Air Force Command said on Saturday that Russian forces launched 15 attacks with the Iranian Shahed-136 and 131 drones, targeting infrastructure in Kherson, Mykolaiv and Odesa.About 10 of the drones were shot down, while the rest reached their targets. Facilities in Odesa were severely damaged.Russia had not launched a similar number of Iranian-made drones to attack Ukraine in three weeks, according to the ISW.“The increased pace of Russian drone attacks may indicate that Russian forces accumulated more drones over the three-week period of not using them or that Russia has recently received or expects soon to receive a new shipment of drones from Iran,” the ISW said in its analysis.

No comments:

Post a Comment