natural gas prices settle at a 28 month low; commercial crude oil inventories are at a 20 month high after 8 straight increases and a record 12.1% jump YTD; global oil production exceeded demand by 440,000 barrels per day in January, despite OPEC production that was 931,000 barrels per day below their reduced quota
US oil prices fell for the third week in four on stronger than expected US inflation data and on a massive build of US crude inventories... after rising 8.6% to $79.72 a barrel last week after an earthquake shut a key Turkish pipeline, the Saudis hiked their prices on crude to Asia, and Russia unilaterally cut their oil output, the contract price for the benchmark US light sweet crude for March delivery fell in early Asian trading on Monday on fears that higher US inflation would lead to tighter monetary policy and hence a US recession, but then moved higher in US trading as traders weighed the impact of Russia’s plans to cut production in March, and settled 42 cents higher at $80.14 a barrel as the U.S. dollar retreated ahead of the release of Tuesday's inflation report, and its potential impact on monetary policy...however. oil prices opened lower and fell as much as 3.3% early Tuesday following a late Monday announcement that the US DoE would release more crude from its Strategic Petroleum Reserve, at a time when U.S. markets were already flush with supply, and settled $1.08 lower at $79.06 a barrel following a strong US inflation report that triggered repricing of how aggressive Fed rate hikes would need to be to bring inflation down...oil prices slipped further in early Asian trade on Wednesday, after American Petroleum Institute figures released late Tuesday pointed to a jump in U.S. crude supplies, and then extended those losses in late morning trading after the EIA reported a massive build of US inventories, and as US refiners unexpectedly slowed their run rates, but seesawed in afternoon trading after stronger-than-expected retail sales revealed more evidence of a reaccelerating U.S. economy, strengthening the case for higher interest rates, and settled just 47 cents lower at $78.59 a barrel, as an International Energy Agency forecast for record demand later this year limited losses...oil prices recovered marginally in early Asian trading on Thursday, despite the large build in US inventories, following higher oil demand forecasts for 2023 from OPEC and the International Energy Agency, and rallied further on expectations of a surge in oil demand in China, the world's largest oil importer. but fell back in US trading after the U.S. producer price index offered more evidence of inflation,,raising the odds that the Fed would raise interest rates more aggressively in the coming months and settled 10 cents lower at $78.59 a barrel as traders weighed mixed U.S. economic signals and prospects for a Chinese demand recovery with a big build in U.S. crude stockpiles...;prices slid further in Asian trading on Friday as strong US economic data heightened concern that the Fed would continue tight monetary policy to tackle inflation, which would hit fuel demand even as supply grew, and then plummeted more than 3% in early New York trading as traders repriced the risk that The Fed would bring back larger interest rate increases in the coming months to combat stubbornly high inflation and a tight labor market. and settled $2.15 lower at $76.34 a barrel as oil traders worried that future U.S. interest rate hikes would weigh on demand and about mounting signs of ample crude and fuel supply. thus finishing with a 4.2% loss on the week....
meanwhile, US natural gas prices fell for the ninth week out of the past ten as output increased while forecasts turned warmer....after rising 4.3% to $2.514 per mmBTU last week on weather induced short covering and expectations of higher LNG exports, the contract price of US natural gas for March delivery moved lower in early trading Monday as traders weighed signs of a return to action for the long-idled Freeport LNG export terminal against loose supply balances driven by mild winter weather and settled down 10.9 cents to a near 25 month low of $2.405 per mmBTU on rising output and forecasts for warmer weather than had been expected....Natural gas prices strengthened on Tuesday on signs of life at the long-dormant Freeport LNG export terminal, and on the potential for another cold snap to arrive in the Lower 48 later this month with the March NYMEX gas futures contract settling 16.2 cents higher on the day at $2.567 per mmBTU as the amount of gas going to liquefied natural gas (LNG) export plants jumped to a 10-month high with a rapid increase in gas flows to Freeport LNG's export plant in Texas....however, natural gas futures fell about 4% to $2.471 per mmBTU on Wednesday on forecasts for lower demand than had been previously expected over the next two weeks, even as spot prices moved higher on coal-to-gas switching in the power generation sector...natural gas prices retreated again on Thursday, after the EIA reported that inventories of the heating fuel were 17% higher than a year ago, and settled 8.2 cents lower at a 25 month low of $2.389 per mmBTU, as traders were reminded of the demand weakness that permeated the U.S. market through early 2023...natural gas prices moved lower again on Friday with more warm-ups projected in the 1-15 day temperature outlook further tempering demand, and well production remaining robust and settled down 11.4 cents at a 28 month low of $2.275 per mmBTU, after shedding 9.5% over the week..
The EIA's natural gas storage report for the week ending February 10th indicated that the amount of working natural gas held in underground storage in the US fell by 100 billion cubic feet to 2,266 billion cubic feet by the end of the week, which left our natural gas supplies 328 billion cubic feet, or 16.9% above the 1,938 billion cubic feet that were in storage on February 10th of last year, and 183 billion cubic feet, or 8.8% more than the five-year average of 2,083 billion cubic feet of natural gas that were in storage as of the 10th of February over the most recent five years….the 100 billion cubic foot withdrawal from US natural gas working storage for the cited week was less than was expected by a Reuters survey of analysts, whose average forecast called for a 109 billion cubic feet withdrawal, and it was much less than the 195 billion cubic feet that were pulled out of natural gas storage during the corresponding week of 2022, and also much less than the average 166 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 February 10th indicated that even after a substantial decrease in our oil imports, we had quite a bit of surplus oil left to add to our stored commercial crude supplies for the 8th consecutive week, and for the 27th time in the past 43 weeks, partly due to a significant drop in refinery throughput, but mostly due to a large increase in oil supplies that could not be accounted for... Our imports of crude oil fell by an average of 826,000 barrels per day to average 6,232,000 barrels per day, after falling by an average of 225,000 barrels per day during the prior week, while our exports of crude oil rose by 246,000 barrels per day to average 3,146,000 barrels per day, which combined meant that the net of our trade in oil worked out to a net import average of 3,086,000 barrels of oil per day during the week ending February 10th, 1.072,000 fewer barrels per day than the net of our imports minus our exports during the prior week. Over the same period, production of crude from US wells was reportedly unchanged at 12,300,000 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 15,386,000 barrels per day during the February 10th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,027,000 barrels of crude per day during the week ending February 10th, an average of 383,000 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 an average of 2,326,000 barrels of oil per day were being added to the supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures provided by the EIA for the week ending February 10th appear to indicate that our total working supply of oil from net imports and from oilfield production was 1,967,000 barrels per day less than what was added to storage plus our oil refineries reported they used during the week. To account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a [+1,967,000] 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 was an omission or error of that magnitude in this week’s oil supply & demand figures that we have just transcribed.... Furthermore, since last week’s “unaccounted for crude oil” was at [-702,000] barrels per day, that means there was a 2,669,000 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, thus rendering any such comparisons meaningless nonsense.... However, since most everyone treats these weekly EIA reports as precise, and since these weekly 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)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,619,000 barrels per day last week, which was still 3.8% more than the 6,375,000 barrel per day average that we were importing over the same four-week period last year. This week's 1,967,000 barrel per day increase in our overall crude oil inventories was all added to our commercially available stocks of crude oil, while the amount of oil in our Strategic Petroleum Reserve remained unchanged.. This week’s crude oil production was reported to be unchanged from last week's thirty-three week high of 12,300,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,800,000 barrels per day, while Alaska’s oil production was 4,000 barrels per day higher at 456,000 barrels per day and added 500,000 barrels per day to the the rounded national total....US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was still 6.1% below that of our pre-pandemic production peak, but was 26.8% above the pandemic low of 9,700,000 barrels per day that US oil production had fallen to during the third week of February of 2021.
US oil refineries were operating at 86.5% of their capacity while using those 15,027,000 barrels of crude per day during the week ending February 10th, down from their 87.9% utilization rate during the prior week, but still close to normal utilization for early February, when seasonal maintenance starts to impact throughput. The 15,027.000 barrels per day of oil that were refined this week were 8.4% more than the 14,902,000 barrels of crude that were being processed daily during week ending February 11th of 2022, while 7.3% less than the 16,210,000 barrels that were being refined during the prepandemic week ending February 14th, 2020, when our refinery utilization was 89.4%, also close to normal for early February ...
With the decrease in the amount of oil being refined this week, the gasoline output from our refineries was a bit lower, decreasing by 4,000 barrels per day to 9,089,000 barrels per day during the week ending February 10th, after our gasoline output had decreased by 350,000 barrels per day during the prior week. This week’s gasoline production was still 2.9% more than the 8,830,000 barrels of gasoline that were being produced daily over the same week of last year, while 4.6% less than the gasoline production of 9,525,000 barrels per day during the prepandemic week ending February 14th, 2020. Meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 155,000 barrels per day to 4,692,000 barrels per day, after our distillates output had decreased by 28,000 barrels per day during the prior week. Even with that, our distillates output was 1.2% more than the 4,455,000 barrels of distillates that were being produced daily during the week ending February 11th of 2022, while 7.9 less than the 4,852,000 barrels of distillates that were being produced daily during the week ending February 14th 2020...
Even with the recent decreases in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the twelfth time in fourteen weeks and for the 15th time in 27 weeks, increasing by 2,316,000 barrels to 241,922,000 barrels during the week ending February 10th, after our gasoline inventories had increased by 5,008,000 barrels during the prior week. Our gasoline supplies rose by less this week even though the amount of gasoline supplied to US users fell by 154,000 barrels per day to 8,274,000 barrels per day, and even though our imports of gasoline fell by 400,000 barrels per day to 589,000 barrels per day, while our exports of gasoline fell by 157,000 barrels per day to 786,000 barrels per day.. But even after 12 recent gasoline inventory increases, our gasoline supplies were still 2.1% below last February 11th's gasoline inventories of 247,061,000 barrels, and still about 5% below the five year average of our gasoline supplies for this time of the year…
With the big decrease in our distillates production, our supplies of distillate fuels increased for the 5th time in 7 weeks, and for the 26th time over the past year, falling by 1,285,000 barrels to 119,237,000 barrels during the week ending February 10th, after our distillates supplies had increased by 2,932,000 barrels during the prior week. Our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, increased by 132,000 barrels per day to 3,894,000 barrels per day, and because our imports of distillates fell by 471,000 barrels per day to 221,000 barrels per day, while our exports of distillates fell by 156,000 barrels per day to 1,020,000 barrels per day... After a run of fifty-seven inventory withdrawals over the past ninety-three weeks, our distillate supplies at the end of the week were were 0.8% below the 120,262,000 barrels of distillates that we had in storage on February 11th of 2022, and about 15% below the five year average of our distillates inventories for this time of the year...
Meanwhile, boosted by the big jump in oil supplies that could not be accounted for, our commercial supplies of crude oil in storage rose for the 15th time in 27 weeks and for the 24th time in the past year, increasing by 16,283,000 barrels over the week, from 455,111,000 barrels on February 3rd to 471,394,000 barrels on February 10th, after our commercial crude supplies had increased by 2,423,000 barrels over the prior week. With even larger oil supply increases in the weeks following the Christmas refinery freeze offs, our commercial crude oil inventories were at a new 20 month high, up 12.1% from December 30th, and now about 8% above the most recent five-year average of commercial oil supplies for this time of year, and also about 45% above the average of our available crude oil stocks as of the second weekend of February over the 5 years at the beginning of the past decade, with the apparent disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels. And even 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 February 10th were 14.6% more than the 411,508,000 barrels of oil we had in commercial storage on February 11th of 2022, and 2.1% more than the 461,757,000 barrels of oil that we had in storage during the 2nd Covid surge on February 12th of 2021, and 2.9% more than the 442,883,000 barrels of oil we had in commercial storage on February 14th of 2020…
Finally, with the SPR at a 39 year low and our supplies of all products made from oil trending near multi-year lows over the recent months, we have been watching the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR for a sense of the big picture.. After the commercial crude and gasoline 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 19,209,000 barrels this week, from 1,610,547,000 barrels on February 3rd to 1,629,756,000 barrels on February 10th after our total inventories had increased 3,354,000 barrels the prior week. Even after six straight increases, our total petroleum liquids inventories were still down by 487 887,000 barrels, or by 23.0% from their early pandemic high, but are now up by 3.3% from their December 30th 18 1/2 year low....
OPEC's Report on Global Oil for January
Tuesday of this past week saw the release of OPEC's February Oil Market Report, which includes the details on OPEC's & global oil data for January, and hence it gives us a picture of the global oil supply & demand situation during a period when global demand for oil was increasing after China reopened to foreign travelers and removed the Covid-related lockdowns on its citizens, while oil supplies from Russia were further reduced by the European Union's ban of Russian oil imports by sea, and by the G7's Russian oil price cap....January was also the third month that OPEC and aligned oil producers were operating under a 2 million barrel per day production cut, meant to take roughly 2% of global oil supplies off the market, in response to a perceived global surplus and related lower prices... 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 58), 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 in the bottom right hand corner of the above table, OPEC's oil output decreased by a rounded 49,000 barrels per day to 28,876,000 barrels per day during January, down from their revised December production total that averaged 28,926,000 barrels per day....however, that December output figure was originally reported as 28,971,000 barrels per day, which therefore means that OPEC's December production was revised 45,000 barrels per day higher with this report, and hence OPEC's January production was, in effect, a rounded 95,000 barrels per day less than the previously reported OPEC production figure (for your reference, here is a copy of the table of the official December 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 beginning in November, and while the net 653,000 barrel per day they've cut since were well short of that, OPEC's production was already running 1,585,000 barrels per day below what they were expected to produce when this policy was initiated in October, so the 28,876,000 barrels per day they produced in January still leaves them short of what they were expected to produce during the month, as we'll see in the next table...
The above table was originally included as a downloadable attachment to the press release following the 33rd OPEC and non-OPEC Ministerial Meeting on October 5th, 2022, which set OPEC's and other aligned oil producers' production quotas for November and the following months through 2023, and the quotas shown above were reaffirmed for the first 6 months of 2023 in the press release following the 34th OPEC and non-OPEC Ministerial Meeting on December 4th, 2022....the first column above, labeled "August 2022 required production", actually matches the October 2018 baseline production level on which OPEC and aligned producers have based all of their quotas since the onset of the pandemic, and the "Voluntary adjustment" is the production cut each country is expected to make from that level, leaving each with a Volunary Production level they're expected to hit during 2023, whether they've produced that much recently or not....since war torn Libya and US sanctioned producers Iran and Venezuela have been exempt from the production cuts imposed by the joint agreement that has governed the output of the other OPEC producers since May 2020, they are not shown on the above list, and OPEC's quota excluding them is aggregated under the total listed for the 'OPEC 10', which you can see was expected to be at 25,416,000 barrels per day from November 2022 through December 2023...therefore, the 24,485,000 barrels those 10 OPEC members actually produced in January were 931,000 barrels per day short of what they were expected to produce during the month, with Nigeria, Angola and Saudi Arabia 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 February 2021 to January 2023, and it comes from page 49 (pdf page 59) of OPEC's January 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 49,000 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 increased by a rounded 600,000 barrels per day to average 101.70 million barrels per day in December, a reported increase which came after December's total global output figure was apparently revised down by a rounded 600,000 barrels per day from the 101.70 million barrels per day of global oil output that was reported for December a month ago, as non-OPEC oil production rose by a rounded 700,000 barrels per day in January after that downward revision, with most of January's production growth coming from OECD Americas, OECD Europe, and Latin America, which were partially offset by a further oil production decline in Russia…
After that 700,000 barrel per day January increase in global output, the 101.70 million barrels of oil per day that were produced globally during the month were 3.16 million barrels per day, or 3.2% more than the revised 98.54 million barrels per day that were being produced globally in January a year ago, which was the sixth month of the series of 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 February 2022 OPEC report for the originally reported January 2022 details)…since this month's decrease in OPEC's output contrasts to the reported global increase, their January oil production of 28,876,000 barrels per day was down by 0.2% to at 28.4% of what was produced globally during the month, after their share of the global total in December was revised up from the 28.5% reported last month (due to the large downward revision to global output)….OPEC's January 2022 production was ultimately revised to 28,033,000 barrels per day with the March 2022 OPEC report, which means that the same 13 OPEC members who were part of OPEC last year produced 843,000 barrels per day, or 3.0% more barrels per day of oil this January than what they produced last January, when they also accounted for 28.4% of a smaller global output total…
With the modest increase in global oil output that we've seen in this report, the amount of oil being produced globally during the month was again a bit above the expected global demand, as this next table from the OPEC report will show us..
The above table came from page 28 of the February Oil Market Report (pdf page 38), and it shows regional and total oil demand estimates in millions of barrels per day for 2022 in the first column, and then OPEC's estimate of oil demand by region and globally, quarterly over 2023 over the rest of the table…on the "Total world" line in the second column, we've highlighted in blue the figure that's relevant for January, which is their estimate of global oil demand during the first quarter of 2023….OPEC is estimating that during the 1st quarter of this year, all oil consuming regions of the globe will use an average of 101.26 million barrels of oil per day, which is an upward revision of 220,000 barrels per day from their estimate 101.04 million barrels per day for 1st quarter demand of 2023 a month ago (that revision is highlighted 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 101.70 million barrels per day during January, which would imply that there was surplus of around 440,000 barrels per day of global oil production in January, when compared to the demand estimated for the month...
Note that in addition to figuring the January oil surplus that's indicated by this report, the downward revision of 600,000 barrels per day to December's global oil output that's implied in this report means that the 520,000 barrels per day global oil output surplus we had previously figured for December would now have to be revised to an oil production shortage of 80,000 barrels per day...
This Week's Rig Count
The number of drilling rigs active in the US decreased for the 14th time over the prior 29 weeks during the week ending February 17th, and was 4.2% below the prepandemic level, even after increasing ninety-five times over the past 125 weeks...Baker Hughes reported that the total count of rotary rigs drilling in the US fell by one rig to 760 rigs over the past week, which was still 115 more rigs than the 645 rigs that were in use as of the February 18th report of 2022, but was 1,169 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 2 to 607 oil rigs during the past week, after the number of rigs targeting oil had increased by 10 during the prior week, and there are still 87 more oil rigs active now than were running a year ago, even as they amount to just 37.7% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and while they are now down 11.1% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 1 to 151 natural gas rigs, which was also up by 27 natural gas rigs from the 124 natural gas rigs that were drilling during the same week a year ago, even as they were only 9.4% 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 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 was just one such "miscellaneous" rigs running...
The offshore rig count in the Gulf of Mexico decreased by one to 17 rigs this week, with 16 of those drilling for oil in Louisiana's offshore waters and one also drilling for oil in Texas waters….that Gulf rig count is still up by 5 from the 12 Gulf rigs running a year ago, when 11 Gulf rigs were drilling for oil offshore from Louisiana and one was deployed for oil offshore from Texas….since there aren't any rigs drilling off our other coasts at this time, the Gulf rig count is equal to 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 were also two rigs drilling on inland waters...
The count of active horizontal drilling rigs was unchanged at 700 horizontal rigs this week, which was still 126 more rigs than the 574 horizontal rigs that were in use in the US on February 18th of last year, but just 50.9% of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....however, the directional rig count was down by 1 to 42 directional rigs this week, but those were still up by 11 from the 31 directional rigs that were operating during the same week a year ago…meanwhile, the vertical rig count was unchanged at 18 vertical rigs this week, which was down by 7 from the 25 vertical rigs that were in use on February 18th of 2022…
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 February 17th, the second column shows the change in the number of working rigs between last week’s count (February 10th) and this week’s (February 17th) count, the third column shows last week’s February 10th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 18th of February, 2022...
the Louisiana rig count was down by two with the removal of one of the rigs that had been drilling in the state's offshore waters, and a natural gas rig that had been drilling in the Haynesville shale the northwest corner of that state; the Haynesville rig count remained unchanged, however, as a natural gas rig was added across the border in the Texas part of that formation...meanwhile, Oklahoma saw two oil rigs added in the Cana Woodford, but since the state count is only up by one, a rig must have been removed from an Oklahoma formation not tracked by Baker Hughes at the same time...
to make a determination on what happened in Colorado and Wyoming, we'll check the North America Rotary Rig Count Pivot Table at Baker Hughes, where they include individual well records going back to 2011; there we find that one of the 13 DJ-Niobrara rigs that had been drilling in Weld County, Colorado last week was removed, which means that the rig added in Wyoming was added in that formation, apparently in Laramie county, to leave the Niobrara count unchanged....then, to determine where the rig removed from New Mexico had been drilling, we check the Rigs by State file at Baker Hughes to see what the changes were in the Texas Permian basin; there we find that there were two rigs added in Texas Oil District 8, which overlies the core Permian Delaware, but there was a rig pulled out of Texas Oil District 7C, which overlies the southernmost counties in the Permian Midland...since the Texas Permian was thus up by one rig while the national Permian rig count was unchanged, we can conclude that the rig pulled out of New Mexico had been drilling in the far west reaches of the Permian Delaware, in the southwest corner of that state...meanwhile, one of the District 8 Permian rig additions was targeting natural gas, accounting for this week's natural gas rig increase...
elsewhere in Texas, there were two rigs added in Texas Oil District 1, but there were three rigs pulled out of Texas Oil District 2, both in districts that overlie the Eagle Ford shale...so while it's likely two of those involve offsetting changes in the Eagle Ford, at least one removal was targeting a formation not tracked by Baker Hughes...there was also a natural gas rig added in the Haynesville shale of Texas Oil District 6, while there was also a rig pulled out of Texas Oil District 10, which overlies the Granite Wash basin of the Texas panhandle, but apparently was not pulled from that basin, unless another Granite Wash rig were added in Oklahoma at the same time...if anyone really needs to know, you can dig through the well records of Texas and Oklahoma in the Pivot Table to find out for sure...
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Court of Appeals Issues Significant Mineral Trespass Opinion Upholding Multi-Million-Dollar Future Damages Award -- On January 18, 2023, in TERA, LLC v. Rice Drilling D, LLC, et al., --- N.E.3d ----, 2023-Ohio-273, the Seventh District Court of Appeals issued a key decision concerning mineral trespass law in Ohio. The court of appeals upheld the trial court’s summary judgment decisions in favor of the landowner, Plaintiff TERA, LLC, and against the producers, Defendants Rice Drilling D, LLC and Gulfport Energy Corporation, on the issue of liability and bad faith trespass. The Court additionally upheld a sizable future damages award to TERA following a jury trial on damages. The decision by the court of appeals included holdings on important and current topics in Ohio oil and gas law including the standard for good faith / bad faith trespass and the proper calculation of mineral trespass damages. The dispute in TERA centered on two oil and gas leases in which TERA’s predecessor (and sole member) Thomas Shaw leased to Rice Drilling D “all the oil, gas minerals and their constituents (not including coal) in the formations commonly known as the Marcellus Shale and the Utica Shale” underlying 271 acres of property in Belmont County, Ohio. The leases further reserved to the lessor “all formations below the base of the Utica Shale.” Defendant Gulfport Energy later acquired an interest in the leases. Portions of the property were pooled into several units and horizontal wells were drilled and began producing. However, each of the six wells were drilled past the Utica Shale formation and were producing oil and gas from the Point Pleasant formation, which is located below the base of the Utica formation.Accordingly, Plaintiff TERA filed a lawsuit against the oil and gas producers for conversion and trespass. The trial court granted partial summary judgment in favor of TERA on the issue of liability, concluding that the unambiguous language in the leases reserved the subsurface rights to the Point Pleasant formation to the surface owner. Subsequently, the trial court granted a partial summary judgment in favor of TERA on the issue of bad faith trespass—a determination that significantly increased the amount of potential damages—because the measure of bad faith mineral trespass damages is the value of the oil and gas unlawfully produced at the time of removal without any deductions for any cost or expense incurred by the producers. The case proceeded to a jury trial on damages, just prior to which the trial court issued a ruling limiting the defendants’ ability to present evidence about the actual quantity of gas produced from the wells or the actual price for which it sold, as a sanction for failing to provide that information to TERA during discovery. Ultimately, the jury awarded TERA $40,129,357 in damages, comprised of $23,171,457 in compensatory damages and $18,958,462 in consequential damages, the total being reduced by $2,000,559 for royalties previously paid. The trial court denied the producers’ motions for judgment notwithstanding the verdict and remittitur. The producers appealed to the Seventh District Court of Appeals. In a 2-1 decision, the Court upheld the trial court’s summary judgment decisions that the defendants trespassed and that they did so willfully and in bad faith. The Court upheld the jury’s award of future damages, concluding that the “application of the pv-10 multiplier was essential to compensate Tera for the damages sustained due to the oil and gas companies’ bad faith trespass.” Id. at ¶ 132. And the Court concluded that TERA had proven present and future damages to a reasonable degree of scientific certainty based on expert testimony. Id. at ¶ 100.
Ohio Governor Mike DeWine Greenlights Fracking on State Lands - Cleveland Scene - Environmentalists in Ohio say they're concerned oil and gas operations planned on state lands could harm the health and property of citizens living nearby.Last month Gov. Mike DeWine signed House Bill 507 into law, which approves licenses for companies seeking to extract natural resources from state lands. Former U.S. Department of Energy scientist Yuri Gorby explained that oil and gas wells drilled into the Marcellus and Utica shale dredge-up radium, uranium, and potassium deposits, along with all of the chemicals used in the fracking process. The result generates radioactive waste that can seep into the local drinking water supply. "That the whole process is releasing this material," said Gorby, "and the potential, not just the potential but the reality, is those chemicals and radioactive elements are getting into surface and ground waters and being spread around." Gorby pointed out there are no existing federal or state regulations that treat waste from fracking as hazardous material - known as the Halliburton Loophole in the federal Safe Drinking Water Act.In a press statement, Gov. DeWine said he believes the new law does not fundamentally change the criteria and processes established by the Ohio General Assembly in 2011, that created the policy of leasing mineral rights under state parks and lands. Gorby, now a private consultant, added that in addition to the public health impacts, the extraction, refining, and transportation of natural gas will significantly alter the landscape of public parks and lands. "People in these areas that visit the state parks that enjoy nature," said Gorby, "they really need to know that the information that we are being given by our political leaders and the industry itself, is painting this as 'oh, when this is an operation, you won't even notice this well pad there.' And that is not true."Pennsylvania-based Environmental Attorney Lisa Johnson said these operations could increase residents' exposure to toxic chemicals - noting that children, the elderly, and those living with disabilities are particularly vulnerable. Landowners need to be educated about this," said Johnson, "and demand that these materials be deemed hazardous and that they be regulated."According to data from the state's Department of Natural Resources, more than 250,000 oil and natural gas wells have been drilled in Ohio.
Ohio state lands at risk as new law allows resource extraction through fracking - The Ohio state government's recent approval of oil and gas operations on state lands has raised concern among environmental groups. The new law, House Bill 507, signed into effect by Governor Mike DeWine, allows companies to extract natural resources from state lands by obtaining licenses. However, environmentalists worry that this could risk nearby residents' health and property.A former U.S. Department of Energy scientist, Yuri Gorby, has warned that drilling oil and gas wells in the Marcellus and Utica shale could releaseradioactive waste into the drinking water supply. The drilling process uncovers radium, uranium, and potassium deposits and the chemicals used in fracking. Gorby stated that this radioactive waste has the potential to enter drinking water and spread around the area.The lack of federal regulations on waste from fracking is a significant concern, as the Halliburton Loophole in the Safe Drinking Water Act does not apply to state or federal regulations that treat the waste as a hazardous material.The policy of leasing mineral rights under state parks and lands was established in 2011, and Governor DeWine believes that the new law does not fundamentally alter the criteria and procedures. However, Gorby, now a private consultant, has warned that natural gas extraction, refining, and transportation will significantly alter public parks and lands and harm public health.Gorby said that people who enjoy nature and visit state parks need to be aware of the actual effects of these operations, as they are often portrayed as undetectable. Environmental attorney Lisa Johnson, based in Pennsylvania, agreed that these operations could expose residents to toxic chemicals, with children, the elderly, and people with disabilities particularly vulnerable.Johnson believes that landowners need to be educated about the dangers of these operations and demand that the materials be regulated as hazardous. With Ohio already facing numerous environmental issues, the recent approval of oil and gas operations on state lands is a cause for concern among environmentalists and the public.
Region's Shale Gas, Oil Production Expected to Increase – Youngstown Business Journal – Oil and natural gas produced from the Utica/Point Pleasant and Marcellus shale formations in eastern Ohio, Pennsylvania and West Virginia are projected to increase next month, according to the latest data provided by the U.S. Energy Information…
In Dimock, a Pennsylvania Town Riven by Fracking, Concerns About Ties Between a Judge and a Gas Driller - At first glance, the photograph seems unremarkable: 11 people, all men wearing blazers and ties except for one woman, posing behind a gleaming table. This photo can be found in the 2015 annual report for the Community Foundation of the Endless Mountains, and the article accompanying the picture touts 2015 as “a year to celebrate.” To some residents of Susquehanna County whose lives have been affected by fracking, this picture is not something “to celebrate”: it’s a sign of a potential conflict of interest. That’s because of who it shows standing, side by side, in the second row: George Stark, tanned, grinning widely, hands neatly clasped, and Jason Legg, tight smile, red tie, glasses. Stark was then, and still is, the Director of External Affairs for Cabot Oil & Gas (now called Coterra Energy), the company that pleaded no contest in 2022 to criminal charges of water contamination, brought by then state Attorney General Josh Shapiro, related to drilling in the village of Dimock. In 2015, Legg was elected to the Court of Common Pleas of Susquehanna County as President Judge, a position he also still holds. “He’s right next to him,” said Craig Stevens, a longtime ally of the affected Dimock families who also owns property in Susquehanna County. “These are buddies.” In November, as representatives of the state Attorney General’s office and Coterra Energy met in the Susquehanna County Courthouse in Montrose to finalize the plea deal, Stevens said that Judge Legg asked both parties if he should recuse himself from the proceedings. Neither side objected, according to Stevens.Anthony Ingraffea, who testified as an expert witness in an earlier lawsuit filed by Dimock residents against Coterra, was also in the courtroom that day. If he had asked any of the families whose water had been contaminated, Ingraffea said, ”‘Hey, do you think I’m in conflict?,’ …they would have said, ‘Yes, you are.’” Instead, Dimock residents listened as the charges against Coterra were dropped from eight felonies (out of 15 total original charges) to a single misdemeanor. Coterra would have to pay $16.29 million to build a public water line, but construction could take five years. In the meantime, the company would provide residents with bottled water and water treatment systems. Some residents of Dimock have been without clean water for more than a decade, relying on water buffalos, huge tanks designed to store and haul water. “Before we went to court, they were already building mega pads not a mile from my house,” said Ray Kemble, a Dimock resident whose water is still contaminated. “Six hundred feet from the moratorium line.” In February 2022, Legg recused himself from another case involving Coterra and Ray Kemble. Coterra claimed in this $5 million lawsuit that Kemble and his former lawyers had “tried to extort it through frivolous litigation,” according to the Associated Press. Legg stepped aside after a recusal motion revealed that Coterra had donated $6.4 million to the Community Foundation of the Endless Mountains since 2010. In an expert opinion solicited by Kemble’s former lawyers, Pennsylvania Supreme Court retired Chief Justice Ron Castille recommended that Legg recuse himself from the case because of his role as a board member of the Community Foundation and Coterra’s role as a “significant donor” to the foundation. “Reasonable minds could infer that a board member of a charity (such as Judge Legg) would favor a major charitable donor (here, Cabot Oil) in order to sustain the donor’s continuing financial support,” he wrote. In Castille’s view, “reasonable minds might even conclude that Cabot Oil is seeking a sympathetic judicial forum (a single judge county) with a seemingly friendly judicial official.”
EQT Ready to Curb Activity if Natural Gas Prices Stay Lower for Longer - EQT Corp. continues to wait for antitrust regulators to clear its $5.2 billion acquisition of Tug Hill Inc.’s upstream and midstream assets in West Virginia, and management now expects to provide more details on the timing of the transaction around the middle of the year. The deal, which would add 800 MMcfe/d of production from properties near EQT assets, was originally expected to close in 4Q2022. It was announced last September. EQT has consolidated the Appalachian Basin in recent years, where it now holds more than one million net acres. Management is working to comply with a second request from federal regulators seeking more information about the transaction. However, CEO Toby Rice said the company’s mergers and acquisition strategy would remain unchanged. It continues to target “low-cost, high quality assets,” he said.In the meantime, the largest U.S. natural gas producer expects the market to remain volatile. CFO David Khani said EQT expects higher-cost producers to continue dropping rigs and curbing supplies as prices slide. He added that it could take time to balance the market and provide more support for prices. Last week, U.S. energy companies cut gas-directed rigs by the most in a week since 2017 as prices have nosedived. “What you’re seeing with us this year is putting a plan in place that will get our production capacity back to a 500 Bcf per quarter run rate,” Rice recently told analysts during a call to discuss 2022 financial results. “That will give us the ability to respond in real time if we continue to see gas prices decline.”EQT produced 459 Bcfe in the fourth quarter, down from 527 Bcfe in the year-ago period. It was largely flat year/year, going from 1.86 Tcfe in 2021 to 1.94 Tcfe in 2022. The company is aiming to produce 1.9-2.0 Tcfe this year. EQT has kept production flat in recent years while it waits for more takeaway capacity to come online in Appalachia. Management again said it expects the in-service date for the 2 Bcf/d Mountain Valley Pipeline to slip to the second half of 2024. The project continues to work through regulatory delays. Rice also noted that the company would turn-in-line (TIL) 110-150 wells this year. That would be up from 74 in 2022, when third-party issues hampered the company’s schedule and shifted roughly 30 TILs into 2023, which weighed on 4Q2022 production as well. The company also said it expects to spend $1.7-1.9 billion on capital expenditures this year, excluding the Tug Hill acquisition. That’s up from the $1.3-1.45 billion it guided for at the same time last year. “The low-end of our guidance range contemplates a scenario where we slow our production cadence for the year should natural gas prices continue to deteriorate,” Rice added. EQT has also entered into hedge positions for 2023 and 2024 covering 62% of its production with weighted average floors of $3.37/MMBtu and 10% with weighted-average floors of $4.20. Khani noted that natural gas price volatility has tripled since early 2021. “We think that is going to continue and our hedging strategy really encapsulates that volatility,” he said. The company reported a $4.6 billion loss on derivatives last year amid the spike in volatility. The losses were largely offset from revenue on the sale of natural gas as prices climbed higher. Overall, EQT reported revenue for the year of $7.5 billion, up from $3 billion in 2021.
Antero Able to Generate Profits in Sub-$3 Henry Hub Environment, CEO Says- Antero Resources Corp. is better prepared to withstand a bearish natural gas price cycle than many of its gas-weighted peers, management said Wednesday. CEO Paul Rady hosted a conference call to discuss the Appalachian pure-play’s fourth-quarter and full-year 2022 results. Antero is a leading producer of natural gas and liquids in the Marcellus and Utica shale formations. Antero sells 100% of its production outside the Appalachian Basin, “including 75% into the LNG fairway where we capture premiums” to New York Mercantile Exchange (Nymex) pricing, Rady said. “The majority of our peers have significant exposure to local markets that trade at levels as low as $1.25 back of Nymex. These markets are particularly at risk in times of increasing storage levels, where price is the only mechanism to force shut-ins.” Rady also noted that nearly half the company’s revenue comes from liquids. “The uplift we’ve received from our liquid sales, combined with our premium priced natural gas, provides better stability and predictability in financial and operating results through the different commodity cycles,” the CEO said. CFO Michael Kennedy, also on the call, said the unhedged Henry Hub breakeven natural gas price required for Antero to generate free cash flow (FCF) is estimated at $2.32/Mcf, versus FCF breakevens above $3 for peers in the dry gas-rich Haynesville Shale. Appalachia and the Haynesville, which straddles Western Louisiana and East Texas, are the Lower 48’s most prolific pure gas plays. Appalachia is the leading gas producing basin overall, followed by the oil-rich Permian Basin.
These natural gas ads are full of hot air -- If you’ve read Politico, Axios, or E&E News lately, you may have come across ads claiming that natural gas is an effective solution to the climate crisis.One ad, which appeared last week in an E&E article about a gas industry misinformation campaign, says that “Natural gas is the best way to reach climate goals faster and power our future cleanly, reliably, and affordably.” Another piece of sponsored content published in Politico cites multiple studies to claim natural gas will help America “reach climate goals faster.” It adds: “This is not political conjecture or industry rhetoric.” But these ads, run by the nonprofit Natural Allies for a Clean Energy Future, are the definition of industry rhetoric. The group is wholly run and funded by the fossil fuel industry, as the Guardian and Floodlight reported in June 2022.In addition, the “independent studies” the group cites are not actually independent. An analysis by HEATED shows that each is published by an organization with significant financial ties to the fossil fuel industry.As a result, multiple climate scientists and disinformation experts told HEATED that Natural Allies’s ads are misleading. “Their claims are all either extremely vague or disproved with middle-school-level science,” said Kate Marvel, a climate scientist at Project Drawdown, who previously worked at NASA’s Goddard Institute for Space Studies.“Using natural gas warms the climate. Period, full stop,” said Andrew Dessler, professor of atmospheric sciences at Texas A&M University. “There is no world in which natural gas is a long-term ‘solution’ to the climate problem.”Still, Politico and Axios each defended the practice of running the ads, despite concerns they may be misinforming millions about the climate crisis. “It is not up to us to decide what is factually accurate or what is not factually accurate,” Politico executive vice president Cally Stolbach Baute told HEATED. “We frankly respect our readers enough to be fully transparent with them on our advertising and encourage them to evaluate our journalism on its merit and its accuracy.”
States with fracking disclosure rules have higher water quality: study - Increasing transparency requirements around fracking activity and the specific fluids used in the process are associated with lower pollution levels from that activity, new research shows. A recent study from the University of Chicago’s Energy Policy Institute examined water quality in watersheds where fracking occurred. Specifically, researchers analyzed salt concentration, a common indicator for fracking impact due to its associated health and development hazards. They found consistent improvement on this benchmark in cases where the state imposed disclosure rules. In states with transparency rules, salt concentration fell by up to 17.8 percent. In contrast, their research found no comparable decline for pollutants not specifically associated with the fracking process. Meanwhile, researchers also found that in states with mandatory disclosure rules, fracking firms’ use of chloride-related chemicals declined, and about 5 percent fewer new wells were drilled. They further found that other mechanisms of public pressure were also associated with lower salt concentrations. For example, the greatest drop occurred in areas with more local newspapers and local environmental nongovernment organizations, as well as states with higher rates of Google searches for hydraulic fracturing. The research also indicated water quality is better in regions where more fracking wells are owned by publicly traded companies.
Natural Gas Rig Count Likely Declining on Market 'Softness,' Says Patterson-UTI CEO Lower 48 natural gas-directed rigs are likely to retreat because of weak prices, Patterson-UTI Inc. CEO Andy Hendricks said Thursday. Hendricks held a conference call to share quarterly results and discuss the outlook for contract drilling services, the company’s forté. At the end of January, the company had 130 rigs on average working in the Lower 48.“While gas markets outside of the Northeast may soften in activity, we do not believe that the release of any Tier-1, super-spec rigs from these areas would negatively impact pricing, as utilization for available rigs of this type is near 100%,” Hendricks said.The Houston-based oilfield services company provides contract drilling, pressure pumping and directional drilling for mostly U.S. customers. Hendricks noted that U.S. natural gas activity generally is focused in the Northeast. In Appalachia, he said, “we expect drilling and completion activities to remain steady, as production from those fields primarily services that local region.” Beyond the Northeast, though, “there is going to be some softness in the natural gas markets.” More oil rigs, though, are forecast to go up as demand rises. On balance, “we expect our rig count to increase modestly in 2023,” Hendricks said.Patterson-UTI’s outlook mirrors that of rival Liberty Energy Inc. Earlier this month the Denver-based driller warned that low prices would lead some producers to move gas-directed rigs to oil-rich plays. Customers continue to snap up Patterson-UTI’s top-of-the-line Apex rigs, giving it an edge in pricing. A 13th pressure pumping spread also is set to be reactivated this year. “Our average rig count in the United States increased to 131 rigs in the fourth quarter from 128 rigs in the third quarter,” Hendricks said. Availability for the super-specs “remains constrained. We expect our rig count in the United States will average 130 rigs in the first quarter and then grow modestly throughout the remainder of 2023.”During the final three months of 2022, contract drilling revenue and margins improved, as the company benefited from “successful contract renewals at more favorable pricing,” Hendricks noted.With the contract renewals, average rig revenue jumped by $3,160/day in 4Q2022 to $31,830. Average daily rig operating costs also climbed, up by $190 to $18,380. In addition, the average domestic adjusted rig margin soared by $2,970/day to average $13,450 in the quarter.
Lower Natural Gas Prices Lead Comstock to Cut Rigs in Haynesville - As natural gas prices swing lower from 2022 highs, Haynesville Shale-focused Comstock Resources Inc. said it is dropping two of nine operated natural gas drilling rigs. After a strong third quarter bolstered by high natural gas prices, the Frisco, TX-based independent has taken note as “natural gas prices have fallen over 70% since September,” said CEO Jay Allison during the fourth quarter and full-year earnings call. “In 2023, we will continue to derisk and delineate our western Haynesville play with a two-rig program in 2023 and we are managing our drilling activity to levels to prudently respond to the lower gas price environment we’ve had so far this year,” Allison said. “We’re in the process of releasing two of our operated rigs on our legacy Haynesville footprint to pull down our activity and respond to lower natural gas prices…” Comstock fetched an average realized price of $5.57/Mcf for its natural gas in the final quarter of 2022, versus the 4Q2021 average of $5.22. Full-year 2022 gas prices averaged $6.23/Mcf, nearly double the average in 2021 of $3.63. The independent’s 4Q2022 average realized gas price reflected a 69-cent discount differential from the New York Mercantile Exchange benchmark, the company noted.“This differential was wider than normal, due to the wider regional differentials that we had in the Haynesville and a much weaker Houston Ship Channel and Katy Hub prices that we incurred, really since last summer due to the Freeport shutdown,” CFO Roland Burns said in reference to Freeport LNG going offline last June. “About 7% of our gas is tied to those Gulf Coast markets.”
Low Natural Gas Prices Could Cause A Supply Crunch - Earlier this month, the benchmark price for U.S. natural gas fell below $3 per million British thermal units for the first time in almost two years. Forecasts are that it will remain below $3 until at least the middle of the year. The natural gas price drop is already forcing producers to taper production plans just as Europe begins to plan for its summer gas storage refill season when demand is expected to surge. Since the start of the year, U.S. natural gas prices have slumped by 46 percent. The number of drilling rigs in gas-rich parts of the shale patch rose by 48 percent in the first half of 2022 but now this trend is about to reverse as oilfield service providers warn they will be moving equipment out of gas fields, Reuters reports, citing Liberty Energy and Helmerich & Payne. The surge in drilling rig additions last year was quite understandable: a whole new LNG export mark opened up in Europe, and prices for U.S. natural gas ended up averaging $5.46 per mmBtu for the year. This was the highest price for the commodity in more than ten years, according to Reuters. Of course drillers would add rigs. But then the warm winter that provided a much-needed break for Europe changed things. With storage sites full to the brim and demand lower than the seasonal average, Europe stopped taking so much U.S. LNG. Winter in the United States itself was, for the most part, warm, keeping domestic demand down as well. Prices, consequently, fell. But this may spell trouble for the future. In Europe, gas prices remain highly volatile and much higher than they were before 2022. Early this month, after a substantial slump, these jumped once again on forecasts for a cold spell across much of the continent. Germany’s chief of the energy market watchdog, Klaus Mueller, once again warned Germans were saving too little gas. In Asia, there are signs of recovering demand, thanks largely to the lower prices at which gas is being sold. With China returning to normal after a series of Covid lockdowns last year, this demand is expected to increase even further. Yet it might not be enough to push prices to where they were last year because demand from Europe may remain lukewarm. The continent is ending winter with more gas in storage than it usually has at this time of the year. This is the result of Europe’s luck with the weather from November to January. And this means it would need to buy less gas to replenish that storage in the spring and summer. According to Morgan Stanley, Europe’s higher-than-usual levels of gas in storage means that the risk of a supply gap for next winter is much lower than previously suspected. The bank’s analysts, as quoted by Bloomberg, actually expect there to be enough gas in storage in Europe to offset the drop in Russian pipeline flows and secure enough gas in storage for winter 2023/24. Russian gas supplies to Europe this summer will be 18 billion cubic meters lower than they were last year, Morgan Stanley said, and Europe will have 29 billion cubic meters of gas in key EU members by the end of March. The figures appear to be based on Russian gas exports to Europe after the flow cuts and the sabotage of Nord Stream, which took 5 cubic meters of pipeline export capacity offline last summer. Yet all this means that U.S. gas prices will remain lower for longer, and if prices remain lower, so will production. And if this year Europe doesn’t have last year’s luck with the weather, prices could surge once again because even the most nimble U.S. gas producer cannot respond to a sharp change in gas demand in a matter of hours.
Williams Giving Leg Up to Chevron for Natural Gas Deliveries from Haynesville, Gulf of Mexico - Williams has inked agreements with Chevron U.S.A. Inc. to build greenfield infrastructure onshore and expand a massive offshore system to support growing natural gas deliveries from the Haynesville Shale and deepwater Gulf of Mexico. In one deal, the Tulsa-based pipeline giant would provide gas gathering services for Chevron’s 26,000-acre Haynesville dedication. Chevron in turn made a long-term capacity commitment on Williams’ Louisiana Energy Gateway (LEG) gathering system. LEG, set to ramp in 2024, is designed to collect 1.8 Bcf/d.Additionally, Williams plans to use existing deepwater infrastructure to serve increased gas production from the Chevron-operated Blind Faith platform. . “This is a great example of Williams and Chevron working together to accelerate the development and delivery of natural gas to supply affordable, reliable, ever cleaner energy both here in the United States and overseas,” said Williams CEO Alan Armstrong. For the Haynesville transaction, Williams plans to construct a greenfield gathering system that has connectivity to the LEG. Chevron’s Haynesville production then could be delivered to premium markets via Williams’ Transcontinental Gas Pipeline, or Transco. Supply also could be transported to industrial markets and to LNG export facilities along the Gulf Coast. Chevron overall has an estimated 70,000 net acres in the Haynesville within East Texas. Low transportation cost and proximity to the Gulf Coast position the resource as a competitive, long-term source of gas supply, including for liquefied natural gas exports, Chevron noted. According to Williams, LEG is considered a “key component of Williams’ lower carbon, wellhead-to-water strategy, proving up what an important role natural gas can play in reducing emissions, lowering costs, and providing secure and reliable energy at home and around the world. “LEG is ideally positioned to incorporate carbon capture and storage as a further decarbonizing solution for natural gas production in the rapidly growing Haynesville basin.”
Energy Transfer Working to Sign More SPAs in Tight LNG Market --Energy Transfer LP said the “extremely competitive” environment for long-term LNG contracting has meant slower progress toward a final investment decision (FID) on its proposed Louisiana export project, but the firm is making progress and could announce new deals soon. Co-CEO Marshall McCrea told investors during a quarterly conference call that the team was “disappointed” with the progress it’s made signing long-term sales and purchase agreements (SPA). However, international customers are still looking for supplies, “especially reliable, cheaper gas supplies in the U.S.” Despite the competition between approved U.S. projects, Energy Transfer’s Lake Charles liquefied natural gas terminal proposed for southwestern Louisiana landed six SPAs last year after remaining relatively dormant since 2020. The brownfield project has around 8 million metric tons/year (mmty) under contract out of a base capacity of at least 16.45 mmty. The firm previously guided first cargoes could be delivered in 2026 if an FID was reached by the end of last year.“We still believe we have the best project for a number of reasons, especially with the ability to feed it from so many different basins,” McCrea said.McCrea added the firm’s alternative energy team, formed in 2021, has been meeting with international clients, some of which could be “down the road quite a ways on consummating a new deal.” On the call, Co-CEO Thomas Long said the firm expects global demand for LNG to remain strong for the foreseeable future as the fuel continues to belinked to energy security for regions including Europe.“In addition, U.S. natural gas producers have shown increased interest in committing a portion of their production to long-term sales arrangements at European and Asian natural gas or LNG index prices,” Long said. “We view these two factors as key drivers toward securing additional long-term LNG offtake agreements.”Elsewhere in Louisiana, Energy Transfer could be partnering with Occidental Petroleum Corp. (Oxy) to establish a carbon capture and sequestration project. The firm signed a letter of intent with Oxy to obtain long-term commitments from industrial partners in the Lake Charles, LA, area. If there is enough support, it could lead to a pipeline system to the firm’s Magnolia Hub in Allen Parish, LA.
Freeport LNG seeks approval for return to full commercial service with Liquefaction Train 3 ready, other units close - Freeport LNG wants permission to resume full commercial operations, the operator said in a Feb. 13 filing with US energy regulators, which came a day after the operator of the Texas export terminal shipped its first cargo since a June 2022 fire shut the facility. Freeport told the US Federal Energy Regulatory Commission that its Liquefaction Train 3 is "ready to transition to full, commercial operations and production of LNG" after successfully completing restart activities. The remaining two trains of the 15 million mt/year capacity terminal south of Houston are close, the operator said. To load the first shipment since the outage, Freeport used supplies that were in its storage tanks when the fire forced the terminal offline in June, an Atlantic market source said. The export was loaded onto the BP-chartered Kmarin Diamond, which departed the morning of Feb. 12. A second tanker, the SK-operated Prism Agility, docked at the Freeport terminal Feb. 12 and remained at the facility by early afternoon Feb. 13. Freeport told FERC that Train 3 had been fully restarted and is "is ready to ramp up to full production rates," adding that it is ready to begin restart activities of Train 2 and expects Train 1 to follow "within the next few weeks." Freeport spokesperson Heather Browne declined to comment Feb. 13, but an increase in feedgas deliveries to the Freeport terminal over the weekend was consistent with reports from market sources that a production restart was close. Freeport was scheduled to receive more than 467 MMcf/d of feedgas Feb. 13, based on nominations for the morning cycle that could later be revised, S&P Global Commodity Insights data showed. The scheduled deliveries to Freeport were up from more than 216 MMcf/d Feb. 12, which marked the highest volumes of daily feedgas deliveries to Freeport since outage began. Overall US LNG feedgas demand was nearly 13.3 Bcf/d Feb. 13. Freeport told FERC that it completed a pre-startup safety review of Train 2 and that it had identified and completed work required to restart the LNG production unit. The operator said it planned a similar review for Train 1 and would complete any corrective work to safely restart the facility. Freeport told FERC that since its LNG trains were not involved in the June 8 incident and did not require restoration work, Freeport wants to be able to resume commercial operations once the safety reviews and other work deemed necessary for a safe restart of the units is complete. Freeport asked in the Feb. 13 for FERC to respond the same day.
U.S. natgas drops to near 25-month low despite return of Freeport LNG exports (Reuters) - U.S. natural gas futures dropped by about 4% to a near 25-month low on Monday on rising output and forecasts for milder weather and less heating demand over the next two weeks than previously expected. That price decline came even though U.S. liquefied natural gas (LNG) exports to other countries were on track to jump to their highest since May 2022 after a vessel picked up a cargo from Freeport LNG's long-idled export plant in Texas. Freeport, the second biggest U.S. LNG export plant, shut in a fire in June 2022. The company, which started producing LNG in one of its three liquefaction trains, asked federal regulators on Monday for permission to restart commercial operations at the plant. Front-month gas futures for March delivery fell 10.9 cents, or 4.3%, to settle at $2.405 per million British thermal units (mmBtu). That was just one cent over its $2.396 per mmBtu settle on Feb. 8, which was its lowest close since December 2020. Gas flows to Freeport were on track to reach 0.5 billion cubic feet per day (bcfd) on Monday, up from an average of 43 million cubic feet per day since Jan. 26 when federal regulators approved the company's plan to start cooling parts of the plant. That is still only a fraction of the roughly 2.1 bcfd of gas Freeport can pull in to make LNG when operating at full power. Energy regulators and analysts have said Freeport will likely not return to full capacity until mid March or later. A couple of Freeport's customers - Japan's JERA and Osaka Gas - have said they do not expect to get LNG from the plant until after March. With the amount of gas flowing to Freeport rising the average amount of feedgas going to U.S. LNG export plants climbed to 12.7 bcfd so far in February, up from 12.3 bcfd in January. That compares with a monthly record of 12.9 bcfd in March 2022 before Freeport shut. On a daily basis, however, LNG feedgas was on track to reach 13.3 bcfd on Monday, the most in a day since May 2022 before Freeport shut in June 2022. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell to 97.0 bcfd so far in February, down from 98.3 bcfd in January. That compares with a monthly record of 99.8 bcfd in November 2022. On a daily basis, however, production hit a two-week high of 98.6 bcfd on Saturday as oil and gas wells return to service after freezing earlier in the month in several states, including Texas, New Mexico, Oklahoma and Pennsylvania. Meteorologists forecast the weather would remain mostly warmer than normal through Feb. 28 except for a few cold days around Feb. 17-18 and Feb. 23-25. With three cold days expected next week versus just two this week, Refinitiv forecast U.S. gas demand, including exports, would rise from 119.2 bcfd this week to 122.6 bcfd next week. Those forecasts were lower than Refinitiv's outlook on Friday.
Natural Gas Futures Higher on Freeport Activity, Looming Cold Snap; Cash Markets Mixed - Natural gas futures strengthened on Tuesday, driven in part by signs of life at the long-dormant Freeport LNG export terminal. The potential for another cold snap to arrive in the Lower 48 later this month also proved supportive, with the March Nymex gas futures contract settling 16.2 cents higher on the day at $2.567/MMBtu. April climbed 15.3 cents to $2.652. Spot gas prices were mixed amid a mostly mild weather pattern. NGI’s Spot Gas National Avg. slid 17.0 cents to $2.690.Though the near-term gas outlook is decidedly bearish, the long-awaited return of the Freeport liquefied natural gas export terminal on the upper Texas coast stoked price gains on Tuesday. The first cargo partially loaded and exited the facility over the weekend, and another partial cargo departed Tuesday, according to Kpler vessel-tracking data. Though the recently loaded vessels were supplied with LNG that has been in storage since the summer, feed gas deliveries to the terminal are starting to increase eight months after the terminal shuttered last June following an explosion.Total feed gas volumes hit 13.48 million Dth/d on Tuesday, up from 13.2 million Dth/d on Monday, NGI’s U.S. LNG Export Tracker showed.Freeport LNG also has asked federal regulators for permission to restart all three liquefaction trains. Rystad Energy said it expects Freeport LNG to achieve partial restart this month, though incremental LNG export volumes are expected to be minimal this month. The firm expects the plant to bring all three trains online in March, with a full ramp-up by early April. “Given the facility is capable of providing over 20% of total U.S. LNG exports, the Freeport LNG outage played a significant role in shaping U.S. gas market fundamentals in 2022 and will continue to do so going forward,” said Rystad Vice President (VP) Emily McClain.
Power Burns and Winter Storm Supporting Natural Gas Cash Prices - Natural futures retreated midweek amid strong production and a mostly mild outlook for the remainder of the month. The March Nymex gas futures contract settled 9.6 cents lower at $2.471/MMBtu, and the April contract slipped 9.7 cents to $2.555. Spot gas prices gained ground, however, as the lower price environment is driving coal-to-gas switching in the power generation sector. NGI’s Spot Gas National Avg. climbed 32.0 cents to $3.010. The ongoing warmth that has pressured futures and cash prices alike in recent weeks is showing few signs of a lasting turnaround based on the latest weather data. Models continue to show only a brief period from Feb. 22-26 as having any meaningful cold weather to boost demand. The rest of February should see moderate temperatures and thus, light demand at the national level. NatGasWeather noted that although the current data indicate that cold air would retreat to the Canadian border Feb. 27-28, it is far enough out in time where changes are likely, and potentially to the colder side. This makes each new model run important in case of notably colder or warmer trends. Long-range weather maps also have been inconsistent for March 1-7. Bigger picture, after the next two government inventory reports are accounted for, surpluses are expected to increase to more than 260 Bcf before the cold snap arrives in the Lower 48 around the middle of next week (Feb. 22). For the upcoming Energy Information Administration (EIA) report, to be published at 10:30 a.m. ET Thursday, withdrawal estimates ranged from 82 Bcf to 125 Bcf. That was the range in a Reuters survey of 14 analysts, which produced a median draw of 109 Bcf. A Bloomberg poll produced a median draw of 96 Bcf, while a Wall Street Journal survey averaged at a 100 Bcf withdrawal. NGI modeled an 82 Bcf pull. A withdrawal anywhere within the range would fall far short of last year’s 195 Bcf draw for the similar week and the 166 Bcf five-year average pull.
Natural gas prices dip 3% as stockpiles 17% higher on the year -- Natural gas prices fell 3% Thursday after the U.S. government said inventories of the heating fuel were 17% higher than a year ago, delivering another stinging data to those long on the trade amid an unusually warm winter. Utilities drew a lower-than-forecast 100 bcf, or billion cubic feet, from U.S. natural gas storage for heating and electricity generation last week, according to the EIA weekly report on gas supply-demand. Analysts tracked by Investing.com had expected the EIA, or Energy Information Administration, to report a draw of 109 bcf for the week ended Feb. 10, less than half of the prior week’s consumption of 217 bcf. Worse were total stockpiles of gas, which closed last week at 2.266 tcf, or trillion cubic feet, up 16.9% from the year-ago level of 1.938 tcf. Still, gas prices did not crater on the data, having lost two-thirds of their value over the past two months. With the market seeking more clarity on the potential for cold before winter ends in five weeks, prices have bounced back and forth in the mid $2 levels. The front-month March gas contract on the New York Mercantile Exchange’s Henry Hub settled at $2.3890 per mmBtu, or metric million British thermal units, down 8.2 cents, or 3.3%, on the day. March gas sank to a 20-month low of $2.341 after the previous storage report on Feb. 3. Prior to that, the lowest for a front-month gas contract on the Henry Hub was $2.02, a level struck on Sept. 28, 2020. An unusually warm start to the 2022/23 winter season has led to considerably less heating demand in the United States versus the norm, leaving more gas in storage than initially thought. Responding to the warmth and lackluster storage draws, gas prices plunged from a 14-year high of $10 per mmBtu in August, reaching $7 in December and mid-$2 levels over the past three weeks.
U.S. natgas drops 5% to 28-mth low on warmer forecasts, less heating demand - (Reuters) - U.S. natural gas futures plunged about 5% to a 28-month low on Friday on forecasts for less cold weather and lower heating demand next week than previously expected. "This (price drop) comes as bearish fundamentals have continued to dominate the market with more warm-ups projected in the 1-15 day temperature outlook further tempering demand and production remaining robust," analysts at energy consulting firm Gelber and Associates said in a report. That mild weather should allow utilities to keep pulling less gas from storage than normal for this time of year. Gas stockpiles were already about 9% above their five-year average (2018-2022) and were on track to rise to about 15% above normal this week, according to analysts' estimates. The price drop came despite recent increases in the amount of gas flowing to U.S. liquefied natural gas (LNG) export plants to a 10-month high as Freeport LNG in Texas gets ready to exit an eight-month outage. Front-month gas futures for March delivery on the New York Mercantile Exchange (NYMEX) fell 11.4 cents, or 4.8%, to settle at $2.275 per million British thermal units, their lowest close since September 2020. For the week, the front-month fell about 10% after gaining about 4% last week. With interest in gas markets rising in recent weeks, open interest in gas futures on the NYMEX rose to 1.24 million shares on Thursday, the highest since December 2021. The premiums of futures for April over March and November over October both rose to record highs. The market uses both spreads to bet on winter weather when gas burned to heat homes and businesses causes demand for the fuel to peak. The April over March premium means the market has given up on this winter, while the November over October premium shows that the market is betting on colder weather next winter. The amount of gas flowing to U.S. LNG export plants was on track to reach 13.4 billion cubic feet per day (bcfd) on Friday, the highest since March 2022, due to a rapid increase in flows to Freeport LNG as the facility prepares to exit an outage caused by a fire in June 2022. Freeport LNG, the second-biggest U.S. LNG export plant, was on track to pull in about 0.5 bcfd of gas from pipelines for a fifth day in a row on Friday, according to data provider Refinitiv. When operating at full power, Freeport LNG can turn about 2.1 bcfd of gas into LNG for export. Earlier this week, Freeport LNG asked federal regulators for permission to put the first phase of its restart plan into commercial operation. Phase 1 includes the full operation of the plant's three liquefaction trains, which turn gas into LNG, two storage tanks and one LNG loading dock. Energy regulators and analysts, however, have said they do not expect Freeport LNG to return to full commercial operation until mid-March or later. Federal regulators approved the restart of Freeport LNG liquefaction Train 3, but have not authorized the facility to commence liquefaction operations. Freeport LNG still needs permission from regulators to place new LNG in the tanks and transfer it to ships. Meteorologists forecast the weather would remain mostly near normal through March 4 except for some cold days around Feb. 24-25 and Feb. 28-March 2. That forecast has more warmer than normal days than the previous outlook on Thursday. With colder weather coming, Refinitiv forecast U.S. gas demand, including exports, would rise from 117.2 bcfd this week to 118.6 bcfd next week and 125.0 bcfd in two weeks. The forecast for next week was lower than Refinitiv's outlook on Thursday.
BOEM Adjusts Monetary Penalties for Oil and Gas Companies | Bureau of Ocean Energy Management --The Bureau of Ocean Energy Management (BOEM) today announced a Final Rule that implements the 2023 inflation adjustments for the maximum daily civil monetary penalties contained in BOEM regulations in accordance with Federal law. The Federal Civil Penalties Inflation Adjustment Act Improvements Act (FCPIAA Improvements Act) of 2015 requires Federal agencies to adjust the level of civil monetary penalties for inflation annually. These adjustments are intended to maintain the deterrent effect of civil penalties and to further the policy goals of the underlying statutes. Under the FCPIAA Improvements Act of 2015, this rule adjusts the maximum civil monetary penalties per day per violation to $52,646 for violations under the Outer Continental Shelf Lands Act and to $55,808 for violations under the Oil Pollution Act of 1990. The Final Rule is available via the Federal Register. The adjusted penalty levels will take effect immediately upon publication of this rule.
EPA's refinery exemptions denial not subject to Congressional Review Act, GAO says - EPA’s denial of exemptions for small refineries under the Renewable Fuel Standard last year does not constitute a rule and therefore is not subject to the Congressional Review Act, the U.S. Government Accountability Office said Thursday. The determination closes the door on potential efforts by lawmakers to use the law to undo the agency’s action. GAO concluded in a report Thursday that the agency’s actions fall within the definition of an “order” — not a rule — and are not subject to the CRA’s requirement that they be submitted to Congress. The CRA provides a vehicle for lawmakers to undo recent agency rulemaking through a simple majority vote. GAO was responding to a June request from Sens. Bill Hagerty (R-Tenn.), Shelley Moore Capito (R-W.Va.) and Roger Wicker (R-Miss.) to determine whether EPA’s action on the small refinery exemptions constitutes a rule that would be subject to the CRA. Spokespeople for the senators did not immediately provide comment. Under the RFS program, refiners must blend minimum volumes of renewable fuels into the nation’s fuel supply, but can petition the agency for an exemption. EPA last year finalized a decision to deny 69 pending small refinery exemption petitions, arguing the refineries did not face disproportionate economic hardship caused by compliance with their volume obligations. GAO concluded Thursday that the action falls within the definition of an order because its purpose was to “provide the final disposition” of particular small refinery exemption petitions.
U.S. crude inventories up 16.3M barrels, fourth largest build ever - - U.S. crude stockpiles rose for an eighth straight week last week and almost 10 times more than forecast, government data showed. U.S. crude inventories rose by 16.283 million barrels during the week ended Feb. 10, the Energy Information Administration, or EIA, said in its Weekly Petroleum Status Report. U.S. commercial crude inventories have risen 50.75M barrels so far this year. The climb came as most U.S. refineries entered seasonal maintenance that foresaw less processing of crude. U.S. crude oil refinery inputs averaged 15.0M barrels per day during the week ending February 10, which was 383,000 barrels per day less than the previous week’s average, the EIA said. Refineries operated at 86.5% of their operable capacity last week, the agency added. Typically, inventory runs at this time of the year are about 90% or more. Last week’s crude build was the fourth-largest ever in the history of the EIA’s reporting, data showed. It was also the third largest in eight straight weeks of builds. Industry analysts tracked by Investing.com had forecast a build of just 1.166M for the week. “That's a gigantic build,” analyst Adam Button said on the ForexLive platform. “It's not entirely shocking as the API data late yesterday also showed a large build, but not that large.” Trade group API, or the American Petroleum Institute, using its own data, reported a crude build of 10.507M barrels for the week ended Feb. 10. Besides crude, the EIA also reported a build in stockpiles of gasoline while noting a dip in distillate inventories. On the gasoline inventory front, the EIA reported a build of 2.317M, versus the forecast rise of 1.543M and adding to the previous week's rise of 5.008M. Gasoline inventories have gone up by more than 19M barrels since 2023 began. Automotive fuel gasoline is the No. 1 U.S. fuel product. The EIA said U.S. gasoline demand over the past four weeks slipped by 3.2% from a year ago, to 8.334M barrels per day. Distillate stockpiles resumed their drop last week after rising in the previous week for the first time in five weeks. Distillate stockpiles fell by 1.285M versus the expected build of 0.447M. In the previous week, the distillate build was 2.932M.
US to move forward with scheduled 26M barrel sale from strategic oil reserve - The United States is moving forward with a congressionally required sale of oil from its Strategic Petroleum Reserve (SPR). On Monday, the Energy Department advised that it would sell 26 million barrels from the oil reserve this year — a sale that was required by a 2015 budget law. The transaction comes as the Biden administration seeks to refill the reserve after releasing a record 180 million barrels last year to combat high gasoline prices. The announcement also states that the Energy Department is more broadly seeking to avoid “unnecessary” sales that aren’t related to supply disruption. A department proposal to Congress led to the cancellation of congressionally mandated sales equivalent to 140 million barrels through the December 2022 omnibus bill, the announcement said. The Biden administration has also detailed plans to refill the reserve, saying it would seek to buy the oil when it is priced between $67 and $72 per barrel. President Biden’s move to release SPR barrels last year caused controversy among Republicans, who accused the administration of raiding an important resource for political gain. The GOP-led House recently passed two bills aimed at limiting SPR withdrawals. The administration, however, has defended the sales, saying that presidents of both parties have used the reserve to address oil supply disruptions. It has also pointed to projected savings. The Treasury Department found that Biden’s use of the SPR, alongside coordinated releases from other countries, could have saved consumers between 17 cents to 42 cents at the pump if companies passed along the full value of the savings.
Devon Focusing Capex on Permian Delaware, Says Natural Gas Takeaway Sufficient - Devon Energy Corp. is planning to focus a majority of its capital on the Permian Basin’s Delaware sub-basin this year, management said Wednesday.Oklahoma City-based Devon, a leading Lower 48 independent, operates primarily in the Permian Delaware, Anadarko, Williston and Powder River basins, along with the Eagle Ford Shale. Devon has set a 2023 capital expenditures (capex) budget of $3.6-3.8 billion. The midpoint of the budget would be a 46% increase from 2022’s capex spending of $2.54 billion. The company expects to self-fund the entire budget even if West Texas Intermediate oil prices drop as low as $40/bbl, CEO Rick Muncrief said during the fourth quarter earnings call. The Delaware “will be the top funded asset in our portfolio, representing roughly 60% of our total capital budget for this year,” said COO Clay Gaspar, who joined Muncrief on the call. Gaspar said Devon’s Delaware wells have shown “world-class productivity.” In addition, “The marketing team has done an excellent job of diversifying across multiple transportation outlets and sales points, allowing us to avoid many of the takeaway constraints in the basin,” said Gaspar. “Looking specifically at the gas volumes, approximately 95% of our gas in the Delaware is protected by either firm contracts…or by regional basis swaps.”Across its sprawling Lower 48 portfolio, Devon plans to consistently run 25 rigs throughout the year, resulting in about 400 wells placed online, Muncrief said. More than 200 new wells are planned for the Delaware.Roughly two-thirds of the Delaware drilling activity “will be directed toward development opportunities in New Mexico, with the remaining investment allocated to high-return projects across the company’s acreage in Texas,” management said. Through March, though, “production in the Delaware will be impacted by infrastructure downtime resulting from an outage at a compressor station in the Stateline area along with minor third-party midstream downtime across the basin.”The temporary outages are expected to curtail volumes by about 10,000 boe/d. Devon expects to “resume normal operations by the end of the first quarter.”In the Eagle Ford, Devon is planning to run three rigs during 2023 and bring online nearly 90 wells across its 82,000 net acre position.In the Anadarko, plans are to operate a four-rig program and bring online more than 40 wells across its 300,000 net acre position. Powder River Basin (PRB) activity this year includes drilling about 20 wells across the 300,000 net acre position.Meanwhile, Williston production late last year was impacted by severe winter weather that caused temporary well shut-ins, facility downtime and delays in completion activity. Devon has since restored the affected production. Plans now are in place to bring online around 40 gross wells in 2023 across its 123,000 net acres.
U.S. EPA sets soot pollution rule, energy companies warn of costs - The EPA told Reuters the White House's Office of Management and Budget(OMB) accepted the agency's proposal for review on Feb. 9 and that the final rule was expected by March 23.The EPA docket for the stricter rules has received more than 112,000 comments, including from industry heavyweights who say the EPA is underestimating the cost of implementation by billions of dollars. Kinder Morgan warned the plan would cost an estimated $4.1 billion in upgrades and retrofits to about 950 engines along its pipelines, which carry about 40% of the natural gas consumed in the United States. That estimate is 16 times higher than the one by the EPA, whose assessment for the industry would factor in less than 100 engines for Kinder Morgan, the company said in its letter to the agency.Kinder Morgan and other companies also opposed the EPA's 2026 deadline to get upgrades completed.“It would likely take at least until 2045 to implement the (EPA’s proposal) across all of the engines that currently exceed the proposed emissions limits,” it said.
U.S. oil industry flags concern about EPA's methane 'super emitter' plan (Reuters) - U.S. oil industry groups said on Monday they are concerned the Biden administration's proposed plan to crack down on methane emissions gives too much power to environmental advocacy groups, by forcing companies to react when third-parties report suspected leaks of the powerful greenhouse gas. The Environmental Protection Agency last year unveiled a plan that would allow approved and "credible" third parties using remote sensing technology to report suspected "super emitter" leaks of at least 100 kilograms per hour. Once notified, the company involved would be required to perform a root-cause analysis within five days and take corrective actions within 10 days, according to the plan. "Our concerns are ultimately that this kind of program can have a chilling effect on companies' ability to work with EPA," Frank Macchiarola, senior vice president of regulatory affairs at the American Petroleum Institute, told reporters on Monday, the deadline for public comment on the EPA's proposed supplemental methane rule. Lobby group for independent oil producers the American Exploration and Production Council said in written comments to EPA that the proposal empowers "private entities, such as activist NGO groups, to publicly report 'super-emitter' events and require follow up action without any involvement or data verification." An EPA official did not immediately respond to a request for comment. Methane is the second-biggest cause of climate change after carbon dioxide, and the oil and gas industry is a major source of the gas
Enforcement of Oil and Gas Regulations Under Threat in New Mexico Legislature -- As the 2023 New Mexico legislative session rolls on, the number and pace of hearings, as well as the number of bills filed, has jumped dramatically — and oil and gas issues began bubbling to the surface. This is another record budget year for state government, and everyone has their hand out for some of the money sloshing around state coffers. Oil and gas revenues, depending on how you count, make up some 35%-40% of the total budget — courtesy of record high oil and gas production, coupled with continuing high energy prices. The sheer magnitude of that percentage, coupled with the unpredictable, rollercoaster nature of fossil fuel revenues, has legislators both excited at the near-term fiscal possibilities and nervous about a future when that money suddenly, inevitably shrinks. But that’s not all. About 52% of all greenhouse gases emitted in New Mexico come not from consumers burning gas in cars or in furnaces to heat their homes, as is common in other states, but from oil and gas extraction operations themselves — operations that continue to increase in number. As the state suffers the effects of an ever-warming climate, reining in carbon pollution from its biggest industry is increasingly important for both state government and the planet going forward. Three factors in the physics of climate change make what New Mexico emits now more consequential than what has been emitted in the past. First, the CO2 concentration in the atmosphere is cumulative, because it takes decades for the gas to cycle back out. Warming lags behind the CO2 added, so rising temperatures generated by CO2 added today won’t show up for years. Second, New Mexico emits a lot of methane in the form of natural gas, which is more than 80 times more powerful than CO2 as a greenhouse gas. And third, ever more climate studies show that the timeframe to avert catastrophic change is quickly shrinking. Among the latest from December: James Hansen of Columbia University, whose previous work laid much of the groundwork for current climate science and prognostication, was lead author on a new paper that finds global warming already in the pipeline is greater than previously thought, making further carbon emissions all the more fraught and immediate carbon emission reductions all the more urgent. So if New Mexico is to meet its climate goals, at the very least it has to keep oil and natural gas — particularly natural gas — inside pipelines and out of the atmosphere where it forcefully adds to warming.
Toxic Water Project Sparks Controversy With Navajo Neighbors -In October 2021, workers from a water treatment company irrigated a 10 x 20 foot test plot of scrubby grass on an oil well site near a Navajo Nation chapter house in northwest New Mexico. The grass thickened, grew and later shriveled under the high desert sun and drought. Even so, it nourished a statewide, petroleum-based controversy when locals learned that the company was researching “produced water,” a toxic byproduct of oil and gas development, as part of a program to search for new methods of treatment and disposal of the industrial waste. Daniel Tso, who was chairman of the Health, Education and Human Services Committee of the Navajo Nation Council at the time, says that, since hearing about the test plot, he and others have been working to stop all use of produced water from oil and gas production on the Navajo Nation “through the courts if necessary.” But the oil production and water treatment companies at the center of the issue and the head of a New Mexico group studying produced water are wondering what all the fuss is about, because they say no produced water was used. It’s all a big miscommunication, they say. Even so, that miscommunication highlights the sharp divides between state agencies tasked with protecting human health and the environment, an industry trying to treat and reuse toxic waste and the people who live amid wells in oil and gas fields and feel left out of crucial conversations about regulation and enforcement.
Environmental Groups and Native Leaders Say Proposed Venting and Flaring Rule Falls Short - --The Bureau of Land Management ignored requests for a public hearing on the proposed rules for venting and flaring methane on public and tribal lands, hindering community members’ efforts to reduce the impacts of gas releases.Oil companies collect crude in tanks by their pumps but often vent the methane gas that also comes up out of the ground into the air, unwilling to invest in the infrastructure to capture it. While the companies pay royalties to landowners for the liquid petroleum they take, no payments are made for the vented methane, a wasted resource that is more than 80 times more effective at warming the atmosphere than carbon dioxide. Oil companies also burn methane at the wellhead through a practice known as flaring, either to reduce pressure as a safety precaution or, more typically, to dispose of unwanted natural gas that surfaces as a byproduct of oil extraction. Methane is the primary component of natural gas.Federal regulators have struggled to rein in this massive source of greenhouse gas emissions through venting and flaring. A new rule advancing at the Bureau of Land Management proposes to charge oil producers for the gas they release or burn on federal and Indigenous land. But the proposal falls short of the Biden administration’s commitment to eliminate regular venting and flaring by the oil and gas industries by 2030 through investments in innovations to create more environmentally friendly infrastructure for fossil fuel extraction.
North Dakota Oil Field Explosion Injures One (AP) – One person was severely burned in an explosion and fire at an oil field in western North Dakota, fire officials said. The explosion was reported about 10:30 p.m. Friday at a saltwater disposal site north of Alexander on U.S. 65 in McKenzie County, the Williston Fire Department said in a Facebook post. Preliminary reports indicated several tanks exploded. The cause of the explosion and fire remains under investigation, the fire department said. One man was treated for severe burns and then flown to a regional trauma center, according to the statement. No other injuries were reported. The fire was extinguished about 1:15 .m. Saturday.
Oil field pipeline spill contaminates range land, creek near Williston - A pipeline spill in northwest North Dakota has led to the release of about 5,500 barrels, or 231,000 gallons, of produced water, affecting range land and a creek about 6 miles northeast of Williston. The North Dakota Department of Environmental Quality announced the spill on Tuesday. Produced water is saltwater that can contain oil and drilling chemicals. Grayson Mill Operating LLC on Monday notified regulators of the spill from a pipeline that transports produced water, a waste byproduct of oil production. The brine flowed about 100 feet over range land and into Stockyard Creek, officials said. Containment structures were put in the creek, according to the spill report on file with the state. The cause of the spill is under investigation. Environmental Quality staff are inspecting the site and monitoring the cleanup. Grayson Mill Energy LLC did not immediately respond to a request for comment.
Nevada declares state of emergency due to gas pipeline leak- Nevada is in trouble because there is a problem with a gas pipe that carries gas from Los Angeles to Las Vegas. Because of this, there are not enough gas supplies for everyone. The leak was found at a gas station near Los Angeles. The people who run the pipeline, called Kinder Morgan Energy Partners, are trying to figure out what caused the leak. They say nobody was hurt, and there were no fires because of the leak.The pipelines are expected to start working again today and give gas to those who need it. The governor of Nevada, Joe Lombardo, has declared a state of emergency because of the gas shortage. He has asked for help from the federal government to get more gas to Nevada. He also asked the people in Las Vegas not to buy too much gas at once so there would be enough for everyone.Clark County, which is the area that includes Las Vegas, has also declared an emergency. This will allow more gas to be delivered to the area. Officials in Nye County, Nevada, have said that the gas pipes are starting to work again and that people should try to wait to buy gas if they can.In the past, Kinder Morgan has had problems with their pipelines. In 2020, they had to pay a fine of $2.5 million because a gas pipe broke and spilled gas into a water channel in California. Last year, there was a gas spill in Illinois because of the cold weather.To sum up, Nevada is facing a state of emergency because of a gas pipeline leak. This has caused a shortage of gas in the area. The pipeline's people are trying to figure out what caused the leak. The pipelines are expected to start working again today, and the governor of Nevada has declared a state of emergency.He has asked for help from the federal government to get more gas to the area. Clark County has also declared an emergency so more gas can be delivered. Officials in Nye County have said that the pipes are starting to work again and that people should wait to buy gas if they can. Kinder Morgan has had problems with their pipelines in the past.
Watch NBC Nightly News with Lester Holt Excerpt: Gas pipeline leak causes panic in Nevada - NBC.com video
Gas pipeline to Vegas to resume operating after shutdown - (AP) — A pipeline facility in California that was forced to shut down deliveries of gasoline and diesel from the Los Angeles area east to areas including Las Vegas and Phoenix due to a leak, resumed operations on Saturday, according to the pipeline's operator. The source of the leak was isolated within its Watson Station in Long Beach, California, and the facility began to deliver fuel by Saturday afternoon, according to pipeline operator Kinder Morgan. The amount and cause of the leak were under investigation, said Kinder Morgan communications manager Katherine Hill. Clark County officials said they believed supplies would not be affected by the leak. “As the pipeline is expected to be fully operational by this evening, I again urge Las Vegas residents to refrain from panic buying fuel,” said Nevada Gov. Joe Lombardo, who had declared a state of emergency to help mitigate the impact of the leak. Kinder Morgan said the leak was discovered Thursday afternoon at a company station near Los Angeles and that its CALNEV and SFPP West pipelines were shut down while the Houston-based pipeline operator worked to resolve the issue. The pipeline provides fuel storage facilities in southern Nevada with unleaded and diesel fuel, according to Clark County officials. Another pipeline operated by UNEV Pipeline LLC serves the Las Vegas area from northern Utah. The Kinder Morgan website says its 566-mile (911-kilometer) CALNEV pipeline transports gasoline, diesel and jet fuel from Los Angeles refineries and marine terminals through parallel 14-inch (35.5-centimeter) and 8-inch (20-centimeter) diameter pipelines to Barstow, California, and the Las Vegas area. Hill said later that only the larger, 14-inch (35.5-centimeter) pipeline to Las Vegas had been shut down.
California Oil Industry Uses High Gasoline Prices to Roll Back Climate Agenda, Critics Allege - Over the last few years, as California has introduced stronger regulations on oil and gas drilling aimed at protecting public health, a pattern of events has started to emerge.Here’s how it typically goes: After years of advocacy, environmentalists successfully push for new oil and gas drilling regulations. Then the industry fights back; companies pour money into an anti-regulation referendum, buying advertising and hiring canvassers to claim that they’re protecting jobs. Though they’re accused of misleading people into signing their petitions, the tactic works as regulations are suspended until voters have a final say. That scenario — in which, for example, oil giants including Aera and Chevron spent $7 millionto gather signatures and sway Ventura County voters, who elected to toss out local restrictions on oil drilling projects in 2022 — is now being repeated, but on a much bigger scale.This time, the industry is taking aim at California’s setbacks law, SB 1137, which bans new and reworked wells within 3,200 feet of homes, schools and hospitals and was signed with much fanfare by Gov. Gavin Newsom in September 2022. On Feb. 3, California Secretary of State Shirley Weber certified that referendum after canvassers collected 978,610 signatures. The state agency that oversees oil and gas drilling has since suspended the law pending the vote on the referendum on Nov. 5, 2024.“It’s like I’m having PTSD seeing the same playbook they did on a smaller level, now on a larger level,” said Tomás Rebecchi, Central Coast organizing manager for Food and Water Watch, who organized for years to pass the doomed setbacks ordinance in Ventura County.Now the industry is planning the same for the whole state. A PAC organized by the California Independent Petroleum Organization (CIPA) spent over $20 million on signature gathering, with some of the biggest donors rushing to put new wells in the prohibited zone last year. Most of the funds were sent to PCI Consultants, the same firm contracted by the fast food industry to overturn state legislation meant to improve fast food workers’ wages and working conditions.
MSC part of $45m settlement for Southern California pipeline spill - Mediterranean Shipping Company (MSC) has confirmed it is part of $45m settlement for claims from October 2021 pipeline spill in California, although maintains full responsibility for the incident lies with pipeline owner Amplify Energy. MSC said in a statement that it was part of settlement with local business owners and residents in Orange County, California by shipping companies alleged to be involved in the incident. The MSC Danit and Cosco Beijing are accused of allowing their ships to drag anchor damaging the pipeline which led to a spill of 25,000 barrels of oil on 2 October 2021. Although the pipeline spill occurred in October 2021, the MSC vessel involved was alleged to have damaged the pipeline in January of that year. The settlement has to be approved by the courts, and MSC said: “Additional terms of a formal settlement are still being negotiated and once reached will have to be approved by the Court.” While MSC is part of the proposed settlement it continues to claim that pipeline owner Amplify is responsible for the spill. The company said it agreed to the joint fund proposal in order to move forward in a “positive and constructive manner”. Last year Amplify agreed to pay $50m to residents and businesses affected by the spill which are reported to include, a Huntington Beach surf school, coastal property owners, a Seal Beach bait and tackle store, and several groups of fishing and seafood sales companies. MSC said expert reconstruction showed its vessel had maneuvered “a reasonable and prudent manner despite adverse weather and intense marine traffic in January 2021”. The incident occurred in a period when large numbers of vessels were anchored offshore from the Ports of Los Angeles and Long Beach due to severe congestion at the two US West Coast Gateway ports. “MSC's investigation has revealed that the pipeline did not comply with its original permit to be built sufficiently away from the federal anchorage zone in which the MSC Danit and other ships were anchored, and that the negligent conduct of Amplify Energy including its repeated failure to take reasonable preventative steps to better protect its pipeline and detect latent damage was the true cause of the oil spill,” MSC alleged.
Alaska Native leaders, US senators back major oil project (AP) — Alaska’s Republican U.S. senators and several Alaska Native leaders on Tuesday urged the federal government to approve a major oil project on the petroleum-rich North Slope, casting the project as economically critical for Indigenous communities in the region and important for the nation’s energy security. The Biden administration “damn well better not kill the project, period,” Sen. Lisa Murkowski told reporters on a video conference. The U.S. Bureau of Land Management earlier this month released an environmental review for ConocoPhillips Alaska’s Willow project that listed as a preferred alternative an option calling for up to three drill sites initially, compared to the five that had been favored by the company. It is an option project proponents, including Alaska’s bipartisan congressional delegation, have expressed support for. But Murkowski and Sen. Dan Sullivan said any further limiting of the project could kill it. The Bureau of Land Management noted its listing of a preferred alternative “does not constitute a commitment or decision.” The U.S. Interior Department said separately that it had “substantial concerns” about the project and the report’s preferred alternative, “including direct and indirect greenhouse gas emissions and impacts to wildlife and Alaska Native subsistence.” The Bureau of Land Management falls under Interior.
Imperial Oil files cleanup plan for tailings leak in Alberta - Imperial Oil Ltd. has filed a plan for the interim cleanup of what could be one of the largest oilpatch spills in Alberta history. Imperial spokeswoman Lisa Schmidt confirmed in an email Monday that the plan was submitted on Friday. Neither Imperial nor the Alberta Energy Regulator are releasing new information about the massive spill and nearby seepage that forced the regulator to issue an environmental protection order last week. The size of the affected area and the total amount of the releases is unknown. A spokeswoman for the regulator said it can't release any information while it's investigating how more than 5,000 cubic metres of tailings overflowed from a dam at Imperial's Kearl site north of Fort McMurray. That alone would make it one of Alberta's largest spills, but Imperial must also deal with a separate but nearby seepage of an unknown amount of toxic tailings into groundwater, which has also pooled on the surface. “On Nov. 29, 2022, Imperial Oil confirmed that the substance is industrial wastewater and is seeping from its external tailings area through a common fill layer placed during construction, mixing with shallow groundwater, and coming to surface,'' says the order from the regulator. The seepage has been going on since at least May and continues. It exceeds federal and provincial guidelines for iron, arsenic, sulphates and hydrocarbons that could include kerosene, creosote and diesel. Imperial submitted a cleanup plan in December. But the regulator ruled that plan wouldn't get rid of the mess until after the spring melt, which could send the contaminants into the nearby Firebag and Muskeg Rivers. The plan submitted Friday was to indicate how spill remediation could be complete before then. Imperial's plan is supposed to include ways to stop and clean up both the leak and seepage as well as outline a plan to communicate it to the public. Although information released so far suggested there have been no wildlife impacts, the plan is also to study those effects and include a “plan for the humane euthanasia of impacted fish and wildlife.”
Oil and gas industry earned $4 trillion last year, says IEA chief (Reuters) - The global oil and gas industry's profits in 2022 jumped to some $4 trillion from an average of $1.5 trillion in recent years, the head of the International Energy Agency (IEA), Fatih Birol, said on Tuesday.Despite those profits, countries depending on oil and gas revenue should prepare to reduce their reliance on petroleum as demand is going to fall in the longer term, Birol told a conference in Oslo while speaking via video link. "Especially the countries in the Middle East have to diversify the their economies. In my view, the COP28 (climate summit) could be an excellent milestone to change the destiny of the Middle East countries," Birol said."You cannot anymore run a country whose economy is 90% reliant on oil and gas revenues because oil demand will go down," he addedThis year's United Nations climate talks will be hosted by the United Arab Emirates, a members of the OPEC group of oil producing countries.
U.S. carried out Nord Stream bomb attack under top secret plan led by Joe Biden, report claims | Daily Mail Online - Specialized U.S. Navy diving teams carried out the bombing attack against the underwater Nord Stream pipelines which supply Russian gas to western Europe during a top secret mission overseen by President Joe Biden, a bombshell report claims.Divers planted C4 explosives on three Nord Stream pipelines in June 2022 which were detonated three months later using a sonar buoy which broadcast a signal that triggered the bombs, according to the report.The attack was carried out in response to Vladimir Putin's invasion of Ukraine and designed to force Germany and other European nations to end their reliance on Russian gas, it is claimed. The move would also disrupt Moscow's income from gas sales - which have contributed billions of dollars to its war effort.The sensational report by Pulitzer Prize-winning journalist Seymour Hersh, published to his Substack, cites a source 'with direct knowledge of the operational planning' behind the alleged plot. The White House and the CIA flatly rejected the report on Wednesday, branding it 'complete fiction'.Nord Stream 1 and 2 pipelines were sabotaged by bomb blasts on September 26 2022 in an attack that, ostensibly, continues to baffle investigators. While analysts say the immediate impact of the attack was 'limited' - because the pipelines were not fully operational - the geopolitical consequences were huge.A report by Pulitzer Prize-winning journalist Seymour Hersh claims the U.S. was responsible for the Nord Stream pipeline attacks. Navy divers alleged planted the explosives in June, using NATO exercises as cover. They were then detonated remotely in September, it is claimed.Various theories have been floated for who carried out the attack, and how. Both the U.S. and Russia deny responsibility.The blasts happened on September 26, 2022. The report claims U.S. Navy divers planted the explosives three months earlier, in June, before they were remotely detonated. Russia, which has pointed the finger at the U.S., reportedly believes repairs will cost at least $500 million, but the Kremlin still hasn't confirmed the pipes will be fixed. The Nord Stream project cost around $20 billion and took 15 years to construct. In a compelling, 5,000-word report about the alleged attack, Hersh claims diving experts trained at the U.S. Navy Diving and Salvage Center in Florida planted the explosives.The divers are said to have carried out the top secret and highly-dangerous operation during BALTOPS22, a series of military exercises in the Baltic Sea carried out by 16 NATO countries. The U.S. divers reportedly used the highly-publicized, 13-day event in June 2022 as cover for their top-secret mission.The C4 explosives attached to the pipelines were fitted with sensors that enabled them to be detonated remotely at a later date, Hersh reports.Hersh reports that the explosions were triggered by a sonar buoy dropped by an aircraft. The buoy emitted a sequence of 'unique low frequency tonal sounds', compared to those produced by a flute or piano, which triggered the C4.A spokesman for the White House said the report is 'false and complete fiction'. A spokesman for the CIA said: 'This claim is completely and utterly false.'In February, Biden said the U.S. would 'bring an end' to Nord Stream if Russia invaded Ukraine. During a joint news conference with German Chancellor Olaf Scholz, Biden said: 'If Russia invades... then there will be longer Nord Stream 2. We will bring an end to it.'Asked how he would do that, the President responded cryptically: 'I promise you we will be able to do it.' The press conference was held as Russia was mounting tens of thousands of troops at its border with Ukraine, in preparation for the invasion which began weeks later, on February 24.
The War Of Terror Of A Rogue Superpower - Cui Bono- - by Pepe Escobar -- Everyone with a brain already knew the Empire did it. Now Seymour Hersh’s bombshell report not only details how Nord Stream 1 and 2 were attacked, but also names names: from the toxic Straussian neoliberal-con trio Sullivan, Blinken and Nuland all the way to the Teleprompter Reader-in-Chief. Arguably the most incandescent nugget in Hersh’s narrative is to point ultimate responsibility directly at the White House. The CIA, for its part, gets away with it. Hersh’s report happened to pop up immediately after the deadly earthquakes in Turkey/Syria. This is an investigative journalism earthquake in itself, straddling over fault lines and revealing countless open air fissures, nuggets of truth gasping for air amidst the rubble. But is that all there is? Does the narrative hold from start to finish? Yes and no. First of all, why now? This is a leak – essentially from one Deep State insider, Hersh’s key source. This 21st century “Deep Throat” remix may be appalled at the toxicity of the system, but at the same time he knows that whatever he says, there will be no consequences. Cowardly Berlin – ignoring the nuts and bolts of the scheme all along – will not even squeak. After all the Green gang has been ecstatic, because the terror attack has thoroughly advanced their medieval de-industrialization agenda. In parallel, as an extra bonus, all the other European vassals receive further confirmation this is the fate that awaits them if they don’t follow His Master’s Voice. Hersh’s narrative frames the Norwegians as the essential accessory to terror. Hardly surprising: NATO’s Jens “Peace is War” Stoltenberg has been a CIA asset for perhaps half a century. And Oslo of course had its own motives to be part of the deal; to collect loads of extra cash selling whatever spare energy it had for desperate European customers. A little narrative problem is that Norway, unlike the U.S. Navy, still does not have any operational P-8 Poseidon. What was clear at the time is that an American P-8 was commuting back and forth – with mid-air refueling – from the U.S. to Bornholm island. A positive screamer is that Hersh – rather, his key source – had the MI6 completely vanish from the narrative. SVR, Russian intel, had focused like a laser on MI6 at the time, as well as the Poles. What still cements the narrative is that the combo behind “Biden” provided the planning, the intel and coordinated the logistics, while the final act – in this case a sonar buoy detonating the C4 explosives – may have been perpetrated by the Norwegian vassals. The problem is the buoy may have been dropped by an American P-8. And there’s no explanation of why one of the sections of Nord Stream 2 escaped intact. Arguably the whole planet is thinking what will be the Russian response. Surveying the chessboard, what the Kremlin and the Security Council see is Merkel confessing Minsk 2 was merely a ruse; the imperial attack on the Nord Streams (they got the picture, but might not have all the insider details provided by Hersh’s source); former Israeli PM Bennett on the record detailing how the Anglo-Americans killed the Ukraine peace process which was on track in Istanbul last year. So it’s no wonder that the Ministry of Foreign Affairs has made it clear that when it comes to nuclear negotiations with the Americans, any proposed gestures of goodwill are “unjustified, untimely and uncalled for.” The Ministry, on purpose, and somewhat ominously, was very vague on a key issue: “strategic nuclear forces objects” that have been attacked by Kiev – helped by the Americans. These attacks may have involved “military-technical and information-intelligence” aspects. When it comes to the Global South, what the Hersh report imprints is Rogue Superpower, in giant blood red letters, as state sponsor of terrorism: the ritual burial – at the bottom of the Baltic Sea – of international law, and even the Empire’s tawdry ersatz, the “rules-based international order”. It will take some time to fully identify which Deep State faction may have used Hersh to promote its agenda. Of course he’s aware of it – but that would never have been enough to keep him away from researching a bombshell (three months of hard work). The U.S. mainstream media will do everything to suppress, censor, demean and ignore his report; but what matters is that across the Global South it is already spreading like wildfire. Meanwhile, Foreign Minister Lavrov has gone totally unplugged, much like Medvedev, denouncing how the U.S. has “unleashed a total hybrid war” against Russia, with both nuclear powers now on a path of direct confrontation. And as Washington has declared the “strategic defeat” of Russia as its goal and turned bilateral relations into a ball of fire, there can be no “business as usual” anymore.
Russia wants UN Security Council to ask for NordStream blast inquiry -(Reuters) - Russia wants the United Nations Security Council to ask for an independent inquiry into September attacks on the Nord Stream gas pipelines, connecting Russia and Germany, that spewed gas into the Baltic Sea. Russia gave the 15-member council a draft resolution on Friday, seen by Reuters, which would ask U.N. Secretary-General Antonio Guterres to establish an international investigation into the "sabotage" and identify who was to blame. Russia's Deputy U.N. Ambassador Dmitry Polyanskiy said the aim was to put the text to a vote within a week. A council resolution needs at least nine votes in favor and no vetoes by the United States, Britain, France, China or Russia to pass. This means a vote could coincide with meetings of the U.N. General Assembly and Security Council to mark the first anniversary of Moscow's invasion of Ukraine. The 193-member General Assembly is likely to vote on Thursday to again demand Moscow withdraw its troops and call for a halt to hostilities. Sweden and Denmark, in whose exclusive economic zones the attacks on the NordStream pipelines occurred, have concluded the pipelines were blown up deliberately, but have not said who might be responsible. The United States and the North Atlantic Treaty Organization have called the incident "an act of sabotage." Moscow has blamed the West. Neither side has provided evidence. Investigative journalist Seymour Hersh, who won a Pulitzer Prize in 1970, wrote last week - citing an unidentified source - that U.S. Navy divers had destroyed the pipelines with explosives on the orders of President Joe Biden.
Europe Gas Futures Indicate Energy Crisis May Linger for Months - European natural gas prices are set to move higher through the rest of the year, futures contracts show, a sign that the energy crunch isn’t over yet. Benchmark Dutch futures for December are currently priced above €60 per megawatt-hour, compared with about €54 for March. Both are elevated for their respective times of year, though far below the record-setting levels seen last August. As the past year has shown, prices can change quickly along with the supply situation. Mild weather and steady imports of liquefied natural gas have so far helped to prevent energy rationing and blackouts in Europe. But attention is now turning to refilling stockpiles, this time without Russia as the primary supplier, due to the fallout over its invasion of Ukraine. In the coming weeks, the European Commission plans to consult with member states over whether to prolong emergency steps to reduce gas demand. Those measures, put in place at the height of the crisis, are set to expire at the end of March. Traders are focusing on the market for LNG to replace lost supplies form Russia. With few long-term contracts to deliver the super-chilled fuel to Europe and limited supply, competition is high with Asia. “Prices seem likely to remain structurally higher than they were before the Russian invasion,” Henning Gloystein, director for energy, climate and resources at Eurasia Group, said in a note. “New regasification capacity in Europe — especially in the big industrial gas hubs of Germany, Italy, and the Netherlands — will help avoid serious supply shortages, though steeper LNG costs and risks of sudden price spikes could cause energy shortages,” he added. Most of the recent LNG deals are for deliveries from new plants starting from the middle of the decade. That makes the next two winters challenging as Europe needs to tap spot markets for the fuel. Spot LNG prices are at about $16-$17 per million British thermal units, while long-term contract prices are much lower, according to Inspired Energy. Dutch front-month gas, Europe’s benchmark, rose for a second session, trading 3.1% higher at €54 per megawatt-hour by 11:57 a.m. in Amsterdam.
South Asia's LNG import appetite on radar after price plunge: Maguire -(Reuters) - Traders of liquefied natural gas (LNG) and climate watchers alike are both on the lookout for signs of a rise in import demand from buyers across South Asia, which until 2022 had been the world's second largest market for LNG after North Asia. For LNG traders, more demand from buyers in India, Pakistan and Bangladesh would tighten global LNG supplies, and may support prices that have slumped nearly 70% since August on lower consumption in key markets such as Europe and China. For climate watchers, South Asia's appetite for LNG has a direct correlation with the region's use of high-polluting coal to generate power, with higher use of cleaner-burning LNG a goal for government and businesses keen to reduce emissions. A key factor that complicates the outlook for South Asian LNG demand is how cost-sensitive buyers are across the region. In 2022, South Asian imports of LNG dropped by their most on record in response to the steep climb in LNG prices to record highs, ship tracking data from Kpler shows. But with benchmark LNG prices now sharply off their 2022 peak and forecasted by forward markets to remain relatively flat over the coming year, 2023 may trigger a turnaround in demand for LNG in India and elsewhere across South Asia, with potentially significant repercussions for both gas markets and regional air pollution levels. The 16.5% drop in LNG imports in 2022 from 2021 was the first annual decline in South Asia's LNG imports since 2013, according to ship tracking data from Kpler. That in turn helped free up LNG supplies for other buyers last year, especially in Europe where utilities were forced to replace reduced pipelined natural gas supplies from Russia with LNG imports following the outbreak of the Russia-Ukraine war. However, reduced LNG imports also triggered more coal demand in South Asia, with total thermal coal imports by the region jumping by 11.5% to over 173 million tonnes in 2022. That reversed a declining trend in coal imports into South Asia since 2019, and pushed up coal purchases by more than any other region last year. South Asia also dialled up imports of other fuels that can be used in power generation in 2022, including diesel and fuel oil that can release sulphur and other pollutants when burned to generate power. In combination, the forced adjustment of power fuels and sharp swings in fuel imports pushed power prices higher last year, and along with a rise in interest rates took a toll on South Asian industry through widespread reductions in output levels.
Factbox: How the EU ban on Russian crude affects oil flows | (Reuters) - Russian oil exports to the European Union fell by 430,000 barrels per day to 1.4 million bpd in November from the previous month, according to the International Energy Agency (IEA). Russian seaborne crude volumes dropped by 330,000 bpd to 500,000 bpd, below Druzhba pipeline deliveries of 590,000 bpd for the first time, it said in a monthly oil market report. As a result, the EU's share of Russian crude oil exports fell to 28% in November from 31% in October, and from 50% before Moscow's invasion of Ukraine on Feb. 24. Meanwhile, Russian crude exports to India reached a record of 1.3 million bpd in November, while exports to China, including seaborne and pipeline, were broadly unchanged at 1.9 million bpd. On Dec. 5, the EU ban on Russian crude imports and a G7 price cap on Russian seaborne exports at $60 per barrel came into effect, which is expected to reduce Russia's output. Exports of Russian crude via Druzhba pipeline to eastern Europe are exempt from the ban, but the IEA expects already reduced supplies to fall further forcing Russia to shut in more production. The EU is seeking to offset the decline in Russian crude imports by increasing supplies from the Middle East, West Africa, Norway, Brazil and Guyana, the IEA has said. The United States and Kazakhstan could help to replace the approximately 1.1 million bpd of Russian oil that will be lost after Dec. 5, according IEA estimates in its previous report in November. Norway also plans to ramp up output from Western Europe's largest oilfield, Johan Sverdrup, in December. The field's Phase 2 development could add 200,000 bpd when it reaches the peak next year, its operator Equinor (EQNR.OL) has said. Some Russian oil will continue to flow into the EU via pipelines as the ban excludes some landlocked refineries in eastern Europe. Germany, the Netherlands and Poland were the top importers of Russian oil in Europe last year, but all have capacity to import seaborne crude from elsewhere. The EU's dependence on Russia has also been underpinned as companies such as Rosneft (ROSN.MM) and Lukoil (LKOH.MM) control some of the bloc's largest refineries. Germany, however, has taken control of the Rosneft-owned Schwedt refinery, which supplies about 90% of Berlin's fuel needs, while the Lukoil-owned ISAB refinery in Sicily could be sold by the end of the year. EU countries that received temporary exemptions to import Russian crude oil are not allowed to export products obtained from this feedstock. Bulgaria, Slovakia and Hungary have all considered the potential impact on run rates of this restriction and are seeking to arrange exemptions for trading any excess products, the IEA said.
India's Russian oil imports surge to a record in January - trade (Reuters) - India's Russian oil imports climbed to a record 1.4 million barrels per day (bpd) in January, up 9.2% from December, with Moscow still the top monthly oil seller to New Delhi, followed by Iraq and Saudi Arabia, data from trade sources showed. Last month Russian oil accounted for about 27% of the 5 million bpd of crude imported by India, the world's third-biggest oil importer and consumer, the data showed. India's oil imports typically rise in December and January as state-run refiners avoid maintenance shutdowns in the first quarter to meet their annual production targets fixed by the government. Refiners in India, which rarely used to buy Russian oil because of costly logistics, have emerged as Russia's key oil client, snapping up discounted crude shunned by Western nations since the invasion of Ukraine last February. Last month India's imports of Russian Sokol crude oil were the highest so far at 100,900 bpd, as output from the Sakhalin 1 field resumed under a new Russian operator, the data showed. In January, India's imports of oil from Canada rose to 314,000 bpd as Reliance Industries (RELI.NS) boosted purchases of long-haul crude, the data showed. Canada emerged as the fifth-largest supplier to India in January after the United Arab Emirates, the data showed.
Russia to send most 2023 oil exports to friendly countries after output cut announcement | S&P Global Commodity Insights - Russia plans to send most of its 2023 oil exports to non-sanctioning countries, Deputy Prime Minister Alexander Novak said, days after announcing a significant crude production cut from March. Russia plans to ship 80% of its Russia's crude oil and condensate exports and 75% of its refined products exports to "friendly" countries, Novak said in a column published in an energy ministry magazine Feb. 13. "Today, we continue to seek and find new markets," Novak said, without elaborating on exact volumes planned for export, nor how this would compare to 2022 shipments. Russia is redirecting oil exports away from the traditional markets in Europe due to Western sanctions introduced in response to Russia's invasion of Ukraine launched in February 2022. To mitigate the impact of this lost market share, Russia is significantly increasing oil exports to countries including China, India and Turkey. In 2022 Russian exports grew by 7.6% to 242 million mt, equivalent to around 4.9 million b/d, Novak said. Russia estimates that its oil output rose 2% to 535.2 million mt in 2022, equivalent to around 10.75 mil b/d. Analysts expect sanctions introduced in late 2022 and early 2023 to hit oil production and exports, however. From Dec. 5, an EU embargo on seaborne imports of most Russian crude oil and a $60/b price cap agreed by the G7 and Australia came into force. Russia responded by banning the sale of oil under price cap conditions. To date, the restrictions have not had a major impact on Russian crude oil production volumes. Russian output fell 10,000 b/d on the month to 9.85 million b/d in January, according to the latest Platts survey by S&P Global Commodity Insights. That compares with 10.11 million b/d in February 2022. From Feb. 5, a similar embargo on Russian oil products was introduced alongside price caps of $100/b for imports of Russian products that typically trade at a premium to crude, such as diesel, gasoline and kerosene, and $45/b on products like fuel oil that generally trade at a discount to crude. The latest sanctions are expected to have a significant impact on production and export volumes in coming months.
Exclusive: China ministry meets refiners for update on Russian oil trade -sources - (Reuters) - China's commerce ministry has met independent oil refiners to discuss their deals with Russia, five sources with knowledge of the matter said, imports which have saved Chinese buyers billions of dollars. China and India are buying at deep discounts amid Western sanctions on Russian oil and more recently, embargoes and price caps. In discussions with about 10 independent refiners last week, the ministry enquired about the volumes and prices of their Russian oil imports, the sources said. Officials also asked refiners if they had encountered any obstacles in these transactions, they added. "The government wants to understand how much independent refiners could possibly buy and their actual appetite for such imports," said one source with direct knowledge of the discussions. The sources declined to be named as the discussions were not public. The ministry did not respond to a request for comment.
Australian Court Overturns Natural Gas Exploration Ban -- The Federal Court of Australia on Tuesday quashed a decision by former Prime Minister Scott Morrison to block a natural gas exploration license offshore Australia’s east coast, ruling that the refusal to allow exploration was biased. Last year, the former Australian government, led by Morrison, and the petroleum authority issued a decision to block the exploration permit offshore Australia, a large gas producer and major LNG exporter, but one that faces a gas crisis on its east coast.The former government had said that Petroleum Exploration Permit PEP-11 would not go ahead.“This project will not proceed on our watch,” Morrison said in December 2021.“Gas is an important part of Australia’s current and future energy mix but this is not the right project for these communities and pristine beaches and waters.”After the former PM said the project would not proceed, the Commonwealth - New South Wales Offshore Petroleum Joint Authority efused the application for exploration.However, the license holders, Asset Energy and Bounty Oil & Gas NL, sued last year to have the blocking of the permit overturned, saying that “In making the Decision, the Former Prime Minister breached the requirements of procedural fairness in that he predetermined the Application and the purported decision was infected by actual bias.”Today, the Federal Court “has agreed with the consent position reached by the parties, quashed the Decision and concluded that the Decision of the Joint Authority was affected by apprehended bias,” BPH Energy, the owner of Asset Energy, said in a statement. “In light of the decision of the Federal Court of Australia the PEP 11 Joint Venture sincerely hopes that the relevant applications can be re-considered in a timely manner and according to law by the Ministers now comprising the Joint Authority,” BPH’s chief executive David Breeze said, commenting on the court decision.
CCSIRO under fire over 'nonsense' report on offsetting Beetaloo Basin fracking emissions The CSIRO is defending a report on the prospect of offsetting massive new greenhouse gas emissions from developing the Beetaloo Basin, in the face of calls for the findings to be reviewed or thrown out. The report, which was published on Friday, found it would be technically possible to offset emissions from developing the basin south-east of Darwin, but only if a number of challenges were overcome. In the meantime, the Northern Territory government is preparing to announcewhether it will allow full-scale fracking to go ahead and has promised all domestic emissions from the basin will be offset if it does.Offsetting a small-scale fracking industry would use up 10 per cent of all carbon credits available annually in Australia, the authors found.They also said it would require the use of "nascent" carbon capture and storage (CCS) technology, which is not yet proven to work at scale.The costs of offsetting the emissions were not calculated and it was assumed that the bulk of Beetaloo gas would be exported from Darwin.However, the offsets calculations underpinning the report have been labelled "wildly unrealistic" by whistleblower and former head of the Clean Energy Regulator's offsets integrity committee, Professor Andrew MacIntosh. The territory government promised a plan to offset emissions would be in place before full-scale fracking begins.(Supplied: Empire Energy) In a follow-up interview, Professor MacIntosh said that, while he had collaborated with and greatly respected the work of many CSIRO researchers, "in this case, something has gone wrong". He said the amount of pollution the report estimated could be offset using a range of abatement methods — such as revegetation of certain land categories — was "demonstrable nonsense".
OPEC Output Drops As Saudi Production Falls By 156,000 Bpd - Crude oil production from all 13 OPEC members slid by 49,000 barrels per day (bpd) in January from December as top producer Saudi Arabia slashed output by 156,000 bpd, OPEC’s latest Monthly Oil Market Report (MOMR) showed on Tuesday. OPEC’s crude oil production in January fell by 49,000 bpd from December to average 28.88 million bpd, according to secondary sources in OPEC’s report. Saudi Arabia, the biggest producer and de facto leader of the cartel, pumped 10.319 million bpd in January, down by 156,000 bpd month on month, and more than 100,000 bpd below its quota of 10.478 million bpd as part of the OPEC+ agreement, set out at the October meeting and valid from November 2022 through December 2023, or until OPEC+ decides otherwise. A Bloomberg survey found earlier this month that OPEC’s crude oil production fell in January due to cuts by Saudi Arabia which may have been steeper than the Kingdom’s quota. Saudi Arabia, however, self-reported to OPEC that its crude oil production averaged 10.453 million bpd in January, up by 17,000 bpd from December. According to OPEC’s secondary sources, Nigeria and Angola boosted their production the most, by 65,000 bpd and 47,000 bpd, respectively. But these producers are among the biggest laggards in their OPEC+ targets—they continue to pump well below their quotas. The monthly Reuters survey pegged OPEC’s January production nearly in line with the OPEC figures from secondary sources reported today—production at 28.87 million bpd, down by 50,000 bpd from December. The 10 OPEC members that are part of the OPEC+ collective target production were estimated to have produced around 920,000 bpd below the January target, per the Reuters survey. Going forward, OPEC and OPEC+ don’t plan to change the course in oil production targets after Russia announced last week a 500,000 bpd cut in its output for March.
IEA raises 2023 global oil demand estimates on China’s reopening - The International Energy Agency has raised its 2023 global oil demand estimates as top crude importer China reopens its economy after about three years of adhering to a strict zero-Covid policy. Global oil demand will rise by 2 million barrels per day to 101.9 million bpd this year, said the agency, which had forecast a growth of 1.9 million bpd last month. “Nearly a year on from Russia’s invasion of Ukraine, global oil markets are trading in relative calm,” the Paris-based agency said in its monthly oil market report on Wednesday. “World oil supply looks set to exceed demand through the first half of 2023, but the balance could quickly shift to deficit as demand recovers and some Russian output is shut in.” China, which is expected to consume 900,000 bpd of crude this year, “dominates” the growth outlook, with the reopening of its borders boosting air traffic, the agency said. Jet fuel demand will increase by 1.1 million bpd to 7.2 million bpd, or about 90 per cent of 2019 levels, according to the agency's estimates. Meanwhile, global crude output is expected to rise by 1.2 million bpd this year, driven by non-Opec+ countries, said the agency, which expects Russian supply to contract this year on western sanctions. Russia, the world’s second-largest oil producer after Saudi Arabia, said it would cut oil production by 500,000 bpd, or about 5 per cent of its crude output, in March after the West imposed price caps on its crude and refined oil products. On February 5, the G7 and the EU agreed to set the price cap at $100 a barrel for products that trade at a premium to crude, such as diesel, and $45 a barrel for products that trade at a discount, such as naphtha and fuel oil. Russian oil exports in January rose by 300,000 bpd from a month ago to 8.2 million bpd, the agency said. The country’s export revenue stood at $13 billion, slightly higher than in December, but down 36 per cent from the same period a year ago, the agency said. “The impact on Russia’s product exports following the EU embargo and price cap … will be a key factor when it comes to meeting that demand growth,” said the agency.
OPEC Raises World Oil Demand Forecast For 2023 -- OPEC has raised its world oil demand growth forecast for 2023 by 100,000 bpd, to 2.3 million bpd the organization said on Tuesday in its latest edition of the Monthly Oil Market Report. The demand growth forecast calls for 400,000 bpd in growth from Organization for Economic Cooperation and Development (OECD) countries and 2 million bpd from non-OECD countries. The organization did not make significant changes to its 2022 overall world oil demand growth forecast, although it made downward OECD demand adjustments, and upward non-OECD demand adjustments, largely on the back of “improvements in economic activity in some countries and a slight recovery in oil demand in China after the lifting of its zero-Covid-19 policy.” OPEC did not make any changes to the 2022 demand for OPEC crude oil either, which remains at 28.6 million bpd—around 500,000 bpd higher than in 2021. But for this year, OPEC revised up its demand outlook for OPEC crude oil by 200,000 from its previous forecast, to 29.4 million bpd—800,000 bpd higher than last year. Global oil demand for last year is estimated to have grown by 2.5 million bpd, according to the MOMR, on the back of growth from both OECD and non-OECD countries with the exception of China, which saw its oil demand fall as its net zero Covid-19 policies took hold. For oil products, OPEC sees transportation fuels as the main drivers of oil demand, with gasoline and diesel consumption forecast to increase 1.1 million bpd year over year—well above pre-pandemic levels. Jet fuel demand is also expected to rise 1.1 million bpd year over year as travel recovers. According to OPEC, the “key” to oil demand growth this year will be the return of China from its Covid-19 economic slumber. OPEC also delicately mentioned “geopolitical tensions” as a 2023 “global economic concern” that could impact the demand for crude oil and crude oil products.
The UAE Is Worried About An Oil Supply Shortage In 2024 - Declining oil production in many countries and the potential of insufficient crude supply will be a bigger problem for the oil market next year than how demand will evolve, according to the United Arab Emirates (UAE). “I’m not worried about demand — what worries us is whether we are going to have enough supplies in the future,” the UAE’s Energy Minister Suhail Al Mazrouei told Bloomberg TV on Tuesday.“What worries me is the decline that I see in many countries’ production,” said the top energy official at one of OPEC’s biggest producers and most influential members. According to Al Mazrouei, the global oil market is currently balanced. This suggests that the OPEC+ group will not rush to change production quotas in light of Russia’s announcement last week that it would cut its production in March by 500,000 bpd.The OPEC+ group currently doesn’t plan to change the course in its oil production targets after Russia announced the cut, two delegates from the OPEC+ alliance told Reuters on Friday. According to the Kremlin, Russia discussed its plan to cut production with some members of the OPEC+ alliance, in which Russia is a key member leading the group of non-OPEC producers. Russia, however, had not formally consulted with OPEC+ on its plans before announcing the decision, a Russian government source has told Reuters.Concerns from the UAE about oil supply next year were the latest statements from major OPEC figures who also said this week that the oil industry has been suffering from years of chronic underinvestment.The industry has been “plagued by several years of chronic underinvestment,” OPEC’s Secretary General Haitham Al Ghais said earlier this week, calling on climate activists to look at the big picture and allow for an orderly energy transition.Environmental, Social, and Governance (ESG) investment, if outright biased against the oil and gas industry, is a threat to energy affordability and energy security, Saudi Aramco’s CEO Amin Nasser said this weekend.
Oil prices fall ahead of crucial upcoming US inflation data | Philippine News Agency – Oil prices fell on Monday ahead of the release of critical United States inflation data due later this week, sparking recession fears in the country. International benchmark Brent crude traded at $85.56 per barrel at 09:55 a.m. local time (0655 GMT), down 0.96 percent from the closing price of $86.39 a barrel in the previous trading session. At the same time, American benchmark West Texas Intermediate (WTI) traded at $78.86 per barrel, a 1.07 percent drop after the previous session closed at $79.72 a barrel. Oil prices came under pressure ahead of the release of US inflation data. This week, markets will focus on macroeconomic data, especially the consumer price index (CPI) in the US, and statements from US Federal Reserve (Fed) officials. Sentiments over soaring inflation raised oil demand concerns and caused a decrease in prices. The acceleration in economic activity in the world's largest oil importer, China, raised hopes of a demand recovery while limiting price declines. On the supply side, Russia's March announcement of a 500,000-barrel cut in oil production raised supply concerns. In a statement last week, Russian Deputy Prime Minister Aleksandr Novak warned that Western countries' price caps on Russian oil and petroleum products could cause supply problems in the market. Reiterating that Russia will not sell oil to those who impose a price cap, Novak said Russia would reduce production to maintain market balance.
Oil edges higher as market weighs Russian supply cuts amid demand fears (Reuters) -Oil prices edged higher on Monday, rebounding from early losses, as investors weighed Russia's plans to cut crude production and short-term demand concerns ahead of U.S. inflation data this week. Brent futures for April delivery rose 22 cents, or 0.3%, to $86.61 a barrel, while U.S. crude rose 42 cents, or 0.5%, to $80.14 per barrel gain. "With China reopening, we will see more demand and Russia and OPEC has the same or less supply, which is bullish." Oil prices rose on Friday to their highest in two weeks after Russia, the world's third-largest oil producer, said it would cut crude production in March by 500,000 barrels per day (bpd), or about 5% of output, in retaliation against Western curbs imposed on its exports in response to the Ukraine conflict. The United Arab Emirates' energy minister said there was no need for the OPEC+ group of oil-producing nations to meet earlier than scheduled as the market was balanced. Both the Brent and WTI contracts rose more than 8% last week, buoyed by optimism over demand recovery in China after COVID curbs were scrapped in December. U.S. main stock indexes also rose on Monday. The U.S. Federal Reserve has been raising interest rates to rein in inflation, leading to concerns the move would slow economic activity and demand for oil. "It is difficult to overstate the importance of this single data point, as traders and the Fed look for confirmation of the gradual downward trend of the past few months," Additionally, supply concerns were relieved somewhat as a cargo of Azeri crude set sail from Turkey's Ceyhan port on Monday, the first since a devastating earthquake in the region on Feb. 6. Ceyhan is the storage and loading point for pipelines that carry oil from Azerbaijan and Iraq. Also on the supply side, U.S. shale crude oil production in the seven biggest shale basins is expected to rise to its highest on record in March, the Energy Information Administration said on Monday.
The U.S. Government Said it Would Release More Crude from its SPR --The oil market started the session lower on news that the U.S. government said it would release more crude from its SPR, while the market looked for U.S. inflation data for further direction. The U.S. Department of Energy announced it would sell 26 million barrels of oil from the SPR, which is already at its lowest level since 1983. The market opened slightly lower and traded mostly sideways after testing its support at the $79.00 level. However, the market sold off sharply, extending its losses to over $2.60 as it posted a low of $77.46 following the release of the CPI data. The inflation report showed that the inflation rate was 6.4% in January. However, the market, which retraced nearly 38% of its move from a low of $72.25 to a high of $80.62, bounced off its low and retraced most of its losses as the market continued to digest the data. While the U.S. consumer prices increased in January, the annual increase was the smallest since late 2021, pointing to a slowdown in inflation and likely keeping the Federal Reserve on a moderate interest rate hiking path. The market traded sideways during the remainder of the session, ended the session in negative territory for the first time in three session. The March WTI contract settled down $1.08 at $79.06 while the April Brent contract settled down $1.03 at $85.58. The product markets ended mixed, with the heating oil market settling up 3.44 cents at $2.9401 and the RB market settling down 4.26 cents at $2.4885.On Monday, the Biden administration said it is selling 26 million barrels of oil from the Strategic Petroleum Reserve, a release that had been mandated by Congress in previous years. The sale will likely temporarily push the reserve below its current level of about 372 million barrels, the lowest level since 1983. U.S. Energy Department said bids on the oil are due on February 28th and that the oil would be delivered from April 1st to June 30th. OPEC raised its 2023 forecast for global oil demand growth in its first upward revision in months, citing China’s relaxation of COVID-19 restrictions and slightly stronger prospects for the world economy. In its monthly report, OPEC said global oil demand will increase this year by 2.32 million bpd or 2.3%. The forecast was 100,000 bpd higher than last month’s forecast. The report also showed that OPEC's crude oil production fell in January after the wider OPEC+ alliance pledged output cuts to support the market. OPEC said its crude oil output in January fell by 49,000 bpd to 28.88 million bpd as declines in Saudi Arabia, Iraq and Iran offset increases elsewhere. OPEC also lowered its forecast for 2023 growth in supply from non-OPEC producers to 1.4 million bpd from 1.5 million bpd last month. OPEC said it expects Russian production to fall by 900,000 bpd this year, down from a decline of 850,000 bpd expected last month. With non-OPEC supply declining and demand growth increasing, OPEC raised its estimate for the amount of crude OPEC needs to produce in 2023 to balance the market by 200,000 bpd to 29.4 million bpd. U.S. consumer prices increased in January but the annual increase was the smallest since late 2021, pointing to a continued slowdown in inflation and likely keeping the Federal Reserve on a moderate interest rate hiking path. The U.S. Labor Department reported that the Consumer Price Index in January increased 0.5% on the year compared with a 0.1% increase in the previous month due in part to rebounding energy and shelter prices. In the 12 months through January, the CPI increased 6.4%. It was the smallest gain since October 2021 and followed a 6.5% increase in December.
Oil Futures, Equities Fall on Strong Inflation Report -- A third straight session gain by the ULSD contract was an outlier in an otherwise down session for oil futures on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange, which declined Tuesday following a mostly stronger inflation report for January that triggered some repricing by markets in how aggressive the Federal Reserve would need to be this year in raising interest rates to bring inflation down towards its 2% target. Inflation in the United States increased 0.5% last month. On an annualized basis, consumer prices climbed 6.4% in January from a year earlier, still slightly lower than the 6.5% year-on-year increase in December. Tuesday's inflation report will also keep the Federal Open Market Committee on track to raise the federal funds rate by another 0.25% in both March and May and, according to CME's FedWatch Tool, the market now expects a 0.25% rate hike during the FOMC's June meeting which would lift the federal funds rate to a 5.25% to 5.5% target range. Based on the FedWatch Tool, markets are no longer pricing in a cut in the federal funds rate in December in the aftermath of the stronger inflation report, betting that the Federal Reserve will keep rates higher for longer. Last week, Fed Chairman Jerome Powell reiterated that there is still a long way to go in the fight against inflation. Powell also noted that interest rates could rise more than markets anticipate if high inflation readings do not abate, dampening optimism over the disinflation narrative. Further weighing on the oil complex, the U.S. Department of Energy Monday afternoon announced the sale of an additional 26 million bbl from the Strategic Petroleum Reserve this year to "meet Congressional mandate." The sale comes atop of a record 180 million bbl release executed last year in response to the Russian invasion of Ukraine and subsequent price increases in gasoline prices. The oil offered for sale will be sweet and drawn from the Big Hill site in Texas, 6 million bbl, and the West Hackberry site in Louisiana, 20 million bbl. DOE said the oil sold from the SPR will be delivered from April 1 through June 30. Also on Tuesday, oil traders positioned ahead of the release of the weekly inventory report from the American Petroleum Institute on tap for 4:30 PM ET, followed by official data from the U.S. Energy Information Administration. Analysts and traders expect commercial crude inventories to have risen by 800,000 bbl during the week ended Feb. 10, with estimates ranging from a decrease of 3.2 million bbl to an increase of 2.6 million bbl. At settlement, West Texas Intermediate futures for March delivery declined $1.08 to $79.06 bbl, and the international crude benchmark Brent contract on ICE fell $1.03 to $85.58 bbl. NYMEX RBOB March contract retreated $0.0426 to $2.4885 gallon, and March ULSD futures added $0.0344 for a $2.9401 gallon settlement..
Oil falls after industry data points to jump in U.S. crude stocks (Reuters) - Oil prices slipped in early Asian trade on Wednesday after falling by more than $1 a barrel in the previous session as industry data pointed to a much bigger-than-expected surge in U.S. crude inventories.Brent crude futures lost 20 cents to $85.38 per barrel by 0111 GMT, while U.S. West Texas Intermediate (WTI) crude futures shed 19 cents to $78.87.U.S. crude inventories rose by about 10.5 million barrels in the week ended Feb. 10, according to market sources citing American Petroleum Institute figures on Tuesday. The build was much larger than the 1.2 million-barrel rise that nine analysts polled by Reuters had expected, potentially pointing to a drop in fuel demand.Gasoline stocks rose by about 846,000 barrels, while distillate stocks rose by about 1.7 million barrels, according to the sources, who spoke on condition of anonymity.
WTI Extends Losses After Massive Crude Inventory Build -- Oil prices are extending yesterday's losses as a surge in crude inventories reported by API overnight, combined with a strong dollar weighed on sentiment. But all eyes are on the official data this morning to see if it confirms the giant build from API...
API
- Crude +10.507mm (+600k exp)
- Cushing +1.954mm
- Gasoline +846k (+1.6mm exp)
- Distillates +1.782mm (-100k exp)
DOE
- Crude +16.28mm (+600k exp)
- Cushing +659k
- Gasoline +2.316mm (+1.6mm exp)
- Distillates -1.285mm (-100k exp)
And it did... If you thought the API print was big, the official crude inventory build was even bigger-er... at 16.28mm barrels! Gasoline stocks also rose (while distillates drewdown)... Graphs Source: Bloomberg Stocks at the Cushing hub continue to rise (7th straight week), now at their highest since June 2021... Bear in mind, as Bloomberg's Valle reports, refinery utilization has yet to recover from outages due to bad weather in Texas and seasonal maintenance activity. Supply may be curtailed for the next few weeks as plants resume full activity. This may hurt gasoline margins as refiners empty winter components from tanks ahead of the spring switch. Total US crude stocks are also at their highest since June 2021... Additionally, gasoline demand remains lackluster as last week’s decline snuffed out a five-week streak of gains that kicked off the year, leaving it well below typical seasonal levels. US Crude production was flat at 12.3mm b/d - its post-COVID highs... WTI was trading around $78.50 ahead of the official print and tumbled on the big build...
Oil Seesaws After Strong Sales Data as Traders Look to Fed -- Shrugging off a bullish demand forecast by the International Energy Agency, oil futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange settled Wednesday's session mostly lower after stronger-than-expected retail sales revealed more evidence of a reaccelerating U.S. economy, strengthening the case for the Federal Reserve to keep raising interest rates to fight inflation. Retail sales in the United States jumped 3% last month -- the most in nearly two years -- underpinned by robust consumer demand despite higher interest rates and elevated inflation. Americans spent more on cars, furniture, and purchases at department stores after briefly pulling back on spending at the end of 2022. In reaction to the new data, Atlanta Federal Reserve's GDPNow model estimates first quarter growth higher at 2.4% from 2.2% on Feb. 8. On the flip side, strong retail sales could bolster the Fed's efforts to rein in inflation by raising the federal funds rate, now in a 4.5% to 4.75% target range, even higher than many in the market had previously expected. Markets continued repricing the Fed's terminal rate this year after the January consumer price index report showed inflation in some components of core services proved stickier than previously thought. For context, gasoline prices rose 2.4% in January after falling in November and December, while natural gas utility prices leapt 6.7% higher in January from December -- the biggest increase since June 2022. Lending tepid support for the oil complex is the latest demand forecast from the International Energy Agency that expects global oil consumption would grow to a record high 101.9 million barrels per day (bpd) this year, propelled almost entirely by rising fuel consumption in Asia. The figure is 200,000 bpd higher compared to the IEA forecast last month. The Asia-Pacific region is expected to see demand growth of 1.6 million bpd, led by China, seen up 900,000 bpd from last year on resurgent air travel demand. Jet kerosene demand is now expected to increase by 1.1 million bpd to 7.2 million bpd, equating to 90% of the 2019 consumption rate. Wednesday's inventory report from the U.S. Energy Information Administration was once again bearish, showing U.S. commercial crude oil inventories increased for an eighth consecutive week through Feb. 10, building by a massive 50.7 million barrels (bbl) since the start of the year. Last week, supplies increased by another 16.4 million bbl, lifting inventories to 8% above the five-year average at 471.4 million bbl. The larger-than-expected build occurred as domestic refiners reduced utilization rate by 1.4% from the previous week to 86.5% of capacity. Refiners processed 15 million bpd in the reviewed period, 383,000 bpd less than the previous week's average. . In the gasoline complex, commercial stockpiles built by 2.3 million bbl to 241.9 million bbl compared with expectations for a 1.5 million bbl increase. Demand for transportation fuel fell by 154,000 bpd to 8.274 million bpd last week. In contrast, distillate demand increased by 132,000 bpd to 3.894 million bpd. Domestic distillate stocks decreased by 1.3 million bbl to 119.2 million bbl. At settlement, West Texas Intermediate futures for March delivery declined $0.47 to $78.59 bbl, and the international crude benchmark Brent contract on ICE slipped $0.20 to $85.38 bbl. NYMEX RBOB March contract added $0.0093 to $2.4978 gallon, and March ULSD futures fell $0.0957 to $2.8444 gallon.
Oil dips just a little as bulls buy back plunge after mega U.S. crude build - The U.S. crude inventory build isn’t going away. In fact, it’s growing. But that didn't deter crude bulls who bought back much of the market’s plunge on Wednesday after a mega crude build reported by the U.S. government. Oil prices settled the day just slightly in the red, recovering from a 2% plunge after the Energy Information Administration, or EIA, reported that stockpiles of U.S. crude jumped by a little over 16 million barrels last week in the fourth largest build ever. New York-traded West Texas Intermediate, or WTI, crude for March settled down just 47 cents, or 0.6%, at $78.59 per barrel, rebounding from a session low of $77.28. London-traded Brent crude for March delivery was down even less, with a decline of 20 cents, or 0.2%, at $85.38. The intraday bottom for Brent was $83.91. In oil bulls corner was longer-term demand for crude predicted by the Paris-based International Energy Agency. The so-called IEA raised its forecast for 2023 oil demand by 500,000 barrels per day to nearly 102M bpd. It also cautioned that producer alliance OPEC+ might try to squeeze output to keep crude prices supported. Crude stockpiles rose by 16.283M barrels during the week ended Feb. 10, the Washington-based EIA, which serves as the statistical arm of the U.S. Energy Department, said in its Weekly Petroleum Status Report. U.S. commercial crude inventories have grown by 50.75M barrels so far this year. The climb came as most U.S. refineries entered seasonal maintenance that foresaw less processing of crude. U.S. crude oil refinery inputs averaged 15.0M barrels per day, or bpd, during the week ended Feb. 10 — some 383,000 bpd less than the previous week’s average, the EIA said. Refineries operated at 86.5% of their operable capacity last week, the agency added. Typically, inventory runs at this time of the year are about 90% or more. Last week’s crude build was the fourth-largest ever in the history of the EIA’s reporting, data showed. It was also the third largest in eight straight weeks of builds. Trade group API, or the American Petroleum Institute, using its own count, on Tuesday reported a crude build of 10.507M barrels for the week to February 10. Reuters, meanwhile, cited “unusually large crude oil supply adjustment” in EIA data that it said contributed to the outsized build. "It's the worst kind of build that you can possibly have. It's all about the...adjustment number. There's no getting around that," Aside from crude, the EIA reported a build in stockpiles of gasoline while noting a dip in distillate inventories. On the gasoline inventory side, the EIA reported a build of 2.317M, against a forecast rise of 1.542M and the prior week’s 5.008M. Gasoline inventories have gone up by more than 19M barrels since the start of the year. The EIA said U.S. gasoline demand over the past four weeks fell 3.2% from a year ago, to 8.334M barrels per day. Distillate stockpiles resumed their drop after rising last week for the first time in five weeks. Distillate inventories fell by 1.285M versus an expected build of 0.447M. In the previous week, distillate stocks rose by 2.932M. Also weighing on oil earlier was the rally in the dollar, which slowed demand for oil and other commodities priced in the currency.
Oil Prices Rise On Upbeat Demand Forecasts - Crude oil prices rose in Asian pre-noon trade today after OPEC and the International Energy Agency raised their demand forecasts for the year, shaking off EIA’s latest weekly inventory report that estimated a large inventory build in the United States.In its latest Monthly Oil Market Report, OPEC revised its 2023 oil demand projections up to 2.3 million barrels daily earlier this week. That represented a 100,000-bpd change from last month’s forecast.Of this, 2 million bpd in demand growth will come from non-OECD countries, the oil group said.A day later, the International Energy Agency forecasted oil demand this year would hit a record high of 101.9 million barrels daily, rising by 2 million bpd from last year. The IEA’s upward revision was also to the tune of 100,000 bpd from last month’s projections.In China, the IEA said, demand for crude oil will rise by some 900,000 barrels daily.Meanwhile, the U.S. Energy Information Administration estimated crude oil inventories had added 16.3 million barrels in the week to February 10, confirming the estimate of the American Petroleum Institute, published a day earlier, but topping it substantially. The API had estimated the weekly inventory build at about 10 million barrels.After the initial drop in prices following the release of the EIA’s report, benchmarks started climbing again, pushed by the bullish demand forecasts of OPEC and the IEA.Analysts also noted that the massive inventory build was more the result of a data adjustment than the actual accumulation of crude in storage.Once everyone realized the adjustment threw off the EIA data, scepticism about the big (crude storage) build crept into the market. It's a one-off," John Kilduff, partner at investment advisory Again Capital, told Reuters.At the time of writing, Brent crude was trading close to $86 per barrel and WTI was changing hands for more than $79 per barrel.Headwinds remain, led by continued concern about Fed rate hikes that would push the dollar higher, dampening appetite for crude.
Oil, Stocks Fall After Producer Price Index Lifts Odds for More Rate Hikes - New York Mercantile Exchange oil futures and Brent crude traded on the Intercontinental Exchange followed equity markets lower in afternoon trading Thursday. The losses came after the U.S. producer price index offered more evidence of sticky inflation at the start of the year, raising the odds that the Federal Reserve will lift interest rates more aggressively in the coming months. U.S. producer prices, a measure of inflation at the wholesale level, unexpectedly jumped 0.7% in January compared with 0.2% decline reported at the end of 2022, data released from the Bureau of Labor Statistics showed. Economists estimated a much cooler reading of 0.4% in the reviewed month. An increase in producer prices today typically translates into higher consumer prices tomorrow. Although transmission lags between producer and consumer prices are still a subject of debate among economists, recent price increases will almost certainly force the hand of the central bank to continue to remain aggressive in tightening monetary policy by lifting the federal funds rate in the coming months more than the market had expected. That adjustment in the market's outlook is reflected in expectations that the Fed's terminal rate this year would reach 5.25% to 5.5% as early as June, with the federal funds rate now in a 4.5% to 4.75% range. Some Fed officials have suggested the central bank must move faster to reach the targeted range. Cleveland Fed President Loretta Mester told reporters after a speech Thursday that she saw "a compelling economic case for keeping the pace at 50 basis points at the last meeting." Mester said it was too early to specify the size of the rate increase that would be appropriate at the Fed's next meeting on March 21-22. However, the macroeconomic data released for January and early February clearly points to a reaccelerating economy and a higher outlook for inflation. U.S. retail sales for January unexpectedly jumped 3% last month -- the most in nearly two years despite elevated inflation and evidence of sectorial slowdown in parts of the economy. "The demand side of the economy is not weakening quite as fast as some thought it was," added Mester said. Despite the prospect for higher interest rates, the U.S. dollar eased 0.48% against a basket of foreign currencies to settle the session at 103.791. NYMEX West Texas Intermediate futures for March delivery settled $0.10 lower at $78.49 per barrel (bbl), with the April contract settling at a $0.25 premium to the front-month contract. On ICE, April Brent crude declined $0.24 for an $85.14-per-bbl settlement. NYMEX RBOB March contract dropped $0.0623 to $2.4355 per gallon, and March ULSD futures fell $0.0336 to $2.8108 per gallon at settlement. Mitigating greater losses for the oil complex are signs Chinese refiners increased oil purchases in the physical market, drawing around 10 million bbl in crude cargoes for April delivery from Middle East and West African producers. This week, the International Energy Agency and Organization of the Petroleum Exporting Countries both lifted their global oil demand forecast spurred almost entirely by expectations for rising fuel consumption in Asia. IEA estimates Asia-Pacific region will see demand growth of 1.6 million barrels per day (bpd) in 2023, led by China, up 900,000 bpd from last year's consumption rate.
Oil, Equities Sell Off After Fed Signals 0.50% Rate Hikes - Pressured by a stronger U.S. Dollar Index and a selloff in equity markets, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange plummeted more than 3% early Friday as investors repriced the risk of the U.S. Federal Reserve bringing back larger interest rate increases in the coming months to combat stubbornly high inflation and a tight labor market. The president of the St. Louis Federal Reserve Bank James Bullard told reporters Thursday that he would not rule out raising interest rates by a half percentage point at the March meeting rather than a quarter point, citing upside risks to sticky inflation. "My overall judgment is it will be a long battle against inflation, and we will probably have to continue to show inflation-fighting resolve as we go through 2023." said Bullard, adding that he prefers to raise the Fed's funds rate to 5.375% as soon as possible. Currently, the Fed's funds rate stands in the range of 4.50%-4.75%. Bullard's comments echoed earlier remarks from Cleveland Federal Reserve President Loretta Mester who saw "a compelling economic case for another 50-basis rate increase at the Fed's February meeting." The hawkish comments from the two Federal Reserve officials followed a string of strong inflation data for January, including the Producer Price Index (PPI) and Consumer Price Index (CPI) that showed underlying inflation is stickier than previously thought. The PPI rose 0.7% at the start of the year -- the most since June 2022 when underlying inflation on the consumer level was rising at a rate of 1.3%. "The demand side of the economy is not weakening quite as fast as some thought it was," added Mester. As investors repriced the outlook for the Fed's funds rate, U.S. equities plunged, the dollar rallied to multi-week highs and yields on Treasury bonds jumped. As of 7:45 a.m. EST, the S&P 500 was down 0.63%, and the Dow Jones Industrial Average fell 0.45%. The CBOE Volatility Index was up 5.74%. NYMEX West Texas Intermediate futures for March delivery declined $2.54 to $75.95 barrel (bbl), with the April contract trading at a $0.26 premium to the front-month contract. On ICE, April Brent crude fell $2.58 to $82.56 bbl. NYMEX RBOB March contract dropped $0.0864 to $2.3491 gallon, and March ULSD futures fell $0.0894 to $2.7214 gallon.
Oil down 4% on week as bottom falls out after failed China pursuit --Reality finally seems to be setting in on the oil market. After initially defying blockbuster crude builds reported back-to-back by the U.S. government in pursuit of what they believed would be oncoming Chinese demand, those long the market finally yielded to something greater: incessant data on creeping inflation, accompanied by calls for appropriate rate hikes. "Crude prices are falling as supplies are plentiful and as global growth concerns return," New York-traded West Texas Intermediate, or WTI, crude for March settled down $2.15, or 2.7%, to $76.27. WTI’s session low of $75.08 marked a near two-week bottom. For the week, the U.S. crude benchmark was down 4.4%. WTI has fallen in three of the past four weeks, losing nearly 7% in that stretch. London-traded Brent crude for March delivery settled down $2.14, or 2.5%, at $83. Brent’s intraday bottom was $81.81, a low since Feb. 6. For the week, the global crude benchmark was down 4%. Like WTI, Brent has slid in three of the past four weeks, losing more than 5% in that period The build was the fourth largest cited by the EIA in its history of reporting on oil supply/demand in the United States. It came after the previous week's increase of 2.4 million barrels and marked the eighth straight week of higher inventories that have added nearly 51 million barrels to supply. Traders of most risk assets — except possibly those in oil — have been spooked all week by one data point after indicating stubbornly higher inflation despite a year of rate hikes by the Federal Reserve. US wholesale prices, one of the key determinants of inflation, rose their most in seven months in January, the Labor Department reported on Thursday. That was after Tuesday's report on consumer prices from the department that again suggested stickier-than-thought inflation. Since the updated data on inflation emerged, Federal Reserve officials have been girding for an extended period of high interest rates, including a return to a 50-basis point hike in March, saying creeping inflation makes the 25-basis point quantum that the central bank agreed on this month untenable. “We need to continue rate hikes until we see more progress,” Fed Governor Michelle Bowman said Friday. “Inflation is still far too high. Your guess is as good as mine as to what happens next in the economy.” Richmond Fed President Tom Barkin concurred, saying controlling inflation would require more rate increases. “How many, we'll have to see," he added. The comments by Bowman and Barkin came on the heels of more rate warnings earlier in the week from other officials at the central bank. Cleveland Fed chief Loretta Mester said Thursday US interest rates need to rise to above 5% and remain there an extended time in order to bring inflation down meaningfully. St. Louis Fed President James Bullard, often viewed as the most hawkish official at the central bank, also said on Thursday he hadn’t been in favor of lowering the quantum of rate hikes — something that happened the last two months — until inflation was under better control. Bullard added that he would support a 50-basis point hike at the Fed’s next rate decision on March 22, after the 25-basis point increase on February 1. Former Treasury Secretary Summers, in rounding up the Fed rhetoric, said there’s a risk of the “Fed hitting the brakes very, very hard”. “A broadening in US price pressures shows that the Federal Reserve’s monetary tightening to date is having a limited impact, raising the danger of policymakers having to do more than previously envisioned,” Summers added.
Venezuela to Contract for Two Iran-Built Oil Tankers to Expand Fleet — Venezuela will contract with an Iranian shipyard to build two oil tankers under an existing construction agreement bedeviled by payment delays and difficulties with needed certifications, according to people familiar with the matter and documents. Venezuela's state-run energy firm PDVSA since last year has redoubled efforts to buy and lease oil tankers to rebuild its own fleet. Its maritime operations have suffered from a long-standing lack of capital and U.S. sanctions that have made it difficult to obtain insurance and receive classifications essential to navigate in international waters. The two new Aframax tankers, to be named India Urquia and India Mara, will cost $33.77 million each, an internal PDVSA document detailing the proposed agreement showed. The vessels will be built by Iran Marine Industrial Company (SADRA) at its Bushehr shipyard, which built two previous vessels for PDVSA, the Aframaxes Arita and Anita, that can each carry 500,000-800,000 barrels of oil. "(Construction of) the India Urquia must start soon," one of the sources said. The agreement will come after Venezuela settled an outstanding debt to Iran with fuel, according to the document, one of the reasons why the contract has not worked as originally planned. PDVSA in late 2021 delivered a 644,000-barrel fuel oil cargo to Iran valued at $36.4 million. "The shipyard received 30.34 million euros [$32.5 million] to settle the outstanding debt for tanker Arita," and another $2.1 million went in August to pay accumulated demurrage fees, the document said. Both the Arita and the second tanker, recently renamed Anita, faced long delays to begin navigating amid the unpaid debts and PDVSA maritime arm's struggles to secure insurance and seaworthy classifications. The Arita — now renamed Colon — first set sail in 2017 but was later arrested by a vessel operator for unpaid bills. It was returned to PDVSA in 2019 and has mostly remained in Venezuelan waters since. The Anita departed Iran in late December carrying an Iranian condensate cargo for PDVSA, one of the sources said. It has not yet arrived in Venezuela, according to tanker tracking services. Two separate vessels chartered by Iran's Naftiran Intertrade Company (NICO), the supertankers Wen Yao and Sea Cliff, also are expected to deliver Iranian condensate to Venezuela this month as part of an oil swap with PDVSA, according to monitoring firm TankerTrackers.com. The Sea Cliff was seen near PDVSA's Jose port on Monday, TankerTrackers.com said.
US Shoots Down Iranian-Made Drone Over Occupied Conoco Gas Field The Pentagon has revealed that on Tuesday US forces fired on and took down an alleged 'Iranian-made' drone that was threating a base in Syria where US troops are stationed. The base is located in northeastern Syria, and the drone flew toward Mission Support Site Conoco, named for the huge gas field that US-backed forces have for years occupied in Deir Ezzor province. US Central Command said the drone was shot down mid-afternoon on Tuesday, following several recent attacks on US positions in the region, and also amid a spate of attacks at the Syria-Iraq border base of al-Tanf. One of the biggest recent incidents at Conoco gas field involved an August skirmish wherein the US counter-attacked against what were believed to be Iran-backed fighters. The Pentagon at the time said it took out four enemy militants and destroyed rocket launchers. It's unclear whether the attacks have indeed originated from 'Iranian militias' or else Syrian nationalist militias, or perhaps both, given the close alliance and cooperation among Iranian operatives and Syrian forces. CENTCOM took the rare step in this latest instance of publishing photographs of what appears a large drone over US positions, and it going up in flames after being engaged by US forces...
Airstrikes on Yemen using UK and US weapons “part of a pattern of violence against civilians” - Britain and the United States provided the Saudi-led coalition with the weapons used in hundreds of attacks on civilians in Yemen between January 2021 and the end of February 2022, according to a recent report by Oxfam. Martin Butcher, Oxfam’s Policy Advisor on Arms and Conflict, said that the Saudi-led coalition were responsible for at least 87 civilian deaths and 136 injuries, 19 attacks on healthcare facilities and 293 attacks that forced people to flee their homes—39 percent of all attacks causing displacement. “Our analysis shows there is a pattern of violence against civilians, and all sides in this conflict have not done enough to protect civilian life, which they are obligated to do under International Humanitarian Law.” He added, “The intensity of these attacks would not have been possible without a ready supply of arms. That is why it’s vital the UK government and others must immediately stop the arms sales that are fueling war in Yemen.” The Oxfam report came just days before the Campaign Against Arms Trade (CAAT) launched a lawsuit aimed at ending the British government’s multi-billion pound arms sales, including Typhoon fighter jets, missiles and bombs, as well as ongoing maintenance and support, for use in the Saudi Arabia and United Arab Emirates (UAE)-led war in Yemen. The UK government’s own rules, adopted in 2014 when it signed the Arms Trade Treaty, prohibit arms sales where there is a “clear risk” that a weapon “might” be used in a serious violation of International Humanitarian Law (IHL). Despite the overwhelming evidence that the coalition has repeatedly breached IHL, the government has continued to promote and protect weapons sales. According to CAAT, the UK has supplied arms worth over £23 billion to Saudi Arabia, when “open licences” are taken into account, several times the official figures provided by the government, since the war in Yemen began in April 2015. UK special forces are believed to have played a role in the war, while the British military maintains the Saudi warplanes that attack Yemen and provide intelligence support for the coalition. The British government has persistently rejected calls from the United Nations and other international bodies for a ban on arms sales to Saudi Arabia and the UAE. It boasts of being the second largest exporter of defence items worldwide, after the US, based on the value of orders or contracts signed, with more than half by value going to the Middle East. The venal Saudi monarchy, which routinely assassinates its opponents, tortures, imprisons and beheads oppositionists and dissidents, and the repressive UAE provide the major props for Britain’s defence industry—one of its few remaining manufacturing sectors. They serve as key custodians of Britain’s geostrategic interests in the energy-rich region and as allies in the Washington-led campaign to isolate Iran and its regional allies in Iraq, Syria, Lebanon and Yemen, as part of broader preparations for war with Russia and China, with which Tehran has forged close relations. Prime Minister Rishi Sunak’s government is intent on maintaining the barbaric House of Saud’s control over the Arabian Peninsula. It is suppressing any information that Riyadh or its backers are committing war crimes and avoiding accusations that the UK is violating its own rules against supplying arms.
U.S. ‘deeply troubled’ by Israel’s legalizing 9 outposts - Administration officials said on Monday they were “troubled” and “concerned” by Israel’s settlement advancements over the weekend — the first sign of outward friction between the U.S. and Israel’s new far-right government.“We are deeply troubled by Israel’s announcement that it will reportedly advance thousands of settlements and begin a process to retroactively legalize nine outposts in the West Bank that were previously illegal under Israeli law,” State Department spokesperson Ned Price said in a press briefing on Monday. “Like previous administrations, we strongly oppose these unilateral measures, which exacerbate tensions, harm trusts between the parties, and undermine the prospects for a negotiated two-state solution.”John Kirby, the National Security Council coordinator, also said his team was “deeply concerned” regarding the settlement decision in Israel, during a White House press briefing on Monday afternoon. Secretary of State Antony Blinken expressed his concern in a statement prior to his department’s briefing.Prime Minister Benjamin Netanyahu of Israel agreed to legalize nine settlement outposts in the occupied West Bank on Sunday, The Associated Press reported. This action goes against the United States’ strong opposition to “any unilateral steps that exacerbate tensions,” Price said during the State Department briefing.The Israeli leadership under Netanyahu has faced criticism from some who say the far-right policies are racist or misogynistic. During Netanyahu’s attempt to return to power last year, after being ousted in the previous election, he tapped into far-right extremist coalitions to gain support —coalitions now represented in the new Israeli government.The U.S. has tread lightly in addressing the new coalition government, while also keeping its ties with a historic ally. Blinken previously met with Netanyahu two weeks ago during a two-day trip.
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