natural gas prices settle at a 19 month low; global oil production exceeded demand by 520,000 barrels per day in December; despite OPEC production that was 854,000 barrels per day below their reduced quota; largest US oil rig drop since Hurricane Ida
US oil prices finished higher for the fifth time out of the past six weeks on the belief that China's reopening would boost the demand for crude.... after rising 8.3% to $79.86 a barrel last week on the reopening of China and signs of easing inflation in the US, the contract price for the benchmark US light sweet crude for February delivery headed lower in overseas trading on our Monday holiday as traders took profits from last week’s rally after rising numbers of COVID-19 cases in China clouded prospects for demand, then slipped further in early Asian trading Tuesday as recession fears dominated headlines out of the World Economic Forum's meeting in Davos, draining the optimism that had stoked the market last week on prospects of a fuel demand recovery, but steadied after US markets opened as traders looked to a revival in Chinese demand after data showed that their economy fared better than expected last quarter, but sharply pared an early advance to a nine-week high at $81.23 per barrel to settle for a 32 cent gain to $80.18 a barrel after a survey on manufacturing activity in New York State showed business activity had collapsed to the lowest level since June 2020....oil prices extended Tuesday’s gains into early European trading on Wednesday, rising by 1% as market sentiment turned bullish on hopes that China’s reopening would boost demand growth and that major developed economies might avoid recession and hit their highest intraday prices since early December in New York trading before turning south to settle 70 cents, or 0.9% lower, at 79.48 a barrel as worries about a possible U.S. recession outweighed optimism that China's lifting of COVID-19 curbs would fuel demand for crude....oil prices extended their losses in after hours trading after the American Petroleum Institute reported a bigger crude inventory build than anyone expected, and then traded more than 1% lower in Asia on Thursday on weak economic reports from the US amid recession fears, and on the hefty rise in crude stockpiles, but rallied in US trading despite EIA data showing nationwide crude oil stock levels spiked by 8.4 million barrels, as refinery operations remained below normal follwing widespread disruptions due to the bitter cold weather in late December. and settled 85 cents higher at $80.33 a barrel, the highest close since December 1st, thus extending the rally of recent weeks built around rising Chinese demand....oil prices moved higher in Asian trade early Friday, supported by economic recovery signs from China, then rallied further after Baker Hughes reported the number of US oil-targeting rigs unexpectedly fell by the most in 16 months, while a softer U.S. dollar index further boosted buying to add 98 cents or 1.2% to close at a two month high of $81.31 a barrel, thus finishing 1.8% higher on the week as trading in the February oil contract expired, while the new front-month contract price for the benchmark US crude for March delivery added $1.03, or 1.3%, to settle at $81.64 a barrel, with that contract up 1.9% on the week...
Meanwhile, US natural gas prices finished lower for the seventh time in eight weeks, on indications of a further delay in the resumption of LNG exports from Freeport Texas, following forecasts that again shifted warmer ..after falling 7.8% to an 18-month low of $3.419 per mmBTU last week following the first January addition to US gas inventories on record, the contract price of US natural gas for February delivery jumped 16.7 cents, or almost 5% to $3.586 per mmBTU on Tuesday, as gas started to flow to the long-shut Freeport LNG export plant in Texas, while forecasts indicated colder weather over the next two weeks than had been expected...but natural gas prices reversed lower early Wednesday as updated forecasts reduced the amount of cold expected for the Lower 48 during the final week of January, and prices dropped 27.5 cents to a new 18 month low of $3.311 per mmBTU as gas production climbed, benign weather persisted and traders braced for an anemic storage withdrawal report...natural gas prices were close to even early Thursday ahead of the EIA storage report, then ticked lower after the EIA reported a steeper than expected withdrawal of 82 Bcf of natural gas from underground storage and settled down 3.6 cents at $3.275 per mmBTU, after a gas tanker turned away from Freeport LNG's export plant in Texas, a sign that the plant's restart would likely not happen in January...after trading in a narrow range much of Friday, prices turned lower to settle down 10.1 cents at a 19 month low of $3.174 per mmBTU amid mild weather and elevated gas production levels, and thus ended 7.2% lower on the week...
The EIA's natural gas storage report for the week ending January 13th indicated that the amount of working natural gas held in underground storage in the US fell by 82 billion cubic feet to 2,820 billion cubic feet by the end of the week, which still left our gas supplies 19 billion cubic feet, or 0.7% below the 2,839 billion cubic feet that were in storage on January 13th of last year, but 40 billion cubic feet, or 1.2% more than the five-year average of 2,786 billion cubic feet of natural gas that were in storage as of the 13th of January over the most recent five years....the 82 billion cubic foot withdrawal from US natural gas working storage for the cited week was more than was expected by a Reuters poll of analysts, whose average forecast called for a 71 billion cubic feet withdrawal of gas, but it was well less than half of the 203 billion cubic feet that were pulled out of natural gas storage during the corresponding week of 2022, and far below the average 156 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 January 13th indicated that after another big increase in our oil imports, we again had surplus oil left to add to our stored commercial crude supplies for the 4th consecutive week, and for the 23rd time in the past 39 weeks, despite a big jump in our oil exports and a further rebound in our refinery throughput... Our imports of crude oil rose by an average of 511,000 barrels per day to average 6,861,000 barrels per day, after rising by an average of 637,000 barrels per day during the prior week, while our exports of crude oil rose by 1,735,000 barrels per day to average 3,872,000 barrels per day, which combined meant that the net of our trade in oil worked out to a net import average of 2,989,000 barrels of oil per day during the week ending January 13th, 1,224,000 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 12,200,000 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 15,189,000 barrels per day during the January 13th reporting week…
Meanwhile, US oil refineries reported they were processing an average of 14,853,000 barrels of crude per day during the week ending January 13th, an average of 203,000 more barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that an average of 1,201,000 barrels of oil per day were being added to the supplies of oil stored in the US. So, based on that reported & estimated data, the crude oil figures from the EIA for the week ending January 13th appears to indicate that our total working supply of oil from net imports and from oilfield production was 866,000 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 (+866,000) 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 an omission or error of that magnitude in this week’s oil supply & demand figures that we have just transcribed.... However, since most everyone treats these weekly EIA reports as gospel, and since these 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)….
This week's 1,201,000 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.. Last week marked the end of the emergency SPR withdrawal under Biden's "Plan to Respond to Putin’s Price Hike at the Pump" (sic), that was originally intended to supply 1,000,000 barrels of oil per day to commercial interests over a six month period from its inception in May to the midterm elections in November, in the hope of keeping gasoline and diesel fuel prices from rising over that time, and which was later extended to run through the end of December.. Including the administration's initial 50,000,000 million barrel SPR release much earlier last year, and their subsequent 30,000,000 barrel release, and other withdrawals from the Strategic Petroleum Reserve under recent release programs, a total of 284,567,000 barrels of oil had been withdrawn from the Strategic Petroleum Reserve over the last 29 months, and as a result the 371,580,000 barrels of oil that still remain in our Strategic Petroleum Reserve is at its lowest level since December 2nd, 1983, or at a 39 year low, as repeated tapping of our emergency supplies for non-emergencies or to pay for other programs had already drained those supplies considerably over the past dozen years, even before the Biden administration's SPR releases. While the administration announced in mid-December an initial token purchase of three million barrels of oil to be delivered back to the SPR in February, no one would sell us oil at the below market price we were offering, so the Biden plan to begin refilling the SPR has been postponed...
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,294,000 barrels per day last week, which was 1.1% less than the 6,364,000 barrel per day average that we were importing over the same four-week period last year. This week’s crude oil production was reported to be unchanged at 12,200,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 11,700,000 barrels per day, but Alaska’s oil production was 5,000 barrels per day higher at 453,000 barrels per day and thus added 100,000 barrels per day to the rounded national total. (by the EIA's math). US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 6.8% below that of our pre-pandemic production peak, but was 25.8% 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 85.3% of their capacity while using those 14,853,000 barrels of crude per day during the week ending January 13th, up from their 84.1% utilization rate during the prior week, but still well below normal utilization for early January. The 14,853,000 barrels per day of oil that were refined this week were 3.9% less than the 15,453,000 barrels of crude that were being processed daily during week ending January 14th of 2022, and 12.5% less than the 16,973,000 barrels that were being refined during the prepandemic week ending January 10th, 2020, when our refinery utilization was at a more normal 92.2%, as refinery utilization typically hits a winter peak around New Year's day ...
With the increase in the amount of oil being refined this week, gasoline output from our refineries was also higher, increasing by 332,000 barrels per day to 8,865,000 barrels per day during the week ending January 13th, after our gasoline output had increased by 67,000 barrels per day during the prior week. This week’s gasoline production was still 0.2% less than the 8,688,000 barrels of gasoline that were being produced daily over the same week of last year, and 4.5% less than the gasoline production of 9,281,000 barrels per day during the prepandemic week ending January 10th, 2020. At the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 57,000 barrels per day to 4,601,000 barrels per day, after our distillates output had rebounded by 509,000 barrels per day during the prior week. Even after those increases, our distillates output was still 2.7% less than the 4,728,000 barrels of distillates that were being produced daily during the week ending January 14th of 2022, and 11.4% less than the 5,205,000 barrels of distillates that were being produced daily during the week ending January 10th 2020...
With the increase in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the 8th time in ten weeks and for the 11th time in 23 weeks, increasing by 3,483,000 barrels to 226,776,000 barrels during the week ending January 13th, after our gasoline inventories had increased by 4,114,000 barrels during the prior week. Our gasoline supplies rose by less this week because the amount of gasoline supplied to US users rose by 496,000 barrels per day, and because our exports of gasoline rose by 67,000 barrels per day to 934,000 barrels per day, while our imports of gasoline rose by 340,000 barrels per day to 556,000 barrels per day. Even after 8 recent gasoline inventory increases, our gasoline supplies were still 6.6% below last January 14th's gasoline inventories of 246,621,000 barrels, while falling to about 8% below the five year average of our gasoline supplies for this time of the year…
Even with the increase in our distillates production, our supplies of distillate fuels decreased for the 4th time in 5 weeks, and for the 28th time over the past year, falling by 1,939,000 barrels to 115,777,000 barrels during the week ending January 13th, after our distillates supplies had decreased by 1,069,000 barrels during the prior week. Our distillates supplies fell by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, increased by 202,000 barrels per day to 4,023,000 barrels per day, while our imports of distillates fell by 61,000 barrels per day to 148,000 barrels per day, and while our exports of distillates fell by 83,000 barrels per day to 1,002,000 barrels per day... After a run of fifty-five inventory withdrawals over the past eighty-nine weeks, our distillate supplies at the end of the week were were 9.5% below the 127,952,000 barrels of distillates that we had in storage on January 14th of 2022, and about 20% below the five year average of distillates inventories for this time of the year...
Meanwhile, even without an oil release from the SPR, our commercial supplies of crude oil in storage rose for the 11th time in 23 weeks and for the 22nd time in the past year, increasing by 8,408,000 barrels over the week, from 439,607,000 barrels on January 6th to 448,015,000 barrels on January 13th, after our commercial crude supplies had increased by 18,961,000 barrels over the prior week. After those two big increases, our commercial crude oil inventories were about 3% above the most recent five-year average of crude oil supplies for this time of year, and were nearly 40% above the average of our crude oil stocks as of the second weekend of January over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels. And 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 January 13th were 8.3% more than the 413,813,000 barrels of oil we had in commercial storage on January 14th of 2022, but 7.9% less than the 486,563,000 barrels of oil that we had in storage during the 2nd Covid surge on January 15th of 2021, while 4.6% more than the 428,511,000 barrels of oil we had in commercial storage on January 10th of 2020…
Finally, with our inventories of crude oil and our supplies of all products made from oil trending near multi-year lows over the most recent months, we are also continuing to watch the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR 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 2,378,000 barrels this week barrels this week, from 1,599,229,000 barrels on January 6th to 1,601,607,000 barrels on January 13th, after our total inventories had increased by 21,602,000 barrels during the prior week. Even after those increases, our total petroleum liquids inventories were still down by 355,525,000 barrels or 18.2% from their prepandemic high, and just 1.5% from hitting a new 18 1/2 year low...
OPEC's Report on Global Oil for December
Tuesday of this past week saw the release of OPEC's January Oil Market Report, which includes the details on OPEC's & global oil data for December, and hence it gives us a picture of the global oil supply & demand situation during a period when demand for oil was impacted by strict Covid-related lockdowns in Beijing and several other major Chinese cities, while oil supplies from Russia were further reduced by December 5th's European Union ban of Russian oil imports by sea, and by the G7's Russian oil price cap, also imposed on the 5th....December was also the second 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 surplus and related market 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 on the bottom line of the above table, OPEC's oil output increased by a rounded 91,000 barrels per day to 28,971,000 barrels per day during December, up from their revised November production total that averaged 28,879,000 barrels per day....however, that November output figure was originally reported as 28,826,000 barrels per day, which therefore means that OPEC's November production was revised 53,000 barrels per day higher with this report, and hence OPEC's December production was, in effect, 144,000 barrels per day higher than the previously reported OPEC production figure (for your reference, here is a copy of the table of the official November 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 744,000 barrel per day production cut they made in November came up short of that, OPEC's production was already running 1,585,000 barrels per day below what they were expected to produce during October, so the modest December production increase 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 December in the press release following the 34th OPEC and non-OPEC Ministerial Meeting on November 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, 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 next December...therefore, the 24,562,000 barrels those 10 OPEC members actually produced in December were 854,000 barrels per day short of what they were expected to produce during the month, with Nigeria and Angola still accounting for the majority of the 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 January 2021 to December 2022, 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....
After this month's 91,000 barrel per day increase in OPEC's production from their revised production of a month earlier, OPEC's preliminary estimate is that total global liquids production increased by a rounded 300,000 barrels per day to average 101.70 million barrels per day in December, a reported increase which came after November's total global output figure was apparently revised down by a rounded 100,000 barrels per day from the 101.50 million barrels per day of global oil output that was reported for November a month ago, as non-OPEC oil production rose by a rounded 200,000 barrels per day in December after that downward revision, with most of December's production growth coming from OECD Europe, Latin America and Eurasia ex-Russia, which were partially offset by oil production declines in the US and Russia...
After that 300,000 barrel per day increase in December's global output, the 101.70 million barrels of oil per day that were produced globally during the month were 3.72 million barrels per day, or 3.8% more than the revised 97.98 million barrels per day that were being produced globally in December a year ago, which was the fifth month of the monthly 400 million barrel per day production increases that OPEC and their allied producers initiated as the fourth policy reset in response to the global demand recovery following the early pandemic lockdowns (see the January 2022 OPEC report for the originally reported December 2021 details)...since this month's increase in OPEC's output corresponds to the modest global increase, their December oil production of 28,971,000 barrels per day was unchanged at 28.5% of what was produced globally during the month, after their share of the global total in November was revised up from the 28.4% reported last month....OPEC's December 2021 production was originally reported at 27,882,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 1,089,000 barrels per day, or 3.9% more barrels per day of oil this December than what they produced last December, when they accounted for 28.3% of a smaller global output total...
With the modest increase in OPEC's output and in other global oil output that we've seen in this report, the amount of oil being produced globally during the month was somewhat above the expected global demand, as this next table from the OPEC report will show us....
The above table came from page 27 of the January Oil Market Report (pdf page 37), and it shows regional and total oil demand estimates in millions of barrels per day for 2021 in the first column, and then OPEC's estimate of oil demand by region and globally quarterly over 2022 over the rest of the table...on the "Total world" line in the fifth column, we've highlighted in blue the figure that's relevant for December, which is their estimate of global oil demand during the fourth quarter of 2022....OPEC has estimated that during the 4th quarter of this year, all oil consuming regions of the globe were using an average of 101.18 million barrels of oil per day, which is an upward revision of 70,000 barrels per day from their estimate 101.11 million barrels per day for 4th quarter demand of a month ago (revisions are 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 December, which would imply that there was surplus of around 520,000 barrels per day of global oil production in December, when compared to the demand estimated for the month...
in addition to figuring the December oil surplus that's indicated by this report, the upward revision of 70,000 barrels per day to 4th quarter demand we've highlighted in green above, combined with the downward revision of 100,000 barrels per day to November's global oil output that's implied in this report, means that the 390,000 barrels per day global oil output surplus we had previously figured for November would now be revised to an oil production surplus of 220,000 barrels per day...likewise, the upward revision of 70,000 barrels per day to 4th quarter demand noted above means that the 347,000 barrels per day global oil output surplus we had previously figured for October would now be revised to an oil surplus of 277,000 barrels per day...
Note on the table above that we've highlighted in green a downward revision of 110,000 barrels per day to the third quarter's demand....that means that the 1,270,000 barrels per day global oil output surplus we had previously figured for September would now be revised to a surplus of 1,380,000 barrels per day....in like manner, the 110,000 barrels per day downward revision to 3rd quarter demand means that the surplus of 1,010,000 barrels per day we had previously figured for August would now be revised to a surplus of 1,120,000 barrels per day, and that the surplus of 460,000 barrels per day barrels per day we had previously figured for July would have to be revised to a surplus of 570,000 barrels per day...
Note that in green we have also highlighted a small downward revision of 10,000 barrels per day to OPEC's previous estimates of second quarter demand...based on that downward revision to demand, our previous estimate that there was a surplus of 690,000 barrels per day in June would now be revised to a 700,000 barrels per day surplus, while the oil shortage of 40,000 barrels per day that we had previously figured for May would have to be revised to a shortage of 50,000 barrels per day, and finally, that the 680,000 barrels per day global oil output surplus we had previously figured for April would have to be revised to a surplus of 690,000 barrels per day...
Also note that in green that we have highlighted an upward revision of 40,000 barrels per day to OPEC's previous estimate of first quarter demand, during a period when supply and demand seemed to be close to being in balance.....so for March, that means that the global oil output surplus of 140,000 barrels per day we had previously figured for March would be revised to a surplus of 100,000 barrels per day, and that the 70,000 barrels per day global oil output shortage we had previously figured for February would now be revised to a shortage of 110,000 barrels per day, and that the global oil output shortage of 820,000 barrels per day we had previously figured for January would now be revised to a shortage of 860,000 barrels per day, in light of that 40,000 barrel per day upward revision to first quarter demand...
This Week's Rig Count
The number of drilling rigs active in the US decreased for the 11th time over the prior 25 weeks during the week ending January 20th, and is now 2.8% below the prepandemic level, despite increasing in 94 of the past 121 weeks....Baker Hughes reported that the total count of rotary rigs drilling in the US fell by 4 to 771 rigs over the past week, which was still 167 more rigs than the 604 rigs that were in use as of the January 21st report of 2022, but was 1,158 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 10 to 613 oil rigs during the past week, the biggest oil rig drop since Hurricane Ida shut down Gulf of Mexico rigs in early September 2021, after the number of rigs targeting oil had increased by 5 during the prior week, but there are now 122 more oil rigs active now than were running a year ago, even as they amount to just 38.1% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, while they are now down 10.3% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 6 to 156 natural gas rigs, which was also up by 43 natural gas rigs from the 113 natural gas rigs that were drilling during the same week a year ago, even as they were only 9.7% 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 were were no such "miscellaneous" rigs running...
The offshore rig count in the Gulf of Mexico decreased by three to sixteen rigs this week, with 15 rigs still drilling in Louisiana's offshore waters, and one rig still drilling for oil offshore from Texas....that Gulf rig count is now two less than the 18 Gulf rigs running a year ago, when 17 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, 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 159 more rigs than the 532 horizontal rigs that were in use in the US on January 21st of last year, but just overr half of the record 1,374 horizontal rigs that were drilling on November 21st of 2014....in addition, the directional rig count was also unchanged at 49 directional rigs this week, and those were up by 12 from the 37 directional rigs that were operating during the same week a year ago…on the other hand, the vertical rig count was down by 4 to 22 vertical rigs this week, which was also down by 1 from the 23 vertical rigs that were in use on January 21st 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 January 20th, the second column shows the change in the number of working rigs between last week’s count (January 13th) and this week’s (January 20th) count, the third column shows last week’s January 13th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 21st of January, 2022...
the three rig decrease in Louisiana was due to the 3 rigs that were pulled out of the state's offshore waters; rigs elsewhere in the state were unchanged... checking the Rigs by State file at Baker Hughes for changes in the Texas Permian basin, we find that there was one rig pulled out of Texas Oil District 7B, which includes the easternmost counties in the Permian Midland, but that rig counts in other Texas Permian districts were unchanged....since the national Permian basin count was down by two oil rigs, we can thus figure that the rig pulled out of New Mexico had been drilling for oil in the far western Permian Delaware, in the southwest corner of that state....elsewhere in Texas, there was a rig added in Texas Oil District 3, apparently targeting a basin not tracked by Baker Hughes, while there was an oil rig pulled out of Texas Oil District 4, which would have come from the Eagle Ford shale....there was also a rig added in Texas Oil District 6, accounting for the natural gas rig addition in the Haynesville shale, since the rig count in the Haynesville shale area in adjacent Louisiana was unchanged....Texas also saw a rig added in Texas Oil District 5, apparently targeting a basin not tracked by Baker Hughes...
In Oklahoma, there was an oil rig pulled out of the Ardmore Woodford, and since the Oklahoma count is unchanged, there must have been a rig added to another basin in the state not tracked by Baker Hughes...there was also an oil rig pulled out of Alaska, which had been drilling on the North Slope...meanwhile,there was a natural gas rig added to the Utica shale in Beaver county Pennsylvania, while there was a natural gas rig pulled out of the Marcellus shale elsewhere in the state, leaving the Pennsylvania and the natural gas rig count unchanged... other than in the Haynesville, five natural gas rig additions were in basins not tracked by Baker Hughes, and other than the three unidentified rig additions we've already mentioned, there are no anomalous changes in other states that could account for those...that means that 2 oil rigs would have had to have been removed in the same state or states that the natural gas rigs were added to, in order to net a unchanged count for those spots...
DeWine, Ohio Republicans redefine natural gas as ‘green energy’ in service to fossil fuel industry - Folks in my line of work are wise to the “Friday night news dump.” It’s an old tactic used by politicians and PR types who have to release unfavorable news they don’t want anyone to see. They know newsrooms are emptying and fewer eyes are scanning media alerts at quitting time. The strategy is to deep-six damaging news and dodge political blowback with a cache of press statements dumped at 5 p.m. Friday and no returned calls. Recently Gov. Mike DeWine used the tried and true ploy to evade fallout from legislation he signed into law for one of his biggest campaign contributors at the expense of Ohio State Parks. As a fully purchased subsidiary of the fossil fuel industry, DeWine blessed an industry-friendly bill maneuvered on the sly through the lame duck session by Ohio Senate Republicans without public input or review. Not good. Senators tucked two last-minute amendments into an unrelated House bill and passed them in a hurry. One forced state agencies to open up state parks and forested lands for expanded oil and gas drilling. Basically lawmakers cleared the way for a no-exception leasing process to jump-start fracking operations eager to cash in on our natural resources. The amendment, tweeted the Ohio Environmental Council, “removes critical public oversight and locks in polluters’ control over what public lands in Ohio are leased and when.” Republicans also inserted a provision that lined up perfectly with fossil fuel “misinformation campaigns designed to brand natural gas as ‘green energy.’” They lumped natural gas into the same legal classification as “green energy” or renewable energy sources such as solar, wind, and water. For the record, natural gas, which is primarily methane, is a greenhouse gas whose global warming potential is 86 times greater than carbon dioxide over a 20-year period. And leaked methane emissions have dramatically increased in the U.S. as natural gas fracking has boomed as a “clean” replacement for other fossil fuels. So redefining a potent and dangerous fossil fuel gas whose toxic emissions are driving climate change as “green energy” is, well, patently absurd and scientifically nuts.
Lobbying, ‘dark money’ were behind Ohio law rebranding natural gas as ‘green energy,’ records show - cleveland.com - – A dark money nonprofit linked to the natural gas industry pushed for legislation redefining methane-based fuel as “green energy” months before it was introduced and passed in a 36-hour legislative sprint, records show. Gov. Mike DeWine signed legislation earlier this month that will make it easier to drill for oil and gas in state parks. That bill also legally redefines natural gas as “green energy.” Natural gas is a fossil fuel and significant source of climate change. The term “green energy” typically refers to electricity derived from renewable sources like the sun or the wind.
How dark money groups led Ohio to redefine gas as ‘green energy’ - The Washington Post -When Ohio Gov. Mike DeWine (R) signed a bill this month to legally redefine natural gas as a source of “green energy,” supporters characterized it as the culmination of a grass-roots effort to recognize the Buckeye state’s largest energy source.“It’s green. It’s clean. And it’s abundant right under our feet, right here in Ohio,” Rep. Troy Balderson (R-Ohio) wrote in an opinion piece in the Columbus Dispatch.But Ohio’s new law is anything but homegrown, according to documents reviewed by The Washington Post. The Empowerment Alliance, a dark money group with ties to the gas industry, helped Ohio lawmakers push the narrative that the fuel is clean, the documents show. The American Legislative Exchange Council, or ALEC, another anonymously funded group, assisted in the effort.ALEC — a network of state lawmakers, businesses and conservative donors — circulated proposed legislation for Ohio lawmakers and has urged other states to follow suit, according to the documents, which were obtained via a public records request by the Energy and Policy Institute, a group that advocates for renewable energy.“What the emails reveal is just how closely Ohio lawmakers coordinated with a natural gas industry group on the new law that misleadingly defines methane gas as green energy, as the first step of a plan to introduce similar legislation in multiple states,” said Dave Anderson, policy and communications manager for the Energy and Policy Institute.Although Ohio Republicans say they are trying to promote their state’s energy industry, critics have called the new law misleading and“Orwellian.” Unlike renewable energy sources such as wind and solar power, natural gas and other fossil fuels emit significant amounts of greenhouse gases. Leading scientists have said the world must rapidly phase out fossil fuels to avert the worst consequences of unchecked climate change.The law also adds to a fierce linguistic debate, one amped up by the recent furor over gas stoves and their health impacts. Climate activists have urged politicians and journalists to stop using the term “natural gas” and instead use the phrase “methane gas,” since its primary component is a powerful planet-warming pollutant.Last summer, the documents show, a leader of the Empowerment Alliance emailed Ohio state Sens. George Lang (R) and Mark Romanchuk (R) to share a report from Goldman Sachs on the “importance of natural gas” in North America and globally.“We are on the right track with natural gas is green energy,” wrote Tom Rastin, who leads the Empowerment Alliance with his wife, Karen Buchwald Wright.As of last fall, Rastin and his wife were listed in Federal Election Commission filings as executives at Ariel Corporation, a manufacturer of natural gas compressors. The couple also are major Republican donors who have dined with former president Donald Trump. Under their leadership, the alliance spent more than $1 million supporting Ohio Republicans in the 2022 election.
Republican legislators, oil and gas industry, hid like chickens as they redefined natural gas as ‘green energy’ - cleveland.com -- In the span of 24 hours of a substantially altered substitute bill, Ohio Senate Republicans passed legislation to expand oil and gas drilling on state lands, including state parks, and created a novel definition of “green energy” to include natural gas and any energy that “is more sustainable and reliable relative to some fossil fuels.” This vague definition could allow almost anything to qualify.For example, one could argue that methane with its high CO2 emissions or nuclear energy with its radioactive waste qualifies because it is more sustainable and reliable relative to coal. It eviscerates the true definition of green energy that refers to renewable energy such as solar, wind and hydro.Further, in a nose-thumbing to Ohio’s Constitutional Home Rule provisions, it prohibits municipalities from banning pesticides.They hid this gem in HB 507, “the chicken bill” which addresses chickens, rabbits and other food processing issues, a move no doubt to hide these actions from the public and those watching energy and environmental issues.This is a clear example of governmental capture, which is “a form of corruption of authority that occurs when a political entity, policymaker, or regulator is co-opted to serve the commercial, ideological, or political interests of a minor constituency. … When regulatory capture occurs, a special interest is prioritized over the general interests of the public, leading to a net loss for society.”A defense offered by legislators was that Europe had done something similar (Senate passes bill expanding drilling on state land; dubbing gas ‘green energy,’ Dec. 7). That is like your kid caught smoking countering with “Johnny was smoking too.” It is just plain wrong.And what Europe did is not what Ohio did. In Europe, gas was included as a temporary bridge for some countries that could not transition quickly enough from coal to renewables. The definitions were for investors to determine sustainability. The central debates in Europe remain about what qualifies as zero or low-carbon hydrogen.Further, there are arguments and studies demonstrating that gas is not more sustainable relative to some fossil fuels, so including gas is an error.If Ohio policymakers honestly care about our energy future, the way forward is not natural gas orany other fossil fuel.With global warming wreaking havoc across the nation and the world and scientific evidence that it will only get worse, now is the moment to wean us from fossil fuel, instead of lighting a match to the earth by promoting its expansion.
Opinion: Columbia Gas' plan will strip away critical savings tools as costs climb - The Columbus Dispatch - Over many years, Columbia Gas has been a great example in the Midwest of a utility providing strong energy efficiency programs for its customers.The American Council for an Energy-Efficient Economy, where I serve as a Senior Fellow, has often pointed to the Columbus-based utility as an industry leader.That is why we are so surprised by and disappointed at the settlement proposal Columbia Gas has submitted to the Public Utilities Commission of Ohio (Case No. 21-637-GA-AIR).If the PUCO approves this plan, it will not only end the bulk of Columbia’s energy efficiency programs. It would also end Columbia’s role as an industry leader in helping their customers save energy.Energy efficiency programs run by utilities — such as Columbia Gas — have a great proven record.By providing customers incentives to purchase energy-efficient equipment or make other energy-saving home upgrades, they save households and businesses money on energy bills. They also create jobs and reduce emissions that pollute the air and harm people’s health.Columbia Gas’ proposal would end all of their programs, except for one that just helps low-income customers. This proposal would strip Ohio families and businesses of tools they can use to reduce their utility bills at a time when gas prices are on the rise and price volatility is setting all-time records. Moreover, and quite incredibly, their proposal attempts to go far beyond the legitimate scope of this case by including the following restriction on Columbia Gas’ future public pronouncements and policy positions:They would not just be killing their own programs. They would actually be committing to a public policy position of not supportingothers who might pursue policies for energy efficiency programs.That provision would seem way out-of-bounds for anything that would be officially certified by a government agency such as PUCO. We certainly hope the PUCO rejects it or any similar provision.Finally, there is one other harmful aspect of Columbia’s proposal we would oppose.That is the request for a dramatic increase in the monthly “fixed charge” that customers face. Columbia’s plan would increase the current total fixed charges from about $37 to over $56 a month. Reducing your gas usage will not lower this cost for you. That kind of increase is unfair to customers who are trying to reduce their bill by being more energy efficient, and would be particularly harmful for low-income customers. This proposal for Columbia Gas contains several provisions that are especially inappropriate at a time when customers are facing high natural gas prices and are particularly in need of programs to help them become more energy efficient. We urge the PUCO to protect the people of Ohio from this unneeded and harmful request.
Columbia Gas seeks approval for natural gas pipeline for Intel - — Columbia Gas of Ohio is asking for expedited state approval to build a natural gas pipeline in Licking County where Intel, the multinational technology company, is building two fabrication facilities, also called fabs. “Because our pipeline to serve Intel is less than five miles, we're able to go through the accelerated application process versus their standard application process,” said Ellen Macke, the director of government and public affairs for Columbia Gas of Ohio.Macke said the pipeline project is still waiting for approval from the Ohio Power Siting Board, the state agency that reviews pipeline projects. She said she expects to be hearing back within the next 90 days. “The Ohio Power Siting Board technical staff is currently investigating the pipeline proposed by Columbia Gas," said Matt Butler, public information officer for the Ohio Power Siting Board. "The staff’s report of investigation, to be published by March 10, will include findings and recommendations for the Board to consider."“Our proposed route begins on South County Line Road just north of Evans Road," Macke said. "From there it will go south to U.S. 62, then northeast to Beech Road, south on Beech Road, and then east to Miller road where it will finish going up north to Clover Valley Road near the Intel site."Columbia Gas has sent out notices to homeowners near the future construction site, making them aware of the proposed project. Macke said no private properties will be affected.
Columbia Gas to begin pipeline project - Columbia Gas is set to begin a Pipeline Replacement Project in Tiffin.Beginning the week of Jan. 23, crews will be installing approximately 13,075 feet of new plastic pipe serving 309 residences on sections of Market, Lindsay, Niles, Oil, Leitner, Sandusky, Benner, Orange, Maple, Carl and St. Clair streets.In terms of timing, preconstruction camera work is underway. During this phase, residents may notice markers and flags cropping up in yards. Those are to mark the locations of underground facilities. Residents are asked to keep those markers in place until work is complete. Installation of the new mainline will begin in mid-January. Once the mainline is in and put into service, Columbia Gas will follow up with service line replacements for individual homes. These take about 2-4 hours per property and include a brief service disconnection. Indoor meters will be relocated outside as well. Crews will reach out to schedule an appointment with each property owner once we get to this phase.
Utica Shale Academy receives PNC grant — The PNC Charitable Trust has awarded the Utica Shale Academy $14,575 to purchase safety equipment for the facility.The grant award is from the Robert H. Reakirt Foundation, which is a trust administered by PNC’s Charitable Trusts Grant Review Committee. PNC’s charitable trusts support communities through grants to worthy non-profit organizations who align with donors’ charitable intents and geographic focuses. Utica Shale Academy applied for the competitive grant and funds were used to purchase steel-toed boots, welding gloves, flame-retardant jackets and welding boots.The Utica Shale Academy is located in Salineville and offers certifications in welding, industrial maintenance, heavy equipment operation/maintenance as well as courses in Youngstown State University (YSU) 3-D printing, YSU 5G and diesel mechanics. It is open to students in Columbiana, Carroll, Jefferson and Mahoning counties. It is currently in its eighth year and serves 110 students in grades 9-12 through blended learning and hands-on education to prepare them for the workforce.
Oil, Gas Production Across Shale Plays Expected to Rise in Feb. -– Oil and natural gas production across the Utica and Marcellus shale plays is expected to increase in February, according to a new report by the U.S. Energy Information Administration. According to the EIA’s monthly drilling report, oil output is anticipated to increase by 3,000 barrels per day next month in the Utica and Marcellus shale, collectively known as the Appalachian basin. Most of the Utica is found in eastern Ohio, while the Marcellus stretches from western to central Pennsylvania and into West Virginia. In January, oil producers yielded an average of 136,000 barrels per day across the Utica and Marcellus, according to EIA data. It’s projected that producers will increase output to 139,000 barrels per day in February. Natural gas production in Appalachia is projected to rise by 93 million cubic feet in February, EIA said. This month, natural gas wells in Ohio, western Pennsylvania and West Virginia collectively produce an average 35.279 billion cubic feet of natural gas per day. This is expected to increase to 35.372 billion next month, according to EIA. There have been no new drilling permits filed yet this year in the northern tier of the Utica, which encompasses Mahoning, Trumbull and Columbiana counties. Total oil production across all seven of the U.S. shale plays is projected to increase from 9.299 million barrels of oil per day in January to 9.375 million barrels per day next month, a boost of 76,000 barrels per day, EIA reported. Natural gas output is expected to climb by 466 million cubic feet per day across U.S. shale plays, according to EIA. In January, natural gas shale producers across the county yielded 96.190 billion cubic feet of gas per day. That number is projected to reach 96.656 billion cubic feet per day in February.
As The World Tries To Cut Back On Fossil Fuels, Oil Companies Turn To Plastic -From the car window, drivers on Pennsylvania route 18 can see smoke billow from the stacks of the Shell Polymers Monaca plant in Beaver County. It’s taken a decade to get to this point, but Shell’s new plastics plant near Pittsburgh is now open. This new facility will turn ethane, a natural gas component, from nearby fracking operations and process — or “crack” — it into 1.6 million metric tons of plastic in the form of tiny pellets every year, which will mainly be used to make new single-use plastic packaging. “This plant is the largest investment in Pennsylvania since the mid-century and one of the largest of its kind in North America,” Hilary Mercer, senior vice president of Shell Polymers, wrote in a November Facebook post. Pennsylvania’s fracking boom more than a decade ago initially attracted Shell to the area. The state sits atop the Marcellus and Utica Shale gas reserves. Shell officials and some in Pennsylvania’s government are optimistic that the plant in Beaver County could be the first of many, ushering a wave of petrochemical facilities to the region. The company’s leadership has described dreams of opening other polyethylene plants that would use the gas reserves to feed a booming Appalachian plastics manufacturing industry. The prospect represents something of a lifeline for the industry. Major oil companies like Shell and ExxonMobile are rapidly increasing their plastics output to make up for the anticipated shrinking demand for the companies’ fossil fuel products as nations lean on renewables and electrify their economies. Plastics are projected to be a key source of income for Big Oil over the coming decades — and these companies are using these projections to justify building new plants to crank out more. “What’s happening in the power plant sector? We’re slowly shifting to cleaner renewables, so less demand for fossil fuel for electricity,” said Judith Enck, a former EPA regional administrator under the Obama Administration and the founder of the group Beyond Plastics, a project based at Bennington College in Vermont. “What’s happening in transportation? People are buying electric cars, big truck fleets are electrifying, less demand for fossil fuels for transportation.” While Pennsylvania hopes to be the titan of plastic, United Nations members agreed in March to create the world’s first international plastics treaty by 2024 to curb plastic production. By 2030, plastic will emit more greenhouse gases than coal-fired power plants, according to a 2021 study by Beyond Plastics. Prior to the Shell plant opening, the Gulf Coast region was America’s hub for ethane cracker plants. But Chad Newton, deputy communications manager with the Pennsylvania Department of Community and Economic Development, said bringing one of these facilities to Beaver County is a “game changer” because it will “open the door for the entire petrochemical industry to develop.” A significant portion of the plastics manufacturing sector in the United States and Canada — 73 percent — is within 700 miles of Shell’s plant, according to a 2017 IHS Markit study, and could be invigorated by it.
Charles Mitchell: Pennsylvania can lead the nation in energy production, if the state lets it - Pittsburgh Post-Gazette - Pennsylvania brims with natural resources and human talent, but for the past eight years, the state’s heavy regulatory hand has often restrained opportunities for innovation. Our commonwealth has one of the largest and cleanest reliable energy sources in the nation: Pennsylvania exports more electricity than any other state and ranks second for energy exports and natural gas production. Yet, the energy sector faces prohibitive restrictions on drilling and pipeline development. Pennsylvania’s entrance into the Regional Greenhouse Gas Initiative (RGGI) — unilaterally pushed by outgoing Gov. Tom Wolf — will make things worse. Electric bills in Pennsylvania are already up, on average, 73% since 2020, but with RGGI they would skyrocket an additional 24 to 36%. Pennsylvania can change course and move toward innovation and opportunity. To do so, our elected officials must look to entrepreneurs and community leaders who are already leading the way. Consider CNX Resources Corporation, a Canonsburg-based Marcellus and Utica Shale producer led by CEO Nick DeIuliis. CNX produces lower-cost, lower-emission natural gas by employing a new wave of innovative technologies. But the real value for Pennsylvanians comes from CNX’s Appalachia First vision, which outlines how the resources within Pennsylvania and Appalachia can be harnessed to deliver affordable energy — and then reinvested into local communities. As the private sector leads the way on innovation, we must continue to invest in our commonwealth’s most precious resource: our children. Pennsylvania has what it takes to become a national leader in educational opportunity. Despite hostility from the outgoing Wolf administration, the state legislature has made enormous strides in giving students access to high-quality schools of their choice. Last year, Pennsylvania achieved the second-largest expansion of school choice in the country. In the last eight years, state lawmakers have quadrupled the state’s Educational Improvement Tax Credit (EITC) scholarship program, growing it from $60 million to $263 million. Thousands of Pennsylvania’s low- to middle-income kids now have the opportunity to create brighter futures.
Thousands Demand Shapiro Reverse Dimock Fracking Decision - Jan 13, 2023 As he prepares to take office, a petition signed by over 3,000 was delivered to Governor-elect Josh Shapiro demanding that he reverse a decision by the Wolf administration that would allow fracking to resume in Dimock.The DEP decision came as a shock to environmentalists across the state, and to residents of a town that made international headlines due to water contamination linked to drilling by Cabot Oil & Gas. The company has since merged with another drilling company, and re-branded under the new name Coterra. The DEP’s quiet decision to lift the drilling moratorium came on the same day in late November that Coterra was in court to plead no contest to charges that it was responsible for the damage in Dimock – a case brought forward by Shapiro during his tenure as Attorney General. The petition echoes a demand delivered in a December letter to Governor-elect Josh Shapiro decrying the decision to once again put the people of Dimock in harm’s way. That letter – signed by Food & Water Watch, Better Path Coalition, Earthworks, Delaware Riverkeeper Network, Friends of the Earth and others – specifically calls for Governor-elect Shapiro to undo the decision when he takes office next month.“The people of Dimock have suffered long enough, and no one knows better than Governor-elect Shapiro that the Department of Environmental Protection (DEP) cannot be trusted to make the practice safe. He has prosecuted several cases involving the DEP’s complete inability to regulate the fracking industry,” said Food & Water Watch Pennsylvania Director Megan McDonough. “The simple truth is that no amount of regulation can make fracking safe, and subjecting the people of Dimock to the dangers of the oil and gas industry again is an outrageous betrayal. It’s up to Shapiro to set this right.”“Josh Shapiro promised to go after the polluters as Attorney General. His job is about to change; as Governor, his job is to prevent pollution, an outcome all but guaranteed if Coterra is allowed to drill anywhere near Dimock. Governor-Elect Shapiro must reinstate the ban on day one as governor,” said Karen Feridun, Co-founder of the Better Path Coalition.
Transco’s Appalachian Natural Gas Expansion Facing Early Opposition - FERC has issued a certificate to the Transcontinental Gas Pipe Line Co. LLC (Transco) Regional Energy Access Expansion Project (REAE), but environmental groups are planning to oppose it. The project would expand natural gas capacity from the shale fields of Northeast Pennsylvania to other delivery points in the state, along with those in New Jersey and Maryland. Transco has argued that the project would enhance access to natural gas supply in the region by easing constraints caused by limited pipeline takeaway capacity. The Federal Energy Regulatory Commission authorized the project earlier this month, but the Commission stayed the certificate for 30 days to give impacted landowners time to file for a rehearing of the decision. FERC said in its approval that several affected landowners had intervened and protested, noting that Transco had not acquired all the necessary property interests for the project. Transco on Tuesday filed a motion to lift the stay, arguing it would cause hardship for the company and its shippers. The Williams affiliate said it reached an agreement to secure property rights with Reading Blue Mountain & Northern Railroad, which it said was the only remaining holdout. The company also said a stay was unnecessary as it has no intention to begin eminent domain proceedings. The project would expand Transco’s existing interstate pipeline system to move another 829.4 MMcf/d of natural gas. In addition to equipment modifications, the project includes constructing 22.3 miles of 30-inch diameter lateral pipeline and 13.8 miles of 42-inch diameter loop pipeline in Pennsylvania. One compressor station in New Jersey would also be built. A coalition of environmental organizations led by the Sierra Club’s New Jersey chapter said shortly after FERC issued the REAE certificate that it would file a motion for rehearing. The groups argued that the project would expand fossil fuel infrastructure and increase greenhouse gas emissions. They also claimed FERC’s decision ignored a New Jersey Board of Public Utilities (BPU) and Ratepayer Advocate filing with the Commission that found the project is unnecessary for the state’s energy supply. “A BPU commissioned report shows current gas infrastructure will be able to meet demand through 2030, even during peak usage in cold winter weather,” the Sierra Club said.
New England Natural Gas Prices Soared in 2022 Amid Stiffer Global LNG Competition - New England paid some of the highest natural gas prices on record last year amid pipeline constraints and stronger competition for LNG. Daily spot natural gas prices at Algonquin Citygate near Boston peaked last year at $34.900/MMBtu in December, according to NGI data, and were higher than benchmarks in both Asia and Europe at that time. Average prices at Algonquin Citygate last year were $8.880, or nearly double the $4.470 in the prior year, according to NGI data. The region is the only one in the United States that has to import liquefied natural gas for power generation and heating, particularly during cold snaps. “New England pays some of the highest energy prices in the country,” and competes for LNG in a tight global market, said Poten & Partners’ Jason Feer, global head of business intelligence. “Basically this region lacks pipeline capacity to provide supply during cold weather, so LNG imports must fill the gap.”Global LNG and gas prices skyrocketed in 2022, hitting record highs when Europe scrambled to replace Russian gas imports after the Kremlin cut deliveries in response to western sanctions for its invasion of Ukraine. Feer told NGI that New England will have to compete with Europe for LNG supply, but that has not been a problem so far this winter due to relatively warm weather in Europe. The region’s LNG imports are delivered to Exelon Corp.’s Everett terminal in the Boston Harbor, to Excelerate Energy Inc.’s offshore Northeast Gateway in Massachusetts Bay and to Repsol SA’s Saint John LNG facility in New Brunswick, Canada. Between December 2021 and November 2022, Everett and Northeast Gateway imported 22.4 Bcf of LNG at a weighted average price of $27.51/MMBtu, according to the U.S. Department of Energy. Over the same time between 2020 and 2021, the facilities took in 25.3 Bcf, but the weighted average price was just $9.16. National Grid plc, and other utilities in Massachusetts, procure electricity from generators and pass “that cost to customers without mark-up or profit – so customers pay what we pay,” said National Grid spokesperson John Lamontagne. National Grid procures electricity twice a year – in November and May, “and during that 20-year period, the procurement process worked well for customers, as gas prices remained relatively low.” But wholesale day-ahead electricity prices in New England jumped last year as the daily average price rose above $100/MWh 25 times in January 2022, according to the Energy Information Administration (EIA).New England lacks underground gas storage and pipelines are constrained as efforts to build more infrastructure in the region have been stymied by governments and environmental opponents in recent years. But the region still relies heavily on natural gas for its energy needs, especially during the winter season, when demand can spike and exceed the volume of gas that regional pipeline infrastructure can deliver. On peak demand days, LNG contributes up to 35% of the region’s gas supply. “Natural gas is the predominant fuel source for electricity generation in New England, and as such, prices for gas will affect wholesale electricity prices,” said Matt Kakley, a spokesperson for the Independent System Operator of New England (ISO-NE). “As prices have risen for both pipeline gas and LNG, we have seen corresponding increases in electricity prices.” “Until significant new LNG supplies come online by 2025 and beyond for most new capacity, the region may have to compete for supply during periods of peak demand in the winter periods,” Feer said when asked how long-term contracts can mitigate price risk in New England. An average U.S. residential customer is forecast to pay 14.82/KWh for electricity in 1Q2023, according to the EIA. In New England, customers are expected to pay 27.82/KWh for the same period.Feer said that while there are no easy solutions for New England, the best would be to build additional pipelines to carry more supplies from the Appalachian Basin, where production is currently above 35 Bcf/d.“But New England states are famous for their opposition to new pipelines and energy infrastructure,” he added. “The region is densely populated and locals just have very little interest in new pipelines.”
New England clean energy goals slam into oil reality - New England power plants burned more oil for electricity on a single day during last month’s deep freeze than they have in four years, underscoring the gap between Northeastern states’ clean energy targets and the current resource mix in the region.Oil resources supplied 29 percent of a six-state region’s power on Dec. 24 as temperatures hovered in the teens, natural gas supplies tightened and some generators failed to perform as expected. The amount of electricity generated by oil that day was higher than it had been since a weekslong polar vortex hit New England in January 2018, according to an E&E News review of annual reports from the regional grid operator on fuel use.New England and New York are the only parts of the country that rely extensively on oil resources for backup power when other electricity supplies are expensive or in short supply. In both regions, oil is used sparingly throughout the year, having accounted for 0.2 percent of the total electric load in New England in 2021, according to ISO New England, the area’s nonprofit grid operator.But the exception is on days like Dec. 24, when frigid temperatures spurred New Englanders to crank up the heat, leaving less natural gas available for electricity. That pushes electric generators with oil stored on-site to begin burning the liquid fuel.“It’s certainly better than the alternative of having blackouts,” said Michael Goggin, a vice president at Grid Strategies LLC, a pro-clean energy electric power consulting firm. “But in the long term, there are much better solutions.”Natural gas emits about 30 percent less climate-warming carbon dioxide than oil when burned, although oil emits less carbon dioxide on a unit-by-unit basis than the most polluting fuel: coal. Typically, natural gas makes for a cheaper source of electricity than oil nationwide.New England’s dependence on oil during times of high energy demand is closely linked to its longstanding reliance on natural gas, which provided just under half of the region’s power in 2021. When natural gas supplies are constrained and energy demand is high, there is rarely any option other than oil to keep electricity flowing, based on the current resource mix.“It’s been years that this back and forth switching between fossil fuels has been going on, and it’s not improving,” Amy Boyd, vice president of climate and clean energy policy at Acadia Center, a New England-based environmental advocacy group, said in an email. “We need to instead come to a better solution.”Experts in New England mostly agree that burning oil on rare, exceptionally cold days is probably cheaper and more politically tenable than another option floated over the years: building additional natural gas pipelines to increase the supply of gas flowing to the area.Still, one question for New England is how long its old, oil-burning generators will stick around, given how infrequently they run and the high costs of maintaining them relative to how much revenue they bring in, said John Simonelli, the former director of operations support services at ISO New England.
Activists want Chicago to rule out natural gas in new buildings - Advocates want Chicago to join New York, Los Angeles and Boston in effectively banning the use of natural gas in most new construction. In Chicago, gas is often used to provide residential heat and hot water, and to power stoves and laundry dryers — all of which can now be done with electricity. The news conference was in support of a “Clean Buildings, Clean Air” ordinance that organizers said was being drafted by Mayor Lori Lightfoot’s office, with their input. The clean buildings ordinance is not yet public, according to Kolata, but he expects it to be made available soon. Lightfoot’s office did not comment on whether it was working on an ordinance but released a statement from the mayor commending the work of the clean energy groups. “This topic is critically important, and that’s why I commissioned the Chicago Building Decarbonization Working Group in 2021 to better understand how we can move to decarbonize buildings and alleviate the energy burden for Chicagoans struggling to pay their utility bills,” Lightfoot said in the statement. Kolata said the expected ordinance is not technically a ban on natural gas in new construction. Instead, advocates want Chicago to follow New York’s lead, and establish emissions standards for new buildings that are so high they basically rule out fossil fuels. In New York, that approach has been widely referred to as a ban on natural gas in new construction. Peoples Gas provided a written statement noting that the company has been serving Chicago for 170 years and called the reasoning behind the proposed clean buildings ordinance “flawed and unrealistic.” “Electric heat pumps may help keep Chicago warm in the future, but they cannot be relied upon today,” the statement said. “Not only do they struggle to work in cold climates, but it costs up to $60,000 to convert a single home to an electric heat pump. Further, Chicago’s electric system will be powered by natural gas for years to come, which shows that these activists’ thinking is flawed and unrealistic.” A Consumer Reports survey found that members paid a median price of $7,791 to purchase and install a heat pump, versus $6,870 for a gas furnace. Whole-house heat pumps for cold climates can easily cost more than $10,000, Consumer Reports noted, but that’s for both heating and cooling — heat pumps provide air conditioning. With state subsidies, heat pumps can cost less than gas furnaces, according to Consumer Reports. The federal government’s Inflation Reduction Act provides a 30% tax credit of up to $2,000 for heat pumps and ComEd offers rebates.
Scientists hit back at gas industry for twisting stove study - The furor last week over a potential ban of gas stoves sparked rants of protest and partisan posturing.But one voice was not heard amid the clamor: the researcher whose study the gas industry seized on to tout the safety of gas stoves.He says his research is being misused. Bert Brunekreef, a professor of environmental epidemiology at the Netherlands’ Utrecht University, is the co-author of a 2013 study looking at associations between the use of different cooking fuels and asthma in 47 countries. The research, which was published in The Lancet as part of the International Study of Asthma and Allergies in Childhood, found that open fire cooking did increase the prevalence of asthma in young children, but “detected no evidence of an association between the use of gas as a cooking fuel and either asthma symptoms or asthma diagnosis.”The finding has been seized on by the American Gas Association and American Public Gas Association in recent weeks as a way to undercut calls for a federal ban on gas stoves, as well as more recent research that has linked gas stove use to asthma in children.But Brunekreef said, “That’s not a good use of our study.” AGA has used Brunekreef’s research to combat the findings of another analysis that was heavily cited last week when one member of the U.S. Consumer Product Safety Commission, Richard Trumka Jr., expressed interest in his agency banning gas stoves altogether due to health concerns. The other four members of the CPSC do not support that position and the agency has no plans to regulate gas stoves, but Trumka’s comments set off a frenzy of opposition from Republicans and the natural gas industry (Greenwire, Jan. 10).The industry groups take particular issue with a peer-reviewed paper, published in the International Journal of Environmental Research and Public Health (IJERPH) last month that found 13 percent of childhood asthma cases in the United States — affecting some 650,000 kids — “is attributable to gas stove use” and could theoretically be prevented by the use of electric appliances in the home.AGA argues that the study is not trustworthy because some of the study’s authors work for the nonprofit clean energy group RMI, which advocates electrifying buildings. AGA also says that the study “ignored literature” like Brunekreef’s study from a decade earlier that the industry says shows the safety of gas stoves. Ironically, that IJERPH study linking asthma and gas stoves is actually based on other research Brunekreef co-authored in 2013.“It is entirely based on our meta-analysis,” Brunekreef said.That meta-analysis was a literature review of more than 40 research papers looking at the effects of nitrogen dioxide emissions from gas stoves and asthma. It found, “In children, gas cooking increases the risk of asthma and indoor NO2 increases the risk of current wheeze.” Specifically, it calculated that children who live in homes with gas stoves had a 42 percent increased risk of current asthma and a 24 percent increased asthma risk over their lifetime.
Tampa Bay environmentalists push back on proposed fracked gas pipeline expansion - Energy companies are pushing for the expansion of a pipeline that would increase the amount of fracked gas sent from Pinellas to Hillsborough, but environmental advocates say it infringes on local clean energy goals. Last November, Florida Gas Transmission Company (FGTC), which is based in Texas, and Tampa Electric Company quietly introduced a pipeline expansion proposal to the Federal Energy Regulatory Commission (FERC). The proposal, called the “Tampa West Project” says the expansion includes, “the construction of approximately 1.26 miles of 8-inch lateral loop pipeline” along with piping attachments. The proposed area would run alongside the Gandy Bridge, and would attach to a current pipeline to help increase the flow of gas from Pinellas to Hillsborough. Proposal documents say the addition of the piping could allow the peak hourly flow of gas to the TECO Energy Plant at Big Bend Road to double, from 360 million thermal units of gas per hour to 667 million. The gas increase would consist of fracked gas from other states, mainly via the Gulfstream Natural Gas Pipeline, which runs across the gulf from Alabama to Florida and is fed by other pipelines. Estimates show that fracking produces about 67% of America’s natural gas. For decades, the process has proven harmful to the environment via creating large amounts of wastewater, emitting greenhouse gasses, such as methane, and releasing other toxic air pollutants. The cost of the proposed project does not yet have an estimate, which is dependent on what’s agreed to during a suggested contract agreement date of April 1, 2023, should FERC approve the project. If the project is approved, the cost would most likely be passed along to the taxpayer. The proposal indicates that part of the preliminary agreement says that the companies will seek to, “recover the cost of service associated with the Project.”
North American E&P Spend to Increase 14% in 2023; Maintain in Appalachia, Grow in Haynesville -Only a few U.S.-based exploration and production (E&P) companies have provided formal capital spending plans for 2023, but expenditures overall are forecast to decelerate from a year ago. E&P executives are surveyed twice a year by Evercore ISI to determine the level of capital expenditures (capex) and activity, which often are revised. Respondents indicated that global spending should continue to rise, up by 14% from 2022. However, it’s down from the rate of increase in 2022, when capital spending jumped 20% overall from 2021. North America, however, is still seen with a solid gain in capex for 2023. “While we forecast growth to decelerate in both North America and internationally, North America’s impressive 18% end-of-year growth follows a near record 44% in 2022,” said Evercore managing director James West. U.S. E&P executives surveyed in late December were setting their capex for 2023 using an average oil price forecast of $78/bbl West Texas Intermediate (WTI) oil and $5.10/MMBtu Henry Hub (HH) natural gas.“Average oil and gas prices of $125 WTI and $7.70 HH were cited for budgets to revise higher while $62 WTI and $3.25 HH were cited for budgets to revise lower,” West said. “With energy security, surety of supply and production capacity additions key drivers for a cyclical recovery in global E&P spending, we believe there is only moderate risk to our initial estimates for 2023 growth rates in the 15-20% range for all the key operating regions.”U.S. natural gas futures averaged above $5.00 late last year, while NGI’s Spot Gas National Avg. surged to nearly $20 as freezing weather hit typically mild winter climates, including in California.Although natural gas prices staggered into the new year, HH is set to recover to average near $5.00 through March, according to updated projections from the U.S. Energy Information Administration. The projections were published in the January edition of its Short-Term Energy Outlook.U.S.-based supermajors Chevron Corp. and ExxonMobil issued their capex plans in December. ExxonMobil’s 2023 capital budget of $23-25 billion has almost three-quarters directed to developments in Brazil, Guyana, the Permian Basin and for LNG projects. Through the first nine months of 2022, the supermajor had spent about $15 billion, implying full-year capex of around $20 billion-plus.Chevron, which set a $17 billion budget this year, plans to spend nearly $8 billion for U.S. upstream projects, up 25% year/year. About one-half of the capex, $4 billion, is budgeted for the Permian, up by one-third. The Evercore survey indicated that North American E&P capex “should increase by 18% in 2023, rising 6% above 2017 and within 5% of 2019 levels,” West noted.This year may approach pre-Covid levels, he said. “Building on strong growth in 2022, we project North American E&P spending to increase by 18% in 2023 to within 7% of pre-Covid levels. The U.S. should lead again with spending up 19% in 2023 while Canada moderates at 10.5%.”Independents and private operators account for more than 70% of regional capex in North America. “While privates were faster to increase capex post-Covid, the publicly traded independents shored up their balance sheets and prioritized returning cash to shareholders,” West noted. “We believe this trend could be reversing, with privates becoming more fiscally minded as service cost inflation begins to rise.”The private E&Ps account for around 20% of Evercore’s U.S. capex estimate – but 6% of the rig count. That suggests that overall U.S. spending could be larger than Evercore’s estimate.
U.S. Midstream Working to Expand Permian, Haynesville Natural Gas Pipelines - As the United States works toward casting a wider net on the global natural gas market via exports, key domestic markets like the Permian Basin and Haynesville Shale could be turned upside down in 2023 as midstream bottlenecks leave gas stranded. LNG developers on the Gulf Coast are in a race to boost liquefied natural gas exports to capitalize on rising demand in Europe and Asia. Some projects are under construction and could begin operations in 2024. A handful of others could be sanctioned this year. East Daley Analytics Inc. projects U.S. liquefaction capacity could swell to nearly 30 Bcf/d by 2030. That’s up from around 13 Bcf/d in 2022. Gas companies up and down the value chain also see continued momentum for LNG. Producers have taken notice of the export growth potential. As head of one of the largest North American independents, Ovintiv Inc. CEO Brendan McCracken told investors on the 3Q2022 earnings call that “what we see unfolding is a call on North American gas supply and global LNG demand, whether it’s in Europe or Asia or other parts of the developing world…That’s durable pricing that we see unfolding over decades…” U.S. regulators share a similarly optimistic view. The Energy Information Administration sees export demand growth driving an increase in natural gas production this year. The agency expects output to average 100.4 Bcf/d in 2023. At the heart of the increased supply is rising output in the prolific Permian Basin of West Texas and southeastern New Mexico, and the Haynesville Shale in East Texas and southwestern Louisiana. The problem is, pipelines in the Permian and Haynesville are nearly tapped out and could fill completely this summer. That means any additional production hitting the market this year is likely to struggle to make its way downstream. It’s a sore spot for the midstream sector, one that isn’t likely to be remedied anytime soon. For the Permian in particular, East Daley’s Rob Wilson, vice president of analytics, said he expects supply growth to fill basin takeaway sometime in the first quarter of 2023. The lack of takeaway out of the Permian has been an issue before. In 2019, swelling gas output filled pipelines, and the market awaited Kinder Morgan Inc.’s Gulf Coast Express (GCX). The 2.0 Bcf/d conduit was a boon for producers, which sometimes were forced to pay customers to take their gas before GCX began service in the fall of 2019. Gas prices at the Waha Hub in West Texas at one point fell to negative $9.00/MMBtu. Pipeline space grew hard to come by the following year, with prices tumbling to negative $10 as producers paid to get gas off their hands. Kinder then brought online the 2.1 Bcf/d Permian Highway Pipeline (PHP). WhiteWater Midstream LLC and its partners brought online the Whistler Pipeline in the summer of 2021. However, Whistler began operations in a far different landscape than its predecessors. After Covid-19 upended the energy industry and decimated demand, Whistler started flowing gas when there was pipeline capacity to spare in the Permian. That didn’t last long, though. Permian production was reported to be close to a record 16.5 Bcf/d in December. Though estimates vary, more growth is expected. What’s preventing analysts from providing clearer guidance? Tightening egress and uncertainty over when more pipeline capacity may hit the market.
Natural Gas Futures, Spot Prices Rally Ahead of Cold Front -- Following back-to-back weekly declines to start the new year, natural gas futures on Tuesday rebounded amid forecasts for fresh bouts of cold later this month. The February Nymex gas futures contract gained 16.7 cents day/day and settled at $3.586/MMBtu. March rose 5.7 cents to $3.253. NGI’s Spot Gas National Avg. on Tuesday jumped 90.5 cents to $6.115. The prompt month had shed 27.6 cents on Friday ahead of the Martin Luther King Jr. Day holiday weekend and after several days of unseasonably warm weather to start 2023. Production also proved strong and held around 101 Bcf/d, near record levels of about 102 Bcf/d, according to Bloomberg’s estimate Tuesday. However, colder forecast trends over the long weekend sent the outlook for the Jan. 25-31 period “solidly to the bullish side,” NatGasWeather said Tuesday. “Frosty Canadian air will pour into the western and central U.S. this weekend…for a bump in national demand,” the firm said. “Cold air will finally advance into the East next week, resulting in below-normal temperatures covering most of the U.S.,” bolstered by “several reinforcing cold shots into the northern U.S. “Lows of 20s and 30s will also advance relatively deep into Texas and South next week to aid strong national demand.” EBW Analytics Group’s Eli Rubin, senior analyst, said that while production is near all-time highs, colder weather late this month and, potentially, into early February could cause wellhead freeze-offs across the Bakken, Rockies and MidContinent, resulting in lighter supply. Still, natural gas prices are more than 50% lower than where they were just a month ago. Rubin cautioned that for futures to sustain an upward trajectory, colder air will need to arrive soon and forecasts for more of it into February may be needed.
U.S. natgas futures drop 8% to 18-month low on forecasts for less demand (Reuters) - U.S. natural gas futures plunged about 8% to an 18-month low on Wednesday on forecasts for less heating demand in late January than previously expected. Adding to the price drop, a growing number of analysts have said they do not expect Freeport LNG's export plant in Texas to restart until February or later even though the company has said repeatedly that the liquefied natural gas (LNG) plant was on track to exit its seven-month outage in the second half of January, pending regulatory approvals. Whenever Freeport returns, demand for U.S. gas will jump, which should cause prices to rise. The plant can turn about 2.1 billion cubic feet per day (bcfd) of gas into LNG, which is about 2% of U.S. daily production. Front-month gas futures NGc1 for February delivery fell 27.5 cents, or 7.7%, to settle at $3.311 per million British thermal units (mmBtu), their lowest close since June 22, 2021. That price drop pushed the contract back into technically oversold territory with a relative strength index (RSI) below 30 for the 12th time in 14 days. It also continues the record volatility seen last year, with the contract now up or down over 5% on six of the 11 trading days in 2023. With colder weather coming, Refinitiv forecast U.S. gas demand, including exports, would jump from 121.4 bcfd this week to 128.7 bcfd next week. The forecast for next week was lower than Refinitiv's outlook on Tuesday. Traders said the biggest market uncertainty remains when the Freeport plant will return after shutting due to a fire on June 8, 2022. Gas started flowing to the Freeport plant on Jan. 14, according to data from Refinitiv, but was only being used to maintain the flare system, according to a source familiar with the plant. Although Freeport LNG says the plant is still on track to restart in the second half of January, pending regulatory approvals, that restart timeline has been delayed many times from October to November to December and most recently to January. Freeport has not yet filed a request with federal regulators to restart the plant, according to a source familiar with the company's filings. Even when the company was saying the plant could restart last year, many analysts said it would likely take Freeport until the first or second quarter of 2023 to get the plant ready due to the large amount of work needed to satisfy federal regulators, including training staff in new safety procedures. Even though some vessels have turned away from Freeport in recent weeks, a few tankers, including Prism Diversity, Prism Courage and Prism Agility, were still waiting in the Gulf of Mexico to pick up LNG from the plant. Some have been there since early November.
U.S. natural gas slips to fresh 18-mth low on expected Freeport LNG delay (Reuters) - U.S. natural gas futures eased about 1% to a fresh 18-month low on Thursday as another liquefied natural gas (LNG) tanker turned away from Freeport LNG's export plant in Texas, a further sign that the plant's restart will likely not happen in January. That price decline flew in the face of a storage report showing a bigger-than-expected draw last week and forecasts for colder weather and more heating demand next week than previously expected. The U.S. Energy Information Administration (EIA) said utilities pulled 82 billion cubic feet (bcf) of gas from storage during the week ended Jan. 13. That was more than the 71-bcf decline analysts forecast in a Reuters poll and compared with a decrease of 156 bcf in the same week last year and a five-year (2018-2022) average decline of 203 bcf. Analysts said utilities pulled less gas from storage than usual because the weather last week was warmer than normal, keeping heating demand low. Last week's decrease cut stockpiles to 2.820 trillion cubic feet (tcf), or 1.2% above the five-year average of 2.786 tcf for this time of year. Front-month gas futures for February delivery fell 3.6 cents, or 1.1%, to settle at $3.275 per million British thermal units (mmBtu), their lowest close since June 22, 2021 for a second day in a row. In a sign that a growing number of market participants have given up hope that extreme cold will bring massive price spikes later this winter, the premium on March futures over April NGH23-J23, which the industry calls the widow maker, fell to a record low of one cent per mmBtu. The industry calls the March-April spread the "widow maker" because rapid price moves resulting from changing weather forecasts have forced some speculators out of business. With colder weather coming, Refinitiv forecast U.S. gas demand, including exports, would jump from 121.7 bcfd this week to 130.6 bcfd next week. The forecast for next week was higher than Refinitiv's outlook on Wednesday. Traders said the biggest market uncertainty remains when the Freeport plant will return. Although Freeport says the plant is still on track to restart in the second half of January pending regulatory approvals, that restart timeline has already been delayed many times from October to November to December and most recently to January.
Natural Gas Futures Finish Bruising Week on Sour Note; Cash Prices Tumble - Natural gas futures traded in a narrow range much of Friday, ultimately culminating another sluggish week with a loss amid mild weather and elevated production levels. The February Nymex gas futures contract settled at $3.174/MMBtu, down 10.1 cents day/day. March lost 8.8 cents to $3.036. The prompt month futures contract finished the week down 7% from the prior week’s close. This reflected unseasonably warm weather across much of the eastern half of the country through much of January to date, along with strong production that steadily held around 100 Bcf/d. However, colder weather may soon arrive, bolstering heating demand and potentially interrupting production, NatGasWeather noted. It projected fresh arctic air arriving in the week ahead and potentially carrying into early February. Ahead of Friday trading, both the American and European weather models added heating degree days for that period, according to the firm. “National demand will increase to strong levels as cold air over the central U.S. spreads into the East,” NatGasWeather said. However, the American model “remains notably colder” than its European counterpart for the Jan. 28-Feb. 2 time frame, according to the firm. The European dataset shows less “coverage of subfreezing temperatures, especially over the South and East, as it favors a stronger ridge, effectively blocking colder upstream air.” “On a seasonal basis, there is little fundamentally to excite bulls at present. Technical indicators and oversold conditions suggest a bounce is possible, but every recent attempt to move rapidly higher has succumbed to bearish fundamental pressure,” Rubin said. “With gas production up 6 Bcf/d year-over-year and Freeport LNG offline, storage surpluses may continue to expand even during modestly supportive colder February weather.” The Freeport liquefied natural gas export plant in Texas, forced offline in June following a fire, is expected to complete repairs by the end of this month, according to the facility’s management. This would enable it to ramp up 2 Bcf/d of capacity within weeks, drawing gas from domestic supplies and compensating for the mild weather start to 2023. However, the Freeport LNG relaunch was originally planned for last year – and was delayed twice. This has left analysts dubious about its return in January. Meanwhile, the U.S. Energy Information Administration (EIA) on Thursday reported a storage decrease of 82 Bcf for the second week of January. It compared bearishly with a five-year average draw of 156 Bcf and a year-earlier pull of 203 Bcf. The decrease for the Jan. 13 week lowered inventories to 2,820 Bcf but left stocks above the five-year average of 2,786 Bcf. Analysts at the Schork Report called it a “meager” pull. It followed a rare January injection of 11 Bcf reported for the first week of the month…
U.S. Adds Six Natural Gas Rigs as Oil Count Pulls Back - The U.S. natural gas rig count rose six units to 156 for the week ended Friday (Jan. 20), while a sharp pullback in the oil patch saw the combined domestic tally drop four units to 771, the latest figures from Baker Hughes Co. (BKR) show. The increase in natural gas rigs only partially offset a 10-rig decline in U.S. oil-directed drilling for the period. Land drilling declined by one rig overall, while the Gulf of Mexico count fell three units to end at 16. Vertical rigs dropped four units week/week, while directional and horizontal rig totals were unchanged domestically. The combined 771 active U.S. rigs as of Friday compares with 604 rigs running in the year-earlier period, according to the BKR numbers, which are partly based on data from Enverus. Canada’s rig count, meanwhile, surged 14 units higher week/week to finish at 241, up from 212 in the year-ago period. Gains there included 12 oil-directed rigs and two natural gas-directed rigs. Counting by major drilling region, the Permian posted a two-rig decline for the period, dropping its total to 354, versus 292 a year ago. The Haynesville and Utica shales each added one rig, while the Ardmore Woodford, Eagle Ford Shale and Marcellus Shale each posted one rig declines for the period, according to the BKR numbers. In the state-by-state breakdown, Louisiana dropped three rigs from its total to fall to 64, versus 56 at this time last year. Alaska and New Mexico each saw one-rig declines, while one rig was added week/week in Texas.Only a few U.S.-based exploration and production (E&P) companies have provided formal capital spending plans for 2023, but expenditures overall areforecast to decelerate from a year ago. E&P executives are surveyed twice a year by Evercore ISI to determine the level of capital expenditures (capex) and activity, which often are revised. Respondents indicated that global spending should continue to rise, up by 14% from 2022. However, it’s down from the rate of increase in 2022, when capital spending jumped 20% overall from 2021.
Scientists: Tougher oil and gas rules needed in gulf to protect rare whale -Two years ago, scientists announced they had discovered a new species in the Gulf of Mexico: Rice’s whale, which they called one of the rarest whales on the planet.The endangered species — only about 50 are believed to exist — lives in the northern Gulf of Mexico. Environmental scientists and advocacy groups are now pressing the federal government to set tougher restrictions on oil and gas companies operating in the gulf to prevent the whale from going extinct.“It’s not too often that we discover new species of whales. And to discover that was exciting, but it was also a little bit bittersweet because they are so critically endangered,” said Kristin Carden, a senior scientist for the Center for Biological Diversity oceans program.Discovered by scientists at the National Oceanic and Atmospheric Administration, the whale can weigh up to 60,000 pounds — about the same as a firetruck — and is part of the baleen whale family, toothless whales that use hairy fringes called baleen to filter food from seawater. It’s the only baleen whale known to live in the gulf, and Carden said its isolation led to it evolving into its own species.Rice’s whales usually hang out near the northeastern Gulf of Mexico off the coast of Florida, but a single whale has been observed off the coast of Texas, suggesting they move throughout the gulf. Scientists at the National Marine Fisheries Service, also called NOAA Fisheries, are conducting research to understand the whales’ migration patterns.According to NOAA, the most significant threats Rice’s whales face are energy exploration and development, oil spills and chemicals used to disperse oil after a spill. The whales were hit hard by the 2010 Deepwater Horizon oil spill, which killed 11 workers when a British Petroleum drilling platform exploded and sank, spilling 4 million barrels of oil into the gulf over 87 days.NOAA estimates that about 22% of the whale population was lost because of the spill, along with countless other marine mammals, sea turtles, fish, birds and other wildlife.
Environmental groups sue U.S. to stop deepwater oil-export facility- (Reuters) - Environmental groups on Thursday sued the United States to overturn its approval of a deepwater oil-export facility off the Texas Gulf Coast, saying it would boost oil-production and greenhouse gas pollution. The Sea Port Oil Terminal (SPOT), owned by energy pipeline operator Enterprise Products Partners, (EPD.N) would be the largest offshore export terminal in the United States with the capacity to load two supertankers at a time and export 2 million barrels of crude oil per day. Environmental groups, including the Sierra Club, Center for Biological Diversity and others, said the terminal and related pipeline construction could cause oil spills and affect some species. The U.S. Maritime Administration (MARAD), an agency of the Department of Transportation, failed to adequately assess the oil-spill risk and harm to species in approving the terminal, the environmental groups said. MARAD in November issued an order saying construction and operation of the offshore port was in the national interest and the project met environmental quality goals. The agency had found in its decision that construction of the offshore export terminal will reduce the number of ship-to-ship transfers of crude oil and lessen emissions from conventional crude oil loading facilities. The environmental impact analysis requirements of the National Environmental Policy Act have also been satisfied, MARAD had said. "MARAD’s review of SPOT’s environmental and community impacts entirely fails to account for the project’s significant contributions to climate change," said Sierra Club Senior Attorney Devorah Ancel. A license is yet to be issued before SPOT can begin construction of the port.
Boat fire causes oil spill in Corpus Christi Marina | kiiitv.com — A fire left a shrimp boat severely damaged, which then leaked diesel fuel into the waters at the Corpus Christi Marina Sunday, officials with the city said. Boom was immediately deployed to contain the fuel while crews worked to extract it from the water, a news release from the City of Corpus Christi said. The fire was reported just after 12:30 p.m. at the Cooper's Alley L-Head. The Coast Guard, Corpus Christi Fire Department, Port of Corpus Christi, Texas General Land Office and Texas Commission on Environmental Quality all responded to the scene. Fire crews quickly had the fire out and no injuries were reported, officials said. The owner of the boat said that around 200 gallons of diesel fuel were onboard but city officials said it is unclear how much of it spilled into the water. Some of the fuel drifted north with the strong winds but was contained and removed from the water, officials said. The boat owner hired EnviroServe, a company providing a 24-hour emergency environmental response, to deploy additional boom and provide cleanup services. As of 9 p.m., the city reports all clean-up operations are complete, including the removal of the remaining diesel fuel from the damaged boat's tank. Environmental teams will return to the site tomorrow at 8 a.m. to determine if additional cleaning is needed, officials said. The boat, which is partially submerged, will be removed from the bay in the coming days. Portions of the L-Head will be closed to pedestrian and vehicular traffic until further notice.
Heavy slate of U.S. oil refinery overhauls to crimp fuel output (Reuters) - U.S. oil refiners plan twice as many refinery overhauls this spring as usual, aiming to resume maintenance delayed by the pandemic and by the lure of record-high margins, according to data provider IIR Energy and Reuters reporting. The size of the planned outages suggests supplies of gasoline and diesel could tighten and margins rise as the European Union's Feb. 5 ban on imports of Russian petroleum products takes effect, increasing the call on U.S. fuels. At least 15 U.S. oil refineries plan maintenance ranging from two to 11 weeks through May, tallies by Reuters and refining intelligence firm IIR Energy show. By mid-February, U.S. refiners will drop some 1.4 million barrels per day of processing capacity, double the five-year average, according to IIR. "A lot of plants didn't want to shut down last year when margins were strong, but they have to get this work done," said John Auers, refining analyst with Refined Fuels Analytics. Nine U.S. refineries operated by Marathon Petroleum, Valero Energy, Exxon Mobil, Phillips 66, and BP will shutter some of their fuel producing units this spring, according to IIR and Reuters sources. PBF Energy's Toledo, Ohio, refinery remains largely offline from December, according to two people familiar with the matter. TotalEnergies is restarting most of the units at its Port Arthur, Texas, refinery after several shut due to frigid weather in late December. Fuel-producing margins have crept higher on the outages. The gasoline crack spread is hovering around $26 per barrel, $5 higher than a year ago. Heating oil margins are $58 per barrel, more than double the year-ago level. U.S. gasoline inventories are 226.8 million barrels, compared to 240.7 million at this time last year, while refinery capacity is 8% lower than before storm Elliott. "Refiners are going to have a hard time catching up with refinery row struggling to make a comeback," said Bob Yawger, director of energy futures at Mizuho. New capacity is coming to market soon. Exxon this month launched start up procedures at a $2 billion expansion of its Beaumont, Texas, refinery, Iraq's Karbala oil refinery is expected to start in March, and a second leg of Kuwait's 615,000 barrel per day al-Zour refinery is due to start up next quarter. "Beaumont's startup, and startup of other plants across the world in the first half of the year, should prevent significant product shortages," said Auers.
2023 State of Oil and Gas presentation promises bright year for the industry - — The 2023 State of Oil and Gas presentation was held Tuesday at the Bush Convention Center. It seems that an increase in oil production will be coming to the Permian Basin, with keynote speaker Rich Dealy predicting high growth in the oil and gas industry until 2040. However, it may also come with some slight stagnation in 2023. "I think that we can expect some increase, and then it starts to level off," said Tracee Bentley, president and CEO of the Permian Strategic Partnership. "But I think importantly what we also learned today is that we know that the mineral is there. So, in order to increase production, we need to make some infrastructure investments, so that means more pipeline and more ways to get to the market product." However, any type of growth in the oil and gas field can result in positive economic news for all of the Permian Basin. With the growth coming, it will also come with more production of rigs and labor. "Any area that is growing is going to be positive for the economics of the Permian Basin," Dealy said. "If you look at rig counts, like what I said, that is expected to grow from the 330 we have right now, to about 400 over the rest of this decade. Frack fleets are going to be up, service company and labor is going to be up, so all of these things bode well from an economic standpoint." Economic success can be moved to other areas of the Permian Basin, which is why the Permian Strategic Partnership was created. Pioneer Natural Resources, who also presented the presentation, and nineteen other oil and gas companies invest their money in work areas across the area to make it a better and safer place to live. "We can put funds in a pool that can really be directed in scale and can be leveraged in other trusts and funds and foundations out there to really make a difference in education and health care and roadways," Dealy said.
Lower 48 Natural Gas, Oil Permitting Rebounds in December, Led by Texas and Wyoming - U.S. natural gas and oil drilling permit activity ended the year surpassing expectations, climbing 13% in December or up by 389 permits from November, according to Evercore ISI. The energy analyst team led by James West compiles domestic permitting figures using state and federal data. Lower 48 permits often are issued three to six months before development begins. “After November’s 7% decline, issued permits rebounded in the last month of the year to 3,452, a 29% increase from December 2021, an 83% increase from December 2020, and a 49% increase from the same month in 2019,” the Evercore analysts said. In 2022, there were 39,833 permits issued for drilling overall in the United States. That was 50% higher than in 2021 and 106% more than in 2020, the Evercore data indicated. However, permitting fell by 26% last year from the strong year of 2019, when 53,933 permits were issued and the year before the pandemic sent activity reeling. The Permian Basin recorded a 21% jump in December permitting month/month (m/m), increasing by 205. In the Powder River Basin, there was a reported 52% increase, up by 126 permits m/m. In the Eagle Ford Shale, 102 more permits were issued in December, a gain of 29% m/m. And in the Haynesville Shale, permitting activity rose 29% or 48 more permits than in November. The permits issued offset losses in the Mississippian Lime, which saw a 38% retreat from November, down by 83 permits. The Utica Shale’s permitting activity declined by 43%, off by 19. “Smaller plays” recorded a 52% decrease, down by 125 m/m, Evercore noted. “The Permian represented 34% of the total issued permits over the month, in-line with November’s 34% share,” the analyst team said. “The Eagle Ford was the basin with the second largest count share with 13%, and the Powder River Basin and smaller basins with 11% each.” According to Evercore, Pioneer Natural Resources Co. had the largest Permian count for December with 111 permits, which was 30 more than in November or up 37%. Occidental Petroleum Corp. recorded a 395% increase in Permian permit activity, with 37 more m/m. ExxonMobil drew 14 more permits for the Permian m/m, up by 69%. EOG Resources Co. procured three more permits last month, up 11% from November. By state, Texas and Wyoming led the permit rally, with California and Kansas falling behind, Evercore analysts noted. “Texas permits increased to 1,655,” up by 290 m/m or 21%, while Wyoming rebounded from November losses, increasing by 146 to 422 (53% higher m/m), analysts said. “These were partially offset by losses reported in California (off 79, minus 22% m/m), Kansas (down 72, or 46% decline) and Pennsylvania (down 22, or 16% decrease m/m).
U.S. oil output set to rise in Feb to record, but growth slows -EIA (Reuters) - Oil output from top shale regions in the United States is due to rise by about 77,300 barrels per day (bpd) to a record 9.38 million bpd in February, the U.S. Energy Information Administration (EIA) said in its productivity report on Tuesday. The oil increase was the lowest in more than a year, with volumes shrinking on weaker productivity per well and on inflation cutting into oil companies’ production budgets. U.S. crude oil output in the Permian in Texas and New Mexico, the biggest U.S. shale oil basin, is set to rise by about 30,400 bpd to 5.64 million bpd in February, its highest on record, the EIA projected. In the Bakken region of North Dakota and Montana, the EIA forecast oil output next month will rise 20,000 bpd to 1.23 million bpd, the largest total since November 2020. In the Eagle Ford shale in South Texas, output will rise about 4,200 bpd to 1.21 million bpd in February, its highest total volume since April 2020. In the Permian basin of West Texas and New Mexico, oil production is forecast to fall by nearly two-thirds from the same month a year ago. Total natural gas output in the big shale basins will increase 0.5 billion cubic feet per day (bcfd) to a record 96.7 bcfd in February, the EIA forecast. In the biggest shale gas basin, Appalachia in Pennsylvania, Ohio and West Virginia, output will rise to 35.4 bcfd in February, the highest since hitting a record 36.2 bcfd in December 2021. Gas output in the Permian and the Haynesville in Texas, Louisiana and Arkansas will rise to record highs of 21.7 bcfd and 16.6 bcfd in February, respectively. The EIA said producers drilled 1,011 wells in December, the most since March 2020. Total drilled-but-uncompleted (DUC) wells rose by 40 to 4,577 in December, the most since August 2022.
U.S. Oil Rig Count Sees Largest Single Week Drop In 16 Months -- The total number of total active drilling rigs in the United States fell by 4 this week, according to new data from Baker Hughes published on Friday.bThe total rig count fell to 771 this week—167 rigs higher than the rig count this time in 2022, and 304 rigs lower than the rig count at the beginning of 2019, prior to the pandemic.Oil rigs in the United States fell by 10 this week, to 613. It is the largest single week drop in the number of oil rigs since September 2021. Gas rigs rose by 6, to 156. Miscellaneous rigs stayed the same at 2.The rig count in the Permian Basin fell by 2, while rigs in the Eagle Ford fell by 1.Primary Vision’s Frac Spread Count, an estimate of the number of crews completing unfinished wells—a more frugal use of finances than drilling new wells—broke it’s six week losing stream during the week ending January 13. The frac spread count is now 254, up 4 from the previous week. This is 11 fewer crews than a month ago and the same as a year ago.Crude oil production in the United States stayed the same at 12.2 million bpd level in the week ending January 13, according to the latest weekly EIA estimates. U.S. production levels are up 500,000 bpd versus a year ago.At 11:00 a.m. ET, the WTI benchmark was trading up $0.12 on the day (+0.15%) at $80.45 per barrel—a less than $1 per barrel gain since this time last week.The Brent benchmark was trading up $0.14 (+0.16%) at $86.30 per barrel on the day, and up about $1.30 per barrel compared to last Friday. WTI was trading at $81.45 minutes after the data release, up nearly 1.4% on the day.
Natural Gas Prices Plunge in North Dakota Amid Midwest Oversupply - Natural gas prices have plummeted in North Dakota because of a regional supply glut and lack of pipeline capacity to the more lucrative Gulf and West Coast markets, according to the state’s top oil and gas regulator. The price of natural gas delivered to TC Energy Corp.’s Northern Border pipeline system at Watford City, ND, had fallen to $2.88/Mcf as of Tuesday (Jan. 17), the lowest since December 2021, said the Department of Mineral Resources’ (DMR) Lynn Helms, oil and gas division director. The low price is “due to oversupply in the Midwest U.S. even as LNG prices in Europe remain very high,” Helms said. -year average as of the week ended Jan. 13, the U.S. Energy Information Administration said Thursday, corroborating Helms’ assessment.In addition, “We haven’t had really severely bitter cold winter weather for extended periods of time,” he said. European buyers, meanwhile, are paying substantially more for natural gas, Helms noted. Gulf Coast netback prices published by NGI’s LNG Insight show that U.S. liquefied natural gas exports to Europe remained well in the money despite a softened near-term European pricing outlook and above-average gas storage levels on the continent.“We’ve got, really, a lot of incentive to try to find a way to get North Dakota natural gas out of the Midwest, to move it toward the Gulf Coast or the West Coast” in order to capture premium pricing, Helms said.Projects under development to move Bakken Shale Gas south include WBI Energy Transmission Inc.’s Grasslands South Expansion project. WBI launched an open season earlier this month for up to 94,000 Dth/d of firm transport capacity on the 16-inch diameter pipeline, which would transport Bakken gas to the Cheyenne hub in Wyoming. The open season concludes on Jan. 28, with a targeted in-service date in the second half of the year.TC, meanwhile, is looking to reverse the direction of gas flows on its existing 30-inch diameter Bison pipeline, which was originally built to transport gas from the Powder River Basin in Wyoming into Midwestern markets.The proposed project would allow the pipeline to transport Bakken gas into the Cheyenne market, said Justin Kringstad, director of the North Dakota Pipeline Authority. Kringstad also highlighted the displacement of Canadian gas volumes by Bakken gas on the Northern Border system, which originates at the Canada-Montana border. Williston Basin gas has a roughly 75% market share on the pipeline, versus about 25% for Canadian gas, Kringstad said.
The Biden Administration Finally Admits Its Mistake in Canceling the Keystone XL Pipeline - At long last, the Biden administration is admitting what experts have always known: reckless energy policies have disastrous consequences. This time, the Department of Energy quietly released a report highlighting the positive economic benefits of developing the Keystone XL pipeline from Canada, an energy project canceled by President Biden in the hours following his inauguration. But the DOE’s report is a proverbial day late and a dollar short. The cancelation of the Keystone XL pipeline has already cost the United States thousands of jobs and billions in economic growth while families suffer under the weight of record high energy prices. It’s time for lawmakers to make American energy independence a top priority. Released without a formal announcement, the DOE’s report points out that the pipeline would have created between 16,149 and 59,000 jobs and would have had an economic benefit of between $3.4 and 9.6 billion. That’s no small impact. Yet with one stroke of his pen, Biden slashed the project and instead focused his efforts on costly “green energy” goals. As a result of his executive action, 11,000 pipeline workers were promptly laid off and told to “go to work to make solar panels” instead. But Biden’s green energy efforts are bound to backfire sooner rather than later. That’s because today, more than 70 percent of the energy produced and consumed in America comes from oil, gas and coal. That’s not likely to substantially change anytime soon. In fact, the International Energy Agency predicts that oil’s share of energy production in the United States will only fall 8 percent in the next two decades, from 31 to 23 percent. And that’s assuming a sustained commitment to green energy policies. The forecast spells bad news for the Biden White House. At his political peril, Biden ignores the lessons of Presidents Jimmy Carter and George H. W. Bush, who both lost elections due to spiked oil prices and accompanying recessions. Two years into sowing its Green New Deal policies, the administration is reaping a bitter harvest. Due to Biden’s folly, oil, natural gas and electricity prices have more than doubled in just a single year. Meanwhile, more than 28 percent of Americans abstained from purchasing food or medicine to pay an energy bill in 2021. And now, the misnamed Inflation Reduction Act includes wind and solar spending that will cost Americans $369 billion. If the president and his Democratic allies in Congress refuse to heed lessons from the past, they have a rare opportunity to view an even more desperate future of what will certainly come to pass by staying on the same irresponsible course.
How fossil fuel companies take climate change policies to court -Investor-state dispute settlements increasingly allow oil and gas investors to sue countries over their climate policies.For over a decade, debate has raged over the Keystone XL pipeline project, which aimed to transport Canadian tar sands to the Gulf of Mexico. After approving the project’s initial stages, the Obama administration rejected a permit allowing the pipeline to cross the national border in 2015.However, the energy company backing the project didn’t take no for an answer: TransCanada soon sued the U.S. for $15 billion dollars — the future expected profits it claimed the pipeline would have earned, in addition to the $3.1 billion it had already invested in the project. The company was able to do so because the North American Free Trade Agreement, the treaty known as NAFTA that the U.S. signed with Canada and Mexico in 1994, included a clause about something called an investor-state dispute settlement, or ISDS — a closed-door legal process that’s an often overlooked, but increasingly urgent, hurdle to addressing climate change. ISDS mechanisms are included in many other bilateral and international trade agreements, allowing a country to be sued by investors from other member countries if it takes any subsequent actions that adversely affect those investments.The threat of this liability has hung over the pipeline conflict ever since: When President Trump signed an executive order in 2017 reversing course and allowing Keystone XL to move forward, TransCanada announced that it would suspend its ISDS case against the U.S. for 30 days — exactly the deadline for the decision on their new permit application. In March of that year, the newpermit was approved, and TransCanada dropped its ISDS claim. It’s far from the only recent example: Take Italy, which banned oil drilling within 12 nautical miles of its coast only to be sued by the UK-based oil company Rockhopper, which had hoped to develop a near-shore oilfield at Ombrina Mare, off the coast of Abruzzo. This summer, an international tribunal authorized to adjudicate investor-state disputes ordered the Italian government to compensate the firm $210 million pounds.These settlements are decided in a private legal process. Unlike public judicial systems, these tribunals are typically run by three arbitrators chosen jointly by the disputing parties. These people tend to be repeatedly selected from a small group of experts in corporate law, and at times they act as lawyers for an investor in one case and arbitrators deciding the case in another, though the cases may be similar or even simultaneous — a practice known as “double hatting.”Because ISDS systems are written into thousands of different treaties, each with different wording, there’s also no system of precedence. Just because arbitrators decide something in one case doesn’t mean that logic has to be applied to another. Proceedings can be kept confidential, and there is no way to appeal a tribunal’s decision.
Big Oil's good times set to roll on after record 2022 profits (Reuters) - The West's top energy firms are expected to rake in a combined record profit of $200 billion from a turbulent 2022 marked by huge volatility in oil and gas prices after Russia's invasion of Ukraine with buoyant earnings likely to roll through 2023. Flush with cash, BP, Chevron, Exxon Mobil, Shell and TotalEnergies also delivered shareholders unprecedented returns through dividends and share buybacks last year. These firms are expected to post a combined profit of $199 billion for 2022 when they report final quarterly results later this month and in early February. Profits are forecast to decline to $158 billion this year due to weaker energy prices and inflationary concerns, but that would still be well above the previous 2011 record, according to analysts estimates provided by Refinitiv. A strong 2022 also helped these companies cut their debt to a combined $100 billion, a 15-year low, allowing them to start 2023 more prepared for any future downturn.
Exclusive: Venezuela's PDVSA freezes most oil exports for contract reviews (Reuters) - The new head of Venezuela's state oil company PDVSA has suspended most oil export contracts while his team reviews them in a move to avoid payment defaults, according to an internal document seen by Reuters and people familiar with the matter. Since U.S. trading sanctions were first imposed on PDVSA in 2019, the company has increasingly resorted to little known middlemen to allocate its oil exports, leading to big price discounts and problems with payments affecting its cashflow. The freeze order is leading to port delays, as vessels that were loading have been sent away and are waiting for new directions, the people said. PDVSA's new Chief Executive Pedro Rafael Tellechea last week wrote to the heads of the company's divisions of supply and trade, domestic market, international market, finances and foreign affairs and notified them of the contract suspensions. The letter did not specify how long the freeze would last. Tellechea, an engineer graduated from a military academy who is also running state petrochemical company Pequiven since 2019, was appointed on Jan. 6 to PDVSA by President Nicolas Maduro along with eight new vice presidents. The suspension so far has affected little known firms that act as middlemen in PDVSA's sales to Asian refiners. Cargoes chartered by U.S. oil firm Chevron Corp (CVX.N) and Cuba's Cubametales have not been affected by the contract revision, according to separate documents and the sources.
Fracking: Is a moratorium enough? -A few months ago, I proposed a ‘no to fracking’ motion to East Sussex County Council. This was just after the short-lived Truss government had lifted the moratorium. East Sussex is known as a possible shale oil/gas exploration region. While there are no current requests for licences, the Greens on ESCC wanted to make sure that there is a clear council policy that would prevent any future exploration or exploitation. The reasons are clear and mostly uncontested: fracking is a dangerous way of extracting oil or gas and can lead to the contamination of water aquifers, the creation of toxic wastewater – and in some places earthquakes. Fracking also relies on the excessive use of water at a time when droughts are likely to become more commonplace. It would likely lead to an increase in heavy industrial traffic at a time when our roads are in a serious state of deterioration. Most importantly, fracking and any oil or gas extraction will lead to more fossil fuel use and therefore more carbon emissions at a time when we must reduce our emissions urgently. As the moratorium was reinstated when the chaotic Conservative party changed their leader again, we were asked by the council to withdraw our ‘no to fracking’ motion. I decided to press on with it because government decision-making, especially to protect the environment and mitigate global heating, has been notoriously unstable over the last 12 months. As expected, the motion was sent to the Lead Member for Transport and Environment to consider before it was put to the Full Council. She issued an amendment which became the substantive motion. It was a weakened motion, just agreeing with the Government’s position on reinstating the moratorium. And, of course, the dulled-down motion was duly passed, with every Conservative councillor voting in favour and my original (and stronger) motion fell. While this was disappointing, it was not unexpected. What was surprising was the content of the background paper ESCC officers had prepared for the Lead Member. The paper explained that ESCC is the Minerals Planning Authority dealing with oil and gas matters – and would therefore be the presiding body considering any planning application for exploration or exploitation of fossil fuels, should the moratorium be lifted again. The paper made the case that the Council cannot declare a clear policy against fracking as this would mean councillors would have a pre-determined view for any planning application. This is clearly nonsense. If this were the case, then ESCC would not be able to have any policies to protect nature and the people of East Sussex in the face of planning applications, which is clearly not true.
Austria Gains No Benefits From Gas Fracking, Energy Minister Says - (Sputnik) - Austria does not benefit much from gas produced by fracking either from the economic or from the environmental points of view, Energy Minister Leonore Gewessler said on Wednesday. "It is not since yesterday that we have been discussing the fracking. It is pointless from environmental, climate policy and economic perspectives. If everyone — the communities in Lower Austria and both ruling parties — are against it … then it would be logical for me if the cabinet made the decision [to ban fracking]," Gewessler said prior to a cabinet meeting. The minister added that the relevant proposal had already been sent to the government and was being discussed informally.Austria is evaluating prospects for finding a replacement to the gas no longer supplied by Russia. On January 11, the Austrian authorities said they were examining the possibility of replacing Russian gas with domestically-produced biogas. They warned, however, that volumes produced would be limited and the biogas could only be used in periods of high demand.
Germany sees LNG import capacity of 37 Bcm/year in 2024: ministry --Germany expects the country’s LNG import capacity to reach 37 Bcm/year in 2024 and to double again by 2028, the German economy ministry said in response to a parliamentary question published Jan. 13. Responding to a series of questions from the German political party, die Linke (Left Party), the ministry also said it expected gas supply in 2023 to continue at the same level as last year. A total of 10 projects for direct LNG imports to Germany are under development, the ministry said, as Berlin looks to offset the impact of lost Russian pipeline gas imports. The projects include the five FSRU projects initiated by the federal government as well as the onshore LNG terminal in Brunsbuttel in which the state bank KfW holds a 50% stake. There is one private project at Lubmin — which will ultimately comprise two FSRUs — operated by Deutsche ReGas, as well as two private onshore terminals at Stade (Hanseatic Energy Hub) and Wilhelmshaven (TES). “To ensure gas supply in Germany in winter 2022/2023 and beyond, the government has taken a series of short-term measures, including developing LNG import infrastructure,” the ministry said. “Floating LNG import terminals will be used to close the supply gap,” it said. It said that for the winter 2022/2023, the three new LNG import terminals in Wilhelmshaven, Brunsbuttel and Lubmin would have a combined capacity of 13.5 Bcm/year. The terminals at Wilhelmshaven and Lubmin have already started operations, with the Brunsbuttel FSRU expected online soon with an initial capacity of 3.5 Bcm/year, rising to 7.5 Bcm/year in 2024-2026. Once the additional three FSRUs are operational by the end of 2023, capacity in 2024 will reach 37 Bcm/year, and with the startup of three permanent onshore terminals from 2027 capacity will be doubled again.
Natural Gas Futures in Europe Plunge 15% Today, Down 84% from Crazy Spike - The price of Dutch front-month TTF Natural Gas Futures – a benchmark for northwest Europe – plunged 15% today to €54.85 per megawatt-hour (MWh), and has now collapsed by 84% from the crazy spike in the summer of 2022. The price is now back where it had first been in early September 2021 (data via Investing.com): What spooked the European natural gas market today into the 15% sell-off were reports that Chinese importers of LNG were trying to divert February and March LNG shipments from China to Europe, as they were sitting on large stockpiles of LNG amid dropping prices in China.There had been fears that the reopening of China’s economy would put further strain on the global LNG markets. Or was that just hype all over again?In 2022 and into 2023, several factors came together to avert what had been seen as a potentially dreadful energy crisis:
- Surging supply of LNG from the US and other locations around the world.
- Rapid deployment of floating storage and regasification units (FSRU) in Europe to offload this LNG supply, including in Germany.
- Pipeline natural gas from Norway to the rest of Europe grew by 4% year-over-year in 2022 113 billion cubic meters (Bcm), according to S&P Global. Norway is now Europe’s largest supplier. Norwegian gas deliveries to Germany reached historic highs.
- A large-scale effort by households and businesses particularly in Germany to reduce natural gas consumption (heating, hot water), motivated also by the big price increases of natural gas.
- A shift in power production from natural gas to other energy sources, including coal, also motivated by big price increases of natural gas through the summer of 2022.
- A warm winter.
All of this worked together to reduce demand for natural gas and increase supply to replace pipeline natural gas from Russia.Natural gas storage facilities in Europe are in exceptionally good shape for this time of the year. In the European Union overall, storage facilities were 81.7% full on January 14, according to GIE (Gas Infrastructure Europe). This is how the 916 terawatt-hours (TWh) of natural gas in storage on January 14, compares to the levels at the same time of the year in prior years: 76% above 2022.
Column: Europe's gas price plunge churns up global coal markets: Maguire - (Reuters) - Thermal coal markets were a prominent beneficiary of Europe's power sector turmoil in 2022, with prices surging more than 250% through mid-March as utilities and trading firms scrambled to replace lost supplies of Russian natural gas with other fuels. Benchmark European thermal coal prices remained close to historic highs throughout 2022 on sustained higher use across the continent, averaging roughly $285 per tonne for the year, compared with about $115 a tonne in 2021. Higher coal use also yielded more pollution, with cumulative discharge of carbon dioxide (CO2) by Europe's coal power sector topping 600 million tonnes through November, the highest tally for the period since 2019, data from Ember shows. However, thanks to a recent plunge in European natural gas prices - down 60% since December 1 on mild winter temperatures, filled storage tanks and diminished industrial use - European coal prices and demand have slumped so far in 2023. That clashes with the more bullish posture of coal markets in top coal consuming region Asia, which has been bracing for sharply higher coal use and purchases in 2023 as dominant coal consumer China reboots its economy following a COVID-hit 2022. The divergent tones of Europe's and Asia's coal markets are captured by the record-wide price spread between them. From 2010 through 2020, Europe's API2 (All Publications Index) coal price and Asia's Newcastle coal price traded within $50 a tonne of one another, with Newcastle prices averaging a $5.70 premium over API during that 11-year span.
Eni makes “significant” gas discovery offshore Egypt— Eni announces a significant new gas discovery at the Nargis-1 exploration well in Nargis Offshore Area Concession, in the Eastern Mediterranean Sea, offshore Egypt. The Nargis-1 well has encountered approximately 200 net ft. (61 m) of Miocene and Oligocene gas-bearing sandstones and was drilled in 1,014 ft. (309 m) of water by the Stena Forth drillship. The discovery can be developed leveraging the proximity to Eni’s existing facilities. Nargis-1 confirms the validity of Eni’s focus on Egypt Offshore, which the company will further develop thanks to the recent award of exploration blocks North Rafah, North El Fayrouz, North East El Arish, Tiba and Bellatrix-Seti East. Egypt’s Nargis Offshore Area concession is approximately 445,000 acres (1,800 km^2). Chevron Holdings C Pte. Ltd. is the operator with a 45% interest, while Eni’s wholly owned Affiliate IEOC Production BV holds a 45% and Tharwa Petroleum Company SAE holds a 10% interest. Eni has been present in Egypt since 1954, where it operates through the subsidiary IEOC. The company is currently the country's leading producer with an equity production of hydrocarbons of approximately 350,000 barrels of oil equivalent per day. In line with the net-zero strategy by 2050, Eni is engaged in a series of initiatives aimed at decarbonizing the Egyptian energy sector, including the development of CCS plants, renewable energy plants, agro feedstock for bio refining and others.
Russian gas will eventually return to Europe as people 'forgive and forget': Qatari energy minister -The European Union's rejection of Russian energy commodities following Moscow's invasion of Ukraine won't last forever, Qatar's Energy Minister said during an energy conference over the weekend. "The Europeans today are saying there's no way we're going back" to buying Russian gas, Saad Sherida al-Kaabi, energy minister and head of state gas company QatarEnergy, said at the Atlantic Council Energy Forum in Abu Dhabi. "We're all blessed to have to be able to forget and to forgive. And I think things get mended with time… they learn from that situation and probably have a much bigger diversity [of energy intake]." Europe has long been Russia's largest customer of most energy commodities, especially natural gas. EU countries have dramatically cut down their imports of Russian energy supplies, imposing sanctions in response to Moscow's brutal, full-scale invasion of Ukraine. Gas exports from Russian state energy giant Gazprom to Switzerland and the EU fell by 55% in 2022, the company said earlier this month. The cut in imports has dramatically increased energy costs for Europe, sending leaders and oil and gas executives scrambling to develop new sources of energy and shore up alternative supplies. "But Russian gas is going back, in my view, to Europe," al-Kaabi said. Russia's invasion of Ukraine has so far taken tens, if not hundreds of thousands of lives, destroyed entire cities, and exiled more than 8 million people as refugees. Russian missiles and drone strikes regularly hit and decimate residential buildings, schools, hospitals, and vital energy infrastructure, leaving millions of Ukrainians without power. A residential building destroyed after a Russian missile attack on Jan. 15, 2023, in Dnipro, Ukraine. Global Images Ukraine | Getty Images News | Getty Images Europe has managed to avert a major crisis this winter, owing to mild weather and substantial stocks of gas amassed over the last year. Energy officials and analysts warn of a more precarious situation in late 2023, when these supplies run out. "Luckily they [Europe] haven't had a very high demand for gas due to the warmer weather," al-Kaabi said. "The issue is what's going to happen when they want to replenish their storages this coming year, and there isn't much gas coming into the market until '25, '26, '27 ... So I think it's going to be a volatile situation for some time."
UAE's Dana Gas says explosive device was detonated in Iraqi Khor Mor gas field - UAE-based Dana Gas said on Monday that an explosive device was dropped and detonated within its Khor Mor Block in the Kurdistan Region of Iraq last week. In a bourse filing on Abu Dhabi Securities Exchange (ADX), the energy firm said the detonations on Friday morning caused no injuries to people or damage to facilities. Production operations continue at the Khor Mor Gas plant as normal without interruption, it added. In June last year a series of rocket attacks targeted the energy firm's facilities in Sulaymaniyah in northern Iraq. No group had claimed responsibility for the attacks. Dana Gas and Crescent Petroleum are joint operators for the Khor Mor and Chemchemal gas fields on behalf of the Pearl Petroleum consortium.
Exclusive: Russia sees sanctions impact on oil products, eyes crude export boost -senior source (Reuters) - Russia expects Western sanctions to have a significant impact on its oil products exports and therefore its production, but that will likely leave more crude oil to sell, a senior Russian source with detailed knowledge of the outlook told Reuters. In what the West casts as unprecedented sanctions and President Vladimir Putin deems a declaration of economic war, the United States and its allies are trying to constrict the economy of Russia, the world's second largest oil exporter after Saudi Arabia.In an attempt to punish Russia for the conflict in Ukraine, the European Union banned seaborne Russian crude imports from Dec. 5 and will ban Russian oil products from Feb. 5. "The oil products' embargo will have a greater impact than the restrictions on crude oil," said the senior Russian source who spoke on condition of anonymity due to the sensitivity the situation. The source said the sanctions will lead to more crude oil supplies from Russia, which lacks storage capacity for oil products. "We think that the refined product embargo may be more significant than the crude embargo, given that exporting a given amount of products is much more logistically complex than an equivalent amount of crude," said Ron Smith of Moscow-based brokerage BCS.
China’s Oil Demand Is Set To Hit A Record High In 2023 --China’s oil consumption is expected to jump by 800,000 barrels per day (bpd) this year to a record 16 million bpd, after Beijing abandoned the strict ‘zero Covid’ policy and re-opened its borders, a median estimate of 11 China-focused consultants polled by Bloomberg News showed.Following the initial exit Covid wave after the strictest curbs were lifted, Chinese oil demand is set to rebound from the second quarter onwards, also raising global oil demand for this year, many analysts say. Despite the fact that China’s crude oil imports in 2022 were slightly lower than the previous year, for a second consecutive year, crude imports in December rose by 4% annually for the third highest monthly purchases in 2022, data showed on Friday. Despite the current Covid wave, China is preparing for the re-opening with the issuance of a huge batch of oil import quotas for its private refiners.“Higher quotas support the view of recovering Chinese demand this year and the quicker-than-expected change in Covid policy means that the demand recovery could be more robust than initially expected,” ING strategists Warren Patterson and Ewa Manthey said this week.Global oil demand in 2023 is expected to grow by around 1.7 million bpd, of which 50% will be driven by China, according to ING, which says “There could be some upside risk to this” forecast.“As China’s infection rate slows post-Chinese New Year, we see domestic oil demand rebounding. As the population hits the roads and the skies, our expectation is Chinese oil consumption in 2023 will increase by around 1.0 million b/d, an impressive performance considering Q1 demand is likely to contract by 190,000 b/d,” Gavin Thompson, Vice Chairman, Energy – Asia Pacific, at Wood Mackenzie, said on Thursday.
OPEC says Chinese oil demand to rebound in 2023 after drop (Reuters) - OPEC said on Tuesday Chinese oil demand would rebound this year due to relaxation of the country's COVID-19 curbs and drive global growth, and sounded an optimistic note on the prospects for the world economy in 2023. World demand in 2023 will rise by 2.22 million barrels per day (bpd), or 2.2%, the Organization of the Petroleum Exporting Countries (OPEC) said in a monthly report, unchanged from last month's forecast, which had ended a series of downgrades. A stronger economy, if it materialises, could lead to upward demand revisions and support oil prices, which have rallied in 2023 on Chinese demand hopes. OPEC sounded an upbeat tone on the world economy's prospects, even though it still expects a relative slowdown from 2022. "The global momentum in the fourth quarter of 2022 appears stronger than previously expected, potentially providing a sound base for the year 2023," OPEC said in the report. "Chinese oil demand is on course to rebound due to the recent relaxation of the country's zero-COVID-19 measures," it said in a separate section, adding that plans to expand fiscal spending were also likely to support demand. OPEC expects Chinese demand to grow by 510,000 bpd in 2023. Last year, the country's oil use posted its first contraction for years due to the COVID containment measures. In the report, OPEC raised its 2022 world economic growth estimate to 3%, saying growth last year in the United States and the euro zone had surpassed previous forecasts, and left 2023's forecast steady at 2.5%.
IEA Sees Global Oil Demand Hitting A Record High In 2023 - China’s reopening is set to drive global oil demand to a record high of 101.7 million barrels per day (bpd) this year, up by 1.9 million bpd from 2022, the International Energy Agency (IEA) said on Wednesday, raising its demand growth estimate for 2023 by 200,000 bpd from 1.7 million bpd growth expected in December. Almost half of the oil demand growth this year will come from China after Beijing lifted its Covid restrictions, the IEA said in its closely-watched Oil Market Report (OMR) for January. At the same time, world oil supply growth in 2023 is set to slow to 1 million bpd, following last year’s OPEC+ led growth of 4.7 million bpd. “An overall non-OPEC+ rise of 1.9 mb/d will be tempered by an OPEC+ drop of 870 kb/d due to expected declines in Russia,” the IEA said in the report. As a result, market balances are set to tighten as this year progresses, the agency noted. “This year could see oil demand rise by 1.9 mb/d to reach 101.7 mb/d, the highest ever, tightening the balances as Russian supply slows under the full impact of sanctions. China will drive nearly half this global demand growth even as the shape and speed of its reopening remains uncertain,” the IEA said. Russia and China will be the two wild cards in the market this year, it added. Russian oil exports dropped by just 200,000 bpd in December despite the EU embargo and the G7 price cap. But the record price discounts on Russian benchmark export grades reduced Russia’s oil revenues by $3 billion to $12.6 billion last month – the lowest since February 2021, the agency has estimated. The EU ban on Russian oil products from February 5 could soon mean that “the well-supplied oil balance at the start of 2023 could quickly tighten however as western sanctions impact Russian exports.”
TotalEnergies launches Lapa South-West Project -TotalEnergies has approved the final investment decision of the Lapa South-West oil development located in the Santos Basin, 300 km off the coast of Brazil. TotalEnergies operates the project with a 45% interest, in partnership with Shell (30%) and Repsol Sinopec (25%). Lapa South-West will be developed through three wells, connected to the existing Lapa FPSO located 12 km away and currently producing the North-East part of Lapa field since 2016. At production start-up, expected in 2025, Lapa South-West will increase production from the Lapa field by 25 000 barrels of oil per day, bringing the overall production to 60 000 barrels of oil per day. This development represents an investment of approximately US$1 billion.
Libyan Court Suspends Controversial Oil And Gas Deal With Turkey - A Libyan court has suspended a deal for offshore oil and gas exploration that Libya and Turkey inked last year, a deal that sparked outrage from neighbors Egypt and Greece.The deal concerned waters that Libya and Turkey have declared to be theirs but that are disputed by Egypt and Greece, Reuters noted in a report on the news that cited an unnamed source. The Libyan government can appeal the ruling, the source also told Reuters.Greece’s Permanent Representative at the UN, Maria Theofili described the deal as one “violating the sovereign rights of Greece, is a violation of international law and a deliberate escalation that undermines stability in the region.”The deal, signed in October last year, followed an earlier, security agreement, inked in 2019, that demarcated the maritime border between Libya and Turkey—the same demarcation that angered Egypt and Greece."We've signed a memorandum of understanding on exploration for hydrocarbons in Libya's territorial waters and on Libyan soil, by mixed Turkish-Libyan companies," the foreign minister of Turkey, Mevlut Cavusoglu said at the time, asquoted by the AFP.The official noted, then, that the deal is only between Libya and Turkey, "two sovereign countries -- it's win-win for both, and other countries have no right to interfere".The eastern Mediterranean was put in the spotlight by a series of large gas discoveries off the coast of Israel in the past decade or so, as well as discoveries in Turkish and Cypriot waters. The potential of the region has become particularly relevant now when Europe is looking for new sources of gas.At the same time, the events around the deal with Turkey had contributed to the deterioration of the internal political situation in Libya, as Ankara signed its deals with the Government of National Unity—the entity recognized by the UN but not by rival political factions in Libya itself.
UAE energy minister: OPEC+ faces oil market volatility in both supply and demand (Reuters) - OPEC+ is facing "volatile prospects" in oil markets both in supply and demand, UAE energy minister Suhail al-Mazrouei told Asharq TV on Saturday. He said this was due to European sanctions on Russian crude taking effect in addition to China lifting its "zero-COVID" policy. OPEC+ production capacity was down 3.7 mln bpd due to fewer investments in the oil sector, Al-Mazrouei said. He also said UAE is taking preemptive steps to compensate for the reduced oil production capacity in some countries by bringing forward its five million barrel per day oil production capacity expansion to 2027 from a previous target of 2030. Regarding gas, Al-Mazrouei told the Atlantic Council Global Energy Summit earlier that the world would need natural gas for a long time and more investment was required to ensure supply security and affordable prices during the global energy transition.
Saudi Arabia stays top crude supplier to China in 2022, Russian barrels surge (Reuters) - Russia remained China's second-largest source of crude oil in 2022, following repeat top supplier Saudi Arabia, as Chinese refiners snapped up low-cost Russian barrels while Western countries shunned them after the Ukraine crisis. China's crude oil imports from Russia jumped 8% in 2022 from a year earlier to 86.25 million tonnes, equivalent to 1.72 million barrels per day (bpd), data from the General Administration of Customs showed on Friday. Russian crude has been trading in widening discounts to global oil benchmarks following Western sanctions over its invasion of Ukraine, which the Kremlin has called a "special operation". China, which refused to condemn the attack, cranked up procurement of Russian barrels and has largely ignored the sanctions imposed by Western nations on seaborne Russian crude from Dec. 5. In December, it brought in 6.47 million tonnes of crude oil from Russia, or 1.52 million bpd, compared to 1.7 million bpd in the same period in 2021. China's state-backed refiners have wound down the purchase of Russian oil since November, but the independent refineries have continued buying from intermediary traders who arrange shipping and insurance, shielding them from the risk of secondary sanctions. Saudi Arabia shipped a total of 87.49 million tonnes of crude to China in 2022, equivalent to 1.75 million bpd, customs data showed, on par with the level in 2021. China's state-backed oil refiners largely fulfilled their term contracts with Saudi in 2022 despite the sluggish domestic demand. Saudi Arabia is expected to remain a key, if not the dominant, crude exporter to China after President Xi Jinping's visit to Riyadh in December, where he told Gulf leaders that China would work to buy oil in Chinese yuan, rather than U.S. dollars. Customs data also showed that crude imports from Malaysia almost doubled in 2022 to 35.68 million tonnes. The Southeast Asian country is a transfer point for sanctioned shipments originating from Iran and Venezuela. No Venezuelan crude imports were recorded by Chinese customs throughout 2022 and a total of 780,392 tonnes of crude oil from Iran arrived in China. China is Iran's biggest oil buyer, but most Iranian exports are rebranded as crude from other countries to evade U.S. sanctions. Vortexa, a ship tracking specialist, assessed that China's December imports of Iranian oil rose to a record of 1.2 million bpd, up 130% from a year earlier. Crude shipments from the United States reached 7.89 million tonnes in 2022, down 31% year-on-year.
Jeb Bush: How to stop Panama from helping Iran avoid oil sanctions - The Washington Post - The Iranian regime has survived for more than four decades, thanks in large part to countries’ putting economic self-interest ahead of international peace and security. In strengthening Iran by helping it circumvent sanctions, these countries work against the brave Iranian women and men who are now risking their lives for a future free of the regime’s rule. Russia and China are well known as Iran’s allies and trading partners, but there is another country that has been instrumental in the regime’s continued survival: Panama. Without Panama’s support, the Iranian regime would face significant hurdles in smuggling its oil and gas around the world. At least 16 percent of the world’s shipping fleet, by deadweight tonnage, is registered in Panama, including 39 percent of the 288 vessels that United Against Nuclear Iran, an organization I advise, has identified as suspected of participating in Iran’s foreign-flagged ghost armada. The Treasury Department should block this oil tanker fleet in its entirety from engaging with Americans and U.S. businesses for violating U.S. sanctions. The ships are at the core of a smuggling network that helped the regime export $30 billion worth of oil in 2021, according to UANI’s analysis of the monthly volume of Iran’s oil exports and the discounted price at which Iran sells its oil. That revenue helps Iran fund terrorist organizations and pay security forces responsible for gross human rights abuses against Iranian protesters. Given that Panama enjoys the fruits of billions of dollars in annual trade with the United States and receives more direct U.S. investment than any other Central American country, the Panamanian government appears remarkably unconcerned about ensuring that it is not helping a U.S. adversary evade U.S. sanctions.
Oil Prices Head Lower As Traders Take Profits - . Crude oil began the week with a decline as traders took profits from last week’s rally and settled down to wait for market forecasts due this week by OPEC and the International Energy Agency.At the time of writing, Brent crude was trading at a little over $84.50 per barrel while West Texas Intermediate had slipped below $80 and was changing hands for about $79.30 per barrel.Last week, crude oil booked its sharpest weekly price rise since last October, largely on expectations of a demand rebound in China after the country reversed its zero-Covid policy that had hobbled industrial activity and, consequently, oil demand for three years.Brent crude settled at over $85 per barrel last Friday and WTI ended the week at close to $80 per barrel, both benchmarks adding more than 8 percent during the week.OPEC is due to release its latest Monthly Oil Market Report tomorrow and traders are waiting to see if the cartel has revised its oil demand expectations for the year from last month’s report. In December, OPEC forecast that oil demand this year would grow by 2.2 million bpd, down from 2.5 million bpd last year. Demand growth from the OECD countries was forecast at a modest 300,000 bpd while non-OECD growth was seen at 1.9 million bpd. Non-OPEC supply, according to OPEC, was to grow by 1.9 million bpd as well this year, according to the December MOMR. "Now with China opening, hopefully we will see a pickup in demand and when we meet, we will analyze that as usual. We always take the decision that serves the balancing of the market,” UAE’s oil minister, Suhail al-Mazrouei, said on the sidelines of the Atlantic Council’s Global Energy Forum, which took place in Abu Dhabi this weekend.
Crude oil prices slip on global recession gloom; Brent hits $84.08/bbl – Oil prices fell in early trade on Tuesday as recession fears dominated headlines out of the World Economic Forum's meeting in Davos, draining optimism that stoked the market last week on prospects of a fuel demand recovery in top oil importer China. Brent crude LCOc1 futures were down 38 cents, or 0.5%, at $84.08 at 0114 GMT, extending a 1% loss in the previous session. US West Texas Intermediate (WTI) crude CLc1 futures slid $1.16, or 1.5%, to $78.70 from Friday's close. There was no settlement on Monday due to a US holiday for Martin Luther King Day. In a bearish survey released at the Davos summit, two-thirds of private and public sector economists polled expected a global recession this year, with about 18% considering it "extremely likely". At the same time, a survey of chief executives' views by PwC was the gloomiest since the firm launched the poll a decade ago. "Brent crude has gained nearly 10% over the past 10 days as optimism over China's reopening boosted sentiment. However, the outlook for the rest of the global economy is uncertain," ANZ commodity analysts said in a client note. ANZ also pointed to a jump in crude supply from Russia weighing on the market, with seaborne exports having risen to 3.8 million barrels per day last week, the highest level since April. Reuters reported on Friday that at least four Chinese-owned supertankers were shipping Russian Urals crude to China and a fifth supertanker was shipping crude to India, with the oil available at a discount following the imposition of an oil price cap by the Group of Seven (G7) nations. A rise in the dollar off seven-month lows also dragged on oil prices, as a stronger greenback makes oil more expensive for those holding other currencies.
WTI Gains Fade as NY Manufacturing Falls to Post-COVID Low -- New York Mercantile Exchange oil futures ended mixed Tuesday, with the nearby-month West Texas Intermediate contract sharply paring an advance to a nine-week high $81.23 per barrel (bbl) after a survey on manufacturing activity in New York State showed business activity collapsed to the lowest level since June 2020, underscoring the depth of demand destruction as the Federal Reserve hikes interest rates into restrictive territory. A key measure for manufacturing activity in the Empire State plummeted 22 points early January to a negative 32.9 reading, showed the survey released Tuesday morning by the Federal Reserve Bank of New York. The figure represents the fifth-worst reading in the survey's history and was twice as weak as even the most pessimistic estimates. "New orders and shipments declined substantially. Employment growth stalled, and the average workweek shortened. Looking ahead, firms expect little improvement in business conditions over the next six months," according to comments by the Fed bank. Taking a broader look, business activity across the U.S. manufacturing sector fell in December for the second straight month, with five out of six biggest manufacturing industries registering a contraction. By all accounts, domestic manufacturing is already in recession even as the broader economy still hangs on a resilient consumer. The data doesn't bode well for distillate fuel consumption. Distillate product supplied to the U.S. market -- a measure of demand -- averaged 3.6 million barrels per day (bpd) over the past four weeks, down 5.5% from the same period last year. Traders expect little improvement in the coming weeks. Globally, the picture doesn't look as bleak. China is well into the reopening phase of its economy following the abrupt end of Beijing's zero-COVID policies despite surging cases and deaths. Addressing the wave of COVID infections that has strained hospitals in China, Vice Premier Liu He at the World Economic Forum in Davos, Switzerland, said the peak of infections had passed, and consumption-related industries have returned to normal. High-frequency data for early January suggests mobility in China is indeed recovering from a December low, with the number of domestic flights, subway and train usage is trending higher. Goldman Sachs said in a weekend research note that China is sharply increasing crude imports while reducing refined fuel exports, which it says implies "China is preparing for a significant up-lift in demand, meaning the impact on global oil prices will likely be felt much earlier than realized improvements in end-demand." At settlement, WTI for February delivery added $0.32 to $80.18 per bbl, and Brent March futures on ICE advanced $1.46 to $85.92 per bbl. NYMEX RBOB February contract gained $0.0123 to $2.5451 per gallon, and front-month ULSD futures declined $0.0049 to $3.2510 per gallon.
Oil prices extend gains on optimism over China's recovery - (Reuters) - Oil prices rose on Wednesday, extending the previous session's gains, driven by optimism that the lifting of China's strict COVID-19 curbs will lead to a recovery in fuel demand in the world's top oil importer. Brent crude futures firmed 63 cents, or 0.73%, to $86.55 a barrel by 0401 GMT, following a 1.7% rally in the previous session. U.S. West Texas Intermediate (WTI) crude futures rose 68 cents, or 0.85%, to $80.56, having risen 0.4% on Tuesday. China's economic growth slowed sharply to 3% in 2022, missing the official target of "around 5.5%" and marking its second-worst performance since 1976. But the data still beatanalysts' forecasts after China started rolling back its zero-COVID policy in early December. Analysts polled by Reuters see 2023 growth rebounding to 4.9%. The Organization of the Petroleum Exporting Countries (OPEC) said in a monthly report that Chinese oil demand would grow 510,000 barrels per day (bpd) this year after contracting for the first time in years in 2022 due to COVID containment measures. "Growing hopes that China's fuel demand will pick up after a recent shift in its COVID-19 policy lent support to oil prices," said Toshitaka Tazawa, an analyst at Fujitomi Securities Co Ltd. "OPEC's optimistic outlook on China's demand also supported the market sentiment," he said, predicting a bullish tone for this week.
WTI Falls on Weak US Macros Ahead of Weekly Inventory Data- - After eight consecutive sessions of gains, oil futures settled Wednesday's session lower after weaker-than-expected economic data in the U.S. fueled recession fears, souring sentiment in broader markets. U.S. retail sales declined in December at the sharpest pace of 2022, marking a dismal end to the holiday shopping season as rising interest rates joined with still-high inflation dragged on consumer spending. Sales at stores and restaurants unseasonably declined by 1.1% from the prior month, the Commerce Department said Wednesday. Sales were also revised lower in November and have now fallen in three of the past four months. The decline in retail sales clearly shows the U.S. economy slowed late last year as American consumers pulled back on spending. Further signs of slowdown could be found in industrial production data for December that showed output declined more than expected, indicating manufacturing activity is rapidly losing momentum as inflation pressure and higher interest rates cut demand for goods. Manufacturing output dropped 1.3% last month, the Federal Reserve said on Wednesday. Data for November was also revised lower to show production at factories decreased 1.1% instead of the previously reported 0.6%. Earlier in the session, the oil complex got a leg up from upbeat demand projections by the International Energy Agency that forecasts global oil demand this year would reach a record high 101.7 million bpd helped by the reopening of China's economy. Paris-based energy watchdog lifted its 2023 estimates for worldwide oil consumption by 200,000 bpd to 1.9 million bpd. In the final months of 2022, weak industrial activity in OECD countries coupled with zero-COVID policies in China sliced off nearly 1 million bpd in global demand growth. Also on Wednesday, oil traders positioned ahead of the release of U.S. inventory data delayed one day due to the observance of the Martin Luther King Jr. holiday on Monday (1/16). Analysts expect U.S. commercial crude oil inventories to decrease by 1.1 million bbl, with estimates ranging from a decrease of 4 million bbl to an increase of 4.5 million bbl. At settlement, WTI for February delivery declined $0.70 to $79.48 bbl after climbing above $82 bbl in intrasession high, and Brent March futures on ICE fell $0.94 to $84.98 bbl. NYMEX RBOB February contract dropped $0.0216 to $2.5235 gallon, and front-month ULSD futures added $0.0120 for a $3.2630 gallon settlement.
Oil prices settle lower after touching their highest intraday prices since early December – Oil futures settled lower on Wednesday, with U.S. prices posting their first loss in nine sessions. Prices for the commodity had climbed to their highest intraday levels since early December on expectations for stronger energy demand following the reopening of China’s economy, with the International Energy Agency boosting its forecast for crude demand growth in 2023. Oil prices turned lower, however, after comments from a U.S. Federal Reserve official renewed uncertainty over the pace of upcoming interest-rate hikes — raising uncertainty over the outlook for the U.S. economy. West Texas Intermediate crude for February delivery fell 70 cents, or 0.9%, to settle at $79.48 a barrel on the New York Mercantile Exchange after trading as high as $82.38. Price settled lower for the first time in nine sessions. March Brent crude, the global benchmark, lost 94 cents, or 1.1%, at $84.98 a barrel on ICE Futures Europe, after touching a high of $87.85. Both WTI and Brent had touched their highest intraday levels since Dec. 5, according to FactSet. Back on Nymex, February gasoline shed nearly 0.9% to $2.5235 a gallon, while February heating oil gained 0.4% to $3.263 a gallon. February natural gas lost 7.7% to $3.311 per million British thermal units after posting a gain of 4.9% on Tuesday. The settlement was the lowest for a front-month contract since June 22, 2021. Oil prices had spent much of the session trading higher, buoyed by expectations for higher energy demand from China. However, oil turned lower following comments Wednesday by St. Louis Fed President James Bullard . Bullard suggested that despite cooling U.S. inflation data and soft retail sales, the Federal Reserve still needs to move quickly to get to benchmark interest rates above 5%. That “raised fears that the Fed may raise rates at the 50 basis point clip again,” providing some support for the U.S. dollar and pressuring prices for dollar-denominated commodities such as oil. Traders have also been concerned that aggressive U.S. interest rate rises could lead to a recession and lower energy demand. Early Wednesday, the Paris-based IEA lifted its forecast for oil-demand growth this year by nearly 200,000 barrels a day to 1.9 million barrels a day. The extra demand means that the IEA now expects total oil demand this year to average 101.7 million barrels a day, well above pre-pandemic levels and a record amount. The IEA raised its forecast for Chinese demand by 100,000 barrels a day to 15.9 million barrels a day. Output data from China showed that oil refiners processed around 14.17 million barrels a day (mb/d) of crude in December, down from 14.69 mbd in November but up 2% year over year, Full-year 2022 numbers averaged 13.57 mb/d, down almost 4% year over year. “Weaker domestic demand and low refined product export quotas would have weighed on refinery runs through 2022. Activity should recover this year, given the expected recovery in oil demand following China’s reopening, along with the government releasing larger volumes of refined product export quotas more recently,”
WTI Extends Losses After API Reports Big Crude Build -- Oil prices tumbled today. Overnight saw gains on the heels of China reopening hope (and optimistic IEA forecasts for 2023 demand) and then dumped it all back and then some during the US day session as macro data signaled a harder landing than so many have hoped for. “Oil’s rally could not last after energy traders saw broad weakness across large parts of the US economy,” “Crude-demand concerns are growing as the consumer is much weaker than expected and as the manufacturing sector is plunging.” After last week's utterly chaotic looking inventory data (massive builds likely due to the national 'deep freeze'), traders are waiting for outputs to normalize somewhat, and expect this week's data to remain noisy. API:
- Crude +7.6mm
- Cushing +3.7mm
- Gasoline +2.8mm
- Distillates -1.8mm
Echoing last week's official data, we suspect API is playing catch-up as it reports huge builds in crude and at Cushing and a Distillates draw WTI was hovering around $79.50 before the print and slipped lower after..
Oil prices down amid recession fears, US crude stock growth - Oil prices decreased on Thursday influenced by weak economic data from the US amid recession fears and a hefty rise in crude stockpiles. International benchmark Brent crude traded at $83.92 per barrel at 9.20 a.m. local time (0620GMT), down 1.25% from the closing price of $84.98 a barrel in the previous trading session. The American benchmark West Texas Intermediate (WTI) traded at $78.63 per barrel at the same time, a 1.47% fall after the previous session closed at $79.8 a barrel. Oil prices retreated from their highest level in over a month after weak US data fueled recession worries. US Producer Price Index recorded its biggest decline since April 2020 in December, with a 0.5% fall, according to data released Wednesday. Retail sales in the US fell 1.1% in December, below expectations, while industrial production fell 0.7%, the biggest drop since September 2021. Additionally, the US Fed reported that American companies expect "low growth" in the economy in the coming months. Meanwhile, US crude oil inventories rose by about 7.6 million barrels during the week ended Jan. 13, data from the American Petroleum Institute showed. A more-than-expected stockpile increase signals a drop in crude demand, weighing prices down. Official stock data from the US Energy Information Administration is scheduled to release later in the day, and if the estimated build-in stock levels is confirmed, prices are expected to fall further.
WTI Extends Gains Despite Huge Crude Build, Surge In Cushing Stocks - Oil prices are rebounding this morning, after yesterday's growth-scare-driven tumble as investors wagered China’s demand revival would sustain the market even amid signs of rising US crude inventories (reported by API overnight). “The reopening is proceeding sooner (by one quarter) and more rapidly than we originally expected,” JPMorgan analysts wrote in a note to clients. “This opens a possibility that China is poised for a strong economic recovery that will gather steam in February, after the end of the Lunar New Year holiday.” Will API prove to be right or is this 'noise' hanging over from the 'deep freeze' impact on refiners? DOE
- Crude +8.408mm (+4.8mm exp)
- Cushing +3.646mm - biggest build since April 2020
Confirming API's report, the official data showed another huge crude build of 8.41mm barrels and a massive rise in stocks at Cushing... US Crude production was flat at its cycle highs... WTI was hovering at $80.50 ahead of the official data and bounced after the data... "Two wild cards dominate the 2023 oil market outlook: Russia and China. This year could see oil demand rise by 1.9 mb/d to reach 101.7 mb/d, the highest ever, tightening the balances as Russian supply slows under the full impact of sanctions. China will drive nearly half this global demand growth even as the shape and speed of its reopening remains uncertain," the IEA said.
Oil Adds to Gains Despite Large Crude, Gasoline Builds - Oil futures edged higher post-inventory trade Thursday despite federal data from the U.S. Energy Information Administration showing nationwide crude oil stock levels spiked 8.4 million barrels (bbl) during the week ended Jan. 13 as refinery operations remained below normal after widespread disruptions related to bitter cold weather in late December. U.S. refiners again increased run rates by a smaller-than-expected 1.2% last week to 85.3% of capacity after runs fell to the lowest weekly rate since Winter Storm Uri in February 2021 shuttered much of the refining capacity in the Gulf Coast. Analysts mostly expected run rates to recover by 3% from the previous week. For the week, refiners processed 202,000 barrels per day (bpd) more crude averaging 14.853 million bpd, which is still near the lowest processing rate since late March 2021. Slow recovery in refinery run rates indicates some refiners might have gone into early maintenance, with the turnaround season heaviest in February and March. Slow recovery in refinery runs led to a massive 8.4-million-bbl build in commercial crude stockpiles compared with expectations for a 1.1-million-bbl decline. At 448 million bbl, commercial crude stockpiles stand about 3% above the five-year average. Oil stored at Cushing, Oklahoma, hub, the delivery point for West Texas Intermediate, also increased 3.6 bbl from the previous week to 31.4 million bbl. Domestic oil producers, meanwhile, remained unchanged at 12.2 million bpd. In the gasoline complex, commercial stockpiles jumped 3.5 million bbl in the reviewed week to 230.3 million bbl compared with expectations for a 1.7 million bbl increase. Demand for gasoline recovered 496,000 bpd in the reviewed week to 8.054 million bpd. Distillate demand rose 204,000 bpd to 4.024 million bpd after consumption hit the lowest level since April 2020 when the coronavirus pandemic shuttered large chunks of the economy two weeks earlier. Domestic distillate stocks declined by 1.9 million bbl to 115.8 million bbl. Total products supplied to the U.S. market over the last four-week period averaged 19.7 million bpd, down 6.7% from the same period last year. Over the past four weeks, gasoline supplied averaged 8.1 million bpd, down 4.6% from the same period last year. Distillate fuel supplied averaged 3.6 million bpd over the past four weeks, down 9.8% from the same period last year. Near 11:45 p.m. EST, WTI for February delivery advanced to $80.22 per bbl, up $0.52, and NYMEX RBOB February contract gained $0.0547 to $2.5782 per gallon, and front-month ULSD futures added $0.0470 to $3.3195 per gallon.
Oil prices rally to highest close since Dec. 1 on China optimism (Reuters) -Oil prices settled 1% higher on Thursday, extending a recent rally built around rising Chinese demand, while the market wrote off a second straight week of large builds in U.S. crude inventories. Brent crude futures gained $1.18, or 1.4%, to settle at $86.16 per barrel, while U.S. West Texas Intermediate (WTI) crude futures rose by 85 cents, or 1.1%, to settle at $80.33 per barrel. Those were the highest closing levels for both contracts since Dec. 1. Chinese oil demand climbed by nearly 1 million barrels per day (bpd) from the previous month to 15.41 million bpd in November, the highest level since February, according to the latest export figures published by the Joint Organisations Data Initiative. Energy markets could be tighter in 2023, especially if the Chinese economy rebounds and the Russian oil industry struggles under sanctions, International Energy Agency (IEA) head Fatih Birol said on Thursday. Oil prices were down by more than a dollar per barrel earlier in Thursday's session, as traders booked profits and U.S. data showed the economy losing momentum. Both oil benchmarks hit their highest level in more than a month on Tuesday. Prices also came under pressure briefly after U.S. Energy Information Administration (EIA) data showed U.S. crude stocks last week rose by 8.4 million barrels, their biggest gain since June 2021. UBS analyst Giovanni Staunovo described the EIA data as a "bearish report, with large crude and gasoline inventory increases, but an improvement from last week, with a recovery of implied oil demand and refinery runs from the impact of Storm Elliot." U.S. gasoline refining margins traded at a new five-month high for the fourth straight session on Thursday, amid optimism about rising travel demand from China's reopening and threats to refined products supply from strikes in France. "There's just so much bullish sentiment out there, so much fear, that it keeps underpinning this market."
Oil up as bulls push back against another big U.S. crude build -- Oil prices settled up about 1% Thursday, recouping losses from the previous session, as bulls in the space bet on falling U.S. refinery runs to lead to an imminent tightening in fuel supply, even as latest weekly data showed big builds in both crude oil and gasoline. February, the most-actively traded contract on New York West Texas Intermediate, or WTI, crude settled up 85 cents, or 1.1%, at $80.33 per barrel. February WTI earlier hit an intraday high of $81.48. Meanwhile, March WTI, which Investing.com is already using as the front-month marker for U.S. crude, settled up 81 cents, or 1%, at $80.61. London-traded Brent crude for March delivery settled up $1.18, or 1.4%, at $86.16, after a session peak at $86.84. Oil prices ran up despite the Energy Information Administration, or EIA, saying in its Weekly Petroleum Status Report that U.S. crude inventories rose by 8.408 million barrels for the week ended Jan. 13, versus market expectations for a draw of 593,000 barrels. In the previous week to Jan. 6, the statistical arm of the U.S. Energy Department reported a crude build of 18.962M barrels. In total, the EIA has reported almost 30M barrels in crude builds over the past four weeks. On the gasoline inventory front, the EIA reported a rise of 3.483M barrels versus expectations for a build of 2.529M and against the previous week's growth of 4.114M. Gasoline is America's number one automotive fuel. The only real bullish number in the weekly dataset was that of distillate stockpiles. The EIA cited a drop of 1.939M barrels for this, versus the forecast build of 122,000 barrels and against the previous week's slide of 1.069M barrels. Distillates are refined into heating diesel, diesel for trucks, buses, trains and ships and fuel for jets, U.S. refineries operated at 85.3% of their capacity last week, the EIA said, versus the 90%-95% range typical for this time. “There’s this notion that fuel stockpiles, including that of gasoline, will fall appreciably in the coming weeks and that’s what oil bulls are holding on to as their idea of ‘demand’,” "But, of course, slower refinery runs means a continuous buildup in crude. That's being conveniently ignored here." The IEA, or International Energy Agency, said on Wednesday that global oil demand could reach an all-time high in 2023 as China rolls back lockdowns and restrictions related to its tough COVID-zero policy. In a more material development, the weekly inventory report showed that the Biden administration has stopped drawing crude oil from the U.S. Strategic Petroleum Reserve, or SPR, as it attempts to rebuild a reserve it pulled more than 200M barrels to keep fuel prices low for Americans. The EIA reported an SPR crude balance of 371.6M barrels at the end of the Jan. 13 week, unchanged from the previous week to Jan. 6. The zero SPR draw for last week closes the chapter on some 220M barrels taken from the emergency oil reserve since November 2021 by the Biden administration to provide more crude to the marketplace and bring pump prices of gasoline down. Prior to those draws, SPR inventories stood at just under 600M barrels. At their present level of just above 370M, the reserve’s stockpiles are at their lowest since December 1983, the EIA said. The crude releases from the SPR, along with other global market developments, added significantly to international oil supplies over the past year. At one time, the EIA reported weekly draws of as much as 8M barrels from the reserve. Those additional supplies helped slash crude prices from a high of more than $130 a barrel in early March, right after the outbreak of fighting in Ukraine and the subsequent sanctions on Russian crude, to below $90 a barrel by August. The strategy worked for the administration: pump prices of gasoline fell to below $3 a gallon at some U.S. pumps by late last year from a mid-June record high of $5 as the SPR draws flooded the domestic marketplace for crude. Gasoline at U.S. pumps now average $3.38 a gallon, the American Automobile Association said on its website Thursday. Last week’s zero SPR draw came after the administration announced late last year that it was winding down its dependence on the reserve and preparing to add to its inventory. The administration is negotiating purchases with U.S. energy firms to refill the reserve, starting with a base offer of $70 per barrel. With WTI at just above $81 a barrel on Thursday, sellers will likely be seeking more, resulting in a longer lag to replenish the reserve.
Oil heads for second week of gains on China demand outlook | (Reuters) - Oil rose on Friday and was heading for a second straight weekly gain, spurred largely by brightening economic prospects for China and resulting expectations of a boost to fuel demand in the world's second-biggest economy. The lifting of COVID-19 restrictions in China is set to increase global demand to a record high this year, the International Energy Agency (IEA) said on Wednesday, a day after OPEC also forecast a Chinese demand rebound in 2023. Brent crude gained 38 cents, or 0.4%, to $86.54 a barrel by 0912 GMT. U.S. crude advanced 74 cents, or 0.9%, to $81.07."Many traders believe it is highly likely that we are going to see higher demand coming from China as it continues to dismantle its COVID policies," said Naeem Aslam, analyst at broker Avatrade. B0th benchmarks were heading for a weekly gain of about 1.5%. Oil was also supported by hopes that the U.S. central bank will soon downshift to smaller rises in interest rates and by hopes for the U.S. economic outlook.A Reuters poll predicted that the U.S. Federal Reserve will end its tightening cycle after increases of 25 basis points at each of its next two policy meetings and is then likely to hold rates steady for at least the rest of the year.The chances of a "soft landing" for the U.S. economy appear to be growing, Federal Reserve Vice Chair Lael Brainard said on Thursday. The Fed's next rate-settingThe two largest economies in the world need more crude, said Edward Moya, senior market analyst at OANDA."The oil market has been down on global recession fears, but it is still showing signs it can remain tight a little while longer," he said.Oil rose despite U.S. inventory figures this week showing crude stockpiles rose by 8.4 million barrels in the week to Jan. 13 to about 448 million barrels, the highest since June 2021.
WTI Feb. Futures Expire at 2-Month High on Large Rig Count Drop -- New York Mercantile Exchange oil futures and Brent crude traded on the Intercontinental Exchange settled Friday's session higher, with the February West Texas Intermediate contract expiring above $81 per barrel. The gains came after industry data reported the number of oil-targeted rigs in the United States unexpectedly declined this week, while a softer U.S. dollar index further boosted buying interest for U.S. crude benchmark. Bakers Hughes reported Friday that the number of active U.S. oil rigs dropped by 10 this week -- the largest weekly decline since late 2021 that depressed the total rig count to 613. Even the prolific Permian Basin of West Texas and New Mexico saw a decline in activity, with its oil rig-count falling from a nearly three-year high of 353 rigs the week prior. The decline is inconsistent with forecasts for robust U.S. production growth this year and fueled concerns that the weakening economy could be behind the softer drilling activity. This week's macroeconomic data painted a rather dismal outlook for the U.S. economy at the start of the year, with business activity in manufacturing and service sectors falling to post-pandemic lows. Sharp deceleration across the key sectors of the economy suggests the Fed's aggressive rate hikes have clearly worked their way into the broader economy, depressing consumer demand. Federal Reserve Vice Chair Lael Brainard indicated in remarks on Thursday that the central bank is still "probing" for the correct level of interest rates that will both tame inflation and ensure the economy avoids recession. "Inflation has been declining over the past few months against a backdrop of moderate growth," said Brainard, adding that "significant weakening in the manufacturing sector and a moderation in consumer spending pointing to subdued economy in 2023." At settlement, West Texas Intermediate for February delivery expired at $81.31 per barrel (bbl), up by $0.98 on the session, with the March contract expanding its premium against the expired contract to $0.33. Brent March futures on ICE rallied $1.47 to $87.63 per bbl. NYMEX RBOB February contract advanced to $2.6454 per gallon, up 4.86 cents on the session, and front-month ULSD futures jumped 9.09 cents to $3.4668 per gallon.
Saudi Arabia: Government Agents infiltrate Wikipedia, sentence Independent Admins to Prison– The Saudi Arabian government infiltrated Wikipedia by recruiting the organization’s highest ranked administrators in the country to serve as government agents to control information about the country and prosecuting those who contributed critical information about political detainees, said SMEX and Democracy for the Arab World Now (DAWN) today. Following an internal investigation in 2022, Wikimedia terminated all of its administrators in Saudi Arabia in December. DAWN and SMEX documented Wikimedia’s infiltration by the Saudi government based on interviews with sources close to the company and the imprisoned administrators. “The Saudi government’s infiltration of Wikipedia with government agents acting as independent editors, and imprisonment of non-compliant editors, demonstrates not only its persistent use of spies inside international organizations but the dangers of attempting to produce independent content in the country,” said Sarah Leah Whitson, DAWN’s Executive Director. “It’s wildly irresponsible for international organizations and businesses to assume their affiliates can ever operate independently of, or safely from, Saudi government control.” Wikipedia relies on varying ranks of volunteer administrators and editors, referred to as “Wikipedia users,” authorized by Wikimedia, the parent company of Wikipedia. Users are not employees of Wikimedia and do not receive any compensation. However, Wikimedia has established the Wikipedia community rules to grant them privileges as trusted, independent editors who self-regulate and administer content on Wikipedia. Administrators have exclusive authorization to use tools to edit, delete, and protect content pages (meaning no one else can edit them), and to block and unblock lower-ranking users and editors. To learn more about the different user access levels on Wikipedia pleasevisit this page.
Recalling CNN’s Fraudulent “Interview” With A Seven Year-Old Syrian Girl – Caitlin Johnstone - There’s a thread going around on Twitter by Columbia University’s Sophie Fullerton advancing the claim that I have promoted crazy conspiracy theories about child “crisis actors” in Syrian war atrocities. Fullerton has me blocked on Twitter so I can’t respond to her there, but in her thread she brings up one of the most egregious instances I’ve ever seen of US war propaganda in the mass media, so it’s worth taking some time to unpack her claims here as a public service. Fullerton has written for The Washington Post slamming social media users who travel to Syria and dispute the official mainstream narrative about what’s been happening in that country, and has served as an expert analyst in a Daily Beast hit piece on the progressive Gravel Institute for their scrutiny of US warmongering. So it’s fair to call her a spinmeister on the side of the US empire, and it’s probably fair to predict that her young career will bring her tremendous success and mainstream elevation as a result of this. “It takes a special kind of evil to see what happened yesterday in Dnipro and immediately start doing PR for the perpetrator,” Fullerton tweets, with a screenshot of me saying it’s deceitful for people to talk about the Russian invasion of Ukraine without also talking about the ways the US empire provoked and benefits from this war. “It should come at no surprise that this account built a following out of claiming Syrian children impacted by Assad/Russia atrocities were crisis actors,” she adds. Fullerton’s thread has gained a lot of traction because it has been amplified by Olga Lautman, a Senior Fellow at the imperialist think tank Center for European Policy Analysis (CEPA) with a large following. CEPA’s donor list includes the US State Department, the CIA cutout National Endowment for Democracy, and the weapons manufacturers Lockheed Martin, BAE Systems, and General Atomics. Fullerton uses the phrase “crisis actors” to evoke the image most people have of that term and what it means: conspiracy theories about actors pretending to have been wounded or otherwise involved in a false flag mass shooting or bombing incident, particularly Alex Jones’s infamous claims about Sandy Hook victims. But for her evidence of my “crisis actors” conspiracy theorizing, Fullerton cites something very different from any such claim. She cites an article I wrote in 2018 titled “That Time CNN Staged A Fake Interview With A Syrian Child For War Propaganda“, and revealingly she includes only a screenshot of the top of the article rather than providing a link. She did this because the arguments made in the article are unassailable, and she doesn’t want people to see them. In 2017 CNN conducted a fraudulent interview with a seven year-old Syrian child named Bana Alabed, whose name had earlier been popularized by a Twitter account operated by an adult calling for US interventionism in Syria to overthrow president Bashar al-Assad. I know the interview was fraudulent not because I’m some kind of dogged investigative journalist who spent months digging into the facts and the sources, but because I watched the interview. It is plain as day that the child was either reading or reciting words that had been prepared for her, and every comment I can see on CNN’s YouTube share of the segment agrees with this assessment. To the best of my knowledge, no serious attempt has ever been made by anyone to dispute this.