natural gas supplies above average for first time since April; Strategic Petroleum Reserve at a 19 year low; total oil & products supplies near a 7 year low; total oil supply falls by most in 25 weeks; gasoline supplies jump most in 20 months; distillates demand falls by most in 5 years; DUC wells in four basins are lowest on record; DUC backlog at 5.5 months is below prepandemic norm..
oil prices rose for the 2nd time in the past nine weeks, rallying first on a force majeure declaration in Libya, then on the largest drawndown in US crude supplies in 5 monhs, and lastly on a refiney explosion in Texas....after falling 1.1% to $70.86 a barrel last week as the rapid spread of the Omicron virus variant began to impact oil demand, the contract price for US light sweet crude for January delivery opened more than 1% lower on Monday and slid to a two-week low of $66.04 a barrel in early trading, as global oil demand was seen to be further restrained amid increased travel restrictions in Europe amid spiking COVID cases, but recovered from the day's lows as the January contracted expired with a loss of $2.63 at $68.23 a barrel, after Biden’s $2 trillion spending package was derailed by Senator Joe Manchin...with oil price quotes now citing the contract price for US light sweet oil for February, which had fallen $2.11 to $68.61 a barrel on Monday, prices moved higher in early trading Tuesday, retracing a portion of Monday's selloff, as oil traders mulled over the effects of the omicron variant on global oil demand. and settled with a gain of $2.51 at $71.12 a barrel as traders' appetite for risk improved even as the fast-moving Omicron variant swept the world, throwing Christmas travel plans into chaos and unnerving financial markets...oil prices were little changed early Wednesday after a force majeure declaration by Libya's National Oil Company staved off a selloff sparked by increasing mobility restrictions in Europe, and then rallied again on the EIA's report of the largest oil inventory drawdown since July to close $1.64 higer at $72.76 a barrel...the rally continued into pre-holiday trading on Thursday morning, with gasoline and oil prices trading at one month highs following an explosion and fire at a gasoline unit at ExxonMobil's Baytown refinery near Houston. and settled $1.03, or 1.4%, higher at $73.79 a barrel as signs that the worst effects of the Omicron variant might be more containable than previously feared were countered by new COVID-19 restrictions amid surging infections...oil prices thus finished the week 4.1% higher at a one month high, while the February oil contract, which had closed the prior week at $70.72 a barrel, ended the week up more than 4.3%...
natural gas prices also finished the week higher for the first time in 4 weeks on signs of an impending polar air mass intrusion.....after falling 6% to $3.690 per mmBTU last week on continued mild temperature forecasts for December, the contract price of natural gas for January delivery opened lower on Monday but rebounded with a flurry, driven higher by surging demand for U.S. exports of LNG, and by domestic forecasts for colder weather in the month ahead. and settled 14.4 cents or nearly 4% higher at $3.834 per mmBTU....prices see-sawed higher on Tuesday, shrugging off forecasts for milder weather, and settled with a 3.5 cent gain at $3.869 per mmBTU, after gas prices in Europe jumped to an all-time high after Russian gas shipments to Germany through a major transit pipeline reversed direction and colder weather increased demand....natural gas prices shot even higher Wednesday, on the increasing likelihood that frigid air would finally descend into vast stretches of the US in early January, and settled with a 10.7 cents gain at $3.976 per mmBTU....however, natural gas prices gave up most of the week's gains on Thursday in tumbling 24.5 cents to $3.731 per mmBTU, as the weather forecast for the new year shifted milder and European gas prices slid from record-high levels, and thus finished the week with just a 1.1% gain...
The EIA's natural gas storage report for the week ending December 17th indicated that the amount of working natural gas held in underground storage in the US fell by 55 billion cubic feet to 3,362 billion cubic feet by the end of the week, which left our gas supplies 234 billion cubic feet, or 6.5% below the 3,596 billion cubic feet that were in storage on December 17th of last year, but 34 billion cubic feet, or 1.0% above the five-year average of 3,328 billion cubic feet of natural gas that have been in storage as of the 17th of December over the most recent years...the 55 billion cubic foot withdrawal from US natural gas working storage this week was slightly below the average forecast for a 57 billion cubic foot withdrawal from a S&P Global Platts' survey of analysts, but was much less than the 147 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2020, and was also much less than the average withdrawal of 153 billion cubic feet of natural gas that have typically been pulled out natural gas storage during the same week over the past 5 years…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending December 17th showed that despite a drop in our oil exports, we needed to pull oil out of our stored commercial crude supplies for the sixth time in thirteen weeks and for the twenty-sixth time in the past thirty-eight weeks….our imports of crude oil fell by an average of 277,000 barrels per day to an average of 6,471,000 barrels per day, after falling by an average of 28,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 766,000 barrels per day to an average of 2,879,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 3,315,000 barrels of per day during the week ending December 17th, 489,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude oil from US wells was reportedly 100,000 barrels per day lower at 11,600,000 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 totaled an average of 14,915,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,818,000 barrels of crude per day during the week ending December 17th, an average of 148,000 more barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 1,036,000 barrels of oil per day were being pulled out the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 133,000 barrels per day more than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-133,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed....however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
This week's 1,036,000 barrel per day decrease in our total crude oil inventories, the largest since July 2nd, came as 674,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 362,000 barrels per day of oil were pulled out of our Strategic Petroleum Reserve, part of the first installment from Biden's plan to release 50 million barrels from the SPR, in order to incentive continued use of US gas guzzlers...however, most of that unrefined sour oil is expected to go to China and India, so how it could impact US gasoline prices is unclear...including the drawdowns from the Strategic Petroleum Reserve under such politically motivated programs, a total of 57,594,000 barrels have been removed from the Strategic Petroleum Reserve over the past 18 months, and as a result the amount of oil in our Strategic Petroleum Reserve has fallen to an 19 year low of 596,381,000 barrels per day, or to the lowest since November 29, 2002, as repeated tapping of our emergency supplies for political expediency or to “pay for” other programs had already drained those supplies over the past dozen years...based on an estimated prepandemic consumption level of 18 million barrels per day, the US will have roughly 30 1/2 days of oil supply left in the Strategic Petroleum Reserve when the Biden program is complete..
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,502,000 barrels per day last week, which was still 12.7% more than the 5,717,000 barrel per day average that we were importing over the same four-week period last year….this week’s crude oil production was reported to be 100,000 barrels per day lower at 11,600,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was 200,000 barrels per day lower at 11,100,000 barrels per day, while Alaska’s oil production was 5,000 barrels per day higher at 449,000 barrels per day and added 100,000 barrels per day from the reported rounded national production total (by the EIA's math)...US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 11.4% below that of our pre-pandemic production peak, but still 37.6% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016...
US oil refineries were operating at 89.6% of their capacity while using those 15,818,000 barrels of crude per day during the week ending December 17th, down from a utilization rate of 89.8% the prior week, and lower than the historical utilization rate for mid December refinery operations… the 15,818,000 barrels per day of oil that were refined this week were 12.9% more barrels than the 14,183,000 barrels of crude that were being processed daily during the pandemic impacted week ending December 18th of last year, but 6.2% less than the 16,980,000 barrels of crude that were being processed daily during the week ending December 20th, 2019, when US refineries were operating at what was then also a bit less than seasonal 90.6% of capacity...
Even with the increase in oil being refined this week, the gasoline output from our refineries was somewhat lower, decreasing by 100,000 barrels per day to 9,942,000 barrels per day during the week ending December 10th, after our gasoline output had increased by 479,000 barrels per day over the prior week.…this week’s gasoline production was still 12.6% more than the 8,829,000 barrels of gasoline that were being produced daily over the same week of last year, but 3.2% less than the gasoline production of 10,269,000 barrels per day during the week ending December 20th, 2019….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 40,000 barrels per day to 4,852,000 barrels per day, after our distillates output had decreased by 105,000 barrels per day over the prior week…after that increase, our distillates output was 5.7% more than the 4,590,000 barrels of distillates that were being produced daily during the week ending December 18th, 2020, but 10.0% less than the 5,394,000 barrels of distillates that were being produced daily during the week ending December 20th, 2019..
Even with the decrease in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the third time in eleven weeks, and for the twenty-first time in thirty-five weeks, increasing by 5,533,000 barrels to 218,585,000 barrels during the week ending December 17th, the largest jump in 20 months, after our gasoline inventories had decreased by 719,000 barrels over the prior week...our gasoline supplies increased this week because the amount of gasoline supplied to US users decreased by 486,000 barrels per day to 8,986,000 barrels per day, and because our imports of gasoline rose by 189,000 barrels per day to 688,000 barrels per day, while our exports of gasoline rose by 200,000 barrels per day to 821,000 barrels per day…after this week’s big inventory increase, our gasoline supplies were still 5.7% lower than last December 18th's gasoline inventories of 238,879,000 barrels, and about 4% below the five year average of our gasoline supplies for this time of the year…
With the increase in our distillates production, our supplies of distillate fuels increased for the fourth time in seventeen weeks and for the 12th time in 37 weeks, rising by 396,000 barrels to 124,154,000 barrels during the week ending December 17th, after our distillates supplies had decreased by 2,852,000 barrels during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by a near record 1,074,000 barrels per day to 3,882,000 barrels per day, even as our exports of distillates rose by 403,000 barrels per day to 1,176,000 barrels per day, and as our imports of distillates fell by 247,000 barrels per day to 203,000 barrels per day....but after twenty-five inventory decreases over the past thirty-seven weeks, our distillate supplies at the end of the week were still 16.6% below the 148,934,000 barrels of distillates that we had in storage on December 18th, 2020, and about 8% below the five year average of distillates stocks for this time of the year…
Meanwhile, despite the drop in our oil exports and the big SPR release, our commercial supplies of crude oil in storage fell for the 20th time in the past thirty weeks and for the 34th time in the past year, and by the most in 15 weeks, decreasing by 4,715,000 barrels over the week, from 428,286,000 barrels on December 10th to 423,571,000 barrels on December 17th, after our commercial crude supplies had decreased by 4,584,000 barrels over the prior week…after this week’s decrease, our commercial crude oil inventories slipped to around 8% below the most recent five-year average of crude oil supplies for this time of year, but were still about 23% above the average of our crude oil stocks as of the third weekend of December over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated for most of the year after that, our commercial crude oil supplies as of this December 17th were 15.2% less than the 499,534,000 barrels of oil we had in commercial storage on December 18th of 2020, and are now 4.0% less than the 441,359,000 barrels of oil that we had in storage on December 20th of 2019, and also 4.0% less than the 441,411,000 barrels of oil we had in commercial storage on December 21st of 2018…
Finally, with our inventory of crude oil and our supplies of all products made from oil all near multi year lows, we are continuing to track the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that total oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 9,525,000 barrels this week, from 1,809,406,000 barrels on December 10th to 1,799,881,000 barrels on December 17th, and is now at the lowest level since December 26th, 2014, or nearly at a 7 year low...
This Week's Rig Count
The number of drilling rigs active in the US increased for the 56th time during the past 66 weeks during the holiday shortened week ending December 23rd, but still remained 26.1% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs running in the US increased by seven to 586 rigs this past week, which was also 238 more rigs than the pandemic hit 348 rigs that were in use as of the December 23rd report of 2020, but was still 1,343 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 oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil increased by 5 to 480 oil rigs during this week, after they had increased by 4 rigs during the prior week, and there are now 218 more oil rigs active now than were running a year ago, even as they still amount to just 29.8% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations rose by 2 to 106 natural gas rigs, which was also up by 23 natural gas rigs from the 81 natural gas rigs that were drilling during the same week a year ago, but still only 6.6% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….note that last year's rig count also included a rig that Baker Hughes had classified as "miscellaneous', while there are no such "miscellaneous' rigs deployed this week...
The Gulf of Mexico rig count was unchanged at 15 rigs this week, with thirteen of this week's Gulf rigs drilling for oil in Louisiana waters and two more drilling for oil in Alaminos Canyon, offshore from Texas...that's now two less than the count of 17 rigs that were active in the Gulf a year ago, when 14 Gulf rigs were drilling for oil offshore from Louisiana and three were deployed for oil in Texas waters…most of those Gulf rigs appear to be directional rigs targeting oil at depths greater than 15,000 feet, and include five targeting the Mississippi Canyon and three targeting oil under the Green Canyon...since there is now no drilling off our other coasts, nor was there a year ago, the Gulf rig counts are equal to the national offshore totals for both years....In addition to those rigs offshore, we continue to have one water based rig drilling for oil inland in the Galveston Bay area, and hence the inland waters rig count of one is now down from two a year ago..
The count of active horizontal drilling rigs was up by 7 to 528 horizontal rigs this week, which was also 219 more than the 309 horizontal rigs that were in use in the US on December 23rd of last year, but also 61.6% less than the record 1,374 horizontal rigs that were deployed on November 21st of 2014...at the same time, the vertical rig count was up by 1 to 27 vertical rigs this week, and those were up by 10 from the 17 vertical rigs that were operating during the same week a year ago….on the other hand, the directional rig count was down by one to 31 directional rigs this week, but those were still up by 9 from the 22 directional rigs that were in use on December 23rd of 2020….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of December 23rd, the second column shows the change in the number of working rigs between last week’s count (December 17th) and this week’s (December 23rd) count, the third column shows last week’s December 17th 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 23rd of December, 2020...
with the majority of this week's rig increase coming in the Permian basin, .we'll start by checking the Rigs by State file at Baker Hughes for changes in the Texas Permian basin...there we find that four rigs were added in Texas Oil District 8, which is the core Permian Delaware, and that another rig was added in Texas Oil District 7C, which includes the northernmost counties in the Permian Midland, but that three rigs were pulled out of Texas Oil District 8A, which covers the southern counties in the Permian Midland....since the Texas Permian rig count was thus up by a net of two and the national Permian rig count was up by six, that means that the four rigs that were added in New Mexico were deployed in the western Permian Delaware...
elsewhere in Texas, three rigs were added in Texas Oil District 6, which encompasses the portion of the Haynesville shale in the state; at the same time, a Haynesville shale rig was pulled out of northern Louisiana....since the Haynesville shale rig count was only up by one nationally, we'll have to assume one of those district 6 additions was not targeting the Haynesville...note that Texas also saw a rig removed from Texas Oil District 3, but that rig was also not targeting one of the basins that Baker Hughes reports details on...
the only other change in the table above we've not accounted for is the two rig addition in Oklahoma's Cana Woodford...however, since the Oklahoma rig count was unchanged, we know that two other rigs were pulled out of Oklahoma, from a basin that Baker Hughes doesn't track...meanwhile, for natural gas rigs, we have the Haynesville shale addition, and another natural gas rig added in a basin that Baker Hughes lists as "other", which could have been anywhere, but which can be determined by tediously checking the individual well records in the North America Rotary Rig Count Pivot Table (Feb 2011 - Current), if anyone really needs to know..
DUC well report for November
Monday of last week saw the release of the EIA's Drilling Productivity Report for December, which includes the EIA's November data on drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions....that data showed a decrease in uncompleted wells nationally for the 18th consecutive month, as both completions of drilled wells and drilling of new wells remained well below the pre-pandemic levels...for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 226 wells, falling from 5,081 DUC wells in October to 4,855 DUC wells in November, which was also 39.1% fewer DUCs than the 7,968 wells that had been drilled but remained uncompleted as of the end of November of a year ago...this month's DUC decrease occurred as 659 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during November, up from the 649 wells that were drilled in October, while 885 wells were completed and brought into production by fracking, up from the 876 completions seen in October, and up from the pandemic hit 589 completions seen in November of last year, but still down by 9.4% from the 979 completions of November 2019....at the November completion rate, the 4,885 drilled but uncompleted wells left at the end of the month represents a 5.5 month backlog of wells that have been drilled but are not yet fracked, down from the 5.9 month DUC well backlog of a month ago, a ratio that is now below that of the year prior to the pandemic, despite a completion rate that is still around 20% lower than the pre-pandemic norm...
both oil producing regions and natural gas producing regions saw DUC well decreases in November, while none of the major basins reported a DUC well increase....the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico decreased by 105, from 1,669 DUC wells at the end of October to 1,564 DUCs at the end of November, as 300 new wells were drilled into the Permian during November, while 405 wells in the region were being fracked...at the same time, DUCs in the Eagle Ford shale of south Texas decreased by 35, from 796 DUC wells at the end of October to a record low of 761 DUCs at the end of November, as 63 wells were drilled in the Eagle Ford during November, while 98 already drilled Eagle Ford wells were completed....in addition, there was also a decrease of 30 DUC wells in the Bakken of North Dakota, where DUC wells fell from 516 at the end of October to a record low of 486 DUCs at the end of November, as 43 wells were drilled into the Bakken during November, while 73 of the drilled wells in the Bakken were being fracked....meanwhile, DUC wells in the Niobrara chalk of the Rockies' front range decreased by 11, falling from 372 at the end of October to a record low 361 DUC wells at the end of November, as 87 wells were drilled into the Niobrara chalk during November, while 98 Niobrara wells were being fracked...in addition, the number of uncompleted wells remaining in Oklahoma's Anadarko basin decreased by 10, falling from 799 at the end of October to 789 DUC wells at the end of November, as 47 wells were drilled into the Anadarko basin during November, while 57 Anadarko wells were completed.....
among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 28 wells, from 537 DUCs at the end of October to a record low of 511 DUCs at the end of November, as 71 wells were drilled into the Marcellus and Utica shales during the month, while 97 of the already drilled wells in the region were fracked....meanwhile, the uncompleted well inventory in the natural gas producing Haynesville shale of the northern Louisiana-Texas border region was down by nine to 383 DUCs, as 48 wells were drilled into the Haynesville during November, while 57 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of November, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 191 wells to 3,961 wells, while the uncompleted well count in the natural gas basins (the Marcellus, the Utica, and the Haynesville) decreased by 35 wells to 894 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
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FERC Proposes $40M Fine Over Alleged Rover Pipeline Violations; Steps Up Industry Enforcement FERC plans to fine Energy Transfer Partners LP and subsidiary Rover Pipeline LLC $40 million over alleged violations during work on a 2017 horizontal directional drill (HDD) at the Tuscarawas River in Stark County, OH. The Federal Energy Regulatory Commission handed down a show cause order during last week’s monthly meeting, formalizing its intent to impose the fine based on the findings of its Office of Enforcement. After an investigation, enforcement staff determined that Rover contractors “intentionally and routinely” added diesel fuel and other unapproved substances to the drilling mud to speed up completion of the Tuscarawas HDD during construction of the 711-mile Appalachia-to-Midwest natural gas conduit. Rover also failed to properly monitor the right-of-way at the HDD site, and the developer improperly disposed of contaminated drilling mud, according to FERC. The Tuscarawas HDD was the site of an inadvertent release of 2 million gallons of drilling mud that reached the surface and impacted a nearby wetland, regulators found. The incident resulted in construction delays and additional regulatory scrutiny for Rover, including the start of FERC’s enforcement investigation after test results indicated the presence of diesel fuel in the drilling mud.. In its latest action, FERC staff alleged that from April 2-13, 2017, Rover contractors working at the Tuscarawas HDD “intentionally added toxic diesel fuel, hydraulic oil, contaminated fluids, and non-toxic but unapproved lubricants to combat drilling difficulties and keep up with drilling progress demands. Witnesses testified that at least seven Rover contractor HDD crew members added diesel fuel to the drilling mud…and that this was done intentionally and routinely.”Energy Transfer, for its part, through a spokesperson denied knowing that diesel fuel was being used at the Tuscarawas HDD site.In its order, FERC said it had not received a response from the pipeline operator “to the substance” of the allegations and noted that the Natural Gas Act makes the developer “solely responsible” for the actions of its contractors.
FERC Gets Tougher on Natural Gas Pipeline Pollution Violators - Toughening its enforcement of environmental infractions on large completed natural gas pipelines during construction, the Federal Energy Regulatory Commission said Dec. 16 it will propose $40 million in civil penalties against Energy Transfer Partners LP and its Rover Pipeline LLC unit for both intentional and inadvertent discharge of diesel fuel and other toxics during drilling of the Rover pipeline in Ohio. FERC also said it is weighing a penalty against Midship pipeline in Oklahoma and a unit of owner Cheniere Energy Inc. for impacts from construction debris left behind on private land. Both line owners must demonstrate to FERC why they should not be fined. Agency Commissioner Alison Clements said the environmental violations by Energy Transfer and Cheniere do not represent standard industry behavior but should motivate sector firms to help identify reforms that would build confidence in in FERC’s “decisionmaking and compliance oversight.” Related to Rover, a 711-mile, $4.2-billion line (see map) that was fully commissioned in 2018, FERC alleged it “intentionally and routinely” discharged unapproved diesel fuel and other toxics with drilling mud during drilling under the Tuscarawas River in Ohio. A second violation involved the 2017 inadvertent release of two million gallons of diesel-tainted drill mud into a protected wetland. FERC did not propose a fine against, nor identfiy, any project contractor or subcontractor. In a statement, Energy Transfer cited “no evidence to show" that it or its Rover unit "had any knowledge of, or involvement in this action.” The firm says it learned months later that a “rogue employee” of the unidentified drilling subcontractor "admitted under oath to the discharge on his own volition and then tried to hide it." The energy firm says the area has been restored to a “pristine condition” and that it will seek recovery from the contractor for any FERC fine. FERC also ordered the Midship line and equity owner Cheniere Energy to explain to the agency why its also unidentified contractor has not removed construction debris from private land along the 36-in. line’s 234-mile route. The agency said its enforcement office will further investigate and recommend penalties if necessary. A Cheniere statement said the firm “has dedicated tremendous resources to restoration efforts and welcomes continued engagement with FERC and all stakeholders.”
32 New Shale Well Permits Issued for PA-OH-WV Dec 13-19 | Marcellus Drilling News - Two weeks ago the Marcellus/Utica region saw 30 new permits to drill shale wells. Last week we improved that a bit, to 32. Pennsylvania issued 13 new permits to three drillers for five well pads in four counties. Ohio issued eight new permits to two drillers for three pads in two counties. And West Virginia issued 11 new permits to two drillers for two pads in a single county.
- In Pennsylvania, Range Resource received six permits, EQT received four, and Chief Oil & Gas received three. Pennsylvania New Shale Permits Issued Dec 13-19 (embedded list)
- In Ohio, Ascent Resources received six permits and Encino Energy (EAP) received two permits. Ohio New Shale Permits Issued Dec 13-19 (embedded list)
- In West Virginia, CNX Resources received eight permits and Antero Resources received three permits. All of the permits were in Tyler County. West Virginia New Shale Permits Issued Dec 13-19(embedded list)
Natural gas production growth in Appalachia limited to supply mainly northeast demand, says GlobalData -- Natural gas production from the US’s Marcellus and Utica shale plays is forecast to cross the 42 billion cubic feet per day (bcfd) mark by 2025, according to GlobalData — assuming gas prices stay above $3.5 per one million British thermal units (mmbtu). The leading data and analytics company notes that no new pipelines are expected to come online after 2023, despite the fact that North America is the largest gas producer and supplies approximately 40% of the total natural gas production in the US. Svetlana Doh, Senior Upstream Oil & Gas Analyst at GlobalData, comments: “Environmental opposition in Pennsylvania, home to the majority of Appalachia basin production, created an onerous and exhausting approval process for pipeline operators. Pipeline projects in both the Atlantic Coast and PennEast were canceled on environmental grounds, and it appears that getting approval is going to be challenging for any future major pipeline in the Northeast.” While the Appalachia basin has the potential to ramp up production to 47 bcfd by 2030, pipeline and infrastructure limitations put the play at risk of curtailing production in the future based on the midstream factor alone. Doh continues: “The combined power of both current pipeline infrastructure and the eleven gas pipelines planned to be built in Pennsylvania, Ohio and West Virginia by 2023 will be able to support a mere 41 bcfd of natural gas flowing capacity.” Doh adds: “With respect to liquefied natural gas (LNG) production, Marcellus and Utica could play an important role in driving demand for natural gas supply in the US, given their resource potential. However, it will require additional pipeline capacity to bring natural gas to the Gulf Coast, where most of the under-construction and approved plants are to be located.” Although there is additional natural gas from other plays such as Permian and Haynesville, with a combined growth of 6.9 bcfd of natural gas by 2025, future LNG capacity can require much more. In only six years, US LNG capacity increased from zero to almost 11 bcfd, and, currently, the pool of LNG approved projects totals 26.3 bcfd. With natural gas demand worldwide expected to continue to increase, US LNG developers can have the economic incentive to accelerate the addition of new capacity. Doh adds: “The US has large accumulations of natural gas that could be developed in the current price environment, and coupled with additional LNG capacity, can further increase the US’s natural gas exporting capacity. Shale operators have generally recovered from the lows caused by demand destruction during the 2021 pandemic-related crisis and have also remained competitive. This means that even with the increase in Henry Hub prices, given natural gas prices in other world regions, US LNG exports are quite profitable. “With new LNG terminals launching next year, the US is on track to become the largest LNG exporter in the world and an important player to partially fill the demand gap in Europe and Asia.”
USA Marcellus and Utica Shales Market Report- Statistical Analysis, Business Opportunity and Forecast - The USA Marcellus and Utica Shales Market research report segments the market based on type, applications, end-users, and different geographies. USA Marcellus and Utica Shales Market helps new entrants/ stakeholders to understand the market trends and plan robust market strategies. Moreover, the report also offers a covid-19 impact on the USA Marcellus and Utica Shales Market, enabling businesses to understand market drivers and restraints. The Appalachia Basin which is made up of the Marcellus formations and the Utica Shale, accounted for more than 40% of the natural gas produced in the United States in 2020. Most of the production comes from the state of Pennsylvania and Ohio and partially from West Virginia. Unlike many of the oil plays in the US Lower 48, the natural gas plays including the Appalachia Basin saw a less drastic change in production and drilling activity during the economic contraction caused by the Covid-19 pandemic. While major oil-producing operators slashed their 2020 capital expenditure up to 50% - 60%, the top three producers in the Appalachia Basin EQT Corporation, Antero Resources, and Southwestern Energy have only cut their capital by 20%, 35% and 40%, respectively. This region averaged 32.19 billion cubic feet of natural gas per day (bcfd) and 33.44 bcfd in 2019 and 2020, respectively.USA Marcellus and Utica Shales Market Report analyzes the crude oil and natural gas appraisal and production activities in Marcellus and Utica Shales play in the US. The scope of the report includes -
- Comprehensive analysis of natural gas and crude oil historical production and short term outlook of Marcellus and Utica shale plays during 2019-2021
- Detailed information of impact on well development, permits and deals due to COVID-19 pandemic
- In-depth information on net acreage, operational performance and financial standings of major operators in Marcellus and Utica shale plays
- Analysis of top companies’ future plans and cost trends in 2020
- Up-to-date information on associated infrastructure and major mergers and acquisitions in Marcellus and Utica shale plays between 2018 and 2020
Despite moratorium, 2 million gallons of conventional oil and gas waste spread on Pa. roads since 2018 - Conventional oil and gas producers have spread millions of gallons of drilling waste on Pennsylvania roads in the last few years, despite a 2018 moratorium on the practice. For years, companies have spread oil and gas waste on roads to suppress dust and melt ice. But in 2016, the state blocked the practice for waste from Marcellus shale wells. In 2018, it also prohibited the spreading of waste from conventional oil and gas wells, which typically tap shallower rock formations. The decision resulted in a 90 percent drop on the amount of conventional waste, or brine, spread on roads, said Karen Feridun of the non-profit Better Path Coalition, which produced a report on the topic. Still, Feridun says, companies have disposed of over 2 million gallons of conventional drilling waste on Pennsylvania roads since 2018. “What really are the distinctions between conventional and unconventional (waste)?” Feridun said. “If you are going to take that step of banning unconventional, why not both?” Both conventional and unconventional drilling waste contain salts, metals, and naturally-occurring radioactive materials. Most conventional waste is disposed of at treatment facilities or injection disposal wells. But companies are still disposing of some of their waste through road spreading. They are using a loophole in state law called “coproduct determination,” which allows for companies to replace a commercially-available product with industrial waste as long as using that waste does not “present a greater threat of harm to human health and the environment” than the product it’s replacing. As part of this process, companies are required to evaluate “total levels of hazardous or toxic constituents” in their waste. Earlier this year, the DEP asked 17 companies that had reported road spreading for additional information on these activities. Their responses showed the companies had tested their waste for salts and other minerals. But Feridun, who reviewed these submissions to the DEP obtained through Right-to-Know requests, says the companies aren’t testing the waste for radioactivity and other contaminants. “There are just all sorts of substances and chemicals that are in the waste that are extremely dangerous and are going to have long lasting effects,” Feridun said.
FERC cracks down on pipelines The Federal Energy Regulatory Commission toughened its stance on alleged violations associated with natural gas pipelines yesterday, saying enforcement has been too lax in the past and that stricter policies may be needed. “We are being more aggressive and ensuring that those conditions are actually being enforced,” FERC Chair Richard Glick told reporters after the agency’s open meeting yesterday. “Under previous leadership, the commission did not adequately enforce its conditions.” Yesterday’s meeting showcased the sharp divisions among commissioners about the agency’s oversight of natural gas projects. In contrast to Glick’s get-tough rhetoric, Republican members of the panel warned that putting up obstacles to pipeline development can lead to problems, such as potential gas outages this winter in the Northeast. “We’re going to have to face the reality that the need for gas-fired generation is not going to go away next month, next year, in the short term. It is not,” said Republican Commissioner Mark Christie. “We’re going to have to deal with that and be willing to build the transportation facilities to get the gas to the generators so we can keep the lights on.” Commissioner Allison Clements, a Democrat on the panel, said the agency’s moves “illustrate the profound challenges” facing natural gas projects and signal the need for broader policy changes. She and fellow Democrat Glick reiterated their support for changing how the agency assesses proposed new natural gas pipelines, a process outlined in its certificate policy statement. “To address the challenges ahead, we need to stop debating whether change is necessary and take the forward-looking steps required to meet our statutory obligations,” Clements said. The meeting was the first with Willie Phillips, a fellow Democrat who was sworn in this month as FERC’s fifth commissioner. Phillips could give Glick and Clements the votes they need to revise the pipeline policy statement and add “greater emphasis on environmental impacts” into FERC’s review processes, ClearView Energy Partners said in a note Dec. 3. Phillips, for his part, did not vote on any of the items yesterday, but he said he looked forward to getting up to speed while prioritizing electric reliability and affordability. “This small but very critical agency can have a big effect on public welfare,” Phillips said. The other commissioners approved moving forward with enforcement actions seeking a $40 million fine against Energy Transfer LP on allegations that it leaked toxic diesel fuel while building its Rover pipeline in Ohio, and alleging that Cheniere Energy’s Midship pipeline in Oklahoma is violating its permit for leaving construction debris on the private land it condemned for construction. In the case of the Rover pipeline, the company will need to explain why it should not pay the penalty proposed by agency staff. The commission also revoked the permits of two other projects that were canceled amid staunch opposition, the PennEast pipeline — a project proposed by a consortium of energy companies that would have run through New Jersey and Pennsylvania — and the Pacific Connector project, which was to carry gas to the Jordan Cove liquefied natural gas terminal in Oregon. Developers of Jordan Cove told FERC this month that they were not moving forward with the project because of challenges in obtaining state permits (Energywire, Dec. 2). Energy Transfer, best known as the developer of the Dakota Access pipeline, acknowledged yesterday that diesel was leaked during Rover construction, but said it was introduced to the project by the "rogue employee" of a contractor who then tried to conceal his actions.
Eastern Generation shutting oil-fired power in New York City, adding battery storage | S&P Global Platts --Independent power producer Eastern Generation said it plans to retire oil-burning peaker plants and build battery storage projects providing over 350 MW of storage capacity at three existing generating stations in New York City. "Eastern Generation is well positioned to assist in the transition to a carbon free future, while continuing to provide a safe and reliable electric system," Mark Sudbey, Eastern Generation's CEO, said in a Dec. 16 statement. "We are prepared to help meet zero carbon goals," he said, adding "our actions today are part of this larger effort as we look at our existing sites and beyond to help reimagine a safe, reliable power supply." The company owns electric generating stations that account for nearly 18% of New York City's power generation capacity, according to the statement. The first storage project, which filed for authorization at the New York Public Service Commission, is planned to be located at the Astoria Generating Station and will provide 135 MW of energy storage. Eastern Generation also said that it is withdrawing an application previously submitted to the New York State Siting Board to repower the Gowanus Generating Station on the Brooklyn waterfront with new gas turbines so that it may effectively proceed with energy storage development at the site. Additionally, the company will file with the NYPSC and the New York Independent System Operator to retire two oil-only power barges at Gowanus as soon as November 2022, six months ahead of the scheduled May 2023 closure mandated by state regulations, Eastern Generation said.
Three House Democrats ask watchdog to probe 'peaker' power plant pollution --Three House Democrats from New York on Tuesday called on a federal watchdog to investigate pollution generated by “peaker” power plants, or those that only generate electricity during periods of high demand.House Oversight Committee Chair Carolyn Maloney (D-N.Y.) joined Rep. Alexandria Ocasio-Cortez (D-N.Y.) and Rep. Yvette Clarke (D-N.Y.) in calling on the Government Accountability Office (GAO) to investigate the effects of such plants on local communities.The lawmakers noted that the plants are both less energy-efficient than standard power plants and are frequently located in lower-income or predominantly minority neighborhoods.“Addressing the use of peaker plants, which can emit twice the carbon and up to 20 times the nitrous oxides of a typical plant while operating significantly less efficiently, represents a high-impact opportunity to reduce climate risks and tackle a life-threatening environmental justice issue,” they wrote. “We request GAO’s assistance in reporting on key data to assess damage, uncover health burdens, calculate economic costs, and identify alternative solutions to the use of peaker power plants.”There are 89 peaker plants in New York City alone, including 28 in or near Maloney’s district and 16 in Ocasio-Cortez’s district. An area in western Queens with a number of such plants has become known as “Asthma Alley” due to its disproportionate rates of the respiratory condition.
Burning Oil To Generate Electricity In The US -- As Bad As Coal But A Whole Lot More Expensive -- December 20, 2021 
Large heating oil spill near Millers River in Athol could take days to clean up - (WWLP) – A tanker rollover in Athol on Wednesday has caused gallons of heating oil to spill, some into the Millers River. On Wednesday, the Orange Fire Department announced they are working to contain the heating oil in the Millers River with assistance from Environmental Services Inc. from South Windsor, Connecticut. Residents may see a slick look to the water for several days as they work to clean the water. Cleanup continued into Thursday and more people are now assisting. State, federal and local groups are working to remove the oil from the river. The Orange Fire Chief requested assistance from Massachusetts State Police Airwing to flyover the river to find areas with larges amount of oil. Residents should expect to see equipment and vehicles along the Millers River for the next several days. It is estimated more than 6,000 gallons of heating oil was spilled at the accident but it is unknown how much of that spill went into the Millers River. The Massachusetts DEP will be setup all along the river in the coming days to assist in the cleanup. The Orange Fire Department says there is no threat to the general public at this time.
Gas Company Continues to Push for Potomac Pipeline Project, Mixed Signals from State Agencies - A dormant court case that could lead to the construction of a natural gas pipeline beneath the Potomac River and Western Maryland Rail Trail has come back to life, and the utility company behind it is quietly renewing its permits as it continues to fight the matter in court. At issue is a 3.5 mile pipeline in Maryland, sought by TC Energy which is based in Canada, that would bring natural gas from Pennsylvania to West Virginia’s panhandle. Environmentalists say that this could endanger drinking water for communities in Washington County and others all the way to Washington, D.C., while business leaders have argued that natural gas is critical for the economic development of Western Virginia’s panhandle. In 2019, the Board of Public Works voted unanimously not to grant an easement for TC Energy’s “Eastern Panhandle Expansion Project,” and the company filed an appeal in the United States Court of Appeals for the Fourth Circuit. The case had been sitting there until the U.S. Supreme Court ruled in PennEast Pipeline Co. v. New Jersey this summer that pipeline projects with federal approval can seize state-owned land to build natural gas pipelines. Since then, Columbia Gas Transmission, LLC. — which is a part of TC Energy — asked the Fourth Circuit to rule in its favor based on the New Jersey decision. Columbia Gas had received federal approval through the Federal Energy Regulatory Commission back in 2018 and contended that they can use the federal government’s power of eminent domain to seize Maryland land to build a pipeline through the Natural Gas Act. TC Energy said in a statement that they plan to complete the pipeline within a year of getting approval to start constructing. “We only consider condemnation as a ‘last resort’ when constructing a project of this nature, but it was unfortunately necessary in this case despite reaching agreement with all private landowners along the route. While the process to uphold federal authority under the Natural Gas Act continues at the 4th Circuit, we continue to work with permitting agencies to ensure that all necessary permits are in place. We plan to complete construction within a year of initiation,” TC Energy said in a statement.
Virginia Regulators Bring MVP One Step Closer to Construction Restart with Water Quality Permit -The Mountain Valley Pipeline (MVP) received a new water quality permit from Virginia regulators last week, a development that could prove critical in the embattled Appalachian natural gas conduit’s quest to overcome regulatory setbacks and finish construction. Virginia’s State Water Control Board, on the recommendation of staff from the state Department of Environmental Quality, on Tuesday voted 3-2 to issue a Virginia Water Protection permit to MVP. The permit is issued through authority established under Section 401 of the federal Clean Water Act (CWA). The Virginia-issued permit marks a major stepping stone toward fulfilling a revamped permitting and construction plan laid out by the developers in early 2021 as an alternative to previous waterbody crossing authorization that was stalled by legal challenges. Part of the new permitting plan involves obtaining state-issued CWA Section 401 approvals from Virginia and from West Virginia, the two states along the 2 million Dth/d pipeline’s mountainous journey from the Marcellus Shale region to an interconnection with the Transcontinental Gas Pipe Line in Pittsylvania County, VA. Missing waterbody crossing authorizations have “been a significant contributor to the project’s delays,” analysts at ClearView Energy Partners LLC wrote in a note to clients shortly after the Virginia board’s decision. “We expect West Virginia to issue its pending authorization by year end as well.” The state-issued permits should then allow the U.S. Army Corps of Engineers to move forward with pending CWA Section 404 authorization early next year, according to the analysts. In August, MVP drew closer to realizing its revised water-crossing plan when itreceived an environmental assessment from the Federal Energy Regulatory Commission (FERC). FERC originally issued a certificate to the pipeline in a split decision in 2017, but myriad regulatory snags and legal setbacks have driven delays and cost overruns in the intervening years. MVP has said that construction of the 42-inch diameter, 303-mile pipeline is close to 94% complete, with 53% of the pipeline’s right-of-way now fully restored.
The Infrastructure Bill’s Hydrogen Funding Is a Big Win for the Oil and Gas Industry - The infrastructure bill signed into law by President Biden in November includes $9.5 billion dollars to support the creation of a clean hydrogen industry — but much of the money is going to support the U.S. fracked gas industry under the guise of “clean” blue hydrogen. While being presented as a clean hydrogen plan for decarbonizing the energy system, the main focus of the hydrogen section of the bill is to continue and expand the use of natural gas (that is, methane) in the U.S. economy via what’s known as blue hydrogen. Blue hydrogen is the name for a fuel product that currently cannot be produced on a commercial scale. Hydrogen gets labeled different colors based on how it’s produced. There’s gray, made from fossil fuels, and green, made using renewable energy. And then there’s blue. The theoretical idea is to make hydrogen from methane while using carbon capture technology to eliminate more than 90 percent of CO2 emissions released during the production process, thus making the hydrogen “low carbon.” Most of the world’s current hydrogen is “gray,” produced from methane without carbon capture, which is an inexpensive but dirty process. Hydrogen production currently contributes to 2 percent of global CO2 emissions, in addition to all of the globe-warming methane released during natural gas production. The gas industry is promising that carbon capture can eliminate most of the CO2 emissions associated with hydrogen production, but there is increasing evidence that carbon capture technology can’t deliver as promised and even if it could, it is very expensive. Bloomberg recently reported that U.S. Senator Joe Manchin (D-WV) played a powerful role in shaping the components of the infrastructure bill that support the use of fracked shale gas as a feedstock for hydrogen production. However, even Manchin has recently admitted that carbon capture — which is essential to blue hydrogen’s supposed climate credentials — isn’t a realistic solution. “I’d love to have carbon capture, but we don’t have the technology because we really haven’t gotten to that point,” Manchin explained to E&E. “And it’s so darn expensive that it makes it almost impossible.” More recently the CEO of Italian energy company Enel acknowledged the same truth about carbon capture, stating: “The fact is, it doesn’t work.” This reality about carbon capture’s failure, however, did not prevent the inclusion of $3.5 billion in subsidies to support carbon capture development for the fossil fuel industry in the infrastructure bill, in addition to the money earmarked for developing blue hydrogen. The Build Back Better bill, Biden’s signature climate and social policy legislation, also is full of more handouts to the fossil fuel industry to support carbon capture.
Natural gas prices fall after warm start to winter - This past fall, surging energy prices were one of the most visible and alarming side effects of the world’s monumental effort to reopen economies all at once. But just a few months later, a warm start to the winter — and worries that the Omicron variant will cause a slowdown — have cut the price of one of America’s main fuel sources nearly in half from its peak. Natural gas is a major source of heating and electricity for American homes. Heading into the winter, these lower prices shouldn't cause the pocketbook shock that analysts had recently feared, as growing inventories change the pricing landscape. Compare that to Europe, which doesn't produce its own gas and still faces steep shortages. Rising prices in the U.S. often stem from the size of natural gas inventories held in storage. In September, when prices were climbing toward their peak, storage levels had shrunk to 7.4% below the five-year average — thanks to a combination of the rapid demand increase from the reopening, the cooling needs from a hot summer, and then the disruption from Hurricane Ida, Sindre Knutsson, natural gas analyst at Rystad Energy, tells Axios. But storage levels have recovered — in large part because of the unseasonably warm start to winter — and over the past few weeks are hovering right around the five-year average, according to the Energy Information Administration. The EIA’s next weekly report will probably show a surplus to the average for the first time since February, analysts at BofA Global Research write. Th Weather can turn on a dime. A colder U.S. winter would likely deplete some of the inventory. But don’t expect prices to head back to the $5 or $6 area, Knutsson says. More likely, are bouts of short-term volatility. "The market is much more healthy than it was" a few months ago, and can withstand a few cold snaps, he says. Oil prices have eased as well. U.S. crude had its worst day of the month yesterday, down 3.7% — and is off 19% from its November peak.
Natural Gas Futures Jump Higher as U.S. Exports Estimated at Record Level -- Natural gas prices rebounded with a flurry on Monday, driven higher by surging demand for U.S. exports of liquefied natural gas (LNG) and domestic forecasts for colder weather in the month ahead. The January Nymex gas futures contract settled at $3.834, up 14.4 cents day/day. The prompt month was up more than 20 cents in intraday trading. The February contract advanced 11.9 cents to $3.758. The gains marked a reversal from cumulative losses over the prior three weeks, including back-to-back declines last Thursday and Friday. Spot gas action was mixed, with prices up in most regions but down substantially in the volatile Northeast. NGI’s Spot Gas National Avg. was down 75.5 cents to $4.615. LNG feed gas volumes climbed above 13 Bcf over the weekend, reaching a new high, according to preliminary estimates early Monday. Estimates are often revised, but analysts said demand for American exports is clearly mounting and expected to set official records this winter. “Daily LNG feed gas nominations at Sabine Pass spiked above 5.0 Bcf/d on Sunday, lifting national LNG demand to 13.1 Bcf/d and shattering prior records — further contributing to upward movement in the Nymex front-month contract,” European calls for U.S. gas, already elevated ahead of winter due to anemic supplies on the continent, have further intensified in December as freezing weather settles in and heating demand surges. At the same time, anticipated increases in supply from Russia to Europe this winter via the recently completed Nord Stream 2 (NS2) pipeline have yet to flow. NS2 gas deliveries are in limbo amid regulatory delays, leaving European markets increasingly in need of U.S. LNG. Analysts at Rystad Energy said it appeared NS2 may not get certified in time for this winter season. Meanwhile, aside from parts of the western United States, domestic weather-driven demand continues to prove modest and is expected to remain so late into December. However, as Rubin noted, forecasts on Monday showed “coalescing indications for a cold first week of January,” providing support for futures.
U.S. natgas near three-week high on colder weather forecasts - (Reuters) - U.S. natural gas futures rose more than 2% to a near three-week high on Wednesday, helped by forecasts for colder weather over the next two weeks than previously expected and hopes that soaring prices in Europe will keep demand for U.S. liquefied natural gas (LNG) exports strong. Front-month gas futures rose 10.7 cents, or 2.8%, to settle at $3.976 per million British thermal units (mmBtu), their highest close since Dec. 3. "Some cold and more seasonal weather on the horizon, and record LNG export pulling gas away from domestic consumption are contributing to the upside," "Given these market fundamentals, expect prices will remain at the current levels or go higher before heading south when the winter is over and higher production news hitting the market. Data provider Refinitiv estimated 409 heating degree days (HDDs) over the next two weeks in the lower 48 U.S. states, up from the 405 HDDs estimated on Tuesday. The normal is 429 HDDs for this time of year. HDDs, used to estimate demand to heat homes and businesses, measure the number of degrees a day's average temperature is below 65 Fahrenheit (18 Celsius). Refinitiv projected average U.S. gas demand, including exports, would rise from 109.7 billion cubic feet per day last week to 125.1 bcfd this week before easing to 116.8 bcfd next week. Gas prices in Europe jumped to a record high on Tuesday after Russian gas shipments to Germany through a major transit pipeline reversed direction and colder weather increased demand. Global gas prices have repeatedly touched all-time highs over the last few months as utilities around the world scrambled for LNG cargoes to replenish low stockpiles in Europe and meet surging demand in Asia, where energy shortfalls caused power blackouts in China. The amount of gas flowing to U.S. LNG export plants has averaged 11.9 bcfd so far in December, now that the sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana is producing LNG. That compares to 11.4 bcfd in November and a monthly record of 11.5 bcfd in April. Output in the U.S. Lower 48 states has averaged 96.7 billion cubic feet per day (bcfd) so far in December, which would top the monthly record of 96.5 bcfd in November.
US gas inventories drop well below normal as mild winter weather persists | S&P Global Platts -- (NB: headline is wrong) US natural gas inventories fell about one-third of the five-year average rate, and the remaining Henry Hub winter strip tumbled more than 20 cents. Storage fields withdrew 55 Bcf for the week ended Dec. 17, according to data the US Energy Information Administration released Dec. 23. The survey has missed the mark by an average of 2 Bcf over the past six storage weeks. The withdrawal was slightly below the 57 Bcf draw that an S&P Global Platts survey of analysts expected. The draw was well below the five-year average of 153 and the 147 Bcf pull from the corresponding week of last year. Working gas inventories decreased to 3.362 Tcf. US storage volumes now stand 234 Bcf, or 6.5%, below the year-ago level of 3.596 Tcf and 34 Bcf, or 1%, above the five-year average of 3.328 Tcf. The remaining NYMEX Henry Hub winter fell about 23 cents to average $3.63/MMBtu in Dec. 23 trading following the data release. Production has seen strong growth in the fourth quarter, which caused the NYMEX 2022 Henry Hub strip to sell off late in the year to maintain an average below $4/MMBtu. Platts Analytics' supply and demand model currently forecasts a 128 Bcf draw for the week in progress, which is more than the five-year average pull of 121 Bcf. An early look at the week ending Dec. 31 points to a drawdown of 83 Bcf, which is 15 Bcf below the five-year average, increasing the nascent storage surplus. Demand looks to grow in multiple sectors in 2022, which should lead to larger year-on-year pulls if normal winter weather arrives with the New Year. Total US demand is forecast to add another 1.4 Bcf/d in 2022 compared with 2021 to an average of 97.3 Bcf/d, according to Platts Analytics. LNG export demand will be the main driver of the increase as feedgas is forecast to average 12.4Bcf/d in 2022, 1.6 Bcf/d higher than 2021. Industrial demand is also forecast to rise to an average of 23.3 Bcf/d in 2022, up from 22.6 Bcf/d in 2021. Offsetting some of these increases will be a 1.2 Bcf/d drop in power demand to average 29 Bcf/d in 2022. The higher-priced environment expected in 2022 is likely to keep gas-to-coal switching high, limiting the upside to gas demand for power generation much of the year.
U.S. natural gas futures plunge on bearish winter weather outlook - U.S. natural gas futures plunged to the lowest since July as the weather forecast for the new year shifted milder and European gas prices slid from record-high levels. Futures fell 6.2 per cent on the New York Mercantile Exchange Thursday, the most since early December. Unseasonably high temperatures are expected on the East Coast and southern U.S. through next week, dampening demand for the heating and power-plant fuel. Trading has meanwhile thinned heading into the U.S. holiday weekend, raising the likelihood of sudden swings. Embedded Image “We expect the weather data will continue to bounce between colder and warmer trends for the first week of January in the coming days, making holding over the long Christmas Holiday break extremely risky,” analysts with NatGasWeather.com wrote in a note to clients. Thursday’s sell-off comes after gas prices in Europe plunged 20 per cent on expectations that a flotilla of liquefied natural gas cargoes en route from the U.S. will help to ease an energy crisis that has driven futures to record highs and shut factories. U.S. LNG export facilities have been operating at or above capacity in recent weeks and 30 tankers carrying nearly 5 million cubic meters of the fuel combined are crossing the Atlantic. Anemic declines to U.S. gas inventories at the start of winter have underscored the impact of higher-than-normal temperatures. Utility companies and other customers drew just 55 billion cubic feet of natural gas from winter storage last week, in-line with analyst expectations but less than half the 5-year average demand for that time of year, a report released Thursday showed. Gas for January delivery settled down 24.5 cents to US$3.731 per million British thermal units. Futures earlier fell to US$3.599, the lowest since July 16.
Venture Global Signs Another Pair of LNG Supply Deals With China - Venture Global LNG Inc. signed two more gas export contracts with China as cargo prices at record levels add pressure on overseas buyers to enter into long-term deals and lock in lower costs. The U.S. liquefied natural gas developer signed a pair of 20-year supply deals with China’s CNOOC Gas & Power Group Co for a total of 3.5 million metric tons a year, the companies said in a joint announcement Monday.
A $550 million Bia plant may be coming to the Port of Caddo-Bossier - Bia Energy Operating Company announced that it is evaluating a $550 million blue methanol production plant that would be located at the Port of Caddo-Bossier in Shreveport. “Louisiana welcomes and supports Bia Energy’s plans for investment, job creation and increased economic activity in Northwest Louisiana,” Gov. John Bel Edwards said. The possibility of this plant could result in the creation of 75 direct new jobs, with an average annual salary of $80,000, plus benefits. “The long-term economic impact of quality jobs created by Bia Energy will greatly benefit North Louisiana,” North Louisiana Economic Partnership President and CEO Justyn Dixon said. “With our region’s strong education partners and training programs, these well-paying, permanent jobs will contribute to retaining that skilled workforce in Caddo Parish. Bia Energy’s dedication to energy efficiency will bring our region to the forefront of modern energy. We commend the effort between the Port of Caddo-Bossier, BRF, LED and NLEP, and thus proving collaboration is the way to bring long-term investment to North Louisiana.”Louisiana Economic Development estimates the project would result in 390 indirect jobs, for a total of 465 new jobs in Louisiana’s Northwest region.The plant would feature carbon capture capabilities, reducing carbon dioxide, or CO2, emissions by more than 90 percent compared to other methanol plants. If it moves forward, BEOC plans to locate its facility on a 74-acre site located at the Port of Caddo-Bossier. The company is expected to make a final decision in the 1st quarter of 2022, with construction expected to last approximately two years, and commercial operations to begin soon after.
Sixteen Hispanic House Democrats ask EPA for tougher methane rule -Sixteen members of the Congressional Hispanic Caucus on Wednesday asked the Environmental Protection Agency (EPA) to tighten its rules on methane emissions, citing the particular impact of emissions on Hispanic and Latino communities.The members, led by Congressional Hispanic Caucus Climate Change Task Force Chair Nanette Diaz Barragán (D-Calif.), called the EPA’s latest methane rule “historic.” However, they called for two key expansions of its provisions: regular inspections for smaller oil and gas wells at risk of leaking, and further action to address so-called flaring, or burning gas it would not be profitable or safe to sell.The letter notes that about 1.81 million Latino Americans live within a half-mile of an oil and gas well, citing data from the Environmental Defense Fund.“[U]nder the current proposal, operators that calculate lower potential emissions (less than 3 tons per year of methane) could still escape regular leak monitoring. This is problematic because these smaller, leak prone wells can release more methane or natural gas into the air than they produce,” the letter states. “Also, large leaks can occur at smaller well sites. EPA must address this issue by enacting comprehensive requirements for frequent leak inspections, without exceptions for smaller wells.” Flaring, too, is a particular concern for low-income communities and people of color, the letter says, citing research from the University of Southern California that found Black, Indigenous and Latino communities are at disproportionate risks to their health from flaring. The practice has been linked to asthma, heart issues and premature births in pregnant women.
Biden’s crude sale moves to second round with bids due Jan. 4 ---The Biden administration’s release of crude from U.S. emergency reserves in an effort to cool oil’s rally is going into a second round, with bids due by the first working day of the year. The Department of Energy is selling 18 million barrels of sour crude from storage caverns in Texas and Louisiana in a tender that closes Jan. 4, with deliveries from Feb. 1 through March 31, according to a statement on its website. Crude futures have dropped about 15% since late October, when President Joe Biden and his team began indicating they were considering a variety of tools to bring down fuel prices. Oil has fallen more sharply since news of the omicron variant of the coronavirus broke in late November. In a first effort, a loan program offered 32 million barrels of high-sulfur crudes from the Strategic Petroleum Reserve. Of that total, just 4.8 million barrels was awarded to Exxon Mobil Corp. In the latest tender, the Energy Department is offering to sell supplies from caverns in Big Hill and Bryan Mound in Texas, as wells as West Hackberry and Bayou Choctaw in Louisiana. The agency is allowing early deliveries where possible.
US Crude Oil In Supply Slips to 27.3 Days -- December 19, 2021 -Link here. One month ago: 28.5 days. Most recent week: 27.3 days.
Taylor Energy OK's $475 million settlement for longest oil leak in U.S. history - Taylor Energy Co. has agreed to pay $475 million to settle litigation with the federal government over the 17-year leak of crude oil – the longest in U.S. history – from its hurricane-destroyed production platform 20 miles off the mouth of the Mississippi River. According to a proposed consent decree filed Wednesday in U.S. District Court in New Orleans, the company will transfer to the Interior Department a $432.5 million trust fund that it set up to pay for capping and plugging the 28 wells, decommissioning what's left of the platform and cleaning up any soils contaminated by the leak. The company has also agreed to pay more than $43 million in civil penalties, federal costs for removing the platform and wells and expenses for restoring or replacing natural resources such as wildlife, fisheries or wetlands contaminated by oil. Louisiana is a co-trustee with the federal government in overseeing the money to restore natural resources. The proposed settlement signals the end of Taylor Energy, a company founded in 1979 by Patrick Taylor, the independent oil executive known for his efforts to create the now state-funded Taylor Opportunity Program for Students, or TOPS. The program provides college scholarships to thousands of Louisiana students. The drawn-out compliance process illustrates not only the difficulty of stopping underwater oil leaks but also the determination of an independent oil company with deep pockets and the shifting priorities of a federal government that changed parties three times in 17 years. Taylor died in 2004, only a few weeks after Hurricane Ivan destroyed the platform in the Gulf of Mexico. In the ensuing years, his company sold its other oil and gas assets, retaining only the failed wells and the cleanup response trust fund. The company is controlled by Taylor’s widow, renowned New Orleans philanthropist Phyllis Taylor. Phyllis Taylor company representatives did not respond Wednesday to a request for comment on the settlement. The settlement, which is subject to public comment for 40 days, requires Taylor Energy to drop its lawsuits against the federal government, including a challenge to the Coast Guard’s decision to install a spill containment system over the well site. The containment system collects oil that continues to leak from some unplugged wells. It also requires the company to drop its challenge to the Coast Guard’s denial of Taylor’s request for $353 million, which would have been reimbursement for the company’s spending on fighting the leak and plugging the wells. Further, the settlement resolves all federal claims on the company. And when Taylor Energy sells its remaining assets after the settlement, the proceeds will go to the federal government, according to the Justice Department. The company will be allowed to hold onto enough money to pay for operations until the liquidation is complete.
Louisiana energy firm to pay millions following oil spill that began 17 years ago -America’s longest running oil spill dispute is close to a resolution after a Louisiana-based energy firm has agreed to a proposed multi-million dollar settlement. Taylor Energy agreed to pay more than $43m in clean-up costs, civil penalties and natural resource damage, and transfer a $432m clean-up trust fund to the Department of Interior, according to a proposed settlement announced by the Department of Justice. The proposed agreement stems from more than a dozen Taylor Energy-owned wells in the Mississippi Canyon area of the Gulf of Mexico that began leaking after a production platform was damaged by Hurricane Ivan in 2004. The pipeline has lost hundreds of thousands of gallons of oil, and continues to leak. “Offshore operators cannot allow oil to spill into our nation’s waters,” said Todd Kim, assistant attorney general for the DoJ’senvironment and natural resources division, adding: “If an oil spill occurs, the responsible party must cooperate with the government to timely address the problem and pay for the cleanup.” As part of the settlement, Taylor Energy will withdraw three existing lawsuits it filed against the government and will not be required to admit “any liability to the United States or the State arising out of the MC-20 Incident.” The agreement will now put before a court’s review and approval. The National Oceanic and Atmospheric Administration’s national ocean service, said in a statement that the “settlement represents an important down payment” to the costs of the environmental clean-up. “Millions of Americans along the Gulf Coast depend on healthy coastal ecosystems. Noaa and our co-trustees look forward to working in partnership with the National Pollution Funds Center to ensure the region and the ecosystem can recover from this ongoing tragedy,” said Nicole LeBoeuf, national ocean service director The spill began 17 years ago when a cluster of pipes connecting sixteen wells off the Louisiana coast were damaged by a subsea mudslide caused by the toppling of a Taylor production platform by hurricane winds. The company plugged nine wells but has said it cannot plug the rest. The Coast Guard said a system had captured and removed more than 800,000 gallons of oil since April 2019. Taylor Energy sold its oil and gas assets in 2008, according to its website. The trust fund will be created to plug the wells, as well as to permanently decommission the platform and clean contaminated soil.
Baytown, Texas: 4 injured after explosion and fire reported at an ExxonMobil refinery officials say – CNN - A "major industrial accident" injured at least four people early Thursday at one of the United States' largest oil refineries, sheriff's officials in the Houston area said. Initial reports indicated an explosion happened at the ExxonMobil oil refinery in Baytown, Texas, Harris County Sheriff Ed Gonzalez said in a tweet, and residents in the area reported a loud explosion. A fire happened at the refinery around 2 a.m. ET, according to ExxonMobil, which did not immediately confirm an explosion or say what led to the fire. Four people were injured, the sheriff's office said, three of whom were taken for treatment by helicopter and one by ambulance. The fire happened in a unit that produces gasoline, and the plant's emergency workers still were working before sunrise to extinguish the fire, ExxonMobil refinery manager Rohan Davis told reporters early Thursday. The conditions of the four injured people were stable, said Davis, who said he could not comment on the extent of their injuries. The cause of the fire wasn't immediately known and will be investigated, Davis said. The company is coordinating with authorities and is monitoring air quality with regulators, Davis said. "All of those results so far have shown no impact to the community from an air quality perspective," Davis said.The Baytown refinery, which began operations in 1920, has an average daily capacity to refine 561,000 barrels of oil, according to the US Energy Information Administration.That makes it the fourth-largest US refinery, only 8% smaller than the largest, the Motiva Enterprises facility in Port Arthur, Texas, owned by Saudi Aramco. Baytown is one of only five US refineries with a capacity of more than 500,000 barrels a day. The refinery incident Thursday could hamper output for months, weighing on gasoline supply at a time when US refining capacity has already been reduced, saidTom Kloza, chief oil analyst for the Oil Price Information Service.
Fire that injured four people at ExxonMobil's Baytown refinery extinguished— A fire that broke out overnight at ExxonMobil's Baytown refinery has now been extinguished, according to the latest update from the company.ExxonMobil officials say four people were injured in the fire, which started at around 1 a.m. Sheriff Ed Gonzalez said three of the injured workers were taken to the hospital by Life Flight. One other was taken by ground ambulance. ExxonMobil says all other employees are accounted for and those who were hospitalized are reportedly stable. We're told it happened in the part of the refinery that produces gasoline. While employees were evacuated from that section, the rest of the plant is still in operation.The cause of the fire remains under investigation.We've gotten multiple viewer reports of the fire. One person sent us video, which is below. ExxonMobil released the following statement to us: "Our first priority is people in the community and in our facilities. Air monitoring continues along the fence line. Available information shows no adverse air quality monitoring impact to the community or personnel on site at this time.We are saddened to inform that four people were injured and are receiving medical treatment. All four individuals are in stable condition. All other personnel have been accounted for.We are in the process of setting have set up an information line for community members affected by this incident. Please call 1-800-241-9010.The causes of the incident have not yet been determined. We are coordinating with authorities as appropriate, and all findings will be incorporated in our continuing effort to enhance our safety performance. We deeply regret any disruption or inconvenience that this incident caused to the community."
Intertribal agency raises concerns with state's draft review of a proposed oil pipeline reroute | Wisconsin Public Radio An intertribal agency says the state’s draft environmental review of a Canadian firm’s $450 million plan to reroute an oil and gas pipeline across northern Wisconsin is incomplete and flawed.The Wisconsin Department of Natural Resources released its draft environmental impact statement on Thursday for a roughly 40-mile reroute of Enbridge’s Line 5 in Ashland and Iron counties. The pipeline carries up to 23 million gallons of oil and natural gas liquids per day from Superior to Sarnia, Ontario.Enbridge wants to move the pipeline after the Bad River Band of Lake Superior Chippewa sued the company in 2019 to shut down and remove Line 5 from the tribe’s reservation.The company’s proposed route is expected to cross nearly 200 waterbodies and temporarily affect 135 acres of wetlands. Enbridge maintains the nearly 70-year-old pipeline serves as a vital link to fuel across the region.The Great Lakes Indian Fish and Wildlife Commission, which represents 11 Ojibwe tribes, told the DNR in a Dec. 10 letter that the state’s review has significant gaps in information.The commission’s environmental section leader John Coleman and environmental specialist Esteban Chiriboga said the draft released Thursday lacks adequate data to support the impacts of any oil spill to downstream waters, including Lake Superior. They said it also fails to assess compliance with the Bad River tribe’s water quality standards or combined impacts of other projects."There really needs to be a thorough description of the risks being posed by putting this pipeline around the reservation ... and Enbridge does not have a great history with spills," said Coleman.Enbridge was responsible for one of the nation's largest inland oil spills in July 2010, which cost more than $1.2 billion to clean up. More recently, Minnesota regulators fined the company $3 million for failing to follow the state’s environmental laws after Enbridge pierced a groundwater aquifer during construction of Line 3, releasing at least 24 million gallons of water."This was a topic that was brought up time and time again, recognizing that Red Cliff specifically has a huge reliance on commercial fishing," said Noah Saperstein, environmental justice specialist for the Red Cliff tribe. "Not to mention, the cultural connection that the community has with the lake."
U.S. Oil and Natural Gas Drilling Activity Rises Ahead of Holidays, Latest Baker Count Shows - Onshore gains in both oil and natural gas-directed drilling saw the U.S. rig count surge seven units higher to finish at 586 during the week ended Thursday (Dec. 23), according to the latest figures from Baker Hughes Co. (BKR). Five oil-directed rigs and two natural gas-directed rigs were added domestically for the period, with the combined U.S. tally outpacing its year-earlier total by 238 units. The Gulf of Mexico held flat at 15 rigs for the period, down from 17 a year ago. Seven horizontal units were added, along with one vertical rig. Partially offsetting was a decline of one directional unit, according to the BKR numbers, which are partly based on data from Enverus. The Canadian rig count pulled back sharply for the period, down 34 rigs week/week to 133. Declines included 20 oil, 13 natural gas and one miscellaneous rig. The Canadian count remained well ahead of the 82 rigs running in the year-ago period. Broken down by major region, the Permian Basin led the way with six rigs added for the period, raising its total to 294, up from 173 at the same time last year. The Cana Woodford added two rigs for the week, while the Haynesville Shale added one. In terms of state-by-state counts, Texas and New Mexico each posted net gains of four rigs week/week. Louisiana, meanwhile, saw a net decline of one rig for the period, the BKR data show. According to the latest round of Energy Information Administration (EIA) inventory data, Americans pulled back on distillate fuel, gasoline and jet fuel consumption in the week-earlier period as spread of the Omicron variant of the coronavirus accelerated. EIA said Wednesday that total petroleum demand for the week ended Dec. 17 dropped 12% week/week to 20.5 million b/d. Demand for gasoline fell 5% week/week, while jet fuel consumption declined 9% and distillate fuel demand dropped 22%. “Much uncertainty remains regarding the impact of the Omicron variant on mobility, demand and oil prices,” Raymond James Inc. chief economist Scott Brown said the new variant would inevitably create enough trepidation to cause travel and economic interruptions, affecting energy demand. However, because a majority of Americans are vaccinated, he does not expect government imposed lockdowns that would cause lasting impacts. Omicron “is likely to be a near-term constraint on growth, but a temporary one, as we saw with the Delta variant,” Brown said.
Shale companies are swimming in cash -- Two things to start:
- Au revoir, long-term European gas contracts. The European Commission has proposed banning deals between EU members and energy suppliers outside the bloc, such as Russia, that would last beyond 2049. That’s a long time away, but is the last year before the EU economy is supposed to have hit a net zero emissions target.
- Remember peak oil consumption? US weekly oil demand soared last week, hitting a new record of almost 23.2m barrels a day, according to the Energy Information Administration, leaping by 17 per cent compared with a week earlier. The four-week average is not — yet — at a record high.
That US demand number is startling. But Omicron seems certain now to decide whether the US — or indeed global — energy consumption continues to rise so quickly. Opec remains sanguine about the variant, saying in its latest market report that the impact on demand “is expected to be mild and shortlived”. The International Energy Agency was less confident, saying in its December oil-market report that Omicron “poses a significant risk to the economic outlook”.Meanwhile, although Joe Biden’s Build Back Better legislation — with its sweeping climate and energy provisions — is stalled in Congress, some of its supporters have launched a new TV spot to promote it. The PR blitz marks an interesting change of tack by positioning BBB — and its funding for “affordable clean energy” — as the answer to American anxieties about high energy costs and inflation. That stands in contrast to the White House’s approach to tackling soaring oil and gas prices in recent months by trying to increase fossil fuel supply. Our first note is on the torrent of cash now flowing into shale companies’ bank accounts. An industry once notorious for destroying capital is now swimming in it. Living within their means has never been a strong point for US shale producers. But last year’s crash, and colossal Wall Street pressure, have proven to be the nudge companies needed to get their houses in order. After years of burning through investor cash in pursuit of ever-greater growth, America’s shale patch is suddenly making money. Lots of money. As 2021 rounds to a close, public shale companies shelled out a combined $6bn in capital expenditure in the last quarter, according to consultancy Rystad Energy. That is less than a quarter of their levels at the height of the boom. Cash from operations, meanwhile, sits at around $13bn, approaching record levels. All of which means that free cash flow, a key shale investor metric determined by the difference between cash from operations and capex, is coursing through a sector that once exemplified value-destruction and some of the worst excesses in corporate America. The transformation — helped by a doubling in oil prices in the past 12 months — is stark, as the chart below shows. It has been a long time coming. Investors have left oil and gas in droves in recent years, causing the sector to shrink from one of the biggest hitters on the S&P 500 to representing less than 3 per cent of the index — half of Apple alone. The old guard of growth investors have run for the hills, to be replaced with a new breed of value investors, keen on returns rather than untrammelled expansion of drilling. “Our investors have evolved,” a senior shale executive told me when I visited Midland last week. “They pushed for growth at all costs and now they get the new model and they like it . . . it’s important to them.” That new model involves not injecting cash back into drilling new wells but rather funnelling cash back to investors in the form of healthy dividends. Scott Sheffield, chief executive of Pioneer Natural Resources, the biggest shale player, described it to me in Houston last week as a new “contract” between the industry investors. In Pioneer’s case that means growing by no more than 5 per cent annually and distributing a hefty chunk of free cash flow back to investors. And this new model is here to stay, he told me: “There’s no way that the industry is going to change overnight and start growing again.”
USGS Releases Oil and Gas Assessment for the Bakken and Three Forks Formations of Montana and North Dakota - The USGS has completed an oil and gas estimate for the Bakken and Three Forks Formations in the Williston Basin of Montana and North Dakota. The estimate includes 4.3 billion barrels of unconventional oil and 4.9 trillion cubic feet of unconventional natural gas in the two formations. This assessment updates the 2013 USGS assessment of the Williston Basin. "This assessment is the latest in a long line of work we've conducted in the Williston Basin," said Sarah Ryker, USGS Associate Director for Energy and Minerals. "The Williston Basin has, in many ways, mirrored our broader energy work. What began with assessments of potential energy resources has grown to encompass both energy and water production, infrastructure and impacts, demonstrating the importance of both to the regional and national economies." A substantial amount of drilling (over 11,000 wells) has occurred in the basin since 2013, resulting in both more production and more knowledge of the basin’s resources. The USGS assessment focuses on areas where less drilling has occurred and less is known about potential resources. “The USGS assessment is of undiscovered resources; in other words, it’s a science-based estimate of what may be discovered in the basin in the future,” said Ryker. “It’s different from – and complementary to – industry production numbers, which focus on the known or discovered resource. Our research focuses on areas of uncertainty.” This assessment also contributes to an ongoing USGS effort to better understand interactions and dependencies between energy resources and water resources. In 2016, the USGS conducted an assessment of the water and proppant requirements and water production associated with potential future production of undiscovered oil and gas resources in the Williston Basin's Three Forks and Bakken Formations. In addition, the USGS has published geochemical data from water samples taken during hydraulic fracturing (fracking) of unconventional oil wells in the Bakken and Three Forks Formations. This assessment was conducted based on a peer-reviewed, publicly available methodology that is used for all USGS oil and gas assessments. This allows an apples-to-apples comparison for USGS assessments across the country and over time. This assessment is for undiscovered, technically recoverable resources. It includes estimates of continuous resources.
Recoverable oil in western North Dakota revised downward -(AP) — A federal report shows that untapped recoverable oil in western North Dakota has dropped significantly in the last eight years due to the number of new wells. The U.S Geological Survey estimates that the Bakken and Three Forks rock formations contain another 4.3 billion barrels of crude, a 40% drop from the agency’s last estimate in 2013. About 11,000 wells have been drilled into the formations in the last eight years, collectively producing billions of barrels of oil predicted in the earlier estimate. “We weren’t all that surprised that the number went down,” state Mineral Resources Director Lynn Helms said Friday. “I think we were surprised how much the number went down.” The wells drilled into the rock formations have produced 4 billion barrels of oil to date. Helms said he anticipates the future output of those wells will consist of another 4 billion barrels, The Bismarck Tribune reported. Helms said about 80% of what’s considered the best mineral acreage in the Bakken oil patch has already been drilled and companies are looking to innovate in parts of the region farther from the center. The USGS also revised down its expectations for natural gas production. The 2013 estimate anticipated 6.7 trillion cubic feet per day of additional recoverable gas. The latest estimate puts the figure at 4.9 trillion cubic feet per day.
Bakken still has 4.3 billion barrels of undiscovered oil out there, in addition to the 8 billion already proven or produced --In 2013, the Bakken and Three forks formations in the Williston Basin had 7.4 billion barrels of undiscovered but technically recoverable oil and 6.7 trillion cubic feet of undiscovered natural gas, according to a United States Geological Services survey. Since 2013, more than 11,000 wells have been drilled in the Bakken and Three Forks formations. Produced resources, of course, no longer count as undiscovered. And the same goes for proven reserves. Those factors have dropped the amount of undiscovered oil in the new undiscovered resources report substantially, to 4.3 billion barrels. Undiscovered gas, meanwhile, dropped to 4.9 trillion cubic feet. "The USGS assessment is of undiscovered resources; in other words, it’s a science-based estimate of what may be discovered in the basin in the future," said Sarah Ryker, USGS Associate Director for Energy and Minerals. "It’s different from – and complementary to – industry production numbers, which focus on the known or discovered resource. Our research focuses on areas of uncertainty." The new report takes into account what the latest technology can do, as well as new information about the formations that has become available. The fact that undiscovered resources dropped was not a surprise, North Dakota Director of Mineral Resources Lynn Helms said during the December oil production report. “What we have to keep in mind is that the Bakken and Three forks, as of the end of October, had cumulative production of 4 billion barrels of oil and it is still producing one million barrels a day, which indicates to us that from the existing well inventory it’s going to produce another 4 billion,” he said. “And then add to that 4.3 billion of undiscovered or undrilled and you actually have a pretty solid numbers pretty good number of 12.3. billion.” Helms said he believes that the USGS figure is on the lower side of what the ultimate number really is. “So you know, a little disappointed in the amount of the reduction, but not that surprised that it went down,” Helms said. “We’re doing a deeper dive into the analysis.” The methodology of the USGS study follows that used for all USGS oil and gas assessments, so that it can be compared to other USGS assessments for other basins across the country and over time. USGS is the only provider of publicly available estimates of undiscovered, technically recoverable oil and gas resources for onshore lands and offshore state waters. Technically recoverable resources means those resources that can be produced using today’s standard industry practices and technology. That differs from economic reserves, which refers to which quantities of oil and gas can be produced profitably.
Standing Rock, Corps urge Supreme Court to reject Dakota Access appeal -- The Standing Rock Sioux Tribe and a federal agency are urging the U.S. Supreme Court to reject an appeal of the five-year-old lawsuit over the Dakota Access Pipeline. The project developer in the appeal seeks to have the high court reinstate a federal permit for the line’s Missouri River crossing. The justices are expected to decide early next year whether to take up the case. The appeal follows a January ruling by the U.S. Court of Appeals for the D.C. Circuit affirming part of a lower court order that revoked the permit and required a new environmental review of the pipeline. “Though the dispute over the pipeline garnered national attention, the D.C. Circuit’s decision plowed no new ground,” lawyers for Standing Rock and other Sioux tribes fighting the pipeline wrote in a brief filed Thursday. The tribes argued that the justices should decline the pipeline developer’s petition to hear the case because appeals courts are not split on the issues surrounding the dispute. Disagreement among lower courts can prompt the Supreme Court to weigh in on an issue. The tribes say the D.C. Circuit judges applied a “conventional” review of the U.S. Army Corps of Engineers' permitting decisions and “found no abuse of discretion” in the lower court’s order revoking the permit. The Corps permitted the pipeline’s river crossing, which is just upstream from the Standing Rock Sioux Reservation and where tribal members fear a leak could occur and harm their water supply. The pipeline is controlled by Texas-based Energy Transfer, which has long maintained that the line is safe. Past court decisions have found shortcomings in the Corps' original environmental analysis of the pipeline. The agency began a lengthier review last year and has pushed back the anticipated completion date several times. Attorneys for the Corps said in a court document filed Friday that the study should wrap up in November 2022, two months later than its previous estimate. The tribes in their brief said that once the review is complete, "The Corps will make a new permitting decision on a new record. In short, the (pipeline company’s) petition presents no question that merits review by this Court.” The Corps on Friday joined Standing Rock in opposing Dakota Access's appeal. The agency said a question at the heart of the dispute -- whether federal law obligates the agency to prepare a more thorough environmental review -- "will lack any substantial importance after the Corps in fact prepares one." Dakota Access has transported a significant portion of North Dakota’s oil production since 2017. The pipeline operator filed the appeal with the Supreme Court in September, arguing that lower courts indeed disagree on issues raised in the lawsuit. .
Texas Oil Company Charged for Negligence that Caused Disastrous Oil Spill in California Coast | Nature World News -A Houston-based oil corporation and two subsidiaries have been charged in connection to a large oil leak that occurred off the coast of southern California in October, contaminating seas, beaches, and endangering animals.Prosecutors claim that part of the cause of the leak was a failure to respond appropriately when alarms repeatedly warned personnel of a pipeline breach.A federal grand jury indicted Amplify Energy and its subsidiaries, which operate numerous oil rigs and a pipeline off the coast of Long Beach, with a single misdemeanor offense of unlawfully dumping oil.Investigators suspect the pipeline was damaged when the anchor of a cargo ship grabbed it in heavy winds in January, months before it exploded on October 1 and spilled up to 25,000 gallons (94,600 liters) of crude oil into the ocean.According to US authorities, the corporations were found to be irresponsible in six ways, including failing to respond to eight leak detection system alerts over a 13-hour period that should have alerted them to the spill and reduced the damage. Instead, the pipeline was shut down after each alert and then reactivated, pouring more oil into the water.Amplify claimed the pipeline was displaced by an unidentified shipping firm. That staff on and offshore responded to what they thought were false alerts since the system wasn't working correctly. According to the corporation, it alerted a potential leak at the platform where none existed.According to Amplify, the leak came from a portion of subsea pipe 4 miles (6.4 kilometers) distant.The business stated that "had the staff understood there was a genuine oil leak in the water, they would have shut down the pipeline immediately."The leak washed up on the beach at Huntington Beach, forcing the city's beaches and others around the Orange County coast to close for almost a week. Fishing in the affected area has only just restarted after tests revealed that the fish did not contain dangerous levels of oil pollutants. It also contaminated sensitive wetlands, which are important habitats for migratory and shorebirds and other endangered species. Even after the black globs were cleaned off the beaches, it's still unknown how much of a long-term impact the spill had on plants and animals. The corporation faces up to five years of probation if convicted and fines that might reach millions of dollars.According to Orange County Supervisor Katrina Foley, the indictment verifies locals who saw the leak a day earlier and reported it."It's unfortunate that they practically misled to the community during press conferences and led people to believe that what they saw, smelled, and knew with their own eyes was not real," she added.
Second Oil Sheen Discovered Off Huntington Beach Coastline – (CBSLA) – A second oil sheen was spotted off the Huntington Beach coastline Wednesday, about one week after the first was discovered in the same general area.The sheen was detected about a mile offshore from Bolsa Chica State Beach, according to the California Department of Fish and Wildlife’s Office of Spill Prevention and Response.Authorities reported on Thursday afternoon that despite preventative measures being taken, several tarballs were located on shore in Huntington Beach.In addition to this, a statement from the City of Long Beach indicated that shorelines could be further impacted, “The size of the sheen is currently undetermined, however, on its current trajectory northbound, the San Gabriel River, Long Beach shoreline and Port of Long Beach could be impacted as early as tomorrow morning, Dec. 24.”They noted that the inclement weather on Thursday would impact containment efforts, and make it easier for the oil sheen to travel.The source of the sheen was unknown.According to OSPR, “protective strategies” were implemented overnight at “sensitive environmental sites” as a precaution, including Talbert Marsh, Bolsa Chica wetlands, Newport Slough and the Santa Ana River.“An overflight is scheduled for this (Thursday) morning,” according to an OSPR Twitter post. “Samples were collected yesterday as part of the investigation and the source is yet to be determined.”On Dec. 15, an oil sheen about the size of a football field was discovered about two miles off of Bolsa Chica State Beach. Investigators said that sheen did not appear to be the result of a pipeline leak. It’s also unclear if it was connected to a storm which had occurred a day prior.On the morning of Oct. 2, a rupture was reported to a pipeline owned by Amplify Energy in federal waters at the Elly oil-rig platform, about 4 1/2 miles offshore of Huntington Beach. The nearly 18-mile pipeline runs from Amplify’s offshore drilling platforms to a pump station in Long Beach. About 25,000 gallons of crude oil leaked into the ocean.Federal authorities confirmed that a section of Amplify’s pipeline was damaged and moved more than 100 feet along the ocean floor, an indication that a ship’s anchormay have caused the spill.On Dec. 15, the same day that the first oil sheen was discovered, three companieswere federally charged in connection with the October oil spill.
New reports of oil sheen off Bolsa Chica prompt search Wednesday afternoon – Orange County Register - A response team has set out to search for an oil sheen reported Wednesday, Dec. 22, about a mile offshore of Bolsa Chica State Beach. If oil is found, it would be the second sighting in a week’s time and the third in the past month following the October spill that shut down beaches, businesses and harbor activity along the Orange County coastline. An afternoon post on Twitter by the California Department of Fish and Wildlife’s Spill Prevention and Response said agencies were “responding to a report of a sheen approximately one-mile offshore Bolsa Chica State Beach.” “At this time, the source has not been determined.” officials said, adding any additional information would be posted when available. The U.S. Coast Guard and the county of Orange were participating, the message said. Bolsa Chica State Parks Lifeguard Chief Jeff David said someone first reported seeing a sheen off Seal Beach and the Coast Guard set out to investigate. He said response boats were near the Bolsa Chica wetlands inlet with booms. “They put those out possibly precautionary,” he said. “If it gets back there, that could damage the wildlife and the birds.” Lifeguards were told no further assistance was needed, he said. Just last week, a sheen about 400 feet long and 100 feet across sent response crews racing to protect wetlands inlets with berms and set booms to capture oil before it hit sensitive areas. Divers inspected the pipeline that spilled oil in October, reporting that breach was still secured. Further testing showed the oil wasn’t from that spill or a natural seepage, leaving authorities wondering where the oil came from. There had not been any new sightings reported since Friday. About a month ago, a sheen about 30-by-70-feet was determined to be possible residue from small droplets of oil coming from the damaged section of the pipeline.
Lawsuit to Protect Arctic Polar Bears From Oil Drilling Launched Against Biden Administration --The Center for Biological Diversity filed a notice of intent this week to sue the U.S. Department of the Interior and Bureau of Land Management (BLM) for allegedly failing to adequately protect polar bears from a Western Arctic exploration project. Under the Endangered Species Act, a notice of intent is required 60 days before the pursuit of a formal lawsuit.The 88 Energy’s Peregrine Exploration Program, a five-year oil and gas exploration project that would run almost year-round and cause “near constant air and vehicle traffic, and other drilling-related activity” was approved by the outgoing Trump administration, the press release said. The company still needs approval from the Biden administration before drilling any new wells. Located in Alaska’s National Petroleum Reserve along the Colville River, the project would include the construction of roads and aircraft runways and cause disruptive noise pollution in polar bear habitats.“Every new oil well in the Arctic is another step toward the polar bear’s extinction,” Kristen Monsell, senior attorney at the Center for Biological Diversity, said in the press release. “Biden should be phasing out oil and gas activity in the Arctic, not flouting key environmental laws to let oil companies search and drill for more oil in this beautiful, increasingly fragile ecosystem.”The population of polar bears in the Southern Beaufort Sea area is the most fragile population in the world, with only around 900 bears. Studies predict unless greenhouse gas pollution is immediately and drastically reduced, most subpopulations of polar bears in the world, including that of the Southern Beaufort Sea, will become extinct this century, and perhaps even as early as mid-century, the Center for Biological Diversity stated in the notice. The excessive noise caused by the drilling-related activities can cause the polar bears to stop feeding, interfere with their movements or even frighten mothers and cubs so that they leave their dens, according to the press release.
Oilsands Specialist Suncor Targeting 5% Production Growth in 2022 - With a vow to focus on efficiency, Suncor Energy Inc. set 2022 performance targets of 5% production growth while cutting capital expenditures by 6%. The 2022 corporate budget aims for combined oil and natural gas output of 750,000-790,000 boe/d. Spending goes down by C$300 million ($240 million) to C$4.7 billion ($3.76 billion). “We enter 2022 with strong momentum and remain steadfast in our focus on operational excellence, capital and cost discipline, increasing shareholder returns and delivering a more resilient future,” said Suncor President Mark Little. The northern Alberta oilsands continue to dominate Suncor operations, with the Calgary firm setting a 2022 annual average oil production target of 395,000-435,000 b/d. Oilsands operating costs are forecast to average C$25-28/bbl ($20-22.40), including purchases of natural gas for thermal extraction processes. Suncor described its pared down 2022 spending plans as “enabled by efficiencies across the business.” Oilsands plant maintenance and mine tailings pond clean ups, forecast to cost C$3.2-3.4 billion ($2.56-2.72 billion), top the budget. An additional C$2.1 billion ($1.68 billion) is earmarked for power projects, bitumen extraction wells and a life extension project for the Terra Nova production platform offshore of Newfoundland. The 2022 performance targets rely on annual average prices of US$70/bbl for West Texas Intermediate light oil, US$55/bbl for Western Canada Select heavy oil, and C$3.80/gigajoule ($3.20/MMBtu) for Canada natural gas.
New Oil And Gas Projects In UK Need To Pass Net-Zero Test - The UK will still allow the development of new oil and gas oilfields in the North Sea if they pass a so-called net-zero test, the government said on Monday as it opened a consultation seeking input on a new climate compatibility checkpoint for the oil and gas industry. The checkpoint will apply to any future oil and gas licenses to ensure they are aligned with the UK’s climate change commitments and net-zero by 2050 target, the government said. The proposed climate compatibility checkpoint “sets out potential tests that could be used to assess new licenses, including domestic demand for oil and gas, the sector’s projected production levels, the increasing prevalence of clean technologies such as carbon capture and hydrogen generation, and the sector’s continued progress against emissions reduction targets,” the UK said. “This new checkpoint will be key to our plans to support the oil and gas sector during its net zero transition. It helps safeguard the future of this vital UK industry as we create more opportunities for green jobs and investment across the country,” Energy and Climate Change Minister Greg Hands said. The intention of the checkpoint is to assess the compatibility of future licensing with UK climate change objectives and will not impact the consenting process for proposed developments that come under licenses that have already been awarded to licensees. “Such proposals are subject to a number of further checks including by the OGA under its revised Strategy, which is effectively a net zero test,” the government said.
UK Natural Gas Prices Hit New High, Trigger "Marketwide Crisis" - The latest jump in U.K. natural gas prices has been called a "national crisis" by multiple energy firms and industry groups in the country. They're requesting the government protect customers and suppliers as critical Russian gas flows into Europe plunge, nuclear outages in France, and cold weather send gas prices to stratospheric levels. On Tuesday, U.K. wholesale natural gas prices hit a new record high of 470p per therm (intraday). Prices have since eased to 451p per therm. FT spoke with London-listed Good Energy, EDF Energy, and the trade body Energy U.K. about the alarming situation in the country as the winter in the Northern Hemisphere begins. "This is a national crisis. Wholesale gas and power prices have increased to unprecedented levels over the last three weeks, creating an extremely difficult operating environment for every business in the industry," said Nigel Pocklington, CEO of Good Energy, a small renewable energy supplier. EDF Energy, the fourth-largest supplier in Britain, said high natgas prices are sending power prices skyrocketing, and it's "critical" for the government to "act now to support energy customers." Emma Pinchbeck, chief executive of Energy U.K., said Britain faces "a marketwide crisis." "Other Treasuries in Europe have already responded to the crisis, but in the U.K., the energy sector is still asking if the chancellor knows that energy bills going up by over 50 percent in the new year is a problem for ordinary people, businesses, and the economy," Pinchbeck added. U.K. lawmakers are in panic mode to protect households by possibly capping power bills. The same is true for other politicians across Europe.
Germany says no decision on Nord Stream 2 before July - A regulatory decision allowing natural gas flows to Europe via Russia’s controversial Nord Stream 2 pipeline won’t be made before July, Germany’s federal network agency said. The regulator, also known as Bundesnetzagentur, halted the certification process in mid-November and asked the Swiss-based operator of the pipeline — which is owned by Russia’s Gazprom PJSC — to set up a German subsidiary to comply with European regulations. The agency will resume the certification as soon as the necessary criteria are met, its president, Jochen Homann, said Thursday at a news conference. “A decision won’t be made in the first half of 2022,” he said. The German regulator is still waiting for project operator Nord Stream 2 AG to submit documentation, Homann said, adding that “this is not in our hands.” In an emailed response, the company declined to specify “details of the procedure, its possible duration and impacts on the timing of the start of the pipeline operations.” The move confirms what the market had anticipated. European benchmark gas prices briefly jumped amid concerns that pipeline may only start operating once stockpiling for next winter is well under way. The continent is suffering from the worst supply crunch in decades, with gas inventories abnormally low and futures prices soaring to record levels. Once the German regulator resumes the certification process, it has some two months to reach a preliminary decision. It then has to submit the draft conclusion to the EU Commission, which will have another two to four months to express its own opinion. The German agency then has a further two months to make a final decision. Those are the maximum timeframes under European law, and the statement from Germany indicates the process may take the whole time allotted. Nord Stream 2, a twin gas link across the Baltic Sea, is set to carry as much as 55 billion cubic meters per year from Russia to Germany. The project was initially expected to start operations by the end of 2019, but it has faced multiple hurdles, including opposition in Europe and from the U.S. Construction of the pipeline was completed in September, despite U.S. sanctions. Germany and the U.S. have also indicated the future of Nord Stream 2 could be at risk due to the possibility of conflict, as Russia escalates its troop presence near the border with Ukraine. The pipeline was set to be among the issues raised at a meeting of EU leaders in Brussels Thursday amid the growing military threat. Latvia Prime Minister Arturs Karins was among those to say that sanctions for the gas link should be on the table ahead of the summit.
Ukraine calls for Russia sanctions as some EU leaders push for Nord Stream 2 to be added to list - Ukraine wants the EU to quickly outline a package of sanctions to use against Russia if the Kremlin chooses to step up its military aggression against Kyiv. The call comes as concerns grow about the intentions of President Vladimir Putin and the increasing Russian troop presence near the Ukrainian border. "If you at least set up or pull together a serious package of sanctions and you let Russia know this is what's going to happen then that will deter Russia," Dmytro Kuleba, Ukraine's foreign minister, said. "At this point our partners maintain the constructive ambiguity approach, they say that consequences for Russia will be severe and unprecedented and so far and so on, but they don't go into details," The heightened tensions at the Ukraine border with Russia are being discussed by EU heads of state in Brussels on Thursday. It is so far unclear how far they are willing to go to address Russia's military activity, but some EU leaders share Ukraine's view that a package of sanctions needs to be developed soon. In fact, some European capitals have even suggested that Nord Stream 2, the contentious gas pipeline that bypasses places like Ukraine and Poland, should feature on a potential sanctions list against Russia. "I think we will raise this issue because this is one of the instruments which could be very strong in relation to Russia," Gitanas Nauseda, the president of Lithuania, said at his arrival in Brussels on Nord Stream 2. This energy project is meant to bring gas into Europe from Russia to Germany. However, the pipeline has not yet gained full regulatory approval and has been embroiled in political controversy. On the one hand, some politicians, notably in Germany, argue that the project is an economic matter. Critics of the pipeline, however, say it increases Europe's dependency on Russia. Germany's Foreign Affairs Minister Annalena Baerbock has said that Nord Stream 2 should not be allowed to operate if there's more Russian aggression toward Ukraine. Putin has previously pressured EU officials to approve the project, saying it is an easy solution to bring down energy costs in the region. A spokesperson for the Kremlin said Thursday that Nord Stream 2 was in the interests of Russia and Germany, Reuters reported.
Russian gas exports to Europe via Yamal pipeline remain tiny -- Russian natural gas deliveries to Germany through the Yamal-Europe pipeline have remained at very low levels early on Monday after a drop on the weekend, data from German network operator Gascade showed. Flows at the Mallnow metering point on the German-Polish border were down to an hourly volume of only 366,734 kilowatt hours (kWh/h) comparing with more than 1,200,000 kWh/h on Saturday and more than 10,000,000 kWh/h on Friday. Flows on the pipeline, a major route for Russian gas to Europe via Belarus, are hovering at between 9,000,000 and 12,000,000 kWh/h on average this month. Russian gas exporter Gazprom did not respond to a request for comment. Gazprom has not booked volumes for transit via the pipeline for December and buys the capacity at daily auctions. Nominations for Monday’s volumes at the Velke Kapusany metering point on the Slovakia-Ukraine border, another major route to Europe, were for 953,313.0 megawatt hours (MWh), or 89.97 million cubic metres, similar to levels so far in December.
Russia Reluctant To Boost Gas Flows As Cold Snap Hits Europe - Natural gas exports from Russia via the Yamal-Europe pipeline will remain limited at the start of this week as true winter begins and Russia keeps more gas for domestic consumption, with maximum temperatures in Moscow dipping below zero. Bloomberg reports that after booking limited transit space on the Yamal-Europe pipeline over the weekend, Russia has remained reluctant to boost volumes today, which will likely aggravate the already grave gas supply situation in Europe, which is also facing colder temperatures this week.According to data from the Regional Booking Platform, bookings for Russian gas flows via the pipeline, which terminates in Germany, stood at 4 percent of its capacity. This compares with an average bookings level of 35 percent of capacity since the start of the month.Russia has also not booked any capacity on the transit route via Ukraine for today. However, Gazprom has started refilling the gas storage facilities it manages in Europe, although slowly.Meanwhile, the temperatures in several European countries are expected to fall below zero this week, which will put additional strain on already strained grids, with wind power output much lower than demand requires, and gas in storage depleting fast due to the seasonal peak in demand.On top of this, France's EDF had to shut down two nuclear plans after an inspection revealed signs of corrosion on some reactors. These account for a tenth of the country's electricity output and will add to Europe's troubles.The situation is deteriorating fast, and could end in blackouts. Last month, Trafigura's chief executive Jeremy Weir warned that rolling blackouts were a possibility because of the limited natural gas supplies on the continent. "We haven't got enough gas at the moment quite frankly, we're not storing for the winter period. So hence there's a real concern that there's a potential if we have a cold winter that we could have rolling blackouts in Europe," Weir said.
Europe Desperate for LNG While Asia Has Plenty - Asia’s relentless buying of liquefied natural gas earlier this year has left the region so well stocked for winter that spot shipments are being diverted to energy-hungry Europe. Multiple vessels are now being diverted from Asia after prices in Europe traded at a rare premium, traders with knowledge of the matter said. A looming LNG wave will bring much needed supplies just as temperatures are dropping fast and is helping push European gas prices down from record-highs last week. Energy prices soared in Asia earlier this year as China stockpiled everything from coal to fertilizers ahead of the winter. Now that a mild start to winter has ensued in Northeast Asia, buyers from Japanese utilities to Chinese factories are sated, while spot inquiries for cargoes have dropped to a whimper last week, said traders. In Europe however, buyers are struggling to replenish inventories amid uncertainty over the startup of the Nord Stream 2 pipeline from Russia. From Italy to Poland, the continent has started to bid up the market to secure cargoes, although at prices surpassing those seen at the peak of last winter. “Europe is simply bidding gas away from Asia to not run out of electricity,” Goldman Sachs analyst Damien Courvalin said in a call with reporters Friday. Temperatures are plunging while it’s been a relatively mild winter so far in Asia, he said. Sellers have begun diverting cargoes away from Asia to take advantage of the spread, which may only accelerate over the next weeks. Traders are watching for any signs on whether economics would shift to make it profitable to send supplies to Europe directly from production facilities in the Pacific region. Typically, Europe is supplied from the Atlantic basin producers such as the U.S., northern Russia or Nigeria, or the Middle East. Supplies not limited by destination restrictions can head where the best market is. Prices in Europe are so high that some Asian countries may even choose to re-export LNG they imported for their own consumption. But this rare move is unlikely at the moment because LNG cargoes from the U.S. and Western Africa are much preferred due to the time traveled, Mathew Ang, an analyst at Kpler, said. The Minerva Chios vessel was sailing from the U.S. to Asia when it U-turned around December 15 and is heading toward the Red Sea, according to Bloomberg shipping data. The Lngships Manhattan, which was originally heading to China, is on its way to North Europe from the U.S., Kpler’s Ang said. More shipments could follow suit although they aren’t likely to be cheap.
Europe’s Gas Prices Jump To Record As Key Pipeline From Russia Halts Flows - European gas prices jumped to an all-time high on Tuesday after natural gas on a key pipeline from Russia to Germany reversed flow eastward and freezing temperatures took hold in many parts of Europe. The benchmark price for Europe at the Dutch Title Transfer Facility (TTF) surged by 11 percent early on Tuesday to a record 162.78 euros per megawatt-hour. According to data from German operator Gascade, cited by Reuters, flows of natural gas from Russia on the Yamal-Europe pipeline via Belarus to Poland and Germany have been falling since the start of the weekend, stopped completely on Tuesday, and then reversed direction from Germany east to Poland. Gas prices in the UK also surged to a new all-time high after hitting the previous record just a few days ago last week. UK gas prices soared to an all-time high of 350 pence per therm last Thursday, which was a massive 520 percent jump year to date. Today, the UK benchmark price hit 400p per therm—a new record. Freezing temperatures across Europe, low Russian gas supply, and low wind power generation in Germany have all combined to send European and UK gas prices to new records today.“EU gas and power open higher again today with gas flows from Russia on the Yamal-Europe pipeline dropping to near zero. Just as German wind output falls to a five-week low and freezing temperatures spread across Europe,” Ole Hansen, Head of Commodity Strategy at Saxo Bank, noted.At the start of this week, natural gas exports from Russia via the Yamal-Europe pipeline remain limited as true winter begins, Russia keeps more gas for domestic consumption, and Gazprom has not booked too much additional day-ahead capacity at auctions.Traders are watching closely every tender in which Gazprom is set to book pipeline capacity via the main pipeline routes to Germany and Poland. Every time Russia doesn’t book too much additional capacity, Europe’s benchmark gas prices jump.Some analysts and EU officials have said that Russia is deliberately keeping extra gas supply – the one on top of its contractual obligations – low amid the row over Ukraine and the delays in the certification of the Nord Stream 2 gas pipeline.Russia denies there is a connection between its limited extra gas supply to Europe and the current events with Ukraine and Nord Stream 2.“This is a purely commercial situation. You have to ask Gazprom about the details,” Kremlin spokesman Dmitry Peskov said on Tuesday, commenting on the halted gas flows to Germany via the Yamal-Europe pipeline.
Natural gas prices in Europe explode to all-time highs as major Russian flow stops --Natural gas prices in Europe exploded on Tuesday, December 21, 2021, after a major pipeline that brings Russian gas to Europe slowed output over the past couple of days and completely stopped delivering on Tuesday. This combined with record-high prices of electricity after France closed 4 of its largest nuclear reactors last week, low wind energy output, and cold weather to further deteriorate Europe's energy stability ahead of very cold Christmas and New Year. On Saturday, December 18, gas flow at the Mallnow metering point on the German-Polish border sharply dropped from around 13 500 000 kWh/h to 2 250 000 kWh/h and to 1 800 000 kWh/h on December 19. The flow further dropped to 1 634 206 on December 20 until it completely stopped early December 21.1 The westward flow was still 0 as of 08:30 UTC on December 22. As a result, the front-month wholesale Dutch gas price (European benchmark) rose to all-time high of 180.27 EUR per MWh on December 21. On July 5, 2021, it was 37.95 EUR per MWh and on October 5 116.8 EUR per MWh. To put these prices in perspective, take a look at numerical and percentage data for 2021 (first two graphs) and all-time data (graphs 3 and 4). "Europe has very little storage buffer this winter and it's balance is therefore a lot more dependent on imports than in previous years," James Waddell, head of European gas at Energy Aspects, said.2 "Additionally, Gazprom has traditionally shipped around 20% of its supply to Europe through Poland, but these flows have been inconsistent this year and driving up uncertainty about how much gas Europe will actually receive from Russia." On Monday, December 20, European electricity prices also surged to record highs after France announced the closure of four of its largest nuclear reactors.3 To meet the rising energy demand, French power giant EDF restarted fossil fuel generators and the same is happening with some other producers.
Russia Puts The Blame On Europe As Energy Crisis Worsens -The European Union (EU) is reportedly reconsidering its position on extending long-term natural gas contracts beyond 2049 as part of reforms in its natural gas market to meet the net-zero by 2050 goal. Should the European Commission’s proposal be endorsed by EU heads of state and government this week, putting a timeline to the end of long-term gas contracts would open another rift with Russia, which provides one-third of Europe’s gas supply via pipelines under long-term deals. The measure, if approved by the EU, would run against Russia’s position that long-term deals are beneficial for Europe and moving away from them and increasing reliance on liquefied natural gas (LNG) was and will be a mistake. Some EU member states are wary of what they perceive as Moscow using gas as a political tool to influence geopolitics. However, as it stands, especially with the low levels of gas in storage and surging gas and energy prices, supply from Russia and Russia’s willingness to provide additional volumes to Europe on top of its contractual commitments has been and will be a key driver of the gas market and prices at European hubs this winter. Despite the current crisis, the EU’s executive branch, the European Commission, is reportedly drafting plans to quit long-term gas supply contracts by 2049. At the same time, it plans to enhance the security of its gas supply, Bloomberg reportedthis week, citing a draft document prepared by the Commission. The EU has struggled with insufficient gas supply for months now, and the situation is not about to change as Russia continues to supply precisely what it had committed to deliver under long-term contracts. This has earned it accusations of using gas as a political weapon and increased the EU’s determination to reduce its reliance on Russian gas.Russia, for its part, denies any accusations about using gas for geopolitics and reaffirms it supplies the volumes of gas to its customers in Europe as per long-term contracts. And it says Europe’s decisions to move away from long-term deals are one of the reasons for the current“[T]he practices of our European partners [are to blame]. These practices have reaffirmed that, properly speaking, they have made mistakes. We were talking with the former European Commission; all of its activities were aimed at curtailing the so-called long-term contracts and at transitioning to gas exchange trading,” Russian President Vladimir Putin said in early October during a meeting to discuss Russia’s energy industry. “It turned out – and today this is absolutely obvious – that this policy is erroneous, erroneous for the reason that it fails to take into account the gas market specifics dependent on a large number of uncertainty factors,” Putin said, per the Kremlin’s website, just as Europe’s gas prices hit record highs.
Asia diverts extra LNG inventories to gas-starved Europe--Asia’s relentless buying of liquefied natural gas earlier this year has left the region so well stocked for winter that spot shipments are being diverted to energy-hungry Europe. Multiple vessels are now being diverted from Asia after prices in Europe traded at a rare premium, traders with knowledge of the matter said. A looming LNG wave will bring much needed supplies just as temperatures are dropping fast and is helping push European gas prices down from record-highs last week. Energy prices soared in Asia earlier this year as China stockpiled everything from coal to fertilizers ahead of the winter. Now that a mild start to winter has ensued in Northeast Asia, buyers from Japanese utilities to Chinese factories are sated, while spot inquiries for cargoes have dropped to a whimper last week, said traders. In Europe however, buyers are struggling to replenish inventories amid uncertainty over the startup of the Nord Stream 2 pipeline from Russia. From Italy to Poland, the continent has started to bid up the market to secure cargoes, although at prices surpassing those seen at the peak of last winter. “Europe is simply bidding gas away from Asia to not run out of electricity,” Goldman Sachs analyst Damien Courvalin said in a call with reporters Friday. Temperatures are plunging while it’s been a relatively mild winter so far in Asia, he said. Sellers have begun diverting cargoes away from Asia to take advantage of the spread, which may only accelerate over the next weeks. Traders are watching for any signs on whether economics would shift to make it profitable to send supplies to Europe directly from production facilities in the Pacific region. Typically, Europe is supplied from the Atlantic basin producers such as the U.S., northern Russia or Nigeria, or the Middle East. Supplies not limited by destination restrictions can head where the best market is.
European Gas Drops 18% As US Sends LNG Flotilla -European natural gas prices plunged Thursday after news that a liquefied natural gas (LNG) flotilla from the U.S. was headed to Europe. Data compiled by Bloomberg shows that ten vessels are headed to the fuel-starved continent while another 20 ships are crossing the Atlantic but have not determined their final destination. The news of the flotilla sent the benchmark Dutch front-month gas spiraling down 18% to 141 euros in Amsterdam, wiping out this week's gains. Plunging gas prices were a relief for European power customers. French power contracts tumbled 24% to 775 euros per megawatt-hour and German electricity fell 15% to 277 euros per megawatt-hour. The reason for the flotilla is that the European and U.S. natgas spread is the widest ever and well over a 15-year range. The hefty premium has made it worthwhile for commodity traders to take advantage of massive arbitrage opportunities. While the spread has plunged from the highest extreme ever, for context, European gas is equivalent to a $273 price for a barrel of crude oil... strongly suggesting that demand for U.S. oil products is building.
Oil spills hit 14m litres as Shell’s N800b judgment upsets industry - As International Oil Companies (IOCs) are planning to divest from Nigeria, concerns are beginning to mount over growing cases of oil spillage in the Niger Delta region and the N800 billion court judgment between Shell Nigeria and some communities in the region. In less than three years, weak infrastructure, especially pipelines, according to stakeholders, has led to the spillage of 14 million litres of crude oil, worth N2.8 billion coupled with cascading environmental dangers and health burden, leading to increase in cases of infant mortality and cancers. In fact, fresh intrigues are beginning to emerge ahead January, when the court would decide the fate of Shell Nigeria in an N800 billion damages earlier awarded by the Federal High Court in Owerri for the 2019 spillage in Eleme communities of River State. The jury is nearly out in the biggest dispute award ever in Nigeria’s volatile oil industry. But whether Shell Petroleum Development Company (SPDC) Limited, along with its two parent companies in the United Kingdom and The Hague, Netherlands, can come clean of culpability in a historic dispute debt awarded against it in a spill that occurred on swamp farmlands in Egbalor, Ebubu in Eleme Local Government Area of Rivers State, is what industry watchers are waiting to see next month. Shell, using all its legal resources, is seeking to convince the judge at the Court of Appeal to obviate payment of damages to some 88 persons, who got judgment in November 2020 from a Federal High Court in Owerri over spillage on their fishing facilities in Ejalawa community, Oken-Ogogu swamp farmlands. The judge of the Federal High Court, Owerri, Imo State, T.G. Ringim, had in the judgment last year, held that Shell Nigeria, Shell International Exploration and Production BV (SIE&P) and the Nigerian National Petroleum Corporation (NNPC) were liable for the spill.
Chinese Teapot Refineries Ramp Up Oil Imports From Iran - Independent Chinese refineries increased its crude oil imports from Iran last month as the government issued a new batch of import quotas. Total crude imports were up by almost 40 percent from October to an average of 600,000 bpd, Bloomberg reported, citing data from Kpler. The new quotas were issued in mid-October. What follows now, however, will be a slowdown in imports from all sources as China tightens restrictions in response to the Omicron variant and as Beijing continues to crack down on independent refiners. An effort to curb pollution ahead of the Winter Olympics will also affect imports negatively, as will the Lunar New Year holiday when demand declines. Chinese imports in March 2022 are set to be around 10.7 million barrels per day (bpd). This would be about 1 million bpd lower than the crude oil imports in March this year, according to estimates from consultants FGE cited by Bloomberg. This year, Chinese crude oil imports are already on track to post the first annual decline compared to 2020. This would be the first such drop in average annual crude imports since records began back in 2004, according to data from the Chinese General Administration of Customs. Even so, imports of Iranian crude have been strong among private refiners, or teapots, due to the price discount, especially as Saudi Arabia, China’s top supplier of crude, raised its official selling prices for Asian clients. According to traders cited by Bloomberg, Iranian crude sells at a discount of up to $4 per barrel to ICE Brent futures prices. Although Chinese state refiners shun Iranian oil, at least publicly, because of U.S. sanctions, private refiners are not subject to that much international scrutiny and have never really stopped buying Iranian crude. Also, private refiners do not have long-term contractual commitments with other suppliers, unlike state refiners.
OPEC+ DOC turns five - The Declaration of Cooperation (DOC) between OPEC Member Countries and 10 non-OPEC oil-producing countries turned five this month, OPEC highlighted. OPEC Member Countries and Azerbaijan, the Kingdom of Bahrain, Brunei Darussalam, Equatorial Guinea (which later joined OPEC), Kazakhstan, Malaysia, Mexico, the Sultanate of Oman, the Russian Federation, the Republic of Sudan and the Republic of South Sudan gathered in Vienna, Austria, to agree the deal back in December 2016. The birth of the DOC built on the ‘Algiers Accord’, signed in Algeria on September 28, 2016, and the subsequent ‘Vienna Agreement’, decided on November 30 of the same year in Vienna at the 171st Meeting of the OPEC Conference, OPEC outlined. The inaugural OPEC and non-OPEC Ministerial Meeting saw participating countries take several decisions in view of oil market conditions and prospects in the short and medium terms, as well as in recognition of the need for joint cooperation by oil producers to achieve sustainable oil market stability in the interest of producers, consumers, investors and the global economy, OPEC noted. “The Declaration of Cooperation is an unprecedented collaborative framework of leading oil producers that saw the need to come together during a critical juncture in the global oil industry,” OPEC Secretary General Mohammad Sanusi Barkindo said in an organization statement. “If it was not for this group of countries and the courageous act that they have undertaken, the oil sector would, without a doubt, be in a different situation,” he added in the statement. “Looking back to 2016, very few believed that the collaborative efforts would grow and evolve into a major, robust cooperative force to help restore much needed stability in the global oil market. However, the 23 oil-producing countries have continued to rise to the challenges they have encountered, including instrumenting effective and visionary policies to combat the devastating impact of the Covid-19 pandemic,” Barkindo went on to say. In response to the oil market contraction caused by the pandemic, the DoC’s 23 countries adopted the largest in size and longest in time voluntary oil production adjustment in the history of OPEC and the oil industry, OPEC noted. The organization stated that these efforts have supported the global pandemic recovery process and were recognized at the highest levels of government and by other international organizations and academia. The last OPEC and non-OPEC Ministerial Meeting was held via videoconference on December 2. The meeting technically remains in session, according to an OPEC release earlier this month, with an additional meeting planned for January 4, 2022.
Goldman says oil could hit $100, demand might reach 'new record high' in the next two years - Goldman Sachs predicts a new high in oil demand in 2022, and again in 2023. Damien Courvalin, the investment bank's head of energy research, also said Friday that oil at $100 per barrel was a possibility. Oil demand was already at record levels before the latest omicron variant hit, and furthermore, demand for air travel should continue to recover, he said. "We've already had record high demand before this newest variant, and you're adding higher jet demand and the global economy is still growing," Courvalin said in an energy outlook briefing with reporters on Friday. "You see how we will average a new record high in demand in 2022, and again, in 2023." Both international benchmark Brent crude and U.S. crude prices have spiked above $80 in recent months as post-pandemic demand outstrips supply. Surging natural gas prices have also caused crises around the world, most notably in Europe. The omicron variant has dampened sentiment, however, pushing prices back to just above $70 in recent weeks. Meanwhile, Courvalin expects restrictions that were hurting air travel to ease. Courvalin said he would not rule out the possibility of oil prices hitting $100, and there are "two paths" that could lead to that. The first is that costs go up as oil companies ramp up production. "There's inflation, everywhere else in the economy, and eventually there's inflation in oil services," he said. The other possibility is if the supply of oil can't meet the demand as global economies reopen from the pandemic.
Oil may hit $380 per barrel -- World oil prices could hit $380 per barrel in 2050. That’s according to one scenario published in Lukoil’s recent Global Energy Perspectives to 2050 report, which considered three scenarios for the global energy sector – Evolution, Equilibrium and Transformation. The report outlined that, taking into account a carbon price, oil prices will vary greatly depending the scenario. High carbon prices and inflation were projected to lead to $380 per barrel oil prices in the Transformation scenario, with prices in the Equilibrium and Evolution scenarios forecasted to come in at $197 per barrel and $128 per barrel, respectively. Lukoil’s report notes that the Evolution scenario assumes the ongoing development of global energy markets within the framework of the current international energy policy and national programs, considering existing technological capabilities. The Equilibrium scenario is said to be based on a balance between achieving climate goals and economic development and the Transformation scenario is said to assume a radical restructuring of global energy and industry as well as carbon neutrality of the leading economies by 2050. “In our outlook we estimate three possible decarbonization trajectories, including the Transformation scenario, which assumes aggressive phase out of hydrocarbons and the most efficient and rapid development of renewable energy and electric transport,” The President of Lukoil, V.U. Alekperov, stated in the report. “At the same time, according to our estimates, the development of the global energy is currently going according to the Evolution scenario, which does not allow to achieve the goals of the Paris Agreement,” he added in the report. “In this regard, it is necessary to focus even more on decarbonizing production, creating incentives for the development of renewable energy, other low-carbon technologies and energy efficiency. At the same time, it is important to minimize the possible negative consequences of an accelerated energy transition, including a significant increase in the cost of energy resources,”
Oil Futures Slide to 2-Week Low as Demand Outlook Weakens - Oil futures nearest delivery on the New York Mercantile Exchange and the prompt-month Brent contract on the Intercontinental Exchange slid to two-week lows in early trading Monday as global oil demand, already set to weaken seasonally in the first quarter, is seen further restrained amid increased travel restrictions in Europe amid spiking COVID cases. Most countries in Europe have adopted some form of restriction on travel, from the more extreme state of emergency declared through March 2022 in Bulgaria, to self-quarantine requirements in Italy for unvaccinated travelers in an effort to slow COVID infections. Late last week, France banned nonessential travel to and from Britain, where omicron is now the dominant COVID strain, while in the Netherlands officials reimposed a lockdown that closes through mid-January all nonessential business activity. Health officials in the United States are raising concerns that the fast-spreading omicron variant will swamp hospitals in coming weeks, but the United States hasn't added new restrictions, although outgoing New York City Mayor Bill de Blasio said his administration is considering changes to the New Year's Eve celebration in Times Square. The latest concerns over COVID are taking place as air travel in the United States is picking up pace. The Transportation Security Administration reported passenger throughput at TSA checkpoints in U.S. airports topped two million from Dec. 16 through Dec. 18, the most recent data available, albeit down 16% from the comparable period in 2019. Seasonally, global oil demand is weakest in the first quarter, although the Organization of the Petroleum Exporting Countries earlier this month revised higher its projection for first quarter 2022 demand by 1.11 million barrels per day (bpd) to 99.13 million bpd compared to a fourth quarter estimate of 99.49 million bpd. OPEC said a slowed demand recovery in the fourth quarter would be realized in the first quarter. On Dec. 14, International Energy Agency said global oil supply would likely outpace demand by 1.7 million bpd in the first quarter 2022, and by 2 million bpd in the second quarter, as supply cuts from OPEC+ continue to unwind. OPEC+ is set to increase production by 400,000 bpd in January, continuing their agreement reached in July to return 400,000 bpd in oil output cut in April 2020 in the depths of the pandemic each month until all cut production is restored. In early trading, NYMEX January WTI futures were down more than $3 at $67.75 bbl, with the February contract trading at $67.70 bbl. ICE February Brent futures were $2.70 lower near $70.80 bbl, with the March contract trading at parity. NYMEX January ULSD futures were down more than 8 cents at $2.1370 gallon, with January RBOB futures 6cts lower near $2.0610 gallon.
Oil Down on Virus and Manchin Fallout - Oil headed for its worst single-day rout this month on growing concern over the rapid spread of the omicron virus variant and turmoil for President Joe Biden’s economic plans. Futures in New York fell as much as 6.4% to trade near $66 a barrel ahead of the January contract’s expiration on Monday. Pessimism prevailed across financial markets as rising infections prompted restrictions on travel. U.S. economic sentiment took a hit after Biden’s $2 trillion spending package was derailed by the surprise revolt of Senator Joe Manchin. “The uncertainty around the response to omicron” is fueling the fear and volatility in oil markets, said Rebecca Babin, senior energy trader at CIBC Private Wealth Management. While some governments at first said they were trying to avoid lockdowns, more may be forced to capitulate as omicron takes hold. Oil’s market structure is also showing signs of weakness. West Texas Intermediate futures for delivery in January slipped to a discount to February contacts as omicron darkened the near-term demand outlook. The Brent prompt spread was also in a bearish contango pattern. Oil has fluctuated in recent weeks amid conflicting signals about omicron’s potential impact to demand. Bearish headwinds continue mounting with consumption in Asia softening and central banks pivoting toward tighter monetary policy to reign in accelerating inflation. As the year comes to an end, moving into the holiday period, thinner trading volumes can exacerbate prices swings. Manchin blindsided the White House on Sunday with his rejection of Biden’s tax-and-spending package, leaving Democrats with few options for reviving it. Goldman Sachs Group Inc. economists cut their U.S. economic growth forecasts. West Texas Intermediate for January delivery, which expires Monday, fell $4.50 to $66.36 at 10:45 a.m. in New York. The more active February contract dropped $4.13 to $66.59. Brent for February settlement dropped $3.41 to $70.11 a barrel. Meanwhile, New York state broke a record for new infections and New York City Mayor Bill de Blasio called on the federal government to step up supplies of tests and treatments amid a spike in infections caused by omicron. The Dutch government announced plans to enforce a stricter lockdown, while Germany’s health minister warned of another virus wave caused by omicron.
Oil caps biggest selloff of month --Oil posted its worst single-day rout this month on growing concern over the rapid spread of the omicron virus variant and turmoil for President Joe Biden’s economic plans. Futures in New York closed down 3.7 percent, trading around $68 a barrel, as the January contract expired on Monday. Pessimism prevailed across financial markets as rising infections prompted restrictions on travel, while U.S. economic sentiment took a hit after Biden’s $2 trillion spending package was derailed by the surprise revolt of Senator Joe Manchin. West Texas Intermediate for January delivery, which expired Monday, fell $2.63 to settle at $68.23 in New York. The more active February contract dropped $2.11 to $68.61 Brent for February settlement dropped $2 to $71.52 a barrel “The uncertainty around the response to omicron” is fueling the fear and volatility in oil markets, While some governments at first said they were trying to avoid lockdowns, more may be forced to capitulate as omicron takes hold. Oil’s market structure is also showing signs of weakness. West Texas Intermediate futures for delivery in January slipped to a discount to February contacts as omicron darkened the near-term demand outlook. The Brent prompt spread was also in a bearish contango pattern. Oil has fluctuated in recent weeks amid conflicting signals about omicron’s potential impact to demand. Bearish headwinds continue mounting with consumption in Asia softening and central banks pivoting toward tighter monetary policy to rein in accelerating inflation. As the year comes to an end, moving into the holiday period, thinner trading volumes can exacerbate prices swings. Manchin blindsided the White House on Sunday with his rejection of Biden’s tax-and-spending package, leaving Democrats with few options for reviving it. Goldman Sachs Group Inc. economists cut their U.S. economic growth forecasts. Meanwhile, New York state broke a record for new infections and New York City Mayor Bill de Blasio called on the federal government to step up supplies of tests and treatments amid a spike in infections caused by omicron. The Dutch government announced plans to enforce a stricter lockdown, while Germany’s health minister warned of another virus wave caused by omicron. The World Economic Forum postponed its annual meeting in Davos, Switzerland, next month. “It is not a case of if but when governments impose tougher restrictions,”
Oil Futures Advance as Traders Gauge Omicron Demand Loss - Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange moved higher in early trading Tuesday, retracing a portion of Monday's selloff, as market participants consider the effects of the omicron variant on global oil demand. Monday's selling pressed the oil contracts to test their early December lows plumbed following news the fast-moving COVID variant that emerged from South Africa having reached Europe in late November, with new cases spiking in Europe that have prompted a series of government responses, including travel restrictions and reinstating lockdowns. Overnight, Thailand is reported to have reinstated mandatory quarantines, with tightening COVID restrictions in Asia again risking further supply chain disruptions that have fanned inflation. Centers for Disease Control and Prevention said Monday the omicron variant now accounts for 73% of new U.S. COVID cases. The World Health Organization said the new variant has been found in 43 states in nearly 90 countries globally. Where there is community transmission, the number of cases is doubling in 1.5 to 3 days. The Imperial College COVID-19 response team on Dec. 16 issued a report that found "strong evidence of immune evasion" both from natural infection and vaccine-induced protection, and that the risk of natural reinfection from omicron is 5.41 times higher than for the delta variant. Omicron cases have been mild overall compared with previous COVID strains, with both the rapidity in new cases and the less lethal strain an historic precession in how pandemics end. However, WHO said it is "unwise" to assume omicron is mild. The surge in COVID cases in Europe is expected to again dent consumer sentiment in the Eurozone, which fell to a negative 6.8 in November and is seen declining to a negative 8. Exorbitant energy costs are also seen to again having derailed consumer confidence, including in Germany where a survey on consumer climate for January by Growth From Knowledge released overnight declined from a negative 1.8 to a negative 6.8 that was well above market expectations for a negative 2.5. In early trading, NYMEX February West Texas Intermediate was up $1 near $69.65 barel (bbl), with ICE February Brent up a similar amount to $72.50 bbl. NYMEX January ULSD futures gained a little more than 3 cents to $2.2040 gallon and January RBOB futures were up 2.3 cents at $2.1130 gallon.
Oil prices rise but Omicron worries linger - Oil prices rebounded on Tuesday after a sharp fall in the previous session as investors' appetite for risk improved, although they remained cautious amid the rapid spread of the Omicron coronavirus variant across the globe. Brent crude settled $2.46, or 3.4%, higher at $73.98 per barrel, and U.S. West Texas Intermediate (WTI) crude rose $2.51, or 3.66%, to settle at $71.12 per barrel. "After a rough couple of days, crude prices are rebounding as much of the COVID wall of worry has been priced in," said Edward Moya, senior analyst at OANDA. Countries across Europe were considering new curbs on movement as the fast-moving Omicron variant swept the world days before Christmas, throwing travel plans into chaos and unnerving financial markets. Omicron infections are multiplying rapidly across Europe, the United States and Asia, including in Japan, where a single cluster at a military base has grown to at least 180 cases. "This is a pragmatic market that wants to be bullish but knows relief rallies, like the one this morning, will not last," said Tamas Varga, oil analyst at London brokerage PVM Oil Associates. "The upside is likely to be limited and more restrictions will be greeted with renewed selling," he added. Still, Moderna Inc said on Monday that a booster dose of its COVID-19 vaccine appeared to be protective against the fast-spreading Omicron variant in laboratory testing, providing some hope to investors. On the supply front, OPEC+ compliance with oil production cuts rose to 117% in November from 116% a month earlier, two sources from the group told Reuters, indicating production levels remain well below agreed targets. In the United States, crude oil inventories were expected to have fallen for a fourth consecutive week, while distillate and gasoline stockpiles likely rose last week, a preliminary Reuters poll showed on Monday. The poll was conducted ahead of reports from the American Petroleum Institute, an industry group, due on Tuesday, and the EIA, the statistical arm of the U.S. Department of Energy, due on Wednesday.
Oil Futures Waver After Libyan Crisis Spurs Relief Rally - - Oil futures nearest delivery on the New York Mercantile Exchange and the Brent crude contract on the Intercontinental Exchange were little changed early Wednesday after Tuesday's relief rally following Monday's selloff to two-week lows. The market is grappling with the prospect of less oil demand amid reaction to spiking omicron cases, an energy crisis in Europe and geopolitical flareups that could endure. A force majeure declaration by Libya's National Oil Company on Monday staved off a selloff sparked by increasing mobility restrictions in Europe in response to surging COVID infections, with the omicron variant found to infect at a rate 5.41 times higher than for the delta variant and to evade current vaccines, according to a Dec. 16 report from the Imperial College COVID-19 response team. A widening conflict in Libya that cuts off more exports would tighten the oil-demand balance against expectations, with Libyan oil production having averaged 1.14 million bpd in November, according to the most recent data available. Centers for Disease Control and Prevention on Monday said the omicron variant now accounts for 73% of new U.S. COVID cases, with the World Health Organization reporting that the new variant has been found in 43 states in nearly 90 countries globally. The International Energy Agency earlier this month cut its global oil demand outlook by 100,000 barrels per day (bpd) for both 2021 and 2022 because of surging COVID cases, noting in particular that a recovery in jet fuel demand would be most hobbled. Travel restrictions proliferate through Europe. Separately, natural gas and electricity prices in Europe are again reaching record highs as another cold front descends on parts of the continent with gas reserves low and Russian oil flow running below its historic rate. Russia accounts for 35% to 40% of Europe's gas supply. Critics say Russia is willfully holding back gas supply, which it denies. Overnight, Russian President Vladimir Putin said the West has taken an "aggressive line" regarding Ukraine that could force Moscow to make a tough response, according to Reuters. Putin said Russia has nowhere to run, noting Ukraine sits at its border. While rejecting accusations from Ukraine and the United States that Russia is planning an invasion of Ukraine, Moscow has amassed tens of thousands of troops at the border. NYMEX February West Texas Intermediate futures were little changed at $71.20 barrel (bbl), and ICE February Brent was trading near $74 bbl. NYMEX January ULSD futures were flat at $2.2580 gallon, and the January RBOB contract softened to $2.1450 gallon.
WTF WTI? Oil Spikes After Biggest Gasoline Inventory Build In 6 Months -- Bwuahahaha... WTI reversed its loss on the big gasoline build and is now screaming higher... One possible reason is, as Bloomberg reports, total crude stockpiles, including both commercial inventories and crude in the Strategic Petroleum Reserve, fell by 7.25 million barrels in the week to Dec. 17. The withdrawal of 2.5 million barrels from the SPR came on top of a 4.7 million barrel drop in commercial stockpiles. That’s the biggest drop in total crude stockpiles since July. Oil prices continued their exuberant 'Omicron Schmomicron' rebound overnight with WTI back above $71.50 ahead of this morning's official inventory and production data. Amid utter carnage in the European power markets, US energy markets remain relatively calm.“Data remains supportive, with supply outages, elevated flight activity and congestion on roads resulting in still falling inventories,” “Concern on new mobility restrictions impacting oil demand as a result of the omicron variant is keeping prices in check, however.”DOE
- Crude -4.715mm (-3.15mm exp, API -3.67mm)
- Cushing +1.463mm
- Gasoline +5.533mm - biggest build since June
- Distillates +396k
After a big draw last week, analysts expected another sizable drop in US crude stocks and they were right as crude inventory drew down 4.7mm barrels (more than the 3.15mm expected). Cushing stocks rose for the 6th straight week. Most notably, Gasoline stocks surged higher last week by 5.5mm barrels - the biggest weekly build since June...
Oil prices rise on inventory drawdown, though Omicron caution lingers -- Oil prices rose on Wednesday on fears of tight supply and a drawdown in U.S. inventories, despite worries about the likely hit to economic activity from the spread of the Omicron coronavirus variant. U.S. inventories fell more than expected, with crude stocks down by 4.7 million barrels, though that is in part due to year-end tax considerations that encourage companies not to store crude barrels. Brent crude futures settled $1.31, or 1.77%, higher at $75.29 a barrel after gaining 3.4% in the last session. U.S. West Texas Intermediate (WTI) crude futures advanced $1.64, or 2.3%, to settle at $72.76 per barrel. "Because supplies are below average across the board, there's not a lot of room for error." Gasoline storage rose sharply in the most recent week, fanning worries that U.S. travellers were abruptly changing plans, potentially hurting demand in the world's largest gasoline consumer. Coronavirus-driven mobility curbs across the globe added to fears of a drop in fuel demand. Germany, Ireland, the Netherlands and South Korea are among countries that have reimposed partial or full lockdowns or other social distancing measures in recent days. It is still unclear whether the Omicron variant is more deadly than Delta, the strain which has been dominant in recent months. A study from South Africa suggested the virus was less likely to send people to the hospital than Delta as governments worldwide try to contain the rapid spread of the variant. Moderna Chief Executive Officer Stephane Bancel said on Tuesday that the vaccine manufacturer does not expect any problems in developing a booster shot to protect against the Omicron variant and could begin work in a few weeks. Pfizer, one of the primary manufacturers of COVID-19 vaccines, said its antiviral COVID-19 pill was approved for at-home use. On the supply side, investors are looking ahead to a meeting of the OPEC+ producers group on Jan. 4. With the growing production issues in Russia and various others in the Atlantic Basin, it is likely that Middle Eastern producers could push for a continuation of monthly quota increases
Oil Futures Up, RBOB at 1-Month High After Baytown Explosion -- Oil futures nearest delivery on the New York Mercantile Exchange were trading near fresh one-month highs and Brent crude on the Intercontinental Exchange at a two-week high late Thursday morning, with the RBOB contract leading the advance following an explosion and fire at a gasoline unit at ExxonMobil's Baytown refinery near Houston. Early reports indicate the gasoline unit was closed Wednesday to investigate a leak ahead of the overnight incident at the 584,000 barrels per day (bpd) refinery, the country's second largest. Four people were reported injured. The market was taking the news in stride with January RBOB futures initially rallying overnight to a $2.2089 gallon four-week high on the spot continuous chart before paring the advance, trading up 2.1 cents near $2.1890 gallon late morning. On Wednesday, the Energy Information Administration reported a 5.533 million barrel (bbl) increase in nationwide gasoline stocks for the week ended Dec. 17, lifting inventory to 224.118 million bpd, the highest stock level since the end of the third quarter. NYMEX January ULSD futures, which settled above resistance at the $2.2780 50% retracement point for the fourth quarter downtrend for the first time in December on Wednesday, added to gains early Thursday, up about 1 cents at $2.3178 gallon after trading at a fresh $2.3345 gallon four-week high on the spot continuous chart. EIA reported a modest 396,000 bbl build in distillate inventories for the week ended Dec. 17, with stocks at 124.154 million bbl, 7.1 million bbl or 5.4% below the three-year average. February West Texas Intermediate on NYMEX was up modestly near $73 bbl, having traded earlier in the session at a fresh four-week spot high at $73.33 bbl, continuing to hold below the $73.72 trendline for the uptrend from the November 2020. EIA on Wednesday reported a steep 4.715 million bbl draw in commercial crude inventory in the United States for the week ended Dec. 17, lowering the stock level to a 423.571 million bbl 11-week low, while 37.2 million bbl or 8.1% below the three-year average. February Brent futures were also up modestly, trading at $75.60 bbl and near a $75.79 fresh two-week high. A firmer U.S. dollar, trading 96.155 in index trading, is also limiting the upside for WTI futures. Dollar strength follows macroeconomic news Thursday morning that was largely supportive for the U.S. economy. The Census Bureau this morning reported durable goods orders surged 2.5% in November that was above market expectations for a 1.5% increase, while October's initial reading of a 0.5% decline was revised up to a modest 0.1% gain. Durable goods orders have now increased in six of the last seven months.
Oil prices stable as positive COVID news balances curbs - Oil prices were broadly stable on Thursday as signs that the worst effects of the Omicron variant might be more containable than previously feared were countered by new COVID-19 restrictions amid surging infections. Brent crude futures advanced 2.07%, or $1.56, to $76.85 per barrel, after a 1.8% gain in the previous session. U.S. West Texas Intermediate (WTI) crude futures settled $1.03, or 1.4%, higher at $73.79 a barrel after jumping 2.3% in the previous session. "Oil's direction is entirely reliant on Omicron headlines, and as long as they stay more contagious but less virulent, oil's rally is likely to continue, with intra-day ranges exacerbated by thin liquidity," said OANDA market analyst Jeffrey Halley. Both contracts are set for a third straight day of gains. So far this year, Brent has risen around 46% and WTI 50%. The big gains on Wednesday were partly spurred by a larger-than-expected drawdown in U.S. crude stockpiles last week. The United States authorized Pfizer Inc's antiviral COVID-19 pill for people aged 12 and older, the first oral and at-home treatment as well as a new tool against the fast-spreading Omicron variant. Meanwhile, AstraZeneca said a three-dose course of its COVID-19 vaccine was effective against Omicron, citing data from an Oxford University lab study. On the flip side, governments reimposed a range of restrictions to slow the spread of Omicron. The Chinese city of Xian on Wednesday ordered its 13 million residents to stay home, while Scotland imposed gathering limits from Dec. 26 for up to three weeks, and two Australian states reimposed mask mandates. The Organization of the Petroleum Exporting Countries (OPEC), Russia and allies have left the door open to reviewing their plan to add 400,000 barrels per day of supply in January.
Oil up 4% on Week in Volatile, Omicron-Impacted Trade - Oil prices jumped more than 4% on the week, rebounding from last week’s slump, as energy markets were caught in a wave of year-end volatility worsened by Covid’s Omicron variant. West Texas Intermediate, the benchmark for U.S. crude, settled Thursday's trade up $1.03, or 1.4%, at $73.79 per barrel. That put WTI up 4.1% for the week, versus a 1.1% decline last week and a 8.2% gain the week before that. London-traded Brent, the global benchmark for oil, settled up $1.56, or 2.1%, at $76.85 a barrel. For the week, Brent showed a gain of 4.5%, just like WTI, and following a pattern of volatility similar to the U.S. crude benchmark in previous weeks. Thursday is the last trading day of this week, with U.S. markets closed on Friday in observation of Saturday’s Christmas holiday. Oil prices were down about 6% between Friday and Monday combined as markets reacted to news of the Omicron becoming the dominant strain of the coronavirus in most parts of the world, including the United States. Major U.S. cities, including New York, Los Angeles and Chicago, announced mass cutbacks in social activity earlier this week and introduced various new restrictions to deal with the Covid variant. President Joe Biden had also warned that Americans who do not get vaccinated for the virus faced “a winter of severe illness and death”. Those cautions aside, a general spike in Covid infections, hospitalizations — and, in some countries, even deaths — had triggered broad risk aversion. Much of the bearish mood, however, dissipated in the past 48 hours as evidence increasingly showed the Omicron to be a less lethal form of Covid despite its fast-spreading ability. The US Food and Drug Administration’s emergency authorization on Thursday for Pfizer’s Paxlovid pill — the world’s first for Covid — also boosted risk appetite.
