Strategic Petroleum Reserve at a new 19 year low; total crude supplies near a 10 year low; gasoline production & gasoline demand fall by most in 21 months; gasoline supplies rise by most in 21 months; distillate supplies rise by most in a year
oil prices rose for the third consecutive week on political unrest and/or production difficulties among several OPEC allied producers....after rising 1.9% to $75.21 a barrel last week as oil traders became convinced that Omicron posed little risk to oil demand, the contract price for US light sweet crude for February delivery opened 47 cents higher on Monday amid reports that OPEC and Russia-led producers expected that the omicron disruption to global oil demand would be isolated to the first quarter, and later settled 87 cents higher at $76.08 a barrel on hopes of a further demand recovery in 2022, despite the cartel's readiness to agree to another output increase, amid skepticism about whether OPEC and its allies could successfully raise output as much as they intended...oil prices continued higher early Tuesday after the technical committee for OPEC signaled tighter supply-demand fundamentals for the first quarter, and as unplanned supply disruptions in a number of smaller oil producers, including Libya and Ecuador, offset a tsunami of Omicron infections in major oil-consuming countries. with oil finishing 91 cents higher at a six week high of $76.99 a barrel as OPEC and Russia agreed to stick with their planned production increase for February, based on indications that the Omicron variant would have only a mild impact on demand....oil prices opened higher again on Wednesday and rallied to $78.58 a barrel after the American Petroleum Institute reported a larger-than-expected drop in U.S. commercial crude oil inventories during the final week of 2021 accompanied by massive builds in gasoline and distillates fuel supplies, signs of Omicron-led destruction to domestic fuel demand, but then slipped back below $78 after the EIA reported the biggest build in gasoline inventories since April 2020 amid plunging fuel demand, but still settled with a gain of 86 cents on the day at $77.85 a barrel, extending gains even after OPEC+ producers stuck to an agreed output target increase for February output....oil slipped from that 6 week high in early Thursday trading, as fuel supplies had surged amid declining demand, while the draw in U.S. crude inventories was smaller than expected, but rallied on escalating unrest in major oil producer Kazakhstan and supply outages in Libya to settle $1.61, or 2.1%, higher at $79.46 a barrel, after earlier touching a session high of $80.24....oil prices rose again early Friday and briefly traded a dollar higher, as ongoing protests in Kazakhstan prompted fears of a disrupted crude supply from the OPEC and its allies (OPEC+), along with decreased production in Libya, where the political situation continued to deteriorate, but turned downward following a disappointing employment report in the US that heightened concerns over a laggard recovery in the world's largest consuming economy to finish trading 56 cents lower at $78.90 a barrel, but still finished with a gain of 4.9% on the week, and at the highest level since late November...
natural gas prices also finished higher in seesaw trading this week amid vacillating weather forecasts....after rising 2.8% to $3.730 per mmBTU last week on an outbreak of polar air, the contract price of natural gas for February delivery rose 8.5 cents, or 2.3%, to $3.815 per mmBTU on Monday after production fell over the New Years weekend because cold weather had frozen some production wells in Texas, New Mexico and in Colorado, reminding traders of what can happen when temperatures drop...but that gain was more than reversed on Tuesday as prices tumbled 9.8 cents to $3.717 per mmBTU after midday forecasts called for less cold weather and lower heating demand over the next two weeks than had previously been expected...however, strength in cash prices and expectations for ongoing blasts of frigid air over swaths of the Lower 48 pushed natural gas prices upwards on Wednesday, as the February contract settled 16.5 cents higher on the day at $3.882 per mmBTU...however, natural gas prices stumbled again on Thursday, after the EIA's weekly inventory report showed ample supplies and relatively modest early-winter heating demand, with gas shedding 7.0 cents to finish at $3.812 per mmBTU...but prices were rising again on Friday and finished 10.4 cents higher at $3.916, as a major winter storm blanketed the Northeast in snow, driving overall gas demand to its highest in a day since hitting a record in 2019 and left natural gas prices 5.0% higher on the week..
The EIA's natural gas storage report for the week ending December 31st indicated that the amount of working natural gas held in underground storage in the US fell by a modest 31 billion cubic feet to 3,195 billion cubic feet by the end of the week, which left our gas supplies 154 billion cubic feet, or 4.6% below the 3,349 billion cubic feet that were in storage on December 31st of last year, but 96 billion cubic feet, or 3.1% above the five-year average of 3,099 billion cubic feet of natural gas that have been in storage as of the 31st of December over the most recent five years....the 31 billion cubic foot withdrawal from US natural gas working storage for the cited week was quite a bit less than the average forecast for a 50 billion cubic foot withdrawal from a S&P Global Platts' survey of analysts, and was far less than the 127 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2020, and also far less than the average withdrawal of 108 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 31st showed that despite a major shift of “unaccounted for crude oil” from demand to supply, a concurrent drop in our oil imports meant we still needed to pull oil out of our stored commercial crude supplies for the sixth week in a row and for the 22nd time in the past thirty-two weeks….our imports of crude oil fell by an average of 875,000 barrels per day to an average of 5,884,000 barrels per day, after rising by an average of 565,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 375,000 barrels per day to an average of 2,554,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 3,330,000 barrels of per day during the week ending December 31st, 500,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude oil from US wells was reportedly unchanged at 11,800,000 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 15,130,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,867,000 barrels of crude per day during the week ending December 31st, an average of 163,000 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 499,000 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 238,000 barrels per day less than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+238,000) 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...and since last week’s EIA fudge factor was at (-631,000) barrels per day, that means there was a 869,000 barrel per day difference between this week's error and the EIA's crude oil balance sheet error from a week ago, and hence the week over week supply and demand changes indicated by this week's report are just about meaningless.....however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
This week's 499,000 barrel per day decrease in our total crude oil inventories left them at 1,011,533,000 barrels, the lowest level since February 17th 2012, or nearly at a 10 year low....this week's oil inventory decrease came as 306,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 192,000 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....including the drawdowns from the Strategic Petroleum Reserve under such politically motivated programs, a total of 57,980,000 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 593,682,000 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 6,327,000 barrels per day last week, which was still 16.7% more than the 5,421,000 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 changed at 11,800,000 barrels per day even as the EIA's rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 11,400,000 barrels per day, because Alaska’s oil production was 10,000 barrels per day lower at 459,000 barrels per day and hence added 100,000 barrels per day to the reported rounded national production total (by the EIA's math)...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 9.9% below that of our pre-pandemic production peak, but 40.0% 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 89.8% of their capacity while using those 15,867,000 barrels of crude per day during the week ending December 31st, up from a utilization rate of 89.7% the prior week, but still lower than the historical utilization rate for late December refinery operations…the 15,867,000 barrels per day of oil that were refined this week were 10.4% more barrels than the 14,287,000 barrels of crude that were being processed daily during the pandemic impacted week ending January 1st of 2021, but 9.4% less than the 16,897,000 barrels of crude that were being processed daily during the week ending January 3rd. 2020, when US refineries were operating at what was then a more seasonal 93.0% of capacity...
Even with the increase in oil being refined this week, the gasoline output from our refineries was quite a bit lower, decreasing by 1,607,000 barrels per day to 8,506,000 barrels per day during the week ending December 31st, the largest drop in 21 months, after our gasoline output had increased by 171,000 barrels per day over the prior week.…this week’s gasoline production was still 6.2% more than the 8,010,000 barrels of gasoline that were being produced daily over the same week of last year, but 4.2% less than the gasoline production of 8,887,000 barrels per day during the week ending January 3rd. 2020, when gasoline output had also seen a steep drop at year end….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 30,000 barrels per day to 4,965,000 barrels per day, after our distillates output had increased by 83,000 barrels per day over the prior week…after those increases, our distillates output was 3.8% more than the 4,785,000 barrels of distillates that were being produced daily during the week ending January 1st of 2021, but 6.5% less than the 5,310,000 barrels of distillates that were being produced daily during the week ending January 3rd. 2020...
Even with the big drop in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the fourth time in thirteen weeks, and by the most in 21 months, increasing by 10,128,000 barrels to 232,787,000 barrels during the week ending December 31st, after our gasoline inventories had decreased by 1,459,000 barrels over the prior week...our gasoline supplies increased this week because the amount of gasoline supplied to US users decreased by 1,552,000 barrels per day to 8,172,000 barrels per day, the largest drop in implied demand in 21 months, and because our imports of gasoline rose by 164,000 barrels per day to 596,000 barrels per day, while our exports of gasoline fell by 144,000 barrels per day to 470,000 barrels per day…after this week’s big inventory increase, our gasoline supplies were still 3.4% lower than last January 1st's gasoline inventories of 241,081,000 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 sixth time in nineteen weeks and by the most in 51 weeks, rising by 4,418,000 barrels to 126,846,000 barrels during the week ending December 31st, after our distillates supplies had decreased by 1,726,000 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 312,000 barrels per day to 3,739,000 barrels per day, and because our exports of distillates fell by 481,000 barrels per day to 811,000 barrels per day, and because our imports of distillates rose by 55,000 barrels per day to 217,000 barrels per day....but after twenty-six inventory decreases over the past thirty-nine weeks, our distillate supplies at the end of the week were 19.9% below the 158,419,000 barrels of distillates that we had in storage on January 1st of 2021, and about 16% below the five year average of distillates inventories for this time of the year…
Meanwhile, with the big drop in our oil imports, our commercial supplies of crude oil in storage fell for the 15th time in 22 weeks and for the 34th time in the past year, decreasing by 2,144,000 barrels over the week, from 419,995,000 barrels on December 24th to 417,851,000 barrels on December 31st, after our commercial crude supplies had decreased by 3,576,000 barrels over the prior week…after this week’s decrease, our commercial crude oil inventories fell to about 8% below the most recent five-year average of crude oil supplies for this time of year, but were still around 28% above the average of our crude oil stocks as of year end 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 31st were 13.9% less than the 485,459,000 barrels of oil we had in commercial storage on January 1st of 2021, and are now 3.1% less than the 431,060,000 barrels of oil that we had in storage on January 3rd of 2020, and also 5.0% less than the 439,738,000 barrels of oil we had in commercial storage on January 4th 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, rose by 8,819,000 barrels this week, from 1,779,614,000 barrels on December 24th to 1,788,433,000 barrels on December 31th, but still left our total inventories at the 2nd lowest level since August 29th, 2014.....
This Week's Rig Count
The number of drilling rigs active in the US increased for the 57th time over the past 68 weeks during the week ending January 7th, but still remained 25.9% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs running in the US increased by two to 588 rigs this past week, which was also 228 more rigs than the pandemic hit 360 rigs that were in use as of the January 8th report of 2020, but was also still 1,341 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 was up by 1 to 481 oil rigs during this week, after they had been unchanged during the prior week, and there are now 206 more oil rigs active now than were running a year ago, even as they still amount to just 29.9% 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 was up by 1 to 107 natural gas rigs, which was also up by 23 natural gas rigs from the 84 natural gas rigs that were drilling during the same week a year ago, but still only 6.7% 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 up by 1 to 16 rigs this week, with fifteen of this week's Gulf rigs drilling for oil in Louisiana waters and another rig drilling for oil in Alaminos Canyon, offshore from Texas....that's one less Gulf rig than the 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…since there is not any drilling off our other coasts at this time, nor was there a year ago, the Gulf rig counts are equal to the national offshore totals for both years....but 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 down from two a year ago..
The count of active horizontal drilling rigs was up by 2 to 532 horizontal rigs this week, which was also 212 more than the 320 horizontal rigs that were in use in the US on January 8th of last year, but still 61.3% less than the record 1,374 horizontal rigs that were deployed on November 21st of 2014....at the same time, the directional rig count was up by 3 to 33 directional rigs this week, and those were also up by 11 from the 22 directional rigs that were operating during the same week a year ago….on the other hand, the vertical rig count was down by 3 to 23 vertical rigs this week, but those were still up by 5 from the 18 vertical rigs that were in use on January 8th of 2021….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of January 7th, the second column shows the change in the number of working rigs between last week’s count (December 31st) and this week’s (January 7th) count, the third column shows last week’s December 31st 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 8th of January, 2021..
the Louisiana rig count was up by 3 this week with the addition of two Gulf of Mexico rigs in the state's offshore waters, and another rig in the northern part of the state, in an area we'd usually associate with the Haynesville shale, but apparently not targeting that formation this time...on the other hand, the Texas rig count was down by three with the shut down of a Gulf rig that had been drilling for oil in Alaminos Canyon, offshore from the state, and the removal of two rigs that had been drilling in Texas Oil District 8, which is the core Permian Delaware....since the Texas Permian rig count was thus down by two while the national Permian rig count was down by just one, the rig that was added in New Mexico had to have been deployed in the western Permian Delaware to balance the national total....while we can see there were two rigs pulled out of the Cana Woodford, the Oklahoma rig count remained unchanged, which means that two rigs were added in an Oklahoma basin that Baker Hughes doesn't track...in addition, the rig added in the Denver-Julesburg Niobrara chalk appears to have been set up in Wyoming, since the Colorado rig count was unchanged...and finally, this week's new natural gas rig was set up in a basin that Baker Hughes doesn't track, and hence doesn't show up in the table above...
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Utica Shale Saves Eastern Ohio Counties from COVID Recession | Marcellus Drilling News - Economists are still analyzing the impact of the coronavirus pandemic from 2020, let alone assessing impacts from 2021. Cleveland State University researchers have run the numbers and have discovered something interesting. Of Ohio’s 88 counties, only 18 grew their economies in 2020. Of those 18, two counties stood head and shoulders above the rest for increases in economic activity. Both counties have something in common: Utica Shale drilling.The two counties that soared in 2020 due to Utica drilling were Monroe and Harrison. Other Utica-drilling counties were also on the list of 18 counties improving in 2020, including Belmont and Jefferson. Beginning to see a trend here?We laugh at anti-fossil fuel fools who yammer on that “there is no increase in jobs or economic activity from shale oil and gas drilling.” What planet do they live on?! The Utica pulled Ohio eastern counties’ bacon out of the fire in 2020, and (we suspect) in 2021 as well.Hydraulic fracturing has buoyed the economy in eastern Ohio.Two small eastern Ohio counties in the heart of Ohio’s natural gas country posted the biggest economic gains among the state’s counties in 2020.The big gains in Harrison and Monroe counties came even as COVID-19 plunged most of Ohio’s 88 counties and its biggest metro areas into a brief, but steep, recession. Only 18 counties had growth last year.Harrison and Monroe counties each posted a 20.5% increase in their economy in 2020, according to federal data released this month.Both counties are small so even a minimal increase in the economy can produce big change.Monroe County’s economic activity was measured at $1.9 billion in 2020, while Harrison’s was measured at $1.6 billion.Both counties have benefited from the surge in natural gas and oil drilling in Appalachia over the past decade that has helped offset the decline in coal use.Total investment in the region has hit $93 billion from 2011 through 2020, according to Cleveland State University researchers who track oil and gas spending in the region. Monroe County also has benefited from the redevelopment of the old Ormet aluminum smelter site in recent years that includes the new natural gas power plant at the Long Ridge Energy Terminal, which one day could run on hydrogen as well as gas.Harrison County also is developing a power plant.Monroe County’s gain follows a 23.7% increase in 2019 and 7.7% in 2018.Other counties in Appalachia also were among the 2020 winners.The county in between Monroe and Harrison, Belmont, had the fifth-highest growth rate in 2020, 5.4%. That county also has benefited from the natural gas boom.The economy of Jefferson County, north of Belmont County and also a benefactor of the energy investments, grew by 5.6% in 2020.In the northwest part of the state, Paulding County posted a 7.7% growth rate, the third highest in Ohio.
$40M Penalty Proposed for Gas Pipeline Builder After Spill | Ohio News (AP) — Federal regulators have proposed a $40 million fine against the builder of a multistate natural gas pipeline, the second hefty penalty sought against the company within the past year. The Federal Energy Regulatory Commission accused the company of repeatedly using diesel fuel and other toxic substances while drilling under a river in Ohio four years ago. The proposed fine stems from an accidental spill of 2 million gallons (7.6 million liters) of drilling mud, some of which seeped into a protected wetland during construction. It comes after the commission last March proposed a $20 million fine against the company over the destruction of a historic farmhouse that stood in the pipeline’s path. Dallas-based Energy Transfer Partners denied having involvement in using the diesel fuel for drilling. The company and its subsidiary Rover Pipeline LLC built the twin pipelines to carry natural gas from Appalachian shale fields to Canada and states in the Midwest and the South. The 700-mile (1,126-kilometer) pipeline crosses much of Ohio and stretches from Michigan to West Virginia. The $4.3 billion project was completed in 2018 following court battles with landowners and state and federal regulators who delayed the work after drilling mud spills. The federal commission in December told Energy Transfer Partners and Rover Pipeline to explain why it should not pay a $40 million civil penalty for alleged violations related to a spill near the Tuscarawas River in northern Ohio’s Stark County. Regulators said Rover Pipeline intentionally and routinely used diesel fuel and other toxic substances and unapproved additives in drilling mud while it was installing the pipeline under the river. The violations were the result of a corporate culture that emphasized finishing the work quickly over complying with regulations, the commission said. Energy Transfer Partners said in a statement that the commission has no evidence that anyone at the company knew diesel fuel was being used and that it did not tell anyone to do so. It said a rogue employee from an independent subcontractor said under oath that he made the decision on his own and then tried to hide it. The company has cleaned up and restored the area and will seek to recover any fines from the contractor in charge of the drilling, said spokesperson Alexis Daniels. Energy Transfer Partners has until the middle of March to file a formal response with the commission. Last March, the commission proposed a $20 million fine against the company, accusing it of not being truthful about its intention to demolish a 170-year-old farmhouse it had purchased. That matter is still pending.
Hilcorp Applies for 3 New Permits in Columbiana County – Youngstown Business Daily -– video - Hilcorp Energy continues to explore its interests in the Utica Shale play in Columbiana County.
Three New Horizontal Wells Sought for Columbiana County – Youngstown Business Daily -– Houston-based Hilcorp Energy Co. continues to display interest in unlocking natural gas and oil from the Utica-Point Pleasant shale formation in Columbiana County. According to the Ohio Department of Natural Resources, the company has applied for permits to drill three new horizontal wells in Elkrun Township at the Wertz pad off Daner Road. The applications – filed on Dec. 28 – still need to be approved by ODNR. In 2021, Hilcorp was awarded 14 permits from ODNR…
Energy Transfer set to finish Mariner East pipeline in 2022 - Troubled Mariner East pipeline construction at Marsh Creek State Park in Chester County has restarted, leading Energy Transfer, the parent company of Sunoco Pipeline, to announce that it expects to finish the project in the first quarter of 2022. That announcement comes more than two years after the initial planned completion of the 350-mile-long natural gas liquids pipeline. Pennsylvania’s Department of Environmental Protection issued new permits allowing construction on the section of the pipe that had been halted since August 2020, after the company spilled between 21,000 and 28,000 gallons of drilling mud fluid into Marsh Creek Lake. That section is one of the last legs of the line left to be completed.The updated permits include a new route that allows open trench excavation rather than below-ground horizontal directional digging. Their approval came despite the filing of 48 criminal charges in October by the state Attorney General’s Office against the Texas-based company. From the outset, Mariner East’s construction has faced delays. It has caused dozens of drilling mud spills into wetlands and waterways across the state, led to dangerous sinkholes in Chester County, and polluted drinking water supplies across the entire length of the project. The company purchased at least five homes in Chester County after its work damaged the aquifer and created sinkholes. The DEP has issued more than 120 notices of violations to the company, which has paid more than $20 million in fines and assessments since construction began in February 2017. The Pennsylvania Public Utility Commission temporarily shut down the operation of the Mariner East 1 pipeline in 2018 over safety concerns. Local residents and politicians say construction of this final section of pipe should be halted, at least until the company completes a cleanup of Marsh Creek Lake.
Appalachian Natural Gas Output Growth Said Threatened by Long-term 'Uncertainties --Higher natural gas prices were a positive for natural gas producers in the Appalachian Basin in 2021, but ongoing “uncertainties” threaten the industry’s long-term growth prospects. “These include a number of challenges at the federal level being pushed by the Biden administration and some members of Congress, such as a punitive methane tax, and statewide issues such as Gov. Tom Wolf’s continued efforts to join the Regional Greenhouse Gas Initiative and a pair of rulemaking petitions by activist groups seeking to greatly increase the cost of well bonding,” President Daniel J. Weaver of the Pennsylvania Independent Oil and Gas Association (PIOGA) told NGI Last year Wolf joined fellow governors in New Jersey and New York to support a permanent ban on hydraulic fracturing in the Delaware River Basin.Weaver also said PIOGA is concerned about state and federal rulemakings to control volatile organic compounds and methane emissions, along with “continued opposition to pipeline expansion projects that limit our region’s ability to deliver natural gas to markets where it is needed.”Marcellus Shale Coalition (MSC) President Dave Callahan told NGI that natural gas development remains a major driver of economic growth and job creation in Pennsylvania.“There are more than 102,000 direct jobs tied to the natural gas and oil industry, supporting more than 480,000 jobs statewide when accounting for supply chain and ancillary positions,” he said.A proposed $6 billion natural gas-to-liquids fuel plant in Luzerne County could add to the list of shale-driven investments that have helped to bolster Pennsylvania’s economy, noted Callahan.He noted the industry has generated more than $2 billion in revenue for Pennsylvania since 2012 via impact fees that unconventional natural gas producers pay the state. Callahan’s reference to how Pennsylvania government coffers generate revenue from unconventional gas producers segue into his broader point that “policies matter.” He said “embracing additional domestic energy production and use” could alleviate the impact of volatile energy prices.
Repsol Acquires Marcellus Assets in Rockdale Bankruptcy - Repsol SA is bolting on acreage in the Marcellus Shale after successfully bidding for 43,000 net acres in Northeast Pennsylvania in a bankruptcy auction. The Spanish energy company has agreed to pay $222 million, including $2 million in debt, for Rockdale Marcellus LLC’s assets in Tioga, Lycoming and Bradford counties, according to court documents. The sale has been approved by the U.S. Bankruptcy Court for the Western District of Pennsylvania. Rockdale, which was formed through the acquisition of Shell plc’s Marcellus properties in northern Pennsylvania in 2017, filed for bankruptcy protection in September. Repsol has also reached a deal with UGI Energy Services LLC for gathering services on the properties, resolving a legal dispute between Rockdale and UGI. The 48,000 gross acres acquired in the sale produced 110 MMcf/d early last year, according to Rockdale. Repsol has factored the Marcellus into its 2021-2025 strategy, with plans to spend $600 million annually. Prior to the Rockdale acquisition, Repsol held 171,000 net acres in the Marcellus, mainly in Bradford, Susquehanna and Tioga counties. The company has focused on driving free cash flow and generating more value from its global exploration and production portfolio. It’s also focused on narrowing the portfolio by concentrating assets in key areas such as the Marcellus.
UGI expands Marcellus Shale gas pipeline network - In another sign of the ongoing demand for fossil fuels, UGI Corp., the Valley Forge energy company, is expanding its natural gas pipeline network in Pennsylvania’s Marcellus Shale region. UGI Energy Services LLC announced Tuesday that it will pay $190 million to acquire Stonehenge Appalachia, a 47-mile pipeline in Butler County that transports natural gas produced from local wells to interstate pipelines. The acquisition is UGI’s third deal in recent years that has expanded its footprint in the shale-gas region northeast of Pittsburgh. The largest deal was the $1.3 billion acquisition in 2019 of Columbia Midstream Group LLC, a 240-mile system in Butler, Armstrong, and Indiana Counties that includes the Big Pine pipeline. UGI last year also bought a 49% interest in the Pine Run Midstream system, which like the Stonehedge pipeline, is interconnected with the larger Big Pine system. Together, the three pipelines form what is known as a “midstream system,” which connects gathering pipelines linked to individual wells to big interstate pipelines, which deliver fuel to distant, large customers, including power plants and local utilities. “When we acquired the assets of Columbia Midstream Group in 2019, we committed to additional investments to build or buy quality systems in the region,” Robert F. Beard, UGI’s executive vice president of natural gas, global engineering, construction and procurement, said in a statement. He said the Stonehenge acquisition “demonstrates our commitment to the Appalachian basin,” which produced record volumes of natural gas in the first half of 2021. Midstream pipeline systems, which have long-term customers under contract and largely operate outside public view, are stable generators of cash flow for companies such as UGI. “This investment is consistent with our strategy of delivering reliable earnings growth while continuing to rebalance our business activities with increasing investments in natural gas and renewables,” Roger Perreault, UGI’s president and chief executive, said in a statement. UGI also owns several gas and electric utilities, and distributes propane through its AmeriGas subsidiary. Its UGI Energy Services subsidiary operates about a dozen gas pipelines in Pennsylvania, Ohio and West Virginia, as well as several liquified natural gas production plants, gas power plants, a gas storage facility and 21 solar farms. It was also the operator and 20% owner of the unsuccessful $1 billion PennEast Pipeline project, which was scuttled last year after public opposition and New Jersey regulators’ vow to block its construction to its terminus near Trenton. Despite pressure on policymakers to transition away from production of fossil fuels to curtail emissions of greenhouse gases, Pennsylvania operators have continued to produce prodigious amounts of natural gas from shale formations since the development of hydraulic fracturing technology, or fracking. Pennsylvania produces about one-fifth of the nation’s natural gas, and is the second largest gas producer behind Texas. Its wells produced a record 7.1 trillion cubic feet of natural gas in 2020, and were on pace to set a new record last year, according to production reports posted through October by the U.S. Energy Information Administration.
New York City Natural Gas Price Jumps Fivefold From Thursday – A fast-moving winter storm on the East Coast is driving up demand for natural gas, and causing New York City prices to quintuple since Dec. 30. The spot prices mark the strongest start to a new year since 2018, according to New York-based hedge fund E360 Power LLC and broker data compiled by Bloomberg. The spot prices mark the strongest start to a new year since 2018, according to New York-based hedge fund E360 Power LLC and broker data compiled by Bloomberg. An unusually warm December “has bred a lack of respect for cold weather,” and the dropping temperatures are causing a scramble to secure more gas supplies, said James Shrewsbury, co-founder of E360 Power. “This isn’t crazy cold yet.” Natural gas for delivery on Monday in New York City was $20 per million British thermal units in trading this afternoon, the strongest prices for the start of a year in since they soared to $138 on Jan. 4, 2018.
New timeline: Nearly 100 S.I. families in NYCHA complex will wait until spring to get gas turned back on - -- An entire holiday season without a stove or oven to cook meals; this is the reality for 96 families in Stapleton, who haven’t had cooking gas since March of this year. It may be spring before residents of 181 Gordon St. in the Stapleton Houses can use their stoves and ovens again, according to the New York City Housing Authority (NYCHA), which owns and manages the apartment complex. A NYCHA spokesperson told the Advance/SILive.com on Tuesday that the construction work necessary to restore the gas is “expected to begin in early February and it will take approximately three months until the gas can be restored.” The spokesperson noted that the timeline is considered “tentative.” In the meantime, NYCHA has given residents one hot plate and one slow cooker per household to make due, according to the agency
Eastern Generation scuttles natgas plans in NYC --Eastern Generation LLC, which accounts for nearly 18% of New York City’s power generation capacity, is withdrawing its application to regulators to repower the Gowanus Generating Station with gas turbines. Instead, the company plans to install 350 MW of energy storage solutions. “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,” said CEO Mark Sudbey. The move comes weeks after New York City’s city council voted to ban natural gas hookups in new buildings starting at the end of 2027. For buildings up to six stories tall, the ban would take effect at the end of 2023. Environmental lawyer Ramond Pomeroy told NGI that new natural gas infrastructure is unlikely in New York state. He said in October power plants in Astoria, Queens and Orange County had their permits rejected by regulators. In both cases, he said, “these were existing natural gas power plants looking to upgrade to more efficient units. And the state rejected both those permits because it was not consistent with the state’s climate goals.”
Lack of gas infrastructure sends New England’s power prices soaring --Electricity prices in New England jumped on Tuesday as a frigid start to the day spurred demand when the cost of natural gas used to fuel power plants soared. New England is frequently the most sensitive region to gas-supply constraints because it’s geographically at the end of the massive U.S. pipeline network. Attempts to build more pipelines to increase the flow have failed, and the region has to compete with places like Europe and Asia to lure cargoes of the fuel. Real-time power prices on the six-state grid in the U.S. Northeast averaged $141.90 a megawatt-hour as of 11 a.m., up fourfold from the same period on Monday, according to ISO New England data. Temperatures were at about 24 degrees Fahrenheit (-4 Celsius) in Boston at 11 a.m., spurring heating demand. Power is also more expensive this week because of a jump in natural gas prices, the main fuel for power plants. Spot gas prices on Enbridge’s Algonquin system that serves New England jumped 88% on Monday from the prior trading day.
Appalachia gas flows shift north, following higher prices - Larger spreads between spot gas prices in the US Northeast and Southeast has helped shift the direction of flows from Appalachia since Jan. 1, with higher prices in New England and New York attracting more molecules at the expense of southbound flows.Northbound flows from Appalachia have increased nearly 40% since Jan. 1 to reach 9.4 Bcf on Jan. 3, data from S&P Global Platts Analytics shows. This is more than 800 MMcf/d, or 9%, higher than the December average.Cash Algonquin city-gates was trading up $5.08 at $10.57/MMBtu in Jan. 3 trading for next-day flows, according to Platts preliminary settlement data. Other regional spot gas prices moved in a $7-9/MMBtu range.Iroquois, receipts and Niagara were the region’s sole hold-outs from the materially upward trend, likely reflecting how inflows from Canada nearly doubled Jan. 3 to 1.6 Bcf from Jan. 1 levels.Total Northeast gas demand across all sectors rose more than 9 Bcf/d, or 45%, since Jan. 1 to reach 29.5 Bcf Jan. 3, according to Platts Analytics data.Colder temperatures drove the increase, breaking a 10-day stretch of above-average temperatures and sluggish demand Dec. 24 – Jan. 2. The average Northeast temperature slid more than 20 degrees to 30 degrees Fahrenheit Jan. 3 from 53 F on Jan. 1, according to Platts Analytics and CustomWeather data.Flow data from Platts Analytics shows that Northeast production outflow capacity utilization to the Southeast fell to 4.9 Bcf Jan. 3, down from 5.2 Bcf Jan. 1 and a prior seven-day average of 5.2 Bcf/d (Dec. 27-Jan. 2).The lower outflow capacity utilization comes despite elevated Southeast gas demand, with Platts Analytics data showing materially higher residential-commercial and gas-fired power demand between Jan. 1 and Jan. 3, with further increases projected in the near term.Southeast res-comm demand increased 2.4 Bcf, or 75%, to 5.6 Bcf Jan. 3 from Jan. 1 levels, while gas-fired power demand rose 1.7 Bcf, or 19%, to 10.4 Bcf Jan. 3 from Jan. 1.Regional res/com demand is expected to jump around 650 MMcf/d on Jan. 4 and remain at the higher level Jan. 5. Similarly, Southeast gas-fired demand was projected to remain above 10 Bcf/d through Jan. 5.One driving factor of lower Northeast-to-Southeast capacity utilization despite higher Southeast gas demand could be the lukewarm Southeast prices.Cash Henry Hub fell to $3.58/MMBtu at preliminary settlement on Jan. 3, with other Southeast spot gas prices trading at a similar level of $3.40-$3.70/MMBtu. Regional spot gas prices weakened upon unusually mild temperatures in December that kept overall gas demand low. Cash Henry Hub averaged $3.71/MMBtu during December, down from $5.03/MMBtu in November.
State Appeals Court Dismisses Legal Challenge To Weymouth Gas Compressor – The State Appeals Court is throwing out yet another attempt to close or halt the natural gas compressor station in Weymouth. The court has dismissed a lawsuit filed by the group known as the “Fore River Residents Against The Compressor StationGroup.” The court ruled that the citizens group did not have a right to a hearing or a review of state approval for the project. The $100 million compressor was built to pump natural gas through Weymouth into Maine and Canada. It officially went online in January after neighbors spent years protesting the project citing health and safety risks. Despite several unplanned releases of natural gas over the last year and a half, the facility, which is run by Enbridge, stands by its safety standards.
GlobalData: Natural gas production growth in Appalachia | LNG Industry - Natural gas production from the US’s Marcellus and Utica shale plays is forecast to cross the 42 billion ft3/d mark by 2025, according to GlobalData – assuming gas prices stay above US$3.5 per 1 million Btu. 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 cancelled 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 billion ft3/d 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 11 gas pipelines planned to be built in Pennsylvania, Ohio, and West Virginia by 2023 will be able to support a mere 41 billion ft3/d of natural gas flowing capacity.”Doh adds: “With respect to 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 billion ft3/d 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 billion ft3/d, and, currently, the pool of LNG approved projects totals 26.3 billion ft3/d. 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.”
Ritchie County Economic Development Authority awarded $900K over wrongful trespassing by developer - Parkersburg News— The Ritchie County Economic Development Authority was awarded over $900,000 in damages last month against a Clarksburg developer for wrongful trespassing. In July 2002, Ron Lane, president and owner of Ronald Lane Inc., asked the EDA for help to obtain grant funding for a water and sewer extension on his property along U.S. Route 50 near Ellenboro, according to a press release from Windom Law Offices PLLC, Harrisville. Lane also asked members of the EDA to help him gain approval from the West Virginia Department of Transportation for “a break in the controlled access of Route 50 and the installation of a turning lane along the west-bound lane of the highway onto its property,” the release said. In exchange for the help, Lane claimed he would develop “several commercial attractions” on the property including a hotel, swimming pool, restaurant, convenience store, gas station, fast food restaurant, car wash, a retail strip mall and a tractor equipment sales store, according to the release. Instead of the proposed commercial retail project, RLI developed the Ritchie Center site into a pipeline storage yard which was leased to Dominion Energy.” From 2011 through 2016, RLI used the site for fracking and leased it for oil and gas industry purposes, the release said. RLI received $3,000 per acre per month for a term of three years, totaling more than $2.4 million, $1.166 million of which was paid to lease the 10.8 acres owned by the EDA. “Lane did not notify the RCEDA of the lease agreement or payment,” the release said. “He testified that he needed the advance payment to pay the $3 million development costs required to make the Ritchie County Industrial Park site lease property usable by the lessee, Columbia Gas.” The release said Lane said his company did site development work on the lease property and “RLI failed to produce the paid invoices to justify such expenses.” In February 2017, Lane and his son came to an EDA board meeting and asked for the re-conveyance of the 10.8 acre parcel of land, which Haught said was still being used as collateral for the loan intended for the water and sewer project, the release said. “Lane claimed the 10.8 acres ‘reverted’ to him because the RCEDA had not obtained additional government funding from the WVDOH for a separate access road to the adjacent Ritchie County Industrial property, which was vacant at the time,” the release said. Lane warned the RCEDA board that unless they deeded the 10.8 acres back to his company, he ‘would call in the big dog lawyers’ and take it back,” the release said. Attorneys from two law firms contacted the EDA’s counsel to demand the return of the land to RLI and after attempts to negotiate, a declaratory judgment was filed on behalf of the RCEDA against RLI in July 2018. “This is simply a case of Ron Lane wanting to eat his cake and have it, too,” Rod Windom of Windom Law Offices, PLLC in Harrisville, said. The suit required proof of the deed transfer for the 10.8 acres from RLI to the EDA “and to award it damages plus interest for the lease monies which were improperly paid to RLI,” the release said. Lane appeared before Third Judge Circuit Court Judge Timothy Sweeney and a six-person jury last month. “The RCED has filed a post-trial motion for the award of pre-judgment interest on the amount of the jury verdict from 2017 until the verdict,” Scott A. Windom, the EDA’s lead trial counsel said. “That was the amount of time during which RLI enjoyed the use and benefit of the RCEDA’s money and those dollars should be restored to the plaintiff. If granted, that interest will increase the total award to more than $1.2 million.”
West Virginia approves permit for 300-mile controversial natural gas pipeline - West Virginia on Friday granted a key permit for the construction of a controversial pipeline stretching for more than 300 miles into Virginia. The state's Department of Environmental Protection (DEP) granted a water protection permit for the construction of the Mountain Valley Pipeline (MVP), certifying the natural gas pipeline has met state standards for water quality.The news follows Virginia's certification of a water quality permit for the project earlier this month, but that move is being challenged at the U.S. 4th Circuit Court.The project has met stiff resistance in West Virginia from environmental opponents. Peter Anderson, the Virginia policy director for Appalachian Voices, an organization opposed to the pipeline, said the state has a "wretched environmental record" and that he did not trust the awarded permit met sufficient environmental standards."The West Virginia’s DEP has regrettably granted MVP new permission to pollute," he said in a Thursday statement. "We hope the Biden Administration listens to the thousands of members of the public who oppose this project and finds that more water pollution in service of an unneeded project is not in the public interest.”The $3 billion to $6.2 billion project comes from multiple companies, including Equitrans Midstream. It's expected to be built in 2022.The pipeline could impact up to 20,000 feet of streams and up to 12 acres of wetlands, the West Virginia News reported. West Virginia's approval along with Virginia's paves the way for the Army Corps of Engineers to next issue a stream-crossing permit for the pipeline.
Challenge filed to WVa permit for Mountain Valley Pipeline - The Washington Post — Opponents of the Mountain Valley Pipeline filed a legal challenge Monday to a West Virginia water permit for the natural gas project. The petition filed by environmental and community groups argues that the state Department of Environmental Protection violated the Clean Water Act in granting the permit. The Sierra Club was among the groups that filed the petition with the 4th U.S. Circuit Court of Appeals. A challenge was filed last month involving a similar permit in Virginia. The 303-mile pipeline would take natural gas drilled from the Marcellus and Utica shale formations and transport it through West Virginia and Virginia. Attempts to kill the $6.2 billion project have so far failed. Five energy companies constructing the pipeline say it’s necessary to provide natural gas along the East Coast.
Sierra Club challenges West Virginia DEP's approval of MVP water permit -(WV News) — The Sierra Club has filed a lawsuit against the West Virginia Department of Environmental Projection, objecting to the DEP’s recent approval of a key water permit for the Mountain Valley Pipeline project. The suit — filed by lawyers from Appalachian Mountain Advocates on behalf of the Sierra Club and a coalition of other environmental groups — argues the DEP’s approval violates the Clean Water Act. “MVP has repeatedly violated environmental safeguards, clean water protections and plain common sense in their construction of this fracked gas pipeline,” Sierra Club Senior Organizer Caroline Hansley said. The DEP approved the water protection individual permit Thursday, allowing the pipeline to proceed. The pipeline, which is 42 inches in diameter, is projected to permanently impact 1,276 feet of streams, as well as less than a half acre of wetlands. The DEP also determined that more than 20,000 feet of streams and about 12 acres of wetlands will be temporarily impacted during the pipeline’s construction. But the DEP determined the pipeline complied with state water quality guidelines. The Mountain Valley Pipeline will run from Northern West Virginia to Southern Virginia. It will go through Wetzel, Harrison, Doddridge, Lewis, Braxton, Webster, Nicholas, Greenbrier, Fayette, Summers and Monroe counties before crossing into Virginia.
Mountain Valley Pipeline faces another legal battle - Another round of litigation against the Mountain Valley Pipeline is revving up, this time over last week’s vote by the State Water Control Board allowing the infrastructure to cross streams and wetlands. The Sierra Club and eight other environmental and community groups filed a petition late Wednesday with the 4th U.S. Circuit Court of Appeals, asking the court to review the board’s decision. Legal grounds were not included in the two-page document; those will be spelled out in future filings. But pipeline opponents have long criticized the board and the Virginia Department of Environmental Quality, who they say failed to stop construction of the natural gas pipeline from harming natural resources — first in 2017, and more recently with a second permit. “MVP’s dirty, dangerous pipeline project has already impacted both air and water quality along the route, leading to major environmental degradation, as well as public health concerns for communities,” Caroline Hansley, a senior organizer for the Sierra Club, said in a statement. Opponents say Mountain Valley should not be allowed to continue its past track record of nearly 400 violations of erosion and sediment control regulations in Southwest Virginia. Mountain Valley contends that the problems, largely caused by heavy precipitation in 2018, have been corrected. “We believe the Court’s review of the work completed by the VA DEQ during the past year will find that the agency met or exceeded all legal and regulatory requirements, and that the agency’s action will be upheld,” company spokeswoman Natalie Cox wrote in an email. Joining the Sierra Club in the latest challenge are: Appalachian Voices, the Blue Ridge Environmental Defense League, the Chesapeake Climate Action Network, Preserve Bent Mountain, Preserve Craig County, Preserve Franklin County, Preserve Giles County and Wild Virginia. The Fourth Circuit has been a frequent pipeline battleground, with both Mountain Valley and the government agencies that regulate it often suffering setbacks. So far, however, there has not been a fatal blow to the $6.2 billion project. Five energy companies building the pipeline say it’s needed to provide 2 billion cubic feet per day of natural gas to markets along the East Coast.
EnCap's Paloma Takes Goodrich Private, Gains Estimable Shale Assets, Including Haynesville -An affiliate of private equity giant EnCap Investments last month took Houston-based Goodrich Petroleum Corp. private after completing a $23/share tender offer. Paloma Partners VI Holdings LLC, an entity of Houston’s Paloma Resources LLC, completed the estimated $480 million takeover, which was announced in November. Paloma, now active in Oklahoma, gained a broad set of assets across the Lower 48, including a substantial and growing business in the natural gas-rich Haynesville Shale. Goodrich has around 32,000 net acres in the Haynesville, 34,000 net acres in the Tuscaloosa Marine Shale and 4,300 net undeveloped acres in the Eagle Ford Shale. The Haynesville has been the primary target, with its proved gas reserves making up 99% of the total 543 Bcfe at the end of 2020. Goodrich’s production climbed 7% sequentially in 3Q2021 to 166 MMcfe/d, 99% weighted to natural gas. During the quarterly conference call in November, CEO Gil Goodrich said the company’s current hedge position for natural gas prices provided “substantial downside protection while also giving us substantial exposure to higher unhedged prices as we execute our 2022 plans.” The company has an estimated 2.4 Tcfe of resource potential in Northern Louisiana, with 127 net potential drilling locations using 880-foot spacing. Goodrich has an 85% working interest in the core of the Haynesville position, with Chesapeake Energy Corp. holding 15%. Capital expenditures in 3Q2021 totaled almost $28 million, with most of it “spent on drilling, completion and facility costs associated with Haynesville wells,” COO Robert Turnham told analysts in November. “To date, we’ve only seen a small amount of service cost inflation, and our economics…are as good as we have seen them in the basin.” The Paloma Resources arm initially was sponsored by EnCap in 2014. Previous entities have created and sold positions in the Barnett, Eagle Ford and Utica shales.
Milestone Environmental Bullish On Growth in Haynesville, Permian - Milestone Environmental Services LLC has repositioned itself in the core of the Haynesville Shale by acquiring an energy waste disposal facility in East Texas from High Roller Wells LLC.“We believe the Haynesville will be a growing market given the increased global demand for natural gas as the world transitions its energy usage to lower-carbon sources,” said CEO Gabriel Rio.One exploration and production (E&P) company that is elevating its Haynesville profile is Southwestern Energy Co., which recently acquired about 700 drilling locations in the shale play. Through that and another deal in September, the company is boosting its access to the Gulf Coast liquefied natural gas export market.Another E&P adding Haynesville acreage is Paloma Resources LLC, which in November completed its takeover of Goodrich Petroleum Corp.Rio noted that E&Ps increasingly are having their energy waste streams professionally managed, requiring more infrastructure to meet growing demand.“Our decision to acquire these assets was a strategic one that supports Milestone’s growth while serving the environmental needs of E&P operators in major U.S. basins,” Rio said.The acquisition gives Milestone an active slurry injection facility with two injection wells in Shelby County, three miles north of Center, TX. The company called the facility “a cornerstone of the environmental infrastructure in place” for managing gas-focused E&Ps operating in the Texas and Louisiana Haynesville, adding that it “plans several upgrades to the location over time.”The High Roller transaction also included purchase options on two unconstructed energy waste landfill permits in Texas – one in the Haynesville and another in the Permian Basin. The permits are from state rather than federal regulators, a Milestone spokesperson told NGI.
US becomes world's top exporter of liquefied natural gas – CNN - The United States is now the world's leading exporter of liquefied natural gas as Europe's energy crisis and shortages in China send demand for American shipments soaring.LNG exports from the United States topped 7 million tonnes (7.7 million tons) in December, according to ship-tracking data from ICIS LNG Edge, narrowly edging out rival producers Qatar and Australia for the first time.The United States only shipped its first LNG cargo from the lower 48 states in 2016, and has risen to become the world's top exporter in just six years as a shale gas revolution boosted domestic production and turned the country into a powerful force in global energy markets.The United States will be the biggest exporter in the world through 2022 as a whole, according to forecasts from ICIS and the US Energy Information Agency. Demand is expected to remain high in Europe, where there are fears about natural gas supplies from Russia as tensions grow over a military buildup at its border with Ukraine.Gas prices in Europe surged to new records in late December as confidence in Russian deliveries waned and controversy swirled over the Nord Stream 2 pipeline that could carry gas from Russia directly to Germany. The European Union gets about 40% of its imported natural gas from Russia, much of it piped via Ukraine.Wholesale prices were rising again Wednesday as the flow of gas in a pipeline from Russia to Europe was reversed for a 16th successive day, Reuters reported.US producers have responded by boosting LNG shipments to Europe, where prices are now higher than in east Asia. Prices in both regions far exceed those in the United States, suggesting that US LNG exports will continue to increase in 2022.
U.S. World's Top LNG Exporter in December With Deliveries to Europe Surging - The U.S. became the world’s No. 1 exporter of liquefied natural gas for the first time ever last month, as deliveries surged to energy-starved Europe. Output from American facilities edged above Qatar in December after a jump in exports from the Sabine Pass and Freeport facilities, according to ship-tracking data compiled by Bloomberg. Cheniere Energy Inc. said last month that a new production unit at its Sabine Pass plant in Louisiana produced its first cargo. A shale gas revolution, coupled with billions of dollars of investments in liquefaction facilities, transformed the U.S. from a net LNG importer to a top exporter in less than a decade. Gas production has surged by roughly 70% from 2010 and the nation is expected to have the world’s largest export capacity by the end of 2022 once Venture Global LNG’s Calcasieu Pass terminal comes online. But the U.S.’s position as top LNG shipper may be short-lived. Exports were just a hair above those from Qatar and Australia, and any production issues could affect the rankings. Looking further out, Qatar is planning a gargantuan export project that will come online in the late 2020s, which could cement the middle eastern nation as the top supplier of the fuel. “Qatar and the U.S. will be vying for being the largest LNG producers in the world over the next decade,” said Muqsit Ashraf, senior managing director of Accenture’s global energy practice. In the meantime, the jump in U.S. LNG exports will help ease a global supply crunch. Europe is facing a winter energy crisis as utilities grapple with seasonally low natural gas inventories. Overseas buyers purchased 13% of U.S. gas production in December, a seven-fold increase from five years earlier when most of the infrastructure required to ship the fuel out of the country didn’t yet exist. U.S. LNG export terminals sent out a record 1,043 cargoes in 2021, with Asian nations making up nearly half of the destinations and Europe making up one-third, ship tracking data compiled by Bloomberg shows.
U.S. claims title of world’s largest LNG exporter--The U.S. became the world’s No. 1 exporter of liquefied natural gas for the first time ever last month, as deliveries surged to energy-starved Europe. Output from American facilities edged above Qatar in December after a jump in exports from the Sabine Pass and Freeport facilities, according to ship-tracking data compiled by Bloomberg. Cheniere Energy Inc. said last month that a new production unit at its Sabine Pass plant in Louisiana produced its first cargo. A shale gas revolution, coupled with billions of dollars of investments in liquefaction facilities, transformed the U.S. from a net LNG importer to a top exporter in less than a decade. Gas production has surged by roughly 70% from 2010 and the nation is expected to have the world’s largest export capacity by the end of 2022 once Venture Global LNG’s Calcasieu Pass terminal comes online. But the U.S.’s position as top LNG shipper may be short-lived. Exports were just a hair above those from Qatar and Australia, and any production issues could affect the rankings. Looking further out, Qatar is planning a gargantuan export project that will come online in the late 2020s, which could cement the middle eastern nation as the top supplier of the fuel. “Qatar and the U.S. will be vying for being the largest LNG producers in the world over the next decade,” said Muqsit Ashraf, senior managing director of Accenture’s global energy practice. In the meantime, the jump in U.S. LNG exports will help ease a global supply crunch. Europe is facing a winter energy crisis as utilities grapple with seasonally low natural gas inventories. Overseas buyers purchased 13% of U.S. gas production in December, a seven-fold increase from five years earlier when most of the infrastructure required to ship the fuel out of the country didn’t yet exist. U.S. LNG export terminals sent out a record 1,043 cargoes in 2021, with Asian nations making up nearly half of the destinations and Europe making up one-third, ship tracking data compiled by Bloomberg shows.
First US LNG cargo from certified gas could set sail --Third-party gas certification that took off in 2021, particularly in the Haynesville Shale in Louisiana and East Texas, could lead to the first certified gas US LNG export cargo in 2022, market watchers say. The first US LNG cargo sourced entirely from certified gas could set sail as early as the second quarter of 2022, according to Project Canary CEO Chris Romer. “I think next year LNG buyers are going to start insisting on the methane intensity being measured at the well level, pad level, compressor station, all the way through to it being put on a ship and delivered to that foreign hub,” Romer said in a Dec. 14 telephone interview. Emmanuel Corral, a low-carbon gas analyst with S&P Global Platts Analytics, has also predicted the first certified gas US LNG cargo in 2022. “The more companies jump on this movement, the more confidence I gain that it will happen,” Corral said
Rio Grande LNG project final investment decision delayed to second half of 2022 - NextDecade has delayed an expected final investment decision related to its proposed Rio Grande LNG export project in Texas to the second half of 2022, an investor presentation posted Jan. 3 on the company's website said. The company had previously targeted a decision on a first phase consisting of at least two liquefaction trains by the end of 2021. The adjusted timing comes as NextDecade continues to seek sufficient supply deals with buyers to support the cost of construction. To date, it has secured a single long-term contract, with Royal Dutch Shell, covering 2 million mt/year of the about 11 million mt/year of supply that is expected to make up the first phase of the project in Brownsville. The full project, as currently proposed, would involve five trains and 27 million mt/year of capacity. During 2021, there was a flurry of commercial activity tied to current and proposed US LNG export terminals. The main beneficiaries were Cheniere Energy and Venture Global LNG, especially with Chinese buyers as high spot prices in end-user markets spurred new term deals that carry a lower fixed price. Two proposed US projects were scrapped during the year – Pembina's Jordan Cove in Oregon and Exelon-backed Annova LNG, which was to be built in Brownsville near NextDecade's site. In its new investor presentation, NextDecade said negotiations were "advancing with multiple counterparties in Europe and Asia" and that financing would "commence" upon execution of additional sale and purchase agreements. It did not elaborate. A company official did not immediately respond to a message seeking further comment. NextDecade has said it plans to advance a carbon capture and storage project shortly after it sanctions the first phase of the liquefaction terminal. NextDecade is also partnering with a Colorado company to measure and report the greenhouse gas intensity of the LNG to be produced at the export facility. The goal of the reporting initiative includes enabling the development of responsibly sourced natural gas from producers in the Permian Basin and Eagle Ford shale that will be fed to the terminal. In November, NextDecade pitched to US regulators a limited amendment to its federal authorization for the LNG terminal that would allow it to voluntarily capture and store CO2 produced at the facility. That proposal came as a federal appeals court found fault with the original Federal Energy Regulatory Commission authorization for the LNG project, remanding FERC's orders to the commission without vacating them. NextDecade expects to receive FERC approval in 2022 for the CCS project, according to the new investor presentation.
U.S. natural gas faces high volatility in 2022 --U.S. natural gas is in for another wild year as the insularity that once shielded North American energy consumers from overseas turmoil disintegrates. Benchmark American gas futures climbed almost 45% in 2021 for the strongest annual performance in half a decade after a deadly freeze that crippled output was followed by summer heatwaves that lifted demand and hindered efforts to stow away supplies for winter. As 2022 dawns, traders, explorers and utility operators are facing the prospect of continued volatility amid rising competition from buyers as far away as Poland and the Netherlands who are dealing with a crisis so acute that factories have shut down and Goldman Sachs Group Inc. is warning there’s a “clear risk of running out of gas.” Overseas buyers purchased 13% of U.S. gas production in December, a seven-fold increase from five years earlier when most of the infrastructure required to ship the fuel out of the country didn’t yet exist. Prior to the advent of the American gas-export business, the U.S.-Canada market was a provincial sphere where prices were dictated by cold snaps in places like Pittsburgh and Chicago, and hurricanes in the Gulf of Mexico. But those days are long gone as brokers in Seoul and Rotterdam shell out record amounts to entice tankers laden with U.S. gas to sail their way. “We continue to expect more price volatility to be present in these markets relative to recent history, albeit at a more diminished level once exiting the peak demand season of winter weather,” said Natasha Kaneva, head of commodities research and strategy at JPMorgan Chase & Co. “This is particularly true in the U.S., where price volatility has long been absent.”
U.S. natural gas prices rise as cold freezes wells (Reuters) – U.S. natural gas prices rose more than 2% on Monday after production fell over the New Years weekend as cold weather froze some production wells in Texas, in New Mexico and Colorado, reminding the market of what can happen when temperatures drop.Last February, a severe winter storm named Uri killed more than 100 people and left an estimated 4.5 million homes and businesses in Texas without power or heat – some for days – after gas lines and gas pipes froze. power stations. The New Years weekend cold, however, was nowhere near as extreme as the frost last February. Well freezing occurs whenever temperatures drop enough to freeze the water and other liquids in a well or pipe and stop production. “Gas prices fell recently with the increase in production, but rose on Monday as freezes puzzled the market,” said John Abeln, senior natural gas research analyst at data provider Refinitiv .According to data from Refinitiv, gas production in the lower 48 U.S. states has fallen to an average of 94.8 billion cubic feet per day (bcfd) so far in January, from a record 97.6 bcfd in December.Much of that drop in production occurred in Texas and occurred on Sunday.Low temperatures in the city of Midland, West Texas, dropped to a nightly low of 16 degrees Fahrenheit (minus 9 Celsius) on Sunday, but are expected to reach a near-normal nightly low of 32 F on Monday, according to the AccuWeather meteorologists.Midland is located in the Permian Basin, which is the largest oil-producing shale formation and the second largest producer of gas in the United States.Since the freeze last February, Texas has approved numerous laws and regulations that state officials say should improve the reliability of the electricity and gas markets and prevent price spikes and blackouts like those observed last winter.
Natural Gas Forwards Explode on Near-Term Cold, but Outlook Casts Doubt on Sustainability -Plunging temperatures, soaring demand and falling production resulted in stout price gains across U.S. natural gas forward curves for the Dec. 31-Jan 5 period, NGI’s Forward Look data showed. Dollar-plus price increases spread across Appalachia and the Northeast as output struggled to recover amid ongoing cold in the region. The reduction in supply – a whopping 1 Bcf according to estimates – occurred at the same time the biggest snowstorm of the winter hit the Mid-Atlantic. The storm resulted in whiteout conditions, extensive power outages and gnarly road conditions that left motorists on Interstate 95 in Virginia stranded for more than 24 hours. Amid the bullish backdrop, exacerbated by tight pipeline capacity in the Northeast, prices throughout the region surged week/week.Transco Zone 5 recorded the steepest climb, with February forward prices jumping $2.130 from Dec. 31-Jan. 5 to reach $8.832/MMBtu, according to Forward Look. Transco Zone 5’s premium over the Henry Hub also ballooned, edging up $1.810 to $4.950. Fixed-price increases were not nearly as stout further out the curve, but were notable nonetheless. March was up 31.0 cents to $4.535, while the summer strip (April-October) shot up 24.0 cents to $3.820, Forward Look data showed.Similarly, Cove Point climbed steeply on the week as export demand continued to run rampant amid the surge in domestic demand. NGI data shows feed gas deliveries to U.S. terminals continuing to hover around 12 Bcf/d since the final days of 2021, with volumes sitting at around 12.20 Bcf on Friday.Robust U.S. LNG exports have continued unabated since the summer as a dire supply outlook in Europe and steady building of inventories in Asia have left buyers clamoring for the super-chilled fuel. LNG capacity should ramp up further in the coming months as Sabine Pass continues to commission its sixth production unit and the Calcasieu Pass facility nears in-service.In Appalachia, prices swelled for the molecules still able to flow to market. February forward prices at Tenn Zone 4 200L – a new addition to the Forward Look suite of pricing locations – rose 39.0 cents from Dec. 31-Jan. 5 to reach $3.571. Summer prices averaged $3.110, up 26.0 cents during the period.The addition of Tenn Zone 4 200L enhances NGI’s coverage of the Utica Shale region. The pricing location incorporates transactions along Tennessee
U.S. natgas futures slide on forecasts for less cold weather - (Reuters) - U.S. natural gas futures slid almost 3% on Tuesday after midday forecasts called for less cold weather and lower heating use over the next two weeks than previously expected. That U.S. price decline came even though the market expects a 24% jump in European gas prices will keep demand for U.S. liquefied natural gas (LNG) exports strong. In the last quarter of 2021, U.S. gas futures followed the rise and fall of global prices about two-thirds of the time as utilities around the world scrambled for LNG cargoes to replenish low stockpiles in Europe and meet surging demand in Asia. Front-month gas futures fell 9.8 cents, or 2.6%, to settle at $3.717 per million British thermal units (mmBtu). More than 330,000 homes and businesses located mostly in Virginia were without power early Tuesday after a snow and ice storm battered the U.S. East Coast from Georgia to Maryland on Monday. Although the snowstorm blew out to sea, cold weather blanketed the U.S. Northeast, causing next-day gas prices in New York City to soar from $3.60 per mmBtu for Monday to $8.50 for Tuesday. That was the highest daily spot price in New York since last winter's February freeze cut power and gas supplies in Texas and boosted energy costs to record highs in several parts of the country. Even though gas prices in Europe dropped by about half since hitting an all-time high near $60 per mmBtu in late December, global prices continue to trade around eight times higher than gas in the United States. U.S. futures followed that global gas price spike, reaching a 12-year high of more than $6 per mmBtu in early October, but have since retreated because the United States has plenty of gas in storage and ample production for the winter. Analysts have said European gas inventories were about 20% below normal for this time of year, compared with about 1% above normal in the United States. Data provider Refinitiv said well freeze-offs in several states -- including Texas, New Mexico and North Dakota -- earlier this week caused gas output in the U.S. Lower 48 states to drop to an average of 94.5 billion cubic feet per day (bcfd) so far in January, versus a record 97.6 bcfd in December. With the weather expected to remain colder than normal through mid-January, Refinitiv projected average U.S. gas demand, including exports, would rise from 128.4 bcfd this week to 134.3 bcfd next week as homes and businesses crank up their heaters. The amount of gas flowing to U.S. LNG export plants eased to an average of 12.0 bcfd so far in January from a record 12.2 bcfd in December. With gas prices around $32 per mmBtu in Europe and $31 in Asia, compared with just about $4 in the United States, traders said buyers around the world would keep purchasing all the LNG the United States can produce.
Cash Prices, Natural Gas Futures Bounce Higher as Temperatures Drop - Strength in cash prices and expectations for ongoing blasts of frigid air over swaths of the Lower 48 sent natural gas futures higher on Wednesday. The February Nymex contract settled at $3.882/MMBtu, up 16.5 cents day/day. March gained 12.8 cents to $3.710. NGI’s Spot Gas National Avg. advanced 81.0 cents to $5.105, bolstered by freezing temperatures and elevated demand in the nation’s midsection. Though volatile to start 2022 – with weather models each day showing varying degrees of cold through most of January – the bottom line remains firm: Frosty winter weather and robust heating demand are in store this month. “The weather models have been bouncing between colder and warmer trends all week,” NatGasWeather’s forecasters said. However, they added, subzero temperatures in the Northern Plains and Upper Midwest early Wednesday were expected to advance down the Plains and to the East by Friday, generating “strong national demand.” After a brief break this coming weekend, “another frigid cold shot will sweep across the Midwest and Northeast early next week” with more freezing overnight temperatures, according to NatGasWeather. At the same time, winter conditions have curtailed production work in the Permian Basin in recent days, lowering total U.S. output on Wednesday to below 92 Bcf and putting it far from late 2021 highs around 97 Bcf. Meanwhile, demand for U.S. exports of liquefied natural gas (LNG) is holding strong. LNG feed gas volumes hovered above 12 Bcf on Wednesday, according to NGI estimates. Analysts said robust demand from Europe could push those volumes to record levels above 13 Bcf/d this winter. The “nascent” storage surplus versus the five-year average may peak with the Energy Information Administration’s (EIA) storage report for final the week of 2021, “Subsequent declines into a renewed deficit by mid-January — and a storage deficit rebuilding to triple digits by the end of the month — may provide additional near-term fundamental price support,” he said.
U.S. natgas futures rise as cold continues to reduce output -(Reuters) - U.S. natural gas futures edged up on Wednesday as freezing wells continued to reduce output in some producing regions and the weather was forecast to remain colder than normal through late January. Front-month gas futures NGc1 rose 5.3 cents, or 1.4%, to $3.770 per million British thermal units (mmBtu) at 8:17 a.m. EST (1317 GMT). In the spot market, next-day gas at the Waha hub in the West Texas Permian producing area rose over the U.S. Henry Hub NG-W-HH-SNL benchmark in Louisiana for the first time since September 2021 as cold weather continues to freeze wells and cause some gas processing equipment to fail. Over the New Year's weekend when overnight low temperatures dropped to the mid teens Fahrenheit (-9 C) in West Texas, well freeze-offs and equipment problems caused the state's gas output to fall by over 1 billion cubic feet per day (bcfd) to its lowest since last February's freeze left millions without power and heat for days. Around the world, meanwhile, global gas prices have repeatedly reached all-time highs in recent months - most recently during the week before Christmas - as utilities scramble for liquefied natural gas (LNG) cargoes from the United States and elsewhere to replenish low stockpiles in Europe and meet surging demand in Asia. European gas prices were up about 5% on Wednesday. NG/GB U.S. futures, which followed prices in Europe about two-thirds of the time during the fourth quarter of 2021, jumped to a 12-year high of more than $6 per mmBtu in early October. Since then, however, U.S. prices have retreated because the United States has ample production and plenty of gas in storage for winter. Analysts have said European inventories were about 20% below normal for this time of year, compared with about 1% above normal in the United States. Global gas was currently trading about eight times higher than in the United States. Data provider Refinitiv said average gas output in the U.S. Lower 48 states dropped from a record 97.6 bcfd in December to 94.5 bcfd so far in January due to well freeze-offs and other cold weather-related equipment problems in Texas and other producing states this week. Refinitiv projected average U.S. gas demand, including exports, would rise from 128.4 bcfd this week to 134.0 bcfd next week as homes and businesses crank up their heaters. The forecast for next week was a little lower than Refinitiv's outlook on Tuesday. The amount of gas flowing to U.S. LNG export plants eased to an average of 12.0 bcfd so far in January from a record 12.2 bcfd in December.
Natural Gas Futures Stumble as Stockpiles Hold Above Historic Average - Natural gas futures faltered on Thursday after the latest government inventory report showed ample supplies and relatively modest early-winter heating demand. The February Nymex gas futures contract fell 7.0 cents day/day and settled at $3.812/MMBtu. March dipped 4.0 cents to $3.670. NGI’s Spot Gas National Avg., in contrast, jumped $1.155 to $6.260. Next-day prices in the Northeast surged and fueled the overall gain. The U.S. Energy Information Administration (EIA) on Thursday reported a withdrawal of 31 Bcf natural gas from storage for the final week of 2021. The result missed expectations by a wide margin. Prior to the report, major polls showed analysts expecting a pull in the low 50s Bcf. NGI’s model predicted a 50 Bcf withdrawal. What’s more, expectations were modest relative to historic norms for late December. In the year-earlier period, EIA recorded a 127 Bcf withdrawal, while the five-year average is a 108 Bcf pull. Analysts noted that production was elevated during the week and weather-driven demand was seasonally paltry, given much warmer-than-normal temperatures over most of the Lower 48. Commercial and industrial demand eased as well during a week that spanned the Christmas holiday and New Year’s Eve. The draw for the Dec. 31 period lowered inventories to 3,195 Bcf. Stocks were 154 Bcf lower than a year earlier but 96 Bcf above the five-year average of 3,099 Bcf. The Midwest posted a decrease of 25 Bcf to lead all regions. The Pacific followed with a withdrawal of 16 Bcf. EIA recorded a 10 Bcf pull for the East and an 8 Bcf decrease for the Mountain region. The South Central, meanwhile, posted an increase of 27 Bcf. Despite the disappointing finish in terms of supply/demand balances to end 2021, Bespoke noted that weather shifted notably colder early in January, particularly in the Midwest and stretches of the East, boosting heating demand. Another round of wintry conditions is expected by mid-month. The firm also noted reduced production levels this week amid freezing temperatures in the Permian Basin. Bloomberg estimated output at 91.5 Bcf on Wednesday, about 3 Bcf below the level of the prior week. Bespoke projects triple-digit pulls with each of the next three EIA storage reports.
U.S. natgas rises as winter storm boosts demand to near record high - U.S. natural gas futures rose almost 3% to a one-week high on Friday as a major winter storm blanketed the Northeast in snow, driving overall gas demand to its highest in a day since hitting a record in 2019. As homes and businesses in New York and New England cranked up their heaters, next-day power and gas prices in the region jumped to their highest since January 2018. European gas futures fell 14%. U.S. gas futures followed European gas prices about two-thirds of the time during the fourth quarter of 2021 as utilities scrambled for liquefied natural gas (LNG) cargoes to replenish low stockpiles in Europe and meet surging demand in Asia. Front-month gas futures rose 10.4 cents, or 2.7%, to settle at $3.916 per million British thermal units (mmBtu), their highest since Dec. 29. That increase put the front-month up about 5% for the week after it held steady last week. Lingering cold since New Year’s Day has continued to cause well freeze-offs and other weather-related equipment problems in several regions, including the Permian in Texas and New Mexico, the Bakken in North Dakota and Appalachia in Pennsylvania, West Virginia and Ohio. Data provider Refinitiv said those weather-related problems, which are normal during winter months, have cut average output in the U.S. Lower 48 states to 94.5 bcfd so far in January, down from a record 97.6 bcfd in December. With colder weather coming, Refinitiv projected average U.S. gas demand, including exports, would rise from 128.8 bcfd this week to 134.3 bcfd next week, before easing to 131.1 bcfd in two weeks with the weather expected to turn less cold. The forecasts for this week and next were higher than Refinitiv’s outlook on Thursday. On a daily basis, Refinitiv projected total U.S. gas demand plus exports would reach 147.9 bcfd on Friday, its highest since hitting a record 150.6 bcfd on Jan. 30, 2019. That would top the 147.2 bcfd hit on Feb. 12, 2021 just before Winter Storm Uri left millions without power and heat for days after freezing gas wells and pipes in Texas and other U.S. Central states. The amount of gas flowing to U.S. LNG export plants has averaged 12.0 bcfd so far in January, down from a record 12.2 bcfd in December. With gas prices around $30 per mmBtu in Europe and $34 in Asia, compared with less than $4 in the United States, traders said buyers around the world would keep purchasing all the LNG the United States can produce. Still, the United States only has the capacity to turn about 12.2 bcfd of gas into LNG.29dk2902l Global markets will have to wait until later this year for some of the 18 liquefaction trains under construction at Venture Global LNG’s Calcasieu Pass in Louisiana to start producing LNG. The plant has been pulling in small amounts of feed gas since around September as it prepares to begin operating.
Energy expert says Texas should weatherize natural gas to prevent future blackouts - Some regions of the state have seen below freezing temperatures over the last few days, leaving some Texans worried the electrical grid could fail, as it did last February. After that winter storm left millions freezing and in the dark, Texas lawmakers pressured both the gas and electrical power systems to make their infrastructure more resistant to cold weather. Even though 2022 has kicked off with chilling temperatures, UT Austin professor and energy expert Micahel Webber said people shouldn’t be too worried about the power grid failing since the recent winter weather wasn’t as severe as last year’s. “The grid held up, there weren't major problems with gas production. So it's not really surprising that this winter storm we've endured the last couple days didn't really test the system the same way, because it wasn't the same kind of storm,” Webber said. Unlike in Feb. 2021, the winter weather isn’t consistently at or below freezing all across Texas. Webber said that means the energy system isn’t as strained as it was last year. “It was below freezing for many hours at a time and never got above freezing for some days at major population centers,” Webber said. “So that storm in February 2021, was just much worse, much colder for much longer across a much wider area of Texas. The last few days were cold, but not that cold, not as long and it kind of warms up during the day.” The real test for the power grid will be when demand is high, and supply is low, Webber said. Senate Bill 3 mandated that energy facilities be prepared for “weather emergencies” moving forward. While the legislation helped reform ERCOT and its regulator, the Public Utility Commission, it had few requirements for weatherizing natural gas fuel facilities. Webber also pointed out that ERCOT only controls the electrical system, not the gas system. It was the gas system, which is regulated by the Texas Railroad Commissioner, that primarily failed during last year’s storm. “The legislature is not giving gas the same kind of attention or scrutiny or expectations of reliability that the power sector gives to its power plants,” Webber said. “So that's part of the challenge in Texas is the way we experienced the outages at home was with a blackout. That blackout was triggered primarily by gas system failure, and people don't know that. So, we have to look at the whole problem to really get it improved.”
State says Xcel's inoperable gas plants added tens of millions to February storm costs - Peaking plants can be the unsung hero of natural gas systems, firing up to provide vital reserves during an emergency like the historic storm last February. But Xcel Energy's three Minnesota peaking plants were inoperable then, resulting in tens of millions of dollars in costs for customers in the state, the Department of Commerce concluded in a report to state utility regulators. The department is recommending that the Public Utilities Commission (PUC) disallow $127 million of the $179 million Xcel wants to charge Minnesota ratepayers for extraordinary gas costs from the February storm. Peaking-plant issues account for two-thirds of that $127 million. "Thus far, Xcel has not shown it prudently operated or maintained" the plants, said the report from the Commerce Department, filed last week with the PUC. Xcel's largest peaking plant in Inver Grove Heights was mothballed in early January after it malfunctioned and twice leaked gas. A cautious Xcel then closed two smaller peaking plants. State pipeline safety regulators are still investigating the leaks. Xcel, in a statement, said it "strongly" disagrees with the Commerce Department's conclusions and will file a detailed response with the PUC in January. The company said it adjusted its gas-supply plans last winter to account for the loss of the peaking plants, "making sure we could continue to serve our customers reliably without those facilities."
Life after Deepwater Horizon: the hidden toll of surviving disaster on an oil rig - On the morning of 21 April 2010, Sara Lattis Stone began frantically calling the burn units of various hospitals in Alabama and Louisiana. She was searching for news about her husband, Stephen, who worked on an offshore oil rig in the Gulf of Mexico where a massive explosion had occurred. The blast took place the day before Stephen was scheduled to return home from his latest three-week hitch on the rig, a semisubmersible floating unit called the Deepwater Horizon. ... Eventually, Sara received another call from Transocean, informing her that although the blowout had caused multiple fatalities, Stephen was among those who had managed to escape from the burning rig. The survivors were now being transported by ferry to a hotel in New Orleans, she was told. The following morning, at about 3.30am, she got a call from Stephen, who told her he was on his way to the hotel where she and other family members had gathered to wait. “Are you OK?” she asked him. “Yeah, I’m fine,” he said. Later, when she saw him shuffle through the hall that had been cordoned off for surviving crew members, she knew immediately that he wasn’t fine. His expression was blank and, like the other survivors, he looked shell-shocked and traumatised. “When he walked in, from the look in his eyes, it was obvious that something horrible had happened,” she recalled. There were also human costs, which Sara sought to capture in her art. She painted a portrait of Chris Jones, whose brother, Gordon, was one of 11 workers killed in the disaster. In Sara’s portrait, Jones’s lips are pursed and his face, painted ash blue, is creased with anguish. Titled Survivors, Sara’s paintings were stark and vivid, capturing the raw grief that filled the room at the congressional hearing on the Deepwater spill in Washington. But the portrait she drew of Stephen captured something different. Based on a photo that was taken during his testimony at the congressional hearing, it shows a bearded figure with a vacant, faraway expression in his eyes. He does not look grief-stricken so much as bewildered and unmoored. The bewilderment was still apparent when I met Stephen several years later, at a bar not far from where he and Sara were living at the time. Stephen was in his late 20s, with a shaggy mop of chestnut-coloured hair and languid, downcast eyes. At the bar, he was taciturn, nodding occasionally at something Sara said while straining to keep his gaze from drifting off. Unlike some of the workers on the Deepwater Horizon, he had managed to escape from the rig without sustaining any burns or physical injuries. But as I would come to learn, the absence of visible wounds was a mixed blessing, prompting friends to wonder what was wrong with him and exacerbating the shame he felt for struggling to move on.
Lime Rock Adds Austin Chalk, Upper Eagle Ford Prospects to Lower 48 Portfolio -Houston-based Lime Rock Resources said it recently spent $271.3 million to pick up a bundle of oil and gas prospects in the Austin Chalk formation and Upper Eagle Ford Shale. The deal with an undisclosed seller coincided with an $87.3 milion acquisition of Williston Basin assets from Abraxas Petroleum Corp., management said. In the past four months, the private equity-backed company said it has spent more than $850 million on oil and gas acquisitions.“We have been patient, acquiring only one small overriding royalty interest in the two years before this past October,” CEO Eric Mullins said. “We believe that the nearly $1 billion of acquisitions in the last several months testifies to changing market dynamics, a robust opportunity set, and our ability to work with sellers over many months on transactions that work for all parties.” The Austin Chalk and Upper Eagle Ford deal included producing properties on about 46,000 contiguous net acres in Burleson, Milam, and Robertson counties. The properties recently were producing an estimated 7,700 boe/d. The Abraxas transaction included 3,500 acres in McKenzie County, ND. The Lime Rock team has been an active operator in the Williston since 2014, and it said it now manages about 19,400 boe/d net. Lime Rock has a portfolio of Lower 48 projects under development, with a focus in the Midcontinent, Permian and Williston basins, along with the Gulf Coast. Natural gas properties include the Cedardale-Laverne play in northern Oklahoma, Denton Creek in the Barnett Shale of North Texas and in the Arkoma, an East Texas property.
NexTier stock jumps as frac demand swells revenue--NexTier Oilfield Solutions Inc. soared more than 20% after the frac provider disclosed higher-than-expected quarterly sales, signaling an acceleration in U.S. shale drilling. The Houston-based provider of pumps that blast water, sand and chemicals underground to crack open oil-soaked rocks said fourth-quarter revenue more than doubled to at least $500 million, almost 3% above the average of analysts’ forecasts in a Bloomberg survey. The shares jumped to $4.64 at 10:14 a.m. in New York for the biggest intraday gain since November 2020. “We expect many others also experienced this trend during Q4,” analysts at Tudor Pickering Holt & Co. wrote Tuesday in a note to investors. The improved performance was “likely driven less by pricing gains and more by better-than-expected activity levels through the holiday weeks/months into year-end.” While activity in U.S. oilfields typically slows during the final three months of the year, explorers are racing to frack wells in the Permian Basin and elsewhere before an expected uptick in costs in coming months. NexTier also said in a late Monday statement that worker absenteeism is on the rise as the latest Covid-19 variant spreads.
Fed survey shows oil and gas firms planning a modest 2022 comeback --The Dallas Federal Reserve Bank published results of a new poll this week showing that almost half of 131 oil and gas firms surveyed plan to increase oil and gas production during 2022. It’s a finding that will no doubt cause a great deal of consternation among ESG investor groups and the climate alarm lobby. The finding comes at the end of a year, 2021, during which the prevailing watch words in the oil and gas U.S. upstream sector were “capital discipline,” “debt reduction” and “maximize returns to investors.” Those three overarching objectives, along with the creation of free cash flow, certainly appeared to dominate the shale landscape throughout the year, as companies scrambled to focus on demands from the investor community, with a strong emphasis on their ESG-related goals. Given the past history of the shale sector during times of rising commodity prices, it seemed a remarkable display of maintaining discipline by the hundreds of E&P companies that drill for oil and gas in the U.S. One potential wild card in this finding is that the Fed does not provide information breaking down the companies surveyed between corporate producers and those that are privately-held. ESG investor group concerns would certainly carry more weight in the corporate sector, especially related to their governance-related objectives. Another finding in this poll that ties into companies’ plans to increase production in 2022 is that 75% of the respondents plan to increase capital spending, with 31% saying they are planning to increase spending “significantly.” The natural bias among the core functions within E&P companies – engineering, geophysical, operations and drilling – is towards investing capital and drilling wells. This is the essential reason why E&P companies even exist, after all. So, a full year of being told they must exercise capital discipline in order to meet goals designed largely to placate a subset of a company’s investors has no doubt left many professionals inside these firms champing at the bit to get back to doing what they do best.
Fed energy survey finds intensifying cost pressures - Continued expansion of the state’s oil and gas sector was obvious in the Fourth Quarter Energy Survey issued by the Federal Reserve Bank of Dallas. But what was also obvious in responses from the survey is that companies are facing intensifying cost pressures. Those cost pressures are the theme of the fourth quarter survey, Kunal Patel, business economist with the bank, told the Reporter-Telegram in a telephone interview. “The survey shows costs are rising. The question is how will the industry manage that?” he said. The survey found costs rose sharply for a third-straight quarter, with input costs for oilfield service firms climbing to a record 69.8 from the record high of 60.8 set in the third quarter. Only one of 44 service companies participating in the survey reported lower input costs. For exploration and production firms, finding and development costs rose to a record 44.9 from 33 in the third quarter while lease operating expenses jumped to a record high of 42 from 29.4 in the previous quarter. Patel noted that service firms reported improvement across the board, though the pace of growth for some indicators slowed. For example, the index of prices received for services was positive but fell to 30.3 from 42.2 while equipment utilization edged up to 51.1 from 47.8. Operating margins also remained positive but sank to 11.6 from 21.8 in the third quarter. One service company representative responded that the company is seeing an across-the-board increase in demand for services but “we are fighting to get back to acceptable margins for our products and services.” Inability to hire qualified workers was a frequent comment from respondents, though the labor market showed further growth in the fourth quarter. The employment index remained positive, though it dropped to 11.9 from 14 in the fourth quarter. Service sector hiring continued to dominate. Patel noted employees are working more hours, though the employee hours index was essentially unchanged at 18. The wages and benefits index did move to a record high of 36.6 from 30.3 in the third quarter. Positive news in the survey was that business activity rose to 42.6, pointing to strong growth, and six-month corporate outlooks improved. Respondents forecast West Texas Intermediate prices will end 2022 at $75 a barrel – price forecasts ranged from $50 to $125 – and Henry Hub gas prices will end the year at $4.06 per MMBtu. Approximately 75 percent of respondents expect to increase capital spending slightly (44 percent) or significantly (31 percent) in 2022. Patel pointed out that the number of respondents expecting significant increases in spending was higher than in the fourth quarter of 2020. Despite the positive outlooks, Patel stressed that uncertainty remains among industry executives, who cited uncertainty over demand, the COVID-19 virus and the regulatory environment. “There were more comments this time about the regulatory environment,” he said. Takeaways from the survey’s special questions:
- • A majority of firms are using an oil price at or above $60 for budgeting purposes. The average response across all firms was $64.
- • Forty-nine percent of exploration and production (E&P) companies said that growing production was their primary goal for 2022.
- • Almost two-thirds of large E&P companies reported having plans to reduce carbon and methane emissions. Larger firms, which make up a sizable amount of U.S. oil production, are much more likely to have these plans in place than smaller firms.
- • On average, support service firms expect the price of their primary service or product to increase by 8.5 percent in 2022 while input prices are expected to rise roughly 10 percent. Increasing demand for their service or product was cited as the main factor that will influence the change in their firm’s selling price.
- • Ninety-five percent of executives said they believe countries will be unable to meet their 2030 commitments for reducing greenhouse gas emissions.
A Ban on U.S. Crude Oil Exports Would Not Lower Gasoline Prices at the Pump – Dallas Fed - High gasoline prices have stimulated interest in what the Biden administration can do to lower the price at the pump. We argue that there is little policymakers can do to address this concern. Calls for a U.S. crude oil export ban, in particular, appear counterproductive.High U.S. fuel prices in October 2021 prompted the Biden administration to consider a variety of policy measures to reduce the prices at the pump after OPEC+ (consisting of OPEC and its oil-producing allies such as Russia) declined to raise its oil production further. Most prominent among these measures have been calls for a release of oil from the U.S. Strategic Petroleum Reserve (SPR) and for a U.S. crude oil export ban.In late November 2021, the administration announced that the Department of Energy would release 50 million barrels of medium-grade crude from the SPR in an effort to lower the price of gasoline, hoping that OPEC+ would not offset this release by cutting its production targets.The 2021 SPR release accelerates to early 2022 an 18-million-barrel sale of crude oil authorized by the Bipartisan Budget Act of 2018 for the fiscal years 2022–25. The release also includes a 32-million-barrel SPR exchange that allows refiners to borrow crude oil starting in December 2021. This oil must be returned with “interest”—in the form of additional barrels of oil—over the following three years.It is unclear what the demand for this oil will be, given that SPR exchanges are designed to deal with temporary supply shortfalls rather than persistent gasoline price increases driven by higher demand. Indeed, there are concerns that oil prices may surge, starting in 2023, when rising demand after the COVID-19 pandemic confronts inelastic supplies following years of underinvestment in oil production.Hence, evidence for the success of previous SPR releases intended to offset temporary oil supply shortfalls (as discussed in “Does Drawing Down the U.S. Strategic Petroleum Reserve Help Stabilize Oil Prices?”) provides little insight about the effects of the latest SPR release, which was prompted by persistent supply shortfalls. Another important concern is how much appetite there will be among U.S. refiners for additional sour medium crude of the type made available through the SPR, given that many refineries typically process other types of oil.While the effectiveness of the recent SPR release on the price of West Texas Intermediate crude oil will continue to be debated, the emergence of the COVID-19 Omicron variant after the SPR release in November 2021 led many forecasters to lower their global demand outlooks for 2022, resulting in a substantial decline in the oil price. As a result, Secretary of Energy Jennifer Granholm, who had broached the subject of an oil export ban in October 2021—describing it as another possible tool—recently signaled that such a measure was off the table. Although the idea of a U.S. crude oil export ban has been shelved for now, it is useful to reflect on its economic merits because this idea may reemerge if pump prices rise again in the coming months.'
U.S. oil producers plan to boost output despite rising costs - Companies in the heart of the U.S. oil patch plan to keep boosting production this year despite rising costs. The Dallas Fed's fourth-quarter 2021 survey of oil-and-gas execs finds that "costs rose sharply for a third straight quarter." However, most expect to keep boosting output as prices and demand have recovered from the pandemic. The Dallas Fed's quarterly survey takes the pulse of companies in the region that includes the Permian Basin in Texas and New Mexico. Anonymous comments take stock of the changing landscape. "The political pressure forcing available capital away from the energy industry is a problem for everyone. Banks view lending to the energy industry as having a 'political risk,'" one respondent said. The big picture: The U.S. Energy Information Administration estimates domestic crude production will average 11.8 million barrels per day (bpd) this year, exceeding 12 million bpd late in the year. That remains below the pre-pandemic peak of around 13 million bpd.
Permian giant Pioneer removes 2022 hedges in bullish oil outlook -- Pioneer Natural Resources Co., the biggest oil producer in the Permian Basin, closed out almost all its hedges for this year, indicating a bullish outlook for crude prices. The move will cost $328 million spread over the course of 2022, Pioneer said in a filing Wednesday, but leaves the company well positioned to bank any uplift in oil prices. The company also said it bought back $250 million of its own shares during the fourth quarter. “The hedge monetization strategically positions PXD for further strength in 2022 oil prices,” RBC Capital Markets analysts Scott Hanold said in a note. U.S. shale drillers use financial instruments like swaps and options to hedge oil and natural gas production and make sure they have enough cash to cover drilling costs and debt payments. The strategy that paid off handsomely during 2020’s crude-price collapse turned painful in 2021 as the market surged. Pioneer incurred losses valued more than $2 billion last year as crude prices rose and hedges acquired during the early days of the pandemic moved underwater.
Pioneer CEO sees oil above $100 as a net negative for shale --Bosses for some of the biggest oil explorers in the Permian Basin say their industry could be hurt if crude climbs above $100 a barrel. With an expectation that oil demand exceeds supply by later in the year or in early 2023, Scott Sheffield, chief executive officer at Pioneer Natural Resources Co., said he sees oil prices to be in the range of $75 to as much as $100. “I hope it stays there,” he said Wednesday in a Goldman Sachs Group Inc. energy conference webcast. Sheffield added that “$110, $120 oil or higher, like what Europe is seeing, is not going to help our industry.” While activity in the U.S. showed no sign of slowing down at the end of last year, public explorers in the world’s biggest shale patch are continuing to preach the new mantra of restricting production growth so they can send more profits back to investors. Diamondback Energy Inc. and Devon Energy Corp. executives said on the same webcast panel that they’d need to see shareholder sentiment change to increase output again. The global oil industry has yet to fully climb back from the boom era of $100 oil since tumbling more than seven years ago. Ed Morse, global head of commodities research at Citigroup Inc., said Wednesday in a Bloomberg Television interview that even if crude climbs back to those levels, it wouldn’t stay there long. Travis Stice, chief executive officer for Diamondback, agreed that oil higher than $100 wouldn’t be good for the industry as it could be seen as a signal for production growth again. But right now, he said shareholders are still saying they don’t want to see oil explorers boost output. “Eighteen months ago, we were in a global apocalypse for the energy sector, and now you’re talking about outsized returns,” Stice said. “We should all pause and recognize the Tectonic shifts that is in capital allocation.”
US oil, gas rig count rises one on week to 707: Enverus data - The US oil and gas rig count rose by one on the week to 707, energy analytics and software company Enverus said Jan. 6, as the eight largest domestic plays experienced flattish activity in the first days of 2022. Oil-directed rigs dropped one for the week ended Jan. 5, leaving 537, while rigs chasing natural gas gained two for a total 170. "I think it's fair to assume that the lack of change in the last couple weeks can be explained, at least partially, by end-of-year seasonality," Taylor Cavey, senior analyst-supply and production for S&P Global Platts Analytics, said. "[But] we're expecting similar growth to 2021 through this year." The domestic oil and gas rig count, which started 2021 at 406 rigs, gained an even 300 rigs over the year. However, "we're starting to see a shift in the rate of rig additions," Cavey said. "Since the beginning of September, majors have increased rigs by 24%, large-cap independents by 17%, small/mid-caps by 19% and privates by 10%. That said, private operators have added the most rigs during this time." Rig counts within individual basins moved little during the week ended Jan 5, with virtually all ticking up or down a single a rig or remaining the same. The biggest change came from the gas-prone Haynesville Shale in East Texas/Northwest Louisiana, which added two rigs for a total 65. Two other basins – the SCOOP-STACK of Oklahoma and the Marcellus Shale largely in Pennsylvania and West Virginia – added one rig. Marcellus rigs now total 38. But the SCOOP-STACK's rig add pushed that play's total to 40, where it had been twice in late 2021 (once at 41). Apart from that, SCOOP-STACK rig levels haven't been above 40 since the first week of March 2020. Two other plays shed one rig apiece – the Permian Basin of West Texas/New Mexico and the DJ Basin mostly in Colorado. That left the Permian at 299 rigs and the DJ at 16 rigs. Three other plays, the Eagle Ford Shale of South Texas, the Bakken Shale of North Dakota/Montana and the Utica Shale mostly sited in Ohio, remained at prior-week activity levels. That left the Eagle Ford at 57 rigs, the Bakken at 32 rigs and the Utica at 10 rigs. This is the third consecutive week for the Eagle Ford and the Utica at those levels.
Strong Earthquakes Spell Trouble For America’s Oil Heartland -A week ago, an earthquake with a 4.5 magnitude struck Texas in the most prolific shale play in the country—the Permian. Days later, another quake shook America’s oil heartland. And seismic activity might eventually force drillers to curb production.The December 27 quake was the strongest in Texas for the last ten years, the Midland Reporter-Telegram reported at the time. It happened at a depth of 4.3 miles near Stanton. And it followed a series of earlier quakes in December.In the middle of December, the U.S. Geological Survey reported four earthquakes in the vicinity of Midland that occurred within 24 hours. The magnitude of these quakes ranged from 2.9 to 3.7, which is not a whole lot, but the number was concerning, especially since it came after more tremors were detected by the University of Texas at Austin’s Bureau of Economic Geology earlier in the year. And after the stronger quake, regulators have stepped in.The Texas Railroad Commission banned the injection of wastewater from well drilling into deep wells just before the big quake. After the big quake, the commission sent out inspectors to the field as the quake had occurred in an area already under investigation for wastewater disposal in deep wells.According to Reuters, if the inspection results in a halt of wastewater disposal in the area, this could lead to the shutdown of some 18 disposal wells that pump a combined 9,600 barrels of wastewater. And if drillers cannot dispose of wastewater, then they cannot really drill.That hydraulic fracturing, or fracking, causes increased seismic activity has been one of the main weapons in the arsenal of anti-fracking activists. Indeed, according to the U.S. Geological Survey, the practice of splitting shale rock formation to extract the oil contained in it does cause increased seismic activity. Only it’s not the fracking itself. It’s the wastewater.Fracking requires enormous amounts of liquid, and this liquid, called wastewater but in fact, a mixture of water and chemicals, needs to be disposed of. Disposal usually takes place in disposal wells, some of them quite deep to hold more wastewater. It is these underground wastewater reservoirs that have been linked to increased seismic activity in some oil regions.Five years ago, for instance, Oklahoma drew media attention because of the significantly increased frequency of earthquakes since the start of the shale boom. The state, one of the big oil producers in the U.S., had negligible seismic activity before 2009 when fracking really took off. By 2016, Oklahoma was recording an average of two quakes a day—what was earlier the average for a year. To date, quakes are just as frequent. According to website Earthquake Tracker, there have been 10 earthquakes in Oklahoma in the last seven days, 68 quakes in the past 30 days, and 2,063 quakes in the past year. Of course, most of these are minor, but due to their increased frequency, they can still cause—and have caused—material damage. The issue even led to litigation seeking insurance coverage against the effects of wastewater disposal from oil wells. Unfortunately for the plaintiffs in this case, the Supreme Court of Oklahoma this month ruled that no insurance coverage exists for bodily injury or property damage caused by wastewater disposal-related seismic activity.
Bureau of Land Management Takes Next Steps to Protect Chaco Canyon | Bureau of Land Management -The Bureau of Land Management today formally proposed to withdraw approximately 351,000 acres of public lands surrounding Chaco Culture National Historical Park. This action, published today in the Federal Register, follows President Biden’s announcement on November 15 of the Department’s new efforts to protect the Chaco Canyon and the greater connected landscape, and to ensure that public land management better reflects the sacred sites, stories, and cultural resources in the region.The proposed withdrawal of federal lands within a 10-mile radius around Chaco Culture National Historical Park would bar new federal oil and gas leasing on those lands. The two-year segregation and potential withdrawal would not affect existing valid leases or rights and would not apply to minerals owned by private, state, or Tribal entities. In additional to today’s proposed withdrawal, the BLM is initiating a 90-day public comment period and will be hosting several public meetings as well as undertaking formal Tribal consultation. The public may submit comments on the proposed withdrawal until April 6, 2022. Comments may be submitted through ePlanning at: https://eplanning.blm.gov/eplanning-ui/project/2016892/510 In early 2022 the BLM and the Bureau of Indian Affairs (BIA) will also be initiating a broader assessment of the Greater Chaco cultural landscape to explore ways the Interior Department can manage existing energy development, honor sensitive areas important to Tribes and communities, and build collaborative management frameworks toward a sustainable economic future for the region.
BLM hosts roundtable discussion about federal funding for orphaned wells - Randy Pacheco, the chief executive officer of the San Juan Basin-based A-Plus Well Service, said the state’s workforce needs to be built up to address the orphaned oil and natural gas wells that dot the landscape in many states including New Mexico. Pacheco was one of the panelists who participated in a roundtable-style webinar discussion about the federal orphaned well program and the Bureau of Land Management’s efforts to implement it. The bureau hosted the webinar, which drew hundreds of people, on Thursday. The bipartisan Infrastructure Investment and Jobs Act that was signed into law in November provided $4.7 billion for clean-up, remediation and restoration at orphaned well sites. That led to the U.S. Department of the Interior releasing initial guidelines on Dec. 17 for states to apply for funding. The states had until Dec. 30 to notify the department if they were interested in applying for a formula grant, which is one of three types of funding opportunities the law made possible. According to the U.S. Department of the Interior, this garnered overwhelming interest and 26 states submitted notices of intent to apply for formula grants. New Mexico was one of those states. A preliminary analysis from that notice of intent process revealed that there are more than 130,000 documented orphaned oil and gas wells in the United States, Interior announced this week. That number is more than two times more than previously estimated. Steve Feldgus, deputy assistant secretary for land and minerals management for the Department of the Interior, said that is “roughly twice the amount of documented orphan wells from just a couple years ago. And that’s not even including the countless numbers we don’t know.” Jason Walsh, the executive director of the BlueGreen Alliance, also emphasized the need for a skilled workforce to address the orphaned wells. He said one of the goals of plugging the abandoned wells is to stop them from emitting methane into the atmosphere, which contributes to climate change. “If we actually want to achieve the methane reduction goal of this program, we need to make damn sure that the workers who were doing the work are skilled enough to actually cap these wells effectively and that we’re not, we’re not seeing any leaks,” he said.
Interior: US has twice as many abandoned oil and gas wells as previously thought -- The U.S. has more than double the amount of abandoned oil and gas wells than previously thought, according to a preliminary analysis by the Interior Department. In a memo Wednesday, the department said there are currently more than 130,000 documented abandoned, or orphaned, wells. Comparatively, a 2019 report from the Interior documented a total of 56,600 orphaned wells across 30 states. Across the entire country they found that the number of abandoned wells in that report ranged from zero to 13,226. The bipartisan infrastructure bill President Biden signed into law in November of last year includes $4.7 billion to restore and plug orphaned wells. In December, the department released guidance on state applications for grants under the program. Since then, the majority of states, 26, have submitted notices of intent to apply for the grants, according to the memo. Nearly every state documented contained orphaned wells. States applying for funding included Alabama, Alaska, Arizona, Arkansas, California, Colorado, Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, Nebraska, New Mexico, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, Texas, Utah, West Virginia and Wyoming, according to the memo. The Interior Department is set to publish the full amount of grant funding each state is eligible to receive in the months ahead, according to the memo. On Thursday, the Bureau of Land Management will host a presentation on its orphaned-well reclamation program. Plugging orphaned wells has been top priority for Interior Secretary Deb Haaland since her nomination. The White House’s budget request for fiscal 2022 also included a proposal to more than double the enacted 2021 budget for orphaned well cleanup and reclamation, which the administration said would create 250,000 union jobs. The White House’s more ambitious climate and social spending bill — which has not passed either chamber of Congress — would also put $41 billion toward environmental remediation, including reclamation of orphaned wells. Its path forward remains unclear after Sen. Joe Manchin (D-W.Va.) said in December that he would not back the package.
Oil and gas drilling is getting dangerously close to our national parks | TheHill - Millions of Americans are spending more time exploring the waters we fish, the national parks we enjoy and wild places near and far. The benefits of these activities are numerous and they breathe life into the many local economies that depend on booming outdoor recreation — this year more so than ever. At the same time, many of these same public lands have long been important to America’s energy portfolio. We believe that communities thrive when energy development is responsibly done, and balanced with the need for healthy lands, thriving fish and wildlife populations, and quality outdoor recreation experiences. Unfortunately, outdated policies prioritize oil and gas development over other public land uses. Spurred by antiquated federal leasing policies — some of which are over a century old — recent energy development proposals threaten the landscapes Americans from all walks of life cherish. While the Biden administration has undertaken a long-overdue review of the federal oil and gas program, we are still grappling with the mistakes of the past and policies that have opened iconic landscapes to drilling and exploration. In two special landscapes — a prized mountain range in southwestern Montana and a unique national monument in eastern Utah — this reality is playing out today. They are case studies for the larger problems with antiquated oil and gas policies for public lands. In southwestern Montana, the Forest Service is weighing an exploratory drilling proposal in the Tendoy Mountains. Oil and gas drilling is not normally associated with this region. Its streams support populations of native Westslope cutthroat trout — the state fish — and are the headwaters of the Beaverhead River, which attracts anglers from around the nation. Moreover, water in the Beaverhead Valley is vital for agricultural operations that, along with outdoor recreation, support the local economy. But that could all change. Several years ago, despite objections from local anglers and hunters, the Bureau of Land Management issued a block of leases in the Tendoys. Some of the leases sold for the minimum allowable bid — just $2/acre — while others sold “noncompetitively,” which means they didn’t sell at auction and were later issued for just $1.50/acre. Meanwhile, in eastern Utah, the Bureau of Land Management is evaluating a proposed drilling project less than half a mile from the western boundary of the National Park Service’s Dinosaur National Monument long after the leases should have expired. The outcome could remove a “no surface occupancy” restriction, allowing for the construction of roads and well pads on public lands that are rich in cultural sites, fossils and wildlife habitat. Energy development here not only poses a direct threat to those resources and Dinosaur National Monument, but could also contribute to air pollution and to water shortages in the Colorado River Basin. The agency estimates that nearly 1 million gallons, approximately three acre feet of fresh water, is needed to drill wells here. Apart from conservation values, there are other good reasons oil and gas leasing near national parks and monuments has sparked controversy. These crown jewels of our public land system generate billions of dollars in revenue every year from outdoor recreation. Further, protected public lands are often the centerpiece of much larger landscapes, providing secure habitat for fish and wildlife and scenic vistas that bring in millions of visitors every year. These drilling proposals underscore fundamental flaws with the federal oil and gas leasing system. When public lands can be leased for as little as $1.50/acre, it’s time to take a step back, scrutinize federal policies and evaluate whether oil and gas development is the highest and best use of our most valuable public lands. This is especially true where there are little to no economically viable reserves of oil and gas. Evaluating the federal oil and gas program is long overdue. Oil and gas development is one of the multiple uses of our public lands — but only one — and public policy that made sense a century ago doesn’t necessarily make sense today. This is critical in light of the administration’s recent decision to resume leasing on public lands because of a court order. Nor can the administration ignore circumstances on the ground, where development proposals threaten places like the Tendoy Mountains and Dinosaur National Monument.
Pipeline expert testifies that state agency is downplaying Line 5 tunnel explosion risk - An oil and gas pipeline expert testifying in a permitting case involving Enbridge’s Line 5 says state energy staffers are downplaying the risk of a potentially catastrophic explosion within a proposed tunnel that would carry oil and propane beneath the Straits of Mackinac.Richard Kuprewicz, the president of Washington-based Accufacts Inc. who has been retained by Indigenous tribes and environmental law firms, provided formal testimony on behalf of Bay Mills Indian Community last month in a permitting case before the Michigan Public Service Commission (MPSC).Kuprewicz disagrees with MPSC staff and other consultants who have said the risk of Line 5 products entering the Great Lakes would be “negligible and unquantifiably low” if housed within the proposed tunnel. The tunnel project, first negotiated under former Gov. Rick Snyder, has been held up by supporters as a fail-safe alternative to Line 5 that currently sits exposed along the lakebed. “From an engineering standpoint, there is a potential for a release into the Straits from the tunnel by way of a catastrophic explosion,” Kuprewicz said in written testimony filed on Dec. 14. “While a risk of release in this manner may be considered low, it is not negligible and, in my opinion, should not be downplayed in such a way by the (MPSC) Staff.”MPSC staff have testified that a tunnel would virtually eliminate the risk of an oil and gas release into the Great Lakes by sheltering the pipeline from anchor strikes and providing an additional layer of protection in the event of a pipeline spill. Kuprewicz countered: “This testimony fails to recognize that both propane and crude oil are highly hazardous and volatile substances and there is always a risk of explosion when handling these substances. When transporting these substances through a pipeline enclosed in a tunnel, the risk of an explosion is enhanced which in turn enhances the probability that the secondary containment vessel will fail.”
Komatsu apologizes for oil spill on Menomonee River An official at manufacturing giant Komatsu on Friday apologized and told Milwaukee elected leaders that the company should have communicated more quickly in the wake of an oil spill on the Menomonee River in early December. "The spill itself is something that should never have happened," said John Koetz, Komatsu's president of surface mining. "We should have done a better job communicating more promptly the details to the stakeholders." Koetz said the company had been focused on communicating with regulators and "putting in place an action plan to address the cleanup." Immediate calls to local entities could have helped limit the oil's spread and mitigate the damage, city officials and others said during a meeting of the Public Safety and Health Committee Friday. City officials urged immediate communication with not only the Mayor's Office and Common Council but also the Port of Milwaukee and 911. Port Director Adam Tindall-Schlicht said the port, other city entities and "community partners" were not notified until about a week after the spill. While Komatsu had to bring in two contractors to respond, Tindall-Schlicht said the port can act immediately with boats and staff that regularly train for such incidents. Fire Chief Aaron Lipski also said the Fire Department should have been contacted, saying by not calling 911 the company missed "an enormous step." "If you have any sort of material release, please call us. Doesn't matter how big or how small, please call us," he said. "This could all have been avoided." The Dec. 3 spill at Komatsu's facility on West National Avenue allowed about 400 gallons of oil to enter a storm drain that goes to the Menomonee River, the state Department of Natural Resources said previously. The spill happened while oil was being transferred between two tanks, Koetz told the committee. The DNR and U.S. Environmental Protection Agency were alerted that day, he said. Efforts to clean up the oil have included launching three or four boats onto the water each day along with a crew on land running a "vacuum truck" to get rid of the sheens and oil pockets while groups of employees have walked the shores to find any areas where residue remains, Koetz said.
Iowa State study shows slow yield recovery after Dakota Access Pipeline construction — Recovering yield production after a pipeline project is a slow process, say researchers at Iowa State University who have been able to watch the process firsthand. When the Dakota Access Pipeline route crossed an ag research area at Iowa State in 2016, it provided a unique opportunity to study the effects of pipeline construction, especially soil compaction caused by heavy machinery, on crop yields. The Iowa State team found yields in the 150-foot pipeline right-of-way were reduced by an average of 25% for soybeans and 15% for corn in the first two crop seasons after construction, compared to undisturbed fields. "Recovering crop yields is a slow process," said Mehari Tekeste, an assistant professor in the Iowa State Department of Agricultural and Biosystems Engineering. In addition to compaction, mixing of the topsoil and subsoil also had negative effects.
New research shows sustained damage to agricultural land near pipelines - Before it began digging into the earth to bury its two-and-half-foot-wide, 1,172-mile-long pipeline in the ground, Dakota Access, LLC promised to restore the land to its previous condition when construction was finished. The pipeline company signed that pledge in its contracts with landowners stretching from North Dakota to Illinois, and the project was approved by the South Dakota Public Utilities Commission under that condition. But farmers in the path of the pipeline have a different story to tell – one of broken promises and sustained damage to their land. Now, there’s data to back them up. Researchers at Iowa State University found that in the two years following construction of the Dakota Access Pipeline corn yields in the 150-foot right-of-way declined by 15 percent. Soybean yields dropped by 25 percent. One of the selling points that energy companies often tout is that pipeline infrastructure is seemingly invisible, buried and forgotten over the long run. The new study, published in the journal Soil Use and Management, seems to contradict that claim.The scientists said the major issue is that soil is compacted by heavy machinery during pipeline construction, and that topsoil and subsoil are mixed together. Taken together, the damage “can discourage root growth and reduce water infiltration in the right-of-way,” Robert Horton, an agronomist at Iowa State and the lead soil physicist on the project, said in a statement. He and his colleagues also found changes in available water and nutrients within the soil. The findings are important for a number of planned pipelines across the Midwest. In one instance, the planned Midwest Carbon Express would be built on land already used for the Dakota Access pipeline, leaving farmers reeling from double impact on their crops.It also adds to other new research on the long-term effects of pipelines on agriculture. In Ohio, using data collected from 24 different farms, researchers recently announced that corn and soybean yields were still being negatively affected three years after the construction of a series of smaller pipelines. “Every pipeline site is going to be slightly different, but there is a general trend of degradation overall,” Theresa Brehm, one of the researchers and a graduate student at Ohio State University, told Grist.For corn, yields were down an average 23.8 percent. “That means [farmers are] losing almost a quarter of the productivity of that land,” Brehem said, adding “it’s not just a 23 percent decrease from one year. There’s actually a longevity impact of that.”
Challenge to Biden Keystone XL revocation dismissed as moot - A federal judge in Texas dismissed a challenge to Biden’s decision to revoke a key permit for the Keystone XL pipeline — saying that the case is moot since the project has already been canceled. Judge Jeffrey Brown cited a brief from pipeline owner TC Energy confirming that it was starting to remove the pipeline’s border-crossing segment and was expected to have done so by November. “The court takes TC Energy at its word that Keystone XL is dead. And because it is dead, any ruling this court makes on whether President Biden had the authority to revoke the permit would be advisory,” the Trump appointee wrote. “Thus, the court has no jurisdiction and the case must be dismissed as moot,” he added. On his first day in office, President Biden revoked a border crossing permit for the Keystone XL pipeline. The move spurred cheers from environmentalists who had long despised the project, which was slated to bring carbon-intensive tar sands oil from Canada to the U.S. But Biden’s move was criticized by numerous Republicans, who argued that it was an attack on fossil fuels. More than 20 states with Republican attorneys-general sued over the decision, but their suit was ultimately rejected on Thursday. .
Judge dismisses lawsuit alleging police used excessive force at Dakota Access Pipeline protest -A federal judge has taken the side of police in a civil lawsuit brought by Dakota Access Pipeline protesters who alleged officers from Morton and Stutsman counties used excessive force on them during a demonstration in 2016. U.S. District Court Judge Daniel Traynor dismissed the case Wednesday, Dec. 29, finding that officers acted reasonably during an hourslong standoff with protesters near the Standing Rock Indian Reservation on Nov. 20, 2016. Protesters alleged that police fired rubber bullets, tear gas and exploding munitions into the crowd, injuring more than 200 in attendance. Officers also sprayed water over protesters on the frigid winter night, according to news reports.. Lawyers representing the Morton County Sheriff's Department, Stutsman County Sheriff's Department and Mandan Police Department said outnumbered officers were worried for their safety and had to use force to disperse the protesters they believed were trespassing. Morton County Assistant State’s Attorney Gabrielle Goter said the defendants are pleased by Traynor's dismissal of the case, adding,"law enforcement was permitted to use less lethal force to protect themselves and others from violent protestors."
Federal oil lease sale planned for early 2022 in North Dakota, Montana after yearlong pause -Oi l and gas leasing on federal lands is expected to resume early this year in North Dakota and Montana after the Biden administration halted the process nationwide almost one year ago. The federal Bureau of Land Management is planning a lease sale for the first quarter of 2022 with 6,850 federally owned mineral acres up for grabs in western North Dakota and eastern Montana. The agency has not yet announced a date, nor has it finalized details of the sale. Oil and gas companies will bid to secure federal leases during the event, and those that are successful will have a 10-year window to obtain a federal permit allowing them to drill. President Joe Biden halted the leasing process upon taking office last January when he issued an executive order announcing a review of the program “to restore balance on America’s public lands and waters to benefit current and future generations.” While that now-concluded review took place, oil- and gas-producing states including North Dakota and Montana sued to try to force leasing to continue.They scored an early victory in June 2021 when a court order required the federal government to resume the sales. The ruling came in a lawsuit joined by a number of states, including Montana. North Dakota filed a separate legal challenge, and a hearing is scheduled for Jan. 12 at the federal courthouse in Bismarck.
Alaska oil and gas regulators fine Hilcorp more than $50,000 for violations -- The state agency that oversees Alaska oil production has upheld two fines against Hilcorp totaling $64,000, for violating requirements needed to prevent spills or leaks in fields in the Cook Inlet region in Southcentral Alaska. The penalties, issued Dec. 29, come on the heels of a $10,000 fine issued against Hilcorp in late November for a violation at the giant Prudhoe Bay fields on the North Slope. The agency called that violation, involving a spill-prevention safety valve that was shut down during oil production, part of Hilcorp’s “substantial history of noncompliance.” In the new orders, the Alaska Oil and Gas Conservation Commission continued to express concerns about Hilcorp’s record. Hilcorp, based in Houston, Texas, operates Alaska’s largest oil field at Prudhoe Bay. Hilcorp is also the leading oil and gas producer in Cook Inlet in Southcentral Alaska. Hilcorp said in a statement on Monday it is taking action to prevent similar violations. Hilcorp has been credited for helping stabilize production at aging oil fields, including at Prudhoe Bay, where it took over as operator from BP in 2020 in a $5.6 billion deal. But critics have said the company is prone to environmental accidents, like gas leaks in Cook Inlet in recent years. Hilcorp has rewarded employees with large bonuses for boosting oil production and the value of the company. In one of the newly issued orders, the three-member commission levied a $39,000 penalty against Hilcorp Alaska for violating three requirements associated with a well drilled in September at the Swanson River field. After the company began drilling the well, it failed to provide the agency with a 24-hour notice so regulators could witness two tests designed to help ensure the safety of the well, according to the three-page order. One of the tests the agency was not able to witness involved the integrity of steel pipes placed inside the well. Hilcorp also did not provide the agency with data about one of the tests, as required, until the agency requested it, the order says. The agency’s concerns included “Hilcorp’s lack of good faith in its attempts to comply with the clearly stated conditions on the (drilling permit),” the potential seriousness of the violation, and the company’s “track record of regulatory non-compliance,” according to the order. Hilcorp did not challenge the penalty, after the agency issued a notice in November. Hilcorp said it would work with its crews to prevent future violations. It said it would inform engineering staff about “differences in processes” involving North Slope and Cook Inlet permits, the order said. The agency took issue with those proposed improvements. It said Hilcorp’s statement about different North Slope and Cook Inlet permitting conditions is “inaccurate” and “troubling.” “Hilcorp’s compliance issues can only be addressed by reading the conditions of approval attached to each permit — regardless of where in the state of Alaska the permitted work occurs,” the order says. Also on Dec. 29, the agency upheld a $25,000 proposed fine against Hilcorp, for failing to conduct a required test associated with blowout-prevention equipment, according to that three-page order. Such equipment is used to prevent an oil spill or gas leak. That violation came at a well in the North Cook Inlet field, during work designed to extend the well’s operational life. Hilcorp did not dispute the agency’s findings. It said it would communicate with workers to prevent future violations.
Will Biden's oil plans unleash an Arctic 'carbon bomb'? - - The Biden administration is facing a critical test about oil drilling in a vast region of the Arctic with so much crude it has been called a “carbon bomb.” The Interior Department has declared that it may stymie drilling in the well-known Arctic National Wildlife Refuge (ANWR) — suspending leases pushed through at the end of the Trump administration. But it’s unclear what it may — or can — do in the 23-million-acre National Petroleum Reserve-Alaska (NPR-A). The decisions that the administration make in the reserve will help shape the future of the Alaska oil and gas industry, which state leaders and industry advocates argue remains vital to the state’s economic well-being. Environmentalists counter any more drilling could irreparably damage a priceless landscape and cause a major uptick in emissions. Yet industry and greens agree on one aspect of NPR-A’s future: They don’t know what to make of the White House’s strategy. “Policies out of the gate, you know, have been a little bit mixed,” said Kara Moriarty, president of the Alaska Oil and Gas Association. President Biden moved quickly in calling for a review of NPR-A’s management plan, called an “integrated activity plan.” Penned with guidance from pro-oil Alaskans during the Trump administration, it expanded oil’s potential for leasing to 82 percent of the reserve, up from 52 percent previously. It also carved into special protections around the Teshekpuk Lake, a coastal wetland treasured for its beauty, rich avian life and herds of caribou. Laura Daniel-Davis, principal deputy assistant secretary for land and minerals management, said in a September memo that the plan was “inconsistent” with the Biden administration’s priorities and warranted greater attention. But she also made it clear that the administration has yet to decide whether to revoke the old management plan. As a stopgap, Interior has frozen the sale of new leases in areas opened by the Trump-era plan. Raising the stakes on what comes next is the oil potential maturing in the NPR-A. The region’s future is under scrutiny with high oil prices and recent efforts by the administration to increase oil supplies. The reserve also has pivoted in recent years from a quiet expanse of federal lands with limited oil activity to the new hot spot on the North Slope. Recent oil and gas discoveries in the reserve — located like ANWR on the Arctic Coast — have driven talk of a renaissance for Alaska’s declining North Slope oil fields.
European court to decide if Arctic drilling violates human rights--The European Court of Human Rights is asking Norway to respond to charges by activists that allowing new oil and gas drilling in the Arctic during an environmental crisis may breach fundamental freedoms. In a document seen by Bloomberg, the court will give the Norwegian government an April 13 deadline to comment, in writing, on the merits of the case which it said may potentially be designated an “impact” case, meaning it could have broad ramifications beyond Norway. Such a designation would substantially shorten the length of time to a ruling, which now can take as long as six years, and could provide climate activists with a new route for holding governments accountable. The move by the court is a victory for the environmental groups and climate activists who filed the application for consideration after repeated defeats in Norwegian courts. “The Court’s request to the Norwegian Government is a significant development, as just one out of ten cases reach this point,” Cathrine Hambro, the lawyer representing the applicants in the case, said in a statement. “A judgment from ECtHR would be important not just for Norway, but also for the pan-European application of the European Convention on Human Rights in climate cases.” An attorney for the government said it maintains that no human rights have been violated. “We look forward to presenting the views of the Norwegian authorities on the case, and to reiterate the legal assessment of the national Supreme Court that the granting of licenses as such do not constitute a breach of any individual rights under articles 2 and 8 of the Convention,” Henriette Busch, a lawyer in the office of the Attorney General for Civil Affairs, said in an emailed response to questions. Climate activists are increasingly turning to the courts to force companies and governments to pay for the damage that lax regulation has caused and to prevent future threats to the environment. Germany’s top court has given national leaders until the end of this year to specify how they plan to limit global warming after finding efforts so far have failed.
Defying U.S. sanctions, Venezuela doubles crude oil exports --Oil exports from Venezuela doubled in December from a year earlier as the country raises production of revenue-generating hydrocarbons in defiance of U.S. sanctions. Shipments averaged 619,000 barrels a day in December. The OPEC-founding member increased exports for a third straight month with the support of ally Iran, which boosted the supply of a key ingredient that aids production. Output touched the crucial mark of 1 million barrels on a single day in December, state-owned oil company Petroleos de Venezuela SA said. Production averaged 625,000 barrels a day during the entire month of November. Exports are rising after benchmark Brent oil rose 50% last year, the largest gain since 2016, as global demand bounces back from the pandemic. The increase also comes at at time when the Organization of Petroleum Exporting Countries and its allies may boost supplies amid a tighter first-quarter surplus than initially expected. Still, it’s unclear if the spike in shipments is sustainable because China, the biggest buyer of Venezuelan oil, continues to crack down on the energy sector. Private fuelmakers in the Asian nation are at the center of allegations of tax violations and non-compliance with environmental rules. There are already signs of problems. Supertankers laden with Venezuelan oil that have sailed to Asia end up floating off the coasts of Singapore and Malaysia for months waiting for Chinese buyers. The U.S. amped up sanctions against the regime of President Nicolas Maduro in 2017, cutting off the South American nation’s access to U.S. refiners. Crippled by the move and with buyers in India and Spain also shunning its oil, Venezuela resorted to unorthodox tactics. It has been disguising and rebranding the oil in order to hide its origins and circumvent sanctions.
Gazprom misses 2021 gas export targets, straining European markets--Russian gas giant Gazprom PJSC missed its own “conservative” target for 2021 exports to Europe, and those capped flows contributed to the continent’s worst energy supply crunch in decades. Gazprom delivered 185.1 billion cubic meters to its main clients abroad, including Turkey, China and Europe, excluding the former Soviet Union nations, Chief Executive Officer Alexey Miller said in a statement on Sunday. That’s 3.2% above 2020 levels, but lower than 2018 and 2019, which were around 200 billion cubic meters. Deliveries to Europe and Turkey were about 177 billion cubic meters last year, according to calculations by Bloomberg News and BCS Global Markets based on Gazprom’s data. That fell short of Gazprom’s forecast for exports to Europe and Turkey of as much as 183 billion cubic meters -- an estimate it stuck to since the spring and maintained at the end of October, even as Europe clamored for more supplies. While Gazprom’s flows to Europe and Turkey were seen below Gazprom’s outlook, they were in line with recent estimates from BCS Global Markets, said Ron Smith, the company’s senior oil and gas analyst in Moscow. “It was clear in recent weeks that high prices had caused a reduction in nominations from its European customer base,” he said. Flows to Europe and Turkey could be even lower -- at some 175.4 billion cubic meters last year, based on assumption that Gazprom’s daily flows to China were more than a third above its contractual volumes in November and December, according to Mitch Jennings, an energy analyst at Sova Capital. Gazprom’s exports have been closely scrutinized as tight supplies in Europe recently sent prices soaring to records. With winter setting in and the region’s stockpiles dangerously low, the Russian company has been sending only as much gas to EU clients as it’s obliged to under long-term contracts, and for months hasn’t offered spot cargoes going into early 2022. It’s unclear why Gazprom has been reluctant to offer spot gas to Europe. While the company has pointed to demand destruction as a result of surging regional prices, European officials say the Russian producer is intentionally withholding in hopes of speeding up approvals for the contentious Nord Stream 2 pipeline. Gazprom doesn’t break export data down by country, making it difficult to estimate 2021 flows to individual markets. However, Miller said that the largest growth in deliveries was to Germany, Turkey and Italy. Flows to China exceeded Gazprom’s contractual obligations throughout 2021, according to Miller.
Gas prices surge in Europe over tight Russian supplies (Reuters) - European gas prices soared more than 30% on Tuesday after low supplies from Russia reignited concerns about an energy crunch as colder weather approaches. A pipeline which normally delivers gas from Siberia to Europe was sending flows from Germany to Poland on Tuesday for the 15th successive day, instead of the usual westward flow into Europe. Supplies of Russian gas from Ukraine to Slovakia were also subdued. Russian energy exports have been in the spotlight during a broader standoff https://www.reuters.com/world/europe/biden-putin-hold-second-call-this-month-ukraine-tensions-simmer-2021-12-30 between Russia and the West, including over a Russian troop buildup near neighbouring Ukraine, which is trying to forge closer ties with NATO. Ambassadors from the NATO military alliance and Russian officials are scheduled to meet next week as both sides seek dialogue to prevent open conflict over Ukraine. Some European Union lawmakers have accused Russia, which supplies more than 40% of the bloc's natural gas, of using the crisis as leverage. They say Moscow has restricted gas flows to secure approval to start up the newly built Nord Stream 2 pipeline, which will supply gas to Germany. Russia has denied the allegations, and says the pipeline will boost gas exports and help alleviate high prices in Europe. It has said it is meeting its contractual obligations on gas deliveries. Moscow also denies U.S. assertions that it is planning an invasion of Ukraine, which it accuses of building up forces in the east of the country. Gas flows via the Yamal-Europe pipeline jumped on Tuesday in the eastward direction, data from German network operator Gascade showed. The benchmark Dutch front-month contract was up 23.20 euros at 95.20 euros per megawatt hour (MWh) by 1429 GMT, with the day-ahead contract up 29.00 euros at 95.50 euros/MWh. Expectations for colder weather in Europe were contributing to upward pressure on prices, but the low Russian gas flows were the main driver, a trader said.
Another LNG cargo appears to divert to Europe -- Traders may have diverted another cargo of liquefied natural gas to Europe instead of China amid the continent’s energy crunch. The vessel Hellas Diana sharply changed course from Tianjin and is likely headed to Europe, according to Mathew Ang, an analyst at Kpler. The ship, which left Corpus Christi, Texas, around Nov. 27, U-turned near Hawaii and is traveling toward the Panama Canal, Bloomberg shipping data showed. At least seven other cargoes originally bound for Asia have been diverted to Europe, where rapidly falling temperatures and energy shortages pushed Dutch TTF prices to record highs last week. The region is attracting more supplies as Asia’s biggest buyers are opting to use their inventories this winter instead of procuring more. Japan-Korea benchmark prices are trading at a rare discount to European rates.
EU NatGas Rally Continues Amid Russian Shipment Plunge; More LNG Tankers Come To Rescue -- European natural gas prices soared for the third consecutive session as Russian shipments to the fuel-starved continent remain muted. Elevated gas prices have slapped a hefty price premium, opening up massive arbitrage opportunities for international commodity traders. Dutch month-ahead gas, the European benchmark, has rallied as much as 42% this week from 65 euros a megawatt-hour to 92 euros on slumping pipeline supply from Russia. For context, this shift is the BTU/Barrel of oil equivalent of a move from $100 to a $180 barrel of oil... On Monday, we first discussed this issue in a commodity note titled "European NatGas Prices Soar As Supply Constraints From Russia Build." Three days later, Russian supplies via Ukraine remain curbed, while the Yamal-Europe pipeline is flowing in the reverse direction from Germany to Poland, according to Bloomberg. Russia's ability to control the European gas market comes as the continent has mismanaged its power grid through green initiatives. With cold weather returning, Europe will deplete even more gas inventories. This may suggest gas is headed back over 100 euros. Europe's energy crisis has been a boon for energy traders who have access to liquefied natural gas (LNG) and LNG cargo vessels. We first reported a flotilla of US LNG tankers were headed to Europe a few weeks ago. Now shipping data from Kpler and Bloomberg show 13 LNG carriers from the U.S. and West Africa are rerouting to Europe instead of Asia. Gas prices in Europe are more expensive relative to Asia, which is why LNG ships are being rerouted to collect a hefty premium. It's called arbitrage.
Gas prices surge again in Europe, leaving some business owners 'terrified' for the future— Europe is facing continued volatility in its wholesale gas markets, prompting concerns across the region that an energy crisis could be about to get even worse. The front-month gas price at the Dutch TTF hub, a European benchmark for natural gas trading, was around 5% higher by 1 p.m. London time on Wednesday, with the price reaching 93.3 euros per megawatt-hour. Contracts for March and April delivery were also up by 5% on Wednesday, according to New York's Intercontinental Exchange. Meanwhile, the European day-ahead price increased to 94 euros per megawatt-hour, according to data from Reuters. While a far cry from the peak of around 182.3 euros seen in December, Wednesday's activity still marked a significant price rise from the end of 2021, when prices dipped below 70 euros per megawatt-hour. Wednesday also saw German day-ahead baseload power prices gain more than 50%, while their French equivalents increased 17% during early trade, according to Reuters. It comes after European benchmark gas prices surged 30% on Tuesday, amid concerns about a cold winter, low gas inventories and Russia constricting supply to Europe. Over the course of 2021, European wholesale gas prices rose by more than 400%, setting new records. "Into January, the price of gas has resumed its ascent, again with the prospect of colder weather driving increased demand for heating and very, very low supplies from Russia, especially via two important pipelines through Poland and Ukraine," Hansen added. "Whether Russia is deliberately keeping supplies down due to Nord Stream 2 pipeline approval delaysand the Ukraine border crisis is difficult to say. But it highlights failed energy and storage policies in Europe and the U.K., which has left the region very dependent on imports of gas, especially given the still unreliable level of power generation from renewable sources." Front-month natural gas contracts in the U.K. were up almost 6% on Wednesday, with contracts for April delivery gaining more than 7%. Meanwhile, day-ahead prices at the National Balancing Point, the U.K.'s benchmark for natural gas trading, rose more than 10% to around £2.25 per therm. The U.K. is particularly reliant on natural gas as an energy source, with more than 22 million households connected to the country's gas grid. Britain's largest single source of gas is the U.K. Continental Shelf, which made up around 48% of total supply in 2020. However, the UCS is a mature source, meaning it has to be supplemented with gas imported from international markets. 'Frightening' prices for U.K. businesses The U.K. has limits on how much suppliers are able to charge consumers for energy, with price caps reviewed by the government every six months. The next review is due in February. Speaking at a press conference on Tuesday, Prime Minister Boris Johnson said the government was "not ruling out" measures such as tax cuts to keep energy prices stable, although he questioned the efficacy of such a move. Trade body Energy U.K. told the BBC in December that it expected energy bills in the country to rise by up to 50% in the spring. The soaring cost of wholesale gas led to the collapse of a number of British energy suppliers last year. Several U.K.-based small and medium sized businesses told CNBC on Wednesday that higher energy bills would deal a fresh blow to their already struggling companies.
Russia’s weak December oil production signals lack of capacity --Russia failed to boost oil output last month despite a generous ramp-up quota in its OPEC+ agreement, indicating the country has deployed all of its current available production capacity. With OPEC+ meeting in two days to consider output policy in the face of the fast-spreading omicron variant, Russia’s lack of growth highlights the limits of the group’s attempt to boost supply if demand continues to recover. Saudi Arabia, Iraq and the UAE can raise output, but others such as Angola, Nigeria and Kuwait are struggling to meet their quotas. Russian companies pumped 46.11 million tons of crude oil and condensate last month, according to preliminary data from the Energy Ministry’s CDU-TEK unit. That equates to 10.903 million barrels a day -- based on a 7.33 barrel-per-ton conversion rate -- and is flat to November. It’s difficult to assess Russia’s compliance with the OPEC+ deal, as the CDU-TEK data don’t provide a breakdown between crude and condensate -- which is excluded from the agreement. If condensate output was the same as in November -- some 930,000 barrels a day -- then daily crude-only production was around 9.973 million barrels, about 37,000 barrels below its December quota. Until recently, Russia ramped up production by restoring operations at wells that were shut-in or idled in spring 2020 as the pandemic shattered global demand. Now any further growth in output will mostly come from newly drilled wells, officials at Lukoil PJSC and Gazprom Neft PJSC said late last year. OPEC+ will meet Jan. 4 to discuss output plans for February as uncertainty remains over the impact of the omicron strain on energy consumption.
Shell sends seismic vessel home after South African court loss- The vessel hired by Royal Dutch Shell Plc to look for potential oil and gas fields is on course to leave South African waters after community groups won a court case to temporarily halt the activity. A judge on Dec. 28 granted local activists an interim interdict blocking any seismic surveys until a ruling can be made on whether further environmental authorization is required. No date was set for that decision, and just a few days later the vessel named the Amazon Warrior headed back around the Cape of Good Hope, according to ship-tracking data compiled by Bloomberg. “Shell has decided to terminate the current contract for the survey vessel early,” a company spokesperson said, citing ongoing legal hearings and a limited weather window to conduct the work. The company said it is considering how it will proceed in the longer term. Protests against the activity started in South Africa in November with the arrival of the Amazon Warrior. It was set to explore an area known as the Wild Coast, a relatively untouched coastline where whales are frequently spotted.
ExxonMobil tallies two new discoveries offshore Guyana– ExxonMobil announced two oil discoveries at Fangtooth-1 and Lau Lau-1 in the Stabroek block offshore Guyana. The Fangtooth-1 well encountered approximately 164 feet (50 meters) of high-quality oil-bearing sandstone reservoirs. The well was drilled in 6,030 feet (1,838 meters) of water and is located approximately 11 miles (18 kilometers) northwest of the Liza field. The Lau Lau-1 well encountered approximately 315 feet (96 meters) of high-quality hydrocarbon-bearing sandstone reservoirs. The well was drilled in 4,793 feet (1,461 meters) of water and is located approximately 42 miles (68 kilometers) southeast of the Liza field. These discoveries will add to the previously announced recoverable resource estimate for the block, of 10 billion oil-equivalent barrels. “Initial results from the Fangtooth and Lau Lau wells are a positive sign for Guyana and continue to demonstrate the potential for the country’s growing oil and gas sector, ExxonMobil and our co-venturers in the Stabroek block,” Fangtooth was drilled by the Stena DrillMAX, and Lau Lau was drilled by the Noble Don Taylor, which are two of six drillships supporting exploration and development drilling across three blocks operated by ExxonMobil offshore Guyana. Separately, progress continues on infrastructure for future field development. The Liza Unity floating production storage and offloading (FPSO) vessel is undergoing hookup and commissioning after arriving in Guyanese waters in October 2021. The Unity is on track to start production in the first quarter of 2022 and has a target of 220,000 barrels of oil per day at peak production. The hull for the Prosperity FPSO vessel, the third project on the Stabroek block at the Payara field is complete and topside construction activities are ongoing in Singapore for planned production start-up in 2024. The Field Development Plan and Environmental Impact Assessment for the fourth potential project, Yellowtail, have been submitted for government and regulatory review. These new projects continue to drive investment in Guyana’s growing economy. More than 3,200 Guyanese are now employed in supporting project activities, and ExxonMobil and its key contractors have spent more than $540 million with more than 800 local companies since 2015.
Damaged pipeline cuts Libya’s oil output by 200,000 barrels per day--Libya expects its oil production to drop by another 200,000 barrels a day over the next week as workers try to fix a damaged pipeline. The latest outage comes less than two weeks after militias shut down the OPEC member’s biggest field, Sharara, causing output to fall by around 350,000 barrels a day. Together, the closures will reduce Libyan production to about 700,000 barrels a day, the lowest in more than a year. Any sustained drop from Libya, which sits on Africa’s biggest oil reserves, could counter efforts by the Organization of Petroleum Exporting Countries and its partners to boost exports. OPEC+ meets on Tuesday and is likely to proceed with another monthly increase of 400,000 barrels a day, according to a Bloomberg survey, as it restores supplies halted during the coronavirus pandemic. Libya’s state-owned National Oil Corp. said late Saturday that the main pipeline linking the eastern Samah and Dhuhra fields to the country’s biggest export terminal, Es Sider, will be shut for maintenance. It said the pipe will be working again in a week. Libya pumped 1.2 million barrels a day on average last year. The NOC has warned it lacks the funds needed to sustain that level of production, let alone reach its target of 2 million barrels per day within six years. The government is trying to attract billions of dollars of investment from foreign energy companies, including France’s TotalEnergies SE and Italy’s Eni SpA. Oil facilities can no longer be properly run because of “the large number of leaks” and “the consequences of illegal closures in the past years,” the NOC said in a statement. It also blamed lawmakers for failing to sign off on a budget for the company for the past two years. Fighting between rival factions in the country, which has been at war or in chaos for much of the past decade, has hindered efforts to increase output. Last month, Libya delayed a presidential election meant to end political divisions and help stabilize the energy sector.
Struggling African producers put OPEC output pledges into question--OPEC made only part of its planned production increase last month, with supplies hampered by disruptions in two of the group’s African members. The Organization of Petroleum Exporting Countries added just 90,000 barrels a day in December, as a boost by Saudi Arabia was offset by losses in Libya and Nigeria, according to a Bloomberg survey. The OPEC+ coalition led by Saudi Arabia and Russia has been restoring production halted during the pandemic, and on Tuesday agreed to press on with further increases at a rate of 400,000 barrels a day. But the process has been hindered as some members struggle with investment constraints and internal instability. The coalition’s travails are helping to support oil prices even as global markets tip back into oversupply, with Brent crude futures trading near $80 a barrel in London on Wednesday. Libya’s production is in turmoil again after the country enjoyed a year of recovery and stabilization. Output began to falter after militias shut the country’s biggest oil field, Sharara, ending the month down by 70,000 barrels a day at 1.06 million. With the outage dragging on -- and compounded by damage to a pipeline connecting the largest export terminal -- production is sinking to just 700,000 daily barrels. In Nigeria, Royal Dutch Shell Plc warned of difficulties with shipments of crude oil from its Forcados terminal -- one of the country’s largest -- during the last 10 days of the month. The Bonny terminal, also operated by Shell, has also had trouble loading cargoes. The country’s output was down 110,000 barrels a day to 1.42 million. Ten of OPEC’s 13 members were permitted to add roughly 250,000 barrels a day last month under the terms of the group’s accord with the wider coalition, but their combined hike amounted to only 150,000. While Angola managed a modest recovery last month, its output is down almost three times the amount required by the agreement.
Iraq approves sale of Exxon oil field to state-owned firm --Iraq approved a state company’s potential purchase of Exxon Mobil Corp.’s interest in a huge oil field in the south of the country. The cabinet on Wednesday approved a proposal for Iraq National Oil Co. to start the process of acquiring the stake, Oil Minister Ihsan Abdul Jabbar said in a statement. He didn’t say if INOC had made a formal offer to Exxon or if it had been accepted. Exxon entered into an agreement to sell its 32.7% stake in the West Qurna-1 field to Chinese firms PetroChina Co. and CNOOC Ltd. in January last year, but failed to get the Iraqi government’s support for the deal. An Exxon spokesperson said via email that the company doesn’t comment on commercial matters. While West Qurna-1 is one of the world’s biggest oil deposits, with expected recoverable reserves of more than 20 billion barrels, it needs billions of dollars of investment. Exxon was among the first Western oil explorers allowed into Iraq in 2010 as the Middle Eastern nation sought to rebuild its energy industry following the fall of Saddam Hussein and years of conflict. Before that, Iraq’s crude bounty had been mostly off limits to foreigners for around 40 years. But the company soured on West Qurna amid tough contractual terms, OPEC supply constraints and ongoing political instability.
OPEC+ agrees oil output hike from February as omicron Covid cases soar --An influential group of some of the world's largest oil producers agreed on Tuesday to stick to its planned increase in oil production from February as energy investors weigh the potential impact of soaring omicron Covid cases. OPEC and its non-OPEC allies, known collectively as OPEC+, decided to raise its output target by 400,000 barrels per day from next month. The move had been broadly expected given U.S. pressure to boost supply and no major new Covid restrictions. Led by OPEC kingpin Saudi Arabia and non-OPEC leader Russia, the energy alliance is in the process of unwinding record supply cuts of roughly 10 million barrels per day. The historic production cut was put in place in April 2020 to help the energy market after the coronavirus pandemic cratered demand for crude. "Oil prices are still hovering around $80 a barrel, that's probably higher than what [U.S. President] Joe Biden wants," Herman Wang, managing editor of OPEC and Middle East news at S&P Global Platts, told CNBC's "Street Signs Europe" on Tuesday. "And then you look at the resilience of the market so far to the omicron variant, which OPEC, of course, has dismissed as mild and short-lived. So, there's a lot of optimism around what demand is going to do even though there are these predictions of looming oversupply in the first quarter," Wang said. "I think we are going to look for OPEC+ to continue with their 400,000 barrel per day increase at this meeting. What they are going to do at the February meeting and the March meeting, that is a problem for another time." International benchmark Brent crude futures traded at $79.87 a barrel during afternoon deals in London, up around 1.1%, while U.S. West Texas Intermediate futures stood at $76.89 a barrel, roughly 1% higher. Oil prices climbed more than 50% last year, with energy investors optimistic that the highly infectious omicron variant may be less severe than feared. That's despite Covid infections reaching new record highs, with the U.S. reporting a global daily record of over 1 million infections in just 24 hours.
OPEC to increase oil output as 2022 demand confidence grows--OPEC and its allies are expected to revive more oil supplies when they meet next week, underscoring the group’s optimism in the outlook for global demand. The 23-nation alliance led by Saudi Arabia and Russia is likely to proceed with another modest monthly hike of 400,000 barrels a day as it restores production halted during the pandemic, according to a Bloomberg survey. Several national delegates also said they expect the boost -- due to take effect in February -- will go ahead. The Organization of Petroleum Exporting Countries and its partners see global demand continuing to recover this year, taking only a “mild” hit from the omicron variant. Their confidence is being validated as busy traffic across key Asian consuming countries and dwindling crude inventories in the U.S. buoy international prices near $80 a barrel. “The market can take the extra oil, as long as omicron or a macro downturn don’t crush demand again,” said Bob McNally, president of consultant Rapidan Energy Group and a former White House official. Fifteen of 16 analysts and traders surveyed by Bloomberg predicted the output increase will be approved when the coalition gathers online on Tuesday. Indicators on fuel consumption suggest the barrels can be absorbed, with all but one major Asian country registering a rise in mobility month-on-month, according to data compiled by Bloomberg using Apple Inc. statistics to Dec. 27. Adding supplies would also show that Riyadh continues to be mindful of the inflationary risks afflicting their biggest customers, having acquiesced last month to U.S. President Joe Biden’s calls for extra production to cool runaway gasoline prices. While that surprise move was initially read as bearish by traders, Saudi Energy Minister Prince Abdulaziz bin Salman helped to shore up market sentiment by resolving that OPEC’s meeting would remain technically “in session” -- allowing it to reverse the output increase at short notice if needed.
Oil bulls return as the threat from Omicron recedes: Kemp (Reuters) - Portfolio investors have started to rebuild bullish positions in the oil market, reassessing earlier fears about the likely impact of the Omicron variant of coronavirus on major economies and passenger aviation in 2022. Hedge funds and other money managers purchased the equivalent of 54 million barrels in the six most important petroleum futures and options contracts in the week to Dec. 28 (https://tmsnrt.rs/3JE0yqq). Funds have purchased a total of 70 million barrels over the two most recent weeks, after selling 327 million over the previous 10 weeks, according to records published by regulators and exchanges. Last week's buying was the fastest since August, and among the most rapid rates for more than a year, signalling a sharp turnaround from previously bearish investor sentiment. Purchases were split fairly evenly between the establishment of new bullish long positions (+32 million barrels) the closure of previous bearish short ones (-22 million). The ratio of long to short positions climbed to 4.86:1 (in the 64th percentile for all weeks since 2013) up from 3.83:1 (47th percentile) two weeks earlier. In the most recent week, funds were major buyers of Brent (+33 million barrels) and NYMEX and ICE WTI (+15 million) with smaller purchases of European gas oil (+7 million). There were only small purchases of U.S. heating oil (+1 million barrels) and small sales of U.S. gasoline (-2 million). The pattern of buying, with its concentration on crude and middle distillates, is consistent with a continued upswing in the macroeconomic cycle despite the rapid spread of Omicron. Funds are calculating the pessimism about the impact on the global recovery and international quarantines that pressured oil prices in November and early December is no longer justified. Portfolio managers are calculating the continued recovery in oil consumption, including jet fuel, coupled with limited production increases by OPEC, its allies, and U.S. shale firms, will keep prices trending higher in 2022.
Oil Futures Up Early Monday - In early activity on the first trading day of 2022, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange powered higher, lifting the international benchmark above $78 per barrel (bbl) amid reports suggesting Organization of the Petroleum Exporting Countries and Russia-led partners expect the omicron-led disruption to global oil demand to be isolated to the first quarter amid better mitigation efforts to soften the pandemic's impact on the economy and public life. Oil complex kicked off 2022 on firm footing despite ongoing challenges surrounding the fast-paced spread of the Omicron variant over the holiday weekend. U.S. airlines cancelled more than 2,000 flights on Saturday and Sunday, bringing the total cancellations over the past ten days to nearly 14,000 due to shortfalls in staffing crews and severe winter weather in parts of the country. Flight data published by Transportation Security Administration showed 1,616,316 passengers were able to pass through domestic airports on the first day of 2022 -- about 30% below pre-pandemic levels. Fueling labor shortages is the rampant spread of the new COVID-19 variant announced in late November that appears to be less lethal but more transmittable compared with previous strains. The United States recorded more than 400,000 new daily COVID infections over the holiday weekend, shattering the previous record. The same trendline is seen across European Union where new infections set daily records in the United Kingdom, France, and Italy, although hospitalizations have not yet shown a marked increase. Despite this backdrop, OPEC+ is reported to be optimistic about a demand recovery in 2022 with the group's technical panel releasing a document showing the Omicron impact is likely to be short-lived. Manufacturing and service sectors across advanced and emerging economies have effectively weathered the previous waves of COVID-19 pandemic, with the public less likely to pullback on economic activity the way it did during the first outbreak. Additionally, U.S. and European governments rolled-out vigorous booster programs and at-home rapid testing that should help elevate the pressure on hospitals. That is one of the many reasons why OPEC+ is expected to increase production by 400,000 barrels per day (bpd) next month in line with the previously agreed quotas. The group meets on Tuesday (Jan. 4). In early trade, West Texas Intermediate February futures advanced $0.26 to trade near $75.47 bbl and March Brent gained $0.41 to near $78.19 bbl. NYMEX February RBOB futures rallied 1.5 cents to $2.2396 gallon, with the new front-month ULSD contract adding 1.95 cents to $2.3448 gallon.
Oil Settles Higher on 2022 Demand Optimism (Reuters) - Oil settled higher on Monday on hopes of further demand recovery in 2022, despite OPEC+ looking set to agree to another output increase and persistent concerns about how rising COVID infections might affect demand. OPEC and its allies, or OPEC+, are expected on Tuesday to agree to the output hike. The Omicron coronavirus variant has brought record case counts and dampened New Year festivities worldwide, with more than 4,000 flights cancelled on Sunday. "The monthly OPEC + meeting that will be developing during the next couple of days is more likely to prove bullish than bearish since several of the OPEC members are having difficulty achieving assigned quotas," Brent crude settled up $1.20, or 1.5%, at $78.98 a barrel at 12 p.m. EST (1700 GMT), having earlier risen as high as $79.05. U.S. West Texas Intermediate (WTI) crude settled up 87 cents at $76.08 a barrel. "Infection rates are on the rise globally, restrictions are being introduced in several countries, the air travel sector, amongst others, is suffering, yet investors' optimism is tangible," Many U.S. schools that would normally welcome students back to classrooms on Monday are delaying their start dates, scrambling to test pupils and teachers and preparing, as a last resort, to return to remote learning as record numbers of COVID-19 cases from the Omicron variant sweep the country. Oil gained some support from an outage in Libya. Oil output will be cut by 200,000 barrels per day for a week due to pipeline maintenance.
WTI, Brent Futures Add to Gains - Oil futures nearest delivery continued higher early Tuesday after the technical committee for the Organization of the Petroleum Exporting Countries signaled tighter supply-demand fundamentals for the first quarter as unplanned supply disruptions in a number of smaller oil producers, including Libya and Ecuador, offset a tsunami of Omicron infections in major oil-consuming countries. Multiple sources have indicated OPEC+ ministers are set to agree today on a 400,000-barrel-per-day (bpd) production increase for February -- in line with their roadmap drafted in July last year to restore output they shut-in in response to the global pandemic. The agreement envisaged monthly increases of 400,000 bpd through April, and then at 432,000 bpd every month until all of the 9.7 million bpd they cut two years ago is returned. The increases must be approved each month and can be paused or deepened should market conditions warrant an adjustment. This month, the consensus is calling for the group to go forward with their agreement despite record-breaking numbers of Omicron infections in oil-consuming behemoths, like the United States and European Union. The Omicron tsunami have triggered severe disruptions to global air travel that is impacting jet fuel demand, with over 14,000 flights have been grounded recently in the United States alone. OPEC+ technical committee, however, expects those disruptions to be transient as governments around the world have learned how to cushion the blow from the pandemic and consumer spending remained solid at the end of 2021. This has been joined with underproduction by a number of African oil producers that have struggled to raise their output in line with agreed quotas and unplanned supply disruptions in countries like Libya and Ecuador. Libya, in particular, has recently seen its oil production drop sharply, with over 300,000 bpd from the country's largest oil field at Sharara shut-in by an insurgency and another 200,000-bpd shut-in over the weekend due to a leaking pipeline that carries crude to the nation's crude oil terminal El Sider. Combined, these closures have reduced Libyan oil production to about 700,000 bpd -- the lowest in more than a year. In Ecuador, soil erosion caused by deforestation in the Amazon have closed the nation's two major oil pipelines that carry crude oil across the Andes. . In Africa, Nigeria and Angola have consistently underproduced their OPEC quotas, seemingly unable to raise production further, with operations plagued by years of underinvestment and political turmoil. This underproduction could become increasingly problematic going forward, and lead to sharply higher oil prices later this year or in 2023, especially if Omicron's dent to global oil demand remains limited to jet fuel as the most recent estimates and analyses show occurred at the end of 2021. The internal document released by the OPEC+ technical committee already showed a much smaller surpluses at the beginning of 2022 compared with the previous projections. The committee pegged the first-quarter surplus at 1.4 million bpd, down markedly from a 3.1 million bpd oversupply seen last month when data on Omicron was still limited. In 2022, the committee put the surplus at 1.4 million bpd, down from its previous forecast of 1.7 million bpd. Near 7:30 a.m. ET, West Texas Intermediate February futures gained $0.25 to $76.33 per barrel, and March Brent added $0.26 to trade near $79.23 per barrel. NYMEX February RBOB futures surged 1.48 cents to near $2.2713 gallon, with the front-month ULSD contract trading near $2.3760 gallon, 1.87 cents higher on the session.
Oil prices rise on skepticism of OPEC’s production plan--Oil climbed amid skepticism about whether OPEC and its allies can successfully raise output as much as they intend. Futures in New York rose as much as 2% and the global benchmark traded above $81 a barrel on Wednesday. OPEC+ on Tuesday stuck to its plan to add 400,000 barrels a day next month after it cut estimates for a surplus in the first quarter. However, recent history shows the group has been severely limited in how much it can boost output -- adding just 90,000 barrels a day in December, according to a Bloomberg survey. “Outside of Saudi Arabia, OPEC is seeing a challenge in increasing production,”. “The more months we roll forward and OPEC is unable to demonstrate adding 400,000 barrels a day of supply, it could start to spook the market.” Adding to worries about supply constraints, U.S. crude stockpiles fell 2.14 million barrels last week, according to a Energy Information Administration report on Wednesday. Inventories dropped for a sixth straight week. Oil ended 2021 on a strong footing as a string of global supply outages boosted sentiment. Consultant Facts Global Energy said the disruptions -- which in recent weeks have included Ecuador, Libya and Nigeria -- totaled close to 1 million barrels a day. Though concerns about the hit to demand from the omicron virus variant have eased and major economies continue to rebound from the pandemic, there’s still some uncertainty in Asia. Hong Kong announced tighter curbs on Wednesday. Earlier this week, the small Chinese city of Yuzhou went into lockdown after a few virus cases, while Xi’an has seen prolonged restrictions after a flare-up. “The market is clearly concentrating on the price supportive news,” said Barbara Lambrecht, an energy analyst at Commerzbank AG. “Whether the optimism will suffice to ignore the looming supply surplus in any lasting fashion will presumably depend chiefly on the omicron wave.” West Texas Intermediate for February delivery rose $1.52 to $78.51 a barrel at 1:08 p.m. in New York. Brent for March settlement added $1.30 to $81.30 a barrel. The actual volume that OPEC+ adds to the market in February could be less than planned, due to some members struggling to hit production targets. Energy Aspects Ltd. co-founder Amrita Sen predicts the alliance will increase output by 250,000 barrels a day next month.
Oil ends up at $80/bbl as OPEC+ sticks with Feb output hike - Global benchmark Brent crude jumped on Tuesday to $80 a barrel, its highest since November, as OPEC+ agreed to stick with its planned increase for February based on indications that the Omicron coronavirus variant would have only a mild impact on demand. Brent futures settled up $1.02, or 1.3%, at $80 a barrel, almost back to the level they were at on Nov. 26 when reports of the new variant first appeared, sparking a more than 10% decline in prices on that day. U.S. West Texas Intermediate (WTI) crude rose 91 cents, or 1.2%, to $76.99. "The oil market is bullish today as a result of optimism sourced from today's monthly OPEC+ meeting, which is helping oil prices trade higher," said Rystad Energy's head of oil markets, Bjornar Tonhaugen. OPEC+, comprising of the Organization of the Petroleum Exporting Countries and allies, agreed to stick to its planned increase of 400,000 barrels per day (bpd) in oil output in February. Its decision reflects easing concerns over a big surplus in the first quarter, as well as a wish to provide consistent guidance to the market. Crude stockpiles in the United States, the world's top consumer, were forecast to have dropped for a sixth consecutive week, analysts polled by Reuters estimated ahead of weekly industry data due at 4:30 p.m. EST (2130 GMT), followed by the government's report on Wednesday. The White House welcomed the decision by OPEC+ to continue increases in production which will help facilitate economic recovery, a spokesperson said. "It appears that the market is making the bet that Omicron is the beginning of the end of COVID-19," said Scott Shelton, an energy specialist at United ICAP. In Britain, people being hospitalised with COVID-19 were generally showing less severe symptoms than previously. While in France, the finance minister said some sectors were being disrupted by the surge of the fast-spreading Omicron variant, but there was no risk of it "paralysing" the economy and stuck to a forecast of 4% GDP growth in 2022.
Oil Futures Waver on Mixed API Data -- Nearby delivery month oil futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange edged higher in early trade Wednesday after the American Petroleum Institute reported a larger-than-expected drop in U.S. commercial crude oil inventories during the final week of 2021 accompanied with massive builds in gasoline and distillates fuel supplies amid early signs of Omicron-led destruction to domestic fuel demand. DTN Refined Fuels Demand data showed gasoline demand in the United States slumped 18.4% from the previous week during the final week of 2021, while sliding more than 9% below pre-pandemic level in 2019. On Monday, United States recorded more than one million new COVID-19 infections, a global record high during the pandemic declared in March 2020. Exponential growth offers more evidence that Omicron is better at infecting people who have been previously vaccinated or infected with earlier strains of the SARS-2 virus, which is giving it a larger pool of people to infect. A similar trend is found in diesel consumption, with DTN's Refined Fuels Demand data showing demand for the middle of the barrel fuel declining more than 20% during the week-ending Dec. 31, although up 6% relative to the same week in 2019. Continued rebound in domestic manufacturing, surging imports and popularity of online shopping have offered solid support for diesel demand throughout the pandemic. The data also showed distillate inventories jumped 4.38 million bbl, well above calls for a gain of 400,000 bbl. Commercial crude oil inventories tumbled 6.432 million bbl during the week ended Dec. 31, more than twice calls for a 3 million bbl drop. If realized in Energy Information Administration data to be released later this morning, the draw would press domestic crude oil inventories to about 10% below the five-year average. Separately, overnight data from Eurozone showed economic activity across the 19-nation bloc dropped to a nine-month low 53.3 reading in December that, while still showing growth, resumes a downtrend seen at the start of last year due to renewed COVID shutdowns. In early trade, West Texas Intermediate February futures gained $0.30 to $77.28 bbl, and March Brent added $0.34 to $80.35 bbl. NYMEX February RBOB futures edged higher to $2.2779 gallon, with the front-month ULSD contract gaining to $2.4211 gallon, 1.20 cents higher from Tuesday's settlement.
WTI Slides Back Below $78 As Gasoline Demand Plunges -Oil prices extended their recent gains overnight with WTI topping $78 after very mixed data from API. The recent rally comes as OPEC+ continue to drip-feed production output at 400,000 barrels a day, as the cartel estimates a crude surplus in the first quarter.Concerns about the Covid-19 omicron variant effect on demand may be somewhat overblown if it broadly continues to yield less-severe illness, which bodes well for crude-oil demand in the long term.Still Bloomberg Intelligence Senior Energy Analyst Vince Piazza may face near-term headwinds from U.S. monetary policy. API
- Crude -6.432mm (-3.65mm exp) - biggest draw since Aug 2021
- Cushing +2.268mm
- Gasoline +7.061mm - biggest build since April 2020
- Distillates +4.38mm - biggest build since June 2021
DOE
- Crude -2.144mm (-3.65mm exp)
- Cushing +2.577mm - biggest build since Feb 2021
- Gasoline +10.128mm - biggest build since April 2020
- Distillates +4.418mm - biggest build since June 2021
Airline staffing shortages and weather disruptions forced thousands of flight cancellations over the past two weeks appear to have impacted product inventories dramatically, along with the plunge in gasoline demand.. US gasoline demand fell by the most since April 2020... Graphs Source: Bloomberg Cushing crude stocks grew another week, making it now two months of growing inventories at the commercial storage hub. The storage depot is now sitting at the largest volume since July, after the biggest increase since February.Crude production was flat week over week, at its highest since May 2020...
Oil rallies even as OPEC+ boosts output, US fuel demand dips - Oil prices rose on Wednesday, extending gains even after OPEC+ producers stuck to an agreed output target rise for February and U.S. fuel inventories surged due to sliding demand as COVID-19 cases spiked. Brent crude futures ended up 80 cents, or 1per cent, to US$80.80 a barrel. U.S. West Texas Intermediate (WTI) crude futures closed up 86 cents, or 1.1per cent, to US$77.85. The market pared gains late in the day after the release of minutes from the latest U.S. Federal Reserve meeting that showed policymakers may have to raise rates more quickly than markets anticipated. Oil dropped, following other risk assets like stocks. U.S. crude stocks dropped by 2.1 million barrels, owing in part to tax incentives for producers to reduce inventories before year-end. However, gasoline inventories jumped by more than 10 million barrels, and stocks of distillates rose by 4.4 million barrels. Analysts cited soft demand during the last week of 2021 as people hunkered down due to the Omicron variant of the coronavirus. [EIA/S] The United States reported nearly 1 million new coronavirus infections on Monday, the highest daily tally of any country in the world and nearly double the previous U.S. peak set a week earlier. Overall product supplied, a proxy for demand, fell sharply, though the last four weeks has seen stronger demand than the same period two years ago before the pandemic's onset. "Implied product demand – particularly for gasoline – slumped, suggesting that the public were cautious about travel in the wake of surging cases of the Omicron variant. These fears are likely to persist for a few weeks yet," OPEC+ producers, which include members of the Organization of the Petroleum Exporting Countries along with Russia and others, on Tuesday agreed to add another 400,000 barrels per day of supply in February, as they have done each month since August. Still OPEC+ will probably struggle to reach that target, as members including Nigeria, Angola and Libya face difficulties ramping up production, Barclays analysts said in a note. Even as the group boosts targets, "actual incremental supplies are likely to be much smaller, similar to the demand effect from Omicron," the bank wrote.
Oil slips from one-month high after US fuel inventory surge - Oil prices lost ground on Thursday, falling from their highest levels in more than a month after U.S. fuel stockpiles surged amid declining demand. The global benchmark Brent crude futures fell 63 cents, or 0.8%, to $80.17 a barrel, as of 0727 GMT. U.S. West Texas Intermediate (WTI) crude futures lost 58 cents, or 0.8%, to $77.27 a barrel. U.S. crude oil stockpiles fell last week while gasoline inventories surged more than 10 million barrels, the biggest weekly build since April 2020, as supplies backed up at refineries due to reduced fuel demand. “Implied product demand – particularly for gasoline – slumped, suggesting that the public were cautious about travel in the wake of surging cases of the Omicron variant,“ Caroline Bain, chief commodities economist at Capital Economics said in a note. “These fears are likely to persist for a few weeks yet.” The United States reported nearly 1 million COVID-19 cases on Monday, setting a global record as the spread of the Omicron variant showed no signs of slowing, while heavy snow also disrupted traffic. As well, minutes from a U.S. Federal Reserve meeting that showed policymakers may raise rates more quickly than markets anticipated weighed on riskier assets such as oil. On Wednesday, Brent and WTI futures climbed to their highest since late November as a decision by OPEC+ to increase supplies signalled easing concern of a big surplus in the first quarter. OPEC+, a group that includes members of the Organization of the Petroleum Exporting Countries, Russia and other producers, agreed on Tuesday to add another 400,000 barrels per day (bpd) of supply in February, as it has done each month since August. “Our reference case now assumes the alliance will fully phase out the remaining 2.96 million bpd of oil production cuts by September 2022,“ JP Morgan analysts said in a note. “With signs of demand withstanding the Omicron variant, low stocks and increasing market vulnerability to supply disruptions, we see the need for more OPEC+ barrels,“ the bank said. JP Morgan forecast Brent prices to average at $88 a barrel in 2022, up from $70 last year.
WTI, Brent Up 2% on Kazakhstan Turmoil, Alberta Deep Freeze -- Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange settled higher for the fourth consecutive session Thursday, finding strong buying support from political unrest in non-OPEC+'s second largest producer, Kazakhstan, where antigovernment protests halted operations at the nation's key oil fields along with supply disruptions in a number of Africa's oil producing nations that undermine the ability of OPEC+ to raise supply quotas. Kazakhstan's antigovernment protests that were sparked by soaring fuel prices reached the nation's largest oil field, Tengiz, on Thursday, affecting nearly 800,000 barrels per day (bpd) in daily crude oil production. Contractors disrupted train lines and halted operations in support of protests taking place across the central Asian country. Dozens of people were killed Thursday at the capital, Almaty, and Russia's President Vladimir Putin sent military troops to quell protests that turned violent overnight. The situation in Kazakhstan is becoming increasingly tense. The country produces around 1.6 million bpd and was called out at this week's OPEC+ meeting for low compliance with output quotas. For February, the quota for Kazakhstan is 1.589 million bpd, per the group's decision. Further supporting the oil complex, a Bloomberg survey published Thursday morning found OPEC added only 90,000 bpd in new production in December against a quota to increase output by 250,000 bpd last month, which the cartel is entitled to under their deal with Russia-led producers. The output has been severely limited by Africa's largest producers Nigeria and Angola, that combined underproduced to a tune of 250,000 bpd in recent months. Furthermore, Libya's crude production declined sharply at the start of a new year, with over 300,000 bpd from the country's largest oil field at Sharara shut-in by an insurgency and another 200,000 bpd shut-in over the weekend due to a leaking pipeline that carries crude to the nation's crude oil terminal El Sider. Combined, these closures have reduced Libyan oil production to about 700,000 bpd -- the lowest in more than a year. Also on Thursday, TC Energy said it has resumed operations at its 590,000 bpd Keystone oil pipeline following two days of unplanned maintenance amid frigid temperatures affecting western Canada. Temperatures in Alberta plunged to minus 31 degrees Fahrenheit Wednesday night. Most of Alberta is under an extreme cold warning that is expected to last until the weekend. Canadian heavy crude prices tightened as traders anticipated oil sands production issues relating to the cold snap. On Wednesday, Western Canada Select heavy blend crude narrowed its discount to WTI futures to $12.10 barrel (bbl). On the session, front-month West Texas Intermediate futures rallied $1.61 to $79.46 bbl settlement -- a fresh 6 1/2-week high. International crude benchmark Brent for March delivery advanced $1.19 to $81.99 bbl. NYMEX February RBOB futures surged 1.22 cents to $2.3043 gallon, with the front-month ULSD contract gaining to $2.4777 gallon, up more than 3 cents on the session.
Oil Rallies on Kazakhstan Turmoil - Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange extended higher in early trade Friday following overnight reports that antigovernment protests in Kazakhstan, the second largest non-OPEC oil producer in OPEC+, disrupted operations at the nation's key oil fields, while investors in the United States are waiting for the last month's employment data for clues on the economy's performance at the end of last year. In early trade, front-month West Texas Intermediate futures advanced $0.57 to $79.45 per barrel (bbl), and international crude benchmark Brent for March delivery was up $0.67 to $82.69 bbl. NYMEX February RBOB futures surged 2.26 cents to $2.3329 gallon, with the front-month ULSD contract gaining to $2.4939 gallon, up more than 1.51 cents on the session. WTI, Brent futures rallied to pre-Omicron levels this week amid political turmoil in one of the world's largest oil producer, Kazakhstan, that have disrupted production from the nation's largest oil field, Tengiz. Kazakhstan currently produces around 1.6 million barrels per day (bpd) and was called out at this week's OPEC+ meeting for low compliance with its output quotas. For February, the quota for Kazakhstan is 1.589 million bpd, per the group's decision. Kazakhstan President Kassym-Jomart Tokayev ordered security forces this morning to "kill without warning" to crush the protests that have paralyzed the former Soviet republic and reportedly left dozens dead. Further supporting the oil complex, a Bloomberg survey published this week found OPEC added only 90,000 bpd in new production in December against a quota to increase output by 250,000 bpd last month, which the cartel is entitled to under their deal with Russia-led producers. The output has been severely limited by Africa's largest producers Nigeria and Angola that combined underproduced to a tune of 250,000 bpd in recent months. In outside markets, investors are waiting for the release of U.S. employment report that is expected to show 400,000 new jobs were added by the labor market last month. Hiring is expected to have picked up before the latest surge in Omicron-related infections meaningfully impacted the labor market. The unemployment rate is expected to slip 0.1% to 4.1%, a new pandemic-era low. ADP's December employment report, which measures the change in employees on private companies' payrolls, said that 807,000 jobs were added last month, significantly above the 400,000 expected by economists. .
Oil slips, but set for weekly gain on Kazakh, Libyan concerns -- Oil prices settled lower on Friday, as the market weighed supply concerns from the unrest in Kazakhstan and outages in Libya against a U.S. jobs report that missed expectations and its potential impact on Federal Reserve policy. Brent crude settled down 24 cents, or 0.3%, to $81.75 a barrel, while U.S. West Texas Intermediate (WTI) crude was down 56 cents, or 0.7%, at $78.90 a barrel. Brent and WTI were on track for gains of about 5% in the first week of the year, with prices at their highest since late November, spurred on by the supply concerns. "Employment data injected a question mark into where we are going from here and Omicron fears have crept back into the market," said John Kilduff, a partner at Again Capital Management. In Kazakhstan's main city Almaty, security forces appeared to be in control of the streets and the president said constitutional order had mostly been restored, a day after Russia sent troops to put down an uprising. The protests began in Kazakhstan's oil-rich western regions after state price caps on butane and propane were removed on New Year's Day. Production at Kazakhstan's top oilfield Tengiz was reduced on Thursday, its operator Chevron Corp said, as some contractors disrupted train lines in support of protests taking place across the central Asian country. Production in Libya has dropped to 729,000 barrels per day from a high of 1.3 million bpd last year, partly due to pipeline maintenance work. A barrel of oil for delivery in March was selling at a discount of as much as 70 cents to a barrel for delivery in February, the highest since November. Both benchmarks were up $1 earlier in the session but oil, along with stock markets and the dollar, came under pressure after U.S. employment figures missed expectations. U.S. employment in the country increased less than expected in December amid worker shortages, and job gains could remain moderate in the near term as spiralling COVID-19 infections disrupt economic activity. Meanwhile, supply additions from the Organization of the Petroleum Exporting Countries, Russia and allies - together called OPEC+ - are not keeping up with demand growth. OPEC's output in December rose by 70,000 bpd from the previous month, versus the 253,000 bpd increase allowed under the OPEC+ supply deal which restored output slashed in 2020 when demand collapsed under COVID-19 lockdowns. Government data this week also showed that crude inventories in the United States, the world's top consumer, have fallen for six consecutive weeks by the end of the year to their lowest since September. Extreme frigid weather in North Dakota and Alberta is also expected to hurt production in the region and led operators to shut the 590,000 bpd Keystone Pipeline for a short period of time earlier in the week. U.S. oil rigs rose one to 481 this week, their highest since April 2020, energy services firm Baker Hughes Co said in its closely followed report.,
Afghanistan Has Become the World’s Largest Humanitarian Crisis Four months after the Biden Administration withdrew U.S. troops, more than twenty million Afghans are on the brink of famine. On a recent afternoon in a Kabul hospital, seventeen babies lay beside one another on small beds, their bony elbows touching. Some of them, pink and a little plumper, cried and wriggled as nurses rushed by. Others, their pallid skin shades of blue and gray, were still—save for their skeletal rib cages silently rising and falling. The infants often weigh less than four pounds when they arrive in the neonatal intensive-care unit. Pregnant women across Afghanistan are increasingly malnourished, and their bodies, unable to carry their babies to full term, give birth prematurely. Meagre diets then leave new mothers unable to breast-feed. “A lot of babies are premature,” Abdul Jabad, a pediatrician in his late twenties, told me. “Some survive. Some not.” Two or three infants occupied I.C.U. beds meant for a single child, owing to a surge in cases, Jabad, who stood in a white coat in the center of the ward, explained. As a result, most babies contract infections. On the day I visited, some of the sheets on the I.C.U. beds were stained with feces. Exhausted mothers stood next to the beds and stared wide-eyed at their babies. One leaned over, sang lullabies, and gently kissed her child’s cheek. Others paced in the hallway outside. About a third of the children who arrive at the unit do not survive. A month after the Biden Administration pulled U.S forces out of Afghanistan, only seventeen per cent of the country’s more than twenty-three hundred health clinics were functional. Doctors in the hospital in Kabul told me that they hadn’t been paid since the Taliban seized power, in August, and that medicine is in short supply. The new government is struggling to feed the country’s thirty-nine million people, and the chance that an Afghan baby will go hungry and die is the highest in twenty years. Half of the country’s population needs humanitarian assistance to survive, double the number from 2020. More than twenty million people are on the brink of famine. The United Nations Development Programme projects that by the middle of this year Afghanistan could face “universal poverty,” with ninety-seven per cent of Afghans living below the World Bank-designated international poverty line of $1.90 a day.
'Absolutely unprecedented': Massive protests in Kazakhstan are making international shockwaves - Over the span of just two days, what began as protests over spiking fuel prices have snowballed into the most serious unrest the Central Asian nation of Kazakhstan, a major energy producer and long a symbol of stability among the former Soviet states, has faced in decades. "I've never seen anything like this in Kazakhstan," Maximilian Hess, a Russian and Central Asian expert and fellow at the Foreign Policy Research Institute, told CNBC on Thursday. "It's absolutely unprecedented." Dozens of protesters are reported to have been killed, according to Kazakh media. On Wednesday, protesters lit government buildings in the business capital of Almaty ablaze and took over Almaty airport, which was retaken by military forces by the end of the night. The internet has been suspended by the authorities, and by Wednesday evening, Kazakh President Kassym-Jomart Tokayev had requested support from Russia, which has responded by deploying forces from the Collective Security Treaty Organization, a Moscow-led military alliance of former Soviet states. Russian paratroopers have now rolled into the country, which for many brings back chilling memories of Kazakhstan's days under Soviet rule. Videos on social media showed demonstrators facing off against hundreds of security forces in riot gear, and crowds pulling down the statue of longtime strongman and former President Nursultan Nazarbayev. Nazarbayev, who stepped down from the presidency in 2019 but still holds significant power, was removed on Wednesday from his position as head of the country's powerful Security Council by Tokayev — his hand-picked successor. Kazakhstan's entire Cabinet has resigned, but this has not quelled the protesters. Unrest began after Kazakhstan's government announced it would lift price controls on liquefied petroleum gas, which is what the majority of Kazakhs use for their cars. Suddenly letting the market dictate LPG prices meant that most Kazakhs were paying nearly double for their gas during the new year period. The impact was particularly acute in Kazakhstan's western Mangystau province, where despite residing in a country rich in oil and gas, living standards are low. Monthly salaries average a few hundred dollars per month, and price increases in a basic amenity like gas are painful. Kazakhstan, a country of nearly 20 million people about four times the size of Texas and the second-largest oil producer among the ex-Soviet states in the OPEC+ alliance, has always been seen as operating under an authoritarian system. Upon taking up the presidency in 2019, Tokayev pledged political and economic reforms — but critics and country analysts say that has been slow to come. The government pulled the fuel price hikes in an attempt to appease the public. But protests sparked by anger over the lifting of the LPG price controls are now taking an increasingly political tone, with reports of demands for democratic change. "The protesters' slogans went well beyond objecting to recent loosening of price controls for transport fuel to challenging the country's leadership," said Nick Coleman, a senior editor for oil news at S&P Global Platts who spent several years living in Kazakhstan. "In that regard the concerns are not dissimilar to those in a number of other ex-Soviet countries over the years." Kazakh authorities are having none of it. Tokayev has already accused the protesters of being part of a foreign terrorist plot, and has pledged to be "as tough as possible" in the face of the demonstrations. Some Russian state media outlets have already accused the West of being behind the unrest.
Kazakhstan's deadly protests hit bitcoin, as the world's second-biggest mining hub shuts down -As the Central Asian nation of Kazakhstan plunged into chaos this week, an internet shutdown hit the world's second-biggest bitcoin mining hub, in yet another blow to miners searching for a permanent and stable home. Less than a year ago, China banished all of its cryptocurrency miners, many of whom sought refuge in neighboring Kazakhstan. But months after these crypto migrants set up shop, protests over surging fuel prices have morphed into the worst unrest the country has seen in decades, leaving crypto miners caught in the middle. After sacking his government and requesting the aid of Russian paratroopers to contain the fatal violence, president Kazakh President Kassym-Jomart Tokayev ordered the nation's telecom provider to shutter internet service. That shutdown took an estimated 15% of the world's bitcoin miners offline, according to Kevin Zhang of digital currency company Foundry, which helped bring over $400 million of mining equipment into North America. As Kazakh miner Didar Bekbau put it, "No internet, so no mining." Bitcoin dropped below $43,000 for the first time since September in trade on Thursday, falling over 8% at one point. The price move followed the release of hawkish minutes from the Federal Reserve's December meeting. Castle Island Ventures' Nic Carter thinks the supply delta from changing the pace of mining is minimal and that the falling price of bitcoin is more a function of the Fed and "general risk-off behavior." Internet service was briefly restored in the country, but data from monitoring group NetBlocks Internet Observatory shows that connectivity levels continue to flatline at just 5% of ordinary levels across the country. "It's now Friday morning in Kazakhstan where internet has been shut down for some 36 hours, placing public safety at risk and leaving friends and family cut off," NetBlocks wrote in a tweet. The entire episode lays bare two significant facts about the state of the bitcoin mining industry. For one, the bitcoin network is resilient to the point that it doesn't skip a beat, even when a substantial portion of miners are unexpectedly taken offline. Second, the U.S. may soon see a fresh influx of crypto miners looking to avoid future disruptions.
China slashes fuel export quotas in first 2022 tranche--China slashed its fuel export quota by more than half in the first batch of allocations for 2022, highlighting the nation’s strategy of progressively limiting overseas sales. A total of 13 million tons were issued, including both general trade and tolling issuances, according to refinery officials who have direct knowledge of the matter. That’s 56% less than 29.5 million tons in the same batch for 2021. Last year, the overall fuel export quota was 36% lower than in 2020. The Ministry of Commerce didn’t immediately reply to a fax seeking comment. The world’s biggest oil importer has been slow giving out this year’s crude import and fuel export quotas amid a slew of challenges. Complex tax investigations of some refiners, rising competition between private and state-owned firms, and the uncertainty caused by the pandemic caused the delays, according to several traders. Beijing is also thought to be considering limiting both the import and export allowances to cut carbon emissions, they said. “Looks like this year’s total fuel export quota will keep declining,” said Yuntao Liu, analyst with Energy Aspects Ltd., adding that a smaller issuance may boost competition between state refiners and independents. Traditional teapots just received a reduction in their crude oil import quota for 2022 last week. Of the general-trade allocations, Zhejiang Petroleum & Chemical Co. received 1.34 million tons of compared with 2 million tons in the first batch 2021, while Sinopec saw the largest cut, getting 2.71 million tons of general-trade quota versus 9.67 million tons last year. Separately, refiners got 6.5 million tons of low-sulfur bunker fuel export quota, 30% more than the same period in 2021. There’s speculation that China may eliminate product exports by 2025. Should that happen, Asian fuel exporters -- in Northeast Asia, Singapore, Malaysia and Brunei -- stand to benefit as regional margins will have to rise to make up for lost Chinese barrels
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