Strategic Petroleum Reserve at a 1055 week low, US oil supplies at a 745 week low; distillates supplies at a 726 week low, total oil + products inventories at an 710 week low
US oil prices finished the past week higher despite an early 7% plunge, and thus logged their fifth consecutive monthly increase, as fears of lower supplies from Russia outweighed concerns about reduced demand from China….after falling 4% to $102.07 a barrel last week after the International Monetary Fund (IMF) cut its global economic growth forecast and as Covid-related lockdowns in China continued to impact demand, the contract price for US light sweet crude for June delivery opened lower on Monday on the increasing likelihood of a 0.5 percent Fed rate hike and continued to fall on recession fears as China extended its Covid lockdown, and tumbled to as low as $95.28, triggered by concerns over expanded quarantine restrictions in China after health authorities discovered a new cluster of Omicron cases in Beijing, before recovering to settle $3.53 lower at $98.54 a barrel on growing worries about the global energy demand outlook and about potential increases in U.S. interest rates...however, oil prices rebounded moderately in mid-morning trading on Tuesday, as worries over China's fuel demand were soothed by their central bank's pledge to support their economy through renewed Covid-19 curbs, and then spiked more than 3% in afternoon trading on reports that Russia had halted gas supplies to Poland, after the German government indicated an embargo on Russian oil imports was feasible, and subsequently settled $3.16 higher at $101.70 a barrel....oil prices climbed again in mid-morning Asian trading Wednesday, extending overnight gains, as China announced a fresh wave of financial stimulus, which helped alleviate demand concerns, but then turned mixed in late morning trading after the EIA inventory report showed commercial oil stocks had increased in line with consensus, while refiners unexpectedly reduced run rates and distillate stocks dropped to the lowest level in 14 years, before rebounding late in the session to settle 32 cents higher at $102.02 a barrel as worldwide supply concerns remained at the fore...after an initial dip of nearly 2% early Thursday as a soaring US dollar made oil barrels more expensive for foreign buyers, oil prices rallied in afternoon trading on reports suggesting Germany -- the largest buyer of Russian oil and gas in the EU -- had dropped its opposition to a proposed ban on Russian oil imports after Berlin struck a deal with Poland that would grant access to seaborne crude shipments drawn from the global market, and settled $3.34, or more than 3% higher at $105.36 a barrel...oil prices extended their gains early Friday, as fears over a Russian supply disruption trumped Covid-19 lockdowns in China, but reversed late in the session, pulled downward by an expiring heat oil contract that plummeted by more than 20% at one point, with June US crude sliding 67 cents to settle at $104.69 a barrel, as panicked traders sold energy contracts across the board...but even though the 3 day winning streak had been snapped, the front month oil contract booked weekly and monthly gains, as supply worries tied to Russia's invasion of Ukraine outweighed concerns over a hit to demand from China's Covid lockdowns, with the U.S. benchmark logging a 2.6% weekly rise and a 4.4% April gain, based on the most actively traded contract, and thus achieved a fifth straight month of gains – the longest streak since early 2018 – with demand concerns viewed as fleeting but supply worries more persistent...
Meanwhile, natural gas prices rose for the sixth time in seven weeks, after Russia began to cut off gas supplies to European countries for nonpayment....after falling 10.4% to $6.534 per mmBTU last week as an early Spring cold spell gave way to more seasonable temperatures, the contract price of natural gas for May delivery traded 3% lower and 6% higher on Monday before settling up 13.5 cents at $6.669/MMBtu, as gas well freeze-offs in the Rockies over the weekend had dented production....prices moved higher again on Tuesday, as production losses steepened in the Rockies and output also declined elsewhere amid a host of seasonal maintenance activities, as natural gas settled 18.1 cents higher at $6.850 per mmBTU...with trading of the May natural gas contract expiring, its price surged for a third consecutive day on Wednesday, jumping 41.7 cents to a final settlement at $7.267 per mmBTU, after Russia cut off natural gas supplies to Poland and Bulgaria; while at the same time, contract price of natural gas for June delivery, which would be the quoted front month price the next day, climbed 36.1 cents to $7.339 per mmBTU...however, with the June contract price now being quoted, prices reversed Wednesday's gains to tumble 45.1 cents or 6% to $6.888 per mmBTU on Thursday, as warmer weather in North Dakota thawed wells, and forecasts pointed to milder weather and lower demand next week than had been expected...but the rally resumed on Friday, with gas prices rising 35.6 or 5% to $7.244 per mmBTU, as parts of the country began to shift from heating to cooling demand while protracted production interruptions in the northern Plains persisted...natural gas prices thus ended 10.9% higher on the week, while the June futures contact price, which had finished last week priced at $6.663 per mmBTU, ended 8.7% higher....
The EIA's natural gas storage report for the week ending April 22nd showed that the amount of working natural gas held in underground storage in the US rose by 40 billion cubic feet to 1,490 billion cubic feet by the end of the week, which left our gas supplies 406 billion cubic feet, or 21.4% below the 1,896 billion cubic feet that were in storage on April 22nd of last year, and 305 billion cubic feet, or 17.0% below the five-year average of 1,795 billion cubic feet of natural gas that have been in storage as of the 22nd of April over the most recent five years....the 40 billion cubic foot injection into US natural gas working storage for the cited week was a bit less than the average forecast for a 42 billion cubic foot injection from an S&P Global Platts survey of analysts, and it was also less than the average injection of 53 billion cubic feet of natural gas that have typically been added to our natural gas storage during the same week over the past 5 years, whle it was considerably more than the 18 billion cubic feet that were added to natural gas storage during the corresponding week of 2021...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending April 22nd indicated that because of a drop in our oil exports and a big increase in oil that could not be accounted for, we managed to add oil to our stored commercial crude supplies for the 8th time in 22 weeks and for the 17th time in the past forty-seven weeks…our imports of crude oil rose by an average of 98,000 barrels per day to an average of 5,934,000 barrels per day, after falling by an average of 159,000 barrels per day during the prior week, while our exports of crude oil fell by 549,000 barrels per day to 3,721,000 barrels per day during the week, after our exports had risen by a record 2,090,000 barrels per day during the prior week...using our oil exports to offset oil supplies from imports to determine our effective trade in oil, we find there was a net import average of 2,213,000 barrels of oil per day during the week ending April 22nd, 647,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude oil from US wells was reportedly unchanged at 11,900,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have totaled an average of 14,113,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,684,000 barrels of crude per day during the week ending April 22nd, an average of 33,000 fewer barrels per day than the amount of oil than our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 317,000 barrels of oil per day were being pulled out of 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 storage, from net imports and from oilfield production was 1,254,000 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 (+1,254,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet in order to make the reported data for the daily supply of oil and for the consumption of it balance out, a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been an error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed....moreover, since last week’s EIA fudge factor was at (+433,000) barrels per day, that means there was a 821,000 barrel per day difference between this week's balance sheet error and the EIA's crude oil balance sheet error from a week ago, and hence the week over week supply and demand changes indicated by this week's report are completely worthless....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 317,000 barrel per day decrease in our overall crude oil inventories left our total oil supplies at 967,494,000 barrels at the end of the week, our lowest oil inventory level since January 4th, 2008, and thus a 14 year low….this week's oil inventory decrease came even though 99,000 barrels per day were being added to our commercially available stocks of crude oil, because 416,000 barrels per day of oil were being pulled out of our Strategic Petroleum Reserve at the same time....that draw on the SPR included a withdrawal under the initial 30,000,000 million barrel release from the SPR to address Russian supply related shortfalls, as well as an earlier ongoing withdrawal under the administration's plan to release 50 million barrels from the SPR to incentivize US gasoline consumption....including other withdrawals from the Strategic Petroleum Reserve under similar recent programs, a total of 103,077,000 barrels have now been removed from the Strategic Petroleum Reserve over the past 21 months, and as a result the 553,070,000 barrels of oil still remaining in our Strategic Petroleum Reserve is now the lowest since January 18th, 2002, or at a 20 year low, as repeated tapping of our emergency supplies for non-emergencies or to pay for other programs has already drained those supplies considerably over the past dozen years...with Biden's recent "Plan to Respond to Putin’s Price Hike at the Pump", an additional and unprecedented 1,000,000 barrels per day will be released from the SPR daily starting in May and running up to the midterm elections in November, in the hope of keeping gasoline and diesel fuel prices from rising further up until that time....that total 180,000,000 barrel drawdown over the next six months will remove almost a third of what remains in the SPR at this time...
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,017,000 barrels per day last week, which was 0.3% less than the 6,034,000 barrel per day average that we were importing over the same four-week period last year….this week’s crude oil production was reported to be unchanged at 11,900,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,500,000 barrels per day, while Alaska’s oil production rose by 19,000 barrels per day to 447,000 barrels per day but had no impact on the final rounded national total....US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was still 9.1% below that of our pre-pandemic production peak, but was 41.2% 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 90.3% of their capacity while using those 15,684,000 barrels of crude per day during the week ending April 22nd, down from the 91.0% utilization rate of the prior week, but still close to the historical utilization rate for late April refinery operations…the 15,684,000 barrels per day of oil that were refined this week were 4.4% more barrels than the 15,018,000 barrels of crude that were being processed daily during week ending April 23rd of 2021, when refineries were still recovering from winter storm Uri, and 22.9% more than the 12,761,000 barrels of crude that were being processed daily during the week ending April 24th, 2020, when US refineries were operating at what was then a much lower than normal 69.6% of capacity during the first wave of the pandemic, but still 4.6% less than the 16,446,000 barrels that were being refined during the prepandemic week ending April 26th 2019, when refinery utilization was also at a somewhat below normal 89.2% for the same week of April...
With the decrease in the amount of oil being refined this week, gasoline output from our refineries was also lower, decreasing by 322,000 barrels per day to 9,514,000 barrels per day during the week ending April 22nd, after our gasoline output had increased by 335,000 barrels per day over the prior week.…this week’s gasoline production was 1.2% less than the 9,629,000 barrels of gasoline that were being produced daily over the same week of last year, and 4.2% below the gasoline production of 9,927,000 barrels per day during the week ending April 19th, 2019, ie, the year before the pandemic impacted gasoline output....at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 34,000 barrels per day to 4,782,000 barrels per day, after our distillates output had increased by 162,000 barrels per day over the prior week…even with that decrease, our distillates output was 3.4% more than the 4,626,000 barrels of distillates that were being produced daily during the week ending April 23rd of 2021, but 6.7% less that the 5,128,000 barrels of distillates that were being produced daily during the week ending April 26th, 2019...
With the decrease in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the eleventh time in twelve weeks, decreasing by 761,000 barrels to 232,378,000 barrels during the week ending April 22nd, after our gasoline inventories had decreased by 761,000 barrels over the prior week....our gasoline supplies decreased again this week even though the amount of gasoline supplied to US users decreased by 129,000 barrels per day to 8,739,000 barrels per day, and even though our imports of gasoline rose by 248,000 barrels per day to 845,000 barrels per day while our exports of gasoline rose by 40,000 barrels per day to 958,000 barrels per day....but even with 11 inventory drawdowns over the past 12 weeks, our gasoline supplies were still only 1.8% lower than last April 23rd's gasoline inventories of 234,982,000 barrels, and 4% below the five year average of our gasoline supplies for this time of the year…
Likewise, even with this week's increase in our distillates production, our supplies of distillate fuels decreased for the twelfth time in fifteen weeks and for the 24th time in thirty-four weeks, falling by 1.449,000 barrels to a fourteen year low of 107,286,000 barrels during the week ending April 22nd, after our distillates supplies had decreased by 2,642,000 barrels during the prior week…our distillates supplies fell again this week as the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 12,000 barrels per day to 3,834,000 barrels per day, and as our exports of distillates fell by 197,000 barrels per day to 1,281,000 barrels per day, and while our imports of distillates rose by 21,000 barrels per day to 125,000 barrels per day.....after thirty-six inventory decreases over the past fifty-two weeks, our distillate supplies at the end of the week were 22.8% below the 139,049,000 barrels of distillates that we had in storage on April 23rd of 2021, and about 21% below the five year average of distillates inventories for this time of the year…
The depressed level of our distillate supplies has led to diesel fuel and heat oil prices that are often $1 per gallon more than the already elevated price of gasoline...supplies of diesel and pricing of it are also elevated in Europe and globally, leading to economic restrictions and power outages in countries that cant afford it, such as Sri Lanka, Pakistan, and now India...although those diesel shortages had developed over time, the loss of Russian oil has exacerbated the situation, because refineries get more diesel per barrel oil out of a heavy crude than they do from a light one, and most Russian oil exports are medium heavy sour crudes....that global shortage of diesel also explains the thinking behind the 1 million barrel per day SPR release better than the administration's political messaging about gasoline prices...for US Gulf Coast and European refineries that were built to use a medium heavy crude like Russian Urals, they need to find an equivalent grade of crude to replace it, or do some expensive blending of other grades to match it…remember that the administration’s first frantic moves after the Russian oil ban were to try to get Venezuelan oil and even Iranian oil back on the market to replace it?…well, the US Strategic Petroleum Reserve is 60% heavier grades of crude, so it appears that they’re pulling it out to partially replace embargoed Russian oil globally…most oil we get from shale is light and sweet, typically more expensive, but worthless when one is trying to replace Russian oil losses...and those losses also explain our rising exports to Europe..
Meanwhile, with this week's drop in our oil exports, the withdrawal from the SPR, and the increase in oil supply that could not be accounted for, our commercial supplies of crude oil in storage rose for the 15th time in 39 weeks and for the 19th time in the past year, increasing by 691,000 barrels over the week, from 413,733,000 barrels on April 15th to 414,424,000 barrels on April 22nd, after our commercial crude supplies had decreased by 8,020,000 barrels over the prior week…but even with this week’s increase, our commercial crude oil inventories slipped to about 16% below the most recent five-year average of crude oil supplies for this time of year, but were still about 19% above the average of our crude oil stocks as of the fourth weekend of April 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 spring 2020, and then jumped again after last year's winter storm Uri froze off Gulf Coast refining, our commercial crude oil supplies as of this April 22nd were 16.0% less than the 493,107,000 barrels of oil we had in commercial storage on April 23rd of 2021, and were also 21.5% less than the 527,631,000 barrels of oil that we had in storage on April 24th of 2020, and 11.9% less than the 470,567,000 barrels of oil we had in commercial storage on April 26th of 2019…
Finally, with our inventories of crude oil and our supplies of all products made from oil remaining near multi year lows, we are also continuing to keep track of the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that the total of our oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and thus including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 2,187,000 barrels this week, from 1,699,086,000 barrels on April 15th to 1,696,899,000 barrels on April 22nd, after our total inventories had fallen by 12,795,000 barrels during the prior week, thus leaving them down by 91,534,000 barrels over the first 12 weeks of this year....at 1,696,899,000 barrels our total inventories of oil & its products are now the lowest since December 26th, 2008, or at an 13 1/2 year low, as the graph below shows...
This Week's Rig Count
The number of drilling rigs running in the US rose for the 71st time over the prior 83 weeks during the period ending April 29th, but it still remained 12.1% below the prepandemic rig count.....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by three to 698 rigs this past week, which was also 258 more rigs than the pandemic hit 440 rigs that were in use as of the April 23rd report of 2021, but was still 1,231 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global market with oil in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 3 to 552 oil rigs during this week, after rigs targeting oil had increased by 1 during the prior week, and there are now 210 more oil rigs active now than were running a year ago, even as they still amount to just 34.3% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 19.2% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations was unchanged at 144 natural gas rigs, still up by 48 natural gas rigs from the 96 natural gas rigs that were drilling during the same week a year ago, even as they were still only 9.0% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to rigs targeting oil and gas, Baker Hughes continues to show two "miscellaneous" rigs active; one is a rig drilling vertically for a well or wells intended to store CO2 emissions in Mercer county North Dakota, and the other is also a vertical rig, drilling 5,000 to 10,000 feet into a formation in Humboldt county Nevada that Baker Hughes doesn't track...
The offshore rig count in the Gulf of Mexico increased by one to thirteen this week, with all of this week's Gulf rigs drilling for oil in Louisiana waters....that matches the number of offshore rigs that were active in the Gulf a year ago, when twelve Gulf rigs were drilling for oil offshore from Louisiana and one was deployed for oil in Texas waters…in addition to rigs drilling in the Gulf, there's also an offshore rig drilling in the Cook Inlet of Alaska, where natural gas is being targeted at a depth greater than 15,000 feet....a year ago, there were no rigs offshore other than those in the Gulf of Mexico....however, last year did have an inland water based rig active, while this year there are no "inland waters" remaining...
The count of active horizontal drilling rigs was up by 4 to 643 horizontal rigs this week, which was also 245 more rigs than the 398 horizontal rigs that were in use in the US on April 30th of last year, but still 53.2% less than the record 1,374 horizontal rigs that were drilling on November 21st of 2014....on the other hand, the directional rig count was down by one to 30 directional rigs this week, but those were still up by 7 from the 23 directional rigs that were operating during the same week a year ago…meanwhile, the vertical rig count was unchanged at 25 vertical rigs this week, while those were still up by 6 from the 19 vertical rigs that were in use on April 30th 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 April 29th, the second column shows the change in the number of working rigs between last week’s count (April 22nd) and this week’s (April 29th) count, the third column shows last week’s April 22nd 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 30th of April, 2021...
once again, there weren't many changes this week; the two rigs added in Louisiana included the oil rig added in the Gulf of Mexico and a natural gas rig targeting the Haynesville shale in the northwestern part of the state, while the rig added in the Williston basin was in Montana, where there are now 2 rigs deployed, thus accounting for the difference between the North Dakota rig count and that of the Williston basin...meanwhile, the rig pulled out of Utah had been drilling into the Uintah Basin, which we have established previously, even as Baker Hughes still does not track that fairly active basin...
while it's likely that the two rigs that were added in New Mexico were in the Permian basin, we'll need to check the Texas Permian details to determine that...so checking the Rigs by State file at Baker Hughes for the changes in the Texas Permian, we find that two rigs were added in Texas Oil District 8, which encompasses the core Permian Delaware, but that a rig was pulled out of Texas Oil District 7C; which includes the Texas counties in the southern part of the Permian Midland, and that a rig was pulled out of Texas Oil District 8A which includes the counties in the northern Permian Midland...based on that, it appears that the rig count in the Texas Permian was unchanged, which would mean that either one of the New Mexico rig additions was in a basin other than the Permian, or that one of the Texas oil District 8 rigs was...(the North America Rotary Rig Count Pivot Table (XLS) provides county level details, should you want to comb thru the rigs in Texas and New Mexico to find out exactly where those changes were)...
elsewhere in Texas, we find that a rig was added in Texas Oil District 1, but that a rig was pulled out of Texas Oil District 4, and it appears that both of those were Eagle Ford shale rigs, since the Eagle Ford shale saw the addition of an oil rig and a removal of a natural gas rig, while the overall basin count remained unchanged...in addition, there was rig pulled out of Texas Oil District 6, which would have been a Haynesville shale natural gas rig, offsetting the one added in Louisiana, and leaving the Haynesville shale rig count unchanged...meanwhile, to offset the natural gas rig that was removed from the Eagle Ford, Baker Hughes shows the addition of a natural gas rig in an "other" basin that they don't track...since everything else on our tables is otherwise accounted for, it's possible that natural gas rig could have been added in the San Juan basin of New Mexico...
‘This Needs to Be Fixed’: Nuclear Expert Calls Radioactivity Levels Found Outside Ohio Oilfield Waste Facility ‘Excessive’ – DeSmog - Activists and scientists have found alarming levels of radioactivity in samples collected along the road and soils outside Austin Master Services, an oilfield waste processing facility with a history of sloppy practices in eastern Ohio. The facility is located just down the street from a high school football stadium and less than 1,000 feet from a set of city drinking water wells, raising public health concerns from a nuclear forensics scientist about the extent of possible radioactive contamination. Last November, members of two advocacy groups, Concerned Ohio River Residents and Mountain Watershed Association, collected soil samples from outside the Martins Ferry, Ohio facility of Austin Master Services, a Pottstown, Pennsylvania-based company that operates in 10 states. Both groups are concerned about the handling of radioactive oilfield waste in their region, which has seen over a decade of intensive fracking development in the Marcellus and Utica shale formations. All of that oil and gas drilling produces huge volumes of liquid and solid waste that need treatment and disposal. Oilfield waste service companies pick it up directly at the wellhead, and sometimes perform an initial processing, before bringing some of it to facilities like Austin Master’s for additional treatment. But how well-prepared such companies are to handle the industry’s radioactive waste is being increasingly called into question. For instance, a DeSmog investigation has revealed that railcars carrying radioactive oilfield waste from Austin Master in Martins Ferry have arrived leaking at a final disposal facility in Utah on multiple occasions between 2015 and 2020. The Ohio and Pennsylvania advocacy groups sent the Austin Master samples to Marco Kaltofen, a nuclear forensics scientist in Massachusetts who has extensive experience examining radioactive waste from the nuclear weapons, nuclear power generation, and oil and gas industries. Before the activists gathered the samples, Kaltofen advised them on appropriately handling and shipping the potentially radioactive samples. After reviewing them, he then sent the samples to Eberline Analytical, a radiological analysis lab in Oak Ridge, Tennessee. The relatively high levels of radioactivity in the results, returned in February, immediately caught Kaltofen’s attention. “This needs to be fixed,” he says. They found levels of radium-226 at 14.1 picocuries per gram, and radium-228 at 3.7 picocuries per gram. Radium is one of several naturally occurring radioactive elements well-known to occur in oilfield waste. Soil nationwide generally has a radium background level of about 1 picocurie per gram, and the U.S. Environmental Protection Agency (EPA) limit for topsoil at uranium mills and Superfund toxic waste dumps is 5 picocuries per gram above background levels. The samples analyzed by Eberline also showed elevated levels of radioactive forms of lead and thorium. “This is an impressive source of contamination. These numbers are well above background and excessive,” says Kaltofen. “I have very grave concern about the accidental inhalation and ingestion of these particles. My concern here is wind is going to move this out into the neighborhood.” The radioactive dust and soil may settle in yards where children play, he says, and kids tend to dig around in grass and dirt, and then touch their fingers to their mouths. This is especially worrisome, according to Kaltofen, because radium is considered a “bone-seeker.” If accidentally inhaled or ingested, the radioactive element tends to accumulate in the bones, where it continues emitting radiation and can lead to cancer. “Radium 226 is a potent source of radiation exposure, both internal and external,” notes a 1982 report that discusses oilfield radioactivity hazards and was produced by the American Petroleum Institute’s Department of Medicine and Biology’s Committee for Environmental Biology and Community Health.
Ohio's Low-Producing Wells Leave Huge Methane Footprint - They account for a minuscule amount of U.S. oil and gas production, but new research found low-producing oil and gas wells have a large methane footprint.Methane is a powerful greenhouse gas responsible for at least one-quarter of current global warming. According to the report, the country's 565,000 low-production well sites are responsible for a combined four million metric tons of methane, or nearly half of all U.S. methane emissions.Tracy Sabetta, an organizer for Moms Clean Air Force in Ohio, explained a huge share, 30%, comes from the Appalachian Basin, which includes Ohio."With Ohio having as many oil and gas producing wells as we do, it is a pollutant that we just can't ignore," Sabetta asserted. "In fact, our state has the second-highest number of individuals who live within a half-mile of an oil and natural gas producing facility."The study is published in the journal Nature Communications. The Environmental Protection Agency is considering new standards to reduce oil and gas methane emissions, but operators producing lower emissions would be exempt. Mark Omara, senior analyst for the Environmental Defense Fund and the study's lead author, said the bulk of emissions from low-production natural gas sites is the result of prolonged negligence by operators. "Rusted pipes from which leaks occur, pressure-relief valves that malfunction, open-thief hatches on tanks that continue to vent," Omara outlined. "All of these issues can be fixed via regular monitoring and leak inspection and repair."Sabetta suggested it is in the best interest of the oil and gas industry to address methane leaks, as about 10% of low-production well sites are less than 10 years old."If you look at prices from 2019, there's more than $700 million in wasted natural gas," Sabetta pointed out. "That is enough to supply over 3.6 million homes in the U.S. annually, or to power every single home in Ohio."An earlier analysis by the Environmental Defense Fund found the vast majority of low-production wells are owned by major companies with the financial resources to reduce energy waste.
Utica Gas Power Plant on Ohio River Uses Hydrogen in World First - A world-first happened along the banks of the Ohio River in Hannibal (Monroe County), OH in March. The Long Ridge Energy Terminal, host to a Utica shale gas-fired power plant that went online last November, successfully added a 5% mixture of hydrogen to the natural gas it burns in March. The plant is now using and continuing to experiment with up to 20% hydrogen as part of the mix it burns through next year. Eventually, the plant’s owners plan to burn 100% hydrogen, crowding out Utica Shale gas (a shame).
Study: Ohio has infrastructure, industries to develop hydrogen hub - Ohio is an optimal location to develop the hydrogen industry, according to a new study commissioned by JobsOhio and the Stark Area Regional Transit Authority. The state has a plentiful supply of natural gas, as well as energy from nuclear, solar, wind and even biomass sources like landfills that can be used in the process to produce hydrogen, Cleveland State University researchers concluded in the report "Developing a Hydrogen Economy in Ohio: Challenges and Opportunities."SARTA is a founding member of the Ohio Clean Energy Hub Alliance, which wants to create a hydrogen hub in the region.The study, which was released earlier this month, also noted that the state's natural gas pipelines can be repurposed to more cheaply transport hydrogen, which can be costly to move by truck. Ohio has several industries that would find it efficient and economical to use hydrogen in manufacturing and to fuel heavy-duty zero-emission vehicles that use fuel cells like buses, forklifts and trucks. And Ohio has the storage capacity and manufacturing applications to capture the carbon emitted when using natural gas to make hydrogen.The 75-page study projected higher demand for hydrogen whether the federal or state government mandates zero-carbon emissions.But the study by Mark Henning and Andrew R. Thomas of the Midwest Hydrogen Center of Excellence at Cleveland State also points out the challenges of adopting hydrogen. Hydrogen is more costly to store and transport than other energy sources. The two wrote that for hydrogen to be viable and eventually carbon free decades down the road, Ohio's hydrogen development must have an "all of the above" approach.The cost of extracting natural gas to make the hydrogen will eventually increase as the Utica Shale's natural gas reserves are drained decades from now. That will require a transition to other energy sources, which for now require a higher cost to make hydrogen and are not yet as plentiful. And using natural gas to make hydrogen results in the emission of carbon, which has to be mitigated to be a true carbon-free technology that reduces climate change.
Clean energy future? Fossil fuel boondoggle? Chamber pushes for hydrogen hub in Ohio - An association of natural gas, transportation and tech businesses are pushing for a piece of an $8 billion federal investment to create a “clean hydrogen hub” in Ohio.Hydrogen, the most abundant chemical element in the universe, could overtake coal, oil, and gas as America’s predominant source of energy, its proponents say. It’s lightweight and can create energy without accompanying fossil fuel emissions.So-called “green hydrogen” is created via electrolysis, where electricity splits hydrogen from oxygen molecules in water. However, the green technology has yet to scale; estimates suggest that about 96% of hydrogen currently produced is “blue hydrogen,” created from a mix of electrolysis and the “steam methane reforming” of natural gas.Hydrogen burns cleanly as a fuel, but its creation via natural gas leaks methane and emits carbon dioxide into the air — both of which are greenhouse gasses and major contributors to climate change.On Thursday, the Ohio Clean Energy Hub Alliance — represented by the Stark Area Regional Transit Authority, Ohio Chamber of Commerce, technology company Battelle, and hydrogen car maker Hyperion — pitched their efforts to build Ohio into a hub of blue hydrogen production. The green hydrogen, the alliance representatives said, would come later as the technology develops.Carbon capture technology, the alliance says, would catch the carbon emissions before they leave any hydrogen-producing plant. The carbon would then be compressed and stored underground at a yet-unspecified site in Southeast Ohio, further limiting environmental footprint.Environmentalists are leery of blue hydrogen. The Ohio River Valley Institute called the hub a “boondoggle” in the making. The Sierra Club, an environmental advocacy organization, only supports hydrogen as a clean fuel if it’s produced without fossil fuels. Neil Waggoner, who works on the Sierra Club’s Beyond Coal campaign, said blue hydrogen isn’t really reducing carbon. It’s just capturing it and burying it.“This is all about finding the future for the gas industry, so they stay relevant and don’t have to change that much,” he said.The hub’s advocates, however, painted a rosier picture. Steve Stivers, the former congressman turned CEO of the state Chamber of Commerce, argued hydrogen can boost domestic energy production and lessen foreign energy dependence. He focused on hydrogen’s use as a clean fuel and less so on the carbon footprint of producing it — 2021 modeling in the journal Energy Science and Engineering estimated that the greenhouse gas footprint for blue hydrogen is more than 20% greater than burning coal or gas for heat. The hydrogen supporters were vague on details as to when blue (gas-created) hydrogen would sunset and green hydrogen would rise. Its champions, however, point to its current uses. Kirt Conrad, SARTA’s CEO, oversees a fleet of 21 hydrogen-fueled buses that emit bits of water and steam instead of smoggy exhaust. They’ve driven 700,000 miles since they were acquired in 2016, he said, preventing 1,700 tons of carbon dioxide from entering the oxygen.
Oil And Gas Production Projected To Rise In Utica, Marcellus Shale - – Oil and natural gas production from wells in eastern Ohio’s Utica-Point Pleasant and Pennsylvania’s Marcellus shale is expected to climb in May, according to the latest data from the U.S. Energy Information Agency.According to EIA’s Drilling Productivity Report released April 18, the Utica-Point Pleasant and Marcellus region – collectively referred to as Appalachia – is projected to step up oil production by 3,000 barrels per day and increase natural gas output by 197 million cubic feet per day by next month.In April, EIA estimates that energy companies across the region produced 111,000 barrels of oil per day. That should increase to 114,000 barrels per day in May. Total natural gas production is expected to jump from 35.443 billion cubic feet per day in April to 35.640 billion cubic feet daily in May.Six of the seven shale plays across the country are projected to increase oil or natural gas production next month, EIA reports. Every shale region in the United States is expected to increase oil production with the exception of the Haynesville shale, which straddles Louisiana and Texas. That shale play is expected to remain unchanged at 34,000 barrels produced per day. The largest output of oil is expected from the Permian Basin in Texas at 5.137 million barrels per day next month, an increase of 82,000 barrels per day compared to April’s production data.The Appalachian region continues to be the country’s gas giant with expected yields in May of 35.640 billion cubic feet of natural gas per day. The next-largest producer is the Permian, with a projected 19.533 billion cubic feet of natural gas produced each day for that month.Just one shale region, the Anadarko in Oklahoma, projected a decline in natural gas production. That shale play is expected to decrease production by 15 million cubic feet per day, from 6.118 billion to 6.103 billion cubic feet per day, according to EIA’s report.Despite higher oil prices, no new permits to drill new oil or gas wells in the Utica-Point Pleasant’s northern region – generally consisting of Columbiana, Mahoning and Trumbull counties — have been issued by theOhio Department of Natural Resources this year.In April, EAP Ohio, which acquired much of Chesapeake Energy’s position in Columbiana County several years ago, applied for permits to deepen three wells it drilled earlier in Hanover Township. Those permits have yet to be awarded, according to ODNR records.
Antero Betting on Bullish 'Structural Shift' in Natural Gas Prices - Appalachian Basin pure-play Antero Resources Co. is betting on continued high natural gas prices, driven by a “structural shift” in the relationship between U.S. prices and storage levels, CEO Paul Rady said Thursday. “The primary driver behind this shift is the supply side,” Rady told analysts during a call to discuss first quarter earnings. He cited “limited access to capital, limits on infrastructure buildout, and also supply chain constraints that limit production growth” as impediments to growing supply and filling storage capacity ahead of the 2022-2023 winter. Other bullish pricing factors include upstream inventory exhaustion, continued liquefied natural gas (LNG) export growth and low global storage levels, Rady said. “We believe this bodes well for commodity pricing moving forward and Antero is best positioned to directly benefit from higher prices.” Antero holds more than 501,000 net acres in the Marcellus and Utica shale plays, where it produced 3.2 Bcfe/d during the first quarter. Russia’s invasion of Ukraine has exacerbated each of these factors, Rady indicated. “As Europe looks to strengthen its energy security, it has become clear that there will be a significant call on U.S. shale gas in the coming decades,” the CEO said. “Importantly, with Antero’s 2.3 Bcf/d of firm transportation to the LNG fairways, we are uniquely positioned to supply the increase in international demand.” Rady said Antero already is selling nearly 1 Bcf/d of gas to LNG facilities on a mix of long- and short-term contracts. As additional export capacity is built out, Antero believes its gas will fetch a higher premium to New York Mercantile Exchange (Nymex) pricing “and will become more closely linked to international prices,” Rady said. “we’re not interested in longer-term supply deals unless we receive significantly higher premiums,” Rady said, citing that “there’s too much optionality today to get locked in prematurely.” Antero’s Justin Fowler said that Antero expects U.S. supply growth “to underwhelm” in 2022, making it difficult to hit consensus estimates of around 3.5 Tcf of gas in storage when injection season officially ends Oct. 31. “Production would need to average over 97 Bcf/d every single day, beginning from today through November,” Fowler said. “This represents a nearly 4 Bcf/d increase from current production levels.” In addition to supply constraints and geopolitical tensions, Fowler said that, “We continue to see very strong power generation and industrial demand,” and noted that LNG exports are expected to grow as incremental capacity comes online this year. “This suggests even higher supply growth will be required to fill storage ahead of next winter,” he said. Fowler echoed Rady’s prediction that, as U.S. LNG export capacity grows, pricing along the main U.S. LNG supply corridors will see a higher premium to Henry Hub and track closer to global LNG benchmarks.
Range Resources CEO Calls for Federal, State Support as Natural Gas Prices, Demand Spike - Range Resources Corp. CEO Jeff Ventura said Wednesday Appalachian natural gas producers need more support from policymakers if they are expected to help meet increasing demand for the fuel at home and abroad. Aggressive domestic and international energy transition policies, along with Russia’s invasion of Ukraine, which has jeopardized European gas imports, have pushed prices higher. The policies also have reduced supply, Ventura said during a first quarter conference call. Range holds nearly 500,000 net acres in the core of the Marcellus Shale in Southwest Pennsylvania, where it still has a multi-decade drilling inventory. Ventura said Appalachian natural gas and natural gas liquids (NGL) should have a stronger role in the global call for supplies. However, the CEO stressed that “a more meaningful increase in natural gas supply will require support from federal, state and local governments, to provide critical infrastructure in the form of pipelines, compression and LNG terminals to get Appalachian natural gas to the end markets that need it.” Some in-basin demand and incremental takeaway projects are expected in Appalachia in the years ahead, Ventura said. Still, he noted that more infrastructure is needed to significantly boost production. “But the industry is currently hindered by a lack of additional infrastructure due to permitting delays, policy decisions and rhetoric that discourages long-term capital investment in natural gas and natural gas infrastructure,” he said. Rising commodity prices lifted Range’s first quarter results. Realized natural gas, NGL and oil prices during the period, including cash-settled hedges and derivative settlements. averaged $4.83/Mcfe, up from $3.01 in the year-ago period. Average realized natural gas prices, including the impact of basis hedging, was $4.92/Mcf, or 3 cents above the average New York Mercantile Exchange price for the period. Pre-hedge NGL realizations were $40.03/bbl, or 74 cents above the benchmark Mont Belvieu equivalent during the quarter. Range said first quarter NGL realizations were driven by higher ethane prices and an improving market for propane and heavier NGL products. The company expects up to a $2 premium to Mont Belvieu pricing this year given its international exposure at the Marcus Hook export terminal near Philadelphia. As buyers in Europe look to diversify energy supplies in a pivot away from Russia, COO Dennis Degner said the company expects strong international NGL demand. He added that domestic propane levels are at historic lows as well. About 30% of Range’s full-year production is expected to be NGLs. The company produced 2.071 Bcfe in the first quarter, flat with 1Q2021 volumes of 2.081 Bcfe as the company looked to better control spending and output heading into the year. Management also stressed that it was keeping a close eye on inflation and supply chain issues as the costs for fuel, steel and sand have increased. Some costs have been offset by previous moves to secure 2022 tubular goods and extend a contract for the company’s electric hydraulic fracturing fleet, Degner said. Range reported a first quarter net loss of $457 million (minus $1.86/share), compared with year-ago net profits of i$27 million (11 cents). The 1Q2022 results were primarily related to a $939 million hedging loss from a wrong-way bet on the direction of natural gas prices.
API releases statement regarding Pennsylvania-produced natural gas - American Petroleum Institute Pennsylvania (API PA)'s Executive Director, Stephanie Catarino Wissman, released the following statement for Earth Day on 22 April 2022: “No other nation has cut carbon dioxide (CO2) emissions more than the US since 2000, thanks in part to the shift to cleaner natural gas as a source of electricity generation and Pennsylvania’s abundant supply of shale gas. Our industry is investing and prioritising breakthrough technologies with initiatives like The Environmental Partnership to provide cleaner, reliable and affordable energy around the world. American energy leadership not only can help provide stability and security but also further global environmental progress.”As the second-top producer of natural gas in the nation, Pennsylvania energy is transforming the country and the world in the following ways:
- In 2019, federal estimates show that natural gas from Pennsylvania’s Marcellus and Utica Shale has been shipped out to 20 different countries.
- By exporting cleaner natural gas – in the form of LNG – the dual challenge of powering a growing population while lowering greenhouse gas emissions can be met.
- Average methane intensity declined by nearly 60% across key US producing regions, including Appalachia, between 2011 and 2020, according to the U.S. Environmental Protection Agency and Energy Information Administration data.
Marcellus Natural Gas Conduit Adelphia Begins Partial Service on Expansion - Adelphia Gateway LLC has started partial service on its brownfield natural gas pipeline expansion project moving Marcellus Shale supply to growing demand markets in eastern Pennsylvania and beyond, pipeline flow data shows.Adelphia started flowing on Monday, moving natural gas supply from the Quakertown meter station through the Marcus Hook facility to the Tilghman meter. Receipts at the Texas Eastern Transmission Co. West Rockhill interconnect are at around 8.1 MMcf/d, while deliveries at Peco Energy Co.’s Tilghman interconnect are at 8 MMcf/d, according to Wood Mackenzie.However, flows are expected to ramp up, Wood Mackenzie analyst Devin Cao said. “This partial service will deliver 31.5 MMcf/d from the West Rockhill receipt to the Peco-Tilghman delivery point,” which is subscribed by Peco and parent company Exelon Corp.The Adelphia Gateway Phase II project is around 93% completed, with most of the remaining work still to be done at the Quakertown compressor station, Cao said. The meter station portion of the Quakertown facility already is operational and flowing gas to the south zone.FERC granted Adelphia a certificate for the expansion project in late 2019 in a 2-1 vote after it secured the permits needed to begin construction from the Pennsylvania Department of Environmental Protection. It started pre-construction activities in the fall of 2020.Part of the pipeline was already moving gas to two power plants in Northampton County, PA, but the expansion repurposes the southern segment to move additional volumes. The system – which once delivered oil to a refinery near Philadelphia – has been designed to move 175,000 Dth/d on Zone North A, 350,000 Dth/d on Zone North B and 250,000 Dth/d on Zone South.In January, the Federal Energy Regulatory Commission granted Adelphia an extension until June 2023 to complete the entire project. The pipeline developer cited regulatory delays, the ongoing Covid-19 pandemic and supply chain issues in its request for an extension. However, Cao said it seems more likely that the project would come online before the end of this year.
CNX Resources Corp. extends contract for hydraulic fracturing - Pittsburgh Business Times --CNX Resources Corp. has extended its contract for the electric hydraulic fracturing fleet for its natural gas production.CNX said it had signed a four-year agreement with Evolution Well Services of The Woodlands, Texas, extending a deal that began in 2018 for natural gas-fueled hydraulic fracturing fleets to replace diesel engines on the well pad. CNX was the first in the basin to employ electric fracturing units, which is something that other companies are also now doing."Four years later, with the safety, environmental, and efficiency benefits clearly demonstrated, we are pleased to enter into another long-term contract that provides certainty in an uncertain supply chain world that is disrupting all facets of our economy," said CNX COO Chad Griffith in a statement. "We'll continue to improve the local environment, increase the quality of our execution, and mitigate ongoing inflationary cost risks with this important relationship."Financial terms weren't announced.The turbines save money, run cleaner than diesel, reduce truck traffic and are much more efficient than what had been employed previously.
CNX Extends Contract for Electric Fracturing Fleet in Appalachia - CNX Resources Corp. said Tuesday it would extend a long-term agreement with Evolution Well Services to continue utilizing an all-electric fracturing fleet in the Appalachian Basin.COO Chad Griffith said after four years of working with Evolution’s fleet the “safety, environmental and efficiency benefits” have been clearly demonstrated. CNX holds more than one million Marcellus and Utica shale acres scattered across Ohio, Pennsylvania and West Virginia. The company has extended the agreement for another four years. Griffith said the deal also “provides certainty in an uncertain supply chain world that is disrupting all faces of our economy.” Service from Evolution’s 100% electric and natural gas-fueled fleet started in 2019. CNX management said the deal has resulted in higher operational efficiencies, lower emissions and significant well cost savings. As part of the agreement, both CNX and Evolution could continue introducing technologies to further cut emissions and improve operations. Hydraulic fracturing (fracking) has largely been done using diesel-powered pumps, but in recent years e-fracking has made inroads in basins across the country. The process utilizes what would otherwise be flared gas by shuttling it to gas-fired turbines that power electric motors.
Documents show Spire scrambling for survival of St. Louis pipeline after court ruling -- Deep into Missouri’s feverish summer, a St. Louis hardware store owner found his customers clamoring for something surprising: Electric space heaters. “The weather was warm and it was strange that people were worried about it,” said Don Heberer, owner of Rathbone Hardware. He estimates he sold about 20% more space heaters than normal for that time of year. The reason? The local gas utility company was warning people that, come winter, they might not have heat. Spire Inc — an investor-owned gas conglomerate — issued the warnings last year after a court ordered it to shut down its new 65-mile STL Pipeline. The court ruled that the company hadn’t proved to federal regulators that the customer-funded $287 million project was even needed. Spire’s only buyer for the gas from the pipeline was the utility it owns, Spire Missouri Inc. Critics said Spire was self dealing, at the expense of captive gas customers. The court decision left Spire — and St. Louis — with a problem. The company had spent years disconnecting its customers from the region’s existing pipelines and routing them to its own. Without the new pipeline, Spire warned that a winter storm could leave up to 400,000 customers without heat in the depths of winter. The energy company quickly undertook a bare-knuckles marketing campaign to warn the public of the threat — and try to convince them of the need for the pipeline. In radio spots, social media ads and press releases to reporters, the utility warned that people risked freezing. Missouri regulators at the Public Service Commission have said Spire “created unnecessary panic and confusion.”
Production Drop Sends Natural Gas Futures Higher, while Chilly Weather Lifts Cash Natural gas futures volatility continued ahead of contract expirations this week, with the May Nymex contract up early as freeze-offs in the Rockies over the weekend dented production. The prompt month traded in a nearly 50.0-cent range before settling Monday at $6.669/MMBtu, up 13.5 cents from Friday’s close. June futures rose 14.2 cents to $6.805. Spot gas prices rebounded on Monday ahead of a chilly late-season weather system arriving in the country’s midsection. NGI’s Spot Gas National Avg. bumped up 27.0 cents to $6.465. After a huge downturn along the Nymex futures curve last week, the May contract was up early in Monday’s session. That followed some unseasonably cold weather that smacked the Rockies over the weekend, resulting in freeze-offs. Pipelines in the region had warned of potential impacts ahead of the cold front, but actual disruptions began Sunday. Wood Mackenzie noted that Williston Basin Pipeline issued a force majeure as a result of weather conditions. Additional constraints developed on Monday. Northern Border Pipeline, meanwhile, issued a low line pressure operational flow order from the Port of Morgan to Glen Ullin effective Sunday until May 2. Bespoke Weather Services said although it expects production figures to be revised higher, the decline in output likely explains some of the “wild volatility” in price action at the start of the week. Upside price risks may remain limited awhile in the near term, though, according to the firm. However, “we do expect volatility to remain elevated, and the bullish case later this year still exists,” it said. Liquefied natural gas (LNG) export demand is expected to remain strong throughout the remainder of this year and beyond given Europe’s desire to wean itself off Russian gas in the wake of its invasion of Ukraine. Though no incremental LNG capacity is scheduled to come online in the United States after Calcasieu Pass fully ramps up until around 2024, exports could swell to nearly 15 Bcf/d by December. This continued call on U.S. LNG during that time is likely to translate to below normal storage levels, according to BMO Capital Markets. Rising cooling demand could drive prices even higher.
U.S. natgas futures gain 3% as output declines raise storage worries - (Reuters) - U.S. natural gas futures gained about 3% on Tuesday on worries Russia may cut gas flows to Poland and expectations that recent declines in output due to cold weather in North Dakota and the Rockies will cut the amount of gas utilities can inject into storage in coming weeks. Russian energy giant Gazprom told Poland's Polskie Górnictwo Naftowe gas company it will halt gas supplies along the Yamal pipeline from Wednesday morning. Traders also noted that technical factors likely also played a part in Tuesday's trade with the upcoming expiration of the May options. "Over the past year, the front-month contract has increased in eight of twelve months ... on options expiration day," On its second to last day as the U.S. front-month, gas futures NGc1 for May delivery on the New York Mercantile Exchange (NYMEX) rose 18.1 cents, or 2.7%, to settle at $6.850 per million British thermal units (mmBtu). NYMEX gas options expire the day before the futures contract expires. Futures for June NGM22, which will soon be the front-month, gained about 2.5% to $6.98 per mmBtu. U.S. gas futures were up about 82% so far this year as higher global prices have kept demand for U.S. liquefied natural gas (LNG) exports near record highs since Russia invaded Ukraine on Feb. 24. Gas was trading around $31 per mmBtu in Europe and $25 in Asia. The U.S. gas market, however, remains mostly shielded from those higher global prices because the United States is the world's top gas producer, with all the fuel it needs for domestic use while capacity constraints inhibit exports of more LNG no matter how high global prices rise. Data provider Refinitiv said average gas output in the U.S. Lower 48 states rose to 94.3 billion cubic feet per day (bcfd) so far in April from 93.7 bcfd in March. That compares with a monthly record of 96.3 bcfd in December 2021. On a daily basis, however, output was on track to drop about 3.9 bcfd over the past three days to a preliminary 91.6 bcfd on Tuesday, the lowest since early February. Traders said most of those declines were caused by freezing wells in North Dakota and the Rockies. Those wells will likely return to service over the next week or so as the weather warms.
Natural Gas Surges to Close Wednesday, Sending May Futures Expiring 41 Cents Higher Natural gas futures surged for a third consecutive day against a backdrop of escalating global supply uncertainties after Russia cut off natural gas supplies to two European countries. With domestic fundamentals also tight this week, the May Nymex contract rolled off the board Wednesday at $7.267/MMBtu, up a massive 41.7 cents on the day. The June contract, which moves to the front of the Nymex curve on Thursday, climbed 36.1 cents to $7.339. Spot gas prices were mixed, as pipeline maintenance led prices lower in a few regions, while stronger-than-normal demand lifted others. NGI’s Spot Gas National Avg. picked up 27.5 cents to $7.070. Volatility continued along the Nymex futures strip, with the expiring May contract bringing about a fiery buying spree in the final half hour into the close of Wednesday’s session. Solid 30.0-cent gains were seen throughout the remainder of the year and into February. Though Russia’s halt of gas supplies to Poland and Bulgaria were not expected to have a significant impact on global balances, the potential for further cuts to European countries were keeping the market on its toes and fueling volatility. NatGasWeather noted that the political turmoil and resulting surge in global gas prices were likely infiltrating U.S. trading. Domestically, however, there were no major changes in balances. Although the overnight weather data added a little demand, the latest Global Forecast System model gave it back – and then some. NatGasWeather said strong demand was expected to continue through the weekend, with a mix of chilly late-season weather systems sweeping across the northern and eastern United States. The forecaster expects there to be enough demand the next 14 days to stall current supply deficits of 300 Bcf to keep the background state relatively bullish through May 10.
US natural gas storage climbs 40 Bcf to 1.49 Tcf as NYMEX future rally stalls - US working gas inventory expanded at a below-average pace in the third week of April, growing this season’s storage deficit to its widest yet, but failing to spur a bullish response from the NYMEX gas futures market. The US Energy Information Administration on April 28 announced another undersized injection of 40 Bcf to US gas storage for the week ending April 22 in its fourth reported inventory build of the season. The injection was just 2 Bcf less than anticipated by S&P Global Commodity Insights’ survey of analysts, which called for a 42 Bcf addition to stocks in the third week of April. With another below-average injection, US working gas inventories climbed to 1.49 Tcf in the week ended April 22. The storage deficit to 2021 narrowed as stocks climbed to 406 Bcf, or about 21%, below the year-ago level of 1.896 Tcf. Compared with the five-year average injection, though, the build came up short, growing this season’s deficit to its widest yet at 305 Bcf, or 17%, below the historical average, EIA data showed. The NYMEX Henry Hub June contract dropped 25 cents, or about 3%, from its prior-day settlement price to around $7.10/MMBtu following the report’s release. The balance-of-summer forward curve moved into slight backwardation from July to October, pricing at an average of about $7.20/MMBtu, data from CME Group showed. Futures, fundamentals Since April, the 2022 NYMEX Henry Hub futures curve has traded comfortably above $6/MMBtu, even testing highs in the upper $7 range more recently, S&P Global data shows. At a time of year when the US market typically troughs, the outlook for $6-$7/MMBtu gas remains on solid footing as this season’s inventory deficit lingers fueled by strong demand and flagging production. Through the reporting week ending May 6, unseasonably low temperatures in the US Northeast and across parts of the Midwest have and are expected to keep heating demand elevated, limiting storage injections. The storage deficit is expected to further widen in the upcoming two reporting weeks by anywhere from 30-40 Bcf in total, according to updated forecasts from S&P Global.
U.S. natgas futures drop 6% as output rises, demand slips (Reuters) - U.S. natural gas futures fell about 6% on Thursday on rising output as warmer weather in North Dakota thawed wells and forecasts pointed to milder weather and lower demand next week than previously expected. That U.S. price decline also came as gas futures in Europe TRNLTTFMc1 dropped about 8%, reversing some gains from earlier in the week after Russia stopped selling gas to Poland and Bulgaria, and after a U.S. report showing an expected smaller than usual storage build last week. NG/EU The U.S. Energy Information Administration (EIA) said utilities added 40 billion cubic feet (bcf) of gas to storage during the week ended April 22. That was close to the 38-bcf build analysts forecast in a Reuters poll and compares with an increase of 18 bcf in the same week last year and a five-year (2017-2021) average increase of 53 bcf. EIA/GASNGAS/POLL On its first day as the U.S. front-month, gas futures NGc1 for June delivery fell 45.1 cents, or 6.1%, to settle at $6.888 per million British thermal units (mmBtu). On Wednesday, when May was still the front-month, the contract settled at its highest since closing at a 13-year high of $7.82 on April 18. U.S. gas futures have gained about 86% so far this year as higher global prices kept demand for U.S. liquefied natural gas (LNG) exports near record highs since Russia invaded Ukraine on Feb. 24. Gas was trading around $31 per mmBtu in Europe and $25 in Asia. Refinitiv projected average U.S. gas demand, including exports, would slide from 93.6 bcfd this week to 90.5 bcfd next week due to a seasonal warming of the weather. The forecast for next week was lower than Refinitiv's outlook on Wednesday. The amount of gas flowing to U.S. LNG export plants slid to 12.3 bcfd so far in April due to maintenance at Gulf Coast plants, down from a record 12.9 bcfd in March. The United States can turn about 13.2 bcfd of gas into LNG.
U.S. natgas futures jump 5% as cooling demand starts to rise -- U.S. natural gas futures jumped about 5% on Friday as parts of the country move from heating demand to cooling demand, which could increase the amount of gas power generators burn to meet air conditioning loads and keep storage injections lower than usual in coming weeks. Traders noted U.S. futures also gained support from lower output in North Dakota following a brutal spring blizzard this week. U.S. front-month gas futures for June delivery rose 35.6 cents, or 5.2%, to settle at $7.244 per That put the contract up about 11% for the week and 28% in April after falling about 10% last week and rising about 28% in March. The premium for futures for July over June rose to a record 11 cents per mmBtu. U.S. gas futures have already gained about 95% so far this year as higher global prices kept demand for U.S. liquefied natural gas (LNG) exports near record highs since Russia invaded Ukraine on Feb. 24. Gas was trading around $30 per mmBtu in Europe and $25 in Asia. U.S. natural gas futures jumped about 5% on Friday as parts of the country move from heating demand to cooling demand, which could increase the amount of gas power generators burn to meet air conditioning loads and keep storage injections lower than usual in coming weeks. Traders noted U.S. futures also gained support from lower output in North Dakota following a brutal spring blizzard this week. U.S. front-month gas futures for June delivery rose 35.6 cents, or 5.2%, to settle at $7.244 per mmbtu. That put the contract up about 11% for the week and 28% in April after falling about 10% last week and rising about 28% in March. The premium for futures for July over June rose to a record 11 cents per mmBtu. U.S. gas futures have already gained about 95% so far this year as higher global prices kept demand for U.S. liquefied natural gas (LNG) exports near record highs since Russia invaded Ukraine on Feb. 24. Gas was trading around $30 per mmBtu in Europe and $25 in Asia. The U.S. gas market, however, remains mostly shielded from those much higher global prices because the United States is the world’s top gas producer, with all the fuel it needs for domestic use while capacity constraints inhibit exports of more LNG no matter how high global prices rise.
Oil spill cleanup continues in Edwardsville— Work crews on Tuesday were using heavy equipment to move earth along Old Alton Edwardsville Road just south of Illinois 143 in Edwardsville as cleanup of a large crude oil spill last month continues.The spill was first reported March 11 when the 165,000-gallon-spill was found coming from a Marathon Pipe Line buried near Cahokia Creek. Some of the spill reached the water prompting a massive cleanup effort, including some oil drenched wildlife.Crews have been working non-stop on cleanup since the spill, especially on the land closest to where the ruptured pipe was repaired. Dump trucks were transporting dozens of loads of clean dirt to the site Tuesday. Officials have said it will likely take months to complete the entire cleanup of the area.
Michigan group: Oil pipeline tunnel plan not in sync with state's climate goals - This Earth Month, Michigan leaders took the opportunity to release a new roadmap for a carbon-neutral state economy by 2050. In addition to highlighting state agencies' plans to power state-owned buildings and facilities with renewables, reduce energy usage, electrify vehicles and offer more recycling services, the plan calls for action from local governments, businesses and institutions, communities and individual households.
Sean McBrearty, Michigan legislative and policy director for Clean Water Action, said the most recent report by the Intergovernmental Panel on Climate Change makes a clear case there is no time to waste. "The impacts we're already going to see from climate change are extreme," McBrearty asserted. "To avoid the absolute worst impacts of climate change, we need to decarbonize now. " McBrearty is also campaign coordinator for the coalition Oil and Water Don't Mix, which advocates for shutting down the Line 5 dual pipelines running through the Straits of Mackinac. Enbridge Energy has said there is currently no alternative to deliver the energy Line 5 transports, and it would take significant energy to build infrastructure to do so. McBrearty countered experts have testified before the Michigan Public Service Commission, pointing out a plan to build a tunnel around the pipeline would add 27 million metric tons of carbon pollution to Michigan's output, which is not in line with the state's overall goals set out in the Michigan Healthy Climate roadmap.
"It makes no sense when we're trying to address the climate crisis to spend any amount of time building an oil tunnel underneath the Great Lakes that's going to add the equivalent of 10 coal-fired power plants to the carbon load already in Michigan," McBrearty contended.
DOE Secretary Granholm Refuses to Answer Pipeline Prosperity Question at Hearing - Former governor of Michigan now serving as Joe Biden’s Secretary at the Department of Energy, Jennifer Granholm, would not answer a question about what economic impact the Line 5 pipeline has on the state at a House Energy and Commerce Subcommittee on Energy hearing on Thursday. “Would you say that Line 5 [pipeline] plays a massive economic impact on the state of Michigan?” Rep. Bob Latta (R-OH) asked Jennifer Granholm at the hearing. “I’m not going to respond to that one,” Granholm said. “You’re not going to respond to that?” Latta asked. “No, I’m not going to get into that because it’s in court,” Granholm said, referring to the ongoing litigation in Michigan over Democrat Governor Gretchen Whitmer’s attempts to shut down the pipeline. “When I’ve talked to people in the state of Michigan and the state of Ohio they said it does have a major economic impact,” Latta said. According to the website of Enbridge, the company behind Line 5, the pipe has operated for decades without a leak and provides abundant energy to the state of Michigan: The products moved on Line 5 heat homes and businesses, fuel vehicles, and power industry in the state of Michigan. Line 5 supplies 65% of propane demand in the Upper Peninsula, and 55% of Michigan’s statewide propane needs. Overall, Line 5 transports up to 540,000 barrels per day (bpd) of light crude oil, light synthetic crude, and natural gas liquids (NGLs), which are refined into propane. Built in 1953 by the Bechtel Corporation to meet extraordinary design and construction standards, the Line 5 Straits of Mackinac crossing remains in excellent condition, and has never experienced a leak in more than 65 years of operation. The Line 5 crossing features an exceptional and incredibly durable enamel coating, and pipe walls that are three times as thick—a minimum of 0.812 inches—as those of a typical pipeline. What’s more, the Bechtel Corporation—renowned for the iconic Hoover Dam—designed and built Line 5 in an area of the Straits that would minimize potential corrosion due to lack of oxygen and the cold water temperature. This setting contributes to preserving the integrity of Line 5, which has enabled it to serve the region safely and reliably for more than six decades. In an article on the MLive Media Group website, critics of the stance of environmentalists and Whitmer said shutting down the pipeline is counter to what is beneficial to the state and its residents. “The state’s ongoing legal maneuvering and attempt to force a shutdown of Line 5 runs contrary to well-established legal principles and jeopardizes Michigan’s energy security, economy and efforts to strengthen environmental protections along with that of Canada, our fellow Great Lakes states and entire nation – all at a time when we can least afford it,” Jim Holcomb, president and chief executive officer for the Michigan Chamber, said in the article.
Energy Dept OKs expanded LNG exports from Texas, Louisiana - — The Energy Department on Wednesday authorized additional exports of liquefied natural gas, or LNG, from planned terminals in Texas and Louisiana.The orders allow Golden Pass LNG Terminal near Port Arthur, Texas, and Magnolia LNG Terminal in Lake Charles, Louisiana, to export additional natural gas as LNG to any country not prohibited by U.S. law or policy.The $10 billion Golden Pass LNG export project is expected be operational in 2024, with Magnolia coming online by 2026. The two terminals are expected to produce more than 3 billion cubic feet of natural gas per day.The approvals come as the United States seeks to boost LNG exports to Europe amid Russia's war with Ukraine. The Energy Department approved expanded permits for two other LNG terminals in Texas and Louisiana last month.Cheniere Energy Inc. said its Sabine Pass facility in Louisiana and its Corpus Christi plant in Texas have been improved and are making more gas than covered by previous export permits.Energy Secretary Jennifer Granholm said last month that the U.S. “is exporting every molecule of liquefied natural gas that we can” to helpEuropean buyers of Russian fuel.U.S. LNG exports have reached new highs of about 12 billion cubic feet per day and are expected to grow to more than 13 billion cubic feet by the end of the year, with most going to Europe, the Energy Department said.The U.S. and its allies also have released oil from their strategic reserves to counter Russia’s aggression. The U.S. has banned imports of Russian oil. The U.S. and other countries “will act quickly to hedge against energy disruptions,’’ Granholm said at the International Energy Agency’s ministerial meeting in Paris. “We will not allow Vladimir Putin to wedge our nations apart.”
How Much Oil Did The Government Release From The SPR? April 23, 2022 -- So much oil is going to be released from the SPR that the Louisiana Offshore Oil Port (the LOOP) is designating segregated storage capacity for crude deliveries from the US SPR beginning in May. I guess this is being done to make bookkeeping easier and to facilitate exporting oil from our strategic reserves to China and India. It took decades to fill the SPR and now in six months, half of it will be gone. Link here. Having said all that, the release is a non-issue. Even after the release there will still be more in storage than required by law, and Congress can change that requirement any time.
US refiners set for strong start to 2022 as fuel prices surge worldwide, -US oil refiners expect strong first-quarter earnings as margins to sell gasoline and diesel strengthened due to a steep dropoff in refining capacity and crude oil supplies tightened because of Russia's war with Ukraine. Refining capacity worldwide has dropped during the coronavirus pandemic, with several less profitable oil refineries closing in the last two years. However, worldwide fuel demand has rebounded to near pre-pandemic levels, boosting profits for facilities that are still operating. Seven US independent refining companies are projected to post earnings-per-share of 61 cents, compared with a loss of $1.32 in first quarter of 2021, according to IBES data from Refinitiv. Profit margins for making both gasoline and distillates - diesel, jet fuel and heating oil - were already at their highest in several years coming into 2022, and have since risen, with the heating oil crack spread at nearly $41 per barrel by the end of March, nearly $20 more than average over the past five years. US independent refiners including Marathon Petroleum Corp , Valero Energy Corp and Phillips 66 also benefited from a surge in natural gas prices in Europe which occurred due to the risk of European sanctions on Russian energy exports. Valero kicks off refinery earnings on Tuesday; Phillips reports on Friday, with Marathon the following week. Natural gas is needed to operate various units of oil refineries and the expense caused some European refineries to cut runs, particularly distillate-producing units. This contributed to a sharp fall in distillate inventories worldwide, putting a premium on production of diesel and jet fuel. "Geopolitical dynamics should support US refiners on wide natural gas spreads, though some impacts may be less visible with first quarter earnings than in future quarters,"
In Texas, some fines paid by polluters benefit the fossil fuel industry -- After a Taiwanese plastics and petrochemical company leaked harmful gasses from its chemical plant in the Gulf Coast town of Point Comfort in 2021, Texas’ environmental agency fined it nearly $267,000. Instead of paying the entire fine to the state, Formosa — which uses fossil fuels to create plastics — sent half the money to the Texas Natural Gas Foundation, a nonprofit entity that promotes natural gas to the public.Texas state law allows polluters to divert some of their fines that normally go to the state’s general revenue fund to “supplemental environmental projects,” or SEPs. The Texas Natural Gas Foundation has qualified as an SEP since 2016.In theory, SEPs are meant to remediate industrial pollution and environmental harm by funding programs like cleanups at illegal dump sites, habitat restoration or household hazardous waste pickups in communities.Public documents obtained by Floodlight show that SEPs like the one with the Texas Natural Gas Foundation can directly benefit the companies that are being penalized — by paying to staff and run industry programs.According to the Texas Commission on Environmental Quality’s description of the Texas Natural Gas Foundation’s SEP, the nonprofit aims to raise $8 million to replacestate government-owned diesel trucks and buses with new gas vehicles that the foundation argues are cleaner. Several school districts receive SEP funding for similar bus replacement projects. But by allowing entities like the Texas Natural Gas Foundation to receive state funds, Texas is allowing the fossil fuel industry to reshuffle money back to itself, public documents show.“You get back to this policy question [of] is [TCEQ] putting SEP dollars into the hands of a marketing organization that is using those dollars to create further demand for natural gas?” said James Bradbury, an environmental lawyer and professor at Texas A&M University School of Law.
Kinder Morgan to Expand Natural Gas Compression as Permian Takeaway Constraints Loom - Kinder Morgan Inc. (KMI) is planning compression expansions on its Permian Highway Pipeline (PHP) and Gulf Coast Express (GCX) natural gas pipelines in order to alleviate takeaway constraints in the Permian Basin expected to mount by 2023. “Combined, the two expansions can add 1.2 Bcf per day of capacity out of the Permian,” CEO Steven Kean told analysts during a conference call to discuss first-quarter earnings.Once a final investment decision (FID) is taken, KMI estimates the expansions could be in service within 18 months, meaning they may be online as soon as 4Q2023, management said.“We believe the market will need that capacity in that timeframe and see one or both of these expansions as the near-term solution, pushing out our potential greenfield third pipeline further in time,” Kean explained.Achieving a 2023 in-service date “will really help alleviate a containment issue that we’re starting to see now and certainly expect to get much worse as we get into 2023,” said KMI’s Tom Martin, president of natural gas pipelines.Martin said the firm expects a greenfield pipeline to be needed in the Permian by 2026, “which would lend itself toward” an FID by “sometime early next year with that kind of a project.”In addition, KMI is looking into a small-scale expansion at its Elba Island liquefied natural gas (LNG) terminal, Martin said. While it’s still early days in terms of greenlighting an expansion, “the market opportunity suggests there may be something worth looking at,” he told analysts.“This crisis has demonstrated the continued dependence of the world on fossil fuels, especially natural gas, and the inability to develop a satisfactory substitute in the short to intermediate term,” said executive chairman Rich Kinder. “This situation is illustrated by the frantic efforts of Europe to wean itself from its overwhelming reliance on Russian natural gas.”He added, “I anticipate that all of our present LNG export facilities will be running at capacity for the foreseeable future, and the contracts necessary to support the construction of new facilities in the next few years will be more attainable than they’ve been in the past.”Although the Biden administration recently granted approval for two liquefaction expansion projects on the Gulf Coast, Kinder warned that LNG projects could still be bogged down by permitting delays.“By way of caution, I’m still concerned that our federal government will not properly expedite the permitting of these new facilities, but I’m reasonably hopeful that at some point this administration will recognize the importance of playing its energy card to support its allies and sanction its adversaries,” Kinder said.
The Permian Basin Oil Field Is Running Out of Workers, Materials—and Cash --MIDLAND, Texas—America’s most prolific oil field is running out of the workers, cash and equipment needed to produce more oil. In the Permian Basin, the sprawling oil-rich region in West Texas and southeastern New Mexico, drillers are facing long delays and steep competition for everything from roughnecks to steel to fracking pumps.The region is the only place where U.S. crude production is expected to grow significantly this year, and the Biden administration is hoping production there can help alleviate high prices at the pump . But mounting supply-chain crunches are putting a ceiling on how much more frackers can produce there , said energy executives and analysts, despite the highest oil prices in roughly seven years. Unlike the last time oil fetched about $100 a barrel, the vast service industry of steel suppliers, drilling-rig operators
New study shows New Mexico has seen an increase in oil spills -According to a new study by the Center for Western Priorities, oil and gas companies spilled over 658,000 gallons of oil in New Mexico last year from a total of 1,368 spills. That’s significantly higher than the 1,269 spills in 2020. Officials are attributing the lower numbers in 2020 to the pandemic and now things are returning to normal, and so is oil production. “What we’re trying to do is, you know, encourage operators to look at, their operations holistically,” said ENMRD Oil Conservation Division Direction Adrienne Sandoval. She said that would encourage companies to take preventative measures beforehand. “What we have found is that if we trend all of the spill data a lot of times these spills are preventable, so we want to encourage operators to take a look at their operations, put preventative mechanisms in place so that, we’re preventing these spills upfront rather than having to clean them up on the backend,” said Sandoval. Sandoval said the state recently adopted new rules to eliminate pollution from oil and gas. “The OCD changed our spill rules in 2021, which went into effect at the end of the year and it changed small wording that spills are now unlawful,” said Sandoval. The new regulations would slap violators with immediate fines and bans routine flaring, which is the burning of excess gas.Critics say the new rules are too demanding for small oil producers. State Representative Jim Townsend (R), who represents much of southern New Mexico, said the companies he’s worked with have always put safety first by thinking of the community.
DJ Basin Unconventional (Civitas Resources Inc) CO Unconventional Oil Field, US DJ Basin Unconventional CO is a producing unconventional oil field located onshore the US and is operated by Civitas Resources. The field is owned by Civitas Resources.The DJ Basin Unconventional CO unconventional oil field with peak production expected in 2022. The peak production was approximately 89.98 thousand bpd of crude oil and condensate, 375 Mmcfd of natural gas and 49.28 thousand bpd of natural gas liquids. Based on economic assumptions, production will continue until the field reaches its economic limit in 2022. Total Production, boed220,000-40,000-20,000020,00040,00060,00080,000100,000300,000250,000200,000150,00050,000-50,000-100,000L20102011201220132014201520162017201820192020202120222023Value Civitas Resources Inc (Civitas Resources), formerly Bonanza Creek Energy Inc is an exploration and production company, engaged in the acquisition, extraction and development of oil and related liquids which are rich in natural gas. It extracts minerals using horizontal drilling and hydraulic fracturing. The company uses horizontal drilling methods for exploration and production of oil and natural gas and hydraulic fracturing to crack rock formation. Bonanza Creek is developing the Niobrara B Bench, the Niobrara C Bench, and the Codell formation in wattenberg field. It has assets and operations in Wattenberg Field, Colorado. Bonanza Creek is headquartered in Denver, Colorado, the US.
Search Ongoing For Suspect Who Shot At Fracking Company Truck In Weld County – CBS Denver – The Weld County Sheriff’s Office says someone shot a truck on Colorado Highway 52 early on April 22. They say the shooting appears random, but they want to find the suspect. Authorities say a man driving a truck belonging to a fracking company was driving eastbound on CO 52 when he thought he heard a loud “backfire.” He told deputies he thought it came from a vehicle heading in the opposite direction between Weld County Roads 37 and 43.When the man got to his worksite, he saw the driver’s door had a large bullet hole and the bullet after it fell on the ground when he opened the door.There were no reports of injuries.Now, deputies are looking for more information about a light-colored sedan. However, further details have not been released.
Climate activist's fight against 'terrorism' sentence could impact the future of protests - In the fall of 2016, under the cover of darkness, Jessica Reznicek had a singular focus: to halt the construction of the Dakota Access Pipeline. At valve sites across America's heartland, she snuck through security fences, set fire to equipment, and used chemicals to burn holes in the pipeline itself.To Reznicek, a veteran climate activist, the damage was justified: a nonviolent act of civil disobedience in pursuit of saving the planet. The Justice Department saw it differently. After Reznicek publicly acknowledged her crimes and entered a guilty plea, federal prosecutors subsequently persuaded a judge to apply a sentencing increase known as the "terrorism enhancement" against her, putting her behind bars for eight years. The enhancement was applied "even though no person was ever hurt, no person was intended to be hurt, she wasn't charged with terrorism, and she didn't plead guilty to terrorism," said Bill Quigley, Reznicek's attorney and a professor emeritus at the Loyola University New Orleans Law School. "The terrorism enhancement doubled her amount of time in prison, which is troubling." Most frequently used against violent extremists or those with ties to foreign terrorist organizations, the terrorism enhancement is praised by national security officials and prosecutors as an effective tool of deterrence -- a stiff penalty meant to discourage others from engaging in similar behavior. But critics say the use of the enhancement against Reznicek reflects a broader push from the powerful oil industry to level harsh penalties against activists who target energy infrastructure.At a time when domestic violent extremism is on the rise, experts say Reznicek's appeal presents a fresh opportunity to reexamine how terrorism cases are prosecuted -- and who deserves to be labeled a terrorist.Long before Reznicek committed herself to a life of environmental activism, the Iowa native felt a deep connection to nature. In an interview with ABC News' Iowa affiliate, WOI, shortly after her sentencing, Reznicek described a childhood spent swimming in a local river, which she called her sanctuary."I've carried that love with me all my life," she said. "And I've also witnessed that desecration and the pollution that has occurred during my lifetime."She described a spiritual calling that eventually led her to fight the construction of the Dakota Access Pipeline, an oil conduit that would eventually run more than 1,000 miles from North Dakota to Illinois. Beginning in April 2016, thousands of Native American and environmental activists gathered to protest the project. Over time, Reznicek's actions grew increasingly dangerous."I entered the valve sites multiple times in multiple locations on multiple days," Reznicek told WOI. "Each time, there was a process of preparation for that, knowing full well what the legal consequences were." In public and in court, Reznicek admitted to her actions -- which included setting fire to multiple construction vehicles -- and encouraged others to follow suit. She never hurt another person and said she never targeted human life. But her actions led to a delay in the pipeline's construction and more than $3 million in damages.
Interior rule delays underscore Biden's energy challenge – The Biden administration is behind on the release of its highly anticipated oil and gas regulations for drilling on federal lands at a time when the politics of oil are increasingly tangled in partisan disagreements over climate and prices at the pump.Among the most closely watched delayed proposals are new methane rules for oil and natural gas operations on public lands, which are critical given their direct impact on drilling and emissions. They were due out last month.
But the Interior Department also hasn’t moved on several other proposed rulemakings on energy issues anticipated for early this year, such as new offshore regulations for high-pressure drilling, as well as those dealing with offshore oil spills and renewable energy.It’s not clear why the administration appears off target, but outside observers say the thorny politics of oil policy, the cumbersome reality of federal rulemaking and a mess of court battles the Biden administration is currently fighting over climate metrics and oil leasing could all play a role.The delays could hurt the Biden White House’s agenda if they linger too long, observers say. The methane rules, and other pending updates to federal energy policy, are the first steps for the Biden administration to creating its long-term legacy, potentially affecting the future of federal greenhouse gas emissions, drilling standards and environmental rules on public lands.Officials also face an increasingly narrow window to put their policies on the books. With midterm elections later this year, it’s possible GOP victories could lead to congressional obstacles to President Joe Biden’s executive actions, said Mark Squillace, a federal energy law expert at the University of Colorado Law School and a former special assistant to the Interior Department solicitor during the Clinton administration.“Of course, no one knows how the 2022 or 2024 elections are going to go yet, but [the administration] ought to be thinking about those things,” Squillace said. The administration’s pace is also drawing scrutiny because planned reforms are stacking up even as the Office of Information and Regulatory Affairs’ regulatory agenda calls for Interior to move soon on additional high-profile updates to the federal oil program’s bonding rules, fees and royalty rates.
Biden raised fees on oil companies. But drillers might not pay - - The Biden administration is hiking the royalty rates that companies pay to extract oil and gas from public lands, framing the move as a balance between better returns for taxpayers and new drilling opportunities for energy companies. But two loopholes in President Joe Biden’s plan could allow drillers to pay the older, lower royalty rate. And the administration says only Congress can close them. Environmentalists, many of whom are unimpressed with Biden’s plan, say the royalty loopholes demonstrate that trying to reform federal oil and gas leasing is a dead end. Industry has spent a century shaping leasing laws to its benefit, they say, so anything short of a total drilling halt on public lands — which Biden promised during his campaign — empowers the oil and gas sector. “The way that industry has captured and shaped this law over several decades … is not easily unwound,” said Collin Rees, U.S. program manager for Oil Change International. This is an example, he added, of why Biden cannot hope to advance his climate and environmental justice goals by taking an “incrementalist, technocratic approach to issues that are fundamentally political.” Biden has moved to restart oil and gas leasing over 144,000 acres to address growing public concern over rising gasoline prices (Greenwire, April 15). The Bureau of Land Management plans to charge a 18.75 percent royalty rate for the new leases it sells, up from the statutory minimum of 12.5 percent. The administration says that’s a fairer return for the federal government, which set its royalty rate a century ago and now charges much less than many states, like Colorado (20 percent) or Texas (typically 20 percent to 25 percent). But that new federal royalty rate only covers leases sold competitively through auction. If the government offers leases that don’t receive bids, those so-called noncompetitive leases remain available for a flat fee. And if those noncompetitive leases ever produce oil or gas, the driller will only have to pay the old 12.5 percent royalty, according to BLM. About one-quarter of federal leases were acquired noncompetitively, according to data from 2003 to 2019 compiled by the Government Accountability Office. Furthermore, a leaseholder paying the new, higher royalty rate would have the ability to petition the Interior Department for a reduction or waiver of their royalties, if drilling becomes uneconomic. “Once in production, if a well becomes uneconomic at a royalty rate of 18.75%, the operator may petition for a royalty rate reduction under existing regulations,” the agency wrote in planning documents released this week on the new lease sales. By offering more oil and gas leases for sale, Biden is breaking a campaign promise — ending fossil fuel development on public lands — in hopes of taming higher energy prices. The administration says the higher royalty rate aligns with its goal of encouraging more drilling, in part because of those two carve-outs.
Oil prices may not drop even as companies drill more - Oil production is set to grow later this year, but it may not fully cure the price spikes caused by the Russian invasion of Ukraine, analysts and company executives said last week. Customer spending in North America is likely to increase by over 35 percent this year, Halliburton Co. CEO Jeff Miller said, up from the oil field service provider’s previous estimate of more than 25 percent. National oil companies in the Middle East also may increase their activity. “What’s key is we’re seeing them both at the same time,” Miller said on a conference call with analysts. Oil and natural gas prices hit their highest levels in more than a decade after Russia invaded Ukraine this year. The U.S. and the European Union promptly imposed economic sanctions on Russian companies, and a series of western oil companies said they were abandoning projects in Russia (Energywire, March 2). The price for domestic oil was about $120 a barrel before falling. AAA said the cost for regular U.S. gasoline hit a record average — not adjusted for inflation — of $4.33 a gallon on March 11. The average was $4.12 as of yesterday, AAA reported. High energy prices in turn have been driving inflation, which in the U.S. hit levels not seen since the 1980s. The Biden administration has committed to releasing 1 million barrels a day for six months from the U.S. Strategic Petroleum Reserve, and has coordinated releases from other countries (Energywire, April 4). The U.S. has added 257 drilling rigs in the past year, for a total of 695, according to Baker Hughes Co. The number of hydraulic fracturing crews has more than tripled to 70 in the last two years, according to the data firm Enverus. The uptick in drilling and fracking could push U.S. production up by 1 million barrels a day by the end of the year, said Al Salazar, vice president of intelligence at Enverus. But it still may not be enough to make up for the Russian production that’s been taken off the market by economic sanctions, he said. “The potential hole that has to be filled is pretty big,” Salazar said in an interview. Under those conditions, it’ll be hard for domestic oil prices to fall below $100 a barrel, he said. Demand for oil has started to fall in response to inflation and the ongoing Covid-19 lockdowns in China, according to the consulting firm Rystad Energy. Global consumption has fallen below the pre-pandemic high set in 2019, and it may not recover until 2023, the company said. Normally, a reduction in oil demand would push down prices, but “it’s not that simple,” Claudio Galimberti, Rystad’s senior vice president of analysis, said in an email. The drop will help avoid spikes in oil prices, but international grades of crude oil are likely to stay between $80 and $120 a barrel through the end of September, he said. Halliburton and its peers in the oil field service industry like Baker Hughes and Schlumberger Ltd. have argued the industry has underinvested in new oil and gas production since the price crash of 2014-2015. The oil field service providers are typically viewed as good predictors of trends in energy production. They provide the equipment and services that the industry relies on, and can see upticks in their orders long before new oil and gas start flowing.
Hess Giving 'Serious Consideration' to Adding Bakken Rig to Boost Oil Supply - U.S. independent Hess Corp. expects to add a fourth rig to its Bakken Shale activity by the end of this year, but the company continues to prioritize capital discipline. “As our portfolio becomes increasingly free cash flow positive in the coming years we commit to return up to 75% of our annual free cash flow to shareholders, with the remainder going to strengthen the balance sheet by increasing our cash position or further reducing our debt,” CEO John Hess said in an earnings call Wednesday. Given the strength of the oil market and the world’s need for more supply, he said the company “will give serious consideration to adding a fourth rig later this year” in the Bakken. Overall cash flow is expected to increase 25% annually in the 2021-2026 period, the CEO said. Hess fetched an average realized crude oil selling price, including the effect of hedging, of $86.75/bbl in 1Q2022, versus $50.02 in the prior-year quarter. The average realized natural gas liquids selling price was $39.79/bbl, compared with $29.49, while the average realized natural gas selling price was $5.28/Mcf, versus $4.90 a year earlier. Bakken net production was 152,000 boe/d in the first three months of this year, down from 158,000 boe/d in the year-ago period. The decline in output was attributed to winter storms, executives said. Hess drilled 19 wells and brought 30 new wells online in the Bakken during the quarter. In the second quarter, the company aims to drill 22 wells and to bring about 18 online. Because of operational issues related to winter weather, Bakken net production for this year is forecast to be near the bottom of the company’s previous guidance range of 160,000-165,000 boe/d. Production is expected to reach 175,000-180,000 boe/d during the fourth quarter.
Bakken Challenged by Labor Shortages, while Federal Auction Set for June --The Department of the Interior’s (DOI) Bureau of Land Management (BLM) plans to hold a lease sale on June 28 for 23 federally owned parcels spanning nearly 3,406 acres in Montana and North Dakota.The sale notice issued by BLM’s Montana/Dakotas state office is part of a larger plan announced at the federal level to hold auctions on 144,000 acres of government land in compliance with a court ruling. A federal judge in Louisiana last year ordered the resumption of federal onshore and offshore lease sales. The sales had been paused by the Biden administration. One Gulf of Mexico lease sale was held, but its results were invalidated by a federal court.The Montana/North Dakota lease sale notice incorporates recommendations from a DOI report on the federal oil and gas leasing program commissioned by Interior Secretary Dab Haaland.Changes include “a first-ever increased royalty rate of 18.75% for the leases sold in the current competitive lease sales, in keeping with rates charged by states and private landowners,” BLM said.The sale is “essentially a ditto of what was announced before and then canceled,” said Lynn Helms, director of North Dakota’s Department of Mineral Resources, during a briefing with reporters on Tuesday.Despite the resumption of federal lease sales, Helms said that North Dakota intends to move forward with pending litigation against DOI in federal court seeking assurance of mandatory quarterly lease sales.Federal policies around leasing are not the only challenge facing North Dakota’s oilpatch, which is centered around the mighty Bakken Shale.In recent conversations with Bakken operators, Helms said he has mostly heard the same story, “that it’s difficult to get workforce. It is difficult to get capital.” As a result, Helms said operators that he’s spoken with are mostly forecasting 1-2% annual production growth. The operators are “not really starting that until the third quarter of this year,” according to Helms. While North Dakota has managed to add a few drilling rigs of late, “all but one of our drilling rig operators has moved 90%-plus of their iron to the Permian,” Helms said. “So the actual physical rigs, for the most part, aren’t here anymore.” An uptick in Williston Basin drilling helped the U.S. rig count inch two units higher for the week ended Friday (April 22), according to the latest tally from Baker Hughes Co. The one remaining rig operator “has significant inventory that they could deploy…However they’re finding that they can only hire and train up a crew about every two months. So you’re looking at [adding] six rigs a year in a best-case scenario that could be added between now and mid-2023. So we’re not going to see rapid growth.”
Oil pipeline project moving forward after pandemic slowed plans; North Dakota regulators set hearing -- Plans for a $122 million pipeline slated to carry Bakken oil toward a Wyoming hub are moving forward after the coronavirus pandemic stalled the project. Bridger Pipeline is building the 145-mile South Bend Pipeline from Johnsons Corner in McKenzie County to one of the company’s pipeline facilities in eastern Montana. The pipeline is expected to transport up to 105,000 barrels per day, with the potential to expand up to 250,000 barrels per day in the future. The North Dakota Public Service Commission is tasked with permitting pipelines and is slated to hold a hearing for the project on May 5 in Watford City. Bridger estimates construction will take at least six months, and the company aims to begin operating the pipeline by the end of the year, according to an application it filed with the PSC. South Bend would be the first major oil export pipeline built in North Dakota since Dakota Access began operating in 2017, said Justin Kringstad, director of the North Dakota Pipeline Authority. Dakota Access is the largest oil pipeline in the state, transporting as much as 750,000 barrels per day from North Dakota to Illinois. North Dakota produces about 1.1 million barrels of oil each day. The oil industry has bounced back somewhat from a drop in production early on in the pandemic during 2020. The downturn made the South Bend project uneconomical at the time, but that’s since changed, according to Bridger spokesperson Bill Salvin. “There are producers bringing wells online, and they need a reliable way to bring this crude to market,” he said. “This allows us to do that.” South Bend is part of what’s been dubbed the “Bridger Expansion,” which includes two new pipelines. Bridger in 2020 completed the Equality Pipeline that runs from Hulett in northeastern Wyoming to Guernsey, an oil hub farther south in that state. Oil carried through South Bend is expected to eventually arrive in Guernsey before moving elsewhere. “This pipeline will be part of the only direct route for Bakken oil to the trading hub in Cushing, Oklahoma,” Bridger said in its application. The Oklahoma town is home to one of the country’s largest oil hubs.
Bridger pipeline would carry 105,000 barrels per day of Bakken crude to Baker, Montana - Bridger Pipeline, a subsidiary of True Companies, is proposing to build an 147-mile pipeline that will land just a few miles outside of Baker, Montana. The line would initially carry up to 105,000 barrels of crude oil per day from North Dakota, but could increase to as much as 250,000 barrels per day. From Baker, the oil would head to Guernsey, Wyoming, for further marketing and national transport. It will provide an important pipeline alternative for taking crude oil to markets in the West instead of using truck and rail options, Bridger wrote in its permit application with the North Dakota Public Service Commission. It will also allow Bakken crude oil to access a wider range of markets. North Dakota Pipeline Authority Justin Kringstad said the continued investment in pipeline systems for the Bakken is an encouraging sign. “North Dakota’s oil production is expected to increase in the coming years, and having a robust pipeline system to diversified markets will strengthen North Dakota’s ability to meet growing demand around the United States and with allies internationally,” he said. Baker, Montana happens to be the same location where TC Energy had proposed an on-ramp for about 100,000 barrels of Bakken crude on its now abandoned Keystone XL pipeline. Bridger’s 147-mile, 16-inch crude oil pipeline would originate at the Eighty Eight Oil Company’s existing Johnson’s Corner Terminal in North Dakota and end at Bridger’s existing sandstone Station, which is 8.5 miles west of Baker. It will Las interconnect with Bridger facilities at the Bicentennial Station and Wilson Station. About 81 miles of the transmission pipeline are in North Dakota. That portion will cost $61 million. The project will include some aboveground facilities, including pipeline markers, rectifier sites, pig launcher and receivers, block valves and small fenced-in enclosures along the route to house power, communication, and control systems to allow valves to be operated remotely. The state’s Public Service Commission has set a hearing for the proposed pipeline at 9 a.m. May 5 at Teddy’s Residential Suites in Watford City. Bridger Pipeline was responsible for a 2015 oil spill that released an estimated 758 barrels of oil into the Yellowsonte River. The company settled a civil suit last year with Montana, agreeing to pay $2 million to recover natural resource damages caused by the spill near Glendive, Montana. Of that amount, $1.7 million went to a natural resources damages fund managed by the state, while the rest went to a U.S. Department of the Interior fund aimed at recovering costs of damage to natural resources. The $2 million was on top of a $1 million fine for the same spill collected b the Montana Department of Environmental Quality. The company also paid $80,000 toward spill response, cleanup and site management work by Montana DEQ as well as $100,000 for monitoring equipment at Glendive’s water treatment facility. The 2015 spill was caused by a weld that split open, allowing oil to leak into the river 7 miles above Glendive. Ice and snow at the time complicated efforts to contain and clean the spill, allowing some oil to travel downstream rapidly before it was contained. An oil sheen from the spill was reported as far away as the Williston area, which shut its water system down to prevent any contamination of the water supply. Bridger is owned by True Companies, which also owns Black Hills Trucking, fined by North Dakota regulators for dumping produced water and lacking a waste-hauling permit.
Chevron's profit quadruples in the first quarter as higher oil and gas prices boost operations - Chevron's profit more than quadrupled during the first quarter of 2022, as higher oil and gas prices boosted the company's results. The oil giant reported $6.3 billion in earnings during the period up from $1.37 billion during the same quarter in 2021. Chevron's revenue rose to $54.37 billion, up from $32.03 billion during the first quarter of 2021. Chevron's results follow a surge in commodity prices. West Texas Intermediate crude futures spiked to $130.50 in early March, a price last seen in 2008 as Russia's invasion sparked supply fears. International benchmark Brent nearly hit $140, also the highest since 2008. Prices have since cooled, but are still sitting above $100, boosting energy companies' operations. "Chevron is doing its part to grow domestic supply with U.S. oil and gas production up 10 percent over first quarter last year," CEO Michael Wirth said in a statement. Shares of Chevron were flat during premarket trading. On an adjusted basis the oil giant earned $3.36 per share. It was not clear whether Chevron exceeded expectations. Wall Street was expecting the company to earn $3.27 per share on $47.94 billion in revenue, according to estimates compiled by Refinitiv.
California Regulators Banned Fracking Wastewater for Irrigation, but Allow Wastewater From Oil --California prohibits farmers from growing crops with chemical-laced wastewater from fracking. Yet the state still allows them to use water produced by conventional oil drilling—a chemical soup that contains many of the same toxic compounds.When rumors spread several years ago that California was growing some of the nation’s nuts, citrus and vegetables with wastewater produced from hydraulic fracturing, known as fracking, regulators said that would be illegal.Advances in fracking, a process that injects high-pressure chemical mixtures and sand into underground rock formations to stimulate the release of fossil fuels, revolutionized oil and gas extraction in the United States. But it alarmed environmental, public health and consumer groups, who were concerned that the massive quantities of highly toxic wastewater produced during fracking posed unacceptable threats to groundwater, ecosystems and communities. California quickly moved to regulate fracking, and water regulators ruled that wastewater from fracking could not be used to irrigate crops, acknowledging that the extractive chemicals might taint the crops grown in the water. But those same regulators have for years allowed farmers to irrigate nearly 100,000 acres of nuts, citrus and vegetables with wastewater from conventional oil drilling, even though many of the same chemicals are used in fracking and detected in fracking wastewater, a review of chemical disclosure lists and scientific studies by Inside Climate News has found. To cope with California’s perpetual droughts, state officials encourage recycling of water whenever possible, and have relied on oil field wastewater to help Kern County’s $7.6 billion agricultural industry stay afloat. But scientists said in interviews that the state’s distinction between the two types of “produced water” is essentially meaningless. “It doesn’t matter from a chemical perspective if you’re hydraulically fracturing something or you’re doing even the most pedestrian, old-school oil production techniques,” said Seth Shonkoff, an expert on the health and climate impacts of oil and gas development and executive director of Physicians, Scientists and Engineers (PSE) for Healthy Energy. “Everything uses chemicals. And a lot of the chemicals are exactly the same.” An Inside Climate News analysis cross-referenced lists of chemicals that oil companies reported using in California to operate conventional oil wells with those reported by frackers in Texas, Ohio, Pennsylvania and West Virginia, and found many of the same chemicals. And research over the past several years has found that mixing chemicals together, as happens with both types of drilling, greatly elevates toxicity.
Will California ban offshore oil drilling?- Six months after a busted ocean floor pipeline leaked 25,000 gallons of crude oil into the waters off the coast of Huntington Beach, lawmakers today will vote on a bill that could end offshore oil and gas activity in state waters by 2024. Senate Bill 953 by Costa Mesa Democratic Sen. Dave Min is a direct response to the oil spill, which shut down beaches from Orange County to San Diego in October and renewed calls from progressives to further stem Caifornia’s oil and gas production. The bill gets its first hearing in the Senate Natural Resources and Water Committee this morning, but faces opposition from groups that say an end to offshore drilling will only increase California’s reliance on foreign oil imports, creating a higher risk of spills. Once upon a time, the state had more than 50 oil and gas leases, most of them issued between 1938 and 1958. The state hasn’t issued any new leases for offshore drilling since a massive spill near Santa Barbara in 1969, but 11 of those decades-old leases are still ongoing — and would be shut down under the proposed law. In general, these leases continue so long as the platforms are producing oil. But after the Orange County spill, Min wants the state’s State Lands Commission to take steps to end them for good. “We must end offshore drilling off the coast of California now,” Min said at the unveiling in February. “Not in 5 years, or 10 years or after the next major oil spill. Now.” Originally SB 953 had directed the commission to negotiate terminations by the end of 2023. But as POLITICO’s Colby Bermel reported last week, the bill was recently amended to give fossil fuel companies an extra year to negotiate the terms and make sure the state wasn’t violating the Takings Clause, a federal requirement that the government not acquire private property without paying for its value. Gov. Gavin Newsom’s support could prove critical on this bill, which unsurprisingly faces industry opposition. But despite exorciating the “damn platforms” after last year’s oil spill, the governor hasn’t publicly backed SB 953. Min in October told POLITICO that the Newsom administration had cautioned him about the money and logistics involved with halting all drilling in state waters.
Pregnant women living near natural gas sites experience higher rates of depression, substance use: Study -- Women living close to natural gas operations – as well as the economic boom towns that often spring up around them – experienced higher rates of depression and substance use during pregnancy, according to a new study.The study, published in the International Journal of Hygiene and Environmental Health, focused on more than 6,300 women who gave birth in northeastern British Columbia, an area known for its natural gas industry.“Living near natural gas operations has been associated with an array of negative health outcomes, but little is known about the potential impact on maternal mental health,” says Élyse Caron-Beaudoin, an assistant professor in the department of health and society and one of the study’s authors.“This adds to a growing body of evidence that living near unconventional natural gas operations is linked to adverse health outcomes.” The study included women who gave birth at Fort St. John Hospital, the largest hospital in northeastern British Columbia, over a 10-year period. Mental health data came from the local health network while information about substance use came from a self-reported questionnaire.The research team estimated exposure to natural gas operations by using the distribution of wells in four zones around the participants’ postal codes that extended 2.5, 5, 10 and 50 kilometres, respectively. Caron-Beaudoin says there are many potential reasons why living close to these operations can lead to higher rates of depression and substance use. While exposure to chemicals might be a factor, she says natural gas operations in general are highly disruptive to a community. The area of B.C. involved in the study was once predominantly known for agriculture but has since been transformed by the oil and gas boom. This has resulted in a flood of people moving into the community, which has driven up the cost of living. Caron-Beaudoin points to research done on oil and gas boom towns in the U.S. that experienced increases in violent crimes, alcohol and substance use, as well as other community health crises. Many of the communities were not equipped to handle these challenges due to a lack of social services, she says. “There is a big disturbance in the social fabric of those communities,” she says. “Studies in the U.S. identified higher levels of anxiety and a loss of community cohesion among residents because their communities were upended.”In northeastern B.C., natural gas is extracted using a technique called hydraulic fracturing, often referred to as “fracking.” However, some of the chemicals used in fracking operations are toxic and can contaminate the surrounding air, water and soil. Recently, a study from the University of Calgary found that proximity to fracking operations was associated with greater risk of preterm birth in Alberta. This echoes findings on birth outcomes in northeastern B.C. published last year by Caron-Beaudoin.“It’s concerning that important policy decisions are being made with such a blatant lack of knowledge and information,” she says.The area of northeastern B.C. where the study participants were located will also be home to a massive new gas plant that could significantly increase the number of wells in the near future.“Fracking operations in particular have completely changed the landscape of oil and gas extraction, but we don’t have a lot of Canadian-based research on the public health impacts of this industry. It’s time for that to change.”
Biden closes half of NPR-A acreage to oil drilling - Alaska Public Media - The Bureau of Land Management announced Monday that it is ditching a Trump administration plan for the National Petroleum Reserve-Alaska and instead will revert to managing the area according to a 2013 plan crafted by the Obama administration. The move closes millions of acres in the NPR-A to potential oil drilling. The 2013 plan is especially protective of Teshekpuk Lake, a large wetlands important to shorebirds, loons and caribou. But the BLM says the decision still leaves nearly 12 million acres available for oil and gas leasing. That’s slightly more than 50% of the NPR-A. The Trump administration had wanted closer to 80% open to drilling. There was never a lease sale under Trump’s plan. The Biden administration indicated in January it was considering reversing the Trump-era policy, drawing outrage from Alaska’s congressional delegation. “Sweeping restrictions like this — which are being imposed even as the Biden administration implores OPEC+ to produce more oil — demonstrate everything that is wrong with its energy policies,” Sen. Lisa Murkowski said in a news release in January. The NPR-A is roughly the size of Indiana and is the country’s largest unit of public land. Environmental groups prefer to call it the Western Arctic. Several environmental groups quickly issued statements praising the decision. But the Arizona-based Center for Biological Diversity said the decision doesn’t go far enough because it still allows new Arctic drilling. “Addressing the climate emergency means ending new fossil fuel extraction, and we can’t keep going in the opposite direction,” Kristen Monsell, a senior attorney at the Center for Biological Diversity, said in an emailed statement. While the Trump administration’s plan called for allowing oil development in most of the NPR-A, it also had leasing restrictions aimed at, among other things, reducing the impact on the land surface and limiting activity during certain seasons.
Biden administration shrinks area eligible for drilling at Arctic reserve - The Biden administration is shrinking the amount of land eligible for drilling at an oil reserve in the Arctic. The administration announced on Monday that it would return to an Obama administration plan that would enable the government to lease up to 52 percent of the National Petroleum Reserve in Alaska for oil and gas exploration. It reverses a Trump-era plan that would have opened up 82 percent of the reserve. While the Bureau of Land Management (BLM) had previously indicated that it had selected the Obama administration’s plan as its “preferred alternative” for further consideration, on Monday it issued a Record of Decision formally affirming that it would return to the Obama-era plan. The National Petroleum Reserve in Alaska is an approximately 23 million-acre area in Alaska’s north slope. In 1923, then-President Harding set the area aside as an emergency oil reserve for the Navy. It was later transferred to the bureau, which can sell leases for companies to drill for oil there. The move comes as the Biden administration is grappling with high gasoline prices and Republican criticism over its energy policies, but Monday’s move is not expected to have any immediate impacts on gasoline prices at the pump. When a lease sale is held, it takes more than four years on average for companies to begin production. The new decision represents an even earlier step in the process, designating what lands are eligible for lease. In addition to shrinking the amount of land available for lease, returning to the 2013 plan also reinstates protections for certain areas of particular environmental significance. One such area that will regain protections is Teshekpuk Lake, which the Biden administration document said is “of critical importance for nesting, breeding, and molting waterfowl and the Teshekpuk Caribou Herd.” In explaining its rationale, the administration said that it would better protect the environment while still allowing energy development. Specifically it said that it provides “greater protections to environmental values and subsistence uses in the NPR-A while still allowing for oil and gas exploration and development consistent with BLM’s management responsibilities.” During its tenure, the Trump administration pushed to expand Arctic drilling both at the petroleum reserve and, more controversially, in the Arctic National Wildlife Refuge.
Vaca Muerta Natural Gas Pipeline Advances as Regional Market Tightens - Argentine officials last week celebrated the launch of the Néstor Kirchner pipeline to bring natural gas from the Vaca Muerta shale deposit to capital Buenos Aires.“Here in Argentina we have natural gas for another 200 years, and gas is the energy that the world has decided will be the transition fuel to renewable energies,” President Alberto Fernández said during an official ceremony from Neuquén province. He was flanked by company CEOs and local politicians.Fernández said the new pipeline would give the country “energy peace of mind.”Argentine state firm Integración Energética Argentina (Ieasa) is in charge of the project. Ieasa head Agustín Gerez reportedly said the project would be tendered in mid-May with construction to begin in September. In-service is targeted for 2023.Vaca Muerta is one of the biggest shale resources in the world, but development has been slowed by financing, infrastructure and regulatory challenges. Despite the resource, this upcoming Southern Cone winter Argentina faces a widening gas deficit and will need to import liquefied natural gas (LNG) and additional volumes from Bolivia.“We need to distribute gas throughout all of Argentina” and “take gas to every corner,” said the president.The $3.4 billion pipeline will be carried out in two stages. The $1.5 billion, 24 million cubic meters/day (Mm3/d) first stage is to run from Tratayen in Neuquén to Salliqueló in Buenos Aires province. It would be key in allowing more natural gas from the Vaca Muerta shale formation to reach demand centers. A second stage would redirect gas to the north to replace Bolivian imports.Energy minister Darío Martinez called the pipeline “the most important gas transport project in 40 years.” The infrastructure would also allow for seasonal exports of natural gas to regional neighbors Chile, Uruguay and Brazil, he said.
Can Colombia’s Offshore Oil Potential Rival That Of Brazil? The strife-torn Latin American nation of Colombia punches well above its weight when it comes to petroleum production. The Andean country is the region’s third-largest oil producer, even after experiencing a significant deterioration in industrial productivity since the COVID-19 pandemic arrived, despite only having proven oil reserves of 1.8 billion barrels. Colombia has not had any major oil discoveries in over a decade, placing ever greater pressure on the country’s scant reserves and its soil-dependent economy. A solution planned by presidential candidate leftist senator Gustavo Petro, who is leading the polls (Spanish) for the May 2022 election, is to end oil exploration while building other more economically productive industries, notably agriculture and manufacturing. The current hard-right government of President Ivan Duque, protégé of former President Alvaro Uribe, who is credited with reasserting Bogota’s control over Colombia’s national territory, 2021 doubled down on offshore petroleum exploration. There is a belief that Colombia possesses similar offshore petroleum potential to Brazil, which if correct would be a game-changer for the Andean country’s struggling oil industry and hydrocarbon-dependent economy. Brazil’s massive offshore pre-salt oil boom located primarily in the Atlantic Ocean’s Santos and Campos Basins catapulted the country to Latin America’s leading crude oil producer. There are signs that Colombia’s coastal waters hold considerable petroleum potential with four recognized offshore basins along the Caribbean coast and a further situated on the Pacific coast. Offshore oil exploration and production holds many advantages over onshore crude oil operations in Colombia. Key are the risks associated with a volatile onshore security environment and deteriorating social license with most local communities opposed to nearby industry operations. Rising cocaine production is fueling conflict among myriad illegal armed groups that predominantly operate in remote regions where there are significant petroleum industry operations. The Putumayo Basin, which is Colombia’s second-highest producing basin, like the Catatumbo region near the Venezuelan border that encompasses part of the Llanos Basin, the epicenter of Colombia’s oil industry, is riven by conflict. Illegal armed groups in those regions are battling for control of lucrative coca cropping territory and smuggling routes. Pipelines bombings and illegal taps for the theft of petroleum, which is rising, remain constant hazards for onshore operations adding to the risk of production outages and higher transport costs. The decline of the petroleum industry’s social license is responsible for community blockades and invasions of oilfields as well as legal action by various civil society groups. Thelatest legal action (Spanish) impeding onshore petroleum industry operations is the first court of Barrancabermeja suspending the environmental licenses for the Kale and Platero hydraulic fracturing pilots. Fracking, which is a highly controversial technique for extracting petroleum in Colombia, is blocked by a moratorium imposed by the country’s highest administrative tribunal the State Council, although this does not prevent pilot projects. Court order requires the operator, Colombia’s national oil company Ecopetrol, to suspend operations and engage in consultation with the Afro-Wilches community in the municipality of Puerto Wilches, located in the Llanos Basin. Those issues coupled with the considerable uncertainty surrounding unconventional hydrocarbon exploitation in Colombia as well as a dearth of conventional discoveries are deterring onshore investment by energy majors. In fact, in late-2020 U.S. driller, Occidental Petroleum sold its onshore Colombian oil assets but retained its offshore interests. It is estimated that Colombia’s offshore Caribbean hydrocarbon basins could hold anywhere up to 32 billion barrels of crude oil, or roughly 16-times the Andean country’s current proven reserves. That makes their exploitation an important step required to reinvigorate Colombia’s petroleum industry and expand production to the all-important target of 1 million barrels per day. Colombia’s offshore Caribbean hydrocarbon basins are attracting considerable attention. Since 2015 Ecopetrol has reported a series of hydrocarbon discoveries along the Caribbean coast, helping to confirm the considerable oil and natural gas potential thought to exist in the region.
Thousands of litres of diesel spilled near Galapagos Islands -State-run oil firm Petroecuador has confirmed a ship carrying diesel fuel sank on Saturday off one of Ecuador’s ecologically sensitive Galapagos Islands.Local authorities assumed that nearly 7,500 litres of diesel were on board the ship at the time of the accident.The company said as part of an emergency plan, containments booms were set up around the area of the oil spill in a bid to control it and mitigate the impact of the shipwreck.The Galapagos National Park said there was a presence of a fuel stain at several points of the bay and the water activities were suspended at some sites.Galapagos Islands are a protected wildlife area and home to unique species of flora and fauna.The area is also home to giant tortoises. Petroecuador added that it has been decided as a preventive measure to carry out an additional control on all vessels that come to supply fuel.
Dow Chemical Touts Advantages of Natural Gas Availability, Joins Germany LNG Project -Management at global petrochemical giant Dow Chemical Co. said Thursday that manufacturing sites with access to shale natural gas resources enjoyed a favorable position during the first quarter of 2022. “Natural gas has been stubbornly high,” said CEO Jim Fitterland during Dow’s earnings call for the first quarter of 2022. “It was higher than last year before the Russia-Ukraine incident and then, obviously, then that drove it quite a bit higher.”But in spite of rising raw material and energy costs, Dow “effectively leveraged our…feedstock and derivative flexibility in a very dynamic environment,” he said. “And higher operating rates compared to the impact of Winter Storm Uri in the year-ago period enabled us to capture better end market demand.”CFO Howard I. Ungerleider noted that Dow has benefited from having the majority of its global manufacturing capacity near rich shale natural gas resources.“About 65% of our production capacity is based in the Americas where we have a cost advantage from abundant shale-based feedstocks,” the CFO said.Dow, whose products go into plastics, coatings, building materials, and numerous other applications for consumer and industrial end markets, anticipates “ongoing underlying demand strength” across those markets in 2Q2022.“Despite elevated inflation, consumer spending continues to grow and balance sheets remain healthy with household debt service levels at some of the lowest levels in the last 30 years,” Ungerleider said. “Industry activity also remains robust” and continues “to point toward expansion.”Fitterling said “the biggest issue behind natural gas pricing in the near term has been freeze-offs in the U.S. and the fact that we’ve not been back to the 98 Bcf a day that we need to produce…to get inventories back to the five-year level.” According to the U.S. Energy Information Administration, Lower 48 U.S. working gas in storage increased by 53 Bcf for the week ending April 15.Fitterling added, however, that “we’re starting to see the production and the rigs shift into natural gas production.” As a result, he predicted that “natural gas production is going to come on faster” than liquefied natural gas (LNG) export capability.“We’re pretty well maxed out on LNG export capability today,” he said. “So we’ll — if we can get these inventories back to the five-year average levels by the fall, then I think you’re going to see natural gas prices really come back into a more normal trading range.”In the medium-term, Fitterling said he expects gas prices in the $4.00-$6.00/MMBtu range. Longer-term, “as those inventories get to that five-year level,” he said gas prices should be closer to $3.00/MMBtu territory.
Yellen Warns EU About Banning Russian Oil -- A full EU ban on Russian crude oil and gas imports could have unintended economic consequences for the United States and its Western allies, U.S. Treasury Secretary Janet Yellen told reporters in Washington on Thursday. The Treasury Secretary added that such a ban could do more harm than good.Europe does need to reduce its dependence on Russian oil and gas, Yellen said, “but we need to be careful when we think about a complete European ban on, say, oil imports.”Europe has been under pressure to stop purchases of Russian oil and gas—an action that would cut off revenue streams for Russia, but would also starve the EU of much needed energy supplies.Yellen’s warning follows JP Morgan’s from earlier this week that suggested a full and immediate ban in the EU on Russian energy supplies would cut off more than 4 million bpd of Russian oil and send crude oil prices to $185 per barrel.The EU and the European Commission has been discussing an embargo on Russian crude oil, but the group is divided on the issue, with countries such as Germany strongly opposed due to its significant reliance on Russian energy supplies. Even if all EU members do agree on such a ban, it would still take months to draft and prepare, European officials said last week. The EU is already in talks with other oil-producing countries with the end goal of obtaining alternative oil suppliers so it can more readily wean itself off Russian oil supply. Yellen agreed that a European energy ban would raise oil prices, “and, counterintuitively, it could actually have very little negative impact on Russia” because while Russia could end up exporting less oil, the price it would get for each barrel could also go up. The U.S. Administration has been railing against highgasoline prices—a result of high crude oil prices—since last Fall.
Kremlin’s gas-for-roubles demand threatens Europe’s gas supply The prospect of Europe getting cut off from Russian gas supplies is starting to get real. The clock is ticking in a standoff over the Kremlin’s demand that its customers in Europe pay in roubles for the fuel, which the region depends on for a fifth of its power generation. The EU has said the decree violates sanctions and hands more power to Russia. It suggested an alternative that avoids roubles on Friday, but it is up to Moscow to decide if that is acceptable. Payments come due in May, and that is when the moment of truth arrives. By refusing President Vladimir Putin’s payment terms and testing his threat to turn off the taps, European buyers “would be running a very real risk of their supplies being cut,” said Katja Yafimava, a senior research fellow at the Oxford Institute for Energy Studies. The game of geopolitical chicken could lead to Europe rationing energy for the first time since the oil crisis in the 1970s. As the biggest consumer of Russian gas in Europe, Germany is most exposed, but the fallout would ripple across the continent and beyond. Europe’s natural gas market would show the impact immediately. Trading is already on edge, with prices five times higher than the same time last year. That could get worse. In the event of a supply disruption, forward contracts could more than triple, especially if Europe enters next winter with depleted storage, according to Kaushal Ramesh, senior analyst, gas and LNG at Rystad Energy. Such a surge would put governments and central banks under pressure as they seek to control soaring inflation. The risk is that the mounting cost-of-living crisis intensifies and spills over into wider unrest and a deeper crisis. With less fuel for gas-fired generators, the risks of rolling blackouts would increase. While countries would try to shift to other sources, the options are limited. France would halt large gas-fired power plants to conserve the fuel for other needs, Italy would maximise production from coal or fuel oil, and Germany has discussed burning more local lignite, the dirtiest form of coal. The workarounds are likely to make the region even more polluting. On the upside, warmer weather would reduce gas consumption for heating, delaying the worst effects at least until the fall.
EU asks people to use less air conditioning, drive slower, and work from home to help reduce reliance on Russian energy -The European Union is asking people to use less air conditioning, drive slower, and work from home to help it reduce reliance on Russian energy amid the war in Ukraine.In a nine-step plan published Thursday, entitled "Playing My Part," the International Energy Agency (IEA) and EU outlined different ways people could cut down on fossil-fuel consumption in their daily lives. The suggested measures to save energy include:
- Using less heat in the winter and less air conditioning in the summer
- Driving slower on highways
- Flying less
- Taking more public transport
- Working from home
The measures would not only cut Europe's reliance on Russian energy but also help reduce greenhouse gas emissions, saving an average household around 450 euros ($485) per year, the IEA and EU said. It would also save enough oil to fill 120 supertanker ships and enough natural gas to heat almost 20 million homes in the EU, they said."Most households are also experiencing higher energy bills because of the energy crisis exacerbated by the war," the EU and IEA said."Using less energy is not only an immediate way for Europeans to reduce their bills, it also supports Ukraine by reducing the need for Russian oil and gas, thereby helping to reduce the revenue streams funding the invasion," they added.Western countries, especially in Europe, have been desperately trying to pull themselves away from Russian energy imports since the start of the invasion on February 24.In March, the EU pledged to become independent from Russian oil and gas by 2030.The EU sends Russia around $450 million a day for oil and $400 million per day for natural gas, the Associated Press reported, citing analysts at the Bruegel think tank in Brussels.One of Russia's biggest buyers is Germany, which purchases about 25% of its oil and 40% of its natural gas, per Reuters.
Watch: Construction of Norway-Poland gas pipeline resumes Work on a pipeline to deliver natural gas from Norway to Poland has resumed in Denmark after a nine-month suspension. The Baltic Pipe, which is expected to deliver 10 billion cubic metres of gas annually to Poland — about half of the country's total consumption — should be fully operational from 1 January 2023. The European Union has announced plans to slash by two-thirds its imports of Russian gas by the end of the year to reduce its dependence on Moscow which supplies about 45% of the bloc's natural gas imports. This is in response to Russia's invasion of Ukraine with the EU's energy dependence on Russia seen as a potential pressure point for Moscow to use against the bloc. Although the EU has imposed sanctions against Russia for its military assault on its neighbour, it has steered clear of punitive measures against the gas and oil sectors. Watch our report in the video player above.
Live updates: Russia halts gas supplies to Poland and Bulgaria as tensions rise with the West ---Russia's gas supplies to Poland and Bulgaria have been halted on Wednesday morning after the countries refused Moscow's demand to pay for gas supplies in rubles. Russia's state gas giant Gazprom had contacted Poland and Bulgaria's state gas companies on Tuesday telling them that their supplies would be halted on Wednesday. Poland said its supplies had been cut today, while the situation in Bulgaria is more uncertain. Poland's state-owned oil and gas company PGNiG said Russia's gas giant Gazprom had informed it on Tuesday that it would halt gas supplies that are delivered via the Yamal pipeline on Wednesday morning. PGNiG said in a statement Tuesday that the company is monitoring the situation "and is prepared for various scenarios" and to receive gas from other sources, but said that currently it has enough gas in storage and is meeting demand. The halting of gas supplies to Poland, which imports around 45% of its natural gas from Russia, according to recent data from the EU, is another sign of rising tensions between Russia and the West following the invasion of Ukraine. One official in Kyiv described Russia's latest move to cut supplies as "gas blackmail." Bulgaria imported almost 73% of its natural gas from Russia in 2020, EU data shows. Russia had demanded that countries importing its gas (the EU as a bloc imports around 40% of its natural gas from Russia every year) must pay in rubles, prompting a backlash from importers, including Poland and Bulgaria, which refused and said the demand is a breach of contract.
Poland, Bulgaria cut off from Russian gas as Ukraine tensions mount - — Polish and Bulgarian leaders accused Moscow of using natural gas to blackmail their countries after Russia's state-controlled energy company said it would stop supplying the two European nations Wednesday.The gas cutoff came after Russian President Vladimir Putin said last month that “unfriendly” countries would need to start paying for gas in rubles, Russia's currency, which Bulgaria and Poland refused to do.Russian energy giant Gazprom said in a statement that it hadn’t received any payments from Poland and Bulgaria since April 1 and was suspending their deliveries starting Wednesday.If the countries siphon off gas intended for other European customers, deliveries to Europe will be reduced by that amount, the company said.Polish Prime Minister Mateusz Morawiecki told Poland's parliament that he thinks the suspension was revenge for new sanctions against Russia that Warsaw imposed over the war in Ukraine.Morawiecki vowed that Poland would not be cowed by the cutoff. He said the country was safe from an energy crisis thanks to years of efforts to secure gas from other countries.Lawmakers stood and applauded when he said that Russia’s “gas blackmail” would have no effect on Poland.The new sanctions, announced Tuesday, targeted 50 Russian oligarchs and companies, including Gazprom. Hours later, Poland said it had received notice that Gazprom was cutting off its gas supplies for failing to adhere to the demand to pay in Russian rubles.Poland’s gas company, PGNiG, said the gas supplies from the Yamal pipeline stopped early Wednesday, as Gazprom had warned they would.Bulgaria said Tuesday that it also was informed by Gazprom that the country's gas supplies would end at the same time.Bulgarian Prime Minister Kiril Petkov called Gazprom’s suspension of gas deliveries to his country “a gross violation of their contract" and “blackmail.”“We will not succumb to such a racket,” he added.Russia's move raised wider concerns that other countries could be targeted next as Western countries increase their support for Ukraine amid a war now in its third month.European Union officials were holding emergency talks on Wednesday. European Commission President Ursula von der Leyen said the announcement by Gazprom “is yet another attempt by Russia to use gas as an instrument of blackmail.”The Greek government was to hold its own emergency meeting in Athens. Greece's next scheduled payment to Gazprom is due on May 25, and the government must decide whether it will comply with the demand to complete the transaction in rubles. Greece is ramping up its liquefied natural gas storage capacity, and has contingency plans to switch several industry sectors from gas to diesel as an emergency energy source. It has also reversed a program to reduce domestic coal production over the next two years.
Russia accused of 'blackmail' after halting gas supplies to two European countries - Russia's gas supplies to Eastern Europe are looking highly uncertain after the country's state-run gas giant Gazprom told Poland and Bulgaria that it would halt supplies. The move comes after both countries refused Moscow's recent demand to pay for gas supplies in rubles, but also coincides with a sharp rise in tensions between Western allies and Russia as the war in Ukraine continues into a third month. Early Wednesday morning, Gazprom released a statement saying it had halted supplies to Poland and Bulgaria — both heavy consumers of Russian gas — due to payments not being made in the Russian currency. It said supplies would resume once these payments were made. In the statement, Gazprom warned both countries against any "unauthorized withdrawal" of gas supplies flowing through their territories. "Bulgaria and Poland are transit states. In case of unauthorized withdrawal of Russian gas from transit volumes to third countries, supplies for transit will be reduced by this volume." Natural gas prices surged in Europe on Wednesday morning. The Dutch wholesale gas contract for the day-ahead, a benchmark for Europe, rose 24.2% to 115.75 euros ($122.40) per megawatt hour, while the U.K. natural gas price for June rose around 20 pence to 222 pence ($2.78) a therm. Poland's state-owned oil and gas company PGNiG said Gazprom had informed it on Tuesday that it would halt supplies that are delivered to the country via the Yamal pipeline, starting Wednesday morning. But after dropping to zero earlier Wednesday, physical gas supplies appeared to edge up again, data from the European Union network of gas transmission operators showed, according to Reuters. Poland, however, said the supplies had indeed been halted. Bulgaria has not confirmed that its supplies have been stopped but its prime minister, Kiril Petkov, described the move as "blackmail" and said any halt in supplies would be a breach of contract. Bulgaria's energy minister, Alexander Nikolov, said supplies to customers were guaranteed for at least a month ahead, Reuters reported.
European gas prices have surged 28% since Russia halted supplies to Poland and Bulgaria - European gas prices surged on Wednesday, after Russia halted supplies to Poland and Bulgaria, stoking concern that other countries in the continent could be targeted for their support towards Ukraine.Benchmark Dutch futures contracts tracking Europe's wholesale gas price rose as much as 28% to 117 euros per megawatt hour ($124) in early trading Wednesday, according to data from Investing.com.That jump came as Russia's state-owned energy major Gazprom said it would "fully halt" gas supplies to Bulgaria's Bulgargaz and Poland's PGNiG "due to their failure to pay in rubles."Both countries were informed that all flows would be stopped from Wednesday, April 27.For more than a month, tensions have been rising between Western nations and Russia over the Ukraine war. President Vladimir Putin in March ordered "unfriendly countries" to pay for Russian gas using its official currency, even though these contracts are generally required to be paid in dollars. Europe has leaned on Russia for decades because it's dependent on the country for around 40% of its gas supplies. Poland and Bulgaria are among other European nations that have rejectedpaying rubles for gas supplies, disputing that this would be a breach of contractand would avoid sanctions on Russia's central bank.European Commission President Ursula von der Leyen said Wednesday that Gazprom's announcement is another attempt to use gas as an "instrument of blackmail.""This is unjustified and unacceptable. And it shows once again the unreliability of Russia as a gas supplier," she said in a statement, adding that the bloc is working on alternate sources of delivery to ensure continued supply.
Europe scrambles for natural gas solution as Putin squeezes supply - The European Union is racing to find alternative suppliers of natural gas after Russia's Gazprom halted flows to two EU nations, sparking fears that other countries may also be cut off. The developments come as Brussels is fearful about nations and energy firms circumventing strict international sanctions on Russia — imposed on Moscow in the wake of its unprovoked invasion of Ukraine. Gazprom, Russia's state-owned energy firm, cut supplies of natural gas to Poland and Bulgaria earlier this week, after both nations refused to pay for the commodity in rubles — something that President Vladimir Putin requested amid growing Western support for Ukraine. The decision puts further pressure on the EU, which imports roughly 40% of all its natural gas from Moscow, to find alternative solutions. "It contributes to opening the eyes of those who were still thinking Russia would not use gas as a leverage," one EU official, who did not want to be named due to the sensitive nature of the situation, told CNBC about Russia's latest move. European Commission President Ursula von der Leyen went further Wednesday, accusing the Kremlin of blackmailing the bloc. Kremlin spokesman Dmitry Peskov dismissed accusations that Moscow was using its gas supplies to blackmail European nations Poland and Bulgaria, saying Russia was a reliable energy supplier. He also declined to say how many countries had agreed to switch to paying for gas in rubles, Reuters reported. But the pressure could escalate if Gazprom chooses to cut supplies to other EU nations. The Kremlin warned Wednesday that other countries will face the same issue if they do not pay in rubles — something that the commission, the executive arm of the EU, opposes as it would breach current sanctions. "Russia's move to halt gas flows to Poland followed Berlin's decision—under intense political pressure—to supply Ukraine with air-defense weaponry. The implied threat is that Russia will cut off Germany's gas supplies if Berlin continues to ship arms to Ukraine," analysts at Gavekal, a financial research firm, said in a note Thursday. "The economic effects would be catastrophic," they added.As such, the commission has been working on becoming less dependent on Russian gas. It signed an agreement with the United States earlier this year, where the EU will receive at least 15 billion cubic meters of liquefied natural gas in 2022.In the meantime, Brussels will have to decide how to keep paying for Russian natural gas without breaching the bloc's own rules. Russia issued a decree in late March saying European companies will continue to pay for gas in euros to Gazprombank — an institution that is not part of European sanctions — and then this cash would be converted into rubles in a secondary account opened by these energy firms.
Russian Supply Concerns Drive Natural-Gas Prices Higher - Natural-gas prices swung higher on both sides of the Atlantic on Wednesday after Russia stopped exports to Poland and Bulgaria , a move that investors feared could portend deeper global supply strains ahead. Prices climbed as traders in Europe pondered whether Russia’s action against two of its neighbors in Eastern Europe foreshadows trouble in bigger markets such as Germany’s. In the U.S., trading was driven by the prospect that producers could continue to ship abroad as much natural gas as infrastructure allows in response to tighter supply abroad.
Poland and Bulgaria say they won't bow down to Russia after Gazprom shut off their gas supply --=Poland and Bulgaria said Wednesday they won't bow down to Russia after its state-owned energy supplier Gazprom announced it will shut off their gas supply.In a statement seen by Reuters, the Russian energy giant said that its services will not be restored in the countries until they pay for gas in rubles — Russia's currency, which has suffered since Russia invaded Ukraine.Poland confirmed to the BBC that its gas supply had already been cut.Bulgaria's gas network operator Bulgartransgaz told local news provider Novinite that supplies were still flowing as of Wednesday morning, but said this could change throughout the day.Both countries said they can cope without Gazprom's gas in the short term, and that are seeking out alternative options."We have provided alternative quantities for a sufficiently foreseeable period," Bulgaria's energy minister Alexander Nikolov said on Wednesday, according to Novinite."As long as I am a minister and responsible for this, Bulgaria will not negotiate under pressure and with its head bowed," he added. "Bulgaria does not give in and is not sold at any price at any trade counterparty." Bulgaria relies on Gazprom for more than 90% of its gas supply,according to the BBC. Nikolov reassured the public that no restrictions on consumption were currently required, as per Novinite.
Four European gas buyers have paid Russia in rubles for supplies, bucking the EU's urging in the energy face-off - Four European natural gas buyers have already paid Russia in rublesfor supplies, complying with the country's demand to pay in its official currency, Bloomberg reported Wednesday. This development emerged as Russia halted gas supplies to Poland and Bulgaria on Wednesday, spurring a 28% surge in European gas prices. Russia's Gazprom said the reason for the stoppage is that both countries didn't pay for supplies in rubles, an order President Vladimir Putin put forth last month.The report didn't mention which four European buyers have made ruble payments. But Austria, which gets 80% of its gas from Russia, said Wednesday that deliveries are continuing unrestricted, according to Reuters.Additional cutoffs — as a result of failure to meet Moscow's rubles-for-gas requirement — are unlikely until the second half of May, Bloomberg said, citing a source close to Gazprom.Separately, the report said 10 European companies have opened accounts at Russia's Gazprombank as a means to meet Putin's payment demands. No company names were mentioned in the report.Under a special mechanism, a requirement for companies wanting to receive Russian gas is that buyers should open special accounts at Gazprombank. These would allow for foreign currency to be converted to rubles for settlements.Europe depends on Russia for around 40% of its gas supplies, but Moscow's demands have changed this trade dynamic. After Russia demanded payment for gas in rubles, some European governments said this would amount to a breach of contract and would avoid sanctions. Germany is especially reliant on Russian energy, particularly the natural gas that's shipped directly through the Nord Stream pipeline network. The Bundesbank has warned that cutting out Russian gas would plunge Germany's economy into recession.
Gas Flares: Europe Has a Hissy, Flails About as Russia Imposes Gas Payment Countersanctions and Economies Already Feel Blowback Bite by Yves Smith -On the whole, European and US leaders are continuing to make a very poor showing of the situation they instigated with Russia. The Biden Administration decided to seize $300 billion of Russian foreign exchange reserves, overconfident that they would crater the Russian economy. Ironically, however, the sanctions greatly reduced the Russian need for foreign exchange for trade, since respectable US and European companies took it upon themselves to stop or limit exports to Russia. And Russian banks don’t fund in dollars or euros (in contrast with the 1990s, when the economy was significantly dollarized). And the world still needs Russian oil, gas, metals, you name it.So after an initial shock and awe plunge, the rouble is very close to its highs versus the dollar over the last two years…despite the dollar being at its highest level against major currencies in the last 20 years. From XE: And Russia energy revenues have been fine, thank you very much: Russia projected a budget surplus before this crisis and its government income will be even higher due to the increase in energy revenues. Prime Minister Mikhail Mishustin told the Duma in early April that all receipts would now be spent into the economy. As you can see from the embedded document below, the government is embarking on more investment, loan discount, and tax relief programs. But Russia spent decades having to be a good budget-balancing-surplus running economy because (per above) it was significantly dollarized and had to look fiscally responsible to support the value of the rouble. Russia will suffer a serious recession, not just due to adaptation to having to produce even more internally, but also due to not being willing to run deficits when it is now able to operate as a fiat currency issuer. And even though the real economy shock has yet to fully manifest itself, the Russian top team is doing what it can to get in front of those issues, and they’ve also been warning the public that a second phase of difficulties is in the offing, which they expect to be the most acute starting soon and for the following six months.In other words, Russia managed the initial financial shock vastly better than the US and Europe imagined was possible. That leaves the West with the big problem that Russia can and is pushing back. It is telling that only very mild Russian counter-sanctions are putting Europe on tilt.The US and even more so Europe look to be hoist on their own sanctions petard. Yet they’ll be damned if they’ll formally walk back, even though there’s a lot of fudging going on. To recap: Putin announced its so-called “gas for roubles” program late last month, with details to follow. The reasoning was simple: Russia had just had $300 billion of what amounted to payment on past commodities exports stolen. It was not going to have payments on its gas exports to “unfriendly” countries subject to being clawed back again. The only way to assure that was to get payments in rouble, since rouble payment and clearing is under the control of the Russian Central Bank. As we anticipated, Russia implemented pretty much the only version that would respect Putin’s boundary conditions, which included adhering to the terms of current contracts.1 So all that really changed was that gas buyers would have to set up accounts at Gazprom Bank, which was not sanctioned.2Russia did not make this requirement effective until the next payments were due, and the earliest were the end of April..If you take the war out of the picture, this matter would otherwise be a pretty routine commercial dispute: “You stiffed me on some (actually really big) payments. Rather than argue about that, I’m requiring a minor change in payment arrangements to prevent that from happening.” But the screeching from Europe was astonishing. You’d think they believed they had the right to have Russia send them gas for free.
Europe faces recession if Putin fully shuts off the gas taps - Europe could be pushed into recession if Russia's gas squeeze widens, economists have suggested, after Gazprom cut off flows to Poland and Bulgaria. The state-owned energy giant on Wednesday announced that gas supplies to the two Eastern European countries had ceased after they refused Moscow's demand to pay for gas in rubles. Gazprom said that supplies would resume once these payments were made, prompting accusations of "blackmail" from Bulgarian Prime Minister Kiril Petkov. With deadlines approaching in the coming weeks for payment from a host of other European countries that are unlikely to acquiesce to the Kremlin's demands for ruble payment, concerns over President Vladimir Putin's previous threats of a broad blockage of gas supplies to "unfriendly" nations have returned to the fore. In a research note Wednesday, Berenberg Chief Economist Holger Schmieding and Senior Economist Kallum Pickering said the switch-off appeared to be a warning from Moscow that it could make good on this threat. Gas accounts for around a quarter of the European Union's energy generation, and Russia typically supplies around 40% of the bloc's natural gas imports. Europe faces concurrent economic shocks from the war in Ukraine and a surge in food and energy prices exacerbated by the conflict, which has prompted concerns about "stagflation" — an environment of low economic growth and high inflation. Berenberg suggested that the current headwinds will likely maintain stagflationary pressures in the second quarter of 2022. "A sudden stop of Russian gas supplies to Europe could push Europe into a recession. The precise impact of such an immediate gas embargo is hard to predict," Schmieding and Pickering said. "Calculations that it would lower the level of euro zone GDP in 2023 by 3 percentage points relative to a baseline call ... seem to be slightly too pessimistic, in our view, but it would certainly be a major hit to activity until the end of the next cold season in the spring of 2023." However, such a move would also be costly for Russia and tricky to implement, and although the decision to stop flows to Poland and Bulgaria may strengthen the EU's resolve to end its dependency on Russian gas, many member states oppose an immediate embargo of imports.
Russia’s halt of European gas could see 'catastrophic' winter pricing, veteran trader warns --Veteran natural gas trader Bill Perkins warned Thursday of potentially "catastrophic pricing" this winter if Russia's move to cut gas supplies to Poland and Bulgaria ends in a full-blown energy blockade. "It's a dicey market right now," Perkins, CEO and head trader at Skylar Capital Management, told CNBC. "We're in a hot-box button-panic mode," Perkins added. "If Russia shuts off the gas and oil, Europe is going to be scrambling this winter to maintain heating, and just maintain their economies," he said. Russia's Gazprom on Tuesday informed Poland and Bulgaria's state gas companies, PGNiG and Bulgargaz, that it will halt gas supplies after the two countries refused President Vladimir Putin's demands to pay for supplies in the Russian ruble. The escalation sent the Dutch wholesale gas contract for the day-ahead, a benchmark for Europe, up more than 20% Wednesday. Dutch TTF Natural Gas futures are up almost 60% year-to-date. "Expect an elevated price and lots of volatility for the next few years," Perkins warned, describing his forward market outlook as "slightly bearish in the front" but "constructive and bullish long term." "Given where prices are right now, and the flows of LNG [liquefied natural gas] to northwest Europe, it's actually a bearish situation barring the complete removal of Russian gas," he said. "Given that they've fired the first missile … everybody else is on notice, so those bearish bets are trimmed back," he added. "In the winter, all bets are off," Perkins said. "Without Russian gas, which is about 40% of their gas supply or their demand for gas, it's really difficult to see how the market balances without running out of gas."
New gas pipeline boosts Europe's bid to ease Russian supply - (AP) — Mountainous and remote, the Greek-Bulgaria border once formed the southern corner of the Iron Curtain. Today, it’s where the European Union is redrawing the region’s energy map to ease its heavy reliance on Russian natural gas. A new pipeline — built during the COVID-19 pandemic, tested and due to start commercial operation in June — would ensure that large volumes of gas flow between the two countries in both directions to generate electricity, fuel industry and heat homes. The energy link takes on greater importance following Moscow’s decision this week to cut off natural gas supplies to Poland and Bulgaria over a demand for payments in rubles stemming from Western sanctions over the war of Ukraine. The 180-kilometer (110-mile) pipeline project is the first of several planned gas interconnectors that would give eastern European Union members and countries hoping to join the 27-nation bloc access to the global gas market. In the short term, it’s Bulgaria’s backup. The new pipeline connection, called the Gas Interconnector Greece-Bulgaria, will give the country access to ports in neighboring Greece that are importing liquefied natural gas, or LNG, and also will bring gas from Azerbaijan through a new pipeline system that ends in Italy. It's one of many efforts as EU members scramble to edit their energy mixes, with some reverting back to emissions-heavy coal while also planning expanded output from renewables. Germany, the world’s biggest buyer of Russian energy, is looking to build LNG import terminals that would take years. Italy, another top Russian gas importer, has reached deals with Algeria, Azerbaijan, Angola and Congo for gas supplies. The European Union wants to reduce its dependence on Russian oil and gas by two-thirds this year and to eliminate it completely over five years through alternative sources, the use of wind and solar power, and conservation. Russia's invasion of Ukraine is likely to accelerate changes in the EU’s long-term strategy as the bloc adapts to energy that is more expensive but also more integrated among member nations, said Simone Tagliapietra, an energy expert at the Brussels-based think tank Bruegel. EU policymakers argue that while Eastern European members are among the most dependent on Russian gas, the size of their markets makes the problem manageable. Bulgaria imported 90% of its gas from Russia but only consumes 3 billion cubic meters annually — 30 times less than lead consumer Germany, according to 2020 data from EU statistics agency Eurostat. The Greece-Bulgaria pipeline will complement the existing European network, much of which dates to the Soviet era, when Moscow sought badly needed funds for its faltering economy and Western suppliers to help build its pipelines. The link will run between the northeastern Greek city of Komotini and Stara Zagora, in central Bulgaria, and will give Bulgaria and neighbors with new grid connections access to the expanding global gas market. That includes a connection with the newly built Trans Adriatic Pipeline, which carries gas from Azerbaijan, and suppliers of liquefied natural gas that arrives by ship, likely to include Qatar, Algeria and the United States. As many as eight additional interconnectors could be built in Eastern Europe, reaching as far as Ukraine and Austria. The 240 million-euro ($250 million) pipeline will carry 3 billion cubic meters of gas per year, with an option to be expanded to 5 billion. It received funding from Bulgaria, Greece and the EU, and has strong political support from Brussels and the United States.
Algeria Threatens to Cut Off Gas Exports to Spain Amid Rising Geopolitical Tensions -Until mid-March this year, Spain appeared to hold an enviable position in Europe’s natural gas markets. While it produced virtually no gas of its own, it was also almost completely free of dependence on Russian-supplied gas, thanks largely to its long-standing commercial ties with Africa’s largest exporter of natural gas, Algeria. In 2021 Algeria provided 43% of all the gas consumed in Spain. But those ties could be on the verge of breaking, leaving Spain in a much less enviable position.On Wednesday (Apr 27), Algiers threatened to cut off the gas supply to Spain if the Sánchez government diverted any of the energy it received from Algeria to any third countries (without naming any names).“Any transport of Algerian natural gas delivered to Spain whose destination is contrary to that provided for in the contracts will be considered a breach of contractual commitments, and consequently, could lead to a breach of the contract that binds Sonatrach (NC: Algeria’s state-owned natural gas company) with its Spanish customers,” the Algerian government said in a statement.Though Algeria did not name any names, it didn’t need to. Spain has been talking for months about reversing the flow of the now dormant Maghreb-España (MGE) pipeline in order to shift gas to Morocco, which has struggled to secure new supplies since Algeria closed the MGE in November 2021.This Algiers did for a number of reasons, including as retaliation for a cyber-espionage campaign by Rabat against high-ranking Algerian officials, including the president, the minister of foreign affairs, and a former military chief of staff. A staunch defender of Western Sahara’s claims for independence and home to close to 200,000 Western Sahrawi refugees, Algiers is also livid about Morocco’s aggressive (and so far largely successful) efforts to garner international support for its territorial claims over Western Sahara.For both Spain and Morocco the pipeline was an important source of natural gas that has now gone. Spain is still receiving gas from Algeria through the Medgaz pipeline that links the two countries by sea as well as from LNG shipments. Morocco is having to depend on domestic production, which is not nearly enough to meet domestic demand. The new plan, hatched between Madrid, Rabat and quite possibly Washington (more on that later) would work as follows: Morocco would purchase liquified natural gas on the international market, most likely the US, which will be regassified in Spain and then piped to Morocco. The US has already replaced Algeria as Spain’s largest supplier of gas in recent months.
Qatar Energy weighs expansion of LNG capacity - State-run Qatar Energy is considering further expanding its liquefied natural gas (LNG) capacity amid the rising gas demand in Europe, reported Bloomberg News, citing people familiar with the matter. The European nations are attempting to secure supplies to cut reliance on Russian gas, following the invasion of Ukraine. Qatar Energy is in talks with undisclosed gas buyers on whether to expand the $30bn project by adding six gas-liquefaction plants. Each of the proposed six new units is expected to have the capacity to produce eight million tonnes of LNG per year.
Three Chinese energy firms are in talks to buy Shell's stake in a huge Russian natural gas export project, a report says -- Three Chinese state-run energy companies are in talks to buy Shell's 27.5% stake in a huge Russian natural gas export project, Bloomberg reported, citing people with knowledge of the matter.CNOOC, CNPC, and Sinopec are in joint discussions with the Anglo-Dutch oil and natural gas giant over its holding in the Sakhalin-2 liquefied natural gas venture, the people said.The sources said discussions, which could include selling the stake to one, two, or all three of the firms, were at an early stage and could still fall through. One of the sources said that Shell was also open to talks with potential buyers outside of China.Shell says that Sakhalin-2 supplies about 4% of the world's current liquefied natural gas market, with Japan, South Korea, and China as the main customers. Russian state-owned energy giant Gazprom owns a 50% stake in the venture, while Japanese corporate group Mitsui owns 12.5%, and fellow Japanese firm Mitsubishi holds 10%.Shell, CNOOC, CNPC, and Sinopec did not immediately respond to Insider's request for comment.Russia has huge natural gas reserves, and supplied around a third of the EU and UK's total natural gas demand in 2021, according to the International Energy Agency. It's also the world's third largest oil producer and the second largest crude oil exporter, the agency said.Some Western oil firms have said they would discontinue operations in Russia following the outbreak of the conflict and the ensuing package of international sanctions, designed to force Russian President Vladimir Putin to abandon the invasion. China, in comparison, hasn't taken sides and has continued buying energy supplies from Russia.
CPC crude export terminal operating at full capacity --The Caspian Pipeline Consortium's (CPC) crude export terminal in the Black Sea is operating at full capacity for the first time since two of its three single point mooring (SPM) buoys were damaged in a storm a month ago.The terminal, which is the main export route for Kazakhstan's crude, requires two SPMs in operation to function at full capacity, with the third buoy serving as an emergency spare. It had been operating with just one buoy since 24 March.SPM 2 remains offline, but SPM 3 was restarted on 23 April, the CPC said. The Delta Commander tanker completed loading a crude cargo from SPM 3 yesterday, according to market and shipping sources.Russia's technical watchdog Rostekhnadzor has finished an inspection on CPC infrastructure that it began on 12 April, the consortium said, adding that no oil spill was recorded in the Black Sea.The CPC terminal handles roughly 80pc of Kazakh crude and condensate loadings. It is scheduled to export a provisional 1.42mn b/d in May, up from a revised 1.35mn b/d this month.The disruption at the terminal briefly cut Kazakh crude production by around a quarter. Output was 1.68mn b/d on 22 March, before dropping to 1.25mn b/d on 3-4 April and rising to 1.65mn b/d on 24 April, according to Kazakhstan's Information Analytical Centre of Oil and Gas and Arguscalculations. Kazakh crude production averaged 1.59mn b/d in March, down by 50,000 b/d from February, Argus estimates.Chevron, which leads the Tengizchevroil (TCO) consortium operating Tengiz, told Argus that output at the field is back to "normal rates." The company was forced to adjust production at the Tengiz field in late March, following the disruption to exports. "[TCO] is currently exporting its crude oil in line with full allocations by the Caspian Pipeline Consortium," Chevron said.
Russian oil exports rebound, but destinations are harder to track - Asia is probably still snapping up cheap Russian oil that European buyers don’t want. Seaborne exports of the nation’s crude rebounded in the seven days to April 22. One-fifth of the volume shipped from ports on the Black Sea, Baltic and Arctic coasts is on tankers showing no final destination, with most expected to end up in Asia. A total of 40 tankers loaded about 28-million barrels from Russian export terminals, according to vessel-tracking data and port agent reports collated by Bloomberg. That put average seaborne crude flows at 4-million barrels a day, up by 25% against the week ended April 15. The weather played a big part. The jump in oil exports means a boost to revenues for Moscow as President Vladimir Putin steps up his war in Ukraine, while the US and EU discuss options to wean Europe off Russian oil. At current rates of crude oil export duty, the week’s shipments will have earned the Kremlin about $232m; that’s $46m more than the previous week. Russia exports crude from four main areas: the Baltic Sea in northwest Europe, the Black Sea, the Arctic and terminals on its Pacific Coast. From three of the four areas, flows to Asia or unknown destinations rose. The weekly shipment figures can swing depending on the timing of when tankers depart, which is also heavily influenced by the weather at ports — as has been the case for the past several weeks. The past week saw higher aggregate volumes from all four regions. Flows of Urals and Siberian Light crude from terminals in the Baltic and Black Sea rose by 663,000 barrels a day, or 36%. The volume of crude leaving the Black Sea port of Novorossiysk more than doubled as a backlog of ships that built up during the previous week’s bad weather started to clear. Meanwhile, shipments from the country’s three eastern terminals on its Pacific Ocean coast were up by 105,000 barrels a day, or 10%. Cargoes from Murmansk, which handles crude produced along Russia’s Arctic coastline were also up, increasing by 29,000 barrels a day, or 9%.
Israeli oil firm fined $490,000 decade after major spill -An Israeli court ruled Tuesday that state-owned Europe Asia Pipeline Company must pay a fine of 1.6 million shekels ($490,000) for polluting a stream in Israel in 2011.In addition, the company’s former CEO and two other senior executives were fined tens of thousands of shekels each. The penalties, which will be paid to the Environmental Protection Ministry’s Maintenance of Cleanliness Fund, come after the court convicted EAPC and the senior officials in February of polluting Nahal Zin and its environs in separate incidents in June and September 2011. In both cases, hundreds of thousands of liters of jet fuel leaked into the stream from a company pipeline. In her ruling on Tuesday, Judge Sara Haviv of the Be'er Sheva Magistrate's Court said the “nature and scope of the damage” were severe. Nevertheless, she added, the senior executives “aren’t directly responsible for the damage to the pipeline.” Their crime was failing to do everything they could to prevent it.EAPC’s fine must be paid within three months, she ruled, and if the company commits any similar offenses over the next two years, it will have to pay an additional penalty of 3 million shekels.EAPC’s former CEO, Yair Vida, was fined 75,000 shekels, though he can choose six months in jail instead. Shlomo Levy, the current vice president for safety and environmental protection, who was deputy head of the engineering department in 2011, was given the choice of paying a fine of 150,000 shekels or serving nine months in jail. Nir Savyon, the vice president for engineering, who was a project manager in 2011, was given the option of a 100,000-shekel fine or nine months in jail.In her verdict in February, Haviv wrote that the company and the three executives hadn’t prepared sufficiently to cope with such an emergency or done enough to minimize the risks of a spill. Therefore, even though the damage to the pipeline was actually caused by employees of a subcontractor, EAPC was ultimately responsible for it.
Over 100 killed in massive explosion at illegal oil refinery in Nigeria --More than 100 people were killed overnight in an explosion at an illegal oil refining depot on the border of Nigeria's Rivers and Imo states, a local government official and an environmental group said on Saturday. "The fire outbreak occurred at an illegal bunkering site and it affected over 100 people who were burnt beyond recognition," the state commissioner for petroleum resources, Goodluck Opiah, said. The bunkering site was in the Ohaji-Egbema Local Government Area of Imo state in the Abaezi forest that straddles the border of the two states. Unemployment and poverty in the oil-producing Niger Delta have made illegal crude refining an attractive business but with deadly consequences. Crude oil is tapped from a web of pipelines owned by major oil companies and refined into products in makeshift tanks. The hazardous process has led to many fatal accidents and has polluted a region already blighted by oil spills in farmland, creeks and lagoons. The Youths and Environmental Advocacy Centre said several vehicles that were in a queue to buy illegal fuel were burnt in the explosion. The border location is a reaction to a recent crackdown by the Rivers state governor on illegal refining in an effort to reduce worsening air pollution.
100 killed after blast at illegal Nigerian oil refinery -Charred bodies were left scattered among burnt palms, cars and vans on Sunday after a weekend explosion which killed more than 100 people at an illegal oil refining depot on the border of Nigeria's Rivers and Imo states. Flip flops, bags and clothing belonging to those who died littered the ground, which was blackened by oil and soot while still emitting smoke in some places despite overnight rain. "There are so many people that died here. I'm pleading to the government to look into this," Uche Woke, a commercial bike rider, told Reuters at the scene of the blast on Saturday night. The Nigerian Red Cross Society was on the scene on Sunday to assess the blast, which destroyed a section of the Abaezi forest, which straddles the border of the Ohaji-Egbema Local Government Area of Imo state with Rivers state. Nigerian President Muhammadu Buhari said in a statement that he would intensify the clampdown on illegal refineries after what he described as a "catastrophe" and "national disaster". Unemployment and poverty in the oil producing Niger Delta have made illegal refining attractive, but with often deadly consequences. Crude oil is tapped from a web of pipelines owned by major oil companies and refined in makeshift tanks. The process has led to fatal accidents and polluted a region already blighted by oil spills in farmland, creeks and lagoons. The Youths and Environmental Advocacy Centre said several vehicles that were in a queue to buy illegal fuel were burnt. "The fire outbreak occurred at an illegal bunkering site and it affected over 100 people," Goodluck Opiah, the state commissioner for petroleum resources, said of the accident. The border location is a reaction to a recent crackdown in Rivers on illegal refining in an effort to reduce worsening air pollution. "In the last month or two, there were several raids and some security agents involved were tackled," Ledum Mitee, former president of the Movement for the Survival of the Ogoni People (MOSOP), said. At least 25 people, including some children, were killed in an explosion and fire at another illegal refinery in Rivers state in October. In February, local authorities said they had started a crackdown on the refining of stolen crude, but with little apparent success. Government officials estimate that Nigeria, Africa's biggest oil producer and exporter, loses an average of 200,000 barrels of oil per day, more than 10% of production, to illegal tapping or vandalising of pipelines. That has forced oil firms to regularly declare force majeure on oil and gas exports.
Nigeria's oil rig count improves amid rise in oil prices - The number of total active oil drilling rigs in Nigeria improved slightly in March 2022 to 10 from 8 recorded in February 2022. The new development is captured in the Organisation of Petroleum Exporting Countries (OPEC) latest Monthly Oil Market Report for April 2022. Oil rig a global index for measuring activities in the upstream sector when it comes to oil production. However despite the improve oil activities, Nigeria recorded a drop in oil production to 1.354 million barrels per day in March compared to 1.413 million barrels of crude oil daily in January, and 1.378 million barrels per day in February. Operators in Nigeria’s oil and gas sector have consistently attributed the drop in oil production to oil theft, while the government had raised concerns about the exit of international oil companies from Nigeria due to the global push for net zero carbon emission. The difficulties in Nigeria’s oil production is coming at a time oil prices are trading above $100. On Friday Brent Crude, the international benchmark Nigeria’s oil, closed at $106.7 per barrel while US oil, WTI, closed $102.1 per barrel.
TotalEnergies, Shell renew bid for oil exploration wells off SA coast - TotalEnergies and Shell are seeking to drill oil exploration wells off SA’s southwest coast months after two attempts to conduct seismic surveys in the country’s waters were thwarted by legal challenges. TotalEnergies is seeking comments from “interested and affected” parties and has invited them to participate in public meetings on the proposed programme, SLR Consulting, which has been contracted to conduct an environmental assessment, said in the notice dated April 19, seen by Bloomberg. “The main purpose of the pre-application phase is to provide initial notification to stakeholders and specifically to identify and develop the stakeholder database for the project,” SLR said in a response to queries. This will ensure SLR has a comprehensive database for future stakeholder engagement and more information will be released in May, the company said. Shell was blocked from carrying out a seismic survey off the country’s south coast in December after local communities took legal action against it, saying they had not been consulted and the programme may harm marine life and disrupt fishing. Last month Searcher Seismic abandoned exploration off the west coast after a court ordered it to halt activity. Still, in both cases a later ruling could allow a resumption of exploration, though Searcher Seismic said it would not return. TotalEnergies has not responded to requests for comment since Thursday. It has said on its website that it plans to drill one exploration well in the area and then, if it is successful, as many as four more. The notice, sent out on behalf of TotalEnergies, is in three widely spoken languages in SA — English, Afrikaans and isiXhosa — and details plans to explore a 10,000km² part of a block off the coast between Cape Town and Cape Agulhas. The block is 60km-170km offshore and covers water depths of between 700m and 3.2km. In addition to TotalEnergies and Shell, the government’s PetroSA is a partner. TotalEnergies has made two gas condensate discoveries in 2019 and 2020 off the SA coast.
$2.1 billion natural gas facility planned in Guaymas, Sonora -- A Singapore-based company plans to build a major natural gas facility in neighboring Sonora. LNG Alliance intends to invest $2.1 billion in a gas liquefaction facility in Sonoran port city Guaymas, state government officials say. The liquefied natural gas would then be shipped to Japan, Indonesia and other Asian countries, as well as other parts of Mexico itself. Sonoran Governor Alfonso Durazo said that Sonora played a key role in enabling the project. The project will be built on roughly 250 acres of state-owned land administered by the port authority, according to Durazo. In return, he said the state will receive “a small part of the benefits” generated by the company. The facility’s construction is expected to create some 3,000 jobs, and nearly 300 once operations begin.
KOGAS Signs Long-term LNG Import Contract with BP -Korea Gas Corp. (KOGAS) has signed a long-term U.S. LNG sale and purchase agreement (LNG SPA) with BP p.l.c, a comprehensive energy company. KOGAS will import 1.58 million tons of Henry Hub-linked LNG per year for up to 18 years from 2025. A signing ceremony was held at BP headquarters in London on April 21 (local time), with the attendance of representatives of the two companies including Chae Hee-bong, president of KOGAS and Ms. Carol Howle, executive vice president of trading & shipping at BP. KOGAS sealed the deal with BP Singapore Pte., a BP subsidiary in Singapore. BP was selected through an international tender organized by KOGAS in 2018 to secure a stable LNG supply. The two sides signed a head of agreement (HoA) in Sept. 2019. Experts call this contract very advantageous for KOGAS in light of the recent rise in oil and international LNG market prices. They predicted that the contract will make a significant contribution to stabilizing natural gas prices in Korea in the future.
Indian LNG imports down 8% in March --India’s LNG imports in March came in at 2.61bn m3 (about 1.89mn metric tons), down 7.8% year/year, the country’s oil and gas ministry's Petroleum Planning and Analysis Cell (PPAC) website showed on April 23. The imports were up 4.4% month/month, however. The cumulative imports of 31.9bn m3 (about 23mn mt) for the 12 months to March 31, 2022 (FY22) were lower by 3.4% compared with the corresponding period of the previous year. Meanwhile, LNG imports in March cost $1bn, up from $800mn in the same month last year. In FY22, the import bill was $11.9bn, up from $7.9bn in the same period last year, the PPAC data showed.
Russian oil - Reliance Industries stocks up on Russian oil - Reliance Industries, operator of the world’s biggest oil refining complex, has ordered at least 15 million barrels of Russian oil since Russia invaded Ukraine in February, trade sources said. Reliance has bought an average 5 million barrels a month for the June quarter, the sources said. Reliance did not immediately respond to a Reuters’ email seeking comment. Before the Ukraine war, Indian refiners, including Reliance, rarely bought Russian oil owing to high freight costs.
Pakistan’s petroleum import bill doubled to $15bn in 9 months - Pakistan’s petroleum import bill for nine months of the current fiscal year doubled to $15 billion from $7.5 billion in the same period during the last fiscal year, mainly because of soaring international prices and a steadily surging consumer demand. The price of petroleum products for Pakistan swelled twice the amount in dollar terms, but the former PTI-led government and the incumbent PML-N government still preferred to keep prices at existing levels, which caused losses on both internal and external accounts. Such a grave situation requires the conservation of petroleum products in order to curtail the import bill, but the ruling elites and policymakers stay unaffected. Despite being fully aware that the country is sliding towards bankruptcy and default, they prefer to gain political mileage at the cost of economy, the report stated. It was unwise of the PTI-led government to freeze fuel and power prices till June 2022 at the cost of Rs400 billion as subsidy. However, the new PM Shehbaz Sharif government also preferred to keep petroleum prices unchanged in an attempt to take populist measures to appease voters. The current account deficit touched over $1 billion mark in March 2022 clearly indicating it was a totally unsustainable level. The current account deficit reached $13.2 billion for the first nine months (July-March) period of the current fiscal year. Pakistan’s renowned economist Dr Hafiz A Pasha sees the current account deficit around $19 to $20 billion for this fiscal year. However, the official said the government procured four LNG containers at a rate of $27 per mmbtu so it would have total cost of approximately $350 million. This needs detailed analysis how much it is going to cost per unit electricity when the LNG is purchased at highest rates.
The Coming Russian Struggle For New Markets For Its Oil --Russia can increase domestic energy consumption and boost exports to new markets after some “unfriendly" countries have rejected Russian oil. So says President Vladimir Putin. It sounds simple, but it’s going to be a lot tougher in practice once the next wave of restrictions on Moscow’s oil trade kicks in. So far, there has been little obvious impact on the volume of crude flowing from Russia’s export terminals. While seaborne shipments drifted lower during the first weeks after Russia’s invasion of Ukraine, there was no sudden collapse. And the rate of exports surged in the first week of April, due in part to the easing of storms in the Black Sea, which had led to a backlog of ships waiting to load at a key port. What has changed, though, is where a lot of those ships are going. There has been a big jump in the number of cargoes heading for Asia from ports in the Black Sea, the Baltic and even, in one case, from the Arctic port of Murmansk. Flows of crude to Asian countries from Russia’s western ports have surged from zero in the weeks prior to the invasion to 875,000 barrels a day in the first full week of April. That’s almost as much as Russia’s combined daily shipments to Germany, France, Greece, Italy and the U.K. before the invasion. While Russian oil companies had to offer steep discounts of more than $30 a barrel to sell crude into Europe, they weren’t offering the same price cuts to buyers in India. That’s likely to change, though, as state-run oil refiners switch to privately negotiated deals in the hunt for better terms, instead of buying through public tenders. But there’s likely to be a limit to how much India’s refiners will buy from Russia. Increased imports of Russian crude will displace purchases from elsewhere and buyers will likely be wary of damaging relations with their traditional suppliers in the Middle East. That may put a cap on the volume they are prepared to take from Russia. There is also a question of the chemical make-up of the crude. Every crude oil is different and refineries operate most profitably when they process a specific grade of crude, or blend of grades. Increased volumes of Russian crude would have to displace crudes of similar quality, in terms of their gravity and sulfur content, which may also limit the volumes refiners are able to take. Increased crude flows from ports in western Russia to India and China, perhaps offset by higher flows of Persian Gulf crude to Europe, is also going to put a strain on tanker markets. The greater distances involved will tie up more vessels for longer periods on each delivery. It takes three times as long to carry a cargo of crude from the Russian port of Novorossiysk on the Black Sea to Sikka in India as it does to deliver it to Trieste in Italy. From the Baltic, which has become Russia’s primary outlet for westbound shipments, the increase is even bigger. It takes a day or two to deliver crude from Primorsk or Ust-Luga to Finland, Lithuania, or Poland, and about a week to ship it to the Netherlands or Germany. A voyage to the west coast of India takes a month, to the east coast, even longer. Given Russia’s pre-invasion mix of destinations for its Baltic Sea crude exports, a full diversion of flows to India would require five to six times as many ships as are typically used. The increased demand will push up prices — good news for ship owners, but bad news for whoever is going to have to absorb the transport costs. The increase is similar for shipments from Russia’s Arctic port of Murmansk. Most cargoes make a week-long voyage to Rotterdam. One is now on a month-long journey to Paradip on the east coast of India. More may be forced to follow, as the EU begins to toughen up its stance on Russian oil imports.
If Putin Wants New Customers for His Crude Oil, He'll Need a Lot More Tankers – Russia can increase domestic energy consumption and boost exports to new markets after some “unfriendly” countries have rejected Russian oil. So says President Vladimir Putin. It sounds simple, but it’s going to be a lot tougher in practice once the next wave of restrictions on Moscow’s oil trade kicks in. So far, there has been little obvious impact on the volume of crude flowing from Russia’s export terminals. While seaborne shipments drifted lower during the first weeks after Russia’s invasion of Ukraine, there was no sudden collapse. And the rate of exports surged in the first week of April, due in part to the easing of storms in the Black Sea, which had led to a backlog of ships waiting to load at a key port.
FUJAIRAH DATA: Oil product stocks drop after rare fuel oil shipment to US | S&P Global Commodity Insights --Oil product stockpiles at the UAE's Port of Fujairah fell to a three-week low as of April 25 after a rare fuel oil shipment to the US, according to the Fujairah Oil Industry Zone and Kpler shipping data. The total inventory was 16.088 million barrels as of April 25, down 5.7% from a week earlier and the lowest since April 4, the FOIZ data published April 27 showed. Stocks of heavy distillates and residues used as fuels for power generation and marine bunkers declined 7.4% over the same period to 11.068 million barrels, the first decline in five weeks, according to the data provided exclusively to S&P Global Commodity Insights. Some 1.06 million barrels of fuel oils were set to be exported out of Fujairah to the US in the week started April 18, only the second such shipment since at least June 2020, the Kpler data showed. The other weekly shipment of fuel oil to the US from Fujairah was in February, according to Kpler. Bunker demand has also improved at Fujairah, sources told S&P Global. Heavy distillates are needed at this time of year as Saudi Arabia looks to use more fuel oils instead of crude to burn for power generation as demand for air conditioning ramps up with summer. Other Middle Eastern countries including the UAE typically rely on natural gas for power generation. Heavy distillates stocks are 14.5% lower than this time last year. Stocks of middle distillates including jet fuel and diesel stood at 1.271 million barrels as of April 25, up 9% from a week earlier and the first gain in three weeks. Middle distillates stocks are down 60.62% over the past year. Light distillates including gasoline and naphtha stocks stood at 3.749 million barrels as of April 25, down 4.9% from a week earlier and the lowest in three weeks. Light distillates are down 31.61% since this time last year. Shipments of naphtha were headed to Japan and Taiwan from Fujairah for the week started April 18 while 707,000 barrels of gasoline were destined for Kenya, according to the Kpler data.
Column: Oil prices paralysed between Russia sanctions and China lockdowns: Kemp (Reuters) - Portfolio investors purchased petroleum last week for the first time in four weeks, but overall positioning remained subdued by the high cost of margin and large uncertainties surrounding both crude supply and demand. Hedge funds and other money managers bought the equivalent of 14 million barrels in the six most important petroleum-related futures and options contracts in the week to April 19. But the position has remained unchanged since mid-March as opposing concerns about the sanctions-related loss of production from Russia and lockdown-related loss of consumption in China have cancelled each other out. The combined net long position of 553 million barrels is in only the 39th percentile for all weeks since 2013 while the ratio of long to short positions at 4.59:1 is somewhat higher in the 59th percentile. Fund managers remain moderately bullish about the outlook for prices but extreme volatility has made it risky and expensive to maintain existing positions or initiate new ones. Reflecting higher margin calls, the total number of open futures positions for all categories of trader is the lowest for seven years, although it has stabilised in the last fortnight after falling sharply since mid-February. The most recent week showed hedge funds buying Brent (+27 million barrels), U.S. gasoline (+3 million) and U.S. diesel (+1 million) but selling NYMEX and ICE WTI (-16 million) and European gas oil (-1 million). Fund managers rotated out of WTI into Brent, likely reflecting the massive offer of extra barrels from the Strategic Petroleum Reserve in the United States and possible European Union sanctions on imports from Russia. Overall, funds are much more bullish for middle distillates and other refined products than for crude, reflecting strain on the refining system from strong demand for diesel and gas oil by manufacturers and freight firms.
Crude futures open lower on likely Fed rate hike, Shanghai lockdown - The Hindu BusinessLine - US Fed may hike rate by 0.5 point, China tightens curbs to control Covid spread Crude oil futures traded lower on exchanges in early trade as China continued with lockdown in Shanghai, affecting the demand prospects from a major consumer. Added to this, the expected move by the US Fed Reserve to hike interest rates affected the price movements. At 10.10 am, the June Brent oil futures were at $103.55, down by 2.90 per cent; and June crude oil futures on WTI were at $98.99, down by 3.02 per cent. May crude oil futures were trading at ₹7,623 on Multi Commodity Exchange (MCX) in the early deals against the previous close of ₹7,824, down by 2.57 per cent; and June futures were trading at ₹7,578 against the previous close of ₹7,777, down by 2.56 per cent. According to a Bloomberg report, China’s demand for gasoline, diesel and aviation fuel is expected to fall by 20 per cent year-on-year in April. It said that that is equivalent to a drop in crude oil consumption of 1.2 million barrels a day. The markets had noted the Shanghai authorities erecting fences outside residential buildings to control the Covid outbreak foring 25 million people to remain indoor in the region. 0.5 point hike on table Added to this, the US Federal Reserve Chairman Jerome Powell has indicated that a half-point interest rate increase ‘will be on the table’ when the Fed meets in May. In his crude oil outlook for the day, Rahul Kalantri, VP (Commodities) of Mehta Equities Ltd, said crude oil lost nearly 5 per cent last week on demand concerns. Oil prices extended losses on Monday amid persistent worries that prolonged Covid lockdowns in Shanghai and potential US rate hikes would dent global economic growth and demand for fuel. Natural gas fell hastened by a larger-than-expected weekly storage build, he said. However, banning Russian oil by European Union and decline in crude oil inventories in the US supported oil prices at lower levels. IMF revised down global growth due to Russia-Ukraine crisis and Federal Reserve Chairman also gave signal for aggressive rate hikes last week. He said the dollar index crossed two-year highs and hit 101 mark. Strength in the dollar also pushed oil prices lower. “We expect crude oil prices may show some more pressure in today’s session. Crude oil is having support at $97.20-$95.40 and resistance is at $103.10–105.00, In rupee terms, crude oil has support at ₹7,650-7,520, while resistance at ₹7,920–8,050,” he said. May natural gas futures were trading at ₹504.50 on MCX in the initial hour of Monday morning against the previous close of ₹520.40, down by 3.06 per cent. NCDEX On the National Commodities and Derivatives Exchange (NCDEX), May dhaniya futures were trading at ₹12,670 in the initial hour of Monday morning against the previous close of ₹12,480, up by 1.52 per cent. May cottonseed oilcake contracts were trading at ₹2,827 on NCDEX in the initial hour of Monday morning against the previous close of ₹2,883, down by 1.94 per cent.
Crude oil futures continue to fall as China extends lockdown, recession fears | S&P Global Commodity Insights - Crude oil futures continued to decline in mid-morning Asian trade April 25 as China intensified its COVID-19 related lockdowns and as the US Federal Reserve's aggressive rate hike stance fueled recession fears, which weighed on demand sentiment. At 11:02 am Singapore time (0302GMT), the ICE June Brent futures contract was down $2.85/b (2.66%) from the previous close at $103.80/b, while the NYMEX June light sweet crude contract fell $2.86/b (2.8%) at $99.20/b. China's COVID-19 woes continued to worsen with 51 new deaths reported on April 24, the highest one-day toll to-date, up from 39 the day before, according to media reports. The worsening infection rate has led to tightening enforcement and subsequently a hard lockdown in Shanghai. "For oil, reports that Chinese oil demand has fallen by the most since the Wuhan lockdown of 2020 reversed any thoughts of a weekend rally," SPI Asset Management Managing Partner Stephen Innes said in an April 24 note. "China's zero-COVID policy means that oil demand will be taking a hit as authorities try to bring the outbreak under control," Warren Patterson, head of commodities strategy at ING said in an April 25 note. "Refiners have already cut operating rates significantly due to lower demand. There are reports that state refiner, Sinopec, cut rates at two refiners in Shanghai by around 18% over the first 20 days of April." Meanwhile, the US Federal Reserve's increasingly aggressive stance on tightening monetary policy, with a 50 basis point interest rate hike expected, has rattled financial markets and raised the possibility of an economic recession, industry sources said. Tighter credit spurred consumers and companies to further rein in spending, which is weighing on demand sentiment. According to the latest forecast by independent research firm Rystad Energy on April 22, global oil demand is expected to fall by 1.4 million b/d to 99.6 million b/d on average, with it not expected to recover until 2023. Elsewhere, Libya's 120,000 b/d Zawiya refinery has been damaged due to armed clashes on April 22, the state-owned National Oil Corp said.
WTI Falls to Two-Week Low on China Demand Fears, Firmer USD-- With the exception of the advance in the ULSD contract, oil futures nearest delivery settled the Monday session with sharp losses. The drop was triggered by concerns over expanded quarantine restrictions in China after health authorities discovered a new cluster of Omicron cases in Beijing, a city of 21 million people, prompting citywide testing and renewed controls on movement in and out of the affected area. China's oil demand looks more uncertain today than it did just a week ago when health authorities proposed to loosen up COVID-19 lockdowns in the nation's financial hub -- Shanghai. Since then, the death toll in the city nearly tripled, spooking officials in Beijing and strengthening the case for continued lockdown measures. According to various estimates, China's daily oil consumption may have fallen by as much as 1.4 million barrels per day or 20% over the March to April period. Investors are worried that strict policies China put in place to combat the Omicron surge will further disrupt global supply chains. Continued disruptions to manufacturing and the movement of goods since the start of the pandemic have contributed to U.S. inflation reaching a four-decade high. New lockdowns in China and Russia's war in Ukraine are likely to add to price pressures. The German government on Monday raised its 2022 inflation forecast to 6.1%, up from 3.3% expected just three months earlier. German producer price index, a measure of inflation on a wholesale level topped 30% in March, according to the country's Federal Statistics Office, making it the highest level since the agency began collecting data 73 years ago. Western sanctions on Russia's coal and oil exports -- and efforts by the European Union to slash consumption of its natural gas -- have pushed prices up even further. Due to those factors, Morgan Stanley revised down its 2022 economic growth forecasts for the euro area from 3% to 2.7%, anticipating a meaningful slowdown in economic growth in the second half of this year. Against these headwinds, the U.S. dollar index climbed on Monday to its highest trade since April 2020 when the global pandemic shuttered a large chunk of the global economy, squeezing investors into the safe-haven currencies like the dollar. The greenback sliced through the basket of foreign currencies at the start of the week to finish at 101.769, while the Chinese yuan eroded further against the dollar. On a session, NYMEX West Texas Intermediate futures for June delivery fell $3.53 to $98.54 per barrel (bbl), and June Brent dropped $4.33 to $102.32 per bbl. NYMEX RBOB May futures declined 6.52 cents to $3.2398 per gallon, while the front-month ULSD contact rallied 15.23 cents to $4.0909 per gallon.
OIL FUTURES: Crude rebounds after sharp drop amid China demand concerns - Crude oil futures rose moderately in mid-morning Asian trade April 26 to recoup some losses after China lockdowns and a surging US dollar sent crude prices lower at the start of the week. At 10:42 am Singapore time (0242 GMT), the ICE June Brent futures contract was up 85 cents/b (0.83%) from the previous close at $103.17/b, while the NYMEX June light sweet crude contract rose 63 cents/b (0.63%) to $99.17/b. "A rebound with risk appetite and overdone concerns about demand destruction helped oil pare losses," Edward Moya, senior market analyst at OANDA, said in a note on April 26. Chinese authorities on April 24 tightened restrictions in parts of Shanghai, including erecting fences around apartment buildings with COVID-19 infected individuals. Similarly, authorities in Beijing have ordered 3.5 million residents and workers in the biggest district of Chaoyang to report for three coronavirus tests this week to stem a surge in cases, according to media reports. "COVID worries in China weighed heavily on oil prices yesterday ... the key for the market is how the situation in Beijing develops in the coming days and week," Warren Patterson, head of commodities strategy at ING, said in an April 26 note. Patterson noted that the potential EU ban on Russian oil remains the key upside risk for oil markets. "While it is looking more likely that we will ultimately see a ban, the uncertainty is how quickly a ban will be introduced," he said. On the supply side, production from shuttered fields in Libya will resume "in the coming days," the country's oil and gas minister Mohamed Oun said in a statement April 24. "Supply fears are not the primary focus for energy traders and now you have a surging dollar that is adding extra pressure across all commodities. The oil market could easily become very tight if China shows they are close to reversing their stance on lockdowns, but right now that doesn't seem to be happening anytime soon," Moya added. Meanwhile, Dubai crude swaps and intermonth spreads were lower in mid-morning trade in Asia April 26 from the previous close.
Oil Spikes on Reports Russia Halting Gas Supply to Poland -- Oil futures rallied more than 3% in afternoon trade Tuesday, with both crude benchmarks retracing Monday's losses on reports of Russia halting gas supplies to Poland in a sign of major escalation in the standoff over Ukraine after the German government indicated an embargo on Russian oil imports is feasible. Poland's main gas supplier, PGNiG, confirmed on Tuesday gas flows through Yamal pipeline with a daily capacity of 24.6 million cubic meters has been suspended, shuttering a vital artery for gas shipments into the European Union. European gas prices surged as much as 17% in late afternoon Tuesday as traders calculated the risk of other European countries being hit next. The threat of cutoff has loomed for weeks after Russian President Vladimir Putin demanded gas payments in Russia's national currency the ruble. Polish Prime Minister Mateusz Morawiecki furthered that his government received threats from Gazprom that unless Poland paid for Russian supplies in rubles, gas shipments would be stopped. Last year, PGNiG imported 9.9 billion cubic meters of Russian gas under long-term contracts, meeting around 63% of Poland's demand. Poland will be able to replace Russian gas imports with Norwegian gas once the Baltic Pipe natural gas pipeline with capacity of 10 bcm connecting Norwegian gas networks with Polish and Danish markets comes online in October. Interestingly, the cutoff comes hours after German Economy Minister Robert Habeck suggested Russia's oil embargo is now manageable for Germany, with Germany the largest importer of Russian oil and gas in the European Union. If realized, the development would mark a major reversal of Germany's position on imports of Russian energy imports. Limiting the upside for the oil complex are concerns over larger-than-expected economic slowdown in China due to prolonged and more widespread lockdowns which are causing a deeper slump in personal consumption and investments that are leading to heightened stagflationary risks for Asian region. At settlement, NYMEX West Texas Intermediate futures for June delivery advanced $3.16 to $101.70 bbl, and June Brent rallied $2.67 to $104.99 bbl. NYMEX RBOB May futures gained 9.9 cents to $3.3388 gallon ahead of expiration Friday (4/29) afternoon, with the prompt spread settling at 2.78cts backwardation. May ULSD contact rallied 37.70 cents to $4.4679 gallon -- a record high settlement on the spot continuous chart, spiking on a tight distillate market, with U.S. distillate stocks last measured at 108.735 million bbl, the lowest stock level since May 2008, while 20% below the five-year average. June ULSD futures settled at a 65.06 cents discount to the May contract, which expires Friday afternoon.
Oil prices dip as dollar soars -- Oil prices dipped on Wednesday as a soaring US dollar made barrels more expensive and coronavirus outbreaks in China clouded the economic outlook in the world’s biggest importer of crude oil. Supplies remained tight in the world’s largest oil producer, the US, as government data showed crude stockpiles rose modestly last week as fuel inventories declined. Brent crude futures fell by $1.08, or 1%, to $103.91 a barrel as of 1640 GMT. US WTI crude futures dropped $1.19 a barrel to $100.51. The dollar rose to its highest in five years, making oil purchases more expensive for holders of other currencies. “This (is) a risk-off environment with a stronger US dollar and mobility restrictions in the second largest oil consumer, China,” said UBS commodity analyst Giovanni Stauvono. The US Energy Information Administration said crude stocks rose by just 692,000 barrels last week, short of expectations, while distillate inventories, which include diesel and jet fuel, fell to their lowest since May 2008. Energy markets worldwide are dealing with massive disruptions to supply following Russia’s invasion of Ukraine and subsequent sanctions slapped on Moscow by the United States and its allies. UK major Shell said it would no longer accept refined oil blended with Russian products, according to trading documents, while Exxon Mobil said it had declared force majeure on its Sakhalin-1 operations in the far eastern part of Russia. This week, Moscow escalated its use of energy as a cudgel against countries opposed to the invasion. Russian energy giant Gazprom said on Wednesday it halted gas supplies to Bulgaria and Poland. European Commission chief said Russia was using fossil fuels to blackmail the EU but added the era of Russian fossil fuels in Europe was coming to an end. Germany, which has relied heavily on Russia energy, faces a hit to economic growth as it pushes ahead with attempts to become independent of Russian gas and oil imports. Germany’s economy minister said plans to take control of the PCK Schwedt refinery, majority-owned by Rosneft and the last big buyer of Russian crude in Germany, were progressing.
Oil Futures Mixed, ULSD Rallies on Tight Distillate Supply --- Oil futures nearest delivery on the New York Mercantile Exchange turned mixed in late morning trade Wednesday after an inventory report from the U.S. Energy Information Administration revealed commercial oil stocks for the week ended April 22 increased in line with consensus, while refiners unexpectedly reduced run rates and distillate stocks dropped by a larger-than-expected margin to the lowest level in 14 years, rallying front-month ULSD futures above $4.57 gallon. At 107.3 million barrels (bbl), U.S. distillate stocks now stand 21% below the five-year average, having dropped by 1.4 million bbl from the previous week. Market analysts expected distillate inventories to have declined by a more modest 100,000 bbl. The larger-than-expected drop came even as demand for middle of the barrel fuels stalled below 4 million barrels per day (bpd) for the fifth consecutive week. For gasoline, EIA data showed demand unexpectedly dropped 129,000 bpd last week to a four-week low 8.739 million bpd despite the seasonal pattern for a pickup in consumption. Stocks fell 1.6 million bbl to 230.8 million bbl, compared with analyst expectations for inventories to have fallen by 100,000 bbl. U.S. commercial crude oil inventories rose 691,000 bbl to 414.4 million bbl, and are now about 16% below the five-year average, EIA said. Analysts expected crude stockpiles to have risen 600,000 bbl from the prior week. Oil stored at the Cushing tank farm in Oklahoma -- the delivery point for NYMEX West Texas Intermediate futures -- increased 1.3 million bbl from the previous week to 27.5 million bbl. U.S. crude oil production remained unchanged from the previous week at 11.9 million bpd, according to EIA. Total products supplied over the last four-week period averaged 19.4 million bpd, down 1.6% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 8.7 million bpd, down 2.2% from the same period last year. Distillate fuel product supplied averaged 3.7 million bpd over the past four weeks, down 7.4% from the same period last year. Jet fuel product supplied to the U.S. market was up 23.9% compared with the same four-week period last year. Near 11:30 a.m. EDT, NYMEX June WTI futures dropped $0.87 to $100.78 bbl, and the international crude benchmark Brent contract declined $0.76 to $104.28 bbl. NYMEX May RBOB futures gained 4.41 cents to $3.3865 gallon, and front-month ULSD futures advanced 8.85 cents to $4.5564 gallon.
Oil Prices Edge up as Worldwide Supply Concerns Remain at the Fore (Reuters) -Oil prices rose modestly on Wednesday due to ongoing concerns about tight worldwide supply, underscored by another drawdown in U.S. distillate and gasoline inventories. The market rebounded late in the session after losing ground for most of the day, in part due to strength in the dollar and as China grapples with fresh coronavirus outbreaks that are sapping demand. However, Russia's move to cut off gas shipments to two European nations added to overall worries about tight energy supply. Brent crude futures settled up 33 cents to $105.32 a barrel, while U.S. West Texas Intermediate crude settled up 32 cents to $102.02 a barrel. The U.S. Energy Information Administration said crude stocks rose by just 692,000 barrels last week, short of expectations, while distillate inventories, which include diesel and jet fuel, fell to their lowest since May 2008. [EIA/S] The drop in distillate stocks helped boost U.S. heating oil futures to an all-time closing record at more than $4.67 a gallon. Refiners process crude into diesel, jet fuel and other products, and U.S. refiners have been running at high rates to meet demand, particularly in Europe, a big user of diesel fuel. Energy markets worldwide are dealing with massive disruptions to supply following Russia's invasion of Ukraine and subsequent sanctions slapped on Moscow by the United States and its allies. U.K. major Shell said it would no longer accept refined oil blended with Russian products, according to trading documents, while Exxon Mobil said it had declared force majeure on its Sakhalin-1 operations in the far eastern part of Russia. This week, Moscow escalated its use of energy as a cudgel against countries opposed to the invasion. Russian energy giant Gazprom said on Wednesday it halted gas supplies to Bulgaria and Poland. "Russia wants the payments in roubles for gas, and the fear is that before long they may want to do the same with oil," said Claudio Galimberti, senior vice president of analysis at Rystad. European Commission Chief Ursula von der Leyen said Russia was using fossil fuels to blackmail the EU but added the era of Russian fossil fuels in Europe was coming to an end.
Crude falls on China’s COVID-19 concerns as mass testing begins - Crude oil futures fell in mid-morning Asian trade on April 28 as news of China’s mass testing for COVID-19 weighed on sentiment, overshadowing supply-side concerns of a modest US inventory build and looming risk of further Russian energy sanctions. At 11:00 am Singapore time (0300 GMT), the ICE June Brent futures contract was down $1.63/b (1.55%) from the previous close at $103.69/b, while the NYMEX June light sweet crude contract fell $1.44/b (1.41%) at $100.58/b. On April 27, China reported 48 new symptomatic and 2 new asymptomatic COVID-19 cases in Beijing, state broadcaster CCTV reported April 28. Beijing rolled out a mass testing program with millions of people in Beijing taking their 2nd COVID-19 test of the week on April 27. In Hangzhou, similar measures were undertaken as state media reported that mass testing also began in the city with a population of 12.2 million. "Beijing is unlikely to adjust the current COVID policy anytime soon despite economic and social costs rising rapidly," Stephen Innes, managing partner at SPI Asset Management said in an April 28 note. "However, the CCP may fine tune its COVID approach gradually, but the roadmap and triggers for this change remain the top macro uncertainty for oil markets." On the supply side, a Russian oil embargo by the EU looks increasingly likely after Russian gas exporter Gazprom fully suspended gas deliveries to Bulgaria and Poland April 27 due to non-payment in rubles, coupled with Germany signaling it might be ready to support a gradual ban on Russian oil, according to market analysts. Germany would be able to deal with a complete embargo on Russian crude and oil product imports, its economy minister Robert Habeck said April 27, S&P Global Commodity Insights reported earlier. Habeck added that Europe's biggest economy has slashed its dependence on Russian crude to 12% of imports from 35% before the invasion of Ukraine, signaling that they might be ready to support a gradual ban on Russian oil.
Oil drops as China fuel demand falls on looming COVID-19 lockdown concerns -- Oil prices decreased on Thursday as declining fuel demand in China due to the spread of COVID-19 eased supply concerns. International benchmark Brent crude cost $103.27 per barrel at 0600 GMT for a 1.60% decrease after closing the previous session at $104.95 a barrel. American benchmark West Texas Intermediate (WTI) traded at $100.44 per barrel at the same time for a 1.55% fall after the previous session closed at $102.02 a barrel. The drop in oil prices was triggered by lockdowns in the world's largest importer, China, meaning less fuel demand while relieving pressure on global supply and demand. China continues to battle with COVID-19, risking further lockdowns in other major cities. Shanghai has been in quarantine since the beginning of March, but the possibility of the virus spreading to Beijing, a city with a population of more than 21 million, has been raised, along with the possibility of Shanghai-like closures. The Beijing Center for Epidemic Control and Prevention reported that one region where new cases were detected had been declared high risk, while seven regions had been designated medium risk. Additionally, data showing an increase in US commercial crude oil inventories by 700,000 barrels to 414.4 million barrels last week also contributed to lowering prices.
Oil Soars with Expectation of the EU Ban on Russian Crude | Rigzone - Oil closed at the highest level in nearly two weeks as prospects for a European Union ban on crude imports from Russia seemed more likely, with an extra jolt of support coming from a growing global diesel supply crunch. West Texas Intermediate crude settled 3.3% higher in New York after swinging between gains and losses earlier. Germany is prepared to stop buying Russian oil in a phased approach, clearing the way for a European Union ban on Russian imports. Fresh reports Thursday fueled a jump in prices. U.S. diesel futures extended its record rally as supplies tighten in the wake of restricted Russian exports. “The news that the EU is getting close to banning Russian energy imports gave the market a firmer tone but now heating oil is taking the lead, driving U.S. crude futures higher,” said Spencer Vosko, oil director with energy brokerage Liquidity Energy. The sharp gains in WTI futures shrank its discount to international benchmark Brent crude to the narrowest level since November. Germany’s Economy Minister Robert Habeck said this week that the country has already cut its reliance on Russian oil enough to make a full embargo “manageable,” potentially laying the groundwork for a continent-wide ban that would upend the global trade in petroleum. The U.S. and U.K. have already pledged to end imports from Russia. “With Germany open to it, the probability of a ban has increased further,” Giovanni Staunovo, a commodity analyst at UBS Group AG, said. “The question will be if also Hungary supports it or not to get it through as it needs to be unanimous.” Meanwhile, oil demand in China is weaker while prices for refined products elsewhere are surging. The gap between the first and second month of New York heating oil futures has also climbed to a record of nearly 85 cents a gallon ahead of the May contract’s expiry on Friday. WTI for June delivery rose $3.34 to settle at $105.36 a barrel in New York. Brent for June settlement gained $2.27 to $107.59. China’s top state-run oil processor said during an earnings call that the resurgence of Covid-19 was slowing fuel demand. Hangzhou is the latest Chinese city to start mass virus testing. Traders are also grappling with just how big the hit to Russian production will be as the country’s invasion of Ukraine continues. While crude supply is keenly focused on Russian flows, replacement barrels from the North Sea are set to dwindle in the coming months. Loadings of the grades that make up the dated Brent benchmark will fall to the lowest level since at least 2007 in June, while shipments from the Johan Sverdrup will hit a 21-month low amid a raft of planned maintenance.
Oil up for fourth day as supply fears outweigh COVID-19 lockdowns Oil prices rose for a fourth day on Friday as fears over Russian supply disruption outweighed the impact of COVID-19 lockdowns in China, the world’s biggest crude importer. Brent crude futures rose $1.99, or 1.9 per cent, to $109.58 a barrel by 1:04 p.m. EDT (1704 GMT), after gaining 2.1 per cent in the previous session. The front-month June contract expires on Friday. The more active July contract rose by $1.67 to $108.93. U.S. West Texas Intermediate crude rose $1.40, or 1.3 per cent, to $106.76 a barrel, after advancing by 3.3 per cent on Thursday. Brent and WTI are set to finish up for the week. For the month, Brent should finish up 1.5 per cent and WTI up 6.4 per cent. It would be their fifth straight monthly increases, and prices have been buoyed by the increased likelihood that Germany will join other European Union member states in an embargo on Russian oil. In fuel prices, U.S. heating oil futures, a proxy for diesel prices, climbed to $5.65 per gallon during the session, an all-time record. On Wednesday, Russia cut gas supplies to Bulgaria and Poland. “There are rising concerns about the conflict disrupting more supply,” said Phil Flynn, an analyst at Price Futures Group. “The market is getting prepared for the possibility that we’re going to see more supply cut off going into the weekend.” Russian oil production could fall by as much as 17 per cent this year, an economy ministry document seen by Reuters showed on Wednesday, as Western sanctions over Russia’s invasion of Ukraine hurt investments and exports. Sanctions have also made it harder for Russian ships to send oil to customers, prompting Exxon Mobil Corp to declare force majeure for its Sakhalin-1 operations and curtail output.
Oil Prices Reverse Late in Session as Heating Oil Contract Plunges - Oil prices fell on Friday, reversing in volatile trade, pulled downward by the U.S. heating oil contract that plummeted by more than 20% at one point on the day of its expiration. The front-month U.S. heating oil contract, which is a proxy for diesel prices, soared to a record high of $5.8595 a gallon before falling as low as $4.4067 a gallon. Diesel futures have climbed as investors worry about tight supplies globally following Russia's invasion of Ukraine. The heating oil contract expired on Friday, along with the global Brent benchmark and U.S. gasoline futures. Volumes in all three front-month contracts was low, creating outsized volatility in the market and leading to late-day sell-offs, analysts said. "The fireworks were all in the expiring diesel contract," said Andrew Lipow of Lipow Oil Associates in Houston. "Today's expiry is especially volatile and may not be reflective of actual tightness." The more-active second-month Brent crude futures contract fell 12 cents to settle at $107.14 a barrel. The expiring front-month contract rose $1.75 to settle at $109.34 a barrel. U.S. West Texas Intermediate crude, which does not expire on Friday, fell 67 cents to settle at $104.69 a barrel, as traders sold energy contracts across the board. The front-month heating oil contract's volatility was not mirrored in the more-active second-month U.S. heating oil contract, which gained $0.0088 a gallon to settle at $4.0172 a gallon. Both Brent and WTI rose for the week and posted their fifth straight monthly gain. Brent ended the month up 1.3%, while WTI ended up 4.4%. Prices have been buoyed by fears that Russian supply will continue to be disrupted by the conflict in Ukraine. Futures rose this week on the increased likelihood that Germany will join other European Union member states in an embargo on Russian oil. Russian oil production could fall by as much as 17% this year, an economy ministry document seen by Reuters showed on Wednesday, as Western sanctions over Russia's invasion of Ukraine hurt investments and exports.
Oil prices snap 3-day winning streak but book April rise - Oil futures snapped a three-day winning streak Friday, but booked weekly and monthly gains as supply worries tied to Russia's invasion of Ukraine outweighed concerns over a hit to demand from China's COVID lockdowns.Meanwhile, May heating oil futures expired at a record, with tight distillate stocks also sending cash prices for all-important diesel fuel soaring.West Texas Intermediate crude for June delivery fell 67 cents, or 0.6%, to close at $104.69 a barrel on the New York Mercantile Exchange, with the U.S. benchmark logging at 2.6% weekly rise and a 4.4% April gain, based on the most actively traded contract.June Brent crude, the global benchmark, rose $1.75, or 1.6%, to close at $109.34 a barrel on ICE Futures Europe. July Brent, the most actively traded contract, fell 12 cents, or 0.1%, to $107.14 a barrel.Meanwhile, diesel prices have surged amid tight supplies of distillates on both sides of the Atlantic, Fritsch noted. The U.S. Energy Information Administration on Wednesday reported that distillate inventories dropped by 1.4 million barrels last week, versus forecasts for a decline of just 100,000 barrels.
Oil Achieves Fifth Straight Months Of Gains As Supply Fears Trump Demand Concerns - Despite oil trading's extreme volatility of late and mixed results for the session overall, the commodity on Friday achieved a fifth straight month of gains – the longest streak since early 2018 – with demand concerns viewed as fleeting but supply worries persistent. West Texas Intermediate settled down 67 cents at $104.69 per barrel, while Brent for June settlement, which expired Friday, settled up $1.75 to $109.34 (the more active July contract settled down 12 cents to $107.14). The late-session sell-offs were attributed to low volumes in the front-month contracts of U.S. heating oil (a proxy for diesel prices), Brent, and U.S. gasoline futures, according to analysts: "The fireworks were all in the expiring diesel contract; today's expiry is especially volatile and may not be reflective of actual tightness." Oil prices for the past few weeks have been influenced by China's Covid lockdowns and the European Union coming closer to enacting an embargo on oil from Russia for its invasion of Ukraine. "Next week will be critical as we will get official selling prices from Saudi as a good litmus test for how much demand is suffering in China." But tight global supplies remain the dominant concern for many analysts, especially as there seems to be no end in sight of the Russian/Ukraine war; and on Friday Chevron Corp, despite equipment shortages, announced that it had lifted its production target in the Permian Basin in Texas by 15 percent this year (to the equivalent of about 725,000 barrels per day). The expansion follows similar moves by Continental Resources, Hess Corp., and Matador Resources amid sky-high crude and gasoline prices, and Chevron CFO Pierre Breber told media his company is now "back on the trajectory that we were on pre-Covid" in the biggest U.S. shale basin. Overseas, U.K. prime minister Boris Johnson will meet with key oil and gas producers in a bid to spur new field developments in the North Sea, whose new projects up until recently were dwindling in the face of pressure to tackle climate change. The roundtable discussion was originally scheduled for May 4 but will now take place in the coming weeks, according to insiders. In other oil-related news on Friday, Exxon Mobil's first quarter profits were revealed to be $5.5 billion, up from $2.7 billion in the same period last year and despite the company taking a $3.4 billion after-tax charge related to its Sakhalin-1 operation in Russia. CEO Darren Woods said in a statement, "Earnings increased modestly, as strong margin improvement and underlying growth was offset by weather and timing impacts."
Russia reported a large fire at an oil depot in the same area that its officials claimed was earlier attacked by Ukrainian helicopters - A large fire has erupted at a Russian oil depot in Bryansk, a city near the Ukrainian border, authorities said Monday, according to multiple media reports.The incident has so far not been linked to the war in Ukraine, but the depot is located in the same area that Russia accused Ukraine of attacking last week, Reuters reported.On April 14, Russian officials said Ukrainian helicopters had struck residential buildings and injured seven in the region, according toReuters. Ukrainian officials called the accusation "a plan to carry out terrorist acts to whip up anti-Ukrainian hysteria," per the outlet.According to the Russian emergencies ministry, the fire took place at 2 a.m. Moscow time in a facility owned by Russian oil pipeline giant Transneft, per Reuters.Footage of what appears to be part of the oil depot engulfed in flames has been shared on Telegram, The Moscow Times first reported.Russia's emergencies ministry told state news agency TASS that there have not been any casualties due to the fire, citing preliminary information.There are also no plans to evacuate the city of 400,000 people, and kindergartens and schools will continue with classes as planned, Bryansk city authorities said, per TASS. Citing Russian television, The Moscow Times reported that the fire affected two facilities — a civilian site holding 10,000 tons of fuel and a military storage facility holding 5,000 tons.