natural gas price hits 164 month high after doubling in 2 months; SPR at a 1058 week low, total US oil supplies at a 746 week low; distillates supplies at a 729 week low, total oil + products inventories at a 711 week low, gasoline imports at a 8 month high; natural gas rigs at a 31 month high..
oil prices rose for the third time in four weeks after the EU advanced a plan to phase out imports of Russian oil...after rising 2.6% to $104.69 a barrel last week as fears of lower supplies from Russia outweighed concerns about reduced demand from China, the contract price for US light sweet crude for June delivery opened lower and tumbled more than 3% early Monday on forecasts of weak economic growth in China following restrictive lockdowns of millions in Shanghai, and as the U.S. dollar rallied ahead of this week's Fed meeting, when a half point interest rate hike was expected, but bounced off the $100 a barrel level to rally late and finish trading 48 cents higher at $105.17 a barrel, triggered by reports that OPEC was only able to raise their output a little over 40,000 bpd, with their production shortfall growing to 200,000 bpd last month....but oil prices slipped out of the gate again on Tuesday, as demand worries stemming from China's prolonged COVID-19 lockdowns outweighed the prospect of a European embargo on Russian crude, and their losses accelerated in afternoon trading as traders positioned ahead of the weekly release of U.S. inventory data, and the likelihood for the biggest Fed rate hike since at least 2000, and settled $2.76 lower at $102.41 a barrel...however, oil prices jumped 3% in Asian trading on Wednesday after the American Petroleum Institute reported a larger-than-anticipated draw from US oil supplies and after the EU spelled out plans to phase out their imports of Russian oil, and then accelerated higher in afternoon trading, sending both major crude benchmarks 5% higher, after the Fed raised interest rates half a percent and the EIA reported a much larger-than-expected drop in domestic fuel stocks due to higher demand for gasoline and diesel, as front month oil prices settled $5.40 higher at $107.81 a barrel...oil continued higher in early trade Thursday, after the OPEC and Russian-led cartel agreed on a small, incremental production increase in June, sticking to their earlier plan, despite the European Union's decision to embargo Russian oil, and then jumped 3% to over $111, after CNN leaked news of the administration's “long-term buyback plan” to partially refill the SPR, before paring its gains amid a 5% stock market selloff, as traders reassessed the risk that the Fed's aggressive interest rate hikes would tilt the U.S. economy into a recession, with oil closing just 45 cents higher at $108.26 a barrel... oil climbed for the third straight session during mid-morning Asian trade on Friday, erasing earlier losses, as concerns lingered over the prospect of tighter supplies after the EU’s embargo on Russian oil, and closed the week at a six week high of $109.77 a barrel, $1.51 higher on the day, as impending sanctions on Russian oil raised the prospect of tighter supply and had traders shrugging off worries about global economic growth...oil prices thus ended 4.9% higher on the week, with energy traders completely fixated on the looming European sanctions on Russian oil, and none willing to be on the wrong side of a major crude supply disruption...
Meanwhile, natural gas prices rose for the seventh time in eight weeks and traded at their highest price levels since 2008 all week, as cold weather turned hot, leading to early demand for cooling....after rising 8.7% to $7.244 per mmBTU last week after Russia began to cut off gas supplies to European countries for nonpayment, the contract price of natural gas for June delivery opened 2% higher on Monday as domestic supply remained constrained by sluggish production and an enduring inventory deficit, and closed 23.1 cents higher at $7.475 per mmBTU, on forecasts of warmer-than-usual weather for the next two weeks, which would increase cooling demand and keep storage injections lower than normal during the season for the greatest inventory builds...natural gas prices then surged 9% to their highest level since 2008 on Tuesday, as fallout from the Ukraine war wreaked havoc on global energy markets, but backed off the $8 level to end 47.9 cents higher at $7.954 per mmBTU....but natural gas prices shot right past $8 early Wednesday, as inventory concerns mounted ahead of a summer that promised high demand, and settled 46.1 cents higher at $8.415 per mmBTU, with underwhelming gas production, tight U.S. supplies, and forecasts for hot conditions across Texas and surrounding states into early next week seen as the primary drivers of spiking natural gas prices...natural gas prices rallied to their 3rd consecutive 13 year high on Thursday, and approached the $9 level, before settling with a 36.8 cent increase at $8.783 per mmBTU, as hot spring weather boosted air conditioning demand, while much higher global prices kept demand for LNG exports strong....however, after pushing to a hair below $9 at $8.996 early on Friday, natural gas prices tumbled 74.0 cents or more than 8% to $8.043 per mmBTU, as traders took profits on forecasts for a rise in output, milder weather and a drop in demand for the next two weeks....natural gas prices still ended 11% higher on the week, and remained at a level more than double that at the beginning of this year, which is fairly evident in the daily price graph we have included below...
the above is a screenshot of the interactive natural gas price chart from barchart.com, which i have reset to show daily natural gas prices over the past 6 months...this same chart can be reset to show prices of front month or individual monthly natural gas futures contracts over time periods ranging from 1 day to 30 years, as the menu bar on the top indicates, and also to show natural gas prices by the minute, hour, day, week or month for each...each bar in the graph above represents the range of natural gas prices for a single day, with days when prices rose indicated in green, and days when prices fell indicated in red, with the small sticks above or below each daily bar representing the extent of the price change above or below the opening and closing price for the day in question....likewise, the bars across the bottom show trading volume for the days in question, again with up days indicated by green bars and down days indicated in red...you'll note that by positioning our cursor over December 31st, indicated by a thin vertical line, we have caused that day's natural gas prices to be displayed in green in the upper left corner of the graph...there we can see that natural gas prices closed at $3.579/mmBTU on that date, clearly less than half of any price seen this week...in fact, we can also see that natural gas traded below $4 on February 11th, so gas prices have more than doubled in less than two months..
The EIA's natural gas storage report for the week ending April 29th indicated that the amount of working natural gas held in underground storage in the US rose by 77 billion cubic feet to 1,567 billion cubic feet by the end of the week, which still left our gas supplies 382 billion cubic feet, or 19.6% below the 1,949 billion cubic feet that were in storage on April 29th of last year, and 306 billion cubic feet, or 16.3% below the five-year average of 1,873 billion cubic feet of natural gas that have been in storage as of the 29th of April over the most recent five years....the 77 billion cubic foot injection into US natural gas working storage for the cited week was 16 billion cubic feet more than the average forecast for a 61 billion cubic foot injection from an S&P Global Platts survey of analysts, but it was close to the average injection of 78 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, while it was well more than the 54 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 29th indicated that because of an increase in our oil inports, a decrease in our oil exports, a withdrawal from the SPR, and a slowdown in our refining, we again had oil left to add to our stored commercial crude supplies, for the 9th time in 23 weeks and for the 18th time in the past forty-eight weeks, even after a big decrease in oil that could not be accounted for…our imports of crude oil rose by an average of 397,000 barrels per day to an average of 6,332,000 barrels per day, after rising by an average of 98,000 barrels per day during the prior week, while our exports of crude oil fell by 147,000 barrels per day to 3,574,000 barrels per day during the week, which together meant that our trade in oil worked out to a net import average of 2,758,000 barrels of oil per day during the week ending April 29th, 544,000 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 14,658,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,466,000 barrels of crude per day during the week ending April 29th, an average of 218,000 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 255,000 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 553,000 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 (+553,000) 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 unaccounted for oil was at (+1,254,000) barrels per day, that means there was a 701,000 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 meaningless....however, since most everyone treats these weekly EIA reports as gospel, and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
This week's 255,000 barrel per day decrease in our overall crude oil inventories left our total oil supplies at 965,712,000 barrels at the end of the week, our lowest total oil inventory level since January 4th, 2008, and thus a 14 year low….this week's oil inventory decrease came even though 186,000 barrels per day were being added to our commercially available stocks of crude oil, because 441,000 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 106,162,000 barrels of oil have now been removed from the Strategic Petroleum Reserve over the past 21 months, and as a result the 549,985,000 barrels of oil still remaining in our Strategic Petroleum Reserve is now the lowest since December 28th, 2001, 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 this week 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 and leave us with what would be about a 20 day supply of oil at today's consumption rate...
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,025,000 barrels per day last week, which was 3.3% more than the 5,831,000 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 even though the EIA's rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 11,400,000 barrels per day, because Alaska’s oil production rose by 6,000 barrels per day to 453,000 barrels per day and added 100,000 barrels per day back to the final rounded national total (that's the EIA's math, not mine)....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 88.4% of their capacity while using those 15,466,000 barrels of crude per day during the week ending April 29th, down from the 90.3% utilization rate of the prior week, and below the historical utilization rate for late April refinery operations…the 15,466,000 barrels per day of oil that were refined this week were 1.5% more barrels than the 15,243,000 barrels of crude that were being processed daily during week ending April 30th of 2021, when refineries were still recovering from winter storm Uri, and 19.2% more than the 12,976,000 barrels of crude that were being processed daily during the week ending May 1st, 2020, when US refineries were operating at what was then a much lower than normal 70.5% of capacity during the first wave of the pandemic, but still 6.0% 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...
Even with the decrease in the amount of oil being refined this week, gasoline output from our refineries was somewhat higher, increasing by 175,000 barrels per day to 9,689,000 barrels per day during the week ending April 29th, after our gasoline output had decreased by 322,000 barrels per day over the prior week.…this week’s gasoline production was 5.9% more than the 9,146,000 barrels of gasoline that were being produced daily over the same week of last year, but 2.4% below the gasoline production of 9,927,000 barrels per day during the week ending April 26th, 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 63,000 barrels per day to 4,719,000 barrels per day, after our distillates output had decreased by 34,000 barrels per day over the prior week…even after those decreases, our distillates output was 4.9% more than the 4,498,000 barrels of distillates that were being produced daily during the week ending April 30th of 2021, but 8.0% less that the 5,128,000 barrels of distillates that were being produced daily during the week ending April 26th, 2019...
Even with the increase in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the twelfth time in thirteen weeks, decreasing by 2,230,000 barrels to 228,575,000 barrels during the week ending April 29th, after our gasoline inventories had decreased by 1,573,000 barrels over the prior week....our gasoline supplies decreased again this week because the amount of gasoline supplied to US users increased by 117,000 barrels per day to 8,856,000 barrels per day, and even though our imports of gasoline rose by 282,000 barrels per day to an eight month high of 1,127,000 barrels per day while our exports of gasoline fell by 122,000 barrels per day to 836,000 barrels per day....but even with 12 inventory drawdowns over the past 13 weeks, our gasoline supplies were still only 3.1% lower than last April 30th's gasoline inventories of 235,811,000 barrels, and 4% below the five year average of our gasoline supplies for this time of the year…
with this week's decrease in our distillates production, our supplies of distillate fuels decreased for the 13h time in sixteen weeks and for the 25th time in thirty-five weeks, falling by 2,344,000 barrels to a fourteen year low of 104,942,000 barrels during the week ending April 29th, after our distillates supplies had decreased by 1,449,000 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 122,000 barrels per day to 3,956,000 barrels per day, while our exports of distillates fell by 92,000 barrels per day to 1,189,000 barrels per day, and while our imports of distillates fell by 34,000 barrels per day to 91,000 barrels per day.....after forty inventory decreases over the past fifty-six weeks, our distillate supplies at the end of the week were 22.9% below the 136,153,000 barrels of distillates that we had in storage on April 30th of 2021, and about 22% 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 have been $1 per gallon more than the already elevated price of gasoline, and both gasoline and diesel hit new record highs on NYMEX this week...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...because price of diesel for immediate delivery versus the next month widened to the largest ever gap this week, Gulf refiners have found it more profitable to sell immediately to Europe than wait weeks for pipeline delivery to the US east coast, with those exports to Europe exacerbating domestic shortages....although those diesel shortages had developed over time, the loss of Russian oil has compounded the problem, 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 increase in our oil imports, the withdrawal from the SPR, and the decrease in our oil refining, our commercial supplies of crude oil in storage rose for the 16th time in 40 weeks and for the 20th time in the past year, increasing by 1,303,000 barrels over the week, from 414,424,000 barrels on April 22nd to 415,727,000 barrels on April 29th, after our commercial crude supplies had increased by 691,000,000 barrels over the prior week…with this week’s increase, our commercial crude oil inventories rose to about 15% 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 US Gulf Coast refining, our commercial crude oil supplies as of this April 22nd were 14.3% less than the 485,117,000 barrels of oil we had in commercial storage on April 30th of 2021, and were also 21.9% less than the 532,221,000 barrels of oil that we had in storage on May 1st of 2020, and 11.7% 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 479,000 barrels this week, from 1,696,899,000 barrels on April 22nd to 1,696,420,000 barrels on April 29th, after our total inventories had fallen by 2,187,000 barrels barrels during the prior week, and left our liquids inventories down by 92,013,000 barrels over the first 17 weeks of this year....at 1,696,420,000 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 72nd time over the prior 84 weeks during the period ending May 6th, but it still remained 11.1% below the prepandemic rig count.....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by seven to 705 rigs this past week, which was also 257 more rigs than 448 rigs that were in use as of the May 7th report of 2021, but was still 1,224 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 5 to 557 oil rigs during this week, after rigs targeting oil had increased by 3 during the prior week, and there are now 213 more oil rigs active now than were running a year ago, even as they still amount to just 34.5% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014, and as they are still down 18.4% from the prepandemic oil rig count….at the same time, the number of drilling rigs targeting natural gas bearing formations rose by 2 to 146 natural gas rigs, which was the most natural gas rigs deployed since September 27th, 2019, up by 43 natural gas rigs from the 103 natural gas rigs that were drilling during the same week a year ago, even as they were still only 9.1% 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; a year ago, there was only one such "miscellaneous" rig running...
The offshore rig count in the Gulf of Mexico increased by three to sixteen this week, with all of this week's Gulf rigs drilling for oil in Louisiana waters....that's three more than the count 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 offshore rigs other than those deployed in the Gulf of Mexico....however, last year did have an inland water based rig active, while this year there are no "inland waters" rigs remaining...
The count of active horizontal drilling rigs was up by 3 to 646 horizontal rigs this week, which was also 238 more rigs than the 408 horizontal rigs that were in use in the US on May 7th of last year, but still 53.0% less than the record 1,374 horizontal rigs that were drilling on November 21st of 2014....at the same time, the directional rig count was up by 4 to 34 directional rigs this week, and was up by 11 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 8 from the 17 vertical rigs that were in use on May 7th 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 May 6th, the second column shows the change in the number of working rigs between last week’s count (April 29th) and this week’s (May 6th) count, the third column shows last week’s April 29th 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 7th of May, 2021...
there doesn't appear to have been much activity in the major oil basins this week; the four rigs added in Louisiana included the three oil rigs added in the Gulf of Mexico and a natural gas rig targeting the Haynesville shale in the northwestern quadrant of the state, while two more natural gas rigs were added in Pennsylvania's Marcellus, which were offset by the removal of a natural gas rig from a basin that Baker Hughes doesn't track...in Oklahoma, an oil rig was added in the Granite Wash near the Texas panhandle, and another oil rig was added in the Mississippian shale near Kansas, while an oil rig was pulled out of the Cana Woodford shale, which means that the 2 rig increase indicated for Oklahoma includes an oil rig added in a basin that Baker Hughes doesn't track...
meanwhile, to account for the changes in Texas and New Mexico, we need to check the Rigs by State file at Baker Hughes for the changes in the Texas Permian, where we find that a rig was pulled out of Texas Oil District 8A, which includes the counties in the northern Permian Midland, while the rig counts in other Texas Permian districts were unchanged...based on that, it appears that the rig that was added in New Mexico was in the western Permian Delaware, thus leaving the national Permian rig count unchanged...elsewhere in Texas, we find that a rig was added in Texas Oil District 4, but that a rig was pulled out of Texas Oil District 6, but since neither the Haynesville or the Eagle Ford counts reflect those changes, we have to assume both of those rig also involved basins that Baker Hughes doesn't track...
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Up close look: Buckeye students tour working drilling rig - — About 20 students in Buckeye Career Center's energy operations program got a hands-on, up close look at the oil industry last week as they toured a working drilling pad in Carroll County.The students, wearing hard hats and safety glasses and clad in fire-resistant coveralls, toured on Thursday Encino Energy's Leeper pad, located close to the Tuscarawas-Carroll County line near Sherrodsville. The pad has been in operation for the past several months and will have four wells on it when drilling is completed in mid-May.State Sen. Jay Hottinger, R-Newark, and Commissioner Al Landis, also came along to see the well pad.One of the students on the tour, Brysen Thompson, a junior from Carrollton, said he plans on seeking employment in the oil and gas industry once he graduates."There's so many opportunities in Ohio. You wouldn't have to travel far from family. It's a very big opportunity," he said. His biggest takeaway from the tour?"It's crazy to see how far people come to Ohio to work for these opportunities and how much money you can make, and how well organized everything was," Thompson said. "Everything was set up to help prevent big spills, to protect our nature and things like that."The level of professionalism at the well site "was very cool as well," he said. The energy operations program at Buckeye has 27 juniors and 27 seniors currently enrolled. The students learn a variety of skills to prepare them for employment in the oil and gas industry. Those skills include operating and maintaining heavy equipment, determining survey elevations for gas and oil pipeline construction and earning safety credentials necessary for employment in the industry.
Union County court rejects pipeline eminent domain - — A Union County judge has rejected Columbia Gas of Ohio’s request to approve eminent domain to install a pipeline through preserved farmland. The ruling did leave the door open for eminent domain action in the future, however, noting that ag easements don’t prevent it. The court ruling, issued April 26 by the Union County Court of Common Pleas, combines two cases: Columbia Gas of Ohio vs. Patrick Bailey et al., and Columbia Gas of Ohio vs. Don Bailey Jr., successor trustee of the Arno Renner Trust. Columbia Gas filed the petitions asking the court to allow the company to use eminent domain to obtain easements for its pipeline. Judge Mark S. O’Connor dismissed the petitions and encouraged further mediation. The decision to dismiss the petitions was not based on the fact that ag easements are already in place on the land. Instead, O’Connor pointed to an inconsistency between the easement language approved by the Ohio Power Siting Board and what was presented to the court. He disagreed with the argument that the existing ag easement should protect the land from eminent domain. In his ruling, he explained, “This is contrary to the terms of that easement and contrary to the State’s historic right to exercise the right of eminent domain.” The judge criticized both Columbia Gas and the Ohio Power Siting Board for their handling of the project. In his ruling, he noted, “Given the particular fact of this case where the 25-foot easement was labeled ‘temporary’ before the Siting Board and transformed itself into ‘perpetual’ before this Court, this Court is of the opinion that the Siting Board did not do its job. This Court finds it was ‘bad faith’ to represent one thing to the Siting Board and then ask this Court to approve something greater.” The Ohio Power Siting Board approved the pipeline project in August of 2020, and construction was originally scheduled to start in February of 2021. Columbia Gas won’t be able to start construction, however, until it holds easements for the entire route. Several other landowners, who do not have agricultural easements, are also fighting eminent domain action for the pipeline. The court previously ruled in favor of those landowners in two other cases, and Columbia Gas has appealed those rulings to the Ohio Third District Court of Appeals.
Court of Appeals Rules That Oil and Gas Company Has Ongoing Obligation to Restore Property Despite General Release of Damages in Surface Use Agreement -- On April 11, 2022, the Fourth District Court of Appeals issued a significant decision in Zimmerview Dairy Farms, LLC v. Protégé Energy III LLC establishing that a general release of damages signed in connection with a pad site surface use agreement did not release the oil and gas company from its ongoing obligations to remediate and restore damage to a landowner’s property.In the Zimmerview case, Plaintiff Zimmerview Dairy Farms (“ZDF”) signed a surface use agreement with Defendant Protégé Energy III LLC (“Protégé”) permitting Protégé to construct and operate a pad-site for Utica Shale wells on a portion of the ZDF farm. The agreement consisted of three documents: a recorded surface use agreement (favorable to Protégé); a confidential supplemental agreement (with terms favorable to ZDF); and a damage release under which ZDF released Protégé from the anticipated damages already paid for by Protégé. This three-document structure is typical, especially for pipelines easements, and one which many oil and gas companies insist on. Often, the damage release is explained by landmen as an unimportant formality and that the company is still going to fix the land as required under the unrecorded agreement. However, what a landman says, what an agreement says and what a company does can differ dramatically.In Zimmerview, Protégé proceeded to construct and operate its pad-site without adequately remediating, restoring and reseeding the areas disturbed during construction, including the slopes of the pad-site. Over several years, Protégé’s failure to remediate resulted in significant topsoil damage, invasive weed infestations and ongoing erosion, which rendered large portions of the ZDF farm unusable. Protégé refused to pay or fix the ZDF farm, claiming that the damage release signed by ZDF released Protégé from any obligation to remediate or pay for damages caused to the ZDF farm. When ZDF filed suit and won at trial, Protégé appealed. On appeal, Protégé once again argued that ZDF had released Protégé from all damages resulting from construction and operation of the pad-site including damages from not remediating the ZDF farm. Despite the broad language of the release, however, the Court of Appeals rejected Protégé’s argument on the basis that the damage release, signed when the surface use agreement was executed, could not have been intended to release Protégé from damages that resulted from the ongoing obligations and requirements Protégé had just agreed to under the surface use agreement. Accordingly, the Fourth District affirmed the trial court judgment (and $800,000 verdict for damages) against Protégé. Given the common use (and abuse) of similar damage releases by both operators and pipeline companies, this decision is a welcome addition to Ohio caselaw and should assist (and hopefully encourage) Ohio landowners to insist on producers and pipeline companies meeting their construction and remediation obligations.[View source.]
To arbitrate or not? – Ohio Ag Net -Ascent Resources-Utica, L.L.C. (“Defendant”) acquired leases to the oil and gas rights of farmland located in Jefferson County, Ohio allowing it to physically occupy the land which included the right to explore the land for oil and gas, construct wells, erect telephone lines, powerlines, and pipelines, and to build roads. The leases also had a primary and secondary term language that specified that the leases would terminate after five years unless a well is producing oil or gas or unless Defendant had commenced drilling operations within 90 days of the expiration of the five-year term. After five years had passed, the owners of the farmland in Jefferson County (“Plaintiffs”) filed a lawsuit for declaratory judgment asking the Jefferson County Court of Common Pleas to find that the oil and gas leases had expired because of Defendant’s failure to produce oil or gas or to commence drilling within 90 days. Defendant counterclaimed that the leases had not expired because it had obtained permits to drill wells on the land and had begun constructing those wells before the expiration of the leases. Defendant also moved to stay the lawsuit, asserting that arbitration was the proper mechanism to determine whether the leases had expired, not a court. After considering the above provisions of the Ohio Revised Code, the Jefferson County Court of Common Pleas denied Defendant’s request to stay the proceedings pending arbitration. The Common Pleas Court concluded that Plaintiffs’ claims involved the title to or possession of land and therefore was exempt from arbitration under Ohio law. However, the Seventh District Court of Appeals disagreed with the Jefferson County court. The Seventh District reasoned that the controversy was not about title to land or possession of land, rather it was about the termination of a lease, and therefore should be subject to the arbitration provisions within the leases. The case eventually made its way to the Ohio Supreme Court, which was tasked with answering one single question: is an action seeking to determine that an oil and gas lease has expired by its own terms the type of controversy “involving the title to or the possession of real estate” so that the action is exempt from arbitration under Ohio Revised Code § 2711.01(B)(1)? The Ohio Supreme Court determined that yes, under Ohio law, an action seeking to determine whether an oil and gas lease has expired by its own terms is not subject to arbitration. The Ohio Supreme Court reasoned that an oil and gas lease grants the lessee a property interest in the land and constitutes a title transaction because it affects title to real estate. Additionally, the Ohio Supreme Court found that an oil and gas lease affects the possession of land because a lessee has a vested right to the possession of the land to the extent reasonably necessary to carry out the terms of the lease. Lastly, the Ohio Supreme Court provided that if the conditions of the primary term or secondary term of an oil and gas lease are not met, then the lease terminates, and the property interest created by the oil and gas lease reverts back to the owner/lessor.
The race is on (again) to build out a low-carbon hydrogen economy --At an industrial site on the banks of the Ohio River, Vance Powers pointed to a brand new building – a big blue box with pipes coming in and out of it. Inside the building is a 485-megawatt electric generator owned by Long Ridge Energy Generation. Since opening two years ago, Long Ridge has run the plant on natural gas from the nearby Marcellus and Utica shale region. But a few weeks ago, it began an experiment that its owners hope is the start of new, cleaner way to power the economy – on hydrogen. In March, the plant, in Hannibal, Ohio, started feeding its combustion turbine with a small percentage of hydrogen, trucked in from a nearby chemical plant. Powers says the company plans to use more hydrogen, but has been using small amounts of it as a test. “Will the turbine burn it? We’ve just proved, yes, it will,” he said. “The next step is how do you get it in industrial-scale size and at an economical level?” That is the ultimate question with hydrogen, the most common element in the universe. It’s been the subject of attention from scientists and policy makers for decades, because of its potential to replace fossil fuels. That’s because when it’s used to power a car or fuel a power plant, hydrogen creates no carbon dioxide – its chief byproduct is water. But getting a clean, cheap source of it has been hard to do. That might be changing. Thanks to a combination of government support and pressure from investors, companies are trying to revive the dream of a hydrogen economy. Eventually, the company wants to run the plant completely on hydrogen. Right now, Long Ridge gets a few truckloads of hydrogen a month in big, white tubes from a nearby chemical plant. But it would need much more to run completely on hydrogen. Most industrial hydrogen is made from natural gas, in a process called “steam methane reforming.” This method – known as “grey hydrogen,” creates CO2. Long Ridge says it wants to capture that CO2 and store it underground, a method known as “blue” hydrogen. Around the country, others are beating a path to hydrogen, which the federal government has been trying to support since the George W. Bush administration. President Biden’s bipartisan infrastructure bill included $8 billion to create four “hydrogen hubs” around the country – where facilities create, store, and use hydrogen in industrial settings. A consortium of companies is hoping to land one in the Pennsylvania, West Virginia and southeast Ohio region. That has Bo Wholey, Long Ridge’s CEO, excited. “This location here…is perfect for at least one of those hydrogen hubs,” he said. “That’s certainly something that we’re going to be evaluating, as we think about how to make running on hydrogen more economical.”
VOICES: We need more pipelines - Dayton Daily News - One of the roadblocks in the world’s attempts to punish Russia for their invasion of Ukraine has been the reliance of western countries like Germany and Italy on Russian natural gas and oil. These countries rely on the Kremlin to keep their homes warm in the winter and the lights on throughout the year. Europe cannot risk losing access to this essential energy source no matter how egregious Russia’s actions have been. Thanks to the shale revolution in Ohio, America has become a world leader in the production of these essential energy sources. U.S. Energy Information Administration data indicates that in 2019, prior to the COVID-19 pandemic, Ohio was producing more than 2.65 trillion cubic ft of natural gas a year and about 29 million barrels of oil.At those rates, Ohio could heat 26.5 million homes during the winter and produce 551 million gallons of gasoline. Amazingly, that’s only a fraction of what Ohio’s natural gas and oil industry is capable of producing.What’s the holdup then? Why are gas prices rising and why is America not providing more natural gas and oil to Europe?The answer comes down to energy infrastructure. Producing more natural gas and oil is not helpful if it cannot get to where there is need. The pipelines required to transport these products throughout the country and the natural gas liquefaction plants required to ship it across the Atlantic are already operating at or near capacity. This means producers who want to bring more natural gas and oil to consumers are physically unable to.The need for more pipelines is clear, and yet anti-energy activists continue to fight against them. Efforts to shutdown Line 5 in Michigan and the Mountain Valley Pipeline are misguided at best and dangerous at worst. The reality is that pipelines not only ensure reliable access to essential energy, they reduce carbon emissions and are demonstrated to be the most environmentally efficient solution to deliver natural gas and oil to the market. The Secretary of the U.S. Department of Energy, Jennifer Granholm, has even publicly stated that pipelines are the best way to distribute the essential energy we need.Ohio made natural gas and oil can provide safe, reliable, and clean energy to the world and help reduce the cost of energy for all of us. For that to happen, we must build more pipelines and natural gas liquefaction plants. Doing so will ensure aggressors like Russia no longer hold power over western society, and energy prices here at home remain steady and affordable in the long term.
Conventional oil and gas industry sues to be excluded from Pa. methane rule - Three trade groups for Pennsylvania’s conventional oil and gas industry are suing state environmental regulators to block a forthcoming rule for controlling methane and other air pollution from applying to their well sites.The state Department of Environmental Protection created a single rule that applies to conventional and unconventional wells sites “in blatant disregard” of a 2016 state law that requires conventional wells to be regulated independently from those tapping the Marcellus and Utica shales, the industry groups argue.DEP rejected that argument when it crafted the rule, which largely mirrors federal standards the state must enforce by mid-June or face sanctions, including the loss of federal highway funds. But DEP withdrew the rule from consideration by the state’s Independent Regulatory Review Commission at its upcoming meeting on May 19 in a letter received by the commission Thursday morning.DEP said the rule “will be resubmitted at a later time.”The Commonwealth Court has scheduled a May 10 hearing on the conventional drilling groups’ request to stop the rule from taking effect on them while the court considers the case.The state Environmental Quality Board voted to adopt the final rule in March, two years after DEP released a draft and more than five years after federal regulators released the guidelines that form the backbone of the rule.It must still be reviewed by the state Independent Regulatory Review Commission and the attorney general’s office before it can be published. The Legislature can also seek to delay or block it.DEP estimates the rule will curb emissions of a smog-forming group of chemicals called volatile organic compounds by 12,000 tons per year and emissions of methane, a powerful climate-warming gas, by about 221,000 tons per year as a side benefit.Regulators expect upward of 75% of the rule’s total emissions reductions to come from the conventional industry, largely because, by DEP’s count, there are eight times as many conventional well sites as shale well sites and most of them will have to replace equipment that intentionally vents gas with less leaky parts.The Pennsylvania Independent Oil & Gas Association, the Pennsylvania Grade Crude Oil Coalition, and the Pennsylvania Independent Petroleum Producers Association are asking the court to prohibit the state from publishing the rule “unless and until the scope of the rule is clarified to apply only to unconventional wells” and associated equipment. They are also asking the court to declare any part of the rule that applies to conventional well sites “unlawful.”They say the state’s environmental rule-making board was required to create separate air pollution standards for the tanks, valves and other equipment attached to their usually small, shallow wells. Because the board didn’t create separate standards, conventional well operators “will be forced to comply with requirements that are not technologically feasible, economically feasible, or neither,” they wrote in court filings.The 2016 law requiring separate treatment for conventional wells and shale wells applies only to rules established under the authority of the state’s oil and gas law, DEP wrote in documents defending the regulation. This rule falls under Pennsylvania’s air pollution law.The federal guidelines it builds on make no distinction between conventional and unconventional wells, and DEP “does not have the authority to exempt sources from federal requirements,” it wrote. Instead, well sites must comply with the rule based on their existing equipment, how much oil and gas they produce and how much pollution they are expected to emit.DEP estimates the rule will have a net economic benefit for the conventional industry, saving it $5.9 million more than it costs to comply by capturing gas that would otherwise be wasted.
Pa. DEP 're-evaluating' oil and gas air pollution rule as deadline looms Pennsylvania environmental regulators are “re-evaluating” their overdue rule for cutting air pollution from oil and gas well sites even as they face a deadline to finalize the new standards or risk the loss of federal highway funds.On Wednesday, the state Department of Environmental Protectionwithdrew the rule from consideration by the state’s Independent Regulatory Review Commission, which was scheduled to vote on it at an upcoming meeting on May 19.DEP spokesman Neil Shader said the department pulled the rule after the House Environmental Resources and Energy Committee sent a disapproval letter that triggers a legislative review process that could stretch through the end of the year.The rule is the last piece of Democratic Gov. Tom Wolf’s strategy to reduce methane emissions from new and existing oil and gas well sites and associated equipment. It’s designed to curb emissions of a smog-forming group of chemicals called volatile organic compounds while cutting emissions of methane, a powerful climate-warming gas, as a side benefit.Pennsylvania is more than three years past the deadline when it was required to implement the oil and gas air pollution controls, which are based on federal guidelines.It now faces a June 16 deadline to finalize the rule or face sanctions by the U.S. Environmental Protection Agency.“This delay caused by the disapproval resolution would jeopardize billions of dollars in federal highway funds,” Mr. Shader said. “DEP believes that re-evaluating the regulation and resubmitting to [the Environmental Quality Board] could avoid or minimize sanctions from the federal government.”The state Environmental Quality Board reviews and formally adopts rules developed by DEP. It voted to adopt the final oil and gas pollution rule in March.In its letter, the Republican-led House committee wrote that the rule has “a fatal flaw” because it did not follow a 2016 state law that requires conventional oil and gas wells to be regulated independently from those tapping the Marcellus and Utica shales.The air pollution rule, like the federal guidelines it is based on, does not distinguish between the two types of well sites. DEP has said the law requiring separate oil and gas rules does not apply to air pollution rules.“DEP had every opportunity to comply with this law, but chose not to and instead chose to concoct a specious argument to justify their failure instead of addressing the issue,” 16 members of the committee wrote, including all of its Republican members and Democrat Pam Snyder of Greene County.The disapproval letter echoes a complaint made in a lawsuit by the state’s conventional oil and gas producers, who are seeking court action to block the rule from applying to their well sites.In a court filing Thursday, DEP said the conventional industry’s claims should be dismissed since “only the possibility of a future regulation exists” at this point. The Commonwealth Court tossed “virtually indistinguishable” claims made by one of the industry trade groups in 2016 at a similar stage of the rule-making process for that reason, DEP wrote.Environmental advocates said there was no time to waste.“Methane is a growing climate threat and Pennsylvania urgently needs to adopt these regulations,” said Joseph Otis Minott, executive director of the Philadelphia-based Clean Air Council. “At this point, it is likely that EPA will sanction Pennsylvania shortly for not adopting the rule. Unless DEP can figure out how to quickly adopt the rule, the EPA sanctions will be quite draconian.”
Pennsylvania Oil Lobby Keeps Abandoned Wells Unplugged --Arthur Stewart took a seat at a table facing a panel of legislators in a nondescript room in the Pennsylvania State Capitol in Harrisburg. On a Monday morning in early February, he was there to meet with the Pennsylvania House Environmental Resources & Energy Committee to provide evidence of one of the state’s major environmental hazards. He guided lawmakers through a series of slides, eventually reaching one with a jarring photo: a piece of rusted pipe jutting out of the frost-covered forest floor, tucked between barren branches. Flames pour out of the top of the pipe: It’s an abandoned gas well, one of hundreds of thousands in the state that is emitting methane, which Stewart has lit on fire to demonstrate the danger.“I lit this well so that you could get a visual image of what’s happening every minute of every hour of every day of every month that that well has been sitting there,” he told the meeting of legislators, who’d gathered to discuss the disbursement of the influx of $104 million in federal funding to address the state’s orphaned and abandoned oil and gas well crisis.Stewart is no starry-eyed environmentalist. He’s the president of Cameron Energy Company and the founder of the Pennsylvania Grade Crude Oil Coalition, an industry lobbying group. And despite the dramatic evidence he provided of the hazards of abandoned wells, he was there in part to oppose proposals to increase the rates that oil and gas companies have to set aside for plugging such wells. That resistance could potentially endanger the state’s ability to get even more federal money to plug the wells through a round of performance grants earmarked for states that tighten their regulations. (Pennsylvania could receive up to $411 million over 10 years under the federal legislation.) The industry has long had a powerful influence on lawmakers in the state, where the country’s first successful oil well was drilled back in 1859, and has helped shape legislation that affects oil and gas companies.
Service provider costs increase, raising pressure on energy industry - Appalachia's natural gas producers have been on a roll lately, at least in terms of revenue, as commodity prices have more than quadrupled from their lowest point two years ago at the beginning of the Covid-19 pandemic. But everything isn't rosy: The cost of creating energy is going up, too. The region's big natural gas producers — EQT Corp., Range Resources, and Southwestern Energy - all talked about inflation and how it was hitting their expenses now and into the future during their first-quarter conference calls recently. And in an industry that depends on outside companies for much of their heavy lifting, it could be significant. Many of the big pressure points — steel for casing and pipes down drilling holes and to transport gas, as well as fuel and trucking — are well known across the industry. But there are also higher prices for other key pieces, including the cost of the sand that is used in hydraulic fracturing. The costs matter to the gas companies, as well as Wall Street, because shale is such a capital-intensive industry. Each one of the publicly traded natural gas producers' capital budgets range from around $460 million to almost $2 billion, depending on company size, drilling plans and basins. None of the big companies plan to increase drilling — and thereby production — by anything significant, opting instead for what the industry calls maintenance capital. That means drilling enough to keep up a steady state of production, and cash flow. In recent years, with gas prices at record lows and then the economic impact of the pandemic, service provider costs have mostly favored producers. That's not the case anymore, with the cost of raw materials rising with inflation and a fight for workers that has hit just about every industry. "The biggest factor I think people are looking at in the industry in general is just service cost inflation," said EQT CEO Toby Rice. EQT Corp., the nation's largest natural gas producer, acknowledged inflation has hit every part of the oilfield services industry. CFO David Khani told financial analysts last week that EQT had 50% of the spending for its capital budget already set and felt comfortable with keeping its capital expenditures pegged where they are right now. One reason for that confidence: It has a long-term contract for sand, which is a vital ingredient. Rice said that sand supply has been a concern for many in the industry, especially in the Permian basin. "But for EQT, with our sand supply agreements, we're not seeing much inflation on that front," Rice said. "Our challenge is more on the labor side and getting that sand to location." Range Resources spent about 25% of its 2022 capital expenditures, $117 million, of the $460 million to $480 million it is planning for the year. That's to be expected, as Range and other companies frontload drilling in the first half of a normal year and then slow drilling in favor of hydraulic fracturing and turning wells into sales in the second half of the year. Even with the cost increases it felt, Range said it was able to cut well-per-foot costs by 4% compared to a year ago due to higher efficiencies and longer laterals. Southwestern Energy, unlike most other natural gas producers, doesn't depend on outside service providers for drilling and hydraulic fracturing. Seven of the 16 Southwestern rig crews are their own. And the company said its services are contracted for 2022. That will save about $35 million to $40 million for 2022 compared to having an outside provider. "As a result of our procurement strategy and long-standing working relationships with key service providers, we have not encountered any material issues related to obtaining goods and services in any of our operating areas," said COO Clay Carrell. Southwestern also described occasional challenges with trucking and last-mile logistics.
Equitrans to seek renewed federal permits for MVP, eyes H2 2023 service start - Equitrans Midstream said May 3 it will pursue new federal permits for the 304-mile, 2 Bcf/d Mountain Valley Pipeline, after several were struck by the US Court of Appeals for 4th Circuit, and set a new target for placing the natural gas facility in service in the second half of 2023. Top company officials during Equitrans' first-quarter earnings call May 3 said they remained "committed to the path forward" for the 304-mile, 2 Bcf/d project, with support from joint venture partners. "After extended review of the recent court decisions and discussions with federal agencies, external counsel and our partners, we believe the path forward is to pursue new permits from the relevant federal agencies," Equitrans Chairman and CEO Thomas Karam said. Legal challenges from environmental groups and subsequent adverse decisions by the 4th Circuit have proven a major hurdle for the project in West Virginia and Virginia connecting Appalachian gas to downstream markets. The 4th Circuit in early-2022 invalidated federal authorizations allowing the MVP project to cross the Jefferson National Forest, as well as striking the US Fish and Wildlife Service's Endangered Species Act authorizations for the facility. The company's pitch for rehearing in those cases was then rejected by the full court in March, leaving MVP with a choice of requesting US Supreme Court review or seeking new federal permits, if it continued pursuing the projects. Another important permit is pending from the US Army Corps of Engineers.
Mountain Valley Pipeline to Seek New Permits, Boosting Cost (AP) — Mountain Valley Pipeline will seek new permits that courts have rejected twice, increasing the cost for the proposed natural gas pipeline that would run through Virginia and West Virginia and delaying its completion, officials said Tuesday. Equitrans Midstream Corp., the lead partner in the pipeline project, outlined the latest plan in a conference call with financial analysts on Tuesday, The Roanoke Times reported. The pipeline's cost is now projected to be $6.6 billion and its completion would be delayed to 2023. “After engaging with the federal agencies and evaluating all options, we believe the best path forward for MVP’s completion is to pursue new permits,” said Thomas Karam, chairman and chief executive officer of the Pittsburgh company. Four other energy companies, including a subsidiary of Roanoke Gas Co., are building the 303-mile (487-kilometer) pipeline that would transport natural gas drilled from the Marcellus and Utica shale formations through West Virginia and Virginia. “We are still all lockstep in agreement with our partners in terms of the path forward and what our costs will be,” Diana Charletta, Equitrans’ president and chief operating officer, said during the call.
Equitrans says it'll apply for new Mountain Valley Pipeline permits - Pittsburgh Business Times - Equitrans Midstream Corp. said Tuesday that it will seek new permits for the delayed Mountain Valley Pipeline, setting a new in-service date of the second half of 2023. MVP had been in holding pattern since late January, when the U.S. Fourth Circuit Court of Appeals issued rulings that invalidated two previously issued federal permits, permission to cross the Jefferson National Forest and a biological opinion related to nearby endangered species. The $6.6 billion pipeline had been scheduled to become operational at the end of the summer 2022 but that became untenable with the court's rulings. MVP is designed to bring Marcellus and Utica Shale gas from southwestern Pennsylvania through West Virginia and Virginia, opening up new markets for natural gas. There was good news for the company in April when the Federal Energy Regulatory Commission approved MVP's revised plan, which Equitrans said was an important step forward. “After engaging with the federal agencies and evaluating all options, we believe the best path forward for MVP’s completion is to pursue new permits," said Equitrans CEO Tom Karam in a statement Tuesday. Karam said Equitrans still believed the circuit court was wrong. "We are confident the agencies can and will produce even more comprehensive documentation to address the court's concerns," Karam said. "To reflect the time required for permit re-issuance and to ensure safe, responsible project construction, we have revised our MVP in-service target to the second half of 2023." The construction, which has already cost about $6 billion, is now expected to cost about $6.6 billion on the new timeline. Equitrans, which has spent $2.6 billion already on the construction, will pay about $3.4 billion, according to the new estimates. Its joint venture partners will pay for the rest. Less certain was the fate of MVP Southgate, an extension of the pipeline into North Carolina. "The MVP JV continues to evaluate the MVP Southgate project, including engaging in discussions with the shipper regarding options for the project, which includes potential changes to the project design and timing in lieu of pursuing the project as originally contemplated," Equitrans said.
Key US natural gas pipeline delayed as costs grow to $6.6 billion - Al Arabiya - A major US natural gas pipeline project has been delayed again as developer Equitrans Midstream Corp. pursues new permits for the troubled conduit. The Mountain Valley Pipeline is now estimated to start up in the second half of 2023 and will cost $6.6 billion, the company said Tuesday in a statement. That’s up from a previous forecast of $6.2 billion. Until late last year, Equitrans expected the pipeline to start operating by this summer. It was originally expected to be in service in 2018, and the cost estimate has roughly doubled since the project was announced in 2014. Equitrans is trying to get new permits for the project after a US appeals court earlier this year tossed the federal government’s approval for Mountain Valley to go through Jefferson National Forest in the Virginias. Mountain Valley, which is more than 90 percent complete, aims to connect drillers in the gas-rich Marcellus and Utica shale basins with major East Coast markets. Other projects in the region were scrapped amid fierce opposition from environmental groups, including proposals from Dominion Energy Inc., Duke Energy Corp. and Williams Cos. Equitrans, which owns 48 percent of the 488-kilometer conduit, has funded about $2.6 billion of the project and expects to spend $3.4 billion.
Mountain Valley Pipeline, a litmus test for big projects, is delayed again | Pittsburgh Post-Gazette - Equitrans Midstream Corp. has again delayed the start date for its 303-mile Mountain Valley Pipeline and raised its estimated cost to $6.6 billion, more than twice the original estimate. But the big question was whether the natural gas pipeline would ever be completed and what that could mean. Mountain Valley Pipeline, MVP for short, has become the harbinger of whether there’s still a desire for, or even the possibility of, large infrastructure projects being completed, even as Congress and the Biden administration talk about “building back.” The Canonsburg-based midstream firm said on Tuesday that it plans to apply for two environmental permits to replace the ones that were challenged and struck down in court. The process is likely to delay the restart of construction until at least the second quarter of next year. MVP’s journey from conception in the early 2010s through permitting, construction — the project is 94% completed, according to the company — lawsuits, protesters chaining themselves to bulldozers, and project sponsors losing faith, is viewed by supporters and opponents as a cautionary tale. The pipeline was envisioned to bring shale gas from the Marcellus and Utica in Appalachia to markets in the Southeast. It began construction in 2018 and has been beset by legal challenges. In February, the U.S. Court of Appeals for the Fourth Circuit invalidated two key environmental permits — one from the U.S. Fish and Wildlife Service that concluded no endangered species would be harmed by the pipeline, and another from the U.S. Forest Service and Bureau of Land Management that allowed MVP to cross the Jefferson National Forest. A few weeks later, NextEra Energy Resources, an energy company that would be using the gas transported by MVP and part owner of the project, wrote down its entire investment $800 million — concluding that the “continued legal and regulatory challenges have resulted in a very low probability of pipeline completion.” AltaGas, another much smaller stakeholder, has written down $271 million in Canadian dollars. Downtown-based EQT Corp., which was one of the project developers early on and had signed up for capacity on the pipeline, has been looking to lower its exposure to it. Last month, EQT disclosed that it sold its remaining stock in Equitrans, which spun out of EQT, for $189 million. It also sold at least half of its capacity on the MVP pipeline. In the meantime, EQT’s CEO Toby Rice has continued to talk about the pipeline project as “critical to the region” and as a litmus test for the political will to build energy infrastructure that backs up the promises being made abroad to help Europe quit Russian gas.Increasingly, oil and gas companies and their supporters have channeled their ire at the Federal Energy Regulatory Commission, which authorizes interstate pipelines, liquefied natural gas and similar projects. MVP secured its FERC approval after two years of review. That meant the commission found the project necessary — or, in practical terms, that customers will use it. FERC has been taken to task by landowners and environmental advocates for relying too heavily on pipeline contracts to determine need. In February, FERC commissioners voted to approve a policy requiring all future and pending projects to undergo an explicit review of their environmental and societal net benefits, including their impact on climate change — a move that was denounced by the industry and supporters in Congress. Sen. Joe Manchin, a Democrat from West Virginia who chairs the Senate Energy and Natural Resources Committee, called a hearing where he grilled FERC commissions on the new policy and issued a warning about MVP. “I know what's going to happen if the Mountain Valley Pipeline is not completed,” he said during that hearing in March. “There’ll not be another investment, taking the most abundant, plentiful gas reserves out of an area ... so that we have LNG, so we're able to do the things that we need … to not only … defend our great country but to help our allies. “I know these people,” he said, referring to pipeline developers and investors. “They’re not going to invest. They’re done. They’re walking away.”
Biden Admin Silent On The Fate Of Major Natural Gas Pipeline As Energy Prices Soar -The Biden administration has yet to take a public position on a major natural gas pipeline as the project faces an uphill federal permitting battle. Equitrans Midstream, the energy company that proposed the Mountain Valley Pipeline (MVP) in 2014, delayed the project’s expected completion to late 2023 and said it would pursue new federal permits for a second time, in an earnings reportpublished Tuesday. The project — a 303-mile pipeline that would transport natural gas from West Virginia to Virginia — faced another setback earlier this year after a federal appeals court struck down its Trump-era permits, ruling in favor of environmental groups. Federal agencies involved in the MVP permitting process didn’t respond to requests for comment or declined to comment altogether, and the White House has yet to intervene in the matter despite soaring energy prices and pleas from a Democratic senator. “After engaging with the federal agencies and evaluating all options, we believe the best path forward for MVP’s completion is to pursue new permits,” Thomas Karam, the chairman and CEO of Equitrans, said in a statement Tuesday. “To reflect the time required for permit re-issuance and to ensure safe, responsible project construction, we have revised our MVP in-service target to the second half of 2023.” The total project cost of the pipeline has increased to $6.6 billion, the company added in its earnings report. The MVP pipeline was originally projected to begin operations in 2018 and the total cost has doubled since the project was unveiled, Bloomberg reported. “Since the project’s inception, groups opposing energy infrastructure development have challenged the MVP project at every turn, filing dozens of petitions contesting MVP’s previously issued state and federal authorizations,” Equitrans spokesperson Natalie Cox told the DCNF in an email. “The agencies have expended substantial time and resources on the permit reviews; and the final authorizations exceeded regulatory and legal requirements for these types of projects.” The U.S. Court of Appeals for the Fourth Circuit ruled in January that the Forest Service and Bureau of Land Management (BLM) under the Trump administration failed to conduct proper environmental reviews of the pipeline. Weeks later, the same federal panel invalidated the Fish and Wildlife Service’s biological opinion permit for the MVP, saying it failed to consider project impacts on endangered fish species such as the Roanoke logperch and candy darter. The plaintiffs, a group of conservation groups led by the Sierra Club, argued the pipeline would cause widespread environmental damage. The permits had been issued in 2017 and reissued in early 2021 under the Trump administration. Former BLM official Katherine MacGregor said in 2017 the project would “efficiently deliver domestic natural gas resources.” But President Joe Biden has yet to address the project even as his administration has shut down other pipelines, environmental activists have urged him to rescind the project’s permits and Democratic West Virginia Sen. Joe Manchin, who supports MVP, has pushed for the president to expedite the permitting process.“Ultimately, the decision on MVP is one that President Biden can influence,” climate group Food & Water Watch stated in an October blog post.A coalition of 60 environmental organizations called upon the administration to revoke the MVP’s permits in an April 2021 letter. The letter alleged the pipeline’s construction has already caused “irreparable harm to landscapes and clean water.”The White House and U.S. Forest Service didn’t respond to requests for comment from the Daily Caller News Foundation. The Bureau of Land Management declined to comment.
Fewer gas pipelines will mean higher carbon emissions and more Russian threats - When dealing with major challenges, too many elected officials scramble for Band-Aid solutions rather than tackle the root of the problem. That’s certainly been the case with today’s high energy costs, to which the Biden administration and other officials have responded by pinning blame on Vladimir Putin and throwing various short-term fixes at the wall, just to see what will stick. But we cannot fix the real problem by merely ramping up oil imports from Canada, implementing a gasoline tax holiday, or allowing expanded sales of higher-ethanol gasoline during the summer driving season. It is also insufficient to dip into the nation’s strategic petroleum reserve. To stabilize and lower energy prices for the long haul, policymakers must take lessons from this latest global crisis and focus on the long term, especially when it comes to energy infrastructure. That was the key message from a report released earlier this month by the U.S. Energy Information Administration. The EIA examined a scenario under which no new natural gas pipeline capacity is built between 2024 and 2050. The consequences for consumers and the climate were quite damaging; such a scenario also eviscerated our potential to provide secure and reliable energy to allies around the world. Under this no-pipeline scenario, energy prices will surge even higher. U.S. natural gas prices recently hit their highest intraday level in over 13 years as American drillers struggle to meet high worldwide demand. Without additional interstate pipeline infrastructure, EIA projects that the Henry Hub spot price for natural gas will rise an additional 11%. Unfortunately, the administration has done nothing to promote the kind of pipeline infrastructure build-out that we’ll need to support natural gas development adequately. In fact, we’ve been moving in the opposite direction, with large interstate natural gas pipeline projects such as the Atlantic Coast Pipeline, the Penn East Pipeline, and the Constitution Pipeline being shelved because of heightened legal and public pressure. Second, higher natural gas prices will result in higher carbon emissions. Although they may provide an opportunity in some instances for carbon-free power sources such as solar and wind, they are also likely to resurrect coal-fired power — in the EIA’s own words, the agency forecasts "increased coal-fired power generation, which would be more carbon intensive than the natural gas-fired generation it displaces.” That’s exactly the opposite result from what the Biden administration is trying to achieve. Third, inadequate investments in energy infrastructure will mean less geopolitical security for the U.S. and the world. Without sufficient pipelines and export terminals, the U.S. won’t be able the meet the call to provide additional volumes of natural gas to Europe. American LNG is already critically important to Europe and should play an increasing long-term role in Europe’s energy security and decarbonization goals.
Chesapeake Pushed to Sell Oil, Keep Natural Gas by Activist Investor Kimmeridge - A day after reports surfaced that activist investor Kimmeridge Energy Management Co. LLC had taken a stake and was pushing for change, Chesapeake Energy Corp. CEO Nick Dell’Osso said Thursday he agreed the company is undervalued. Reuters initially reported that Kimmeridge took a 1.6% stake in the Oklahoma City-based independent, putting it among the largest shareholders. The private equity firm is reportedly pushing to enhance value, partly by divesting oilier assets in favor of natural gas. Dell’Osso during the first quarter conference call said management also believes shares are undervalued. Chesapeake kicked off a $1 billion share buyback program in the first quarter. He added that the buyback program could soon be exhausted “given the current valuation of our stock.” At that point, the company would seek board approval to increase buybacks and continue retiring shares. Kimmeridge has pushed for changes with success at other unconventional producers over the years. Chesapeake, once a natural gas behemoth, filed for bankruptcy in June 2020 after a shift into oilier assets. The company has refocused its efforts on natural gas in the Marcellus and Haynesville shales in recent years. It plans to run up to 15 rigs throughout 2022, with four in the oilier Eagle Ford Shale and the others roughly split between Louisiana and Pennsylvania. Dell’Osso said that despite a bullish turn in commodity prices this year amid conflict in Ukraine, oil and gas shortages, and wavering demand, the company would continue to exercise “strong capital discipline.” Management, he said, would need to be certain that demand is resilient before ramping up more than it already has after recent acquisitions in theMarcellus and Haynesville. The company also recently restarted its Eagle Ford program after a pause during the pandemic.Chesapeake produced 620,000 boe/d in the first quarter, 87% weighted to natural gas. That’s up from 539,000 boe/d in 4Q2021.The company is also trying to take advantage of upside in the U.S. liquefied natural gas (LNG) sector as overseas prices soar for the super-chilled fuel.He noted the company markets 4.5 Bcf/d of production, more than 2 Bcf/d of which is produced near LNG export terminals on the Gulf Coast. Despite Kimmeridge’s move on the company, Chesapeake reported record free cash flow (FCF) of $572 million during the quarter. It returned more than 70% to shareholders through dividends and buybacks. The company is also maintaining its capital expenditures forecast despite the impact of inflation on goods and services.Chesapeake reported a first quarter net loss of $764 million (minus $6.32/share). The period’s results were primarily related to a $2.1 billion loss on oil and natural gas derivatives as commodity prices soared. After Chesapeake finished restructuring last year, it qualified for fresh start accounting. That means its consolidated financial statements after Feb. 9, 2021 were not comparable with previous financial statements. The company continues to proactively add hedges, though, with 81 Bcf of 2023 natural gas locked in at prices of $3.48-7.29/Mcf. Chesapeake also has 1.1 million bbl of oil hedged next year at prices of $79.83-94.07/bbl.
Gas Giants Have Been Ghostwriting Letters Of Support From Elected Officials -For the past several months, local officials in Virginia and North Carolina, primarily elected Republicans, have been peppering federal regulators with glowing letters in support of gas projects in their states. Internal emails reviewed by HuffPost show that these letters all had something in common: They were ghostwritten by lobbyists and consultants of the two major pipeline firms behind those projects.The communications show how Williams Companies Inc. and TC Energy Corporation worked to boost political support for a number of natural gas infrastructure projects currently under federal review to fill a void left behind by Dominion Energy and Duke Energy’s canceled Atlantic Coast Pipeline.Industry watchdog group Energy and Policy Institute obtained the documents through a series of public records requests that it and others filed. It shared them exclusively with HuffPost.Meanwhile, the United Nations’ Intergovernmental Panel on Climate Change, the world’s premier climate research body, has released its latest sobering reports on global warming. The most recent analysis, published in early April, warns that global greenhouse gas emissions must peak no later than 2025, then be slashed nearly in half by 2030 in order to stave off the worst effects of climate change.On Jan. 10, Robert Crockett, the president of Advantus Strategies and a lobbyist for the Oklahoma-based Williams Companies, emailed Wayne Carter, the administrator of Mecklenburg County, Virginia, a draft letter of support for Williams’ Southside Reliability Enhancement Project. The proposed expansion of the company’s existing Transco natural gas pipeline would allow for more natural gas to be transported into North Carolina. The project includes the construction of a new, electric compressor station in Mecklenburg County.“Attached is a draft letter expressing support to the Williams project that we have reviewed with you and your board previously,” Crockett wrote. “Please feel free to modify.” Carter put his signature on the letter and sent it back to Crockett a couple of hours later with only minor tweaks.“Thank you Wayne!” Jay McChesney, a community and project outreach specialist at Williams, responded. “If you wouldn’t mind putting this in the mail and sending to FERC [the Federal Energy Regulatory Commission] that would be much appreciated…Thank you again for your support of our project.”The letter, which Carter submitted to the regulatory agency later that day on behalf of the county board of supervisors, notes that the project “will be done in a manner that is protective of the environment while providing much-needed benefits to our rural county” and applauds Williams for being “transparent and forthright as an existing corporate citizen in the state.”
Fewer gas pipelines will mean higher carbon emissions and more Russian threats - When dealing with major challenges, too many elected officials scramble for Band-Aid solutions rather than tackle the root of the problem. That’s certainly been the case with today’s high energy costs, to which the Biden administration and other officials have responded by pinning blame on Vladimir Putin and throwing various short-term fixes at the wall, just to see what will stick. But we cannot fix the real problem by merely ramping up oil imports from Canada, implementing a gasoline tax holiday, or allowing expanded sales of higher-ethanol gasoline during the summer driving season. It is also insufficient to dip into the nation’s strategic petroleum reserve. To stabilize and lower energy prices for the long haul, policymakers must take lessons from this latest global crisis and focus on the long term, especially when it comes to energy infrastructure. That was the key message from a report released earlier this month by the U.S. Energy Information Administration. The EIA examined a scenario under which no new natural gas pipeline capacity is built between 2024 and 2050. The consequences for consumers and the climate were quite damaging; such a scenario also eviscerated our potential to provide secure and reliable energy to allies around the world. Under this no-pipeline scenario, energy prices will surge even higher. U.S. natural gas prices recently hit their highest intraday level in over 13 years as American drillers struggle to meet high worldwide demand. Without additional interstate pipeline infrastructure, EIA projects that the Henry Hub spot price for natural gas will rise an additional 11%. Unfortunately, the administration has done nothing to promote the kind of pipeline infrastructure build-out that we’ll need to support natural gas development adequately. In fact, we’ve been moving in the opposite direction, with large interstate natural gas pipeline projects such as the Atlantic Coast Pipeline, the Penn East Pipeline, and the Constitution Pipeline being shelved because of heightened legal and public pressure. Second, higher natural gas prices will result in higher carbon emissions. Although they may provide an opportunity in some instances for carbon-free power sources such as solar and wind, they are also likely to resurrect coal-fired power — in the EIA’s own words, the agency forecasts "increased coal-fired power generation, which would be more carbon intensive than the natural gas-fired generation it displaces.” That’s exactly the opposite result from what the Biden administration is trying to achieve. Third, inadequate investments in energy infrastructure will mean less geopolitical security for the U.S. and the world. Without sufficient pipelines and export terminals, the U.S. won’t be able the meet the call to provide additional volumes of natural gas to Europe. American LNG is already critically important to Europe and should play an increasing long-term role in Europe’s energy security and decarbonization goals.
Tennessee certified gas plan sidelined over FERC's reluctance to review criteria - Just days before Tennessee Gas Pipeline was hoping to offer a new pooling service for gas from producers certified to meet methane intensity standards, the US Federal Energy Regulatory Commission rejected the company's proposal. But the regulator emphasized that it was primarily uncomfortable with Tennessee's proposal to have FERC weigh in on criteria for so-called responsibly sourced gas, preferring instead to allow market-driven initiatives to unfold more organically. FERC rejected the plan without prejudice to Tennessee refiling an alternative proposal that doesn't trigger such concerns. Except for the proposal to include the criteria for pooled certified gas in its tariff, FERC would otherwise find Tennessee's proposal to be just and reasonable, said the order, approved by all five commissioners. The proposal, if approved, would have sent a signal to the industry on market design for this nascent product, with the most recent filing supporting a certificate design over exchange-based physical gas trading hubs. Tennessee first proposed in December to offer the pooling service to encourage transportation and trading of gas from producers with third-party certification that their supply meets minimum environmental, social and governance standards. The option as proposed then would have allowed for aggregation of certified supplies at pooling points, with plans to use Project Canary and MiQ to certify the gas, using a methane intensity threshold. Tennessee subsequently added Xpansive Data Systems' Digital Fuels Program as a third, optional certifier. After some stakeholders including major shippers raised concerns that the pipeline company would serve as too much of a "gatekeeper" in defining certified gas and picking the certifiers, Tennessee proposed to place criteria in its tariff, allowing for FERC review. Further, it proposed to include the list of certifying agencies in its tariffs, and asked for a May 1 effective date. But FERC's April 29 order said it was unclear how the commission would evaluate Tennessee's decision to adopt specific criteria. "To date, based on the record in this proceeding, there are neither industry nor government-established standards that could guide the commission's review given the nascent [responsibly sourced gas] market," Further, FERC noted that there is no federal regulation for oil and gas methane emissions. The commission also worried that by acting on criteria, it could hinder development in the market and acceptance of further RSG standards and certification vendors.
Largest U.S. Fuel Pipeline Underused Despite East Coast Shortage - The main U.S. fuel artery should be nearly bursting with products headed to New York Harbor where prices are soaring. Instead, the Colonial pipeline has ample space available as a market structure prompts traders to export fuel rather than send it to the East Coast. The price of diesel for immediately delivery versus the next month widened to the largest ever gap in what’s known as a backwardated market structure. This means holding onto product -- whether by putting it in a storage tank or in a pipeline that takes weeks to reach its destination -- is a losing bet. Diesel prices have surged since the war in Ukraine scrambled global markets, as efforts to isolate Russia restricted supplies from one of Europe’s most important producers of fuels. U.S. Gulf Coast refiners have stepped up to fill the global void, sending more exports to Europe and Latin America at the expense of the U.S. East Coast. The effects are trickling down to consumers with the national average retail price for diesel rising to a record Friday. “The United States has become the marginal supplier of an export barrel,” “That’s why the Colonial pipeline has been underutilized even as fuelmakers on the Gulf Coast are cranking out as much diesel as they can. With exports rising, diesel tanks on the East Coast are the emptiest they have been in 26 years. The pipeline has not been full since late last year, according to the last update from the company. It’s especially unusual for the pipeline to have available space given that wholesale diesel in New York was fetching $1.23 a gallon more than on the Gulf Coast on Friday, more than ten times what it was two weeks ago. That premium is typically enough to draw shipments to New York. The arbitrage for shipping fuel on Colonial is considered open when the price difference between the two regions exceeds the pipeline tariff at around 6 cents a gallon. It is now more than 20 times that. However, the surge in prompt prices makes this a losing proposition for sellers who can also tap lucrative markets abroad. It currently takes more than 19 days to deliver fuel from Houston to Linden, New Jersey. The depreciation during the lengthy transit time means few traders are shipping on the line, leaving East Coast storage tanks precariously low.
Record Fuel Exports from USA Gulf Coast Drain Tanks -Record fuel exports from the U.S. Gulf Coast are eating into domestic supplies, leaving gasoline and diesel tanks on the East Coast emptier than they have been in decades. As much as 2.09 million barrels a day of gasoline, diesel and jet fuel shipped out of the refining hub in April, the highest level since oil analytics firm Vortexa began tracking the data in 2016. The bulk of the exports went to Latin America. The strong pull from overseas shows the world needs U.S. Gulf Coast refiners more than ever. But producers there will have to balance lucrative exports with domestic demand heading into the peak travel season this summer, with pump prices already at record highs for diesel and hovering just shy of peak for gasoline. Export demand will likely stay strong through the next few months as countries in South America continue to burn diesel fuel for power generation during the Southern Hemisphere’s winter season, when hydropower supply falls. Mexico, the largest overseas buyer of U.S. gasoline by far, will likely draw more from the U.S. Gulf Coast as high crude prices derailed the country’s plans to produce more fuel at home. When push comes to shove, U.S. consumers will be able to outcompete overseas buyers, said Andy Lipow, president of Lipow Oil Associates LLC in Houston. “Demand destruction will happen overseas first,” he said in a phone interview. Domestic fuel demand is expected to exceed 2019 levels this summer despite high prices, a government forecast shows. Meanwhile, the distillates segment of the largest U.S. domestic pipeline connecting fuelmakers on the Gulf Coast and consumers on the East Coast has been running below capacity since the beginning of the year.
U.S. natural gas production growth wanes as need arises (Reuters) - U.S. natural gas production growth is waning at the same time many countries are looking for new suppliers to help break their dependence on Russian gas after Moscow's invasion of Ukraine. The United States is already the world's largest producer of natural gas. But the two mainstays of production - the Appalachian region and West Texas - are seeing growth slow, with companies blaming lack of adequate pipeline infrastructure, despite prices near 14-year highs. Since Moscow invaded Ukraine on Feb. 24, U.S. gas prices have soared about 50% as European countries look to the United States, the world's second biggest exporter, to sell more liquefied natural gas (LNG) to wean Europe off Russian fuel. Growth has slowed in Appalachia, which supplied about 37% of U.S. gas in 2021, because it has become increasingly difficult for energy firms to build new pipes to move gas out of the Pennsylvania, Ohio and West Virginia region. With pipelines in the Permian Shale, the nation's second biggest gas supply basin, filling quickly, analysts said production growth in that Texas-New Mexico basin could slow significantly next year unless firms start building new pipelines soon. The Permian supplied about 19% of U.S. gas in 2021. Energy analysts expect benchmark gas prices will average $4.24 per million British thermal units (mmBtu) in 2022, which would be the highest annual average in eight years. The largest European economies import about 18.3 billion cubic feet per day (bcfd) from Russia. The United States currently can export about 9.8 bcfd as LNG. Several companies are looking to boost exports, but substantial new LNG export capacity is not expected for at least two years. A billion cubic feet is enough gas to supply about five million U.S. homes for a day.
As Gas Prices Soar, Nobody Knows How Much Methane Is Leaking - No one knows how long natural gas had been seeping out of a meter at the Greenville Downtown Airport in South Carolina. A satellite chartered by Duke Energy Corp., the power company for the airport, eventually spotted the billowing greenhouse gas, and workers came to fix the leak. But in the intervening time between leak and discovery, an untold amount of methane—the main component of natural gas—escaped into the atmosphere. For the next two decades, all that gas will trap 84 times more heat than a similar amount of carbon dioxide. Duke says it’s the first U.S. utility to use satellites to search their own infrastructure for invisible leaks, both to save fuel that’s rarely commanded today’s skyrocketing prices and to help stem global warming. The company’s blindness to a dangerous methane plumefrom its own infrastructure surprised executives. And it underscores an even more concerning fact about the global energy industry: those involved in extracting, moving and burning oil and gas aren’t required to know anything about the actual volume of planet-warming pollution being released into the air. Lost gas from gaping leaks in pipelines and storage tanks isn’t just a climate catastrophe—it’s now an acute economic setback as well. Fallout from the two-month-old Russian invasion of Ukraine has intensified a worldwide energy crunch and set off a scramble to secure new supplies of natural gas. U.S. natural gas futures have been holding near a 13-year high after hitting $8 in April, just as Russia halted gas flows to Poland and Bulgaria last week in an escalating use of energy as a geopolitical weapon. But the rush to build new gas infrastructure is being undertaken without accurate measurements on how much gas is being wasted from existing pipelines and tanks. Estimates of the losses are based on emissions projections that prove to be disconnected from reality, which means the warming impact is also severely undercounted. While almost 8,000 power plants, oil and gas companies and refineries in the U.S. report their emissions to the Environmental Protection Agency each year, experts say those figures drastically underestimate the contribution to rising temperatures from the industry. Even with new methane-detecting technologies available, companies aren’t obligated to physically monitor infrastructure, and federal regulators rarely collect data of their own. Disclosure comes down to companies simply tallying figures—for example, how many gas wells they have—and applying an outdated formula developed by the EPA that assigns an assumed emissions rate.
NYMEX Henry Hub gas rises to mid-$7/MMBtu level amid lingering supply concerns - US gas futures prices edged back toward the mid-$7/MMBtu range in May 2 trading as domestic supply remains constrained by sluggish production and an enduring inventory deficit. As US upstream activity continues to build, though, the now aging rally faces increasing downside risk later this summer. In early trading, the June contract briefly edged up to $7.55/MMBtu while balance-of-summer futures traded into the mid-$7.60s/MMBtu. The market remained mostly in contango through next winter with January 2023 briefly pricing at nearly $7.90/MMBtu, data from CME Group showed. At a time of year when US gas prices typically trough, the NYMEX bulls are steering the market, apparently spurred persisting supply concerns this spring. In April, spring pipeline maintenances helped to keep US gas production sputtering around 93.2 Bcf/d. Following a steep New Year production decline in January, domestic output remains about 2 Bcf/d, or roughly 2%, below late-December levels, S&P Global Commodity Insights data shows. Low storage levels have added to the market's concern. As of the week ended April 22, US inventories are estimated at 1.49 Tcf. In it's latest storage report, data from the US Energy Information Administration showed the inventory deficit at 305 Bcf – its widest yet this year. An updated forecast published by S&P Global shows cooler weather and elevated heating demand helping to widen the deficit over 330 Bcf by the first week of May. After unseasonably cool weather last month, US temperatures are expected to trend closer to normal through mid-May, according to recent forecasts from the National Weather Service and S&P Global. Heating demand should average about 18 Bcf/d over the next week, undershooting the prior five-year average by about 250 MMcf/d. Gas demand from generators, meanwhile, is expected to average about 26.4 Bcf/d, setting a record high for the seven-day period thanks partly to the continued retirement of coal-fired generating capacity and the recent coal-to-gas fuel switching in the power markets. Based on the Weather Service's seasonal forecast for June, July and August, the outlook for gas-fired electric this summer looks more bullish. Nearly the entire Lower 48 states face an elevated probability for hotter-than-normal temperatures more concentrated risks across the Rocky Mountain and desert West and along the Northeastern Atlantic seaboard.
Natural Gas Tops $8 Again as US Output Slows Amid Strong Global Demand - Natural gas futures are skyrocketing on Tuesday as weather models and storage challenges supported the energy commodity. After enduring a modest decline following its last runup to $8, natural gas prices are back above this enormous level. Could energy markets see $9 before the summer? June natural gas futures rallied $0.478, or 6.32%, to $8.044 per million British thermal units (btu) at 12:47 GMT on Tuesday on the New York Mercantile Exchange. Natural gas prices are up 125% so far this year and have skyrocketed 170% over the last 12 months. US natural gas production growth has slowed down in the last month, despite soaring global demand. Despite the US being the world’s largest producer of natural gas, especially in West Texas and the Appalachian region, output has slumped. Many energy producers are blaming inadequate pipeline infrastructure.In Appalachia, for example, energy firms have been unable to construct new pipelines to transport natural gas out of Ohio, Pennsylvania, and West Virginia. In the Permian Shale, pipelines are filling quickly and it has been tough for companies to keep producing.Market analysts are forecasting that prices will average $4.24 per million Btu this year, the highest annual performance in eight years.Now, here is the problem for the natural gas industry: The largest European Union markets import roughly 18.3 billion cubic feet per day from Russia and the US can only export roughly 9.8 billion cubic feet per day.Even if energy companies produce more and try to increase exports, there is not enough infrastructure to support this goal. All eyes will be on Thursday’s natural gas storage report. The market is penciling in an inventory build of 33 billion cubic feet. Recent weather models are showing that summer temperatures are expected to heat up, adding to ballooning cooling demand, which could weigh heavily on storage levels. In other energy commodities, June West Texas Intermediate (WTI) crude oil futures tumbled $1.09, or 1.04%, to $104.08 per barrel. July Brent crude futures shed $1.11, or 1.03%, to $106.47 a barrel. June gasoline futures slipped $0.0385, or 1.1%, to $3.4716 a gallon. June heating oil futures fell $0.0729, or 1.73%, to $4.1302 per gallon.
Natural gas surges 9% to highest level since 2008 as Russia's war roils energy markets -- U.S. natural gas surged Tuesday to the highest level in nearly 14 years as Russia's invasion of Ukraine wreaks havoc on global energy markets. Henry Hub prices jumped more than 9% at one point to a session high of $8.169 per million British thermal units (MMBtu) during morning trading on Wall Street, the highest level since September 2008. The contract later pulled back from its high, ending the day at $7.954 per MMBtu for a gain of 6.4%. Campbell Faulkner, senior vice president and chief data analyst at OTC Global Holdings, said the increase was sparked by a "flurry of tighter market conditions," including the European Union considering a sixth round of sanctions against Russia that could include the nation's energy complex. In addition, production is down in the U.S., and gas in storage is 21% lower than at this time last year. "Higher power burn this summer with zero coal gas ... switching will reduce the amount of spare gas for storage infill which is pushing prices up in a classic commodity cycle ('backwardation") to get gas into the market now," he added. Over the last two sessions, natural gas prices have jumped more than 8%, which follows a nearly 30% gain in April. The swift upward price action, which is also being fueled by surging demand for U.S. liquified natural gas, is adding to inflationary pressures across the economy. For example, consumers' electricity bills are rising as utility companies pass along their higher input costs.
Natural Gas Prices Hit Fresh 13-year High -On Tuesday, natural gas prices surged higher but settled off the season’s highs. The weather is expected to be mixed, colder on the West Coast and warmer on the East Coast for the next 2-weeks. LNG exports declined in the latest week, but natural gas arrivals at LNG export terminals continued to remain steady. U.S. LNG exports decrease by three vessels this week from last week. Twenty-three LNG vessels, nine from Sabine Pass, five from Freeport, four from Corpus Christi, three from Cameron, and one each from Cove Point and Calcasieu Pass, combined LNG-carrying capacity of 84 Bcf departed the United States between April 21 and April 27. On Monday, natural gas prices rose higher, hitting a new 13-year intra-day high. Support is seen near the 20-day moving average at 6.9. Target resistance is seen near the May highs at 8.16. The pattern looks like a cup-and-handle, a continuation pattern that follows the trend. .
U.S. Natural Gas Prices Hit A 13-Year High On Inventory Concerns | OilPrice.com - Natural gas prices in the U.S. continue to rally Wednesday, with futures soaring past $8 for gains of over 5% this morning, as inventory concerns mount ahead of a summer that promises high demand. In the U.S., natural gas prices hit $3.347, for a 5.29% rally as of 9:36 a.m. EST. In the previous session, U.S. natural gas hit a 14-year high, jumping more than 9%, before pulling back to close at just under $8. On Tuesday, the American Petroleum Institute (API) reported a draw in gasoline inventories of 4.50 million barrels for the week ending April 29—after the previous week's 3.91-million-barrel draw.This decline in stockpiles comes as weather forecasts show unusually high temperatures in some parts of the country for early May, which will mean an early start to the American air-conditioning season, signaling increasing demand for natural gas. Natural Gas Intelligence cited Bespoke Weather Services as saying that current inventory and production levels would not be sufficient to meet this demand, which could lead to a situation in which natural gas prices top $10 in the coming weeks. U.S. gas inventories are now an estimated 17% below normal for this time of year as exports hit new records and producers hold back from new production. Record volumes of fuel are being exported from the Gulf Coast, draining domestic supplies of both gasoline and diesel. According to Vortexa tracking data cited by Bloomberg, In April, U.S. companies were exporting up to 2.09 million bpd of gasoline, diesel, and jet fuel from the Gulf Coast.
As Natural Gas Prices Hit 14-Year High, Shale Awaits | Arkansas Business News Arkansas Public Service Commission Chairman Ted Thomas had heard about the problem from lawmakers, their constituents and regulatory colleagues. “Even my wife asked me what’s going on with our natural gas bill,” the utility regulatory chief told state legislators last month, describing a “triple whammy” of brutality in the market. Natural gas on the Henry Hub market was selling last week at nearly $7 per million British thermal units, its highest price in 14 years, after Russia cut off Poland and Bulgaria to punish their resistance to its invasion of Ukraine. That price is still about half the peak in 2008, when prices neared $14 per million BTU, but a shock to the system in a post-fracking world. Hydraulic fracturing revolutionized production after being applied to shale formations, including the Fayetteville Shale in Arkansas. Booming about the time gas prices hit $14, fracking unleashed a torrent of natural gas for more than a decade, glutting the market and sending prices below $2 several times between 2012 and 2020. As reserves grew and prices collapsed, fracking fell off in most U.S. shale plays. Producers stopped drilling in the Fayetteville Shale in 2015-16, and the industry’s workforce was decimated. Thomas’ “triple whammy” started with an extreme cold catastrophe in February 2021, when the Texas grid failed lethally. The crisis meant some utilities spent “four or five times the dollar cost of gas in 10 days than they did for the entire previous calendar year,” Thomas said. “We’ve had five years of low and stable natural gas prices. In fact, some natural gas producers went bankrupt.” The third problem, of course, is the war in Ukraine. “Europe is dependent on Russian natural gas,” and despite U.S. efforts to ramp up exports of liquefied natural gas, “it’s just part of what’s driving the price up for American consumers.” Looking back, Thomas said, fossil fuel defenders may have chosen the wrong carbon to protect as decarbonization became a political force on the left. “Fracking saved consumers billions and billions of dollars,” the PSC chairman continued. “Fracking is what drove coal bankruptcies, because gas and coal compete [as a fuel for generating electricity]. And you never heard that. … We should have defended fracking jobs instead of coal jobs. If we had, customers might be in a better place.” Sustained prices above $4 per million BTU will eventually stimulate gas drilling, said Hugh Daigle, a drilling expert and associate professor at the University of Texas. Daigle said drilling is already up, but mostly in fracking areas that produce both gas and oil, like the Permian in Texas. Oil prices have been high for months, with gas costs trailing along. “Fayetteville is a dry gas play, not producing oil,” said Daigle, who quoted studies suggesting that $4 gas is the break-even point in Arkansas’ gas fields. Some fracking companies are hiring, including Calfrac Well Services, which has 10 jobs open in Beebe and Searcy.
US natural gas storage rises 77 Bcf to 1.567 Tcf spurring NYMEX futures rally | S&P Global Commodity Insights - Chilly spring weather across much of the country curbed net injections to US natural gas storage in the final week of April, helping to widen the inventory deficit and propel a rally in NYMEX gas futures. The US Energy Information Administration May 5 reported a larger-than-expected injection of 77 Bcf to gas storage for the week ended April 29 in a build that barely undershot the prior five-year average. The injection was 16 Bcf more than anticipated from an S&P Global Commodity Insights' survey of analysts, which called for a 61 Bcf addition to stocks, and just 1 Bcf shy of the prior five-year average build. As a result, US working gas inventories climbed to 1.567 Tcf. The storage deficit to 2021 narrowed again as stocks climbed to 382 Bcf, or about 20%, below the year-ago level of 1.949 Tcf. The inventory deficit to the prior five-year average expanded to its widest yet this season, leaving stocks 306 Bcf, or about 16%, below the historical average of 1.873 Tcf, EIA data showed. The NYMEX Henry Hub June contract rebounded about 15 cents, or nearly 2%, after the storage report's release, rising to $8.30/MMBtu after falling steadily in overnight trading from fresh 14-year highs in the mid-$8/MMBtu range, CME Group data showed. Unseasonably low temperatures across the Midwest and the Northeast through April and even into early May have been a key driver of the NYMEX futures rally and the widening storage deficit. In the week ended April 29, population-weighted temperatures across the Upper Midwest averaged a chilly 54 degrees Fahrenheit, while the Northeast rose to just 55 F. During the week, US residential-commercial gas demand, led by the two key heating regions, briefly spiked to more than 25 Bcf/d, S&P Global Commodity Insights data showed. Storage builds of 15 Bcf in both the Midwest and the Northeast, totaled about 4 Bcf below average for the corresponding week. In the Mountain and Pacific regions, the weekly storage injections were also undersized, but more than offset by a larger-than-average build in the South-Central region. During the week in progress, a smaller but not insignificant jump in US heating demand to around 20 Bcf/d could limit storage injections again. According to preliminary forecasts S&P Global published, the EIA is likely to report a storage injection in a 65-75 Bcf range for the week ending May 6, compared with a five-year average injection of 82 Bcf in the corresponding week. The chilly start to spring this year has increased the call on already-strained US gas supply. After trending at more than 93 Bcf/d in April, domestic production has slumped since the start of May to average just 92.6 Bcf/d this month, according to S&P Global data. While the US rig count, at 803, is now estimated at its highest in over two years, US gas production has continued to flounder, trending about 2-3 Bcf/d below record highs recorded in December 2021.
U.S. natgas jumps to 13-year high on hot spring weather, strong LNG demand - (Reuters) - U.S. natural gas futures jumped about 4% on Thursday to a fresh 13-year high as hot spring weather boosted air conditioning demand, while much higher global prices kept demand for U.S. liquefied natural gas (LNG) exports strong. Traders said the increased domestic and export demand limits the amount of gas utilities can inject into storage for next winter. U.S. stockpiles were currently about 16% below normal for this time of year despite last week's near-normal injection. "Besides a big storage deficit, natural gas is also bid on the assumption the U.S. effort to supply the European Union (EU) with LNG ... will ultimately leave less gas for domestic consumption, as spare capacity and new production gets scooped up by desperate customers on the other side of the Atlantic," U.S. front-month gas futures for June delivery rose 36.8 cents, or 4.4%, to settle at $8.783 per million British thermal units (mmBtu), their highest close since August 2008 for a third day in a row. Earlier in the week, U.S. gas futures followed oil prices higher after the EU proposed a phased embargo on Russian oil in response to Moscow's Feb. 24 invasion of Ukraine. Analysts said the proposed oil embargo increased the possibility the EU will also ban Russian gas in the future. In the spot market, meanwhile, gas prices in several parts of the United States and Canada soared this week as power generators burned more of the fuel to meet higher air conditioning demand during an early spring heatwave in the U.S. South and West. U.S. gas futures have already gained about 136% 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. Gas was trading around $34 per mmBtu in Europe and $24 in Asia. . Data provider Refinitiv said average gas output in the U.S. Lower 48 states has slid to 94.0 billion cubic feet per day (bcfd) so far in May from 94.5 bcfd in April. That compares with a monthly record of 96.1 bcfd in November 2021. Refinitiv projected average U.S. gas demand, including exports, would slide from 90.8 bcfd this week to 89.9 bcfd next week as the weather turns seasonally milder. The forecast for next week was lower than Refinitiv's outlook on Wednesday. The amount of gas flowing to U.S. LNG export plants has held around 12.2 bcfd so far in May, the same as in April, and down from a record 12.9 bcfd in March. The United States can turn about 13.2 bcfd of gas into LNG.
Natural Gas Futures Falter, Ending Furious Rally; Spot Prices Sputter - Natural gas futures retreated Friday, ending five days of frenzied rallying, as markets assessed an increase in production and traders took profits. The June Nymex gas futures contract fell 74.0 cents day/day and settled at $8.043/MMBtu. July dropped 71.3 cents to $8.128. The prompt month, which reached $8.783 on Thursday, still finished the week up 11%. Following a frenetic rally of its own this week, NGI’s Spot Gas National Avg. dipped 1.5 cents to close at $7.985 on Friday.Production, after hovering as low as 93 Bcf this week – far from highs above 96 Bcf earlier in the year – was back to around 95 Bcf on Friday, according to Bloomberg’s estimate. This provided some relief that output is beginning to recover following late-season blizzards in the North that caused freeze-offs and prolonged production interruptions. Spring maintenance work also has hampered output. Saal, StoneX’s senior vice president of energy, told NGI some market participants sold off to claim profits while others, viewing prices as simply too high, moved to the sidelines. “Pricing just got to a point where even the most aggressive buyers said enough is enough,” he said.The bump in production likely influenced markets as well. Though Saal noted output estimates have been choppy and are likely to remain so until maintenance culminates. Even then, production may struggle to keep pace with demand if summer cooling season starts early and proves intense, as forecasters are predicting. Saal also noted that exploration and production companies are grappling with soaring inflation that hit a four-decade high this year as well as chronic labor shortages.“We haven’t seen inflation like this in natural gas markets,” Saal said. “So it’s a big wildcard. And it’s really hard right now to pick a top as far as prices. We could still go higher.” Early summer weather in the South proved a catalyst for prices much of the week and could again, Bespoke Weather Services said.“We have some very impressive heat on the way in the South,” the firm said. Cooling degree days in Texas and neighboring states “are forecast to hit daily records potentially on several days over the next week to 10 days,” given forecasts for highs in the 90s and low 100s.Friday’s pullback aside, “momentum is clearly bullish and psychological resistance at the $9.00 mark may not hold for long,” said EBW Analytics Group’s Eli Rubin, senior analyst. “With little change in the storage trajectory,” he added, “the balance of price risks for natural gas into early summer remains sharply higher.”
Southwestern, CNX See Challenges, Advantages in Meeting Growing LNG Demand - The world’s growing appetite for U.S. liquefied natural gas (LNG) continued to take center stage during earnings calls at two more of the nation’s top exploration and production companies, with management at both acknowledging the opportunities and challenges that come with meeting rising demand. Southwestern Energy Co. said Friday it’s already sending a third of its production, or about 1.5 Bcf/d, to LNG export terminals. The company became the nation’s second largest natural gas producer last year after it entered the Haynesville Shale by acquiring Indigo Natural Resources LLC and GEP Haynesville. “We’re having conversations with current and future key LNG players and continuously looking at value-enhancing opportunities on a risk-adjusted basis…to enter into additional agreements down the line.,” Southwestern is also the largest producer in the Haynesville, where strong nearby LNG demand and higher domestic gas prices have set the stage for resurgent development. “There is going to be a very big call on demand of natural gas for this ramp up in LNG, and we think we’re positioned quite well – advantageously – to work in that space.” Europe and Asia, where natural gas prices have surged this year, are poised to compete more fiercely for LNG cargoes as buyers turn away from Russian imports in response to the invasion of Ukraine. U.S. natural gas prices are trading at a steep discount to overseas benchmarks, making American LNG even more attractive. The Biden administration has also committed to fast-tracking LNG plant approvals and sending more supplies to Europe as Russia threatens energy security on the continent. There are roughly 20 LNG projects under development in the United States. U.S. producers are seizing the moment this earnings season to promote the climate and economic benefits of American natural gas. During its call, the nation’s largest producer, EQT Corp., touted its initiative to boost U.S. LNG export capacity to 55 Bcf/d by 2030. CNX Resources Corp. CEO Nicholas DeIuliis chimed in with less optimism. He said that for all the talk about rescuing overseas buyers with additional supplies, there are significant domestic challenges that remain before higher output can be unlocked. He said the nation’s producers can’t ramp up gas volumes quickly because of infrastructure constraints. That’s particularly true in the Appalachian Basin, where CNX is a leading producer. Years of opposition from environmental groups have stopped pipeline projects altogether and created legal hurdles for other systems under development. DeIuliis said a large part of the setbacks are “simply and starkly because of policy that has consciously and methodically looked to strangle infrastructure investment in the pipes, processing, power generation and LNG infrastructure that is needed to meet the world’s energy demand.”
Terminal utilization high as new liquefaction projects gain steam - Utilization at US liquefaction terminals remained high and momentum for adding new capacity around the middle of the decade increased during the week to May 3, even as FOB Gulf Coast cargo values fell for the fifth straight week. S&P Global Commodity Insights assessed the Platts Gulf Coast Marker for US FOB cargoes loading 30 to 60 forward at $20.300/MMBtu on May 3, down $2.250/MMBtu week on week. Northwest Europe remained the best netback. GCM has fallen by almost two-thirds since its March 4 record high of $58.250/MMBtu, though the current level remains three times higher than a year ago. Cargoes have flooded the Atlantic Basin as the war in Ukraine led to fears of gas supply disruptions in Europe. Netbacks to the Gulf Coast remain strong, even with rising US feedgas costs. The NYMEX Henry Hub prompt-month contract was trading nearly 70 cents higher at $8.03/MMBtu as of afternoon in New York on May 3. Persistently sluggish production numbers and higher-than-normal demand have increased supply concerns, as expectations of a hot summer demand season complicate the potential for injections to close the storage deficit before winter 2022-23. In the week of April 26-May 3, US LNG export facilities nominated 12.2 Bcf/d of feedgas on average, a similar amount compared with the previous week. Overall, in April, US Gulf facilities nominated 4.6% less feedgas than in March, amid shoulder-season scheduled maintenance at Freeport LNG in Texas and Sempra Energy's Cameron LNG in Louisiana. Meanwhile, amid high spot prices in end-user markets, there has been a flurry of commercial activity during the first several months of 2022 tied to current and proposed US LNG export terminals, which offer long-term contracts with fixed fees and destination flexibility. That activity continued during the most recent week. French utility Engie agreed to a 15-year deal to buy 1.75 million mt/year of supply on a free-on-board basis from NextDecade's proposed Rio Grande LNG export facility in Texas, while Swiss commodity trader Gunvor agreed to a 20-year FOB deal to buy 2 million mt/year of supply from Energy Transfer's proposed Lake Charles LNG export facility in Louisiana. Both of those deals were announced May 2, with commercial startup targeted for as early as 2026.
Calcasieu Pass, the seventh U.S. liquefied natural gas export terminal, begins production - The Federal Energy Regulatory Commission (FERC) has authorized Venture Global Calcasieu Pass, LLC, (Venture Global)—the developer of the Calcasieu Pass liquefied natural gas (LNG) export terminal—to commission the first six of nine liquefaction blocks. Each block contains two liquefaction systems called trains. The first authorization, issued in November 2021, was one of the initial steps toward full commercial service.Calcasieu Pass is a 1.3 billion cubic feet per day (Bcf/d) liquefaction facility located in Cameron Parish, Louisiana. Similar to nearby LNG terminals Sabine Pass and Cameron, Calcasieu Pass will export LNG through the Calcasieu Ship Channel located on the Gulf of Mexico. Calcasieu Pass is the seventh U.S. LNG liquefaction export facility to begin producing LNG since 2016.In addition to 18 mid-scale liquefaction trains, the Calcasieu Pass facility includes an onsite natural gas-fired plant to generate electricity for the facility’s operations, three pre-treatment trains, two LNG storage tanks (with a capacity of 4.4 Bcf each), and two shipping berths capable of loading LNG vessels with carrying capacities of up to 185,000 cubic meters (4 Bcf). The Calcasieu Pass terminal receives its feedgas through Venture Global’s 24-mile, 42-inch diameter TransCameron Pipeline, which has interconnections with the ANR, TETCO, and Bridgeline pipelines.Since November 2021, Venture Global has received FERC approval to commission Blocks 2–6, most recently on March 30, 2022. Natural gas deliveries to the terminal have increased throughout 2022, averaging approximately 0.7 Bcf/d in April, according to PointLogic. With only three blocks left to authorize for commissioning, and given the pace at which the terminal has received FERC approvals to commission blocks, Calcasieu Pass could reach its full LNG production capacity of 1.3 Bcf/d baseload (1.6 Bcf/d peak) by the third quarter of this year. On March 1, Calcasieu Pass loaded and shipped its first LNG cargo, often called a commissioning cargo, aboard the tanker Yiannis, chartered by JERA Global Markets, which delivered the LNG to ports in the Netherlands and France. Calcasieu Pass loaded its first cargo 30 months after its final investment decision, which was the shortest amount of time of all the LNG export projects in the United States. As of April 27, Calcasieu Pass has shipped nine cargoes, according to Bloomberg Finance, L.P.
LNG Demand Driving Williams' $1.5B Investment in Natural Gas Pipeline Expansions - Midstream giant Williams is spending about $1.5 billion to grow its natural gas transportation capacity by nearly 2 Bcf/d over the next few years to accommodate growing demand, particularly for exports, according to management. One of the six transmission projects the Tulsa-based midstreamer is developing is a 364 MMcf/d expansion on the Transcontinental Gas Pipe Line Co. (Transco) system, the country’s largest gas system. Williams management said Tuesday it has secured customer commitments for the Texas to Louisiana Energy Pathway Project to serve liquefied natural gas (LNG) demand. It is targeting an in-service for the expansion by the end of 2025. “As we look overseas to the energy crisis in Europe, we recognize the need for reliable, affordable and clean energy that can keep up with the growth that the world demands on a global scale,” CEO Alan Armstrong said. “Williams has critical infrastructure connected to the best natural gas basins in the United States to serve these growing needs.” Management cited ongoing demand for transportation capacity on the Transco system, not only for LNG but also power and industrial sectors. On the 1Q2022 earnings call, CFO John Porter said average daily transmission volumes for Transco increased by more than 6% year/year amid record winter demand. Transco revenues, he said, are driven by reserve capacity not throughput, “but continued growth in actual throughput does highlight the criticality of Transco service.” The higher gas price environment has done little to deter demand, according to Porter. “Admittedly, it has been somewhat surprising to us how inelastic this demand has remained.” Meanwhile, Williams last week closed on its acquisition of Quantum Energy Partners’ Trace Midstream. The purchase more than doubled its Haynesville Shale footprint to 4 Bcf/d-plus from 1.8 Bcf/d. As important, the deal included a long-term capacity commitment from a Trace customer to support the proposed Louisiana Energy Gateway (LEG). The project would move Haynesville supply to markets along Transco, as well as to growing industrial and LNG export demand along the Gulf Coast. Williams continues to see upside from its commodity price-exposed rates in the Haynesville, according to Porter. It also is seeing substantially higher volumes in the East Texas/Northwest Louisiana play, which drove an 11% overall increase in volumes in the company’s West segment. The company expects the strong sequential growth trajectory to continue throughout the rest of the year, especially in the second half, driven primarily by Haynesville drilling activity. Williams also is “close” to commercializing the LEG project, given “significant interest” by shippers. More than half of the 1.8 Bcf/d project is contracted, according to Armstrong. As part of the Trace acquisition, Quantum signed on to be an equity partner in the project.
Williams greenlights Transco expansion to move more gas from Texas to Louisiana - Williams plans to move forward with its Texas to Louisiana Energy Pathway natural gas expansion project after securing sufficient long-term transportation commitments, company executives said in a May 3 earnings call. The 364 MMcf/d expansion project on the Transcontinental Pipeline will primarily serve burgeoning LNG export demand along the Gulf Coast. Williams is anticipating the expansion to enter service in the fourth quarter of 2025. The Texas to Louisiana expansion project builds on Williams' strategy of growth through brownfield capacity expansions, especially on the Transco Pipeline. Expansion projects have surged in popularity in recent years, as midstream operators seek to increase capacity without having to navigate an increasingly tough permitting environment for newbuild pipelines. "We continue to set new records for contracted transmission capacity and expect this record-breaking performance to continue for many years to come as we execute on the six unique transmission expansion projects totaling 1.9 Bcf per day," CEO Alan Armstrong said. Four of the six transmission expansion projects are located on infrastructure in the Northeast, a region that flirted with production exceeding takeaway capacity in late 2021. Amid the expansion project announcements, Williams executives indicated that progress was being made toward a final investment decision on a potential greenfield pipeline, the Louisiana Energy Gateway, that would move up to 1.8 Bcf/d of Haynesville gas south to Gulf Coast LNG export terminals. "We are close to commercializing the Louisiana Energy Gateway project, and given significant interest by various shippers, we do expect to announce the final investment decision on that project soon," Armstrong said.
Gulf of Mexico oil drilling makes comeback, but won’t close supply gap — A new wave of oil platforms is sweeping into the U.S. Gulf of Mexico as crude prices are riding historic levels and demand for barrels is higher than ever. But don’t count on the new production to close the oil-supply gap that has plagued the world’s economies since the pandemic. Even with the new platforms coming online, Gulf oil production won’t grow substantially in the coming years as mature fields decline, according to analysts. BP Plc’s Argos and Shell Plc’s Vito — floating production platforms that are taller than 20-story buildings and have decks the size of football fields — will start pumping crude off the Louisiana shore later this year. They will join Murphy Oil Corp.’s King Quay, a behemoth that started producing oil in April, also off the Louisiana coast. Others from Chevron Corp., Shell and Beacon Offshore Energy are expected to start production in two years. Once all six platforms are online, they could produce up to 560,000 barrels a day. The timing for these new Gulf projects couldn’t be better. The offshore sector has been battered by back-to-back busts and a pandemic that forced mass layoffs and bankruptcies. But even with oil at $100 a barrel, a big comeback is unlikely. After a decade that saw one of the worst oil spills in U.S. history, shale’s ascendance and mounting climate-change concerns, some experts believe that the sun may be setting on the Gulf. “There’s probably some growth still left in the Gulf of Mexico, but it’s a more modest growth.” Last year, Shell said its global oil production had peaked in 2019 while BP in 2020 said it would cut oil and gas production worldwide 40% by 2030. Shell and BP are the two biggest Gulf producers. Since the first offshore rig was built off the coast of Louisiana in 1938, the Gulf of Mexico has been a reliable source of domestic oil. Its deep trove of reservoirs is responsible for about 14% of the U.S.’s crude production, second only to the country’s prolific shale fields. Gulf producers extracted 1.7 million barrels of oil per day in January, still shy of the pre-pandemic record of 2 million barrels a day. The U.S. Energy Information Administration expects Gulf output to remain flat through 2023, while S&P Global Commodity Insights projects production may recover to the pre-pandemic record by the end of the year. Energy consulting firm Wood Mackenzie is more bullish, forecasting crude and natural gas production this year could jump to the equivalent of 2.3 million oil barrels per day.
OTC 2022: Reaching net zero will require more investment in oil, gas and renewables - The pandemic had a unique impact on the energy industry and will pave the path of the energy transition on its way to net zero emissions, Society of Petroleum Engineers President Kamel Ben-Naceur said during a keynote presentation at the Offshore Technology Conference on Monday.The energy transition is looking more like a reality, as electric car sales jumped from 1 million to 2 million before 2018 to almost 7 million, or 9% of new cars sold, in 2021. Renewable power capacity continues to be added, and the industry is always learning about incentives of decarbonization, Ben-Nacuer said. He said recently, one ton of CO2 was valued at 100 Euros for the first time.There are a few different energy transition scenarios predicted by the International Energy Agency, and each one would bring different costs and results. For the first time, today’s pledges – if implemented on time and in full – would keep the rise in global average temperatures in 2100 to below 2 degrees Celsius, according to the presentation, but there’s still a large gap to 1.5 degrees Celsius.Decarbonization will require many combined factors to be successful, including avoided demand, CO2 capture and storage, hydrogen, bioenergy, technology performance, electrification, other renewables and other fuel shifts. But no matter the combination or policies, reaching the net zero emissions goal still requires more oil and gas investment, Ben-Nacuer said.
Permian natural gas outlet Whistler Pipeline to grow 25% with more compression | S&P Global Commodity Insights - Capacity of the Whistler Pipeline from the Waha header in the Permian Basin in West Texas to Agua Dulce in South Texas is slated to grow from 2.0 Bcf/d to 2.5 Bcf/d, with additional compression, operator MPLX said May 2 in announcing a final investment decision for the project. Three compressor stations are to be added, with in-service planned for September 2023. The additional compression would take Whistler to its maximum potential without building a new pipeline, MPLX said earlier this year. "The decision to move forward with this expansion project after securing sufficient commitments from shippers demonstrates our disciplined approach to investing," said Timothy J. Aydt, MPLX executive vice president and chief commercial officer. "Whistler has demonstrated its ability to provide reliable and cost-efficient residue gas transportation out of the Permian Basin, which is vital to our growing gas processing position, producers in the region and gas customers." The 450-mile, 42-inch diameter Whistler provides direct access to South Texas and export markets. An approximately 85-mile, 36-inch diameter lateral provides connectivity to the Midland Basin. Demand for Permian takeaway capacity is being driven by gas output associated with surging crude production, and the growing feedgas needs of LNG exporters. Restrictions on the flaring of associated gas also support future takeaway capacity demand from the Permian. With Permian producers eager to avoid the kind of basis blowouts that were commonplace before the most recent wave of intrastate pipelines came online in 2021, midstream companies have turned to brownfield expansion projects rather than proposing new pipelines. Expanding existing pipelines with established rights of way helps operators avoid the kind of permit-related delays that have plagued greenfield projects in recent years, adding a needed element of speed to the process. Analysis from S&P Global Commodity Insights estimates that current takeaway capacity is around 17 Bcf/d, which could be reached as early as the fourth quarter of 2023.
Are pipeline companies too powerful? Texas' unusual gas market faces fight over winter storm costs - As energy- and climate-related legislation passes through committees in the California legislature, some lawmakers are refusing to vote on bills critical to the state’s transition from fossil fuels.The 10 bills examined by Capital & Main would significantly expand California’s transmission infrastructure to deliver more electricity to homes and buildings, help the state bring more zero-carbon energy sources online and build more charging infrastructure for battery electric vehicles. These large-scale changes are essential to meeting the state’s emissions goals, which have been calibrated to limit global warming and stave off severe climate change. Combined, the 23 lawmakers who failed to approve legislation have taken more than $1.58 million from the oil and gas industry and its employees throughout their careers.Most are Republicans, but several are Democrats from oil- and gas-producing regions of the state. Those same areas, such as the San Joaquin Valley and Los Angeles’ South Bay, have some of the dirtiest air in the country, for which fossil fuel companies bear significant responsibility. In addition to making people sick, their wells and refineries warm the planet.Lawmakers’ obstructionism didn’t stop the legislation from advancing in the committees. But their mostly passive resistance could have an impact if the bills go to a floor vote.
Diamondback Holding Line on Permian Production – Despite High Prices, Demand - Permian Basin pure-play Diamondback Energy Inc. is not budging on plans to keep oil production flat this year, despite increased market tightness because of Russia’s invasion of Ukraine, said CEO Travis Stice.Diamondback “is committed to maintaining our current production levels, providing a significant supply of energy to our country and the world,” said Stice in presenting first quarter earnings. “While we believe that efficiently growing our production base is achievable over the long term, we do not feel that today is the appropriate time to begin spending dollars that would not equate to additional barrels until multiple quarters from today given the uncertainty and volatility currently in the market.”Midland, TX-based Diamondback operates in the Permian’s Midland and Delaware sub-basins, which have led recent growth in Lower 48 drilling and production. High oil and natural gas prices have benefitted producers, who nonetheless face numerous headaches.“Like many other industries, we are operating in a challenging environment,” Stice said. “We are seeing inflationary pressure across all facets of our business, with labor and materials shortages now present across the supply chain.” He added, “We are fortunate to have secured the necessary equipment, personnel and materials to run our capital program, but increasing activity today would result in capital efficiency degradation and would not meaningfully contribute to the global supply and demand imbalance in the oil market today.”As a result, “we are focused on maintaining our operational excellence and producing one of the lowest cost and environmentally friendly barrels in the world. By doing so, we expect to continue generating differentiated returns, hitting our production and capital targets and returning at least 50% of our free cash flow to our stockholders.”
Matador's Lower 48 Natural Gas, Oil Output Set to Climb 14% - Matador Resources Co., whose upstream operations span the Eagle Ford and Haynesville shales, as well as the Permian Basin, reported record production in the first quarter with plans to top that by the end of June. (matador asset map) “The first quarter of 2022 was another outstanding quarter both operationally and financially for Matador, highlighted by the successful completion of 26 gross operated wells with better-than-expected results,” said CEO Joseph Foran. The results mark the second straight quarterly production record for the Dallas-based independent. During the latest period, Matador completed and turned to sales 26.4 net wells in the Permian’s Delaware sub-basin. The producer has been focused on the Delaware, particularly in New Mexico. Average daily production volumes totaled 94,000 boe/d (57% oil), with the Delaware accounting for 89,400 boe/d (59% oil). There also was 2,800 boe/d from the gassy Haynesville and 1,800 boe/d (73% oil) from the Eagle Ford. Total average production for 1Q2022 was 8% higher than guidance. Its 2Q2022 guidance is about 107,000 boe/d, or a 14% sequential increase.
Lower 48 Oil Production Growth Forecasts Too Aggressive, Says Pioneer’s Sheffield - Projections of Lower 48 oil production growth this year are “way too high,” Pioneer Natural Resources Co. CEO Scott Sheffield said Thursday. Irving, TX-based Pioneer is among the largest producers in the Permian Basin, with operations focused on the Midland sub-basin. As evidence, Sheffield pointed to comments by oilfield services CEOs, including Halliburton Co.’s Jeff Miller and Helmerich & Payne Inc.’s John Lindsay, who indicated that drilling equipment was nearly sold out. Fracturing fleets “are pretty much used up,” particularly for the high-tech equipment, Sheffield told analysts during a conference call to discuss first quarter earnings. “The good-spec rigs are pretty much used up and you can always do newbuilds, but you’re going to pay significantly higher pricing, and you’re going to sign three-year type contracts. “So, I think in this world of returning capital to shareholders, I just don’t see that happening.” Due in part to the scarcity of equipment, production growth forecasts by the Energy Information Administration (EIA) and other prognosticators are “too aggressive over the next two years for U.S. oil production,” Sheffield said. EIA in its last Short-Term Energy Outlook forecast that U.S. oil output would rise by 800,000 b/d year/year in 2022 to average 12 million b/d, and by another 900,000 b/d in 2023. Pioneer, for its part, produced 637,756 boe/d during the first quarter, including 355,270 b/d oil, 152,929 b/d natural gas liquids (NGL) and 777 MMcf/d natural gas. These figures compare with 473,937 boe/d, 281,017 b/d, 105,675 b/d and 523.5 MMcf/d, respectively, in the year-ago period. Pioneer is sticking to its plans to cap annual production growth at 0-5% for the foreseeable future. The company is forecasting average production in 2022 of 623,000 to 648,000 boe/d, including 350,000-365,000 b/d oil, which would be essentially flat versus current levels. Sheffield said he does not expect natural gas takeaway constraints to be an issue in the coming months, citing recent announcements of planned capacity expansions. Pioneer has set an expected capital budget of $3.3-$3.6 billion for this year, to be fully funded by operating cash flow. The company expects to operate an average of 22-24 horizontal drilling rigs in the Permian Midland this year, and to place 475-505 wells on production. Pioneer is forecasting average drilled lateral length of 10,500 feet/well in 2022, which would be a 4% increase from 2021. The increase includes adding about 50 wells with 15,000-foot laterals to the 2022 program, management said. In 2023, this figure should double to about 100 wells, and reach “100 to 150 in future programs,” CFO Richard Dealy told analysts during the call. He estimated that 20-25% of Pioneer’s drilling program “will be those longer laterals for the foreseeable next five to seven years, probably.” The company also highlighted increases in its completed feet per day for its simultaneous fracturing (simul-frac) and zipper fleets. Pioneer’s completed feet per day increased by more than 20% in 2021 versus 2020, “with further increases expected in 2022,” management said. “Drilling longer laterals, reducing drilling days per well and completing more feet per day, among other operational efficiencies, continue to improve capital efficiency and is helping to mitigate cost inflation pressures being experienced by the industry,” management said. Dealy said Pioneer expects to feel cost inflation impacts most acutely this year in its purchases of steel, diesel fuel, drilling chemicals, “and to a much smaller extent,” fracturing sand. The CFO estimated that about 60% of Pioneer’s costs are locked in for the 2022 capital program, with the remainder subject to incremental inflation.
Continental Raising Capex, Output Guidance, Touts Oklahoma Natural Gas Gushers - Continental Resources Inc. has upwardly revised its 2022 forecast for capital spending, as well as oil and natural gas production, management said Thursday. Oklahoma City-based Continental is the top producer in the oily Bakken Shale and the gassy, liquids-rich Anadarko Basin. Following a pair of recent acquisitions, it also is the No. 2 leaseholder in the Powder River Basin and the No. 10 leaseholder in the Permian Basin. Continental’s updated capital program entails spending of $2.6-2.7 billion, up from previous guidance of $2.3 billion. The spending increase is expected to enhance the company’s return on capital employed and free cash flow versus previous projections, management said. Continental in late 2021 snapped up Pioneer Natural Resources Co.’s position in the Permian’s Delaware sub-basin in a deal valued at $3.25 billion. This followed a $215 million acquisition of 130,000 net acres in the oily Powder River Basin from Samson Resources II LLC. The new assets are showing “better than expected productivity, capital efficiency and resource potential,” COO Doug Lawler told analysts during a conference call to discuss first quarter earnings. Lawler joined Continental’s C-suite in January after serving as Chesapeake Energy Corp. CEO from 2013-2021. Continental reported average daily production of 373,810 boe/d during the first quarter, including 194,767 b/d oil and 1.07 Bcf/d natural gas. These figures compare to 307,942 boe/d, 151,852 b/d and 936 MMcf/d in the year-ago period. The Bakken led Continental’s quarterly oil and gas production at 171,401 boe/d, up from 160,577 boe/d in the first quarter of 2021. Anadarko output rose to 143,963 boe/d from 138,386 boe/d. In the Permian, production from the former Pioneer assets was 40,248 boe/d. Powder River Basin production grew to 11,653 boe/d from 2,464 boe/d in the year-ago period. Oil production is now expected to average 200,000-210,000 b/d in 2022, versus the prior forecast of 195,000-205,000 b/d. Continental expects to end the year producing about 220,000-230,000 b/d, management added. For natural gas, Continental has raised its annual production forecast to a range of 1.1-1.2 Bcf/d from 1.04-1.14 Bcf/d. The uptick in expected gas output is due to “strong early performance from our 2022 gas wells” in the South Central Oklahoma Oil Province (SCOOP) and Southern Trend of the Anadarko Basin, mostly in Canadian and Kingfisher Counties (STACK). The additional SCOOP and STACK volumes “are benefiting our free cash flow and return on capital employed,” Lawler said.
Enbridge, Nessel fight over Line 5 pipeline in holding pattern ⋆ Michigan Advance - When Democratic Gov. Gretchen Whitmer and Attorney General Dana Nessel took office in 2019, both having campaigned on decommissioning Enbridge’s Line 5, they ushered in a flurry of legal and regulatory battles over the embattled oil pipeline.Two federal lawsuits could determine the fate of the 69-year-old Canadian pipeline that transports oil under the tumultuous waters where Lakes Michigan and Huron connect.Two main questions have yet to be answered: Who will determine whether Line 5 as it currently exists will be decommissioned? If the state wins a favorable decision, the existing Line 5 will be shut down. If Enbridge wins, the pipeline will continue to operate for years until the planned construction of a new, tunnel-encased pipeline is completed, when/if that project is approved.What will happen to the “tunnel project,” which Enbridge is seeking immediate approval for but is facing pushback from environmentalists and tribal citizens?There are currently two active lawsuits awaiting a decision in federal court. Both are overseen by U.S. Judge Janet Neff in the U.S. District Court for the Western District of Michigan.With the help of Christopher Clark of Earthjustice, the Advance breaks down where things currently stand.
Enbridge’s Line 5 pipeline faces second shutdown risk in the Great Lakes after Indigenous band asks U.S. court for injunction - The Line 5 energy pipeline is facing another threat of shutdown: a Wisconsin Indigenous band has asked a U.S. court for a quick judgment on an application to evict the pipeline from its land. The Bad River Band of the Lake Superior Tribe of Chippewa, which filed its application earlier this year, is asking a U.S. federal court for a permanent injunction that would require owner Enbridge Inc. ENB-T to “cease operation of the pipeline and to safely decommission and remove it.” This latest risk to Line 5 is on top of an effort by Michigan Governor Gretchen Whitmer to cease the pipeline’s operations over fear of an oil spill in the Great Lakes. The Canadian government is trying to quash that attempt via negotiations with the United States. Enbridge’s 1,038-kilometre pipeline is a crucial energy source for Ontario and Quebec that transports up to 540,000 barrels of petroleum a day – mostly from Western Canada. It takes a route to Ontario through Wisconsin and Michigan before re-entering Canada at Sarnia, Ont. Enbridge spokesperson Jesse Semko said the risk to Line 5 from Wisconsin, like the Michigan shutdown effort, is contrary to a 1977 treaty between Canada and the U.S. intended to “ensure the uninterrupted transmission” of pipelines. If Ottawa wants to take up the matter with Washington, it would likely have to invoke the treaty again, as it did with Ms. Whitmer’s shutdown order, international trade lawyer Lawrence Herman said. Easements granted for Line 5 to cross the Bad River Band’s reservation have expired, and while Calgary-based Enbridge has proposed to reroute the pipeline around the land, the Indigenous group is not prepared to wait. The pipeline’s future was put in jeopardy in 2021, after Ms. Whitmer ordered it shut down over fears of a spill where it crosses the Straits of Mackinac waterway in her state. It remains in operation, and Canada and the U.S. are in negotiations over the matter after Ottawa invoked the 1977 bilateral treaty. The application for summary judgment in Wisconsin asks the court to rule on the Bad River Band’s lawsuit without a trial.
Aging pipelines, pipeline leaks, oil spills pose problems for Illinois -The cleanup continues from a recent oil spill in Edwardsville, but statistics serve as a reminder that it was far from an isolated incident. The spill was first reported on March 11 when the 165,000-gallon-spill was found coming from a Marathon Pipe Line buried near Cahokia Diversion Channel. Some of the spill reached the water, prompting a massive cleanup effort, including some oil-drenched wildlife. Officials have said it will likely take months to complete the entire cleanup of the area, and dump trucks were transporting dozens of loads of clean dirt to the site Tuesday. “There have been 432 combined incidents of pipeline spills in Missouri and Illinois just since 2020, and 72 of those incidents have resulted in spills of more than 1,000 gallons of crude oil. These numbers are obviously deeply concerning to the environment and to our communities,” said Hannah Lee Flath, a spokesperson for the Illinois Sierra Club. “Unfortunately, all pipelines are at risk for incidents like this and it’s because of the aging infrastructure and how hard it is to do safety checks. We don’t think that they are kept up to date enough in order to be safe and for us to have that security and peace of mind that incidents like this won’t happen in the future.” Virginia Woulfe-Beile is the Three Rivers Project Co-Coordinator for the Piasa Palisades Group of The Sierra Club, which is based out of Alton. Woulfe-Beile notes that the Metro East is a crossroads for pipelines, whether going across the country or going into local refineries. “In my mind, it has always been a matter of not if there may be pipeline leaks, but when, because these types of things do fail,” Woulfe-Beile said. “We need to make sure that this is kept to a minimum and that when pipelines are built, they are using the best material and that they are monitored and kept in good maintenance to prevent spills.” The oil spill resulted in a lawsuit against Marathon Pipe Line by Illinois Attorney General Kwame Raoul. Still, Woulfe-Beile said that many questions remain, including what effects the spill might have on agricultural land. “We all know how it came out into Cahokia Diversion Channel, but we don’t know much seeped into the ground and possibly into the groundwater,” Woulfe-Beile said. “Also, we want to make sure that Marathon is being held accountable and we want to know what regulators and authorities are doing to ensure that a future spill doesn’t end up in the Mississippi River, which could be devastating. “We have this huge confluence of rivers and our wetlands and the natural resources we have around here, and our job is to protect them and to hold folks accountable. We’re concerned about the long-lasting impacts of this (Marathon) oil spill and how the impact can be remediated.”
'This valve had been known to leak': Documents show Superior oil refinery knew about equipment issues years before 2018 explosion | Wisconsin Public Radio The blast injured workers and caused a mass evacuation. Investigators found no evidence key equipment had been inspected by the refinery for years. Most workers were on break when an explosion rocked the Superior oil refinery, then owned by Husky Energy Inc., four years ago. In interviews with investigators after the incident, operations manager Brian McCusker recalled hearing two loud blasts that shook the control room of the refinery’s fluid catalytic cracking unit. I saw asphalt leaking out of the asphalt tank across the road," said McCusker, according to documents from federal labor regulators obtained by Wisconsin Public Radio. The blast knocked workers to the ground, injuring 36 refinery workers and contractors. Two workers suffered serious injuries including a punctured lung and spinal fractures while others walked away with minor cuts and bruises. Debris from the explosion struck a nearby tank and asphalt spilled into the refinery, catching fire and creating a large plume of black smoke that could be seen for miles. Many of the city’s 27,000 residents were forced to evacuate due to the smoke and fears that a tank containing the highly toxic chemical hydrogen fluoride may be compromised. Parents waited in bumper-to-bumper traffic to pick up their kids who were bussed to a nearby evacuation site. While no chemical release occurred, evacuees stayed overnight in Duluth at hotels and a local convention center until authorities lifted the evacuation order the next morning.The Occupational Safety and Health Administration, or OSHA, previously fined the refinery more than $83,000 for failing to take steps to protect workers and prevent the incident. The company reached a nearly $70,000 settlement with the agency in 2018.Nearly 1,300 pages of documents from OSHA obtained by WPR shed new light on what refinery officials knew in the days leading up to the explosion. The documents also indicate the company was aware years earlier of issues with the very equipment investigators believe caused the explosion.These include problems with a critical valve malfunctioning days before the explosion and documented erosion on that key piece of equipment dating back to 2008. When the explosion happened on April 26, 2018, the refinery was shutting down its fluid catalytic cracking unit as it prepared for a five-week "turnaround," or a routine break in production conducted every five years by the refinery to perform maintenance. The unit uses heat and a sand-like catalyst to crack or break apart large hydrocarbons of crude oil into smaller molecules to make gasoline and other products. Calgary-based Cenovus Energy Inc., the refinery’s new owner, said officials have since taken steps to improve safety in their operations. Those actions will play a vital role in mitigating risks as the refinery will continue using hydrogen fluoride — which can be hazardous to human health if released — as part of its refining process to make gasoline.
The Permian Basin Oil Field Is Running Out of Workers, Materials—and Cash – WSJ - —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 U.S. Shale Patch Is Facing A Plethora Of Problems - There is a fairly blithe assumption in government circles that shale production can be raised at will. That assumption is about to be put to the test as the American shale drilling and fracking industry attempts to respond to the entreaties and outright demands of legislators, members of the administrative branch’s leadership, and even the president himself to put more capital toward increasing production. This is happening, but at a level and rate that will be insufficient to boost production significantly. In fact, data from the most recent publication of the Energy Information Agency’s Drilling Productivity Report-DPR indicates trouble could lie ahead. As the graph taken from EIA-DPR data reveals, the rig count is going steadily higher, but production from the eight major shale basins has leveled off and, as of Feb, 22, has actually slightly declined. If the May edition of the DPR confirms this trend then there is going to have to be a drastic reevaluation of what will be expected from shale in the future. One obvious cause of the decline is not directly related to the rig count, but in the decline of Drilled but Uncompleted-DUCs, wells being turned to production. Over the last couple of years, operators have cut the DUC inventory from ~8,500 to ~4,200. A year ago in an Oilprice article, I predicted this point would come. It has now arrived as operators have drastically curtailed the DUC withdrawal that was maintaining and increasing production over the past couple of years. There are multiple reasons for this situation and the primary ones will be discussed in the remainder of this article. Recently I attended an industry conference, where the Keynote speaker- Richard Spears, an industry analyst, and consultant, spoke about a key difficulty in forecasting in regard to estimating the likely year-end rig count. His point was that events occur and make prior forecasts seem ridiculous. His case in point was the invasion of Ukraine, which was on no one's radar...until it happened, and immediately made every forecast up to that point out of date. Almost ludicrously so. He then took a poll of the room as to where we thought the land rig count would end up for 2022. He threw out numbers starting with 800, about a hundred higher than where we are now, and we responded when he hit the number that matched our personal belief. Virtually every hand rose with 800, about half dropped at 900, half again at 1,000, and just a few at 1,100. One or two hands stayed up at 1,200 and he stopped there. He then gave us his number, 800. This surprised me as I was one of the 1,100 hands. His justification for that number didn't surprise me, as it involved capital restraint, lack of financing, and logistics impacts that are causing inflation in the oilfield. All things I have discussed in prior Oilprice articles. An article in the Wall Street Journal put a personal spin on this situation, as they quoted a small independent driller’s frustration with being able to secure needed materials. “If somebody walked in and put a pile of money on the table and said, ‘Drill me a well next week,’ it isn’t going to happen,” said Jamie Small, president of private-equity-backed oil producer Element Petroleum III. “You just can’t get the stuff to do it.”
U.S. oil producers increased capital expenditures and cash from operations in late 2021 – EIA - In response to higher crude oil prices, financial results for 42 U.S. exploration and production (E&P) companies showed large increases in both cash from operations and capital expenditures in the fourth quarter of 2021 (4Q21). Cash from operations for the E&P companies reached $27.5 billion in 4Q21, the largest amount in any quarter since 3Q14. Compared with 3Q21, capital expenditures increased 60% to $15 billion. However, despite higher capital spending and increasing crude oil prices, crude oil production by the E&P companies was still 10% below pre-pandemic levels.We base our analysis of the E&P sector on the published financial reports of 42 publicly traded U.S. oil companies. These companies do not necessarily represent the sector as a whole. In 4Q21, these 42 publicly traded companies collectively produced 3.8 million barrels per day of crude oil in the United States, or about 33% of total U.S. crude oil production.The West Texas Intermediate crude oil price averaged $77 per barrel (b) in 4Q21, an increase of $35/b (82%) compared with 4Q20. An increase in crude oil prices generally results in higher production, but production has not grown in response to higher crude oil prices.One constraint on well drilling and completions is the ability of oil field service companies to provide the needed rigs and crews to bring a well online. Published financial reports for 14 U.S. oil field service companies show that less cash from operations over the past two years has led to decreased capital expenditures compared with pre-pandemic levels, likely resulting in reduced operating capacity.According to U.S. Bureau of Labor Statistics data, employment in oil and natural gas extraction in March 2022 remained 8% below February 2020, its pre-pandemic value. Statements from oil field service companies during recent earnings calls suggest that inflationary pressures and industry shortages in labor and equipment continue to constrain operations.Another constraint on well completions is a declining inventory of drilled but uncompleted wells (DUCs). After drilling is finished, the well completion process involves casing, cementing, perforating, hydraulic fracturing, and other procedures required before crude oil production can begin from that well. After the crude oil price decline in 2020, E&P companies chose to complete wells at a faster rate than they drilled new wells.Completing more DUC wells kept operating costs low in the near term; however, production growth could slow if the number of newly drilled wells continues to remain lower than the number of completed wells. DUC inventories provide E&P companies with the flexibility to coordinate drilling and well completion to avoid operational delays, especially because of the long-term advanced booking that completion crews require. According to our April 2022Drilling Productivity Report, key U.S. oil-producing regions contained 3,423 DUCs in March 2022, the fewest number since May 2014.
Drilling for shale oil is getting more expensive at the worst possible time— Inflation in the oil sector is worsening and industry executives see no reason to expect cost pressures on everything from steel pipe to frac sand to ease any time soon. The price spiral has been so swift and dramatic that oil CEOs are being forced to revise annual spending plans higher just to preserve crude and natural gas output targets. Those same executives are warning that rampant oilfield inflation make any significant increase in domestic oil production much more difficult to attain despite the incentive of $100-a-barrel crude. Benchmark U.S. and international oil prices have surged more than 40% this year as strong post-pandemic demand crashed headlong into anemic growth in crude supplies and the worldwide market dislocations triggered by Russia’s invasion of Ukraine. “Given the substantial supply-chain bottlenecks and scarcity of oil-service equipment and field personnel, any attempt to increase activity in the U.S. will be logistically challenging and capital inefficient,” The inflationary trend has hit every corner of the oil exploration and production cycle. Drillers said they’re experiencing sticker shock on everything from rigs and workers to diesel fuel and frack sand. Shale giant Continental Resources Inc. said the price of steel tubes used to line the interior of oil wells jumped about 7% in the month of March alone. Meanwhile, another shale specialist, Coterra Energy Inc., noted that it can take as long as two years to take delivery of pipes, compressors and other production equipment. Both companies said their drilling and production costs are up 16% to 20% from last year. That represents an acceleration from earlier this year, when the sector was bracing for cost hikes in the 10% to 15% range.
Devon launches its own mobile sand mine to cut fracing costs— Devon Energy Corp., one of the biggest oil explorers in the Permian Basin, is getting into the sand business to combat rising costs. The Oklahoma City-based company told investors of a new, so-called mobile frack-sand mine it launched on 15,000 acres of land it owns in the West Texas county of Loving. The mine is expected to save the shale giant more than $200,000 per well amid rising sand prices and can account for as much as a quarter of its sand needs in the Delaware half of the Permian Basin, Chief Operating Officer Clay Gaspar said Tuesday on a conference call. “Sand is one of those things that nobody worries about until it’s an issue, and then it’s a major major issue,” Gaspar said. Mobile sand mines are starting to slowly grow within the industry, offering a smaller footprint compared to permanent mines and are closer to the well site. The sand is crammed in cracks of oil-soaked rock during production. Devon said it’s also looking at expanding the mobile sand mines to the areas it operates in Wyoming and Oklahoma.
GOP blocks 3 land bills over proposed mining, drilling bans - Republican senators said they would present a united front against any bill proposing to withdraw federal lands from mining and drilling. Three ambitious public lands bills with broad local support failed to advance yesterday as Senate Republicans sent a clear message to their Democratic colleagues that they will strongly oppose legislation that bans energy development and mining on federal land. Republican members at yesterday's Energy and Natural Resources Committee markup say they want the committee to approve legislation advancing critical minerals extraction and oil and gas development, and they vowed to continue a united front against any bill proposing to withdraw federal lands from mining and drilling until it does so. Thus, the committee yesterday deadlocked 10-10 along party lines on S. 173 , the "Colorado Outdoor Recreation and Economy (CORE) Act," sponsored by Colorado Democratic Sens. Michael Bennet and John Hickenlooper. It would extend varying levels of protection to more than 400,000 acres in the state, including banning oil and gas drilling in sections of the Thompson Divide. Bennet has championed the bill for years.
Biden officials plan large purchases to replenish oil reserve -The Department of Energy announced Wednesday it will solicit bids to buy 60 million barrels of oil to help start to replenish the record release from the Strategic Petroleum Reserve (SPR) that President Biden approved earlier this spring to address high gas prices. The bidding process will begin in the fall, with a goal of replenishing about one-third of the 180 million barrels released in response to the Russian invasion of Ukraine. The department said in a statement that it has timed the buyback and subsequent delivery for when it projects oil prices to have dropped significantly. It did not offer details on when delivery will take place. “The U.S. Strategic Petroleum Reserve, the largest emergency supply in the world, is a valuable tool to protect the American economy and consumers from supply disruptions — whether caused by emergencies at home or petro-dictators weaponizing access to energy resources,” Energy Secretary Jennifer Granholm said in a statement. “As we are thoughtful and methodical in the decision to drawdown from our emergency reserve, we must be similarly strategic in replenishing the supply so that it stands ready to deliver on its mission to provide relief when needed most,” she added. The department said it will take steps to loosen buyback regulations to allow competitive bidding rather than the usual index-pricing system used for SPR sales. The buyback is separate from revenue-raising SPR sales mandated by Congress, which the department predicted will total around 265 million barrels between fiscal 2023 and 2031. Biden in late March announced the biggest-ever release from the SPR — 180 million barrels over six months — to offset price spikes that began months before and were exacerbated by the war in Ukraine. Before that, the administration had announced smaller SPR releases of 30 million barrels in March and 50 million in November.
Marathon Petroleum ramps up Q2 rates to meet strong ULSD, gasoline demand -- Marathon Petroleum, the largest US refiner, is ramping up rates at its refineries, with expectations of reaching 95% capacity in the second quarter to meet the rising demand for both diesel and gasoline as the summer driving season looms. The company is deferring some planned work to capture the strong current spot market environment, "backloading" the company's 2022 turnaround work, according to Ray Brooks, Marathon's head of refining, on the May 3 results call. "With current demands, we are really seeking to maximize our refining system as indicated by the second-quarter guidance," Brooks said, adding, "what this really means...is that we've looked at some fixed bed catalyst changes that we had planned for [Q2]. We've determined we have a little bit as far as catalyst activity. So we've deferred that out later in the year. "We're working right now to maximize distillate production across our system. Just to give you a little more color on that, that's something that we look at daily, make sure that we're maximizing the total recoverable distillate, the endpoint, and maximizing the front end of the distillate," he said. Increased ULSD exports tighten the USAC market Marathon, like its peers, has been running in maximum distillate mode to take advantage of global rising diesel cracks from tight supplies and backwardation in distillate markets. The company's total exports averaged 200,000 b/d at the end of Q1 and have moved up to an average of 250,000 b/d and 300,000 b/d so far in Q2, with barrels moving primarily into Latin America, but with some barrels moving to Europe. Brian Partee, Marathon's head of clean products, said that increased distillate exports have tightened the US Atlantic Coast market, which is seeing lower European imports as well as lower flows up the Colonial Pipeline, the main conduit of refined products from the USGC refiners to New York Harbor. But this is a function of timing, and the "run-up in the prompt front end of the cycle," he said, allowing Marathon to capture current high diesel prices immediately through export rather than waiting for the time it takes diesel to move up the Colonial Pipeline.
U.S. distillate stocks fall critically low: Kemp - Chartbook: https://tmsnrt.rs/3KNYcVl (Reuters) - U.S. distillate fuel oil inventories have fallen to a 14-year low as refiners prove unable to satisfy strong demand from freight hauliers and manufacturers, sending diesel prices surging and pulling crude prices higher in their wake. Stocks have fallen in 60 of the last 96 weeks by a total of 69 million barrels since the start of July 2020, according to high-frequency data from the U.S. Energy Information Administration. The depletion has more than reversed a 49-million-barrel build-up during the first wave of the COVID epidemic and lockdowns in the second quarter of 2020. By last week, stocks had fallen to just 104 million barrels, the lowest since 2008 and before that 2005 (“Weekly petroleum status report”, EIA, May 4). Distillate stocks are now 31 million barrels, or 23% below the pre-pandemic five-year seasonal average for 2015-2019. Inventories are on course to fall even further to a projected low of just 102 million barrels before the middle of the year, with a possible range of 97 million to 105 million barrels, based on seasonal trends over the last decade. The projected inventory outlook has tightened since the start of April, when stocks were on course to fall to a low of 107 million barrels with a range of 96 million to 114 million. The resulting shortages of distillate are driving prices for both distillate itself and crude sharply higher and are bleeding across into shortages and higher prices for gasoline and jet fuel.Distillate is mostly used in road and rail freight, manufacturing, construction, farming, mining, and oil and gas extraction, so consumption is very sensitive to the business cycle. In this instance, shortages are a symptom of the strong rebound in economic activity following the pandemic and its bias towards fuel-hungry merchandise rather than services. Similar shortages have been observed in the late stages of previous business cycles, with stocks rebuilding once the economy enters a mid-cycle slowdown or an end-of-cycle recession. The long-term time series shows distillate stocks do not replenish themselves spontaneously; they only recover when the economy goes into a "soft patch" or a full-blown recession. At present, refiners in the United States and the rest of the world do not have enough capacity to satisfy the high level of demand. The shortage is likely to be intensified later in 2022 and 2023 as a result of U.S. and European Union sanctions on Russia's petroleum exports because Russia is a major supplier of distillate fuel oil.
Exxon, Chevron will spend more on stock returns than production — Exxon Mobil Corp. and Chevron Corp. will together give more cash to shareholders than they invest in oil and gas production this year even as political leaders call on the industry to increase output to help ease soaring consumer prices. The U.S. supermajors will shower investors with a combined $50.3 billion in stock buybacks and dividends this year, compared with $37.5 billion in total capital expenditures, according to data compiled by Bloomberg. That gap is the highest since Big Oil’s heyday in 2008. In fact, for 11 of the past 15 years, Exxon and Chevron have actually done the opposite: Their combined capital expenditures have exceeded shareholder returns. U.S. President Joe Biden has implored oil companies to reinvest profits from surging oil prices into more production in an effort to curb rampant inflation and ease the energy shortages caused by Russia’s war against Ukraine. Some U.S. Democrats as well as European leaders have gone further, accusing Big Oil of “profiteering” from high energy prices and calling for a windfall tax on earnings. “Consumers should not get punched in the face so that Big Oil can stuff its overflowing coffers,” said Robert Weissman, president of Public Citizen, a non-profit consumer advocacy group. Chevron is “very sensitive” to the needs of consumers, Chief Financial Officer Pierre Breber said on a Friday call with analysts. The oil giant is increasing production in the Permian Basin by at least 15% this year and has become much more efficient in recent years, meaning it can produce more oil with less capital spending than in the past. Chevron’s global production will be roughly flat this year but remains near a record high. “We’re growing energy supply in the U.S.,” Breber said. “At the same time, the objective for a capital-intensive commodity business is to do it in the most capital-efficient way. The more capital-efficient we are, the more capital gets returned to shareholders.” Exxon is plotting its own ramp up in the Permian Basin, with plans to grow output about 25% this year; it’s also accelerating offshore oil developments in Guyana. The Texas-based oil giant is also becoming more efficient due to $9 billion of cost cuts by 2023, enough to fund more than half its dividend. However, its first quarter production was just 3.7 million barrels a day, the lowest since the merger with Mobil more than two decades ago. When asked whether high energy prices could mean Exxon would increase capital spending above its guided range, Chief Executive Officer Darren Woods was blunt: “The short answer is no.”
Shale Explorers Boost Payouts Over Production - Shale drillers Diamondback Energy Inc., Devon Energy Corp. and Coterra Energy Inc. are boosting dividends while keeping oil output flat despite pleas from President Joe Biden to increase supplies and help take some the edge off of inflation. Diamondback announced a five-fold bump to quarterly payouts on Monday while Devon pledged to lift its dividend by 27% to a record $1.27 a share. Coterra also boosted distributions to shareholders. At the same time, all three shale specialists said they’re holding the line on crude and natural gas output. As oil and gas producers reap the fattest profits in years, corporate boards and management teams are grappling with pleas from politicians and consumer advocates to plow more of that cash into drilling so energy supplies expand and pump prices drop. Although Diamondback, Devon and Coterra are resisting that pressure, rivals including Exxon Mobil Corp., Continental Resources Inc. and Hess Corp. last week signaled they’re taking the brakes off of output. “Russia’s actions have increased the volatility in our sector, creating significant swings in commodity prices as a result of uncertainty around global oil supply,” Diamondback Chief Executive Officer Travis Stice said in a statement. “We do not feel that today is the appropriate time to begin spending dollars that would not equate to additional barrels until multiple quarters from today given the uncertainty and volatility currently in the market.” Diamondback, Devon and Coterra all posted stronger-than-expected first-quarter results on Monday. Diamondback raised its regularly quarterly payout by 17% to 70 cents a share, and declared a variable dividend of $2.35, bringing the total distribution to $3.05. Coterra lifted its combined regular and variable payout by 7% to 60 cents a share, payable on May 13.
U.S. shale’s cash bonanza is about to wipe out $300 billion loss— It may have taken an investor rebellion, a pandemic and a war in Europe, but U.S. shale oil and gas producers are now on the cusp of making back their losses from the last decade. The industry is on course to make $172 billion of free cash flow this year, enough to wipe out 60% of its losses from 2010 through 2019, according to Deloitte LLP. With smaller gains already chipping away at the $292 billion deficit in 2020 and 2021, U.S. shale should be back in the black next year. It’s been a long road. When small domestic oil and gas producers pioneered the combination of horizontal drilling and hydraulic fracturing in the 2000s, it seemed like a wealth of riches was imminent. But they were almost too successful, pumping so much that natural gas prices spiraled into a long-term decline through the 2010s. A surge in oil output followed, and OPEC allowed crude prices to collapse in 2014 in an attempt to win back market share from the U.S., which later overtook Saudi Arabia as the world’s biggest producer. Investors also got burned. Shale companies borrowed heavily to fund production growth, resulting in massively negative cash flow. Energy went from more than 16% of the S&P 500 Index in 2008 to 2% in 2020. All those trends have now reversed. Shareholders pushed shale to become more financially disciplined, while the pandemic forced executives to cut back on production and spending. Now, with the war in Ukraine causing oil prices to soar above $100 a barrel, the turnaround is almost complete. The industry is now leveraging the “short-cycled nature of shales to quickly monetize an opportunity, without giving away discipline,” said Amy Chronis, managing partner of Deloitte’s Houston office. “The recent oil and natural gas price surge has given the shale industry a shot in the arm.” Investors are taking notice. Nine of the 10 top-performing stocks in the S&P 500 this year are oil companies. Energy is now 4.4% of the S&P 500 Index, up from 2.7% at the beginning of the year.
Shale Giants Dump Oil Hedges -U.S. shale giants stung by billions of dollars in hedging losses are spending big bucks to ditch their positions in a risky bet that prices stay high. Companies including Pioneer Natural Resources Co. and EOG Resources Inc. are poised to post historic profits when they report earnings this week. But those windfall earnings would be even higher if it weren’t for massive accounting losses from hedges that protect against falling prices while limiting upside potential. Producers in the aggregate are looking at about $42 billion in oil and gas hedging losses through 2023, according to BloombergNEF calculations of data from last year. While such a hit won’t necessarily affect their balance sheets — instead representing money left on the table — the sheer scale of the miss has companies spending hundreds of millions of dollars to exit their positions. Hess Corp. in March paid $325 million to exit some of its hedges – more than twice what it cost to enter the contracts six months earlier. Pioneer, which reported $2 billion in hedging losses in 2021, spent $328 million to drop its hedges. And EOG, with $2.8 billion in hedging losses in the first-quarter alone, has paid $85 million. The moves could pay off big. For Pioneer, dropping the hedges could generate more than $1 billion of additional revenue this year, according to energy researcher Enverus. But it’s also risky. If oil prices fall and producers aren't hedged, they could be left with losses in the billions — and those won't be just on paper. That kind of blowback would likely unravel all the hard work companies have put into earning back investor trust over the last couple of years. And it could bring another rollback to oil production at a time when global markets are incredibly tight. “My main concern about unwinding hedges is that you had unrealized losses on hedges as prices go higher,” “If you take off those hedges and make them realized losses and then prices come down, then you lose twice.” Producers can lose money on hedges in a couple of ways. Companies using so-called collars to insure against a downturn will buy put options that allow them to sell their oil at a predetermined price. But to fund those puts, they simultaneously sell bullish call options that pay a premium while capping their exposure to higher prices. Those hedging with swaps can incur losses when prices rise above the fixed levels at which they are sold. Such strategies paid off during the pandemic-driven crash of 2020, but turned painful as recovering economies and Russia’s war in Ukraine lifted energy prices to historic highs. Some producers have capped upside prices at $30 below where oil is currently trading. Laredo Petroleum Inc. — which capped upside at an average of about $69 for 2022 — had about 73% of its crude output for this year covered by hedges, according to a March investor presentation. Losses, meanwhile, topped $400 million by the end of 2021, according to data from BNEF.
Oil Prices Top $111 As Biden’s SPR Buyback Plan Leaks -- The Biden Administration will purchase 60 million barrels of crude in Q3 in an effort to replace volumes in the U.S. strategic petroleum for the first time in nearly 20 years, CNN reports, after authorizing a record release over six months.Citing an unnamed Energy Department official, CNN said what is referred to as a “long-term buyback plan” for oil would be announced later on Thursday.Delivery of those first 60 million barrels, according to CNN, would be paid for with revenue received from sales of emergency oil, while the time frame is not specific beyond “future years”.Oil jumped to $111.5 per barrel for Brent–the highest price since late March–and over $108 for WTI on news of the buyback plan, along with results of an OPEC+ meeting earlier today in which the cartel refrained from increasing output quotes beyond 423,000 bpd for June.The full process for replenishing the SPR will take years.Bloombergcited UBS Group commodity analyst Giovanni Staunovo as saying that the market is now pricing in what amounts to U.S. plans to buy when the market is tight and inventories and spare capacity are low.On March 31st, U.S. President Joe Biden authorized the release of 1 million barrels of oil from the country’s strategic reserves per day for six months in a bid to bring down soaring oil prices as a result of Russia’s invasion of Ukraine.Over the next six months, the International Energy Agency (IEA) and the U.S. together are set to release a total of 240 million barrels of crude oil from their respective strategic reserves. During Thursday’s meeting, OPEC Secretary-General Mohammad Sanusi Barkindo said combined strategic reserve releases would mean that “the equivalent of over 1 mb/d for a period of eight months” would be “made available to the global market”.
Pipeline Operators Sued by the United States and North Dakota for Two Oil Spills - On Monday, the United States and North Dakota filed a complaint in the District of Montana against Bridger Pipeline LLC and Belle Fourche Pipeline Company alleging violations of the Clean Water Act (CWA) along with North Dakota state and federal law. According to the complaint, Bridger and Belle Fourche are Wyoming corporations that own and operate hundreds of miles of buried pipelines that gather and transport crude oil in Montana, North Dakota and Wyoming. The complaint also states that Bridger and Belle Fourche are affiliates and under the common control of the True Companies, a privately held conglomerate with operations focused on the oil and gas industry. Further, the complaint purports that Bridger owns and operates the Polar Pipeline, and Belle Fourche owns and operates the Bicentennial Pipeline. The plaintiffs allege that on January 17, 2015, the Polar Pipeline ruptured where it crosses the Yellowstone River, resulting in the discharge of approximately 1,257 barrels of crude oil into the Yellowstone River near Glendive, Montana. The Yellowstone spill allegedly resulted in oil sheens on the Yellowstone River which lasted for weeks and contamination of local drinking water. The complaint argues that the Yellowstone spill was a result of Bridger’s failure to conduct adequate risk analysis and was in violation of the CWA, Federal Pipeline Safety Regulations and North Dakota state law. Additionally, the complaint alleges that around December 1, 2016, the Bicentennial Pipeline ruptured resulting in the discharge of approximately 14,400 barrels of crude oil, including into Ash Coulee Creek, the Little Missouri River and their adjoining shorelines. The plaintiffs argue that the Ash Coulee spill was avoidable and was caused by Belle Fourche’s failure to address a known risk of slope failure, due to the hilly terrain the pipeline passed through, and to correct a miscalibrated flow meter at the bicentennial station. The plaintiffs further allege that Belle Fourche failed to immediately shutdown the Bicentennial Pipeline when it became aware of the spill causing further damage. Specifically, the complaint states that, despite clear discrepancies with the volume of crude oil at its pump stations caused by the rupture on December 1, Belle Fourche operated the Bicentennial Pipeline as usual until December 5, 2016. The complaint argues that the Ash Coulee spill resulted in the contamination of surface water, groundwater and soil at and near Ash Coulee Creek.
State, feds sue pipeline operator after 2016 spill leaked 600,000 gallons of oil in Billings County -The state of North Dakota and the federal government are suing a pipeline operator over a 600,000-gallon oil spill that contaminated the Little Missouri River and a tributary in 2016. The federal lawsuit filed against Belle Fourche Pipeline this week also names Bridger Pipeline as a defendant and raises allegations related to a 2015 oil spill in eastern Montana that affected the Yellowstone River. Both businesses are part of Wyoming-based True Companies. The suit seeks civil penalties related to the spills and reimbursement for nearly $100,000 the North Dakota Department of Environmental Quality has spent responding to the Belle Fourche spill. The total amount of civil penalties sought is unclear. A spokesman for Belle Fourche and Bridger said the companies are “very disappointed that the government decided to abandon settlement talks and file the lawsuit.” “We’ve been talking with them for a number of years and we believe we made good progress and ultimately believe we would have been able to reach a settlement,” spokesman Bill Salvin said. “Unfortunately, this takes that off the table.” Bridger last year reached a $2 million settlement with the federal government and Montana tied to the Yellowstone River spill, according to the U.S. Justice Department. The new lawsuit alleges violations of the federal Clean Water Act related to both spills, as well as violations of North Dakota law pertaining to the Belle Fourche spill.The pipeline segment where the spill occurred in Billings County “passes through hilly, unstable terrain, which is prone to failure and other mass movements,” according to the complaint. A landslide ruptured the pipeline, leaking 14,400 barrels of oil. A barrel holds 42 gallons. The spill reached Ash Coulee Creek, which is a tributary of the Little Missouri, as well as the river itself, contaminating water, soil and groundwater, according to court documents. Belle Fourche detected leaks by comparing the incoming volume of oil flowing through the pipeline to the outgoing volume based on data from a meter, the complaint says. A company “scheduler” receives daily information from Belle Fourche about volumes of oil shipped through the pipeline and on Dec. 3 noticed a discrepancy in the figures, reporting it to the company’s control room. A worker there reviewed recent pipeline data and spoke to a field employee, concluding that the discrepancy was the result of a miscalibrated meter and did not indicate a leak, the complaint alleges. While the miscalibration could explain a small discrepancy, it would not explain a major one, which “should have been apparent to Belle Fourche’s controllers” on Dec. 1, according to the government.
Natural Gas Futures Shoot Past $8 as Supply Concerns Mount – Mexico Spotlight - North American natural gas prices charged ahead this week amid worries over longer term supplies. In Mexico, meanwhile, natural gas demand is growing despite the higher prices. On Wednesday, the June New York Mercantile Exchange gas futures contract jumped 46.1 cents day/day and settled at $8.415/MMBtu. July rose 44.7 cents to $8.472.“U.S. production underwhelming, tight U.S. supplies, and hot conditions across Texas and surrounding states this weekend into early next week are viewed as the primary drivers of spiking natural gas prices this week,” NatGasWeather said.Mexico, meanwhile, continues to ramp up imports of natural gas as power demand rises with the hotter weather. “Mexico’s gas burns for power generation are starting strong in May,” Wood Mackenzie analyst Ricardo Falcón told NGI’s Mexico GPI. So far this month, power burns in Mexico are above 4.4 Bcf/d, up around 7% month/month. This is “already robust when compared to the 6% average of the preceding seven years for the same month/month period.”Power burns are driving pipeline imports from the United States, which are above 6 Bcf/d so far in May. NGI calculations had U.S. imports via pipeline into Mexico at 5.860 Bcf on Thursday. More than 75% of the gas arrived via South Texas.“Wood Mackenzie believes that there is room for additional growth in May, especially if Mexican dry gas output stays at the current level,” Falcón said. Mexico dry gas production fell by 11% in April to slightly below 2.5 Bcf/d. This month dry gas output in Mexico has been largely flat.Flat natural gas output across North America has been the general theme of ongoing earnings calls. Public exploration and production companies are set to shatter records this year in profits, but most of this money is being channeled back to shareholders, according to analysts at Rystad Energy.“Despite the robust growth in cash from operations, investments are not expected to grow significantly this year, inching up to $286 billion from $258 billion in 2021,” the analysts said in a note.In earnings calls, operators and midstream companies have added that demand isn’t being impacted despite the higher prices. U.S. natural gas transporter Williams CFO John Porter said this week that “it has been somewhat surprising to us how inelastic this demand has remained.”A natural gas shipper in Mexico City told NGI’s Mexico City GPI that “everything is the same despite the higher prices. We’ve seen some clients lower their consumption a little bit, but motivated more by the lack of other raw materials in their processes and not because of the price of gas.”Meanwhile, supply pressure in Europe continues to cast a shadow over energy markets. The European Union also appears on the verge of banning Russian oil imports, which could potentially lead to a reprisal from Russia, further squeezing the European natural gas market.
Europe Needs Natural Gas And America Could Help—If We Could Get Out Of Our Own Way – Forbes - Last week, Russia began enforcing its demand that European Union (EU) countries pay for Russian natural gas in rubles. Poland and Bulgaria were the first countries to have their Russian gas supplies halted, but they may not be the last: The European Commission reiterated that payments in rubles violate the economic sanctions placed on Russia. Now EU countries, which get on average 40% of their natural gas from Russia, are stuck between a rock and a hard place. Like Russia, the United States is a big producer of natural gas. Since Russia’s belligerent behavior and refusal to sell gas is hurting our European allies, it would be great if we could step in and provide some relief. This is a good idea in theory, but unfortunately our own policy decisions undermine it. As the figure below shows, America produces more natural gas than it uses, so exports to Europe are possible. In 2020, America produced 33.5 trillion cubic feet of natural gas and the top five natural gas producing states were Texas, Pennsylvania, Louisiana, Oklahoma, and West Virginia. In 2020, the United States was able to export 2.7 trillion cubic feet of natural gas. The EU uses about 45 billion cubic feet of natural gas per day and imports 80% of that. So even if we sent all our extra natural gas to Europe, it would only provide about 75 days’ worth of supply. But the amount of gas we produce is not carved in stone. Public policies, global demand, and technological improvements all influence the supply of natural gas. Global demand is outside of our control, but we can change our domestic policies to make it easier to both produce natural gas and incentivize investment in additional capacity. The Marcellus Shale rock formation primarily sits beneath Ohio, New York, Pennsylvania, West Virginia, and Maryland. It is the most productive shale formation in the country based on output, as shown in the figure below, providing around 25 billion cubic feet of gas per day. That is a lot of gas, but we could produce more if not for state and local bans on fracking. Maryland banned fracking in 2017 and New York’s legislature banned fracking in 2020, though former New York governor Andrew Cuomo essentially banned fracking back in 2014. New York used to produce a considerable amount of natural gas, producing 56 billion cubic feet in 2006. After Cuomo banned fracking production slowed, falling below 10 billion cubic feet by 2020. This decline occurred despite the fact that New York sits on 12 million acres of gas-rich Marcellus shale. More recently, in 2021, the Delaware River Basin Commission voted 4-0 to permanently ban fracking in the areas under its control. This includes seven northeast Pennsylvania counties that sit on top of Marcellus shale. So even though Pennsylvania allows fracking and is one of the country’s biggest producers of natural gas, these seven counties are now off limits. We can help our European allies quit Russian natural gas by producing more in America, but only if state and local governments revoke their regulations that prevent more production.
S Korea's SK Gas to buy supply from Energy Transfer's Lake Charles LNG - South Korea's SK Gas will buy 400,000 mt/year of supply from Energy Transfer's proposed Lake Charles LNG export facility in Louisiana under an 18-year deal announced by the US operator May 3. Some 5.1 million mt/year of the terminal's capacity has now been covered under long-term agreements, all of which were announced within the last month or so. Amid high spot prices in end-user markets, there has been a flurry of commercial activity during the first several months of 2022 tied to current and proposed US LNG export terminals, which offer long-term contracts with fixed fees and destination flexibility. The long-term deal with SK Gas Trading is on a free-on-board basis. The purchase price is indexed to the US Henry Hub benchmark plus a fixed liquefaction charge. First deliveries are expected to begin as early as 2026. The sale and purchase agreement will take effect upon Energy Transfer meeting certain conditions, including taking a final investment decision on the project. The other long-term supply deals tied to Lake Charles LNG are with Swiss commodity trader Gunvor, announced May 2, and with China's ENN and affiliates, announced March 29. Energy Transfer, which lost Shell as a joint venture partner in 2020, has proceeded with the development of Lake Charles LNG. Energy Transfer may reduce the size of the project to two trains with 11 million mt/year of LNG capacity, from three trains with 16.45 million mt/year of capacity, the company said in a US regulatory filing in February.
The U.S. Has Lost Its Position As The World’s Top LNG Exporter -After briefly surpassing Qatar and Australia as the world’s top LNG exporter, the United States lost the top slot to Qatar in April as volumes in the north dropped along with heating fuel demand, Bloomberg reports. Bloomberg data now shows that Qatar exported 7.5 million metric tons of LNG in April. American LNG production was somewhat reduced in April, Bloomberg notes, due to the end of the winter season and lower demand for heating fuel. With promises to help the European Union replace Russian gas and a new American export terminal due to come online soon, however, the U.S. could once again reclaim the top spot later in the year. In March, U.S. LNG exports rose 16%, according to Reuters. Soaring demand for U.S. LNG has now rebooted export projects that had previously languished, and the Biden administration has approved new export licenses for projects under development. Last week, the Biden administration authorized more LNG shipments from two U.S. plants under development. The move came as Russia cut off gas to Poland and Bulgaria for refusal to pay in roubles. One of those plants is Texas-based Golden Pass LNG, which is owned by Exxon and Qatar Petroleum and is expected to go online in 2025. The second is the Louisiana-based Magnolia LNG, owned by Glenfame Group LLC and expected to launch in 2027. Another factor adding to U.S. LNG exports in the coming months will be the ramp-up launch, on April 29, of the Louisiana-based Calcasieu Pass export terminal, which is the seventh export terminal to begin production in the United States since 2016. This terminal can turn around 3.1 billion cubic feet per day, according to the EIA, with two shipping berths that can load up to 185,000 cubic meters. Calcasieu shipped its first LNG on March 1st, and natural gas deliveries to the terminal have steadily increased since the beginning of the year. Three blocks are still awaiting approval at this plant, expected by year’s end.
BP Reports $20B Loss in 1Q Results - BP reported a loss of $20.4 billion, and an underlying replacement cost profit of $6.2 billion, in its first quarter 2022 results statement published on Tuesday. The reported loss for the quarter was primarily due to BP’s decision to exit its Rosneft shareholding and includes adjusting items before tax of $30.8 billion, BP outlined. This figure compared with a profit of $2.3 billion in the fourth quarter of 2021 and a profit of $4.6 billion in the first quarter of 2021. BP’s first quarter 2022 underlying replacement cost profit of $6.2 billion marked an increase from the $4.1 billion recorded in the previous quarter and the $2.6 billion recorded in the first quarter of last year. The 1Q 2022 underlying replacement cost profit was said to be driven by exceptional oil and gas trading, higher oil realizations and a stronger refining result, partly offset by the absence of Rosneft from the first quarter underlying result. BP reported an operating cash flow of $8.2 billion during the first quarter, compared to $6.1 billion in 4Q 2021 and 1Q 2021, and a surplus cash flow of $4.1 billion, compared to $2.9 billion in 4Q 2021 and $1.6 billion in 1Q 2021. The company’s net debt was said to have fallen to $27.5 billion at the end of the first quarter of 2022. This figure stood at $30.6 billion in 4Q 2021 and $33.3 billion in 1Q 2021. “In a quarter dominated by the tragic events in Ukraine and volatility in energy markets, BP’s focus has been on supplying the reliable energy our customers need,” BP’s chief executive officer Bernard Looney said in a company statement. “Our decision in February to exit our shareholding in Rosneft resulted in the material non-cash charges and headline loss we reported today. But it has not changed our strategy, our financial frame, or our expectations for shareholder distributions,” he added in the statement.
Oil is soaring. Will the majors stick with net zero? - Weeks after BP PLC declared it would go net zero in February 2020, oil prices plummeted to $18 a barrel because of the pandemic. Some analysts wondered if oil demand would ever recover, making it easier for other oil giants, like Equinor ASA and Shell PLC, to follow suit with net-zero plans of their own.Instead, the opposite has happened.Demand has come surging back to pre-pandemic levels, sending oil prices soaring to around $110 a barrel and offering a potential test of oil majors’ climate commitments. The clamor for oil has become more acute since Russia invaded Ukraine, with Western companies limiting purchases of Russian crude.It’s against that backdrop that the three European oil majors will report first-quarter earnings this week. Analysts expect all three — BP, Equinor and Shell — to boast substantial profits.The big question is what they plan to do with the money. Those companies have pursued a strategy of funneling investments to their best oil and gas fields, renewable projects and emerging technologies like hydrogen. BP and Shell explicitly pledged to gradually ratchet back oil production. One of the big questions entering this week is whether the majors unveil plans to increase oil production. Like many companies, the trio entered 2022 cautiously. Oil prices were already climbing at the start of the year, but companies were initially hesitant to increase investment in new drilling. Equinor initially targeted a 2 percent increase in production this year. BP predicted output would be flat while Shell said it expected production to fall in the first three months of the year.Shell, in particular, could face challenges ramping up production, Dewar noted. The company sold its assets in the Permian Basin, a Texas shale field, to ConocoPhillips for $9.5 billion last year (Climatewire, June 21, 2021).But so far, the European giants have focused on bolstering their balance sheets rather than drilling, paying down debt and funneling money to shareholders in the form of higher dividends, Russia will weigh heavily on BP and Shell. Both companies pulled out of the country after Russian President Vladmir Putin ordered his invasion of Ukraine. Exxon Mobil Corp. was able to post a $5.5 billion profit in the first quarter, despite writing off a $3.4 billion investment in its Sakhalin 1 operation in Russia.America’s oil majors have been reluctant to reduce oil output and embrace renewables, like their European counterparts, focusing instead on technologies like hydrogen and carbon capture and sequestration. A better preview of what to expect this week from the European giants could come from TotalEnergies SE, the French oil major.Total said last week it would deploy two additional gas rigs in the North Sea off Denmark, as part of a $15 billion budget for 2022. That was on the high end of what the company had initially forecast it would spend this year.But Total CEO Patrick Pouyanné dismissed the idea of an all-out drilling boom. “I don’t want to enter into the mistakes we have done on the previous supercycles where inflation costs rise and because any barrels might be profitable we’ll begin to drill anything,” he said.Instead, he said the company would focus on low-cost oil projects while continuing to pursue its strategy to achieve net zero by 2050.
As world demand increases, US natural gas production slows -As many countries look for new suppliers to end their dependence on Russian gas after Moscow's invasion of Ukraine, U.S. natural gas production growth has slowed. While the U.S. is already the world's largest producer of natural gas, and despite prices nearing a 14-year high, its two mainstays of production, the Appalachian region and West Texas, are seeing slower growth, with companies blaming a lack of adequate pipeline infrastructure. Since Russia invaded Ukraine on 24th February, U.S. gas prices have soared about 50 percent as European countries look to the U.S., the world's second largest exporter, to sell more liquefied natural gas (LNG). In Appalachia, which supplied about 37 percent of U.S. gas in 2021, growth has slowed because energy firms are finding it harder to build new pipes to move gas out of Pennsylvania, Ohio and West Virginia. With pipelines in the Permian Shale, the nation's second largest gas supply basin, which provides some 19 percent of U.S. gas in 2021 filling quickly, analysts said production growth in that Texas-New Mexico basin could slow significantly next year unless firms start building new pipelines soon. Energy analysts expect benchmark gas prices will average $4.24 per million British thermal units (mmBtu) in 2022, which would be the highest annual average in eight years. Pipeline construction has slowed, and output growth dropped to an average of 4 percent in 2020 and 2021. Analysts at Bank of America said Appalachia "is nearing takeaway capacity limits." One giant project, the Atlantic Coast pipeline, was canceled in 2020 after costs rose from an estimated $6.0 to $6.5 billion to $8 billion, while another long-delayed project, Equitrans Midstream Corp's $6.2 billion Mountain Valley line from West Virginia to Virginia has been delayed by ongoing lawsuits.
Europe Gas Slips as Mild Weather, LNG Offset Russia Risk for Now - -- European natural gas edged lower amid mild weather and an abundance of supply arriving by tankers from global suppliers. Dutch next-month futures fell as much as 3.1% for a fourth consecutive daily decline before paring some of those losses. Higher-than-usual temperatures are expected across most of western Europe. The region has also imported huge amounts of liquefied natural gas on the back of muted consumption in Asia. Still, traders remain on edge due to Russian President Vladimir Putin’s request for ruble payments for gas supplied in April. Moscow has already cut supplies to Poland and Bulgaria for failing to comply with its new mechanism, and more regional suppliers will face payment deadlines in coming weeks. Italian Prime Minister Mario Draghi said that setting up a ruble-denominated account to pay for Russian gas would be a breach of contract. “It’s very important that the EU Commission gives a clear legal opinion if payment in rubles is a violation of sanctions,” Draghi said at a press conference Monday. He urged clearer direction from the European Union as Italy is due to make payments in about two weeks, adding that the country will adhere to the EU’s guidance. Observed Russian flows transiting Ukraine and supplies via the Nord Stream pipeline were stable on Tuesday. Gas supplies to and from Germany via Russia’s Yamal-Europe link remained at zero despite capacity bookings, grid data show. Still, the EU is pushing ahead with efforts to line up alternative deliveries. The bloc will seek to step up cooperation with African countries to help replace imports of Russian gas and reduce dependence on Moscow by almost two-thirds this year. That mainly includes LNG from western African nations. Benchmark futures for next-month delivery declined 1.1% at 96 euros per megawatt-hour by 8:26 a.m. in Amsterdam.
East Med. gas could substitute only 20% of EU's Russian gas imports - Eastern Mediterranean natural gas resources could only substitute 20% of the EU's Russian gas imports at most if LNG facilities in Egypt work at full capacity and the proposed Turkiye-Israel pipeline is realized, according to Sohbet Karbuz, director of Hydrocarbons at the Mediterranean Observatory for Energy (OME). Karbuz said in an exclusive interview with Anadolu Agency that the only gas resources in the Eastern Mediterranean operational for exports are via two LNG facilities located in Egypt. These facilities broke a ten-year export record last year with a cumulative capacity of 19 billion cubic meters (bcm). If Israeli gas is brought into the equation over the next three to five years, Karbuz said Egypt could reach its full export capacity but this would only cover a 12% share of the EU’s demand. Furthermore, he argued that only an additional 10 bcm of gas could be exported under a best-case scenario from the Eastern Mediterranean in the next five to 10 years. With the EU target to cut two-thirds of its 155 bcm of annual Russian gas imports by the year-end and cutting all by 2027, he said it would be difficult to acquire replacement gas. 'This year's LNG imports from Egypt are projected to remain the same, and even if all these LNG cargoes are sent to Europe, this amount only equals 6% of the EU's total gas imports from Russia,' he warned. Assuming the proposed Turkiye-Israel pipeline is realized, he said it could only help the EU substitute only 20% of its Russian gas imports. “In short, Eastern Mediterranean gas cannot be an alternative to Russian gas. It only has a limited potential to substitute it,' he said.
Gas Prices Could Rocket in the Near Term - If Russia implements gas shutoffs to more countries unwilling to pay in Rubles, in addition to Poland and Bulgaria, prices could rocket in the near term. That’s according to Rystad Energy analyst Nikoline Bromander, who said many European energy ministers are actively exploring and discussing how to effectively phase out Russian oil and gas while keeping the lights on and avoiding a full-blown domestic energy crisis. “As these countries look for alternative sources of energy, any decrease in sales will negatively impact Gazprom’s income and could lead to operational issues,” Bromander said in a statement sent to Rigzone late Monday. “Russia will have to find a balance between reduced domestic production, domestic storage availability and diversity of pipeline exports,” Bromander added. To accept Putin’s terms, European buyers may make Dollars or Euro payments into an account at Russia’s Gazprombank, which is later converted into Rubles and transferred into a second account for the payment to be finalized, according to the Rystad analyst. “After Gazprom shut off gas to Bulgaria and Poland, many European countries could accept Putin’s payment terms in fear of suffering the same fate,” Bromander said. “For instance, gas distributors in Germany and Austria are currently working on ways to accept Putin’s demand for payment in Rubles,” the analyst added. “Not all countries have readily available alternatives to Russian gas, and as new and upgraded infrastructure requires considerable time and financial investment, many countries could struggle to replace a sudden drop in supply,” Bromander continued. Bromander outlined that Russian pipeline exports are stable after supplies to Poland and Bulgaria halted last week and added that the reversed flow from Germany to Poland is also stable. In a separate statement sent to Rigzone last week, Bromander and fellow Rystad analayst Kaushal Ramesh described the gas embargo on Poland and Bulgaria as Russia’s first shot back at the West. In her opening remarks at the press conference of the Extraordinary Energy Council on May 2, Kadri Simson, the European commissioner for energy, outlined that Gazprom’s decision to suspend gas supplies to Poland and Bulgaria marked “another turning point in the current crisis”. “It is an unjustified breach of existing contracts and a warning that any Member State could be next,” Kadri warned. “It is also an attempt to divide the EU, to which we must respond by reinforcing our unity and solidarity,” Kadri added. “The Commission has provided guidance to the Member States on the issue of payment in Rubles. We made clear that this is a unilateral change to contracts, unjustified by commercial reasons, and it is perfectly legitimate under commercial law to reject it. We have explained that payments in Rubles lead to a clear breach of sanctions, as they provide assets for the operations of the Central Bank,” Kadri continued.
Dutch dockers refuse to unload ship with Russian diesel cargo - Dutch dock workers are refusing to unload a tanker with a consignment of Russian diesel in the port of Amsterdam, a day after a similar action by dockers kept the ship from entering Rotterdam port.The Sunny Liger, a 42,000-tonne tanker was lying at anchor off Amsterdam on Saturday, while port companies were mulling her entry into the Dutch capital.On Friday, dock workers in Rotterdam also refused to handle her cargo.“Late last night we requested all parties in the port of Amsterdam not to let the ship dock and not to (handle) it,” the FNV trade union’s harbour worker branch chairwoman Asmae Hajjari said.“The ship will not enter the Amsterdam port,” she added in a tweet.The European Union has imposed a wide range of sanctions on Moscow since Russia’s invasion of Ukraine on February 24. However, oil and gas are not part of the punitive measures.Dockworkers in Sweden had already turned away the tanker, after which it set course for the Netherlands.“Russia is financing the war in Ukraine with the cargo,” the FNV union said in a statement thanking the Swedish workers for turning the ship away.Sailing from Primorsk near Russia’s St Petersburg a week ago, the Marshall-Islands-flagged tanker’s final destination was Amsterdam, according to the maritime website MarineTraffic.com.“At the moment the ship lies at anchor in the North Sea. So far it has not applied for permission to enter the harbour,” Port of Amsterdam spokeswoman Marcella Wesseling said.“In principle we cannot refuse her entry because she doesn’t fall under the sanctions regime (against Russia),” Wesseling told AFP.Wesseling said the ship could be allowed into port once it has made a formal request, but “only if it was safe for it to do so”.“If there is any doubt about this, we can decide otherwise,” Wesseling said.“The port’s nautical service providers and terminal have indicated that they have concerns about the safety surrounding the handling of this ship,” she stressed.A company responsible for towing the ship into port said it would decline if asked, saying it could lead to an unsafe situation if protesters want to block the ship from entering, the Dutch commercial news station RTL Nieuws reported.Dutch foreign minister Wopke Hoekstra said Friday legally the Sunny Liger could not be refused entry into a Dutch port, but that he supported the dock workers’ actions.
America Is the World's Largest Oil Producer. So Why Is Losing Russia's Oil Such a Big Deal? - The federal government does not claim any right to the oil or gas under private land. It has no policy tool to quickly increase or decrease drilling. During the first half of the 20th century, when America truly dominated the global oil industry, one government in the United States actually was able to set prices at the global level in the same way that the OPEC Plus cartel does today. But this happened, remarkably, at the state level. The Texas Railroad Commissionopened and closed the state’s formidable taps.Texas’s easy-to-reach resources have since dried up, so the commission no longer plays its price-setting role. Now Texas oil comes from modern horizontal fracking wells, which take six to eight months to produce their first drop of oil.That means, under the U.S. oil industry as it exists today, there is no way to spin up new oil production in a few weeks or months. But more important, it means that U.S. oil companies have developed the opposite of independence. Since Congress lifted the ban on oil exports in 2015, all American-drilled oil and some of our natural gas have been priced on the international market. Global market forces, not our abundance of domestic fossil fuels, set the price of oil and gasoline in the United States.This has exposed every fracking company to the volatility of the global oil market. Twice over the past decade, oil prices surged enough that frackers responded by drilling more wells and putting more oil on the global market. Each time, they drilled so much oil that prices crashed again, ruining their investment and driving a wave of consolidation in the industry. By far the worst of these bust cycles happened during the pandemic. Today, the U.S. fracking industry, which used to comprise hundreds of firms, has been whittled down to several dozen companies.The industry, which has twice betrayed its investors, now has financial PTSD. Fracking companies are so worried about shanking their investors that they have barely drilled new wells as prices have climbed. (Last week, as Russian oil fell off the global market, the number of fracking wells in the U.S. actually went down.) This new “capital discipline” has turned the industry into something of a cartel. Scott Sheffield, the head of Pioneer Natural Resources, the country’s biggest shale company, declared last year that no fracking company would drill a new well even if the price of oil went above $100 a barrel—which it has. “All the shareholders that I’ve talked to said that if anybody goes back to growth, they will punish those companies,” he said.This means that although America may be “energy independent” on paper, American consumers have won no benefits from this independence, and American officials cannot assert this independence in any meaningful way. Market dynamics, not overzealous regulations, have imprisoned the industry.That hasn’t stopped lobbyists from pretending otherwise. The American Petroleum Institute recently sent a policy wish list to the Department of Energy. The letter chides the White House for pursuing “false solutions” to the country’s high energy prices. It asks, for instance, that the Biden administration speed up several regulatory processes, such as a new five-year offshore-leasing plan. It implies that the government should loosen certain environmental regulations. Many of these ideas wouldn’t start to affect the oil market for several years. The API makes no estimate of how many thousands of barrels a day its members would produce, nor does it promise that these ideas would fill the gap left by Russian producers.
Russia raises crude exports via key routes despite lower output — Russia’s crude oil exports in the first 28 days of April jumped more than 17%, with hikes recorded for flows via all key pipelines and ports even as the nation’s production declined. The country exported an average of 4.66 million barrels a day over the period to its key markets via pipelines and port facilities operated by Transneft PJSC, according to Bloomberg calculations based on data from the Energy Ministry’s CDU-TEK unit. Deliveries via the nation’s ports jumped nearly 54%, compared with the prior month, while supplies via the Druzhba pipeline to Europe and the ESPO conduit to China grew 7.8%, the calculations show. The only direction where the flows dropped compared with the same period in March was the Druzhba pipeline leg toward Germany, according to the data. At the same time, Russia’s oil output fell to 38.4 million tons, or an average of 10.05 million barrels a day, according to Bloomberg calculations based on the data. That’s 8.7% below production in March and the lowest level for the nation since November 2020. Russia, which accounts for roughly 10% of global crude output, has faced an unprecedented wave of economic sanctions as western countries and their partners try to end the invasion of Ukraine by curbing the Kremlin’s revenues. The real impact of these overlapping measures has hard to gauge, with key statistics on production and overseas shipments pointing in different directions. That’s because the country’s refineries have been processing less crude as they lose overseas markets and domestic fuel demand drops, freeing up more crude for export. Some nations, such as the U.S. and the U.K., have announced outright bans on imports of Russian crude and oil products. The European Union is considering such restrictions, even though they could hurt the regional economy. As Western customers look elsewhere, Russia has been able to find new markets, notably in Asia, by offering its crude at deep discounts.
EU leans towards Russian oil ban by year-end, diplomats say - The European Union is leaning towards a ban on imports of Russian oil by the end of the year, two EU diplomats said, after talks between the European Commission and EU member states this weekend. The European Union is preparing a sixth package of sanctions against Russia over the invasion just over two months ago of Ukraine that Moscow calls a special military operation. The package is expected to target Russian oil, Russian and Belarusian banks, as well as more individuals and companies. The Commission, which is coordinating the EU response, held talks dubbed "confessionals" with small groups of EU countries and will aim to firm up its sanctions plan in time for a meeting of EU ambassadors in Brussels on Wednesday. EU energy ministers are also due to meet in the Belgian capital on Monday to discuss the issue. The EU diplomats said some EU countries were able to end their use of oil before the end of 2022, but others, particularly more southerly members, were concerned about the impact on prices. Germany, one of the bigger buyers of Russia oil, appeared to be willing to go along with the end-2022 cut-off, the diplomats said, but countries including Austria, Hungary, Italy and Slovakia still had reservations. Some EU countries have proposed opting for a cap on the price they are willing to pay for Russian oil. However, it would still leave them forced to pay higher prices for supplies from elsewhere.
The Coming EU Embargo of Russian Oil, Russia’s Economic Challenges, and the Question of Operational Capacity by Yves Smith - When the EU commits to a measure to undermine Russia that the US opposed as unproductive, one has to wonder when rationality and self interest left the room. The West is only beginning to suffer the cost of blowback from economic sanctions against Russia in terms of higher energy and food costs, which are soon to be followed by price increases and shortages of other commodities where Russia has significant market share. Yet the EU is launching an embargo of Russian oil, just after Poland, Bulgaria, and Finland have decided to cut themselves off from Russian gas, and Russia is also in a spat with Germany after Germany seized Gazprom’s operations there.The EU is set to provide more details about its scheme this week, so we’ll give only a high level discussion now.There is always the possibility that the EU program will be unexpectedly well thought out, particularly in terms of contingency planning, despite the idea only having been mentioned as a possibility at the start of March and getting more serious interest in early April.Our concern is the limited time to consider such a big change means there may be quite a few unknown unknowns. To give an idea of scale of study it takes to understand a system, it took a team of physicists 7 years to identify and map the physical inputs and outputs of Australia and deliver their findings in the early 2000s. And at least in Germany, and I suspect in other EU countries, energy rationing schemes have industry taking the cuts first, households last. In a world of extended supply chains and just-in-time manufacturing, which creates fragility and tight coupling, it’s all too easy to have energy-shortfall-induced problems at one company propagate to others in the same sector.Admittedly, the EU is not planning to wean itself fully off Russian oil until the end of the year, but that still seems aggressive.It’s even more difficult to judge the Russian side of the equation, but we’ll also briefly discuss the latest update by its central bank governor, Elvira Nabiullina, which we’ve embedded at the end of this post.
EU proposes gradual ban on Russian oil in sixth round of sanctions against Moscow - The European Commission, the executive arm of the EU, on Wednesday put forward new sanctions against the Kremlin, which will include a six-month phase out of Russian crude imports. Russia's unprovoked invasion of Ukraine, and evidence of war crimes, has pushed the European Union to take bolder steps on energy sanctions. But imposing measures that could reduce, or fully cut, Russian energy supplies to the EU has been a complicated task for the bloc. This is because the region is reliant on Russia for several sources of energy, including oil. In 2020, Russian oil imports accounted for about 25% of the bloc's crude purchases, according to the region's statistics office. "Let us be clear: it will not be easy," European Commission President Ursula von der Leyen said during a speech at the European Parliament on Wednesday. "Some member states are strongly dependent on Russian oil. But we simply have to work on it. We now propose a ban on Russian oil. This will be a complete import ban on all Russian oil, seaborne and pipeline, crude and refined." Oil prices were trading about 3% higher on Wednesday morning. Brent crude futures were at $108.30 a barrel in late-morning deals in Europe. The ban had been a highly controversial topic within the EU, but the move gained more momentum after Germany backed the idea. Two EU nations — Slovakia and Hungary which are both highly dependent on Russian energy — have been demanding exemptions. Von der Leyen chose not to give any details on exemptions during her speech, but three EU officials, who did not want to be named due to the sensitive nature of the issue, confirmed to CNBC that the commission's proposal includes this flexibility — giving Hungary and Slovakia a longer period of time to phase out Russian oil.
E.U.'s Russian oil ban could reduce global emissions - The European Union’s plan to phase out imports of Russian oil could have the added benefit of reducing the fossil-fuel-based emissions that are rapidly warming the planet. The proposed ban, announced yesterday as part of the E.U.’s latest sanctions package, is largely an attempt to further deprive the Kremlin of the revenue it’s using to fund its war in Ukraine. However, the move could also end up further reducing Russian production and incentivizing Europe to accelerate its move away from fossil fuels, according to energy experts. Much depends on what gets final approval as policymakers continue talks on the embargo. Under the proposal, imports of Russian crude oil to most of the E.U. would stop within six months, with refined products to follow by the end of the year. European Commission President Ursula von der Leyen said the phased-in embargo will allow Europe to secure alternative supplies of oil from outside Russia and minimize the impact on global oil markets. “Let us be clear, it will not be easy. Some member states are strongly dependent on Russian oil. But we simply have to work on it,” she said yesterday when announcing the package to the European Parliament. Hungary and Slovakia are pushing for an extra year to cut their imports, and opposition from them and other member states could lead policymakers to water down parts of the initial proposal, according to a note from Oslo, Norway-based research firm Rystad Energy. Part of what will come with an embargo is an element of forced demand reduction, since there’s not enough supply available elsewhere to make a one for one swap for Russian imports, said Abhiram Rajendran, head of oil markets research at Energy Intelligence and adjunct research scholar at Columbia University’s Center on Global Energy Policy. Russia’s oil production has already taken a hit due to a ban on imports by the U.S and United Kingdom, as well as some self-sanctioning by major traders and oil companies. The International Energy Agency’s latest oil report said Russian production had fallen by 700,000 barrels a day as of early April. Russian deliveries of oil imports to the E.U. fell by 20 percent in mid-April, compared to the period before Russia’s invasion of Ukraine, according to an analysis by the Centre for Research on Energy and Clean Air. At the same time, oil deliveries from Russia to destinations outside the E.U. grew by 20 percent. But shipments to those new destinations “are nowhere near enough to make up for the fall in exports to Europe,” CREA said in its latest research.. An E.U. embargo could deal a further blow by forcing Russia to permanently close some of its aging oil wells, said analysts. Rystad Energy estimates that an E.U. embargo could reduce Russian exports and upstream oil production by 2 million barrels of oil per day within six months. “So we are looking at the overall shrinking oil production capacity of Russia, which will likely lead to reduced emissions from the Russian oil and gas sector,” said Maria Pastukhova, a senior policy advisor for climate think tank E3G.
Lured by cheap oil, India becomes largest customer of Russian Urals crude - India emerged as the largest buyer of Russian Urals crude in April enticed by hefty discounts, as several of the grade's regular European customers have boycotted this oil following Russia's invasion of Ukraine. Urals has been trading at record-lows in recent weeks, with some deals being done at discount of almost $40/b to the Platts Dated Brent crude oil benchmark. Around a quarter of Russia's seaborne crude exports of the medium sour Urals in April is poised to travel to the South Asian country, according to trading sources and ship tracking data. Russia exported 627,000 b/d of Urals crude to India in April compared to according to 274,000 b/d and zero in March and February respectively, according to data from commodity intelligence firm Kpler. Seaborne Urals crude exports averaged 2.24 million b/d, its highest since May 2019, despite sanctions and boycotts by several of Europe's refiners, Kpler data showed. Until Russia's invasion of Ukraine, India very rarely bought Russian oil. But with Russian crude trading at record-lows in recent week weeks, Indian refiners have been unable to resist buying cheap crude despite pressure from Western governments. The medium sour grade Urals was assessed at its lowest level ever relative to Dated Brent at minus $39.40/b CIF Rotterdam on April 29, according to S&P Global Commodity Insights' Platts assessment. The price of Russian Urals CIF Rotterdam averaged $69.89/b in April, according to Platts data. This compares with a monthly average of $104.40/b for United Kingdom's Forties, which is similar in quality to Urals.
ExxonMobil Declares Force Majeure on Sakhalin-1, Writes Off $3.4 Billion in Q1 -- Exxon Mobil Corp. has declared force majeure on its Sakhalin-1 operations offshore Sakhalin Island in the Russian Far East, attributing its decision to a disruption in crude oil shipments and a subsequent slowdown in production following the West’s imposition of sanctions against Russia over the ongoing conflict in Ukraine.Exxon subsidiary Exxon Neftegaz Ltd. (ENL) operates Sakhalin-1 under a production-sharing agreement (PSA) in which it holds a 30% stake in partnership with the Japanese Consortium, Sakhalin Oil and Gas Development (SODECO), which holds another 30%; India’s ONGC Videsh Ltd. with 20%; and a further 20% held by Russia’s state-owned Rosneft.In its Q1 earnings call on 29 April, ExxonMobil announced that it had recorded a $3.4 billion charge related to its Sakhalin-1 investment, reflected as an unfavorable identified item which “mainly impacts the upstream segment.”The company estimated its Q1 earnings at $5.5 billion ($1.28 per share assuming dilution) and reported that the $3.4 billion charge related to its planned exit from Sakhalin represented $0.79 per share assuming dilution.Exxon’s chairman and CEO Darren Woods told investment analysts participating in the analysts call that Sakhalin-1 operations represented “less than 2% of our total production” in 2021, “about 65,000 oil equivalent barrels per day, and about 1% of our corporate operating earnings.”A poster child for world records in extended-reach drilling, Sakhalin-1 initiated oil production in 2005 and is today exporting about 273,000 B/D of light, sweet “Sokol” grade crude (a grade similar in quality to that produced in the US Permian Basin). South Korea is the principal buyer of Sokol along with some sales going to Japan, Australia, Thailand, and the US, according to Exxon.India’s ONGC Videsh told Reuters on 2 March that it did not see “any immediate impact” on Sakhalin-1’s operation when asked to comment after Exxon declared that same day its decision to exit about $4 billion in assets (including Sakhalin-1) and cease all of its Russian activities. In late March, another partner in the PSA, Japan Petroleum Exploration Co. (Japex) said, in unveiling its long-term business plan, that it planned to keep its stake in Sakhalin-1, Reuters reported at the time. Japex owns a 15.28% stake in the SODECO consortium.
BP to pay more than $65,000 over 2020 jet fuel spill in Adelaide's Port River - Petroleum giant BP will pay a $48,000 fine and other costs for spilling jet fuel into Adelaide's Port River in 2020. The UK-registered fuel company BP Shipping Limited has agreed to pay $65,319 to avoid prosecution by South Australia's Environment Protection Authority (EPA). The EPA said it received 16 complaints about the spill, with residents reporting health effects from the fumes. BP's payment includes a $48,000 civil penalty and more than $17,000 in technical expenses. The company will additionally pay almost $11,000 in legal costs, but the EPA conceded the fine had been reduced because of BP Shipping's "good compliance record". The fuel spill happened on February 29, 2020, when BP vessel British Engineer was moored at Largs Bay, transferring A-1 jet fuel to the onshore terminal owned by Mobil. A-1 fuel is variously described as kerosene-like and kerosene-based, and is among the most common fuels used in the global aviation industry. It is also regarded as toxic — according to BP's website, the fuel can "cause severe and potentially fatal" consequences if ingested. The 2020 spill occurred when a pressurised liquid chemical hose on the ship failed, sending an "unknown quantity of fuel onto the deck of the ship and into the Port River", the EPA said. It found the company did not take "all reasonable steps" to prevent the hose failure.
Thai, Malaysian oil companies pull out of Myanmar gas project - Thailand’s oil state-run oil company PTTEP and Malaysia’s Petronas have withdrawn from the Yetagun gas project, becoming the latest energy firms to pull out from Myanmar after a military coup in February 2021. “The withdrawal is part of the company portfolio management to refocus on projects that support the energy security for the country,” PTTEP chief executive Montri Rawanchaikul said in a statement late on Friday. PTTEP said its stake would be reallocated proportionately to the remaining shareholders with no commercial value, pending regulatory approval. The Thai company has a 19.3 percent stake in the Yetagun gas field in the waters of southern Myanmar. Carigali, a subsidiary of Petronas, owns 40.9 percent. The Myanmar public has a 20.5 percent stake, and the Japanese Nippon Oil has 19.3 percent. Petronas, operating the project since 2003, said the decision followed a review of the “asset rationalization strategy” to adapt to the “changing industrial environment and accelerated energy transition.” International energy companies like Chevron and Total pulled out of Myanmar after the military coup ended the fledgling Myanmar democracy. The companies denounced alleged human rights abuses committed by the coup junta. At least 1,803 people have died in the alleged brutal repression of Myanmar security forces on peaceful and unarmed protesters, nonprofit Assistance Association for Political Prisoners data showed.
Perenco shuts Gabon oil terminal after 300 000-barrel leak - Anglo-French oil company Perenco has shut its Cap Lopez oil terminal near Port Gentil in Gabon after a storage tank leaked more than 300 000 barrels of oil, it said in a statement. The oil, which amounts to more than Gabon’s daily crude output, leaked into retention tanks on Thursday and did not spill into the surrounding area, the company said. The cause of the spill was not yet clear and Perenco has opened an investigation. Reuters was unable to reach the site on Saturday. “A situation of force majeure has been declared, in order to secure the facilities and prevent any environmental damage,” the statement said. No marine pollution has been detected yet, it said. A spokesman said that it could take a few days to pump the oil back into the tanks. Gabon, in Central Africa, produces about 200 000 barrels of oil a day. Output from its mature fields have declined in recent decades, down from around 370 000 barrels a day in 1997.
Gunmen Storm Shell Owned Military Checkpoint in Nigeria --Gunmen in the Nigerian Bayelsa state stormed a military checkpoint owned by the Shell Petroleum Development Agency in three boats recently, according to Dryad Global’s latest Maritime Security Threat Advisory (MSTA) report, which was updated on May 2. One person died and one member of military personnel was injured during a gunfight, the MSTA outlined. Rigzone has asked Shell for comment on the incident but has not yet received a reply at the time of writing. Also in Nigeria, the country’s senate passed a bill imposing jail sentence of at least 15 years for paying a ransom fee for someone who has been kidnapped, and the act of kidnapping is now punishable by death, the MSTA highlighted. “It remains unclear how the new law will be enforced and how this would impact the payment of ransom by K&R insurance on behalf of the shipping companies,” the MSTA noted. Looking elsewhere, the MSTA pointed out that numerous European port workers and protestors across Europe have refused to unload Russian oil tankers. “Dutch dockworkers refused to unload a tanker carrying Russian oil after it was rejected entry to Swedish, Rotterdam, and Amsterdam ports,” the MSTA stated. “The European Union has thus far excluded oil and gas from its stringent sanctions on trade, however, it is set to propose a ban on Russian oil by the end of the year with restrictions on imports introduced gradually until then,” the MSTA added. “Nonetheless, there is an impetus amongst many European dock workers to refuse to unload the oil in a show of ‘international solidarity’ despite the absence of sanctions,” the MSTA continued. Dryad’s latest MSTA also noted that the force majeure at Marsa El Brega continues in Libya due to protests demanding Prime Minister Dbeibah step down. “On 1 May 2022, the NOC announced the ‘temporary lifting of the force majeure from the Zeuitina oil terminal’ in order to allow two tankers to load to allow for enough space to store the displaced volume of the crude oil,” the MSTA stated. “The concessions in addition to the resumptions of operations at El Sharara oil field signal the potential of the series of force majeures being lifted shortly,” the MSTA added. Dryad Global’s previous MSTA, which was updated on April 25, highlighted that an explosion at an illegal oil refining depot in the Nigerian Rivers state left more than 100 people dead. This MSTA also pointed out the refining effects of clashes between government-allied militias in Al-Zawiya and noted that reports indicated that Houthi Rebels had continued their attacks on the Marib government stronghold despite a truce.
Iran boosts oil exports as China cuts imports from Russia -Iran is boosting oil exports in the current year as major oil buyers like China are cutting back imports from Russia due to the war with Ukraine, the Wall Street Journal reported, citing data from commodity data provider Kpler. As reported, Iranian oil exports increased by 30 percent in the first quarter of 2022 compared to the previous year, to reach 870,000 barrels per day (bpd). The jump in Iran’s oil exports in Q1 was the fastest among all producers in West Asia, while the volume of exports is estimated to be the highest since former U.S. President Donald Trump withdrew from the so-called Iranian nuclear deal in 2018, the report said. China is a major buyer of Iranian crude oil which has never stopped shipping in the Islamic republic’s oil even during the sanctions. Now, the Asian country is emboldened to import more oil from Iran, not expecting to be hit by U.S. sanctions “because Washington has its plate full with Russia,” a Kpler analyst told the Journal. Earlier this month, Washington Free Beacon, an American conservative political journalism website, said in a report that Iran’s “fleet of ghost ships” has been successfully sidestepping U.S. sanctions, delivering millions of barrels of crude oil and petroleum products to foreign destinations. The report claimed that Iranian oil tankers have shipped at least $22 billion worth of oil only to China since 2021. According to Iranian President Ebrahim Raisi, the country’s oil exports have increased by 40 percent in recent months. Iran’s crude oil production in March reached 2.546 million bpd to register a 7,000-barrel increase compared to the figure for February, according to OPEC’s latest monthly report. The country produced 2.539 million bpd of crude oil in February, the report said citing secondary sources. The Islamic Republic’s average crude output for the first quarter of 2022 stood at 2.528 million bpd indicating a 56,000-bpd increase compared to the figure for the fourth quarter of the previous year, the report indicated. The country’s heavy crude oil price also increased by $19.36 in March, to register a 20.8 percent rise compared to the previous month, according to the OPEC report.
Iran's oil minister visits Venezuela, strengthening sanctioned OPEC members' alliance -Venezuela President Nicolas Maduro and Iranian petroleum minister Javad Owji met May 2 in Caracas, local media reported, deepening ties between the two OPEC members who have helped each other boost their vital crude oil production in defiance of US sanctions. Venezuela, which has had difficulty securing diluent required to produce its Orinoco oil due to the sanctions, has imported several cargoes of Iranian condensate since October to blend with its extra heavy crude, helping output rebound from historic lows. Little detail was given of the official business conducted, with Venezuela releasing no official details and Iran's oil and foreign ministries declining to confirm the trip. Owji and more than a dozen delegates arrived in Caracas on April 30 without prior announcement. According to local media, the delegation visited the Paraguana refining complex in western Venezuela with the president of state-owned PDVSA, Asdrubal Chavez, before Owji's meeting with Maduro at the Miraflores Palace. "A productive meeting to deepen the ties of brotherhood and cooperation in energy matters," Maduro said in a message posted on his social networks. Owji also met separately with Venezuelan counterpart Tarek el-Aissami, according to a televised report by Venezolana de Television, the state-owned broadcaster. "Caracas and Tehran reviewed the alliances they maintain in the OPEC Declaration of Cooperation, the opportunities for bilateral cooperation in the oil, gas and petrochemical sector, as well as in the multilateral," the Venezuelan petroleum ministry said on social networks. S&P Global Commodity Insights previously reported that seven 2 million barrel cargoes of Iranian condensate have arrived at the Jose terminal, one of Venezuela's main oil ports, located in the northeast. The shipments arrived in September, October, November, January, February, March and April, and have helped Iran clear some of the volumes it had accumulated in floating storage as it has struggled to find buyers. Venezuela has used the condensate to produce its extra heavy Merey 16 crude, some of which it has shipped to Iran to sell, under their deal.
Libya losing $60 million a day in oil installations shutdown - Libya is losing tens of millions of dollars a day from the shutdown of its oil facilities, while global prices are at their highest in years, the country’s oil minister said. Oil is the lifeblood of the North African country trying to move past a decade of conflict since the fall of ruler Muammar Gadhafi in a 2011 NATO-backed uprising. But since mid-April, Libya’s two major export terminals and several oil fields have been held hostage to the country’s latest political schism. “Production has fallen by about 600,000 barrels a day,” half the prior level, Oil and Gas Minister Mohammed Aoun said in an interview with AFP at his office in Tripoli. “Calculating the sale price at $100 a barrel, losses are at least $60 million daily,” he said. Since Russia began its invasion of Ukraine in February, triggering Western sanctions, global crude prices have reached levels unseen since 2014. On Friday, the US benchmark West Texas Intermediate crude traded above $106 per barrel. The price of Brent crude exceeded $109 a barrel. The Libyan closures follow the selection in February of a new prime minister, Fathi Bashagha, by Libya’s eastern-based parliament in a direct challenge to Tripoli-based interim Prime Minister Abdulhamid Dbeibah. Analysts say eastern Libyan forces who back Bashagha have forced the closure of the oil facilities in a bid to press Dbeibah to step down, but the incumbent insists he will only hand power to an elected successor. The political bloc supporting Bashagha is aligned with Libya’s eastern-based Libyan national army commander, Field Marshal Khalifa Haftar, who in 2019-20 led a failed offensive against Tripoli, when his forces also blockaded oilfields. Haftar’s external backers include Russia, which belongs to the OPEC+ crude producers’ group.
IRAQ DATA: Federal oil exports rise 4% in April amid higher OPEC+ quota -Iraq's federal oil exports, excluding flows from the semi-autonomous Kurdistan region, rose 4.2% month on month in April, oil ministry data showed May 1, amid a higher OPEC+ quota. Total federal exports reached 3.380 million b/d in April, compared with 3.244 million b/d in March, according to ministry data. In March, federal oil exports had fallen 2.1%. Exports from southern oil terminals stood at 3.270 million b/d in April, up 2.3% from a month earlier. Exports of Kirkuk crude via the Turkish port of Ceyhan more than doubled to 99,702 b/d. Iraq's OPEC+ quota rose to 4.414 million b/d in April from 4.370 million b/d in March as the group continued to relax oil output curbs. Iraq is likely unable to increase oil exports in response to the surge in global oil prices and Russia-related supply disruptions, Deputy Prime Minister Ali Allawi said April 19 during a visit to Washington, exacerbating the ability of OPEC+ to boost its output to compensate for production shortages that have helped lift prices near record highs.OPEC+ approved on March 31 another modest oil production increase, saying it saw no need to respond to oil disruptions from the Ukraine war being waged by Russia. The OPEC+ agreement called on the 23-country producer alliance to boost output by 432,000 b/d in May. Under the deal, quotas for some countries were amended in line with production baseline changes agreed last July for Saudi Arabia, Russia, Iraq, the UAE and Kuwait that reflect their higher spare capacity. OPEC+ ministers are due to meet May 5 to decide on June production levels.
As of 2021, China imports more liquefied natural gas than any other country - In 2021, China imported more liquefied natural gas (LNG) than any other country, according to data from Global Trade Tracker and China’s General Administration of Customs. Prior to 2021, Japan had been the world’s largest LNG importer for decades, according to data from Cedigaz.China’s LNG imports averaged 10.5 billion cubic feet per day (Bcf/d), a 19% increase compared with 2020. LNG imports accounted for more than half of China’s overall natural gas imports and 30% of China’s total natural gas supply in 2021.China began importing LNG in 2006 and, with the exception of 2015, has imported more LNG each year since then. China has rapidly expanded its LNG import capacity, which was estimated at 13.9 Bcf/d in 2021. By the end of 2022, China’s regasification capacity could increase by 2.8 Bcf/d to 16.7 Bcf/d, according to data by S&P Global Platts. In 2021, China imported LNG from 25 countries. The largest six suppliers—Australia, United States, Qatar, Malaysia, Indonesia, and Russia—provided 8.9 Bcf/d, or 85%, of China’s total LNG imports.Since China lowered tariffs on LNG imports from the United States from 25% to 10% in 2019, U.S. LNG exports to China have increased and in 2021 averaged 1.2 Bcf/d. The United States was the largest supplier of spot LNG volumes to China last year. During 2022 and 2023, several new long-term contracts between China and the United States are expected to start from the Sabine Pass and Corpus Christi terminals for a combined estimated volume of up to 0.5 Bcf/d. The new U.S. LNG export terminal at Calcasieu Pass will supply China’s two national energy companies—Sinopec with 0.13 Bcf/d and CNOOC with 0.2 Bcf/d—starting next year.
China flips to selling LNG export cargoes as pandemic curbs dent demand -- China, the world’s largest LNG importer, has become a seller of LNG export cargoes as domestic demand wanes amid pandemic movement curbs in Shanghai and fears of similar restrictions being imposed elsewhere in the country as authorities move decisively to stem the spread of COVID-19. “Except for the big three national oil companies – PetroChina, Sinopec and CNOOC– which have an obligation to ensure natural gas supply, others LNG importers were heard to have resold many of their LNG imports recently,” a trade source with an LNG terminal in south China told S&P Global Commodity Insights. LNG terminals were still profiting from selling long-term LNG cargoes in the domestic market, but reselling LNG cargoes in the international market was proving more profitable, the source said. A trade source with one of the top three state-owned oil majors said it was considering diverting some summer LNG supplies to other places where prices were higher. “China’s demand for natural gas, especially for LNG, is expected to slow down this year,” he said. This comes as an COVID-19 outbreak in Beijing has sparked fears of a Shanghai-style lockdown there. Mass testing for COVID-19 has also been ordered in several other major cities such as Hangzhou and Guangzhou, adding to concerns of further restrictions. “Not only spot LNG cargoes, but also those term contract volumes with destination flexibility are expected to be resold to other places where prices are higher this year,” a third trade source said.
China processed record amounts of crude oil in 2021 but exported less gasoline and diesel --China processed record amounts of crude oil in 2021 to meet rising domestic consumption of petroleum products. In the second half of the year, China processed slightly less crude oil and began exporting significantly less gasoline and diesel than in the first half of the year to ensure sufficient domestic supply.According to China’s National Bureau of Statistics, China processed a record 14 million barrels per day (b/d) of crude oil in 2021, a 4.6% increase from 2020. Crude oil processing in China was particularly high in the first half of 2021, in response to high demand both domestically and elsewhere in Asia. Despite more refinery capacity, crude oil processing decreased by 0.4 million b/d in the second half of 2021 compared with the first half.Beginning in August 2021, several COVID-19 outbreaks in China led to mobility restrictions, which in turn reduced domestic demand for petroleum products. Mobility restrictions during the Winter Olympics and COVID-19 travel restrictions that began in March 2022 in several parts of China continued to reduce demand for petroleum products in China at the beginning of this year. China’s crude oil processing has also declined because relatively high crude oil prices are making importing crude oil more expensive.In addition, China’s refiners met their petroleum product export quotas in the first half of the year. They were not granted a second batch of export quotas until August, and those quotas were relatively low. These quotas set the maximum amounts of each product that refiners can export and are disseminated on a rolling basis.China’s exports of diesel and gasoline ended 2021 at lower levels than at the beginning of the year. Low petroleum product exports have continued into 2022 because China’s first batch of export quotas in 2022 were 56% lowerthan its first batch in 2021. Because of these quotas, in February 2022, China exported the lowest amount of diesel since early 2015.
Oil prices drop amid data showing weak growth in China - Oil prices fell on Monday, pushed by slow economic growth concerns in China, the world's biggest oil importer, due to Covid-19 pandemic. International benchmark Brent crude cost $103.34 per barrel at 1230 GMT for a 3.55% loss after closing the previous session at $107.14 a barrel. American benchmark West Texas Intermediate (WTI) traded at $100.71 per barrel at the same time for a 3.80% drop after the previous session closed at $104.69 a barrel. Factory activity in China contracted for a second month to its lowest since February 2020 due to Covid-19 quarantine measures, data released on Saturday showed. As the cases of Kovid-19 continue to increase in China, the authorities are trying to control the situation through lockdowns and isolation. Experts believe the government's strict zero-Covid strategy is putting a strain on the economy. Meanwhile, Libya's National Oil Corp said on Sunday it would temporarily resume operations at the Zueitina oil terminal, which was offline since mid-April. Low fuel demand in China and additional supply from Libya offset global supply concerns and relieved pressure on oil prices.
June WTI Futures Bounce Off $100 on OPEC+ Supply Shortfall - Reversing morning losses, oil futures powered higher in afternoon trade Monday, sending the U.S. crude benchmark above $105 per barrel (bbl) on the back of a growing supply shortfall among Organization of the Petroleum Exporting Countries and ten allied producers outside the cartel that are expected to approve this week another 432,000-barrel-per-day (bpd) production increase for next month despite the potential for deeper output losses in Russia -- OPEC+'s second largest oil producer. Monday saw another session of volatile trading triggered by reports suggesting OPEC continues to badly underperform production quotas with the shortfall growing to 200,000 bpd last month, meaning the cartel was only able to raise output a little over 40,000 bpd. That does not include a production target of 200,000-bpd allocated for 10 producers outside the cartel-led by Russia, with preliminary data showing production from Russia and Kazakhstan was sharply depressed last month. In a month-on-month comparison, Russia's oil production in the first 19 days of April was 8.2% lower than the March average, reaching around 10.11 million bpd. It could further fall to 8.74 million bpd or 17% by the end of the year as Western traders and bankers shun dealing with Russian oil, according to the country's finance minister, Anton Siluanov. The International Energy Agency forecast that almost 3 million bpd in Russian production would be turned off starting in May. Against this backdrop, OPEC+ ministers are set to wave through the predetermined production increase in June on Thursday (5/5), with Saudi Arabia and United Arab Emirates, two countries with the spare capacity to increase their output to cover shortfalls, seeing no need to further expand their production. OPEC+ cited market uncertainty tied to China's oil demand and the extent of production losses in Russia as the reason for maintaining their gradual monthly production increase, according to reports. China's refusal to abandon its zero-COVID policy that entails strict containment measures is fanning fears over what is viewed as a looming recession in the world's second largest economy. Beijing has begun the process of school closures along with mandatory COVID-testing for 21 million residents. In Shanghai, a city of 25 million people, authorities continue to resort to extreme lockdown measures. Analysts estimate that at least 20% of China's oil demand has been wiped out during March and April as lockdowns proliferated. In financial markets, U.S. dollar index drifted higher in afternoon trade Monday, hitting an intrasession high of 103.775, just shy of last week's 103.950 -- a level not seen in twenty years, as investors fled to the safety of safe-haven currencies. Dollar strength is making it more expensive for overseas buyers to purchase dollar-denominated commodities such as oil. Greenback's strength comes ahead of U.S. central bank's monetary policy meeting scheduled for Tuesday and Wednesday, which is expected to see Federal Reserve officials hike borrowing costs by 0.5%, which would be the biggest rate hike since 2000, with several more increases in the federal funds rate projected before the end of the year. On the session, NYMEX West Texas Intermediate futures for June delivery gained $0.48 to settle at $105.17 bbl, and the international crude benchmark July Brent contract advanced $0.44 bbl to $107.58 bbl. NYMEX June RBOB rallied 6.77 cents to $3.35101 gallon, and the front-month ULSD contract surged 18.77 cents to a $4.2049 gallon settlement.the Consumer Credit Report for March was released by the Fed on Friday of this week, and it showed that overall consumer credit, a measure of non-real estate debt, grew by a seasonally adjusted $52.4 billion, or at a 14.0% annual rate, as non-revolving credit expanded at a 7.4% annual rate to $3,441.5 billion, while revolving credit outstanding grew at a 35.3% rate to $1,097.5 billion, the largest jump since January 2006...
Oil Slides as China Lockdowns Outweigh Proposed EU Russia Oil Ban (Reuters) -Oil prices fell by more than 2% on Tuesday as demand worries stemming from China's prolonged COVID-19 lockdowns outweighed the prospect of a European embargo on Russian crude. Beijing is mass-testing residents to avert a lockdown similar to Shanghai's over the past month. The capital's restaurants were closed for dining in while some apartment blocks were sealed shut. Brent crude settled down $2.61, or 2.4%, at $104.97 a barrel. U.S. West Texas Intermediate (WTI) crude ended $2.76, or 2.6%, lower at $102.41. "There are real concerns about whether Chinese demand, which is a huge factor in global demand, will remain strong in 2022," said Gary Cunningham, director at Tradition Energy. Prices remain high, however, with Brent crude having reached $139 in March for its highest since 2008 after Russia's invasion of Ukraine exacerbated supply concerns that were already driving a rally. The European Union is working on a sixth round of sanctions against Russia, with officials saying that European Commission President Ursula von der Leyen is expected to spell out the plans on Wednesday, including a ban on imports of Russian oil by the end of this year. Price action is likely to remain volatile as traders weigh the impact of China's lockdowns against the West's oil sanctions and ahead of a U.S. Federal Reserve meeting on Wednesday. "We have a market that's in flux and reacting from headline to headline in a very choppy trading range," Also in focus will be the latest round of U.S. inventory and supply reports. Nine analysts polled by Reuters estimated on average that crude inventories decreased by 800,000 barrels last week.
WTI Slides 2% Ahead of Stock Data, Fed's Call on Rates -- Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange accelerated losses in afternoon trade Tuesday, with the West Texas Intermediate contract falling more than 2%. The losses came as investors positioned ahead of the weekly release of U.S. inventory data and the likelihood for the biggest interest rate hike from the U.S. Federal Reserve since at least 2000, which has the potential to slow anticipated gains in summer oil demand. Fanning concerns over a sharp slowdown of the U.S. economy, manufacturing data for April showed business activity unexpectedly dropped to the lowest level since May 2020, strangled by rattled supply chains and employment challenges. Measures of both new orders and production decelerated to 1-1/2-year lows yet remained above the threshold that indicates growth. "Demand registered slower month-over-month growth likely due to extended lead times and decades-high material price increases and consumption softening amid labor force constraints," said Timothy R. Fiore, chair of the Institute for Supply Management Manufacturing Business Survey Committee. Further evidence of economic slowdown could be found in U.S. first-quarter GDP data, showing a sharp deceleration of growth during the first three months of the year, down to a negative 1.4% compared to 6.9% recorded in the final months of 2021. Against this backdrop, the U.S. Federal Reserve Open Market Committee is poised to decide Wednesday on the largest interest rate hike in the U.S. since at least 2000 to slow the record surge in consumer prices. Nearly 100% of investors expect FOMC to raise interest rates by 50-baisis points Wednesday, followed by similar increases in June and July, according to CME Fed WatchTool. Some analysts forecast the FOMC could even announce a 0.75% increase this summer as it battles a record surge in inflation. Such a move, however, could lead to recessionary pressures in the U.S. economy. Tuesday's lower settlements also follow reports that some members of the European Union seek exemptions from any potential ban on Russian oil imports, which is expected to be part of a sixth sanctions package against Moscow for its invasion of Ukraine. Hungary and Slovakia Tuesday morning reiterated their opposition to such a move, claiming it would be economically impossible for them to exit from Russian energy trade. At settlement, NYMEX West Texas Intermediate futures for June delivery fell $2.76 to $102.41 per bbl, and the international crude benchmark July Brent contract declined $2.61 to $104.97 per bbl. NYMEX June RBOB eased 0.89 cent to $3.5012 per gallon, and the front-month ULSD contract plunged 12.22 cents to $4.0827 per gallon.
Oil prices jump 3% as EU plans ban on Russian oil | The Straits Times - Oil prices jumped on Wednesday (May 4) as the European Union, the world’s largest trading bloc, spelt out plans to phase out imports of Russian oil, offsetting demand worries in top importer China. Brent crude futures rose US$2.94, or 2.8 per cent, to US$107.91 a barrel by 3.46pm Singapore time amid thin trading volume, with China and Japan closed for holidays. West Texas Intermediate crude futures rose US$3.02, or 3 per cent, to US$105.43 a barrel. European Commission president Ursula von der Leyen on Wednesday proposed a phased oil embargo on Russia over its war in Ukraine, as well as sanctioning Russia’s top bank, in a bid to deepen Moscow’s isolation. The Commission’s measures include phasing out supplies of Russian crude within six months and refined products by the end of 2022, Ms von der Leyen said. She also pledged to minimise the impact on European economies. European energy prices jumped after the announcement as a ban, if agreed by EU governments, could boost demand for natural gas and coal while prompting Moscow to retaliate. Benchmark gas futures for delivery next month surged as much as 7.4 per cent to €106.75 per megawatt-hour (MWh), while the equivalent British contract soared 9.8 per cent. German power for next year, a European benchmark, gained 5.4 per cent to €216 per MWh by 10.15am local time. Europe relies on Russia for about 25 per cent of its oil and about a third of its gas needs. The proposed EU sanctions, which also include cutting off more banks from the international Swift payment system, add to concern about energy supplies just a week after Gazprom gas halted shipments to Poland and Bulgaria due to a dispute over payment terms. “Our central scenario envisions more interruptions of Russian gas supplies to Europe going forward,” said Mr Mark Haefele, chief investment officer at UBS Global Wealth Management. “Some of the targeted countries may experience economic stagnation or mild contractions in the process.” He does not expect a complete halt in all Russian gas supplies to Europe.
Oil Rallies After Rate Hike and Looming Russian Oil Embargo -- Nearby-month delivery oil futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange accelerated gains in afternoon trade Wednesday, sending both crude benchmarks as much as 5% higher. The moves came after the U.S. Federal Reserve raised interest rates by 50 basis points -- the most since 2000 -- to quell surging inflation that stands to undermine demand growth domestically and globally at a time when the European Union moved to phase-out Russian imports of oil and refined products.European Commission on Wednesday finalized a sixth package of economic sanctions against Russia for its invasion of Ukraine. In a major policy shift, the majority of the EU member-states agreed to phase-out Russian oil imports in measured steps that would require a six-month transitional period for crude oil and a 12-month period for petroleum products, including gasoline and diesel fuel.Hungary and Slovakia are the only two members of the 27 EU countries that were granted an extended period until the end of 2023 due to their high dependency on Russian energy supplies. "We see no plan or guarantees in the current proposal to manage even a transition period nor what would guarantee Hungary's energy security," said Zoltan Kovacs, a spokesman for the Hungarian government. Acknowledging the risks, German Economy Minister Robert Habeck said that he cannot guarantee that regional supplies will not be disrupted but believes the EU transitional period is adequate. In financial markets, U.S. Federal Open Market Committee on Wednesday approved a rare 0.5% increase in overnight borrowing costs, bringing the central bank's benchmark federal funds rate to a target range between 0.75% and 1%. This marked the most aggressive monetary policy tightening in decades, which is aimed at rapidly reducing the pandemic-era stimulus that has contributed to rising price pressures across the U.S. economy. FOMC, which usually lifts interest rates in 0.25% increments, last raised rates by 0.5% in 2000. In a statement released Wednesday afternoon, FOMC said it "anticipates that ongoing increases in the target range will be appropriate," setting the stage for another large rate hike at the Fed's meeting next month on June 14-15. Further supporting the oil complex, U.S. Energy Information Administration inventory report on Wednesday revealed a much larger-than-expected drop in domestic fuel stocks as demand gasoline and diesel picked up in recent weeks. Distillate stocks currently stand at the lowest level in over 14 years and some 22% below the five-year average at 104.9 million barrels (bbl).EIA said domestic refiners processed 15.5 million bpd of crude oil during the final week of April, 218,000 bpd lower compared with the previous week's processing rate. The refining capacity utilization rate unexpectedly fell 1.9% from the previous week to 88.4% compared with consensus among analysts for a 0.4% increase. U.S. commercial crude stockpiles rose by 1.3 million bbl to 415.7 million bbl and are now about 15% below the five-year average. Analysts expected crude stockpiles would fall by 200,000 bbl from the prior week. Oil stored at Cushing, Oklahoma, the delivery point for U.S. stocks, increased 1.4 million bbl from the previous week to 28.8 million bbl. U.S. crude oil production remained unchanged at 11.9 million bpd. At settlement, NYMEX West Texas Intermediate futures for June delivery advanced more than $5 to $107.81 per bbl, and the international crude benchmark July Brent contract topped $110 bbl, up $5.17. NYMEX June RBOB rallied 15.11 cents to a $3.6523-per-gallon settlement, and the June ULSD contract spiked 11.43 cents to $4.1970 per gallon.
OPEC+ forecasts oil surplus as high prices and lockdowns bite into demand expectations - OPEC+ anticipates oil supply to exceed demand later this year by nearly two million barrels per day, ahead of an expected meeting tomorrow between ministers from the group’s member states. The expanded cartel is forecasting weaker oil demand growth, amid rising inflation from soaring crude oil prices, the resurgence of the Omicron variant across China and market disruption caused by Russia’s invasion of Ukraine. The company, which consists of the Organisation of the Petroleum Exporting Countries (OPEC) and multiple allies including Russia, has downgraded its expectations for world oil demand from 4.15m barrels per day to 3.67m, a 480,000 daily drop on its previous forecasts. The forecasts were made in an internal report seen by news agency Reuters, which expects supply to exceed demand by 1.9m barrels this year, which is also 600,000 – higher than previous estimates. It also predicts OECD oil stocks slightly exceeding the 2015-2019 average in the fourth quarter. The report was prepared ahead of a meeting of the OPEC+ Joint Technical Committee meeting taking place later today. Despite the drop in demand, OPEC+ is set to agree another small increase in production targets for June, even as Russian sanctions bite into the country’s output. Under a deal reached in July last year, OPEC+ has been targeting increases of 432,000 bpd every month until the end of September, to unwind its remaining production cuts. However, the organisation has persistently failed to reach raised production targets this year, with multiple members failing to hit hiked production quotas amid capacity issues and concerns over future supply gluts leaving them exposed. The OPEC+ meeting later this week follows the European Union proposing a phased oil embargo on Russia, as part of its six package of sanctions following the invasion of Ukraine. Russia’s own forecasts showed output may fall by as much as 17 per cent in 2022, according to an economy ministry document seen by Reuters. The document suggests Russian oil output may decline to between 433.8m and 475.3m tonnes – equivalent to between 8.68m and 9.5m barrels per day – in 2022, from 524m tonnes in 2021.
OPEC+ maintains modest hike in oil production as EU weighs up Russian import ban - OPEC+ has agreed a modest increase in its oil production targets next month, following a meeting earlier today, despite Western pressure to significantly ramp up supplies. The organisation, which consists of the Organization of Petroleum Exporting Countries and allies including Russia, has committed to boosting output by a further 432,000 barrels per day. This is in line with existing, gradual plans to unwind curbs made in 2020 when the pandemic hammered global demand expectations. The group has consistently ignored Western calls to significantly speed up increases of oil production with requests from both US President Joe Biden and the Prime Minister Boris Johnson falling on deaf ears. However, OPEC+ has also persistently failed to reach its own raised output targets since the start of the year, with multiple members missing pledged increased production quotas. This is a consequence of capacity issues, alongside fears of both a supply glut and antagonising key member Russia – with the bloc committed to neutrality following the invasion of Ukraine. Two sources present at the meeting told news agency Reuters that delegates completely avoided any discussion about sanctions on Russia, wrapping up talks in near record time of just under 15 minutes. These factors have contributed to supply shortages and elevated concerns of disruption this year, helping to drive oil prices above the $100 milestone across both major benchmarks. Following multiple rallies, which saw Brent Crude prices peak at a 14-year high of $139 per barrel in March, the International Energy Agency agreed last month to release record volumes of oil stocks to help to cool prices and offset supply disruptions from Russia. The pledged flooding of the market with 240m barrels caused prices to drop significantly, while lockdowns in China have continued to weigh down prices in recent weeks. However, the prospect of fresh rallies is increasingly plausible, with the European Union (EU) leaning towards phasing out Russian oil imports over the next six months. This will be a key feature in a sixth package of sanctions against Russia, as it ramps up pressure on the country following its invasion of Ukraine. “Re-routing Russian output from Europe to willing buyers in Asia, in the presence of sanctions, is already so challenging that even Russia has admitted its production will decline significantly. This problem will likely get worse. This leaves EU members competing with other consumers for the remaining available supply.” He also suggested that OPEC+ “continues to view this as a problem of the West’s own making”, rather than as a fundamental supply issue that it should respond to.
Oil Prices Top $111 As Biden’s SPR Buyback Plan Leaks -- The Biden Administration will purchase 60 million barrels of crude in Q3 in an effort to replace volumes in the U.S. strategic petroleum for the first time in nearly 20 years, CNN reports, after authorizing a record release over six months.Citing an unnamed Energy Department official, CNN said what is referred to as a “long-term buyback plan” for oil would be announced later on Thursday.Delivery of those first 60 million barrels, according to CNN, would be paid for with revenue received from sales of emergency oil, while the time frame is not specific beyond “future years”.Oil jumped to $111.5 per barrel for Brent–the highest price since late March–and over $108 for WTI on news of the buyback plan, along with results of an OPEC+ meeting earlier today in which the cartel refrained from increasing output quotes beyond 423,000 bpd for June.The full process for replenishing the SPR will take years.Bloombergcited UBS Group commodity analyst Giovanni Staunovo as saying that the market is now pricing in what amounts to U.S. plans to buy when the market is tight and inventories and spare capacity are low.On March 31st, U.S. President Joe Biden authorized the release of 1 million barrels of oil from the country’s strategic reserves per day for six months in a bid to bring down soaring oil prices as a result of Russia’s invasion of Ukraine.
Oil steadies near $110/bbl; strong dollar offsets supply worry - Oil prices steadied on Thursday, under pressure from a stronger dollar and a drop in global stock markets while supported by supply worries after the European Union (EU) laid out plans for new sanctions against Russia including an embargo on crude. Brent futures added 76 cents to settle at $110.90 per barrel. U.S. West Texas Intermediate (WTI) crude settled 45 cents higher at $108.26 per barrel. The U.S. dollar rebounded to its highest since December 2002, a day after the Federal Reserve affirmed it would take aggressive steps to combat inflation. A strong dollar makes oil more expensive for holders of other currencies. Wall Street stocks tumbled as investors shed risky investments, worried the Fed might hike rates more this year to tame inflation. The EU sanctions proposal, which needs unanimous backing from the 27 countries in the bloc, includes phasing out imports of Russian refined products by the end of 2022 and a ban on all shipping and insurance services for transporting Russian oil. "The oil market has not fully priced in the potential of an EU oil embargo, so higher crude prices are to be expected in the summer months if it's voted into law," Japan said it would face difficulties in immediately cutting off Russian oil imports. The Organization of the Petroleum Exporting Countries, Russia and allied producers (OPEC+) agreed to another modest monthly oil output increase. Ignoring calls from Western nations to hike output more, OPEC+ agreed to raise June production by 432,000 barrels per day, in line with its plan to unwind curbs made when the pandemic hammered demand. A U.S. Senate panel advanced a bill that could expose OPEC+ to lawsuits for collusion on boosting oil prices. Congress has failed to pass versions of the legislation for more than two decades, but lawmakers are worried about rising inflation and high gasoline prices. Prices for near-term Brent and WTI oil futures are much more expensive than for future months, a situation known as backwardation. as futures for both benchmarks through April 2023 were in "super-backwardation" with each future month at least $1 a barrel below the prior month. Yawger said that situation could change as the U.S. government buys crude to replenish strategic crude reserves.
WTI Pares Gains amid Equities Rout as Market Rethinks Fed- While ULSD futures declined, West Texas Intermediate and the gasoline contract on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange settled Thursday's session with modest gains that were limited by a selloff in the U.S. equity market as investors reassessed comments from U.S. Federal Reserve Chairman Jerome Powell as more hawkish, as Powell on Wednesday indicated the central bank is prepared to introduce more aggressive interest rate hikes to quell inflation but risk tilting the U.S. economy into recession. Stocks on Wall Street suffered their worst day of the year on Thursday, sending Dow Jones Industrials as much as 1,315 points or 3.9% lower and S&P 500 down 5.9%. Thursday's selloff appears to have been triggered by concerns over potential recession amid an aggressive path of interest rate hikes by the Federal Reserve after the central bank raised interest rates by 50 basis points on Wednesday. "What's happening right now is exactly what the Federal Reserve wants to happen. They want a weaker stock market. They want higher bond yields," said former New York Federal Reserve President Bill Dudley. Faced with a red-hot jobs market and very high inflation, Powell has conceded that financial conditions must be tightened, meaning lower stock market valuations and more expensive credit for companies with weak balance sheets. On the economic data front, initial jobless claims for the final week of April jumped to a more than two-month high 200,000 but still remained consistent with tightening labor market conditions, according to economists. The Labor Department's Job Openings and Labor Turnover Survey this week showed there were a record 11.5 million job openings on the last day of March. Meantime, a series high 4.5 million Americans quit their jobs in March, with data dating back to 2000. Underlining Thursday's rally in oil markets, Organization of the Petroleum Exporting Countries and Russia-led partners agreed on a planned production increase of 432,000 barrels per day (bpd) for June, sticking to a Moscow-backed agreement reached in July 2021 to return production shut-in during the early days of the pandemic in small, incremental steps. The decision comes despite repeated calls in recent months from the United States and other oil-consuming nations for the coalition to tap into remaining spare capacity in Saudi Arabia and the United Arab Emirates -- two producers that can still rapidly increase output to offset a supply deficit on the global market. Russian crude production has already fallen more than 1 million bpd since the invasion of Ukraine on Feb. 24 in response to reduced demand for its oil overseas and in the domestic market. Of the 10.1 million bpd of crude oil that Russia produced in 2021, it exported more than 45% or 4.7 million bpd. The majority of Russia's crude oil and condensate exports, nearly half of Russia's total exports, are typically sent to Europe. For Russia, it's highly unlikely demand from China and India, Asia's largest importers, could replace the lost export demand from Europe. At settlement, NYMEX June WTI futures advanced $0.45 per barrel (bbl) to $108.26 bbl, and ICE July Brent crude futures gained $0.76 to $110.90 bbl. NYMEX June RBOB edged up 0.64 cents to $3.6587 gallon, and the June ULSD contract declined 15.57 cents to $4.0413 gallon.
Crude oil futures extend gains as concerns linger over EU ban on Russian oil -Crude oil futures climbed for the third straight session during mid-morning Asian trade May 6, erasing earlier losses, as concerns lingered over the prospect of tighter supply after the European Union's embargo on Russian oil, while OPEC+ went ahead with its planned supply increase at its latest meeting. At 10:26 am Singapore time (0226 GMT), the ICE July Brent futures contract was up 42 cents/b (0.38%) from the previous close at $111.32/b, while the NYMEX June light sweet crude contract rose 42 cents/b (0.39%) at $108.68/b. OPEC and its Russia-led partners on May 5 approved another modest 432,000 b/d increase in production quotas for June, continuing to look past the impact that the war in Ukraine has had on the market as they benefitted from a windfall in oil revenues, analysts said. Even with an expected European ban on Russian oil supplies set to squeeze global supplies further, the 23-country OPEC+ alliance insisted that current supply-demand indicators "pointed to a balanced market," according to a statement after the group met for just 13 minutes to reaffirm its plan for monthly measured quota hikes. As has been the case for past months, however, the pledged supply increases from the producer group will likely fall short, with most members of the alliance already unable to raise output because of a lack of investment or internal disruptions. "The group is struggling to hit output quotas due to disruptions and a lack of investment in fields," said ING analysts Warren Patterson and Wenyu Yao in a May 6 note. "Lagging production is unlikely to change anytime soon, particularly given the weaker demand for Russian oil, which will eventually lead to output decreasing." The prospect of tighter supply, as the EU moves ahead with an embargo on Russian oil to be fully phased in by year-end, saw both front month ICE Brent and NYMEX crude contracts gradually reversing losses of more than $1/b in early morning trade. Investors were also mulling the US Department of Energy's plans to buy back 60 million barrels of crude for the Strategic Petroleum Reserve, or one-third of the massive drawdown that just started flowing, at lower prices; likely in the second half of 2023. In outlining the plan announced May 5 to refill the emergency oil stockpile based on a future delivery window, the DOE said it was aiming to encourage US drillers to boost activity and "lower prices this year by guaranteeing this demand in the future at a time when market participants anticipate crude oil prices to be significantly lower than they are today." "The market was surprised by the announcement that the US Energy Department would start purchasing oil to refill the nation's strategic reserve. This is likely to exacerbate the tightness in the oil market," ANZ Research analysts Brian Martin and Daniel Hynes said. Dubai crude swaps and intermonth spreads were higher in mid-morning trade in Asia May 6 from the previous close. The July Dubai swap was pegged at $102.60/b at 10 am Singapore time (0200 GMT), up 56 cents/b (0.55%) from the May 5 Asian market close. The June-July Dubai swap intermonth spread was pegged at $2.37/b at 10 am, up 7 cents/b over the same period, and the July-August intermonth spread was pegged at $1.89/b, up 6 cents/b. The July Brent-Dubai exchange of futures for swaps was pegged at $8.65/b, up 28 cents/b.
Oil Gains 1.5%, Posts Another Weekly Rise on Supply Concerns (Reuters) -Oil prices rose nearly 1.5% on Friday, posting a second straight weekly increase as impending European Union sanctions on Russian oil raised the prospect of tighter supply and had traders shrugging off worries about global economic growth. Brent futures rose $1.49, or 1.3%, to settle at $112.39 per barrel. U.S. West Texas Intermediate (WTI) crude climbed $1.51, or 1.4%, to end at $109.77 a barrel. "In the near term, the fundamentals for oil are bullish and it is only fears of an economic slowdown in the future that is holding us back," said Phil Flynn, an analyst at Price Futures Group. For the week, WTI gained about 5%, while Brent nearly 4% after the EU set out an embargo on Russian oil as part of its toughest-yet package of sanctions over the conflict in Ukraine. The EU is tweaking its sanctions plan, hoping to win over reluctant states and secure the needed unanimous backing from the 27 member countries, three EU sources told Reuters. The initial proposal called for an end to EU imports of Russian crude and oil products by the end of this year. "The looming EU embargo on Russian oil has the makings of an acute supply squeeze. In any case, OPEC+ is in no mood to help out, even as rallying energy prices spur harmful levels of inflation," PVM analyst Stephen Brennock said. Ignoring calls from Western nations to hike output more, the Organization of the Petroleum Exporting Countries, Russia and allied producers (OPEC+), stuck with its plan to raise its June output target by 432,000 barrels per day. However, analysts expect the group's actual production rise to be much smaller due to capacity constraints. "There is zero chance of certain members filling that quota as production challenges impact Nigeria and other African members," said Jeffrey Halley, senior market analyst Asia Pacific at OANDA. On Thursday, a U.S. Senate panel advanced a bill that could expose OPEC+ to lawsuits for collusion on boosting oil prices. On the supply side, U.S. oil rig count, an early indicator of future output, rose five to 557 this week, the highest since April 2020. []RIG/U] Money managers cut their net long U.S. crude futures and options positions in the week to May 3, the U.S. Commodity Futures Trading Commission (CFTC) said. Investors expect higher demand from the United States this autumn as Washington unveiled plans to buy 60 million barrels of crude to replenish emergency stockpiles. Yet signs of a weakening global economy fed demand concerns, limiting oil price gains. On Thursday, the Bank of England warned Britain risks a double-whammy of a recession and inflation above 10%. It raised interest rates a quarter of a percentage point to 1%, their highest since 2009. Strict COVID-19 curbs in China are creating headwinds for the world's second-largest economy and leading oil importer. Beijing authorities said all non-essential services would shut in its biggest district Chaoyang, home to embassies and large offices.
Oil Up this Week as EU Moves Closer to Russian Ban - Oil closed Friday at a six-week high on signs the market is tightening as members of the European Union moved closer toward banning Russian crude. West Texas Intermediate futures posted its first back-to-back weekly gain in two months. The EU intends to ban Russian crude in six months and oil products by the end of the year to punish Moscow for its war on Ukraine. The bloc has proposed giving Hungary -- which has pushed back against an embargo -- and Slovakia an extra year to comply, people familiar with the matter said Friday. “Crude prices just want to head higher as energy traders completely fixate over the looming European sanctions on Russian oil,” said Ed Moya, senior market analyst at Oanda. “No one wants to be on the wrong side of a major crude supply disruption headline, so whatever oil price dips that happen will be short-lived.” The U.S. government said Thursday that it would begin buying crude to replenish the nation’s reserve. While the process could begin in the fall, the actual deliveries won’t take place until later in the future. Oil has rallied more than 40% this year as the invasion of Ukraine upended commodity markets. This week’s advance -- the third in the past four -- has come despite lingering concerns that lockdowns in China to combat Covid-19 outbreaks are hurting consumption. “Chinese oil demand has been down 1.5 million barrels per day,” due to the lockdowns, according to S&P Global Inc. Vice Chairman Dan Yergin.. But knowing China’s ways, it is expected to stage a strong rebound and that would affect all commodity prices, he added. This week, the Organization of Petroleum Exporting Countries and its allies did announce another modest increase in supply, there’s doubt the alliance will be able to deliver the full volume. WTI for June delivery advanced $1.51 to settle at $109.77 a barrel in New York. Brent for July rose $1.49 to $112.39 a barrel. Oil-product markets have also shown signs of strength this week, especially in the U.S., where nationwide holdings of gasoline and diesel have dropped. Gasoline futures are trading near a record high after a weekly gain of about 6%.
NYMEX RBOB Ends at Record High on Strong Payroll Report - While the prompt month ULSD contract was again an outlier with a lower close, oil futures nearest delivery settled Friday's session higher, sending the front-month gasoline contract to a record-high settlement of $3.7590 gallon following the release of a strong employment report in the United States that has boosted optimism for robust demand growth for the motor transportation fuel this summer despite surging inflation and a record surge in fuel prices. On the session, NYMEX June RBOB futures rallied 10.03 cents or 2.7% for a record-breaking settlement on the spot continuous chart of $3.7590 gallon, while on an intraday basis reached a fresh eight-week high $3.7970, with the record high at $3.8904 gallon traded on March 7. In contrast, NYMEX June ULSD futures settled below $4 gallon for the first time since April 22, down 8.7 cents at $3.9543 gallon. Crude contracts pared some of their morning gains with NYMEX West Texas Intermediate June futures settling just below $110 bbl after hitting an intrasession high of $111.18 per barrel (bbl). The international crude benchmark Brent contract for July delivery settled at a six-week high $112.39 bbl, up $1.49 or 1.6% from Thursday's session close. U.S. economy added 428,000 new jobs in April, narrowly beating expectations for a 400,000 gain, while the unemployment rate remained unchanged at 3.6%, just 0.1% above the February 2020 50-year low. April marked the 12th consecutive month of job growth above 400,000, which bodes well for gasoline demand in the United States as a strong labor market typically underpins gains in fuel consumption. Government data this week showed gasoline demand in the United States increased for the third consecutive week through April 29 to 8.856 million barrels per day (bpd), while demand for middle distillates jumped to a seven-week high 3.956 million bpd. Stocks of middle distillates in the United States stand at a critically low level at 104.942 million bbl, roughly 22% below the five-year average. Inventories are expected to fall even further to a projected low of just 102 million bbl before the middle of the year, with a possible range of 97 million to 105 million bbl, according to analysts. Distillate fuels are mostly used in road and rail freight, manufacturing, construction, farming, mining, and oil and gas extraction, so consumption is very sensitive to economic activity. Against this backdrop, European Commission this week proposed an outright ban on imports of Russian fuels, such as distillates, beginning early next year and crude oil imports by October. The decision will most certainly tighten the world market even further with no immediate replacement for the Russian oil currently available on the global market.
Iran agrees to resumes gas deliveries to Iraq - Iraq and Iran reached an agreement on Thursday for Iranian gas supplies to Iraq to resume, with Baghdad repaying debts owed to Tehran, Iraqi Electricity Minister Adel Karim was quoted by the state news agency as saying. In December 2021, the electricity ministry said the reduction in Iranian gas supplies had caused a power loss of around 3,400 megawatts. An Iraqi delegation, headed by Karim, visited Tehran on Tuesday to discuss the resumption of Iranian gas supplies. The visit proceeded “positively” as the two sides had reached an agreement to resume natural gas supplies to Baghdad, Ahmed Mousa, spokesperson for the Iraqi electricity ministry told state media on Thursday. “The visit emphasised on raising the volume of imported gas to Iraq and releasing it in amounts that would suffice the Iraqi need and paying the amounts of debt,” Mousa stated, adding that “the ministry hopes to add four thousand megawatts with an entry of additional … units, to raise production to 25 thousand megawatts in the summer.” The trip came less than two weeks after Iraqi Prime Minister Mustafa al-Kadhimi directed the electricity ministry to assign a team to discuss natural gas supplies with Iran. Iraq, with a population of some 41 million people, is grappling with a major energy crisis and suffers regular power cuts. Despite its immense oil and gas reserves, Iraq remains dependent on imports to meet its energy needs. Neighbouring Iran currently provides a third of Iraq’s gas and electricity demand, but supplies are regularly cut or reduced, aggravating daily load shedding. Iraq expects to be sent 55 million cubic feet of gas from Iran starting May 1, more than double the 25 million it receives at the moment, the electricity minister said.
Missile attack on oil refinery in Iraq’s Erbil hit oil tank, fire erupted - Six missiles targeted the KAR Group oil refinery in Iraq's northern city of Erbil on Sunday, leading to fire erupting in on of the man oil tanks, Iraq’s security forces said. The fire was brought under control, the security forces added. Earlier on Sunday, Kurdistan’s anti-terrorism authorities said six missiles landed near the refinery, adding that the missiles caused no casualties or material damages. Erbil-based TV Rudaw quoted the anti-terrorism authorities as saying the missiles were fired from the Nineveh province. Three missiles also fell near the refinery on April 6, without causing any casualties. In March, Iran attacked Erbil with a dozen ballistic missiles and one person was injured in the attack.
Massive fire breaks out at oil depot in Pakistan's Khyber Pakhtunkhwa -- About 30 oil tankers were gutted in a massive fire that broke out at an oil depot in Pakistan’s Khyber Pakhtunkhwa, local media reported. A police official told Dawn that one person was injured in the blaze. The blaze started around 3 pm at the Tarujaba oil depot in the Nowshera district on Saturday and was brought under control late at night, according to fire and rescue officials, reported Dawn. At least 20 firefighting vehicles took part in a taxing effort to put out the flames. According to a statement issued earlier about 150 tankers were parked in the yard and about 20 were gutted in the blaze. Looking at the intensity of the fire, fire brigades from Mardan and Peshawar were also called for the dousing operations. The cause of the fire has not been ascertained yet. Over 100 oil containers have been removed from the burning oil depot, ARY News reported citing rescue sources.
Saudi to extend oil loan to Pakistan, discussing dollar deposits - Saudi Arabia will extend an oil loan facility to Pakistan and is considering rolling over dollar deposits as the South Asian nation looks to rein in one of Asia’s highest inflation rates and stave off a current-account crisis. The Kingdom is discussing options including extending the term of a $3 billion deposit with the State Bank of Pakistan, the countries said in a joint statement Sunday after Prime Minister Shehbaz Sharif met Crown Prince Mohammed bin Salman. Pakistan welcomed Saudi Arabia’s decision to extend the agreement to finance crude exports and oil derivatives, according to the statement, which didn’t offer details. Sharif, who took office last month after a joint opposition ousted premier Imran Khan, faces the politically tough task of stopping Khan’s fuel subsidies and raising pump prices if he’s to get a loan from the International Monetary Fund. Anti-inflation protests are already roiling parts of the region as the war in Ukraine stokes the costs of everything from crude oil to coal. Saudi Arabia pledged $4.2 billion in assistance to Pakistan when Khan visited the kingdom in October. That included a deposit of $3 billion with the State Bank of Pakistan to help shore up its reserves and a facility to finance oil derivatives trade worth $1.2 billion during the year. Sharif recently rejected a proposal from his minister to raise local fuel costs, days after vowing discipline to unlock $3 billion pending from an IMF loan agreement that was suspended amid the political turmoil in Pakistan. An IMF team will visit Pakistan after May 7 and hold talks on the issues around subsidies on petrol and electricity. Pakistan has seen its foreign exchange reserves fall to less than two months of import cover after a delay in the IMF loan program. It is also resorting to power cuts as electricity plants face fuel and funding shortages.
Al-Qaeda chief blames US for Ukraine invasion in new video - Al-Qaeda leader Ayman al-Zawahri made an appearance in a pre-recorded video to mark the 11th anniversary of the death of his predecessor Osama bin Laden. Al-Zawahri says in the video that “US weakness” was the reason that its ally Ukraine became “prey” for the Russian invasion. The 27-minute speech was released Friday according to the SITE Intelligence group, which monitors militant activity. The leader appears sitting at a desk with books and a gun. Urging Muslim unity, al-Zawahri said the US was in a state of weakness and decline, citing the impact of the wars in Iraq and Afghanistan launched after the 9/11 terrorist attacks. Bin Laden was the mastermind and financier behind the attacks. “Here [the US] is after its defeat in Iraq and Afghanistan, after the economic disasters caused by the 9/11 invasions, after the Corona pandemic, and after it left its ally Ukraine as prey for the Russians,” he said. Bin Laden was killed in a 2011 raid by US forces on his compound hideout in Pakistan. Al-Zawahri’s whereabouts are unknown. He is wanted by the FBI and there is a $25 million reward for information leading to his capture.
Putin Signs Executive Order to Begin “Special Economic Measures” aka Sanctions - by Yves Smith - Why has Russia taken so long to retaliate against Western sanctions? One possibility is it’s because Putin and his team didn’t see the need to do all that much immediately given economic blowback. A second is that they wanted to wait for the gas for roubles arm wrestling to play out before applying new pressure. Regardless, Putin’s executive order sets up an initial framework for what we like to call sanctions. I wish Russia had posted the actual order; the embedded document below is a summary. Putin pointedly calls these punishments “retaliatory special economic measures”. This may seem like a distinction without a difference, but Russia and China both take the view that economic sanctions are illegal unless approved by the UN, which clearly is not happening here. When I come across an explanation of how Russia thinks it has threaded this particular legal needle, I’ll be sure to make mention in Links or a post. The executive order directs Putin’s staff to come back in ten days with initial targets, which at this point are only individuals, and to…define additional criteria for transactions whose implementation and obligations shall be banned under the Executive Order.Admittedly this document is broader and less specific than Putin’s announcement that Russia would require payment for gas by unfriendly countries be paid for in roubles, where he included enough additional boundary conditions as to considerably constrain how the process might work (that’s why we were able to outline the mechanism in advance, with the actual version adding only a couple more wrinkles). And it’s clearly intended to be expanded in scope.The basis for the countersanctions is the violation of international law. The seizure of $300 billion of foreign exchange reserves and the German Gazprom operations, and Poland’s moves to expropriate Novatek’s pipeline infrastructure would all seem to be on the list.Even though the initial targets are to be individuals, the text indicates the scope is broader: “special economic measures are to be applied to certain legal entities, individuals and organisations under their control.”The document at points describes individuals at targets and at other points legal entities and organizations; I doubt the underlying Executive Order is imprecise as to what applies to whom, but we’ll have a better idea in due course. But here is the potential zinger:In addition, the document imposes a ban on exporting products or raw materials manufactured or extracted in Russia when they are delivered to individuals under sanctions, or by individuals under sanctions to other individuals.Limiting this section to individuals seems almost besides the point, since individuals are seldom in the business of buying Russian products or commodities. However, it’s not hard to see that if and when the list expands to include organizations and companies, Russia could inflict a lot of pain by limiting exports of key commodities. If I were them, materials critical to weapons manufacture would be at the top of the list. Cars might be next given how important auto manufacture is to many economies.
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