US oil supplies are at a 13 year low, Strategic Petroleum Reserve at a 19 year low; total oil + products supplies at a 7 1/2 year low; distillate supplies are at 26 month low after refinery freeze offs; DUCs down 40% YoY and are lowest since January 2014, with DUCs in 4 basins at record lows; 5.0 month DUC backlog is lowest in 7 years; natural gas rigs rise most in 57 months…
oil prices fell for the first time in 9 weeks this week as the invasion of Ukraine threatened by the US state department failed to materialize and as oil traders were disheartened by the possibility of a nuclear peace deal with Iran....after rising 0.9% to a 7 year high of $93.10 a barrel last week after the White House advised that a Russian invasion of Ukraine was imminent, the contract price for US light sweet crude for March delivery opened nearly 1% higher on Monday, as Sunday comments from the US about an imminent attack by Russia on Ukraine rattled global financial markets, and surged $2.36, or 2.5%, to settle at $95.46 a barrel, on fears that an invasion of Ukraine by Russia could trigger U.S. and European sanctions that would disrupt exports from the world's top oil producer in an already tight market...but oil prices plummeted nearly $5 a barrel on Tuesday after Russia announced a partial withdrawal of its military troops along the Ukrainian border and settled $3.39 or 3.5% lower at $92.07 a barrel, as Moscow wound down troops that had ringed Ukraine’s borders for more than two months, removing a huge geopolitical premium from energy markets...however, oil prices rallied early Wednesday, after the American Petroleum Institute reported total petroleum stockpiles in the US had declined again, with commercial oil supplies at their lowest level since September 2018 at a time when fuel consumption showed signs of a solid rebound after winter storms and the Omicron surge, and then topped $94 a barrel after the weekly report from the EIA showed gasoline and distillate stocks fell by larger-than-expected margins, offsetting a surprise build in commercial crude oil inventories, before settling with a $1.59 gain on the day at $93.66 a barrel after the head of the International Energy Agency (IEA) called on OPEC and its allies to boost production to meet agreed output targets...oil prices then opened nearly 3% lower on Thursday following reports U.S. and Iranian negotiators were closing in on a nuclear agreement that could soon lead to the lifting of sanctions on the country's crude oil exports, but partly recovered to finish $1.90 or 2% lower at $91.76 as losses were limited by heightened tensions between the world's top energy exporter Russia and the West over Ukraine...oil prices headed lower again on Friday as traders assessed Iran's capacity to bring back more than 1 million barrels per day in now sanctioned oil exports, easing concerns over supply tightness on the global oil market and offsetting the potential risk of supply disruption in Eastern Europe. but pared steep early losses to settle 69 cents lower at $91.07 a barrel amid reports of escalating violence in Russia-controlled regions of eastern Ukraine that, according to U.S. officials, could serve as a pretext for an attack by Moscow that would trigger sanctions on the country's oil and gas exports, but still finished 2.2% lower on the week as traders weighed heightened geopolitical tensions over Ukraine against the potential for Iranian barrels to be added to the market...
natural gas prices, on the other hand, finished higher for the first time in three weeks on forceasts for cold weather to persist into early March...after falling 13.8% to $3.941 per mmBTU last week as temperature forecasts continued to moderate throughout the week, the contract price of natural gas for March delivery opened more than 3% higher on Monday and spiked another 4% from that point before settling 25.4 cents higher at $4.195 per mmBTU, after an 8% jump in European gas prices on the possibility of a Russian cut off of gas supplies kept demand for US LNG exports at new highs. and as the European weather model indicated a prolonged winter for the US....natural gas prices were again more than 6% higher early Tuesday on the increasing potential for cold weather to linger into early March, but settled with an 11.1 cent or a 2.7% gain at $4.306 per mmBTU, sliding as part of a broader commodities sell-off amid easing political tensions...but natural gas prices jumped 41.1 cents or almost 10% to near a two-week high of $4.717 per mmBTU on Wednesday on forecasts for much colder weather and higher heating demand through early March than had been previously forecast, and then gave half of that big gain back on Thursday as March contract prices fell 23.1 cents to $4.486 per mmBTU on a slightly smaller-than-expected storage draw last week and as gas production slowly recovered from freeze-off-related reductions earlier this month...natural gas prices eased on Friday ahead of the long weekend. slipping 5.5 cents or 1.2% to $4.431 per mmBTU, on a continued slow recovery in output from cold weather-related output reductions earlier in the month and on modeerating forecasts for next week, but still finished 12.4% higher for the week, largely thanks to a much colder forecast for early March...
The EIA's natural gas storage report for the week ending February 11th indicated that the amount of working natural gas held in underground storage in the US fell by 190 billion cubic feet to 1,911 billion cubic feet by the end of the week, which left our gas supplies 404 billion cubic feet, or 17.5% below the 2,315 billion cubic feet that were in storage on February 11th of last year, and 251 billion cubic feet, or 11.6% below the five-year average of 2,162 billion cubic feet of natural gas that have been in storage as of the 11th of February over the most recent five years....the 190 billion cubic foot withdrawal from US natural gas working storage for the cited week was less than the average forecast for a 197 billion cubic foot withdrawal expected by an S&P Global Platts survey of analysts, and was much less than the 227 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2021, but also quite a bit more than the average withdrawal of 154 billion cubic feet of natural gas that have typically been pulled out natural gas storage during the same week over the past 5 years…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending February 11th indicated that after a big drop in our oil exports, a major slowdown in our oil refining due to freezing weather on the Gulf Coast, and a big withdrawal of oil from our Strategic Petroleum Reserve, we had oil left to add to our stored commercial crude supplies for the third time in 12 weeks and for the 13th time in the past thirty-eight weeks…our imports of crude oil fell by an average of 599,000 barrels per day to an average of 5,790,000 barrels per day, after falling by an average of 696,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 829,000 barrels per day to an average of 2,271,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 3,519,000 barrels of per day during the week ending February 11th, 230,000 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 11,600,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have totaled an average of 15,119,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 14,902,000 barrels of crude per day during the week ending February 11th, an average of 675,000 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 224,000 barrels of oil per day were being pulled out the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 441,000 barrels per day more than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-441,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed....however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
This week's 224,000 barrel per day decrease in our overall crude oil inventories left our total oil supplies at 996,336,000 barrels, now the lowest since November 7th, 2008, and therefore at a new 13 year low...this week's oil inventory decrease came as 160,000 barrels per day were being added to our commercially available stocks of crude oil, while 384,000 barrels per day of oil were being pulled out of our Strategic Petroleum Reserve, part of the Biden' administration plan to release 50 million barrels from the SPR to incentivize US gasoline consumption....including other withdrawals from the Strategic Petroleum Reserve under similar programs, a total of 71,319,000 barrels have been removed from the Strategic Petroleum Reserve over the past 18 months, and as a result the 584,828,000 barrels of oil now left in our Strategic Petroleum Reserve is now the lowest since September 20th, 2002, or at yet another new 19 year low, as repeated tapping of our emergency supplies for political reasons or to “pay for” other programs has already drained those supplies considerably over the past dozen years...based on an estimated prepandemic consumption level of around 18 million barrels per day, the US would have roughly 30 1/2 days of oil supply left in the Strategic Petroleum Reserve when the Biden program is complete...
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,375,000 barrels per day last week, which was still 9.3% 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 11,600,000 barrels per day as the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,100,000 barrels per day, while Alaska’s oil production was 6,000 barrels per day higher at 461,000 barrels per day but had no impact on the rounded national production total...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 11.5% below that of our pre-pandemic production peak, but 37.6% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016...
US oil refineries were operating at 85.3% of their capacity while using those 14,902,000 barrels of crude per day during the week ending February 11th, down from a utilization rate of 88.2% the prior week, and lower than the historical utilization rate for early February refinery operations…the 14,902,000 barrels per day of oil that were refined this week were just 0.6% more barrels than the 14,819,000 barrels of crude that were being processed daily during the pandemic impacted week ending February 12th of 2021, and 8.2% less than the 16,210,000 barrels of crude that were being processed daily during the week ending February 14th, 2020, when US refineries were operating at what was then a closer to normal 89.4% of capacity...
With the big decrease in oil being refined this week, gasoline output from our refineries was also much lower, decreasing by 560,000 barrels per day to 8,830,000 barrels per day during the week ending February 11th, after our gasoline output had increased by 740,000 barrels per day over the prior week.…this week’s gasoline production was 2.2% less than the 9,031,000 barrels of gasoline that were being produced daily over the same week of last year, and 7.3% less than the gasoline production of 9,525,000 barrels per day during the week ending February 14th, 2020....at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 244,000 barrels per day to 4,455,000 barrels per day, after our distillates output had increased by 97,000 barrels per day over the prior week…with that decrease, our distillates output was 2.6% less than the 4,574,000 barrels of distillates that were being produced daily during the week ending February 12th of 2021, and 8.2% less than the 4,852,000 barrels of distillates that were being produced daily during the week ending February 14th, 2020...
With the big decrease in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the fourth time in the past 12 weeks, decreasing by 1,332,000 barrels to 248,393,000 barrels during the week ending February 11th, after our gasoline inventories had decreased by 1,644,000 barrels over the prior week....our gasoline supplies decreased again this week even though the amount of gasoline supplied to US users decreased by 556,000 barrels per day to 8,570,000 barrels per day, while our imports of gasoline rose by 41,000 barrels per day to 555,000 barrels per day, and while our exports of gasoline rose by 133,000 barrels per day to 439,000 barrels per day…after this week's decrease, our gasoline supplies were 3.9% lower than last February 12th's gasoline inventories of 257,084,000 barrels, and are now about 3% below the five year average of our gasoline supplies for this time of the year…
Meanwhile, with this week's decrease in our distillates production, our supplies of distillate fuels decreased for the seventeenth time in twenty-four weeks, falling by 1,552,000 barrels to a twenty six month low of 120,262,000 barrels during the week ending February 11th, after our distillates supplies had decreased by 930,000 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 25,000 barrels per day to 4,321,000 barrels per day, and as our exports of distillates fell by 182,000 barrels per day to 794,000 barrels per day, while our imports of distillates fell by 3,000 barrels per day to 437,000 barrels per day....after thirty-one inventory decreases over the past forty-five weeks, our distillate supplies at the end of the week were 23.7% below the 157,684,000 barrels of distillates that we had in storage on February 12th of 2021, and about 19% below the five year average of distillates inventories for this time of the year…
Meanwhile, after the drop in our oil exports, the pullback in our oil refining, and a big withdrawal of oil from our Strategic Petroleum Reserve, our commercial supplies of crude oil in storage rose for the 10th time in 28 weeks and for the 19th time in the past year, increasing by 1,121,000 barrels over the week, from 410,387,000 barrels on February 4th to 411,508,000 barrels on February 11th, after our commercial crude supplies had decreased by 4,756,000 barrels over the prior week…after this week’s increase, our commercial crude oil inventories remained about 10% below the most recent five-year average of crude oil supplies for this time of year, but were still about 28% above the average of our crude oil stocks as of second weekend of February 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 remained elevated for most of a year after that, our commercial crude oil supplies as of this February 11th were 10.9% less than the 461,757,000 barrels of oil we had in commercial storage on February 12th of 2021, and are now 7.1% less than the 442,883,000 barrels of oil that we had in storage on February 14th of 2020, and also 9.5% less than the 454,512,000 barrels of oil we had in commercial storage on February 15th of 2019…
Finally, with our inventory of crude oil and our supplies of all products made from oil all near multi year lows, we are continuing to track the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that 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 12,577,000 barrels this week, from 1,758,364,000 barrels on February 4th to 1,745,787,000 barrels on February 11th....that leaves our total supplies of oil & its products now at the lowest since May 2nd, 2014, or at a new seven and a half year low, despite the recent near record increase in gasoline inventories....
This Week's Rig Count
The number of drilling rigs running in the US increased for the 63nd time over the past 74 weeks during the week ending February 18th, but were still 18.7% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by ten to 645 rigs this past week, which was also 248 more rigs than the pandemic hit 397 rigs that were in use as of the February 19th report of 2021, but was still 1,284 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 4 to 520 oil rigs during this week, after oil rigs had increased by 19 during the prior week, and there are now 215 more oil rigs active now than were running a year ago, even as they still amount to just 32.3% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations jumped by 6 rigs to 124 natural gas rigs, which was the largest increase in natural gas rigs since May 19th, 2017, also up by 33 natural gas rigs from the 91 natural gas rigs that were drilling during the same week a year ago, but still only 7.7% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition, Baker Hughes continues to list a rig drilling vertically for a well intended to store CO2 emissions in Mercer county North Dakota as 'miscellaneous', which thus matches the 'miscellaneous' rig count of 1 a year ago
The offshore Gulf of Mexico rig count was down by four to twelve rigs this week, with eleven of this week's Gulf rigs drilling for oil in Louisiana waters and another rig drilling for oil in Alaminos Canyon, offshore from Texas....that's down from the 16 offshore rigs that were active in the Gulf a year ago, when 14 Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil in Texas waters…since there is not any drilling off our other coasts at this time, nor was there a year ago, those Gulf rig counts are equal to the national offshore totals for both years....
In addition to those rigs offshore, we now have 3 water based rigs drilling inland; one is a horizontal rig targeting oil at a depth of between 5000 and 10,000 feet, drilling from an inland body of water in Plaquemines Parish, Louisiana, near the mouth of the Mississippi, another is a directional rig drilling for oil at a depth of over 15,000 feet in the Galveston Bay area, while the new inland waters rig added this week is a directional rig targeting oil at a depth of between 10,000 and 15,000 feet in St. Mary Parish, Louisiana... this week's inland waters rig count of three is up by two from the single inland waters rig that was deployed a year ago..
The count of active horizontal drilling rigs was up by 15 to 589 horizontal rigs this week, which was also 232 more rigs than the 357 horizontal rigs that were in use in the US on February 19th of last year, but still 57.1% less than the record 1,374 horizontal rigs that were drilling on November 21st of 2014....on the other hand, the vertical rig count was down by 3 rigs to 25 vertical rigs this week, which was still one more than the 25 vertical rigs that were operating during the same week a year ago…at the same time, the directional rig count was down by 2 to 31 directional rigs this week, but those were still up by 15 from the 16 directional rigs that were in use on February 12th 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 February 18th, the second column shows the change in the number of working rigs between last week’s count (February 11th) and this week’s (February 18th) count, the third column shows last week’s February 11th 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 19th of February, 2021...
with much of this week's activity centered around Texas, we'll start by checking the Rigs by State file at Baker Hughes for the changes in that state, where we find that three rigs were added in Texas Oil District 8, which encompasses the core Permian Delaware, and that another rig was added in Texas Oil District 7C, which includes the counties of the southern part of the Permian Midland...since that adds up to fours rigs and the Permian rig count was up by five, that means that at least one of the rigs that was added in New Mexico was targeting the Permian, and that one of those rigs added in the Permian basin region of Texas or New Mexico this weekl was not targeting the Permian...if you really need to know where those were, you can compare the 306 Permian well records for this week and the 301 Permian well records for last week in the North America Rotary Rig Count Pivot Table (Excel) and find out where the change occurred...
elsewhere in Texas, there was one rig added in Texas Oil District 2, and two more rigs added in Texas Oil District 3, any of which could have been targeting the Eagle Ford shale...since the Eagle Ford saw two oil rigs pulled out this week while two natural gas rigs were added, some combination of the changes in those two districts, and / or DIstricts 1 & 4, and / or of the three rigs being pulled out of in those districts not targeting the Eagle Ford has to account for those changes; again, check the North America Rotary Rig Count Pivot Table (Excel) for the offsetting changes which don't show up in the totals..
Texas also saw two rigs added in Texas Oil District 6, which accounts for two of the natural gas rig additions in the Haynesville shale...there were also at least two natural gas rig additions in the Haynesville shale of northern Louisiana, and since the 4 rig increase in the Haynesville this week includes 5 new natural gas rig additions offset by the shutdown of an oil rig, that offsetting activity had to have occurred in one of those two states (again, the Haynesville details by county would be in that Pivot Table)...despite those Haynesville shale additions and the new inland waters rig in St. Mary Parish, Louisiana's rig count was still down by one after the removal of four rigs from the state's offshore waters..
other natural gas rig changes this week included rig additions in Oklahoma's Arkoma Woodford, which also has two oil rigs running, and Pennsylvania's Marcellus, which in turn were offset by the removal of a gas rig from Ohio's Utica shale, and two natural gas rig removals from basins that Baker Hughes doesn't track...other rig changes around the country include the addition of two oil rigs in Colorado's DJ Niobrara chalk, the addition of an oil rig in Oklahoma's Cana Woodford, the removal of the last oil rig from Oklahoma's Mississippian limestone, and the removal of a rig from a Wyoming basin that Baker Hughes doesn't track...
DUC well report for January
Monday of the past week saw the release of the EIA's Drilling Productivity Report for February, which includes the EIA's January data on drilled but uncompleted (DUC) oil and gas wells in the 7 most productive shale regions....that data showed a decrease in uncompleted wells nationally for the 20th consecutive month in January, as both completions of drilled wells and drilling of new wells increased, but remained well below average pre-pandemic levels...for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 191 wells, falling from 4,657 DUC wells in December to 4,466 DUC wells in January, which was the lowest number of US wells left uncompleted since January 2014, and also 40.0% fewer DUCs than the 7,449 wells that had been drilled but remained uncompleted as of the end of January of a year ago...this month's DUC decrease occurred as 710 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during January, up from the 686 wells that were drilled in December, while 901 wells were completed and brought into production by fracking them, up by just 2 from the 899 well completions seen in December, but up by 170 from the pandemic hit 731 completions seen in January of last year....at the January completion rate, the 4,466 drilled but uncompleted wells left at the end of the month represents a 5.0 month backlog of wells that have been drilled but are not yet fracked, down from the 5.1 month DUC well backlog of a month ago, and the lowest backlog since December 2014, despite a completion rate that is still more than 20% below 2019's pre-pandemic average...
once again, both oil producing regions and natural gas producing regions saw DUC well decreases in January, while none of the major basins covered by this report reported a DUC well increase....the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico decreased by 89, from 1,444 DUC wells at the end of December to 1,355 DUCs at the end of January, as 320 new wells were drilled into the Permian basin during January, while 409 wells in the region were being fracked...at the same time, DUCs in the Eagle Ford shale of south Texas decreased by 28, from 685 DUC wells at the end of December to a record low of 657 DUCs at the end of January, as 72 wells were drilled in the Eagle Ford during December, while 100 already drilled Eagle Ford wells were completed....in addition, there was also a decrease of 27 DUC wells in the Bakken of North Dakota, where DUC wells fell from 464 at the end of December to a record low of 437 DUCs at the end of January, as 46 wells were drilled into the Bakken during January, while 73 of the drilled wells in the Bakken were being fracked....meanwhile, the number of uncompleted wells remaining in Oklahoma's Anadarko basin decreased by 12, falling from 773 at the end of December to 761 DUC wells at the end of January, as 54 wells were drilled into the Anadarko basin during January, while 66 Anadarko wells were completed.....in addition, DUC wells in the Niobrara chalk of the Rockies' front range decreased by 9, falling from 354 at the end of December to a record low of 345 DUC wells at the end of January, as 88 wells were drilled into the Niobrara chalk during January, while 97 Niobrara wells were being fracked...
among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 23 wells, from 565 DUCs at the end of December to a record low of 542 DUCs at the end of January, as 75 wells were drilled into the Marcellus and Utica shales during the month, while 98 of the already drilled wells in the region were fracked....meanwhile, the uncompleted well inventory in the natural gas producing Haynesville shale of the northern Louisiana-Texas border region was down by three wells to 369 DUCs, as 55 wells were drilled into the Haynesville during January, while 58 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of January, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 165 wells to 3,555 DUC wells, while the uncompleted well count in the major natural gas basins (the Marcellus, the Utica, and the Haynesville) decreased by 26 wells to 911 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
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Thousands of Abandoned Ohio Oil and Gas Wells May Be Hidden; Drones Could Help Find Them - Journal of Petroleum Technology -After successful trials using drones to discover abandoned oil and gas wells, Ohio authorities are looking to expand their use and to speed up remediation at hundreds of sites across the state. Ohio has roughly 1,000 sites on its orphan well inventory. There likely are “many more,” said Eric Vendel, chief of the Ohio Department of Natural Resources’ Division of Oil and Gas Resources Management. The hope is that drones equipped with magnetometers could help locate wells that are not yet on the state’s radar. Orphan wells in Ohio are a subset of the larger group of abandoned oil and gas wells, where no legally responsible owner can be found. Until wells are identified, however, it is unclear whether they should be fixed by the state under its orphan well program. Until now, there have not been good tools to systematically identify which of the quarter-million wells drilled in the state since the mid-19th century have been properly plugged or should be deemed orphan wells. In many cases, wells have come onto Ohio’s orphan well list only after people reported problems. In one case, for example, a well was found under the gym floor at a Lorain County grade school. Nor has any systematic on-the-ground survey been done to check whether recorded wells were properly plugged. Magnetometers have been used to find wells and other geological anomalies for decades. The equipment looks for specific changes in the ground’s magnetic field that signal the presence of a vertical well casing. Walking sites with equipment is time-consuming, however, so it hasn’t been done in a systematic manner statewide. The growing popularity of remotely piloted aerial vehicles, or drones, within the past 20 years has paved the way for surveys to be done efficiently over larger areas. The magnetometer itself looks like a yard-long white surfboard. It hangs from a remote-controlled drone with a wingspan of 4 to 5 ft. “It’s a pretty big piece of equipment,” said Rob Lowe, a survey section manager at the Ohio Department of Natural Resources’ (ODNR) Division of Oil and Gas Resources Management. His section was formally established in 2016.
ODNR in the crosshairs over Martins Ferry's Austin Master plant - — The Austin Masters Services frack waste processing plant in Martins Ferry continues to face criticism from some area residents for its handling of waste products.On Wednesday, an online meeting hosted by the Ohio Department of Natural Resources attracted nearly two dozen residents and members of Concerned Ohio River Residents advocacy group. ODNR representatives Adam Schroader and Tara Kinsey-Lee were pelted with questions and criticism, with participants saying ODNR was not acting quickly enough to regulate the waste product industry, among other concerns.Schroader opened the meeting by explaining the new rule for regulating companies that deal with waste products from hydraulic fracturing operations in the natural gas and oil industry.“The rule governs the citing, permitting, construction, operation and reclamation of oil and gas waste facilities,” he said. “The rule includes general provisions that ensure the prevention of contamination and pollution, protection of underground s ystem drinking water and surface water, and the appropriate handling of oil and gas waste.”Other aspects of the rule include public notices, permit requirements, water well sampling, enforcement procedures and citing criteria.Some meeting attendees were critical that it took so long for a rule to be instituted. The question-and-answer session followed immediately after the explanation of the rule, with many of the questions for ODNR prepared beforehand. Roxanne Groff expressed confusion over injection wells and facilities in referencing the new rule. Kinsey-Lee said a company has 15 days to produce information that is requested. She said the process of sharing information with the public begins with ODNR’s public notice on its website and a notice in the local newspaper “to notify partners required in the format of the rules” after an application to permit a well is filed.
Ohio needs a consistent earthquake-risk policy on permitting fracking waste wells - cleveland.com - Northeast Ohio’s unique geology has long made it a favored site for deep-injection-well disposal of toxic waste. But 35 years ago, two geologists from Columbia University’s Lamont-Doherty Earth Observatory -- John Armbruster and Leonardo Seeber -- first linked a 1987 swarm of Ashtabula County earthquakes to a 1986 injection well. The two men pinpointed the epicenter of the main July 1987 earthquake at 0.7 kilometers from the well, which had started pumping toxic fluids into the sandstone formation one year earlier. They also found that the injected fluids had triggered a previously unknown near-vertical fault in the region’s basement rocks.
SARTA seeks to build support for hydrogen hub in Ohio - Canton Repository – The Stark Area Regional Transit Authority is part of a new alliance seeking a $2 billion federal grant to help build a hydrogen industry hub in the region. The public agency — which uses hydrogen to fuel some of its bus fleet — banded together with about 62 other organizations and government leaders last month to form the Ohio Clean Energy Hub Alliance and begin pushing for the concept. The goal is to provide a cleaner energy source with no or little carbon emissions and to create of tens of thousands of jobs in an area that could encompass Ohio, western Pennsylvania and West Virginia. The U.S. Department of Energy this week began seeking feedback on how to allocate $8 billion to fund at least four clean hydrogen energy hubs throughout the country. The hubs would be areas or regions where the federal government would invest the money, hoping to spark the development of a clean energy hydrogen industry that doesn't contribute to climate change. Such a hub would be close to an energy source that would eventually include emerging industries for generation, storage and transportation to the end users. At least one hub would be based on extracting hydrogen from a fossil fuel, which can include natural gas; one from nuclear power; and one from renewable energy sources. One of the goals is to reduce the cost of hydrogen, which powers fuel cells, down to $1 a kilogram within a decade. SARTA now pays roughly $6 to $10 a kilogram for its 20 hydrogen vehicles. SARTA says a kilogram of hydrogen provides roughly the equivalent of a gallon of diesel. The ultimate federal goals are a carbon-free electrical grid by 2035 and a carbon-free emission economy by 2050. The $1.2 trillion infrastructure bill approved by Congress and signed into law by President Joe Biden in November authorized the new grant program.
Pennant Midstream to supply Australian company with renewable natural gas -Pennant Midstream, which operates wet and dry gas and natural gas liquid pipelines in Pennsylvania and Ohio, signed a series of agreements last year with a subsidiary of Australia-based Energy Developments (EDL) to accept delivery of renewable natural gas (RNG) into its natural gas gathering system. Pennant will transport RNG from the Carbon Limestone Landfill near Youngstown, Ohio, to EDL’s downstream markets. The gas from the landfill is a byproduct of naturally decomposing materials. EDL will process and condition the gas at its largest North American RNG facility to meet Pennant’s gas quality requirements. Gas will be transported starting in early 2023. The Pennant system will take up to 6,500 thousand cubic feet daily once fully operational. “EDL has owned and operated an extensive portfolio of landfill gas to electricity plants across the United States since 1998; and in recent years, several large plants converting landfill gas to RNG,” James Harman, EDL CEO, said. “We are proud to leverage our waste to clean energy expertise through developments such as the Carbon Limestone RNG project and to assist one of our key customers with their goal of de-carbonizing through renewable gas supply.” Accepting delivery of the RNG from the landfill will reduce carbon dioxide emissions by up to 127,500 metric tons annually.
You can't stop a well pad, they were told. Turns out, you can - Pittsburgh Post-Gazette - Jo and Tim Resciniti did what many residents of townships slated for shale development had done before them. They fretted. They talked to their neighbors. They requested public documents. They organized a group, called Crowd, which stands for Concerned Residents of West Deer. When they solicited advice, it came loudly and clearly: You can’t stop a township from granting a land-use permit for oil and gas drilling, as long as the application is complete and complies with the zoning ordinance. “Pretty much everybody told us there was nothing we can do about it,” Ms. Resciniti said. “They were very generous with [that] advice.” It’s so uncommon for a township to deny a permit for an oil and gas well that people in the industry or those opposed to it can cite the legal cases. Because oil and gas extraction is a legal land use in Pennsylvania that must be allowed somewhere in every municipality, it is presumed not to be detrimental to safety and health when it complies with the law. Passing judgment on whether oil and gas is good or bad, healthy or unhealthy, falls to the Legislature. Environmental regulation falls to the state Department of Environmental Protection. Many people who have raised concerns to their township officials about potential air, water or quality-of-life impacts from proposed fracking activity have been told that’s not within a municipality’s purview to consider. In general, it’s been said like this: A municipality can regulate where the fracking is done but not how. But residents and environmental groups have been chipping away at those limits on multiple, parallel tracks and the efforts have intensified, according to the annual energy industry reports put out by Babst Calland, the law firm that represented Olympus Energy in its application to drill for natural gas in West Deer. To cut to the chase, it was a shock to the Rescinitis — and no doubt to others who have followed the industry — when, on Dec. 15, the West Deer Board of Supervisors unanimously denied Olympus’ conditional-use application to build a well pad it called Dionysus. The board deemed it highly probable that “the proposed deep well site will substantially affect the health, safety and welfare of the community, greater than what is normally expected from this type of use.” The members were swayed by testimony from residents in other townships who live next to other Olympus wells and by an analysis of the company’s state environmental violations, among other things. Even the supervisor that works in the oil and gas industry, whom Crowd had tried to prevent from voting on the issue, sided with the group.
Fracking In Pennsylvania Contaminates Drinking Water & Harms Pregnant Women – CleanTechnica - New research has shown that fracking in Pennsylvania has contaminated the drinking water where pregnant women live. Dr. Sandra Steingraber shared a thread on Twitter along with the link to the study. The study found evidence that drilling shale gas wells negatively impacts both the drinking water quality and the health of infants, indicating large social costs of water pollution.NEW RESEARCH: #Fracking in PA contaminates drinking water where pregnant women live and harms their infants. So, here's a link to the goddamn abstract and bc I have a PhD and a full-text pre-proof, I'll do an whole thread but as a mom: THIS IS ENOUGH https://t.co/O71mJEu97z — Dr. Sandra Steingraber (@ssteingraber1) February 10, 2022In her thread, Dr. Steingraber noted that this is a first of its kind study that used exact locations of mothers’ residences, gas wells, and public drinking water sources. The study combined the data with dates of infant births, measurement of water contaminants, and the timing of drilling and fracking activities.The results, she added, showed that prenatal exposure to a fracking well drilled within one kilometer (or 0.62 miles) of water sources, along with drilling near a mother’s home, raises risks for both preterm birth and low birthweight. Preterm birth, she added, is the leading cause of disability in the United States.“Notably, the increases in drinking water contaminants near fracking activities documented by the research team often were not sufficient to trigger regulatory violations. The authors thus conclude that the infant health harms they found were either due to increases in regulated water contaminants below the threshold level OR ‘unregulated contaminants that we, unfortunately, cannot observe.'”Dr. Steingraber also added her own context. “Both could be true. The federal government has legal limits for just over 90 contaminants in drinking water. No new chemicals have been added to the Maximum Contaminant Level list for 20 years, nor were limits set with prenatal or infant development in mind.“Back to the results: ‘We find consistent and robust evidence that drilling shale gas wells negatively impacts both drinking water quality and infant health.’“Personal comment: I’ve been reading fracking and public health data pretty much daily for 10 years, and I still cry. Is anyone okay with these data? I’m not.” You can read Dr. Steingraber’s full thread here.
Construction wraps on problem-plagued Mariner East pipeline - Work is finished on a multibillion-dollar pipeline system that connects the vast Marcellus Shale gas field in western Pennsylvania to an export terminal near Philadelphia, according to its corporate owner, which faces criminal charges that it fouled waterways and residential water supplies during pipeline construction. Energy Transfer said Wednesday that construction work on its Mariner East pipeline network was completed this month. The announcement was included in the company's fourth-quarter earnings report. The Texas-based company said it was preparing to put the newest pipeline into service. The Mariner East 1, Mariner East 2 and Mariner East 2X pipelines are designed to carry propane, ethane and butane from the Marcellus Shale and Utica Shale gas fields to a refinery processing center and export terminal in Marcus Hook. In October, Energy Transfer was charged criminally after a grand jury concluded that it broke Pennsylvania environmental laws and fouled waterways and residential water supplies across hundreds of miles as Mariner East was built. Prosecutors said Energy Transfer ruined the drinking water of at least 150 families statewide. A spill of thousands of gallons of drilling fluid contaminated wetlands, a stream and part of a 535-acre lake at Marsh Creek State Park outside Philadelphia. The company has yet to enter a plea in the case. Energy Transfer has been assessed more than $24 million in civil fines, including a $12.6 million fine in 2018 that was one of the largest ever imposed by the state. State regulators have periodically shut down pipeline construction. Even so, the operational portion of the Mariner East network transported a growing volume of natural gas liquids last year, up nearly 10% over 2020, the company said. With work on the final phase of construction now complete, total capacity is projected at 350,000 to 375,000 barrels per day.
Mariner East pipeline project is finished, after years of environmental damage, construction delays -Pipeline builder Energy Transfer says it has finished the troubled 350-mile-long Mariner East natural gas liquids project — five years after construction began, two years after the initial planned completion date, and several months after the state Attorney General’s office filed 48 criminal charges against the Texas-based company. The bulk of the product will be shipped to Scotland to make plastics.Pennsylvania’s Department of Environmental Protection issued new permits in December allowing construction on the section of the pipe that had been halted since August 2020, after the company spilledbetween 21,000 and 28,000 gallons of drilling mud fluid into Marsh Creek Lake. That Chester County section was one of the last parts of the line to be completed.The end of pipeline construction means the focus will be on shipping more Marcellus and Utica Shale gas overseas — something welcomed by building trades looking to boost jobs at the export terminal in Marcus Hook, but dreaded by those living with an operating pipeline in their backyards.“This is bad news,” said Ginny Marcille-Kerslake, a Chester County resident and organizer for Food and Water Watch. “Putting the … Mariner East 2 pipeline into operation means increased risk of a catastrophic explosion in densely populated communities in Southeastern Pennsylvania.” Kerslake said there are no good emergency plans in the event of a leak. The pipes contain natural gas liquids (NGL) including ethane, butane and propane. They are not odorized, and are heavier than air. When a leak occurs, they sink and can easily ignite and explode. She said families are “put at unacceptable risk for this out-of-state corporation to profit from shipping fracked ethane overseas for more plastic junk. Relying on luck is not enough.”
WV House changes bill to weaken oversight of oil and gas tanks closest to public water intakes - A bill easing aboveground storage tank regulations was rendered signi¦cantly more lenient toward oil and gas tank operators by an amendment added Monday on the §oor of the West Virginia House of Delegates. House Bill 2598 was amended to include tanks closest to public water intakes among those that would be exempted from mandated evaluations and certi¦cations by registered professional engineers or other approved individuals under the state Aboveground Storage Tank Act. The state de¦nes zones of critical concern — the areas nearest to water intakes — as consisting of a ¦ve-hour water-travel time in streams to an intake. The Medicis Are Back americanbanker.com The bill would allow tanks in that category with 210 barrels (8,820 gallons) or less of brine water and other §uids produced in connection with hydrocarbon production, transmission and storage to be self-inspected and self-certi¦ed by their owner or operator at least once per year and reported to the state. Also covered by the exemption would be tanks with 10,000 gallons or less of sodium chloride or calcium chloride water for roadway snow and ice pretreatment. Owners or operators would only have to perform and document secondary containment inspections at least once per month, less often than the current requirement that they be inspected once every two weeks. House Energy and Manufacturing Committee Vice Chairman John Kelly, R-Wood, moved to amend the bill during Monday’s §oor session, saying he did so at the request of the West Virginia Department of Environmental Protection. DEP general counsel Jason Wandling agreed with committee Chairman Bill Anderson, R-Wood, prior to the panel’s approval of the bill last week that it was a “reasonable compromise,” compared with last year’s version of HB 2598. Last year’s HB 2598 would have fully exempted the category of tanks closest to water intakes holding up to nearly 9,000 gallons of oil or gas from regulation under the Aboveground Storage Tank Act, which requires registration and certi¦ed inspection of such tanks, as well as the submission of spill-prevention response plans. The Legislature passed the Aboveground Storage Tank Act in 2014 in response to the Elk River chemical spill in January of that year that contaminated the drinking water supply for 300,000 people. The Medicis Are Back americanbanker.com Nearly 11,000 gallons of a mixture of a coal-cleaning solvent and polyglycol ethers escaped a Freedom Industries aboveground storage tank and §owed downstream to the intake of a West Virginia American Water treatment facility 11/2 miles downriver. The Legislature has gradually weakened its oversight of oil and gas tanks since then. The exemptions started a year after the Elk River spill, when the Legislature in 2015 scaled back the Aboveground Storage Tank Act to only require inspection of tanks that contain either 50,000 gallons or more of hazardous material or are located within a zone of critical concern. In 2017, the Legislature carved out an exemption for tanks outside of zones of critical concern.
Dominion announces deal to sell West Virginia natural gas utility --- Dominion Energy has reached an agreement to sell a natural gas utility in West Virginia.According to a release, Dominion will sell Hope Gas, Inc. to Ullico Inc’s infrastructure fund for $690 million, and the deal is expected to close later this year.Ullico then plans to integrate the utility into Hearthstone Utilities, Inc., which is a portfolio company that owns and operates gas utilities in Indiana, Maine, Montana, North Carolina, and Ohio. As part of the agreement, Hearthstone will also move its headquarters to West Virginia.
Mountain Valley hits another snag in its pipeline plans -Already slowed by winter weather and a court’s reversal of two vital permits, construction of the Mountain Valley Pipeline has hit another hiatus. The U.S. Army Corps of Engineers said this week it will not act on Mountain Valley’s pending application to cross streams and wetlands now that a federal appeals court has struck down another agency’s conclusion that the pipeline would not jeopardize endangered species in its path. “Our evaluation will require review of a valid BO,” or biological opinion, from the U.S. Fish and Wildlife Service, Col. Jayson Putnam of the Army Corps wrote in a letter Wednesday to an attorney for pipeline opponents. On Feb. 3, the 4th U.S. Circuit Court of Appeals invalidated an opinion from the federal Fish and Wildlife Service, ruling that the agency had not adequately considered how construction of the 303-mile long natural gas pipeline would impact endangered species in its path. After receiving the letter from Putnam, attorney Derek Teaney of Appalachian Mountain Advocates on Friday withdrew a request to the Fourth Circuit to stay the stream-crossing permitting process, which had been made before the Feb. 3 ruling. With the Corps’ assurance that it will not move forward for now, there is no longer a showing of “irreparable harm” to the environment that would have required a stay, Teaney wrote in court documents. The latest development means that Mountain Valley is nowhere close to obtaining three sets of federal permits it needs to complete the $6.2 billion project. “The recent letter from the Corps means MVP can’t be granted an ‘all access pass’ to our waterways before the pipeline’s effects on endangered fish are carefully studied,” Caroline Hansley, a senior organizer with the Sierra Club, said in a statement Friday. In rejecting the biological opinion, the Fourth Circuit cited concerns about the fate of two endangered species — the Roanoke logperch and the candy darter — that feed along river bottoms that are in danger of being coated by sediment washed by rainfall from pipeline construction sites. Mountain Valley has been cited nearly 400 times with violating state regulations meant to limit erosion and sedimentation.
Chickahominy Pipeline will 'press pause' on project crossing five Central Va. counties - Chickahominy Pipeline says it will “press pause” on the development of a pipeline through five Central Virginia counties to supply a planned natural gas power plant in Charles City County known as Chickahominy Power. Beth Minear, a spokesperson for Chickahominy Pipeline, confirmed Monday that Chickahominy Pipeline had notified all five counties of the change in plans. The company attributed the halt to a decision by the regional electric grid manager, PJM, to remove the 1,600 megawatt natural gas Chickahominy Power from its planning queue because of its failure to meet development deadlines. In a filing with the Federal Energy Regulatory Commission, PJM said it had canceled Chickahominy Power’s interconnection service agreement — a plan for how new electric generation will be incorporated into the broader grid — because the company “failed to meet its milestones,” including one requiring that 20 percent of the site construction be completed by November 2021. Furthermore, PJM said it had rejected the company’s request to extend those milestones “because Chickahominy has demonstrated no diligence or meaningful progress on the Chickahominy Project since entering the queue in October 2016.” On Friday, FERC upheld PJM’s decision, finding that it had been reasonable and that “in light of the continued regulatory uncertainty facing the project, Chickahominy’s proposed project development timeline appears speculative at this juncture.”
Propane industry part of coalition supporting Line 5 litigation -A coalition of energy product transporters and manufacturers, including propane industry stakeholders, is supporting litigation to keep open the Enbridge Line 5 light oil and natural gas liquids pipeline serving Michigan, the surrounding states and Canada.The coalition, representing retail propane marketers, propane and crude oil pipeline operators, and gasoline, diesel, jet fuel and industrial raw materials manufacturers, filed an amicus brief in federal district court in support of litigation to block Michigan’s attempt to shut down the pipeline.The brief was filed as part of the litigation between Enbridge and the state of Michigan in response to a November 2020 order issued by Michigan Gov. Gretchen Whitmer to shut down the pipeline. Whitmer maintains that Line 5 poses a threat to the Great Lakes.According to the Association of Oil Pipe Lines, the amicus brief reiterates federal law through the Pipeline Safety Act preempts Michigan’s attempts to shut down an interstate pipeline because Congress granted the federal government exclusive authority to regulate interstate pipeline safety.“Attempts by Michigan’s governor to shut down the Line 5 pipeline not only will lead to major energy shortages in the region and severe economic consequences for Michigan, neighboring states and Canada, but it is unlawful and a violation of federal law,” says Andy Black, president and CEO of the Association of Oil Pipe Lines. The National Propane Gas Association (NPGA) and four state propane associations (Indiana, Michigan, Ohio and Wisconsin) signed the amicus brief. “Line 5’s continued operation is crucial to reliably heating homes in Michigan and surrounding states,” says Steve Kaminski, president and CEO of NPGA. “The environmental benefits and relative affordability of propane – recognized by the EPA as a clean, alternative fuel – perfectly positions it to accelerate decarbonization and ensure equitable access to clean energy.”
New report finds Enbridge Line 5 closure will cause little pain to Michigan - Among the arguments used by Canadian energy giant Enbridge in support of its Line 5 pipeline that runs through Michigan is that, if it’s closed, there will be a significant impact on energy prices for consumers. But a new report, released Wednesday, takes issue with that assessment, concluding that any energy increases will be modest if the shutdown is coordinated properly. Environmental Defence Canada, an environmental group, commissioned the report from experts in the gas and oil sector. It suggests that shutting down Line 5 is manageable and that there are other options to meet Canada’s demand for oil and gas. The report, written by Martin Meyers of Meyers Energy Consulting, LLC, found there are viable alternatives to Line 5, which runs from Wisconsin down through the environmentally sensitive Straits of Mackinac and across Michigan to Sarnia, Ontario. Enbridge Line 78, for instance, flows from Illinois through Indiana to Sarnia, the report notes, and can be run at greater capacity to help recoup oil lost from Line 5. In addition, adding rail and truck capacity, as well as one more marine tanker, can make up the remaining shortfall, the report concludes. “The impact of these changes on consumer prices for refined petroleum products such as gasoline and diesel fuel in Ontario and Quebec would likely be very modest, to the point that such changes would likely go unnoticed,” the report concludes. [Disclosure: Research for the report was supported by the Charles Stewart Mott Foundation, which is a funder of The Center for Michigan, which includes Bridge Michigan. Mott had no role in the reporting or writing of this article.]Line 5 is part of Enbridge’s oil and gas pipeline system in western Canada. It carries oil from Superior, Wisconsin through the Straits of Mackinac into Michigan, reaching refineries in Sarnia, Ontario.Opponents of Line 5, which include Indigenous tribes, want the oil pipeline shut down, saying the aging pipes that run along the bottom of the straits pose a risk of polluting the Great Lakes, the world’s largest accessible body of freshwater.Proponents argue the pipeline is safe and well monitored and must remain open to keep trade, jobs and the economy going. They also claim that, without Line 5, Canada and rural northern Michigan will face an energy crisis because there isn’t an alternative to it.Whitney Gravelle, attorney for and chairperson of the Bay Mills Indian Community, opposes Line 5 and said the new report supports Tribal Nations’ appeals to shut down the pipeline and any additions to it.“It only reaffirms essentially what we've been saying all along here in the state of Michigan and from our respective tribal nations that Line 5 can be decommissioned and shut down with minimal impacts,” Gravelle said. Michigan Gov. Gretchen Whitmer announced the state would shut down Line 5 in 2021 but that effort is currently tied up in federal litigation with Enbridge. Canada is backing the Canadian energy company and contends that any efforts by Michigan to shut down the pipeline would breach an international treaty between the two countries.Robert Leddy, a spokesperson for Whitmer, said Tuesday the governor intends on following through with closing Line 5, but he did not specifically comment on the report’s findings.
FERC sets new environmental hurdles for gas pipeline approvals - The Federal Energy Regulatory Commission moved Thursday to more rigorously consider the effects of climate change in weighing whether to approve proposed gas pipelines or related infrastructure projects. The decision will make it more difficult to build infrastructure for fossil fuels, an outcome sought by environmentalists. FERC commissioners voted 3-2 to update the commission's pipeline certificate policy statement and to adopt an "interim greenhouse gas emissions policy statement" to account for a project's greenhouse gas emissions as well as its effects on local landowners and "environmental justice communities," or those which are especially subject to pollution, in gauging if the project is in the public's interest. The commission's three Democratic nominees voted for the measures and the two Republicans against. A fact sheet put out by the commission explains, "The more interests adversely affected, or the more adverse impact a project will have on a particular interest, the greater the showing of public benefits from the project must be to balance the adverse impact." It also said pending and future projects are subject to the updated policy statement. The move was hailed by liberal Democrats and environmentalists, who generally view regulatory agencies like FERC as critical to mitigating climate change. Energy and Commerce Committee Chairman Frank Pallone, a New Jersey Democrat, praised the decision and called it "a significant step towards protecting the property rights of private landowners and ensuring that environmental justice communities are treated fairly and equitably in the pipeline certification process." Meanwhile, critics described the decision as political and threatening to the energy industry. Senate Energy Committee Chairman Joe Manchin, a West Virginia Democrat, said the commission "went too far by prioritizing a political agenda over their main mission — ensuring our nation’s energy reliability and security."
FERC issues 'historic' overhaul of pipeline approvals - The Federal Energy Regulatory Commission issued sweeping new guidance yesterday for natural gas projects, including a first-ever climate change threshold, upending decades of precedent for how major energy infrastructure is approved. FERC updated a 23-year-old policy for assessing proposed natural gas pipelines, adding new considerations for landowners, environmental justice communities and other factors. In a separate but related decision, the commission also laid out a framework for evaluating projects’ greenhouse gas emissions. The commission’s three Democratic members approved both policies, while the two Republicans on the panel opposed them. The natural gas orders came during FERC’s regular open meeting, during which the agency also opened a new proceeding on technologies to make electric power lines more efficient and announced a new senior staff member at the Office of Public Participation. Set up for the first time last year, the office is designed to help members of the public engage with the agency as well as provide technical support for those affected by commission decisions. The revised policies represent a notable departure for FERC, which critics say has a pattern of “rubber-stamping” gas pipelines and liquefied natural gas terminals without enough consideration for environmental harms or effects on communities. But while environmental advocates and some Democratic lawmakers welcomed the decisions, natural gas groups and their allies said the changes could raise energy costs and make it harder to meet demand for gas. FERC’s Republican commissioners also said the policies go beyond FERC’s role as an independent energy regulator, and Sen. Joe Manchin (D-W.Va.), the chair of the powerful Senate Energy and Natural Resources Committee, called FERC’s moves “reckless.” “The Commission went too far by prioritizing a political agenda over their main mission — ensuring our nation’s energy reliability and security,” Manchin said in a statement. “The only thing they accomplished today was constructing additional road blocks that further delay building out the energy infrastructure our country desperately needs.” For years, FERC has generally looked for evidence of economic demand when considering whether or not to approve a new gas project, as outlined in its “certificate policy statement” on natural gas pipelines. So long as a developer could show that one or more shippers had committed to buying the gas, the independent agency would sign off on nearly all gas pipeline applications it received, under FERC policy and historic precedent. Until recently, FERC also generally did not consider how gas proposals would contribute to climate change. While the agency began evaluating projects’ greenhouse gas emissions last year, the commission had no agreed-upon method for determining whether a project’s climate change impacts would be significant. Under the revisions to the certificate policy statement approved yesterday, the commission will consider four major factors before approving a project: the interests of the developer’s existing customers; the interests of existing pipelines and their customers; environmental interests; and the interests of landowners, environmental justice populations and surrounding communities. Henceforward, the commission must weigh all of the benefits against all of the adverse impacts, FERC staff said.
Gas pipeline regulators to consider climate impacts for new projects -A federal agency that considers whether to approve or reject natural gas pipelines will now weigh the projects’ contributions to climate change as part of their decisions. In determining whether a project is in the public interest, the Federal Energy Regulatory Commission (FERC) voted on Thursday to examine greenhouse gas (GHG) emissions from the project’s construction and operations — as well as the emissions from when the gas is ultimately burned to make electricity. Environmental advocates have long criticized the agency for not considering these impacts in its reviews, and have more broadly argued that it should stop approving as many pipelines as it has in the past. According to a 2020 investigation by House Democrats, the agency has, over the past 20 years, approved more than 99 percent of the pipeline projects that have come before it. While FERC’s three Democratic commissioners supported the proposal, its two Republican members opposed it. Chairman Richard Glick (D) said that under the new policy, even if a project will have significant climate change impacts, the commission could still find that its benefits outweigh those costs. He also argued that the decision will add legal certainty, as courts can block FERC-approved projects based on environmental concerns. “If we were to continue the commission’s turning a blind eye to climate change and greenhouse gas emissions, we would simply be adding to the legal uncertainty of each commission order approving a project,” Glick said. Republican Commissioner James Danly disagreed. “The contents are very amorphous,” he said. “It is very difficult for us to achieve the objectives of the Natural Gas Act, which is to encourage the orderly development of natural gas infrastructure…when we’re adopting policies that are either vague or make it difficult to rationally allocate capital.” The new guidance will be applied immediately, though it was only issued on an interim basis. The agency is currently accepting public comments on it, and may make changes down the line based on that feedback. The move is already meeting some opposition from industry. Amy Andryszak, president and CEO of the Interstate Natural Gas Association of America, which represents pipeline interests, said in a statement that the guidance “does not add clarity to the certification process, but instead creates more questions.” “In the interim GHG policy statement, the majority established a seemingly arbitrary number to determine the significance of incremental GHG emissions from a project,” Andryszak said. “Further, it is uncertain how much mitigation will be required of developers to satisfy the Commission.” Meanwhile, the agency also announced that it would update guidelines for its reviews overall, including by taking on “robust consideration” of impacts to communities that are disproportionately harmed by pollution.
U.S. marketed natural gas production forecast to rise in 2022 and 2023 – EIA - We forecast that U.S. natural gas marketed production will increase to an average of 104.4 billion cubic feet per day (Bcf/d) in 2022 and then further increase to a record-high 106.6 Bcf/d in 2023, according to our latest Short-Term Energy Outlook (STEO). Around 97% of production over the next two years will come from the Lower 48 states (L48), excluding the Federal Offshore Gulf of Mexico (GOM). The other 3% will come from Alaska and the GOM.We estimate that the wholesale spot price of natural gas at the U.S. benchmark Henry Hub will average $3.92 per million British thermal units (MMBtu) in 2022, an eight-year high, and will average $3.60/MMBtu throughout 2023. We expect these elevated prices will drive continued increases in U.S. drilling activity and natural gas production.We forecast that legacy production—production from wells drilled before December 2021—in the L48 will average 83.2 Bcf/d in 2022 and fall 21% to 65.9 Bcf/d in 2023. However, production from new wells will contribute 18.1 Bcf/d in 2022 and increase to 37.8 Bcf/d in 2023, offsetting declining production from legacy wells and bringing total L48 marketed gas production to 103.7 Bcf/d in 2023.U.S. natural gas production growth will primarily come from the Appalachia region in the Northeast, the Permian region in western Texas and southeastern New Mexico, and the Haynesville region in Texas and Louisiana.Haynesville production will grow by 1.6 Bcf/d annually, on average, in the next two years, according to our STEO forecast. As natural gas prices remain elevated, drilling in the Haynesville region remains economical, even with relatively deeper and more expensive well development. In addition, Haynesville’s greater well productivity and its proximity to liquefied natural gas export terminals and major industrial natural gas consumers along the U.S. Gulf Coast draws operators to the region.We forecast that the Permian region will contribute 2.2 Bcf/d to production growth in 2022 and 1.2 Bcf/d in 2023. Our forecast for the West Texas Intermediate crude oil price remains above $60 per barrel, prompting operators to increase oil-directed drilling activity in the region, which would also increase associated gas production.In recent years, the Appalachia region has provided the largest share of U.S domestic natural gas output, accounting for one-third of L48 production annually since 2016. Although production growth has slowed in recent years because of less drilling activity and emerging pipeline capacity constraints, Appalachia well-level productivityhas been increasing, offsetting some of the drilling decline. We estimate that production from the Appalachia region will grow by 0.3 Bcf/d in 2022 and 0.7 Bcf/d in 2023.
Natural Gas Production Said on Pace for Growth Across Multiple Lower 48 Regions -Major U.S. onshore plays will add close to 500 MMcf/d of natural gas production from February to March on the strength of growth out of the Haynesville Shale and the Appalachian and Permian basins, according to updated modeling from the Energy Information Administration (EIA). In its latest Drilling Productivity Report (DPR), published Monday, EIA said it expects a combined 499 MMcf/d of production growth from seven key U.S. regions. Combined natural gas production from the Anadarko, Appalachian and Permian basins, as well as from the Bakken, Eagle Ford, Haynesville and Niobrara shales, will rise to 91.686 Bcf/d from February to March, the latest DPR data show.The Haynesville is set to lead with 174 MMcf/d of production growth month/month, with the Permian adding 124 MMcf/d of growth and the Appalachian region contributing an incremental 114 MMcf/d, according to EIA.Rounding out the other projected natural gas production changes, the agency predicted growth out of the Bakken (up 10 MMcf/d), Eagle Ford (up 78 MMcf/d) and Niobrara (up 4 MMcf/d), with the Anadarko expected to see output fall 5 MMcf/d month/month.Oil production from the seven plays is expected to grow 109,000 b/d to just over 8.7 million b/d from February to March. EIA predicted the largest output growth from the Permian at an incremental 71,000 b/d month/month, with the Eagle Ford on track to grow output 24,000 b/d. Other plays were predicted to see more modest sequential growth of 1,000-6,000 b/d for the period.The total drilled but uncompleted (DUC) well backlog across the seven regions shrank by 191 units from December to January to fall to 4,466, according to EIA’s latest count. Each of the seven regions saw a net decline in total DUC wells for the period, with the Permian posting the largest month/month drawdown at 89. DUC well declines were also recorded in the Anadarko (down 12), Appalachia (down 23), Bakken (down 27), Eagle Ford (down 28), Haynesville (down three) and Niobrara (down nine), the DPR data show. EIA’s DPR makes use of recent rig data along with drilling productivity estimates and estimated changes in production from existing wells to model changes in production from the seven regions.
Rally in natural gas futures as the European weather model reflects a prolonged winter; cash rallies – -- Natural gas futures staged a stunning recovery Monday as one of the major weather models added a huge chunk of demand to the late-February forecast. The March Nymex gas futures contract settled on the higher end of its trading range at $4.195/MMBtu, up 25.4 cents from Friday’s close. April jumped 22.5 cents to $4.160. Spot gas prices also strengthened as frigid temperatures continued to drive up heating demand across the eastern United States. NGI’s Spot Gas National Avg. climbed $1.040 cents to $5.670. The latest cold blast that hit the eastern United States this weekend is already its nearing its end, with temperatures set to rise by midweek ahead of another winter storm. It’s this weather system that sent the gas market into a tizzy on Monday as models disagreed on how long the chill would linger. NatGasWeather said the European model gained 17 heating degree days for the 15-day outlook, keeping the cold air around for the last week of February. The Global Forecast System (GFS), however, maintained through subsequent runs a “rather warm and bearish” set-up for Feb. 21-28. Bespoke Weather Services said the bias of the pattern is to the side of below-normal demand given the latest changes in the modeling. However, “it has less impact here, especially with production around 95 Bcf.” Nevertheless, the mere potential for cold to stick around into March appears to have caused a few jitters in the market since the next government inventory report could show inventories taking another large step down. The Energy Information Administration (EIA) is scheduled to release the next weekly storage report on Thursday and though another 200-plus Bcf withdrawal is unlikely, the draw is all but certain to blow past historical levels. NGI is modeling a 189 Bcf pull from stocks for the week ending Feb. 11. For comparison, a 227 Bcf withdrawal was recorded in the same period last year, and the five-year average draw is 154 Bcf.
The price of natural gas in the United States has risen more than 6%, owing to cooler forecasts and an increase in European prices --Natural gas futures in the United States increased by more than 6% on Monday as a result of forecasts for cooler weather and rising heating demand over the next two weeks. Traders claim a 8% rise in European gas prices that kept demand for US liquefied natural gas (LNG) exports at new highs. This is partly due to Russia's possibility of invading Ukraine and delaying gas deliveries to the rest of Europe. The price of front-month gas futures in the United States increased by 25.4 cents, or 6.4 percent, in March, with a profit of $4.195 per million British thermal units (mmBtu), the highest level since February 8. Gas futures traded around $27 per mmBtu in Europe and $25 in Asia. The US market has focused more on changes in weather and domestic demand in the United States than what is happening around the globe so far in 2022. Compared to Europe's oil prices, the United States only followed European prices for one third of the time. In the fourth quarter of 2021, the US market has focused more on changes in weather and domestic demand. The rise in European prices was difficult to ignore, indicating that demand for U.S. LNG will remain high as global gas prices fall significantly above futures, as utilities around the world strive for cargoes to meet growing demand in Asia and replenish low stockpiles in Europe. With growing concerns, Russia may invade Ukraine. Europe and the United States would likely impose sanctions on Moscow, which might cause Russia to reduce gas supplies to Europe. Russia is responsible for 30%-40% of Europe's gas supplies, totaling 16.3 billion by 2021. Tankers were loading at all seven LNG export facilities in the United States for the first time ever after Venture Global received approval from federal authorities to carry the first cargo at its Calcasieu Pass LNG plant in Louisiana on February 7th. A tanker was sent to Calcasieu on February 7 and will likely leave with the plant's first cargo this week. So far in February, the amount of gas flowing to all LNG export facilities in the United States increased to an average of 12.6 billion cubic feet per day, the highest level ever recorded in January as the Calcasieu liquefaction trains reached service. Refinitiv, a data provider, said average output in the Lower 48 states in the United States fell from a record of 97.3 billion in December to 94.0 billion in January and 92.4 billion so far in February, as well as in several producing regions. According to Refinitiv, output increased to 95.2 billion on Friday, the highest level since January 1, with a total of 86.3 billion in the day, which was the lowest level since February 2021. Temperatures in the spot market and rising heating demand in the Northeast have kept power and gas prices in New York and New England at or near their highest levels since January 2018.
Natural Gas Futures See Big Intraday Swings, Finish Higher on Chillier Weather Outlook - Natural gas futures were choppy Tuesday. Prices swung sharply higher early on the increasing potential for cold weather to linger into early March, but then retreated significantly as part of a broader commodities sell-off amid easing political tensions. The last half hour of trading brought another surge following the latest weather data, with the March Nymex gas futures rallying 11.1 cents to a $4.306/MMBtu settlement. April ticked up 8.1 cents to $4.241. Spot gas prices were mostly higher despite a mild break ahead of another winter storm targeting the Lower 48 this weekend. However, a huge slide in the Northeast sent NGI’s Spot Gas National Avg. tumbling $1.595 to $4.075. Although it looked like the upcoming winter blast could be the season’s final bow as recently as last week, models reversed course over the past few runs, erasing all the widespread warmth that had been in the forecast for the end of the month. Bespoke Weather Services said the American and European models made yet another move in the colder direction overnight given some changes in the climate patterns. “Given all of the recent model volatility, confidence is back on the low side,” Bespoke said. “Signals from tropical forcing do not mesh with the colder changes, in our view, but the correlation certainly is not 1:1, so we remain cautious.” NatGasWeather noted that the midday Global Forecast System (GFS) was still warmer than the European model, but it trended closer in line by showing subfreezing temperatures moving more aggressively into the northern United States for Feb. 26-March 2. All said, the GFS added nearly 25 heating degrees in a 24-hour period. “Clearly, this is a bullish trend,” NatGasWeather said.
U.S. natgas jumps almost 10% to near 2-week high on colder forecasts (Reuters) - U.S. natural gas futures jumped almost 10% to a near two-week high on Wednesday on forecasts for much colder weather and higher heating demand through early March than previously expected. Traders noted that prices rose despite the slow return of U.S. production from cold weather-related reductions over the past month, and a 6% drop in European gas futures due to what looks like an easing of Russia-Ukraine tensions. Over the past month or so, the United States has worked with other nations to ensure that gas supplies — mostly from liquefied natural gas (LNG) — would keep flowing to Europe in case Russia cuts off exports to the rest of the continent. The United States and Europe have said they would sanction Russia if it invaded Ukraine, likely prompting Russia to cut some gas exports to Europe. Russia provides around 30%-40% of Europe's gas supplies, totaling about 16.3 billion cubic feet per day (bcfd) in 2021. Since the start of the year, however, the U.S. gas market has focused more on changes in U.S. weather, domestic supply and demand than world events. So far in 2022, U.S. gas followed European prices only about a third of the time versus two-thirds in the fourth quarter. After weeks of near record volatility, U.S. front-month gas futures for March delivery rose 41.1 cents, or 9.5%, to settle at $4.717 per million British thermal units (mmBtu), their highest close since Feb. 3. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell from a record 97.3 bcfd in December to 94.0 bcfd in January and 92.7 bcfd so far in February, as cold weather froze oil and gas wells in several producing regions. But on a daily basis, gas production has gained almost every day since dropping to 86.3 bcfd during a Feb. 4 winter storm, reaching a high of 95.2 bcfd on Feb. 11, the most since Jan. 1. Output on Wednesday, however, was on track to slip for a second day in a row to a preliminary one-week low of 94.3 bcfd. Even though meteorologists forecast colder weather than previously expected, they still predicted higher temperatures next week than this week. Refinitiv projected average U.S. gas demand, including exports, would slide from 122.9 bcfd this week to 121.2 bcfd next week. Next week's forecast was higher than Refinitiv's outlook on Tuesday.
US natural gas inventories decline by 190 Bcf with smaller withdrawals ahead | S&P Global Platts - US gas storage inventories declined by less than 200 Bcf for the first time in a month and below-average draws appear likely in the weeks ahead, but the upcoming Henry Hub summer strip remains near $4.60/MMBtu. Storage fields withdrew 190 Bcf for the week ended Feb. 11, according to data released by the US Energy Information Administration on Feb. 17. Working gas inventories decreased to 1.911 Tcf. US storage volumes now stand 404 Bcf, or 17.5%, less than the year-ago level of 2.315 Tcf and 251 Bcf, or 11.6%, less than the five-year average of 2.162 Tcf. The withdrawal was less than the 197 Bcf draw expected by an S&P Global Platts survey of analysts. Responses to the survey ranged from a 185 Bcf to 214 Bcf withdrawal. It outpaced the five-year average of 154 Bcf but trailed last year's 227 Bcf pull in the corresponding week. That week in 2021 marked the early days of the deep freeze winter event that eventually drove the second-largest withdrawal on record. The NYMEX Henry Hub March contract fell 14 cents to $4.58/MMBtu following the EIA's storage report release. The prompt-month contract closed at $3.22/MMBtu this day last year. The upcoming summer strip, April through October, fell about 8 cents to $4.55/MMBtu. The South Central storage region drew 74 Bcf, the most of all five regions once again. Total Southeast demand was 6.6 Bcf/d higher than the five-year average in the month to date, driven by growing LNG demand, which is averaging 3.7 Bcf/d above the past five years, according to data by S&P Global Platts Analytics. Even excluding LNG demand, Southeast demand is setting new records for this part of February. Residential and commercial, industrial and power are averaging a combined 21.7 Bcf/d month to date, 2.8 Bcf/d above the five-year average. Res-comm demand is leading growth at 5.6 Bcf/d, 1.4 Bcf/d above the five-year average, while power demand is averaging 9.3 Bcf/d, 1 Bcf/d above the past five years. Industrial demand has also grown, to 6.7 Bcf/d in the month to date, 390 MMcf/d above the five-year average. Warmer weather ahead looks to slice into demand in the coming weeks. Population-weighted temperatures in the Southeast are expected to climb in the second half of the month to 58.5 degrees Fahrenheit, 7 degrees warmer than the month to date. On average, over the past five years, res-comm, industrial and power demand have fallen a combined 570 MMcf/d after Feb. 16, so demand may be set to fall through the rest of the month. A forecast by Platts Analytics calls for a 108-Bcf draw for the week ending Feb. 18, which would measure nearly 50 Bcf below the average draw and more than 200 Bcf less than last year.
U.S. natgas falls 5% on smaller-than-expected storage draw, rising output (Reuters) - U.S. natural gas futures fell about 5% on Thursday on a slightly smaller-than-expected storage draw last week and as production slowly recovered from cold weather-related reductions this month. Prices fell despite forecasts for colder weather and higher heating demand than expected, and even though higher global gas prices have kept demand for U.S. liquefied natural gas (LNG) exports near record highs. Traders said the U.S. gas market was shrugging off big moves in Europe, where gas prices were up about 8% on Thursday, due in part to supply concerns related to tension between Russia and Ukraine. The U.S. Energy Information Administration (EIA) said utilities pulled 190 billion cubic feet (bcf) of gas from storage during the week ended Feb. 11. Analysts cited near-record LNG exports for the bigger-than-normal withdrawal. The withdrawal was a little less than the 193-bcf decrease analysts forecast in a Reuters poll. It was smaller than the decline of 227 bcf in the same week last year, which was the start of the February freeze in Texas, but was more than the five-year (2017-2021) average decline of 154 bcf. After weeks of near record volatility, U.S. front-month gas futures for March delivery fell 23.1 cents, or 4.9%, to settle at $4.486 per million British thermal units (mmBtu). On Wednesday, the contract closed at its highest since Feb. 3. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell from a record 97.3 bcfd in December to 94.0 bcfd in January and 92.8 bcfd so far in February, as cold weather froze oil and gas wells in several producing regions. On a daily basis, gas production has gained almost every day since dropping to 86.3 bcfd during a Feb. 4 winter storm, reaching a high of 95.2 bcfd on Feb. 11, the most since Jan. 1. Output on Thursday was on track to hold at a preliminary 94.2 bcfd. With colder weather expected, Refinitiv projected average U.S. gas demand, including exports, would rise from 121.8 bcfd this week to 123.7 bcfd next week. The forecast for next week was higher than Refinitiv's outlook on Wednesday. Gas flowing to U.S. LNG export plants has risen to an average of 12.7 bcfd so far in February, which would top January's monthly record of 12.4 bcfd. A tanker arrived at Calcasieu on Feb. 7 and will likely leave with the plant's first cargo this week.
Unrelenting Cold Fuels Gains for Weekly Spot Natural Gas Prices; Futures Up, but Losing Momentum Futures prices also ended the week higher thanks to a much colder forecast for early March. Despite losing some steam late in the week, three straight days in the green were too much for bears to overcome. The March Nymex futures contract closed out the week at $4.431, up 23.6 cents from Monday’s settlement. With the latest winter storm ushering frigid temperatures and snow, gas markets rallied by more than $1.00 week/week in some parts of the Northeast. Iroquois Zone 1 cash jumped $2.190 to average $7.945, while Tenn Zone 5 200L picked up $2.475 to average $8.325. Upstream, Appalachia prices tacked on less than a quarter. Eastern Gas South was up 16.5 cents to $3.825. Prices in the western United States also put up stout price increases, with more messy weather systems set to hit the region beginning over the weekend. PG&E Citygate jumped 33.0 cents on the week to $4.840, while the SoCal Border Avg. moved up 41.5 cents to $4.210. AccuWeather said the first storm is expected to produce a wave of snow across the Washington and Oregon Cascades, as well as the mountainous terrain of Idaho, Montana and northwestern Wyoming from Sunday to Monday. A general swath of three to six inches is expected. Snow is forecast to expand into much of Wyoming, part of Utah, the Colorado Rockies, parts of northern Nevada and the northern Sierra Nevada by Tuesday. Areas much farther to the east in the Dakotas, Minnesota and Wisconsin also could be enveloped by snow. The second storm is set to arrive late Tuesday into Wednesday and is likely to be more impactful for the Southwest, according to AccuWeather. It is forecast to bring a moderate accumulation to much of the Sierra Nevada on the order of six to 10 inches with locally higher amounts. Strong winds also pose a fire risk to the drought-stricken region. How Long Will Winter Stick Around? With more cold in the forecast for the next couple of weeks, futures traders have been laser-focused on long-range models and whether the chilly temperatures could extend into March. Storage inventories already are well below historical levels, and any prolonged wintry weather could send stocks even lower ahead of the injection season.
EIA: US weekly LNG exports drop by four - EIA stated in its weekly LNG exports report that 23 LNG vessels departed the United States between 10 February and 16 February 2022. This is four LNG carriers less than the last reported week. Eight ships departed from Sabine Pass, five from Freeport, four from Cameron, three from Corpus Christi, two from Cove Point, and one from Elba Island. They held a combined LNG-carrying capacity of 85 billion cubic feet. On the other hand, the Henry Hub spot price rose from $4.06 per million British thermal units (MMBtu) last Wednesday to $4.39/MMBtu this week. Natural gas deliveries to LNG export facilities averaged 12.6 Bcf/d, or 0.2 Bcf/d higher than last week.
Huge U.S. Gulf Refinery Shutdowns Are Spooking the Gasoline Market -- When the second-largest U.S. refinery shuts down unexpectedly with no clarity as to when operations will return to normal, it could have an outsized impact on a market already squeezed for supplies. Marathon Petroleum Corp.’s 593,000 barrel-a-day Galveston Bay refinery in Texas City, Texas, got knocked out of commission Friday as frigid temperatures took out power across the Gulf Coast city. Marathon declined to comment on operations but the refiner has started buying some oil product, indicating it needs to cover obligations to customers, according to a person familiar with operations. Marathon may take several weeks to resolve issues that cropped up during the shutdown. Refiners this year are poised to enjoy fatter profit margins as stronger U.S. demand meets a market where more than 1 million barrels of capacity has been lost during the past two years. With a tightly supplied market and demand set to challenge 2019 levels, the last thing crude oil refiners need are unplanned outages slowing them down. Two Valero Energy Corp. refineries and one Chevron Corp. plant are also shut. Along with Marathon’s Galveston Bay, they represent about 1.2 million barrels a day of Gulf Coast refining capacity. Conventional spot gasoline in Houston jumped as much as 1.38 cents to a 1.5 cent premium to futures in New York on Monday, its strongest showing since Dec. 7. Valero’s 225,000 barrel-a-day plant in Texas City had begun restarting some production units as of Saturday after the Friday power loss, but could also take some days to restore full operations. Big production units like crude processors, cokers and fluid catalytic crackers can take time to restart after abrupt shutdowns leave liquid trapped in cooling pipes. Valero hasn’t responded to a request for comment. Meanwhile, Valero’s 263,800 barrel-a-day Houston refinery shut unexpectedly Monday amid heavy flaring. Chevron’s Pasadena refinery on the Houston Ship Channel is trying to restart operations after the boilers went down. Refinery utilization on the Gulf Coast, the largest concentration of U.S. refining might, was only 86% as of the week ended Jan. 28. This reflects the heavy maintenance season in progress as plants perform work that was pushed back in 2020 and 2021 to conserve cash during the height of the pandemic.
U.S. diesel stocks set to fall critically low: Kemp - Chartbook: https://tmsnrt.rs/3oV0eec (Reuters) - U.S. distillate fuel oil stocks are on course to fall critically low between now and the middle of the year, creating conditions for a potential spike in both crude and fuel prices, unless demand from freight firms falls. Distillate inventories slipped by another 2 million barrels last week to 120 million barrels, according to data from the U.S. Energy Information Administration (“Weekly petroleum status report”, EIA, Feb. 16). Stocks are currently 28 million barrels (18%) below the pre-pandemic five-year seasonal average for 2015-2019 and at the lowest level for the time of year since 2014. Three-quarters of distillate fuel oil is sold to trucking firms, railroads and shipping companies to move farm products, industrial raw materials and manufactured items. Low inventories are a symptom of the booming demand for freight amid a rapid recovery from the coronavirus recession led by the manufacturing sector. Distillate inventories normally deplete during the first half of the year, reaching a short-term minimum before the end of June, as refineries undertake maintenance and focus on making gasoline for the summer driving season. If inventories continue to deplete in line with the average for the ten years before the pandemic, they will fall to 105 million barrels sometime before the end of June, with a range of as much as a comfortable 118 million barrels or as low as 94 million barrels, which would be exceptionally tight. Even the average projection for inventories in 2022 could see them dip to the lowest level for any year since 2007 (https://tmsnrt.rs/3oV0eec). And many trajectories would leave inventories far below levels experienced in the last 15 years. The prospect of a diesel shortage is pushing prices for distillates as well as gasoline and crude higher and could see them spike over the next few months. RAMPING UP Low distillate stocks at mid-year would leave refiners racing to rebuild them before the next winter heating season. To avoid this scenario, refiners will have to process much more crude and/or reconfigure their equipment to boost the production of mid-distillates such as diesel and jet fuel at the expense of light distillates such as gasoline. But gasoline inventories are already 6 million barrels (-2.5%) below the pre-pandemic seasonal average, limiting the scope to squeeze them to rebuild distillate stocks by changing downstream processing. The shortage of distillate is bleeding into the gasoline market, driving up prices there to ensure refiners have an incentive to continue making gasoline rather than switching over to diesel. As a result, the only way for refiners to rebuild depleted distillate stocks will be processing more crude over the next six to nine months, boosting output of both light and medium distillates. The implied increase in refiners’ demand is likely to tighten global crude inventories even further and continue exerting upward pressure on oil prices through September. After adjusting for inflation, on-road diesel prices including taxes are at their highest for the time of year since 2014, averaging more than $4 per gallon (equivalent to $168 per barrel). But prices might need to rise much further to restrain consumption and avoid inventories falling to critically low levels.
USA Refiners Seek Alternatives to Russian Oil - Some U.S. producers of gasoline that have relied on imports of Russian oil are looking for alternative supplies amid heightened tensions in Eastern Europe. At least two major Gulf Coast refiners are seeking to diversify their purchases of fuel oil that can be used as a feedstock to produce gasoline and diesel, according to people familiar with the matter, who asked not to be named because they weren’t authorized to speak. One trader is looking for naphtha, a component of oil that’s used in gasoline blending, from sources other than Russia, another person said. The moves underscore the extent of concerns in the energy industry over the situation in Ukraine, after the Biden administration said Russia could invade. The Kremlin has repeatedly and firmly denied that it plans to attack. While the U.S. is the world’s largest oil producer and one of the biggest exporters, it’s still dependent on imports of crude products, and Russia is a top supplier. Biden has said the U.S. is ready to respond to a Russian attack with crippling economic sanctions. “Any restrictions on Russian flows would cause pain exclusively on the side of the buyer because the Russians can easily place their fuel oil in China or India,” said David Wech, chief economist at oil-data provider Vortexa Ltd. “That would put the U.S. in a difficult position because of the impact on gasoline prices,” he said. The questions over Russian oil supplies come as regular gasoline prices in the U.S. are the highest in almost eight years, putting further pressure on President Joe Biden to alleviate pain at the pump for consumers. Two refiners in Texas are reaching out to suppliers in Mexico and Brazil asking about long-term availability and prices, the people said. Brazil, which typically supplies fuel oil to Singapore and Europe, sold one cargo to the U.S. Gulf Coast in February and has another ship arriving by next month, according to tracking data compiled by Bloomberg. Russian straight-run fuel oil, known as Mazut 100, became a staple for refiners as it’s cheaper than crude oil, which is trading near the highest levels since 2014. The M100 can be used as either a crude substitute in the distillation tower, to top up crude oil from the Permian Basin, or as a feedstock to refinery units called cokers, to make gasoline. The versatility of Russian fuel oil makes it more desirable than the product supplied by Mexico, for example. Mexican fuel oil can only run in cokers, not in distillation units, due to its volatility. Valero Energy Corp, Exxon Mobil Corp. and Chevron Corp. are among the largest buyers of Russian fuel oil.
TotalEnergies Walks Away From North Platte Project in Gulf of Mexico --TotalEnergies, through its affiliate TotalEnergies E&P USA, has decided not to sanction and so to withdraw from the North Platte deepwater project in the US Gulf of Mexico (GOM), calling into question the development’s future. According to TotalEnergies, the decision was taken “as the company has better opportunities of allocation of its capital within its global portfolio.” The operator did not elaborate on what those opportunities might be. TotalEnergies holds a 60% operated interest in North Platte. Joint-interest owner Equinor holds the remaining 40% stake. TotalEnergies has notified Equinor and the relevant authorities of its immediate withdrawal from the project and of its resignation as operator which will be effective following a short transition period to ensure an orderly handover of operatorship. North Platte is a Paleogene discovery located across Garden Banks 959, Garden Banks 915, Garden Banks 916, and Garden Banks 958, in water depth of around 4,850 ft. It was one of three high pressure-/high temperature- fields under development in the GOM that would require 20,000-psi technology. In 2018, Statoil and Total completed their acquisition of Cobalt International Energy’s 60% operated interest in the North Platte discovery for an aggregate purchase price of $339 million. The partners had jointly presented the winning bid in a bankruptcy auction of some of Cobalt’s assets that was held on 6 March 2018. Statoil then owned a 40% nonoperated interest in North Platte, while Total increased its then 40% interest to 60% and took over operatorship. TotalEnergies remains a partner in Chevron’s Anchor project—another Paleogene find—which reached FID (final investment decision) in 2019 and will be drilled out using Transocean’s newbuild 20,000-psi Deepwater Titan drillship. Stage 1 of the Anchor development comprises a seven-well subsea development and semisubmersible floating production unit. First oil is anticipated in 2024. TotalEnergies awarded a front-end engineering design (FEED) contract for North Platte to Worley in early 2020. The base development plan comprised eight subsea wells and two subsea drilling bases connected via two production loops to a newbuild, lightweight FPU capable of producing 75,000 BOPD. Production would have been exported through existing oil and gas subsea networks.Separately, Beacon Offshore Energy reached FID on the Shenandoah project last year andhas contracted another new, 20,000 psi-capable Transocean drillship, the Deepwater Atlas,for the wells on that development. Hyundai Heavy Industries is building the semisubmersible floating production unit (FPU) for the project. First oil is expected in late 2024 or early 2025.
Petrobras Green Flags Gulf Of Mexico Assets Sale - Brazilian oil and gas company Petrobras has started a non-binding phase for the sale of interests in a joint venture company that owns interests in 14 offshore fields in the U.S. part of the Gulf of Mexico. Petrobras confirmed the beginning of the non-binding phase regarding the sale of the entire 20 percent stake held by its subsidiary Petrobras America Inc. (PAI) in the Texas-based company MP Gulf of Mexico (MPGoM) which owns offshore fields in the Gulf of Mexico. The intent to sell this stake was initially announced in October 2021. According to the company, potential buyers qualified for this phase will receive a process letter containing detailed information about the company, in addition to instructions on the divestment process, including guidelines for the preparation and submission of non-binding proposals. MPGoM is a joint venture company with an 80 percent stake held by Murphy Exploration & Production Company and 20 percent by Petrobras America Inc., created in October 2018, with the contribution of all oil and natural gas assets in production, located in the Gulf of Mexico, of both companies. The joint venture company holds participation as an operator or a partner in 14 offshore fields in the Gulf of Mexico. Petrobras’ share of the fields’ production in the first half of 2021 was 10,400 bpd of oil equivalent. The seven operated fields are Chinook/Cascade, Dalmatian, Front Runner/Clipper, Thunder Hawk, and Cottonwood. The company holds interests as a partner in Oxy’s Lucius, Kosmos’ Kodiak, Shell’s Habanero, W&T’s Tahoe, Hess’ Northwestern, Fieldwood’s SMI 280, and Chevron’s St. Malo. Petrobras claimed that the sale was in line with its portfolio management strategy and the improved allocation of the company's capital, aiming to maximize value and greater return to society. The Brazilian giant also started two more divestment processes late last year. Following the announcement that the sale of Gulf of Mexico interests was underway, Petrobras started the process for the sale of its entire interest in the Catuá field in the Campos Basin as well as beginning the bidding phase for the sale of the Uruguá and Tambaú fields in the Santos Basin – all three offshore Brazil.
Louisiana officials investigating methane plume seen from space --Louisiana officials are investigating the cause of a massive methane cloud that was spotted on satellite imagery, Bloomberg reported.A large methane plume — the highest concentration of the powerful greenhouse gas spotted by the satellite in the U.S. since October — was detected on Jan. 21. Had the release lasted an hour, it would have produced the same harmful short-term effects as the annual emissions from more than 1,900 cars, Bloomberg noted. Louisiana's Department of Natural Resources is now looking into what could have caused the plume, which likely originated near gas pipelines owned by Energy Transfer LP, Kinder Morgan Inc. and Boardwalk Pipelines LP. None of the companies have claimed responsibility for the gas cloud. According to the U.S. Pipeline and Hazardous Materials Safety Administration, no reports of a gas release were made in the area. The Biden administration in November announced a series of actions aimed at tackling methane, which is responsible for 10 percent of the nation's contribution to climate change. The methane goals are largely focused on oil and gas sectors, which make up 30 percent of the country’s methane emissions.
EIA expects U.S. petroleum trade to shift toward net imports during 2022 - In 2021, the United States returned to importing more petroleum (which includes crude oil, refined petroleum products, and other liquids) than it exports following its historic shift to being a net exporter of petroleum in 2020. According to our February 2022 Short-Term Energy Outlook (STEO), we expect net crude oil imports to increase, making the United States a net importer of petroleum in 2022.A country is a net importer if it imports more of a commodity than it exports. Conversely, a country is a net exporter if it exports more of a commodity than it imports. Many factors affect net trade numbers because trade reflects supply and demand conditions both domestically and internationally.Historically, the United States has been a net importer of petroleum. During 2020, COVID-19 mitigation efforts caused a drop in oil demand within the United States and internationally. International petroleum prices decreased in response to less consumption, which diminished incentives for key petroleum-exporting countries to increase production. This shift allowed the United States to export more petroleum in 2020 than it had in the past.Also in 2020, the difference between U.S. crude oil imports and exports fell to its lowest point since at least 1985. Net crude oil imports subsequently rose by 19% in 2021 to an average of 3.2 million barrels per day (b/d) as crude oil consumption increased in response to rising economic activity. We forecast that the United States will continue to import more crude oil than it exports in 2022, reaching an estimated annual average of 3.9 million b/d. However, we expect net imports to fall to 3.4 million b/d in 2023. We expect the United States to import less crude oil than it exports in 2023 because we expect domestic crude oil production will increase to an all-time high of 12.6 million b/d. Since 2010, the United States has exported more refined petroleum products, including distillate fuel oil, hydrocarbon gas liquids, and motor gasoline, among others, than it has imported. Net exports of refined petroleum products grew to 3.3 million b/d in 2020 and remained about the same in 2021. We expect petroleum product net exports will reach new highs of 3.6 million b/d in 2022 and 3.8 million b/d in 2023.
Most Oil Companies Unprofitable or Breaking Even - 2020 represented the costliest year in Chapter 11 bankruptcy filings for oil and gas. 62 percent of oil and gas companies are currently either unprofitable or just breaking even. That’s according to the 2022 BDO Energy CFO Outlook Survey, which noted that 2020 represented the costliest year in Chapter 11 bankruptcy filings for oil and gas, surpassing $100 billion of debt from more than 100 companies. The survey found that, in order to raise capital, oil and gas companies identified the pursuit of investment by a strategic partner as their top choice (48 percent), with the pursuit of private sector equity coming in second place (26 percent), and the pursuit of public equity coming in third (22 percent). Looking at where oil and gas companies plan to increase spending, the 2022 CFO Outlook Survey revealed that ESG will be the prime focus (45 percent), followed by a tie between IT projects (38 percent) and back-office operations (38 percent). According to the survey, 68 percent of oil and gas companies believe implementing an ESG program to improve resiliency and address ESG risks will have a positive impact on the company’s long-term financial performance. The survey also outlined that 46 percent of oil and gas companies are pursuing ESG initiatives to address investor and board demands. “While the past year presented a myriad of challenges for the energy industry, CFOs have a diversified mix of strategies at their disposal to restore consumer and investor confidence, and boost operational resilience,” Clark Sackschewsky, BDO’s national leader of energy and global leader of oil and gas, said in a statement sent to Rigzone. “But on the road ahead, securing sufficient working capital will be key to the success of either endeavor and the lifeline to organizations’ near- and long-term growth,” he added in the statement.
ESG And The Dangerous Structural Increase In The Price Of Oil - The end of oil (and gas and coal) literature we’re inundated with is being written by us in the already developed world, with little regard to the nearly 7 billion people that demand the same access to the same energy that have made us Westerners so rich and long-living. And understandably so, the still developing world is now probably realizing us as even more self-centered and hypocritical than before. Cargoes bound for poor Pakistan were literally changing in mid-route and going to rich UK because the British were willing to pay more. Indeed, the still developing world might not be so quick to focus on decarbonizing as much as we in the West like to think. Real experts argue over whether the world’s oil demand will peak in the 2030s or 2040s, but we all should agree on one thing: when oil use does peak, it won’t plummet but plateau. As economies rebound and oil demand roars back (hardly surprising because the world’s most vital fuel has no significant substitute whatsoever), supplies have struggled to keep up. JPMorgan warns that “oil could ‘easily’ hit $120 if Russia-Ukraine crisis escalates.” Despite rising oil prices, we’re not seeing the investments in new supply that we would’ve seen in previous cycles before the pandemic. For the West’s international oil companies (the “supermajors” like BP, Shell, Chevron, ExxonMobil, etc.), the attack is along all fronts. There has been: 1) a lack of access to financing because of climate concerns, 2) investor demands to decarbonize, and 3) a shortage of sufficient investments in new supply for many years. Thus, crude oil inventories have continued to fall to their lowest levels in many years. For the American consumer, troubled times lay ahead. As my Forbes colleague Dan Eberhart explains, the growing ESG movement means increasing climate pressure to “not invest in new oil production” – a “cart before the horse” energy fantasy bound to devastate. In their investment presentations, the big oil companies are putting “climate, low-carbon, ESG” right up front. The new “moderate growth” mode and limited well inventory suggest that we shouldn’t expect American shale to save the day like it used to.We seem to be entering the stage of “post-shale super growth,” where incremental output from the American oil patch will not be outpacing new global demand. This year, a large part of the higher capital spending in the U.S. oil industry will be just to cover the cost inflation for major inputs, such as for steel, labor, and fuel (renewables are facing the same problems). Further, the low-carbon push and “we don’t need more oil because demand is declining” paradigm has many oil companies switching to investments in renewable power, batteries, hydrogen, carbon capture and storage, etc. For example, the supermajors are dominating in offshore wind, and their deep pockets are putting up barriers for smaller firms who have renewables as their core focus to have a real chance in seabed auctions. And all of this is happening as Western governments, politicians, and environmental groups continue to brag about their foolish end goal: “let’s put our oil companies out of business, that’ll show em!”The constant chant of “oil demand will soon peak” is creating great uncertainty and thereby denying investment approvals from the corporate boards of the big oil companies. Simply put, they’ve become unwilling to sanction multi-billion dollar upstream projects that take many years to bring more oil online and even more to see project payout.In turn, especially as environmental activism seeks to blitz them from energy angle, the easiest path forward for the oil industry is to do exactly what it has been doing: paying out dividends, buying back shares, paying down debt, pursuing non-oil opportunities, and quietly and slightly upping production. Make no mistake, naturally-occurring oil field declines mean that even high investments can still lead to drops in oil production. There is no “standing still” in the oil E&P business, and the Red Queen Effect is especially wrecking for shale because its decline rates are higher and faster.The scare of peak oil demand is setting up the reality of peak oil supply.
U.S. demand for residual fuel oil rose late in 2021 In November 2021, more residual fuel oil was consumed in the United States, measured as product supplied, than during any month since January 2017. Residual fuel oil has several uses, but it is primarily consumed as bunker fuel in the maritime shipping sector. Consumption in December 2021 was at its highest end-of-year level since 2012, according to our Weekly Petroleum Status Report (WPSR).On January 1, 2020, tighter regulations from the International Maritime Organization (IMO) on maritime fuel sulfur specifications became effective. Before 2020, marine fuel could have a sulfur content as high as 3.5%, which is considered high-sulfur fuel oil. The IMO now requires ships to switch to fuels with a 0.5% sulfur content or less, forcing ships to use a more processed, and more expensive, variety of residual fuel oil called very-low-sulfur fuel oil.Ships comply with the IMO specification as long as their actual emissions meet the target sulfur emissions level, regardless of the specification of the fuel they use. Ship owners can install sulfur scrubbers on board to reduce sulfur emissions while still consuming high-sulfur fuel oil and remain compliant. Ship scrubbers are expensive and require ongoing maintenance, but vessels can lower operating costs by purchasing high-sulfur fuel oil instead of higher-priced very-low-sulfur fuel oil or low-sulfur marine gas oil.The IMO regulation applies to global shipping. Marine vessels operating within the North American or U.S. Caribbean Sea Emission Control Areas (ECA) were already required to meet 0.1% sulfur content while operating within those waters.Since spring 2020, overall production of residual fuel oil has decreased because of substantially less refinery production resulting from the effects of the COVID-19 pandemic.High crude oil prices indirectly contribute to higher overall bunker fuel prices, and higher prices give ship owners stronger incentives to install scrubbers to take advantage of the price discount that 3.5% high-sulfur fuel oil has to 0.5% very-low-sulfur fuel oil.The increase in residual fuel oil demand comes with record increases in maritime shipping volumes and rising high-sulfur fuel oil prices in Singapore. The Singapore market is a global benchmark for marine shipping. Since the beginning of November 2021, the Singapore very-low-sulfur fuel oil price premium over high-sulfur fuel oil increased to more than $20 per barrel (b) and neared $30/b throughout December 2021 and January 2022.
U.S. Drilling Activity Maintains Upward Momentum as Haynesville, Permian See Growth -Propelled by activity gains in the Haynesville Shale and Permian Basin, the U.S. rig count posted double-digit growth for a second straight week in the latest tally from oilfield services provider Baker Hughes Co. (BKR). Including increases of six natural gas-directed rigs and four oil-directed units, the combined U.S. count jumped 10 units higher to 645 for the week ended Friday (Feb. 18). That follows a 22-rig surge in the week-earlier period. The 645 active U.S. rigs as of Friday represented a 248-rig year/year increase, according to the BKR numbers, which are partly based on data from Enverus. Land drilling rose by 13 units week/week, partially offset by a four-rig decline in the Gulf of Mexico for the period. One rig was added in inland waters for the week. Horizontal drilling rose by 15 units, partially offset by net declines of three vertical rigs and two directional rigs.The Canadian rig count added one unit to reach 220 for the week, up from 172 in the year-earlier period. Net changes included a gain of three natural gas-directed rigs, partially offset by a decline of two oil-directed rigs.Broken down by major play, the Permian led with a net increase of five rigs week/week, growing its total to 306. The Haynesville added four rigs week/week to end with 58 rigs, up from 46 a year ago. The Denver-Julesburg Niobrara added two rigs, while the Arkoma Woodford, Cana Woodford and Marcellus Shale each added one. The Mississippian Lime and Utica Shale, meanwhile, each dropped one rig from their respective totals.Broken down by state, Texas saw a net gain of eight rigs week/week, with Colorado and New Mexico each adding two rigs. Pennsylvania added one rig to its total, while Louisiana, Ohio and Wyoming each dropped one rig, BKR data show. U.S. petroleum demand continued to march higher in the week-earlier period as production held steady, leaving crude stockpiles far below historic averages, the Energy Information Administration (EIA) said in its latest Weekly Petroleum Status Report earlier in the week. Demand rose 4% week/week to average 22.7 million b/d during the week ended Feb. 11, aided by a 4% jump in jet fuel consumption, the agency said.
Power company blames 'switch' for power outage in Texas City — Texas City’s top emergency manager credits “the good Lord’s providence” with preventing a major explosion at petrochemical plants. Bruce Clawson, Emergency Management Coordinator, made those comments to the Galveston County Daily News on Monday, three days after the massive February 4 power outage that left nearly 20,000 homes and businesses in the dark for four hours.Clawson was unavailable for an interview Tuesday. However, during a text message exchange with KHOU 11, he singled out the skill of workers at petrochemical facilities, which flared, or burned off chemicals, to reduce pressure and make these refineries safe.“It can create some tremendous opportunities for bad explosions,” said Ed Hirs, KHOU 11Energy Expert.Both Hirs and Clawson said refineries have backup generators but not enough to run at full strength.“Just like your building has two backup generators to run the elevators and some of the power supplies and to keep water pumping through the building,” said Hirs. “They don’t have enough generation on-site to power the entire plant. That gets to being too expensive.”Hirs says there are no laws requiring backup generation at these facilities.Initial reports to the Texas Commission on Environmental Quality show the Valero andMarathon plants emitted more than 132,000 pounds of emissions, including nearly 75,000 pounds of sulfur dioxide.“So, one event, one night, produced the same amount of sulfur dioxide, four percent from an entire year,” said Jennifer Hadayia, Executive Director of Air Alliance Houston. According to the Environmental Protection Agency’s web page on sulfur dioxide, or SO2, “Short-term exposures to SO2 can harm the human respiratory system and make breathing difficult. People with asthma, particularly children, are sensitive to these effects of SO2.”
What Europe’s need for natural gas means for Texas | Texas Standard -- For years, some European nations have been reluctant to import natural gas from Texas because of the harmful emissions required to extract it. That’s changed in a hurry though, as the continent now faces a gas shortage.Russell Gold, a writer and senior editor for Texas Monthly, spoke to Texas Standard about the factors behind the new demand and how it could affect communities in Texas. Listen to the interview with Gold in the audio player above or read the transcript below.This interview has been edited lightly for clarity.
U.S. crude oil production forecast to rise in 2022 and 2023 to record-high levels – EIA - In our February 2022 Short-Term Energy Outlook(STEO), we forecast that crude oil prices will remain high enough to drive U.S. crude oil production to record-high levels in 2023, reaching a forecast 12.6 million barrels per day (b/d). We expect new production in the Permian Basin to drive overall U.S. crude oil production growth.In the February STEO, we forecast that U.S. crude oil production will increase to 12.0 million b/d in 2022, up 760,000 b/d from 2021. We forecast that crude oil production in the United States will rise by 630,000 b/d in 2023 to average 12.6 million b/d. We expect more than 80% of that crude oil production growth to come from the Lower 48 states (L48), which does not include production from Alaska and the Federal Offshore Gulf of Mexico.Production from new L48 wells, particularly in the Permian region, drive our forecast of U.S. crude oil production growth. Legacy production, or crude oil production from existing wells, typically declines relatively quickly in tight oil formations, and we expect that production from new wells will offset these legacy production declines.Crude oil prices have generally increased since April 2020, resulting in increased crude oil production. The Brent spot price for crude oil (the international benchmark) reached $97 per barrel (b) on February 7, 2022, the highest nominal price (not adjusted for inflation) since September 17, 2014. From January 8, 2021, to February 7, 2022, the L48 added 220 oil-directed rigs, 114 of which were in the Permian region. We forecast that production in the Permian region will average 5.3 million b/d in 2022 and 5.7 million b/d in 2023.
U.S. oil production won't reach pre-Covid high until 2023, analyst says — Even as crude prices hurtle toward $100 a barrel, U.S. oil output won’t be able to reach its pre-pandemic high until later next year as inflation and production logjams present obstacles to the industry’s recovery. That’s according to Elisabeth Murphy, an analyst at industry consultant ESAI. While Murphy estimates that the U.S. is set to add 900,000 barrels a day of supply this year, she pointed to rising costs and issues with drilling as factors that are holding back more growth. New drilling isn’t keeping up with number of well completions, the final step before oil begins flowing. Keeping a good log of newly drilled wells is necessary to maintain and grow production, Murphy said during a webinar. Service-sector price inflation is also an issue, and one that could restrain production growth, she said, noting that the cost of sand for fracking purposes has tripled in the Permian basin, the world’s most prolific oil patch. Other factors that could slow supply recovery include more regulations such as methane rules, rising royalty rates and further industry consolidation, she said. Crude prices have surged 40% since early December to more than $90 a barrel. Many producers have been eager to take advantage of the rally, with U.S. drillers adding the most rigs in four years last week. This week, the U.S. government reported that the Permian reached record volumes of oil supply for three consecutive months. But even with that expansion, global crude supplies aren’t keeping up with robust demand amid some production limitations.
Houston biotech startup will use microbes to make hydrogen from oil — Houston biotech startup Cemvita Factory is partnering with U.S. gas-equipment manufacturer Chart Industries Inc. to use oil-eating microbes to make hydrogen. The venture, which also includes engineering and consulting firm EXP and the Center for Houston’s Future, plans to deploy the microbes into depleted oil reservoirs that are ready to be plugged and abandoned, the companies said Thursday in an emailed statement. The technology would extend the life of the low-value wells and create a new revenue stream from so-called “gold hydrogen,” which is produced biologically and emissions-free underground. Using both natural and genetically engineered microbes that require some supplemental nutrients, a well can make more than 3 kilograms (6.6 pounds) of hydrogen for each barrel of oil consumed as feedstock, Cemvita Chief Executive Officer Moji Karimi said in an interview. The technology can make hydrogen for less than $1 per kilogram, the companies said. By comparison, emissions-free hydrogen made by a process known as wind-based water electrolysis costs between $4 to $6 per kilogram, according to figures compiled by the National Renewable Energy Laboratory. When burned, hydrogen only releases water vapor as a waste product, making it a prized fuel in the global transition to cleaner energy, but the cost of large-scale, emissions-free production remains a challenge.
Cash Waha Hub falls as Permian gas production climbs to new record high | S&P Global Platts - Permian gas production soared to a new record high Feb. 18, which, combined with a forecast for warmer temperatures in West Texas, weighed down cash Waha Hub and other regional spot prices in Feb. 18 spot trading for Feb. 19-22 flows. Cash Waha Hub fell 22 cents to $3.96/MMBtu on Feb. 18, widening its basis to cash Henry Hub to 64 cents, preliminary Platts settlement data shows. Similarly, cash Transwestern, Permian Basin fell 26.50 cents to $3.875/MMBtu. Waha Hub has seen its spread widen as Permian production climbed above the 14 Bcf/d mark, averaging a 55-cent discount Feb. 10-17, compared to a 32-cent discount for the prior 30 days. Gas production in the Permian reached 14.34 Bcf on Feb. 18, the highest level recorded in data going back to 2012, according to S&P Global Platts Analytics. Daily gas production has come in above 14 Bcf/d for Feb. 10-18, putting this February on the path to be the strongest month for Permian gas production on record. Prior to this month, daily Permian production had risen above the 14 Bcf/d mark just four times. The stronger production has been supported by the basin's growing rig count, which reached 308 for the week ended Feb. 16, data from Enverus shows. This is three rigs higher than the previous week and 50% higher than the same week a year ago when the basin had 205 rigs in operation. The National Weather Service forecast that temperatures in West Texas would warm up over the next several days, alleviating the risk of additional production freeze-offs and lowering local gas demand. Midland, Texas, was expected to see its daily low temperature rise into the 40s Fahrenheit Feb. 19-22 from 32 F Feb. 18. Daily highs were also forecast to warm, climbing out of the 50s F Feb. 18 and into the 60s and 70s F Feb. 19-22. While West Texas was set to see temperatures thaw slightly, daily low temperatures in New Mexico were expected to remain below or near-freezing in the near-term. This temperature divergence showed up in Feb. 18 cash pricing, with Transwestern, San Juan and El Paso, San Juan seeing much smaller losses on the day than Waha Hub and El Paso, Permian. Waha Hub's futures contracts were trading slightly lower on the Intercontinental Exchange on Feb. 18, suggesting that the market may be factoring in the impact of stronger production on local supply and demand dynamics. Waha's March contract was trading around 4 cents lower at a 58.81 cent discount to Henry Hub, while the April contract fell 3 cents to trade at a 68 cent discount.
Permian Production Called ‘Indisputable Driver’ of U.S. NGL Growth - U.S. natural gas liquids (NGL) production, particularly from the Permian Basin, hit record levels near the end of last year, propelling hydrocarbon liquid totals to almost pre-pandemic numbers. According to research by Rystad Energy, domestic NGL output soared to 5.84 million b/d in November, mostly from improving ethane recovery and Gulf Coast supplies rebounding following recovery from Hurricane Ida. Total U.S. NGL output climbed above 17.3 million b/d in November, one of the highest points since early 2020. It was a 60,000 b/d sequential increase and the third monthly record in a row. NGL production from the Permian helped lead the surge, according to Rystad’s Artem Abramov, head of Shale Research. He called the Permian the “indisputable driver” of output during the record-setting spike. The 10% growth in NGL output from the Permian, which extends across West Texas and southeastern New Mexico, through the second half of 2021 helped boost the gains from crude oil and condensate across the country during the same time period, Abramov said. Before the pandemic, the Permian accounted for about 30% of U.S. oil output and 14% of domesticnatural gas production in 2020, according to the Energy Information Administration data.During November, NGL production from the Permian hit a record 3.3 million b/d, with the rest of the country making up only 2.5 million b/d of output. The Permian also led in oil production and growth of natural gas output during the same period, though Appalachia still led the total for natural gas at 34.903 Bcf/d. The Permian also led in drawing down the backlog for drilled but uncompleted (DUC) wells from October to November with 105 units, coming down to 1,564 wells. The combined drawdown for all seven regions was 226 wells. One of the nation’s top pipeline operators, Enterprise Products Partners LP, recently announced a $3.25 billion investment in the Permian Midland sub-basin with the acquisition of Navitas Midstream Partners LLC to add more NGLs to its system. Rystad analysis showed other major U.S. onshore basins also are gaining traction toward pre-pandemic levels of all hydrocarbon liquids but were still underperforming by an average of 13% from 1Q2020. Output from the Eagle Ford and Bakken shale formations, and the Anadarko Basin and Niobrara formation, remained relatively flat in November month/month. The natural gas-rich Appalachia Basin and the Haynesville Shale saw their NGL output decline four months in a row, slipping from a total production of 861,000 b/d in August to 856,000 b/d in November. The increase in ethane recovery during the spike in NGL production accounted for most of the added output, and helped keep most of the major gas regions, excluding the Permian, from recording declining numbers.
Marathon Oil chooses cash returns over oil production ramp-up — Marathon Oil Corp. said oil and natural gas production won’t increase this year as it concentrates on pouring cash into dividends and share buybacks. The shale giant announced plans to spend $1.2 billion on capital projects this year, in line with analysts’ expectations for a 20% increase from the 2021 level, according to a statement on Wednesday. The company forecasts generating more than $3 billion of free cash flow, exceeding estimates by half a billion dollars. Marathon said it expects to exceed its commitment to return a minimum of 40% of cash from operations to investors, assuming oil prices average around $60 a barrel or higher. Per-share adjusted earnings of 77 cents exceeded the average estimate by 22 cents. The company pledged to continue buying back shares after repurchasing $1 billion since October, reducing share count by 8%. The promise comes three weeks after Marathon increased its quarterly dividend by 17%.
Shale giants swear they won't drill more, even at $200 a barrel — The Texas wildcatters that ushered in America’s shale revolution are resisting the temptation to pump more oil as the market rallies, signaling higher gasoline prices for consumers already battered by the worst inflation in a generation. Crude prices hurtling toward $100 a barrel typically would spark a frenzy of new drilling by independent explorers in shale fields from the desert Southwest to the Upper Great Plains -- but not this year. Influential players like Pioneer Natural Resources Co., Devon Energy Corp. and Harold Hamm’s Continental Resources Inc. just pledged to limit 2022 production increases to no more than 5%, a fraction of the 20% or higher annual growth rates meted out in the pre-pandemic era. The timing couldn’t be worse for consumers. Outside of OPEC, which has rejected U.S. President Joe Biden’s pleas to accelerate production increases, domestic shale fields are the only other source of crude that can quickly respond to supply shortfalls. Together with fast-rising global consumption, American drillers’ conservatism is likely to keep oil prices elevated for some time to come. “Whether it’s $150 oil, $200 oil, or $100 oil, we’re not going to change our growth plans,’’ Pioneer Chief Executive Officer Scott Sheffield said during a Bloomberg Television interview. “If the president wants us to grow, I just don’t think the industry can grow anyway.’’ To be sure, U.S. oil output will rise substantially this year and is forecast to return to pre-pandemic levels by 2023. But it probably won’t be enough to knock oil prices off their upward trajectory any time soon. Publicly-listed independent explorers like Pioneer and Devon account for more than half of the roughly 10.5 million barrels that America produces daily from fields in the contiguous 48 states, according to IHS Markit Ltd. The rest comes from closely held outfits, family-run enterprises and the international supermajors, all of which are aggressively boosting output. Exxon Mobil Corp. and Chevron Corp., for example, are targeting 25% and 10% shale growth, respectively, this year. At the same time, closely-held entities bankrolled by private-equity firms and family funds now control the majority of the country’s active drilling rigs.
Texas Got Double the Earthquakes in 2021 - An analysis published by the Texas Tribune on Tuesday finds that earthquakes of more than a 3.0 magnitude in Texas more than doubled last year, shooting up from 98 in 2020 to 209 in 2021. It’s not a sudden natural change causing all these new quakes. Both regulators and scientists say that increased fracking and wastewater disposal from the oil and gas industry is likely to blame.Earthquakes are not a direct result of fracking itself, but rather come from the ways oil producers dispose of the wastewater that is a byproduct of the drilling process. Much of the water that is injected underground to frack oil from the shale formations comes back up with that oil, along with a slew of chemicals, salts, and radioactive materials it accumulated underground—between three to six barrels of wastewater comes up with each barrel of oil.The most common and cheapest way to dispose of this wastewater seems logical: why not just pump it back underground? But water added back underground can shake up dormant faults in rock formations, transforming Texas, which before the fracking boom in 2008 saw just a couple of perceptible earthquakes per year, into an earth-shaking hotspot.“The cumulative volumes [of water] increase the pressure, and that is the force that triggers the fault to slip,” Alexandros Savvaidis, a research scientist at the Bureau of Economic Geology at UT-Austin, told the Tribune.And there’s way more wastewater in the Permian Basin than there used to be. According to energy analysts Rystad Energy, which provided the Tribune with figures, the amount of wastewater generated in the Permian Basin sat at 217 billion gallons in 2021, up from 54 billion gallons in 2011.More intense earthquakes are also increasing. Texas saw zero 4.0 earthquakes in 2017, but experienced nine between 2018 and 2020. In 2021 alone, that number shot up to 15. While 4.0 earthquakes are still considered “light,” they can begin to rattle buildings and possibly do damage. The increase in earthquakes is so great that it’s even getting the attention of Texas’s famously industry-friendly regulators. The Texas Railroad Commission (RRC), which is known for being light on regulation and for going to bat for the oil and gas industry, said in September it would stop issuing new injection permits in Midland County after four earthquakes above a 3.0 hit within the span of a week. In December, the RRC suspended 33 injection permits in the Midland area and began monitoring another area of concern in late January.
Chemists discover a range of environmental contaminants in fracking wastewater - As companies that drill for oil and natural gas using hydraulic fracturing consider recycling and reusing wastewater that surfaces from wells during the fracking process, chemists at The University of Toledo discovered that the new and unexplored waste contains many environmental contaminants including organic chemicals and metallic elements. Research scientists at UToledo's Dr. Nina McClelland Laboratory for Water Chemistry and Environmental Analysis in collaboration with the University of Texas Arlington achieved a comprehensive characterization of the chemical composition of produced water samples extracted in Texas, indicating the presence of toxic and carcinogenic contaminants in untreated samples, which can pose a threat to wildlife and human health. Unraveling the complex composition of produced water by specialized extraction methodologies, the results published in Environmental Science and Technology provide critical information that can help regulatory agencies fine-tune proposed guidelines related to the safe treatment and disposal of fracking wastewater to protect drinking water sources. "The discovery of these chemicals in produced water suggests that greater monitoring and remediation efforts are needed since many of them are listed to be dangerous for human health by the World Health Organization," said Dr. Emanuela Gionfriddo, assistant professor of analytical chemistry in the UToledo Department of Chemistry and Biochemistry, and the School of Green Chemistry and Engineering. "Our comprehensive characterization sheds insight into the processes taking place during hydraulic fracturing and the nature of the geologic formation of each well site." Drilling operations are often performed by injecting treated water into the subsurface that contains various publicly undisclosed additives to assist in the drilling process. The injected water mixes with groundwater and then resurfaces as waste byproduct containing contaminants both from the drilling site and the additives used. The chemists used an approach developed by Gionfriddo's research team in 2020 called thin-film, solid-phase microextraction to extract organic solubles from eight produced water samples from the Permian Basin and Eagle Ford formation in Texas. Analysis found a total of 266 different dissolved organic compounds, including a pesticide called atrazine; 1,4-dioxane, an organic compound that is irritating to the eyes and respiratory tract; pyridine, a chemical that may damage the liver; and polycyclic aromatic hydrocarbons (PAHs), which have been linked to skin, lung, bladder, liver and stomach cancers. Using a new polymer developed in 2021 at UToledo, the team also confirmed the presence of 29 elements, including rare earth elements, selenium and hazardous metals such as chromium, cadmium, lead and uranium. The researchers also suggest the technology used for their comprehensive analysis of produced water is essential for proper reuse or disposal by oil and gas producers. "We found a way to use more accessible instrumentation in the analysis of such complex samples compared to more expensive workflows involving high-resolution mass spectrometry," said Dr. Jon Kirchhoff, Distinguished University Professor and chair of the UToledo Department of Chemistry and Biochemistry.
$100 Oil Could Trigger Burst In Shale Oil Production - Up to 2.2 million barrels per day (bpd) of US tight oil could be unleashed in the event of a supercycle – with oil prices remaining around or above $100 per barrel – driven by growing demand and continued supply tightness, Rystad Energy predicts. Tight oil output in the core producing regions of the US – the Permian, Eagle Ford, Niobrara, Bakken and Anadarko – in the fourth quarter of 2021 was around 7.7 million bpd, continuing an upward trend but short of the pre-pandemic levels. Production in these regions is expected to surpass the 2019 high of 8.1 million bpd by the second quarter of this year and expand further if a supercycle materializes. If oil prices reach and remain around $100 per barrel, total production from these core regions would hit 9.9 million bpd by the fourth quarter of 2023, marking a 2.2 million bpd surge from the same quarter in 2021. High oil prices are encouraging operators to increase production as supply from sources outside the US remains tight. Global Covid-19 concerns are waning and countries are removing or relaxing restrictions, causing a surge in demand for oil that the current supply would struggle to meet. In addition, geopolitical uncertainty in major exporting countries is worsening, threatening to disrupt trade flows amid already limited availability. Total unconventional output – including oil, gas and natural gas liquids (NGL) – from these core US oil regions has already returned to pre-Covid-19 levels, totaling around 15.6 million boepd in the fourth quarter of 2021. Total output is expected to keep climbing and reach an all-time high of more than 16 million boepd by the end of March this year. “Although high prices would, in theory, trigger a burst in tight oil production, acute supply chain bottlenecks, a lag between price signals and its impact on production, and winter weather-related disruptions will slow growth. Added to this are expectations that spot sand prices will rise to a $50-$70 per ton range – a level unheard of in the industry’s modern history – which will hit operators’ wallets,” says Artem Abramov, Rystad Energy’s head of shale research.
As oil prices soar, U.S. drillers scramble to find sand for fracking - With crude prices at their highest levels in years, U.S. oil drillers are trying to boost output fast, but their efforts have been hit by a shortage of sand to use for fracking operations. Crude output is expected to hit records in parts of Texas and New Mexico, the heart of U.S. shale activity. Sand supplies are so tight that it is slowing the pace of work for some oil drillers, and higher costs for sand are eating into the bottom line for others. But demand is still heavy as drillers look to cash in on crude prices that this week touched $95/bbl, the highest in roughly seven years. Crude slid about 4% from those peaks on Feb. 15 but remained well above $90/bbl. “We can’t get enough sand. We’re running less than the number of [fracking] stages we could pump in a day because we’ve run out of sand every day,” said Michael Oestmann, CEO of private equity-backed Tall City Exploration, which operates in the Permian Basin of West Texas, the largest U.S. shale region. “Ultimately it will slow everyone down if it doesn’t resolve itself.” Once overbuilt and oversupplied, the sand markets have been turned upside down. Consultancy Rystad estimates that spot prices are between $50 and $70 a ton—a giant leap from prices in early teens at the start of the pandemic and sharply above last year’s levels of $20 to $25 per ton. Rystad Researcher Artem Abramov called current prices for frack sand “unheard of in the industry's modern history.” Tight supplies will probably push sand prices even higher, Abramov said. He estimates that one to two in-basin sand mines have been idled at any given time since December. U.S. shale production is expected to rise by 109,000 bbl/d in March, to 8.7 million bbl/d, according to the U.S. Energy Information Administration. The Permian Basin is expected to see output rise to 5.2 million bbl/d in March, which would be a record, and there are now 301 oil rigs operating in that basin, the most since April 2020. U.S. frackers added three crews in the first week of February, boosting the total to 264 from roughly 167 this time last year, according to consultancy Primary Vision. The sand market is so tight Oestmann said, because fewer people have been working in the mines and there has been a shortage of truck drivers. He said his company is looking to bring sand in by rail, a sourcing method that fell out of fashion following the advent of local mines a few years ago. “The railed sand depots were busy,” said Richard Spears, vice president of oilfield consultancy Spears & Associates, of a recent trip to West Texas. “When that source is kicking in at high volume, and the local mine is full out, you know you’ve got a challenge.”
U.S. Shale Production Hindered By Sand Supply Crunch - U.S. shale producers are tempted to boost production more than previously expected as oil prices rallied to over $90 a barrel with a potential to hit $100 soon. Yet, a supply chain bottleneck for a key material for fracking could slow the coming shale boom.Frac sand in the biggest shale play, the Permian, is in short supply, threatening to slow drilling programs at some producers and sending sand prices skyrocketing. This adds further cost pressure to American oil producers, who are already grappling with cost inflation in equipment and labor shortages.Total U.S. crude oil production is set to rise to an average of 12.0 million barrels per day (bpd) in 2022 and 12.6 million bpd in 2023—an annual record high and 200,000 bpd above last month’s estimate, the EIA said in its February Short-Term Energy Outlook (STEO) last week. The previous annual average record of 12.3 million bpd was set in the pre-pandemic 2019. Crude oil production in the seven most prolific U.S. shale basins is set to increase to 8.707 million bpd in March—a 109,000 bpd rise over February’s 8.598 million bpd, and an increase of 271,000 bpd from January’s tally, the EIA’s latest Drilling Productivity Report showed. However, cost pressures and sand shortages could slow the growth going forward. Not enough frac sand at a time when oil prices topped $90 a barrel could limit the growth as more and more shale firms – especially privately-held ones – seek to boost production materially to capture the high oil prices. $100 oil could unleash a lot more U.S. oil production, in theory, but supply chain constraints and record-high sand prices are likely to temper growth, analysts say. “Although high prices would, in theory, trigger a burst in tight oil production, acute supply chain bottlenecks, a lag between price signals and its impact on production, and winter weather-related disruptions will slow growth. Added to this are expectations that spot sand prices will rise to a $50-$70 per ton range – a level unheard of in the industry’s modern history – which will hit operators’ wallets,” Artem Abramov, Rystad Energy’s head of shale research, said earlier this weekSand tightness, cost pressures, and labor shortages could be deterrents to a massive outburst in U.S. shale production, even if most public companies were to abandon restraint and risk angering Wall Street by seeking to significantly raise output.Oilfield services firms, while hailing the coming of a “multi-year upcycle” in shale, are warning against sand tightness and labor and cost pressures.“There is no doubt, the much-anticipated multiyear upcycle is now underway,” Jeff Miller, CEO at the biggest fracking services provider, Halliburton, said on the Q4 earnings call last month. But he also noted that “As activity accelerates, the market is seeing tightness related to trucking, labor, sand, and other inputs.”During the fourth quarter, Halliburton saw the North American market moderate growth slightly in completions due to the holidays, sand supply tightness, and lower-efficiency levels typically experienced in the winter months, Miller said.
An FTI Consulting Presentation Pulls Back the Veil on Fossil Fuel PR and Shale Greenwashing - “We understand how the oil and gas sector works — we’ve worked in it, studied it, defended it and impacted the policy that regulates it,” a 2015 presentation delivered to the Tennessee Oil and Gas Association begins. “We have been instrumental players in the industry’s highest profile business issues, regulatory hearings, legal disputes and arbitration.”Those bona fides came not from an oil and gas company or investor, but from FTI Consulting, a sprawling consulting firm that markets its strategic communications services to a wide range of industries — including coal, oil, and gas producers.FTI’s 2015 presentation, obtained by DeSmog, offers a rare glimpse at what PR firms offer to fossil fuel companies and how they work their messaging and strategies into news articles and headlines. It comes at a time when the PR industry has been wrestling with its role in the climate crisis. In January, the Clean Creatives campaign, which represents PR professionals concerned about their industry’s role in promoting fossil fuels, released a letter signed by 450 scientists. Itcalls on PR firms to drop fossil fuel clients and stop spreading what the letter described as“advertising and PR efforts by fossil fuel companies that seek to obfuscate or downplay our data and the risks posed by the climate crisis.”FTI’s claim in the 2015 presentation to have been instrumental for the oil industry isn’t bluster. In November 2020, a New York Times investigation found that “FTI has been involved in the operations of at least 15 current and past influence campaigns promoting fossil-fuel interests in addition to its direct work for oil and gas clients.”This is reflected in the 2015 presentation, in which FTI touted its connections to dozens of fossil fuel and chemical companies, including Shell, Halliburton, and Range Resources, and lists groups like the Marcellus Shale Coalition, the Shale Resource Centre Canada, and the Center for Liquified Natural Gas under the heading “redefining communications support.” The presentation focuses on what is perhaps FTI’s best-known project for the fossil fuel industry: Energy In Depth, a project that’s served as a “rapid response platform” for the shale industry.Outside experts called the presentation revealing.“PR firms — I guess FTI Consulting is also strategic management — they don’t want to ever be seen officially to be very overtly trying to control the conversation,” Melissa Aronczyk, a professor of journalism and media studies at Rutgers University, told DeSmog. “They want to be able to say, ‘no, no, we’re just producing our facts, we’re just producing our evidence and using the statistics that are out there.’” “And so this is pretty damning,” she added.
Judge: Oil and gas leases offered without weighing sage-grouse impacts | Western Colorado - A federal judge has ruled that the Bureau of Land Management illegally failed to consider the impacts to the imperiled Gunnison sage-grouse before leasing acreage for oil and gas development in southwestern Colorado. Senior Judge John Kane with the U.S. District Court of Colorado issued his findings this week in rulings in lawsuits brought by conservation groups and the San Miguel County Board of Commissioners in connection with two lease sales. At issue were 1,400 acres leased in 2018 and 9,241 acres leased in 2017. Much of the acreage leased in the sales is in San Miguel County, home to the second-largest population of Gunnison sage-grouse, which is protected under the Endangered Species Act as a threatened species. The BLM relied on environmental analysis in the resource management plan for its Tres Rios Field Office in proceeding with the lease sales, but Kane ruled that it should have done more analysis at the leasing stage in order to comply with the Endangered Species Act and National Environmental Policy Act. He said that new information was available that allowed the BLM to consider additional impacts not previously considered, based on factors such as the specific lease sizes and locations, including their positions relative to Gunnison sage-grouse habitat and existing leases. The BLM also reviews oil and gas proposals when companies apply for drilling permits, and had said it would have more specifics to consider at that stage, “but I conclude that the BLM had new information at the leasing stage that revived its duties” under the Endangered Species Act, Kane said in his ruling. He said the agency was obligated to consult with the Fish and Wildlife Service on the lease proposals and their potential impacts on Gunnison sage-grouse. The plaintiffs in the case want Kane to vacate the BLM decisions authorizing the lease sales and declare the leases void now that he has found the agency violated the law, but he will first consider briefs from plaintiffs and the government on the issue. Megan Mueller, senior conservation biologist with Rocky Mountain Wild, one of the plaintiffs, said she thinks Kane will vacate BLM’s actions, but that otherwise it will have to do more environmental analysis consistent with his rulings. A BLM spokesman contacted Friday provided no comment on Kane’s rulings.
State Supreme Court weighs release of disputed DAPL documents; 2 related cases before high court --The North Dakota Supreme Court is weighing whether to further delay the public release of about 16,000 documents relating to construction security for the Dakota Access Pipeline. Justices also will be deciding in a separate but related case before the high court whether to give pipeline developer Energy Transfer a second avenue to try to block the records from the public. The court already has temporarily stopped any disclosure, and justices are now deciding whether to continue that order while Energy Transfer appeals a state district judge's determination that the documents are open records under North Dakota law. The temporary Supreme Court order means that the 62,000 pages of documents deemed by the judge late last year to be public will remain off limits for now to anyone, including several news organizations that have requested them. The Intercept, a nonprofit online news outlet, sued in November 2020 to get access to the documents to continue investigative journalism on the extensive and sometimes violent pipeline protests in southern North Dakota in 2016-17. The convoluted nature of the dispute that has dragged on more than a year was on display during a Supreme Court hearing this week, with Justice Daniel Crothers asking an attorney if two appeals are necessary, and Justice Lisa Fair McEvers inquiring of another lawyer: "This is not a usual case of an open records request, is it?" The 16,000 documents are being held by the North Dakota Private Investigation and Security Board, which obtained them during an administrative case involving the operations of TigerSwan, the North Carolina company that Energy Transfer hired to oversee security during pipeline construction. South Central District Judge Cynthia Feland in late December ruled that the documents are public and subject to the state's open records law. And last month she refused to delay their release while Energy Transfer attorneys appeal her December ruling. That meant the documents were available to the public, including the media. But Energy Transfer appealed to the Supreme Court before anyone could obtain them. The company maintains the documents should remain private because they're “privileged, confidential and proprietary" -- something Feland concluded company attorneys hadn't backed up with specific evidence. Energy Transfer late last month asked the Supreme Court to put Feland's order on hold while its appeal plays out, arguing that "Once ... (the) documents are disclosed to the public, that disclosure can not be undone." The court on Feb. 2 granted the request "until further order" and put a Feb. 7 deadline on written responses.
Bakken oil play now branded 'mature' as industry appetites shrink in North Dakota - — A consensus is forming among North Dakota’s top oil industry operators: the formation that drove the state’s fracking boom has entered its middle age. “The Bakken has been rebranded — whether we want it to be or not — as mature,” said Lynn Helms, director of the North Dakota Oil and Gas Division, Monday, Feb. 14, recounting a key takeaway from conversations with some of the state's biggest oil producers at a recent industry conference in Houston. While many oil producers still view the Bakken as "a cash cow," Helms said they aren't reinvesting resources in the formation like they once did, focusing instead on Texas and New Mexico. Among the reasons driving the Bakken’s shifting reputation, Helms cited a surge in attention among oil industry operators on their carbon footprints, as well as some concerns about the viability of industry technology that could be needed to sustain high output from North Dakota wells as they get older. North Dakota’s oil output dropped by about 2% in the month of December, according to industry data released on Monday, and sits at 1.14 million barrels per day. Production has hovered around that number for the better part of the last year, as North Dakota has struggled to return to its prepandemic high of 1.52 million barrels per day in November of 2019. If the industry's approach to North Dakota holds, Helms said the state should expect to see flat or slight production growth over the next decade or so, after which output would slowly trail off as the industry continues to pump oil from its existing inventory of wells. A common goal to eradicate natural gas flaring is an “enormous” factor in the shifting mindset toward the Bakken, Helms said. The process of burning off excess natural gas that comes up from oil wells, flaring releases planet-warming carbon dioxide emissions. With financiers increasingly factoring climate consequences into their investments, achieving a gas capture level near 100% has become “goal number one" for many oil producers, Helms said, even more than expanding output. Oil producers in North Dakota captured 93% of their natural gas output in December, clearing the state’s regulatory standard but falling well below the average levels found in oil plays like the Permian in New Mexico and Texas, which have more infrastructure to capture and transport gas. Flaring was particularly high this December on private lands on the Fort Berthold Indian Reservation, where just 46% of natural gas was captured. “Four years ago, visiting these same people, everyone was pounding the table, wanting” more lax flaring regulations so they could produce more oil, Helms said of the Houston visit. “In four short years that has made a complete 180.”
Enbridge misses Minnesota hiring goals for Line 3, exceeds promised spending with Indigenous firms - Enbridge fell short of its Minnesota hiring goals for its new Line 3 oil pipeline, but the Canadian company exceeded its target for spending on tribal-owned businesses. That's the bottom line of an Enbridge report filed Monday with state utility regulators, chronicling some economic impacts of the controversial pipeline, which was completed four months ago. Enbridge anticipated that at least half of the construction jobs for new Line 3 would be filled through "local union halls," according to filings with the Minnesota Public Utilities Commission. The other half would be union workers directly hired by Enbridge's contractors. Of the 12,155 workers hired to build the pipeline during the project's duration, 37% were Minnesota residents. Another 10% were from the Dakotas, Wisconsin or Iowa. (Peak daily employment on Line 3 was 5,500 workers in February 2021.) Looking at it another way: Minnesota residents put in 32% of the 10.8 million work hours on the project, while workers from the four adjoining states contributed 9%. At least two key Minnesota union locals on the Line 3 project have members in Wisconsin and the Dakotas. The U.S. portion of the new pipeline cost Enbridge over $4 billion — most of which was spent on a 340-mile stretch across northern Minnesota. Much smaller sections of new pipe are in North Dakota and Wisconsin. The pipeline, which ferries heavy Canadian crude to Superior, Wis., was one of the largest construction projects in recent Minnesota history. Pranis said that from the Laborers union's perspective, Enbridge essentially met its local hiring goals. Three Minnesota-based Laborers union locals supplied workers for the Line 3 project; one of those also has jurisdiction in northwestern Wisconsin, the other in North Dakota. Over 50% of the laborers on Line 3 were from the three locals — meeting the goals of the union contracts with Enbridge, Pranis said.
Flint Hills' Pine Bend refinery produces more fuel with less pollution - You no longer smell the huge refinery in Rosemount before you see it. Since Minnesota regulators fined Pine Bend $6.9 million in 1998 for spills and oil leaks into the nearby Mississippi River, Flint Hills has invested about $2 billion in emission control and efficiency technology, as well as restoring 1,600 acres of the Pine Bend Bluffs nature preserve along the Mississippi River. The huge facility has lowered emissions of traditional pollutants by about 70% as it increases production of diesel, gasoline, jet fuel, asphalt and other petroleum-based products. In 2021, it also received the U.S. Environmental Protection Agency's Energy Star certification as a top-quartile performer among refineries for energy efficiency. Still, Pine Bend remains among Minnesota's Big 10 emitters of greenhouse gases (GHG), the driver of climate change that results in increasing numbers of environmental disasters that also are economically devastating nationally. Minnesota Pollution Control Agency (MPCA) statistics reveal that Pine Bend's greenhouse emissions grew 9% between 2012 and 2020. However, the emissions declined nearly 6% since 2010 on a per million-barrels-of-product basis. Pine Bend production rose 20.6% from 2010 to 2021, or 316,000 barrels per day of product.
Are oil majors greenwashing? What 12 years of data show - There is a “mismatch” between the public statements of four of the world’s largest oil and gas companies and their actions and investments on clean energy, according to new research that analyzed 12 years of data. The study,, published yesterday in the journal PLOS One, focused on Chevron Corp., Exxon Mobil Corp., BP PLC and Shell PLC. Those companies are responsible for more than 10 percent of global carbon emissions since 1965, the study noted. Using data collected between 2009 and 2020, researchers from Kyoto University and Tohoku University said none of the four majors have entered the renewables market at a scale “that would indicate a shift away from fossil fuels” and that the business models of each company are still dependent on fossil fuels. The authors called for more transparency around each company’s definition of words such as “low-carbon,” “clean energy” and “renewables” and said that until the areas of discourse, actions and investment are “brought into alignment, we conclude that accusations of greenwashing by oil majors are well-founded.” “Mitigating further dangerous warming requires these majors to urgently transform their fossil-fuel-based business models rather than merely increase discourse and pledges,” they said. The study used three categories, or “perspectives,” to assess the companies’ clean energy transition activity, including “discourse,” or keywords used in annual reports, investments, and pledges and actions. The authors said the number of mentions of words like “transition,” “low-carbon energy,” and “climate change” increased in annual reports over the research period, particularly for Shell and BP. California-based Chevron is the “only major not showing a noticeable increase,” the study said, with the word “climate” missing from annual reports in 2009 to 2011. But while there’s been a rise in keywords used, the study concluded that “American majors continuously exhibit defensive attitudes to renewables investment” and a need to move away from fossil fuels. The study also noted that “fluctuations notwithstanding, relative spending trends indicate that upstream exploration and production of oil and gas remain the pillar business for all majors, especially the American majors.” The research comes as oil and gas companies are facing heightened pressure from investors to meaningfully address climate change and as Democrats on Capitol Hill have criticized the companies for making “empty promises” when it comes to their greenhouse gas emissions commitments (Climatewire, Feb. 9)
Oil firms’ climate claims are greenwashing, study concludes -- Accusations of greenwashing against major oil companies that claim to be in transition to clean energy are well-founded, according to the most comprehensive study to date. The research, published in a peer-reviewed scientific journal, examined the records of ExxonMobil, Chevron, Shell and BP, which together are responsible for more than 10% of global carbon emissions since 1965. The researchers analysed data over the 12 years up to 2020 and concluded the company claims do not align with their actions, which include increasing rather than decreasing exploration.The study found a sharp rise in mentions of “climate”, “low-carbon” and “transition” in annual reports in recent years, especially for Shell and BP, and increasing pledges of action in strategies. But concrete actions were rare and the researchers said: “Financial analysis reveals a continuing business model dependence on fossil fuels along with insignificant and opaque spending on clean energy.”Numerous previous studies have shown there are already more reserves of oil and gas and more planned production than could be burned while keeping below the internationally agreed temperature target of 1.5C. In May 2021, the International Energy Agency (IEA) said there can be no new fossil fuel developments if the world is to reach net zero by 2050. Oil companies are under increasing pressure from investors to align their businesses with climate targets. But their plans have faced scepticism, prompting the researchers to conduct the new research, which they said was objective and comprehensive. “Until there is very concrete progress, we have every reason to be very sceptical about claims to be moving in a green direction,” said Prof Gregory Trencher, at Kyoto University in Japan, who worked with Mei Li and Jusen Asuka at Tohoku University.“If they were moving away from fossil fuels we would expect to see, for example, declines in exploration activity, fossil fuel production, and sales and profit from fossil fuels,” he said. “But if anything, we find evidence of the reverse happening.”“Recent pledges look very nice and they’re getting a lot of people excited, but we have to put these in the context of company history of actions,” Trencher said. “It’s like a very naughty schoolboy telling the teacher ‘I promise to do all my homework next week’, but the student has never worked hard.”The new study, published in the journal PLOS One, found mentions of climate-related keywords in annual reports rose sharply from 2009 to 2020. For example, BP’s use of “climate change” went from 22 to 326 mentions. But in terms of strategy and actions, the researchers found “the companies are pledging a transition to clean energy and setting targets more than they are making concrete actions”.
Republicans champion Alaska drilling project that poses major climate test for Biden - House Republicans on Tuesday urged the Biden administration to move forward with a controversial drilling project proposed in Alaska, saying it would bring enormous economic benefits to the region. Their comments referred to ConocoPhillips's Willow project in the National Petroleum Reserve-Alaska, which poses a significant test of the Biden administration's willingness to block fossil fuel drilling and mining on public lands — activities that account for nearly a quarter of the nation's greenhouse gas emissions. : As the largest oil and gas project on the horizon in the United States, Willow could have a significant impact on the climate. It would pump nearly 600 million barrels of oil over 30 years —equivalent to the annual emissions of about a third of all coal plants in the country. : While Willow was approved in the final months of the Trump administration, the Biden administration initially defended the project in court, angering many climate activists.
- However, after a federal judge voided Trump-era permits and approvals for the project last year, the Biden administration declined to appeal the ruling.
- The Interior Department's Bureau of Land Management is now soliciting public comments on a court-ordered supplemental environmental review of the project under the National Environmental Policy Act.
- Climate advocates are urging the administration to conduct a sweeping review of Willow's climate effects, including its greenhouse gas emissions. They argue that such a review would show the project should not go forward at all.
Interior spokeswoman Melissa Schwartz said the department has no further comment on Willow beyond its announcement of the public comment period this month. “As with all public comment periods, all perspectives are welcome,” Schwartz said in an email.
Price tag on Trudeau’s oil pipeline project soars to $17 billion — The cost to expand the Trans Mountain oil pipeline that Justin Trudeau’s government bought from Kinder Morgan Inc. has jumped by 70% to nearly $17 billion, potentially challenging the viability of the line from Canada’s oil heartland to the Pacific Coast. The new estimate of C$21.4 billion ($16.8 billion) includes the costs of enhancements, changes, delays, financing, as well as the impacts of the pandemic and last year’s floods in British Columbia, according to a statement released Friday by Trans Mountain Corp., which was bought in 2018 to save the expansion project from being scrapped. It’s the second time since early 2020 that the cost estimate was raised by about 70%. Canada’s oil industry for years has struggled with a shortage of pipelines to ship crude from Alberta’s oil sands, which hold the world’s third-largest reserves. Trudeau has sought a difficult balance between saving a project that was crucial for the country’s oil industry using taxpayers’ money, at the same time as pledging to help fight climate change. His government on Friday said that it will spend no additional public money on the project, and that Trans Mountain Corp. will instead secure the funding necessary to complete the project with third-party financing, either in the public debt markets or with financial institutions. The government has engaged both BMO Capital Markets and TD Securities to provide advice on financial aspects of the project, according to a statement on the Department of Finance’s website. In order to quell opposition to the project that will increase shipping capacity from about 300,000 barrels a day to more than 800,000, Trudeau’s government has been in talks with First Nations that are willing to own as much as 100% of the pipeline. Trudeau’s government bought the pipeline after Kinder Morgan threatened to halt the expansion because of fierce opposition in British Columbia, including from some indigenous groups along the line’s path that fear it will be a threat to their environment. Completion of the project is now expected in the third quarter of 2023, compared with a previous estimate of as early as this year. “Notwithstanding the cost increase and revised completion schedule, the business case supporting the project remains sound. Canada will benefit from the economic and tax contributions made by the Project once it is in operation,” Trans Mountain said in the statement on its website.
Company responsible for fuel spill off Newfoundland says it's working to mitigate impact -The owner of a cargo ship that spilled fuel into the waters south of Newfoundland says it is working to mitigate the impact of the spill. The MV Alaskaborg, owned by Dutch company Royal Wagenborg, accidentally discharged 30,000 litres of fuel Thursday. In an update Saturday night, the Canadian Coast Guard said the spill occurred over a period of 12.5 hours and a distance of 175 nautical miles. In an emailed statement to CBC, Royal Wagenborg said it has developed a plan using two vessels with pollution response equipment and land-based teams to conduct shoreline assessments in the area. The company said while the accident occurred "as a result of an emergency bilge operation of the cargo hold" amid rough weather, the "exact circumstances of this incident are unknown." The MV Alaskaborg was en route to Rotterdam from Baie Comeau, Que. when the incident occurred. According to a statement from the company, the spill was discovered after daylight on Thursday morning and the incident was immediately reported to authorities in Canada and the Netherlands. The ship was subsequently escorted to St. John's harbour by a coast guard vessel following the incident, arriving in St. John's on Friday night where it remains berthed since.
Calif. wildlife team rescues penguins from Peru oil spill — A California-based wildlife rescue group is helping sea birds that were caught in a major oil spill along the coast of Peru. Unusually large waves from an undersea volcanic eruption in Tonga damaged a tanker ship that was unloading oil at a refinery in Peru. More than 500,000 gallons of heavy crude oil spilled into the Pacific Ocean near the shores of Ventanilla, Peru, on Jan. 15.The spill stained nearly 30 miles of Peru’s beaches and nearby islands. Bird species in the area include the vulnerable Humboldt Penguin, Peruvian Booby, Guanay Cormorant, and the Peruvian Pelican. International Bird Rescue, based in Fairfield, Calif., sent a team of bird experts to help alongside a Brazil-based rescue group, Aiuká. At least 200 oiled animals have been rescued and many are being cared for at Parque de las Leyendas Zoo in Lima, Peru. The spill was described as an “ecological disaster” by the Peruvian government. International Bird Rescue has a long history of working with international emergency response partners to provide the best outcome after an oil spill. Over the past 50 years, International Bird Rescue has responded to over 230 oil spill events, including the 1989 Exxon Valdez Oil Spill, the 2000 Treasure Oil Spill in South Africa where 20,000 oiled penguins were saved, and the 2010 Deepwater Horizon oil rig blowout in the Gulf of Mexico.
Peru: Repsol Must Restore Sea Conditions Prior to Oil Spill - The Peruvian Environment Minister, Modesto Montoya, said on Monday that the Repsol Oil company must restore sea conditions existent before the oil spill. According to Modesto Montoya, the Peruvian Environment Minister said on Monday that Repsol must be in charge of restoring prior conditions of the sea before the events of the oil spill last January 15 at La Pampilla Refinery in Ventanilla district's area. During an interview with Peru Radio Programmes (RPP), the Minister highlighted that even though the cleaning of the crude oil is a complex process, the company must be the one who deals with the matter, because of its responsibility with the events. The Minister noted that the clean-up of the beaches is moving slowly; according to experts in this sector, Repsol has not removed the white foam in areas like the islands where guano birds are found. Such foam is the result of the contact between the oil and the water. He followed by expressing his gratitude to volunteers from universities and disclosed that the clean-up of beaches had been completed to 70 percent, despite the contamination of the seabed remaining, aspects which have to be evaluated. It is estimated that about 2 000 barrels of oil have been already removed from the coast, but the Spanish company Repsol spill is equivalent to around 11 000 barrels. Montoya made emphasis that crude oil has reached other remote places.
Europe relies primarily on imports to meet its natural gas needs --Imports of natural gas by both pipeline and as liquefied natural gas (LNG) provided more than 80% of the supply of natural gas to the countries of the European Union (EU-27) and the United Kingdom (UK) in 2020, up from 65% a decade earlier. During 2020, natural gas imported into the region by pipeline made up 74% of all natural gas imports, and LNG accounted for the remaining 26% of total imports.Pipeline imports of natural gas into the region come from Russia, Norway, North Africa, and Azerbaijan. Pipeline imports originating in Russia—the largest supplier in the region—grew from about 11 billion cubic feet per day (Bcf/d) in 2010 to more than 13 Bcf/d in 2020 (a low consumption year due to COVID-19 related impacts). Despite construction of new pipelines, imports from Norway averaged around 9 Bcf/d between 2010 and 2020, as development of new fields in the Barents Sea section of the Norwegian offshore Continental Shelf was insufficient to offset declines from mature fields in the North Sea. Although LNG imports made up about 26% of all natural gas imports, they provided about 20% of all of the natural gas supplied to the EU-27 countries and the UK in 2020. LNG imports tend to fluctuate from year to year—from as low as 3.6 Bcf/d in 2014 to as high as 10.1 Bcf/d in 2019—depending on global natural gas prices, demand driven by cold weather, and the availability of pipeline supplies. Most LNG delivered to Europe is supplied through long-term contracts. However, growing volumes of flexible LNG supplies, primarily from the United States, contributed to the notable increases in LNG imports to Europe from 2019 to 2021.Regional production has played a smaller role in supplying European natural gas needs over the past decade. From 2010 through 2020, natural gas production in the EU-27 countries and the UK declined by more than 50%, from 18 Bcf/d in 2010 to 9 Bcf/d in 2020. This decline is the result of resource depletion as well as initiatives to fully phase out natural gas production in the region. Regional natural gas demand fell rapidly between 2010 and 2014, and then it stabilized during the five-year period from 2016 to 2020 at approximately 45 Bcf/d. Natural gas consumed by the European industrial sector, where fuel switching is difficult, remained nearly unchanged, averaging 13.7 Bcf/d throughout the 2010–2020 period. Energyefficiency measures and electrification reduced residential and commercial sector natural gas consumption to an average of 17 Bcf/d in 2020. Natural gas consumption in the electric power sector fell the most between 2010 and 2014 as a result of increasing penetration of renewable energy in electricity generation. Starting in 2016, consumption of natural gas in Europe’s electric power sector increased as a result of the systematic retirement of coal-fired power plants across Europe and the retirement of nuclear power plants in Germany in particular.
Putin's threats against Ukraine could reinvigorate the U.S. oil and gas industry - Russian President Vladimir Putin has long made it clear that he is no fan of U.S. shale drilling. But, if he invades Ukraine, he may unwillingly help bring back the American industry. Like other global producers, the U.S. industry was crushed by the pandemic in early 2020. Oil prices crashed, and prices for crude futures even turned negative on the CME for a brief time. An extremely chastened U.S. industry reemerged, with executives more cautious than ever about throwing money down oil wells and angering shareholders. The U.S. industry has been making a slow comeback, helped by rising oil prices, which are up more than 50% in the last year. Putin's threats against Ukraine have helped drive an already rising oil price well above $90 per barrel to a seven-year high, with nearly 30% of that price rise since the start of the year. "The last thing they wanted to do was provide a price incentive for a rebound in U.S. oil and gas production," said Dan Yergin, vice chairman of IHS Markit. "They now succeeded in driving up prices, which is strengthening U.S. oil and gas production." Russia has historically been the largest provider of both oil and natural gas to Europe, and the U.S. has long warned that its control of critical energy sources could prove to be a hazard for European consumers. Yergin said Putin has been a strong opponent of U.S. shale, and as far back as 2013, the Russian president told a public forum in St. Petersburg that shale was a grave threat. President Joe Biden said Tuesday that the U.S. and Russia would continue to use diplomatic channels to avoid a military outcome, but warned the situation remains uncertain. Russia announced Tuesday it was pulling back some of its more than 100,000 troops on the Ukraine border. By Wednesday, however, NATO said Russia instead was increasing its troops. Oil rose Wednesday, with West Texas Intermediate futures for March up 2.6%, at about $94.50 per barrel in afternoon trading. "The geopolitics of energy is back with full fury," Yergin said. Energy is clearly at the center of the conflict. European natural gas prices have been flaring all winter on concerns about short supply. First, the region was unable to put enough natural gas into storage. Then, Russia cut back some supply starting in the fall.
Qatar's Asian gas contracts hamper Ukraine planning - Nikkei Asia U.S. pursues alternative LNG supplies for Europe if Russian cuts flow -- Qatar's deepening trade in natural gas with Asia is complicating global efforts to protect Europe from the threat of an energy squeeze by Russia.
Egypt breaks LNG export records with eye on Europe - — At the end of January, the Gaslog Glasgow departed from the liquefied natural gas (LNG) plant in Damietta, Egypt, and set course for the Gate Terminal in Rotterdam, the only LNG import facility in the Netherlands. With a capacity of 174,000 cubic meters, this was the first such shipment ever from Egypt to the Netherlands, which operates as a hub for the supply of this type of natural gas in the strategic northwest Europe. The shipment symbolically opened the door to a new market at a particularly good time for Egyptian LNG exports. Last year, fueled by an unusually favorable context, Egypt recorded a 10-year high in LNG sales, a flow that local authorities hope to maintain at least in the short term as the country moves to position itself as a regional hub for the trade and distribution of natural gas and to become a major player in the LNG market. Egypt’s road to LNG exports has not been an easy one. For much of the last decade, and especially in the years following the tumultuous 2011, the country has depended heavily on gas imports, to the extent that in 2016 it had to spend some $3 billion to this end. The situation started to reverse rapidly in 2018 after the discovery of new major gas fields, the introduction of far-reaching reforms in the sector, the payment of most dues accumulated to foreign partners and the arrival of extensive foreign direct investments in the industry.The work done over the past few years laid the groundwork for Egyptian LNG exports to register a large increase in 2021, marked by a particularly favorable context. Exports from the Idku plant, one of Egypt’s two liquefied gas facilities, picked up after the fall experienced disruptions amid the early coronavirus pandemic. And the second such facility — the Damietta plant — resumed its production at the end of February after an eight-year hiatus, benefiting from a jump in global LNG prices. The spokesman of the Ministry of Petroleum, Hamdi Abdel-Aziz, considered back then that the return of both plants to operation “will mark the revival and prosperity of Egypt’s LNG production.”At least for now, figures prove him right. Egypt’s exports of natural and liquefied gas jumped during 2021 by 550% to reach $3.9 billion, compared to $600 million the year before, according to a statement attributed to the country’s Minister of Petroleum Tarek el-Mulla, issued Feb. 2 on the ministry’s Facebook page. In December, Mulla detailed that Egypt exports about 1.6 billion cubic feet per day of gas through its two LNG plants. And in a statement following the general assembly of the Egyptian Natural Gas Holding Company (EGAS) Feb. 11, the minister said that the total amount of natural gas and LNG exports reached 3.5 million tons during the first half of Egypt’s current fiscal year, which starts in July, and that he expects them to rise to 7.5 million tons by the end of it.
Azerbaijan's gas exports see nearly 40 pct growth in 2021 (Xinhua) -- Azerbaijan has exported 18.9 billion cubic meters of gas in 2021, registering a 39.8 percent increase year-on-year, the country's energy ministry said in a recent statement. The country's gas production registered 43.9 billion cubic meters last year, increasing by 18.1 percent from 2020. Turkey was the largest market for Azerbaijan's gas in 2021, consuming 8.5 billion cubic meters. Meanwhile, Azerbaijan has exported 28.1 million tons of oil in 2021, a 1 percent fall from 2020, the ministry said. According to the statement, the country produced a total of 34.6 million tons of oil in 2021, falling 2.9 percent short of the forecast. Last November, the government announced plans to raise the gas production output to 50 billion cubic meters by 2026. The country slightly lowered its oil production forecast for the years 2024, 2025 and 2026. In 2023, the oil production is forecast to grow by 2.6 percent. The price of a barrel of Azeri Light crude oil now trades at 99.70 U.S. dollars on world markets
European gas storage levels survive winter but summer refilling looms - (Reuters) - European gas storage levels have fallen less than feared after a mild winter and unprecedented deliveries of liquefied natural gas (LNG), but refilling will be a challenge this summer. The winter gas season runs from October to March and the summer gas season starts in April. Typically in the summer season wholesale gas prices and demand are lower and more gas goes to storage. However, that did not happen last year. Global supply was tight because of high Asian demand for LNG and lower-than-normal Russia gas pipeline flows. Wholesale prices were unusually steep for the summer season and limited the injections of gas into storage. As a result, Europe entered winter with gas storage at its lowest in at least 10 years. Concern that Russian gas supplies would be disrupted if the country invades Ukraine have pushed prices to record levels. Russia has massed troops near Ukraine's border but repeatedly denied it plans to invade. read more "Storage is not expected to end winter at critical levels, and while this gives Europe a bit of a buffer, it does have implications on restocking demand this summer," said Laura Page, senior LNG analyst at data and analytics firm Kpler. According to data from Rystad Energy, northwest European storage levels are around 10% below 2021 volumes. Europe-wide storage remains at a five-year low of 32.6% full, Gas Infrastructure Europe data showed. "Europe received a record 13.15 billion cubic metres of LNG send-out in January after Asia stopped competing for Atlantic basin cargoes," LNG receipts in Europe will remain high this year, but are expected to fall from current levels as Asian buyers need to restock, Japan covers nuclear outages with LNG and overall demand in Asia grows, he added. However, new LNG capacity coming online this year could provide more supply and producers might postpone LNG infrastructure maintenance outages to take advantage of high prices, said Carlos Torres Diaz, head of power and gas markets at Rystad Energy. Russia is unlikely to send higher volumes of natural gas, given its reluctance to book additional pipeline capacity to Europe this year, he added. Another issue is the lack of financial incentive to refill. Putting gas into storage has a cost. That means buyers require lower prices in the summer compared to the following winter to build up stocks, but wholesale prices for gas are uniformally high until next year.\
'A very scary concept': Energy ministers fearful of oil prices surpassing $100 a barrel -- Energy ministers representing Egypt and Cyprus on Monday said they were deeply concerned about the potential for oil prices to climb above $100 a barrel. It comes at a time when more than a dozen countries have urged their citizens to leave Ukraine amid warnings of an imminent Russian invasion. International benchmark Brent crude futures soared to a new seven-year high on Monday morning on the elevated geopolitical tensions. The contract was last seen trading at $94.33, down 0.1% for the session after earlier hitting a peak of $96.16. U.S. West Texas Intermediate futures, meanwhile, stood at $93.20, roughly 0.1% higher. The U.S. and Europe have threatened to sanction Russia if it invades Ukraine, escalating fears of a possible supply disruption from one of the world's top producers. Russia has repeatedly denied it is planning to invade Ukraine dispute amassing around 100,000 soldiers on Ukraine's borders. Speaking at an oil and gas exhibition conference in Cairo, Egypt, energy and petroleum ministers representing Egypt, Cyprus, Israel and the United Arab Emirates were asked whether they expected oil prices to spike into triple-digit territory. "For me, being professional I can see it happening, but I don't want it to happen," Egypt's Petroleum Minister Tarek El Molla told CNBC's Hadley Gamble at EGYPS 2022. Cyprus' Energy Minister Natasa Pilides agreed it was "a very scary concept" to imagine oil prices surpassing $100 a barrel. "It is actually quite tangible," she added. "It is very difficult to deal with because on the one hand, we have the tendency particularly in the last few months of subsidizing basically which is not the norm, so we are in that difficult position where when you start doing that it is very difficult to stop it," Pilides said. "We definitely need to stick to our targets in terms of the energy transition, but I would also add that natural gas has a place in that trajectory as a bridge fuel." Speaking at the same panel event, Israeli Energy Minister Karine Elharrar said: "It is a very hard question, but I think if we don't want to be at [$100 oil] then we have to make sure that we have a diversity of energy sources." The International Energy Agency has previously recognized natural gas as the "cleanest burning and fastest-growing fossil fuel," but has cautioned that its longer-term use in a transition to net-zero energy systems is uncertain. To be sure, the burning of fossil fuels, such as coal, oil and gas, is the chief driver of the climate emergency.
Shutdown of South Africa’s biggest fuel refinery — what it means for jobs and power cuts -- The impending shutdown of the South African Petroleum Refiners (Sapref) joint venture between Shell Downstream South Africa and BP will result in thousands of job losses and help reduce the likelihood of load-shedding.That is according to an analysis of the closure’s potential impact by well-known economist Mike Schussler.Schussler said on Wednesday that the closure of Sapref would see the country producing less than 30% of the petroleum it did in 2005.A chart shared by Schussler showed the country’s petroleum and nuclear fuel output had consistently hovered around 90-100% of 2005’s levels up until 2019.But in 2020, this dropped to 70%, likely driven by Covid-19 reducing demand for petrol with strict lockdowns limiting people’s movement.The downward trend continued in 2021 until production hit 55% of 2005’s levels.The chart below shows the relative production output of petroleum and chemical products in South Africa compared to 2005. Last year’s decline was likely due to Astron Energy and Engen shutting down their refineries in 2021 after fires at the respective facilities in July and December.Executive director of South African Petroleum Industry Association (Sapia), Avhapfani Tshifularo, previously told S&P Global Platts the Astron Energy plant was likely to return to service.However, Tshifularo said they expect Engen would convert its plant into an import terminal.Sapref also had to temporarily pause operations due to the July riots cutting it off from the essential materials needed for refining oil.The loss of Astron and Engen’s plants led to 40% of the country’s petroleum needs being met by imports.
Aquadrill Drillship Catches Fire In Sri Lanka Port - An Aquadrill-owned drillship caught fire earlier this week in a port in Sri Lanka during its stay in layup. According to available information from the port, Aquadrill’s drillship Polaris caught fire on Tuesday at Berth 6 of the Hambantota Port in Sri Lanka. The Hambantota International Port Emergency Response Unit together with the port’s Quality, Health, Safety, and Environment Department, and Port Control responded to a fire that occurred on board the Polaris drillship on Tuesday, February 15. The port authorities said that the ship’s crew alerted Port Control for assistance in dousing the sudden fire that broke out in the ship's emergency generator room. The Emergency Response Unit’s fire trucks arrived on the scene within minutes of being notified, assisting the crew to quickly contain the fire with charged fire hoses. The respective ERU teams brought the fire fully under control within 33 minutes of their arrival and were able to prevent serious damage to the drillship and the surrounding area. “The joint effort of this venture reflects professionalism and assurance to Hambantota International Port users and stakeholders of optimum safety and proactive response to unforeseen events related in maritime operations,” Tissa Wickramasinghe, COO of the port, said. The Polaris drillship has been in layup at the Hambantota Port since January 11, 2021. The ship is expected to remain in port until June 2022.
Navy sent to deal with second oil spill off Rayong - A fresh oil spill was found in the Gulf of Thailand off the coast of Rayong yesterday (Feb 10) and was being cleaned up, according to local authorities. accidents environment pollution It was believed about 5,000 litres of oil had leaked, reports the Bangkok Post. Nine navy ships were deployed to contain the slick which was about 20km from shore, said deputy provincial governor, Pirun Hemarak, adding the situation was under control. He said he did not expect the slick to reach land. The incident comes on the heels of a Jan 25 leak from an underwater pipeline belonging to Star Petroleum Refining Public Company Limited (SPRC), near Map Ta Phut in Rayong. The spill, involving 47,000 litres of crude oil, has since been cleaned up. Yesterday, Pollution Control Department director-general Atthapol Charoenshunsa said SPRC alerted authorities to the latest leak which may have occurred during modification work on an underwater pipeline. An investigation was ongoing to determine the cause. The department initially refused a company request to use about 5,000 litres of dispersant, deeming the amount excessive. However, an unspecified amount was later dispatc
Marine Dept probes second Star Petroleum oil spill off Rayong - The Marine Department is investigating another oil spill off the coast of Rayong that was reportedly caused when Star Petroleum Refining Plc (SPRC) moved the underwater pipeline at its single point mooring (SPM). The same pipeline caused a massive oil spill on January 25. “Moving the pipeline reportedly caused about 5,000 litres of oil that was still in the pipe to flow into the sea on February 10 [Thursday],” said Marine Department deputy director-general Phuri Theerakulpisut on Saturday. The department has banned ships from the area and filed a complaint with Map Tha Phut police accusing SPRC of violating its order to suspend operations at the SPM and causing further marine pollution. The Department also ordered SPRC to issue a Tier 1 warning, which is a standard protocol when less than 20 tonnes of oil is spilled during transport. Under the protocol, after alerting the public, the party responsible for causing the spill must clean up the oil slick or immediately request assistance from agencies to prevent the slick from expanding. “SPRC said they deployed booms around the slick on Thursday and that the situation is now under control,” said Phuri. “The department has dispatched boats and officials to monitor the situation and will investigate to estimate the environmental damage.”
New oil slick washes up at Mae Ramphueng Beach despite SPRC’s blotting efforts (video) A slick caused by the leakage of 5,000 litres of oil from an undersea pipeline off the coast of Rayong has washed up at Mae Ramphueng Beach, press reports said on Saturday. Share this article The sand on the beach is now covered with a glossy film of slime with an oily smell despite Star Petroleum Refining (SPRC)’s efforts to disperse the oil with booms and blotting papers. New oil slick washes up at Mae Ramphueng Beach despite SPRC’s blotting efforts Tapong subdistrict mayor Taweep Saengkrachang echoed Deputy Transport Minister’s assumption earlier that the latest leak had been caused by SPRC’s inspection of the pipeline at the single point mooring (SPM) site. As for the slick on the beach, he reckons it is accumulated from the initial spill of more than 40,000 litres of crude oil on January 25. He also voiced concern that oil accumulated under the sea would wash up between March and April when the monsoon arrives. Meanwhile, the Pollution Control Department has collected samples of the oil slick for tests. So far, related agencies, including the Thai Navy, have been working hard to clear the slick with booms and chemical dispersants. “A large slick is visible seven kilometres off the coast of Mae Ramphueng Beach and 10km from Samet Island,” press reports said. This is a second leak after some 160,000 litres of crude oil was leaked from an SPRC pipeline about 17 kilometres from the Map Ta Phut Industrial Port. Published : February 12, 2022
Second oil spill 'doubles' damage to Rayong coast - A second oil spill from a pipeline owned by Star Petroleum Refining Public Co Ltd (SPRC) has at least doubled the damage to the marine environment off the coast of Rayong, an expert said on Sunday. Thon Thamrongnawasawat, deputy dean of the Faculty of Fisheries at Kasetsart University, wrote on his Facebook page on Sunday that oil slicks can once again be seen along Mae Ramphueng beach, one of the areas worst-affected by the first oil spill on Jan 25. After the first spill, the Ministry of Natural Resources and the Environment urged the police to investigate SPRC. The company was also told to cease operations immediately after the incident. However, SPRC admitted on Thursday that a further 5,000 litres of crude oil had leaked from the same pipeline. Mr Thon said thin films of crude oil can be seen along Mae Ramphueng beach once again. Worse still, he wrote, samples taken from the beach showed the oil was seeping deeper into the sand. A study of wedge clams, a known biological indicator of pollution, that were taken from the area showed many were killed as a result of exposure to crude oil. The spill, he said, isn't just affecting local clam populations, as many other crustaceans commonly found along the coast have also been affected. The clean-up of Mae Ramphueng beach is carried out by the Air and Coastal Defence Command under the navy, which recently said the situation was "under control".
IEA forecast: Oil demand up 900,000 bpd for 2022 - The International Energy Agency (IEA) revised up its global oil demand estimates for 2022 by around 900,000 barrels per day (bpd) compared to last month's assessment. Global oil demand is estimated to reach 100.6 million bpd, increasing by 3.2 million bpd in the 2022 year on year, according to the IEA's latest oil market report on Friday. "The milder-than-expected negative impact of the Omicron variant on demand has been largely offset by additional consumption stemming from a cold snap in the US and a continued switch to oil from gas in some industrial sectors," the agency explained. It noted that the absolute level of demand increased significantly from last month's report, due to changes to the IEA's baseline estimates for Saudi Arabia and China, which have been revised higher on new and more complete data. The agency projects that the fast spread of the omicron variant and accelerated vaccination programs are expected to increase population immunity by the end of the first quarter, while restrictions to mobility are anticipated to be more limited in the second half of the year, supporting a strong recovery in transportation demand. The growth this year will be driven by the Asia Pacific region with 37.5 million bpd of demand, followed by the Americas with 31.03 million bpd and Europe with 14.4 million bpd. The IEA said global oil supply increased by 560,000 bpd in January to 98.7 million bpd, “with non-OPEC+ producers delivering 70% of the increase while the OPEC+ alliance continued to pump far below target levels.” The Agency stressed that the group's persistent supply shortfall, largely due to technical issues and other capacity constraints, has resulted in a loss to the market of around 800,000 bpd since the start of 2021. The prevailing lower output levels versus stated monthly increases by the bloc have led to unintended consequences, with sharp draws in global inventories and supply shortfalls compounding tight oil markets, the Agency said. The report noted that in January non-OPEC+ oil supply rose by 410,000 bpd, led by higher output from Canada, Ecuador, Brazil, and China. Total oil production from OPEC+ rose by a more modest 150,000 bpd after a recovery in Nigeria while higher Middle East and Russian flows were partly offset by lower output in Venezuela and Libya. By the end of this year, the amount of oil lost could approach 1 billion barrels unless members with substantial spare capacity, concentrated in the Middle East, pump more to make up for those who cannot, the Agency warned, adding that "there is no sign of that happening yet." As for Iran, which is in talks to revive the Joint Comprehensive Plan of Action (JCPOA) nuclear deal, crude production could rise towards a sustainable capacity of 3.8 million bpd, up roughly 1.3 million bpd from current levels by the end of this year, according to the IEA. Iran also has about 80 million barrels of crude oil and condensate stored on tankers, the Agency said, adding that it will move to clear that overhang as quickly as possible. In addition to Chinese exports, the IEA also expects Iran to re-establish supply contracts with key customers in India, Korea, Japan, Turkey and Europe.
Nigeria Boosts Oil Production By 200,000b/d - In order to meet its Organization of the Petroleum Exporting Countries (OPEC) quota, Nigeria has boosted its crude oil production by over 200,000 barrels per day (b/d). Data obtained from OPEC’s February Monthly Oil Market Report (MOMR) showed that the country’s output, which slid to around 1.1 million b/d last December, climbed to 1.3 million b/d in January. Nigeria’s output ranged between 1.1 mb/d and 1.2mb/d the whole of last year. The country had shut eight oil terminals between August and October, according to statistics from the Nigerian National Petroleum Company, NNPC, Limited. The affected eight terminals include Forcados, Bonny, Odudu, Brass, Yoho, Urha, Ajapa and Aje. As a result, deferred/lost production in October alone was to the tune of 4,824,946 barrels of oil, the lowest among the figures posted during the three-month period. The shut-ins and losses, according to the report, were due to pipeline vandalism, theft, community interferences, sabotage of oil facilities, among others. Losses and deferment in August, September and October were put at 6,680,620 barrels; 6,362,700 barrels; and 4,824,946 barrels respectively. It was also observed that eight crude oil terminals were affected in August, as production was curtailed at the facilities during the period. The affected terminals in the reviewed month include Forcados, Sea Eagle, Brass, Yoho, Qua Iboe, Escravos, Ajapa and Otakikpo. Explaining some of the incidents that curtailed production in one of the terminals, for instance, the NNPC said, “Energia (an oil firm) injection into Brass line (was) suspended due to pipeline damages. “Pillar injection into Brass was suspended due to third party interferences on NAOC (Nigerian Agip Oil Company) Akiri pipeline.” For the month of September, 18 incidents warranted deferment of 6,362,700 barrels of crude oil following production shut-ins recorded. A total of nine terminals were affected in September, including Forcados, Sea Eagle, Brass, Yoho, Qua Iboe, Escravos, Urha, Ajapa and Otakikpo. On some of the incidents that led to the crude oil losses in September, the NNPC stated that “production (was) curtailed due to pipeline outages” at the Forcados Terminal. It also noted that “Energia injection into Brass line (was) suspended from September 1 to 30, 2021 due to pipeline damage”. Findings from the NNPC reports of events that affected production in October 2021, however, showed that the incidents that led to crude oil production shut-ins, reduced to 11 during the month.
IEA Calls On OPEC+ To Boost Production To Targets - OPEC+ producers need to pump more oil to close the widening gap between nameplate production quotas and actual output, the executive director of the International Energy Agency (IEA), Fatih Birol, said on Monday. The laggards in the OPEC+ oil output targets should look to produce more to balance the tight market, Birol said at the Egypt Petroleum Show in Cairo today, as quoted by Reuters.If OPEC+ continues to fail in delivering its oil production targets amid rising demand and inventories at multi-year lows, oil prices will remain under upward pressure and are set for more volatility, the IEA said in its monthly report.“If the persistent gap between OPEC+ output and its target levels continues, supply tensions will rise, increasing the likelihood of more volatility and upward pressure on prices. But these risks, which have broad economic implications, could be reduced if producers in the Middle East with spare capacity were to compensate for those running out,” the IEA said in its Oil Market Report for February.“If OPEC+ cuts are fully unwound, the bloc could increase output by 4.3 mb/d. Of course, that would come at the expense of effective spare capacity, which could fall to 2.5 mb/d by the end of the year and end up held almost entirely by Saudi Arabia and, to a lesser extent, the UAE,” the agency said.The gap between OPEC+ output and its target levels surged to as much as 900,000 barrels per day (bpd) in January, according to IEA estimates.The chronic underperformance of OPEC+ and geopolitical tensions have pushed oil prices to more than a seven-year high, with Brent hitting $95 per barrel early on Monday amid fears of an imminent Russian invasion of Ukraine that could lead to disruption of oil supplies.
OPEC+ is in no rush to bring oil prices down and rightly so | Analysis – Gulf News -- The oil markets seem to have ignored the informal understandings between OPEC+ oil producing countries and the US to maintain a price level of $70-$75 per barrel. Market factors, especially strong demand and geopolitical tensions with a bit of speculation thrown in, remain the key determinant of oil prices, and raising it up to more than $96 earlier in the week. What matters here is what will happen in the coming months as demand rises as a result of steady global economic recovery. Yes, this will coincide with concerns over political developments, especially the Ukraine-Russian crisis. There is also the relatively limited production capacity in OPEC+ countries. During its meeting early this month, OPEC+ members decided to increase production - based on the previous agreement - by 400,000 barrels per day until next March, which reflects their belief that today’s price levels do not require their intervention. This shows that the OPEC+ group is in no hurry to bring prices down. In any case, the output cut agreement will expire next April, which may require a redistribution of quotas, especially as some member states that have excess production capacity are demanding an increase in their share. This is expected in light of the level of supply and demand in the oil markets. However, if the price of a barrel exceeds $100, there is a possibility that such a step will be taken any time. A possible agreement on Iran’s nuclear programme is looming on the horizon in Vienna, after fulfilling part or most of the Iranian conditions. Washington has agreed, rather submissively, to separate the nuclear program from the rest of the military activities and Iranian interference in the internal affairs of other countries, which means an imminent pumping of Iranian oil for international markets. In fact, Iranian oil is already being traded in the markets, and allowing them to officially pump oil will not have a significant effect on the levels of supply. Oil markets had braced for this return since the Biden administration came to power last year. The Iranian oil production is estimated at 2.5 million barrels per day, down from 4 mbd before the sanctions, of which 1.9 million barrels are consumed internally and 600,000 barrels exported, mostly to China, which imports 340,000 barrels at steep discounts in exchange for goods. This means Iran needs to increase its production capacity to contribute significantly to the global oil markets. In a best-case scenario, Iran’s increase will not exceed half a million barrels in the short-term, which the markets can absorb quickly due to the increasing demand. Yet, the Iranian oil issue will constitute an ideal opportunity for speculators to exploit it to achieve profits by manipulating prices.
Oil Curves Show One of the Tightest Markets Ever | Rigzone -- Oil futures curves are indicating one of the strongest periods the market has ever seen, amid a bout of headline price volatility. Brent prices have swung wildly above $90 this week, but there’s been even more action in the market’s structure. Nearby contracts are commanding enormous premiums over those further out, indicating that traders are clamoring for barrels right now. Some futures spreads have reached their strongest levels in data going back to 2007. Nowhere is the move clearer than in the world’s most important physical oil price -- Dated Brent -- which on Wednesday topped $100 for the first time since 2014. The market for real barrels in the North Sea has boomed in recent weeks, with differentials for some physical cargoes hitting the highest on record as demand from European refiners surges. “The strength in Dated Brent clearly suggests refiners are out procuring short-haul barrels,” Energy Aspects analysts including Amrita Sen wrote in a note to clients this week. “The only way to balance this market over the medium term remains high oil prices to slow demand growth.” In the U.S., stockpiles at the key hub of Cushing, Oklahoma are at their lowest since 2018, spurring tightness in West Texas Intermediate crude. Brent futures were down 1.6% in London near $93.33 on Thursday. West Texas Intermediate lost 1.7% to $92.11. Last week, the International Energy Agency boosted its historical demand numbers, offering the latest indication that consumption has been running ahead of expectations. While most forecasting agencies had expected global oil stockpiles to rise markedly in the early part of the year, that has so far failed to materialize. The tightness has only added to calls that headline prices will soon top $100. Options traders have been betting on that outcome for months, with millions of barrels worth of contracts at $100 and above. “Price action since just before Christmas has been an incredibly bullish one-way street,” said Bjarne Schieldrop, chief commodities analyst at SEB AB. “You don’t see that unless market is very, very tight.” The moves in headline prices in recent days have been driven by two of the market’s biggest geopolitical risks -- the potential return of Iranian barrels to the market and political tension around Ukraine. On Thursday, Russian state media cited Moscow-backed separatists as saying Ukrainian forces had violated cease-fire rules overnight. While Russia has insisted that it’s serious about easing tensions -- and has repeatedly denied that it plans an invasion of its smaller neighbor -- the U.S. says Moscow is still building up troop levels near the border. “It’s a headline-driven market at the moment, with the market reacting to sensitive news from Eastern Europe and related to the Iran nuclear talks,
Oil Prices Hit Seven-year High Over Russia-Ukraine Tensions - Oil prices hit their highest in more than seven years on Monday. A possible invasion of Ukraine by Russia could trigger U.S. and European sanctions that would disrupt exports from the world's top producer in an already tight market. Brent crude futures was at $95.65 a barrel by 0742 GMT, up $1.21, or 1.3%, after earlier hitting a peak of $96.16, the highest since October 2014. U.S. West Texas Intermediate (WTI) crude rose $1.28, or 1.4%, to $94.38 a barrel, hovering near a session-high of $94.94, the loftiest since September 2014. Comments from the United States about an imminent attack by Russia on Ukraine have rattled global financial markets. Russia could invade Ukraine at any time and might create a surprise pretext for an attack, the United States claimed on Sunday. Over the last few months, the US and UK have been accusing Russia of planning to invade Ukraine, which Moscow has vehemently denied, dismissing the allegations as “fake news”. Ukraine has also urged Western media and politicians who are warning of an “imminent” invasion to stop fueling panic. “Oil prices will remain extremely volatile and sensitive to incremental updates regarding the Ukraine situation,” The tensions come as the Organization of the Petroleum Exporting Countries (OPEC) and its allies, a group known as OPEC+, struggle to ramp up output despite monthly pledges to increase production by 400,000 barrels per day (bpd) until March. The International Energy Agency said the gap between OPEC+ output and its target widened to 900,000 bpd in January, while JP Morgan announced the gap for OPEC alone was at 1.2 million bpd. “We note signs of strain across the group: seven members of OPEC-10 failed to meet quota increases in the month, with the largest shortfall exhibited by Iraq,” JP Morgan analysts said in a Feb. 11 note. The bank added that a supercycle is in full swing with “oil prices likely to overshoot to $125 a barrel on widening spare capacity risk premium”.
Oil hits 7-year highs, fueled by Russia-Ukraine tensions - Oil prices surged on Monday over 2% to their highest in more than seven years as Ukraine's President said he had heard that Russia could invade the country on Wednesday. Russia is one of the world's largest oil-and-gas producers, and fears that it could invade Ukraine have driven the rally in oil closer to the $100-per-barrel mark. "The market remains hyper-sensitive to the developments over the Russian/Ukraine situation," Brent crude rose $2.04, or 2.2%, to settle at $96.48 a barrel, after touching its highest since September 2014 at $96.78. U.S. West Texas Intermediate (WTI) crude rose $2.36, or 2.5%, to settle at $95.46 a barrel, after hitting $95.82, the loftiest since September 2014. Ukraine's President Volodymyr Zelenskiy said he had heard that Wednesday could be the day of a Russian invasion. The United States sees no "tangible sign" of de-escalation of Russian forces on the Ukraine border, the U.S. State Department said. Secretary of State Antony Blinken said the United States was relocating its embassy operations in Ukraine from the capital Kyiv to the western city of Lviv, citing the "dramatic acceleration in the buildup of Russian forces." Russia has amassed thousands of troops near Ukraine's borders, but Moscow denies it plans to invade and has accused the West of hysteria. The United States warned on Sunday that Russia could invade Ukraine at any time and might create a surprise pretext for an attack. Russia is one of the largest crude oil producers, with a capacity of about 11.2 million barrels per day, "Any disruption of oil flows from the region would send Brent and WTI prices skyrocketing higher far above $100, in a market struggling to supply the increased demand for crude as economies recover from the pandemic," Investors are also watching talks between the United States and Iran. The Iranian foreign minister said Iran was "in a hurry" to reach a swift agreement in nuclear talks in Vienna, provided its national interests are protected. "A nuclear deal between the United States and Iran could release 1.3 million barrels of supply, but this will not be sufficient to ease the supply constraints," said Pratibha Thaker, the Economist Intelligence Unit's editorial director for the Middle East and Africa.
Oil Falls as Russia Pulls Back Troops, Calls for Diplomacy -- Oil futures nearest delivery plummeted early Tuesday, sending U.S. and international crude benchmarks more than 3% lower after Russia announced a partial withdrawal of its military troops amassed along the Ukrainian border, sharply deescalating tensions in its standoff with the West that has rallied oil futures to their highest price points in 7-1/2 years. Brent plunged towards $93 per barrel (bbl) after Russian Ministry of Defense, Sergei Shoigu, confirmed on Tuesday that some of the forces positioned along the Ukrainian border over the last four months were being pulled back to their bases. The move comes less than 72 hours after the United States government warned of an imminent Russian attack on eastern Ukraine, relocated its Ukrainian Embassy close to the Polish border, and called on its citizens to leave the country as soon as possible. Moscow has consistently denied any plans to invade Ukraine and maintained that the troop buildup was part of military drills that were nearing completion in mid-February. The large buildup of Russian forces however, set off alarm bells in the West, with major news outlets calling for imminent Russian attack for months now that some suggest stoked panic and warmongering among the American public. Fears of a Russian attack, the impact of sanctions on the global economy, and surging commodity prices hit markets hard on Monday, pulling both the Dow Jones Industrial Average and S&P 500 into negative territory for the session, lifting gold prices to the highest levels in eight months, and sparking an oil price rally that took U.S. crude past $95 for the first time since 2014. In morning trade Tuesday, U.S. benchmark fell more than $3 to trade a tad above $92 bbl, and international crude benchmark Brent for April delivery traded near $93.40 bbl after topping $96 bbl on Monday. NYMEX March RBOB futures slumped more than 8 cents to $2.6966 gallon, and the front-month ULSD contract was down 9 cents at $2.8710 gallon. Futures tied to DJIA indicate a 365-point opening bell gain while those linked to the S&P 500, which is down 7.65% for the year, are priced for a 62-point advance. U.S. dollar declined 0.29% against a basket of foreign currencies to trade near 96.080. Russia remains one of the top 10 economies in the world and a leading commodity exporter, which includes palladium, coal, gas, aluminum, and crude oil. A military conflict could have sent commodity prices surging to fresh highs at a time when much of the world is already coping with sky-high inflation.
Oil Dips with Talks of Russian Troops Retreating | Rigzone - Oil fell after Russia said some troops are starting to return to their permanent bases, easing geopolitical tensions that previously rallied prices. Futures in New York closed down 3.6% after falling nearly $5 a barrel during the session, the most since November 30. Crude has swung wildly this week amid a flurry of reports about the tensions over Ukraine. While the U.S. had earlier warned an invasion may be imminent, President Vladimir Putin said talks with German Chancellor Olaf Scholz were businesslike and could be the basis of further discussions. Moscow has repeatedly denied it plans to attack. Still, NATO Secretary General Jens Stoltenberg said it was yet to see any signs of a reduced Russian presence along the border with Ukraine. The market is holding on to every word in the standoff, with everything from natural gas and metals to global equities reacting to Russia’s comments about the pullback of troops on Tuesday. “Profit-taking with oil was inevitable after Russia’s Defense Ministry stated that some troops are starting to return to their regular bases after completing drills,” said Ed Moya, Oanda’s senior market analyst for the Americas. “The Ukraine situation still remains tense and oil prices could swing $10 in either direction.” Adding to geopolitical tensions, the underlying oil market is one of the strongest in years. S&P Global Platts assessed the Dated Brent price, which values more than half of the world’s crude, at more than $99 a barrel on Monday, traders said. Gauges of market strength along the futures curve are trading at some of their firmest levels on record as supply struggles to keep pace with booming demand. WTI for March delivery fell $3.39 to settle at $92.07 a barrel in New York. Brent for April dropped $3.20 to $93.28 a barrel. Falling stockpiles have also been a major driver of recent gains, and later Tuesday the industry-funded American Petroleum Institute will issue estimates for changes in U.S. holdings. Inventories at the key storage hub at Cushing, Oklahoma, have sunk for the past five weeks, according to government data. Still in the U.S., producers are ramping up supplies to take advantage of higher prices. Production from America’s Permian Basin rose to a record for a third month in a row in January, topping 5 million barrels a day, according to data from the Energy Information Administration.
WTI Holds Losses Despite Across-The-Board Inventory Draws Oil prices tumbled today after Russia said some troops are starting to return to their permanent bases, removing some of the geopolitical risk premium that has been embedded recently. “Profit-taking with oil was inevitable after Russia’s Defense Ministry stated that some troops are starting to return to their regular bases after completing drills,” “The Ukraine situation still remains tense and oil prices could swing $10 in either direction.” But for now, the next leg will be governed by any potential surprise in tonight's inventory data. API:
- Crude -1.076mm (-220k exp)
- Cushing -2.382mm
- Gasoline -923k (-900k exp)
- Distillates -546k (-1mm exp)
This is the 6th straight week of falling stocks at the Cushing hub as API reported inventory draws across the board... Having neared $96 amid Friday's panic-fear-mongering of an imminent invasion by the Biden administration, today's Putin headlines sent WTI back to a $90 handle briefly before it bounced back to $92 after Biden spoke again and reiterated the threats. WTI oscillated around $92 after the API report... "Whatever the answer is, the reality is that when they find that number, oil will resume the rally,"
Oil Rallies After API Data Shows US Inventories Drawn Down-- Following Tuesday's selloff triggered by deescalating tensions along the Russian-Ukrainian border, oil futures rallied early Wednesday after industry data from the American Petroleum Institute reported total petroleum stockpiles in the United States declined again last week, with commercial oil supplies standing at their lowest level since September 2018 at a time when fuel consumption shows signs of a solid rebound after demand was constrained from winter storms and Omicron surge of COVID-19 infections. API reported late Tuesday U.S. commercial crude oil supplies fell 1.076 million barrels (bbl) during the week-ended Feb. 11, surpassing calls for a 600,000 bbl draw. If realized in data from the Energy Information Administration later this morning, the decline would be third consecutive drawdown from nationwide oil inventories that currently stand 11% below the five-year average. The report also showed crude stocks at the Cushing, Oklahoma, delivery point for West Texas Intermediate futures declined 2.382 million bbl last week. The report was also bullish for the refined fuel complex, showing gasoline supplies fell 923,00 bbl in the week through Feb. 11 versus an expected build of 500,000 bbl, while distillate inventories declined 546,000 bbl. Analysts mostly expected distillate stocks to have declined 1.7 million bbl from the previous week. Large stock draw coincides with rebounding demand for motor gasoline, with more Americans also seeing the relief from an abating COVID-19 surge. DTN Refined Fuels Demand data revealed gasoline demand in the United States surged 5.6% in the week-ended Feb. 11, while up 9.9% year-on-year. Demand for middle distillates spiked 7.5% from the prior week, reflecting rebounding demand from the prior week which saw demand weakness amid winter storms. In early trading Wednesday, U.S. benchmark advanced more than $1 to near $93.40 bbl, and international crude benchmark Brent for April delivery gained to $94.80 bbl after topping $96 bbl on Monday. NYMEX March RBOB futures added 2.49 cents to $2.6940 gallon, and the front-month ULSD contract rallied 2.79 cents to $2.8876 gallon.
WTI Soars Back Above $95 As "Tank Bottoms" Are Close At Cushing -- A combination of US and NATO comments that Russia is not retreating (providing no evidence of said statement) and the continued plunge in stocks at Cushing, has sent pil prices soaring. With debates about "tank bottoms" being close at America's largest storage hub......WTI has now erased all of yesterday's losses and more and is trading back above $95... That is going to crush Biden's plan to bring down retail gas prices. Oil prices are rebounding dramatically this morning, accelerating gains from last night's across the board inventory draw reported by API, after US SecState Blinken (and NATO's Stoltenberg) claimed that there are no signs that Russia is withdrawing (and remember today was 'invasion day' according to the mainstream media). “Market participants are still willing to pay a sizable premium for oil that is deliverable at short notice,” Will an unexpected crude build spook oil traders or a big draw lift prices back to Biden-crushing highs? DOE
- Crude +1.12mm (-220k exp)
- Cushing -1.90mm
- Gasoline -1.33mm (-900k exp)
- Distillates -1.552mm (-1mm exp)
Flipping the script from API, the official data showed that Crude inventories unexpectedly built last week. Cushing stocks fell for the 6th straight week.. U.S. Gulf refiners cut runs to 83.5%, the lowest since October after a cold spell cut off power to four major refiners. Cushing stocks extend their plunge back towards operational low levels, dropping to the lowest level since Sept 2018 (adding to global inventory tightness fears). Notably, this low level of inventories at the biggest storage hub in the country is one reason why prompt timespreads are soaring.Gasoline demand unexpectedly slowed once again last week, after rebounding from Omicron... Graphs Source: Bloomberg US crude production was flat week over week, despite a big jump in the rig count... After yesterday's biggest daily drop this year, WTI was trading back above $94 ahead of the official inventory data, and extending gains despite the crude build...
Oil resumes rally as Russia-Ukraine tensions stay high (Reuters) -Oil prices rose more than 1% on Wednesday as investors weighed conflicting statements on the possible withdrawal of some Russian troops from around Ukraine. Futures fell after the settlement, however, after U.S. and Iranian officials said they were much closer to an agreement on the latter’s nuclear weapons development that would allow it to ramp up global oil sales. Russia’s threatening posture toward Ukraine has dominated oil markets for several weeks, with concerns that supply disruptions from the major producer in a tight global market could push oil prices to $100 a barrel. “The market has been reflective of what the situation has been and what it could be, which is ambiguity from one day to the next,” Oil was supported by weekly data that showed U.S. fuel demand holding at record highs, while crude inventories at the Cushing, Oklahoma, storage hub and delivery point for U.S. futures dropped to their lowest since September 2018. Brent crude settled up $1.52, or 1.6%, to $94.81 a barrel. U.S. West Texas Intermediate (WTI) crude ended up $1.59, or 1.7%, to $93.66, pulling back from the day’s high of $95.01 a barrel. On Monday, both benchmarks hit their highest since September 2014, with Brent touching $96.78 and WTI reaching $95.82. Following the close, the U.S. State Department said it was in the midst of the final stages of Iran nuclear talks, while Iran’s top nuclear negotiator Ali Bagheri Kani tweeted that after weeks of intensive talks, “we are closer than ever to an agreement.” Oil dropped sharply, albeit on thin volume, with Brent and U.S. crude both falling 1%. “The devil is going to be in the details and how quickly Iranian oil can resume,” The United States and NATO said Russia was still building up troops around Ukraine on Wednesday despite Moscow’s insistence it was pulling back, questioning President Vladimir Putin’s stated desire to negotiate a solution to the crisis. Russia’s finance minister said the country would be ready to re-route energy supplies should Western sanctions target its energy sector. U.S. crude inventories rose by 1.1 million barrels last week, but overall inventories at the Cushing hub dropped by 1.9 million barrels, and product supplied – a proxy for demand – hit a record 22.1 million barrels per day over the past four weeks, the Energy Information Administration said.
WTI, Brent Futures Drop Back on Progress in Iranian Talks -- Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange declined early Thursday. Both benchmarks traded 2% lower following reports U.S. and Iranian negotiators, through intermediaries, are closing in on a nuclear agreement that could lead to the lifting of sanctions on the country's crude oil exports within days. The United States is in "the midst of the final stages" of indirect talks in Vienna with Iran aimed at reviving the 2015 Joint Comprehensive Plan of Action, State Department spokesperson Ned Price said on Wednesday. "It is not a question of weeks, it is a question of days," added French Foreign Minister Jean-Yves Le Drian, referring to a nuclear deal that could lift sanctions on as much as 2 million barrels per day (bpd) in Iranian crude oil exports. Analysts suggest Iran holds a sizable quantity of oil in offshore storage that could be tapped immediately to take advantage of higher oil prices. With a new deal on the horizon, South Korea said on Wednesday it held talks on resuming imports of Iranian crude oil and unfreezing Iranian funds. South Korea was previously one of Tehran's leading oil buyers in Asia. The Vienna talks, which involve Britain, China, France, Germany, and Russia directly, and the United States indirectly, resumed in November 2021 after the Trump administration unliterally withdrew from the deal in 2018 and reimposed heavy economic sanctions, prompting Iran to begin rolling back on its commitments. Further weighing on the oil complex, the U.S. Dollar Index gained in early trade Thursday after minutes from the Federal Open Market Committee's January meeting showed the U.S. central bank is ready to raise interest rates and shrink its balance sheets "soon" to quell inflationary pressures within the economy. Markets have been on edge over the past several weeks as soaring inflation and hawkish talk from some Fed officials, including St. Louis Fed President James Bullard, have prompted traders to price in the equivalent of seven 0.25% rate hikes this year. Market pricing eased some after the minutes were release, with a 50% chance now seen that the Fed lifts the benchmark rate by 50 or 75 basis points in March. In early trading, West Texas Intermediate March futures declined nearly $2.50 to $91.25 barrel (bbl) and international crude benchmark Brent for April delivery fell $2.40 to near $92.40 bbl. NYMEX March RBOB futures slumped nearly 7 cents to $2.6075 gallon, and the front-month ULSD contract declined nearly 9 cents to $2.7685 gallon.
Oil falls, caught between Iran talks and Ukraine crisis - Oil prices fell 2% on Thursday as talks to resurrect a nuclear deal with Iran entered their final stages, but losses were limited by heightened tensions between top energy exporter Russia and the West over Ukraine. Brent crude declined 2% to $92.87 per barrel. U.S. West Texas Intermediate (WTI) crude settled 1.44% lower at $91.76 per barrel. "(The) oil market is locked in a tug of war between Iranian sanctions relief and Russian-Ukraine tensions," said Stephen Brennock at brokerage PVM Oil. The United States is in "the midst of the very final stages" of indirect talks with Iran, aimed at salvaging a 2015 deal limiting Tehran's nuclear activities, State Department spokesperson Ned Price said on Wednesday. A decision on salvaging the nuclear deal was said by France on Wednesday to be only days away and that it was up to Tehran to make the political choice, though Iran called on Western powers to be "realistic." With a new deal possibly on the horizon, South Korea said on Wednesday it had held talks on resuming imports of Iranian crude oil and unfreezing Iranian funds. South Korea was previously one of Tehran's leading oil buyers in Asia. However, continuing tensions over a possible Russian invasion of Ukraine continues to support oil markets because of the potential disruption to energy supplies. Russian-backed rebels and Ukrainian forces traded accusations on Thursday that each had fired across the ceasefire line in eastern Ukraine, raising alarm at a time when Western countries have warned of a possible Russian invasion any day. Moscow's announcement of a partial pullback of troops from near Ukraine this week was countered by Western governments warning that Russia was building up military presence near the Ukraine border.
Oil heads for weekly fall on Iranian oil hopes - Oil prices reversed losses to trade in the green on Friday, but were still headed for a weekly loss. The prospect of increased Iranian oil exports has eclipsed fears of potential supply disruption resulting from the Russia-Ukraine crisis. Brent crude futures advanced 57 cents, or 0.6%, to settle at $93.54 per barrel. U.S. West Texas Intermediate (WTI) crude futures settled 69 cents, or 0.75%, lower at $91.07 per barrel. Fears over possible supply disruptions resulting from the Russian military presence at Ukraine's borders have capped losses this week. "For all the talk of war and conflict, market players remain unconvinced. This is perhaps why the geopolitical risk premium is starting to wane," said Stephen Brennock at brokerage PVM Oil. Both benchmark contracts hit their highest levels since September 2014 on Monday, but the prospect of an easing of oil sanctions against Iran has set prices on course for their first weekly fall in nine weeks. However, a deal taking shape to revive Iran's 2015 nuclear agreement with world powers lays out phases of mutual steps to bring both sides back into full compliance, and the first does not include waivers on oil sanctions, diplomats say. Consequently, there is little chance of Iranian crude returning to the market in the immediate future to ease current supply tightness, analysts said. "Stocks are therefore likely to remain considerably below the long-term average for quite some time yet," said Commerzbank analyst Carsten Fritsch, adding that this could widen already record-high futures spreads. Tight oil supplies pushed the six-month market structure for Brent crude to its widest backwardation on record on Wednesday. Backwardation exists when contracts for near-term delivery are priced higher than those for later months and is reflective of near-term demand that encourages traders to release oil from storage to sell it promptly.
Oil Down this Week with Increased Geopolitical Tensions | Rigzone - Oil posted its first weekly loss in two months as traders weighed heightened geopolitical tensions over Ukraine against the potential for Iranian barrels to be added to the market. West Texas Intermediate closed down near $91 a barrel on Friday. U.S. crude fell 2.2% this week, fluctuating as prices of commodities from gas to metals and food swung with every twist and turn in the standoff between the West and Russia. The U.S. ramped up warnings of a possible Russian attack on Ukraine, Russian officials continued to reiterate that no invasion was underway and none was planned. U.S. Secretary of State Antony Blinken and Russia Foreign Minister Sergei Lavrov have agreed to meet for talks next week. Even with its most recent leg higher, oil’s recent rally has shown signs of cooling. The North Sea market has seen differentials for physical barrels ease, while refining margins have come under pressure. One oil-focused exchange-traded fund saw its biggest daily withdrawal since July 2020. Additionally, mounting speculation that Iran’s nuclear deal may be revived is damping some of the bullish signals. The deal could pave the way for the removal of U.S. sanctions on the nation’s crude exports, adding much-needed supply to the market. WTI’s prompt spread--the difference between its nearest two contracts-- dropped to 86 cents, down sharply from its $2 premium earlier this week. The narrower spread signals that traders expect supplies to be somewhat less tight next month amid muted exports. March crude futures expire on Tuesday. Crude rose to the highest since 2014 this week in a blistering rally underpinned by roaring demand, constrained supply, and declining inventories. The underlying market is one of the strongest its been in years, and Dated Brent, a more immediate measurement of oil prices, hit $100 a barrel. While the market remains strong, prices have weakened as the geopolitical risk premium has declined in the past few days. “In addition to the Ukraine situation, Iran nuclear talks continue to head in the right direction, potentially paving the way for more barrels of crude to hit the oil market later this year.”
Agreement reached on transfer of oil from abandoned tanker off Yemen: UN -An ‘agreement in principle’ has been reached to transfer the toxic cargo from a rusting oil tanker abandoned off the coast of war-torn Yemen to another ship, the UN said Tuesday. Experts warn of the risk of a major environmental disaster posed by the 45-year-old FSO Safer, moored since 2015 off Yemen’s western port of Hodeida. An oil spill could destroy ecosystems in the Red Sea, shut down the vital port and expose millions of people to high levels of pollution, according to independent studies. “I am pleased to report recent progress in efforts to resolve the Safer tanker issue, including an agreement in principle to a UN-coordinated proposal to shift the oil to another ship,” said Martin Griffiths, the UN’s deputy chief for humanitarian affairs. He gave no further details about the operation or when the transfer might take place. Ten days ago the UN indicated that positive discussions between Yemeni government officials and Houthi rebels had seen both sides keen to find an emergency solution to avoid a catastrophic spill. According to environmental group Greenpeace an oil spill would prevent access to Yemen’s main ports of Hodeida and Salif, affecting food aid supplies for up to 8.4 million people. Coastal countries including Djibouti, Eritrea and Saudi Arabia could also be affected, in addition to commercial maritime traffic in the Red Sea. Inspection of the deteriorating ship has dragged on for years with UN requests for access repeatedly delayed over disagreements with the Houthi rebel movement, which controls much of the north including Hodeida and Salif ports. Yemen’s civil war has been a catastrophe for millions of its citizens, dubbed by the United Nations as the world’s worst humanitarian crisis. According to the UN, the war has claimed some 377,000 lives due to both fighting and lack of potable water, hunger and disease.
Rebels attack China's oil pipeline in Myanmar - In what would raise an alarm bell in Beijing a China-backed oil and gas pipeline was damaged when a local resistance group attacked junta forces guarding the energy facility inMyanmar’s Mandalay Region’s Natogyi township on Monday.Natogyi-People’s Defense Force (NPDF) attacked 13 regime personnel, according to a report published by The Irrawaddy, a leading media outlet on Myanmar.The NPDF claimed that the Myanmar military suffered casualties in the attack.The oil and gas pipelines, which run from the Rakhine coast to southern China, were constructed in 2011 and began operation in July 2013.The 973-km pipelines pass through Magwe and Mandalay regions and Shan State to China’s Yunnan Province.Anti-Chinese sentiment has swelled in Myanmar following the military take over last February, with many people believing Beijing had a hand in the takeover. At that time, there were calls for a boycott of Chinese products, along with calls to blow up the pipelines if China refused to condemn the regime, The Irrawaddy reported.The calls prompted China to urge the regime to increase security for the pipelines. Since March last year, the regime has assigned extra forces to protect the pipelines. In May last year, three regime troops guarding the pipelines in Sintgaing Township, Mandalay Region were killed by unidentified attackers.China has urged Myanmar’s civilian National Unity Government to ensure the resistance movement does not harm Chinese investments in the country.The request came after a local resistance group attacked electricity pylons supplying the China-backed Tagaung Taung nickel-processing plant in Sagaing’s Tigyaing Township in early January, according to The Irrawaddy.
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