Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 23 May 2020. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening.
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Well completions fell 34.1% in April, leaving a 10.8 month backlog of DUC wells; horizontal drilling at a 14 year low
Oil prices moved higher for a 4th consecutive week this week on a large drop in US crude supplies and on a continued easing of restrictions imposed in the wake of the coronavirus crisis….after rising 19% to $29.43 per barrel last week after the Saudis announced addition production cuts and the EIA reported the first drop in US crude supplies in sixteen weeks, the contract price of US light sweet crude for June delivery opened higher on Monday, a day before WTI June contract expiry, initially rose over 11% in thin trading before settling $2.39 higher at $31.82 a barrel as production cuts and the easing of stay-at-home restrictions continued to support prices…with most traders already closed out of their June oil positions on fears that prices might again go negative, the June contract then expired another 68 cents higher at $32.50 on Tuesday, while the more actively traded July oil contract, which had ended last week priced at $29.52 and rose $2.13 on Monday, rose 31 cents on Tuesday to settle at $31.96 a barrel…with the price of WTI oil for July delivery now being quoted, oil prices extended their gains early Wednesday after the American Petroleum Institute reported a surprisingly large draw from US crude supplies, and then moved higher still to close up $1.53 at $33.49 a barrel on signs of improving demand after the EIA had confirmed the large drop in US crude supplies...prices then rose 43 cents to $33.92 a barrel on Thursday, the highest oil price since March, supported by lower U.S. crude inventories, OPEC-led supply cuts and recovering demand as governments eased restrictions imposed in the wake of the coronavirus pandemic…however, oil prices tumbled along with global equities on Friday on rising tensions between China and Washington over Hong Kong’s autonomy and ended 67 cents, or 2% lower at $33.25 a barrel, as doubts set in about how quickly fuel demand would recover from the coronavirus crisis…despite the Friday selloff, oil prices still posted their fourth straight week of increases, with the July oil contract finishing with a 12.6% gain on the week..
Natural gas prices moved higher for the first time in four weeks as natural gas production fell to meet lower demand.. after falling 9.7% to $1.646 per mmBTU on milder weather and virus related demand destruction last week, the contract price of natural gas for June delivery opened 8 cents higher on Monday and surged to a 12.5% increase on a larger than expected production cut before pulling back to close 13.7 cents or 8% higher at $1.783 per mmBTU as producers shut wells and slashed spending on new oil drilling, thus reducing the associated gas output… gas prices then rose another 4.7 cents or 2.6% on Tuesday on a continuing slowdown in gas output to settle at $1.830 per mmBTU, their highest close since May 7th….however, prices fell back 5.9 cents or 3% on Wednesday as government lockdowns to stop the spread of coronavirus reduced demand for the fuel and for exports, and then fell another 6.1 cents to $1.710 per mmBTU on Thursday after the EIA’s latest storage data underwhelmed natural gas traders…natural gas prices then saw a modest 2.1 cent bump on Friday ahead of the holiday weekend to to finish at $1.731 per mmBTU, on forecasts for warmer weather and rising cooling demand through the first week of June, to end with a 5.2% gain on the week..
The natural gas storage report from the EIA for the week ending May 15th indicated that the quantity of natural gas held in underground storage in the US rose by 81 billion cubic feet to 2,503 billion cubic feet by the end of the week, which left our gas supplies 779 billion cubic feet, or 45.2% higher than the 1,724 billion cubic feet that was in storage on May 15th of last year, and 407 billion cubic feet, or 19.4% above the five-year average of 2,096 billion cubic feet of natural gas that has been in storage as of the 15th of May in recent years….the 81 billion cubic feet that were added to US natural gas storage this week matched the consensus forecast for a 81 billion cubic feet increase from a survey of analysts by S&P Global Platts, but was below the 87 billion cubic feet of natural gas that have been added to natural gas storage during the same week over the past 5 years, and also below the 101 billion cubic feet addition of natural gas to storage during the corresponding week of 2019…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending May 15th showed that due to a big increase in the amount of oil being used by our refineries, we had to withdraw oil from our stored commercial supplies of crude oil for the second time in 17 weeks, and for the tenth time in the past thirty-six weeks…our imports of crude oil fell by an average of 194,000 barrels per day to an average of 5,197,000 barrels per day, after falling by an average of 321,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 286,000 barrels per day to an average of 3,239,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 1,958,000 barrels of per day during the week ending May 15th, 92,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells fell by 100,000 barrels per day to 11,500,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 13,458,000 barrels per day during this reporting week..
US oil refineries reported they were processing 12,903,000 barrels of crude per day during the week ending May 15th, 521,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that 443,000 barrels of oil per day were being withdrawn from the supplies of oil stored in the US….so based on that data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 998,000 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 plugged a (-998,000) 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 fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…however, since the media treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill for oil, we’ll continue to report them, just as they’re watched & believed as 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)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 5,401,000 barrels per day last week, now 24.6% less than the 7,166,000 barrel per day average that we were importing over the same four-week period last year….the 433,000 barrel per day net withdrawal from our total crude inventories came as 712,000 barrels per day were being withdrawn from our commercially available stocks of crude oil, while 269,000 barrels per day were being added to our Strategic Petroleum Reserve….this week’s crude oil production was reported to be down by 100,000 barrels per day to 11,500,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was down by 100,000 barrels per day to 11,100,000 barrels per day, while a 15,000 barrel per day decrease in Alaska’s oil production to 423,000 barrels per day had no impact on the rounded national total….last year’s US crude oil production for the week ending May 17th was rounded to 12,200,000 barrels per day, so this reporting week’s rounded oil production figure was about 5.7% below that of a year ago, yet still 36.4% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 69.4% of their capacity in using 12,903,000 barrels of crude per day during the week ending May 15th, up from 67.9% of capacity during the prior week, but still among the lowest refinery utilization rates of the last thirty years…hence, the 12,903,000 barrels per day of oil that were refined this week were 22.2% fewer barrels than the 16,578,000 barrels of crude that were being processed daily during the week ending May 17th, 2019, when US refineries were operating at a seasonally typical 89.9% of capacity….
Even with the increase in the amount of oil being refined, gasoline output from our refineries was somewhat lower, decreasing by 331,000 barrels per day to 7,166,000 barrels per day during the week ending May 15th, after our refineries’ gasoline output had increased by 792,000 barrels per day over the prior week….but since we’re still near multi-year lows in gasoline production, our gasoline output this week was 27.5% lower than the 9,883,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 88,000 barrels per day to 4,804,000 barrels per day, after our distillates output had decreased by 190,000 barrels per day over the prior week…after this week’s decrease in distillates output, our distillates’ production was 7.7% less than the 5,206,000 barrels of distillates per day that were being produced during the week ending May 17th, 2019….
Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the first time in 4 weeks and for the 5th time in 16 weeks, rising by 2,830,000 barrels to 255,724,000 barrels during the week ending May 15th, after our gasoline supplies had decreased by 3,513,000 barrels over the prior week…our gasoline supplies increased this week because the amount of gasoline supplied to US markets decreased by 608,000 barrels per day to 6,790,000 barrels per day, even as our exports of gasoline rose by 70,000 barrels per day to 244,000 barrels per day while our imports of gasoline rose by 40,000 barrels per day to 526,000 barrels per day….after this week’s inventory increase, our gasoline supplies were 11.8% higher than last May 17th’s gasoline inventories of 228,740,000 barrels, and roughly 10% above the five year average of our gasoline supplies for this time of the year…
Also, even with the decrease in our distillates production, our supplies of distillate fuels increased for the seventh time in 18 weeks and for the 12th time in 33 weeks, rising by 3,831,000 barrels to 158,832,000 barrels during the week ending May 15th, after our distillates supplies had increased by 3,511,000 barrels over the prior week….our distillates supplies rose by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 150,000 barrels per day to 3,668,000 barrels per day, and because our imports of distillates rose by 129,000 barrels per day to 322,000 barrels per day, while our exports of distillates rose by 145,000 barrels per day to 911,000 barrels per day….after this week’s inventory increase, our distillate supplies at the end of the week were 25.6% above the 126,415,000 barrels of distillates that we had stored on May 17th, 2019, and about 19% above the five year average of distillates stocks for this time of the year…
Finally, with increased refining and lower oil imports and crude production, our commercial supplies of crude oil in storage fell for the second time in seventeen weeks and for the twentieth time in the past 52 weeks, decreasing by 4,972,000 barrels, from 531,476,000 barrels on May 8th to 526,494,000 barrels on May 15th…but since we had just completed a run of 15 straight increases and three record increases over past 7 weeks, our crude oil inventories are still 10% above the five-year average of crude oil supplies for this time of year, and almost 48% above the prior 5 year (2010 – 2014) average of crude oil stocks as of the middle of May, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels, and continued rising from there….since our crude oil inventories have generally been rising over the past year and a half, except for during this past summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of May 15th were 10.4% above the 476,775,000 barrels of oil we had in commercial storage on May 17th of 2019, 20.2% above the 438,132,000 barrels of oil that we had in storage on May 18th of 2018, and 2.0% above the 516,340,000 barrels of oil we had in commercial storage on May 19th of 2017…
Furthermore, if we take the total of our commercial oil supplies and the stores of all the refined product made from oil, we find those supplies are now at a record high of 1,399,920,000 barrels, 9.2% more than the 1,281,538,000 barrel total of a year ago…
This Week’s Rig Count
The US rig count fell for the 11th week in a row during the week ending May 22nd, and is now down by 59.9% over that eleven week period….Baker Hughes reported that the total count of rotary rigs running in the US decreased by 21 rigs to 318 rigs this past week, which was the fewest rigs deployed in Baker Hughes records going back to 1940, down by 665 rigs from the 983 rigs that were in use as of the May 24th report of 2019, and 1,611 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil decreased by 21 rigs to 258 oil rigs this week, after falling by 34 oil rigs the prior week, leaving oil rig activity at its lowest since July 10, 2009, which was also 560 fewer oil rigs than were running a year ago, and less than a sixth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was unchanged at 79 natural gas rigs, but was still down by 107 natural gas rigs from the 186 natural gas rigs that were drilling a year ago, and less than a twentieth of modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, two rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, and one in Lake County, California… a year ago, there were no such “miscellaneous” rigs deployed..
The Gulf of Mexico rig count was unchanged at 12 rigs this week, with all of those Gulf rigs drilling for oil in Louisiana’s offshore waters…that’s ten fewer rigs than the rig count in the Gulf a year ago, when 20 rigs were drilling offshore from Louisiana and two rigs were operating in Texas waters…there are no rigs operating offshore elsewhere at this time, nor were there a year ago, so the Gulf rig count is equivalent to the national rig count, just as it has been since the onset of this past winter…
The count of active horizontal drilling rigs decreased by 22 rigs to 285 horizontal rigs this week, which was the fewest horizontal rigs active since May 26, 2006, and hence is a 14 year low for horizontal drilling…it was also 578 fewer horizontal rigs than the 863 horizontal rigs that were in use in the US on May 24th of last year, and about a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…at the same time, the vertical rig count was down by 2 to 8 vertical rigs this week, and those were down by 43 from the 51 vertical rigs that were operating during the same week of last year….on the other hand, the directional rig count increased by 3 to 25 directional rigs this week, but those were still down by 44 from the 69 directional rigs that were in use on May 24th of 2019….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of May 22nd, the second column shows the change in the number of working rigs between last week’s count (May 15th) and this week’s (May 22nd) count, the third column shows last week’s May 15th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running 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 24th of May, 2019…
As you can see, this weeks basin totals show a decrease of 19 rigs, which is 3 short of the number of horizontal rigs removed nationally this week, which would mean that three this week’s horizontal drilling removals were from “other” shale basins not tracked separately by Baker Hughes…checking the rig losses in the Texas part of Permian basin, we find that 10 rigs were pulled out of Texas Oil District 8, while the rig count in other Texas Permian basins remained unchanged…since the national Permian rig total was down by 13 rigs, that means that the 3 rigs that were pulled out in New Mexico must have been drilling in the western Permian Delaware, to account for the overall Permian reduction of 13 rigs…elsewhere in Texas, two rigs were pulled out of Texas Oil District 1, which could account for the 2 rig reduction in Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state…in other states, the two rigs that were pulled out of North Dakota had been drilling in the Williston basin, home of the Bakken shale, and the two rigs that were pulled out of Colorado probably had been drilling in the Denver-Julesburg Niobrara chalk, while the 2 rigs removed from Wyoming were probably pulled from one of those “other” shale basins not tracked separately by Baker Hughes…meanwhile, the only changes in natural gas rigs this week were in the Marcellus, where one rig was pulled out of Pennsylvania, while another rig started drilling in West Virginia, leaving both the Marcellus and the national natural gas rig counts unchanged…
DUC well report for April
Monday of this past week saw the release of the EIA’s Drilling Productivity Report for May, which includes the EIA’s April data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions….for the first time in fourteen months, this report showed a increase in uncompleted wells nationally in April, as both the drilling of new wells and completions of drilled wells decreased, but completions decreased by more…..for the 7 sedimentary regions covered by this report, the total count of DUC wells increased by 13 wells, rising from a revised 7,604 DUC wells in March to 7,617 DUC wells in April, which is still 11.8% fewer DUCs than the 8,636 wells that had been drilled but remained uncompleted as of the end of April of a year ago…this month’s DUC increase occurred as 718 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during April, down by 272 from the 990 wells that were drilled in March and the lowest number of wells drilled since December 2016, while 705 wells were completed and brought into production by fracking, a decrease of 365 well completions from the 1,070 completions seen in March, and down from the 1,281 completions seen in April of last year, and also the lowest number of completions since December 2016….at the April completion rate, the 7,617 drilled but uncompleted wells left at the end of the month represents a 10.8 month backlog of wells that have been drilled but are not yet fracked, up from the 7.1 month DUC well backlog of a month ago…
Oil producing regions saw a net DUC well increase in April, while natural gas producing regions still saw a net DUC well decrease…the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico increased by 28, from 3,436 DUC wells at the end of March to 3,464 DUCs at the end of April, as 333 new wells were drilled into the Permian, while 305 wells in the region were being fracked….at the same time, DUC wells in the Bakken of North Dakota increased by 10, from 888 DUC wells at the end of March to 898 DUCs at the end of April, as 67 wells were drilled into the Bakken in April, while 57 of the drilled wells in that basin were being fracked…in addition, the drilled but uncompleted well count in the Niobrara chalk of the Rockies’ front range increased by 7 to 460, as 83 Niobrara wells were drilled in April while 76 Niobrara wells were completed…meanwhile, there was an increase of 1 DUC well in the Eagle Ford of south Texas, from 1,356 DUC wells at the end of March to 1,357 DUCs at the end of April, as 99 wells were drilled in the Eagle Ford during April, while 98 already drilled Eagle Ford wells were completed…but on the other hand, DUCs in the Oklahoma Anadarko decreased by 25, falling from 691 at the end of March to 666 DUC wells at the end of April, as 33 wells were drilled into the Anadarko basin during April while 58 Anadarko 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 9 wells, from 536 DUCs at the end of March to 527 DUCs at the end of April, as 71 wells were drilled into the Marcellus and Utica shales during the month, while 80 of the already drilled wells in the region were fracked….on the other hand, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 1 to 245, as 32 wells were drilled into the Haynesville during April, while 31 of the already drilled Haynesville wells were fracked during the same period….thus, for the month of April, DUCs in the five major oil-producing basins tracked by in this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) increased by a net of 21 wells to 6,845 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 8 wells to 772 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas…
Cleanup of last September’s East Toledo oil spill near Duck Creek is finished – Cleanup of an oil spill last September near Duck Creek, a Maumee River tributary that sits between East Toledo and Oregon, is now complete. Work there included removal of 167 tons of soil contaminated by the release and a total price tag of $150,000, of which $120,000 is being billed to the city of Toledo. In a news release, the U.S. Environmental Protection Agency said it has finished with the cleanup of that spill, in which an unknown amount of oil from two abandoned pipelines near York Street and Collin Park Avenue in East Toledo flowed into surrounding soil and a storm sewer that leads to Duck Creek. U.S. Region 5 Administrator Kurt Thiede said it was important to address the situation promptly because oil spills “can endanger public health, imperil the environment and drinking water, and affect local economies.” “Ohio appreciates U.S. EPA’s assistance in this cleanup because the oil spill was cleaned up promptly through multiagency and local coordination,” added Ohio EPA Director Laurie Stevenson. The city and the state environmental agency were the first to respond to the spill, which was noticed on Sept. 16. The city removed the two abandoned underground pipelines that were determined to be the source of the oil, the federal EPA said in its release. The U.S. EPA took charge of the cleanup on Oct. 15. The federal agency said it replaced the 167 tons of contaminated soil with 180 tons of clean gravel, and disposed of an estimated 2,400 gallons of mixed oil and water. It also removed an abandoned storm-sewer line, it said. The federal agency said it is getting $120,000 of the total $150,000 cost reimbursed by the city, but said it expects the city’s share will be covered by money available from the U.S. Coast Guard’s National Pollution Fund Center.
Three barge terminals for drilling wastes proposed – Some residents along the Ohio River are fighting proposals to establish three barge terminals for liquid drilling wastes, Kallanish Energy reports. Petitions directed at the U.S. Army Corps of Engineers and the U.S. Coast Guard are being circulated by Concerned Ohio River Residents against the three projects in eastern Ohio. Opponents say the terminals pose a toxic and radioactive threat to the Ohio River that provides drinking water to 5 million people. They are seeking a public hearing from the Corps of Engineers on the projects. The terminals would be developed by 4K Industrial Frac Water Supply and Recycling Technologies in Martins Ferry, by DeepRock Disposal Solutions about 61 miles downstream at Marietta and by Fountain Quail Energy Services about 38 miles downstream from Marietta in Meigs County, Ohio. The projects, if approved, could result in the first barges carrying briny fracking wastes on the Ohio River. The projects must comply with Coast Guard rules and obtain permits from the Corps of Engineers. The Martins Ferry facility is designed to recycle frack water from Utica and Marcellus wells. It is being developed by the Mull Group, based in Wheeling, West Virginia. It is the parent company of 4K Industrial. The terminal would include a spud barge that is about 195 feet by 35 feet to which two barges could be secured and loaded/unloaded. The Martins Ferry barge-loading facility would also require approval from the Ohio Environmental Protection Agency. The other two Ohio sites both have disposal wells where liquid waste is being injected underground. In 2016, the Coast Guard dropped establishing a new policy and said it would consider individual requests for barge operations. It also drafted a new definition of two types of waste: legacy fluid from traditional vertical-only O&G wells that is allowed on barges and shale gas extraction waste water from horizontal wells that have been hydraulically fractured or fracked and is not allowed on barges. Environmentalists say the waste materials are the same. It is unclear if anyone has moved shale drilling brine wastes by barge on the Ohio River. Such approval is not a public record, the Coast Guard has said. It also appears that the Coast Guard’s position on the shale gas extraction waste water has not been changed since 2016. Previous attempts to move fracking wastes by barge on the Ohio River had been halted by the Coast Guard. GreenHunter Resources of Texas had tried to win approval going back to 2012.
EQT cuts US production as coronavirus depresses natgas prices (Reuters) – EQT Corp, the biggest U.S. natural gas producer, said on Tuesday it started to reduce gas output in Pennsylvania and Ohio on May 16 as demand destruction from the coronavirus cut current prices for the fuel. Although EQT did not say how much gas it would curtail, U.S. pipeline company EQM Midstream Partners LP said in a federal securities filing that its largest producer customer started planned temporary production curtailments of up to about 1.4 billion cubic feet per day (bcfd) in the two states on May 16. EQM was once a unit of EQT. EQT’s Pennsylvania and Ohio wells are part of the Marcellus and Utica shale formation. In 2019, EQT produced about 4.1 bcfd. One billion cubic feet of gas can supply about 5 million U.S. homes for a day. U.S. gas production and demand is expected to drop in 2020 and 2021 from record highs last year as government steps to slow the spread of coronavirus curtailed economic activity and energy prices, according to federal estimates. “Like others in the natural gas industry, we are anticipating a significant increase in natural gas prices from current levels in just a few months,” EQT said in an emailed statement. U.S. gas futures were down about 16% since the start of the year. Looking forward, however, analysts expect prices will rise as governments lift travel restrictions. Futures for the balance of 2020 and calendar 2021 were trading about 25% and 50% over the June front-month, respectively. “To best capture value from this scenario, starting May 16, we began to temporarily curtail production from certain of our wells in Pennsylvania and Ohio, thereby deferring sales into the more favorable gas pricing environment,” EQT said. It said it “will be monitoring the market to determine the optimal time to return production online.”
Report: Marcellus dethrones Permian Basin as top destination for frac crews – The natural gas-rich Marcellus Shale of Pennsylvania has dethroned the oil-rich Permian Basin of West Texas at the top destination in the United States for hydraulic fracturing crews as record-low crude prices continue to take their toll on the industry.The Marcellus Shale, which stretches across Pennsylvania and West Virginia, has dethroned the Permian Basin of West Texas and eastern New Mexico as the top U.S. destination for hydraulic fracturing crews.The Marcellus, which is rich in natural gas, has 31 percent of the active hydraulic fracturing crews in the field, followed by the oil-rich Permian with 30 percent and the Eagle Ford Shale in South Texas and the Haynesville Shale in East Texas and Louisiana with 14 percent each, according to data from Houston investment advisory firm Tudor, Pickering, Holt & Co.Of the 450 available hydraulic fracturing fleets in the United States and Canada, only 70 are deployed in the field, Tudor, Pickering, Holt said.To weather the current crash, oil companies have tightened their budgets and are taking “frac holidays” in which they don’t bring newly drilled wells into production – lowering demand for hydraulic fracturing services.Some industry experts believe that there are fewer than 50 active hydraulic fracturing fleets in the field but Tudor, Pickering, Holt Managing Director George O’Leary wrote in a research note that “both levels are putrid” and that either way, a recovery is not expected until the fourth quarter or the first quarter of 2021.”This is setting up to be the sharpest quarter over quarter active horizontal frac crew count decline in memory,” O’Leary wrote. “Putting lipstick on a pig, it was a teeny-tiny bit comforting to see the month over month decline rate slow in May versus April, but it’s certainly quite bloody out there.”
Judge dismisses lawsuit that contested Mountain Valley’s power of eminent domain — Legal action has failed, once again, to undo the taking of private land for a natural gas pipeline through Southwest Virginia. “This case presents the latest trickle in a veritable flood of litigation” against the Mountain Valley Pipeline, U.S. District Court Judge James Boasberg wrote in an opinion last week dismissing the lawsuit. Three couples with land in the pipeline’s path had sued Mountain Valley and the Federal Energy Regulatory Commission, alleging that the commission should not have given a corporate venture the right to seize their property by eminent domain. Because Congress improperly delegated legislative power to FERC, the lawsuit had claimed, all pipeline approvals by the agency that led to property being taken against a landowner’s wishes should be invalidated. Calling the request “breathtaking in scope,” Boasberg wrote that his courtroom was the wrong place to make it. His 19-page opinion noted that when FERC finds there is “public convenience and necessity” for a pipeline, as it did with Mountain Valley, the law allows it to convey its power of eminent domain to the developer. The first step to challenging such an action is to seek a rehearing with FERC. If the commission refuses to change its decision, as it did in June 2018, an appeal can be taken to the U.S. Circuit Court of Appeals. Such a challenge was brought, with the appellate court upholding all of FERC’s contested findings in 2019, including its decision that there was a public need for the gas that will flow through the pipeline. In January, three sets of landowners filed their lawsuit in Boasberg’s court in Washington, D.C., contending that Congress through the Natural Gas Act gives too much power to FERC, which in turn conveys eminent domain authority to private entities in a way that is unconstitutional. But their “attempt to transform their grievance with FERC over MVP’s certificate into a facial constitutional challenge cannot save them from the statutorily mandated administrative-review process,” Boasberg wrote in his decision. “The court will therefore dismiss the case for lack of subject-matter jurisdiction.” Two similar lawsuits filed earlier, in Roanoke and Washington, D.C., were also dismissed on the same grounds.
New York Rejects Williams Pipeline Over Water, Climate Concerns – New York state has rejected the controversial Williams pipeline that would have carried fracked natural gasfrom Pennsylvania through New Jersey, running beneath New York Harbor and the Atlantic Ocean before connecting to an existing pipeline system off Long Island.The New York State Department of Environmental Conservation (NYSDEC) announced the decision Friday, arguing that pipeline construction would have harmed water quality and threatened marine life.”New York is not prepared to sacrifice the State’s water quality for a project that is not only environmentally harmful but also unnecessary to meet New York’s energy needs,” DEC spokesperson Erica Ringewald said in a statement reported by POLITICO.The decision is a victory for grassroots activists who have long campaigned against the pipeline. After Oklahoma-based company Williams submitted its most recent application, New Yorkers sent in more than 25,000 comments opposing the pipeline in two weeks, according to the Stop the Williams Pipeline Coalition.”We know [New York State Gov. Andrew] Cuomo only did this because we pressured him to do so,” anti-pipeline campaigner Lee Ziesche told HuffPost. “At the end of the day, he still needs to make a plan to get New York off of gas.”The rejection comes a little less than a year after New York state passed ambitious climate legislationrequiring the state to achieve carbon neutrality by 2050. That deadline is one of the reasons that NYSDEC rejected the pipeline, according to POLITICO. “While the Department recognizes that many building assets in the State currently rely on natural gas for heating and other energy uses, the continued long-term use of fossil fuels is inconsistent with the State’s laws and objectives and with the actions necessary to prevent the most severe impacts from climate change,” DEC wrote in a letter explaining its decision. “Without appropriate alternatives or GHG mitigation measures, the Project could extend the amount of time that natural gas may be relied upon to produce energy, which could in turn delay, frustrate, or increase the cost of the necessary transition away from natural gas and other fossil fuels.”NYDDEC also said that construction would disturb toxic sediments like copper and mercury and harm habitats like shellfish beds.
Denial of Permits Signals End for Gas Pipeline Under Raritan Bay – New Jersey and New York once again have denied key permits for a much contested $1 billion new pipeline that would cut through the former state and under Raritan Bay to supply the latter with natural gas. This time, permit denials appear to have killed the Williams Companies’ proposed Transco Northeast Supply Enhancement project, as the company announced it would not pursue the proposal. “While we continue to believe in the fundamentals of this project, we will not refile in New Jersey or New York at this time,” said Laura Creekmur, spokesperson for Williams, in a statement that expressed disappointment and called the decisions unfortunate. For environmentalists and opponents, New York’s decision on Friday and New Jersey officials’ on Saturday marked a big victory in what has been a long-running effort to halt any new fossil-fuel projects that could increase global warming. “It’s a major breakthrough in the battle against new pipelines,” said Jeff Tittel, director of the New Jersey Sierra Club, referring to New York’s argument it would impede its efforts to combat climate change. “That is a big sea change.” In fact, in denying the permit sought by Williams, the Cuomo administration noted it would be incompatible with a new climate law that aims to reduce greenhouse-gas emissions by 85% from 1990 levels by 2050. The New York Department of Environmental Conservation also feared the 23-mile pipeline would impair water quality by releasing copper and mercury buried in the sediments of Raritan Bay. The New Jersey Department of Environmental Protection followed with a denial of a wetlands permit, citing its neighboring state’s rejection of the water quality permit. In rejecting the permit, DEP officials cited New York’s decision as rendering the New Jersey case moot, failing to demonstrate a compelling public need for the project. The permit was dated May 15, but made public Saturday. Transco had contended the project would bring new gas capacity to Long Island and New York City, where some suppliers had stopped connecting new customers because of concerns about unreliable deliveries of the fuel.
New York’s Use of Landmark Climate Law Could Resound in Other States – A recent decision out of New York is turning heads in the legal community over what law professors and environmental activists say is a turning point for the state’s energy economy, with potentially broader implications nationwide.In a long-awaited decision, New York environmental regulators last week denied for the third time the water quality permit for the controversial Williams Northeast Supply Enhancement pipeline – more commonly known as the Williams Pipeline – that would deliver fracked natural gas 37 miles from the shale fields of Pennsylvania to New York City and Long Island. In its May 15 decision, the New York State Department of Environmental Conservation argued that the pipeline’s construction would stir up toxic sediment containing mercury and copper at the bottom of New York Harbor, compromising water quality and endangering the sensitive habitats nearby, including Raritan Bay, where hard clams are harvested to eat. But the agency also found that the introduction of a new natural gas pipeline would be “inconsistent” with New York’s recently-enacted climate law – landmark legislation that requires the state to transition its power sector to net-zero emissions by 2040 and reduce overall greenhouse gas emissions by 85 percent from 1990 levels by 2050.”In order to achieve the state’s critical and ambitious climate change and clean energy policies, the state needs to continue its ongoing transition away from natural gas and other fossil fuels,” Daniel Whitehead, director of the agency’s Division of Environmental Permits, wrote in his letter to the Williams Pipeline developers. The decision sends a clear signal to utilities and other developers that future proposals for fossil fuel infrastructure in the state will likely face legal challenges under the state’s climate law and it could spur other states to follow suit, said Peter Iwanowicz, the executive director of Environmental Advocates of New York and a former acting commissioner of the Department of Environmental Conservation.
Tree Deaths in Urban Settings Are Linked to Leaks from Natural Gas Pipelines Below Streets – Natural gas leaks from underground pipelines are killing trees in densely populated urban environments, a new study suggests, adding to concerns over such leaks fueling climate change and explosion hazards. The study, which took place in Chelsea, Massachusetts, a low-income immigrant community near Boston, also highlights the many interrelated environmental challenges in a city that faces high levels of air pollution, soaring summer temperatures and is now beset by one of the highest coronavirus infection rates in the nation. Dead or dying trees were 30 times more likely to have been exposed to methane in the soil surrounding their roots than healthy trees, according to the study published last month in the journal Environmental Pollution. “I was pretty blown away by that result,” said Madeleine Scammell, an environmental health professor at Boston University’s School of Public Health who co-authored the study. “If these trees were humans, we would be talking about what to do to stop this immediately.” The study measured soil concentrations of methane and oxygen at four points around the trunks of 84 dead or dying trees and 97 healthy trees. For trees that had elevated levels of methane in the surrounding soil, the highest concentrations were found in the dirt between the tree and the street, suggesting that the gas had leaked from natural gas pipelines, which are typically buried beneath roadways. Suspicions that gas leaks kill plants aren’t new. Robert Ackley, a study co-author who spent decades identifying gas leaks for utility companies in the region, was trained to find them by looking for dead and dying vegetation. Such anecdotal evidence, along with decades-old studies, had previously suggested the link between gas leaks and tree death. The current study, however, was the first to formally quantify the relationship between gas in the soil and tree health in an urban setting, the authors said.
First gas disaster settlement checks going out Friday – The first $70 million in settlement payments to residents affected by the Merrimack Valley gas explosions will be mailed Friday about six weeks earlier than expected. “For those residents who filed a claim with the administrator seeking a lump-sum payment, the average per-household payment will be more than $8,000,” according to the statement from several lead attorneys involved in the $143 million class action lawsuit. Attorneys previously asked for settlement payments to be fast tracked due the COVID-19 pandemic which shut down parts of the economy. As a result of the fires and explosions caused by overpressurized pipelines operated by Columbia Gas, Leonel Rondon, 18, of Lawrence, was killed, three firefighters and 19 civilians were hurt, and damages are estimated at $1 billion. About 50,000 people were forced to evacuate and the severity of the damage depended on the age of appliances. Five homes were destroyed and 131 properties damaged, according to findings by the National Transportation Safety Board. Prior to the final hearing on the settlement Feb. 27, a total of 11,077 claims had been filed. That figure includes 10,432 residential claims and 645 claims from area businesses that suffered losses or closed.
Answers Sought Regarding Explosion and Pipeline Construction in Burrillville – The Burrillville, R.I., compressor station has been a difficult neighbor, operating in relative secrecy as it discharges toxic pollutants and occasionally generates window-rattling explosions.All of these flaws occurred recently, when a parade of construction vehicles and equipment descended on the Enbridge Inc. property off Wallum Lake Road. Soon after, there was an explosion heard and felt by neighbors. Enbridge, the Calgary-based owner of the compressor station, has been characteristically evasive about the incident and the work being done at the fossil-fuel facility. Photos and videos taken by neighbors show excavated portions of the Algonquin pipeline and other construction along a stretch of an access road.An access road to the Burrillville compressor station.Enbrige wouldn’t describe the work being done nor explain the source of the noise. Spokesperson Max Bergeron noted that, “Algonquin Gas Transmission is conducting routine maintenance work near our Burrillville Compressor Station in Rhode Island, in accordance with applicable regulations.” Routine maintenance can mean a lot of things. When asked specifically about a leak, Begergeorn would only say “the work is being conducted safely, and there have not been any unexpected safety-related issues.”The Federal Regulatory Energy Commission (FERC) authorized nearly $1 billion in upgrades to the Algonquin natural-gas pipeline in March 2015. The order is a blanket certificate that allows Enbridge to build natural-gas infrastructure in New York, Connecticut, Rhode Island, and Massachusetts that meet certain cost criteria. Governors from each state supported the Algonquin Incremental Market (AIM) project, including all of Rhode Island’s members of Congress. That same year, the Rhode Island Department of Environmental Management (DEM) issued a permit for the installation and operation of a 15,900-horsepower, gas-powered turbine and a 585-horsepower emergency generator. The permit allows the release of benzyne, formaldehyde, and about eight other carcinogens.
Compressor breakdown leads to release of 4,000 pounds of sulfur dioxide at Delaware City refinery – The Delaware Department of Natural Resources and Environmental Control reported the release of 4,000 pounds of sulfur dioxide at Delaware City Refining Co. The release was reported at 5:28 p.m. at the refinery on Wrangle Hill Road, Delaware City. Sulfer dioxide, a byproduct of the refining process, is considered to be hazardous by the EPA. A compressor issue led to flaring, a procedure used to relieve pressure. Refinery workers repaired and restarted the compressor.
Dominion to keep exporting LNG from Maryland Cove Point during June maintenance – (Reuters) – Dominion Energy Inc said it plans to conduct maintenance at its Cove Point liquefied natural gas (LNG) export plant in Maryland in June but does not expect that work to affect the export side of the facility. Dominion notified customers in a posting on its website that it would work on the plant’s “small liquefier” from June 2-15. The company said that work is unrelated to the LNG export service. The amount of pipeline gas flowing to Cove Point has held around 0.76 billion cubic feet per day – near the plant’s capacity – since the facility exited its last maintenance outage in the middle of October, according to data provider Refinitiv. Even though the plant is not expected to stop LNG exports in June as some traders and brokers said earlier in the week, analysts noted this is a good time for any LNG export plant anywhere in the world to shut. The global LNG market is oversupplied due to several factors including a sharp drop in demand from coronavirus lockdowns that have caused gas prices in Europe and Asia to plunge to record lows in recent weeks. In April, LNG buyers canceled about 20 U.S. cargoes due to be shipped in June. Analysts said they expect even more cancellations in coming months especially now that U.S. gas at the Henry Hub in Louisiana are more expensive for June, July and August than the European Title Transfer Authority (TTF) benchmark in the Netherlands.
With new energy regime only months away, regulators grapple with gas expansion proposal – Three years after private backers secured state regulators’ approval to build a major new natural gas plant in Charles City County, the fate of the facility has become a key factor in a controversial proposal by Virginia Natural Gas to expand its pipeline infrastructure throughout Northern and Central Virginia. “The big issue here is risk, and how are we going to allocate the risk and who’s going to be holding the bag if this plant doesn’t get built,” said Judge Mark Christie during a Wednesday hearing conducted via Skype. The facility, known as C4GT, has been in the works since 2016, when private developers first applied to the State Corporation Commission for a certificate of public convenience and necessity. A combined-cycle natural gas plant, the facility is expected to produce some 1,060 megawatts of power – about two-thirds the size of Dominion Energy’s most recent natural gas plant, the Greensville Power Station, which is capable of powering some 400,000 homes. Yet despite securing regulators’ thumbs-up in 2017, the project stalled. Last March, the backers asked for a two-year extension of their certificate, citing declining interest from investors in light of changes in the regional PJM power grid’s capacity market. Since then, Virginia’s energy landscape has also changed significantly. The passage this spring of the Virginia Clean Economy Act and a law that will join the state to the Regional Greenhouse Gas Initiative, a carbon cap-and-trade market, have committed Virginia to transitioning off fossil fuels and toward renewable energy sources. Mandatory renewable portfolio standards for electric utilities and ambitious targets for solar and wind development are all designed to phase out the use of coal and natural gas by 2045. “This legislation casts serious doubt on the financial viability of the C4GT plant and the likelihood it will ever be built,” said Greg Buppert, an attorney with the Southern Environmental Law Center representing environmental and consumer protection groups Appalachian Voices and Virginia Interfaith Power and Light, at the beginning of Wednesday’s hearing. But Virginia Natural Gas, in arguing that regulators should approve its pipeline expansion proposal, dismissed those concerns, seeking instead to focus the proceedings on what it described as a “simple need solution” to its obligation as a utility to serve any customer in its territory that requests service.
Natural gas outlook remains bleak through 2020 and affects major gas-producing shale operators, says GlobalData – Natural gas prices have struggled in early 2020, hitting record lows due to US dry gas production being at a record high – which has impacted major shale plays such as the Appalachian basin. Although the reduction in associated gas from crude oil production across major oil basins has provided support to the natural gas market, it does not eliminate the fact that the market remains oversupplied. By assessing the readjustment of capex of 15 companies, which account for approximately 85% of total production from Marcellus and Utica Shale, GlobalData estimates a reduction of 1.45 billion cubic feet of natural gas per day (bcfd) in output from this group of companies as compared to the forecast for 2020 before the sector crisis happened Steven Ho, Oil and Gas Analyst at GlobalData, comments: “From GlobalData’s analysis of 15 company positions, rig count is expected to drop by six rigs, from 41 as of the end of March 2020 to 35 rigs by the end of 2020. Overall, this reduction is a result of capex cuts summing up to approximately US$1.5bn reported by operators.” Image Ho continues: “GlobalData took gas wells drilled between 2018 to date as the most representative sample set to determine the economic viability of future wells to be developed in Marcellus and Utica. The sample set consists of slightly more than 2,800 wells, of those less than 25% have breakeven below US$2.05 per thousand cubic feet (mcf). “However, the slowdown is affecting the natural gas consumption over the next few months with the largest demand declines expected from commercial and industrial sector. Reduction in demand will be offset marginally by residential power usage with upcoming summer weather. Natural gas industry will not recover in the near term through 2020, with dry gas production expected to remain at approximately similar level as 2019, accompanied by high level of working natural gas inventory and reduced demand due to current economic slowdown.”
EIA expects lower natural gas production in 2020 — Updated May 18, 2020 at 10:30 a.m. to revise the forecasted change in production and Henry Hub prices. EIA currently forecasts U.S. natural gas production to average 97.1 Bcf/d in 2020, 2% lower than the 2019 average. A previous version stated the 2020 forecast as 94.3 Bcf/d, or 5% lower than the 2019 average. Corrections to the Henry Hub price were relatively minor. Text and figures have been updated accordingly.In its May 2020 Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) forecasts that U.S. marketed natural gas production will decrease by 2% in 2020 because of a weakening economic outlook from the impact of efforts to reduce the spread of the 2019 novel coronavirus disease (COVID-19). EIA expects U.S. marketed natural gas production to average 97.1 billion cubic feet per day (Bcf/d) in 2020, down from 99.2 Bcf/d in 2019.Before the economic contraction caused by mitigation efforts in response to COVID-19, EIA expected natural gas production would flatten in 2020 because of the oversupplied market created as natural gas production growth has outpaced demand growth. The United States set annual natural gas production records in 2018 and 2019, largely because of the increase in drilling in shale and tight oil formations. This increase in production led to higher volumes of natural gas in storage and a decrease in natural gas prices.Declines in crude oil and natural gas prices in March and April have led producers to announce plans to further reduce capital spending and drilling levels, as well as curtail production from some existing wells. Most of the expected decline in natural gas production is from associated gas in oil-directed plays, particularly in the Permian Basin that spans parts of western Texas and eastern New Mexico. EIA expects that the natural gas spot price for the U.S. benchmark Henry Hub will average $2.14 per million British thermal units (MMBtu) in 2020, 43 cents lower than the 2019 average of $2.57/MMBtu. Natural gas prices were already decreasing earlier this year because of the previous year’s record production level and a warmer-than-normal winter. In part because of reduced business activity and higher-than-average storage levels before the summer, Henry Hub prices fell to an average of $1.74/MMBtu in April 2020, the lowest monthly average since March 2016.EIA expects natural gas prices to increase starting in the third quarter of 2020, driven by an increase in industrial demand as business activity resumes. Projected natural gas prices rise to an average of $2.89/MMBtu in 2021 because of upward pricing pressure from declining growth in natural gas production.
U.S. natgas futures jump over 8% as output slows – (Reuters) – U.S. natural gas futures jumped over 8% on Monday on slowing output as energy firms shut wells and slash spending on new oil drilling after crude prices sank earlier this year due to demand destruction from the coronavirus. Those oil wells also produce a lot of gas. Front-month gas futures for June delivery on the New York Mercantile Exchange (NYMEX) rose 13.7 cents, or 8.3%, to settle at $1.783 per million British thermal units. That was their biggest daily percentage gain since April 20. Last week, however, gas speculators cut their net long positions on the NYMEX and Intercontinental Exchange for the first time in six weeks as government lockdowns to stop the spread of the coronavirus cut energy use, causing fuel prices and exports to drop. U.S. crude futures were still down about 45% since the start of the year, even though prices have gained more than 90% over the past four weeks. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell to 89.5 bcfd so far in May, down from an eight-month low of 92.9 bcfd in April and an all-time monthly high of 95.4 bcfd in November. With the coming of warmer weather, Refinitiv projected demand in the Lower 48 states, including exports, would rise to 79.8 bcfd next week from an average of 78.2 bcfd this week. That is similar to Refinitiv’s forecasts on Friday. Refinitiv said U.S. pipeline exports to Canada averaged 2.3 bcfd so far in May, down from 2.4 bcfd in April and an all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico averaged 4.5 bcfd so far this month, down from 4.7 bcfd in April and a record 5.6 bcfd in March. Refinitiv said U.S. LNG exports averaged 6.8 bcfd so far in May, down from a four-month low of 8.1 bcfd in April and an all-time high of 8.7 bcfd in February. U.S. gas prices for June at the Henry Hub benchmark in Louisiana have mostly traded over the Title Transfer Facility (TTF) in the Netherlands since late April. As long as U.S. prices remain over the European benchmark – Henry Hub is also trading over TTF for July and August – analysts said LNG buyers would keep canceling U.S. cargoes. In April, buyers canceled about 20 U.S. LNG cargoes due to be shipped in June.
U.S. natgas futures rise near 3% as output slows – (Reuters) – U.S. natural gas futures rose almost 3% on Tuesday on a continued slowdown in output as energy firms shut oil and gas wells and slash spending on new drilling after crude prices sank earlier this year due to the sharp demand decline caused by the coronavirus pandemic. That price increase came despite expectation that the pandemic will keep domestic energy use and exports low for months. Front-month gas futures for June delivery on the New York Mercantile Exchange rose 4.7 cents, or 2.6%, to settle at $1.830 per million British thermal units, their highest since May 7. Looking forward, analysts expect that prices will rise as governments lift travel restrictions with futures for the balance of 2020 and calendar 2021 trading about 25% and 50% over the front-month, respectively. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell to 89.9 billion cubic feet per day (bcfd) so far in May, down from an eight-month low of 92.9 bcfd in April and an all-time monthly high of 95.4 bcfd in November. EQT Corp, the biggest U.S. natural gas producer, said on Tuesday it started to reduce output in Pennsylvania and Ohio on May 16 as demand destruction from the coronavirus cut current prices for the fuel. Energy consultant Rystad Energy said the pandemic would cause U.S. gas production to fall every month through November, when it is expected to reach 82.5 bcfd. Refinitiv projected that demand in the Lower 48 states, including exports, would hold at around 78.2 bcfd this week and next, which is lower than its 79.8-bcfd forecast for next week on Monday. U.S. LNG exports averaged 6.7 bcfd so far in May, Refinitiv said, down from a four-month low of 8.1 bcfd in April and an all-time high of 8.7 bcfd in February.
U.S. natgas futures slip 3% as demand and exports decline – (Reuters) – U.S. natural gas futures fell about 3% on Wednesday as government lockdowns to stop the spread of coronavirus cut demand for the fuel and exports. That decline comes even though energy firms continued to cut production in response to the collapse in oil and gas prices earlier this year, which ironically was also due in part to demand destruction from the pandemic. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 5.9 cents, or 3.2%, to settle at $1.771 per million British thermal units. Analysts said they expect prices to rise as governments lift travel restrictions and economies rebound. Futures for the balance of 2020 and calendar 2021 were trading about 25% and 50% over the front-month, respectively. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell to 89.7 billion cubic feet per day (bcfd) so far in May, down from an eight-month low of 92.9 bcfd in April and an all-time monthly high of 95.4 bcfd in November. Refinitiv projected demand in the Lower 48, including exports, would slip from 78.7 bcfd this week to 78.4 bcfd next week. That compares with Refinitiv’s forecasts on Tuesday of 78.2 bcfd this week and 78.1 bcfd next week. Refinitiv said U.S. pipeline exports to Canada averaged 2.2 bcfd so far in May, down from 2.4 bcfd in April and an all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico averaged 4.6 bcfd so far this month, down from 4.7 bcfd in April and a record 5.6 bcfd in March. U.S. LNG exports averaged 6.7 bcfd so far in May down from a four-month low of 8.1 bcfd in April and a record 8.7 bcfd in February.
US working natural gas volumes in underground storage rise 81 Bcf on week: EIA | S&P Global Platts – US natural gas stocks increased by 81 Bcf last week, which was directly in line with market expectations, but the remaining Henry Hub summer strip fell further Thursday as demand is expected to dip moving forward. The amount of natural gas in US storage facilities increased 81 Bcf in the week that ended May 15 to 2.503 Tcf, the US Energy Information Administration said Thursday. The injection matched the consensus expectations of an S&P Global Platts survey of analysts. Responses to the survey ranged from an injection of 67 Bcf to one of 99 Bcf. The injection was 19.9% smaller than the 101 Bcf build reported during the same week last year as well as 6.9% below the five-year average addition of 87 Bcf. Cooler-than-normal temperatures boosted residential and commercial demand in the East and Midwest storage regions last week. Across the Eastern and Central US, total demand increased about 4.5 Bcf/d, according to S&P Global Platts Analytics. Upstream, total supplies increased slightly due to a 400 MMcf/d rise in Canadian imports. Supply for the week averaged 92.6 Bcf/d, or about 16.4 Bcf/d higher than the average 80.2 Bcf/d of total demand. Storage volumes now stand 779 Bcf, or 45%, above the year-ago level of 1.724 Tcf and 407 Bcf, or 19.4%, higher than the five-year average of 2.096 Tcf. Henry Hub opened the week with a rally on news of a planned production curtailment by EQT, the country’s largest natural gas producer. The company instated a roughly 1.4 Bcf/d temporary production cut, which sent the balance-of-summer strip nearly 12 cents higher, settling at $2.02 on Monday after trading down to $1.90 last Friday. However, most of the bullish sentiment has retreated as prices have shed most of those gains. The strip was trading at $1.91 Thursday afternoon, keeping spreads to next winter at 81 cents/MMBtu. Platts Analytics’ supply and demand model expects a 108 Bcf addition to US storage volumes for the week ending Friday. Such a build would be 15 Bcf higher than the five-year average. Sizable declines in residential and commercial demand have outpaced an otherwise huge drop in onshore production for the week in progress. Total US demand has averaged 5.7 Bcf/d lower compared with the week prior to average 74.5 Bcf/d. The Midwest and Northeast regions account for a 6.5 Bcf/d decline.
U.S. natgas futures edge up on higher cooling demand, slowing output – (Reuters) – U.S. natural gas futures edged up on Friday on forecasts for warmer weather and rising cooling demand over the next two weeks, and a continued slowdown in output. That price increase was held back by a drop in exports due to demand destruction from the coronavirus. In Europe, gas prices are falling toward zero as stockpiles fill quickly after a warm winter and demand destruction from the pandemic. European buyers started canceling U.S. LNG cargoes in April for delivery in June. Analysts said they expect LNG buyers will cancel dozens of additional cargoes over the summer since U.S. gas forwards are trading higher than European benchmarks through at least September. Front-month gas futures for June delivery on the New York Mercantile Exchange rose 2.1 cents, or 1.2%, to settle at $1.731 per million British thermal units. For the week, the front-month was up about 6% after falling about 10% in the prior week. Futures for the balance of 2020 and calendar 2021 were trading about 27% and 53% over the front-month, respectively, on expectations the economy will snap back once governments lift travel restrictions. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell to 89.5 billion cubic feet per day (bcfd) so far in May, down from an eight-month low of 92.9 bcfd in April and an all-time monthly high of 95.4 bcfd in November.
Natural Gas Prices Could Double Next Year — April has seen a marked reversal of fortunes for shale oil drillers in the United States. The price for May deliveries of West Texas Intermediate crude briefly dropped to minus $40.32 per barrel on 20 April,[i] before rebounding to over zero. For the first time ever, traders were paying to have crude taken off their hands. The supply glut, combined with fears of limited storage space in Cushing, Oklahoma running out, is crushing the shale industry. The record low gas price, not seen since December 2009, mirrors oil since 40 percent of America’s natural gas production is associated gas derived from oil production. Even before the current crisis, natural gas prices were unusually low at just $2.33 in December 2019,[ii] as supply greatly exceeded demand thanks to a mild winter, a slowdown of economic growth in the U.S., China and the rest of the world as well as a glut in liquid natural gas thanks to new export projects coming online in the U.S., Africa and Australia. The arrival and spread of COVID-19 is turning things from bad to worse. “U.S. electricity demand is beginning to rapidly decline due to coronavirus-related containment measures” [iii] states Andy Weismann, CEO of EBW Analytics Group on an industry website. And, since electricity consumption is now a major driver for gas usage in the U.S., demand for gas has fallen. Crude oil prices look subdued for the coming year according to industry observers. By contrast, some analysts expect natural gas prices to rise by the fall for, in response to low crude prices, an increasing number of E&P companies are being forced to cut activity and reduce drilling budgets by between 30 and 50 percent. This is already being mirrored in a reduction in new fracked well-starts from 780 in January to just 162 in April 2020, according to recent statistics from Rystad Energy, April 2020.[iv] The U.S. government’s own estimates show output falling by 660,000 barrels per day by next year, from a peak of 13.2 million barrels a day. As crude output declines so will natural gas output and the price of the latter will rise. The EIA’s April note forecasts rising gas prices in the autumn, in anticipation of higher winter demand for heating and a revival of industrial activity. [v] At the start of April, gas was priced at just $1.64 per million British thermal units (MMBtu), the lowest it has been since December 2009. Goldman Sachs analyst Samantha Dart expects gas prices to jump to $3.50 / MMBtu gas by winter 2020-2021 and reach $ 3.25 / MMBtu by summer 2021. Bank of America concurs but puts the rise to just $ 2.45 / MMBtu in 2021.[vi]
Agency review process on Enbridge tunnel still pending – Enbridge and state officials are waiting to see if a state agency will waive its normal vetting process for the proposed utility tunnel in the straits of Mackinac. Last month, the energy company filed two requests with the Michigan Public Service Commission, one of the many pending applications being processed before the corporation can move ahead with its plan to build a tunnel beneath the Straits of Mackinac which will house a replacement section of its Line 5 pipeline. The first part of Enbridge’s joint requests asks the regulators to approve their plan for the construction of the tunnel after a standard vetting procedure. The second request, on the other hand, urges the commission to waive their normal review on the grounds that it is unnecessary. According to their application, the project “involves no more than maintaining and continuing to operate Line 5 by replacing and relocating one approximate four-mile segment of the over 600-mile line.” Many in the state have taken issue with that latter request, including Attorney General Dana Nessel who, in a press release late last week, reiterated previous public comments she made, asking the commissioner to go through with their normal review process. “Enbridge’s proposed new pipeline must be thoroughly and publicly vetted through the processes required by Michigan law, including full review by the MPSC,” said Nessel. “There is too much at stake to allow anything else.” Her comments in response to the filing maintain that the project does not constitute the mere maintenance of an existing tunnel, but instead an entirely new piece of infrastructure. In late April, the commission delayed their decision to allow for a 20-day public comment period. That public comment period ended last week. In a statement Tuesday, Enbridge spokesman Ryan Duffy said the company’s requests are “consistent with the agreements reached in 2018 between the State of Michigan and Enbridge.”
Environmental advocates, landowners seek to stop Enbridge taking land for northern Wisconsin pipeline – A coalition of environmental advocates and landowners is seeking to stop a Canadian company’s attempt to take private land in order to reroute an oil pipeline around a Native American reservation in northern Wisconsin.As a result of a lawsuit filed by the Bad River Band of Lake Superior Chippewa, Enbridge Energy is planning to remove a 12-mile segment of its Line 5 pipeline from the Bad River Reservation and bypass the reservation with about 41 miles of new pipe.Enbridge has asked the Wisconsin Public Service Commission to grant the power of eminent domain to take private land in Ashland and Iron counties, which would require the PSC to determine that the project is in the public interest. The company says the line, which transports an average of 540,000 barrels a day between Superior and southwestern Ontario, is a key piece of energy infrastructure providing essential fuel for homes, schools and businesses in Wisconsin, as well as the Midwest and eastern Canada.Midwest Environmental Advocates filed a petition Thursday on behalf of five organizations asking the PSC to hold a contested hearing on the issue and to allow five groups it’s representing to participate in the case. In these challenging times, our local businesses need your support. Find out how to get food, goods, services and more from those remaining open. “Giving a multinational energy company the right to condemn private property … is not in the public interest,” said Tony Gibart, executive director of Midwest Environmental Advocates, who said the potential harm to the climate, northern Wisconsin and the Great Lakes “far outweighs any benefit.” Midwest Environmental Advocates is representing the Sierra Club, Honor the Earth, the League of Women Voters, the Superior Rivers Watershed Association and 350 Madison Climate Action Team. Enbridge spokeswoman Juli Kellner said the proposed route “will minimize environmental and human impacts while protecting critical resources.” A group of more than 20 northern Wisconsin landowners and a property rights group filed similar requests, arguing the U.S. Constitution prohibits taking private land except for public use and that only Enbridge shareholders would benefit.
Hidden underwater landslides pose new dangers in the Gulf of Mexico – Seismic data show that earthquakes more than 600 miles away can trigger submarine mudslides that threaten offshore oil rigs and could lead to catastrophic spills.Human error has caused some of the most infamous oil spills in U.S. history, such as those from the Exxon Valdez and Deepwater Horizon. But natural causes can also trigger epic disasters: A spill that has been gushing crude oil for 16 years started when an oil production platform off the coast of Louisiana was demolished by an underwater landslide.Now, evidence from seismic data suggests these undersea avalanches are more common in the Gulf of Mexico than previously recognized, raising concerns about the region’s nearly 2,000 offshore oil platforms as well astens of thousands of miles of oil and gas pipelines that transport fossil fuels to shore.The analysis, published today in Geophysical Research Letters, shows that between 2008 and 2015, 85 previously unknown submarine landslides occurred in the Gulf. Ten of these, the study found, occurred without any detectable trigger. To the researchers’ surprise, the other 75 appear to have been set off by distant earthquakes – mostly small to mid-size tremors that occurred hundreds of miles away along North America’s west coast. “I didn’t expect landslides would be that prevalent in the Gulf of Mexico,” says lead author Wenyuan Fan, a seismologist at Florida State University. “And I didn’t know landslides are so susceptible to dynamic triggering caused by passing seismic waves.” Scientists long have known the Gulf of Mexico has a history of submarine landslides. The largest underwater slump ever documented along any U.S. coastline occurred off the shore of Texas. Scars from other big landslides are visible on the seafloor near the mouth of the Mississippi River.Researchers also have a good idea of why this terrain is so prone to collapse: Every year, rivers dump huge amounts of sediment into the Gulf, causing this loose material to pile up quickly on the seafloor and create steep, unstable topography. But most of the Gulf landslides geologists have cataloged via seafloor mapping surveys occurred thousands of years ago. These events can’t tell us much about the frequency of undersea landslides today, or what exactly sets them off.
Big Oil Taking $1.9 Billion in CARES Act Tax Breaks – Sen. Bernie Sanders was among critics outraged that the fossil fuel industry is using tax breaks in the CARES Act meant to help businesses keep workers employed to avoid paying millions of dollars in taxes – and then delivering that money to executives.”Good thing President Trump is looking out for the real victims of the coronavirus: fossil fuel executives,” Sanders tweeted sarcastically Friday.Reporting Friday from Bloomberg News showed that “$1.9 billion in CARES Act tax benefits are being claimed by at least 37 oil companies, service firms, and contractors” – what watchdog group Documented senior researcher Jesse Coleman described as a “stealth bailout” of the climate-killing industry.”In the name of ‘small business,’ we’re shoveling out billions of dollars to big corporations and rich guys,” Steve Rosenthal, a senior fellow with the Urban-Brookings Tax Policy Center, told Bloomberg.Bloomberg used the example of how Diamond Offshore Drilling Inc. manipulated the bailout to explain the tax scheme:As it headed toward bankruptcy, Diamond Offshore Drilling Inc. took advantage of a little-noticed provision in the stimulus bill Congress passed in March to get a $9.7 million tax refund. Then, itasked a bankruptcy judge to authorize the same amount as bonuses to nine executives.According to Bloomberg’s reporting, Diamond’s refund pales in comparison to some of its larger competitors, “including $55 million for Denver-based Antero Midstream Corp., $41.2 million for supplier Oil States International Inc. and $96 million for Oklahoma-based producer Devon Energy Corp.”The fossil fuel industry was already in financial trouble before the outbreak, which has effectively crippled Big Oil’s ability to make money – even with the generous subsidies given by the federal government. Access to bailout tax break funding is helping fossil fuel companies prosper, along with other climate-destroying industries like mining companies, which have also reaped millions from coronavirus relief legislation.”The Trump administration’s favor factory hasn’t stopped with a global pandemic,” Accountable U.S. spokesperson Jayson O’Neill said in a statement Friday. “As millions of jobs disappear week after week, the Trump administration is prioritizing aid for wealthy, well-connected corporations before small businesses.”
Local lawmakers engage in partisan feud over federal loans for oil industry – Houma-Thibodaux’s two congressmen are defending new government-backed stimulus loans for the oil industry in a partisan fight over the aid.At issue is the Main Street Lending Program, which will provide a total of $600 billion in financing for companies with as many as 15,000 workers to help them weather the economic downturn during the coronavirus pandemic.The Federal Reserve Board, which is administering the program, loosened initial rules so they now allow companies to use the money to repay major debts they may have racked up before the pandemic.Oil interests, backed by many Republican lawmakers, lobbied for the change, saying the loans are needed to help the industry weather plunging oil prices and decreased demand caused by the pandemic that have resulted in layoffs and bankruptcies.”Global oil prices have declined nearly 60 percent since January 2020,” a group of 60 Republican lawmakers wrote ina May 11 letter to Treasury Secretary Steven Mnuchin and Federal Reserve Chair Jerome Powell.Houma-Thibodaux congressmen Garret Graves, R-Baton Rouge, and Steve Scalise, R-Metairie, are among the lawmakers who signed the letter, which urges the two federal officials to resist Democratic efforts to exclude the oil industry from the loans.”America’s oil and natural gas industry supports 10.3 million jobs in the United States and nearly 8 percent of our nation’s gross domestic product,” the letter says. “It is crucial to keep the energy sector functioning and hard-working Americans employed, not only to retain U.S. energy dominance, but to rebuild our overall American economy.”Democrats and environmental groups opposed the change, saying it amounts to a taxpayer bailout of companies that were already in trouble before the pandemic.”Funds from the CARES Act are intended to support struggling families, workers, businesses, states, and municipalities,” 41 Democratic lawmakers say in an April 15 letter to Mnuchin and Powell. “Giving that money to the fossil fuel industry will do nothing to stop the spread of the deadly virus or provide relief to those in need. It will only artificially inflate the fossil fuel industry’s balance sheets.
Few U.S. oil and gas firms return small-business COVID-19 loans – (Reuters) – U.S. securities filings show that only four of 12 listed oil and gas companies that received emergency government aid made available for small businesses said they would return it ahead of a deadline for firms that do not need the funds to do so. The U.S. Treasury Department offered amnesty to public companies that return money they borrowed by May 18, saying it would deem they made the application in good faith due to economic uncertainty fueled by the coronavirus outbreak, before guidelines were clarified. The U.S. energy sector has been clamoring for government aid in the wake of plummeting oil prices that have driven several debt-laden exploration and production companies into bankruptcy. While President Donald Trump said last month his administration would formulate a plan to help the oil and gas industry, no specific aid has been announced. This has left energy companies to seek relief under the broader $2.3 trillion U.S. stimulus package. One aspect of the latter that has been used by oil and gas firms is the so-called Paycheck Protection Program (PPP) for small businesses, which provides loans that can be forgiven to cover payroll expenses, as well as mortgage interest, rent and utility costs. Denver-based exploration and production company PDC Energy Inc (PDCE.O), which has a market capitalization of $1.3 billion, said on May 8 it had returned its $10 million PPP loan.
Pointe LNG raising investment capital for La. project — A proposed liquefied natural gas facility in Louisiana that had been dormant is alive again, Kallanish Energy reports. Pointe LNG has hired Whitehall & Co. to raise investment capital and secure offtake for a liquefaction/export facility in Plaquemines Parish, Louisiana, to process 6 million tons per year of LNG. It said $4 billion in capital would be needed for the project. That includes $56 million in development capital. The project marks the return to the 600-acre site on the Mississippi River for two Pointe LNG founders: Tom Burgess and Jim Lindsay. They had started development of an LNG project under the name Louisiana LNG Energy which they sold in 2015 to a joint venture between Cheniere Energy and Parallax. When those plans did not advance, Pointe LNG resumed development under its new name. The company plans to close development of the capital portion in third quarter 2020 with a final investment decision in mid-2022 and commercial operation by 2026. The facility would be part of a second wave of LNG facilities being developed in the United States. “The project has the best greenfield LNG site in the United States, and we are very excited to kick off this project,” Burgess said in a recent statement. The site is only seven miles from two major natural gas pipelines: TGPL and SONAT. It could process natural gas from the Appalachian Basin, Oklahoma and the Hayneville Shale. The ground at the site is stable with little dredging or additional work required and there are minimal wetlands to mitigate. The facility could be doubled on the current site, the company said. The current plan is three times larger the original size of the Louisiana project. Since late 2018, the company has submitted paperwork to the Federal Energy Regulatory Commission and signed initial contracts to design, build and operate the plant.
Saudi Aramco’s Bahri puts LNG tanker plan on hold – sources (Reuters) – Saudi Aramco’s shipping division Bahri has put on hold plans to charter up to 12 liquefied natural gas (LNG) tankers after Sempra Energy delayed its decision on whether to proceed with an LNG export project in Texas, two sources said. Bahri issued an expression of interest (EOI) last year to charter the vessels from 2025 in Saudi Aramco’s first foray into LNG as part of the state oil giant’s plan to become a major global player in the gas market. In May last year, Aramco signed a 20-year agreement to buy LNG from Sempra Energy’s planned Port Arthur export terminal and also agreed to buy a 25% equity stake in the first phase of the multi-billion dollar project. However, Sempra said this month it was delaying its decision about whether to proceed with the project until 2021 following the slump in global demand for energy because of the coronavirus pandemic. “The shipping requirement was meant for Port Arthur, so given the delay and also the current market, it makes sense to put the shipping on hold,” one of the sources said. The Saudi state-owned company has been developing its own gas resources as well as eyeing assets in the United States, Russia, Australia and Africa, the company’s chief executive officer and the Saudi energy minister have said. The slump in LNG prices to record lows since the coronavirus struck may make financing more difficult and Aramco might be more cautious about its gas investments in the future, one industry source said.
Blanco landowner concerned about stormwater runoff from Kinder Morgan pipeline construction (KXAN) – Following severe weather in Central Texas Friday night into Saturday morning, a Blanco landowner said her property has continued to be impacted by runoff from nearby construction of Kinder Morgan’s Permian Highway Pipeline. The pipeline will be 42 inches wide and is slated to travel from Waha in West Texas to the Katy area, passing through the Hill Country. Myra Corbett, who lives on a property in Blanco, told KXAN Saturday morning that she has continued to see mud and runoff from the pipeline construction effort that cuts through her property. Corbett and her husband moved to this property more than three years ago where they have a guest cabin they rent out as well as ostriches, zebras, donkeys, wildebeest and gazelles. An ostrich struts across Myra Corbett’s property. (KXAN Photo/ Alyssa Goard). SEE IT: Storm water floods Blanco County properties Corbett was one of two Blanco property owners who spoke with KXAN on Friday, expressing concerns about runoff that had come from Kinder Morgan’s construction to their properties. Both of these landowners said they had filed complaints with the Texas Railroad Commission – the state agency in Texas which regulates pipelines – believing pipeline company Kinder Morgan didn’t do enough to control erosion. While the other landowner told KXAN that Kinder Morgan representatives came by to check his property after Friday’s weather and that the barriers they placed had held up, Corbett feels the runoff on her property actually got worse with the weather. On Corbett’s land in Blanco, a pond is situated in the middle of a grassy expanse nearby a gazebo where here Airbnb guests like to go. After rains earlier in the week, Corbett said she had noticed, “runoff had come into the pond and it went from a beautiful, clear, blue pond to an ugly muddy one.” The pond on Myra Corbett’s property has been muddied. She believes runoff from the nearby Kinder Morgan Permian Highway Pipeline construction site is to blame. (KXAN Photo/Alyssa Goard). She said Kinder Morgan employees came by and installed straw bales on her property to prevent further erosion near the pipeline a few days ago. “This morning it was even worse than a couple days ago before it rained,” she said Saturday. “I hate to see the pond like this, it grieves me, instead of the beautiful clear water, you see this,” she said gesturing to the muddied pond. Prior to Kinder Morgan’s construction work, she said the pond would never get muddied to the degree it is now. Corbett doesn’t like the look of it and fears the renters who come to vacation at her cabin won’t like it either. Even beyond the look of the mud coming onto her property, she worries what other impacts this pipeline construction may have on her land, her animals and her family. Corbett is concerned that the netting around the pipeline construction on her property isn’t sturdy enough either.
Permian Basin Leads Decline In U.S. Shale – U.S. shale production is set to fall to a two-year low in the coming weeks, with the Permian basin leading the way down.In the latest Drilling Productivity Report, the EIA estimates that oil production from the country’s leading shale basins is set to fall by 197,000 barrels per day in June compared to a month earlier. The Permian is set to lose 87,000 bpd, but other losses come from the Eagle Ford (-36,000 bpd), Anadarko (-28,000 bpd), Niobrara (-24,000 bpd) and Bakken (-21,000 bpd).U.S. natural gas production is also set to fall in June by about 1 percent, or 779 million cubic feet per day (mcf/d). Notably, the nation’s largest gas producing region in Appalachia loses a relatively modest 85 mcf/d. Instead, much deeper declines from associated gas production in the Permian (-210 mcf/d) and the Anadarko (-244 mcf/d).The larger decline in Permian gas compared to the Marcellus is a reflection of the fact that natural gas prices were already in the dumps prior the pandemic, wallowing below $2/MMBtu. Marcellus drillers began cutting late last year. Natural gas prices didn’t change much after the pandemic (in fact, natural gas prices briefly rallied). Meanwhile, the much larger loss of gas production in the Permian has more to do with the sharp downturn in oil drilling. Texas gas followed oil on the way up, and it will follow oil on the way down. The data from the EIA shows that the decade long U.S. shale boom has come to a screeching halt and is now heading in reverse. Oil production from the top shale basins will dip to 7.8 million barrels per day (mb/d), rewinding output back to late-2018 levels. There is now a confounding disconnect between the health of the U.S. shale industry on the ground and the stock prices for a variety of energy companies. Part of that can simply be chalked up to the rally in oil prices from worthless levels (or less than worthless) to above $30 per barrel in the course of a few weeks.But the Federal Reserve is also pumping trillions of dollars into the stock market, while also more directly buying up corporate bonds of energy companies. The central bank is even buying up bonds from shale companies that recently declared bankruptcy.
EIA expects record liquid fuels inventory builds in early 2020, followed by draws –As mitigation efforts to contain the 2019 novel coronavirus disease (COVID-19) pandemic continue to lead to rapid declines in petroleum consumption around the world, the production of liquid fuels globally has changed more slowly, leading to record increases in the amount of crude oil and other petroleum liquids placed into storage in recent months. In its May Short-Term Energy Outlook (STEO), the U.S. Energy Information Administration (EIA) expects global inventory builds will be largest in the first half of 2020. EIA estimates that inventory builds rose at a rate of 6.6 million barrels per day (b/d) in the first quarter and will increase by 11.5 million b/d in the second quarter because of widespread travel limitations and sharp reductions in economic activity. After the first half of 2020, EIA expects global liquid fuels consumption to increase, leading to inventory draws for at least six consecutive quarters and ultimately putting upward pressure on crude oil prices that are currently at their lowest levels in 20 years. As with the March and April STEO, EIA’s forecast reductions in global oil demand arise from three main drivers: lower economic growth, less air travel, and other declines in demand not captured by these two categories, largely related to reductions in travel because of stay-at-home orders. Based on incoming economic data and updated assessments of lockdowns and stay-at-home orders across dozens of countries, EIA has further lowered its forecasts for global oil demand in 2020 in the May STEO. The STEO is based on macroeconomic projections by Oxford Economics (for countries other than the United States) and by IHS Markit (for the United States).In the May STEO, EIA forecasts global liquid fuels consumption will average 92.6 million b/d in 2020, down 8.1 million b/d from 2019. EIA forecasts both economic growth and global consumption of liquid fuels to increase in 2021 but remain lower than 2019 levels. Any lasting behavioral changes to patterns in transportation and other forms of oil consumption once COVID-19 mitigation efforts end, however, present considerable uncertainty to the increase in consumption of liquid fuels, even if gross domestic product (GDP) growth increases. Members of the Organization of the Petroleum Exporting Countries (OPEC) and partner countries (OPEC+) agreed to new production cuts in early April that will remain in place throughout the STEO forecast period ending in 2021. EIA assumes OPEC members will mostly adhere to announced cuts during the first two months of the agreement (May and June) and that production compliance will relax later in the forecast period as stated production cuts are reduced and global oil demand begins growing. EIA forecasts OPEC crude oil production will fall to less than 24.1 million b/d in June, a 6.3 million b/d decline from April, when OPEC production increased following an inconclusive meeting in March. If OPEC production declines to less than 24.1 million b/d, it would be the group’s lowest level of production since March 1995. The forecast for June OPEC production does not account for the additional voluntary cuts announced by Saudi Arabia’s Energy Ministry on May 11.
With Storage Space Evaporating, the Oil and Gas Industry Will Get to Put Its Products Back Underground — Last month, as the COVID-19 pandemic pushed oil prices into negative figures, drillers in the state’s sprawling shale plays were still pumping and piping oil and gas to the Texas Gulf Coast as usual. But there was a problem: The massive storage tanks dotting the coastline, where tankers load and ship the product abroad, were filling quickly. With limited space to store crude, oil producers resorted to paying buyers to take the stuff off their hands. Then the industry had an idea: Why not just put it back in the ground? After all, the U.S. Strategic Petroleum Reserve, where 641 million barrels of crude are stored in a network of underground salt caverns, underlies much of East Texas and Louisiana. There’s not much space left in the reserve, however, which is why industry players have asked state regulators for permission to store oil and gas in “unconventional” geological formations. On May 5, their wish was granted. The Texas Railroad Commission (which regulates oil and gas producers, not railroads) voted at its regular meeting totemporarily allow the industry to store hydrocarbons underground outside of the usual salt caverns. The commission unanimously rolled back some provisions of Statewide Rule 95, which historically has prohibited storing hydrocarbons outside of salt caverns to prevent groundwater contamination. The rules were waived for a year; producers may store hydrocarbons underground for up to five years.Now environmental watchdogs are warning that the leeway given to oil and gas producers could lead to polluted water across the state. “It’s pretty troubling. Allowing storage in these other formations obviously raises a lot of concerns for both environmental health and the health of our aquifers,” Advocates also say they had little time to prepare for the change or submit public comments to oppose it. “We were pretty shocked by that,” “Usually for something this major, there would be a comment period, where we’d have some time to look into it.”
Google says it won’t build AI tools for oil and gas drillers – Google says it will no longer build custom artificial intelligence tools for speeding up oil and gas extraction, separating itself from cloud computing rivals Microsoft and Amazon. A statement from the company Tuesday followed a Greenpeace report that documents how the three tech giants are using AI and computing power to help oil companies find and access oil and gas deposits in the U.S. and around the world. The environmentalist group says Amazon, Microsoft and Google have been undermining their own climate change pledges by partnering with major oil companies including Shell, BP, Chevron and ExxonMobil that have looked for new technology to get more oil and gas out of the ground. But the group applauded Google on Tuesday for taking a step away from those deals. “While Google still has a few legacy contracts with oil and gas firms, we welcome this indication from Google that it will no longer build custom solutions for upstream oil and gas extraction,” said Elizabeth Jardim, senior corporate campaigner for Greenpeace USA. Google said it will honor all existing contracts with its customers, but didn’t specify what companies. A Google cloud executive had earlier in May revealed the new policy during a video interview. Greenpeace’s report says Microsoft appears to be leading the way with the most oil and contracts, “offering AI capabilities in all phases of oil production.” Amazon’s contracts are more focused on pipelines, shipping and fuel storage, according to the report. Their tools have been deployed to speed up shale extraction, especially from the Permian Basin of Texas and New Mexico.
Ailing oil companies get a pass on royalties – – In April, oil prices dipped below zero and into negatives for the first time in history. In effect, companies were paying investors to take oil off their hands. The coronavirus pandemic had caused an unprecedented plunge in global demand. The market was saturated; storage facilities filled up across the world. News reports from Singapore described dozens of oil tankers sitting off the coast, filled with petroleum that no one would buy. And the low prices have endured, causing the largest ever-recorded decline in U.S. oil and gas rig counts. Some companies have gone bankrupt, with more likely to follow, and many others have laid off workers and scaled back operations. When it comes to addressing this oil supply excess, the federal government has few tools at its disposal. In some of the nation’s top oil-producing regions, including West Texas and North Dakota, much of the drilling takes place on private land. In the Western U.S., however, the federal Bureau of Land Management oversees about 96,000 oil and gas wells on more than 24,000 leases, according to 2018 statistics. Today, even Texas and Oklahoma – states that tend to favor industry, not regulation – have considered measures to limit drilling. But the federal government has taken the opposite approach. The day after oil futures went negative, Nicholas Douglas, a top-ranking national BLM official, emailed the agency’s Western state directors. This email thread, obtained by High Country News, shows the agency encouraging public-land drilling, despite the continued glut in the global market. The new policies instruct state offices to let companies apply for lease suspensions and avoid royalty payments, which are the legally mandated taxes on the revenue from resources drilled or mined on public lands. Several BLM state offices confirmed to High Country News that they are carrying out these policies. These new directives are not outliers. Despite the pandemic, the BLM appears to be encouraging public-lands drilling, rather than pressing operators to shut in wells and not produce oil. In the past few months, the BLM held lease sales in Colorado, Montana, Nevada and Wyoming. A September auction could make more than 100,000 acres of public land available for drilling just outside Canyonlands and Arches national parks in Utah. No such aid has been offered to renewable energy industries, which have also suffered in the downturn. Instead, the Interior Department hit solar and wind projects on federal land with large retroactive rent bills in mid-May, Reuters reported.
Trump administration cuts royalty rates for oil and gas (AP) – The Trump administration has started giving energy companies temporary breaks on royalties and rent they pay to extract oil and gas from leases on public lands because of the coronavirus pandemic. The move drew quick criticism as a handout to industry that will mean less money for state governments. A Democratic lawmaker called for an investigation into whether the breaks were justified. Government data shows companies in Utah receiving steep cuts in the standard 12.5% royalty rate, to as low as 2.5% of the value of the oil and gas they produce. More reductions are expected in the coming days in other states with oil and gas activity on federal lands, primarily in the western U.S. The Interior Department’s Bureau of Land Management said last month that royalty-rate cuts were possible if companies could show they could not successfully operate public energy leases economically or can’t maintain enough employees at drilling sites. Half the money that comes in through royalty payments is typically disbursed to the states where the oil or gas was extracted. The payments totaled $2.9 billion nationwide in 2019, including $94 million in Utah.
Texas Attorney General Ken Paxton challenges Keystone pipeline ruling – Texas Attorney General Ken Paxton, working with counterparts in 17 other states, has filed a friend-of-the-court brief in a West Coast federal appeals court criticizing a lower court’s decision that will could delay oil and gas pipeline projects. U.S. District Judge Brian Morris in April canceled an environmental permit for the long-delayed Keystone XL oil pipeline in Montana. Morris said that the U.S. Army Corps did not adequately consult with the U.S. Fish and Wildlife Service on risks to endangered species and habitat when it renewed a nationwide permit in 2017 that allows dredging work on pipelines across water bodies. To allow the agency to continue authorizing new oil and gas pipeline construction “could seriously injure projected species and critical habitat,” the judge ruled. While the ruling does not block the construction of Keystone or other pipelines, Keystone officials have said that many projects could be delayed without permission to do the dredging work authorized by the Corps’ 2017 permit. The ruling was welcomed by the environmental groups that filed the challenge in the first place but opposed by energy companies. “Maintaining a stable electrical grid is absolutely vital to the public, and the need for consistent, reliable electricity has been met by the growing production of oil and gas,” Paxton said in a statement announcing the amicus brief filing Friday, which asks the San Francisco-based 9th District Court of Appeals to stay the Montana judge’s ruling.
Biden White House would yank Keystone XL permit – Joe Biden would rescind President Donald Trump’s permit allowing the Keystone XL oil pipeline to cross the border into the U.S., a move that would effectively kill the controversial project, his campaign told POLITICO on Monday. The statement is the first from Biden’s campaign about how the presumptive Democratic nominee would handle the project that has been stalled for over a decade if he wins the White House in November. Biden’s opposition also raises the stakes for the TC Energy’s efforts to start construction on the cross-border portion of the pipeline this year that would carry 830,000 barrels of crude oil from Canada to the U.S. “Biden strongly opposed the Keystone pipeline in the last administration, stood alongside President Obama and Secretary Kerry to reject it in 2015, and will proudly stand in the Roosevelt Room again as President and stop it for good by rescinding the Keystone XL pipeline permit,” Biden campaign policy director Stef Feldman said in a written statement to POLITICO. A spokesperson for pipeline developer TC Energy did not immediately respond to questions. The Trump administration is currently appealing a ruling from a federal judge in Montana earlier this month that blocked construction of the pipeline because of an insufficient environmental review. Trump last year signed a cross-border construction permit for Keystone XL, taking it out of the State Department’s hands after years of legal wrangling over the department’s environmental review of the planned route.
Alberta gears up for another legal battle over Keystone XL after Biden vows to pull permissions –Alberta Premier Jason Kenney said he is prepared to go to court anf file a free-trade lawsuit alongside TC Energy Corp. if Joe Biden becomes president and follows through with his promise to pull permits on the Keystone XL pipeline.Construction work on the US$14.4-billion Keystone XL pipeline began in April but fresh opposition from the U.S. Democratic presidential nominee could scuttle the long-delayed pipeline once again.Biden’s election campaign signalled over the weekend that, if the former U.S. vice-president takes the White House this November, he would withdraw presidential permits for the Alberta to U.S. Gulf Coast pipeline Keystone XL. Kenney said at a news conference Tuesday the province “would use every legal means at our disposal to protect our fiscal and economic interests. A spokesman for TC Energy, the Calgary-based pipeline proponent, said in an emailed statement that no other pipeline project “in the history of the industry has been studied more than Keystone XL.”More than a half-dozen Environmental Impact Studies have been done on Keystone XL over the past 10 years, including the latest U.S. Department of State (Federal Environmental Impact Statement), which was released in December of 2019,” Terry Cunha said. Legal scholars, however, said that whoever wins the 2020 U.S. presidential election wields tremendous power over the fate of the Keystone XL project, which was approved by a presidential order under U.S. President Donald Trump rather than by Congress. As a result, a future president could theoretically rescind the permit and even force builder TC Energy Corp. to dig up and remove the pipe. Keystone XL has become a “symbol” of the climate change debate in the United States and announcing opposition to the project is one way for Biden and the Democrats to build support among key liberal voters ahead of the November 2020 election, “It’s become shorthand that you’re an environmentalist if you don’t like Keystone XL,”
First piece of disputed Keystone XL pipeline finished (AP) – A Canadian company has built the first piece of the disputed Keystone XL oil sands pipeline across the U.S. border and started work on labor camps in Montana and South Dakota. But it has not resolved a courtroom setback that would make it hard to finish the $8 billion project. The 1,200-mile (1,900-kilometer) pipeline from Alberta to Nebraska was stalled for much of the past decade before President Donald Trump was elected and began trying to push it through to completion. Environmentalists and Native American tribes are bitterly opposed to the line because of worries over oil spills and that burning the fuel would make climate change worse. Work finally started in April at the border crossing in remote northern Montana. That 1.2-mile section has now been completed except for some site reclamation activity, TC Energy spokeswoman Sara Rabern said. The Calgary-based company has started site work for labor camps near Baker, Montana, and Philip, South Dakota, but it has not set a date to occupy them. Montana officials have not yet received plans requested from the company to make sure it can prevent the camps from spreading the coronavirus, said Erin Loranger, a spokesperson for Montana Gov. Steve Bullock. The state expects to receive the plans before the camps are occupied, she said. The company’s three-year construction timeline was put into doubt following a May 15 ruling from a federal judge in Montana that cancelled a key permit from the U.S. Army Corps of Engineers. The permit is needed to build the line across hundreds of streams, wetlands and other water bodies along its route. The ruling affected all new oil and gas pipeline construction and was appealed by the Trump administration and TC Energy.
Democrats back attempt to shut down North Dakota pipeline – Three dozen congressional Democrats are backing an attempt by the Standing Rock Sioux Tribe to shut down an oil pipeline in North Dakota while the U.S. Army Corps of Engineers conducts an environmental review. The group that includes Sens. Cory Booker, Kamala Harris and Elizabeth Warren filed a brief in federal court Wednesday asserting that allowing the Dakota Access pipeline to operate during the review would give federal agencies “bureaucratic momentum” and violate treaty rights and tribal sovereignty. “The pipeline’s ultimate fate will be a political decision and these leaders understand that DAPL should have never been routed through tribal lands,” Earthjustice attorney Jan Hasselman, who represents the tribe, said of the 36 Democrats. A Department of Justice spokesman declined to comment on behalf of the Army Corps. A half-dozen briefs have been filed by states and groups in favor of keeping the pipeline running. The pipeline was the subject of months of protests, sometimes violent, during its construction in late 2016 and early 2017 near the reservation that straddles the North Dakota-South Dakota border. It began carrying oil in June 2017. U.S. District Judge James Boasberg said in April the pipeline remains “highly controversial” under federal environmental law and requires a more extensive review.
The Energy 202: Public hearings on Zoom have Native Americans worried they won’t be heard on oil projects – The Trump administration is holding virtual public meetings during the coronavirus pandemic to move forward with long-standing plans to expand oil and gas development on public lands. Native American groups, many of whom lack consistent access to the Internet, are worried their voices will not be heard. This is a big obstacle in their fight to stop projects set to take place on lands with cultural significance to them. Tribal groups also say the government’s effort to gather feedback, as required by law, on its efforts to expand drilling in both Alaska’s North Slope and in northwest New Mexico has been plagued with technical issues. Since the hearings transitioned to Zoom with much of the nation on lockdown, tribal groups in both states and other opponents to the projects report that speakers were disconnected due to bad connections or even muted by moderators. “How many North Slope members have access to WiFi?” Raymond Ipalook, vice president of the tribal council in the Alaska Native village of Nuiqsut, asked during one virtual hearing on April 21. “That’s what I want to know. How many of them know that this webinar is going on?” But officials at the Interior Department’s Bureau of Land Management, which oversees federal oil and gas leasing, says these virtual town halls have allowed more people than ever to weigh in on drilling plans. More than 300 people participated in the eight virtual public meetings in Alaska while 100 participated in the first in New Mexico on Thursday, with yet more viewing on Facebook, the BLM said. By contrast, 250 attendees showed up to six in-person meetings held in Anchorage, Fairbanks and other spots in Alaska last year.
The number of active U.S. crude oil and natural gas rigs is at the lowest point on record — Producers were operating the fewest oil and natural gas drilling rigs on record in the United States at 339 on May 12, the lowest level in the Baker Hughes Company’s rig count data series that dates back to 1987. The number of active rigs began sharply decreasing in mid-March as crude oil prices fell: rigs have fallen by 56% (433 rigs) since March 17. Most of the decrease was in oil-focused geologic plays, but natural gas-focused plays also saw significant decreases. Since March 17, 71% (308 rigs) of the rigs taken out of service were in the top three U.S. crude oil-producing regions: the Permian region in southeastern New Mexico and western Texas, the Eagle Ford region in southern Texas, and the Bakken region in Montana and North Dakota. Drilling in oil-focused plays has declined as the impact of mitigation efforts for the 2019 novel coronavirus (COVID-19) have caused declines in petroleum demand and the resulting fall in crude oil prices. In mid-March, the Permian region had 405 operating rigs. By May 12, that number had fallen by 57% to 175 rigs. The Eagle Ford and Bakken regions saw similar declines in their rig counts, of 64% and 69%, respectively, in that time.Rig counts have also fallen in natural gas-focused plays, although those plays had fewer rigs. Earlier this year, the top natural gas-producing regions (aside from the Permian region, where much of the associated natural gas is produced in the United States and where all rigs are classified as oil-directed) were the Marcellus region in Ohio, Pennsylvania, and West Virginia and the Haynesville region in Louisiana and Texas. Drilling rigs in the Marcellus and Haynesville regions, which are exclusively natural gas rigs, declined by 23% and 26%, respectively, from mid-March to May 12. Changes in the number of oil rigs have historically followed changes in oil prices with a lag time of about four months. However, the current drop in rig count followed the recent decrease in the oil price much more rapidly than in the past. The spot price of West Texas Intermediate began March 2020 at $46.78 per barrel (b) and ended the month at $20.51/b; most of the decrease occurred in the first half of the month. The rig count began to decrease sharply in mid-March. The quick reduction in active rigs reflects the sudden loss of petroleum demand related to coronavirus-related mitigation efforts that also resulted in recent increases in theamount of crude oil placed in storage. Similarly, natural gas rig activity has decreased along with the natural gas price. However, the decrease in natural gas prices has been over a longer period than oil prices; natural gas prices were already at multi-year lows in early 2020. Record-high dry natural gas production in November 2019, low demand because of warm weather, and relatively small withdrawals from storage during the winter heating season (November 1 – March 31) have led to a sustained decrease in the natural gas price.
As rigs come down in oil patch, 2 find use in carbon storage projects – As the coronavirus pandemic sent oil demand plummeting and caused many rigs in the Bakken to come down, two of the machines have gone up in other parts of the state for a new purpose: to drill test wells for carbon capture and storage projects. Drilling is underway near Center in Oliver County for Project Tundra, an effort to capture the carbon dioxide from Minnkota Power Cooperative’s coal-fired Milton R. Young Station and inject the emissions underground for permanent storage. And another rig finished drilling a well in late April near Richardton in Stark County alongside the Red Trail Energy ethanol plant. “Everything went very well,” Red Trail CEO Gerald Bachmeier said of the new 6,900-foot hole in the ground near the ethanol facility. “We’re very satisfied.” Now comes a wait of several months for the ethanol plant to hear back from researchers on whether the rock samples removed in the drilling process indicate that the rock layers deep underground have the right characteristics to store carbon dioxide. The analysis also will help identify exactly which layers — such as the Inyan Kara formation or the Broom Creek formation — they should target. A lab in Colorado is doing some of the initial work, then sending the rocks to the Energy & Environmental Research Center at the University of North Dakota in Grand Forks to finish. Rock samples removed in the course of drilling the well for Project Tundra will undergo a similar process. Plus, an extensive study is underway on the project’s design and cost, which could be around $1 billion. Dan Laudal, project manager for Project Tundra, said Minnkota feels “pretty confident” that the site near the coal-fired power plant will work, based on extensive research the EERC has done over the past decade into the feasibility of carbon capture and storage in North Dakota. “But certainly there is a little more work to go to prove to our membership and to regulators that these sites are going to accept CO2 and do what we expect,” he said.
Safety Can’t Be a ‘Pretext’ for Regulating Unsafe Oil Trains, Says Trump Admin | DeSmog –The federal agency overseeing the safe transport of hazardous materials released a stunning explanation of its May 11 decision striking down a Washington state effort to regulate trains carrying volatile oil within its borders. A state cannot use “safety as a pretext for inhibiting market growth,” wrote Paul J. Roberti, the chief counsel for the Pipeline and Hazardous Materials Safety Administration (PHMSA).The statement appeared in the Trump administration’s justification for overruling Washington’s oil train regulation, whichwas challenged by crude-producing North Dakota and oil industry lobbying groups. The Washington rule seeks to limit oil vapor pressure unloaded from trains to less than 9 pounds per square inch (psi) in an attempt to reduce the likelihood that train derailments lead to the now-familiar fireballs and explosions accompanying trains transporting volatile oil.Roberti wrote: “Proponents of the law insist Washington State has a legitimate public interest to protect its citizens from oil train fires and explosions, but in the context of the transportation of crude oil by rail, a State cannot use safety as a pretext for inhibiting market growth or instituting a de facto ban on crude oil by rail within its borders.” With this statement, PHMSA is codifying what has been clear for some time at the regulatory agencies responsible for overseeing the transportation of hazardous materials by rail: that is, profits take priority over safety. A year ago, the U.S. Department of Transportation (DOT), PHMSA’s parent agency, invoked the same legal argument, known as “pre-emption,” to overrule state efforts to require at minimum two-person crews for operating freight trains. As part of the explanation for that decision, the DOT’s Federal Railroad Administration announced that it was adopting a policy of deregulation.”DOT’s approach to achieving safety improvements begins with a focus on removing unnecessary barriers and issuing voluntary guidance, rather than regulations that could stifle innovation,” wrote the agency.A regulatory agency announcing a broad deregulatory agenda was shocking. However, this latest move openly declares that, while Washington state may have an interest in protecting its citizens from “oil train fires and explosions,” that concern should not get in the way of the oil industry’s ability to ship more of its product by rail through the state, apparently even if that increases the risk of oil train fires and explosions to Washington residents. This logic reaches a new level of prioritizing profits over people as regulatory practice.
ExxonMobil seeks to restart three platforms idled after Refugio oil spill – Tuesday, May 19, marks the fifth anniversary of the massive Plains All American Pipeline spill near the Refugio State Beach in Santa Barbara County. The collapse of the severely corroded pipeline resulted in 140,000 gallons of crude oil spilling into the ocean, killing hundreds of birds and marine mammals, halting recreational and commercial fishing and fouling four “marine protected areas” created under the privately-funded Marine Life Protection Act (MLPA) Initiative as the spill was cleaned up. Now, as U.S. oil prices plunge and dozens of oil tankers with no place to store their oil are idling off the California coast, ExxonMobil is trying to restart its three platforms and transport that oil by using up to 70 tanker trucks per day on coastal Highway 101 and accident-prone Route 166 in a project Santa Barbara County is considering this summer. The other four offshore platforms shut down by by the spill are being decommissioned, according to a statement from the Center for Biological Diversity. The idling of the seven offshore platforms served by the pipeline has prevented “massive emissions of climate pollution” since the spill, the Center said. “If the seven offshore drilling platforms served by the pipeline had not gone idle, they would have added 33.9 million metric tons of carbon dioxide pollution to the atmosphere. That’s roughly equivalent to operating two coal-fired power plants in California over the same period – or to burning more than 37 billion tons of coal,” the group stated. Kristen Monsell, oceans legal director at the Center, said, “California is better off without drilling for oil from these polluting platforms, and so is our climate. Santa Barbara County shouldn’t allow ExxonMobil to restart its offshore drilling operations and endanger Californians.”
Trump energy chief compares oil-and-gas financing to racist loaning practice – Bank restrictions on the financing of oil and gas drilling in the Arctic are akin to past practices – known as redlining – of not loaning to communities of color, Energy Secretary Dan Brouillette told Axios in an exclusive interview. A decades-long battle over Arctic drilling is suddenly escalating even as the world grapples with a pandemic. Five of America’s six biggest banks have recently announced they won’t finance oil and gas development in the Arctic, prompting conservative and industry backlash. “For years and years and years, banks would not lend money, insurance companies would not write policies in minority areas in the country. Redlining is the term used all throughout those debates. We didn’t want banks redlining certain parts of the country. We don’t want that here. I do not think banks should be redlining our oil and gas investment across the country.” – Energy Secretary Dan Brouillette Brouillette cited his past work at USAA, a financial services firm. Experts said, though, that the redlining comparison is both inappropriate and inaccurate. “It’s offensive and astounding that they would go there,” said Mehrsa Baradaran, a law professor at University of California-Irvine and an expert on redlining and racial discrimination in banking. “A massive corporation being cut off from a few banks is absolutely nothing like the systematic exclusion and exploitation of black communities for hundreds of years. It displays an unfortunate ignorance about the history of redlining.” “Redlining had to do with race and race is specifically constitutionally protected as an area you can’t discriminate against,” said Tony Fratto, a former top official in the Bush administration who’s now at the public affairs firm Hamilton Place Strategies. “There is no similar protection for businesses.” “Secretary Brouillette has zero tolerance for discrimination of any type, and he was not in any way equating the plight of minority communities to that of energy companies,” Department of Energy spokesperson Shaylyn Hynes said of the redlining analogy. “Accusing him of doing so in order to manufacture a dramatic headline is both disingenuous and not based in any truth.” “What he did do is make the powerful point that historically there had been discrimination practiced by some in the financial services industry, a custom he and many others worked hard to eliminate and continue to oppose.”
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