Oil, Gas, And Fracking News Reads: 04May 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 25 April 2020. Part 2 is available here.

This is a feature at Global Economic Intersection every Monday evening.

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U.S. rig count at a 47 month low after largest percentage rig drop on record

Oil prices finished higher for the first time in four weeks on somewhat less trading volume than in the prior week, as the outlook for production cuts outweighed fears that there’d soon be no place to store any new oil…after falling by a record 32% to $16.94 a barrel in a week that saw the price of May oil fall to $40 below zero, the contract price of the US benchmark crude for June delivery initially fell 7% early Monday on signs that worldwide oil storage was filling rapidly, raising concerns that production cuts would be unable to catch up with the collapse in demand and then collapsed to as low as $11.88 a barrel as it became apparent that oil ETFs (exchange traded funds), fearing negative prices, were dumping June oil in favor of later dates, and then only partly recovered to close down $4.16 or 25% at $12.78 a barrel even as governments worldwide began taking tentative steps towards reducing restrictions that had driven fuel demand down 30%….oil prices then extended Monday’s near 25% decline by sliding more than 15% during overnight trading on ongoing fears that storage around the world was rapidly filling, and traded as low as $10.07 on Tuesday after the Chicago Mercantile Exchange ordered the United States Oil Fund to sell some of its near-dated futures contracts and after reports that OPEC’s oil production had risen more than 2 million barrels per day, but recovered in late trading to finish down just 44 cents at $12.34 a barrel even as storage fears persisted…however, oil prices rebounded more than 20% on Wednesday after EIA data showed a smaller-than-expected build in U.S. oil inventories, and on hopes that economies will reopen sooner than expected, with June oil rising 22%, or $2.72, to settle at $15.06 per barrel, after trading as high as $16.78…oil prices then rallied 25% on Thursday to finish April down just 8%, with the US benchmark crude rising $3.78 to $18.84 a barrel on news that major oil companies and countries outside of OPEC had announced voluntary crude production cuts…oil prices added another 5% to those gains on Friday, closing up 94 cents at $19.78 a barrel, after U.S. drillers cut oil rigs for a seventh week in a row, lowering the total count down to 325, the lowest since June 2016…oil prices thus finished the week 17% higher as traders marked the start date for production cuts under the new agreement between OPEC & other oil producers…

Natural gas prices, on the other hand, finished slightly lower as concerns over falling demand outweighed prospects for lower supplies….recall that the last time we checked natural gas prices, the contract for natural gas for delivery in May was trading, and it had risen 6.9% to $1.733 per mmBTU during the week ending April 10th on forecasts for cooler weather and a resumption of Chinese LNG imports…since that time, the contract price of natural gas for June delivery has become the quoted “natural gas price”, and cooler weather forecasts have become bearish, since they would now indicate less than normal air conditioning demand….the June natural gas contract had finished the week ending April 10 at $1.863 per mmBTU and had gradually moved up to $1.895 by last Friday, with very little of the volatility seen in oil prices over the same period…that natural gas contract opened this week slightly higher but fell to $1.765 per mmBTU on Monday before rising to close 2.1 cents higher, as the two week forecasts for warmer weather were peppered with weak cool shots moving in from the northwest… the June contract price then rose 3.2 cents to $1.948 per mmBTU on Tuesday on expectations that demand would jump once governments loosened travel and work restrictions, even as the May gas contract expired 2.5 cents lower at $1.794 per mmBTU on lower current demand…bearish cooler weather forecasts returned on Wednesday and natural gas prices fell 7.9 cents to $1.869 per mmBTU with demand destruction weighing more heavily on the front month than declines in production…but natural gas prices reversed those losses and rose 8 cents to a 10 week high of $1.949 per mmBTU on Thursday, on reports that drillers were shutting oil wells, which would concurrently reduce associated natural gas output…but gas prices fell back 5.9 cents on Friday on forecasts that demand and exports would decrease due to government lockdowns and ended the week at $1.890 per mmBTU, just a half cent lower than the prior week’s close…

The natural gas storage report from the EIA for the week ending April 24th indicated that the quantity of natural gas held in underground storage in the US rose by 70 billion cubic feet to 2,210 billion cubic feet by the end of the week, which left our gas supplies 783 billion cubic feet, or 54.9% higher than the 1,427 billion cubic feet that was in storage on April 24th of last year, and 360 billion cubic feet, or 19.5% above the five-year average of 1,850 billion cubic feet of natural gas that has been in storage as of the 24th of April in recent years….the 70 billion cubic feet that were added to US natural gas storage this week was in line with consensus forecast for a 69 billion cubic feet increase from a survey of analysts by Reuters, but it was a bit below the 74 billion cubic feet of natural gas that have been added to natural gas storage during the same week over the past 5 years, and well below the 114 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 April 24th indicated that a modest increase in our oil refining combined with import and export increases of the same magnitude still left a large surplus of oil being added to our stored commercial supplies, the twenty-fifth addition of oil to storage in the past thirty-three weeks, but not at the record setting pace of the past three weeks…our imports of crude oil rose by an average of 365,000 barrels per day to an average of 5,302,000 barrels per day, after falling by an average of 743,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 412,000 barrels per day to an average of 3,302,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,000,000 barrels of per day during the week ending April 17th, 47,000 fewer 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 12,100,000 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 14,100,000 barrels per day during this reporting week..

US oil refineries reported they were processing 12,761,000 barrels of crude per day during the week ending April 24th, 305,000 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 1,449,000 barrels of oil per day were being added to the supplies of oil stored in the US….so looking at all that data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 164,000 barrels per day less than what what was added to storage plus 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 (+164,000) 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….(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 fell to an average of 5,448,000 barrels per day last week, now 19.7% less than the 6,789,000 barrel per day average that we were importing over the same four-week period last year….the 1,449,000 barrel per day addition to our total crude inventories included 1,284,000 barrels per day that was added to our commercially available stocks of crude oil, and 164,000 barrels per day that was added to our Strategic Petroleum Reserve….this week’s crude oil production was reported to be down by 100,000 barrels per day to 12,100,000 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 11,600,000 barrels per day, while a 1,000 barrel per day decrease in Alaska’s oil production to 466,000 barrels per day did not impact the rounded national total….last year’s US crude oil production for the week ending April 26th was rounded to 12,300,000 barrels per day, so this reporting week’s rounded oil production figure was 1.6% below that of a year ago, yet still 43.6% 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 69.6% of their capacity in using 12,761,000 barrels of crude per day during the week ending April 24th, up from 67.6% of capacity during the prior week, but still among the lowest utilization rates of the last dozen years…hence, the 12,761,000 barrels per day of oil that were refined this week still 22.4% fewer barrels than the 16,446,000 barrels of crude that were being processed daily during the week ending April 26th, 2019, when US refineries were operating at 89.2% of capacity….

With the increase in the amount of oil being refined, gasoline output from our refineries was quite a bit higher, increasing by 530,000 barrels per day to 6,735,000 barrels per day during the week ending April 24th, after our refineries’ gasoline output had increased by 290,000 barrels per day over the prior week….but since the increases of the past three weeks followed two near record drops in gasoline output, our gasoline production this week was still 32.2% lower than the 9,927,000 barrels of gasoline that were being produced daily over the same week of last year….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 25,000 barrels per day to 5,982,000 barrels per day, after our distillates output had increased by 80,000 barrels per day over the prior week…and after this week’s increase in distillates output, our distillates’ production for the week was 2.8% less than the 5,128,000 barrels of distillates per day that were being produced during the week ending April 26th, 2019….

Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week fell for the first time in 5 weeks but for the 9th time in 13 weeks, falling by 3,669,000 barrels to 259,565,000 barrels during the week ending April 24th, after our gasoline supplies had increased by 1,017,000 barrels over the prior week…our gasoline supplies decreased this week because the amount of gasoline supplied to US markets increased by 549,000 barrels per day to 5,860,000 barrels per day, and because our exports of gasoline rose by 121,000 barrels per day to 905,000 barrels per day while our imports of gasoline fell by 140,000 barrels per day to 228,000 barrels per day….even after this week’s inventory decrease, our gasoline supplies were still 14.5% higher than last April 26th’s gasoline inventories of 226,743,000 barrels, and roughly 10% above the five year average of our gasoline supplies for this time of the year…

Als, even with the small decrease in our distillates production, our supplies of distillate fuels increased for the fourth time in 15 weeks and for the 9th time in 30 weeks, rising by 5,092,000 barrels to 141,972,000 barrels during the week ending April 24th, after our distillates supplies had increased by 6,280,000 barrels over the prior week….our distillates supplies rose by less this week because our exports of distillates rose by 466,000 barrels per day to 1,326,000 barrels per day while our imports of distillates rose by 129,000 barrels per day to 235,000 barrels per day, and while the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 36,000 barrels per day to 3,164,000 barrels per day….after this week’s big inventory increase, our distillate supplies at the end of the week were 12.9% above the 125,722,000 barrels of distillates that we had stored on April 26th, 2019, and about 4% above the five year average of distillates stocks for this time of the year…

Finally, with higher oil exports being mostly offset by higher oil imports against a modest increase in oil refining, our commercial supplies of crude oil in storage rose for the twenty-sixth time in forty-three weeks and for the thirty-third time in the past 52 weeks, increasing by 8,991,000 barrels, from 518,640,000 barrels on April 17th to 527,631,000 barrels on April 24th….but even after 14 straight increases and three record increases over the prior 3 weeks, our crude oil inventories were only 10% above the five-year average of crude oil supplies for this time of year, but roughly 50% higher than the prior 5 year (2010 – 2014) average of crude oil stocks as of the last Friday in April, 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 April 24th were 12.1% above the 470,567,000 barrels of oil we had in commercial storage on April 26th of 2019, and 21.0% above the 435,955,000 barrels of oil that we had in storage on April 27th of 2018, while at the same time remaining fractionally below the 527,772,000 barrels of oil we had in commercial storage on April 21st of 2017…

This Week’s Rig Count

The US rig count fell by 10% or more for the 4th week in a row during the week ending May 1st, and is now down 62.3% from its interim high at end of 2018….Baker Hughes reported that the total count of rotary rigs running in the US decreased by 57 rigs to 408 rigs this past week, which was the least rigs deployed since June 3rd, 2016, and hence is a 47 month low for the US rig count…that count was also down by 582 rigs from the 990 rigs that were in use as of the May 3rd report of 2019, and 1,521 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….this week’s 12.3% drop was also the largest percentage rig drop on record, besting the 12.1% decrease seen during the week ending April 17th….

The number of rigs drilling for oil decreased by 53 rigs to 325 oil rigs this week, after falling by 60 oil rigs the prior week, leaving oil rig activity also at its lowest in 47 months, 482 fewer oil rigs than were running a year ago, and about a fifth 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 decreased by 4 to 81 natural gas rigs, leaving the fewest natural gas rigs active since August 26th of 2016, and hence a new 44 month low for natural gas drilling, down by 102 natural gas rigs from the 183 natural gas rigs that were drilling a year ago, and way down from the 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 down by one rig to 16 rigs this week, with all of those Gulf rigs drilling for oil in Louisiana’s offshore waters…that’s four less than the rig count in the Gulf a year ago, when 17 rigs were drilling offshore from Louisiana and three 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 winter…

The count of active horizontal drilling rigs decreased by 52 rigs to 374 horizontal rigs this week, which was the fewest horizontal rigs active since August 12th, 2016, and hence is a 44 month low for horizontal drilling…it was also 499 fewer horizontal rigs than the 873 horizontal rigs that were in use in the US on May 3rd of last year, and nearly a thousand less than 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 5 to 11 vertical rigs this week, and those were down by 35 from the 46 vertical rigs that were operating during the same week of last year….meanwhile, the directional rig count was unchanged with 23 directional rigs still running this week, but those were still down by 48 from the 71 directional rigs that were in use on May 3rd 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 1st, the second column shows the change in the number of working rigs between last week’s count (April 24th) and this week’s (May 1st) count, the third column shows last week’s April 24th 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 3rd of May, 2019…

As you can see, this weeks basin totals indicate a decrease of 45 rigs, which is 7 fewer than the decrease of the horizontal rig count nationally, which thus means that 7 horizontal rigs were also shut down in basins not tracked separately by Baker Hughes and hence not shown above…offhand, one obvious place where some of those rigs might have been drilling is in Utah, which was down by 5 rigs this week and has both the Uinta and Paradox shale basins that aren’t tracked in this report…in addition, 5 rigs were also removed from Oklahoma which aren’t accounted for in the basin totals…meanwhile, the rig count in the Denver-Julesburg Niobrara chalk was down by 8, leaving just 7 rigs remaining, with 7 of those most likely pulled from Colorado while one Niobrara rig was shut down in Wyoming….next, checking the rig losses in the Texas part of Permian basin, we find that 18 rigs were pulled out of Texas Oil District 8, or the core Permian Delaware, and 5 more rigs were stacked in Texas Oil District 7C, or the southern Permian Midland, and hence the Permian in Texas saw a total reduction of 23 rigs…that total means that the 4 rigs that were shut down in New Mexico must have been drilling in the western Permian Delaware, to bring the national Permian reduction to 27 rigs…elsewhere in Texas, 2 rigs were pulled out of Texas Oil District 1 and 3 rigs were pulled from Texas Oil District 2, which together would account for the 5 rig reduction in Eagle Ford shale, which is now down to 29 oil rigs and just one seeking natural gas….Texas Oil District 6 was also down a rig, thus accounting for one of the Haynesville shale rig losses, while another Haynesville shale rig that had been deployed in northwest Louisiana was also shut down….those two Haynesville rigs, the two Pennsylvania Marcellus rigs, and one of the Eagle Ford rigs account for the natural gas rig reductions, while a natural gas rig actually started drilling elsewhere, in a basin not tracked by Baker Hughes…

UTICA SHALE WELL ACTIVITY AS OF APRIL 25:

• DRILLED: 164 (155 as of last week)
• DRILLING: 97 (102)
• PERMITTED: 509 (504)
• PRODUCING: 2,481 (2,481)
• TOTAL: 3,251 (3,242)

Nine horizontal permits were issued during the week that ended April 25, and 10 rigs were operating in the Utica Shale. TOP COUNTIES BY NUMBER OF PERMITS

• 1. BELMONT: 688 (682 as of last week)
• 2. CARROLL: 530 (530)
• 3. HARRISON: 512 (510)
• 4. MONROE: 438 (438)
• 5. GUERNSEY: 280 (280)

Ohio produced record natural gas, oil in 2019 – Ohio produced all-time record volumes of natural gas and crude oil in 2019, according to a new report. The state’s natural gas production in 2019, mostly from the Utica Shale, was 2.882 trillion cubic feet of natural gas, said the Debrosse Memorial Report. The 2019 full-year totals are estimated because final production totals have not yet been submitted to state regulators for the fourth quarter. That natural gas total is up 22% from 2018 totals and is believed to be the highest in Ohio history. Ohio ranks fifth in the U.S. for natural gas production, Kallansh Energy reports. Estimated oil production in Ohio in 2019 is 27.8 million barrels. That tops 2018’s total of 22.7 million barrels and also surpasses the 1896 total of 23.9 million barrels from the Trenton Limestone formation. The most active operator in Ohio last year was Ascent Resources with 104 new wells, up 49% from 2018. Second was Gulfport Appalachia with 50 additional wells, followed by EAP Ohio (Encino Energy) with 38 wells, Eclipse Resources (now Montage Resources) with 34 wells and Rice Drilling (now part of EQT) with 17 wells. Belmont County was the No. 1 drilling county in Ohio in 2019 with 80 wells drilled. Jefferson and Monroe counties were tied for second, each with 69 wells. Harrison County was fourth with 34 and Guernsey County was fifth with 32. Ohio had 406 well completions in 2019, down two completions from 2018. Ascent Resources drilled 2.2 million feet of laterals and vertical shafts in 2019, more than double second-place Gulfport Appalachia with 1.0 million feet. The rest of the top 5 were Eclipse Resources with 768,269 feet, EAP Ohio with 767,757 feet and Rice Drilling with 347,459 feet. Belmont County was No. 1 for drilled footage with 1.63 million feet, followed by Jefferson with 1.46 million feet and Monroe with 1.41 million feet. Guernsey had 775,218 feet and Harrison had 717,604 linear feet. Statewide, a total of 6.57 million linear feet were drilled in 2019, up slightly from the 6.51 million feet in 2018. In Q4 2019, Ohio had 2,523 Utica wells online. Last year, Ohio had 41 different O&G companies complete wells, up slightly from the 38 operators in 2018. In 2011, the state had 121 producers. Ohio also reported limited drilling in the Clinton (52), Knox (25) and Marcellus (14) formations. Shumway also reported that Ohio’s 225 active injection wells handled less liquid drilling wastes in 2019. The volume injected was 43.372 billion barrels, down 3.5% from the 44.941 billion barrels in 2018. The 2019 total is still the No. 2 highest volume injected ever in the state with 40% of the wastes coming from other states.

Study tries to untangle shale gas and coal impacts on Ohio groundwater – Rob Reed is happy to have clean well water at his family’s Monroe County, Ohio, fruit farm. But in a region rife with fossil fuel extraction, worries about contamination loom. “It seems like eastern Ohio is always under assault from some entity or another, whether it’s an underground coal mine or fracking for natural gas or whatever it is,” Reed said. “They’re always drilling holes and making tunnels under the earth. Of course, that’s where the water comes from.” Samples from the Reeds’ well are among hundreds being analyzed by Yale University researchers who hope to better understand how different types of fossil fuel activity affect groundwater. The study might give some residents a clearer view of where to point a finger if wells do go bad. Results could bolster claims for damages in some future cases or potentially absolve one industry or another in other situations. More generally, the work can provide important insights for lawmakers and regulators. “We’re just trying to get good quality information for policymakers,” said Helen Siegel, a graduate research fellow on the project. The work focuses on Belmont and Monroe counties, which have not been the focus of much prior research. The poverty rate in Monroe County was almost 17% in 2018. Belmont County fared somewhat better, with an overall poverty rate of roughly 13%. But there are wide disparities among cities and towns in that county. St. Clairsville, where Murray Energy is headquartered, had roughly 1 in 20 children living in poverty. In contrast, Martin’s Ferry had more than 1 in 4 children living in poverty.

Decision delayed on Ohio petrochemical plant — Akron Beacon Journal – Two Asian companies have delayed a decision on whether to proceed with a long-talked-about petrochemical plant for eastern Ohio.The companies behind the project, Thai chemical company PTT Global Chemical America and South Korean partner Daelim Industrial Co., are blaming the coronavirus for delaying a decision that was supposed to be made by July.”While, due to circumstances beyond our control related to the pandemic, we are unable to promise a firm timeline for a final investment decision, we are working hard toward that decision,” the companies said in a post on their websites.”We pledge that we will do everything within our control to make an announcement as soon as we possibly can with the goal of bringing jobs and prosperity to the Ohio Valley.”JobsOhio, the state’s economic development arm, said it is continuing to work with the companies. JobsOhio has committed $70 million in loans and grants to the project.”This project remains a top priority,” JobsOhio said in a statement. “We understand that the pandemic will delay some project decisions that companies may make. JobsOhio continues to be in close communication with the PTTGCA and Daelim teams in regard to their plans in Belmont County.” The delay is adding to what already has been a lengthy process for determining whether the companies will go ahead. PTT announced in 2015 that it was considering the site, once the home of a coal-fired power plant along the Ohio River near Shadyside, for the project. PTT later brought on Daelim as a partner. If they go ahead, it would be an economic boon for the region, employing several thousand workers during construction and several hundred once the plant became operational.

Developers Put a Plastics Plant in Ohio on Indefinite Hold, Citing the Covid-19 Pandemic – The developers of a proposed plastics manufacturing plant in Ohio on Friday indefinitely delayed a final decision on whether to proceed, citing economic uncertainties around the coronavirus pandemic.Their announcement was a blow to the Trump administration and local economic development officials, who envision a petrochemical hub along the Ohio River in Ohio, Pennsylvania and West Virginia.Environmental activists have opposed what they say would be heavily polluting installations and say bringing the petrochemical industry to this part of Appalachia is the wrong move for a region befouled for years by coal and steel. Thailand’s PTT Global Chemical America and South Korea’s Daelim Industrial have been planning major investments in the $5.7 billion plant, 60 miles southwest of Pittsburgh, for several years. On the site of a former coal-fired power plant, the facility would have turned abundant ethane from fracking in the Marcellus and Utica shale regions into ethylene and polyethylene, which are basic building blocks for all sorts of plastic products.The partnership had promised a final investment decision by summer, but announced the delay in a statement on its website. “Due to circumstances beyond our control related to the pandemic, we are unable to promise a firm timeline for a final investment decision,” the companies said. “We pledge that we will do everything within our control to make an announcement as soon as we possibly can with the goal of bringing jobs and prosperity to the Ohio Valley.”In March, financial analysts with IHS Markit, a global information and data company, and the Institute for Energy Economics and Financial Analysis (IEEFA), a nonprofit think tank, agreed the project was in trouble even before the coronavirus began to shrink the global economy. A global backlash against plastics, low prices and an oversupply of polyethylene, were all signs of troubling economic headwinds before Covid-19 sent world oil prices tumbling, disrupting the petrochemicals industry. JobsOhio, the state’s private economic development corporation, has invested nearly $70 million in the project, including for site cleanup and preparation, saying thousands of jobs were in the offing. A JobsOhio spokesman declined to comment Friday.

Exclusive: Chesapeake Energy preparing bankruptcy filing Chesapeake Energy Corp (CHK.N), the oil and gas exploration and production company that was at the forefront of the past decade’s U.S. shale boom, is preparing a potential bankruptcy filing as it grapples with an unprecedented rout in energy prices, people familiar with the matter said on Wednesday. The Oklahoma City-based company, cofounded by late wildcatter and outspoken natural gas proponent Aubrey McClendon, has held discussions with creditors about a possible loan that would aid operations while it navigates bankruptcy proceedings, the sources said. The loan could total roughly $1 billion, though its size remains in flux, one of the sources added. Such loans, referred to as debtor-in-possession financing, are key to companies seeking Chapter 11 bankruptcy protection because they help them sustain as much of their business as possible during court proceedings. Chesapeake’s discussions about possibly obtaining bankruptcy financing are in early stages, and the company has made no final decisions about how it plans to address its debts, the sources cautioned. It could attempt to persuade creditors to restructure its debt outside of bankruptcy proceedings, said the sources, who asked not to be identified because the matter is confidential. Chesapeake did not immediately respond to a request for comment. Chesapeake was trying to pivot from gas to a greater emphasis on oil production when a Saudi-Russian energy price war earlier this year upended its plans and the wider crude market. It was dealt another blow by the coronavirus outbreak, which caused energy demand to dwindle by shutting large swaths of the global economy. Chesapeake, which employed about 2,300 people as of the end of last year, faces significant payments due this year on portions of its nearly $9 billion debt pile. Maturities and interest expenses combined total more than $1 billion, according to a regulatory filing. Chesapeake is considering skipping a payment of $192 million due in August, adding urgency to the discussions with creditors, one of the sources said. Chesapeake also faces a $136 million obligation on July 1. Chesapeake is also discussing the prospect of obtaining an additional equity infusion that would likely follow a bankruptcy filing, according to one of the sources. The company does not currently anticipate help in the form of U.S. government aid provided to companies ailing from the coronavirus crisis, the source added.

Energy Transfer racks up more violations on Revolution pipeline – A few months after regulators imposed a historic $30 million fine on Energy Transfer Corp. and allowed it to resume environmental permitting in Pennsylvania, the pipeline company is already negotiating a new settlement to address a slew of violations found since that agreement. The 596 new environmental violations since January stem from the Texas-based company’s inability to stabilize soil along the route of its Revolution pipeline, a 40-mile link between wells in Beaver and Butler counties and a processing plant in Washington County. Regulators have documented masses of rock and soil that have sloughed downhill, spilled over barriers, knocked out trees and filled in streams. Slipping earth that had been repaired failed again; structures to keep soil in place were installed improperly or overwhelmed in wet weather. In February, an inspector arrived at a pitch in Beaver County and found it “actively moving.” The path of a National Fuel pipeline photographed in August 2019 in Center Township. This 4.5-mile link to the Shell cracker plant in Potter will cross the Revolution pipeline close to the explosion site. Repeatedly, the company was put on notice for not following permit requirements or the company’s own state-approved plans for cleaning up and stabilizing the pipeline route, but regulators have stopped short of revoking Energy Transfer’s permits or instituting another permit ban on the company. The Revolution pipeline has been out of service since Sept. 10, 2018, when a portion of it slid down a steep, drenched hill in Center, Beaver County, ruptured and exploded. Although the Jan. 3 consent order and agreement between the Pennsylvania Department of Environmental Protection and Energy Transfer obligates the company to pay $20,000 for each day it is in violation of its conditions – and to remit these payments monthly – the DEP says it hasn’t received any money from the pipeline firm. The agency “has issued letters reminding ETC of its stipulated penalty obligations,” said DEP spokeswoman Lauren Fraley, but declined to provide those letters because they are the “subject of settlement discussions and are confidential.” “We do not agree with DEP’s position on these penalties,” Energy Transfer’s spokeswoman Alexis Daniel said last week. Energy Transfer also believes the DEP “is not in compliance with its own guidelines in the way it notes violations and is citing the same ‘violation’ multiple times (many of which have been self-reported to DEP by Energy Transfer), in essence double, or even triple reporting alleged violations, even in some instances where the issue has already been addressed,” she said.

Plum oil and gas waste well has a permit but no plans to open soon – The Pennsylvania Department of Environmental Protection has granted a permit for an oil and gas wastewater disposal well in Plum, but cratering oil prices and widespread economic disruption have made the controversial project uncertain.Delmont-based Penneco Environmental Solutions received approval from federal regulators in 2018 to operate the disposal well. Pennsylvania regulations required DEP to conduct a second review.The Sedat #3A well would be the first disposal well in Allegheny County and one of about a dozen permitted facilities in the state.Penneco Chief Operating Officer Ben Wallace said the company has no clear timeline for developing the facility.”Candidly, with the whole COVID shutdown and the collapse of oil prices yesterday and Appalachian production being questionable, we’re still trying to figure out what we do now that we finally got a permit,” he said on Tuesday.”All bets are off today, I can tell you that.”The benchmark price for U.S. crude oil fell to an unprecedented low of negative $37 a barrel on Monday, spreading shocks to other oil markets.The posted price for a barrel of Pennsylvania Grade Crude Oil was $0.20 on Monday, with lighter liquid hydrocarbon products from Marcellus and Utica wells priced between negative $38 and negative $58 a barrel.

CNX moving toward production maintenance in 2022 — CNX Resources has announced a first quarter 2020 net loss of $329 million or $1.76 per diluted share, Kallanish Energy reports. That compares to a 1Q 2019 net loss of $87 million or a loss of 44 cents per share, the Pennsylvania-based company said on Monday. It reported a goodwill non-cash impairment of $473 million for midstream operations and a $62 million impairment related to coalbed methane in southwest Pennsylvania. It reported net cash provided by operating activities of $267 million and capital expenditures in 1Q 2020 of $152 million. That compares to net cash provided by operating activities of $309 million and capital expenditures of $299 million in 1Q 2019. Consolidated free cash flow in the quarter was $129 million, an increase from $15 million in 1Q 2019. CNX, an active player in the Appalachian Basin, has reduced its 2020 projected production from 525 to 555 Bcfe to 490 to 530 Bcfe. It said it expects 2021 production to reach 550 Bcfe, perhaps 600 Bcfe if natural gas prices strengthen. The company said it expects to shift to a maintenance of production in 2022-2026 with capital expenses to average $270 million a year. It is planning to turn in-line 25 wells each year. Such a plan would leave its Marcellus Shale assets in southwest Pennsylvania and Utica Shale assets in Ohio available for future development, he said. It said it expects to produce free cash flow in each of those seven years, although production would not grow. In first quarter 2020, the company operated two rigs and drilled 10 wells in the Appalachian Basin. It currently has two rigs and one frack crew working.

Appalachian E&Ps’ shares soar on forecasted associated gas decline. — COVID-related demand destruction and the oil price meltdown have engulfed energy markets and companies in a thick, pervasive shroud of doom and gloom. But investors and analysts have hit upon a potential bright spot for one segment of the industry: Gas-Weighted E&Ps that had been battered by the decade-long shift of upstream capital investment to crude-focused resource plays. The massive cutbacks in 2020 capital investment by oil producers triggered by the recent, dramatic decline in refinery demand for crude will reduce not only oil output, but associated gas production as well. That drop in supply raises the prospect of meaningful increases in natural gas prices in 2021 – – hence Wall Street’s new interest in Gas-Weighted producers, whose equity values have taken off in recent weeks after a big plunge earlier this year. There’s a lingering concern though, namely that LNG exports – a key driver of gas demand for U.S. producers – may be slowed by collapsing gas prices in key international markets. Today, we discuss what’s been going on. Over the past few years, associated gas production from the Permian, Bakken, Eagle Ford and other basins drove total supply growth that outpaced record growth in U.S. natural gas demand. The resulting imbalance steadily eroded Henry Hub prompt gas futures pricing to a recent low in the mid-$1.50s/MMBtu – a level not seen since 1995. The impact on the publicly traded Gas-Weighted E&Ps we track was dramatic, with the share prices of producers such as Range Resources, Southwestern Energy and Antero Resources plunging more than 95% through first-quarter 2020, from their 2013-14 highs. However, since April 1, share prices of the eight significant U.S. Gas-Weighted E&Ps – all Appalachia-focused – have risen sharply, with six of them more than doubling in price over the three-week period.

U.S. court ruling could threaten pipeline projects with delays – (Reuters) – Several major U.S. oil and natural gas pipeline projects could be at risk of delays after a U.S. district judge in Montana this month said the Army Corps of Engineers had inappropriately used a national permit program, energy analysts said on Tuesday. Chief U.S. District Judge Brian Morris ruled on April 15 that the Army Corps violated federal law by issuing the so-called Nationwide Permit 12 that allows pipelines to cross water bodies because it did not adequately consult with other federal agencies on risks to endangered species and habitat. The ruling halted work on pipelines through streams and waterways, but allows other construction to continue. It’s the latest setback to TC Energy Corp’s plans to build the long-delayed Keystone XL crude pipeline to bring heavy Canadian oil from Alberta to the U.S. Midwest. But the decision could impact other projects that rely on the permit too, including the Atlantic Coast, Mountain Valley and Permian Highway projects, according to analysts. The U.S. Department of Justice and the Army Corps filed a motion on Monday to limit the scope of the order by May 11, but it is unclear if the motion is likely to succeed. “Left unchecked, this ruling could lead to delays on several pipeline projects,” Josh Price, an analyst at Height Capital Markets in Washington, said in a note to clients. Analysts at ClearView Energy Partners said “we think it may be unlikely that (Judge Morris) will reverse course … and narrow the applicability of his ruling.” Several pipeline companies said they were monitoring the case, but were continuing to work as normal on their projects in the meantime. “At this point, it is not stopping us from continuing our construction,” on the Permian Highway natural gas pipeline in Texas, said Katherine Hill, a spokeswoman for Kinder Morgan Inc. The pipeline is still expected to enter service in early 2021, she added. Natalie Cox, of Equitrans Midstream Corp, said the ruling had not changed the expected completion date of its Mountain Valley gas pipeline from West Virginia to Virginia.

US Delays Oil Pipeline Approvals After Environmental Ruling — (AP) – The U.S. Army Corps of Engineers has suspended a nationwide program used to approve oil and gas pipelines, power lines and other utility work, spurred by a court ruling that industry representatives warn could slow or halt numerous infrastructure projects over environmental concerns.The directive from Army Corps headquarters, detailed in emails obtained by The Associated Press, comes after a federal court last week threw out a blanket permit that companies and public utilities have used for decades to build projects across streams and wetlands.The Trump administration is expected to challenge the ruling in coming days. For now, officials have put on hold about 360 pending notifications to entities approving their use of the permit, Army Corps spokesman Doug Garman said Thursday.The agency did not provide further details on types of projects or their locations.Pipeline and electric utility industry representatives said the effects could be widespread if the suspension lasts, affecting both construction and maintenance on potentially thousands of projects. That includes major pipelines like TC Energy’s Keystone XL crude oil line from Canada to the U.S. Midwest, the Mountain Valley natural gas pipeline in Virginia and power lines from wind turbines and generating stations in many parts of the U.S. “The economic consequences to individual projects are hard to overstate,” said Ben Cowan, a Houston-based attorney with Locke Lord LLP who represents pipeline and wind energy companies. “It could be fatal to a number of projects under construction if they are forced to stop work for an extended period in order to obtain individual permits.”

DC Circuit grills FERC on use of tolling orders on Atlantic Sunrise pipeline, other natural gas projects – The U.S. Court of Appeals for the D.C. Circuit held an en banc hearing on Monday to examine federal energy regulators’ use of tolling orders, particularly regarding the approval of the Atlantic Sunrise Pipeline. All 11 judges analyzed a section of law that empowers the Federal Energy Regulatory Commission to indefinitely postpone litigation of its orders under the Natural Gas Act (NGA). An en banc hearing is rare in the D.C. Circuit, and indicates a majority of the court wants to take a second look at something inherently complex, according to Gillian Giannetti, an attorney with the Natural Resources Defense Council. NRDC submitted a friend-of-the-court brief to participate in Allegheny Defense Project v. FERC. The case revolves around the NGA and whether some parties are blocked from taking action on an order, like challenging it in court, while allowing construction of the contested project to be carried out. Proponents of tolling, including several pipeline developers that acted as intervenors on the case, say the practice gives FERC sufficient time to respond to complex rehearing requests. Tolling orders are an accessible tool for FERC to delay judgement on rehearing requests when more time is needed to consider arguments regarding the legality of the commission’s actions. FERC attorney Robert Kennedy said tolling orders are “generally entered almost as a matter of routine.” Petitioners argued that pipeline projects have been completed while opponents were unable to litigate because a tolling order was in place. “This case is exceptionally important because it brings to light a habitual practice by [FERC] that raises serious questions of fairness, due process and legality. And the commission’s defense in no way addressed how [a FERC order] can be final for some but not for others,” NRDC’s Giannetti told Utility Dive.

Judges Dissect Pipeline Review Process Called ‘Kafkaesque’ – Federal regulators could be forced to update their review process for pipeline challenges after judges scrutinized the fairness of a longstanding policy that often keeps opponents out of court while a company builds a project. The full slate of active judges from the U.S. Court of Appeals for the District of Columbia Circuit convened via teleconference Monday for a dispute over the Federal Energy Regulatory Commission’s use of “tolling orders” to lengthen the time the agency has to resolve complaints about pipeline approvals. The seemingly bureaucratic debate has sweeping on-the-ground implications for energy companies, landowners, and environmentalists. A ruling against FERC could require the agency to process challenges faster, giving project opponents a better chance of blocking construction in court. The 11-member court didn’t appear to reach clarity on the legal issues at play during more than three hours of arguments. Several judges seemed sympathetic to the notion that tolling orders result in unfairness, but questioned how an alternative process would work. Siobhan Cole, representing Pennsylvania landowners in the path of the Atlantic Sunrise gas pipeline, frequently returned to the same point: FERC shouldn’t be allowed to frame an order as final enough for developers to move forward with construction, but not final enough for opponents to go to court. The D.C. Circuit now has the opportunity to “right that wrong,” the White and Williams LLP attorney argued. “Would that cause practical problems for the commission and the way it operates, if you lived in that world?” Judge David S. Tatel asked FERC at one point, getting to the heart of some judges’ apparent apprehension about the case.

D.C. Circuit Hears Challenge to Unjust FERC Practice Used to Advance Construction of Unnecessary Atlantic Coast Pipeline | Southern Environmental Law Center – Today, the full U.S. Court of Appeals for the District of Columbia heard a challenge to a systematic practice by the Federal Energy Regulatory Commission that prevents landowners and communities from challenging FERC’s decisions in court before energy infrastructure projects get under way – including FERC’s approval of the Atlantic Coast Pipeline.In a rare telephonic argument before the full court, challengers to the Atlantic Sunrise gas pipeline project argued for an end to FERC’s practice of issuing “tolling orders,” which allows construction to begin – and, in some cases, allows entire pipelines to be completed – before court challenges to FERC’s approval can proceed. “FERC has stacked the deck for years in favor of pipeline developers, allowing them to clear-cut forests, trench through rivers, and construct polluting facilities before the communities in the pipeline’s path can even get into court,” said Southern Environmental Law Center senior attorney Mark Sabath. “The Atlantic Coast Pipeline is just one example of the environmental damage done while FERC keeps the courtroom doors shut.”In 2018, FERC used tolling orders to forestall court challenges to the Atlantic Coast Pipeline for eight months while allowing Dominion and Duke Energy to barrel forward with tree-clearing and construction that have permanently scarred land in West Virginia, Virginia and North Carolina.SELC submitted a friend-of-the-court brief in the case jointly with Earthjustice, the Natural Resources Defense Council, and the Chesapeake Bay Foundation. The brief highlights the staggering scope and regularity of FERC’s tolling practice and the significant, permanent harm that property owners, communities, and our lands suffer as a result.

House probe: Energy regulators almost always side with gas pipeline companies -A probe conducted by the House Oversight and Reform Committee has found that the Federal Energy Regulatory Commission (FERC) consistently sides with natural gas pipeline companies over property owners in certain land disputes. The committee found that in more than 99 percent of cases over the past 20 years, FERC has decided to give natural gas pipeline companies eminent domain; the move was approved 1,021 times and only rejected six times. Their investigation also determined that over the past 12 years, when landowners have sought to appeal FERC’s decision to give companies eminent domain over their property, in every case the commission has issued an order extending its time frame to respond. The appeals were ultimately denied every time. “The deck is totally stacked against landowners who want to defend their family’s land against takeover by private natural gas companies,” said a statement from Rep. Jamie Raskin (D-Md.), who heads the panel’s Subcommittee on Civil Rights and Civil Liberties. “FERC habitually delays its administrative duties to respond to landowner requests so long that those landowners have no opportunity to have their voices heard. By the time they have the chance to speak up, their land has already been invaded and in some cases destroyed,” he added. Rep. Chip Roy (Texas), the top Republican on the Civil Rights and Civil Liberties panel, said in a statement on the findings that “we should work to ensure appropriate protections are in place for individual landowners and are balanced with the public benefits of access to abundant, affordable natural gas.” The results of the investigation were released in a video report published Tuesday by the committee. In response, FERC Commissioner Neil Chatterjee said in a statement that the organization “considers natural gas pipeline applications consistent with the Natural Gas Act and longstanding court precedent.” “The Commission recognizes and is sympathetic to landowner concerns, and we are committed to improving our process. We have taken steps to do just that, with the goal of speeding up our consideration of requests for rehearing so that landowners can have their day in court more quickly,” Chatterjee added. FERC regulates interstate transmission of natural gas, oil and electricity as well as natural gas and hydropower projects.

Natural gas markets remain regionalized compared with oil markets –Crude oil markets respond quickly and often dramatically to world events, but natural gas markets have tended to be driven by regional factors and have been less connected to the international market.One indication of this difference between these markets is the correlation, or co-movement, of daily prices. The correlation of daily price movements between West Texas Intermediate (WTI) and Brent is typically higher than 0.90, indicating a strong positive relationship, but recent volatility in the spread between WTI and Brent has lowered the number for the year. In comparison, the daily returns for the international natural gas benchmarks U.S. Henry Hub, Asia’s Japan/Korea LNG (JKM), and the UK National Balancing Point (NBP) show little correlation. Comparing the crude oil benchmarks WTI and Brent to the international benchmarks for natural gas also shows little correlation at present, which is significant because natural gas contract prices were historically determined, at least in part, by the price of crude oil, and many current contracts still contain that link to varying degrees. Most crude oil is traded on short-term contracts based on spot prices, and refiners generally purchase crude oil for processing 90 days in advance. Although there are differences among crude oils, such as density and sulfur content, that help determine price differentials, some refiners (those that have more complex processing units) can switch between lighter and heavier crude oils when necessary. By comparison, the quality of natural gas is standardized as it enters the pipeline delivery system. Events that lead to crude oil shortages or surpluses in one region can quickly affect prices and can create arbitrage opportunities to move crude oil to and from other regions. Crude oil is primarily transported by tanker or pipeline.Natural gas is predominately transported through pipeline systems because of its gaseous state. When converted to liquefied natural gas (LNG) through cryogenic processing, natural gas can be shipped by tanker overseas. However, the liquefaction process is expensive, and LNG requires specially designed tankers to maintain cryogenic integrity (in other words, tankers that have tanks capable of limiting re-vaporization and product loss while in transit). Although the cost of transporting crude oil is usually a fraction of the crude oil cost, the cost of liquefying and transporting natural gas in the form of LNG can, in some cases, cost as much or more than input cost of the natural gas.

U.S. natgas futures fall on mild forecasts, lower demand and exports – (Reuters) – U.S. natural gas futures eased on Tuesday on long-term forecasts government lockdowns to stop the coronavirus spread will reduce domestic demand for the fuel and have already cut liquefied natural gas (LNG) and pipeline exports. Traders noted gas prices slipped despite a continued slowdown in output as drillers shut oil wells in shale basins due to the collapse in crude prices. Those oil wells also produce a lot of gas. On its last day as the front-month, gas futures for May delivery on the New York Mercantile Exchange fell 2.5 cents, or 1.%, to settle at $1.794 per million British thermal units (mmBtu). The June contract, which will soon be the front-month, gained about 3 cents to settle at $1.95 per mmBtu. Looking ahead, gas futures for the balance of 2020 and calendar 2021 were trading even higher than the front-month on expectations demand will jump as the economy snaps back once governments loosen travel and work restrictions. U.S. crude, meanwhile, remained on track to drop for a fourth week in a row, falling about 55% during that time. The U.S. Energy Information Administration (EIA) projected gas production will fall to an annual average of 91.7 billion cubic feet per day (bcfd) in 2020 and 87.5 bcfd in 2021 from a record 92.2 bcfd in 2019 as drillers shut wells and cut spending on new drilling. That would be the first annual production decline since 2016 and the first time output fell for two consecutive years since 2005. Data provider Refinitiv said gas output in the U.S. Lower 48 states averaged just 92.7 bcfd so far in April, down from an all-time monthly high of 95.3 bcfd in November. EIA projected coronavirus lockdowns will cut U.S. gas use – not including exports – to an average of 83.8 bcfd in 2020 and 81.2 bcfd in 2021 from a record 85.0 bcfd in 2019. That would be the first annual decline in consumption since 2017 and the first time demand falls for two consecutive years since 2006.

U.S. natgas futures jump to 10-week high as output slows – (Reuters) – U.S. natural gas futures rose to a 10-week high on Thursday as output slows because drillers are shutting oil wells in shale basins due to the recent collapse in crude prices. Those oil wells also produce a lot of gas. That price increase came despite a report showing an expected storage build last week, and forecasts that government lockdowns to fight the coronavirus will cut domestic demand and exports. The U.S. Energy Information Administration (EIA) said utilities injected 70 billion cubic feet (bcf) of gas into storage during the week ended April 24. That was in line with the 69-bcf build analysts estimated in a Reuters poll and compares with an increase of 114 bcf during the same week last year and a five-year (2015-19) average build of 74 bcf for the period. The increase for the week of April 24 boosted stockpiles to 2.210 trillion cubic feet (tcf), 19.5% above the five-year average of 1.850 tcf for this time of year. Front-month gas futures for June delivery on the New York Mercantile Exchange rose 8.0 cents, or 4.3%, to settle at $1.949 per million British thermal units, their highest since Feb. 19. For the month, the contract gained about 18% after falling around 37% over the prior five months. That is the biggest increase in a month since November 2018. Data provider Refinitiv said gas output in the U.S. Lower 48 states averaged 92.7 bcfd so far in April, down from 93.2 bcfd in March and an all-time monthly high of 95.4 bcfd in November. EIA projected coronavirus lockdowns will cut U.S. gas use – not including exports – to an average of 83.8 bcfd in 2020 and 81.2 bcfd in 2021 from a record 85.0 bcfd in 2019. With milder spring weather coming, Refinitiv projected demand in the Lower 48 states, including exports, would slide from an average of 86.2 bcfd this week to 85.0 bcfd next week. That compares with Refinitiv’s forecasts on Wednesday of 86.3 bcfd this week and 84.6 bcfd next week.

U.S. natgas futures fall from 10-week high as coronavirus cuts demand, exports – (Reuters) – U.S. natural gas futures fell on Friday from a 10-week high on forecasts for demand and exports to decline because of government lockdowns to stop the spread of the novel coronavirus. The declines occurred despite a continued drop in output as drillers shut oil wells in shale basins due to the collapse in crude prices. Those oil wells also produce a lot of gas. U.S. crude futures are down about 70% since the start of the year. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 5.9 cents, or 3.0%, to settle at $1.890 per million British thermal units. On Thursday, the front-month closed at its lowest since Feb. 19. For the week, however, the contract gained about 8% after falling less than 1% last week. Looking ahead, gas futures for the balance of 2020 and calendar 2021 were trading higher than the front-month on expectations demand will jump once governments loosen travel and work restrictions. The U.S. Energy Information Administration (EIA) projected gas production will fall to an annual average of 91.7 billion cubic feet per day in 2020 and 87.5 bcfd in 2021 from a record 92.2 bcfd in 2019 as drillers shut wells and cut spending. With many businesses shut due to the coronavirus and milder spring weather coming, Refinitiv projected demand in the Lower 48 states, including exports, would drop from an average of 86.4 bcfd this week to 79.5 bcfd next week before rising to 82.8 bcfd in two weeks. That compares with Refinitiv’s forecasts on Thursday of 86.2 bcfd this week and 85.0 bcfd next week. Even though the coronavirus is cutting gas use worldwide, EIA still expects U.S. exports to hit record highs in coming years as more liquefied natural gas (LNG) export plants and pipelines enter service. Still, the agency has reduced its projections on the pace of that growth due to the pandemic. Refinitiv said average U.S. pipeline exports to Canada fell to a six-month low of 2.4 bcfd in April, down from 2.8 bcfd in March and an all-time monthly high of 3.5 bcfd in December. Average pipeline exports to Mexico, meanwhile, fell to an 11-month low of 4.7 bcfd in April, down from a record 5.6 bcfd in March. U.S. LNG exports averaged a four-month low of 8.1 bcfd in April, according to Refinitiv, down from 8.3 bcfd in March and an all-time monthly high of 8.7 bcfd in February.

These oil and gas industry businesses plan to lay off hundreds in Louisiana, including in Broussard, New Iberia — Several businesses in the oil and gas industry across the state expect to lay off at least 600 workers collectively or have already sent out pink slips due the economic downturn and a glut of oil from reduced demand caused by the coronavirus pandemic. Two companies near Lafayette and one each in Baton Rouge and Bossier City filed layoff notification with the Louisiana Workforce Commission. The largest layoff is for 350 workers in three pipe fabrication facilities in Port Allen run by Turner Industries, based in Baton Rouge. The company has seen a decline in customer orders since the price of oil collapsed and the economy turned downward from the coronavirus pandemic. “We are continuing to watch for new work in the coming months and will be responding to the economy as it turns around,” said Stephen Toups, president of Turner Industries. “We believe these layoffs are temporary and have every intention to resume normal operations.” ASRC Energy Services Omega in New Iberia is closing its facility and laying off 180 workers starting in early June through August. “We would like to have given more notice of this action, but were unable to do so because of how quickly our operations were affected by the COVID-19 pandemic,” the company said in its letter to the state agency. The company did not respond to a request for comment. Ensco Offshore Co., which recently changed its name to Valaris, is laying off an undisclosed number of workers at its Broussard office, who are assigned to work offshore in the Gulf of Mexico. The company has seen customers suspend, defer and terminate drilling contracts due to the economic situation and low oil prices.

Restoring island where cleaned birds brought during BP spill –Louisiana is moving toward restoration of an island so low that high tides often drown the eggs and chicks of the pelicans and other birds that nest there.Bids will be opened Thursday for restoration of Rabbit Island, where hundreds of birds were released after being rescued from the BP oil spill and cleaned of the thick black gunk in 2010.Louisiana’s westernmost nesting site for colonial seabirds and wading birds isn’t a barrier island. Rather, it sits in a cove of Calcasieu Lake. It wasn’t affected by the spill, but is “the poster child for nest inundation,” said Jon J. Wiebe, project manager for the Louisiana Department of Wildlife and Fisheries.BP oil spill money is paying for the $27 million project, which is more than double the size of the recently completed restoration of Queen Bess Island. Pelicans and other birds already have built about 5,000 nests at Queen Bess, with the height of nesting season still to come – an encouraging success, said biologist Todd Baker of the Louisiana Department of Wildlife and Fisheries.Federal scientists estimated that the spill killed up to 102,000 birds gulf-wide, though later studies put the figure much higher. Anywhere from 12,700 to 27,600 pelicans were killed, according to the National Oceanic and Atmospheric Administration estimates.

Watch: Ocean Reefs Hidden Beneath Offshore Oil Rigs – The 2010 BP oil spill dumped more than 200 million gallons of crude oil into the Gulf of Mexico, where it killedbillions of fish. Had things gone as planned, that oil would have fueled cars and trucks, worsening climate change, which is going to kill billions of fish – and that was the best-case scenario. In short, oil is bad for sea life. Except sometimes it’s not. That’s because the legs and bracings holding up oil platforms are the ideal setting for ocean reefs. Fish like to gather around the pylons, which are covered in mussels, barnacles and corals. Emily Hazelwood, who worked as a field technician after the BP oil spill, recalled learning about the reefs firsthand.”BP had hired all the fishermen who lost their jobs to drive our boats,” she said. “Every time we would go out with them, and we would pass one of the many oil platforms, they would say they couldn’t wait to go out there fishing.”Experts say offshore oil will peak this year as prices fall, a trend exacerbated by the coronavirus and the ongoing price war between Saudi Arabia and Russia. The slump is expected to send a growing number of rigs offline.There is a real question as to what to do with the shuttered rigs, which can provide a safe home to ocean life. Oil platforms typically lie far from shore, so they are protected from the water pollution that empties into the ocean, Hazelwood said. They are safe from commercial fishing trawlers that gather up schools of fish out at sea. “Stretching from sea floor to sea surface, these platforms can be as large as the Empire State Building, which provides a lot of real estate for marine life,” Hazelwood said. “That richness of life on an oil platform is just so cool. I have never seen a group of fish like that before.”

Diamond Offshore Files for Bankruptcy— Diamond Offshore Drilling Inc., the rig contractor controlled by Loews Corp., filed for bankruptcy amid an unprecedented crash in crude prices that’s wrecking demand for oil exploration at sea. The company listed $5.8 billion of assets and $2.6 billion of debt in a Chapter 11 petition filed in Houston, citing year-end 2019 data. It has about $434.9 million of cash on hand, according to the document. Diamond owns rigs that can drill in water more than two miles deep. But offshore oil is among the most expensive to produce, putting the company at a disadvantage when prices plunged to less than $30 a barrel. While newer deepwater projects are less expensive, they still take longer to develop than shale wells and they still can’t compete on costs. What’s more, a global glut of offshore vessels has squeezed profit margins. Conditions worsened “precipitously in recent months,” the company said, citing a price war between OPEC and Russia and the Covid-19 pandemic. With cash running short, the Houston-based company led by Chief Executive Officer Marc Edwards skipped a semiannual interest payment due April 15 on some of its senior notes. Diamond Offshore adds to the more than 200 oilpatch bankruptcies dating from 2015, according to a tally by the Haynes & Boone law firm. About 2,500 jobs could be at stake at Diamond.

INTERIOR: Offshore drilling company lied to feds – IG — Wednesday, April 29, 2020 – The crew of an unnamed corporation manipulated results of a blowout preventer test on an offshore drilling platform in the Gulf of Mexico, according to an Interior Department inspector general investigation.

U.S. refinery earnings to detail troubled outlooks as fuel use slumps – (Reuters) – U.S. refiners are expected to report poor first-quarter results starting this week, but investors are more concerned about the outlook for coming months as various states ease movement restrictions designed to curb coronavirus infections. Fuel demand has dropped by roughly 25% in the United States and about 30% worldwide as the coronavirus pandemic has kept billions of people from traveling. U.S. refineries have throttled back production, operating at roughly two-thirds of capacity and global refineries have responded similarly to combat the steep drop in auto and jet fuel use. Most independent refiners are expected to report losses for the quarter, according to Refinitiv Eikon estimates. Valero Energy Corp, the largest U.S. independent refiner, kicks off U.S. refining earnings on Wednesday, followed by Phillips 66 on Friday and several others next week. That company is expected to lose 17 cents per share on revenue of $18.7 million, according to Eikon figures. The company warned two weeks ago that it could lose up to $2.1 billion for the quarter. The seven major independent refining companies, including Valero Energy Corp, Phillips 66, PBF Energy Inc and Marathon Petroleum Corp, are expected to lose, on average, 29 cents a share for the first quarter due to the drop-off in demand, according to Eikon data. Several companies have been cutting overall processing, but only Marathon has begun the process of idling U.S. plants, including its San Francisco-area refinery. Consultants and analysts expect more closures may be needed to rectify the imbalance of crude supply and product demand. April and May are expected to be substantially weaker than the first quarter, as fuel demand remained relatively strong until mid-March. “Refiners were doing alright for the first two months of the year, and then everything fell off of a cliff in March,” said refining analyst Matthew Blair at Tudor Pickering, Holt and Co. U.S. gasoline inventories have surged to a record and U.S. refiners are operating at about two-thirds of capacity. Roughly 85% of worldwide onshore storage was full as of last week, according to Kpler data. North American refiners and other downstream companies face higher credit risk. Inland refiners with less storage space, such as CVR Energy Inc , are also more exposed, according to Fitch Ratings, because they have less options for product offtake.

US Oil Producers Begin Storing Crude in SPR— U.S. oil producers running out of space for storage amid an unprecedented slump in demand have started making deliveries to the nation’s emergency stockpile. This month, 1.1 million barrels have been delivered into Strategic Petroleum Reserve storage. The Energy Department has finalized contracts announced earlier this month for companies to rent about 23 million barrels of capacity in the SPR, according to an official. On April 14, the department said it was negotiating leasing deals with nine producers, with most of the oil to be delivered in May and June, and possible early deliveries in April. It’s part of a plan by the Trump administration to help drain the nation’s growing glut of crude as commercial storage quickly fills up. The oil earmarked for storage under the program was to be aggregated from small, medium and large producers and companies can schedule return of their crude through March 2021, minus a small amount to cover storage costs.

Texas Oil Port Hit by One-Two Punch: Falling Demand and Overproduction – The New York Times – The expansion of the Port of Corpus Christi in the years leading up to the crisis produced new pipelines and distribution facilities, export terminals, liquefied natural gas plants, storage depots and refineries. Corpus Christi has turned into the largest energy exporter and third-largest port in the United States by tonnage. Last year, it handled 122.2 million metric tons of cargo, 60 percent of it exported oil. But April turned out to be a cruel month for the port’s fossil fuel-based business strategy. After the virus outbreak forced Americans into a lockdown, demand for fuel plummeted 40 percent, while prodigious production from Texas oil fields added to a global surplus. Oil prices, hit by the double whammy of falling demand and overproduction, have plunged nearly 80 percent since the start of year. Natural gas prices, under $2 per thousand cubic feet for months, are at their lowest level since before World War II. Global demand for natural gas has been steady: Corpus Christi still ships more than 25,000 tons of it a day. But the flow of oil through the port has started to slow. From his home office, Sean Strawbridge, the port’s chief executive, surveyed the severe market disruption and reached two conclusions. First, he said, construction projects that were underway would continue. Two of them make up almost half of the capital investment of the last four years. Cheniere Energy, a Houston-based company, is constructing a third production line to liquefy and export natural gas from its LNG processing plant that opened two years ago and has cost $16 billion, according to Industrial Info Resources, a consulting firm that tracks plant construction around the world. And Exxon and Sabic, its Saudi Arabian partner, started construction last year on a 1,100-acre site east of the port’s ship channel for a $10 billion chemical plant to turn natural gas liquids into polyethylene, a feedstock for plastics manufacturing. Second, said Mr. Strawbridge, Texas drilling rigs are shutting down, oil and gas production is diving, and industrial developers are nervous. “It’s a different time,” he said. “We fully anticipate a production slowdown. We’ve employed significant austerity measures.”

Texas energy regulators to vote on production curtailments in May 5 meeting – (Reuters) – Texas energy regulators will next week vote on a controversial proposal to reduce the state’s oil output after delaying it on concerns of legal challenges. The vote follows a motion submitted by Texas Railroad Commissioner Ryan Sitton, who has already been vocal about the need for curtailments to address historically low oil prices. Oil and gas companies have been gushing red ink and cutting tens of thousands of workers as prices tumble, prompting regulators in the largest U.S. oil-producing state to wade into global oil politics and consider some producers’ calls for cuts. Sitton’s motion calls here for curtailments of 20% of the state’s output and if agreed, curbs would remain in place until the Railroad Commission of Texas determines that global demand has crossed 85 million barrels of oil per day. The agency has a mandate under state law to “prevent waste of the state’s natural resources,” and some argue that the current oversupply of oil and price crash amounts to “economic waste.” “The presence of ‘waste’ has never been more evident,” said Parsley Energy Chief Executive Matt Gallagher, citing signs of a growing oil glut. “It is my hope that they take this opportunity to lead and vote” in favor of production curbs.” At a meeting last Tuesday, the day after U.S. crude prices crashed into negative territory for the first time, two of three commissioners opted not to make a decision but agreed to talk about output curbs again on May 5. Sitton had already said at that meeting he would vote in favor of cutting output by 1 million barrels per day, or 20%. “Taking weeks or even days right now to act is in itself a choice,” Sitton had said. However the vote was delayed because the other two commissioners, Chairman Wayne Christian and Christi Craddick, said they wanted the state attorney general to weigh in on the legality of production curbs.

Huge amounts of methane leaking from U.S. oil fields, study shows – Oil and gas operations in the Permian Basin, the largest oil-producing area in the United States, are spewing more than twice the amount of methane emissions into the atmosphere than previously thought – enough wasted energy to power 7 million households in Texas for a year. That’s the result of a new study by researchers at Harvard University and the Environmental Defense Fund. The Permian Basin stretches across a 250-mile by 250-mile area of West Texas and southeastern New Mexico, and accounts for over a third of the crude oil and 10% of the natural gas in the U.S. The study, published this week in the journal Science Advances, also found that the rate of leakage of methane gas makes up 3.7% of all the gas extracted in the basin, which is about 60% higher than the national average leakage rate. Methane is a potent greenhouse gas, and since the Permian Basin is so large, this excess waste is a significant contribution to our already warming climate. “These are the highest emissions ever measured from a major U.S. oil and gas basin,” said study co-author Dr. Steven Hamburg, chief scientist at the Environmental Defense Fund (EDF). Since 2005, the rapid increase in oil and natural gas production in the United States has been driven primarily by hydraulic fracturing (also known as fracking) and horizontal drilling. While some see the leaked methane gas as a big waste of natural resources, others are focused on the danger posed by methane. Methane is an extremely powerful heat-trapping greenhouse gas, much more potent than its more well-known counterpart, carbon dioxide (CO2). There is 225 times less methane in the atmosphere than there is CO2, but because of its powerful heat-trapping qualities, methane is contributing about 25% of the current rate of global warming.

PIPELINE EXPOSED: KXAN investigation uncovers safety concerns over pipes used in Kinder Morgan’s Permian Highway Pipeline | KXAN.com Investigative Summary: A tip led us to a storage yard holding hundreds of pipeline segments in Blanco. The segments will become the Permian Highway Pipeline. The group fighting the pipeline is concerned the anti-corrosion coating on the pipes has been outside, uncovered for far too long. Kinder Morgan – the pipeline owner – tells KXAN its handling of the pipeline construction will “meet or exceed state and federal requirements.” Our investigation found there are no regulations to determine how long is too long before UV radiation begins to degrade the pipe coating. Read Part Two: UV degradation inspections set for Permian Highway Pipeline stock yards

Permian natural gas forwards curve signals better days ahead. – The market’s spotlight in recent days has been on negative prices for both Permian crude oil and natural gas, but in the shadows a powerful rally has taken place in the forward market for Permian gas at the Waha hub. Much of this month’s price weakness for gas in West Texas has been driven by pipeline maintenance. But the Waha forward curve indicates market expectations for higher prices in May, and the possibility of a summer in which Permian gas prices could be some of the strongest on a consistent basis since negative pricing first appeared in the basin back in 2018. Today, we dive into the drivers behind the rise in forward Permian gas prices.It’s been even more challenging than usual lately to get a handle on crude oil and natural gas markets, as there have been huge differences between spot – or physical – prices traded on a daily basis, and futures prices for delivery of crude or gas months or even years from now. Last week, we discussed some of the reasons why these dislocations occur, first in One Way Out, where we detailed our view of the unprecedented negative prices that materialized in the crude oil market. Then, in Future(s) Games, we focused on crude oil pricing mechanisms, and inIt’s Always Somethin’, we zeroed in on the recent trend in spot prices for both Permian crude oil and natural gas. While we didn’t devote a full blog to explaining the differences between daily natural gas spot and futures prices in the Permian, the mechanisms are not that different from crude oil. While producers can develop numerous arrangements under which to sell their natural gas, the arrangements usually involve a combination of selling physical gas each day of the month in the daily market for next-day flow, and selling for the month-ahead at a monthly price set during the last five trading days of the previous month’s trading, a period known as bidweek.

Coronavirus has states hitting pause – except when it comes to oil and gas drilling – California Governor Gavin Newsom was elected after promising to tackle global warming and transition the state to clean energy, but last year journalists revealed that his administration was approving fracking permits at double the rate of the previous administration. Newsom soon announced a moratorium on the approval of fracking permits across the state. That pause remained in place into 2020 – until earlier this month, when the state was preoccupied with thousands of documented cases of the novel coronavirus and a statewide shutdown that Newsom ordered in response. Amid a global pandemic, the scientific panel tasked by Newsom with reviewing all pending fracking applications approved 24 new fracking permits in Kern County, the heart of California’s oil country and a major agricultural hub. The decision left environmental advocates baffled. In a region plagued by the kind of air pollution that public health experts are beginning to link to COVID-19 deaths, they questioned why California regulators would greenlight new fracking permits – especially since the state agency in charge of overseeing this process, California’s Geologic Energy Management division (CalGEM), is operating under a new mission to protect public health and safety. Ironically, just as fracking picks back up the state is also pausing efforts to develop tougher regulations to protect those who live or work near oil and natural gas wells – a part of Newsom’s broader initiative to pull back on drilling as the state works toward achieving carbon neutrality by 2045. While the coronavirus has seemingly put those loftier goals on hold, business as usual is resuming for the state’s fossil fuel interests. “I don’t think that there’s anyone – outside the industry – that thinks the prescription for COVID is expanding air pollution and public health threats,”

Oil producers scramble to find ‘creative’ storage options after historic price crash – An unprecedented collapse in oil demand has forced some producers to come up with “creative” measures in order to find places to store their crude, with one energy analyst describing the situation as like a “very elaborate game of hide-and-seek.” It comes as the coronavirus crisis continues to hit energy markets hard, with the world awash with oil and quickly running out of places to put it. As a result, U.S. West Texas Intermediate futures plunged below zero for the first time in history last week. Trading volume was thin given it was the day before the contract’s expiration date, but, nonetheless, the move lower was extraordinary. On Thursday, the June contract of WTI traded at $17.20 a barrel, up more than 14%, while international benchmark Brent crude stood at $24.63, around 9% higher. At the start of the year, WTI and Brent futures both fetched more than $60 a barrel. “The U.S. crude benchmark is quickly gaining pariah status within the commodity sphere due to storage anxieties,” Stephen Brennock, oil analyst at PVM Oil Associates, said in a research note published Wednesday. “Traders are dumping the June contract fearing a repeat of the May expiry should producers struggle again to find storage for their unwanted barrels.” What storage options are available? The global public health crisis caused by Covid-19 has created an extreme demand shock in energy markets, with storage space – both onshore and offshore – rapidly filling up. In the U.S., the country’s main delivery point in Cushing, Oklahoma is expected to reach maximum capacity by the end of May. Oil storage at the closely-watched Cushing hub rose by about 10% to reach 59.7 million barrels last week, according to data from the U.S. Energy Information Administration. That’s approximately 25 million barrels shy of its total working capacity. The Strategic Petroleum Reserve (SPR), the nation’s largest storage facility, has capacity for a whopping 713.5 million barrels of crude oil in its underground salt caverns along the Gulf Coast. But, as of mid-April, it already had 635 million barrels of crude stored, meaning it was 89% full. “As a result, while the SPR can be helpful here, it is not a panacea for the industry,” Stewart Glickman, energy equity analyst at CFRA, said in a research note to clients. The natural home for all crude oil is a refinery, but refiners must have places to store excess purchases of crude before they are processed. Many producers have opted to store their crude in floating tankers. Last week, Reuters reported there were 160 million barrels of crude oil in floating storage on the ocean via crude oil tankers. “The tankers have been hired, filled, and are simply floating around on the ocean, awaiting a recovery in demand,” Glickman explained, noting that the situation had also sent tanker rates “through the roof.”

The Next Chapter of the Oil Crisis: The Industry Shuts Down– Negative oil prices, ships dawdling at sea with unwanted cargoes, and traders getting creative about where to stash oil. The next chapter in the oil crisis is now inevitable: great swathes of the petroleum industry are about to start shutting down. The economic impact of the coronavirus has ripped through the oil industry in dramatic phases. First it destroyed demand as lockdowns shut factories and kept drivers at home. Then storage started filling up and traders resorted to ocean-going tankers to store crude in the hope of better prices ahead. Now shipping prices are surging to stratospheric levels as the industry runs out of tankers — a sign of just how distorted the market has become. The specter of production shut-downs — and the impact they will have on jobs, companies, their banks, and local economies — was one of the reasons that spurred world leaders to join forces to cut production in an orderly way. But as the scale of the crisis dwarfed their efforts, failing to stop prices diving below zero last week, shut-downs are now a reality. It’s the worst-case scenario for producers and refiners. “We are moving into the end-game,” “Early-to-mid May could be the peak. We are weeks, not months, away from it.” In theory, the first oil output cuts should have come from the OPEC+ alliance, which earlier this month agreed to reduce production from May 1. Yet after the catastrophic price plunge on Monday, when West Texas Intermediate fell to -$40 a barrel, it’s the U.S. shale patch that is leading. The best indicator of how the U.S. industry is reacting is the rapid drop in the number of oil rigs in operation, which last week fell to a four-year low. Before the coronavirus crisis hit, oil companies ran about 650 rigs in the U.S. By Friday, more than 40% of them had stopped working, with only 378 left. Trafigura, one of the largest exporters of U.S. crude from the U.S. Gulf of Mexico, believes that output in Texas, New Mexico, North Dakota and other states will now fall much faster than expected as companies react to negative prices, which have persisted for several days last week in the physical market. Until prices collapsed on Monday, the consensus was that output would drop by about 1.5m barrels a day by December. Now market watchers see that loss by late June. “The severity of the price pressure is likely to act as a catalyst for the immediate turndown in activity and shut-ins,” said Roger Diwan, oil analyst at consultant IHS Markit Ltd. The price shock has been particularly intense in the physical market: producers of crude streams such as South Texas Sour and Eastern Kansas Common had to pay more than $50 a barrel to offload their output last week. ConocoPhillips and shale producer Continental Resources Inc. have all announced plans to shut in output. Regulators in Oklahoma voted to allow oil drillers to shut wells without losing leases; New Mexico made a similar decision. North Dakota, which for years was synonymous with the U.S. shale revolution, is witnessing a rapid retrenchment. Oil producers have already closed more than 6,000 wells, curtailing about 405,000 barrels a day in production, or about 30% of the state’s total. The output cuts won’t be limited to the U.S. From Chad, a poor and landlocked country in Africa, to Vietnam and Brazil, producers are now either reducing output or making plans to do so.

Six US oil firms expected to shut 300,000 barrels per day of production in May and June – U.S. energy companies are taking an axe to their rig numbers, deepening production cuts for the industry that in the last few years made America the world’s number one oil producer. Six major U.S. shale producers are expected to shut some 300,000 barrels per day (bpd) of crude for the months of May and June, according to an analysis of the companies’ early communication by Rystad Energy. “Analyzing communication by Continental Resources, Cimarex Energy,ConocoPhillips, PDC Energy, Parsley Energy and Enerplus Corporation, we estimate that oil production cuts in May and June 2020 could amount to 300,000 bpd, an increase from about 100,000 bpd of cuts projected for April 2020,” Rystad wrote in a report Tuesday. In March, American producers were still pumping at record highs, according to the Energy Information Administration, even as prices plunged due to the loss of demand from the coronavirus pandemic. The latest weekly government data shows production at 12.2 million bpd in the third week of April, the lowest level since July and a stunning 900,000 bpd less than its record peak of 13.1 million bpd in early March. US oil needs more explicit support from policymakers: Standard Chartered Oklahoma-based Continental Resources is taking “the most drastic action thus far,” Rystad reported, forecasting a drop of 69,000 bpd from Continental in April and a cut of nearly 150,000 bpd in May and June. Houston, Texas-based ConocoPhillips has announced some 125,000 barrels of oil equivalent of gross output to be slashed in May, Rystad wrote, “estimated to amount to around 60,000 bpd of oil net to the company.” Artem Abramov, Rystad’s head of shale research, estimates a further production decline of “900,000 bpd, 250,000 bpd and 400,000 bpd in Permian, Eagle Ford and Bakken throughout 2Q20 respectively,” referring to the biggest shale formations in the U.S., with shut-ins accounting for 60% of that initially.When OPEC and non-OPEC producer countries including Russia, Canada, Norway and Brazil joined forces to implement a coordinated oil production cut to put a floor under prices – by a historic 9.7 million bpd from May 1 – the U.S. did not technically join, relying instead on market dynamics to force production down. That’s happening now, both in the form of companies shutting in their wells and cutting investment and projects for new wells. The industry hit its most glaring crisis point on April 20 when for the first time in history the price of oil dove below zero, and the May futures contract for U.S. oil benchmark West Texas Intermediate hit negative $40 per barrel as storage space disappeared and producers were literally paying buyers to take the oil off their hands. WTI’s price is currently down more than 75% year-to-date.

Halliburton lays off 233 employees in Kilgore, to move operations to Bossier City – Oilfield services giant Halliburton laid off 233 employees in Kilgore on Wednesday, and it plans to close the facility and move the operations to Bossier City, the company reported. Houston-based Halliburton on Wednesday notified the Texas Workforce Commission of the layoffs at the facility at 2906 FM 349, citing the “continued decline in customer activities,” with U.S. rig counts falling more than 30%. “At this time, it is expected that the facility will not remain open,” the company wrote. Affected employees will not have bumping rights, the letter to the Workforce Commission stated, indicating the workers will not be given preference if another job comes open in the company. Though the letter to the Texas Workforce Commission was dated Wednesday, the federal Worker Adjustment and Retraining Notification act requires companies planning to lay off 50 or more employees to give 60 days of notice. “This decision takes advantage of Halliburton’s real estate footprint and will increase operational efficiencies across the Haynesville Shale and adjacent oil and gas fields,” Halliburton spokeswoman Erin Fuchs said in a statement. “We recognize that this decision will be a hardship for impacted employees, but unfortunately, this was a necessary decision to right-size our organization to current market conditions,” she wrote. Halliburton also closed its Elmendorf facility south of San Antonio and is relocating the operations to field camps in Southern Texas, and it laid off 240 employees from a service center in Duncan, Oklahoma, The Associated Press reported. The number of employees laid off at Elmendorf was not immediately available. The closures and layoffs are blamed on the new coronavirus pandemic, which has cut global demand for oil and natural gas, marking a historic industry slump. Halliburton reported losing $1 billion during the first quarter and laying off 5,000 people. The company has laid off nearly 1,500 employees from Texas, Oklahoma, Colorado and Louisiana in April, filings and state officials show.

Colorado oil and gas downturn affecting economy, jobs – Colorado oil and gas experts are calling this economic situation the “worst they’ve ever seen” with a barrel of oil selling for less than it costs to make it. You won’t see any oil rigs in El Paso County, but our economy will feel the effects of production coming to a halt. Several of Colorado’s oil and gas companies are seeing layoffs and allowing their rigs to sit idle, all partly due to COVID-19. “It’s just one more kick when we’re already down,” said Mark Finley, the fellow in Energy and Global Oil at Rice University’s Baker Institute. He says the country’s oil rig count fell an unprecedented 45% in the span of six weeks. “Unprecedented shock in global oil demand and even with coordinated efforts to cut production there is too much supply and not enough demand,” Finley said. It’s forced companies to make massive layoffs in the state, affecting more than just those jobs. “Oil and gas jobs tend to be high paying jobs and they are jobs that come with other related spending on pipelines and rigs and capital equipment,” he said. Secretary of State Jena Griswold agrees on experiencing a decline in the demand for oil, something she says the coronavirus only made worse after a price war between Saudi Arabia and Russia. “The world is producing more than 30 million barrels of oil a day than we are consuming,” she said. “While the current situation is dire, how dire is going to depend on how long this pandemic continues,”

PANDEMIC: Here’s what an oil bailout could mean for emissions — A federal bailout of struggling oil firms is unlikely to alter the trajectory of carbon dioxide emissions, according to analysts, who say market factors dictate the pace of oil production over stimulus programs related to the coronavirus. Yet if the Trump administration seeks to rescue wobbly shale drillers, an idea floated by Treasury Secretary Steven Mnuchin in an interview with Bloomberg News last week, it could help shape the government’s wider response to the economic free fall caused by the pandemic. And that could have long-term implications for emissions. The Trump administration and Republican lawmakers have so far resisted suggestions to include funding for renewable energy or green infrastructure into federal recovery efforts. President Trump has repeatedly expressed support for aiding the oil industry, which has been clobbered by shrinking oil demand. Mnuchin said the administration will consider extending loans to struggling oil producers. Bloomberg reported that the proposed program would be run by the Federal Reserve, with the government possibly taking an equity stake in some firms. While an injection of federal cash could keep some firms out of bankruptcy court, it is unlikely to change the amount of crude being pumped from U.S. oil fields, analysts said. Demand for crude oil has plummeted as billions of people worldwide limit their movement. Rystad Energy, a Norwegian-based oil consultancy, estimates that American oil demand fell 30% to 14.1 million barrels per day in April. Oil producers have responded by filling up storage tanks around the world, but they are rapidly running out of space. Forecasters think storage tanks worldwide will be full by early May. At that point, well shut-ins will become inevitable. A federal intervention is a secondary factor in whether oil demand recovers. Far more important will be whether Americans decide to start driving and flying again. The idea of a bailout has generated divisions within the oil industry. Some players are wary of accepting government stipulations. Others argue that producers who took on mountains of debt and burned through cash in better times have no business receiving a lifeline from the government. “Propping up zombie E&PS is not a path to a healthier shale E&P industry,” Arjun Murti, a ConocoPhillips board member, tweeted on Friday with the hashtag #NoOilBailout. E&Ps is a reference to exploration and production firms. An oil bailout could be a political bargaining chip in stimulus negotiations to secure federal investments in clean energy. While a bailout for shale drillers is unlikely to change the industry’s emission trajectory, investments in infrastructure and electric vehicle support would green the economy. “The direct impact on emissions will generally be limited due to oil production – it’s economic demand for oil that will be the emissions driver,” Gilbert said.

Don’t Bail Out Oil and Gas — Use the Money for Environmental Cleanup Instead – Despite the evidence that the fossil fuel industry in the U.S. is not profitable and basically a giant money pit, President Trump tweeted last Tuesday that he has directed his cabinet to come up with a bailout plan for the floundering industry. The announcement came on the heels of a historic plunge in crude oil that sent prices deep into the red.Because of decreases in demand due to COVID-19 and a long history of being propped up solely by government funding, the fracking industry in the U.S. looks to be on the verge of collapse, with a huge wave of bankruptcies to come. As these fossil fuel companies go bankrupt or shutter completely, they shirk cleanup responsibilities – and the cost eventually falls on the taxpayer.Instead of bailing out the moribund oil and gas industry, environmental advocates say that the federal government should take a step toward transitioning away from fossil fuels and put money into cleaning up idling or abandoned oil and gas wells. These contaminated spots dot both public and private land as, through the decades, many oil and gas companies have left wells unfilled when the companies become insolvent. Regulatory agencies also allow companies to leave a well idle for years even if they have no intention to turn back to them, providing another avenue to avoid cleaning up. Across the country, there are millions of unplugged oil and gas wells waiting to be cleaned and sealed according to Environmental Protection Agency estimates. The numbers vary, since, due to lax regulation by the Bureau of Land Management (BLM) and other state regulators, there aren’t many records of how many of these wells exist or even where these wells are. In Pennsylvania, according to state officials, there are anywhere from 200,000 to 750,000 sites where the operator has gone bankrupt, leaving so-called orphan wells. As long as they remain unplugged, idling and orphan wells are an environmental hazard. They leak the potent greenhouse gas methane into the air and contaminate ground and surface water, posing risks to both wildlife and humans. “The [oil and gas] industry might view these apportioned and abandoned wells as benign,” said Nadia Steinzor, community empowerment project manager at Earthworks. But “the fact that they are, in many cases, literally falling apart, and are not being maintained or overseen is a serious environmental problem.”

Trump deciding on oil industry bailout as Saudi supertankers approach Gulf of Mexico – The White House’s scramble to contain an energy market crisis became harder on Monday, when U.S. crude oil prices plunged more than 20 percent, an oil services company declared bankruptcy, and a flotilla of about 20 Saudi Arabian supertankers continued their approach to the Gulf of Mexico. The timing and optics couldn’t be worse. With the U.S. oil industry running out of places to store production and consumption of auto, truck and jet fuel crippled by the novel coronavirus, the White House is under growing pressure from Republicans to address the falling oil prices and stop the Saudi tankers from unloading and adding to the oversupply. Citing falling oil prices and mounting job losses, Sen. Ted Cruz (R-Tex.) said in a recent tweet: “My message to the Saudis: TURN THE TANKERS THE HELL AROUND.” The price of U.S. benchmark West Texas Intermediate crude oil has fallen about 90 percent since the beginning of the year. Trump has for three years cheered the idea of low gasoline prices, but prices have now slumped so much that the dynamic risks causing mass layoffs in states such as Texas, Oklahoma and North Dakota. The U.S. economy is already reeling because of the coronavirus pandemic, and economic shocks caused by the oil crisis are making things worse. The United States routinely imports small amounts of Saudi oil, which helps U.S. refiners optimize their facilities for different grades of oil. But the new wave of tankers from the Saudi kingdom will arrive as President Trump is being pressed to do something to aid U.S. oil and gas companies and help navigate an oil glut caused by the coronavirus. Treasury Secretary Steven Mnuchin said on Sunday that the Trump administration is considering government loans to help out the industry, an extreme step to try to limit more economic damage. Markets, however, are moving faster than the administration. Not only did the price for June delivery drop to about $13, but the price of oil for as late as September also fell, a sign that traders lack confidence in a sharp recovery. Instead, investors are expecting the oversupply to increase, even though Russia and the Organization of the Petroleum Exporting Countries vowed to slash output by 9.7 million barrels a day after diplomatic intervention by Trump earlier this month.

‘Whack-a-mole stuff’: Trump’s oil rescue hits a slippery path – POLITICO – President Donald Trump and his advisers are offering a barrage of increasingly urgent ideas for propping up faltering oil producers – but people in the industry are skeptical that anything will come of it.The administration has so far jettisoned plans to buy oil for the nation’s Strategic Petroleum Reserve, nixed an idea to eliminate royalty payments for energy produced on federal lands and dropped a discussion of paying oil companies not to produce oil. The latest idea floated last week calls for the Treasury Department to create a fund to lend money to struggling oil producers – and take partial ownership stakes in the companies while requiring them to reduce their output.”This is whack-a-mole stuff,” said one oil industry official involved in the discussions, speaking on condition of anonymity to speak frankly about the administration’s efforts. “There is a huge interest to ‘do something’ to help. But it all sounds good until step two.”Like most parts of the economy, the oil industry has been hard hit by the coronavirus pandemic. The crash in oil prices that saw U.S. crude futures sink into negative territory last week for the first time in history rattled an industry that has weathered booms and busts for decades. Companies that had lifted U.S. oil production to record levels above 13 million barrels per day in recent months have slashed spending, laid off workers and shut down an estimated 900,000 barrels per day of output since the middle of March. But even market-driven production cuts in the U.S. and planned reductions by Saudi Arabia and Russia have failed to offset the global collapse in demand, as the spread of Covid-19 has shrunk consumption by an estimated 20 million to 30 million barrels per day.That has left the Trump administration scrambling to try to prop up a U.S. oil industry the president regularly praises for achieving global “energy dominance.” Two energy industry officials confirmed to POLITICO that the White House and Treasury Department have raised the idea of the government buying stakes in oil companies and forcing them to scale back production, which could push prices higher. Treasury Secretary Steven Mnuchin indicated on Friday that taking equity stakes in companies could be on the table.

Exxon loses $610 million in the first quarter on writedowns tied to plunging oil – Exxon Mobil on Friday reported its first loss in decades as oil prices plunged to historic lows following a drop-off in demand caused by the coronavirus. The oil giant lost $610 million in the first quarter due to $2.9 billion in write-downs tied to falling oil prices. Exxon posted a GAAP loss of 14 cents per share, and a non-GAAP profit of 53 cents per share. Revenue fell to $56.16 billion. In the same quarter a year earlier the company earned $2.35 billion, or 55 cents per share, on revenue of $63.63 billion. Shares of Exxon slipped slipped 7.2% on Friday. “COVID-19 has significantly impacted near-term demand, resulting in oversupplied markets and unprecedented pressure on commodity prices and margins,” CEO Darren Woods said in a statement. The company said that oil-equivalent production in the first quarter rose 2% year over year to 4 million barrels per day. Looking forward, however, Exxon plans to cut production by around 400,000 oil-equivalent barrels per day due to “economic shut-ins and market curtailments as [a] result of COVID-19.” West Texas Intermediate, the U.S. oil benchmark, has dropped more than 70% this year, which has forced energy companies to slash spending and in some cases, cut their dividend. But Exxon has said the company has no plans to cut its dividend, and on Wednesday, ahead of the earnings release, the company said it would maintain its dividend at 87 cents per share. In April, Exxon slashed its capital spending plan for 2020 by 30% from $33 billion to around $23 billion, and said it would cut operating expenses by roughly 15%. The company said the largest share of the reduction would be in the Permian Basin, where it’s easier to adjust short-cycle investments. .

Trump Poised to Unveil Bridge Loans for Ailing Oil Companies – – The Trump administration may announce as soon as Thursday a plan to offer loans to the ailing oil industry possibly in exchange for a financial stake, according to two people familiar with the matter. Treasury Secretary Steven Mnuchin and Energy Secretary Dan Brouillette have already briefed President Donald Trump on a plan to provide financial aid to oil drillers beset by a historic crash in prices, the people said. Brouillette, during a conference call Tuesday with an industry group, said Mnuchin was leaning toward aid that includes two separate programs — bridge loans and emergency lending authority through the U.S. Federal Reserve — designed to help smaller and medium sized companies.”This is not going to be a bailout,” Mnuchin told reporters in the White House Wednesday. He said a team at both the Treasury and the Energy department are talking with people around the world and are considering “a lot of different strategies.”Trump said an announcement would come “shortly.”The move comes as companies coping with a devastating plunge in prices have been laying off tens of thousands of workers and idling drilling rigs while asking for government assistance as they seek to stave off bankruptcies. Trump last week vowed to make funds available to oil and gas companies, saying he would “never let the great U.S. Oil & Gas Industry down.”Mnuchin said the administration was also exploring the opportunity to store another several hundred million barrels of oil, which would exceed the current physical capacity of the government’s Strategic Petroleum Reserve.The administration has been considering a way around that physical barrier, by buying undeveloped oil reserves and making them part of the U.S. emergency stockpile. Under the approach, the government would effectively pay some domestic drillers to halt production indefinitely — or at least until prices rebound.Trump earlier helped broker a deal by top international oil producers to pull nearly 10 million barrels of crude from the market. Yet demand has collapsed by at least twice that amount and storage tanks will keep filling with crude as long as coronavirus restrictions keep planes grounded and drivers off the roads.If the federal government steps in, some forms of lending would involve it taking a stake in the companies — a condition oil companies are likely loathe to accept, according to the two people familiar with the discussions. The Trump administration has been working to identify oil companies that would be eligible for loans under the existing Main Street program without being forced to establish a new industry-focused initiative that could be unpopular with the public, said a person familiar with the matter who, like the other people, asked not to be named detailing private deliberations.

Fed Changes Open Door for More Drillers to Get Loans – The Federal Reserve revamped its Main Street Lending Program in ways that will allow battered oil companies to qualify for the aid after industry allies lobbied the Trump administration for changes.Larger, more heavily indebted companies can now qualify and use the money to pay off prior loans under the changes the central bank announced Thursday.The move opens the door to more oil and gas producers, said Senator Kevin Cramer, a Republican from North Dakota, who had pressed the administration on the issue as energy companies struggle to survive an epic collapse in fuel demand and crude prices. “With the decrease in demand and oversupply due to the global oil price war creating a valley for these highly leveraged companies, this expansion will help them bridge the gap as we look to reopen America,” Cramer said in an emailed statement Thursday.Environmentalists blasted the shifts they said rewarded oil companies that took on too much debt and were overproducing crude even before the coronavirus pandemic caused demand to plunge.”These changes directly reflect demands from polluters and their favorite members of Congress,” said Lukas Ross with the environmental groupFriends of the Earth. “Long before the coronavirus, the drillers were in deep trouble. Now frackers want to pay back their debts with our money. Trump’s big oil bailout must be stopped.” For weeks, oil industry advocates have warned the original program structure would prevent beleaguered drillers from accessing capital under the program.Senator Ted Cruz, a Texas Republican, and the Independent Petroleum Association of America argued oil companies needed more flexibility to useMain Street loans to repay existing debt — something that was previously off limits but will now be allowed under some conditions.Maximum loan totals under the Main Street program are also being hiked to$200 million — from an earlier $150 million cap viewed as too low to help oil producers.”Great news out of the Fed today in support of struggling U.S. energy companies,” Energy Secretary Dan Brouillette said in a tweet Thursday. He added that he would “continue” his work with Treasury Secretary Steven Mnuchin to provide “other relief” to the industry.The Fed said the changes were not targeted to the oil and gas industry or any industry in particular but followed additional research into what slice of U.S. companies don’t have ready access to capital markets.Nevertheless, the new terms are likely to open it up to a wider group of energy firms, and overseers worried the Fed was bending to pressure.”The major changes announced today mirror the top requests of the oil and gas industry,” said Bharat Ramamurti, a member of the congressional panel appointed to scrutinize implementation of the Fed’s and part of the Treasury’s virus-relief programs. “That raises questions about how the changes promote the broader public interest — especially when these companies will still have no real obligation to retain or rehire their workers,” Ramamurti said on Twitter.

Oilfield Services Headcount Continues to Shrink – The effects of the coronavirus outbreak and volatile oil markets are forcing many companies to continue with headcount reductions and facility closures. Cameron Drilling recently announced plans to permanently close its entire plant facility at 2101 S. Broadway Avenue, Moore, OK 73160. Approximately 74 employees will be separated from employment, with 59 separations occurring during the 14-day period beginning June 23, 2020, and an additional 15 occurring during the 14-day period beginning July 20, 2020. The employee separations are expected to be permanent. “We are trying our best to retain and transfer as many employees as possible,” the company stated in an April 15 notice to the Texas Workforce Commission. “The speed and vast reach of the coronavirus outbreak, as well as the declaration of a national emergency, and national directives for individuals to avoid congregating, limit travel and to work remotely was unforeseeable and caused, and will continue to cause, among other things, a drastic impact on our business,” the company said in a written statement. Meanwhile, Midland, Texas-based ProPetro also launched a mass layoff at its Hydraulic Fracturing Operations facility at 2518 FM 307 and its Coil Tubing Operations facility at #4 Industrial Loop in Midland on April 16. Approximately 18 employees were impacted at the Coil Tubing Facility while 566 were affected at the Hydraulic Fracturing Facility. The separations are permanent, according to the company. Separately, in Houston Diamond Offshore Drilling reported a mass layoff at its corporate office at 15415 Katy Freeway, Houston, TX 77094 on April 15. About 102 employees will be impacted. The separations began on the date of the notice and are expected to be accomplished by April 28, 2020.

North Dakota regulators to decide if producing oil at low prices is ‘waste’ – – North Dakota regulators will hear testimony May 20 on whether oil production at current low prices amounts to wasting natural resources, potentially setting the stage for output restrictions, like those under consideration in Texas and Oklahoma. The state’s active rig count has plummeted in recent weeks in response to the global oil price crash. In March, North Dakota implemented a waiver program allowing oil and natural gas drillers to keep wells in non-completed or inactive status longer than regulations typically allow. The policy was designed to prevent producers from either bringing more unwanted crude onto the market or being forced to abandon wells completely. Ahead of the May 20 hearing, the North Dakota Industrial Commission asked industry to weigh in on a wide range of oil market issues, including price volatility, oversupply amid reduced demand for North Dakota oil, hedged production, impacts on royalty owners when oil prices turn negative, and the challenges of curbing or shutting in production from North Dakota wells. Written comments are due to the commission’s oil and gas division by May 15. During the hearing, speakers will be able to testify by phone for 15 minutes each. North Dakota lost about 40% of its drilling rigs over the course of three weeks in March as the impact of low global oil prices and plunging demand started to be felt in one of the top US oil production regions. The state has 31 active drilling rigs as of Wednesday, according to the Department of Mineral Resources. The rig count has plunged from 55 in January, 54 in February, and 52 at the start of March. North Dakota regulators expect the state’s rig count to fall to the mid- to high 20s, in line with the 27 rigs seen during the 2015 price collapse, DMR Director Lynn Helms told reporters April 14. About 175,000 b/d of production was shut-in during March at 3,600 wells, Helms said. Another 1,000 wells were shut-in as of mid-April, bringing the state’s shut-in production to 260,000 b/d. North Dakota producers also face shrinking oil storage capacity, which Helms said was “nearly full and looks like it could be full by June.”

Hamm’s Continental Sued Over Failed $200MM Oil Deal— Continental Resources Inc. is being sued by a closely held oil driller that accused the shale giant of walking away from a $200 million deal following an historic collapse in crude prices. Casillas Petroleum Resource Partners and Continental signed a so-called purchase and sale agreement on March 6, according to the lawsuit, one trading session before crude tumbled about $10 a barrel for the worst daily crash in almost 20 years. “Almost immediately after the execution” of the contract, Continental sought to delay the closing that was set for the end of March, Casillas said in the suit filed in Tulsa County District Court in Oklahoma. On March 24, Casillas said Continental sent a letter attempting to terminate the deal, citing issues that included alleged wastewater incidents. Casillas said it faces “irreparable harm” if Continental doesn’t hold up its end of the original agreement. A representative for Continental didn’t immediately respond to a request for comment. Reuters first reported the lawsuit. It’s the latest example of an oil and gas deal running into snags amid the unprecedented plunge in crude prices. BP Plc was forced to renegotiate the terms of a sale of its Alaska business to Hilcorp Energy Co., and Devon Energy Corp. had to revise its sale of North Texas shale assets to Banpu Kalnin Ventures LLC.

US seeks return of wetlands permit nixed in pipeline case (AP) – U.S. government attorneys on Monday sought to put on hold a recent court ruling that canceled a permitting program used to approve oil and gas pipelines and other utility work through wetlands and streams across the nation. The attorneys said letting the April 15 ruling stand would hamper thousands of construction projects overseen by the U.S. Army Corps of Engineers. U.S. District Judge Brian Morris in Great Falls declared the permitting program, known as Nationwide Permit 12, had been reauthorized in 2017 without sufficient consideration of its potential environmental harm. That prompted Army Corps officials last week to suspend the program. The case before Morris involved the disputed Keystone XL crude oil pipeline from Canada. But pipeline and electric utility industry representatives said it could affect both construction and maintenance on potentially thousands of projects. That includes major pipelines like the Mountain Valley natural gas pipeline in Virginia and power lines from wind turbines and generating stations in many parts of the U.S. The Army Corps has broad jurisdiction over U.S. waterways. It uses the blanket permit to approve qualifying pipelines and other utility projects after only minimal environmental review. Environmentalists say that allows projects to skirt water protection laws and ignores the cumulative harm caused by thousands of stream and wetlands crossings. U.S. Justice Department attorneys argued in a court filing that Morris had overstepped by applying his ruling not just to Keystone but to the entire program. “The Court has eliminated Nationwide Permit 12 for use by any utility line project anywhere in the country, which has extraordinary and immediate implications for numerous projects,” the attorneys wrote. Since the blanket permit was renewed three years ago it has been used more than 37,000 times, according to federal officials.

PIPELINES: Judge rejects Army Corps’ bid to resume permitting — Thursday, April 30, 2020 — A federal court this week declined to immediately halt an order blocking the Army Corps of Engineers from authorizing national water permits for power line and pipeline projects that cross federally protected waters.

US Marine Service Official Reveals the Future of Oil Tankers Stranded Off California Coast – – Late last week, US media reported that drone footage released on 23 April by the American Coast Guard showed a total of 27 large oil tankers floating off the coast of southern California. The vessels had reportedly been turned into storage tanks while waiting to dock at ports.Several oil tankers currently floating off the coast of California are due to depart in the next few days, while most of the vessels may stay there indefinitely, Captain J. Kip Louttit, executive director of the Marine Exchange of Southern California, said on Wednesday.“There are 20 tankers [in the area], and 14 of them are expected to remain there indefinitely or for a long time; six tankers should leave within the next five days”, he pointed out.Louttit added that five more tankers are expected to arrive this week, and that four of them are set to unload their cargo while one such vessel will anchor for a long time. “So we have a mixture of those [tankers] which anchor or get unloaded, depending on which company they belong to”, he said, referring to a total of 28 vessels, including five cruise liners, that are currently in his area of responsibility.The remarks come a few days after The Los Angeles Times reported that drone footage released on 23 April by the US Coast Guard showed a total of 27 large oil tankers floating off the coast of southern California. The tankers, which were reportedly turned into storage tanks, could be seen anchored at a safe distance from each other near the ports of Los Angeles and Long Beach. Commander Marshall Newberry, from Coast Guard Sector Los Angeles and Long Beach, said in a statement late last week that “due to the unique nature of this situation, the US Coast Guard is constantly evaluating and adapting our procedures to ensure the safety of the vessels at anchor and the protection of the surrounding environment [ … ]”.He spoke after Reuters cited unnamed shipping industry sources as saying that about160 million barrels of oil are currently being stored in large tankers outside shipping ports due to a lack of onshore storage space.Since very large crude carriers (VLCCs) were chartered to store oil at sea in February, the number has increased to 60, and is forecast to triple in the upcoming months. The VLCCs are reportedly mostly located near Singapore and in the US Gulf Coast.The current oversupply, which has already reached around 9 million barrels per day, was triggered by a drop in global oil demand, as a result of the ongoing coronavirus pandemic.The glut fueled unprecedented trading on 20 April, when the price for May oil contracts plummeted below zero, breaking every low for crude prices since 1946. Earlier this month, Saudi Arabia, Russia, and other petroleum-exporting nations within OPEC+ agreed to slash their oil production by 9.7 million barrels per day through June, in a bid to remove some of the oversupply from the market.

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