oil prices rose for a second week as US oil producers curtailed production and states began to loosen restrictions on travel that had been imposed in the wake of the coronavirus pandemic...after rising 17% to $19.78 a barrel last week as OPEC's production cuts kicked in and fears of negative oil prices faded, the contract price of US light sweet crude for June delivery reversed early steep losses and moved higher on Monday as optimism for a demand recovery offset concern over a spat that broke out between the United States and China over the origin of the virus and finished trading 61 cents higher at $20.39 a barrel...prices continued climbing early Tuesday as prospects for rising demand increased as lockdowns began to ease and then surged in late trading as optimism around ongoing production cuts and the reopening of economies around the world pushed prices higher and finished with an increase of $4.17, or more than 20%, at $24.56 barrel, and then extended those gains in after-hours trading despite industry data showing a larger-than-forecast weekly build in U.S. crude inventories, as the report also showed a surprisingly large drop in gasoline supplies...oil prices opened higher but edged down early Wednesday on that increase in US crude inventories, but rebounded after the EIA's data showed both production cuts and a smaller crude build and then rose to as high as $26.08 a barrel before turning lower in profit taking to finish at $23.99 a barrel, a loss of 57 cents on the day...oil prices again opened higher and rose to as high as $26.76 on Thursday, but again turned negative in afternoon trading as optimism that had previously supported prices began to fade, and US crude ended the session down 44 cents at $23.55 a barrel after downbeat comments from Federal Reserve officials and on doubts over producer compliance with the OPEC+ output-cut agreement....after opening lower on Friday, oil prices turned higher after U.S. producers shut-in more crude production and more states announced plans to relax the lockdowns that had destroyed demand, with the benchmark US crude closing $1.19 or 5% higher at $24.74 a barrel...oil prices thus finished the week 25% above those of the prior Friday, largely on optimism over production cuts and rising demand that had yet to materialize...
natural gas prices, on the other hand, finished lower for a second week on ongoing coronavirus demand destruction and rising supplies...after ending last week down less than 1% at $1.890 per mmBTU as concerns over falling demand outweighed prospects for lower supplies, the contract price of natural gas for June delivery opened 4% higher and rose to a gain of 10.3 cents on Monday, as a sustained drop in production and forecasts for another shot of winter-like temperatures fueled the increase...prices then jumped 14.1 cents to a 16 week high of $2.134 per mmBTU on Tuesday after a gas pipeline explosion in Kentucky shut down a section of the Texas Eastern pipeline, cutting off over 1 billion cubic feet per day of gas flows from the Marcellus Shale to the Gulf Coast...but natural gas prices reversed that gain when they tumbled 19 cents on Wednesday on forecasts for lower than expected demand next week and longer-term projections that businesses would use less of the fuel and that exports would drop in coming months on coronavirus related curtailments...a triple digit injection of natural gas into storage hit prices Thursday, and they fell back another 5 cents to $1.894 per mmBTU...gas prices then fell another 4% on Friday on forecasts for lower demand in mid-May due to milder weather while commercial demand was expected to remain low and ended the week at $1.823 per mmBTU, down 3.5% on the week even as three Enbridge pipeline segments remained shut down after the Tuesday explosion...
the natural gas storage report from the EIA for the week ending May 1st indicated that the quantity of natural gas held in underground storage in the US rose by 109 billion cubic feet to 2,319 billion cubic feet by the end of the week, which left our gas supplies 796 billion cubic feet, or 52.3% higher than the 1,523 billion cubic feet that was in storage on May 1st of last year, and 395 billion cubic feet, or 20.5% above the five-year average of 1,924 billion cubic feet of natural gas that has been in storage as of the 1st of May in recent years....the 109 billion cubic feet that were added to US natural gas storage this week was a bit higher than the consensus forecast for a 105 billion cubic feet increase from a survey of analysts by S&P Global Platts, and quite a bit above 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 also above the 96 billion cubic feet addition of natural gas to storage during the corresponding week of 2019...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending May 1st indicated that a large increase in our oil imports offset the increases in our exports and our oil refining to again leave a substantial surplus of oil to be added to our stored commercial supplies, the fifteenth consecutive increase and the twenty-sixth addition of oil to storage in the past thirty-four weeks...our imports of crude oil rose by an average of 410,000 barrels per day to an average of 5,712,000 barrels per day, after rising by an average of 365,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 244,000 barrels per day to an average of 3,546,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,166,000 barrels of per day during the week ending May 1st, 166,000 more barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells fell by 200,000 barrels per day to 11.900,000 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 14,066,000 barrels per day during this reporting week..
meanwhile, US oil refineries reported they were processing 12,976,000 barrels of crude per day during the week ending May 1st, 216,000 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 901,000 barrels of oil per day were being added to the supplies of oil stored in the US....so from 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 189,000 barrels per day more 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 (-189,000) 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 5,408,000 barrels per day last week, now 20.6% less than the 6,812,000 barrel per day average that we were importing over the same four-week period last year....the 901,000 barrel per day addition to our total crude inventories included 656,000 barrels per day that were added to our commercially available stocks of crude oil, and 245,000 barrels per day that were added to our Strategic Petroleum Reserve....this week's crude oil production was reported to be down by 200,000 barrels per day to 11,900,000 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 11,500,000 barrels per day, while a 23,000 barrel per day decrease in Alaska's oil production to 443,000 barrels per day was enough to cause the subtraction of another 100,000 barrels per day from the rounded national total....last year's US crude oil production for the week ending May 3rd was rounded to 12,200,000 barrels per day, so this reporting week's rounded oil production figure was 2.5% below that of a year ago, yet still 41.2% 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 70.5% of their capacity in using 12,976,000 barrels of crude per day during the week ending May 1st, up from 69.6% of capacity during the prior week, but still among the lowest refinery utilization rates of the last dozen years...hence, the 12,976,000 barrels per day of oil that were refined this week still 20.9% fewer barrels than the 16,405,000 barrels of crude that were being processed daily during the week ending May 3rd, 2019, when US refineries were operating at a seasonally weak 88.9% of capacity....
even with the increase in the amount of oil being refined, gasoline output from our refineries was a bit lower, decreasing by 30,000 barrels per day to 6,705,000 barrels per day during the week ending May 1st, after our refineries' gasoline output had increased by 530,000 barrels per day over the prior week....but since the recent increases have been coming off a 22 year low in gasoline output, our gasoline production this week was still 33.8% lower than the 10,129,000 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) increased by 100,000 barrels per day to 5,082,000 barrels per day, after our distillates output had decreased by 25,000 barrels per day over the prior week...and after this week's increase in distillates output, our distillates' production for the week was just a fraction less than the 5,089,000 barrels of distillates per day that were being produced during the week ending May 3rd, 2019....
with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 2nd time in 5 weeks and for the 10th time in 14 weeks, falling by 3,158,000 barrels to 256,407,000 barrels during the week ending May 1st, after our gasoline supplies had decreased by 3,669,000 barrels over the prior week...our gasoline supplies decreased again this week because the amount of gasoline supplied to US markets increased by 804,000 barrels per day to 6,664,000 barrels per day, even as our exports of gasoline fell by 373,000 barrels per day to 532,000 barrels per day while our imports of gasoline rose by 140,000 barrels per day to 368,000 barrels per day....and even after this week's inventory decrease, our gasoline supplies were still 14.5% higher than last May 3rd's gasoline inventories of 226,743,000 barrels, and roughly 9% above the five year average of our gasoline supplies for this time of the year...
with the increase in our distillates production, our supplies of distillate fuels increased for the fifth time in 16 weeks and for the 10th time in 31 weeks, and by the most since January 4th, 2019, rising by 9,518,000 barrels to 151,490,000 barrels during the week ending May 1st, after our distillates supplies had increased by 5,092,000 barrels over the prior week....our distillates supplies rose by more this week because our exports of distillates fell by 397,000 barrels per day to 929,000 barrels per day while our imports of distillates rose by 101,000 barrels per day to 336,000 barrels per day, while the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 35,000 barrels per day to 3,129,000 barrels per day....after this week's big inventory increase, our distillate supplies at the end of the week were 20.6% above the 125,563,000 barrels of distillates that we had stored on May 3rd, 2019, and about 12% above the five year average of distillates stocks for this time of the year...
finally, with higher oil exports and a modest increase in oil refining being mostly offset by higher oil imports, our commercial supplies of crude oil in storage rose for the twenty-seventh time in forty-four weeks and for the thirty-fourth time in the past 52 weeks, increasing by 4,590,000 barrels, from 527,631,000 barrels on April 24th to 532,221,000 barrels on May 1st...after 15 straight increases and three record increases over past 5 weeks, our crude oil inventories are now 12% above the five-year average of crude oil supplies for this time of year, and 49.2% higher than the prior 5 year (2010 - 2014) average of crude oil stocks as of the first of May, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first rose above 400 million barrels, and continued rising from there....since our crude oil inventories have generally been rising over the past year and a half, except for during this past summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of May 1st were 14.1% above the 466,604,000 barrels of oil we had in commercial storage on May 3rd of 2019, and 22.7% above the 435,955,000 barrels of oil that we had in storage on May 4th of 2018, 1.9% above the 522,525,000 barrels of oil we had in commercial storage on May 5th of 2017... and if we take the total of our commercial oil supplies and the stores of all the refined product made from oil, we find those supplies are now at a record high of 1,395,429,000 barrels, 11.6% more than the 1,249,867,000 barrel total of a year ago...
This Week's Rig Count
the US rig count fell for the 9th week in a row during the week ending May 8th, and is now down by 52.8% over that nine week period....Baker Hughes reported that the total count of rotary rigs running in the US decreased by 34 rigs to 374 rigs this past week, which was the fewest rigs deployed in Baker Hughes records going back to 1940, down by 614 rigs from the 988 rigs that were in use as of the May 10th report of 2019, and 1,555 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business....
the number of rigs drilling for oil decreased by 33 rigs to 292 oil rigs this week, after falling by 57 oil rigs the prior week, leaving oil rig activity at its lowest since September 11, 2009, which was also 513 fewer oil rigs than were running a year ago, and less than 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 1 to 80 natural gas rigs, the fewest natural gas rigs active in 80 years of Baker Hughes records, down by 103 natural gas rigs from the 183 natural gas rigs that were drilling a year ago, and just a twentieth of modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, two rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, and one in Lake County, California... a year ago, there were no such "miscellaneous" rigs deployed..
the Gulf of Mexico rig count was down by one rig to 15 rigs this week, with all of those Gulf rigs drilling for oil in Louisiana's offshore waters...that's five 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 36 rigs to 338 horizontal rigs this week, which was the fewest horizontal rigs active since July 1st, 2016, and hence is a 46 month low for horizontal drilling...it was also 534 fewer horizontal rigs than the 872 horizontal rigs that were in use in the US on May 10th of last year, and down by more than a thousand from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, the vertical rig count was down by 2 to 9 vertical rigs this week, and those were down by 36 from the 45 vertical rigs that were operating during the same week of last year....on the other hand, the directional rig count increased by 4 to leave 27 directional rigs running this week, but those were still down by 44 from the 71 directional rigs that were in use on May 10th 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 8th, the second column shows the change in the number of working rigs between last week's count (May 1st) and this week's (May 8th) count, the third column shows last week's May 1st 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 10th of May, 2019...
this weeks basin totals show a decrease of 32 rigs, once again short of the 36 horizontal rigs removed nationally this week, thus indicating that 4 horizontal rigs were also shut down in basins not tracked separately by Baker Hughes and hence not shown above...at first glance, it appears they might have been in Texas, since the other state's totals balance with the listed basin counts...so first checking the rig losses in the Texas part of Permian basin, we find that 23 rigs were pulled out of Texas Oil District 8, or the core Permian Delaware, and 2 more rigs were removed from Texas Oil District 7C, or the southern Permian Midland, and hence the Permian in Texas saw a total reduction of 25 rigs...since the overall Permian rig total was only down by 21 rigs, that means that the 4 rigs that were added in New Mexico must have been set up to drill in the western Permian Delaware, to bring the national Permian reduction back down to 21 rigs...elsewhere in Texas, 1 rig was pulled out of Texas Oil District 1, 1 rig was pulled from Texas Oil District 2, and 1 rig was pulled out of Texas Oil District 4, which together would account for the 3 rig reduction in Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and thus touches on 4 Oil Districts...meanwhile, the 6 rigs that were pulled out of North Dakota had all been drilling in the Williston basin, home of the Bakken shale, and the rig removed from the Ardmore Woodford accounts for one of the two rigs pulled out of Oklahoma....elsewhere, the only rig pulled out of Louisiana was the oil rig that had been drilling in the Gulf, while the Utica shale rig pulled out of Ohio was the only natural gas rig change anywhere nationally this week...
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Residents concerned about wastewater permit -The public comment period is set to end Wednesday on a permit for a docking facility at Deep Rock Disposal Solutions. The docking facility, which would be located just south of Marietta on Ohio 7, is where local residents are concerned fracking wastewater will be offloaded. “(We) are very concerned about the health hazards of his proposed facility, the lack of attention to this issue publicly, and the timing of the public comment period – to end May 6,” Devola resident George Banziger said. “It seems that the intention is to offer the comment period just when everyone is consumed with news about the coronavirus.” Dawn Hewitt of Marietta said the notice was published on the Huntington District, U.S. Army Corps of Engineers’ website. It requests the authorization to operate a barge offloading facility to transfer traditional well waste to existing upload storage tanks. “Who looks there?” Hewitt said of the website. “If it was announced, it was announced in the Huntington (W.Va.) newspaper. It wasn’t brought to the attention of people here. They were following the letter of the law, not the spirit of the law.” Ohio Revised Code notes that all legal advertisements , notices and proclamations shall be printed in a newspaper of general circulation and shall be posted by the publisher of the newspaper on the newspaper’s internet website, if the newspaper has one. Chuck Minsker, public affairs specialist with the U.S. Army Corps of Engineers, noted the regulatory office said there are no plans to expand the public comment period. He was unaware if the notices had run in any newspapers. Marietta resident Rebecca Phillips said drilling waste contents could likely include arsenic, benzene, toulene and mercury, as well as radioactive materials. “What we’ve been told by the corps of engineers is that it is for traditional wastewater by oil and gas wells,” she said. “Anything coming out of the ground has danger of pollutants, even if it’s traditional wastewater.” Phillips said she is concerned that southern Ohio is becoming a dumping ground. “We are geologically suited (for wastewater dumping), but the notion of wastewater, we have no rights to know what’s in it,” she explained. “They can take waste water from all over the country and inject it into the ground here.” She said the area is already getting truck loads of waste, but having a docking facility would add to the current problem. Hewitt said there are brine trucks driving through Marietta that are full of “toxic, contaminated water” that’s being pumped into old wells. She said there are only a few disposal sites in Pennsylvania and West Virginia, but Ohio has thousands.
Gulfport trimming natural gas production - Gulfport Energy plans to cut natural gas production, but will keep a drilling rig in the Utica Shale, as it hopes for prices to rise later this year. Executives of the Oklahoma City-based Gulfport discussed the company’s first-quarter financial results Friday morning with investors. Gulfport has drilled more than 400 wells in Ohio’s Utica Shale, the most of any publicly traded company. The company reported a net loss of $517.5 million, or $3.24 per share for the first quarter. President and CEO David M. Wood said he anticipates U.S. natural gas production to drop over the next few months, leading to higher prices, particularly if the economy returns to something closer to normal. “However, we remain cautious, as there are still many unknowns surrounding the short-term and long-term impacts of COVID-19 on domestic demand for gas,” Wood said. The coronavirus pandemic also could delay the drilling and completion of new wells, the company said. Gulfport expects to lose not more than 20 million cubic feet equivalent of production per day. By comparison, Gulfport’s wells produced 1.05 billion cubic feet equivalent per day during the first quarter. In the Utica Shale, Gulfport drilled seven wells and completed 15 wells during the first quarter. It has begun production from three wells since mid-March, and plans to keep a drilling rig in the Utica through October. Utica wells accounted for a little more than three-fourths of Gulfport’s production, which is 90 percent natural gas.
Tales of The Shale Crescent -- Part 1 -- "Shale Crescent" connotes an industrial boom beginning with an already accomplished explosion of natural gas production, soon to be followed by a buildout of petrochemical processing on a scale comparable to that of the Gulf Coast, and concluding with a blossoming of plastics and polymer manufacturing businesses that will provide tens or even hundreds of thousands of new jobs.But, just as many regional policymakers averted their eyes from the devastating effect the fracking boom would have on the coal industry, they now avert their eyes from the cancellation of the proposed ASCENT cracker in Wood County, West Virginia; the now annual delays (most recently two weeks ago) in a final investment decision for the proposed Belmont County, Ohio cracker; and clear economic indicators, which show that their vision of petrochemical prosperity is likely to be a pipe dream. In this series, we'll explore those indicators, which suggest that:
- The much-ballyhooed buildout of four to five ethylene crackers in the Marcellus/Utica region will almost certainly not happen. In fact, it's doubtful that any more Appalachian crackers will be constructed following completion of the Shell facility in Beaver County, Pennsylvania.
- If the crackers are not built, the economic rationale for support facilities like the nearly-as-ballyhooed Appalachian Storage Hub, largely evaporate.
- And, even if the crackers and storage facilities are built, they're very unlikely to give rise to "game-changing" increases in manufacturing and jobs.
For these reasons, hundreds of millions of taxpayer dollars being spent on efforts to bring about the petrochemical boom are likely being squandered. Meanwhile, more feasible and sustainable economic development strategies are ignored and in some cases actively resisted because they are perceived as threats to the imagined petrochemical nirvana.
So, if concerns about the damage pollution and greenhouse gas emissions would do to people in the region and to the planet are the reasons a petrochemical boom shouldn't happen in the Ohio Valley and Western Pennsylvania, the economic and technological concerns presented here are the reasons it won't happen, or at least it won't happen on a scale that will deliver anything like the promised growth in jobs and prosperity. Under foreseeable economic conditions, additional crackers won't be sufficiently profitable to warrant the multi-billion dollar investments required to build them
Did The Plastics Boom End Before It Even Started? - The Year 2020 was supposed to be a watershed moment for the plastic industry after dozens of state and local policymakers planned to make the ultimate shift away from plastics. They clearly underestimated the sheer tenacity of the plucky industry and a global pandemic. The plastic industry has quickly seized the unexpected opportunity provided by the Covid-19 pandemic and an indulgent government to push back on plastic bans. The plastics and petrochemicals sector received a much-needed shot in the arm after the Trump administration gave it an ‘open license to pollute’ after relaxing tough environmental laws and fines for environmental pollution during the COVID-19 crisis.But maybe they have done the victory lap too soon, and the Trump bonanza will be hardly enough to overcome a much bigger existential crisis. The demise of the shale and fracking boom that has been powering a plastics renaissance is beginning to take a heavy toll on the plastics sector as well. The shale boom led to an overabundance of cheap oil and natural gas, key commodities used in the manufacture of plastics both as feedstocks and as fuel. The fossil fuel industry has been heavily pivoting into the petrochemical sector as a second cash cow even as the world grew increasingly weary of its role in environmental degradation, and investors started giving it a wide berth. Indeed, the plastics industry was poised for an epic explosion--until the coronavirus crisis and subsequent oil price collapse dealt it a potential death blow. Time magazine has reported that South Africa’s integrated energy and chemical giant, Sasol Ltd, opened a new plastic plant in Louisiana last year, one of seven such projects it had in the works while Shell was is in the process of building a huge multi-billion dollar ethane cracker plant in Pittsburgh with the capacity to churn out 1.8 million tons of plastic each year. According to the American Chemistry Council, no less than 343 new plastic production plants and expansions were given the green light in the month of February or planned in the near future. Global plastics production was set to increase by about a third over the next five years and triple over the next three decades.But the ongoing energy and health crisis have put paid to these plans and rosy projections.Thailand-based PTT Global Chemical has announced that it will indefinitely delay its plan to build an ethane cracker plant in Ohio, citing uncertainty amid the health crisis while Shell said in March that it was shelving its Pennsylvania project.Meanwhile, China’s plans to invest $84 billion in plastic and energy investment in West Virginia are yet to materialize three years since the promise was made. The plastic bloodbath could be just beginning.
In Midst Of Natural Gas Glut, Plastic Industry Bent, Not Broken (Yet) - With energy demand dropping like a hot potato on the heels of the COVID-19 crisis, everyone is talking about the oil glut. People are starting to talk about the natural gas glut, too. That’s an interesting twist, considering that gas stakeholders have been expanding their petrochemical operations, anticipating an increase in the demand for plastic. However, it seems that the plastic hedge is also beginning to come apart at the seams — and not just because of the virus. Take a look at the situation in Appalachia, for example. All things being equal, Appalachia is an ideal spot for establishing a string of new petrochemical plants featuring ethane crackers, which produce the building blocks for the plastic industry. As an epicenter of the US fracking boom, the region is awash in gas. The US Department of Energy has been all over the idea. Ironically enough, the new petrochemical hub was to be built partly on the bones of the region’s dying coal industry. Some of the work is already under way, but in recent months the clouds have been rolling in. Last March our friends over at the Institute for Energy Economics and Financial Analysis took a deep dive into the plans for a petrochemical buildout in the region, and came up with this observation: “The petrochemical buildout in the United States has oversupplied the market. Operating rates of cracker plants and plastics manufacturer margins placed downward pressure on operating rates and expected sales prices and margins. Most are expected to decline in the United States and around the world. The supply/demand imbalances are likely to last through 2026.” The victim could be a massive new $5.7 billion petrochemical facility planned for Belmont County in Ohio, which appears to have hit the rocks after a period of site prep. The plant is a project of PTT Global Chemical of Thailand, in partnership with South Korea’s Daelim Chemical. According to IEEFA, Moody’s has soured on the project. Adding more fuel to thepetrochemical dumpster fire, the firm IHS Markit has also reportedly given it the thumbs down. Interesting! According to IEEFA, the same firm once projected that the new plastic hub could support five new petrochemical facilities. As of this writing, our friends over at Shale Daily are reporting that PTT and Daelim had previously set an end-of-June date for deciding whether or not to move forward. That ball of wax now seems to be up in the air, and the drop-dead date is now indefinite. Shale Daily cites a company spokesperson who stated that “we are unable to promise a firm timeline for a final investment decision.”
Pandemic hurts Marathon Petroleum - A drop in fuel demand and low oil prices have battered Marathon Petroleum Corp. during the coronavirus pandemic. The Findlay-based company announced Tuesday it had cut spending and was borrowing money after losing $9.2 billion during the first quarter. “As everyone is aware, the global pandemic became the focus in the quarter and that continues today with our immediate priority on safely operating our assets to supply product to the market, protecting the health and safety of our employees and customers and supporting the communities in which we operate,” Marathon’s new President and CEO Michael J. Hennigan said during a conference call with investors. Marathon operates 16 refineries across the country, including one in Canton. The company also runs Speedway convenience stores and controls MPLX, a company that gathers, processes and transports oil and natural gas in the Utica Shale and other regions. Stay-at-home orders during the pandemic drastically reduced demand for fuel as schools and business closed and commuters worked from home. States have just started to lift some of those restrictions. Marathon’s loss works out to $14.25 per share, compared to its loss of 1 cent per share during the same quarter last year. Hennigan said Marathon’s midstream and retail operations had strong results, but the refining sector struggled. Most of the $9.2 billion loss involved a write-down in the value of assets. Hennigan said Marathon would cut its capital spending for the year by $1.4 billion and planned to trim operating expenses by $950 million.
Shell to Divest Pennsylvania Assets - Shell reported Monday that it has agreed to sell its Appalachia shale gas position to National Fuel Gas Co. (NFG) for $541 million. “Divesting our Appalachia position is consistent with our desire to focus our Shales portfolio,” Shell Upstream Director Wael Sawan commented in a written statement mailed to Rigzone. “While we maximize cash in the current environment, our drive for a competitive position in Shales continues. It is a core part of our Upstream portfolio along with the Deep Water and Conventional oil and gas businesses.” Under the deal, Shell will transfer to NFG approximately 450,000 net leasehold acres in Pennsylvania with approximately 350 producing Marcellus and Utica wells in Tioga County as well as associated facilities, Shell stated. Moreover, the deal – subject to regulatory approvals and slated to close by the end of July 2020 – represents roughly 250 million standard cubic feet per day of current production and includes Shell owned and operated midstream infrastructure, the company added. NFG stated the approximately 142 miles of gathering pipelines and related compression interconnect with various interstate pipelines, including its Empire pipeline system and a potential link to its Covington gathering system. The firm also noted that more than 200,000 of the net acres it will acquire in Tioga County boast net proved developed natural gas reserves of approximately 710 billion cubic feet. “National Fuel’s acquisition of these high-quality assets in one of the most prolific areas in Appalachia will provide the Company with a unique and highly strategic opportunity to further its integrated development approach in the region,” remarked NFG President and CEO David P. Bauer. “With significant economies of scale provided by Shell’s large Tioga County acreage footprint, which is contiguous to our existing development areas, along with significant, integrated gathering facilities and valuable pipeline capacity, Shell’s assets are a perfect fit for the Company’s diversified business model and provide meaningful synergies with our existing operations.”
Shell is getting out of the Appalachian shale business but not petrochemicals -Swepi LP, the exploration and production arm of Netherlands-based Royal Dutch Shell, announced that it is selling its Pennsylvania oil and gas assets to National Fuel Gas Co. for $541 million.National Fuel, through its subsidiary Seneca Resources, drills for natural gas in the Allegheny National Forest and throughout northcentral Pennsylvania. Shell burst onto the Appalachian scene in 2010 with a blockbuster acquisition of Marshall-based East Resources. The $4.7 billion deal ushered in a wave of megadeals that brought the world’s majors to Pennsylvania. But, one by one, many have left or are trying to.California-based Chevron Corp. made it official in December that it is looking to sell its Appalachian portfolio, which includes 890,000 acres in the Marcellus and Utica shales across Pennsylvania, West Virginia and Ohio. Shell has been tapering its shale activity for years now. In 2014, the company launched a restructuring of its shale assets after several years of underwhelming results. It said it would either “fix or divest” of its holdings, which at that time included 900,000 acres under lease.The sale announced on Monday includes 450,000 acres in northern Pennsylvania and 350 wells, all of them in Tioga County.They are in the dry gas areas of the Marcellus and Utica shales and would not be able to produce the ethane, a natural gas liquid that another Shell subsidiary plans to turn into plastic pellets at the petrochemical plant under construction in Potter, Beaver County.“Shell remains committed to Pennsylvania, for example through our Pennsylvania Petrochemicals Complex, which brings new growth and jobs to the region, with up to 6,000 construction workers involved in building the new facility and an expected 600 permanent employees when completed,” the company emphasized in its announcement.
National Fuel makes big deal to buy gas drilling sites that Pegulas once owned - National Fuel Gas Co. is doubling down on its natural gas drilling business in Pennsylvania. The Amherst-based energy company has agreed to a $500 million deal to acquire natural gas fields in northwestern Pennsylvania that Royal Dutch Shell purchased a decade ago from East Resources, the natural gas drilling business owned by Buffalo Bills and Sabres owners Kim and Terry Pegula. The deal will increase National Fuel's drillable acreage in northwestern Pennsylvania by about 50% and also add about 142 miles of gathering system pipelines to its natural gas transportation network. The deal, coming at a time when natural gas prices in northwestern Pennsylvania have been depressed by a lack of pipeline capacity linking those gas fields to major U.S. markets, is viewed by National Fuel executives as a way to bolster its natural gas drilling business at a reduced price, while also expanding its drilling opportunities in the coming years, with the expectations that gas prices will rebound. "It's a one-of-a-kind opportunity," said David Bauer, National Fuel's president and CEO, during a conference call Tuesday. "It checks every box on what we're looking for." The Pegulas sold about 650,000 net acres of Royal Dutch Shell in 2010 for $4.7 billion at the peak of the drilling boom in Pennsylvania. The deal with National Fuel includes about two-thirds as much acreage as in the East Resources deal, but at a much lower cost. National Fuel is paying a price that is the equivalent of about $1,250 per net acre. Royal Dutch Shell paid a price that was more than four times higher – $5,380 per net acre.
Oil Majors Are Abandoning This Key Shale Basin - Royal Dutch Shell announced this week that it was selling its Appalachia shale gas assets for $541 million in a transaction that wouldn’t have caught much attention if it weren’t for the fact that the oil and gas supermajor had paid nearly nine times that price when it bought the assets a decade ago. Shell’s decision to divest its Appalachia shale gas assets is a move indicative of two major trends among international majors. One is the focus on core operations and ditching underperforming assets in recent years. The other is a more recent rush of oil majors trying to dump their assets in the Marcellus and Utica shale plays amid persistently low natural gas prices which have forced supermajors—including Shell and U.S. Chevron—to write down billions of US dollars of valuations on their assets in Appalachia. In this week’s announcement, Shell said it was selling its assets in the region to U.S. energy company National Fuel Gas Company (NFG), in a deal expected to close by the end of July 2020. “The transaction is part of divesting non-core assets and in line with Shell’s Shales strategy which focuses on development of higher margin, light tight oil assets,” Shell said, noting that it is bailing only on the upstream assets in the region and remains committed to Pennsylvania with its Pennsylvania Petrochemicals Complex. With the sale, Shell will be transferring ownership of around 350 producing Marcellus and Utica wells in Tioga County and associated facilities, with current net production at around 250 million standard cubic feet per day. This deal would have been a transaction like many others, were it not for the fact that Shell paid $4.7 billion to enter the Appalachian basin in 2010, at the start of the shale gas boom in the United States. The sale, at a price nearly nine times lower than what Shell forked out a decade ago, shows that the supermajor doesn’t consider its Appalachian assets worth holding onto at times when every project and asset in an oil company’s portfolio is competing for top performance that would not relegate it to the ‘non-core assets’ list earmarked for divestment.
Johnson: Yes, pipeline construction is a virus risk - Residents have documented MVP workers not following the guidelines, this refutes their statements. Also multiple crews of workers have been observed working along the MVP who aren’t erosion and sediment control (E&SC) workers. Therefore, I challenge their assertion that their activities are “limited to the inspection, maintenance, and repair of necessary erosion and sedimentation controls.” I’m not sure what “misrepresentations”, “factual inaccuracies” and “questionable merits” they may be referring to in their commentary. In no way has anyone asked that genuine erosion and soil control measures be halted; rather they ask that outside crews not be brought in to commence construction under the guise of erosion and soil control. Granted, there is opposition to the project, but this is in no way the intent of the letter from Preserve Monroe, myself or anyone else. Their statement that this request is an attempt to halt the use of “natural gas in general” is an absurd over statement. This is not about whether the pipeline should be finished or not. It is about the risks this will bring to our rural communities?” This is a major concern, it is disingenuous of them to imply otherwise. The protection of the at-risk population, elderly, disabled and/or immune compromised people is critical. It is well documented that people living in rural areas are in generally poorer health, have less access to healthcare and will suffer more from this virus. This area has oldest average population in the country. West Virginia is #1 for obesity, heart attacks and respiratory problems, its poverty rate is 20%. This will lead to a higher percentage of citizens needing hospitalization. This could overrun our healthcare system. If they are concerned about the citizens they would cease any further construction during this pandemic. In the commentary, the writer said, “we do not believe using the unfortunate circumstances of the COVID-19 pandemic falls within appropriate avenues of protest.” This is about the safety and welfare of the rural residents and pipeline workers. It is unconscionable to continue construction at this time.
Anxiety builds as court mulls pipeline permit for western Maryland and West Virginia eastern panhandle | WDVM 25 — While a permit for the Trans-Canada natural gas pipeline project is pending a decision in federal court, opponents are warning against the environmental dangers from the “fracking” process on the region’s water quality.The project from Bedford County, Pennsylvania would extend into the town of Hancock in Washington County, Maryland and into the West Virginia eastern panhandle posing potentially harmful geological impacts on the region. Not only would the Potomac River basin be affected, opponents say, groundwater could also be contaminated by leaked gas in fracking wells.Kai Hagen, a Frederick County councilman says that “in addition to local and regional water pollution, a dangerous threat to public health and drinking water, we’re dealing with the global climate change issue. In that context we really should not be investing large amounts of money in brand new fossil fuel- based infrastructure.” Hagen warns that farmers and landowners will have to protect their property rights if the federal court gives the pipeline project a green light.
Delaware Riverkeeper Files Suit to Prevent Damages from LNG Terminal(s) -An environmental group has filed a lawsuit in federal court against a proposed pier in the Delaware River in New Jersey for liquefied natural gas (LNG) tankers. The suit was filed last week in U.S. District Court in New Jersey by the Delaware Riverkeeper Network.The suit charges the U.S. Army Corps of Engineers should not have approved the $96 million project that includes a 1,600-foot pier and a storage facility in New Jersey’s Gloucester County. The permit had been issued last February 28.The project at Gibbstown, New Jersey, is being advanced by Delaware River Partners, a subsidiary of New Fortress Energy LLC. Those tankers would load LNG that had been moved about 200 miles by truck and rail from the Marcellus Shale in northeast Pennsylvania under the plan by New Fortress Energy.The company has gotten a special federal rail permit to be allowed to move LNG by rail in specially designed rail cars.Construction started last fall at a New Fortress liquefaction plant in Wyalusing, Pennsylvania. It is expected to be operational in late 2020 or early 2021.New Fortress has plans for a second facility in Pennsylvania. It would be operational in first quarter 2021. Each plant would produce 3.6 million gallons of LNG per day or 2.15 million tons of LNG per year.In related news, the Delaware River Basin Commission has set a May 11 hearing for an adjudicatory hearing on the project. Hearing officer John Kelly will hear evidence and then decide whether to recommend that the commission uphold or reject its approval of the project last June. The commission, a governmental body, can accept or reject his recommendation. Critics have argued that the commission did not allow enough time for public comment in approving the project that would allow two tankers to dock at Gibbstown on the Delaware River.
About 350 gallons of oil spills into NH river — About 350 gallons of heating oil have leaked into the Connecticut River from a New Hampshire facility, authorities say. The Hanover Fire Department was dispatched to the U.S. Army Cold Regions Research and Engineering Laboratory at about 4 p.m. Saturday after a security officer discovered a leak, according to a statement from the fire department. It was determined that the leak was coming from a newly installed boiler in the main lab. The boiler and leak were quickly isolated and shut down. But some oil made its way into a floor drain and into the river. The spill was contained with 550 feet of a rigid boom across the river. The boom will be in place for a couple of days while Clean Harbors cleans up the spill. Boat traffic will be unable to pass until the boom is removed.
Dominion confirms $8 bln Atlantic Coast natgas pipe cost, early 2022 in service - (Reuters) - Dominion Energy Inc confirmed on Tuesday its previous cost and schedule estimates for the roughly $8 billion Atlantic Coast natural gas pipeline from West Virginia to North Carolina that is expected to enter service in early 2022. That cost and schedule, however, depends on the company being allowed to cut trees along the pipeline’s route during the upcoming November 2020-March 2021 season, Dominion Chief Executive Thomas Farrell told analysts after the company released its first quarter earnings. “We can maintain the existing schedule and cost estimates, so long as we can take advantage of the November 2020 through March 2021 tree filling season,” Farrell said, noting “We remain confident in the successful completion of the project.” Atlantic Coast, the nation’s most expensive gas pipe, is one of several projects to have received federal permits in recent years but which have been delayed by state opposition and local and environmental legal and regulatory battles. Farrell said the company expects to overcome those challenges this year. In the Appalachian Trail case, Dominion said it expects the U.S. Supreme Court to rule in its favor in coming weeks, allowing the pipe to cross the trail along its existing route. In the biological opinion case, Farrell said Dominion is working with the U.S. Federal Energy Regulatory Commission and the U.S. Fish and Wildlife Service (FWS) and expects to receive needed authorizations by the end of this quarter. Dominion suspended construction of the 600-mile (966-kilometer) project in December 2018 after the U.S. Court of Appeals for the Fourth Circuit stayed a FWS biological opinion. On the Nationwide Permit issue, which the Army Corps of Engineers uses to authorize waterbody crossings, Farrell said he expects the U.S. Department of Justice and industry will resolve a legal opinion that questions the legitimacy of the Army Corps’ use of the program “in a timely manner.” In a case involving TC Energy Corp’s Keystone XL oil pipe, a federal judge in Montana said the Army Corps was inappropriately using the permit program.
Dominion's responsibility to shareholders: Abandon the Atlantic Coast Pipeline - Virginia Mercury -- A petition asking shareholders to abandon the Atlantic Coast Pipeline is being circulated. Unfortunately shareholders won’t have the power to do so at this year’s annual meeting today.The U.S. Securities and Exchange Commission has on record two shareholder proposals for the 2020 Dominion annual meeting (Climate Risk and Human Rights and Climate Justice). However Dominion successfully petitioned the SEC to prevent them from being brought before the shareholders for a vote.I was a SCANA shareholder. SCANA merged with Dominion on January 1, 2019. SCANA shareholders almost voted for bankruptcy instead of becoming part of the Dominion empire. We had already been burned by the V.C. Summer nuclear plant boondoggle and Dominion’s ACP venture raised concerns about being burdened with another stranded asset.In a letter to the company’s Board of Directors, I asked Dominion to commission a current analysis to determine if there is an economic necessity for the Atlantic Coast Pipeline. A current economic analysis would reveal how the impact of the rapid drop in cost of renewable energy would affect the demand for natural gas and if the ACP is needed as an additional transmission line.The plans to build the ACP were made four years ago and the energy industry has changed significantly in recent years. SCANA shareholders and customers are still reeling over the abandoned V.C. Summer plant that left SCANA with $9 billion of stranded assets. Dominion shareholders and customers have valid concerns that the ACP costs ($8 billion and counting) might continue to rise, especially since court challenges haveinvalidated numerous permits.If the pipeline isn’t completed then the shareholders will have the value of their shares decrease due to stranded assets. Another concern for shareholders is last week’s report “Social Cost and Material Loss: The Dakota Access Pipeline,” which concludes the final cost of DAPL was nearly double the initial project cost. “The banks that financed DAPL incurred an additional $4.4 billion in costs in the form of account closures, not including costs related to representational damage.”Dominion Energy Virginia testified in front of the Virginia State Corporation Commission that it has never studied the need for a new pipeline in Virginia. In 2014 when the ACP was proposed DEV had plans to build more large gas powered electric plants. Since then DEV has canceled their plans to build the plants and have announced they have no plans to build them in the future. Dominion Energy has a responsibility to their shareholders to not proceed with incurring more construction costs for the ACP until they can establish an economic need for the project, all the necessary permits are in place and all the legal challenges have been resolved.
Thousands of Virginians, Scores of National Groups Tell Dominion CEO and Shareholders to Abandon Atlantic Coast Pipeline — Today, as Dominion Energy meets virtually for its annual shareholder meeting, an unprecedented coalition of advocacy organizations and Virginia residents have sent a message to shareholders and board members, calling on the utility monopoly to abandon its plans to build the highly controversial Atlantic Coast Pipeline (ACP). A coalition of 78 prominent advocacy organizations from Virginia and across the country signed onto a letter that will be displayed in a full-page Richmond Times-Dispatch ad and a half-page Washington Post ad on May 6, the day of Dominion Energy’s annual shareholder meeting. The ad, addressed to shareholders, states: “New legislation and legal challenges have rendered the completion of the Atlantic Coast Pipeline unrealistic.” The letter points to the pipeline’s $8 billion price tag, eight missing permits necessary for construction, and the fact that Dominion recently informed state regulators that “significant build-out of natural gas generation facilities is not currently viable” under the state’s new law requiring Dominion to achieve 100% carbon-free electricity by 2045. A law signed last month by Governor Northam, HB 167, significantly raises the threshold for Dominion to pass any of the cost of the ACP onto ratepayers. In order to recover costs from Virginians as planned, Dominion must now prove a need for the energy the pipeline would supply in Virginia and that the pipeline was the lowest-cost way to produce that energy. Additionally, two petitions garnering nearly 4,000 signatures were delivered to Dominion executives and shareholders today. With one petition, over 2200 Virginia residents called on Dominion CEO Tom Farrell to walk away from the pipeline “for the financial health of the company.” Another petition gathered over 1800 signatures to tell Dominion shareholders that the pipeline “no longer makes economic sense, even based on Dominion Energy’s own logic,” and that “continuing to pursue this project is fiscally irresponsible.” “Dominion Energy’s stubborn push to continue building the Atlantic Coast Pipeline despite ballooning costs, legal and permitting challenges, and a seismic shift in Virginia’s energy landscape betrays its duty to shareholders,” said Brennan Gilmore, Executive Director of Clean Virginia. “The responsible thing — for Virginians and shareholders alike — is for Dominion to shutter the project before another tree is felled.”
FERC has a big pipeline problem - The Federal Energy Regulatory Commission has a pipeline problem. A really, really big one. According to publicly available information on FERC’s website, the commission approved no fewer than 46 onshore gas pipeline “mega-projects” from 1997 to 2019. These largest-of-the-large pipeline projects consist of gas pipelines measuring 24 to 42 inches in diameter, with over 100 miles of new pipeline. FERC’s most productive years during this time period were 2007 and 2017, when the commission approved nine and eight pipeline mega-projects, respectively. What immediately stands out is how notorious the class of 2017 is in terms of environmental impacts and operational risks. The roster is a veritable who’s who of fracked gas behemoths, including the Mountain Valley Pipeline (MVP), Atlantic Coast Pipeline (ACP), and Rover Pipeline, among others. It seriously calls into question FERC’s understanding, and exercise, of its role as a true “regulatory” body. The Rover Pipeline is one of the most environmentally destructive gas pipelines in U.S. history, having incurred several million dollars in fines for environmental violations during construction in Ohio and West Virginia. In spite of that, the Rover Pipeline, unlike the MVP and ACP, was completed and is currently in service. The MVP continues to implode under its second project-wide stop work order – it is $2 billion over budget and two years behind schedule – and is awaiting the outcome of multiple court cases and agency permit review processes. The ACP is in extremis. To resume construction, the ACP first needs a favorable verdict in a case before the U.S. Supreme Court (one which will also impact the MVP). Then it will need a veritable cornucopia of other state and federal permits to be reissued. However, the devil is in the details. The final environmental impact statements for the MVP, ACP, and Rover pipelines are sobering documents. The damages and risks outlined are a strong indictment of the Kafkaesque process FERC employs to approve – indeed, to rubberstamp – interstate gas pipelines in the U.S. They clearly demonstrate FERC is not performing its most basic regulatory duty. While the MVP, ACP, and Rover pipelines account for just 12% of the 12,500-mile total length of the 46 pipeline mega-projects, they have massively outsized impacts. These three pipelines account for 42% – nearly half – of the 1,600+ miles of high landslide risk terrain crossed by all 46 pipeline mega-projects approved by FERC since 1997. Landslides pose grave environmental consequences, and threaten the integrity of pipeline infrastructure. One of the eight mega-projects approved in 2017, the Leach XPress Pipeline, already suffered a rupture and catastrophic explosion due to a landslide-related event. The MVP, ACP, and Rover pipelines also account for 29% – nearly one-third – of the 48,000+ acres of upland forest cleared in order to construct all 46 pipeline mega-projects. In addition to destroying wildlife habitat and facilitating the spread of invasive species and plant disease, clear-cutting large swathes of forest on steep slopes increases the likelihood of landslides.
Gas pipeline explodes in Fleming County - Crews responded to a gas pipeline explosion in Fleming County. It happened shortly after 4:30 p.m. Monday near the Hillsboro community, off Highway 1013. EMA officials say the explosion was in a wooded area and no homes were nearby. No one was hurt. Enbridge identified the explosion at line 10 of their Texas Eastern Natural Gas system. We're told the gas has been shut off to the pipeline while crews monitor hot spots in the burned area. Art Huggins described the sound as fighter jets taking off from his front yard. He says it's a good thing it happened in the wooded area and not any closer. "If it had to happen, it couldn't have happened in a better place," said Huggins. "There is places this line travels where there is occupancy pretty close -- not tremendous amounts. But it runs through areas where there are a lot of people. Right here, that's as good of a spot as it can happen." Gas line professionals arrived on scene Monday evening to begin looking over the explosion site. A cause remains unknown.
Federal agency investigates second Eastern Kentucky pipeline explosion within a year - A natural gas pipeline exploded on a hillside near a highway in Eastern Kentucky Monday afternoon, the second on the same network of pipes in less than a year. No one was injured in the 5 p.m. explosion along Highway 1013 in Fleming County, about 3 miles east of Hillsboro. Another pipe explosion in Lincoln County last August left one woman dead and six hospitalized for burns. The Pipeline and Hazardous Materials Administration is investigating the blast, the agency said. A spokesman for Enbridge, the Canadian-based energy conglomerate that owns the Texas Eastern Transmission Co. pipeline, said in a statement that company crews are on-site and have "secured the area." The 30-inch pipe that exploded, Line 10, feeds into the Texas Eastern — a network of 9,100 miles of piping that stretches from Texas to New York and moves 20% of America's natural gas. About 690 of those piping miles run through the state of Kentucky, from Lewis County on the Ohio border to Monroe County on the Tennessee border. Enbridge spokesman Michael Barnes said in a statement that the company has notified nearby customers but didn't say whether local gas service was interrupted. The pipe has been shut down and remains isolated. Adjacent Lines 15 and 25, which are also part of the Texas Eastern, have been shut down, according to the pipeline safety administration. WTVQ reported the explosion and ensuing "huge fire" Monday afternoon and included footage from a local pilot who was flying a small plane when he saw the explosion from the air. The nearby Daniel Boone National Forest reportedly was not affected. The 30-foot section of pipe that was ejected from the ground near Danville in Lincoln County on Aug. 1, 2019, set ablaze 30 acres of land and damaged several homes and businesses. About 66 million cubic feet of gas was released — enough to power a typical home for 1,000 years. It was the third failure on Line 15 — the first in 1986 severely injured three people about 10 miles from the site of last year's accident, and a second in 2003 in Morehead, Kentucky, that didn't cause injuries but cost $3.3 million. Nine people have died in explosions on the Texas Eastern since 1985. Six of them were in Kentucky.
Texas Eastern explosion, pipeline outage cuts Appalachian gas production, prices— An explosion and resulting outage on Texas Eastern Transmission began pushing back on Appalachian gas production Tuesday, weakening prices at Dominion South while cutting supply to the US Southeast. In midday trading, cash prices at the Appalachian benchmark supply hub were down about 5 cents to $1.51/MMBtu, preliminary data from S&P Global Platts showed. At nearby Texas Eastern M3, stranded regional supply weighed on an otherwise bullish market, dropping hub prices about a penny to $1.62/MMBtu. At other downstream hubs across the Northeast, prices were sharply higher, up as much as 19 cents Tuesday on an uptick in weather-related demand. On the US Gulf Coast, the precipitous drop in incoming supply Tuesday was likely to blame – at least in part – for higher prices at key regional locations including Henry Hub, up 16 cents to $1.93/MMBtu, and Houston Ship Channel, up 21.5 cents to $1.90/MMBtu. Lower prices at select Northeast locations impacted by the outage on Texas Eastern come after an explosion Monday on the pipeline's 30-inch diameter line near the Owingsville, Kentucky compressor station. The subsequent outage at Owingsville has cut southbound capacity through the compressor to zero, according to a critical notice posted Monday by Texas Eastern. Southbound flows through Owingsville have averaged about 1.3 Bcf/d over the past 30 days, S&P Global Platts Analytics data shows. With limited capacity to reroute gas on other pipelines flowing to the US Gulf Coast or to the Midwest, stranded Appalachian production came under pressure Tuesday as combined output from the Marcellus and Utica shales dropped about 1 Bcf/d from the start of the week to an estimated 30.6 Bcf/d. Net gas transmissions from Northeast to the Southeast have also witnessed a steep drop, falling to 3.1 Bcf/d Tuesday, down from an average 4.8 Bcf/d over the 30 days prior.
Three Enbridge Pipelines Shut After Kentucky Natgas Line Fire - (Reuters) - Three of Enbridge's pipelines were shut following a fire on the company's Line 10 segment of its Texas Eastern Natural Gas System, in Fleming County, Kentucky on May 4, the U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA) said on Friday.The company said on Thursday there was no estimated timeline to return its Line 10 to service.The PHMSA has deployed an investigator to the site of the incident, a PHMSA spokesperson said.No injuries were reported in the fire, which occurred in a wooded area in Fleming County.That shutdown stopped gas from flowing through the damaged section of pipe from the Marcellus/Utica Shale in Pennsylvania, Ohio and West Virginia to the U.S. Gulf Coast.Before the blast about 1.2 billion cubic feet of gas was flowing through that area, according to data from Refinitiv and was now down to around zero on some days, according to data from Refinitv.Texas Eastern has three lines between its Danville and Tompkinsville compressors in Kentucky that make up its 30-inch (76-centimeter) system. They are Lines 10, 15 and 25..
U.S. natgas futures soar to 16-week high on slowing output, pipe blast - (Reuters) - U.S. natural gas futures jumped on Tuesday to a 16-week high after a big pipeline shut, on forecasts for cooler weather next week that will boost heating demand, and on slower output as shale drillers hit by collapsing crude prices shut oil wells that also produce a lot of gas. "This week’s rally continues to be driven by reports of diminished associated gas production (while) near-record cool will support lingering heating demand," Front-month gas futures for June delivery on the New York Mercantile Exchange rose 14.1 cents, or 7.1%, to settle at $2.134 per million British thermal units, their highest close since Jan. 14. Canadian energy company Enbridge Inc shut a section of its Texas Eastern pipe in Kentucky following a blast late Monday. That shutdown cut the pipe's gas flows from the Marcellus Shale to the Gulf Coast by over 1 bcfd, according to data from Refinitv. 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 energy firms cut spending on drilling. Refinitiv said average gas output in the U.S. Lower 48 states has fallen to 89.6 bcfd so far in May, down from an eight-month low of 92.8 bcfd in April and an all-time monthly high of 95.4 bcfd in November. The 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 cooler weather coming, Refinitiv projected demand in the Lower 48 states, including exports, would rise from an average of 82.5 bcfd this week to 86.8 bcfd next week. That compares with Refinitiv's forecasts on Monday of 84.2 bcfd this week and 88.5 bcfd next week. Even though the coronavirus pandemic is reducing gas use, EIA still expects U.S. exports to hit record highs in the 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.
U.S. natgas falls near 9% on forecasts for lower demand and exports - (Reuters) - U.S. natural gas futures fell almost 9% on Wednesday on forecasts for lower demand next week than previously expected and longer-term projections that businesses will use less of the fuel and exports will drop in coming months due to government lockdowns to stop the coronavirus spread. That price decline comes after gas prices jumped 13% to a 16-week high earlier this week on a sharp decline in output as shale drillers shut oil wells due to the 60% collapse in crude prices so far this year. Those oil wells also produce a lot of gas. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 19.0 cents, or 8.9%, to settle at $1.944 per million British thermal units. That is the biggest daily percentage drop since January 2019. On Tuesday, the contract closed at its highest since Jan. 14. Those price increases earlier this week boosted the U.S. front-month over the Title Transfer Facility (TTF) in the Netherlands and the Japan/Korea Marker (JKM), making U.S. gas the most expensive of the world's major benchmarks. That is why some liquefied natural gas (LNG) buyers have canceled U.S. cargoes - because it would cost more to buy gas in the United States than it could be sold for in parts of Europe and Asia - and that does not include fees for shipping or liquefaction. Most U.S. LNG, however, has already been sold forward years in advance to utilities consuming the fuel, so some U.S. cargoes will likely continue to go to Europe and Asia. Traders noted the latest price moves marked the point at which the spot market has finally caught up to the forwards market since U.S. gas prices for the summer have been trading over some European and Asian hubs for weeks. Data provider Refinitiv said U.S. LNG exports averaged 7.0 billion cubic feet per day (bcfd) so far in May, down from a four-month low of 8.1 bcfd in April and an all-time high of 8.7 bcfd in February. Gas output in the U.S. Lower 48 states has averaged 89.8 bcfd so far in May, according to Refinitiv, down from an eight-month low of 92.8 bcfd in April and an all-time monthly high of 95.4 bcfd in November. With slightly cooler weather coming, Refinitiv projected demand in the Lower 48 states, including exports, would rise from an average of 82.9 bcfd this week to 85.4 bcfd next week. That compares with Refinitiv's forecasts on Tuesday of 82.5 bcfd this week and 86.8 bcfd next week.
Weekly US gas build exceeds analyst expectations at 109 Bcf | S&P Global Market Intelligence - Storage operators deposited a net 109 Bcf into natural gas inventories in the Lower 48 in the week ended May 1, above the five-year average build of 74 Bcf, the U.S. Energy Information Administration reported. The build, above the 105 Bcf injection forecast by an S&P Global Platts analyst survey, brought total working gas supply in the Lower 48 to 2,319 Bcf, or 796 Bcf above the year-ago level and 395 Bcf above the five-year average. By region::
- * In the East, stockpiles were up 19 Bcf on the week at 424 Bcf, 45% above the year before.
- * In the Midwest, inventories grew 24 Bcf at 530 Bcf, 74% more than a year ago.
- * In the Mountain region, stockpiles were up 8 Bcf at 111 Bcf, 44% higher than the year before.
- * In the Pacific region, storage levels rose 10 Bcf at 228 Bcf, 43% above the year-ago level.
- * In the South Central region, stockpiles rose 48 Bcf at 1,027 Bcf, 49% more than the year-ago level. Of that total, 331 Bcf of gas was in salt cavern facilities and 695 Bcf was non-salt-cavern. Working gas stocks rose 5% in salt cavern facilities from the previous week and were up 4.7% in non-salt-cavern facilities.
U.S. natgas falls on big storage build, coronavirus demand destruction – (Reuters) - U.S. natural gas futures fell almost 3% on Thursday on a much bigger-than-usual weekly storage build that analysts said was caused by coronavirus-related demand destruction. "The larger than expected build suggests ... lost demand is still overwhelming the market," said Daniel Myers, market analyst at Gelber & Associates in Houston, noting gas use will remain low so long as the economy remains shuttered by government lockdowns. The U.S. Energy Information Administration (EIA) said utilities injected 109 billion cubic feet (bcf) of gas into storage during the week ended May 1. That was slightly bigger than the 106-bcf build analysts forecast in a Reuters poll and compares with an increase of 96 bcf during the same week last year and a five-year (2015-19) average build of 74 bcf for the period. The increase last week boosted stockpiles to 2.319 trillion cubic feet (tcf), 20.5% above the five-year average of 1.924 tcf for this time of year. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 5.0 cents, or 2.6%, to settle at $1.894 per million British thermal units. This has been a volatile week for U.S. gas. Prices jumped to a 16-week high on Tuesday after a big pipe shut and on slowing output, but fell almost 9% on Wednesday, the biggest percentage decline in over a year, after the market failed to break above the 200-day moving average and on more signs government lockdowns have cut demand and exports. That price increase on Tuesday briefly made the U.S. front-month the most expensive of the world's major gas benchmarks for the first time ever, ahead of the Title Transfer Facility (TTF) in the Netherlands and the Japan/Korea Marker (JKM), both of which are trading near record lows. Analysts said high U.S. gas prices and low prices elsewhere in the world could prompt buyers of U.S. liquefied natural gas (LNG) to cancel more cargoes in coming months.
U.S. natgas futures fall on forecasts for lower demand in mid-May - (Reuters) - U.S. natural gas futures fell 4% on Friday on forecasts for lower demand in mid-May due to milder weather and as businesses remain shut due to government lockdowns to stop the spread of the coronavirus. Front-month gas futures for June delivery on the New York Mercantile Exchange fell 7.1 cents, or 3.7%, to settle at $1.823 per million British thermal units, their lowest close since April 28. That kept front-month at the Henry Hub benchmark in Louisiana higher than the Title Transfer Facility (TTF) in the Netherlands. Earlier this week, Henry Hub traded higher than both the TTF and the Japan/Korea Marker (JKM) for the first time ever. TTF and JKM both fell to record lows over the past couple of weeks. In addition, to the front-month, Henry Hub was trading higher than TTF in July and August. Analysts said those high U.S. prices and low prices elsewhere would likely prompt buyers of U.S. liquefied natural gas (LNG) to cancel more cargoes in coming months. In April, buyers canceled about 20 U.S. cargoes that were due to be shipped in June. For the week, the U.S. front-month was down about 4% after rising about 8% last week. Looking ahead, U.S. 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 coronavirus 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 (bcfd) in 2020 and 87.5 bcfd in 2021 from a record 92.2 bcfd in 2019 as low oil prices prompt energy firms cut spending on drilling. Those oil wells also produce a lot of gas. The 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. This is normally the mildest time of year when heating and cooling demand are lowest. But with the weather still cooler than normal, Refinitiv projected demand in the Lower 48 states, including exports, would rise from an average of 83.5 bcfd this week to 87.4 bcfd next week before falling to 82.7 bcfd when the weather turns milder and demand destruction from the coronavirus starts to show up in the data.
Cruiser USS Philippine Sea spills diesel fuel into York River - Ticonderoga-class guided-missile cruiser USS Philippine Sea (CG-58) spilled close to 4,000 gallons of diesel fuel into the York River on Thursday morning, the Navy confirmed to USNI News. The spill occurred at 7 a.m. while Philippine Sea was pier side at Naval Weapons Station Yorktown. The cruiser was in Yorktown to load ammunition aboard. The Navy is now investigating the cause of the spill. Absorbent booms were already in place while Philippine Sea was pier side. The diesel fuel spill was mostly contained by the booms or under the pier. The ship’s crew, a Navy oil recovery team from Naval Weapons Station Yorktown and U.S. Coast Guard personnel responded to the incident, Navy officials told USNI News. By Thursday afternoon, 90 percent of the spill was recovered and absorbent materials were left in place to try to capture any remaining fuel. The York County-Poquoson Sheriff’s Office flew an aerial drone over the site to try locating any diesel fuel washing ashore. As of Friday morning, Navy officials said the environmental impact, if any, was minimal. Any remaining diesel sheen on the water is considered unrecoverable and is expected to dissipate.
SUPREME COURT: 4th Circuit to revisit pipeline case after groundwater ruling -- Monday, May 4, 2020 -- A federal appeals court must reconsider a dispute over a South Carolina pipeline leak in light of the Supreme Court's new test for determining the scope of federal water permitting.
Commissioning continues at Elba Island LNG » The Federal Energy Regulatory Commission has given Kinder Morgan approval to introduce feed gas into Unit No. 8 at Elba Island LNG in Georgia, Kallanish Energy reports. It is one of 10 modular units at the LNG facility outside Savannah, Georgia. Six of the units are in service with two additional units starting commissioning activities. Kinder Morgan has said it intends to begin service on the remaining trains in the first half of 2020. Last December, Kinder Morgan had shipped its first cargo of LNG from plant. Construction on the $2 billion modular project with 10 smaller modular LNG trains or units began in late 2016. When complete, Elba Island will be able to export 2.5 million tons per year of LNG, equal to about 350 million cubic feet of natural gas per day, the company said. It is backed by a 20-year contract with Royal Dutch Shell. Initially, the Elba Island plant was to begin service in second quarter 2018, but it has been repeatedly delayed. It is processing natural gas from the Appalachian Basin, as well as from the Gulf Coast.
About half of Louisiana oil businesses expect bankruptcy amid coronavirus -- About half the members of the Louisiana Oil and Gas Association expect to file for bankruptcy as the energy industry's struggles accelerate faster than anticipated since the price of oil has plummeted and storage tanks are increasingly full. Nearly a quarter of oil and gas employees have already been laid off, members said in a recent survey. There are about 33,900 oil and gas industry workers across the state, where more than 33,600 wells operate. About four in five exploration and production businesses have already started shutting in oil wells, the association said. A significant drop in demand for oil spurred by stay-at-home orders due to the coronavirus pandemic, coupled with increased oil production in Saudi Arabia and Russia, crippled U.S. oil and gas extraction businesses when prices collapsed. The trade organization has about 460 exploration and production members, but also oilfield services businesses across the state. "We feared these outcomes would take place by mid- to late-May, but the crushing weight of the crisis is taking hold much quicker than expected," said Gifford Briggs, president of the Louisiana Oil and Gas Association. About 77% of operators have begun to shut in wells, despite some being approved for federal help, such as through the Paycheck Protection Program and Economic Injury Disaster Loan program, both administered by the U.S. Small Business Administration through lenders. Only about 25% of members received economic injury disaster loan amounts they expected. Of those who received funds, about 72% said it was not enough money to avoid layoffs and about 46% said it wasn't enough to keep the business alive either.
Bill sought by oil and gas companies would deep-six coastal lawsuits filed by Louisiana parishes - The companies are pushing a state Senate bill that would kill lawsuits filed by parish governments that, if successful, could produce big dollars to restore Louisiana’s disappearing coast. The politically active Carmouche law firm in Baton Rouge is behind the lawsuits and already has secured a tentative $100 million settlement with Freeport-McMoRan, which drilled 4% of the wells in Louisiana. By stopping the parish lawsuits, Senate Bill 359, will be heard late Thursday afternoon by the Natural Resources Committee, would leave it up to Gov. John Bel Edwards or to Attorney General Jeff Landry to pursue the cases. Neither office has the resources to do so. Oil and gas companies – backed by business interests and some coastal chambers of commerce – say SB359 will promote jobs and investment by taking away the threat of the parish lawsuits. The Talbot Carmouche Marcello law firm in Baton Rouge is trying to derail the bill. It has the support of other trial attorneys, local government interest groups and environmentalists against the oil and gas companies. “What they’re trying to avoid is accountability,” said Russel Honore, the retired general who heads the Green Army, an environmental advocacy group. “They don’t want to clean up their mess.” The Legislature isn’t the only front in the war; the oil companies are also trying to stop the parish lawsuits in federal court. The two sides recently submitted written arguments to the U.S. Fifth Circuit Court of Appeals on whether the cases should be heard in federal or state court. The oil companies prefer federal court. At issue in the bill to be heard Thursday is Louisiana’s Coastal Zone Management Act, which was created in 1978 and has opened the door for six parishes to sue nearly 100 oil and gas companies. The parishes are Plaquemines, St. Bernard, St. John, Cameron, Jefferson and Vermilion.
Is it a good idea to lower taxes on oil production in Louisiana? Legislature starts fast on bill - Though state government is facing a huge drop in revenues because of the coronavirus pandemic, almost the first legislation that moved out Monday from the Louisiana House tax committee was a bill to reduce the severance tax charge on the production of oil.House Bill 506 would reduce the severance tax rate by a half percent each year for the next eight, taking an estimated $151.4 million out of state collections over the next five years.That is money that local government, in particular, cannot afford to lose, said Guy Cormier, the executive director of the Louisiana Police Jury Association who previously had been president of St. Martin Parish for 14 years. Parishes receive about 20% of the severance income and use that money to help fund law enforcement and other local services.But lowering the severance tax would entice the oil industry to drill more in Louisiana thereby creating more jobs, which would translate into more sales and income taxes, said state Rep. Phillip DeVillier, R-Eunice, and chief sponsor of the legislation.“I would feel local governments want more oil and gas production to create more jobs,” he told the House Ways & Means committee.“Is it wise right now to move forward with a bill that will remove tens of millions of dollars from the state of Louisiana?” said Rep. Matthew Willard, D-New Orleans. “It is dangerous to take that risk.”The Legislative Fiscal Office noted, “The bill can only result in a significant loss of state severance tax receipts and parish allocation amounts from what would otherwise be the case.”DeVillier and supporters of the measure said the $151.4 million in losses estimated uses a price per barrel that was conservative at the time the fiscal note was calculated but is now about $30 more than the current price.Present law imposes a severance tax rate on most oil produced in the state was set in 1974 at 12.5% of value. Wells producing less than 25 barrels per day or meeting different criteria pay less.The proposed law reduces the full rate from 12.5% to 8.5% in half percent increments over the next eight years. Gifford Briggs, head of Louisiana Oil and Gas Association, testified that at 12.5% Louisiana has the highest severance tax rate in the nation. Oklahoma charges 7% of the gross value and Texas is 4.6%.But the National Conference of State Legislatures notes that c omparing severance taxes from state to state has proven difficult because the tax structures differ so widely.
TCEQ issues state permit to Texas LNG with stricter standards - Houston liquefied natural gas company Texas LNG on Wednesday received a state permit for a proposed export terminal at the Port of Brownsville with stricter air pollution standards than normal for the region.The Texas Commission on Environmental Quality air pollution permit authorizes the proposed plant to make up to 4 million metric tons of liquefied natural gas per year, but with tougher rules for the project's hot oil heater and oxidizers.Texas LNG has agreed to the tougher standards, which are the same as those applied to the Freeport LNG export terminal, which began operations south of Houston last year, and the proposed Rio Grande LNG along the Brownsville Ship Channel. Texas LNG launched the effort for a permit more than five years ago. The project has been opposed by some residents and others concerned about safety and its effects on the environment. Opponents have sued in an attempt to overturn federal approval of the project.Texas LNG is the smallest of three liquefied natural gas export terminals proposed for the Port of Brownsville. The projects represent nearly $40 billion of investment, thousands of construction jobs, hundreds of permanent jobs and an opportunity to boost U.S. exports."State and federal regulators have consistently refused to listen to concerns from our communities about the threat that these dirty, dangerous fracked gas facilities would pose to already vulnerable populations by pumping even more pollution into the air we breathe," Sierra Club campaign organizer Rebekah Hinojosa said in a statement. "Texas LNG still faces legal challenges at the federal level, and we are determined to ensure that it is never built."
Oil and gas industry affected by coronavirus — Oil and gas prices have hit historic lows but many are hoping for a rebound now that businesses are reopening around the world. In Houston, Ed Hirs, energy fellow at the University of Houston, is more cautious of the oil market’s future. For example, COVID-19 brought the oil and gas industry to a halt. “We’re consuming 20-30 million barrels a day less of oil,” Hirs said. As the economy begins a new chapter, Hirs said it provides some stability for oil prices moving forward. He believes the price at the pump will stay low through the summer. “Not just because the economy is down but because there’s still a huge overhang of supply and not everybody is going back,” Hirs said. Also, he said operating in a limited capacity is not the same as working at 100%. An ongoing price war in the Middle East between Saudi Arabia and Russia will continue to affect the market. “We have two big factors that have driven the number of layoffs, thousands have been laid off because capital spending related to the drilling of new wells has just gone to zero,” Hirs said. He doesn’t think the oil market can bounce back as fast as the rest of the economy, but he said slowly reopening businesses is better than doing nothing. “The benefit, of course, is for consumers getting back to work will be a little less expensive, beginning to travel will be a little less expensive,” Hirs said.
Halliburton lays off 1,000 at Houston headquarters - - Houston oil field services company Halliburton has laid off 1,000 employees at its headquarters as low crude prices take their toll on demand for the products and services the company sells to energy producers.Company officials earlier furloughed 3,500 employees at its Houston headquarters, but attributed this week’s layoffs to an “unforeseeable, dramatic business downturn caused by the coronavirus and unprecedented commodity price decline.”“The reductions are in addition to layoffs across the company’s global operations,” the company said in a statement. “These actions are difficult but necessary as we adjust our business to customers’ decreased activity.” Oil prices have plummeted from more than $60 a barrel at the beginning of the year to less than $25 as the coronavirus pandemic shuts down swaths of the global economy and undermines demand. Last month, U.S. crude prices plunged into negative territory for the first time in history, meaning producers had to pay customers to take their oil.Producers have shut down wells and stopped completing ones that they have been drilling. A large part of Halliburton’s business in North America entails completion services, which include hydraulic fracturing.Halliburton started the year with 55,000 employees across the world, but the workforce has shrunk to about 50,000 people, an April 24 filing with the U.S. Securities and Exchange Commission shows.More than 2,700 of those job cuts happened over the last month at 12 locations in Texas, Oklahoma, Louisiana and Colorado, filings with state workforce officials show.A large number of those layoffs are the result of the company closing locations and moving remaining operations to other locations. Halliburton laid off 384 people when the company closed its Elmendorf facility off Loop 1604 in San Antonio and moved operations to various field camps throughout the Eagle Ford Shale of South Texas.The company laid off another 233 people when it closed a service center in the East Texas town of Kilgore and moved those operations to a field office in Bossier City, La., to better serve customers in the Haynesville shale, an oil and gas field that straddles both states.Fuel Fix: Get energy news sent directly to your inboxHalliburton lost $1 billion during the first quarter after pulling multiple hydraulic fracturing crews from service and writing down $1.1 billion worth of assets.Over the last three months, the company has tightened its belt by cutting $800 million from this year’s capital budget, enacting executive pay cuts and reducing employee benefits.
MPLX abandons Permian NGL pipeline plans amid oil price rout - (Reuters) - MPLX LP said on Tuesday it is no longer pursuing a Permian to Gulf Coast natural gas liquids (NGL) pipeline, called BANGL, after a collapse in oil prices and said it will focus on expanding capacity on existing pipelines instead. The fractionation capacity and export facility associated with the BANGL project have also been deferred. “We are working with others to optimize existing pipeline capacity ... we are still committed to an NGL solution. It just won’t be the original scope that we had envisioned early on,” Chief Executive Michael Hennigan said. “We wanted to not commit to that full scope until we were really sure that the volume commitments would be there (and) with what’s happening in the market, the volume commitments are slower.” Global oil demand has crashed about 30% as the coronavirus pandemic has restricted travel around the world and a brief price war between Saudi Arabia and Russia flooded the market with excess supplies. U.S. crude prices plunged to trade in negative territory for the first time in history last month as storage filled rapidly. [O/R] Oil producers in the Permian, the largest shale basin in the country, and in the Bakken have already begun to slash output and curtail drilling in response to the price crash. Work on the Wink-to-Webster Permian crude oil project, in which MPLX has a 15% equity ownership, is advancing, the company said during its first-quarter results call. One hundred percent of the contractable capacity on the pipeline system is covered by MVCs (minimum volume commitments) or long-term contracts, a company executive said during the call. The line is expected to be placed in service in the first half of 2021. The Whistler natural gas pipeline project, which is expected to transport about 2 billion cubic feet per day (bcfd) of natural gas from Waha, Texas, to the Agua Dulce market in south Texas, also continued to progress, the company said.
Chevron Down to 5 Permian Rigs - Chevron is currently running five rigs in the Permian basin, the company’s chairman and CEO, Mike Wirth, revealed in a recent Bloomberg television interview. “We began the year with 17 rigs running in the Permian. We’re down to five right now,” Wirth said in the interview, which was published on May 1. “Production tends to lag rig activity and so what we’re seeing is production actually reflects wells that came on in the last half of 2019 the first quarter of this year…so our production actually is a little disconnected from the rig decline,” Wirth added. In its latest results statement, which was released on May 1, Chevron reported unconventional net oil-equivalent production of 580,000 barrels per day (bpd) in the Permian basin in the first quarter (1Q) of this year. This marked an increase of 48 percent compared to the same period last year, Chevron outlined in its 1Q statement. In 2019, Chevron’s production in the Permian increased 44 percent over 2018, according to its website. Chevron reported earnings of $3.6 billion in 1Q, compared with earnings of $2.6 billion during the same period in the year prior. The increase was driven by downstream margins and increased Permian production, Wirth revealed in Chevron’s 1Q statement. The company warned in its latest results statement, however, that financial results in future periods are expected to be “depressed as long as current market conditions persist”. “Chevron is responding to these unprecedented challenges by making changes to what we control, and with a commitment to protect the long-term health and value of the company,”
U.S. drillers cut oil & gas rigs to historic low -Baker Hughes (Reuters) - The number of operating oil and natural gas rigs fell to an all-time low - reflecting data going back 80 years - as the energy industry slashes output and spending to deal with the coronavirus-led crash in fuel demand. The rig count, an early indicator of future output, fell by 34 to a record low of 374 in the week to May 8, according to data on Friday from energy services firm Baker Hughes Co going back to 1940. The prior all-time low was 404 rigs in May 2016. Fuel demand has declined about 30% worldwide and companies are making drastic cuts to spending, laying off thousands of workers and closing production to offset a global glut. Consumption has picked up modestly in the last couple of weeks, but the overhang of supply is expected to last for months, if not years. Drillers have cut an average of 52 rigs per week since mid March after crude prices started to plunge due to the coronavirus and a brief oil price war between Saudi Arabia and Russia. U.S. oil rigs fell by 33 this week to 292, their lowest since September 2009, while gas rigs fell by one to 80, their lowest on record according to Baker Hughes data going back to 1987. “The great coronavirus derigging kicked off mid to late in the first quarter, impacting well starts across the major U.S. oil shale plays,” analysts at Enverus Rig Analytics said, noting the rig count was down 38% in April and 62% over the last year. Analysts expect companies will keep pulling rigs for the rest of the year and will be hesitant to activate many new units in 2021 and 2022. Raymond James projected the oil and gas rig count would collapse from around 800 at the end of 2019 to about 400 by the middle of the year and 200 at the end of 2020. The investment bank expects an average of just 225 operating rigs in 2021. The count in Canada already fell to a record low of just 26 rigs two weeks ago, according to Baker Hughes.
Refinery cuts, emerging crude production losses drive Permian volatility.-- Well, it’s happened. The first signs of crude oil and gas production curtailments in the Permian Basin materialized over the weekend. That has followed weeks of extreme oversupply conditions, growing storage constraints and distressed pricing, all to deal with the abrupt and unprecedented loss of refinery demand for crude oil due to COVID, not just along the Gulf Coast, where the lion’s share of the U.S. refineries sit, but also more locally in West Texas. The rapidly shifting supply-demand balance, first from reduced local refining demand and now also the emerging production cuts, is adding volatility to the spreads and flows between the West Texas basin’s regional hub at Midland, and downstream hubs at Cushing and Houston. Today, we look at how the Midland market has responded to the downturn in local refining demand, and how production losses will factor into the balancing act. We’ve done our best to keep on top of a quickly moving crude market, detailing the recent emergence of negative crude oil prices in One Way Out. We followed that with Future(s) Games, where we focused on crude oil pricing mechanisms, and last week in How Much More Can I Take, we considered the prospects and timing of crude oil and refined products storage constraints. We’ve also zeroed in on regional dynamics in the Permian, including the recent trend in spot prices for both crude oil and natural gas (see It’s Always Somethin’). Now, we dig into the details of how the recent flux in global markets has impacted the Permian oil supply and demand balance, as well as price spreads between the Permian and neighboring markets. We then evaluate what those price spread movements mean for crude oil flows on the pipelines leaving the basin.
Permian Basin natural gas pipeline could be blocked by lawsuit filed by Sierra Club - A natural gas pipeline under construction in the Permian Basin could be blocked in court by environmentalists alleging a federal agency ignored a court order that could have vacated permitting allowing the line to be built over bodies of water as it stretches from West Texas to the Gulf Coast. The Permian Highway Pipeline (PHP) owned by Kinder Morgan was planned to transport natural gas 428 miles from the Waha Hub near Pecos County, Texas to Katy, Texas about 30 miles west of Houston. The line would also be able to access connections to export and refinery markets on the coast. . Construction of the $2 billion project began in the fall of 2019, and it was expected to go into service by the end of 2020 with a capacity of 2.1 billion cubic feet of natural gas per day through 41-inch pipeline. The project met backlash from numerous environmental groups and local communities along the route, with Kinder Morgan settling with the City of Kyle in October 2019 for $2.7 million to protect the small town near Austin from “undue” harm associated with the pipeline. And on April 21, the Hays County Commission voted to rescind construction permits it had recently issued to Kinder Morgan for construction under county roadways, in response to a recent spill caused by the pipeline in neighboring Blanco County. The Commission instructed the County’s Transportation Department to send notice to Kinder Morgan to pause the work until a new policy was approved, per minutes from the Hays County Commission Court. The decision would stand, read the minutes, until Kinder Morgan complied with a notice of violation issued by the Texas Railroad Commission and provided a plan to avoid future groundwater contamination, while also providing Hays County with a geology report for each county road crossing.In its lawsuit filed on April 30, the Sierra Club also pointed to a decision issued by Chief District Judge Brian Morris of the District Court of Montana which on April 15 struck down the Army Corps of Engineers’ issuance of Nationwide Permit 12 (NWP12), which “authorized discharges of dredged or fill material” into certain waters as needed by pipeline projects. In his decision, Morris wrote that the permit violated the endangered species act as the Corps allegedly failed to consult with the U.S. Fish and Wildlife Service when it reissued the permit in 2017 for its five-year renewal.
Oil flows spell deep depression - Without energy, nothing gets done. And oil is not just one form of energy in the energy commodity complex; it is the energy source upon which our modern way of life depends. In fact, it is the main energy source running through the arteries of the global economy. Far from being a boon to the world, ultra-low oil prices signal that the global economy is flat on its back—even worse, flat on its back with two broken legs. Petroleum geologist and consultant Art Berman recently detailed the problem in this piece. Berman is the man who accurately predicted—starting way back in 2008—the persistent losses that shale oil and gas would produce for the companies that extracted them. The shale industry continuously vilified Berman for his analysis over the next decade, even as the industry was in the process of blowing 80 percent of investors' capital as of last year. With the arrival of the coronavirus, the coup de grâs has just been delivered to a shale oil and gas industry that was already on its knees. Perhaps the most important thing to understand about the current oil "glut" is that it is not merely the result of producing too much oil for an economy humming on all cylinders. It is primarily the product of a coronavirus-infested economy in which demand has dropped 20 percent in just a few weeks. As Berman points out, estimated U.S. oil consumption has returned to a level not seen since 1971. Energy is the very basis for economic activity. There is now 20 percent less oil flowing through the veins of the global economy, and economic activity is tightly correlated with oil consumption. Ergo, economic activity must be down significantly around the planet. Coal consumption is declining as well, but it is harder to measure in real-time. This piece suggests significant declines in Chinese coal consumption. And the clearing air in China and in practically every city around the globe suggests a lot less burning of everything that we call fuel. For comparison the U.S. Energy Information Administration reports that the decline in worldwide consumption of refined petroleum products between 2007 and the end of 2009 was 1.5 percent, the period now called the Great Financial Crisis (GFC). Total world energy consumption during the same period actually increased by 0.2 percent (though it declined by 1 percent between 2009 and 2010). We are currently looking at energy consumption declines of 20 times that for oil and probably many times that for total energy consumption. The latest consumption numbers for U.S. refined petroleum products do not provide any reason for optimism. It is not at all clear how under these circumstances we could now recover to our previous level of economic activity more quickly than we did after the GFC as some people are predicting. Our energy picture suggests that the world economy has further contraction ahead before even a slow recovery can begin.
TEXAS: State eases underground oil storage rules -- Thursday, May 7, 2020 -- Texas regulators are relaxing rules about where companies can store oil underground, raising concern among environmentalists about potential groundwater contamination and other dangers.
Texas Was The Model For OPEC, But It's 'Not Likely' To Limit Oil Production Now : NPR - In Texas, a proposal to cut the amount of crude that oil companies are allowed to pump from the ground appears dead. The regulator who proposed it — Texas Railroad Commissioner Ryan Sitton — says commissioners "still are not ready to act" on the plan, which would have cut production 20% to try and stabilize prices amid a historic oil glut. Regulators had been expected to vote on the plan Tuesday. Oklahoma and North Dakota have also been debating production limits. In Alaska, the private company that runs the Trans-Alaska pipeline has already imposed a ten percent cut in oil production from the state's North Slope. In Texas, the idea of a state intervention would have been unimaginable to most people just a few months ago, even though it's not without precedent. Somewhat confusingly, the Texas Railroad Commission oversees fossil fuel extraction, and has the power to limit crude production under a law dating back to the 1930's. It hasn't done so since 1972. But even if such a vote does not happen, the fact that the three member commission considered the proposal reveals just how serious the challenges facing the U.S. oil and gas industry are. At a hearing last month, Scott Scheffield, head of Pioneer Natural Resources, said it was time for the commission to mandate cuts again. He argued that his industry — which has enjoyed unprecedented expansion in recent years — couldn't be trusted to cut enough on its own. "Our industry has created so much economic waste that nobody will buy our stocks or own ours stocks," Scheffield said in a live-streamed meeting. "If the Texas Railroad Commission doesn't regulate long-term, we will disappear like the coal industry." But companies and regulators are divided over imposing production limits. Opponents say companies are making needed cuts on their own. They don't want to open the door for government control of industry.
Texas oil and gas regulators reject production cuts - Even as oil prices remain low, state regulators Tuesday dismissed a proposal to limit oil production as a way to prop up struggling producers. In a 2-1 vote, the Texas Railroad Commission rejected production cuts, which had been requested by some independent oil producers. “By allowing the free market to work, producers can determine for themselves what level of production is economical,” said Wayne Christian, chairman of the Texas Railroad Commission, the agency that regulates the oil and gas industry. Amid a global glut of oil, exacerbated by the coronavirus pandemic causing a severe drop in demand, crude prices have nosedived to record lows. Tens of thousands of Texas oil workers have lost their jobs. “The cold, hard truth of this situation is the price of oil is not going to stabilize until the pandemic is behind us and world is once again open for business,” Christian said Tuesday. “This problem is 90% demand.” While oil-producing nations globally have agreed to orchestrate production cuts, some companies — including Austin-based Parsley Energy — had pressed the Railroad Commission to intervene. But the proposal went against free-market instincts of the agency’s three elected commissioners — all Republicans — as well as the wishes of the state’s oil and gas trade associations, who worried that government intervention could lead to further meddling.
Shale Producers Eye Potential Fracking Revival at $30 Oil-- A pair of prominent shale producers said all they need is oil around $30 a barrel to consider bringing back curtailed crude output and fracking new wells. Diamondback Energy Inc. is curbing production this month by 10% to 15% and sending home most of its fracking crews for the whole quarter. The Midland, Texas-based company expects to end this year with more than 150 wells that were drilled but never fracked as U.S. producers avoid pumping oil into a vastly oversupplied market. Parsley Energy Inc., meanwhile, has curtailed a quarter of its output and temporarily abandoned its five-rig, two-frack crew program. The historic rout in crude prices amid the Covid-19 pandemic has spurred an unprecedented retreat from shale exploration. Producers from Chevron Corp. and Exxon Mobil Corp. to mom-and-pop drillers are curbing output as the world runs out of places to store additional oil supply. Benchmark U.S. crude futures rose 20% to $24.34 a barrel at 1:20 p.m. on the New York Mercantile Exchange, little more than two weeks before a precipitous collapse into negative territory. Still, they remain more than 60% below the 2020 peak of $65.65 touched in early January. When asked what oil price Diamondback needs before it turns the spigot back on, Chief Executive Officer Travis Stice said the company’s first priority would be restarting production that was choked back. Then, Diamondback would consider bringing back frack crews to tap supplies from wells that were drilled but never completed. “There’s a lot of factors that weigh into that, but you’ve got to have prices in the high-20s or low-30s before we kind of signal going back to work in an aggressive or even in a non-aggressive way,” Stice said on a call Tuesday. “As we evolve as an industry into this new world order, I think it’s going to look a lot different than what we’ve historically been accustomed to.”
Oil spill cleanup continues at village park lake in Marine - Leaders in the village of Marine believe it will take another two weeks for a crew to finish cleaning the oil spill at the Marine Heritage Park lake. A spill was first detected in an oil field north of Marine on April 19 and the spill was being contained by a series of three dams and vacuum trucks, according to Illinois Environmental Protection Agency spokeswoman Kim Biggs. However, during a “large” rainstorm on April 25, an estimated five barrels, or 210 gallons of crude oil flowed into the park lake, Biggs said in an email to the BND. A combination of salt water and oil leaked from the oil field when a pipeline broke. An estimated 40 barrels, or 1,680 gallons, of crude oil and 350 barrels, or 14,700 gallons, of salt water spilled after the pipe broke. The salt water and the crude oil traveled across a farm field, into a tributary to Marine Creek, and then into Marine Creek, Biggs said. Kimrose Operating Co. is the company that runs the oil field, according to Illinois Emergency Management Agency records. A company representative declined to comment Friday. Investigators do not know why the pipeline broke, according to the Illinois Department of Natural Resources, which is also investigating the spill. Another company has been hired to clean up the spill, village leaders said. Mayor John Molitor said the oil field is less than a half mile from the park lake.
Amid climate change fight, Rev. Jesse Jackson pushes for natural-gas pipeline – Axios - Breaking from other progressives, Rev. Jesse Jackson is calling to build a natural gas pipeline to serve an impoverished community near Chicago.This is one example of the complex tug of war between energy affordability and tackling climate change. The tension is poised to grow as America and much of the world careen into pandemic-fueled recessions.The move puts Jackson at odds with some Democrats and environmentalists who oppose fossil fuels because they drive climate change. The famous civil rights activist says the largely black community is being unfairly cut off from affordable energy. For several months Jackson has been working with local, state and federal officials in Illinois to get an $8.2 million, 30-mile natural gas pipeline built for a community in a rural part of Illinois 65 miles south of Chicago.
- Jackson, who has protested with environmentalists to oppose the Dakota Access oil pipeline, told me in a February interview: “I really do support the environmental movement.”
- However, he said, the people of this community — called Pembroke — have no gas at all and are paying exorbitantly high prices to heat their homes with propane.
- “When we move to another form of energy, that’s fine by me, I support that,” Jackson said. “But in the meantime, you cannot put the black farmers on hold until that day comes.”
- The area has about 400 homes, no manufacturing and only a few commercial establishments, said Mark Hodge, mayor of Hopkins Park, a town in the region.
- The community is 80% black and has an average annual income of less than $15,000, Hodge said. That’s compared to more than $60,000 nationally.
- The region, due at least partly to its rural setting, has never had access to natural gas. The topic is reaching the forefront now because Jackson has been focusing on it since last fall, largely at Hodge's request, the mayor said.
Desperate pipeline companies try to push ahead during pandemic - Winona LaDuke - It’s been looking bleak for Native people: the Minnesota Pollution Control Agency pushed ahead with hearings on the water quality permits for Enbridge’s Line 3, over public concerns. Initially proposed for public meetings in mid March, White Earth Tribal Chairman Mike Fairbanks called on Governor Walz to cancel the public meetings as high risk and postpone the regulatory process. MPCA Commissioner Laura Bishop instead held electronic town hall meetings. The lines clogged at times with Canadian oil workers, pretending they cared about Minnesota water permits. Two days of “meetings”, offering a minute and a half of telephone testimony to the public were taken by the MPCA. The White Earth Tribe was forced to put together comments while most of the tribal employees were off work, to meet the regulatory deadline for comments.Why the rush? Enbridge is desperate, most of the oil industry is desperate. It seems strange that the MPCA would value the feelings of Enbridge over public health. While most of us were sheltered in place, Enbridge has been moving workers into the north country, taking up small motels, into campgrounds with RVs, clearcutting, and moving in equipment and staging for an eminent pipeline move. The problem is that they do not actually have the permits. On February 3, the Minnesota PUC approved in a split decision the certificate of need and the route permits for Line 3. However, those rulings are not formal until issued for the record. Three months later there is no formal record. There are no water permits, and the MPCA process of “electronic town hall meetings” just got challenged by attorneys for Red Lake, White Earth, Honor the Earth, Friends of the Headwaters and other organizations. That’s just the beginning. Enbridge is hoping to put in a pipeline and now there’s no need for oil. That’s why they are hoping to move ahead. On April 20, the price of oil dropped to minus $37 a barrel. No one is buying, and oil producers are basically paying to have the oil purchased. There is no precedent for this in modern capitalism. Storage tanks of oil are full across the planet, and tankers with about 20% of US oil supply are sitting off the coast of California hoping that someone will drive. No one is. Or at least, not like the good old days.
Big Oil posts big losses during coronavirus crisis --The numbers are in: We now know just how badly the country's top oil drillers were hit by the coronavirus-fueled downturn. Three of the four biggest U.S. oil and gas producers posted multimillion to multibillion dollar losses in their latest earnings reports, a sign of just how damaging the drop in energy demand because of the covid-19 pandemic has been to the domestic oil business. ConocoPhillips, the third-biggest U.S. oil driller by market capitalization, announced late last week that it lost $1.7 billion during the first three months of the year. Phillips 66, the fourth-largest, reported a first-quarter loss of $2.5 billion.And ExxonMobil, long the nation's top energy company, bled $610 million during the first three months of 2020, when oil globally lost two-thirds of its value. It is the first time the company has posted a quarterly loss in the past three decades. “We've certainly weathered the ups and downs of many price cycles,” its CEO Darren Woods said during an earnings call Friday. “However, I have to say, we've never seen anything like what the world is experiencing today.”The companies will try to sustain their bottom lines by cutting production in the Permian Basin. The storied oil-rich region stretches through western Texas and southeastern New Mexico, and enjoyed a surge in production with the advent of hydraulic fracturing technology. But now with the drop in the price of oil making Permian crude too expensive to get out of the ground, that boom is quickly turning into a bust.Exxon said it expects to ramp down Permian rigs by about 75 percent and end the year with only about 15 rigs. Altogether, the company is slashing its capital spending for 2020 by 30 percent. Chevron, the nation's No. 2 oil company, said it expects to cut 125,000 barrels per day from its original production target for the Permian by the end of the year. It began the year running 17 rigs in the Permian but now is running only five. And ConocoPhillips said it expects to cut production not just in the Permian, but across North America by about 460,000 barrels per day by June. Overall, output from the top American and European oil majors is set to drop by nearly 11 percent next quarter,according to an analysis by Reuters. The European majors BP and Dutch Royal Shell saw declined profits to start 2020 too, with Shell slashing its dividend to shareholders for the first time since World War II.
Oil and gas companies set to lose $1 trillion in revenues this year - Oil and gas exploration and production companies, or E&Ps, are slated to lose a staggering $1 trillion in revenues in 2020, according to analysis by research firm Rystad Energy. The E&P industry, which includes oil majors, made $2.47 trillion in revenues globally last year, the firm says. But this year it's projected to bring in $1.47 trillion, reflecting a 40% decline year-on-year. It comes as the coronavirus pandemic and ensuing lockdowns cripple demand and force companies to slash spending and cancel projects. Before the virus began to hit economies, Rystad projected E&P revenues for 2020 to reach $2.35 trillion. Returns for 2021 are now also projected lower, at $1.79 trillion compared to a forecast of $2.52 trillion before the pandemic. The slashed revenues, a similar story for most industries amid the worst economic downturn since the Great Depression, have clearly manifested themselves in the industry's equity market position. The energy sector is shrinking so dramatically that it's become the second-smallest group in the whole S&P index. The industry now represents just 3% of the index, compared to 15% a decade ago and 30% in 1980. The International Energy Agency predicts a record demand loss of 9.3 million barrels per day (bpd) in 2020, as all but essential businesses across many major economies are forced to remain closed and millions of residents shelter in place for an indefinite period of time. Air travel has dropped by 95% in the U.S. year-on-year, a reflection of the global travel industry as a whole. The price of global oil benchmark Brent crude is down more than 60% year-to-date to its lowest in more than 20 years, and this month saw an oil futures contract turn negative for the first time in history as the world runs out of storage space, forcing producers to take rigs offline and shut in production. Exxon is cutting its capital spending globally by 30%. Exxon CEO Darren Woods expects oil demand to fall by between 25% and 30% in the immediate term. Chevron, BP, Shell and Saudi Aramco are among other major producers that have announced spending cuts of between 20% and 25% in their operations globally. As an industry, oil companies have so far slashed $54 billion in planned spending, Reuters reported this month. U.S. shale, with higher production costs than many foreign competitors, is the largest contributor to this so far, with rigs and projects dropping like flies. The Energy Information Administration reported that U.S. production has now plunged by 1 million bpd, pumping 12.1 million bpd last week compared to a record 13.1 million bpd in mid-March. "This year might be marked by the lowest project sanctioning activity since the 1950s in terms of total sanctioned investments, dropping to $110 billion, or less than one-quarter of the 2019 level, with most of the projects being deferred," Rystad wrote.
Coronavirus Downturn May Nullify 10 Years of Oil Demand Growth - Up until early April the oil market was being clobbered by the double whammy of a supply glut from a Saudi-Russian price war and demand destruction on an unprecedented scale caused by the coronavirus or Covid-19 global pandemic. The short-lived situation was unique in recent history. For instance, the price crash of 2008-09 was down to a demand slump in the wake of the global financial crisis while the 2015-16 downturn was caused by oversupply. But the current crisis brought both negative elements together for nearly a month before market attention turned back to demand after Moscow and Riyadh helped ink a historic 9.7 million barrels per day (bpd) cut on April 9 to “balance” the market. Those cuts kicked in on May 1 but market balance would be very hard to find, especially since the forecasting community remains divided over the extent of near-term demand destruction. At the start of the crisis in February, some were still suggesting nominal demand growth might still occur in 2020, even if projects were revised substantially down from pre-crisis growth predictions of 1.2-1.4 million bpd. Those projections would have put total global demand just north of a 99.67 million bpd average seen in 2019. But as the pandemic spread well beyond its point of origin in China to wider Asia, Europe and North America – the reality began to bite. From the outset, demand in China, the world’s second-largest crude oil consuming nation which imports on average 14 million bpd was badly hit. Now the biggest crude global consumer – United States – is in the grip of the pandemic, as are India, Japan and South Korea who are the world’s third, fourth and fifth-biggest consumers in that order. Deep into the pandemic airlines are grounded, vehicles are off road, factories are idle, production lines are offline and petrochemical demand is low because we are buying and consuming less, barring essentials wherever we might happen to be. So where does demand go from here? Restrictions and lockdowns may last for most of the second quarter and perhaps even half of third quarter. Furthermore, data suggests 187 countries currently have varying degrees of restrictions. Those will ease at a differing pace implying any demand recovery will not be uniform. Getting a complete handle on things will only occur once a vaccine can be found, which appears to be months or even up to a year away.
Fossil Fuel Companies Try Again to Get Colorado Climate Case Moved to Federal Court - Several Colorado communities squared off against Big Oil on Wednesday, before a three-judge panel in a virtual U.S. 10th Circuit Court of Appeals courtroom, over the perennial issue in climate liability lawsuits: jurisdiction. Richard Herz, an attorney with Earth Rights International, argued on behalf of the City and County of Boulder and San Miguel County that last year’s decision by federal district court Judge William MartÃnez to keep the case in state court should stand, and that the 10th Circuit’s legal leeway to review the lower court’s decision was limited. Representing ExxonMobil and affiliates of Suncor Energy, attorney Kannon Shanmugam countered that the case belongs in federal court, arguing that under the Clean Air Act, as well as precedents set in some other climate cases, federal law preempts state law when it comes to greenhouse gas emissions. Judge Carolyn McHugh seemed unpersuaded. “I have a hard time accepting a complete preemption argument under the Clean Air Act,” said McHugh, interrupting Shanmugam’s argument,“when the statute specifically indicates that it doesn’t displace state law.” The panel questioned Herz closely as well, with Judge Carlos Lucero asking for an explanation of how the communities have calculated the fossil fuel firms’ monetary liability. Herz compared his case to past litigation by states against tobacco firms, as well as more recent opioid lawsuits. “All these things are about sales and misrepresentations,” he told Judge Lucero, ”and local governments have sued for local injuries in these areas, in state court, under state law.” In late March, the Colorado communities sent a letter to the court arguing that the March 2020 decision by the 4th U.S. Circuit Court of Appeals, in which the court ruled that a similar suit by the city of Baltimore belonged in Maryland state court, has set a precedent that applies in the Colorado case. In the lawsuit, first filed 2018, the Colorado communities are seeking monetary damages from the fossil energy firms to cover the costs of dealing with the intensifying effects of climate change, including more frequent and destructive heat waves, wildfires, droughts, and floods. They argue that the firms are liable for these costs because they knowingly misled the public for decades on the link between burning fossil fuels and rising global temperatures, while continuing to produce and sell “a substantial portion of the fossil fuels that are causing and exacerbating climate change.”
ENERGY TRANSITIONS: Coronavirus could drive 'mass abandonment' of oil wells -- Tuesday, May 5, 2020 -- In the wake of the coronavirus pandemic that's shaken the global oil sector, oil states fighting to restart their economies may face another kind of crisis.
Big Oil Fears Keystone XL Ruling Means End of Easy Pipeline Permits - Steve Horn - On April 15, Judge Brian Morris nullified water-crossing permits in Montana that were granted for the Keystone XL, a major setback for the long-embattled tar sands oil pipeline. The ruling came just days after Keystone XL owner TC Energy, formerly known as TransCanada, obtainedbillions of dollars in subsidies from the Alberta government as global oil prices plummeted.The oil and gas industry has taken notice. Seemingly just a ruling on Keystone XL — the subject of opposition by the climate movement for the past decade — the ruling could have far broader implications for the future of building water-crossing pipelines and utility lines. In his decision, Judge Morris cited a potential violation of the Endangered Species Act when he ordered the U.S. Army Corps of Engineers to do a deeper analysis of potential impacts to protected species. Morris required the Corps to demonstrate whether or not it could construct the pipeline without harming endangered species, such as the Pallid Sturgeon or the American burying beetle. Instead, the Army Corps “failed to consider relevant expert analysis and failed to articulate a rational connection between the facts it found and the choice it made,” Morris ruled, when the Corps gave Keystone XL the initial green light. The original July 2019 complaint in that case — filed by Northern Plains Resource Council, Bold Alliance, Sierra Club, Natural Resources Defense Council, and Center for Biological Diversity — also argued that the Army Corps had violated the National Environmental Policy Act (NEPA) in using an obscure regulatory lever to fast-track the review process. Known as Nationwide Permit 12, the permit only requires a short environmental analysis compared to the more robust environmental impact statement required under NEPA for other major infrastructure projects. But Morris also wrote that the decision applied not just to Keystone XL, but to all major federal projects aiming to utilize Nationwide Permit 12, calling for it to be “vacated pending completion of the consultation process and compliance with all environmental statutes and regulations.” Just two days after this decision, Army Corps regulatory program Chief Jennifer Moyer wrote in an email obtained by the Associated Press that the agency should suspend the program indefinitely “out of an abundance of caution” until the issue is resolved legally. The Trump administration has already requested a procedural halt on implementing Morris’ decision until its potential appeal weaves its way through the legal system. “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 U.S. Department of Justice attorneys wrote on behalf of the Army Corps.
'Like watching a train wreck': The coronavirus effect on North Dakota shale oilfields – (Reuters) - Oil executive Bill Kent was with fellow managers in the Colorado board room of Resource Energy headquarters on April 20 when benchmark U.S. crude prices collapsed to minus $37 a barrel. “As we were sitting around the board room watching what was happening with prices, it was like watching a train wreck,” said Kent, vice president of engineering and operations at Resource Energy, backed by private equity giant Apollo Global Management. With businesses locked down and billions of people staying at home, demand for oil to fuel cars, planes and industry has dropped around 30% worldwide. The resulting supply glut has pushed U.S. crude prices well below production costs, forcing companies to start winding down operations. Producers are shutting down the higher-cost output first - and those are also the operations likely to stay shut the longest. The Resource Energy team’s discussion turned to the remote Bakken shale region in North Dakota where the company, a relatively small producer, operates. Costs of extracting are some of the highest in the United States. So are the costs of transporting due to limited storage and the distance to refineries and consuming centers. Oil producers in the Bakken, which sprawls across North Dakota and eastern Montana, on average break even at $46.54 a barrel, according to an analysis by Deutsche Bank. That is well above the around $40 a barrel in the Permian basin, the largest U.S. shale field. Bakken crude BAK- fetched $3.40 a barrel on April 21. It has since recovered to about $14, still below the cost of producing. The team at Resource Energy realized they would need to consider shutting down the remaining 20 percent of output still operating in the Bakken shale region, Kent said. North Dakota, second only to Texas in oil output among U.S. states, was taking a big hit. In just one day in late April, some 60,000 bpd were shut in the state. Output has dropped by at least 400,000 bpd since March 1, nearly a third of the state’s around 1.4 million bpd output before the crisis. State officials expect the volume shut in to rise further. “This is truly unprecedented,” said Lynn Helms, director of North Dakota’s Department of Mineral Resources, the state regulator overseeing oil production. In the days following the price collapse, oil companies sent teams out to shut wells.
Task force aims at incentives for oil drillers amid virus (AP) — Hoping to avoid what North Dakota Gov. Doug Burgum has called a potential “economic Armageddon,” state and industry officials have formed a group intended to help oil and gas producers recover from falling crude prices due to meager demand amid the coronavirus outbreak. State Mineral Resources Director Lynn Helms announced the Bakken Restart Task Force on Wednesday as the number of oil wells in the state has decreased by more than 40% in recent weeks and oil production hit its lowest level in five years. Helms said in a statement the group is focused on proposals for regulatory relief, economic stimulus, tax relief and low-cost financing. The group is scheduled to meet weekly. Oil is a key contributor to the wealth of North Dakota, the No. 2 producer in the U.S. behind Texas. North Dakota’s oil production had exploded in the past decade with improved horizontal drilling techniques into the Bakken shale and the Three Forks formation below it. Before the pandemic devastated the U.S. oil industry, daily oil production in North Dakota was at a near-record 1.45 million barrels daily in February, the latest figures available. There were more than 16,100 wells operating at that time. Helms said Wednesday some 6,800 wells have been idled in recent weeks, amounting to about 450,000 barrels of lost oil production daily, a number he called “staggering.” Ron Ness, president of the North Dakota Petroleum Council, said oil has dipped to about 1 million barrels daily, the lowest production since 2015. The number of wells that have been idled in recent weeks is more than double the number of all wells in the state in 2006, he said.
OIL AND GAS: 14 states to court: Keep pipeline open during NEPA review -- Tuesday, May 5, 2020 -- Fourteen state attorneys general say a shutdown of the Dakota Access pipeline would hurt farmers and increase environmental risks if railways are forced to take on more oil shipments.
Judge Vacates Oil and Gas Leases on 145,000 Acres in Montana – NYTimes — A federal judge on Friday vacated 287 oil and gas leases on almost 150,000 acres of land in Montana, ruling that the Trump administration had improperly issued the leases to energy companies in 2017 and 2018. The judge, Brian Morris of the United States District Court for the District of Montana, said the Interior Department’s Bureau of Land Management failed to adequately take into account the environmental impacts of the drilling. In particular, Judge Morris found that the officials had not accounted for the drilling’s impact on regional water supplies and the global impact that the increased drilling would have on climate change. The decision is at least the third such legal loss that criticized the Trump administration for failing to consider the cumulative impacts of expanding fossil fuel production on the warming of the planet. It comes as the Trump administration is seeking to eliminate the legal requirements that the government take such impacts into account at all. Judge Morris wrote that in issuing the leases, the Trump administration’s failure to provide the legally required environmental analyses “largely relates to the absence of analysis rather than to a flawed analysis. In other words, the Court does not fault B.L.M. for providing a faulty analysis of cumulative impacts or impacts to groundwater, it largely faults B.L.M. for failing to provide any analysis.” Judge Morris sent the case back to the Bureau of Land Management and ordered the agency to perform the legally required environmental analyses before reissuing the leases. Derrick Henry, a spokesman for the bureau, wrote in an email: “With all due respect, we disagree with the Court’s conclusion, and the B.L.M. stands by its analysis in following the letter of the law to issue oil and gas leases in Montana. Regardless of the ultimate outcome of this dispute and despite the attempts of radical, special interest groups, the Department and the B.L.M. will continue to work toward ensuring America’s energy independence while preserving a healthy environment.” Efforts by President Trump to deliver on his campaign promises to help the oil, gas and coal industries and roll back President Barack Obama’s signature environmental policies have repeatedly been blocked by the courts. Many have been denied for reasons similar to those given by Judge Morris in Friday’s decision: The administration did not follow correct legal protocol in justifying its actions. In particular, Judge Morris followed other federal judges and cited the failure of the Trump administration to follow the provisions of the 1970 National Environmental Policy Act, known as NEPA. It requires the federal government to perform analyses of both the immediate local environmental impact of drilling and infrastructure projects and broader, cumulative effects of increased fossil fuel pollution on the planet. In recent years courts have interpreted that requirement as a mandate to study the effects of allowing more planet-warming greenhouse gas emissions into the atmosphere. In 2018, a federal court in New Mexico also concluded that, under NEPA, the Bureau of Land Management was required to consider the cumulative climate impacts of its oil and gas leasing decisions. In 2019, a federal court in Washington, D.C., reached the same conclusion.
Series of failures contributed to Alaska oily water spill (AP) — A succession of mechanical failures led to a persistent spill of oily water in Port Valdez that lasted nearly two weeks, officials said. By the end of last week, crews had recovered 14 barrels of oil from a contained area near a boat harbor at the Valdez Marine Terminal, The Anchorage Daily News reported. More than 240 people are involved in the response to the spill of North Slope crude oil discovered on April 12. The amount of oil spilled is unknown. “The outflow is currently discharging high volumes of snow melt and rain water with a minor sheen being recovered from the tanks,” according to the spill incident management team. The team consists of terminal operator Alyeska Pipeline Service Co., the state Department of Environmental Conservation and the U.S. Coast Guard. There were three failures that led to the spill, Kate Dugan of Alyeska said. A valve in a pipe near a collection well failed to work. The pipe is part of a pipeline system that carries ballast water and water from the well. Debris in the valve prevented full closure. Finally, a pump should have engaged to deliver the liquid in the collection well into the ballast water system as the level of oily water rose. A water-level indicator failed to activate the pump, Dugan said. A single problem normally causes a spill, said Graham Wood, manager of the prevention, preparedness and response program with the Alaska Department of Environmental Conservation. “It’s not common for a series of misfortunes” to be the cause, Wood said. Wood said the response is on track and declined to discuss possible future enforcement actions.
As spill response enters third week, oil continues to make its way into Port Valdez - Entering the third week after an oil spill was identified at the end of the trans-Alaska Pipeline, responders say that some oily water is still making its way into Port Valdez. Kate Dugan, communications officer for the Alyeska Pipeline Service Company, which operates the trans-Alaska Pipeline, said that crews made major progress late last week in stemming the flow of oily water when they located a pipe that was discharging into the port. “We couldn’t see the end of the pipe until at some point last week, and it turns out it’s some part of a historical preconstruction era piping system, so it wasn’t on my of the current drawings that we could find,” she said. Crews found the system in historical diagrams of the area, said Dugan. Late last week, crews installed a treatment system, made up of three successive tanks from which the oil sheen at the top was skimmed. But even after treating that oily water, Dugan said there is still a sheen in water being discharged into the port. Though some oil is still getting into the port, Dugan said that responders have been able to reduce the total boomed area by about two thirds and that they are gradually decommissioning some of the response vessels. It is still unclear how the water made its way from the sump, a four-foot-diameter, sixteen-foot deep tank, that overflowed after a pump malfunctioned, into the old underground piping system. Dugan said that crews are still excavating around the area to try to determine the flow path of the oil in the ground. “We have to do it systematically, we have to engineer and survey because there’s so much underground utilities and piping systems around the terminal so it’s challenging work,” she said. Dugan said it might be weeks before Alyeska can complete an investigation to determine exactly what went wrong to cause the check valve in the sump and the pump to malfunction. So far, over fifty thousand gallons of oily water have been recovered from Port Valdez from which 590 gallons of pure oil have been recovered. The final amount won’t be known until off-site metering is completed.
Oil spill in Herschel, Sask., largely contained to Enbridge property, says Canada Energy Regulator - An above-ground oil spill in Herschel, Sask., was largely contained to Enbridge company property, said a release from the Canada Energy Regulator (CER). CER said about 150 cubic metres of sweet crude oil spilled at an Enbridge pump station. Enbridge said a limited amount of oil impacted nearby municipal land and no waterways were affected. The company told CER wildlife protection measures are in place and surface clean-up is underway. A CER inspection officer is on site, the release said. Herschel is about 150 kilometres southwest of Saskatoon. Pipelines need more monitoring: FSIN FSIN Chief Bobby Cameron said there needs to be "beefed up" monitoring of pipelines, including having First Nations people helping with the monitoring. "This incident shows that there is always a risk of leaks, even on recently built pipelines," said FSIN Chief Bobby Cameron in a news release. "First Nations have reason to worry about the potential oil leaks from all pipelines that are near their lands." The release notes that the Line 3 pipeline in Canada impacts 154 Indigenous communities. The CER release notes that the Enbridge Line 3 Indigenous Advisory Monitoring Committee was notified of the incident and is being kept up to date.
Cleanup underway at Enbridge pump station following oil spill in Herschel, Saskatchewan - The Canada Energy Regulator (CER) is overseeing an oil spill cleanup in Herschel, Sask., after Enbridge notified the federal agency of an above ground release of sweet crude oil. The incident occurred at the company’s Line 3 pump station and involved approximately 150 cubic metres of oil. The CER says there is no risk to public safety. According to Enbridge, the majority of the spill was contained to the company’s property with limited oil migrating to adjacent municipal land. No watercourses are affected and precautionary wildlife measures are in place, says the CER. Surface cleanup is underway, with the removal of contaminated soil to follow.
Trying to contain oil leakage in East Fjords - By the end of May, the Icelandic Coast Guard plans to make the first step toward preventing further leakage from the wreck of a British oil tanker, lying at the bottom of Seyðisfjörður, the East Fjords. The Icelandic government recently decided to allocate ISK 38 million (USD 258,000; EUR 238,000) toward the project. The tanker, El Grillo, was destroyed in the fjord by German military aircraft on February 10, 1944. There were no casualties in the attack, but the tanker sustained considerable damage and was subsequently sunk. The wreck is 134-m (441-ft) long, weighing 7,264 tons. Not surprisingly, there was an extensive oil spill, since the ship had the capacity to carry 9,000 tons of oil. In 1952, about 4,500 tons of oil were pumped from the ship. In 2001, another 60 tons were pumped out, but an estimated 10-15 tons of oil still remain. The heavy crude oil thickens in cold weather, but seeps faster through holes in warm weather and forms an oil slick on the surface of the ocean, causing the death of large numbers of birds. An inspection of the wreck last fall revealed the source of the leakage to be the corroding cover of a manhole, leading to one of the ship’s 36 tanks. The Coast Guard plans to pour concrete into a cast on top of the manhole, in order to close it. A stainless steel pipe and a valve will be installed, going through the concrete to the manhole, through which it will be possible to drill later on, in order to pump out oil. The Coast Guard ship Þór will sail to the location; at least five to six divers will participate in the operation, and there will be a diving chamber on board the ship. Þór will, in addition, be equipped with pollution prevention and pollution cleaning equipment during the operation. The plan is just to close the manhole with concrete, not to pump oil from the tanker. Due to corrosion of the tanker, however, this may only suffice to stop leakage of oil temporarily. The deck of the tanker is at a depth of 32 m (105 ft), and a special barge will be used for the work. A special type of concrete will be poured with a concrete pump through a hose from the barge into the cast around the manhole. Special attention will have to be given to ammunition and shells on board when diving around the wreck. Three of the divers participating in the project will explosives experts as well. Last fall’s expedition revealed 23 shells on board the ship. In the past, depth charges have been removed from the tanker as well.
Ecuador’s Amazon communities sue over oil spill – Indigenous communities in Ecuador's Amazon region have filed a lawsuit against the government and oil companies after a devastating oil spill polluted rivers and deprived them of drinking water. The pollution in Orellana province near the Peruvian border was the result of an April 7 landslide that ruptured 3 pipelines, spewing 15,000 barrels of oil into nearby rivers including Amazon tributary the Napo, a community leader and an NGO said. (READ: Torment in Ecuador: virus dead piled up in bathrooms) "The families living on the river banks are lacking food and no longer know where to find water to drink, or with which to bathe," Marcia Andi, a Kichwa and leader of the Mushuk Llacta community told AFP by phone. Around 27,000 indigenous people from the Kichwa and Shuar tribes living along the Coca and Napo rivers are affected by the spill, according to Maria Espinosa, a lawyer with the Amazon Frontlines NGO. Tulong Anakpawis and Purple Action for Indigenous Women's Rights (LILAK) help communities by getting a permit from the local government units or directly sending money to community leaders They are seeking "immediate measures to guarantee the supply of water, food, and access to health for the populations that have been affected," Espinosa told AFP, adding that aid provided to date was "insufficient" for the communities' needs. State oil company PetroEcuador, named in the suit, said it had distributed 500,000 liters of water in containers to 59 indigenous communities affected by a spill. It said one of its pipelines had been ruptured and later repaired. The company said it had begun environmental cleanup work that also included the Quijos river. A second company, OCP Ecuador, was also named as it owned one of the ruptured pipelines. Local communities accuse the companies of not alerting them to the spill. Amazon Frontlines, which has been gathering evidence of the impact, said the spill is estimated to be the largest in the region since 2004.
Small amount of oil seeped into river from GPL Kingston complex - An oil spill was discovered yesterday, 2020 May 6 within the compound of the Guyana Power and Light Inc. (GPL Inc.) Kingston Power Complex. A small amount of the spill seeped into the Demerara River. After the discovery, GPL’s personnel expedited industry standard safety, health and environmental procedures to contain the spill. The general public is hereby reassured that GPL’s efforts to contain the spill have thus far proven successful. GPL wishes to advise the general public that our company embraces industry standard fuel management practices and a thorough investigation will be conducted to prevent a recurrence.
Depressed demand and falling prices challenges LNG sector - The global liquefied natural gas (LNG) sector has been hit by supply overhang followed by Covid-19-induced economic slowdown and lower demand worldwide, says data and analytics company GlobalData. “Due to the sharp fall in oil prices, spread between oil-indexed long-term LNG contracts and spot contracts have considerably reduced. This can make it challenging for LNG producers to meet their revenue targets. In addition, a rapid decline in gas demand is affecting financing of capital-intensive new liquefaction projects, leading to inordinate delays and capex reductions,” explained Haseeb Ahmed, Oil and Gas analyst at GlobalData. To keep a check on spends, several operators are delaying their upcoming LNG projects. Operators are reducing their expenditures for 2020 as a measure to counter the impacts of Covid-19. Woodside Energy and Exxon Mobil have resorted to downsizing their capex by 60% and 30%, respectively, for 2020. In the meanwhile, British Petroleum has pushed the timeline for its Tortue FLNG project from 2020 to 2023 in response to the Covid-19 impact. Similarly, Qatar Petroleum has also postponed the project timelines of its Ras Laffan North Field LNG terminal development by a year to 2025. “A silver lining amid all the chaos induced by the pandemic outbreak is increased opportunities for new entrants to the LNG sector. Global LNG oversupply, as well as low LNG prices, might encourage new countries and companies to start importing LNG, contributing to LNG industry growth. Sustained low LNG prices will encourage several gas-importing countries to switch from coal and oil to cleaner natural gas,” Ahmed concluded.
Credit Risk: Identifying Early Warning Signals In The Oil And Gas Industry - This article provides a deep-dive analysis on the credit risk impact of the European Oil and Gas industry which takes into account the consequences of the COVID-19 pandemic, causing oil prices to plummet on oversupply and weakened demand. The analysis covers European public companies in the Oil and Gas sector between January 2, 2020 and April 16, 2020 and utilises S&P Global Market Intelligence’s Probability of Default Model Market Signals (PDMS) which captures equity market sentiment, providing signs of potential default for 71,000+ public companies[1]. The oil price war between Saudi Arabia and Russia came to an end on April 13, 2020 and the Organization of the Petroleum Exporting Countries (OPEC+) amongst other oil producing nations agreed to collectively cut production. The initial fall out and subsequent trigger for a decline in oil prices came in early March when Saudi Arabia and Russia could not agree on production cuts given the reduced demand from China. A series of key events from January 2020 until the middle of April 2020, provided early warning signals of a deterioration in credit risk which can be seen via PDMS. Table 1: Key Oil and Gas Industry Events and Median PDMS Scores for Europe News of weakening oil imports and a subsequent global economic slowdown began to surface which raised concerns in the oil markets towards the end of January 2020 (See Table 1). This event was captured by the PDMS early warning signal on January 24, 2020 and further PDMS early warning signals were observed over the course of March and April. These early warning signals mirror key industry events such as OPEC+ breakdown, Saudi Arabia cutting its crude prices, and the eventual OPEC+ agreement. Figure 1 shows the combined PDMS (%) for the Oil and Gas industry in Europe, PDMS early warning signals. The PDMS early warning signal unit is normalized in respect to the number of rating actions (e.g. if the maximum number of observed rating actions per day is 10 then the PDMS early warning signal value in the same period will have a signal equal to 10 plus one). The early warning signs from PDMS were also observed on February 24 2020 and March 9 2020 ahead of the OPEC+ disagreement on supply cuts on March 6 2020, and Saudi Arabia cutting its crude prices three days later on March 9, 2020. Post the OPEC+ production cuts on April 13, 2020, the PDMS model indicated that the market is not fully satisfied with the outcome, flagging further early warning signals on the April 16, 2020.
Oil spill found in Israeli stream - An oil spill was discovered by the Environmental Protection Ministry in the Gdora stream, which runs from Kiryat Ata to Kiryat Biyalik.Members of the Kishon River Authority are working with municipal staff to clean up the spill. The Green Police has opened an investigation into the issue.
Russian oil output falls near to OPEC+ target - sources - (Reuters) - Russia’s oil output in the first five days of May fell to 8.75 million barrels per day (bpd), close to its production target of 8.5 million bpd for May and June under a global deal to cut crude supplies, two sources familiar with the data told Reuters. Together with gas condensate, or light oil, which is not part of Russia’s target, the country’s output was 9.5 million bpd for May 1-5, the first time it has fallen below 10 million bpd since August 2009. While the latest data, which showed production of 1.296 million tonnes per day including gas condensate, was only for the first few days since the deal kicked in on May 1, it shows Russia is following through on its pledges so far. Russia’s Deputy Energy Minister Pavel Sorokin said in an online interview that domestic oil producers are striving to reach the target as soon as possible. He also said that the global oil demand declined by around 30% last month and the fall has eased since then. However recovery to pre-crisis levels would not be achieved quickly. Sorokin added that some countries, where international majors work, may have difficulties with sticking to targets under a global oil output cuts deal. He didn’t named those countries. Traders and industry sources said that Iraq has yet to inform its regular oil buyers of cuts to its exports, suggesting it is struggling to fully implement the cuts deal. Reuters uses a ratio of 7.33 barrels per tonne to calculate the daily output in barrels. Russia’s gas condensate output is typically about 700,000-800,000 barrels a day.
Saudi Arabia gets Moody's downgrade, prepares for 'painful' measures — but can likely weather crisis - Saudi Arabia is preparing to enact "strict, painful measures" in the face of its worst growth contraction in two decades brought on by the twin shock of coronavirus lockdowns and low oil prices, its finance minister Mohammed al-Jadaan said in a sobering interview over the weekend. The oil-rich kingdom, in the midst of historic social and economic liberalization, is going to have to slash projects and spending as it sees its foreign currency reserves shrinking at a record pace, its fiscal deficit widening and its risk assets deteriorating. Forecasts for GDP contraction this year are as steep as -3.2%, while ratings agency Moody's downgraded the country's sovereign outlook to negative from stable on Friday. Aside from the risks to the kingdom's fiscal strength from the pandemic and oil price shocks, further risks lie in "the uncertainty regarding the degree to which the government will be able to offset its oil revenue losses and stabilize its debt burden and assets in the medium term," Moody's wrote. "We must reduce budget expenditures sharply," al-Jadaan told Al Arabiya TV on Saturday. "Saudi finances need more discipline and the road ahead is long." The striking change in tone from the minister, which just ten days prior was more vocally optimistic and spoke of the country's resilience to deal with the situation, was not taken well by markets: Saudi Arabia's stock exchange, the Tadawul, dropped more than 7% during trading the following day. While al-Jadaan in April suggested additional borrowing on international markets, this time he said that "all options for dealing with the crisis are open." "The list is extremely long," the minister said of the cost-cutting possibilities. But likely high on that list are some of the multibillion dollar mega-projects in areas from tourism to infrastructure that fell under Crown Prince Mohammed bin Salman's ambitious Vision 2030, meant to drive private industry and diversify the kingdom's economy away from oil. Still, despite facing what may be the greatest period of uncertainty in its modern history, Saudi Arabia is in a better position than most to weather this crisis. This is thanks to the sizable wealth buffers it's built up over the previous two decades — including $473 billion in international reserves as of March, according to the Saudi Arabian Monetary Authority — the highest of any country in the Gulf and broader Middle East. Saudi Arabia's debts are also low by global standards, and it has easy access to capital markets for borrowing, as its bond issuances of the past two years — oversubscribed many times over — demonstrate. Its $7 billion bond issuance in mid-April reportedly saw some $54 billion in orders by investors. "Though the outlook is challenging, Saudi Arabia has significant balance sheet strength on which it can draw to ensure that the fiscal deficit is adequately funded and the investment programme remains on track," Ehsan Khoman, head of MENA research and strategy at Japanese bank MUFG, wrote in a note Monday. "Stability will come at a cost, however, and we see public debt rising to 31.6% of GDP this year – the highest level since 2005," Khoman wrote, adding that MUFG expects foreign currency reserves to drop by $47 billion this year, though they will remain ample, accounting for nearly three years of import cover. Analysts at Moody's agree on the point of Saudi fiscal strength, despite the crisis and ratings downgrade, affirming its issuer rating of A1. "Saudi Arabia's A1 rating is supported by the government's still relatively robust, albeit deteriorating, balance sheet," Moody's wrote, "which is underpinned by a still-moderate debt level and substantial fiscal and external liquidity buffers."
Global Oil Glut Set to Halve in May - The global imbalance between oil supply and demand is set to halve to 13.6 million barrels per day (bpd) in May. That’s according to a new Rystad Energy analysis, which predicted a further fall to 6.1 million bpd in June. Rystad warned, however, that despite the improvement, the stock build will still overwhelm remaining global storage, which it says will fill “in weeks”. “While this may seem like a drastic improvement from April, the oil market is not magically fixed,” Rystad Energy Oil Market Analyst Louise Dickson said in a company statement. “The storage issue still looms large and will spill over onto trading floors, as buyers are left with crude they cannot physically place, and into the boardrooms of oil companies which must make very costly but necessary decisions to scale back production and give the market some breathing space,” Dickson added. According to Rystad, if sufficient production isn’t shuttered by May 19 - the expiration of the WTI June 2020 contract - then the potential remains for another “nightmare WTI price collapse”, which it does not rule out spreading to other crude blends. “However, given that most oil futures outside of WTI do not require the buyer to physically take oil delivery, and instead have cash settlement options, the destruction to other benchmarks should be tamer,” Rystad stated. Rystad outlined that it expects the oil price bottom is “in front of us rather than behind us” but added that it still believes in an oil price recovery, “possibly starting as early as June”. Rystad also highlighted that it sees a risk for a tight market in 2022 with prices “much higher than pre-crisis levels”. “This will be facilitated by a recovery in demand to above pre-Covid-19 levels in 2022, ongoing OPEC+ cuts, and a loss of supply capacity in both U.S. shale and long-cycled global production,” Rystad stated.
Oil pares losses and turns positive on demand recovery - Oil prices moved higher on Monday, reversing early losses, as optimism around a demand recovery offset fears after a fresh spat broke out between the United States and China over the origin of the virus. West Texas Intermediate crude rose 74 cents, or 3.7%, to trade at $20.46 per barrel, while Brent crude gained 65 cents, or 2.4%, to trade at $27.09. While global oil demand is expected to recover modestly from April lows as countries ease some lockdown measures, the glut created over months in storage facilities will loom over the markets. "As oil inventories are likely still increasing over the coming weeks, oil prices remain vulnerable to renewed setbacks," said UBS analyst Giovanni Staunovo. However, Goldman Sachs was more optimistic than before about the rise of oil prices next year due to lower crude production and a partial recovery in oil demand. The Wall Street bank raised its 2021 forecast for global benchmark Brent to $55.63 per barrel from $52.50 earlier. The bank hiked its estimate for WTI to $51.38 a barrel from $48.50 previously. Signs that the output cuts may help reduce the supply overhang have emerged with the narrowing of Brent's contango - the market structure in which later-dated prices are higher than prompt supplies. The six-month spread of Brent futures hit its narrowest in almost a month at a discount of around $6.50, up from a record wide discount of almost $14 in late-March, reflecting decreasing oversupply expectations and making storage for later sale less profitable. The re-emergence of trade tensions between the United State and China also weighed on prices. Adding to U.S. President Donald Trump's threat last week to impose tariffs on China, Secretary of State Mike Pompeo said on Sunday there was "a significant amount of evidence" that the new coronavirus emerged from a Chinese laboratory. Concerns about weak manufacturing data in Asia and Europe, assessed by Purchasing Managers' Index (PMI) of manufacturing companies, also put pressure on oil prices. In Asia, a series of PMIs from IHS Markit fell deeper into contraction from March, with some diving to all-time lows and others hitting levels last seen during the 2008-2009 global financial crisis. PMIs in France, the euro zone's second-biggest economy, dropped in April to the lowest level on record. IHS Markit's Final PMI for German manufacturing, which accounts for about a fifth of Europe's largest economy, shrank at the fastest rate on record. The U.S. dollar surged against most major currencies on Monday amid fears that last year's U.S.-China dispute will be re-ignited. Oil is usually priced in dollars so a stronger greenback makes crude more expensive for buyers with other currencies.
Oil prices rise on demand prospects as lockdowns start to ease - Oil prices climbed in early trade on Tuesday, adding to gains in the previous session, on expectations that fuel demand will begin to pick up as some U.S. states and nations in Europe and Asia start to ease coronavirus lockdown measures. West Texas Intermediate (WTI) crude futures rose as much as 8.2% to a three-week high of $22.06 and were up 7.6%, or $1.55, at $21.94 at 0108 GMT. The U.S. benchmark is on a five-day win streak that started on April 29. Brent crude futures hit a high of $28.37 a barrel in early trade and were up 4.1%, or $1.12 cents, at $28.32. Brent is up for a sixth straight day. Both benchmark contracts rose about 3% on Monday. Prospects improved for fuel demand as some U.S. states and several countries, including Italy, Spain, Portugal, India and Thailand, began allowing some people to go back to work and opened up construction sites, parks and libraries. "Considering ... the depths of demand destruction, markets are probably inclined to take any good news relatively quickly," said Daniel Hynes, senior commodity strategist at Australia and New Zealand Banking Group. Global oil demand probably collapsed by as much as 30% in April, analysts have said, and the recovery is likely to be slow, especially with airlines expected to remain largely grounded for months to come. Australian national carrier Qantas Airways' Chief Executive Alan Joyce said on Tuesday that "international travel demand could take years to return to what it was." With Saudi Arabia, Russia other major producers and companies slashing output, the market shrugged off a decision by the Texas energy regulator to cancel a vote on mandating a 20% output cut in the United States' biggest oil-producing state. The Texas Railroad Commission had been due to hold the vote on Tuesday, but Commissioner Ryan Sitton was unable to win support from his fellow commissioners for the plan. The proposal was strongly opposed by oil trade groups and major shale producers. "The intent in itself was positive — but it was always going to be a long shot," Hynes said.
Oil jumps 13% in fifth day of gains on demand recovery and production cuts - Oil prices surged on Tuesday as optimism around ongoing production cuts and a recovery in demand with the reopening of economies around the world pushed prices higher. West Texas Intermediate, the U.S. benchmark, jumped 13%, or $2.66, to trade at $23.05 per barrel. The contract gained 3.08% on Monday — closing above $20 for the first time since mid-April — and is on pace for its fifth-straight day of gains for the first time since February. International benchmark Brent crude traded 7.8% higher at $29.32 per barrel, and is also pacing for its fifth-consecutive positive session. "One thing is clear, the demand bottom is behind us, and this is manifesting in oil prices which are on the rise," said Per Magnus Nysveen, Rystad Energy's head of analysis. The "key reason behind the price strengthening is regional traffic data, which indicate the demand bottom is behind us," he added. Oil demand has fallen off a cliff as the coronavirus pandemic spread around the globe, forcing billions of people to remain inside and bringing air travel to a near standstill. By some estimates as much as a third of worldwide demand was erased in April. But with economies gradually starting to reopen — a number of U.S. states, including Florida, began phase one reopening plans on Monday, while millions of Italians will return to work this week — investors believe there will be an uptick in demand. "The reopening of economies has injected a degree of cautious optimism back into an oil market that plunged to historic lows only weeks ago," RBC analyst Michael Tran said in a note to clients Tuesday. "There's reason to believe the worst of the demand destruction is behind us. Commentary from multiple companies pointed to an improvement in US demand at the end of April, particularly for gasoline," added Stacey Morris, director of research at Alerian. The improving demand outlook comes as producers have scaled back production, which has also supported prices. The historic cut from OPEC and its oil-producing allies, which takes 9.7 million barrels per day offline, went into effect on May 1. Norway and Canada have also curbed production. In the U.S., data from the Energy Information Administration showed that weekly production averaged 12.1 million bpd for the week ending April 24, roughly 1 million bpd below the all-time high levels from March. Exxon, Chevron and ConocoPhillips are among the companies that have cut production in the face of depressed prices. Oil's recent strength barely puts a dent in its historic fall, however. Both WTI and Brent are firmly in a bear market, plunging 68% and 62%, respectively, from their 52-week high levels. The decline has also been swift — WTI's 52-week high of $65.65 is from Jan. 8.
Oil surges 20%, posts fifth straight day of gains for first time since July - Oil prices surged on Tuesday as optimism around ongoing production cuts and a recovery in demand with the reopening of economies around the world pushed prices higher. West Texas Intermediate, the U.S. benchmark, jumped 20.45%, or $4.17, to settle at $24.56 per barrel. The contract gained 3.08% on Monday — closing above $20 for the first time since mid-April — and posted its fifth-straight day of gains, which is the longest daily winning streak since July. International benchmark Brent crude settled 13.86% higher at $30.97 per barrel, and also posted its fifth-consecutive positive session. "One thing is clear, the demand bottom is behind us, and this is manifesting in oil prices which are on the rise," said Per Magnus Nysveen, Rystad Energy's head of analysis. The "key reason behind the price strengthening is regional traffic data, which indicate the demand bottom is behind us," he added. President Donald Trump weighed in on the jump in prices, writing "Oil prices moving up nicely as demand begins again!" in a tweet on Tuesday morning. Oil demand has fallen off a cliff as the coronavirus pandemic spread around the globe, forcing billions of people to remain inside and bringing air travel to a near standstill. By some estimates as much as a third of worldwide demand was erased in April. But with economies gradually starting to reopen — a number of U.S. states, including Florida, began phase one reopening plans on Monday, while millions of Italians will return to work this week — investors believe there will be an uptick in demand. "The reopening of economies has injected a degree of cautious optimism back into an oil market that plunged to historic lows only weeks ago," RBC analyst Michael Tran said in a note to clients Tuesday. "There's reason to believe the worst of the demand destruction is behind us. Commentary from multiple companies pointed to an improvement in US demand at the end of April, particularly for gasoline," added Stacey Morris, director of research at Alerian. The improving demand outlook comes as producers have scaled back production, which has also supported prices. The historic cut from OPEC and its oil-producing allies, which takes 9.7 million barrels per day offline, went into effect on May 1. Norway and Canada have also curbed production. In the U.S., data from the Energy Information Administration showed that weekly production averaged 12.1 million bpd for the week ending April 24, roughly 1 million bpd below the all-time high levels from March. Exxon, Chevron and ConocoPhillips are among the companies that have cut production in the face of depressed prices.
Oil prices dip due to rise in US crude inventories -- Oil prices have edged-down as higher than expected rise in US crude inventories has raised concerns over supply glut amid a slump in demand due to coronavirus. US West Texas Intermediate (WTI) crude futures were down $0.27, or 1.1%, to $24.29a barrel, at 0436 GMT, while Brent crude LCOc1 futures fell $0.20 to $30.77 a barrel at this time, Reuters reported. According to the data from the American Petroleum Institute (API), oil prices slipped after a report indicated a rise of 8.4 million barrels in the US crude inventories last week. National Australia Bank commodity strategy head Lachlan Shaw was quoted by the news agency as saying: “We’re talking about normalisation of supply and demand but we’ve got a long way to go.” SK Innovation, the South Korea-based owner of refining firm SK Energy, said that it expects refining margins in the second quarter to be under pressure due to weak fuel demand and a glut in refined products as a result of the pandemic. Analysts also cited comments by US-based hydrocarbon exploration firm Diamondback Energy, which stated that it would consider reviving drilling plans if WTI crude futures are held above $30 per barrel. This signals that shale producers do not intend to shut production for a long period. Meanwhile, investors are awaiting official inventory data from Energy Information Administration (EIA), which is due to be released later today.
WTI Rebounds On Smaller-Than-Expected Crude Build, Production Cuts - Oil prices suddenly tumbled this morning after a five-day surge as it appears the surge in ADP unemployment data (completely expected) seemed to remind the machines of the persistent concern that the global glut will take a long time to eliminate as demand remains crushed by the coronavirus. Most analysts don’t see demand rebounding to pre-virus levels for at least a year, with some questioning if that will ever happen. The risk of a second wave of infections in the U.S. as states reopen can’t be discounted, while deteriorating relations between Washington and Beijing may hamper the global economic recovery.“We’ve gone on Brent from $20 to $32, that’s a lot,” said Tor Svelland, chief executive officer of commodities fund Svelland Capital.“The demand destruction is still there, it’s a very, very strong move.”And while initially last night's bigger-than-expected API-reported crude build was ignored, oil prices are losing steam fast this morning. DOE:
- Crude +4.59mm (+7.1mm exp, +9.51mm WHIS)
- Cushing +2.068mm
- Gasoline -3.158mm (-400k exp)
- Distillates +9.518mm (+3.5mm exp) - biggest build since Jan 2019
This is the 15th straight week of crude inventory builds but notably less than expected (and lower than API's print). It appears the bulls are choosing to ignore the huge build in distillates (think perhaps airlines) WTI tumbled back to around $23.50 ahead of the DOE print and ripped back higher (though still down on the day) after the smaller than expected build... We will see if this spike holds...
Oil Prices Remain Lower Despite Tame Inventories Rise - Oil prices shrugged off bullish weekly report on U.S. inventories Wednesday as traders took a breather after the mammoth recent rally. WTI futuresfell 3.8% to $23.62 at 11:00 AM ET (15:00 GMT). London Brent was down 4.4% at $29.62. Oil inventories rose by 4.6 million barrels for the week ended May1, the EIA said. That compared with expectations for a build of about 7.8 million barrels, according to forecasts compiled by Investing.com. Stocks at the national storage hub at Cushing, Okla., rose by 2.07 million barrels, the smallest increase in six weeks. That continued the downward trend in inventory builds as economies around the globe begin to reopen and eased some worries about storage room in the U.S. that forced futures to turn negative for the first time ever last month. Gasoline inventories unexpectedly fell by 3.2 million barrels, versus forecasts for a rise of about 43,000 barrels. Distillate stockpiles soared by 9.5 million barrels, compared with expectations for a build of about 2.9 million barrels. “On the bullish side, we have an unexpected 3.2-million-barrel drop in gasoline that nicely follows through with the previous week’s 3.7-million drop,” Krishnan said. “You also have a Cushing build that’s slightly higher than the 1.8 million level cited by Genscape, instead of the scarier 2.8 million reported by API. This certainly takes some pressure off Cushing builds that had averaged 5 million barrels in four previous weeks.” “On the bearish end, of course, distillates came in more than treble to expectations,” he added. “And if you add the 1.7 million barrels that went into SPR storage last week, that will give you a net crude build of 6.3 million barrels.” “Also, refinery runs are finally above the 70% to capacity rate. Though that's way below the 90% and above norm for this time of year, it's still helped take more crude off the market compared to the previous week.”
Oil drops 2%, snapping five-day winning streak in volatile trading session - Oil prices dropped on Wednesday, snapping a five-session winning streak, as oversupply concerns outweighed optimism over economies reopening. West Texas Intermediate, the U.S. benchmark, shed 2.3%, or 57 cents, to settle at $23.99 per barrel. In a volatile session, the contract swung between a gain of more than 6% at the high — climbing to $26.08 — and a more than 8% loss, hitting a session low of $22.58 per barrel. On Tuesday the contract soared 20.45%. Brent crude, the international benchmark, settled 4% lower at $29.72 as the coronavirus pandemic continues to hit demand. Data from the U.S. Energy Information Administration released Wednesday showed that for the week ending May 1 inventories rose by 4.6 million barrels, which was smaller than the 8.67 million barrels build analysts had been expecting, according to FactSet. Over the last week, WTI has soared more than 50% as easing shelter-in-place restrictions fueled optimism that demand for oil may have bottomed. "Crude oil volatility persists and after a nearly 100% sensational move higher (off of $14 on 4/29) WTI is incurring some profit taking," he told CNBC. "Additionally, the demand for crude remains quite opaque as re-openings of economies globally occur," he added. NationsShares president and chief investment officer Scott Nations noted that the recent run took the WTI contract for June delivery to its highest level since it became the front-month contract, so "the getting probably seemed good." An improving demand outlook spurred recent optimism, with prices also supported by producers announcing scale backs in operations. The historic cut from OPEC and its oil-producing allies, which takes 9.7 million barrels per day offline, went into effect on May 1. Norway and Canada have also curbed production. In the U.S., data from the Energy Information Administration showed that last week production declined by 200,000 bpd to 11.9 million bpd. This is 1.2 million bpd below March's record high. Exxon, Chevron and ConocoPhillips are among the companies that have cut production in the face of depressed prices. But some note that as storage continues to fill, the announced shut-ins are still not enough. "Indications show that for yet another week, storage is continuing to fill up, despite the shut-ins and the output cuts," noted Bjornar Tonhaugen, head of oil markets at Rystad Energy. "Demand, which indeed now is on the recovery road, is not yet enough to balance the produced oil and that oil has to go somewhere," he added.
Oil drops nearly 2%, erasing earlier gain of more than 11% - Oil prices turned negative in afternoon trading on Thursday, as optimism that had previously supported prices began to fade. Earlier oil moved higher on several bullish factors, including U.S. companies cutting production, Saudi Arabia raising its official oil selling price and gasoline demand improving as economies around the world reopen. But oil couldn't hold onto early gains, and ultimately settle in the red. West Texas Intermediate, the U.S. benchmark, shed 44 cents, or 1.83%, to settle at $23.55 per barrel. Earlier in the session WTI had been up more than 11%, hitting a high of $26.74. Brent crude, the international benchmark, settled 26 cents lower at $29.46 per barrel. Still, for the week WTI is up 19%. "Nascent signs of rebounding gasoline demand in the U.S. and a rapid curtailment of oil production that has seen U.S. producers cut over 1 million barrels per day of output in a matter of weeks has enabled oil prices to recover," Again Capital's John Kilduff told CNBC. "Volatility will remain the watchword, but there is an increasing sense that the worst is behind the industry, at this point." On Wednesday, data from the Energy Information Administration showed that for the week ending May 1 production declined by 200,000 barrels per day to 11.9 million bpd, which is more than 1 million bpd below March's record high. Exxon, Chevron and ConocoPhillips are among the companies that have cut production in the face of depressed prices. "There has just been a fierce reaction by U.S. oil and exploration and production companies to really crater U.S. output. It's still very high, but it's working its way down rapidly," Kilduff added. While inventory in the U.S. is still rising, it's now at a slower clip. Last week, stockpiles grew by 4.6 million barrels, which was smaller than the 8.67 million barrels build analysts had been expecting, according to FactSet. And while demand for gasoline is still well below its highs, government data showed that it is starting to turn a corner as states open up their economies. Mizuho energy analyst Paul Sankey noted that oil also got a boost after Saudi Arabia raised its official oil selling prices, which "alleviates pressure on global crude pricing." "They are still fighting for market share (against Iraq/Iran primarily) in Asia, but have backed off US market share competition all-but completely," he wrote in a note to clients Thursday. Given WTI's nearly 40% gain this month, some say the rally is overdone, especially as storage around the world continues to fill. "We're not out of the woods yet," Kilduff added. "There still may be one more flirtation with negative pricing when this June contract goes off the board in a couple of weeks, but beyond that we should be clear of those kind of worries."
Oil jumps 5%, posts second straight week of gains - Oil prices rose on Friday and were on course for a second consecutive week of gains as U.S. producers rapidly shut crude production and more states moved ahead with plans to relax lockdowns intended to prevent the spread of the worst public health crisis in a generation. U.S. West Texas Intermediate crude gained $1.19, or 5%, to settle at $24.74 per barrel, while international benchmark Brent crude gained $1.51 to settle at $30.97 per barrel. "This advance of the past couple of weeks has been a bit suspect given the fact that coronavirus cases continue to increase and the U.S. crude surplus is maintaining a steep up trend where a record U.S. stock level is likely to be achieved in next week's EIA report," Jim Ritterbusch, president of Ritterbusch and Associates in Galena, Illinois, said in a report. The U.S. Energy Information Administration's weekly report on Wednesday showed 15 weeks of consecutive rises in crude stocks although the rate of growth in inventories has slowed since a record build of 19 million barrels in early April. However, the number of operating oil and natural gas rigs fell by 34 to an all-time low of 374 this week - reflecting data going back 80 years - as the energy industry slashes output and spending to deal with the coronavirus-led crash in fuel demand. North American oil companies have shut production faster than analysts expected and are on track to withdraw about 1.7 million barrels per day (bpd) of output by the end of June. These commercially-driven cuts are in addition to those by Organization of the Petroleum Exporting Countries (OPEC) and allies led by Russia, a group know as OPEC+, which began implementing a deal to curb a record 9.7 million bpd from the start of May. Market spectators are now watching for more data that supports OPEC+ countries are complying with production cuts, according to Andrew Lipow, president of Lipow Oil Associates in Houston. "I expect now prices will pull back to $20 a barrel because skepticism will come into the market about the compliance of OPEC+ on the production cuts," said Lipow. Iraq has yet to inform its regular oil buyers of cuts to its exports, suggesting it is struggling to fully implement supply cuts. "All it takes is one or two countries not to comply and it could open the door for others," Lipow said. .
Oil futures finish higher, with U.S. prices up 25% for the week - Crude-oil futures finished higher on Friday, with optimism over production cuts and rising demand for gasoline lifting to U.S. benchmark prices up by 25% this week. The moves come a day after a sharp rally collapsed amid doubts over compliance with an agreement to cut global production and comments from central bankers that injected some doubt about the pace of global economic recovery in the aftermath of the COVID-19 pandemic. “While rising crude and product stocks continue to pose a threat to market fundamentals, key trends on both the supply and demand side have shifted bullish in recent data,” said Robbie Fraser, senior commodity analyst at Schneider Electric. West Texas Intermediate crude for June delivery on the New York Mercantile Exchange rose $1.19, or 5.1%, to settle at $24.74 a barrel. Prices for the front-month contract rose 25.1% for the week, according to Dow Jones Market Data. Global benchmark July Brent crude added $1.51, or 5.1%, at $30.97 a barrel on ICE Futures Europe, for a 17.1% weekly climb. “On the supply side, Saudi Arabia has increased its export price” as output cuts of nearly 10 million barrels per day by the Organization of the Petroleum Exporting Countries and their allies, collectively known as OPEC+, are officially under way, Fraser said in a daily market note.
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