Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 26 September 2020. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening.
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Distillates demand rose 40.9% to a 6-month high, after teasing a 26-year low last week
Oil prices fell for the 3rd time in 4 weeks last week as coronavirus related demand concerns outweighed supply disruptions and falling inventories…after rising more than 10% to $41.11 a barrel last week after hurricane Sally cut output, US oil supplies fell, and the Saudis pressured their OPEC partners to cut production, the contract price of US light sweet crude for October delivery opened lower on Monday of this week as rising COVID-19 infection rates in Europe and elsewhere prompted renewed lockdown measures, casting doubt on the economic recovery, and continued to tumble to end $1.80 lower at $39.31 a barrel on expectations that crude from war torn Libya would soon return to the market…oil prices rebounded nearly 2% early Tuesday, briefly regaining $40 a barrel, as the latest tropical storm in the Gulf of Mexico lost strength, but then drifted lower to settle with a gain of 29 cents at $39.60 a barrel as oil traders “struggled to assess the uncertainty of U.S. production during the last two months of hurricane season and how bad the demand outlook will get following the winter wave of the coronavirus” as trading in the October oil contract expired…with Wednesday’s market reports quoting US light sweet crude for November delivery, which had risen 26 cents to $39.80 a barrel on Tuesday after falling $1.78 on Monday, oil prices rose 13 cents to $39.93 a barrel as the EIA reported that US crude inventories had decreased, but by less than was expected while they also reported larger than expected drawdowns of gasoline and distillate supplies…oil prices then opened lower and slid nearly 2% early Thursday, as a renewed wave of COVID-19 cases in Europe led to reimposed travel restrictions in several countries, but recovered late to end 38 cens higher at $40.31 a barrel buoyed by signs of tighter supplies despite persistent concerns that rising cases of COVID-19 would lead to weaker energy demand…but mounting Covid cases in the US and globally and related demand concerns cast pall over oil markets on Friday as oil prices stuggled to stay positive, ultimately settling down 6 cents at $40.25 a barrel…oil prices thus finshed 2.1% lower this week, with the November contract price falling 2.6%, amid growing concerns that another wave of the coronavirus pandemic would spark tighter lockdown measures and further stifle crude demand….
Natural gas prices, on the other hand, finished higher for the first time in 4 weeks, after crashing to a seven week low early this week…after falling 9% to $2.048 per mmBTU last week as a bigger than expected injection into storage put gas supplies on track to go into winter at a record level, the contract price of natural gas for October delivery opened nearly 3% lower on Monday and tumbled more than 10% to a seven week low of $1.835 per mmBTU on forecasts for less demand over coming weeks than was expected due to a decline in LNG exports on storm and maintenance issues….prices fell another tenth of a cent to another 7 week low on Tuesday as an expected drop in output to its lowest in two years offset a forecast decrease in LNG exports, but then rallied to rise 29.1 cents or nearly 16%, to $2.125 per mmBTU on Wednesday on storm related flooding in Texas and signs of stronger demand…natural gas prices then rose another 12.3 cents or 6% to $2.248 on Thursday on a smaller-than-expected weekly storage build, a continued decline in gas output and an increase in LNG exports, before falling 10.9 cents or 5% to $2.139 on Friday despite a drop in daily output to a 25 month low, because cash trades continued to be priced much lower than the quoted NYMEX contract price, and on forecasts for less demand over the next two weeks than was previously expected, but still finished this obviously volatile week 4.4% higher than the prior week’s close…
The natural gas storage report from the EIA for the week ending September 18th indicated that the quantity of natural gas held in underground storage in the US increased by 66 billion cubic feet to 3,680 billion cubic feet by the end of the week, which left our gas supplies 504 billion cubic feet, or 15.9% greater than the 3,176 billion cubic feet that were in storage on September 18th of last year, and 407 billion cubic feet, or 12.4% above the five-year average of 3,273 billion cubic feet of natural gas that have been in storage as of the 18th of September in recent years….the 66 billion cubic feet that were added to US natural gas storage this week was somewhat lower than the forecast of a 77 billion cubic foot increase from an S&P Global Platts” survey of analysts, and it was also much lower than the 97 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, and well below the average of 80 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending September 18th showed that because of an increase in our oil exports and an decrease in our production, we needed to withdraw oil from our stored supplies for the 8th time out of the past nine weeks and for the 13th time in thirty-six weeks…our imports of crude oil rose by an average of 160,000 barrels per day to an average of 5,168,000 barrels per day, after falling by an average of 416,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 427,000 barrels per day to an average of 3,022,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,146,000 barrels of per day during the week ending September 18th, 267,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly 200,000 barrels per day lower at 10,700,000 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 12,846,000 barrels per day during this reporting week…
US oil refineries reported they were processing 13,370,000 barrels of crude per day during the week ending September 18th, 119,000 fewer 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 a total of 346,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 178,000 barrels per day less than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+178,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must be an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…since last week’s fudge factor was -755,000, indicating a week over week difference of 933,000 barrels per day in the line 13 balance sheet adjustment, we have to figure that our week over week comparisons of crude oil supply and demand are off by that much…but since most everyone treats these weekly EIA figures as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as published, just as they’re watched & believed to be accurate by most everyone in the industry… (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,125,000 barrels per day last week, which was 24.2% less than the 6,764,000 barrel per day average that we were importing over the same four-week period last year….the 346,000 barrel per day net withdrawal from our total crude inventories was as 234,000 barrels per day were being pulled out of our commercially available stocks of crude oil and 112,000 barrels per day were being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is now being leased for commercial use, and hence the recent SPR additions and withdrawals should really be included in our commercial supplies….this week’s crude oil production was reported to be 200,000 barrels per day lower at 10,700,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states fell by 100,000 barrels per day to 10,300,000 barrels per day, while Alaska’s oil production fell by 53,000 barrrels per day to 408,000 barrels per day and subtracted another 100,000 barrels per day from the rounded national total (EIA’s math)….last year’s US crude oil production for the week ending September 20th was rounded to 12,500,000 barrels per day, so this reporting week’s rounded oil production figure was 14.4% below that of a year ago, yet still 27.0% 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 74.8% of their capacity while using 13,370,000 barrels of crude per day during the week ending September 18th, down from 75.8% of capacity during the prior week, and excluding the 2005 and 2008 hurricane-related refinery interruptions, one of the lowest refinery utilization rates of the last thirty years…hence, the 13,370,000 barrels per day of oil that were refined this week were 19.0% fewer barrels than the 16,513,000 barrels of crude that were being processed daily during the week ending September 20th of last year, when US refineries were operating at 89.8% of capacity….
Even with the decrease in the amount of oil being refined, gasoline output from our refineries was much higher, increasing by 496,000 barrels per day to 9,315,000 barrels per day during the week ending September 18th, after our refineries’ gasoline output had decreased by 111,000 barrels per day over the prior week (when refinery throughput had increased by 709,000 barrels per day)… since our gasoline production is still recovering from a multi-year low in the wake of this Spring’s covid lockdown, this week’s gasoline output was 9.0% less than the 10,240,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 67,000 barrels per day to 4,470,000 barrels per day, after our distillates output had increased by 5,000 barrels per day to 4,398,000 barrels per day over the prior week…but even after this week’s increase in distillates output, our distillates’ production was still 10.6% less than the 4,470,000 barrels of distillates per day that were being produced during the week ending September 20th, 2019….
In spite of the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 10th time in 12 weeks and for the 25th time in 34 weeks, falling by 4,025,000 barrels to 231,524,000 barrels during the week ending September 18th, after our gasoline supplies had decreased by 381,000 barrels over the prior week…our gasoline supplies decreased by more this week because the amount of gasoline supplied to US markets increased by 37,000 barrels per day to 8,515,000 barrels per day and because our imports of gasoline fell by 126,000 barrels per day to 474,000 barrels per day and because our exports of gasoline rose by 240,000 barrels per day to 746,000 barrels per day….after the big gasoline inventory drawdowns of recent weeks, our gasoline supplies were 1.2% lower than last September 20th’s gasoline inventories of 230,204,000 barrels, but still roughly 1% above the five year average of our gasoline supplies for this time of the year…
Meanwhile, with our distillates production still near a three year low, our supplies of distillate fuels decreased for the 7th time in 25 weeks and for the 28th time in 50 weeks, falling by 3,364,000 barrels to 175,942,000 barrels during the week ending September 18th, after our distillates supplies had increased by 1,675,000 barrels during the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 1,150,000 barrels per day to 6 month high of 3,959,000 barrels per day, even as our exports of distillates fell by 84,000 barrels per day to 1,128,000 barrels per day, while our imports of distillates rose by 24,000 barrels per day to 136,000 barrels per day…even after this week’s inventory decrease, our distillate supplies at the end of the week were still 31.6% above the 133,685,000 barrels of distillates that we had in storage on September 20th, 2019, and about 21% above the five year average of distillates stocks for this time of the year…
Finally, with the increase in our oil exports and the decrease in our oil production, our commercial supplies of crude oil in storage (not including commercial oil in the SPR) fell for the 10th time in the past sixteeen weeks and for the 17th time in the past year, decreasing by 1,639,000 barrels, from 496,045,000 barrels on September 11th to 494,406,000 barrels on September 18th…but even after that decrease, our commercial crude oil inventories were still around 13% above the five-year average of crude oil supplies for this time of year, and 49.9% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the third weekend of September, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories have generally been rising over the past two years, except for during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of September 18th were 17.8% above the 419,538,000 barrels of oil we had in commercial storage on September 20th of 2019, 24.9% more than the 395,989,000 barrels of oil that we had in storage on September 21st of 2018, and 4.6% above the 472,832,000 barrels of oil we had in commercial storage on September 15th of 2017…
This Week’s Rig Count
The US rig count rose for the 3rd time in the past 4 weeks during the week ending September 25th, but for just the 4th time in 29 weeks, and hence it is still down by 67.1% over that twenty-nine week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 6 to 261 rigs this past week, which was still down by 599 rigs from the 860 rigs that were in use as of the September 27th report of 2019, and was also 143 fewer rigs than the all time low prior to this year, and 1,668 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 their first attempt to put US shale out of business….
The number of rigs drilling for oil increased by 4 rigs to 183 oil rigs this week, after decreasing by 1 oil rig the prior week, leaving us with 540 fewer oil rigs than were running a year ago, and less than a eighth 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 increased by two to 75 natural gas rigs, which was still down by 71 natural gas rigs from the 146 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico…a year ago, there only one such “miscellaneous” rig deployed…
The Gulf of Mexico rig count remained unchanged at 14 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and two drilling for oil offshore from Texas…that was 8 fewer Gulf rigs than the 22 rigs drilling in the Gulf a year ago, when all 22 Gulf rigs were drilling offshore from Louisiana…while there are no rigs operating off of other US shores at this time, a year ago there were also two rigs deployed offshore from Alaska, so this week’s national offshore count is down by 10 from the national offshore rig count of 24 a year ago…also note that in addition to those rigs offshore, a rig continues to drill through an inland body of water in St Mary County, Louisiana this week, while a year ago there were no rigs drilling on inland waters..
The count of active horizontal drilling rigs was up by 9 to 224 horizontal rigs this week, which was still 528 fewer horizontal rigs than the 752 horizontal rigs that were in use in the US on September 27th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the directional rig count was down by 2 to 21 directional rigs this week, and those were also down by 36 from the 57 directional rigs that were operating during the same week of last year….at the same time, the vertical rig count fell by 1 to 16 vertical rigs this week, and those were also down by 35 from the 51 vertical rigs that were in use on September 27th 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 September 25th, the second column shows the change in the number of working rigs between last week’s count (September 18th) and this week’s (September 25th) count, the third column shows last week’s September 18th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running during the count 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 27th of September, 2019…
As you can see from these tables, most of this week’s changes were concentrated in the basins around Texas…checking the rig counts in the Texas part of Permian basin, we find that 3 rigs were added in Texas Oil District 8, which is largely the core Permian Delaware, and two more rigs were added in Texas Oil District 8A, which corresponds to the northern Permian Midland, while 1 rig was pulled out of Texas Oil District 7C, which roughly aligns with the southern part of the Permian Midland, thus leaving the rig count in the Texas Permian up by four…since the national Permian basin rig count was up by two, that means that the two rigs that were pulled out of New Mexico must have been drilling in the far western Permian Delaware, in order to balance the national rig count on that basin…elsewhere in Texas, one rig was added in Texas Oil District 1, one rig was pulled out of Texas Oil District 2, and three rigs were added in Texas Oil District 4, which together account for the 3 rig increase in the Eagle Ford, a formation which stretches in a relatively narrow band across 4 Texas Oil Districts in the southeastern part of the state….one of those Eagle Ford rig additions was targetting natural gas, as were the rig addtions in Ohio’s Utica and Pennsylvania’s Marcellus, while at the same time a vertical natural gas rig was pulled out of a moderately shallow well in Kanawha county, West Virginia, which had not been targetting the Marcellus…
Ohio Department of Natural Resources Cancels Mountaineer Permits – The Ohio Department of Natural Resources (ODNR) announced that it has cancelled permits Powhatan Salt Company applied for to build three solution mining wells. The solution mining wells would be used to create underground fracked gas liquids storage caverns for Mountaineer NGL Storage to then use to supply fracked gas liquids to petrochemical manufacturers, jeopardizing water supplies. Instead, Powhatan Salt Company will have to go through public notice, comment, draft permitting, and fact sheet preparation in order to receive the permits. The cancellation comes at Powhatan Salt Company’s request and reflects the demands that a coalition of clean water advocates outlined in a lawsuit against ODNR over the permits. Represented by Earthjustice, Buckeye Environmental Network, Concerned Ohio River Residents, Freshwater Accountability Project, Ohio Valley Environmental Coalition and the Sierra Club sued ODNR last month for issuing these permits without public notice or comment or preparing a draft permit, in violation with their own regulations for solution mining projects.
- “This is a huge win for the autonomy of the Ohio River Valley’s people. We cannot allow companies to walk into our community and store highly explosive and toxic chemicals under our river, our drinking water, without the bare minimum of public comment,” said Alex Cole of the Ohio Valley Environmental Coalition.
- “This is a resounding victory for clean water advocates. The public deserves to have a voice, especially on projects that could have a disastrous impact on their health and water quality,” said Megan Hunter, Earthjustice staff attorney.
- “We are happy to see the permits for these wells cancelled. The site location for Mountaineer is very problematic. It is located on the banks of the Ohio River, threatening the drinking water of five million people. The proposed site is in close proximity to coal mines, fracking wells, pipelines, and is less than a mile away from Clarington and the communities drinking water wells,” said Jill Antares Hunkler, member of Concerned Ohio River Residents.
- Shelly Corbin, Ohio Campaign Representative for the Sierra Club’s Beyond Dirty Fuels Campaign said, “This unnecessary fracked gas facility shouldn’t have been proposed in the first place, but we’re glad to see that the people most impacted by it will have their chance to weigh in. The scheme to store dangerous ethane underground is one of the fracking industry’s last ditch efforts to save itself. We shouldn’t be building projects that pollute the air we breathe and the water we drink.”
- Teresa Mills, Buckeye Environmental Network, claims this as a victory. “We will continue to watchdog not only the industry but also any and all agencies that are supposed to regulate the industry and fail to do so,” she said.
U.S. energy secretary talks natural gas, climate in Beaver County – U.S. Secretary of Energy Dan Brouillette on Monday met with Shell staff to talk Appalachian natural gas, petrochemical development and COVID-19’s impact on site construction. Brouillette called Beaver County’s ethane cracker plant the “future of the American economy” following a Monday tour of the petrochemical facility. Brouillette, joined by gas industry supporters and regional economic leaders, met with Shell Chemicals staff to talk Appalachian natural gas, petrochemical development and COVID-19’s impact on site construction. “This is where it all starts,” Brouillette said. “With facilities and infrastructure just like this one. It is so critical, not only to western Pennsylvania or the state of Pennsylvania, but the country and the world.” After a COVID-19 slowdown, thousands of workers are back on site constructing the $6 billion ethane cracker plant in Potter Township. Once open, the site will convert oil and gas into ethylene, used in plastics manufacturing to make a range of products from automotive parts to food packaging. It will eventually support 600 permanent jobs in the region. Brouillette echoed President Donald Trump’s comments that the economy, including natural gas, is experiencing a “V-shaped recovery,” with demand for crude oil and gas improving as nationwide business grows. Demand for products developed by cracker-like facilities is also increasing worldwide, he said, adding that policymakers sometimes forget how products such as hand sanitizer packaging and vital PPE are made. Taking a strong pro-fracking stance, Brouillette said “100% renewable energy” in America is unrealistic. “It does not work with the technologies we have today,” he said. “It’s completely dependent on natural gas, nuclear and sometimes coal and hydro to produce baseload power.” When asked what President Donald Trump would do to address climate change if re-elected this November, Brouillette said the president would take an “all of the above” approach to energy production, adding “no one knows” how much of climate change can be attributed to human involvement.
Pa. shale gas production flatlines in June as producer cuts take effect – Shale gas production in Pennsylvania dropped 2% in June from May, to 18.48 Bcf/d, almost flat to the year prior, according to data from the state Department of Environmental Protection. Volume cuts by EQT Corp., the nation’s largest natural gas producer, accounted for a large part of the falloff. EQT announced in May it was shutting in 1.4 Bcf/d of production, about one-third of companywide volumes. That led to an immediate 11% drop in its Pennsylvania production, followed by another 10% cut in June. EQT’s Pennsylvania production fell to 2.86 Bcf/d in June, a 16% decrease year over year.EQT and other drillers, such as neighbor CNX Resources Corp., are chopping volumes in hopes of timing the gas commodities market to catch a wave of $3/MMBtu prices expected this winter, almost double current prices at the benchmark Henry Hub.While EQT said it had restored all of its production at the end of July, executives were pleased that well performance did not suffer after turning off the valves, and they may repeat the performance this fall until prices improve. CNX plans to restore the 500 MMcfe/d it has shut in by Oct. 1.None of the production cuts changed the basic outline of Pennsylvania’s shale gas play. Production is still dominated by five counties in opposite corners of the state, led by Susquehanna County in the dry gas window in the northeast. Susquehanna production volumes were basically flat in June, both month to month and year over year.
The wooing of a would-be petrochemical plant – Pittsburgh Post-Gazette – It was a long shot, if a shot at all. After years of casual chitchat with ExxonMobil petrochemical executives, Pennsylvania finally detected some interest in a tour. The state Department of Community and Economic Development pounced on the opportunity, securing a date months in the future to allow for a massive herding of local officials, business groups and university leaders. The effort culminated in a four-day trip last fall when Pennsylvania officials hosted two executives from ExxonMobil’s chemicals division – highlighting shuttered industrial sites along the Monongahela River in Washington and Greene counties that they hoped could be the home of a second major petrochemical manufacturing complex in southwestern Pennsylvania. The wooing from Sept. 30 to Oct. 3, 2019, included suite seats to a Steelers game, a visit to a plant where wet natural gas is split into marketable components, a meeting with the environmental regulators that had handled permits for the Shell petrochemical plant under construction in Beaver County, a drive-by viewing of Shell’s $6 billion project and a meeting with Carnegie Mellon University officials working on advanced manufacturing. A spokesman for Texas-based ExxonMobil was unambiguous in a statement last week: “We have no active plans for a facility in Pennsylvania.” Still, documents obtained through open records requests by the Clean Air Council, a Philadelphia-based environmental group, reveal the alternately enticing, frantic, political and sometimes dull behind-the-scenes work that goes into attracting a major project developer like Exxon, one of the world’s largest energy companies, which state officials referred to in the emails as “our client.” Officials assembled an itinerary designed to showcase possible locations for a petrochemical complex in Washington or Greene counties. Planned tours included the Mon River Industrial Park on the site of a former Wheeling-Pittsburgh Steel mill in Allenport and the closed Robena coal mine in Monongahela Township. They dubbed the hoped-for development, “Project West.”
New Research Shows Fracking and Petrochemicals Create Fewer Pennsylvania Jobs than Clean Energy – While Energy Secretary Dan Brouillette toured a Shell petrochemical plant under construction in Pennsylvania today, a new analysis shows that the high-profile project will employ far less workers than promised, and that a similar investment in wind and solar manufacturing would be far more beneficial.The new Food & Water Watch research, “Cracked: The Case For Green Jobs Over Petrochemicals In Pennsylvania,” focuses on the massive Shell petrochemical ‘cracker’ plant outside Pittsburgh. While early backers of the $6 billion project predicted it would create between 10,000 and 20,000 jobs, the facility will only employ 600 workers. Factoring in the massive $1.6 billion tax break granted to the company – the largest in Pennsylvania history – means the state is essentially paying $2.75 million to create each job at the plant.The Food & Water Watch research estimates that a similar level of investment in wind and solar manufacturing would create over 16,000 jobs. Unfortunately, state political leaders are still pushing tax breaks for fossil fuels and petrochemicals in the hopes that it will drive additional job growth. The Shell plant is emblematic of this misguided approach: Minimal job creation, increased pollution, and broken promises on using local labor and in-state materials like steel. The Trump re-election campaign is heavily emphasizing fossil fuel and petrochemical jobs in Pennsylvania. Trump held a campaign-style rally at the facility a few months ago, and more recently falsely claimed credit for its construction. Brouilette’s two-day visit is a strong indicator that the White House will continue to emphasize the importance of fossil fuel jobs.
More spills at Lebanon County Mariner East pipeline drill site earn Sunoco more violations | StateImpact Pennsylvania – The Department of Environmental Protection last month directed Mariner East pipeline pipeline builder Sunoco to find a new path for about a mile of its 20-inch pipeline at a site in Chester County, after a drilling spill of more than 8,000 gallons closed part of Marsh Creek Lake to the public. The DEP order was the first in the troubled 43-month history of the pipeline’s construction to require a route change. It followed criticism that dozens of fines and notices of violation in response to earlier problems had done little to force Sunoco to improve construction practices. Now, a string of spills and notices of violation at a horizontal directional drill (HDD) site in Lebanon County, at Snitz Creek in West Cornwall Township, are prompting questions about whether it’s technically feasible to run the pipeline under the creek, given the fragile karst limestone geology of the area, or whether another route for the pipeline is the only realistic option. Sunoco reported five spills, or “inadvertent returns,” of drilling mud at the site between Aug. 13 and Sept. 18, according to the DEP’s Pipeline Portal, bringing to 12 the number of such incidents there since construction began in February 2017. In response, the DEP issued four notices of violation of two environmental laws, and told Sunoco that it could not restart the operation without approval from the department. DEP spokesman Jamar Thrasher said the department has no rule for the number of spills that would lead to an order to reroute the pipeline. “We generally review each site on a case-by-case basis,” he said. Chester and Lebanon counties share the karst limestone geology that creates problems for industrial projects that use underground drilling. Sunoco did not respond to a request for comment, but the Pennsylvania Energy Infrastructure Alliance, which advocates for the industry, said that any rerouting of the pipeline would mean a further delay to the already years-late project. “Any new route would require a major modification of the existing DEP permit,” said Kurt Knaus, a spokesman for the alliance. “This project is nearly complete, and these remaining drills are connecting parts of the line that are already finished and in the ground. What we need to do is get the job done.” The project already carries natural gas liquids from southwestern Pennsylvania and Ohio through 17 counties to a terminal at Marcus Hook near Philadelphia, where most of it is exported. Although not all sections of its three pipes are complete, different combinations of pipe have been carrying ethane, propane and butane eastward since December 2018.
DEP approves changes to Mariner East construction methods at three troubled sites in Delaware, Chester counties – Construction at three troubled Mariner East pipeline sites in Chester and Delaware counties will shift from the planned horizontal directional drilling (HDD) to open trench, a method that risks greater damage to the surface area but avoids further drilling mud spills and sinkholes that have plagued the project in southeast Pennsylvania.The Department of Environmental Protection approved the amended permitsproposed by pipeline builder Energy Transfer/Sunoco after construction caused several pollution events and risks to worker safety at the three sites.The company chose a route through southeastern Pennsylvania that required drilling through unstable rock formations like limestone that has caused dozens of spills, sinkholes and damage to drinking water. Following a 2017 lawsuit by environmental groups over the company’s pipeline work, an order agreed to by all parties requires the company to submit “reevaluation reports” to DEP whenever operations cause drilling mud spills, also referred to as “inadvertent returns.” Those reports are evaluated by a geologist and are open to public comment.The move is not related to a recent order by DEP to Energy Transfer to re-route a section of the pipeline to avoid further damage to Chester County’s Marsh Creek Lake. In August, drilling at nearby pipeline construction site 290 caused about 8,000 gallons of drilling mud to flow into the lake, the main attraction at Marsh Creek State Park and popular to birders, boaters and anglers. Energy Transfer has yet to agree to that order, and could still file an appeal. The three sites now approved to shift to open trench digging are in Delaware County’s Middletown Township, and Chester County’s West Whiteland and Upper Uwchlan townships.
Snubbed retiree gets back at Sunoco for canceling a Mariner East pipeline meeting -Sunoco Pipeline LP’s abrupt cancellation of a public pipeline safety meeting near Carlisle, Pa., two years ago was the final insult for Wilmer Baker, a retired steelworker who lives about a quarter-mile from the contentious cross-state Mariner East project.Baker filed a formal complaint with the Pennsylvania Public Utility Commission in 2018, alleging a litany of bad behavior by Sunoco. He demanded that the PUC order the company to improve safety measures. This week, he got vindication of sorts when the PUC ordered the pipeline operator to schedule a public awareness meeting within 30 days in Cumberland County. A PUC administrative law judge, who had heard formal testimony last year in Baker’s complaint, chided the company for canceling a July 10, 2018, public safety meeting in Lower Frankford Township on short notice because it suspected that the media and potentially litigious residents would be in attendance.The PUC also levied a $1,000 fine against Sunoco.For Baker, a 65-year-old retired foundry worker who represented himself during the PUC’s formal legal process, the commission’s decision was a sweet victory. “Being a private citizen with no legal experience and going up against Sunoco – they had five lawyers there at the hearing and two paralegals – to be able to challenge Sunoco in court and win, I’m ecstatic,” Baker said Thursday.
The Revolution pipeline, two years since it exploded, is back under construction in Beaver County | Pittsburgh Post-Gazette – Two years and two weeks after the Revolution pipeline slid down a steep hill in Center Township and burst into flames, its owner has begun the process of repair.Texas-based Energy Transfer Corp. got approval from state environmental regulators to reroute part of the 24-inch natural gas pipeline onto flatter ground near the area of the explosion. The company told nearby residents that it is felling trees this week and plans to be done with construction in about 45 to 60 days.The pipeline explosion Sept. 10, 2018, was preceded by a heavy rainfall and a history of landslides in that part of Beaver County. The Revolution pipeline had been operational for only a few days before the rupture, and that part hasn’t operated since.The project is considered a gathering pipeline – it is meant to collect gas from wells starting in Beaver and Butler counties and ferry it to an Energy Transfer gas processing plant in Washington County. Although the company at first advised investors and clients that the Revolution pipeline would be back up and running within a few weeks, then months, regulators put a halt to those plans.In the summer, Energy Transfer revealed what residents of nearby Ivy Lane had long suspected after the company bought out two landowners. It would seek to change the route of the pipeline to avoid the steel hill that failed to hold it. That is what the state Department of Environmental Protection recently approved. Energy Transfer’s plan to stabilize the hillside that slipped two years ago was also approved this week, the DEP said.Construction on the pipeline was permitted to begin Thursday. Ivy Lane resident Karen Gdula had a feeling things were about to ramp up.”They’ve been doing a ton of stabilization all over Center Township,” she said, watchful, as ever, of the comings and goings of Energy Transfer’s contractors and large equipment.There’s so much activity on the ground, “it’s like they’re coming in and doing an entire new pipeline,” she said.It’s not clear when the pipeline will be put back into service or which company’s gas will be flowing through it then.The two major shippers for Revolution in that area were EdgeMarc Energy, which declared bankruptcy allegedly because of the explosion, and PennEnergy Resources, which is involved in a contentious lawsuit against Energy Transfer over the pipeline rupture. Among other things, PennEnergy has charged that the pipeline company orchestrated a cover-up to keep from voiding its contract with the driller. A trial in that case is scheduled to begin in March.
Transco Pays Pennsylvania Nearly $1M for Atlantic Sunrise Violations – Natural Gas Intelligence Transcontinental Gas Pipe Line Co. LLC (Transco) has agreed to pay nearly $1 million in penalties and environmental donations for violations that occurred during the construction of its Atlantic Sunrise expansion project, Pennsylvania regulators said Tuesday. The state Department of Environmental Protection (DEP) said it has collected a civil penalty of $736,294 from Transco for construction violations in Columbia, Lancaster, Lebanon, Luzerne, Lycoming, Northumberland, Schuylkill, Susquehanna and Wyoming counties in the eastern part of the state. The company has also agreed to provide $100,000 to fund two water quality improvement projects in Northumberland County. DEP said the violations included failure to properly maintain erosion and sedimentation best practices, inadvertent returns of drilling fluids and sediment discharges into waters of the state. The agency said it would take $680,000 of the civil penalty, while the remainder would go toward the county conservation districts that helped inspect the project during its construction. Transco parent Williams said severe weather events during construction caused “erosion-related issues that were quickly addressed once identified.” The company added that it notified regulators promptly, “who were kept informed until the issues were resolved.” The Atlantic Sunrise expansion entered full service in 2018 to move 1.7 Bcf/d of natural gas from the Marcellus Shale in Northeast Pennsylvania. The expansion came online in phases beginning in 2017 with Brownfield portions first entering service until the 186-mile stretch of greenfield pipeline was finished. Atlantic Sunrise moves gas into Transco, a 10,000-mile pipeline system that spans a large chunk of the East Coast.
A new tool can show if your water is polluted by fracking – – Penn Medicine researchers have created an interactive tool, called WellExplorer, that allows community members and scientists to find out which toxins may be lurking in their drinking water as a result of fracking. You just have to type your ZIP code in the website or the app and look at the fracking sites near you, with information on the chemicals used at each of them.In a recent study, the researchers behind the interactive tool found worrying data on some of the wells. For example, Illinois, Ohio, and Pennsylvania use a high number of ingredients targeting testosterone pathways. Meanwhile, Alabama uses a disproportionately high number of ingredients targeting estrogen pathways.“The chemical mixtures used in fracking are known to regulate hormonal pathways, including testosterone and estrogen, and can therefore affect human development and reproduction,” Mary Regina Boland, one of the researchers behind the project, said in a statement. “Knowing about these chemicals is important, not only for researchers but also for individuals.”The US already has a central registry for fracking chemical disclosures called FracFocus but the researchers believed it’s not user-friendly for the general public. It also doesn’t have information about the biological action of the fracking chemicals that it lists. That’s why they developed WellExplorer, starting by cleaning and shortening the data from FracFocus to use it in their own interactive tool.The researchers integrated data from the Toxin and Toxin Target Database (T3DB) in order to obtain the toxic and biological properties of the ingredients found at the well sites. They also extracted toxicity rankings of the top 275 most toxic ingredients from the Agency for Toxic Substances and Disease Registry, as well as a list of ingredients that were food additives. Boland explained that the use of chemicals at a fracking site may not necessarily mean that those chemicals would be present in the water supply, which would be dependent on other factors, such as the depth of the hydraulic fracturing. Nevertheless, she said WellExplorer was a very good starting point for residents that may be dealing with symptoms and want to have their water tested.
NRC says gas pipeline rupture wouldn’t pose a danger to Indian Point – Indian Point’s owners concluded this year that it could take as many as eight minutes to cut off the flow of natural gas if a pipeline near the nuclear power plant ruptured, five minutes longer than they said it would take in 2014, federal safety regulators said on Tuesday. But officials with the Nuclear Regulatory Commission said Entergy’s revised timeline did not alter their 2015 assessment of the hazards posed by an expansion of the Algonquin Incremental Market Pipeline that brought it closer to Indian Point’s border. “Whatever assumptions they used, whatever calculational methodology they used, we did an independent review and did not identify any concerns relative to our overall conclusion, that the pipeline was not an undue hazard to the Indian Point plant,” said Ray Lorson, the NRC’s deputy regional administrator, during a video-conference on Tuesday. “That was true in 2015 and it’s true today as well.” Lorson’s comments came ahead of the NRC’s annual safety performance hearing for Indian Point, scheduled to take place by video conference on Tuesday at 6 p.m. It will be the last such hearing before the Buchanan plant closes in late April when its last working reactor – Unit 3 – powers down after generating electricity for Westchester County and New York City for more than four decades. The plant received passing grades from the NRC for its 2019 safety performance.
Mountaineer Gas Pipeline Explosion in Martinsburg West Virginia -A Mountaineer Gas pipeline in Martinsburg, West Virginia exploded this afternoon at about 3:15 p.m. on the Sentz family property on Salvation Road. Anne and Benjamin Sentz were working from home and watching workers dig a trench for a new pipeline that was running by an old pipeline that had gas in it. “We were standing in our kitchen looking out our window watching them dig. We kept an eye on the people doing the work ever since they started. We happened to be watching them dig. They were digging really deep. We heard a bang like they hit metal. All of a sudden there was a loud explosion. Pressurized gas shot up 80 to 100 feet into the air. Six or seven workers just scattered.” “My husband grabbed me and said – we need to get out of here. I grabbed one dog and he grabbed the other. We just ran to our car. While we were on our way to our car, a worker came to the front of our house and said we needed to go. We just left. I left the door open. We were out of there in 30 seconds. We just drove away. We didn’t know if our house was going to explode or what. We kept on driving. I drove all the way to Shepherdstown.” “I called 911. They had already received a call about the incident. They put me through to the fire department. I talked to someone from the fire department. They told me they would give me a call when it was safe to come back to the house. It’s 5:30 and we are still not back. We haven’t received the call yet that it is all clear.” “I’ve been watching this operation for a while,” Sentz said. “I am trying to figure out what is going on. The gas company hasn’t been as transparent as they should be to the property owners and neighbors and people affected by this.” “I was just at the site at 5 p.m. and could still smell the gas,” said Tracy Cannon. “I’ve been watching the pipeline construction in the Eastern Panhandle closely for two years now. I’ve often been concerned about what I saw. Mountaineer Gas Company has been installing new pipeline on Salvation Road without removing the old pipeline first. I was worried that something could go wrong, but I’m still shocked that this happened. Thankfully no one was injured.””This incident is an example of the careless manner in which Mountaineer Gas is installing the gas pipeline to Rockwool,” said Christine Wimer, President of Jefferson County Foundation. “We have again and again tried to get Mountaineer Gas to have the pipeline appropriately permitted, but they have refused to do so. The regulators are all too happy to oblige Mountaineer Gas’s obfuscation of the regulatory requirements. The regulators have abandoned their post of protecting the public. This cannot be tolerated.”
Mountain Valley seeks to resume construction of pipeline – After a winter hiatus in construction that stretched into the spring, summer and fall, builders of the Mountain Valley Pipeline say they are ready to return. In a letter filed with the Federal Energy Regulatory Commission late Tuesday, an attorney for the joint venture of energy companies requested that a stop-work order issued last Oct. 15 be lifted. Matthew Eggerding asked FERC to act by Friday “so that Mountain Valley can maximize final restoration and complete as many activities as possible before winter,” he wrote in the letter. Since work began in early 2018, litigation has caused cost overruns and construction delays for Mountain Valley. Not long after FERC issued its stop-work order, the company said it expected to be back on the job by April. But Mountain Valley still lacks two sets of key permits that were set aside after a federal appeals court sided with conservation groups, who argued that building a 303-mile natural gas pipeline through West Virginia and Virginia was causing widespread environmental harm. A third suspended permit was reissued earlier this month by the U.S. Fish and Wildlife Service, which found that construction would not likely jeopardize protected species. That in turn led Mountain Valley to request that it be allowed to resume “all construction activities permitted by law.” All work except for erosion control and stabilization was ceased a year ago by FERC, after the 4th U.S. Circuit Court of Appeals stayed the original biological opinion pending a legal challenge that has not gone away. The buried pipeline cannot cross nearly 1,000 streams and wetlands until the U.S. Army Corps of Engineers grants new permits. And construction of a 3.5-mile passage through the Jefferson National Forest requires a separate approval from the U.S. Forest Service. In a letter to FERC on Wednesday, the Sierra Club maintained that construction cannot commence until all federal authorizations are obtained. A start to construction at this point would raise the risk of “bureaucratic momentum,” in which agencies that have yet to make a decision might be pressured to go along, senior attorney Elly Benson wrote in a letter co-signed by other environmental groups. The letter also contains the first official hint of additional litigation that could derail any movement forward for Mountain Valley.
West Virginia joins coalition seeking to protect pipeline construction (WV News) – West Virginia has joined a 17-state coalition in asking a federal appeals court to reverse a lower court ruling that brought pipeline construction to a halt nationwide, Attorney General Patrick Morrisey says.The coalition’s brief, filed late Wednesday, argues a federal district judge inappropriately transformed a case challenging one project into a nationwide injunction that affected new oil and gas pipelines in every state – no matter the project’s length, purpose or minimal environmental effect.The coalition won a stay in July at the U.S. Supreme Court. Now its member states seek ultimate reversal of the lower court ruling.”Such overreach by a federal district judge cannot stand,” Morrisey said. “Aside from the ruling being overly broad and deeply flawed as a matter of fairness and court procedure, it presents serious consequences for our national economy and causes unnecessary instability and disruption for the dedicated pipeliners of West Virginia, as well as those who depend upon their success.”The original lawsuit focused upon a permit the U.S. Army Corps of Engineers used to authorize the Keystone XL pipeline. The coalition argues the district court order inappropriately used that issue to strike down all projects that employed the same permitting process nationwide.That decision led to the cancellation of the Atlantic Coast Pipeline – an announcement that came days before the Supreme Court’s stay.The coalition contends the district court ruling, if allowed to stand, would make needed infrastructure projects significantly more costly and time-consuming – and potentially render some completely unfeasible, thus eliminating an untold number of jobs. The West Virginia- and Texas-led brief carries support from attorneys general in Alabama, Alaska, Arkansas, Georgia, Indiana, Kansas, Kentucky, Louisiana, Mississippi, Nebraska, Ohio, Oklahoma, South Carolina, South Dakota and Wyoming.
Industrial sector consumption of natural gas falls amid slowing economy – Natural gas consumption in the U.S. industrial sector declined from 25.4 billion cubic feet per day (Bcf/d) in January 2020 to 20.1 Bcf/d in June 2020, according to the U.S. Energy Information Administration’s (EIA) Natural Gas Monthly. Industrial natural gas consumption in June 2020 was nearly 1.0 Bcf/d lower than its year-ago level. The decline in industrial sector natural gas consumption compared with the previous year began in March 2020, amid responses to the coronavirus disease (COVID-19) that resulted in a global economic slowdown. Industrial sector consumption reached its lowest point in May 2020, falling by 8% compared with 2019 levels. May 2020 consumption of natural gas by U.S. industry marked the largest year-over-year decline since July 2009, during the 2007 – 2009 recession. Before this year, average U.S. industrial natural gas consumption grew 5.4% in 2018 and was relatively flat (growing 0.1%) in 2019.Beginning in March 2020, efforts to mitigate COVID-19 began in the United States. Responses to the virus, including stay-at-home orders and temporary closings of nonessential businesses, contributed to a slowing U.S. economy. According to the Bureau of Economic Analysis (BEA), the value of goods and services produced in the United States, known as gross domestic product (GDP), decreased by 9.1% in the second quarter of 2020 compared with the same quarter a year ago. A slowing economy as a result of COVID-19 mitigation efforts also affected GDP in the first quarter of 2020, which grew 0.3%. Last year, the U.S. economy grew 2.2%. According to the September 2020 Short-Term Energy Outlook, EIA expects annual consumption of natural gas by U.S. industries to decline by 4.4% in 2020 and then grow 1.1% in 2021. EIA forecasts U.S. industrial natural gas consumption to increase in 2021 because of expected growth in the overall economy and the natural gas-weighted industrial production index. The index reflects the growth of the underlying manufacturing subsectors and the relative importance of those subsectors to total natural gas consumption.
You’ve Got Your Troubles, Part 3 – Seasonal Demand Declines, Production Curtailments Hit Appalachian Gas Market – As U.S. natural gas spot and futures prices retreated in the past week, the price of gas at Appalachia’s Dominion South hub fell as low as $0.735/MMBtu, the lowest since fall 2017, before partially rebounding yesterday to about $1.10/MMBtu, according to the NGI daily gas price index. Moreover, the forwards market indicates sub-$1/MMBtu prices are in store for October as well. The regional supply hub didn’t weaken quite as much as prices at the national benchmark Henry Hub, which collapsed in recent days on demand losses – from cooler weather, storm-related power outages, and disruptions to LNG exports – and storage levels in the Gulf Coast region that are well above average and approaching peak capacity levels. The relative support for prices in the Northeast is in part due to a second round of production shut-ins by EQT Corp., which took effect September 1. But seasonal demand declines are underway; the Dominion Energy Cove Point LNG facility in Maryland just went offline for its annual fall maintenance, placing additional pressure on already-packed storage fields and takeaway pipelines; and pipeline maintenance events are reducing outflow capacity and curtailing production. Altogether, that signals more volatility ahead. Today, we provide an update on the fundamentals driving the Northeast gas market. When we last checked in on the Northeast gas market in late July (see You’ve Got Your Troubles Part 1 and Part 2), there already were signs of trouble. Following a mild winter and despite pandemic-induced demand disruptions, Appalachian producers had managed to eke past the low-demand spring season without a price meltdown by shutting in production and increasing flows out of the region. But by late July, LNG cargo cancellations were in full swing. Production shut-ins led by EQT from mid-May through mid-July were roaring back online. Appalachian production volumes, after almost flattening out to year-ago levels in June, had surged back to 2020 highs that surpassed pre-shut-in levels and were approaching the region’s all-time highs seen in late 2019. Northeast demand was also strong and setting records. But storage and takeaway capacity fears were brewing for fall shoulder season as storage levels were already high and reflecting surpluses to prior years after the mild winter, and pipeline capacity utilization for routes moving gas out of the region also was running higher than in previous years. These factors combined signaled the likelihood of pipeline takeaway constraints and a price meltdown this fall, including the potential for a second round of production shut-ins.
You’ve Got Your Troubles, Part 4 – More Northeast Gas Production Curtailments –U.S. natural gas production in recent days has plunged more than 3 Bcf/d. While some Gulf of Mexico offshore and Gulf Coast production is still offline from the recent tropical storms, the bulk of these declines are happening in the Northeast, where gas production has dived 2 Bcf/d in the past week or so to about 30.2 Bcf/d, the lowest level since May 2019, pipeline flow data shows. Appalachia’s gas output was already down earlier in the month, as EQT Corp. shut in some volumes starting September 1. But with storage inventories soaring near five-year highs, a combination of maintenance events and demand constraints are forcing further curtailments of Marcellus/Utica volumes near-term. Today, we provide an update of Appalachia gas supply trends using daily gas pipeline flow data. As we discussed on Wednesday in Part 3 of this blog series, the Northeast gas market has been volatile lately. Appalachian supply prices in the spot market earlier this week fell to three-year lows, despite production shut-ins being in effect. A confluence of factors influenced the downturn, including low weather-driven demand, pipeline outages that are restricting outflows, and the start of an annual fall maintenance event at Dominion Energy’s Cove Point LNG facility that took another 700 MMcf/d or so of export demand out of the market. What’s making all of that worse is that storage levels are soaring, not just in the Northeast but also in downstream markets, reducing flexibility to navigate supply congestion and forcing production curtailments. In the past couple of days, cash prices have strengthened again as production has pulled back. We’re going to delve into the specifics of the latest production pullback using daily pipeline flow data from our good friends at Genscape next. Before we get into the production trends, though, let’s first review a bit about the data itself. The pipeline flow dataset comprises the daily gas volumes nominated by market participants to either be received or delivered at thousands of individual meters along natural gas interstate pipelines across the U.S. The meter volumes are then aggregated by type of connecting facility (i.e., gathering systems and processing plants that represent production, and power plants, industrial plants or distribution companies that represent demand); these pipeline flows provide critical insights into supply and demand trends on a daily basis. How much of the market flow this data captures can vary widely by region, but in the Northeast, it provides a high degree (~95%) of transparency into the region’s supply and demand picture. However, note that initial volumes for the most recent gas day can get revised based on final nominations reported for that day. The data discussed in today’s blog is as of the evening cycle for gas day Thursday, September 24. (See Sooner or Later and One Step Closer for more on flow data. We’ll also be demonstrating how to use flow data to track the Northeast gas market in our upcomingSchool of Energy Virtual on October 20-21, 2020.)
U.S. natgas futures drop over 10% to 7-week low as LNG exports slide (Reuters) – U.S. natural gas futures plunged over 10% on Monday to a seven-week low on forecasts for less demand over the next two weeks than previously expected due to a decline in liquefied natural gas (LNG) exports. Gas flows to LNG export plants dropped because of planned maintenance at Dominion Energy Inc’s Cove Point in Maryland, the continued outage at Cameron in Louisiana and as some ships steer clear of Tropical Storm Beta, which is expected to lash the Texas and Louisiana coasts this week. Front-month gas futures fell 21.3 cents, or 10.4%, to settle at $1.835 per million British thermal units (mmBtu), their biggest one-day percentage drop since January 2019 to their lowest close since July 31. That drop puts the front-month down 33% since hitting an eight-month high of $2.743 per mmBtu on Aug. 28 and boosted the premium of November futures over October NGV20-X20 to a record high of 89 cents. Despite the recent drop in the front-month, gas speculators last week increased their net long positions on the New York Mercantile and Intercontinental Exchanges for the seventh time in eight weeks to their highest since May 2017 on expectations energy demand will rise as the economy rebounds once state governments lift more coronavirus-linked lockdowns. Those added long positions came despite expectations stockpiles will hit record highs by the end of October, which should remove lingering concerns about price spikes and gas shortages this winter. Data provider Refinitiv said the amount of gas flowing to U.S. LNG export plants was on track to slide to a two-week low of 5.2 bcfd on Monday from a four-month high of 7.9 bcfd last week. LNG feedgas has averaged 5.6 bcfd so far in September. That was the most in a month since May as global gas prices rise, making U.S. gas more attractive.
U.S. natgas holds near 7-week low as output drop offsets fall in LNG exports (Reuters) – U.S. natural gas futures held near a seven-week low on Tuesday as an expected drop in output to its lowest in two years offset a forecast decrease in liquefied natural gas (LNG) exports. Front-month gas futures fell 0.1 cents, or 0.1%, to settle at $1.834 per million British thermal units (mmBtu), their lowest close since July 31 for a second day in a row after the contract dropped over 10% in the prior session. Traders said futures, which were down about 33% since hitting an eight-month high in late August, were mostly following the spot market lower. Next-day gas at the Henry Hub NG-W-HH-SNL benchmark in Louisiana plunged to an 11-year low of $1.331 per mmBtu for Tuesday, putting it down almost 50% since it hit a nine-month high in late August. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to fall to 83.9 billion cubic feet per day (bcfd) on Tuesday, its lowest since August 2018, as Tropical Storm Beta swirls along the Texas Coast. That drop occurred even though producers said they did not expect much damage from Beta. With prices expected to remain relatively low, Refinitiv projected demand, including exports, would rise from 81.4 bcfd this week to 83.7 bcfd next week as electric generators burn more gas instead of coal to produce power. That, however, was below Refinitiv’s forecasts on Monday due mostly to reduced LNG exports. The amount of gas flowing to LNG export plants was on track to slide to a two-week low of 3.9 bcfd on Tuesday from a four-month high of 7.9 bcfd last week due to planned maintenance at Dominion Energy Inc’s Cove Point in Maryland, the continued outage at Cameron in Louisiana and as some vessels steer clear of Beta.
Natural-gas futures rally on storm-related disruptions and signs of stronger demand – Natural-gas futures rallied Wednesday, to settle at their highest in a week. Prices found support amid production slowdowns tied to recent storms as well as facility maintenance, and as flooding along the coast of the Gulf of Mexico that reportedly led to disruptions at export facilities, analysts said. The flow of natural gas to major hubs Sabine Pass and the Freeport LNG export facilities in Texas remains “greatly reduced” as Tropical Storm Beta unleashed flooding in the Houston area and inched toward Louisiana. Beta made landfall as a tropical storm late Monday in Texas. By Wednesday, it was downgraded to a post-tropical cyclone, but flash flood watches are in effect across southeast Texas and southern Louisiana, the National Hurricane Center said Wednesday morning. This year marks only the second time that the Greek alphabet has been used to name storms, reflecting that the regular list of 21 names, ended with Tropical Storm Wilfred, have been exhausted. Deliveries of feed gas, which is natural gas that comes from field production, has seen a significant decline in recent days, Natural Gas Intelligence reported on Tuesday.. It also said the Cameron, Corpus Christi, Freeport and Sabine Pass export terminals were in Beta’s path as the storm neared land. Luke Jackson, team lead, North America natural gas at S&P Global Platts, meanwhile, attributed the rally in natural gas to easing worries about stocks in the Gulf Coast hitting capacity. Production in the Northeast U.S. fell 1.5 billion cubic feet per day Wednesday, compared with the September month-to-date average, he told MarketWatch. “That drop is partly maintenance related, but also likely a function of the region’s own storage congestion and lack of demand, which is forcing prices lower and causing production to shut.” On Wednesday, the front-month October natural gas contract rose nearly 16%, or 29 cents, at $2.125 per million British thermal units on the New York Mercantile Exchange, for the biggest one-day percentage rise since early August, according to FactSet data. The settlement was the highest for a front month since Sept. 16. Export demand prospects “have a silver lining,” as well, with traders estimating that less than five U.S. cargoes have been cancelled for November loading, said Redmond. Given that, and “assuming that Gulf LNG export terminals or their surrounding power grids do not sustain substantial damages from Beta, feedgas demand should ramp up again quickly following the storm and could run near full capacity in October,” she said.
US working natural gas volumes in underground storage rise 66 Bcf on week: EIA -The amount of natural gas in US underground storage facilities increased by 66 Bcf to 3.680 Tcf in the week ended Sept. 18, according to data released by the US Energy Information Administration Sept. 24. The injection was much less than an S&P Global Platts’ survey of analysts calling for a 77 Bcf build. The estimate was also a shocking departure from the prior week’s build of 89 Bcf. The EIA’s Weekly Natural Gas Storage Report is a survey, not a census, and the many storm-related logistical difficulties in the South Central region for the first half of September potentially caused sampling errors or discrepancies between the storage fields in the EIA’s sampling frame and those outside of it, according to S&P Global Platts Analytics. It is likely the EIA overestimated net injections for the week-ended Sept. 11. The injection measured less than the 97 Bcf build reported during the same week last year as well as the five-year average gain of 80 Bcf, according to EIA data. Storage volumes now stand 504 Bcf, or 16%, more than the year-ago level of 3.176 Tcf and 407 Bcf, or 12.4%, more than the five-year average of 3.273 Tcf. After briefly trading up 21 cents the morning of Sept. 24, the prompt-month NYMEX Henry Hub contract settled back down to a roughly 9 cent/MMBtu gain day on day, driven by a much smaller-than-anticipated storage build reported by the EIA. The price strength did not extend far into the strip, with November trading just 2 cents higher, and the rest of the winter contracts through March 2021 trading about 1.5 cents higher on the day. Platts Analytics’ supply and demand model currently forecasts a 67 Bcf injection for the week ending Sept. 25. This would lower the surplus to the five-year average by 11 Bcf as about seven net injections remain before the flip to the winter withdrawal season. Total supplies are trending 1.2 Bcf/d lower this week compared with the week ended Sept. 18, driven by a 900 MMcf/d drop in onshore production, the vast majority of which stems from the Northeast region, where output has slid nearly 2 Bcf/d in the past few days due to weak prices and infrastructure constraints. The ICE end-of-season EIA inventory estimate was 5 Bcf lower on Sept. 24, with markets narrowing in on an expected 3.97 Tcf end-of-summer carryout to begin the winter demand season in November. This would be about 250 Bcf more than the five-year average of 3.75 Tcf.
U.S. natgas futures jump 6% on small storage build, rising LNG exports (Reuters) – U.S. natural gas futures jumped almost 6% on Thursday on a smaller-than-expected weekly storage build, a continued decline in output and an increase in liquefied natural gas (LNG) exports. The U.S. Energy Information Administration (EIA) said U.S. utilities injected just 66 billion cubic feet (bcf) of gas into storage in the week ended Sept. 18. That was well below the 78-bcf build analysts forecast in a Reuters poll and compares with an increase of 97 bcf during the same week last year and a five-year (2015-19) average build of 80 bcf. Front-month gas futures rose 12.3 cents, or 5.8%, to settle at a one-week high of $2.248 per million British thermal units. The market has already been extremely volatile this week – prices fell over 10% on Monday and jumped almost 16% on Wednesday – as traders roll out of front-month October contracts, which expire on Sept. 28, and into much higher priced November futures. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to fall for a second month in a row to 86.9 billion cubic feet per day (bcfd) in September from 87.5 bcfd in August. That is well below the all-time monthly high of 95.4 bcfd in November. Refinitiv projected demand, including exports, would rise from 82.6 bcfd this week to 85.3 bcfd next week as LNG exports increase. The amount of gas flowing to LNG export plants was on track to reach 5.7 bcfd on Thursday from a two-week low of 3.9 bcfd on Tuesday as vessels returned to Gulf Coast terminals after Tropical Storm Beta dissipated. Traders said the Cameron LNG export plant in Louisiana will likely return to service around Oct. 8 when the Army Corps of Engineers expects to finish dredging the Calcasieu Ship Channel after Hurricane Laura.
US natgas futures fall with cash prices on lower demand forecasts – US natural gas futures ended a volatile week down almost 5% on Friday as spot prices continued to trade much lower than futures on forecasts for less demand over the next two weeks than previously expected. The decline in futures prices came despite a projected increase in LNG exports, record sales to Mexico and a drop in daily output to a 25-month low. On its second to last day as the front-month, gas futures for October delivery fell 10.9 cents, or 4.8%, to settle at $2.139 per million British thermal units (mmBtu). November futures, which will soon be the front-month, were down about 9 cents at $2.81 per mmBtu. If November continues to trade at that level next week, it would put the front-month on track for its highest close since November 2019. For the week, the front-month was up about 4% after falling over 10% on Monday and rising almost 16% on Wednesday. Next-day gas at the Henry Hub benchmark in Louisiana, which fell to a 21-year low earlier this week, has traded below front-month futures since late August due mostly to weak demand along the Gulf Coast after a series of storms hit LNG exports. Data provider Refinitiv projected demand, including exports, would rise from 82.4 billion cubic feet per day (bcfd) this week to 84.6 bcfd next week and 85.3 bcfd in two weeks, with LNG exports expected to climb. That, however, is lower than Refinitiv’s forecast on Thursday, as an expected increase in gas prices will cause some electric generators to burn more coal instead of gas to produce power. The amount of gas flowing to LNG export plants was on track to reach 6.1 bcfd on Friday, up from a two-week low of 3.9 bcfd on Tuesday, as vessels returned to Gulf Coast terminals after Tropical Storm Beta dissipated.
Sen. Tillis: Trump to extend offshore drilling pause to NC (AP) – President Donald Trump will add North Carolina to a list of southeastern states whose coastal waters won’t be subjected to offshore drilling for a decade, U.S. Sen. Thom Tillis said on Monday. Earlier this month, Trump signed a memorandum instructing his interior secretary to prohibit drilling in the waters off both Florida coasts, and off the coasts of Georgia and South Carolina for 10 years – from July 2022 through June 2032. North Carolina wasn’t on the list. In a short video released by his Senate office, Tillis, a Republican, said he spoke to Trump on Monday morning and asked him to “extend the offshore drilling moratorium to North Carolina. I’m pleased to announce that the president will be doing just that.” The Trump administration didn’t immediately announce such a move Monday. The three-state prohibition marked a policy reversal by Trump and was seen as a potential political asset for Republican senators in Georgia and South Carolina facing tough election fights. The drilling issue hasn’t reached the forefront of the Senate campaign between Tillis and Democrat Cal Cunningham, however. Still, Democratic Gov. Roy Cooper, an offshore drilling opponent, wrote Trump last week asking him to add North Carolina to the list, citing the risk of spills and potential damage to the tourism and fishing industries. Tillis was state House speaker in the early 2010s, when the legislature approved the framework to allow oil and natural gas drilling off the Atlantic coast and to collect taxes from the energy products. But that production hasn’t occurred due to delays from Washington as well as an oversupply of natural gas. A bipartisan group of more than two dozen coastal mayors signed a resolution last year urging such exploration be permanently off-limits. Tillis pressed for Atlantic coast exploration during a floor speech early in his Senate term for jobs and U.S. energy independence. But last year he expressed some concerns, asking the Trump administration to speak with North Carolina tourism and fishing interests to ensure they would be protected under an exploration plan.
Questions Linger on Offshore Drilling, Seismic Testing — Sen. Thom Tillis, R-N.C., announced this week that President Trump had agreed to prevent drilling for oil and natural gas off the North Carolina coast, but the president has yet to speak publicly on the matter, and his administration says it is still moving forward with permitting for seismic exploration in the Atlantic.Tillis, whom polls show trailing his Democratic Party challenger Cal Cunningham, announced Monday that Trump had agreed to add North Carolina to a multistate moratorium on Atlantic offshore drilling announced earlier this month.The president announced Sept. 8 during an event in Jupiter, Florida, an order to extend the moratorium on offshore drilling on Florida’s Gulf Coast and expand it to Florida’s Atlantic Coast, as well as the coasts of Georgia and South Carolina. North Carolina was not included at the time.Tillis said Monday that he had spoken with Trump who agreed North Carolina would be included in the presidential memorandum withdrawing new leasing for offshore oil and gas developments for the next 12 years.Also on Monday, the Department of Justice filed a document with the U.S. District Court for the District of South Carolina, Charleston Division, stating that Trump’s memorandum “has no legal effect” on the status of the applications to conduct seismic surveys in the Atlantic Outer Continental Shelf that are pending before the Bureau of Ocean Energy Management.”If Trump were remotely serious about protecting Florida and the Carolinas from offshore drilling, he wouldn’t be allowing oil exploration along the coast,” Kristen Monsell of the Center for Biological Diversity Action Fund said in a statement. “This Justice Department filing underscores the appalling emptiness of Trump’s election-year effort to hoodwink voters. Seismic testing’s sonic blasts harm whales and other marine life, and they set the stage for future drilling and devastating oil spills.”
SCS resists request for Byhalia Pipeline to run through section of district property – Shelby County Schools is resisting an easement request for an oil pipeline to run along its property on Weaver Road in South Memphis, documents show. Leadership pointed to potential environmental risks and several lingering questions about the Byhalia Connection Pipeline and also pointed to community outcry over the last several months. The pipeline would run through Boxtown, a historically Black neighborhood in South Memphis that is still one of the city’s poorest and most isolated, as reported in-depth by Storyboard Memphis. “From the administration side, there’s still several questions about this project. Especially the idea that there would be an underground oil transfer from President’s Island to Byhalia, would potentially present environmental risks. So our initial response, our recommendation, is to not accept this offer,” John Barker, deputy superintendent for strategic operations and finance, said in a recent capital needs and facilities meeting. During the meeting district representatives Barker and Michelle Stuart, the director of facility planning and property management, said that the pipeline offered $25,340 for a 50-foot-wide easement, which would run along empty land the district owns on Weaver Road, between W. Holmes Road and Ruby Creek Cove. Board member Billy Orgel, who chairs the committee, initially questioned the rejection since the land is vacant and pointed to existing pipelines in Memphis. He later questioned whether the current route was the only one available. “Certainly it’s not running through someone’s neighborhood, is it?” he said. Stuart pointed to community meetings about the pipeline reported in the news. Southerly, which covers ecology, justice and culture in the South, and MLK50: Justice Through Journalism recently c0reported about the pipeline and the people whose families have owned land on the planned route for generations.
Louisiana lawmaker paid to push proposed pipeline through Black, Indigenous communities – Dorothy Ingram is among dozens of Raceland, Louisiana residents who say they’ve received few details about a proposed natural gas pipeline that would cut through historic Black churches and graveyards in their community, which sits about 40 miles west of New Orleans. “We have been treated unfairly and without meaningful involvement,” “We as a community did not have a meeting in our area to participate in the plan.”First proposed in April 2019, the 280-mile Delta Express pipeline would be built through 14 parishes, connecting an existing natural gas pipeline in northern Louisiana to a liquid natural gas facility in Plaquemines Parish – Louisiana’s southernmost parish, where coastal erosion and sea level rise are expected to swallow up 55% of land without coastal restoration projects. The company, Venture Global, has not held a meeting to seek public comments in Lafourche Parish, which includes Ingram’s neighborhood. The pipeline is still in an early stage of permitting: Venture Global hasn’t submitted its formal application to FERC or acquired state permits. But emails show that the company has tried to influence state and federal permitting agencies by employing a Louisiana lawmaker, Rep. Ryan Bourriaque, R-Abbeville, who is also vice chair of the House Natural Resources and Environment Committee. Emails obtained through a public records request by the Energy and Policy Institute reveal that Bourriaque negotiated with the state’s Coastal Protection and Restoration Authority, or CPRA, about a separate Venture Global pipeline crossing a Mississippi River levee CPRA is planning to elevate. Bourriaque also sent a template letter for other Louisiana lawmakers to send to FERC in support of the Delta Express pipeline. “Regular citizens are having a harder time voicing their opposition to projects that impact them directly,” said Energy and Policy Institute researcher Itai Vardi. “At the same time, you see that there’s an acceleration with industry insiders using their cozy relationship with elected officials to influence decisions.”
Max Midstream buys Seahawk pipeline, terminal project – Houston-based Max Midstream has purchased the Seahawk Pipeline project and Seahawk Terminal from Los Angeles-based Oaktree Capital Management. Max Midstream plans to bring the first phase of the terminal-and-pipeline project online in the fourth quarter, exporting crude from the terminal site at the Port of Calhoun on the Texas Coast between Houston and Corpus Christi. If it successfully does so, the project would represent a new place to load crude oil for waterborne export abroad.”By developing the Seahawk Terminal at the port, we will be able to offer a deep-water terminal with little congestion and the ability for producers to get their product to the port at a very reasonable price,” CEO Todd Edwards said in a press release.The project is set to directly create 474 new jobs in addition to 598 construction-related jobs, according to the press release. The eventual goal of the project will be to directly connect oil production in the Permian Basin and Eagle Ford to the Port of Calhoun for export, and the company plans to spend up to $1 billion on the whole endeavor.The company expects it will be able to export up to 4.2 million barrels a month by November, Edwards said.Max Midstream has also reached a deal with the Calhoun Port Authority in which the company will finance $360 million toward an effort to deepen and widen the port to accommodate large vessels.”Once the widening and deepening project is complete, Aframax and Suezmax ships will also be able to load at the port, making it a viable option for any exporter seeking a port other than Houston or Corpus Christi,” the company said in the press release.
Oil well drilling fluid flows through neighborhood – While arriving home from work Wednesday afternoon, Alan Flores was surprised to see some kind of liquid flowing in the bar ditch in front of his house on Nueces County Road 73A just outside of Calallen. “We hadn’t had rain in two or three days, so I wondered, ‘Where is all this coming from?” Flores said. “And the color was unusual. That’s what got me.” Flores tracked the liquid about a quarter of a mile up the street to a property where a Houston-based company drilled for oil last month. He then called the Texas Commission on Environmental Quality concerned that the liquid could be dangerous. “We’re just being taken advantage of because the drilling company said they were going to take care of the community,” he said while motioning to the bar ditch that still contained some of the liquid Thursday. “This isn’t taking care of the community.” Rather than TCEQ, the Texas Railroad Commission says it’s the agency that investigated the drilling fluid release Thursday and will continue to monitor the cleanup process. “The Railroad Commission will inspect the work to ensure public safety and the environment has been safeguarded,” spokesperson Andrew Keese said in an email. The drilling company says the liquid is mostly rainwater but does include some drilling fluids used for lubrication, among other purposes. Tag Operating Company, Inc. says that fluid is not harmful — rather beneficial. “They’re very desirable for agricultural purposes,” Tag Principal Ted Snyder said. “Many landowners are very happy to have that on their soil.” Snyder says the owner of the drill site and the Texas Railroad Commission approved releasing the drilling fluid on the property for that very purpose. But there was a problem. “What we hadn’t really calculated, with the heavy rains that we had last week, the ground was quite saturated,” Snyder said. “As a result – rather than soaking into the soil as we anticipated that it would do – it ran off.” Snyder apologized for the miscalculation and reiterated to concerned residents that the drilling fluid isn’t dangerous. Flores remains convinced there will be a negative impact. “Regardless of whether this (drilling fluid) is good for the environment or not, it shouldn’t end up going into the ditch which eventually goes into the Nueces River,” Flores said.
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