Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 22 August 2020. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening. This week the post has been delayed by one day.
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A record low for drilling of new wells and completions of drilled wells in July, but active rigs jumped by 10 this week
July’s well completions were down 80% from last July to a record low; new wells drilled also at a record low, but drilling rigs were up by 10 this week; distillate imports were at a 60 week low.
Oil prices inched higher for a third consecutive week this week, as early gains on rising demand and falling supplies were largely reversed on fears of potential pandemic impacts….after rising 1.9% to $42.01 a barrel last week on falling US oil and fuel inventories, the contract price of US light sweet crude for September delivery opened higher on Monday on news that China planned to import large volumes of U.S. crude this month and next and finished the session up 88 cents at $42.89 a barrel on a media report that OPEC+ members were complying with the alliance’s production cuts and as a weaker dollar spurred a broad commodities rally…but oil prices slid early Tuesday on demand fears as the coronavirus pandemic showed no signs of letting up but recovered to close the day unchanged as traders awaited the American Petroleum Institute report Tuesday evening and the EIA report the next day, both of which were expected to show that oil and fuel inventories had fallen…US oil contracts traded lower early Wednesday on headlines of a crude inventory draw that was weaker than had been expected, but recovered to close 4 cents higher at $42.93 a barrel as a big drop in gasoline inventories alleviated coronavirus demand fears as the driving season shifted into its final weeks…however, oil prices fell more than 3% early Thursday after Reuters reported that OPEC needed to address a daily oversupply of more than 2 million barrels, and after U.S. unemployment claims rose unexpectedly, signalling a pause in the economic recovery, but then moved higher before the close as trading in the September contract expired 35 cents lower at $42.58 a barrel while the more actively traded October oil contract ended down 29 cents at $42.82 a barrel...now quoting the contract price of US crude for October delivery as the price of oil, prices resumed sliding on Friday under pressure from demand concerns as the Covid-19 pandemic continued to undermine economic growth and ended down 48 cents, or 1.1%, to finish at $42.34 a barrel as the economic recovery worldwide ran into stumbling blocks due to renewed coronavirus lockdowns, thus giving up most of its gains for the week with the October contract price finishing just 3 cents or less than 0.1% higher than the prior Friday’s close…
Natural gas prices also finished higher for the third straight week as record-high temperatures on the West Coast and typical August heat and humidity in the South and Southeast drove demand higher…after rising 5.3% to an eight month high of $2.356 per mmBTU last week on hot weather and on rising LNG exports, the contract price of natural gas for September delivery backed off 1.7 cents on Monday on forecasts for milder weather and lower air conditioning demand than had previously been expected…but gas prices climbed 7.8 cents to a new eight month high on Tuesday on a decline in natural gas output and an increase in LNG exports and then added nine-tenths of a cent to another eight month high on Wednesday, as LNG exports continued rising and as temperature forecasts again trended toward warmer…but natural gas prices gave up all the week’s gains on Thursday in tumbling 7.4 cents to $2.352 per mmBTU as a big storage build showed that the hot weather of last week was not enough to cut the week’s inventory increase to below normal levels…but that lesson was lost on traders Friday as they pushed natural gas prices 9.6 cents higher to a new 8 month high of $2.448 per mmBTU and a 3.9% gain on the week, as hot weather returned and two major storms moved towards the Gulf Coast, threatening production, LNG exports and domestic demand in the coming week….
The natural gas storage report from the EIA for the week ending August 14th indicated that the quantity of natural gas held in underground storage in the US rose by 43 billion cubic feet to 3,375 billion cubic feet by the end of the week, which left our gas supplies 595 billion cubic feet, or 21.4% greater than the 2,780 billion cubic feet that were in storage on August 14th of last year, and 442 billion cubic feet, or 15.1% above the five-year average of 2,933 billion cubic feet of natural gas that have been in storage as of the 14th of August in recent years….the 43 billion cubic feet that were added to US natural gas storage this week was more than the average 39 billion cubic feet increase that was forecast by analysts polled by S&P Global Platts, but it was less than the 56 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, while it was close to the average of 44 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 August 14th indicated that despite a big drop in our oil exports, we still needed to withdraw oil from our stored supplies for the fourth week in a row and for the 6th time in the past eleven weeks…our imports of crude oil rose by an average of 109,000 barrels per day to an average of 5,730,000 barrels per day, after falling by an average of 389,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 1,006,000 barrels per day to an average of 2,137,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,593,000 barrels of per day during the week ending August 14th, 1,115,000 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 was reportedly unchanged 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 14,293,000 barrels per day during this reporting week..
US oil refineries reported they were processing 14,487,000 barrels of crude per day during the week ending August 14th, 171,000 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 net of 615,000 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 421,000 barrels per day more than what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-421,000) 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 an error or errors of that magnitude in the oil supply & demand figures we have just transcribed….and with last week’s fudge factor at +515,000, that means our week over week comparisons on oil supply & demand changes are off by more than twice as much, even as we continue to report them as an indicator of what most oil traders and analysts believe happened, since that’s what affects their behavior… (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 5,627,000 barrels per day last week, which was 21.7% less than the 7,186,000 barrel per day average that we were importing over the same four-week period last year….the 615,000 barrel per day net withdrawal from our total crude inventories came as 233,000 barrels per day were being pulled out of our commercially available stocks of crude oil and 382,000 barrels per day were being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is also being leased for commercial use….this week’s crude oil production was reported to be unchanged at 10,700,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,300,000 barrels per day, while Alaska’s oil production rose by 7,000 barrrels per day to 439,000 barrels per day but had no impact on the rounded national total….last year’s US crude oil production for the week ending August 16th was rounded to 12,300,000 barrels per day, so this reporting week’s rounded oil production figure was about 13.0% 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 80.9% of their capacity while using 14,487,000 barrels of crude per day during the week ending August 14th, down from 81.0% of capacity during the prior week, and excluding the 2005, 2008, and 2017 hurricane-related refinery interruptions, still among the lowest refinery utilization rates of the last twenty-eight years…hence, the 14,487,000 barrels per day of oil that were refined this week were still 18.2% fewer barrels than the 17,702,000 barrels of crude that were being processed daily during the week ending August 16th, 2019, when US refineries were operating at 95.9% of capacity….
With the decrease in the amount of oil being refined, gasoline output from our refineries was also lower, decreasing by 200,000 barrels per day to 9,400,000 barrels per day during the week ending August 14th, after our refineries’ gasoline output had increased by 300,000 barrels per day over the prior week…with our gasoline production still recovering from a multi-year low, this week’s gasoline output was 5.0% less than the 9,897,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 47,000 barrels per day to 4,742,000 barrels per day, after our distillates output had decreased by 120,000 barrels per day over the prior week… after this week’s decrease in distillates output, our distillates’ production was 11.2% less than the 5,340,000 barrels of distillates per day that were being produced during the week ending August 16th, 2019….
Along with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 5th time in 7 weeks and for the 20th time in 29 weeks, falling by 3,322,000 barrels to 243,762,000 barrels during the week ending August 14th, after our gasoline supplies had decreased by 722,000 barrels over the prior week…our gasoline supplies decreased by more this week even though the amount of gasoline supplied to US markets decreased by 253,000 barrels per day to 8,630,000 barrels per day because our imports of gasoline fell by 466,000 barrels per day to 557,000 barrels per day while our exports of gasoline rose by 15,000 barrels per day to 809,000 barrels per day….but even after this week’s inventory decrease, our gasoline supplies were still 4.1% higher than last August 16th’s gasoline inventories of 234,072,000 barrels, and roughly 7% above the five year average of our gasoline supplies for this time of the year…
However, even with the decrease in our distillates production, our supplies of distillate fuels increased for the sixteenth time in 31 weeks and for the 21st time in 46 weeks, rising by 152,000 barrels to 177,807,000 barrels during the week ending August 14th, after our distillates supplies had decreased by 2,322,000 barrels during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 609,000 barrels per day to 3,253,000 barrels per day, while our exports of distillates rose by 108,000 barrels per day to 1,515,000 barrels per day, and while our imports of distillates fell by 100,000 barrels per day to a 60 week low of 48,000 barrels per day…after this week’s inventory increase, our distillate supplies at the end of the week were still 28.7% above the 138,123,000 barrels of distillates that we had in storage on August 16th, 2019, and about 24% above the five year average of distillates stocks for this time of the year…
Finally, even with the big drop in our oil exports, our commercial supplies of crude oil in storage fell for the 9th time in thirty-one weeks and for the 16th time in the past year, decreasing by 1,632,000 barrels, from 514,084,000 barrels on August 7th to 512,452,000 barrels on August 14th….but even after that decrease, our commercial crude oil inventories were still around 15% above the five-year average of crude oil supplies for this time of year, and 54.4% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the second weekend of August, 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 since September of 2018, except for during last summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of August 14th were 17.1% above the 437,778,000 barrels of oil we had in commercial storage on August 16th of 2019, 25.5% more than the 408,358,000 barrels of oil that we had in storage on August 17th of 2018, and 10.6% above the 463,165,000 barrels of oil we had in commercial storage on August 18th of 2017…
This Week’s Rig Count
The US rig count was up for the 1st time in 24 weeks during the week ending August 21st, but is still down by 68.1% over that twenty-four week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 10 rigs to 254 rigs this past week, which was still 150 fewer rigs than the all time low prior to this year…it was also down by 662 rigs from the 916 rigs that were in use as of the August 23rd report of 2019, and 1,675 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 11 rigs to 183 oil rigs this week, after decreasing by 4 oil rigs the prior week, still leaving us with 571 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 decreased by 1 rig to 69 natural gas rigs, which was also down by 93 natural gas rigs from the 162 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, two rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, and one in Sonoma County, California… a year ago, there were no such “miscellaneous” rigs deployed…
The Gulf of Mexico rig count was unchanged at 13 rigs this week, with 10 of those rigs drilling for oil in Louisiana’s offshore waters and three drilling for oil offshore from Texas…that was 13 fewer rigs than the 26 rigs drilling in the Gulf a year ago, when 25 Gulf rigs were drilling offshore from Louisiana and one was deployed in Texas waters…while there are no rigs operating off 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 15 from the national offshore rig count of 28 a year ago…also note that in addition to those rigs offshore, a rig continues to drill through an inland body of water in southern Louisiana this week, while a year ago there were no rigs drilling in inland waters..
The count of active horizontal drilling rigs was up by 14 to 221 horizontal rigs this week, which was still 576 fewer horizontal rigs than the 797 horizontal rigs that were in use in the US on August 23rd 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 4 to 20 directional rigs this week, and those were also down by 49 from the 69 directional rigs that were operating during the same week of last year….meanwhile, the vertical rig count was unchanged at 13 vertical rigs this week, but those were still down by 37 from the 50 vertical rigs that were in use on August 23rd 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 August 21st, the second column shows the change in the number of working rigs between last week’s count (August 14th) and this week’s (August 21st) count, the third column shows last week’s August 14th 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 23rd of August, 2019…
While we have more changes in drilling activity this week than in week’s past, the Permian basin by itself accounts for this week’s change, while activiy in other basins remains relatively subdued …checking the rig counts in the Texas part of Permian basin, we find that seven rigs were added in Texas Oil District 8, which is the core Permian Delaware, and another rig was added in Texas Oil District 7C, which corresponds to the southern Permian Midland….since the Texas Permian count has thus increased by 8 rigs while the national Permian basin rig count was up by 10 rigs, that almost certainly means that the 2 rigs that were added in New Mexico would have set up to drill in the far western Permian Delaware, to fully account for the national Permian increase…elsewhere in Texas, a rig was removed from Texas Oil District 1 while one rig was added in Texas Oil District 3, so to get to the 2 rig loss in the Eagle Ford shale we would have had to see two rigs added in one of those districts that weren’t targeting the Eagle Ford, while two Eagle Ford rigs were being removed at the same time…in other states, the rig pulled out of the Williston basin had been drilling in North Dakota’s Bakken, but the rig increase in northern Louisiana did not register as an increase in the Haynesville, where the other 20 rigs in that area are drilling…among natural gas rig changes, one was removed from Ohio’s Utica shale and two were pulled out of Pennsylvania’s Marcellus, while at the same time three natural gas rigs were added in West Virginia’s Marcellus, resulting in the one rig increase in the Marcellus that you see above…the national natural gas rig count was stil down by one, however, because one of the rigs pulled from the Eagle Ford had been targeting natural gas, leaving the Eagle Ford with just 9 rigs, all targeting oil…
DUC well report for July
Monday of this past week saw the release of the EIA’s Drilling Productivity Report for August, which includes the EIA’s July data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions….for the 3rd time in the past seventeen months, this report showed an increase in uncompleted wells nationally in July, as both the drilling of new wells and completions of drilled wells decreased by similar amounts….for the 7 sedimentary regions covered by this report, the total count of DUC wells increased by 30 wells, rising from 7,655 DUC wells in June to 7,685 DUC wells in July, which was still 8.8% fewer DUCs than the 8,429 wells that had been drilled but remained uncompleted as of the end of July of a year ago…this month’s DUC increase occurred as 292 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during July, down by 32 from the 324 wells that were drilled in June and the lowest number of wells drilled in any month in the history of this report, while 262 wells were completed and brought into production by fracking, a decrease of 29 well completions from the 291 completions seen in June, and down by 80.1% from the 1,315 completions seen in July of last year, and also the lowest number of completions in one month since completions have been reported by the EIA….at the July completion rate, the 7,685 drilled but uncompleted wells left at the end of the month represents a 29.3 month backlog of wells that have been drilled but are not yet fracked, up from the 26.3 month DUC well backlog of a month ago, recogniizing that this normally indicative backlog ratio is being skewed by record low completions…
Oil producing regions saw a net DUC well increase in July, while natural gas producing regions still saw a modest net DUC well decrease, even as some basins went against that overall trend….the number of uncompleted wells remaining in the Permian basin of west Texas and New Mexico increased by 40, from 3,480 DUC wells at the end of June to 3,520 DUCs at the end of July, as 138 new wells were drilled into the Permian, while 98 wells in the region were being fracked….at the same time, DUC wells in the Bakken of North Dakota increased by 6, from 896 DUC wells at the end of June to 902 DUCs at the end of July, as 19 wells were drilled into the Bakken in June, while 13 of the drilled wells in that basin were being fracked…in addition, the drilled but uncompleted well count in the Niobrara chalk of the Rockies’ front range increased by 1 to 484, as 16 Niobrara wells were drilled in July while 15 Niobrara wells were completed… on the other hand, there was a decrease of 6 DUC wells in the Eagle Ford of south Texas, from 1,224 DUC wells at the end of June to 1,218 DUCs at the end of July, as 24 wells were drilled in the Eagle Ford during July, while 30 already drilled Eagle Ford wells were completed…similarly, DUCs in the Oklahoma Anadarko also decreased by 6, falling from 705 at the end of June to 699 DUC wells at the end of July, as 9 wells were drilled into the Anadarko basin during July, while 15 Anadarko wells were being fracked….
Among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 6 wells, from 574 DUCs at the end of June to 568 DUCs at the end of July, as 57 wells were drilled into the Marcellus and Utica shales during the month, while 63 of the already drilled wells in the region were fracked….on the other hand, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 1 to 294, as 29 wells were drilled into the Haynesville during July, while 28 of the already drilled Haynesville wells were fracked during the same period….thus, for the month of July, DUCs in the five major oil-producing basins tracked by in this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) increased by a net of 35 wells to 6,823 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 5 wells to 862 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas…
Utica Shale well activity as of Aug. 15 – Three horizontal permits were issued during the week that ended Aug. 15, and 5 rigs were operating in the Utica Shale.
- DRILLED: 153 (157 previous week)
- DRILLING: 94 (95)
- PERMITTED: 504 (506)
- PRODUCING: 2,535 (2,528)
- TOTAL: 3,286 (3,286)
Pipelines lose bid to lower tax bills, can appeal — Akron Beacon Journal – The Ohio Department of Taxation has denied bids by NEXUS Gas Transmission and Rover Pipeline to lower their tax bills.Both pipelines ship natural gas from the Utica and Marcellus shale regions to markets in Canada and across the United States.NEXUS and Rover appealed the Department of Taxation’s valuation of their pipelines last year.County auditors use state valuations to set tax collections for school districts, townships, library districts and other entities.Based on the state’s valuations, the Rover and NEXUS pipelines, combined, were projected last year to generate $20 million in extra revenue in Stark County and lower the rates on levies with set dollar amounts.But the owners of the pipelines said the assessments were too high.The 36-inch-diameter NEXUS pipeline crosses northern Ohio, including Stark, Summit, Wayne, Medina and Columbiana counties. NEXUS is a partnership between DTE Energy and Enbridge.The state set the taxable value of NEXUS near $1.4 billion, but the owners argued for a taxable value closer to $996 million. The owners said building the pipeline cost $2.6 billion, $400 million more than planned.Rover follows a path a few miles south of the NEXUS route. Rover consists of twin 42-inch-diameter pipelines, plus connecting lines, that traverse Stark, Carroll, Tuscarawas, Harrison, Wayne, Ashland and Richland counties.Energy Transfer Partners, Blackstone Group and Traverse Midstream Partners own the pipeline.The owners sought to cut Rover’s taxable value from $3.5 billion to about $1.85 billion. The owners said the pipeline went $2 billion over budget, costing $6.2 billion.Tax Commissioner Jeffrey A. McClain denied the appeals of both pipelines on July 10. The companies have 60 days from that date to appeal to the Ohio Board of Tax Appeals. The issue ultimately could land before the Supreme Court of Ohio.
Trump administration continues push for Ohio petrochemical plant – A proposed petrochemical plant in eastern Ohio got another push from the Trump administration Thursday, with a top official saying that he’s optimistic a new partner will be found to invest in its development. Mark W. Menezes, deputy U.S. Energy secretary, visited the site of the proposed complex in Shadyside along the Ohio River. “We are all here today for the same reason: We want this project to continue moving forward,” he told local officials in prepared remarks. “We want it to move forward because it will create jobs right here in Belmont County. We want it to move forward because it will strengthen American energy security.” The fresh push comes amid uncertainty about the project’s future. A key partner in the project, Daelim of South Korea, pulled out last month, citing the economic effects of the coronavirus pandemic and oil price volatility. That has left Thailand-based PTT Global Chemical America looking for new partners on the project. “We’re very optimistic that we’ll find a replacement partner on the project, Menezes told The Dispatch, noting that the coronavirus has forced companies of all kinds to put off investment decisions. A Department of Energy report issued last month found that the project would be an economic boon to the region, creating 600 permanent jobs and an estimated 6,000 construction jobs. The study’s results have been disputed by others who say it didn’t fully take into account global market conditions, in which the price of plastic is dropping and there’s already a global oversaturation of ethane cracker plants and plastics manufacturing. The proposed plant would take ethane, a component of natural gas, and break it down to produce ethylene, which is used in chemical and plastics manufacturing. The plant would capitalize on the abundant supplies of cheap natural gas that has been developed in the Marcellus and Utica shale regions. A similar project is under construction in nearby western Pennsylvania.
Belmont College partners with Tri-State Energy Advanced Manufacturing (TEAM) Consortium to build skilled workforce in the tri-state region to meet increasing demand Belmont College, partnered with members of the Tri-State Energy and Advanced Manufacturing (TEAM) Consortium, are working together to build a skilled workforce for the tri-state area of Ohio, Pennsylvania and West Virginia to address the increasing skills gap between growing employer needs and education driven by the discovery of natural gas-rich Marcellus and Utica shale deposits. The tri-state region now accounts for 27% of the natural gas output in the United States – making it the third largest producer of natural gas in the world. Offering certificates and degrees in the technologically advanced energy and natural resources industry, Belmont College prepares students for in-demand careers in HVAC, Welding, Industrial Electronics, Process Control Technician, Instrumentation and Control, Civil Engineering Technology, Energy and Natural Resources, and CDL training. The new oil and gas workforce in the region has led to increased demand for CDL, Welding and Technology, and HVAC skills, leading Belmont College HVAC graduates to a 100% job placement rate at local HVAC dealers. Additionally, pending the final start date announcement which could be as early as 2021, the U.S. subsidiary of PTT Global Chemical (PTTGC America) will begin possible construction of a world-scale petrochemical complex in the Mead Township along the Ohio River in Belmont County, which will use products from the emerging oil and gas industry to product raw materials for the United States and global plastics industry. This complex would be the largest private investment project in the history of the State of Ohio with the potential to create hundreds of full-time jobs and thousands of construction jobs, many of which will utilize training offered at Belmont College.
CNX fined for 2019 shale gas blowout – CNX Gas Co. LLC has agreed to pay a $175,000 fine to settle violations related to a January 2019 Utica Shale gas well blowout in Washington Township, Westmoreland County. The very visible well drilling failure allowed gas from the Utica Shale well to flow into nine nearby shallower gas wells, causing the Cecil-based company to burn off or “flare” gas from them all to alleviate pressure at the wells. The state Department of Environmental Protection said in a Thursday announcement of the consent order and agreement with CNX that the blowout at the company’s Shaw 1G Utica well was likely caused by cracks in the well’s “casing,” a concrete sheath around the well pipe that extends underground to prevent gas from the well from contaminating shallower groundwater, rock and soil formations and nearby wells. DEP Secretary Patrick McDonnell said in the release that the department’s investigation and determination of cause will help improve drilling practices to better protect the environment. According to the state department’s release, CNX was performing hydrological fracturing or “fracking” on the Shaw well on Jan. 26, when an unexpected loss of pressure caused the uncontrolled flow of gas into shallower geologic formations and the nine nearby wells. CNX temporarily flared the wells to relieve gas pressure but didn’t regain control of the Shaw well until Feb. 4, when, the DEP said, it stopped the vertical flow of gas by pumping heavy mud into the wellbore, also referred to as “killing the well.” According to the DEP, CNX failed to use strong enough casing and other safety measures to prevent blowouts, failed to maintain well integrity and vented gas into the atmosphere. The nine conventional wells returned to normal operating pressures, and the DEP said no spills or releases of fluids to the surface were observed or reported as a result of the incident. CNX’s investigation concluded, according to the DEP, which concurred, that stress cracks in the Shaw well casing “most likely caused the incident.”.
DEP fines CNX for well failure near Westmoreland County reservoir – The Pennsylvania Department of Environmental Protection fined CNX $175,000 for allowing a gas well failure near a drinking water reservoir in Westmoreland County. The DEP and the company concluded that a casing pipe inside the well ruptured about 5,000 feet below the surface of the Shaw 1G well on Jan. 26, 2019. The rupture sent gas and fracking fluids into nearby rock layers. The gas reached surrounding gas wells, said Lauren Fraley, a spokeswoman for the DEP. “During that loss of pressure incident, gas was emitted uncontrollably into shallower geologic formations, and that resulted in communication with nine nearby conventional wells that saw some pressure changes during this incident,” Fraley said. The company flared those surrounding wells for a week to relieve the extra pressure until it could contain the gas. Fraley said there were no spills or releases of fluids. The well is near the Beaver Run Reservoir, which provides drinking water for 130,000 people. The Municipal Authority of Westmoreland County conducted numerous tests after the failure and determined water in the reservoir was not affected. The DEP says the company no longer uses the “high tensile” pipe it used at the Shaw well, and has retrofit other wells to prevent a similar accident. The DEP cited the company for violating several environmental laws and regulations, including failing to use strong enough well casing, failing to maintain well integrity, and venting gas to the atmosphere. Fraley said the DEP determined that the higher tensile casing was more susceptible to a type of stress cracking, and has shared this information with other gas companies. Brian Aiello, a spokesman for CNX, said the company was “pleased” with the investigation and that the “collaborative nature of the investigation into this matter yielded results that will further continuous improvement and innovation in CNX’s operations and that of the entire industry.” Local environmental groups criticized the DEP fine. The Westmoreland Marcellus Citizens Group said in a statement Friday the fine was inadequate to the danger posed by the well blowout and the air pollution caused by the company’s flaring activities.
Energy Transfer to deliver plan of action this week following Mariner East spill at Snitz Creek – – The Mariner East pipeline on Aug. 13 dumped 20 gallons of industrial waste into Snitz Creek, according to a notice filed later that day by the Pennsylvania Department of Environmental Protection. The spill follows a few days after a much larger accident in Chester County. A notice sent by DEP to Matthew Gordon, senior director of operations for the Energy Transfer/Sunoco pipeline project, cites the “inadvertent return of drilling fluids” into the creek in West Cornwall Township (PDF). The discharge of industrial waste into Pennsylvania waterways without a permit is a violation of the Clean Streams Law, the letter says. The letter orders Energy Transfer to document the steps taken to contain and remove the wastewater from the creek, along with “a plan for any additional remedial measures necessary to complete remediation,” by Thursday, Aug. 20. The letter also notes that work cannot resume on the project without DEP approval. “If the Department determines that an enforcement action is appropriate, you will be notified of the action,” the letter concludes. The letter was signed by Ronald C. Eberts Jr., an environmental protection compliance specialist of the department’s Conservation, Restoration, and Inspection Section, Waterways & Wetlands Program. It was copied to representatives to the Lebanon County Conservation District, the Pennsylvania Fish and Boat Commission, the U.S. Army Corps of Engineers, West Cornwall Township and several other officials of the Sunoco pipeline partnership. Earlier this month, according to a report by StateImpact Pennsylvania, Sunoco’s Mariner East pipeline construction spilled an estimated 10,000 gallons of drilling mud, or bentonite clay, into Marsh Creek and Marsh Creek Lake at a state park in Chester County. The Department of Environmental Protection shut down two underground drilling sites in West Whiteland and Upper Uwchlan townships, pending an investigation, the report said. The lake is a popular recreation site and provides drinking water for Chester County residents, although it was not immediately clear if any drinking water supplies were affected. Bentonite clay is nontoxic, but in large quantities, it can have an impact on smaller aquatic life. News of the local spill drew criticism from grassroots watchdog Concerned Citizens of Lebanon County (CCLC). In a letter to CCLC members, leaders Pam Bishop and Doug Lorenzen said a tanker truck was parked on Aug. 14 on North Cornwall Road, near the intersection with Route 72, “presumably pumping water out of the creek as part of the ‘clean up.'” They also said in the letter that, during construction of a parallel pipeline at the same site in 2017 and 2018, “there were at least seven discharges of drilling mud,” for which DEP also issued notices of violation to Sunoco.
State Hits Sunoco With $355K Penalty For 2018-19 Violations – – The Pennsylvania Department of Environmental Protection today hit Sunoco Pipeline L.P. with a $355,636 penalty for violations in eight counties between August 2018 and April 2019. The violations are related to construction of the Mariner East 2 pipeline Berks, Blair, Cambria, Cumberland, Delaware, Lebanon, Washington, and Westmoreland counties. The DEP said today the penalty was part of a Consent Assessment of Civil Penalty (CACP) signed earlier this month. “Protecting the waters of the Commonwealth is one of the top priorities of DEP and we will continue to hold polluters of those waters accountable,” said DEP Secretary Patrick McDonnell. Sunoco’s horizontal drilling activities resulted in unauthorized discharges of drilling fluids consisting of bentonite clay and water, also known as inadvertent returns, (IRs) to Piney Creek in Blair County; tributaries and wetlands connected to Hinckston Run, Stewart Run, and Little Conemaugh Creek in Cambria County; Letort Run and wetlands and tributaries to the Yellow Breeches Creek in Cumberland County; a tributary to Chester Creek in Delaware County; Snitz Creek in Lebanon County; a tributary to Peters Creek in Washington County; and a tributary to the Conemaugh River in Westmoreland County. As part of the agreement, DEP has assessed a civil penalty of $355,636 for the violations, which Sunoco has agreed to pay to the Commonwealth. A portion of the civil penalty, $5,912, will be paid to the county conservation districts to reimburse them for their costs incurred during their investigation of the inadvertent returns. The remaining penalty, $349,724, will be paid to the Clean Water Fund. Additional information and documents, can be found on DEP’s Mariner East 2 webpage. The DEP also today issued two violations to Sunoco related to a spill and sinkhole at Marsh Creek State Park and a groundwater release on Shoen Road, both in Chester County. Related story here.
Pennsylvania fines Sunoco Mariner East 2 NGL pipe for spills again (Reuters) – The Pennsylvania Department of Environmental Protection (DEP) fined Energy Transfer LP’s Sunoco Pipeline unit again this week for spilling drilling fluid during construction of its long-delayed Mariner East 2 natural gas liquids (NGL) pipeline. The $355,636 fine assessed Thursday for violations in 2018 and 2019 was just the latest in a long series of sanctions against the company for spills and other violations of its construction permits. The biggest fine was for $12.6 million in 2018. In addition to fining Sunoco, Pennsylvania has also stopped construction work on the pipe several times in the past due to spills and sinkholes. Several politicians and local groups have long urged the state to stop work again and shut the pipe. Officials at Energy Transfer were not immediately available for comment. Since May 2017, Pennsylvania has issued 113 notices of violation to Mariner East, mostly for drilling fluid spills, including 13 so far in 2020. In its latest fine, the DEP said Sunoco’s horizontal drilling activities resulted in unauthorized discharges of drilling fluids consisting of bentonite clay and water in several streams and wetlands between August 2018 and April 2019. Energy companies use horizontal drilling to burrow under waterbodies, roads and other obstacles when building a pipeline. Mariner East transports liquids from the Marcellus and Utica shale in western Pennsylvania to customers in the state and elsewhere, including international exports from Energy Transfer’s Marcus Hook complex near Philadelphia.
Chesco Commissioners Step Up Pressure On Gov. Wolf To Stop Sunoco – – The pipeline accident at Marsh Creek Lake Aug. 10 involved a sinkhole 15 feet wide and 8 feet deep, “a mere 5-feet from the active Mariner East 1 (ME1) pipeline, which presently carries hazardous liquids,” Chester County commissioners said late Tuesday. The board called on Pennsylvania Gov. Tom Wolf to stop construction of the Mariner East 2 pipeline and revoke Sunoco’s authorization for construction, saying civil penalties and temporary suspensions were “no longer sufficient.” Chester County’s Board of Commissioners said they learned of the sinkhole incident during a telephone conference with Commonwealth officials on Friday, Aug. 14, regarding Sunoco Pipeline, L.P.’s (Sunoco) Mainer East 2 project (ME2) in Chester County.The board drafted a letter that was sent late Tuesday to Wolf, expressing grave concern about another in “a series of sinkholes showing up across Chester County.” “This sinkhole is in addition to the numerous other recent sinkholes that began appearing in West Whiteland Township, Chester County in mid-June 2020. As you may be aware, a sinkhole in West Whiteland Township in 2018 exposed the ME1 pipeline and prompted the Chairwoman of the Pennsylvania Public Utility Commission (PUC) to order that the ME1 pipeline temporarily cease operations because ‘permitting the continued flow of hazardous liquids through the ME1 pipeline without proper steps to ensure the integrity of the pipeline could have catastrophic results impacting the public,'” the letter stated. “Yet another sinkhole within feet of the active ME1 pipeline is alarming and deeply troubling,” the commissioners told Wolf. “While we wrote to you last week asking that Sunoco’s permits be suspended, after learning about this new development, it seems that civil penalties and temporary suspensions are no longer sufficient. The construction of ME2 must be stopped and the permits authorizing its construction must be revoked.” “Doing anything less risks ‘catastrophic results impacting the public.'”
Berkeley Solid Waste Authority turns down gas facility – The Berkeley County Solid Waste Authority adopted a motion Wednesday indicating it has no interest in having a compressed natural gas facility at the authority’s Grapevine Road property. The potential for co-mingling of natural gas trucks with traffic to and from the Grapevine Road Recycling Center on Landfill Drive was the dominant safety concern, authority chairman Clint Hogbin said Thursday. The board voted unanimously to adopt a motion authorizing Hogbin to notify Mountaineer Gas Co. of its decision. The gas company is considering developing Eastern Panhandle sites where natural gas can be delivered by truck to meet peaks in local customer demand. Larry Meador, communications manager for Mountaineer Gas, said earlier this month the company has been looking at two or three potential locations to transfer compressed and liquified natural gas from trucks into the company’s existing distribution system. Having multiple facilities effectively reduces the size of each facility, Meador has said. The gas company proposed putting a portable, compressed natural-gas facility off Grapevine Road for up to 18 months after first proposing a lease of up to an acre of solid waste authority property for a period of three to five years with an option to buy, according to Hogbin. The solid waste authority didn’t support that proposal either, according to Hogbin. Meador had said truck deliveries probably wouldn’t be needed for quite a few years if it could connect with a pipeline in Morgan County that has been proposed by Columbia Gas Transmission LLC. That pipeline connection, however, is the subject of a federal lawsuit pending before the 4th Circuit Court of Appeals in Richmond, Va. A subsidiary of TC Energy, Columbia Gas Transmission has proposed an 8-inch pipeline from existing facilities in Pennsylvania, across Washington County and the Potomac River to connect with Mountaineer Gas’s new distribution pipeline in Morgan County. In its federal court appeal, Columbia Gas is challenging a district judge’s August 2019 ruling that upheld the state of Maryland’s denial of an easement that Columbia Gas sought for the pipeline to travel beneath the state-owned Western Maryland Rail Trail west of Hancock. The pipeline also is envisioned to go under Cheasapeake and Ohio Canal Historical Park, which is owned by the National Park Service. In July, the company asked the Federal Energy Regulatory Commission for an extension to July 18, 2023 to complete the pipeline.
Peregrine Acquires Additional Royalties in Doddridge County – Peregrine Energy Partners has agreed to acquire producing royalties in Doddridge County, West Virginia from several private sellers. Continuing their string of acquisitions in the Appalachian Basin, Peregrine finalized the acquisition of royalties in 17 producing natural gas wells across three units under Antero Resources and Jay-Bee Oil and Gas. Antero is the largest natural gas producer in West Virginia with over 451,000 net acres in the Marcellus Shale and another 91,000 net acres in the Utica Shale. “We will continue to look for properties with a similar profile in the Marcellus; a diversified well count generating consistent cashflows with single digit decline rates under a well-capitalized, pure-play operator,” said Josh Prier, Peregrine Managing Director. Peregrine is focused on working with and providing solutions for royalty owners and their families. Throughout the acquisition period, the company worked closely with multiple related royalty owners who had inherited this asset. The family’s initial goal was to solve succession issues to avoid fractionalizing the property further. However, after learning the significant financial opportunity and tax benefit of divesting now instead of receiving the passive income over the next handful of decades, the family decided to fast-forward the income. The Texas based royalty buyer has been actively acquiring in the Marcellus Shale as well as across the country since the company’s inception. The current state of the economy and fluidity of the oil & gas industry has Peregrine committed and focused in their efforts to provide clients with reliable and valuable insight throughout their client’s decision-making process.
Mountain Valley pledges up to $19.5 million to conserve land along Appalachian Trail – The company that plans to burrow a natural gas pipeline under the Appalachian Trail is pledging up to $19.5 million to conserve land in other spots along the footpath’s route through Virginia and West Virginia. Mountain Valley Pipeline on Monday announced what it called a voluntary “stewardship agreement” with the Appalachian Trail Conservancy and The Conservation Fund. More than a year ago – when the pipeline’s path across the Appalachian Trail was still in question – Mountain Valley initiated contact with the two groups, “seeking assistance to identify and develop sustainability efforts that would complement MVP’s infrastructure project,” a joint news release stated. Concerns about the pipeline’s impact on the trail and surrounding views led to talks about how Mountain Valley could help with the purchase of high-priority land near the 2,000-plus-mile footpath. “Those tracts will enhance the Trail hiker experience and protect views from numerous vantage points,” according to the news release, which called the gift the largest of its kind for a single region in the conservancy’s history. Mountain Valley plans to bore 80 feet under the trail, creating a tunnel for a 42-inch diameter steel pipe that will channel natural gas at high pressure from the Marcellus and Utica shale formations to markets along the East Coast. In June, a decision by the U.S. Supreme Court cleared plans for the pipeline to pass under the trail at the top of Peters Mountain, where it will cross the state line into Giles County on its way through Southwest Virginia. Although construction is currently stalled by multiple legal challenges – brought by environmental groups who say the project will scar the landscape, pollute streams and kill endangered species – Mountain Valley says it expects to regain suspended permits in time to finish the 303-mile pipeline by early next year. With Monday’s announcement, Mountain Valley sought to establish some common ground between a commercial venture and the grassroots opposition it has faced for six years.
Pipeline construction firm files lawsuit against Mountain Valley Pipeline – A Texas-based pipeline construction company is suing the Mountain Valley Pipeline to get $103.8 million it alleges it’s owed by the Pittsburgh-based joint venture – and that the under-construction pipeline be sold to meet the terms of the deal.US Trinity Energy Services LLC filed suit against Mountain Valley Pipeline earlier this month in Allegheny County Court of Common Pleas. It follows a back and forth between US Trinity and MVP over costs involving building of the pipeline in West Virginia that led to a mechanic lien for $102.5 million filed March 3 in Monroe County, West Virginia.The company filed three counts in Allegheny County Court of Common Pleas: breach of contract, foreclosure of mechanics’ liens and failure to pay under the Pennsylvania Contractor and Subcontractor Payment Act. US Trinity is looking for $103.8 million in damages, a judgment for the mechanics’ liens and interest of 1% a month and attorneys’ fees.US Trinity in its lawsuit urged the “Notice of Mechanic’s Liens be enforced and that the Pipeline be sold to satisfy the sum determined to be due Trinity up to the value of its lien ($102,469,189.65).”It was another legal setback for the Mountain Valley Pipeline, which is being constructed by Equitrans Midstream Corp. (NYSE: ETRN) and will carry Marcellus and Utica shale natural gas from northern West Virginia down the Mountain State and into southwestern Virginia. The 303-mile pipeline, which has been in the works since 2014, remains shut down for construction due to a stop-work order from the Federal Energy Regulatory Commission as well as several pending permits. Equitrans said recently that it expects to be in service with the pipeline in early 2021.The delays, and the failure to receive one of those permits from the U.S. Army Corps of Engineers called a Nationwide 12, was cited by US Trinity in the lawsuit. US Trinity was named a contractor on the MVP to build in three counties in West Virginia in late 2017 but it said the work was delayed and disrupted for reasons beyond Trinity’s control.”Large portions of Trinity’s work space was unavailable because MVP failed to timely obtain certain environmental permits, including the 12 Permit,” the lawsuit said. “From the outset of the project, Trinity was forced to incur multiple Move Around events, place its crews and equipment on standby, and suspend its work repeatedly between available work spaces.”Trinity and MVP had resolved previous disputes over payment until after February 2019 but filed a mechanic’s lien this year after the Nationwide 12 permit didn’t materialize. MVP told Trinity as part of the FERC stop-work order to stop just about all the work and then was told in November 2019 to terminate all work and submit documents for outstanding payment. US Trinity said it submitted the $103.8 million including $83.8 million related to change-work orders that encompass the delays and disruptions to the MVP schedule.It said MVP approved only $9 million in payment requests out of the $103.8 million, rejecting the rest. It also said it wouldn’t pay the money it did approve May 1 until after the mechanic lien had been released.
Pipeline infrastructure planning in the era of Black Lives Matter – Natural gas pipeline project developers face delays, uncertainty and increased costs arising from intense inquiries from regulators, affected communities and activists concerning their compliance with the various environmental laws and regulations that govern the construction and operation of pipelines and associated facilities. This is owing, at least in part, to arguments invoking environmental justice concerns and consideration of the impacts that project siting has on communities of color rising to prominence. Given the light shone by the Black Lives Matter (“BLM”) movement on the systemic racism faced by people of color, scrutiny of the siting of infrastructure projects is already increasing, and attention paid to disproportionate, adverse effects on communities of color likely will intensify. The BLM movement may also influence how courts and regulatory agencies interpret companies’ obligations under environmental laws, while shareholders may take the movement’s ideals under advisement as part of their larger environmental, social and governance considerations. Energy companies planning to undertake capital-intensive infrastructure projects should consider the implications of the BLM movement and tailor their planning and development to reflect the outgrowths of the current times – the era of Black Lives Matter. Earlier this year, the U.S. Court of Appeals for the Fourth Circuit in Friends of Buckingham v. State Air Pollution Control Board (“Buckingham”) vacated a permit granted to Atlantic Coast Pipeline LLC (“ACP”) to construct and operate a compressor station intended to transmit natural gas through ACP’s pipeline. The compressor station, consisting of four natural gas-fired turbines that emit pollutants, was to be located in a historic, predominantly Black community largely occupied by descendants of freed slaves. Responding to a challenge by community residents, the court found that the granting authority had not determined whether the community was a “minority” environmental justice community – a critical designation when evaluating the likelihood of disproportionate health impacts to residents. The court also concluded that the board failed to assess the compressor station’s potential for disproportionate health impacts on the community, notwithstanding a study by residents that community members suffered from health conditions that would make them more susceptible to the compressor station’s emissions. Ultimately, the court determined that “environmental justice is not merely a box to be checked.” The $8 billion project was abandoned months later, with representatives citing the legal challenges and resulting delays as the cause.
Rule allowing LNG rail shipments in US challenged in court – (AP) – A coalition of six environmental advocacy groups asked a federal judge on Tuesday to block a new Trump administration rule to allow rail shipments of liquefied natural gas, a new front in the movement of energy products backed by both the natural gas and rail freight industries. The groups will argue in court that, among other things, the administration did not adequately study the new rule to ensure that the activity it is authorizing is safe for workers, communities and the environment, said Jordan Luebkemann, a lawyer for Earthjustice, which is representing the groups court. The rule, they said, would allow shipments of the flammable and odorless liquid known as LNG by rail in tanker cars that are untested and that cannot withstand high-speed impacts. “Under this new rule, it’s only a matter of time before we see an explosion in a major population center,” said Emily Jeffers, an attorney with the Center for Biological Diversity. The U.S. Pipeline and Hazardous Material Safety Administration published the rule late last month in the Federal Register and it takes effect in the coming days. The country’s natural gas boom has fueled massive growth in LNG exports, growing last year by more than 65 times the amount exported in 2015, according to federal figures. The rule requires enhancements – including a thicker outer tank made of steel with a greater puncture resistance – to the approved tank car design that, for decades, has been approved for shipments of other flammable cryogenic materials, such as liquid ethylene and liquid ethane. Previously, federal hazardous materials regulations allowed shipments of LNG by truck, but not by rail, except with a special permit. Fifteen states also objected to the rule during the comment period. Those states included Pennsylvania and New Jersey, where the Trump administration issued a special permit in December to ship LNG by rail from northern Pennsylvania’s Marcellus Shale natural gas fields to a yet-to-be-built storage terminal at a former explosives plant in New Jersey, along the Delaware River near Philadelphia. From there, the LNG is expected to be exported to foreign markets for electricity production, although the applicant, a subsidiary of New Fortress Energy, has told federal regulators that some domestic industrial use is possible.
A watchdog emerges for planned LNG site | Editorial – nj.com – Well, at least someone in government can walk and chew gum at the same time on behalf of South Jersey residents. While state Attorney General Gurbir Grewal made news by stating he’ll add the Garden State’s name to litigation trying to stop President Donald Trump from dismantling the post office, the AG also filed an objection to a Trump rule that could send rail cars filled with liquefied natural gas hurtling through the region. Saving the U.S. Postal Service is important, But an accelerated rule to allow potentially dangerous LNG to traverse residential neighborhoods in tank cars not specifically designed for the pressurized cargo could be much more disastrous.You can recount a disputed ballot, but you can’t reverse a derailment that creates fire danger and what might amount to an uncontrolled explosion.There’s special relevance to Gloucester, Camden and Salem counties. A proposed terminal to export domestically sourced LNG by ship, located on the Delaware River at Greenwich Township, has been racking up required permits from various agencies. The developers of the Gibbstown Logistics Center pier and storage site have made clear that, if the train rule is OK’d, they’d try to use that mode to bring the Pennsylvania-extracted gas to Greenwich.The pending federal rule (promulgated by the Department of Transportation’s Pipeline and Hazardous Materials Safety Administration) allows trains with up to 100 cars each to move to destinations around the country. It would go into effect Aug. 24 unless objections – including New Jersey’s – cause regulators to suspend, modify or cancel it.New Jersey becomes the 14th state to challenge the rule as proposed. In his Tuesday announcement, Grewal didn’t go as far as Maryland Attorney General Brian Frosh, who referred to ships carrying LNG as “floating bombs,” and added, “Rolling tank cars filled with LNG though our neighborhoods are vastly more dangerous.”
Is New England’s On-and-Off Embrace of Gas-Fired Power Headed for a Fall? | RBN Energy – The U.S. power sector’s shift to natural gas over the past few years has been a boon to gas producers across the Lower 48, especially in the Northeast. Scores of new gas-fired power plants have been built there during the Shale Era, and a number of coal-fired, oil-fired, and nuclear plants have been taken offline. New England is a case in point; gas-fired power now accounts for about half of the installed generating capacity in the six-state region (Connecticut, Rhode Island, Massachusetts, Vermont, New Hampshire, and Maine) – three times what it was 20 years ago. But New Englanders have a love-hate relationship with natural gas, and with renewables and energy storage on the rise, gas’s role in the land of the Red Sox, hard-to-understand accents, and lobsta’ rolls may well have peaked. Today, we discuss recent developments on the natural gas and power generation fronts in the northeastern corner of the U.S. Over the past few years, we’ve posted many blogs about New England’s natural gas pipeline infrastructure, which, despite the best efforts of midstreamers, has failed to keep pace with either the region’s shift to gas-fired power generation during the 2000s and ’10s or the growth in natural gas production from the Marcellus and Utica shale plays that sit at its doorstep. As we said in Please Come to Boston back in 2014, five pipeline systems provide the vast majority of New England’s gas: Tennessee Gas Pipeline (TGP; blue line in Figure 1) and Algonquin Gas Transmission (AGT; green line) from the south, Iroquois Gas Transmission (IGT; lavender line) from the west through New York State, and Maritimes & Northeast Pipeline (MNP; pink line) along with Portland Natural Gas Transmission (PNGT; yellow line) from Canada, through New Brunswick and Quebec, respectively. There are also two LNG import terminals in the Boston, MA, area capable of importing LNG, regasifying it and then sending it out into the U.S. gas pipeline network during periods of high demand (see our You Dropped a Bomb on Me series). These are: Excelerate Energy’s Northeast Gateway Deepwater Port and Exelon Generation’s Everett terminal, which provides fuel for Exelon’s 1,400-megawatt (MW), gas-fired Mystic power plant (more on this in a moment) as well as gas to gas utilities. There’s also the Canaport LNG import terminal up in New Brunswick, from which regasified LNG can be piped down MNP into New England.
Why Warren Buffett is betting on energy pipelines even as climate fears are rising – With the coronavirus pandemic slashing demand for the oil and gas that has been booming in the U.S. shale during the past decade, energy pipeline development has stalled. The midstream portion of the energy complex, as it is known, may not recover soon, but it will recover, according to energy experts, and none other than Warren Buffett – who has been uncharacteristically shy about making investments during the Covid-19 washout – is betting on that. The billionaire investor recently plunked down near-$10 billion to buy gas pipeline assets and related debt. After a decade of capacity buildout in the pipeline infrastructure to match the U.S. fossil fuel fracking growth, demand is lacking and will stay down, despite a doubling in the price of crude following sub-$20 lows reached in March. “You have to consider what drove the infrastructure development: the shale boom. When you look at oil near $40 and natural gas rising, but still sub-$3, we’re not in a climate where higher production of oil and gas is supported to support a larger build out,” Before Covid-19 hit, Platts Analytics was forecasting U.S. crude oil production to rise by one million barrels per day year over year, and rise by another 600,000 barrels in 2021. Now, as rig counts have declined at the steepest rate since 2009 – 75% of natural gas production comes from the “associated gas” at oil rig sites, as well – crude production is expected to register an annual decline within the next few months, and that decline will persist until at least mid-2021, according to Platts Analytics’ forecast. Instead of the substantial growth that midstream companies had been making investment decisions based on – and which led to a significant number of pipeline projects coming online within the past two years – major shale basins like the Permian will see lower utilization of outbound pipelines for the next few years.But there’s more going on then just a typical commodities boom-and-bust cycle. With successful environmental challenges leading to legal and regulatory roadblocks for pipelines, and a political climate becoming more difficult for fossil fuels, companies in the utility sectors are rethinking their midstream investments, and in some cases, reallocating funds towards renewable energy projects. But Buffett’s acquisition will provide a steady stream of revenue and a quality asset, regardless of the lack of midstream development. Buffett also has always preferred investments in a market where more control is reasonable to expect – lack of new pipeline supply could be a plus as far as his preference for less competition likely to come into the market. The Dominion gas pipeline and storage assets include operations in Connecticut, Maryland, Ohio, West Virginia, Pennsylvania, New York, Maryland and Virginia. The deal won’t burn a hole in his pocket, either, with Berkshire sitting on well over $100 billion in cash and short-term assets, and Buffett always anxious to deploy the capital into projects that generate a return on investment.
Natural Gas Prices Soar As Heat Wave Hits Large Parts Of U.S. – Natural gas prices spiked on Friday by nearly 9%, even as the weekly storage report showed little movement. Natural gas prices hit $2.367 by 2:26 pm EDT, an increase of 8.48% or $0.185, even as the EIA’s weekly storage report a day earlier showed a small increase of 58 Bcf in working gas in storage. The market had anticipated a larger build. Also bullish for natural gas on Friday were forecasts for hot weather and reports of increased LNG exports. Front-month natural gas futures on Friday hit their highest since the end of last year on this data as air conditioning usage is expected to increase as people try to cope with the heat wave. This will increase the demand for natural gas. This will be particularly true in Texas, where demand for power in general – and consequently natural gas – is expected to hit a record high today as the heatwave sets in, according to Reuters. These record highs for power demand will come even as industrial activity has not yet returned to pre-pandemic levels.This unprecedented power demand has led to increases in power prices in the western part of the United States, which has, in turn, boosted natural gas prices.Front-month nat gas futures were up more than $0.15 to $2.335 on Friday afternoon.LNG exports have also increased, with improved demand outlook over the next couple of weeks, although the EIA stated that U.S. LNG exports will remain at lowlevels for the remainder of the summer, with planned cargoes of LNG still being canceled. According to EIA data cited by Kallinish, 46 LNG cargoes were canceled in June, 50 canceled in July, 45 were canceled in August, and so far 30 have been canceled for September.
U.S. natgas futures slip from 8-month high as demand slowly eases – (Reuters) – U.S. natural gas futures on Monday slipped from an eight-month high in the previous session as output slowly increases and on forecasts for milder weather and lower air conditioning demand than previously expected. That price decline came despite a steady increase in liquefied natural gas (LNG) exports. Front-month gas futures fell 1.7 cents, or 0.7%, to settle at $2.339 per million British thermal units. On Friday, the contract closed at its highest since Dec. 5. Electricity prices in the U.S. West, meanwhile, soared to record highs as California consumers prepared for more rotating outages after the grid operator ordered utilities to shut power over the weekend to reduce strain on the system during a brutal heat wave. Gas speculators last week boosted their net long positions on the New York Mercantile and Intercontinental Exchanges to their highest since November 2018 on expectations energy demand will rise as the economy rebounds when state governments lift more coronavirus-linked lockdowns. Although U.S. and European gas contracts mostly trade on their own fundamentals, a 58% jump in prices at the European Title Transfer Facility (TTF) benchmark in the Netherlands so far in August helped pull U.S. gas up about 30% this month. That made it profitable for more U.S. LNG cargoes to go to Europe. U.S. LNG exports were on track to rise in August for the first time in six months. Pipeline gas flowing to the plants climbed to 4.3 billion cubic feet per day (bcfd) so far this month from a 21-month low of 3.3 bcfd in July. With temperatures expected to moderate now that the hottest days of summer are in the past, Refinitiv projected U.S. demand, including exports, will decline from an average of 90.4 bcfd this week to 88.1 bcfd next week.
U.S. natgas futures jump to 8-month high on rising LNG exports, hot weather –(Reuters) – U.S. natural gas futures jumped to an eight-month high on Tuesday on rising liquefied natural gas (LNG) exports, a decline in output and forecasts for warmer weather and higher air conditioning demand over the next two weeks than previously expected. Front-month gas futures rose 7.8 cents, or 3.3%, to settle at $2.417 per million British thermal units, their highest close since Dec. 5. Power prices in the U.S. West, meanwhile, soared to record highs for a second day during a brutal heat wave as California utilities urged consumers to keep conserving energy to avoid more rotating outages with demand expected to near an all-time high on Tuesday. Next-day gas prices at the SoCal Citygate in Southern California, meanwhile, jumped to their highest since February 2019. Although U.S. and European gas contracts mostly trade on their own fundamentals, a 59% jump in prices at the European Title Transfer Facility (TTF) benchmark in the Netherlands so far in August helped pull U.S. gas up about 36% this month. That made it profitable for more U.S. LNG cargoes to go to Europe. U.S. LNG exports were on track to rise in August for the first time in six months. Pipeline gas flowing to the plants climbed to a three-month high of 4.4 billion cubic feet per day (bcfd) so far this month from a 21-month low of 3.3 bcfd in July.
US natgas futures at fresh 8-month high on rising LNG exports – US natural gas futures edged up to a fresh eight-month high on Wednesday as liquefied natural gas (LNG) exports continue to rise and on forecasts for more hot weather and heating demand through early September than previously expected. Front-month gas futures rose 0.9 cents, or 0.4%, to settle at $2.426 per million British thermal units, their highest close since Dec. 5 for a second day in a row. Although US, European and Asian gas contracts mostly trade on their own fundamentals, a 59% jump in prices at the Title Transfer Facility (TTF) benchmark in the Netherlands and a 65% increase at the Japan-Korea Marker (JKM) so far in August helped pull US gas futures up about 33% this month, making US LNG more attractive to global markets. With temperatures expected to remain hot through early September, Refinitiv projected US demand, including exports, will hold around 90.2 bcfd this week and next. That is higher than Refinitiv’s forecast on Tuesday. US production has averaged 88.5 bcfd so far in August, up from a two-month high of 88.0 bcfd in July. That, however, is still well below November’s all-time monthly high of 95.4 bcfd. In California, meanwhile, power companies continued to urge customers to conserve energy through Thursday to avoid more rotating outages as the brutal heat wave blanketing the state over the past week pushes the demand forecast for Wednesday over the prior day’s three-year high.
US working natural gas volumes in underground storage rise by 43 Bcf: EIA | S&P Global Platts – US natural gas stocks increased nearly in line with the five-year average in the week ended Aug. 14 despite net withdrawals being reported in the Pacific region and South Central’s salt-dome facilities as Henry Hub strip prices slip slightly. US underground natural gas storage inventories increased 43 Bcf to 3.375 Tcf in the week ended Aug. 14, the US Energy Information Administration said Aug. 20. The injection was larger than the consensus expectations of analysts surveyed by S&P Global Platts, which called for a 39 Bcf build. Responses to the survey ranged from an injection of 34 Bcf to 51 Bcf. The injection was, however, smaller than the 56 Bcf build reported during the same week a year ago and almost in line with the five-year average increase of 44 Bcf, according to EIA data. Storage volumes now stand 595 Bcf, or 21.4%, above the year-ago level of 2.780 Tcf and 442 Bcf, or 15%, higher than the five-year average of 2.933 Tcf. US supply and demand balances grew tighter during the reference week as a surge in power burn demand helped offset rising supplies, particularly from onshore production gains, according to S&P Global Platts Analytics. Total supply came in 1 Bcf/d higher during the week for an average 92.8 Bcf/d, led by a 800 MMcf/d increase in onshore production and a 400 MMcf/d increase in net Canadian imports, partly counterbalanced by a 200 MMcf/d drop in offshore production receipts. Total demand grew by 2.7 Bcf/d during the week to an average 86.6 Bcf/d, which was mainly the result of a 2.5 Bcf/d increase in powerburn demand, bolstered by a 500 MMcf/d increase in LNG feedgas demand as facilities in the US Gulf Coast continue to see higher LNG liquefaction processing. The NYMEX Henry Hub September contract slid 5 cents to $2.37/MMBtu in trading following the release of the weekly storage report. The winter strip, November through March, fell by an average of 2 cents to $3.08/MMBtu. Spreads from summer to winter have narrowed by nearly 10 cents over the last week to 63 cents, down from 72 cents a week ago and considerably wider than the roughly 90-cent spread seen at the beginning of this month. Since the start of August, the balance of 2020 strip has risen almost 50 cents while the calendar 2021 strip has rallied 15 cents. Platts Analytics expects further upside to the winter and summer 2021 strips amid associated gas production declines.
U.S. natgas falls from 8-month high on big storage build for hot week – (Reuters) – U.S. natural gas futures fell over 3% on Thursday following the release of a report that showed hot weather last week was not enough to cut the storage build below normal levels, meaning it was only enough to offset demand destruction from the coronavirus. Analysts also noted that with prices trading near an eight-month high over the past week, it made economic sense for some generators to burn more coal and less gas to produce electricity. Thursday’s price drop came despite a rise in liquefied natural gas (LNG) exports and forecasts for more hot weather and air conditioning demand through early September than earlier expected. The U.S. Energy Information Administration (EIA) said U.S. utilities injected 43 billion cubic feet (bcf) of gas into storage in the week ended Aug. 14. That matched analysts estimates in a Reuters poll and compares with an increase of 56 bcf during the same week last year and a five-year (2015-19) average build of 44 bcf. Front-month gas futures fell 7.4 cents, or 3.1%, to settle at $2.352 per million British thermal units. On Wednesday, the contract closed at its highest since Dec. 5. U.S. LNG exports were on track to rise in August for the first time in six months. Pipeline gas flowing to the plants climbed to a three-month high of 4.4 billion cubic feet per day (bcfd) so far this month from a 21-month low of 3.3 bcfd in July.
Blistering Heat Wave Behind Latest Run-Up for Weekly Natural Gas Prices – Record-high temperatures on the West Coast and typical August heat and humidity in the South and Southeast this week drove sharp gains in natural gas prices across the Lower 48 for the Aug. 17-21 week. Led by massive increases in California, NGI‘s Weekly Spot Gas National Avg. jumped 20.5 cents to $2.255. However, power conservation efforts, much-needed imports and increased wind generation helped stave off disaster for the nation’s most populous state. Nevertheless, the heightened demand boosted spot gas prices across California to the highest levels of the summer so far. SoCal Citygate traded as high as $14.00 before going on to average $7.040, up $3.205 week/week.Prices in the Desert Southwest also rallied, with Kern Delivery jumping $2.675 on the week to $6.220. In the Rockies, Transwestern San Juan was up 32.0 cents to $2.315.Market hubs in other producing regions also climbed week/week, with increases of about 20 cents or so the norm. Double-digit gains extended across Texas, Louisiana and the Southeast as well. . Analysts saw the move higher as sustainable overall, but cautioned that with two months remaining in the storage injection season, the risk of stocks toppling over still threatened the rally. Indeed, after the U.S. Energy Information Administration (EIA) reported a 43 Bcf build into inventories for the week ending Aug. 14, the market appeared to acknowledge just how loose the market still is, shedding more than 7 cents at the front of the curve. Stocks are now at 3,375 Bcf, nearly 600 Bcf above last year and around 440 Bcf above the five-year average, according to EIA. Even still, two major storms have their sights set on the Gulf Coast, threatening production, LNG exports and domestic demand in the coming days. Two of the biggest operators in the deepwater Gulf of Mexico (GOM), BP plc and Royal Dutch Shell plc, on Friday had begun evacuating employees from platforms and rigs. BP also was shutting in production from its four operated platforms, Atlantis, Mad Dog, Na Kika and Thunder Horse. Work was underway to secure Shell’s drilling operations, but there were no impacts to production as of Friday afternoon. The National Hurricane Center (NHC), in its Friday afternoon update, said on the forecast track, Tropical Storm Laura would move near or over Puerto Rico Saturday morning, and near the northern coast of Hispaniola late Saturday and early Sunday. Tropical Depression 14, which would become Marco if it strengthens as expected, was on track to approach the east coast of the Yucatan Peninsula of Mexico on Saturday before moving over the central GOM toward the northwestern Gulf on Sunday and Monday, NHC said.
Possible oil spill investigated at South Benson Marina – Emergency personnel investigated a possible oil spill Friday at South Benson Marina, according to fire officials. The spill or sheen was reported about 4:40 p.m., according to Assistant Chief George Gomola. Fairfield’s fire and police departments responded to the scene, as did the Connecticut Department of Energy and Environmental Protection. The spill was limited to the H and I docks, according to Lt. Eric McKeon, who said the substance had no odor and was likely oil or gasoline. By the time state environmental officials arrived, much of the spill had dissipated. “We didn’t find any definitive source,” McKeon said, noting the substance could have blown in with the tide or been discharged from a bilge pump. Gomola said the incident was relatively minor in terms of environmental impact.
US Coast Guard- Update on oil spill in Charleston – (WCBD) – On Saturday, an oil spill at the Plum Island Wastewater Treatment Plant released some 3,000 gallons of diesel fuel into a marsh near Dill Creek.A Coast Guard pollution response team has been dispatched to work with the Department of Health and Environmental Control (DHEC) on cleanup efforts. HEPACO, an oil spill response company, was hired to assist in cleanup efforts.Officials are monitoring the impact of the spill, and report “a minimal amount of sheen in Dill Creek.” Booms are reportedly no longer absorbing oil, but “on scene crews will maintain sorbent booms and monitor collection with high tide.”The Coast Guard pollution response team is conducting high tide operations and minimizing foot traffic in the marsh to “reduce the disturbance of the environmentally sensitive area.”
Study: Flaring Linked to Increase in Preterm Births in Eagle Ford Shale – When the fracking boom came to the Eagle Ford Shale, it brought billions of dollars of investment and tax revenue to the rural, sparsely populated swath of South Texas that stretches from the borderlands near Laredo to the northeast toward College Station. In 2015, at the height of the boom, the Eagle Ford was producing more than a million barrels of oil a day. At night, satellite imagery showed rural counties lit up like cities from flaring, the burning of natural gas at well heads. But last month, a new study found that those flares were directly linked to an increase in preterm births in South Texas. Pregnant women exposed to more than 10 nightly flares within three miles of their home had a higher risk of giving birth prematurely. Premature babies can have weak hearts and lungswhen they’re born, and they are more likely to develop chronic health issues later in life. Notably, the study found that trend was exclusive to Hispanic women, who had a higher exposure to flaring than any other demographic in the region.The finding itself is noteworthy, but it’s also one of the rare long term public health studies conducted in the region. “In general, there’s a gap in epidemiology in rural areas,” Jill Johnston, one of the study’s authors, says. “You have to understand the scope of the pollution, and where it’s happening, to link it to an outcome.” That’s already difficult in such a geographically sprawling area, but on top of that, the Eagle Ford also lacks extensive air monitoring to detect the levels of harmful chemicals to begin with.Flaring releases methane, a powerful greenhouse gas, as well as volatile organic compounds, one of ingredients of smog, which irritate the lungs and nervous system. The practice also releases carcinogens like benzene and formaldehyde; nitrogen oxides, which can cause chronic lung issues; and sour-smelling hydrogen sulfide, which causes nausea, dizziness, and headaches. While the state’s Railroad Commission approves permits for oil and gas drilling and flaring, the Texas Commission on Environmental Quality (TCEQ) is tasked with monitoring the emissions from those wells. Across the entire Eagle Ford Shale, which is roughly the size of Delaware, TCEQ maintains seven air monitors – the same number of monitors set up in the city of Dallas, which is a fraction of the size. A handful of the Eagle Ford’s monitors are clustered around large cities like Laredo, measuring particulate matter pollution commonly caused by cars and lighter industrial activity. Only two air monitors track pollutants released from flares: One in Karnes and one in Wilson counties.
Permian Basin natural gas pipeline faces scrutiny after rerouted around Texas river -A controversial natural gas pipeline that would connect extraction operations in the Permian Basin with export and refinery markets in the Gulf Coast continued to face opposition even as the operator announced it would be rerouted around a river in Texas Hill Country. The $2 billion Permian Highway Pipeline project would have a transportation capacity of about 2 billion cubic feet per day of natural gas for about 430 miles east from the Permian Basin area in West Texas to the Gulf Coast. It was expected to be completed and in service by early 2021. The pipeline faced backlash in March after a spill of drilling fluid in the Blanco River in east Texas allegedly contaminated local drinking water and the project’s permits were revoked by Hays County. This week, Kinder Morgan Chief Executive Officer Steven Kean announced in an opinion piece published in the Houston Chronicle that the pipeline would be rerouting around the river instead of being constructed to go underneath. But environmentalist groups were not convinced that the reroute would minimize the pipelines environmental harm on the environment. Throughout the project’s lifetime since it began in 2018, numerous lawsuits were filed seeking to block its construction. Kinder Morgan spokesperson Lexey Long said negotiations about the reroute began with local landowners in June but did not specify the exact new route of the line. Sierra Club Senior Campaign Representative Roddy Hughes pointed to numerous incidents causing environmental harm, he said, as the pipeline was built through Texas from a starting point in Waha near the state’s western border to New Mexico. Hughes said Kinder Morgan cannot be trusted to safely finish building and then operate the pipeline and called for the project to be ceased. “After multiple accidents and spills, Kinder Morgan is picking up and trying to build along a new route, leaving an enormous amount of damage in its wake and putting a whole new group of landowners at risk,” Hughes said.
U.S. Oil Rig Count Rises For First Time Since January – Baker Hughes reported on Friday that the number of oil rigs in the United States rose for the first time since January by 11, to 183 – the first double-digit increase since the pandemic took locked down significant parts of America. The total number of active oil and gas rigs increased by 10 for the week, with oil rigs climbing by 11 and gas rigs falling by one. Total oil and gas rigs in the United States are now down by 662 compared to this time last year. The largest gain was seen in the Permian Basin, which added ten rigs. The EIA’s estimate for oil production in the United States stayed the same for the week ending August 14 – the last week for which there is data, at 10.7 million barrels of oil per day. Oil production in the United States is 2.4 million bpd less than its all-time high reached earlier this year. Canada’s overall rig count rose this week also, by 2, reaching 56 active rigs. Oil and gas rigs in Canada are now down 83 year on year. The Frac Spread Count in North America, provided by Primary Vision, was unchanged last week, at 70. Oil prices were already trading down on the day on Friday despite heightened tensions between the United States and Iran and reports that China is expected to increase its crude oil imports from the United States next month. Dampening the oil spirits on Friday is developments in oil-rich Libya that suggests that a ceasefire has been declared – a development that will surely increase global oil production and ruin OPEC’s 97% compliance rate with its oil production cut agreement. At 12:56 pm EDT, WTI was trading down 2.71% at $41.66 – roughly $0.30 down on the week. Brent was trading down 2.52% on the day, at $43.77, down $1 per barrel from last Friday. At 1:08 pm, WTI was trading at $41.67 per barrel, with Brent changing hands at $43.78 per barrel.
Company finds 74.2M barrels of oil and gas in west Texas – Thanks to a partnership with a geoscientist in the Permian Basin, a family-owned oil company is celebrating its largest discovery yet: a 13,000-acre field in Val Verde County holding an estimated 417 billion cubic feet, or 74.2 million barrels, in oil and gas reserves. Barron Petroleum, based in Graham, announced the discovery on Monday after working with scientist William J. Purves on the project since 2018. Using Purves’ 3D seismic model to estimate the location and size of the oil and gas reservoirs, the company confirmed the find by successfully drilling two wells at the site, located about 35 miles south of the West Texas town of Ozona. “We found out that it was exactly what 3D had shown on Dr. Purves’ study,” said Roger Sahota, president and CEO of Barron Petroleum. “We’re very excited and now we’re trying to figure out how to develop it or get someone to join the venture with us. It’s a large project, and our company is small. It’s just me and my three sons and my wife involved.” Albert G. McDaniel, a petroleum engineer based in Fort Worth, completed the evaluation of the oil and gas reserves and wrote that the project is now so low-risk that it “more resembles that of a development project than an exploration venture.” In an interview, McDaniel added that Barron Petroleum will have the ability to drill some 60 new wells, allowing energy companies to purchase large quantities of gas or oil from one site. “This is a major discovery because these new field designations are all going to be made from this one 13,000-acre lease,” McDaniel said. “These are going to be high-volume, high-rate wells from a major new field that will be developed over the next five to 10 years.” Sahota agrees, and is already negotiating a contract with energy companies Kinder Morgan and Enterprise to lay down a miles-long gas line and sell natural gas drilled out of the field.
Texas Democrat: US natural gas vital in transition to renewables –Rep. Vicente Gonzalez (D-Texas) said energy sources like liquified natural gas are essential in the transition to renewable energy, and that a Biden administration would help in that effort. “It’s not an either or [decision],” Gonzalez said Monday at The Hill’s “Energy Access and Reliability” event during the virtual Democratic National Convention. He said renewable and traditional energy leaders will “need to hold hands and walk this walk together, and I feel fully confident that … we will be able to do it under a Biden administration.” Gonzalez — a member of both the Congressional Renewable Energy Caucus and the Oil & Gas Caucus — argued at the event sponsored by the American Petroleum Institute that the United States should maintain its position as an exporter rather than an importer of energy, so that it can provide oil to allies. One way to do that, he told The Hill’s Steve Clemons, is for Congress to invest in carbon-capturing technology and provide tax credits for companies that develop and use renewable energy technology, all part of the Democratic platform. The 2020 Democratic Party Platform does not mention natural gas but emphasizes investment in renewable energy. Gonzalez’s remarks came the same day the Trump administration announced it had finalized plans to allow oil and gas drilling in 1.5 million acres of the Arctic National Wildlife Refuge in Alaska, dealing a blow to conservationists and proponents of renewable energy. Will Marshall, president of Progressive Policy Institute who also spoke at Monday’s event, said presumptive Democratic presidential nominee Joe Biden is well positioned to help bridge the political divide on the environment by highlighting that energy is “an employment issue” that provides opportunities like investing in manufacturing jobs to build electric vehicles. At a discussion earlier in the day at an event titled “Campaigns and the Pandemic,” Rep. Gwen Moore (D-Wis.) described Biden’s running mate, Sen. Kamala Harris (D-Calif.), as someone who has used her position of power, such as California attorney general and San Francisco district attorney, to fight for the vulnerable, such as going after oil companies that violate environmental standards.
2 bodies found, 2 missing after explosion in Texas port – — The bodies of two missing crew members of a dredging boat were found Saturday following an explosion a day earlier in the Port of Corpus Christi in Texas, according to the U.S. Coast Guard. Two other crew members of the dredging vessel Waymon L Boyd remain missing and the search for them continues, Coast Guard Capt. Jason Gunning said during a Saturday afternoon news conference. The explosion happened at about 8 a.m. Friday when the vessel struck a submerged pipeline, according to the Coast Guard, and Port of Corpus Christi officials said it was a natural gas pipeline. “A full investigation is underway; however, search and rescue efforts are our first priority. It will not be clear for some time the cause of this accident, and any definitive statements to the contrary would be premature,” Strawbridge added. The Waymon L Boyd is owned by Houston-based marine construction contractor Orion Marine Group. The fire onboard the vessel was first extinguished Friday afternoon, but sparked again and was finally put out at approximately 10 p.m. Friday, shortly before the vessel broke apart and sunk, the Coast Guard said. The vessel carried a maximum of about 6,000 gallons of diesel fuel, said Brent Koza, the regional manager for the Texas General Land Office, which investigates oil spills. “We have identified and are preparing for that as our worst case discharge scenario,” and diesel is being recovered from the channel and around environmentally sensitive areas, Koza said.
Public Opinion Is Moving Against Natural Gas and Fracking – The fracked gas industry, already on the ropes financially, has cratered in the pandemic. At the same time, its public support is tanking. This convergence of trends – financial pressure and public skepticism – could spell trouble for at least two big export-oriented fossil fuel proposals in the Northwest that would use vast quantities of gas: the methanol refinery project in Kalama, Washington, and the Jordan Cove LNG project in Coos Bay, Oregon. The decade-long fracking boom that unleashed vast quantities of gas is now fizzling out, doused by a sea of red ink. As evidence mounts that fracking is extremely harmful to the environment and risky for public health, the gas industry seems to be losing the contest for public opinion. In an election year no less. Nationwide in the United States, public opinion has grown skeptical of fracking. Gallup public opinion polling has documented the trend well: in 2015 Americans were evenly split on their support or opposition to fracking. But by 2016 Americans opposed it by an 11-point margin, a figure that widened to 18 points in opposition by 2017. The Pew Research Center documented the same shift in public opinion over the roughly the same period, as fracking fell out of favor. An August 2019 Associated Press-NORC poll found that only 22 percent of Americans support increasing fracking while 45 percent oppose increasing it. And, a YouGov Blue poll in September 2019 found that registered voters support a ban on fracking by 46 to 33 percent. Poll numbers like these have already influenced candidates’ positioning in both state primaries and the US general election. Based on horse race polling, there’s no discernible electoral disadvantage for candidates who take a tough stance on fossil fuels, even in swing states – and even in swing states where fossil fuels loom large, like Ohio, the nation’s fifth-biggest gas producer, and Texas, the nation’s leading gas producer. And no swing state may be more important than Pennsylvania, where the industry cranks out over 6 trillion cubic feet of natural gas annually – a volume that ranks second in the country and ahead of eight OPEC nations. In January 2020, a Franklin and Marshall College poll found that voters in the Keystone State favor a ban on fracking by 48 percent to 39 percent.Okla. oil driller files for bankruptcy protection — Tuesday, August 18, 2020 — Chaparral Energy Inc. has filed for bankruptcy protection for the second time in four years, paving the way for bondholders to take control of the Oklahoma driller in the aftermath of sluggish oil prices.
Walz administration to appeal Line 3 | MPR News – Gov. Tim Walz’s administration is wading deeper into the contentious, long-simmering debate over the proposed Line 3 oil pipeline replacement project. The Minnesota Department of Commerce announced plans Tuesday to appeal state utility regulators’ decision earlier this year to approve Enbridge Energy’s proposal to replace a deteriorating pipeline that crosses northern Minnesota with a new, larger pipe along a different route. In a statement released late Tuesday, the Commerce Department said its decision was consistent with previous agency actions. The department has filed similar appeals earlier in the Line 3 regulatory process, under the administrations of Walz and his predecessor, former Gov. Mark Dayton. The department is arguing the state Public Utilities Commission erred in granting Enbridge Energy a certificate of need – which establishes that a project is in the state’s best interest – to build the Line 3 project, “because Enbridge didn’t introduce, and so the commission could not evaluate the accuracy of, a long-term demand forecast.” The Commerce Department also said the utility regulator unlawfully shifted the burden of proof “to show that demand for product transmitted by Line 3 would decrease during the forecast period” from Enbridge to the department and others. In an announcement Tuesday, the Commerce Department said it plans to formally file its challenge with the Minnesota Court of Appeals Wednesday. Enbridge has proposed replacing its existing Line 3 pipeline, which was built in the 1960s and requires substantial maintenance, with a new line that would allow the company to transport nearly twice as much oil, along a new corridor across northern Minnesota. In a statement after the Commerce Department’s announcement, Walz said, “When it comes to any project that impacts our environment and our economy, we must follow the process, the law, and the science.” He said the appeal is a part of that process, and is “important to ensure clarity in the steps that Minnesota takes to evaluate and approve projects like this one.” Walz has been under increasing pressure from both pipeline opponents and supporters as the decision loomed.
Draft decision released for Little Missouri National Grassland oil and gas leasing — The U.S. Forest Service has released a draft decision regarding updates to oil and gas leasing for the Little Missouri National Grassland and is accepting any public objections for 45 days.The agency has been working to update its oil and gas leasing direction for the western North Dakota grassland, a document that hasn’t been updated since the Bakken oil boom was in its infancy.About 893,000 acres of the grassland are available for oil and gas leasing. The recommended changes would provide access to an additional 216,000 acres, while providing protections for sage grouse, rare plants and fossils, according to the Forest Service’s Dakota Prairie Grasslands office.”Our analysis demonstrates that energy development can be compatible with our grasslands restoration work, grazing activities, and the myriad recreation opportunities the grasslands have to offer,” Acting Grasslands Supervisor Jeff Tomac said in a statement. “The changes to leasing requirements we are considering will enable us to keep up with advancing technologies and trends in energy development in a way that sustains the health of the grasslands for generations to come.”The agency earlier took public comment on a draft supplemental environmental impact statement. It announced the final EIS and draft decision on Monday. They can be found at https://www.fs.usda.gov/project/?project=40652. There are several ways to submit objections. They can be mailed or hand-delivered to Objection Revision Officer, USDA Forest Service, Northern Region, 26 Fort Missoula Road, Missoula, MT 59804. Objections also can emailed to [email protected], with “Northern Great Plains Management Revision for Oil and Gas Leasing Project” in the subject line. They also can be faxed to Objection Reviewing Officer at 406-329-3411.
Giant oil company is building world’s largest facility to turn vegetable oil and grease into cleaner gasoline – Fuel maker Phillips 66 is moving to convert a San Francisco-area crude oil refinery into the world’s largest renewable fuels plant by early 2024, the company announced Wednesday. The facility located in Rodeo, Calif., will be reconfigured to no longer produce fuels from crude oil and instead produce renewable fuel from used cooking oil, fats, greases and soybean oils. The company said it expects to produce 680 million gallons a year of renewable diesel and gasoline and sustainable jet fuel. When combined with production from an existing smaller sustainable fuels project, the facility could produce more than 800 million gallons of renewable fuels each year by 2024, pending regulatory approval. The conversion is expected to cut the plant’s greenhouse gas emissions by 50 percent. “Phillips 66 is taking a significant step with RodeoRenewed to support demand for renewable fuels and help California meet its low carbon objectives,” Greg Garland, chairman and CEO of Phillips 66, said in a statement. “We believe the world will require a mix of fuels to meet the growing need for affordable energy, and the renewable fuels from RodeoRenewed will be an important part of that mix.” The energy giant said the capital-efficient investment is expected to deliver strong returns through the sale of “high value products while lowering the plant’s operating costs.” The announcement comes as crude oil prices dropped more than 30 percent as the coronavirus pandemic has disrupted demand for gasoline and jet fuel. Global oil consumption is expected to stay depressed for years as a result of the coronavirus crisis. Meanwhile, demand for renewable fuel is in a position to potentially grow as government regulations in states like California are aimed at dramatically cutting greenhouse gas emissions.
Bankruptcy court approves Whiting’s reorganization plans – A bankruptcy court in Texas has signed off on Whiting Petroleum’s bankruptcy plan, which exchanges billions in debts for equity in a reorganized company. Under the plan approved by the Southern District of Texas Bankruptcy Court, Whiting will shed $2.4 billion of its debts, in a $3.4 billion bankruptcy reorganization that will leave 97 percent of its ownership in the hands of private equity firms and investors and 3 percent with existing stockholders. Initially, Whiting was to raise $1 billion to pay part of its debt, but the final plan instead establishes a reserve-based revolving credit facility with an initial $750 million, according to the company’s SEC filing. The revolving fund’s credit limit is $1.5 billion. The effective date of this plan will occur only after all conditions required by the plan have been met, which the company projects will be Sept. 1. Up until then, technical amendments are still possible. A complete description of the plan is available online Whiting will emerge from bankruptcy with both a new chief executive officer and a new board. Kevin McCarthy, vice chairman of private equity firm Kayne Anderson Capital Advisors, will serve as chairman of the new board. Former SRC Energy CEO Lynn Peterson, meanwhile, has been tapped to serve as Whiting’s new CEO, replacing Brad Holly, who took the post in 2017 after serving as head of the Anadarko Petroleum Corporation. Holly will receive a $2.53 million severance package, according to regulatory filings with the SEC, and 18 months of health care benefits. This is on top of the $6.4 million he received for steering the company through the bankruptcy process.
North Dakota crude oil production fell in May beyond natural declines – EIA – Production implied by decline consists of wells with more than three months of non-zero production. A hyperbolic decline curve was fit to historical well-level production to estimate the natural decline in production from each well. Production from the PSM and STEO reflect estimated production from all producing wells in North Dakota. Between December 2019 and May 2020, crude oil output in North Dakota fell from an average of 1.5 million barrels per day (b/d) to 0.9 million b/d, a decline of more than 615,000 b/d (41.6%). This production decline is greater than it would have been if producers solely halted new drilling and allowed production from current wells to naturally decline. With only natural declines, the U.S. Energy Information Administration’s (EIA) analysis of Enverus’s data (which covers most, but not all, wells operating in North Dakota) indicates that crude oil production for most of North Dakota would have been approximately 1.1 million b/d in May 2020, 0.4 million b/d more than those wells actually reported. This difference suggests that many producers decided to reduce production from their existing wells beyond the volume the wells would have naturally declined. The principal driver of North Dakota’s production decline was low crude oil prices. After averaging $55.70 per barrel (b) throughout 2019, monthly prices in North Dakota (defined as the average of the Bakken Clearbrook and the Bakken Guernsey prices) averaged $29.82/b in May 2020 after having declined as low as -$38.13/b on April 20. According to survey data from the Federal Reserve Bank of Dallas, the region’s producers need prices of at least $28/b on average to cover their operating expenses and $51/b to drill new wells. In response to these price signals, most North Dakota producers reduced production, which was accomplished in at least one of three ways. First, some operators chose to completely halt production at some of their wells. As a result, although North Dakota had an average of 16,000 producing wells in December 2019, by May 2020, that number had fallen to 12,800 wells, the lowest level in more than four years.
Bakken gas production rebounds, but will it last? – Bakken associated gas production volume, after falling to its lowest levels in three years in early May and remaining depressed through June, has surged by 500 MMcf/d, or about 45%, in the past month and a half to 1.7 Bcf/d. However, the gains have occurred in the absence of a meaningful change in rig counts or well completion activity, which remains sluggish. Similar to the Permian, the Bakken production recovery has been almost entirely driven by existing wells returning to service after being shut in earlier this year in response to the oil price collapse. With little in the way of new drilling and completion activity, how long will it be before natural declines of existing wells begin to take a toll on Bakken output? Today, we examine prospects for continued strength in Bakken gas production volumes. Gas pipeline flow data over the past couple of months has provided the first indications that the bulk of the U.S. oil wells that were shut in this past spring have returned to service and that production volumes are rebounding. The data also provides a glimpse of what likely will follow the rebound in most basins: a gradual contraction in production output measured by the natural decline rates of existing wells, particularly given that producers’ capital spending budget cuts have slowed new drilling and well completion activity to a crawl.We discussed last month in Gimme Some Truth how these dynamics have unfolded in the Permian – from the sharp drop in associated gas output in early May as the basin’s producers shut in some crude-focused wells in response to low crude prices and storage constraints; to the near-vertical rebound in gas production in late June, as U.S. shut-ins (and, on a global scale, OPEC+ cuts) helped to work off some of the surplus in storage and crude prices recovered above $40/bbl; and finally, the inevitable downturn in production as natural declines continued to wear down the strength of output from existing wells. At the peak of the rebound in early July, Permian gas volumes hit a post-shut-in high of 11.7 Bcf/d, up from an average 10.5 Bcf/d during the worst of the shut-ins, but not quite back to pre-shut-in highs near 12 Bcf/d, and they’ve continued a slow slide from there (see the weekly NATGAS Permian and Crude Oil Permian reports for the latest).
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