Oil, Gas, And Fracking News Reads: 26July 2020 – Part 1

Written by rjs, MarketWatch 666

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

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

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Distillate inventories at a 38 year high even as refinery utilization stays near 30 year low

Oil prices ended 1.7% higher this past week on hopes for a virus vaccine and on economic reports that suggested the demand recovery was intact…. after rising 4 cents, or 0.1% to $40.59 per barrel last week as big drop in US crude supplies was offset by OPEC’s announcement that they’d increase production, the contract price of US light sweet crude for August delivery opened lower on Monday, weighed down by reports of an increase in the rate of new coronavirus infections, but rebounded to close 22 cents higher at $40.81 a barrel after reports of safe human clinical trials of a new Covid-19 vaccine….oil prices then jumped nearly 3% on Tuesday, buoyed by positive news about vaccine trials and the completion of an new EU economic stimulus deal, with trading in the August US oil contract expiring $1.15 higher at $41.96 a barrel, while the new front month September oil contract rose $1.00 to close at $41.92 a barrel….with reports now quoting the contract price of US light sweet crude for September delivery, oil prices slipped lower overnight after a surprisingly large crude inventory build was reported by the API, but recovered to finish just 2 cents lower at $41.90 a barrel despite the EIA’s confirmation of that surprise build in U.S. oil supplies….concerns over rising supplies of crude and products and alarming growth in US coronavirus cases weighed on prices Thursday, and September oil ended down 83 cents at $41.07 a barrel as new claims for unemployment benefits unexpectedly rose for the first time in nearly four months…oil prices initially moved lower on rising US / China tensions Friday, but later rallied on strong economic data in Europe and the US to settle 22 cents higher at $41.29 a barrel, thus posting its third positive week in four on demand recovery hopes…

Natural-gas also ended the week higher, supported by a widespread heatwave and a tropical storm in the Gulf of Mexico that threatened to disrupt offfshore production in the region….after falling 4.8% to $1.718 per mmBTU on moderating temperature forecasts and rising natural gas output last week, the contract price of natural gas for August delivery opened lower on Monday and tumbled 7.7 cents or 4.5% to a three week low of $1.641 per mmBTU, as natural gas output increased even as gas stockpiles remained about 16% over the five-year average….but gas prices regained 3.4 cents of that loss on Tuesday as power generators burned record amounts of gas as the heat wave blanketing much of the country intensified…however, gas prices only rose six-tenths of a cent on Wednesday even after forecasts that the heat wave would continue through early August…but prices spiked on Thursday as Tropical Storm Hanna strengthened, threatening natural gas production in the western Gulf, and the August gas contract finished 10.4 cents higher a $1.785 per mmBTU …prices extended that rally by 2.3 cents on Friday, after signs of an improving liquefied natural gas (LNG) export environment and as Hanna was forecast to become a hurricane as it moved westward toward the Texas coast…natural gas prices thus finished the week with a 5.2% gain at a two week high of $1.808 per mmBTU, as forecasts continued to call for hotter weather and higher-than-expected air conditioning demand over the next two weeks.

The natural gas storage report from the EIA for the week ending July 17th indicated that the quantity of natural gas held in underground storage in the US rose by 37 billion cubic feet to 3,215 billion cubic feet by the end of the week, which left our gas supplies 656 billion cubic feet, or 25.6% greater than the 2,559 billion cubic feet that were in storage on July 17th of last year, and 436 billion cubic feet, or 15.7% above the five-year average of 2,779 billion cubic feet of natural gas that have been in storage as of the 17th of July in recent years….the 37 billion cubic feet that were added to US natural gas storage this week was more than the average 33 billion cubic feet increase that was forecast by analysts polled by S&P Global Platts, but it was less than the 45 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, and it matched the average of 37 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 July 17th indicated a large addition to our stored commercial supplies of crude oil for the 5th week of the past seven, following a large withdrawal from supplies last week, despite little net change in the other metrics that effect oil supplies….our imports of crude oil rose by an average of 373,000 barrels per day to an average of 5,567,000 barrels per day, after falling by an average of 1,827,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 450,000 barrels per day to an average of 2,993,000 barrels per day during the week, which means that our effective trade in oil worked out to a net import average of 2,948,000 barrels of per day during the week ending July 17th, 77,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells reportedly rose by 100,000 barrels per day to 11,100,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 14,048,000 barrels per day during this reporting week..

US oil refineries reported they were processing 14,206,000 barrels of crude per day during the week ending July 17th, 103,000 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 699,000 barrels of oil per day were being added to 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 and from oilfield production was 857,000 barrels per day less than what was added to storage plus what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+857,000) 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”….that followed the insertion of a (-768,000) barrel per day figure into last week’s oil balance sheet, when there was a supply surplus of 768,000 barrels per day, and hence from last week to this week the the EIA’s fudge factor swung by a total of 1,625,000 barrels per day, thus rendering the week over week oil supply & demand comparisons statistical nonsense….however, since the media usually treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill for oil, we’ll continue to report them, just as they’re watched & believed as accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,218,000 barrels per day last week, which was 13.5% less than the 7,187,000 barrel per day average that we were importing over the same four-week period last year….the 699,000 barrel per day net addition to our total crude inventories came as 699,000 barrels per day were being added to our commercially available stocks of crude oil while the supplies in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported to be 100,000 barrels per day higher at 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states rose by 100,000 barrels per day to 10,600,000 barrels per day while a 4,000 barrel per day increase in Alaska’s oil production to 461,000 barrels per day wasn’t enough to impact the rounded national total….last year’s US crude oil production for the week ending July 19th, which was impacted by a Gulf storm, was rounded to 11,300,000 barrels per day, so this reporting week’s rounded oil production figure was about 1.8% below that of a year ago, yet still 31.7% 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 77.9% of their capacity while using 14,206,000 barrels of crude per day during the week ending July 17th, down from from 78.1% of capacity during the prior week, but excluding the 2005, 2008, and 2017 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the last thirty years…hence, the 14,206,000 barrels per day of oil that were refined this week were still 16.6% fewer barrels than the 17,034,000 barrels of crude that were being processed daily during the week ending July 19th, 2019, when US refineries were operating at 93.1% of capacity….

With the decrease in the amount of oil being refined, gasoline output from our refineries was a bit lower, decreasing by 16,000 barrels per day to 8,079,000 barrels per day during the week ending July 10th, after our refineries’ gasoline output had increased by 50,000 barrels per day over the prior week… with our gasoline production still recovering from a multi-year low, this week’s gasoline output was 10.0% lower than the 10,089,000 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 97,000 barrels per day to 4,763,000 barrels per day, after our distillates output had increased by 104,000 barrels per day over the prior week… after this week’s decrease in distillates output, our distillates’ production was 8.7% less than the 5,219,000 barrels of distillates per day that were being produced during the week ending July 19th, 2019….

Along with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 9th time in 13 weeks and for the 17th time in 25 weeks, falling by 1,802,000 barrels to 246,733,000 barrels during the week ending July 17th, after our gasoline supplies had decreased by 3,147,000 barrels over the prior week…our gasoline supplies decreased by less this week because the amount of gasoline supplied to US markets decreased by 98,000 barrels per day to 8,550,000 barrels per day and because our imports of gasoline rose by 49,000 barrels per day to 542,000 barrels per day and because our exports of gasoline fell by 122,000 barrels per day to 479,000 barrels per day….but even after this week’s inventory decrease, our gasoline supplies were still 6.1% higher than last July 19th’s gasoline inventories of 232,526,000 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 thirteenth time in 27 weeks and for the 18th time in 42 weeks, rising by 1,047,000 barrels to a 38 year high of 177,883,000 barrels during the week ending July 17th, after our distillates supplies had decreased by 453,000 barrels over 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 469,000 barrels per day to 3,223,000 barrels per day, even while our exports of distillates rose by 107,000 barrels per day to 1,439,000 barrels per day and while our imports of distillates fell by 47,000 barrels per day to 52,000 barrels per day….after this week’s inventory decrease, our distillate supplies at the end of the week were 30.0% above the 136,816,000 barrels of distillates that we had in storage on July 19th, 2019, and about 27% above the five year average of distillates stocks for this time of the year…

With distillate inventories now at a 38 year high, we’ll include a graph of their historical levels and explain why that’s particularly remarkable for this time of year..

The graph above, which originally came from Bloomberg, was copied from the Zero Hedge coverage of this week’s EIA report, and it shows US distillate supplies in millions of barrels, from mid-1982 to this week…while it’s difficult to decipher from that graph, if you check out the EIA’s interactive graph of distillate inventories and the accompanying spreadsheet, you’d find that the fluctuation we see in that graph is an annual pattern, with the yearly high in distillate supplies most often occurring when heat oil is being stockpiled just before midwinter, while the annual lows most often occur in late spring after cold winters have depleted the heat oil stockpile, or in mid-summer, when diesel fuel consumption is strongest…hence, that this week’s 38 year high in distillate inventories should occur during the normally depleted summertime makes this week’s record all the more remarkable…

Finally, with the increase in unaccounted for oil, our commercial supplies of crude oil in storage rose for the 21st time in twenty-six weeks and for the 36th time in the past year, increasing by 4,892,000 barrels, from 531,688,000 barrels on July 10th to 536,580,000 barrels on July 17th….after that increase, our our commercial crude oil inventories were around 19% above the five-year average of crude oil supplies for this time of year, and about 59% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the third weekend of July, 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 July 17th were 20.6% above the 445,041,000 barrels of oil we had in commercial storage on July 19th of 2019, 32.5% more than the 404,937,000 barrels of oil that we had in storage on July 20th of 2018, and 11.0% above the 483,415,000 barrels of oil we had in commercial storage on July 21st of 2017…

This Week’s Rig Count

The US rig count fell for the 20th week in a row during the week ending July 24th, and is now down by 68.3% over that twenty week period….Baker Hughes reported that the total count of rotary rigs running in the US decreased by 2 rigs to 251 rigs this past week, which again was the fewest active rigs in Baker Hughes records going back to 1940 and 153 fewer rigs than the all time low prior to this year…it was also down by 695 rigs from the 946 rigs that were in use as of the July 26th report of 2019, and 1,678 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 1 rig to 181 oil rigs this week, after falling by 1 oil rig the prior week, which was still 595 fewer oil rigs than were running a year ago, and less than an 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 fell by 3 rigs to 68 natural gas rigs, which was the least natural gas rigs running in at least 80 years, and down by 101 natural gas rigs from the 169 natural gas rigs that were drilling a year ago, and was 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 was just one such “miscellaneous” rig deployed…

The Gulf of Mexico rig count was unchanged at 12 rigs this week, with 10 of those rigs drilling for oil in Louisiana’s offshore waters and two of them drilling for oil offshore from Texas…that was 11 fewer rigs than the 23 rigs drilling in the Gulf a year ago, when 22 rigs were drilling offshore from Louisiana and one rig was operating in Texas waters…while there are no rigs operating off other US shores at this time, a year ago there were two rigs deployed offshore from Alaska, so this week’s national offshore count is down by 13 from the national offshore rig count of 25 a year ago

The count of active horizontal drilling rigs was unchanged at 215 horizontal rigs this week, which matches the fewest horizontal rigs drilling in the US since November 18th, 2005, and was also 608 fewer horizontal rigs than the 823 horizontal rigs that were in use in the US on July 26th 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 vertical rig count was down by one to 14 vertical rigs this week, and those were also down by 42 from the 56 vertical rigs that were operating during the same week of last year….in addition, the directional rig count also fell by 1 rig to 22 directional rigs this week, and those were also down by 45 from the 67 directional rigs that were in use on July 26th 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 July 24th, the second column shows the change in the number of working rigs between last week’s count (July 17th) and this week’s (July 24th) count, the third column shows last week’s July 17th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 26th of July, 2019…

We continued to see more changes in drilling activity this week, even as it remains subdued vis-a-vis the norm…checking the rig counts in the Texas part of Permian basin, we find that two rigs were added in Texas Oil District 8, or the core Permian Delaware, and another rig was added in Texas Oil District 7C or the southern Permian Midland, while a rig was shut down in Texas Oil District 8A or the northern Permian Midland, and another rig was shut down in Texas Oil District 7B, which includes a few counties in the far eastern Permian Midland…since the national Permian basin rig count was up by 2 rigs, that strongly suggests that the rig that was added in New Mexico would have been set up to drill in the western Permian Delaware, to account for the national increase…elsewhere in Texas, there was a rig added in Texas Oil District 2, but there were also three rigs shut down in Texas Oil District 3, which are both part of the region we normally associate with activity in the Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and touches on four Oil Districts…since the Eagle Ford shows an increase of one rig, that would suggest that the three rigs shut down in Texas Oil District 3 were not targeting the Eagle Ford, but rather some basin that Baker Hughes does not track…however, checking the breakout for the Eagle Ford basin, we find that one natural gas rig was shut down in that basin, while two oil rigs were added at the same time…that could have occured with any number of combinations of offsetting start-ups and shutdowns in those disticts that wouldn’t show up in the district totals…in addition, since the panhandle Texas Oil District 10 currently shows no activity, that means that the oil rig that was added in the Granite Wash was across the state line in south central Oklahoma…however, Oklahoma shows no net change because a rig drilling for oil in the Cana Woodford was shut down at the same time…lasly, for the three rig decrease in natural gas rigs, we first have the natural gas rig that was removed from the Eagle Ford, and then the two rigs that were removed from the Marcellus, one each of which had been drilling in Pennsylvania and West Virginia…

PTTGC, Mountaineer agree on Ohio NGL storage project — PTT Global Chemical (PTTGC; Bangkok, Thailand) has entered into a precedent agreement with Mountaineer NGL Storage to develop storage and pipeline infrastructure that would support PTTGC’s proposed petrochemical complex in Belmont County, Ohio. Under the agreement, Mountaineer, a subsidiary of Energy Storage Ventures, will develop multiple 500,000 bbl salt caverns capable of storing natural gas liquids (NGLs) or ethylene on a 200-acre site in Monroe County, Ohio. The $250-million storage project will come in two phases of around 1.5 million bbl of capacity each. Mountaineer says it has the necessary permits to begin construction on the first phase, which is slated for completion by 2022 – 23. PTTGC America is working with Mountaineer on 1 million bbl of ethane storage and a pipeline that will link the storage facility to the project 8 miles away. If realized, this would represent the first underground NGL storage site in the Marcellus and Utica shale formations in the US Northeast. Mountaineer first floated the project in 2016 following a successful open season and, according to local news reports, has been courting PTTGC America as a potential customer since at least 2019. “Ethane storage and transportation will be a crucial element of a world-scale petrochemical complex,” PTTGC America president and CEO Toasaporn Boonyapipat says in a statement. “Mountaineer NGL Storage will provide essential infrastructure and capabilities to our project. Our impending partnership with this first-rate organization brings us one step closer to a final investment decision.” The agreement comes after PTTGC America announced on 14 July that it was searching for a new partner in its 1.5-million metric tons/year ethane cracker and associated derivatives units following the withdrawal of South Korea’s Daelim Chemical USA as an equity partner. In June, PTTGC America announced it would delay its final investment decision on the project until late 2020 or early 2021 due to oil price volatility and the COVID-19 pandemic. PTTGC America has completed the first stage of preparation, engineering, and design work for the petrochemical complex and has invested around $200 million into front-end engineering design. The Ohio Environmental Protection Agency has also issued air and water permits for the project following an environmental review. The project would take four to five years to construct once the company makes a final investment decision. It would be the second major petrochemical development in the US Northeast. Shell’s 1.5-million metric tons/year ethane cracker and polyethylene complex is under construction in Monaca, Pennsylvania, about 60 miles north of the PTTGC site. A Shell presentation earlier this year put the target completion date for the Monaca plant in 2022.

PTTGC signs deal to develop NGL storage in northeast US –PTTGC America signed a precedent agreement that outlines the terms and conditions to develop underground natural gas liquids (NGL) storage in northeastern US. This is a critical piece of infrastructure for a proposed polyethylene (PE) complex that the company could develop in the region, it said on Wednesday. It would be the first underground site to store ethane and other NGLs in the Marcellus and Utica shale formations of the northeast US, PTTGC said. Under the agreement, Mountaineer NGL Storage will develop the underground salt caverns on a 200-acre (81 ha) site in Monroe county, Ohio, eight miles (13 km) south of PPTGC’s proposed petrochemical complex in Belmont county, Ohio. Mountaineer will own and operate the storage facility. The storage facility is valued at $250m, and it will be developed in two phases by creating multiple caverns in an existing underground salt formation. Each cavern can store 500,000 bbl of material, including ethane, propane, butane and ethylene. PTTGC did not specify how many caverns will be built. A pipeline will connect the proposed PTTGC complex to 1m bbl of ethane storage. The first phase could store as much as 1.5m bbl of NGLs. PTTGC did not specify if this would be a mix of NGLs. Mountaineer already has all the permits needed to start construction on the first phase, which will take two to three years to complete. Phase two could hold another 1.5m bbl of NGLs, PTTGC said. The facility could also be further expanded in order to meet market demand. It is unclear whether the first phase alone would include 1m bbl of ethane storage, or whether the two phases would combine to reach that level. The storage facility could serve other prospective customers in addition to PTTGC, said David Hooker, president of Mountaineer. Mountaineer is a subsidiary of Energy Storage Ventures LLC. The storage deal brings PPTGC one step closer to making a final investment decision (FID) on the project, said CEO Toasaporn Boonyapipat, CEO of PTTGC America.

PTT Global/Mountaineer agreement a good thing for proposed cracker plant – – The Belmont and Monroe County commissioners see good signs in the future of PTT Global Chemical’s operations in the area now that a storage hub is being proposed to support an ethane cracker plant many are hoping to see built in Dillies Bottom.On Wednesday morning, the Belmont County commissioners referred to a press release just issued from PTT, announcing PTT’s agreement with Mountaineer NGL Storage to provide infrastructure for the proposed cracker plant. The NGL facility would provide storage and transportation services for the proposed plant. The facility will be the first underground NGL storage site in the heart of the Marcellus and Utica shale formations. Mountaineer will develop the underground salt caverns for NGL storage on a 200-acre site in Monroe County. The site, owned and operated by Mountaineer, is located approximately eight miles south of Dilles Bottom. PTT is working with Mountaineer on one million barrels of ethane storage and a pipeline that will link the storage facility to the project. “Ethane storage and transportation will be a crucial element of a world-scale petrochemical complex,” PTT President and CEO Toasaporn Boonyapipat said. “Mountaineer NGL Storage will provide essential infrastructure and capabilities to our project. Our impending partnership with this first-rate organization brings us one step closer to a final investment decision. We deeply appreciate all the support we have received from our federal, state and local partners, including Belmont and Monroe counties, which have brought us to this point.”“We are pleased to partner with PTTGCA as it works toward the development of the second petrochemical plant to be located in the Ohio River Valley,” said David Hooker, president of Mountaineer NGL Storage. “Our storage facility will have an important role in managing the plant’s supply portfolio, along with offering PTTGCA and other prospective customers an option to manage seasonal and operational demand with competitive locally priced production. The PTTGCA team has been great to work with, and we look forward to a long and successful relationship.”

Thailand’s PTT moves closer to decision on Ohio petrochemical plant with storage deal – State-owned Thai oil and gas company PTT Pcl said its U.S. unit took a step forward on its proposed chemical plant in Ohio that will turn ethane into plastics with an agreement to develop a natural gas liquids storage facility. PTT Global Chemical America (PTTGCA) signed an agreement with Energy Storage Ventures LLC to build a facility to store and transport natural gas liquids (NGL) for PTTGCA’s proposed complex.”Our impending partnership … brings us one step closer to a final investment decision,” PTTGCA President and Chief Executive Toasaporn Boonyapipat said in a statement on Wednesday.In June, PTTGCA said it delayed making a final investment decision to build the ethane cracker, which analysts estimate will cost $5.7 billion, from the first half of 2020 to the first half of 2021 due to the coronavirus. Analysts said the pandemic reduced expected growth in global demand for plastics. Energy Storage Ventures’ Mountaineer NGL Storage subsidiary will develop the underground salt caverns on a 200-acre (80-hectare) site in Ohio’s Monroe County about 8 miles (13 kilometers) from the PTTGCA site.PTTGCA said it is working with Mountaineer on 1 million barrels of ethane storage and a pipeline linking the storage facility to the project. PTTGCA said Mountaineer will develop the $250 million storage facility in two phases by creating multiple caverns in the existing underground salt formation. Each phase will be able to hold about 1.5 million barrels. PTTGCA said it is seeking new partners for its ethane cracker project after South Korea’s Daelim Industrial Co Ltd pulled out earlier this month.

Pennsylvania Governor Signs $667 Million Fracking Tax Credit -A bipartisan bill giving tax breaks to Pennsylvania manufacturers that use dry natural gas to make petrochemicals and fertilizers was signed into law Thursday by Gov. Tom Wolf. The measure (HB 732), a compromised version passed last week after the Democratic governor vetoed a similar measure in March, allows for approval of tax credits for four projects a year, adding up to nearly $667 million over the 25-year span of the economic development incentive program. The annual cap will be $26.7 million. Applicants must invest at least $400 million in a project facility using dry natural gas…

More sinkholes develop alongside Mariner East construction in Chester County -Sinkholes and land subsidence have developed alongside Sunoco’s Mariner East pipeline construction in West Whiteland Township, Chester County. About half a dozen sinkholes along the pipeline’s path began appearing June 13, close to active pipelines carrying natural gas liquids, a pipeline valve station and a public hiking trail, according to local officials. The most recent subsidence occurred Friday afternoon, with growing cracks on the busy Route 30, near a sinkhole that had developed last week, according to the Pennsylvania Public Utility Commission. The PUC’s Safety Division of the Bureau of Investigation & Enforcement is on-site and conducting an investigation. “No active pipelines were exposed as a result of the subsidences and engineers from the Safety Division continue to closely monitor the situation,” according to a statement released Friday afternoon by the PUC. The PUC says it is in contact with the Pennsylvania Department of Environmental Protection and PennDot. All of the sinkholes have been filled with cement, according to Township manager Mimi Gleason. Gleason says pipeline builder Energy Transfer, formerly known as Sunoco Logistics, continues to conduct testing and has an employee walking the area around the clock to check for any newly formed sinkholes or subsidence. The PUC says the company is using ground penetrating radar three times a day near the roadway and the hiking trail to detect any new subsidence. “The Township is very concerned,” said Gleason. “We’re glad the PUC is requiring additional testing to make sure the infrastructure is safe going forward.” Gleason says Energy Transfer finished the underground drilling needed to install the pipeline, and reported the drill went through “very hard rock.” The area around Exton is known for its limestone, or karst, geology, which is soft and porous. The state issued permits for the pipeline in 2017, despite warnings by Department of Environmental Protection employees that the area’s geology could trigger sinkholes. Gleason says Energy Transfer also discovered a void 30 feet below the surface, which it filled with cement. It’s unclear whether that void existed before construction, or was caused by it, she said. The Township says it is now safe to use the Chester Valley Trail, which had been closed.

‘Dark money’ groups spent $517,000 against two Philly-area candidates who oppose the Mariner East pipeline –Conservative nonprofit groups that have advocated for the natural gas industry funded hundreds of thousands of dollars worth of attack ads in last month’s primary election in two state House races in the Philadelphia suburbs. Outside political groups spent at least $517,000 on Democratic primary races in Chester County, according to newly disclosed campaign records and data compiled by the ad tracking firm Advertising Analytics. The targets of the attack ads were first-term state Rep. Danielle Friel Otten and Ginny Kerslake, both Democrats and outspoken opponents of Sunoco’s Mariner East pipeline project, which carries natural gas liquids from the Marcellus and Utica shale formations to the company’s terminal in Marcus Hook. Otten won her primary. Kerslake lost to incumbent Democratic Rep. Kristine Howard. That much spending in state House races is unusual – and it came so late in the campaign that one of the political groups involved didn’t have to disclose its donors until a month after the June 2 election. Tracing the funding is almost impossible, as the nonprofits behind it are not required to disclose donors. The spending underscores the influence of “dark money” in seemingly low-profile races, as well as the stakes associated with the controversial pipeline project, a political and legal flash-point in the debate over energy and the environment.

AG charges two pipeline companies over spills in Washington County – Pennsylvania Attorney General Josh Shapiro charged two pipeline companies with polluting groundwater and streams in a series of spills in 2015 along a pipeline project in Washington County. Shapiro said grand jury evidence obtained in the case showed that the pipeline builders chose to ignore a spill along the pipeline, failing to report it on a daily log. The charges stem from a construction project for a 24-inch natural gas pipeline in Robinson Township, about 30 miles west of Pittsburgh. The attorney general is charging two companies, New York-based National Fuel Gas Supply, and its subcontractor, Arizona-based Southeast Directional Drilling, for violating the state’s Clean Streams Law. “I made a commitment to Pennsylvanians that I would protect their constitutional right to clean air and pure water,” Shapiro said, in a statement. “These companies turned a blind eye to that right and will be held accountable.” According to court documents, the crews building the pipeline lost control of fluids used to bore underground tunnels for the pipeline, and the fluid surfaced in a nearby stream. The fluid commonly contains water, a form of clay called bentonite, as well as other chemicals and additives to assist in lubricating the drill and returning the drill cuttings to the surface. Neighbors also began noticing their private drinking water became cloudy and discolored, and tests later confirmed contaminants in the drinking water. A nearby stream that was normally clear became milky. One of the neighbors reporting problems with his water was former township supervisor Brian Coppola. Coppola, who is suing the companies in Washington County court, still can’t use his drinking water, according to the court documents. Pennsylvania Attorney General’s office A grand jury presentment charging two pipeline companies with environmental crimes related to a drilling fluid spill included this photo of a Washington County stream affected by the spill. The documents say that even though the Pennsylvania Department of Environmental Protection tested Coppola’s drinking water, Coppola “never received anything other than the lab results” from the DEP. A subsequent test performed by a private lab found elevated levels of solids and chemicals in Coppola’s water. Other neighbors reported problems. One found “cloudy, white-colored water” when he began filling his pool with a garden hose. Another, Brenda Vance, told the grand jury her water supply had turned white, but when a DEP water quality specialist came to her house, he tested it for contaminants associated with fracking and gas drilling, not pipeline drilling. The DEP later told her that even though “common pollutants associated with oil and gas fluids” were found in her water, it was “not adversely affected by the drilling, alteration, or operation of an oil and gas well.”

West Liberty man indicted, accused of dumping waste – A federal grand jury has indicted a West Liberty man accused of illegally importing radioactive sludge produced by a fracking site in north central West Virginia. The jury sitting in Ashland indicted Cory David Hoskins, the former owner of Advanced TENORM Services LLC on five counts of mail fraud and 22 counts of violating the Hazardous Materials Transportation Act. The federal government has charged Hoskins in connection with a series of shipments and payments between July 2015 and December 2015 for waste dumped in Estill County. The indictment is just the latest in a case that has played out since West Virginia authorities alerted the Commonwealth about the dumping of TENORM waste in January 2016. TENFORM (Technologically Enhanced Naturally Occurring Radioactive Material) is a by-product of fracking. According to the EPA, most oil and gas found inside the earth are actually on the sites of ancient oceans. The actual petroleum products are the remains of sea life that died millions of years ago. The wastewater produced by a fracking operation may contain harmful materials like uranium, thorium, radium and lead, according to the EPA. According to the federal indictment, Hoskins approached Fairmont Brine Processing in West Virginia in July 2015 about trucking the sludge to Kentucky. The feds allege Hoskins lied to Fairmont Brine about having U.S. DOT compliant trucks – those need special placards and certified drivers – and also having engineers, physicists and nuclear experts on staff. He then told federal regulators and the trucking companies he hired out to run the radioactive rubbish that the waste wasn’t hazardous and therefore was exempt from any special regulations, according to the federal indictment. Federal authorities even accuse Hoskins of intentionally approaching trucking outfits, including one in Ashland, that didn’t have the hazardous certifications in order to get a cheaper rate. When the waste made it to a landfill in Irvine, the indictment sates Hoskins provided fudged paperwork showing the radioactive waste to be non-hazardous. The 22 counts of violation of the hazardous materials act are for runs identified by federal authorities. The five fraud counts reflect payments that changed hands between Fairmont Brine and Advanced TENFORM.

State Legislature closes hazardous waste loophole – The State Legislature passed A.2655/S.3392, a statute that closes a loophole that allowed hazardous hydrofracking waste to be dumped in New York even while hydrofracking itself was banned. The legislation passed the Assembly on Monday and the Senate on Wednesday. It must be signed by Gov. Andrew Cuomo to become a law. Shale fracking has polluted drinking water sources throughout the country – in Pennsylvania’s Monongahela River, for example – and Cuomo’s ban defended both public health and the environment. However, the fracking ban still allowed shale oil and gas waste – which can be highly flammable, toxic, and occasionally radioactive – to be imported. Formerly, the loophole let such waste avoid the label of “hazardous,” so it was regularly accepted to be spread on roads, or to be disposed of improperly at dumpsites and landfills throughout the state. A June 2019 report showed that New York had accepted over 638,000 tons and about 23,000 barrels of fracking waste from Pennsylvania fracking operators since 2011.

Plugging abandoned oil and gas wells could be a jobs boon for the U.S. – There’s a lot of jobs potential if the federal government gets serious about plugging what could be as many as 3 million abandoned oil-and-gas wells nationwide, a new report from Resources for the Future and a Columbia University energy think tank concludes. Abandoned wells can leak methane – a very potent planet-warming gas – and other pollutants. If it tackles 500,000 of those, this could mean up to 120,000 more jobs.The idea comes as oil-and-gas industry workers are reeling from layoffs due to the price and demand collapse.Estimates for the number of abandoned wells nationwide range from hundreds of thousands to 3 million, “depending on the definition of such wells needing attention,” the report notes.”A significant federal program to plug orphan wells could create tens of thousands of jobs, potentially as many as 120,000 if 500,000 wells were plugged,” it finds. It points out that the oil industry has equipment and labor available for the job, given that the sector shed more than 76,000 jobs (and counting) this year. They estimate that the costs of plugging the “known inventory” of roughly 57,000 wells could range from $1.4 billion to $2.7 billion, while identifying and plugging 500,000 wells could plausibly cost $12 billion to $24 billion.

US Marcellus and Utica Shales Market Report- Size, Trends, Drivers, Restraints, Opportunities, and Challenges – The US Appalachian Basin located in Pennsylvania, Ohio, West Virginia and New York continues to be the driver in natural gas production within the United States. During May 2019, it produced around 31 billion cubic feet per day (Bcfd) and is forecast to reach a rate of approximately 35 Bcfd by the end of 2019. The basin comprises the two main formations – the Marcellus, and the Utica. The majority of the activity in the Marcellus continues to take place in north east and south west Pennsylvania while the hotspot for the Utica is in eastern Ohio. Fracking activity in the Marcellus and Utica formations is driven by the large demand for natural gas from the nearby populated areas and although natural gas prices have experienced some volatility during recent years, Appalachian producers are generally able to sell their natural gas at a premium in trading hubs located in the North East. The competitive landscape of the Marcellus play is largely dominated by EQT Corp., the largest natural gas producer in the US, whereas, Ascent Resources LLC and Gulfport Energy Corp. lead the natural gas production in the Utica play. The report analyzes the natural gas appraisal and production activities in the Marcellus and Utica shale plays. The scope of the report includes –

– Comprehensive analysis of natural gas production across major counties in Pennsylvania, West Virginia, Ohio, and New York during 2013-2018, as well as production outlook from 2019 to 2023

– In-depth information of well permits issued in the Pennsylvania region of the Marcellus and Utica shale, by county and by company from January 2018 to March 2019

– Detailed understanding of IP rates and type well profiles in Marcellus and Utica formations

– Exhaustive analysis of competitive landscape in the Marcellus and Utica shale in terms of net acreage, gross production, cost trends and planned investments.

– Comparison of type well economic metrics of major players were also analyzed

– Up-to-date information on major mergers and acquisitions in the Marcellus and Utica shales between 2013 and 2019

– Overview of existing and upcoming pipelines and LNG terminals in the Marcellus and Utica.

FERC approves Leidy South gas pipeline project to fuel power in Atlantic states – Natural gas infrastructure firm Williams gained federal regulatory approval for a pipeline project bringing gas for home heating and power generation in the Atlantic Seaboard region. The Federal Energy Regulatory Commission gave permission to proceed with the Leidy South Project which will deliver 582,400 dekatherms per day – enough to serve more than two million homes – of additional pipeline takeaway from the gas-rich Marcellus and Utica shale regions of Pennsylvania. Tulsa-based Williams says the project will help utilities convert from coal-fired power capacity to natural gas, which has half the carbon emissions. “As the United States switches to clean power to energize our electric grids, Williams is excited and proud to be the backbone that connects the best supplies of dry gas with our country’s largest demand centers,” said Alan Armstrong, president and CEO of Williams. “This project represents one of many opportunities to further reduce greenhouse gas emissions with right here, right now available solutions as coal-fired electric generation plants are replaced with natural gas units to reliably balance the intermittency of new renewable resources.” The Leidy South would basically use the same corridor as the company’s interstate Transco pipeline system in that area, so it would reduce the amount of new infrastructure and land use needed. Transco is the nation’s largest-volume interstate natural gas pipeline system, delivering natural gas through a 10,000-mile pipeline network whose mainline extends nearly 1,800 miles between South Texas and New York City. Williams added that there are still more than 80 coal-fired power plants in the states served by the Transco pipeline system. Natural gas fuels more than 35 percent of the nation’s electricity generation mix, while coal has dropped from its once preeminent position to about 25 percent amidst a growing number of plant retirements. Cabot Oil & Gas and Seneca Resources will be producing the natural gas connecting to the Leidy South expansion. Atlantic Seaboard states form one of the fastest growing gas generation regions in the U.S., according to BTU Analytics. Environmental challengers, however, have forced the cancellation of Duke and Dominion’s planned Atlantic Coast Pipeline which would have crossed the Appalachian Trail. The two utilities said the cost of legal challenges make the already multi-billion-dollar project uneconomical for them. Williams says the construction phase will create more than 600 jobs, while operations will support $4.2 million in annual economic impact for origin state Pennsylvania.

Transco Expansion Approved to Connect Marcellus, Utica Natural Gas to Eastern Markets – FERC last Friday approved the Williams Leidy South natural gas pipeline project that would connect Marcellus/Utica shale supply to demand markets along the Atlantic Seaboard ahead of the 2021-2022 winter. The 582,400 Dth/d pipeline, an extension of the massive Transcontinental Gas Pipe Line system, aka Transco, would source gas produced by Cabot Oil & Gas Corp. and Seneca Resources Co. LLC. The project is to include six miles of large-diameter pipeline loop, two compressor stations and associated facilities in Pennsylvania’s Clinton, Columbia, Lycoming, Luzerne, Schuylkill and Wyoming counties. Williams CEO Alan Armstrong said the project represents one of many opportunities to further reduce greenhouse gas emissions, noting that “there remain more than 80 coal plants in the states Transco serves that can potentially be displaced” by gas. By maximizing the use of the existing Transco transmission corridor and expanding existing facilities in Pennsylvania, Leidy South would “substantially reduce” the amount of new infrastructure and land use required to meet these needs, minimizing community and environmental impact, Armstrong said. “With the growing urgency to transition to a low-carbon fuel future, Williams and its natural gas-focused strategy provide a practical and immediate path to reduce industry emissions, support the viability of renewables and grow a clean energy economy,” the CEO said.Approval by the Federal Energy Regulatory Commission for Leidy South comes at an uncertain time for oil and gas pipelines across the country. Earlier this month, Dominion Energy Inc. and Duke Energy Corp. canceled the proposed Atlantic Coast gas pipeline project, citing ongoing delays and increasing cost uncertainty. Meanwhile, the future of the Dakota Access crude pipeline, three years after entering service, is increasingly unclear amid an ongoing legal battle over key water-crossing permits.

‘People Need to Fight It for Everything They’re Worth’ – Battles over Pipelines Are Far from Over – Theresa “Red” Terry and her daughter spent 34 days living in the treetops trying to block construction of a 42-inch-wide gas pipeline through her family’s property in Virginia’s Blue Ridge Mountains. They were eventually forced down by a court order, and the minute Red’s feet touched the ground, chainsaw crews emerged to cut down her oak and maple trees. They were thwarted by an angry crowd of Red’s supporters and police who intervened to prevent violence, but early the next morning, the crews returned to finish the job.That was more than two years ago. The trees remain on the ground today, piled the way they fell in May of 2018.”Every time I go out there, I feel like someone stomped my heart,” said Terry in mid-July. “I feel like the whole mountain has been given cancer.”The Terry property, which has been in the family for seven generations, contains family residences, an orchard, a multitude of wildlife, and the upper reaches of Bottom Creek, a pristine mountain stream that forms the headwaters of the Roanoke River. The land also falls in the path of the Mountain Valley Pipeline (MVP), a planned 303-mile natural gas pipeline running from the fracking fields of the Marcellus and Utica shale formations in northern West Virginia to a terminal in southern Virginia that feeds into the East Coast pipeline network. MVP was announced in 2014 as part of a wave of similar projects, including the 600-mile Atlantic Coast Pipeline (ACP) from West Virginia through Virginia to North Carolina, and the Western Marcellus Pipeline, planned to run along a similar path as MVP. Western Marcellus never got off the drawing board, and the ACP was canceled in early July after six years of regulatory and legal battles, which caused the project’s cost to balloon from roughly $5 billion in 2014 to $8 billion in 2020. The day after the ACP was canceled, a federal court ordered the Dakota Access oil pipeline to shut down. Anti-pipeline activists celebrated the double shot of good news and enjoyed renewed hope that other pipelines like the MVP might be stopped. But since the wins in early July, a series of twists suggest the fight against natural gas infrastructure will continue for some time. A U.S. Appeals Court granted DAPL an administrative stay so it can continue to operate while the court deliberates. Additionally, the U.S. Supreme Court dramatically reduced the scope of a U.S. District Court ruling that factored into the ACP’s cancellation. In a case involving the Keystone XL pipeline, the lower court had ruled in April that the Army Corps of Engineers failed to adequately consider endangered species when it issued what’s known as Nationwide Permit 12. That particular permit was used by dozens of pipelines because it allowed them to win approval to cross multiple waterways through a single process, instead of applying for individual permits for each stream and river. The U.S. District Court not only halted the use of Nationwide Permit 12 for Keystone XL but applied the ruling nationwide. The Supreme Court restored the use of the permit everywhere except with regard to Keystone XL. These developments are only the current hotspots in a long-running legal, political and regulatory battle that’s playing out around the construction of natural gas infrastructure throughout rural America.

Columbia Gas seeks more time to build pipeline –Columbia Gas Transmission Corp. is asking for more time to finish a pipeline that would cross part of Washington County. The Federal Energy Regulatory Commission issued a notice of the request on Wednesday. The company states that, “due to unforeseen delays in acquiring an easement from the government of Maryland across the Western Maryland Rail Trail, additional time is now required in order to complete the construction of the authorized project facilities,” according to the notice. Columbia is asking for an extension, until July 18, 2023, to complete the pipeline. Columbia Gas Transmission, a subsidiary of TC Energy, has proposed running the pipeline from existing facilities in Pennsylvania to a new Mountaineer Gas Co. pipeline in West Virginia. Proponents have said the new pipeline is critical to economic development in West Virginia’s Eastern Panhandle. Opponents have said the pipeline, which would burrow more than 100 feet under the Potomac River, would threaten the environment and drinking water while bringing little benefit to the state. The pipeline would go under the Cheasapeake and Ohio Canal Historical Park, which is owned by the National Park Service, and the Western Maryland Rail Trail, which is owned by the state. The project received green lights from state and federal regulators. But the Maryland Board of Public Works has denied the company’s request for a right-of-way permit to bore under the Western Maryland Rail Trail. In August, a federal court in August upheld that denial. This week’s notice from FERC establishes a 15-calendar day intervention and comment period deadline. Comments are due before 5 p.m. Eastern Time on July 30, according to the notice.

Completion of regional natural gas pipeline project may be delayed – The underground TransCanada natural gas pipeline from Pennsylvania through Maryland into West Virginia may take longer to complete.Columbia Gas, the TransCanada subsidiary building the project, has asked the Federal Energy Regulatory Commission (FERC) to have until the summer of 2023, a decision which must be approved by FERC. For regional industry here, however, officials say the pipeline is important to attract business.”It’s very important that we have another source of natural gas into Berkeley County and our region,” says Sandy Hamilton, head of the Berkeley County Development Authority. “We are at capacity. We have new customers that are looking to come to our area and if they’re a heavy natural gas user I have to give them a ‘no’ or, at least, we have to find them an alternative.”The public is invited to submit public comment to FERC by the end of this month.Pipeline firms scale back plans amid legal protests – – A decade ago, when the shale boom was still in its infancy, developers lined up to build long-distance natural gas pipelines to supply distant markets with low-cost energy to replace aging, dirty coal and oil-burning power plants.But after years of legal fights with environmental groups trying to eradicate carbon-emitting fossil fuels, pipeline companies are backing off large-scale pipeline projects. The decision by its developers earlier this month to cancel the 600-mile Atlantic Coast Pipeline project is just the beginning, experts say. “There’s so much uncertainty on the project timeline and the cost you are unlikely to see another major natural gas pipeline built (that crosses state lines),” said Sam Andrus, executive director of North American gas at the consulting firm IHS Markit. “These environmental groups have made it their explicit goal to delay these projects and raise the costs. And they’re getting better at it as time goes on.” If more pipelines go the way of the Atlantic Coast, it would limit markets for natural gas producers in states such as Texas, which produces more gas than any state and has watched its economy thrive under oil and gas boom brought on by hydraulic fracturing. A recent study by the American Petroleum Institute predicts that demand from oil and gas producers would support the construction of more than 17,000 miles pipelines during the next five years. But between legal fights with environmentalists and Democratic state politicians such as New York Gov. Andrew Cuomo moving to block pipelines from their states to address climate change, it looks unlikely that anywhere close to that amount will be built. “We need infrastructure to get our production out to areas with the most demand,” said Frank Macchiarola, senior vice president at API. “It’s essential we get these projects up and running.”

PIPELINES: Federal court hands FERC more time to use delay tactic — Friday, July 24, 2020 — A federal court yesterday granted the Federal Energy Regulatory Commission extra time to comply with a recent ruling barring the commission from using a procedural stalling tactic in legal challenges. FERC now has until Oct. 5 to comply.

Environmental justice concerns stall Va. power project — Thursday, July 23, 2020 —A $350 million gas project spanning much of eastern Virginia has been put on hold, in part due to environmental justice concerns. Virginia’s State Corporation Commission (SCC) recently deferred action on the proposal by Southern Co. subsidiary Virginia Natural Gas (VNG). The agency told the company to come back by the end of the year with more details on financing and environmental justice issues. The project, a series of pipelines, compressor stations and other infrastructure stretching from the exurbs of Washington to Hampton Roads in southern Virginia, has come under fire from environmental groups for potentially locking in years of natural gas use. They’ve been joined by a group of residents of Charles City County, a poor, majority-minority county east of Richmond. The project is designed to supply a natural gas power plant in the county, and another plant has been proposed. While supporters say the facilities would bring economic development, opponents say developers are pushing big polluters on a vulnerable population. “We were an easy target. They knew exactly what they were doing,” said La’Veesha Rollins, a Charles City County native who is part of the group fighting the project. “We get nothing out of this deal.” Officials at VNG say they remain committed to the project. Spokesman Rick DelaHaya said the company intends to work with the SCC and other agencies “to develop a model project that meets all regulations.” At the center of the project is a proposed 1,060-MW combined-cycle natural gas power plant known as C4GT, a merchant plant that would sell electricity to the wholesale market through grid operator PJM Interconnection. Another plant, called the Chickahominy Power Station, was announced in 2018 and is to be located within a mile of C4GT. Called the Header Improvement Project (HIP), VNG’s plan involves 6 miles of new pipeline for an interconnection to the Transco line in Prince William County, Va. The plan would also add 18 miles of pipelines in existing corridors and three new or expanded compressor stations. One of the compressor stations would be built in an existing metering location in a minority neighborhood of Chesapeake, Va., south of Norfolk. VNG officials say the project would bring jobs, development and tax revenue to Charles City County and beyond, along with gas and electric reliability, noting that gas burns cleaner than coal. They call C4GT among the most efficient natural gas-fueled power plants to be built in Virginia. Environmental groups say the project moves Virginia toward continuing dependence on natural gas, when the Democrats who now run the state have been trying to put it on track for more renewable energy.

Developers: With pipeline canceled, big factories will reject Eastern North Carolina – They say high energy users want natural gas; opponents of the Atlantic Coast Pipeline reject that argument. While environmentalists and private property advocates celebrated the cancellation of the Atlantic Coast Pipeline this month, economic developers said the state literally lost fuel that North Carolina needs to attract large employers to lower-income areas in the eastern part of the state. Over the past three years, Cumberland County and the Fayetteville area were considered for more than $1 billion worth of industrial projects “that either won’t be coming or could not come because we did not have the natural gas structure that they needed,” “Some of them located in other parts of the state and other parts of the Southeast. But once it came down to profiling their energy load, we just weren’t able to accommodate it,” Van Geons said, declining to name the companies.The Atlantic Coast Pipeline would have run about 600 miles and carried natural gas from West Virginia to central and eastern Virginia and Eastern North Carolina. Construction was underway, and it was supposed to be completed this year. But the project was stalled by lawsuits and other efforts by its opponents. The estimated construction price rose from $5 billion in 2015 to $8 billion this year.Duke and Dominion announced the end of the project on July 5. They said ongoing delays and “increasing cost uncertainty” threatened the project’s economic viability.The opposition included a variety of critics.Some were property owners who were angry at being forced to give up land for the pipeline. Others were residents along the route who worried about natural gas leaks, fires and explosions near their homes.And many were environmental activists. They oppose the use of fracking techniques to extract natural gas and they want the world to move away from fossil fuels that exacerbate climate change by adding to the amount of heat-trapping gases in the atmosphere.

U.S. natgas futures drop over 4% to 3-week low as output rises – (Reuters) – U.S. natural gas futures dropped more than 4% on Monday to a three-week low as output increases and stockpiles remain about 16% over the five-year average. Some analysts said the market was starting to write off the rest of the summer after prices dropped about 5% last week even though this is the hottest time of year and the weather is expected to remain hotter-than-normal through at least early August. Front-month gas futures fell 7.7 cents, or 4.5%, to settle at $1.641 per million British thermal units, their lowest close since June 26. Refinitiv said production in the Lower 48 U.S. states averaged 88.4 billion cubic feet per day (bcfd) so far in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November. Traders noted output was rising as EQT Corp boosted production in Appalachia. Refinitiv forecast U.S. demand, including exports, will rise from 92.5 bcfd this week to 94.1 bcfd next week. That is higher than Refinitiv’s outlook on Friday. Pipeline gas flowing to U.S. LNG export plants averaged 3.3 bcfd (34% utilization) so far in July, down from a 20-month low of 4.1 bcfd in June and a record 8.7 bcfd in February. Utilization was about 90% in 2019. U.S. pipeline exports, meanwhile, rose as consumers in neighboring countries cranked up their air conditioners. Refinitiv said pipeline exports to Canada averaged 2.4 bcfd so far in July, up from 2.3 bcfd in June, but still below the all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico averaged 5.56 bcfd so far this month, up from 5.44 bcfd in June and on track to top the record 5.55 bcfd in March.

UPDATE 1-U.S. natgas futures rises as consumers crank up air conditioners – (Reuters) – U.S. natural gas futures rose 2% on Tuesday as power generators burned record amounts of gas this week to keep air conditioners humming during the hottest part of a heat wave blanketing much of the country. That increase, however, came after prices fell over 4% to a three-week low on Monday on forecasts for less hot weather next week. Front-month gas futures rose 3.4 cents, or 2.1%, to settle at $1.675 per million British thermal units. On Monday, the contract closed at its lowest since June 26. As the weather turns hotter, data provider Refinitiv forecast U.S. demand, including exports, will rise from 92.3 billion cubic feet per day (bcfd) this week to 93.6 bcfd next week. The power industry consumed more than half of that gas, gobbling up a one-day record of 47.5 bcfd on Monday. Pipeline gas flowing to U.S. LNG export plants averaged 3.4 bcfd (35% utilization) so far in July, down from a 20-month low of 4.1 bcfd in June and a record 8.7 bcfd in February. Utilization was about 90% in 2019. U.S. pipeline exports, meanwhile, rose as consumers in neighboring countries cranked up their air conditioners. Refinitiv said pipeline exports to Canada averaged 2.4 bcfd so far in July, up from 2.3 bcfd in June, but still below the all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico averaged 5.58 bcfd so far this month, up from 5.44 bcfd in June and on track to top the record 5.55 bcfd in March. Refinitiv said production in the Lower 48 U.S. states averaged 88.3 bcfd so far in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November.

US working natural gas volumes in underground storage rise 37 Bcf: EIA | S&P Global Platts – US natural gas in storage inventories ticked up slightly more than expected last week, prompting slight gains to the NYMEX Henry Hub balance-of-summer prices, which remained nearly 10 cents lower than the week prior. The amount of natural gas in US underground storage facilities increased 37 Bcf to 3.215 Tcf in the week that ended July 17, according to US Energy Information Administration data released July 23. The injection was above consensus expectations of analysts S&P Global Platts surveyed, which called for a 33 Bcf build. The injection was 8 Bcf below the 45 Bcf build reported for the same week in 2020, but matched the five-year average injection, according to EIA data. Storage volumes now stand 656 Bcf, or 25.6%, above the year-ago level of 2.559 Tcf and 436 Bcf, or 16%, above the five-year average of 2.779 Tcf. The build was less than the 45 Bcf injection reported the week prior as total supplies averaged 91.4 Bcf/d, up only 100 MMcf/d from a week earlier, as nominal changes in production were boosted slightly higher by net Canadian imports, according to S&P Global Platts Analytics. Downstream, total demand averaged 85.6 Bcf/d, with gains mostly centered on the power generation and residential-commercial markets, but widespread gains were limited across downstream sectors. The NYMEX Henry Hub balance-of-summer contract – August through October – rose 2 cents to $1.76/MMBtu in trading following the release of the weekly storage report, although that was 8 cents below the week-ago close. The gains have not extended into next winter, though, with the November-March contract strip holding flat at about $2.65/MMBtu as spreads between the two seasons are holding steady around 90 cents/MMBtu. Platts Analytics’ supply-and-demand model currently forecasts a 20 Bcf injection for the week ending July 24, which would be 13 Bcf below the five-year average.

U.S. natgas jumps over 6% as heat keeps air conditioners cranked up – (Reuters) – U.S. natural gas futures jumped over 6% on Thursday, with a couple of storms brewing in the Gulf of Mexico and on forecasts for high air conditioning demand during a heat wave expected to blanket much of the country through at least early August. Prices rose despite a federal report showing an expected near-normal storage build. The U.S. Energy Information Administration (EIA) said U.S. utilities injected a near-normal 37 billion cubic feet (bcf) of gas into storage in the week ended July 17. Front-month gas futures rose 10.4 cents, or 6.2%, to settle at $1.785 per million British thermal units, their highest close since July 10. Tropical Depression 8 is expected to strengthen into a Tropical Storm in the Gulf of Mexico over the next day or two as it moves toward the Texas coast. Refinitiv said production in the Lower 48 U.S. states averaged 88.4 billion cubic feet per day (bcfd) in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November. With the weather expected to remain hot, Refinitiv projected U.S. demand, including exports, will hold around 92.7 bcfd this week and next. The outlook for next week was a little lower than Refinitiv’s forecast on Wednesday. “Gas has been the fuel of choice for power generators looking to meet peak demand this month, and this fuel switching has helped absorb excess gas left by (coronavirus demand) destruction in the LNG and industrial sectors,”

August Natural Gas Futures Extend Rally as Demand Picture Brightens – Natural Gas Intelligence – August natural gas futures on Friday continued a rally ignited a day earlier as storage capacity concerns eased and robust power burns pointed to continued strong summer demand. The August Nymex contract gained 2.3 cents day/day and settled at $1.808/MMBtu Friday. That followed a double-digit advance on Thursday, which pushed futures to a two-week high. September climbed 3.2 cents to $1.867. NGI’s Spot Gas National Avg. rose 4.5 cents to $1.655. The pricing momentum gathered after signs of an improving liquefied natural gas (LNG) export environment and the U.S. Energy Information Administration’s (EIA) latest storage assessment, released Thursday, which showed an injection of 37 Bcf for the week ending July 17. It extended to four weeks a run of sub-100 Bcf additions to gas stockpiles. Shipbroker Fearnleys AS noted news reports of fewer U.S. LNG export cancellations heading into the fall and said the trend signals a potential recovery in the making. “After a very weak summer, expectations of an improving LNG trading environment appear to be bearing fruit as early estimates suggest September U.S. Gulf cargo cancellations are down considerably,” Fearnleys said. Traders surveyed by Bloomberg estimated that between 20 and 30 U.S. LNG export cargoes would not get loaded in September, but that would represent notable and continuing improvement. There were an estimated 50 cancellations for July and between 35-40 for August. U.S. LNG demand from leading consumers in Asia and Europe is gradually recovering with prices on both continents recently trading at a premium to the U.S. benchmark.The latest storage figure, meanwhile, amplified market sentiment on the intensity and broad geographic reach of this summer’s heat. Scorching temperatures are driving strong cooling demand and allaying worries about fall containment challenges. “We see the probability of hitting storage capacity becoming increasingly unlikely,” analysts at Tudor, Pickering, Holt & Co. (TPH) said. TPH estimated that storage would crest at 4.08 Tcf this year. With supply running 1 Bcf/d below its forecasts, however, analysts expect to see an additional 100 Bcf buffer against containment. “Additionally, record power burn” is “lining up for a tight print” with the next EIA storage report, the TPH analysts said. Their early modeling points to a build “in the 20 Bcf range, about half of normal levels.”

Natural Gas Forwards Slide Shows Sweltering Heat No Match for Weak Export Demand, Covid-19 – In an ominous sign of what may evolve to the end of the year, scorching heat across most of the country failed to spark a rally in natural gas forward prices for the July 16-22 period, according to NGI’s Forward Look. Instead, persistently weak global exports and continued uncertainty over the level of economic recovery amid Covid-19 drove prices about a nickel lower through the balance of summer (August-October) and the upcoming winter (November-March), Forward Look data show. Smaller shifts were seen for next summer and beyond. Dismal liquefied natural gas (LNG) demand and robust salt storage inventories stood ready to quell any uptick in prices, according to EBW Analytics. Meanwhile, the pandemic and ongoing economic weakness “took the edge off” strong power burn figures, effectively thwarting any attempt to move higher. The front of the Nymex futures curve held steady in the low $1.70/MMBtu range to end last week. However, on Monday, the August contract slumped to around $1.64 as weather models continued to lower the intensity of heat for the remainder of the month. Prices recovered a few cents by midweek, with the August contract at $1.681, the balance of summer at $1.745 and the winter at $2.662.The latest weather data continued to be less supportive than advertised earlier in the month, while still showing a hotter-than-normal pattern for the next 15 days. The largest errors in the modeling were in the Midwest, where, outside of a few days here and there, the big heat has mostly been a “no-show,” a trend that looked to continue at least for the next couple of weeks, according to Bespoke Weather Services.The cooler medium-range shift, around the end of the month into the opening of August, fits with what Bespoke expects to be a “temporary relaxation of the La Nina base state.” The firm still sees August winding up another hotter-than normal month, but tropical activity could dampen the outlook as a system brewing in the Gulf of Mexico (GOM) was set to bring rain to Texas through the weekend, limiting demand. On Thursday, the market appeared to breathe a sigh of relief after the Energy Information Administration (EIA)’s latest storage injection figure reflected what Bespoke said were “decently tight” supply/demand balances.The EIA said inventories for the week ending July 20 rose by 37 Bcf, which compares with a 44 Bcf storage build in the same week last year and a five-year average increase of 37 Bcf. Prior to the report, a Bloomberg survey found injection estimates ranging from 28 Bcf to 46 Bcf, with a median of 36 Bcf. The average of a Wall Street Journal poll was 35 Bcf, with a low estimate of 28 Bcf and a high of 41 Bcf. A Reuters poll found estimates ranging from 28 Bcf to 46 Bcf with an average injection of 36 Bcf. NGI estimated a build of 35 Bcf.

Will Buffett’s $10 Billion Bet On Natural Gas Go Bust? – On the day on which Dominion Energy and Duke Energy canceled the Atlantic Coast natural gas pipeline, Dominion Energy said it would be selling substantially all of its gas transmission and storage assets to an affiliate of Berkshire Hathaway. For Dominion Energy, the nearly US$10-billion deal, including debt assumption, is part of the company’s push to zero-carbon electric generation by 2050. For Warren Buffett’s conglomerate Berkshire Hathaway, it was the first major acquisition since the start of the coronavirus pandemic, and the biggest acquisition in four years. While there are growing calls from environmentalists that natural gas should follow coal’s fate and start being dumped from power generation because it’s not as clean as the ‘cleaner-than-coal bridge fuel toward renewables’ narrative would like us to think, Warren Buffett is unfazed. Buffett is looking at the asset the way he has always done with his investments – buy cheap assets that very few others are willing to buy. And betting that these assets will deliver returns. Buffett’s bet on natural gas comes at a time when U.S. natural gas prices slumped to a 25-year-low, while natural gas is set to continue to dominate utility-scale electricity generation for years to come. In 2019, natural gas accounted for 38 percent of utility-scale electricity generation in the United States, followed by coal with 23 percent, nuclear with 20 percent, and renewables including hydroelectric with 17 percent, according to EIA data. Natural gas continues to displace coal-fired electricity generation, and so do wind and solar, but still, natural gas is expected to be the biggest source of power generation over the next few years. Buffett’s US$10-billion bet on natural gas infrastructure shows that the billionaire investor believes that natural gas hasn’t run its course, regardless of what environmentalists and climate-conscious investors think. Berkshire Hathaway Energy is buying Dominion Energy’s assets that include over 7,700 miles of natural gas transmission lines, 900 billion cubic feet of operated natural gas storage with 364 billion cubic feet of company-owned working storage capacity, and 25 percent in the Cove Point LNG export, import, and storage facility in Maryland. Berkshire Hathaway Energy will thus own 18 percent of all interstate natural gas transmission in the United States, up from 8 percent now, according to CNBC. The fact that this acquisition was the first one that Buffett saw as attractive after the pandemic sent markets into turmoil in March suggests that the Omaha investor believes in the future of natural gas. “a bet that the future doesn’t come as fast as some people think,” Jim Shanahan, an analyst who covers Berkshire Hathaway at Edward Jones, told Bloomberg.

BOEM proposes Gulf of Mexico oil and gas lease for November 2020 –The Bureau of Ocean Energy Management (BOEM) is proposing to offer approximately 78.8 million acres for a region-wide lease sale scheduled for November 2020. Lease Sale 256, scheduled to be livestreamed from New Orleans, Louisiana, will be the seventh offshore sale under the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program. Lease Sale 256 will include approximately 14 755 unleased blocks – all of the available unleased areas in federal waters of the Gulf of Mexico.”The Gulf of Mexico provides a fundamental role for our nation’s energy portfolio,” said Mike Celata, Director of BOEM’s Gulf of Mexico Region. “As one of the most productive basins in the world, the development of its resources is essential to our nation’s energy security.”The Gulf of Mexico Outer Continental Shelf (OCS), covering about 160 million acres, is estimated to contain about 48 billion bbl of undiscovered technically recoverable oil and 141 trillion ft3 of undiscovered technically recoverable gas.Revenues received from OCS leases (including high bids, rental payments and royalty payments) are directed to the US Treasury, certain Gulf Coast states (Texas, Louisiana, Mississippi, Alabama), the Land and Water Conservation Fund, and the Historic Preservation Fund.Leases resulting from this proposed sale would include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species, and avoid potential conflicts associated with oil and gas development in the region. In addition, the following areas are unavailable and excluded from the lease sale: blocks subject to the congressional moratorium established by the Gulf of Mexico Energy Security Act of 2006, blocks adjacent to or beyond the US Exclusive Economic Zone in the area known as the northern portion of the Eastern Gap, and whole blocks and partial blocks within the current boundaries of the Flower Garden Banks National Marine Sanctuary.

June spill at New Orleans East oil terminal still being cleaned up – Workers continue to clean up the remains of more than 2,000 barrels of crude oil that leaked out of a storage tank at the Gulf Gateway Terminal on Terminal Road in New Orleans East on June 22, according to company officials and the state Department of Environmental Quality. Oil was still visible from the air on July 12 in a small area adjacent to the tank that is surrounded by an earthen containment dam, according to a photo taken by representatives of the Healthy Gulf environmental group. The terminal is the interim destination for dozens of tank cars moved by rail by the New Orleans Public Belt railroad and by BNSF Railway. More than 100,000 barrels of crude a day can be transferred from the cars to barges and ships docking at the terminal. Many of the railcars travel through the French Quarter on their way to the terminal. In an email sent to DEQ soon after the spill, terminal manager Stephen Champagne said 2,032 barrels of light sweet crude leaked from the storage tank, and that company officials immediately pumped the remaining 73,746 barrels of crude oil out of the leaking tank and into barges on the waterway. The company also transferred oil from several railcars at its site to barges “to create space for storage of the collected product as well as the remaining product sucked off the tank bottom.” The oil that spilled was being collected and stored in either small temporary holding tanks or railcars at the site, he said. “The collected product will be sampled to determine if it can be processed by refineries,” Champagne said in the note. If not, it would be properly disposed offsite, he said. The company also reported the spill to the U.S. Coast Guard National Response Center and the Louisiana State Police. DEQ inspectors who visited the site said in an initial report that a contractor was hired by the company to collect a combination of oil and rainwater from inside the earthen containment area. Air monitoring by the inspectors found 20 parts per million of volatile organic compounds in the air on the day of the spill and 10 parts per million of benzene the next day.

Oil & gas company BJ Services to lay off 273 in Shreveport following bankruptcy filing – – Another Northwest Louisiana employer in the oil and gas industry has filed for bankruptcy and announced layoffs.According to the latest Worker Adjustment and Retraining Notification (WARN) notice updated by the Louisiana Workforce Commission, BJ Services plans to lay off 273 employees in Shreveport on August 2.Under federal law, employers are required to provide advance notice of plant closures or mass layoffs.The Texas-based company provides hydraulic fracturing and cementing services to upstream oil and gas companies and has operations in every major basin throughout the U.S. and Canada. The company filed the WARN notice with the LWC on Sunday and filed for voluntary Chapter 11 bankrupcty on Monday. According to a statement released by the company, the plan is to sell its assets and is in active discussions with bidders regarding both the cementing business and portions of the fracturing business. The statement said the company believes the sales would reduce the number of jobs impacted by this process. “The industry continues to face unprecedented uncertainty caused by volatile commodity markets and significantly reduced demand due to the COVID-19 pandemic. Despite maintaining a leading market position and strong client support, the severe downturn in activity and subsequent lack of liquidity resulted in an unmanageable capital structure. After exhausting every possible alternative to address these issues and improve our liquidity, we have made the very difficult decision to proceed with a Chapter 11 process,”

‘A win-win’: Plugging Louisiana’s 4,300 ‘orphaned’ wells could boost industry, cut emissions –A federally funded stimulus program aimed at plugging the growing number of “orphan” oil and gas wells could greatly reduce pollution while giving a much-needed boost to the state’s ailing oil industry, a new report says. As Congress considers a new stimulus package of several trillion dollars to assist with the economic impacts from the coronavirus pandemic, a group of energy policy experts has published a report making the case that a fraction of the money should go toward plugging the millions of wells that have been abandoned by their owners and are now the responsibility of state governments. Louisiana has documented nearly 4,300 such wells, and the number is expected to rise as more companies shut down wells due to low oil prices and a faltering economy.”Plugging wells is a win-win opportunity that would provide good work for people negatively affected by the downturn in the economy and provide environmental benefits,” said Daniel Raimi, a public policy researcher and co-author of a report by Columbia University and Resources for the Future, a Washington D.C. environmental policy think tank.Plugging all of Louisiana’s orphan wells could employ just over 1,000 oil workers full-time for one year. It would also cut methane emissions by 558 metric tons per year, according to the report’s metrics. That’s the equivalent of the annual greenhouse gas emissions from more than 3,000 cars.Gifford Briggs, president of the Louisiana Oil and Gas Association, supports a federal stimulus for well plugging. He said many unemployed oil workers and struggling companies in Louisiana have the skills and equipment to begin doing such work today.”There are multiple layers of benefits,” he said. “It gives the opportunity to put people back to work and money back in our communities … and it continues to improve our environment.”

Tellurian evaluates changes to Driftwood LNG project, plans shares issue -(Reuters) – Tellurian Inc is considering changes to its Driftwood LNG export project in Louisiana that could significantly reduce the overall Phase 1 costs, the U.S. liquefied natural gas producer said on Wednesday. The company also disclosed plans to issue 35 million shares at $1 each, a 37% discount to Tuesday’s close, sending its stock plunging 27%. Shares surged more than 50% on Tuesday after sources said India’s Petronet LNG renewed a deal to give the parties more time to finalize an investment in the project. LNG developers have delayed numerous projects as the COVID-19 pandemic sapped overall fuel demand and hammered gas prices. Natural gas was trading at $1.65 per million British thermal units, about 30% lower than a year earlier. Tellurian has said the Driftwood project, designed to produce 27.6 million tonnes per annum of LNG, is expected to cost $27.5 billion, including pipelines. About $15.4 billion of the estimate is for a contract with Bechtel Oil, Gas and Chemicals Inc to build the export plant. Tellurian did not provide details on the cost cuts, but Scotiabank analysts said the reduction could mean the potential removal of the Permian pipeline, which could lead to savings of $4.2 billion. The equity offering will boost Tellurian’s liquidity to about $123 million on a pro forma basis, and Scotiabank analysts estimated could provide the company “sufficient runway until July 2021” based on a $6 million monthly cash burn.

INVESTIGATION: Lethal fog smothers Texas oil sites as inspections lag — Tuesday, July 21, 2020 — ODESSA, Texas – Permits are rising for handling hydrogen sulfide – a toxic byproduct of oil production that has killed workers. But an E&E News investigation shows little attention is being paid to making sites safer.

Oil-and-gas money flows to Railroad Commission nominee who pledged to recuse himself – Back in March, when Jim Wright, with little money in his campaign account, was an obscure Republican primary challenger to a sitting state oil and gas regulator, he pledged to recuse himself from matters involving campaign contributors. But Wright is now qualifying his pledge as recent campaign finance reports show hundreds of thousands of dollars from oil and gas interests flowed his way after his out-of-nowhere upset primary victory in March. In an interview Wednesday, Wright told the American-Statesman that should he be elected in November to the Railroad Commission, the state agency that regulates the oil and gas industry, he would recuse himself only on matters that involved contributors who give money directly ahead of a commission vote. Environmentalists and watchdog groups have long referred to the Railroad Commission as a “captured agency” – its three elected commissioners, all Republicans, receive the bulk of their campaign contributions from the industry they regulate and have historically been sympathetic to its interests. The close relationship – coziness, say critics – between industry and its chief regulators runs through to the Legislature. In 2016, the staff of the Sunset Advisory Commission, which reviews agency functions, recommended the commission, which no longer has anything to do with railroads, change its name to the Texas Energy Resources Commission to make its work more transparent. The move was opposed by oil and gas interests, and state Rep. Tom Craddick, R-Midland, the long-serving influential member representing the oil-rich Permian Basin – and father of Christi Craddick, one of the three current railroad commissioners – successfully led the effort to quash it.

Watchdog group sues Railroad Commission over oil storage crisis orders – The Austin office of watchdog group Public Citizen has sued the Texas Railroad Commission, the state’s oil and gas regulator, over emergency orders in May that waived fees and relaxed regulations for the storage of crude. In response to a glut of crude and rapidly dwindling room to store it, the agency’s three commissioners voted May 5 to enact orders that waived fees and charges for construction of new oil storage projects through the end of the year. Commissioners also gave oil companies more time to store waste in open pits and to plug abandoned wells. Public Citizen filed its suit Wednesday in state district court alleging that commissioners used the coronavirus pandemic to give handouts to industry – and that they did so without public input, skirting laws such as the Texas Public Meetings Act. Record low oil prices have caused a drop in demand for oil and natural gas and an uptick in bankruptcy filings, which Public Citizen argues will mean that more tax dollars will be spent on cleaning up abandoned wells. The Railroad Commission does comment on litigation but the agency contends that all the action taken during its May 5 meeting complied with state and federal laws. “These legal, emergency actions protect the Texas Miracle while ensuring the environment is protected,” Railroad Commission Chairman Wayne Christian said in a statement. “This complaint is no more than a proxy for fringe extremists to advance their goal of eliminating the domestic production of fossil fuels, a move that would kill 3.2 million jobs, increase energy and gasoline costs by $2,500 a year for American families, and cost Texas $1.5 trillion in GDP between 2021-2025.”

Permian Gains Give Oomph to US Drilling Permits in June, but Recovery to 2019 Levels Not in Sight – Requests for U.S. drilling permits improved in June following a brutal April and May, with the Permian Basin still the top region for operators, according to Evercore ISI. The analyst firm each month compiles permitting statistics for the Lower 48 and offshore using federal and state data. Covid-19 and low commodity prices had crushed permit requests in April, with May possibly the bottom, analyst James West said. According to Evercore, 1,238 permits were approved in June, up by 166 month/month (m/m). However, permitting was off by 66% year-to-date and 77% from June 2019. Most of the new permitting activity in June was focused on the Permian, with 109 more m/m, and in the Bakken Shale, which had 11 more requests than in May.”Permian operators received approval for 381 wells with 70% generated by public companies, 2% by equity sponsored operators, and the remainder originated from private ones,” West noted. The Bakken permit count improved in June to 67, 11 higher m/m. Public E&Ps requested 94% of all the permits, Evercore noted. Operators also increased their permit requests in the Mississippian Lime, up by 11 from May, and in Oklahoma’s Woodford formation, with nine more permits requested.The year-to-date oil permit count at mid-year stood at slightly under 10,000, with more than one-third (36%) for the Permian, Evercore noted. However, Permian permitting remained sharply lower, off by around 32% year/year at 3,618 to date. While the permit count is down from 2019, there has been a “steep fall” in the Powder River Basin, off by 97% year/year, and in the Denver-Julesburg (DJ)/Niobrara formation, which has seen permitting decline by 80%, Evercore analysts noted.Natural gas permitting also has slumped sharply, with the mid-year total at 1,128 in June, down by 48% year/year. The decline was blamed primarily on a deceleration in the Marcellus Shale, which had seen permits decrease by 54%.Meanwhile, in the other big dry gas play, the Haynesville Shale, private operators drove an uptick in permits during June, with 25 more requests m/m. Gas permits in the play stood at 142 in June, up by 40 m/m.Meanwhile, Ohio regulators, who oversee permitting in the Utica Shale, authorized 16 wells to be drilled, up by 15 m/m, with 36% for plugging and abandonment (P&A), according to Evercore.

Texas regulator proactively inspects Permian Highway Pipeline construction – Inspectors with the Railroad Commission of Texas are continuing critical inspections of the Permian Highway Pipeline (PHP), one of the largest pipeline projects under construction in Texas in 2020. Stretching more than 400 miles from the Permian Basin to the Houston area, the pipeline will bring West Texas’ natural gas to the world market. Given the sheer scale of the PHP and its route through the sensitive Texas Hill Country, RRC has engaged in a comprehensive response to ensure that the pipeline is constructed safely in a manner protective of public health and the environment. Since March inspectors from two key RRC divisions, Oil and Gas and Pipeline Safety, have conducted more than 75 inspections and investigated close to 20 complaints related to the pipeline. Currently RRC inspectors are on-site near the Pedernales River in Gillespie County as the pipeline operator, Kinder Morgan, works to excavate a pathway for the pipeline beneath the river. “Our inspectors have been hard at work, even during the COVID-19 pandemic, to ensure Kinder Morgan is compliant with Commission rules that are in place to protect public safety and natural resources,” said RRC Executive Director Wei Wang. “In addition to the all-hands efforts within the agency, we are also in contact with resident groups and the company as construction progresses. When it is complete, this pipeline will add vital capacity to convey natural gas, which in turn will also help ongoing efforts to further reduce flaring in West Texas.” New pipelines are important to efficiently and safely transport large amounts of natural gas and oil. The Texas Pipeline Association estimates that a 20-inch pipeline running 50 miles can replace 1,650 tanker trucks carrying oil on the road. Pipelines also help reduce flaring by alleviating potential backing up of supply at the point of production.

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