Oil, Gas, And Fracking News Reads: 23June, 2019 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 23 June 2019.

This article is a feature every Monday evening on GEI.

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Oil prices up most in 30 months; natural gas prices hit 3 year low; gasoline demand at an all time high; horizontal drilling at 16 month low, DUC wells down most in 15 months, et al

Oil prices saw their largest weekly jump since 2016 this past week after Iran shot down a sophisticated US spy drone which the US claims was operating in international air space and oil traders braced for a US retaliation…after falling 2.7% to $52.51 a barrel last week despite an attack on oil product tankers near the Strait of Hormuz, the benchmark contract price of US crude for July delivery slid steadily throughout the day on Monday as reports of a major industrial slowdown in China outweighed supply fears stoked by the Gulf of Oman oil tanker attacks of last week and finished trading $1.07 lower at $60.94 a barrel…oil prices started lower again on Tuesday, on reports of OPEC struggles to set a date for their next meeting, but then spiked sharply on hopes of a U.S.-China trade deal, after Trump said that he would meet with Chinese President Xi Jingping next week in Japan and ended $1.97 higher at $53.90 a barrel…prices edged up in early trading on Wednesday, following reports that OPEC and its allies were close to agreeing on a meeting date, but slipped back below $54 a barrel after anxieties about global trade and a supply glut overshadowed the EIA report of record gasoline consumption and closed 14 cents lower at $53.76 a barrel…oil prices opened higher Thursday after OPEC and other producers finally agreed on a date for a meeting to discuss output cuts, and then soared more than 5% after Iran shot down a U.S. spy drone, raising fears of a shooting war in the Persian Gulf, with trading in the July oil contract expiring $2.89 higher at $56.65 a barrel and the price of oil for August delivery rising $3.10 to $57.07 a barrel…August oil then opened higher & continued rising to $57.98 a barrel on Friday, but then pulled back slightly after Trump called back U.S. bombers on concern the Iranian death toll would have been disproportionate to Iran’s downing of an unmanned American drone, with oil closing 36 cents higher at $57.43 a barrel…US oil prices thus ended the week nearly 10% higher, in the biggest weekly percentage gain since December 2016, on fears that further conflict would disrupt oil flows from the Middle East, although the price rise in the August contract itself was actually short of 9%..

Natural gas prices, meanwhile, ended the week 20.1 cents, or more than 8% lower at $2.186 per mmBTU after falling each day until Friday. when they eked out a tenth of a cent gain…the natural gas contract for July delivery initially fell 11 cents over Tuesday and Wednesday, as the El Nino forecast suggested sustained heat in the lower 48 would be difficult to come by in the coming month and then fell 9.1 cents to a 3 year low after the EIA’s natural gas storage report indicated a record injection for the season, well above market expectations…

The natural gas storage report from the EIA for the week ending June 14th showed that the quantity of natural gas held in storage in the US increased by 115 billion cubic feet to 2,203 billion cubic feet by the end of the week, which meant our gas supplies were 209 billion cubic feet, or 10.5% more than the 1,994 billion cubic feet that were in storage on June 15th of last year, while still 199 billion cubic feet, or 8.3% below the five-year average of 2,402 billion cubic feet of natural gas that have been in storage after the second week of June in recent years….this week’s 115 billion cubic feet injection into US natural gas storage was well above an S&P Global Platts’ survey of analysts which had expected a 104 billion cubic feet injection, and was much higher than the average 92 billion cubic feet of natural gas that have been added to gas storage during the second week of June in recent years…this week’s injection was the largest ever for the 2nd week in June and the 5th largest injection of the past decade, in addition to being the 7th injection over 100 billion cubic feet this spring, in contrast to just 2 triple digit injections over the prior three years in any season…the 1,096 billion cubic feet of natural gas that have been added to storage over the past 12 weeks has been the largest injection of gas into storage on record for any similar period this early in the injection season, and probably about double the average 12 week build of the past decade, as the 824 billion cubic feet that were added during the same 12 weeks of 2014 is the only year that even appears close…

Once again, a major factor in this week’s seasonal record injection was the below normal temperatures for the week over the most populated areas of the US, which you can see on the map below, which thus reduced demand for air conditioning and power generation:

(source)

The Latest US Oil Supply and Disposition Data from the EIA

This week’s US oil data from the US Energy Information Administration, reporting on the week ending June 14th, showed modest decreases in our oil imports and in our crude production, which when combined with increases in our oil exports and our oil refining meant that we had to withdraw oil from out stored crude supplies for the 4th time in 13 weeks…our imports of crude oil fell by an average of 144,000 barrels per day to an average of 7,467,000 barrels per day, after falling by an average of 316,000 barrels per day over the prior week, while our exports of crude oil rose by an average of 300,000 barrels per day to 3,422,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,045,000 barrels of per day during the week ending June 14th, 444,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells was reported to be 100,000 barrels per day lower at 12,200,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from well production totaled an average of 16,245,000 barrels per day during this reporting week…

Meanwhile, US oil refineries were reportedly using 17,264,000 barrels of crude per day during the week ending June 14th, 200,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that a net of 444,000 barrels of oil per day were being withdrawn from the supplies of oil stored in the US….hence, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 575,000 barrels per day short of what our oil refineries reported they used during the week…to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (+575,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”….with that much oil unaccounted for, we have to figure that one or more of this week’s crude oil metrics are again off by a statistically significant amount…(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) indicated that the 4 week average of our oil imports rose to an average of 7,467,000 barrels per day last week, now 7.6% less than the 8,080,000 barrel per day average that we were importing over the same four-week period last year…the 444,000 barrel per day decrease in our total crude inventories was all taken out of our commercially available stocks of crude oil, while the amount of oil stored in our Strategic Petroleum Reserve remained unchanged…this week’s crude oil production was reported to be 100,000 barrels per day lower at 12,200,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 11,700,000 barrels per day, while a 14,000 barrel per day decrease to 466,000 barrels per day in Alaska’s oil production was not enough to impact the final rounded national total….last year’s US crude oil production for the week ending June 15th was rounded to 10,900,000 barrels per day, so this reporting week’s rounded oil production figure was roughly 11.9% above that of a year ago, and 44.8% 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 93.9% of their capacity in using 17,264,000 barrels of crude per day during the week ending June 14th, up from 93.2% of capacity the prior week, and finally a fairly normal refinery utilization rate for this time of year….however, the 17,264,000 barrels per day of oil that were refined this week were still 2.5% below the 17,701,000 barrels of crude per day that were being processed during the week ending June 15th, 2018, when US refineries were operating at 96.7% of capacity….

With the increase in the amount of oil being refined, gasoline output from our refineries was similarly higher, increasing by 147,000 barrels per day to 10,423,000 barrels per day during the week ending June 14th, after our refineries’ gasoline output had increased by 227,000 barrels per day the prior week….with those big increases in gasoline output, this week’s gasoline production was 2.3% more than the 10,099,000 barrels of gasoline that were being produced daily during the same week last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) rose by 132,000 barrels per day to 5,371,000 barrels per day, after our distillates output had decreased by 165,000 barrels per day the prior week…but even with this week’s increase, the week’s distillates production was still 1.7% less than the 5,468,000 barrels of distillates per day that were being produced during the week ending June 15th, 2018….

Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week fell for the 1st time in 5 weeks and for the 13th time in 17 weeks, decreasing by 1,692,000 barrels to 233,221,000 barrels over the week to June 14th, after our gasoline supplies had increased by 764,000 barrels over the prior week…our gasoline supplies fell this week because the amount of gasoline supplied to US markets increased by 51,000 barrels per day to a record high 9,928,000 barrels per day and because our exports of gasoline rose by 99,000 barrels per day to 630,000 barrels per day, while our imports of gasoline rose by 137,000 barrels per day to 837,000 barrels per day…after our gasoline supplies had reached an all time record high nineteen weeks ago, they then fell by nearly 13% over 10 weeks while US Gulf Coast refineries were crippled by the Venezuelan sanctions, and hence are still 2.8% lower than last June 8th’s inventory level of 240,040,000 barrels, and only 1% above the five year average of our gasoline supplies at this time of the year…

Similarly, even with the increase in our distillates production, our supplies of distillate fuels fell for the 10th time in 14 weeks, decreasing by 1,000,000 barrels to 128,372,000 barrels during the week ending June 14th, after our distillates supplies had decreased by 1,000,000 barrels over the prior week….our distillates supplies fell this week even though the amount of distillates supplied to US markets, a proxy for our domestic demand, fell by 307,000 barrels per day to 4,061,000 barrels per day, because our exports of distillates rose by 416,000 barrels per day to 1,553,000 barrels per day while our imports of distillates rose by 42,000 barrels per day to 165,000 barrels per day….but even after this week’s inventory decrease, our distillate supplies were still 8.9% higher than the 117,408,000 barrels of distillate that we had stored on June 15th, 2018, even as they fell to 5% below the five year average of distillates stocks for this time of the year…

Finally, with greater oil exports and refinery usage, combined with lower oil imports and lower oil production, our commercial supplies of crude oil in storage fell for the seventh time in 22 weeks, decreasing by 3,106,000 barrels, from 485,470,000 barrels on June 7th to 482,364,000 barrels on June 14th…with that decrease, our crude oil inventories slipped to 7% above the recent five-year average of crude oil supplies for this time of year, but still remained more than 37% higher than the prior 5 year (2009 – 2013) average of crude oil stocks after the second week of June, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories have generally been rising since this past Fall, after generally falling until then through most of the prior year and a half, our oil supplies as of June 14th were 13.1% above the 426,527,000 barrels of oil we had stored on June 15th, of 2018, but at the same time still 5.3% below the 509,095,000 barrels of oil that we had in storage on June 16th of 2017, and 3.5% below the 499,994,000 barrels of oil we had stored on June 17th of 2016…

This Week’s Rig Count

The US rig count fell for the 16th time in eighteen weeks over the week ending June 21st and was thus at another 16 month low, as the week saw the slowest drilling activity since February 2nd 2018….Baker Hughes reported that the total count of rotary rigs running in the US decreased by 2 rigs to 967 rigs this past week, which was also down by 87 rigs from the 1059 rigs that were in use as of the June 22nd report of 2018, and quite a bit below the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market…

The count of rigs drilling for oil rose by 1 rig to 788 rigs this week, which was still 73 fewer oil rigs than were running a year ago, and less than half 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 4 rigs to 177 natural gas rigs, which was also down by 11 rigs from the 188 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008…in addition, there was also the startup of a rig classified as miscellaneous this week, the first such miscellaneous running since October, but down from the 2 miscellaneous rigs that were running a year ago, when Cabot Oil & Gas was drilling 2 exploratory wells into the Knox formation in Ohio that Baker Hughes had labeled as miscellaneous…

The rig count in the Gulf of Mexico was unchanged at 24 rigs this week, with 22 rigs running offshore from Louisiana and 2 rigs deployed offshore from Texas….that’s a 6 rig increase from the 18 rigs that were deployed in the Gulf in the same week a year ago, when 17 rigs were drilling in Louisiana waters and one was deployed offshore from Texas..

The count of active horizontal drilling rigs was down by 6 to 846 horizontal rigs this week, which was a new 16 month low for horizontal drilling and 84 fewer horizontal rigs than the 930 horizontal rigs that were in use in the US on June 22nd of last year, and also well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…at the same time, the directional rig count was unchanged at 68 directional rigs this week, but those were up by 6 rigs from the 62 directional rigs that were operating during the same week of last year….on the other hand, the vertical rig count was up by 4 rigs to 53 vertical rigs this week, but those were down from the 60 vertical rigs that that were in use on June 22nd of 2018…

The details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the second table 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 June 21st, the second column shows the change in the number of working rigs between last week’s count (June 14th) and this week’s (June 21st) count, the third column shows last week’s June 14th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the equivalent 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 22nd of June, 2018…

In the Texas Permian, 3 rigs were shut down in Texas Oil District 8, which would be the core Permian Delaware, while a single rig was concurrently started up in Texas Oil District 7C, or the southern Permian Midland basin; since those changes account for the 2 rig loss shown for the Permian above, we have to figure that the rig that was shut down in New Mexico had been drilling in one of the other basins in the state, with the San Juan basin in the northwest most likely, since a decrease in natural gas rigs is not easily accounted for otherwise…while Texas had a rig start up and another shut down in areas of the state not in a major tracked basin shown above, the other two rigs pulled out of Texas that are shown came out of the Granite Wash in the panhandle, with one of those having been drilling for gas…other natural gas rig shut downs that are shown include the two that were shut down in Pennsylvania’s Marcellus, and natural gas rigs that had been operating in Oklahoma’s Arkoma Woodford and Ohio’s Utica shale, while there was also a natural gas rig removed from an “other basin” not tracked separately by Baker Hughes, which, as we’ve speculated, could have been from New Mexico’s San Juan…at the same time, 2 rigs targeting natural gas were started up in West Virginia’s Marcellus, one of just 6 states where there continues to be more drilling than a year ago…

Note that other than the major producing states shown above, Alabama also saw a rig shut down this week, and now have just two rigs deployed, same as their count of a year ago, while one rig was newly deployed in Mississippi, where there are now 5 rigs operating, up from four a year ago…also note that while one rig was shut down in Ohio’s Utica shale, Ohio’s rig count remained unchanged at 20 rigs because a vertical rig began drilling in Sandusky county to a depth of “less than 5000 feet”…that’s the rig that Baker Hughes classified as ‘miscellaneous’, which are usually exploratory wells not specifically targeting a known oil or gas field…to my knowledge, that’s the first drilling in Sandusky county, or anywhere in that part of the state, since the shale era shifted the focus to deeper beds accessed by horizontal drilling in the southeast…

DUC well report for May

Monday of this week saw the release of the EIA’s Drilling Productivity Report for June, which includes the EIA’s May data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions…for the third month in a row, this report showed a decrease in uncompleted wells nationally in May, as both drilling of new wells decreased and completions of drilled wells decreased….while there continued to be a increase of newly drilled but uncompleted wells (DUCs) in the Permian basin of western Texas and New Mexico, all other regions saw decreases in their DUC inventory, thus more than offsetting the Permian increases…for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 77 wells, from a revised 8,360 DUC wells in April to 8,283 DUC wells in May, which still represents a 21.2% increase from the 6,832 wells that had been drilled but remained uncompleted as of the end of May a year ago…the decrease occurred as 1,318 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during May, down by 46 from the 1,364 wells drilled in April and the lowest in 13 months, while 1,395 wells were completed and brought into production by fracking, a decrease of 16 well completions from the 1,411 completions seen in April, but the same number of well completions as in March…at the May completion rate, the 8,283 drilled but uncompleted wells left at the end of the month represent a 5.9 month backlog of wells that have been drilled but not yet fracked…

Unlike what we’ve seen over recent years, oil producing regions saw the majority of the May DUC well decreases, with all major oil producing regions except for the Permian showing double digit DUC drops…the number of DUC wells left in the Oklahoma Anadarko decreased by 33, from 996 in April to 963 DUC wells in May, as 127 wells were drilled into the Anadarko basin during May while 160 Anadarko wells were being fracked….at the same time, DUC wells in the Eagle Ford of south Texas decreased by 24, from 1,479 DUC wells in April to 1,455 DUCs in May, as 181 wells were drilled in the Eagle Ford during May, while 205 already drilled Eagle Ford wells were completed…in addition, the drilled but uncompleted well count in the Niobrara chalk of the Rockies’ front range decreased by 18 to 538, as 177 Niobrara wells were drilled in May while 195 Niobrara wells were being fracked…meanwhile, DUC wells in the Bakken of North Dakota fell by 17, from 716 DUC wells in April to 699 DUCs in May, as 113 wells were drilled into the Bakken in May, while 130 of the drilled wells in that basin were completed…

Among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 24 wells, from 461 DUCs in April to 437 DUCs in May, as 124 wells were drilled into the Marcellus and Utica shales during the month, while 148 of the already drilled wells in the region were fracked…in addition, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory decrease by 2 wells to 220, as 51 wells were drilled into the Haynesville during April, while 53 Haynesville wells were fracked during the same period….

On the other hand, the Permian basin of west Texas and New Mexico saw its total count of uncompleted wells rise by 41, from 3,930 DUC wells in April to 3,971 DUCs in May, as 545 new wells were drilled into the Permian, but only 504 wells in the region were fracked……thus, for the month of May, DUCs in the five oil basins tracked by in this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a net of 51 wells to 7,626 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 26 wells to 657 wells, although as the report notes, once into production, more than half the wells drilled nationally will produce both oil and natural gas…

Fracking in Ohio series: How Ohio compares to Pennsylvania for oversight of gas industry | StateImpact Pennsylvania – (audio & transcript) In reporting a special series looking at how Ohio agencies are handling complaints about fracking, The Allegheny Front found some differences between how Ohio and Pennsylvania are regulating oil and gas development. The Allegheny Front’s Kara Holsopple spoke with Heidi Robertson, the Steven W. Percy distinguished professor of law at Cleveland Marshall College of Law and a professor of environmental studies at Cleveland State University.

Fracking linked to higher radon levels in Ohio homes —A new study at The University of Toledo connects the proximity of fracking to higher household concentrations of radon gas, the second leading cause of lung cancer in the U.S. Measuring and geocoding data from 118,421 homes across all 88 counties in Ohio between 2007 and 2014, scientists found that closer distance to the 1,162 fracking wells is linked to higher indoor radon concentrations. “The shorter the distance a home is from a fracking well, the higher the radon concentration. The larger the distance, the lower the radon concentration,” Dr. Ashok Kumar, Distinguished University Professor and chair of the UToledo Department of Civil and Environmental Engineering, said. The study also found the average radon concentrations among all tested homes across the state are higher than safe levels outlined by U.S. Environmental Protection Agency and World Health Organization standards. The average is 5.76 pCi/l, while the EPA threshold is 4.0 pCi/l. The postal code 43557 in the city of Stryker has the highest radon concentration at 141.85 pCi/l for this data set. “We care about air quality,” Dr. Yanqing Xu, assistant professor in the UToledo Department of Geography and Planning, said. “Our motivation is to save the lives of Ohioans. I hope this eye-opening research inspires families across the state to take action and have their homes tested for radon and, if needed, install mitigation systems to protect their loved ones.” The results of the study were recently published in the journal Frontiers in Public Health. The research is a collaboration between UToledo’s Department of Civil and Environmental Engineering and Department of Geography and Planning. The radon data collection was supported by grants from the Ohio Department of Health and the U.S. Environmental Protection Agency. Radon, which cannot be smelled or seen, begins as uranium found naturally in soil, water and rocks, but transforms into gas as it decays. Most fracking wells are located in eastern Ohio, while Athens County has the highest number of fracking wells with 108. Fulton County is the only county with more than 20 fracking wells in western Ohio. .

PTT Global Chemical taps Bechtel for possible Utica Shale ethane cracker – – Appalachian gas producers, under pressure from prices below $3/Mcf, got a boost Thursday with engineering giant Bechtel’s announcement that Thailand’s PTT Global Chemical had awarded it a contract to build an ethane cracker in Belmont County, Ohio, in the heart of the Utica Shale. The project still needs a final investment decision. But selecting Bechtel as the contractor of the project is a major step toward that decision. Bechtel Oil, Gas & Chemicals Senior Project Manager of Pennsylvania Chemicals Paul Marsden, already working as the manager of Bechtel’s work on Royal Dutch Shell subsidiary Shell Chemical Appalachia’s multibillion-dollar ethane cracker in Monaca, Pennsylvania, made the announcement at the Northeast Petrochemical Conference in Pittsburgh. Another new cracker would give producers a new outlet for ethane, a natural gas liquid that they blend in the gas stream when it cannot be sold. The project is expected to be capable of producing 1.5 million metric tons per year of ethylene and its derivatives. Shell’s plant will produce up to 1.6 million mt/year of polyethylene. Analysts speculated full capex for the project could reach $6 billion. Charlie Schliebs, managing director of private equity funds at Stones Pier Capital, said the lack of a final investment decision announcement at this stage is to be expected. “These things [FIDs] take a long time, but that project is happening,” Schliebs said. The US Department of Energy has estimated that the Marcellus and Utica shales can support up to four more crackers, besides PTT’s and Shell’s. Observers expected a final investment on PTT Global’s project more than a year ago. PTT Global could have been watching to see if costs on Shell’s project spiraled out of control. Asked whether Bechtel would face challenges getting enough labor to work on both the Shell project and the PTT, Marsden said it would be “a challenge. We will have to manage that.” But he noted that the timing of the projects could actually work in the builder’s favor, as having sequential projects lined up could encourage welders and other key workers to relocate to the region instead of simply coming in for one project at a time.

House Votes to Block Trump from Using Clean Energy Funds to Back Fossil Fuels Project — Democrats mounted a challenge in the U.S. House of Representatives on Wednesday against what they call a raid by the natural gas and plastics industries on a pot of federal money created to help finance innovations that reduce greenhouse gas emissions.The fight is over a proposed $1.9 billion government-backed loan guarantee from a program that has primarily been used to back wind power, solar and other types of clean energy. The Energy Department is now considering using that program to support a large-scale underground storage project for ethane, a fossil fuel byproduct used to make plastics.If the loan guarantee goes through, that government backing could help spur funding for a major new petrochemical and plastics industry in the upper Ohio River Valley, spanning West Virginia, Pennsylvania and Ohio.Opponents forced a vote on an amendment to a big spending bill this week to try to stop it, and the House approved it. Rep. Ilhan Omar (D-Minn.) called it “incredibly worrisome that this administration would try to use a program designed for renewable energy to line the pockets of polluters. Grants that are designed for renewable energy projects should go toward renewable energy. Period.” She co-sponsored the amendment, which expressly bans the use of loan guarantees from the program except for “clean energy projects that avoid, reduce, or sequester air pollutants or human-caused emissions of greenhouse gases.” This kind of amendment is often used to tie an agency’s hands or to bolster eventual challenges in court.That amendment, bundled with eight others, passed the House on a vote of 233 to 200, largely along party lines. The win for Omar was just one step in a legislative process, however. The Senate has yet to consider the spending bill.Grassroots opponents of fossil fuel expansion echoed Omar’s concerns. “It’s clear to us that this project is in violation of what the law was intended to fund,” said Mitch Jones, who has been tracking the ethane storage project for Food and Water Watch, an environmental group that helped to coordinate a letter opposing the loan guarantee from nearly 150 organizations.

Pennsylvania Bill Aims to Shift Water Clean-Up Costs From Residents to Polluters – In response to chemical contamination from a naval station in his district, Representative Todd Stephens, a Pennsylvania House Representative from Montgomery County, is pushing for legislation that would remove the financial pressure on citizens to clean their own drinking water. This push from Rep. Stephens is indicative of a larger problem – figuring out how to pay to clean drinking water from the confirmed 21 sites throughout Pennsylvania contaminated with per- and polyfluoroalkyl substances (PFAS). The chemicals are used in products such as stain- and water-resistant clothing, nonstick pots and pans, firefighting foam, carpets, and furniture, and have been linked to various cancers, thyroid problems, low birth weights, and other problems. They’re increasingly showing up in water throughout the U.S. The PFAS class of chemicals includes more than 5,000 individual chemicals with similar properties. PFAS don’t readily break down once they’re in the environment, and they can accumulate in animal and human tissues. PA House Bill 1410 would fund cleanup efforts using some state tax revenue generated by development on and around the original pollution site, Republican Rep. Stephens told EHN, and would also require the state to develop a statewide program to address PFAS contamination in drinking water. In Stephens’ district, the federal government discovered widespread PFAS contamination in drinking water after closing the Willow Grove Naval Air Station in Montgomery County in 2006. They notified local communities, which began filtering the chemicals from drinking water, but had to charge residents new surcharges to cover the costs. The federal government “polluted drinking water, and local residents are paying to clean it up,” Stephens said, calling it “unconscionable.” House Bill 1410 would redirect some of the state tax revenue from the former military site to a newly created municipal authority. The funds would then be used to pay for infrastructure projects aimed at encouraging redevelopment of the vacant former military site, and use some of the state tax revenue generated by future development to clean up lingering contamination in drinking water sources and eliminate those surcharges. The bill also would require the Pennsylvania Infrastructure Investment Authority (PennVEST), which invests in sewer, stormwater, and drinking water projects throughout the state, to develop a statewide funding program to address PFAS water contamination.

Pennsylvania regulators launch broad effort to rethink pipeline safety | Pittsburgh Post-Gazette – At a time when the state has seen numerous problems with pipeline construction crisscrossing its lands, Pennsylvania regulators are moving to get a better grip on safety involving the often massive projects. “The time is ripe to move forward with specific proposals to enhance pipeline safety in Pennsylvania,” the Pennsylvania Public Utility Commission said as it set the stage for what is likely to be a hotly contested review of the topic. “We must proceed expeditiously, but cautiously.” In a pair of rulemaking proposals introduced Thursday, the commission kept it generic. But all over the documents were echoes of Mariner East – a trio of Energy Transfer pipelines that have suffered spills, slides, environmental damage, court-mandated shutdowns, criminal probes, and a public rebuke from Gov. Tom Wolf. The PUC is seeking comments on pipeline construction, materials and inspection, and the disclosure of financial information, among dozens of other topics. The invitation is broad, even if the target of the agency’s proposed rulemaking is specific: public utility hazardous liquid pipelines. Today, that includes three pipeline systems, all in various stages of controversy. They are the Mariner East system; Buckeye Partners’ Laurel Pipe Line, which is seeking federal approval to periodically reverse the direction of flow on part of the line so it can ship petroleum from the Midwest into Central Pennsylvania; and an 84-mile oil pipeline in Eastern Pennsylvania seeking to be reborn as a natural gas line.

Gov. Tom Wolf asked to investigate possible link between Pa. fracking, childhood cancers | Pittsburgh Post-Gazette – More than 100 organizations and 800 individuals have signed a public letter to Gov. Tom Wolf calling on him to direct the state Department of Health to investigate potential links between shale gas development and a proliferation of childhood cancers. The letter, which environmental groups plan to deliver to the governor and state Health Department Secretary Dr. Rachel Levine via email Monday, and hand deliver during a demonstration in Harrisburg Wednesday, also requests that all new shale gas permitting be suspended until the health investigation can demonstrate the cancers are not linked to shale gas drilling and fracking operations. “This is a public health crisis that requires immediate and significant action,” according to the text of the four-page letter. Emily Wurth helped lead the letter-writing effort and said the broad-based support for examination of health impacts of shale gas development was prompted by the ongoing Pittsburgh Post-Gazette series “Human toll: Risk and exposure in the gas lands.” Stories in the Post-Gazette series document up to 67 cases of childhood and young adult cancers in Washington, Greene, Fayette and Westmoreland counties where shale gas operations are active. The total includes 27 cases of Ewing sarcoma, a rare bone cancer. “The letter references the investigative reporting and scientific evidence that strongly suggests a link between childhood cancers and shale gas operations,” said Ms. Wurth, who is organizing co-director of Food & Water Watch and Food & Water Action. “We organized this strong response in just a couple of weeks from the about 125 organizations and even more individuals who are concerned about what they’ve read.” A state health department review of 12 Ewing sarcoma cases in Westmoreland County and six in Canon-McMillan School District in Washington County failed to conclude that either met the criteria for designation as a “cancer cluster.” The study only included three of the six Canon-McMillan area cases in the cluster assessment.

Gov. Wolf wants more data about how gas drilling impacts citizens’ health | Pittsburgh Post-Gazette –Gov. Tom Wolf has asked the state Department of Health to determine how best to spur additional academic and science-based studies of the potential public health impacts caused by shale gas development in the state.“Pennsylvania’s natural gas development is providing economic benefits to the commonwealth. But these benefits should not require a choice between them and public health or safety,” the governor said in a release Wednesday afternoon. “It is essential that as we realize economic benefits, we ensure the public is protected, especially our children, and take the necessary steps to aggressively regulate resource development.”The governor’s directive comes in response to calls Monday by environmental activists, doctors and more than 100 organizations for him to order an investigation into the potential link between high numbers of childhood cancers in southwestern Pennsylvania.The Pittsburgh Post-Gazette has documented up to 67 cases of childhood and young adult cancers in Washington, Greene, Fayette and Westmoreland counties in its ongoing series, “Human toll: Risk and exposure in the gas lands.” Among those cancers during the past decade are 27 cases of Ewing sarcoma, a rare bone cancer affecting mostly children and teens. Twelve of those cases occurred in Westmoreland County and another six within the Canon-McMillan School District in Washington County.The governor said a multi-state environmental health review recently completed by Department of Health epidemiologists was “inconclusive, and suggested that further in-depth research is warranted.” The governor released his statement shortly after receiving a lengthy compendium of scientific and medical studies released in Harrisburg Wednesday by the Concerned Health Professionals of New York and Physicians for Social Responsibility that focuses on topics related to the public health and safety impacts of unconventional shale gas and oil development.

Report: EPA Still Doesn’t Protect Environment From Toxic Oil And Gas Waste – In a follow-up report, Earthworks once again warns the Environmental Protection Agency is failing to protect the environment from hazardous waste from oil and gas drilling.“Still Wasting Away” builds on a report from 2015 that called attention to exemptions or loopholes the Environmental Protection Agency (EPA) has permitted for around two decades. And, four years later, the “volume of waste is increasing per well and per unit of energy.”There are 1.3 million oil and gas facilities in the United States. An oil and gas “threat map” indicates about 12.6 million people live within a half mile of these facilities.The U.S. leads the world in producing toxic oil and gas waste, and from now until 2030, the country is expected to “unleash 60 percent of all new oil and gas production globally.” That is four times more than any other country. President Donald Trump’s administration has granted much more influence to fossil fuel industry interests to deregulate and expand loopholes throughout the U.S. in ways that exacerbate the public health and environmental hazards for communities. Yet, the regulatory capture the industry enjoys is not entirely a product of Trump. The EPA under President Barack Obama had an opportunity to end an exemption carved out of a regulation in 1988 but chose to maintain that loophole. According to Earthworks, before the “shale boom,” the EPA submitted a report to Congress that acknowledged that oil and gas waste contained a “wide variety of hazardous constituents.” However, under the Resource Conservation and Recovery Act (RCRA), the waste was granted an exemption from the regulation’s definition of “hazardous.”Officials made this decision despite the fact that they found contaminant levels higher than “one hundred times the EPA’s health-based standards.”

Even If All US Drilling and Fracking Halts Today, Warns New Report, ‘Flood of Toxic Waste Streams’ Will Grow for Decades – – For more than three decades, the U.S. government has mismanaged toxic oil and gas waste containing carcinogens, heavy metals, and radioactive materials, according to a new Earthworks report – and with the country on track to continue drilling and fracking for fossil fuels, the advocacy group warns of growing threats to the planet and public health. “Even if we stop all new drilling and fracking immediately, the flood of toxic waste streams will continue to grow for decades,” Melissa Troutman, the report’s lead author, said in a statement Tuesday. “In spite of industry claims of innovation, the risks from oil and gas waste are getting worse, not better.”Building on a 2015 Earthworks analysis, Still Wasting Away (pdf) details congressional and Environmental Protection Agency (EPA) actions as well as industry lobbying related to the federal rules for liquid and solid waste from fossil fuel development.”Despite over 30 years of research about the toxic impacts of the industry’s waste, it is far from being handled properly,” the report says. “There is little consistency in tracking, testing, and monitoring requirements for oil and gas waste in the United States.” “At all stages of the oil and gas waste management process,” the report explains, “toxins can enter the environment accidentally (spills, leaks, waste truck rollovers, and illegal dumping) or legally under current state and federal law (road spreading, discharge to rivers, landfill leaching).” Demonstrating the scope of the threat that such waste poses to human health, the report notes that “an estimated 17.6 million Americans live within a mile of oil and gas development, including half of the population in West Virginia and almost a quarter of the population in Ohio.”

Total Ban on Fracking Urged by Health Experts: 1,500 Studies Showed ‘Damning’ Evidence of Threats to Public Health, Climate A comprehensive analysis of nearly 1,500 scientific studies, government reports, and media stories on the consequences of fracking released Wednesday found that the evidence overwhelmingly shows the drilling method poses a profound threat to public health and the climate. The sixth edition of the Compendium of Scientific, Medical, and Media Findings Demonstrating Risks and Harms of Fracking (the Compendium), published by Physicians for Social Responsibility and Concerned Health Professionals of New York, found that “90.3 percent of all original research studies published from 2016-2018 on the health impacts of fracking found a positive association with harm or potential harm.”The analysis also found that:

• 69 percent of original research studies on water quality found potential for, or actual evidence of, fracking-associated water contamination;
• 87 percent of original research studies on air quality found significant air pollutant emissions; and
• 84 percent of original research studies on human health risks found signs of harm or indication of potential harm.

“There is no evidence that fracking can operate without threatening public health directly and without imperiling climate stability upon which public health depends,” the Compendium states. Sandra Steingraber, Ph.D., co-founder of Concerned Health Professionals of New York, said in a statement that “the case against fracking becomes more damning” with the publication of each edition of the Compendium.”As the science continues to come in, early inklings of harm have converged into a wide river of corroborating evidence,” said Steingraber. “All together, the data show that fracking impairs the health of people who live nearby, especially pregnant women, and swings a wrecking ball at the climate. We urgently call on political leaders to act on the knowledge we’ve compiled.”

“No evidence” that fracking can done without threatening human health: Report – A group of doctors and scientists have released a report highlighting that 84 percent of studies published from 2009-2015 on the health impacts of fracking conclude the industry causes harm to human health.The report, published by two groups, Physicians for Social Responsibility and Concerned Health Professionals of New York, sites an earlier literature review that found 69 percent of studies on water quality during the same time period found evidence of or potential for fracking-associated water contamination, and 87 percent of studies on air quality found “significant air pollutant emissions” associated with the industry.The new report looks at 1,778 articles from peer-reviewed medical or scientific journals, investigative reports by journalists, and reports from government agencies on fracking. Fracking is another name for hydraulic fracturing, which is a process of extracting natural oil and gas from the Earth by drilling deep wells and injecting liquid at high pressure. “When we first started issuing this report in 2014, we predicted we’d eventually see health impacts based on what we saw happening to air and water,” Sandra Steingraber, a professor of Environmental Studies and Sciences at Ithaca College and one of the lead authors of the study, told EHN. “Now we’re beginning to see actual evidence of human harm.”Other recent literature reviews have also found links between fracking and a range of health effects including preterm births, high-risk pregnancies, asthma, migraine headaches, fatigue, nasal and sinus symptoms, and skin disorders.The new report also examines studies on the natural gas industry’s impact on climate change, and finds that due to methane leaks, natural gas extraction could be contributing to global warming even more than coal. “It’s now clear that swapping out coal plants for natural gas is at best a lateral move,” Steinraber said. “And it’s beginning to look like it might even be more like getting out of the frying pan and into the fire.”

Massive explosion at refinery in Philadelphia: reports – A massive fireball lit up the night sky in South Philadelphia early Friday in what was apparently an explosion at a local refinery. Early reports gave the location as 31st Street and Passyunk Avenue, not far from the city’s sports complex. Officials in Philadelphia confirmed that the early morning fire started at the 150-year-old Philadelphia Energy Solutions Refining Complex.Shortly after 5 a.m. Friday, Philadelphia’s FOX 29 reported that the fire had been contained with no reports of injuries or evacuations.Reports of the fire began spreading on social media shortly after 4 a.m. Friday. KYW-TV reported that the refinery has its own fire brigade. The cause of the fire was still unclear. Road closures as a result of the blast included a stretch of Interstate 76 from University Avenue to the Walt Whitman Bridge as well as Penrose Avenue and 26th Street, Philadelphia’s FOX 29 reported.The Platt Bridge was temporarily closed, but WPVI-TV reported that it had reopened.Interstate 95 remained open between Center City Philadelphia and the airport, FOX 29 reported.Four SEPTA transit routes have been diverted because of the fire.The complex produced 335,000 barrels of oil daily. Philadelphia Energy Solutions says the oil refining complex is the largest on th e U.S. Eastern Seaboard.

Giant explosion rocks largest refinery complex on the East Coast, sends gasoline prices higher – A series of explosions early Friday tore through a Philadelphia gasoline refinery, the East Coast’s largest, sending shock waves for miles and raining debris on nearby neighborhoods, just as the busy summer driving season was beginning. Four minor injuries were reported, according to the Philadelphia Fire Department. The three-alarm fire at the Philadelphia Energy Solutions refinery was contained but not under control, the fire department said. About 120 firefighters worked to cool off the areas around the fire to keep it from spreading. The fire turned the sky bright orange and shook the homes of startled residents. Some neighbors in South Philadelphia said debris rained from the sky into their neighborhoods after the explosions, according to NBC Philadelphia. The outage occurred as the U.S. summer driving season kicks into high gear.Gasoline futures jumped 3.5% Friday morning. Because RBOB futures reflect New York harbor prices, they are especially impacted by an outage in a refinery in Philadelphia, an important regional refining hub. In addition to the average $2.66 per gallon, pump prices on the East Coast could rise 3 cents to 5 cents per gallon as a result of the explosion, Wells Fargo said in a note to clients Friday. Natural gas prices also rose 1%. “It’s a serious outage that’s going to greatly affect the East Coast in particular,” said John Kilduff of Again Capital. “There’s a cushion for drivers because we’re well supplied, but if there’s major damage, it’s going to change that dynamic dramatically.” Gasoline demand in the U.S. reached a record high last week, according to government data released Wednesday. U.S. drivers consumed a record 9.9928 million barrels a day last week. That is up from the 9.3 million barrels a day used a year ago. It was also up from 9.877 million barrels a day the week earlier.

It Could Burn All Day – Gasoline Futures Soar As Philadelphia Refinery Burns – Gasoline futures for July delivery were up more than 4% on the NY Mercantile Exchange, overtaking an increase in WTI, as an inferno continues to burn through the Philadelphia Energy Solutions oil refinery in South Philadelphia on Friday. The Philadelphia refinery is “the largest such plant on the U.S. East Coast and the main supplier to the local gasoline market” according to Bloomberg. As of 10AM, the fire was still not under control, according to the Philadelphia Fire Department.The PES complex handles up to 335,000 barrels of crude per day and is the main supplier of fuel to the New York Harbor market, where inventory is already below average seasonal levels. The complex has plants at Point Breeze and Girard Point in Philadelphia. After a leak in an alkylation unit, an explosion sent the complex ablaze, forcing the Girard Point section to shut down. The Point Breeze section had already been under repair due to a fire earlier this month. Due to the fact that it is a chemical fire, officials are saying it could burn all day. Joe Brusuelas, Chief Economist at RSM US LLP said: “Any shortage ahead of the peak of the summer driving season does not bode well for U.S. consumer pocketbooks. The video of the early morning explosion is horrific.”Gasoline demand nationwide was already at a record last week, nearing 10 million barrels per day. There was a shelter-in-place for parts of South Philadelphia due to the smoke plume from the fire, but it has since been lifted. The site has been home to refining operations for more than 150 years. Prior to PES, the site was owned by Chevron and Sunoco.

W.Va.-based company to build coal to liquid plant in Mason County – Easy access to coal, natural gas and the river are a few of the reasons a company has decided to build a coal to liquids facility in Mason County. “Domestic Synthetic Fuels” is a West Virginia-based company. The plant will turn coal and natural gas into fuel that burns cleaner than petroleum-based fuel. The plant will be the first of its kind in the United States. According to a news release, there is already one in China. One hundred thirty jobs are expected at the plant, while 100 coal mining jobs are expected at the location where coal will come from in Kanawha County, along with “thousands” of construction jobs, according to the news release. The Department of Environmental Protection has approved the draft plans. The company said there will be community meetings to keep everyone informed.

$1.2 billion project proposed for Mason County – A major, economic development announcement for the area was made on Monday from a company that wishes to place a coal to liquids facility, a reported first of its kind in the United States, in Mason County, W.Va. According to a press release from Domestic Synthetic Fuels (DS Fuels), a West Virginia-owned company, it has plans to convert the state’s “abundant coal and natural gas” to gasoline and other fuels, and will soon break ground on a coal to liquids facility in Mason County. The overall project cost, according to DS Fuel, is $1.2 billion, with 130-plus direct jobs, 130-plus new indirect coal jobs, thousands of indirect jobs, an annual payroll of approximately $11.5 million including employee benefits and $300 million annual estimated gross revenue. The proposed facility will go on 200 acres secured from the Mason County Development Authority in the Mason County Industrial Park. The park is approximately five miles north of Point Pleasant, along W.Va. 62, across from the Mason County Airport and along the Ohio River. Construction is estimated to begin October 2019 with a project completion date of 2022 or early 2023. The West Virginia Department of Environmental Protection (DEP) recently approved the draft construction permit for the project. Company officials plan a series of community meetings to explain the project and its benefits to the community.

West Virginia is still waiting on an $84 billion investment from China that was promised in 2017 – Beijing billed President Donald Trump’s 2017 trip as a “state visit-plus” – rolling out the red carpet for an unprecedented private dinner in the Forbidden City, marching a military parade through Tiananmen Square, and hosting a signing ceremony in the colossal Great Hall of the People to unveil business deals totaling more than $250 billion.One-third of that value was supposed to flow to West Virginia, an energy-rich but high-poverty state whose manufacturing and energy workers handed Trump his widest margin of victory in 2016. He captured more than more than 67% of the vote.Under the deal, China’s largest state-owned energy giant would spend nearly $84 billion over 20 years to build facilities that extract natural gas and turn it into byproducts that generate power and make consumer goods.In celebrating the announcement, West Virginia officials said projects would be underway within a year.“This time next year, you will see construction activity taking place,” the state’s former Commerce secretary, Woody Thrasher, told reporters on Nov. 13, 2017.A month later, Gov. Jim Justice confirmed that timeline. “It would not surprise me, within my 10-month window of today, to see shovels in the ground,” Justice told a town hall on WSAZ television. But skepticism about the deal surfaced almost immediately. Officials referenced the general areas where China Energy would invest, but didn’t provide a detailed list of projects or an accompanying timeline. The memorandum of understanding outlining the deal was never made public and remains sealed by judicial order. CNBC interviewed dozens of local executives, state officials and federal lawmakers about where the deal stands. What emerges is a picture of a proposal hastily assembled for the deadline of Trump’s trip to China without assessments of national security or geopolitical risks – and a cautionary tale as the U.S. tries to hold China to its promises at the federal level.

Mountain Valley Pipeline has Contaminated Public Waters in Eleven WV Counties – The Mountain Valley Pipeline (MVP), is a 303-mile project that extends across 11 counties in West Virginia – Wetzel, Harrison, Doddridge, Lewis, Braxton, Webster, Nicholas, Greenbrier, Fayette, Summers, and Monroe Counties. MVP was recently fined approximately $266,000 by the WVDEP for repeated water quality violations. The proposed agreement for the fine is now open for public comment. Comments are due by June 20. The fine accounts for 26 of the 28 violations WVDEP has issued the company to date. The water quality violations are the result of Mountain Valley Pipeline’s failure to implement and maintain sediment controls, which allowed muddy water to impact 33 streams and wetlands. The picture above depicts sediment flowing into Indian Creek in Monroe County. Learn more here and here. “As issues continue to occur along the Mountain Valley Pipeline route, we as ‘stakeholders’ are objecting to inadequate construction practices and obvious environmental violations. We are objecting to the lack of oversight both the federal and state governments are giving to a project that they approved. We have been left as citizens to defend ourselves, our mountains, our waters,” he said. “We are here to remind not just the MVP that we are stakeholders, but also the politicians who lied to us about it being the most scrutinized project ever.”“A lot of folks are not aware that the West Virginia Department of Environmental Protection has a single inspector for the entire southern region. That means he is not only responsible for the Mountain Valley Pipeline project, he’s also responsible for the MXP (Mountaineer Xpress Pipeline). He’s also responsible for the ACP (Atlantic Coast Pipeline.) There is no way – no physical way – for that inspector to be able to cover that much ground and properly ensure that this project is being done in a viable manner.”

EQM raises cost, delays timing of Mountain Valley natural gas pipeline – EQM Midstream Partners LP said on Monday it had raised the estimated cost of its Mountain Valley natural gas pipeline from West Virginia to Virginia to $4.8-$5.0 billion and delayed the projected completion to mid-2020 due to ongoing legal and regulatory challenges.That is up from the company’s last estimate of $4.6 billion and a target to complete the project in the fourth quarter of 2019.EQM made the comments in a federal regulatory filing in which the company said it had submitted a land exchange proposal to the federal government in an effort to enable the pipe to cross the Appalachian Trail.Crossing the trail became an issue after the U.S. Court of Appeals for the Fourth Circuit in December said the U.S. Forest Service lacked authority to issue a permit for another gas pipe, Dominion Energy Inc’s $7.0-7.5 billion Atlantic Coast, to cross the Appalachian Trail on federal land. That case is on appeal to the U.S. Supreme Court.EQM’s land exchange proposal would grant the federal government full ownership of private lands crossed by the Appalachian Trail, including certain private land located adjacent to the Jefferson National Forest. In exchange, the government would grant Mountain Valley a right-of-way to cross the trail using the pipeline’s previously planned underground method at an existing crossing location approved by the Federal Energy Regulatory Commission in 2017.

Mountain Valley Pipeline will take longer and cost more to complete, company says –Builders of the Mountain Valley Pipeline may have found a way to cross the Appalachian Trail, but it will delay the project’s completion until the middle of next year and increase its cost to as much as $5 billion. The disclosure was made Monday in a filing with the U.S. Securities and Exchange Commission by EQM Midstream, the lead partner in the joint venture. Previously, Mountain Valley had said it would spend $4.6 billion and have the natural gas pipeline finished by the end of this year. The latest plan involves a proposed land swap in which the U.S. Department of the Interior would allow the company to keep its current crossing of the Appalachian Trail – at the top of Peters Mountain along the West Virginia-Virginia line – in exchange for a piece of private property that Mountain Valley owns adjacent to the Jefferson National Forest, according to the filing. Giving the land to the government would “protect one of the last segments of the trail that is currently not under federal ownership or control,” Mountain Valley said. As part of the deal, the company would be allowed to proceed with plans to tunnel under the trail to bury its 42-inch diameter pipe at the mountaintop. The boring plan was cast in doubt in December, when a federal appeals court ruled that the Forest Service had improperly allowed a similar project, the Atlantic Coast Pipeline, to cross the scenic footpath farther to the east, in the George Washington National Forest. But if the land swap is approved, “the applicable federal agencies would grant the MVP venture an easement and right-of-way” to cross the trail at its originally planned location, which was approved in 2017 by the Federal Energy Regulatory Commission, EQM wrote in the SEC filing. “This exchange would effectively privatize MVP’s right-of-way across the trail, potentially avoiding the legal peril of crossing the trail on federal land” that was created by the 4th Circuit’s ruling in the Atlantic Coast case, according to a report from Height Capital Markets, an investment banking firm that has been following the project.

Delays raise new questions for the Mountain Valley Pipeline – As Anne and Steve Bernard recently stood near the pipeway’s path – which passes about 150 feet from their Franklin County home and a studio behind it where the two artists work – Anne recalled what happened the last week of July 2018. “They came in with a storm of machinery and they dug the trench in two days and then they dropped the pipe in it,” she said. “They were in such a hurry.” The next day, the Bernards saw where the buried 42-inch diameter pipe extended to a part of the trench that had filled with water in a low-lying pasture, before work crews had a chance to cover the pipe with dirt. “I called MVP and said, ‘Your pipe is floating here,’” Anne Bernard said. Nearly a year later, the section of pipe remains suspended – as do key parts of a $4.6 billion project to build a 303-mile pipeline to transport newly drilled natural gas from northern West Virginia, through the New River and Roanoke valleys, to connect with an existing pipeline near the North Carolina line. A Mountain Valley spokeswoman said June 6 that the company still hopes to finish the project by the end of the year. But delays in construction, caused in large part by legal challenges from environmental groups opposed to plowing such a large pipeline across rugged mountain slopes and through clear-running streams, have raised questions that were not anticipated when the project was announced five years ago. The welded joints that link the 40-foot pipe sections could weaken over time, especially when the unburied part of the line tips upward in standing water the way it does on the Bernard property, opponents say. That could increase the chance of a rupture and explosion once the line is shipping natural gas under high pressure. And the longer that sections of the pipe remain stored above the ground, exposed to the elements before they are buried, the greater the chance that a protective coating could be degraded to the point that it contaminates the surrounding water, critics fear.

Williams submits new permits for pipeline, compressor station in NJ – Williams has filed new permit applications with the New Jersey Department of Environmental Protection (DEP) to build its proposed Northeast Supply Enhancement Project, which includes a natural gas pipeline under Raritan Bay to New York and a new compressor station in Franklin Township. Williams filed the new applications on June 10, five days after the DEP denied the company’s initial application. “We strongly believe the discrete technical issues raised by the DEP on June 5 were addressed in our previous application and, in this application, we have provided additional information showing that these issues have been addressed,” Christopher Stockton, a Williams spokesperson, said in a statement. The company’s action has already come under fire by an environmental group. “The speed in which the company reapplied for permits first in New York and now in New Jersey is an insult,” Peter Blair, policy attorney for Clean Ocean Action, said in a statement. “New Jersey’s denial outlined the serious violations of laws and regulations, in particular the lack of need, the impact from toxic contaminated sediments, and the failure to prove that this project is in the public interest. It is clear that as long as the door is left open they will continue to try and push this pipeline through.”

NextEra-Backed Venture Trucks LNG to Northeast — A venture backed by NextEra Energy Inc. is trucking natural gas from the Marcellus Shale to New England, where pipeline bottlenecks have helped send prices for the fuel soaring in the winter. Closely held Edge Gathering Virtual Pipelines 2 LLC is using tractor trailers to treat gas, chill it and truck it from northeastern Pennsylvania to Rhode Island, Chief Executive Officer Mark Casaday said in a telephone interview. NextEra Energy Marketing LLC, a subsidiary of the biggest North American utility owner, is a shareholder in the company and the exclusive sales and marketing partner for the fuel. Gas explorers are looking for new ways to get their supply to market as multibillion-dollar pipeline projects to transport shale gas to consumers in the Northeast stall amid opposition. The Trump administration has sought to speed up approval of gas lines, which have faced legal and regulatory roadblocks amid concern about fossil fuels’ contribution to climate change. “By next year this time we will probably have increased our production five or 10 times” as more Marcellus producers sign on, Casaday said. “It’s pipeline constraints, but it’s also the connectability of pipelines. A lot of wells are in no man’s land.” New Fortress Energy LLC, founded by billionaire Wes Edens, is also considering trucking Marcellus LNG north. Casaday said Edge Gathering is in discussions to haul supply from the Permian Basin of West Texas and New Mexico and the Bakken formation in North Dakota and Montana, where gas is a byproduct of oil drilling and is often burned off in a process known as flaring.

Worcester residents demand gas leak repairs near schools – – Residents and advocates filed into City Hall Monday demanding that public utility Eversource fix five natural gas leaks near five schools in the city, citing health concerns surrounding asthma. Councilors on the Standing Committee on Public Health and Human Services filed an order asking the full council to require Eversource to fix the leaks and kept the matter on the agenda for future meetings. Massachusetts law dictates that gas companies prioritize repairing leaks within a school zone, or within 50 feet of a public or private school, preschool or Head Start. District 4 Councilor Sarai Rivera expressed confidence that the city can work with Eversource to fix the “public health crisis.” Ms. Rivera said next steps include reaching out to the gas company and including the effects of gas leaks on the public in future community health improvement plans. “You’re talking about five schools, you know, we can do it,” she told reporters after the meeting. “I’m concerned at the fact that we’re still having the summer schools, we have these amazing recreations in Worcester where we have hundreds of kids throughout the city – sometimes over 100 kids in one area.” Mothers Out Front, a national advocacy organization composed of mothers promoting a livable climate for children, petitioned for the topic to be discussed at the meeting. Patricia Kirkpatrick, the Worcester chapter’s volunteer coordinator, said the issue of gas leaks is correlated with poor air quality and pulmonary issues such as asthma. The Boston chapter originally alerted team members in Worcester about unrepaired gas leaks. Mrs. Kirkpatrick noticed that some leaks were on public grounds, such as schools, playgrounds, hospitals, and day care centers, after looking at a map created by the Home Energy Efficiency Team. “Asthma, in particular, is what we’re concerned about because Worcester has very high rates when compared to the rest of the country and to the rest of Massachusetts,”

Maryland seeks dismissal of federal lawsuit by company blocked from building natural gas pipeline – Maryland Attorney General Brian Frosh has asked a federal judge to dismiss a lawsuit filed by a company that wants to build a natural gas pipeline in Washington County that the state’s top officials have rejected. Columbia Gas Transmission, which is owned by TransCanada Corp., filed the lawsuit last month in U.S. District Court in Baltimore. It seeks a preliminary injunction to give the company immediate access to property to drill a pipeline under the Western Maryland Rail Trail. It also seeks the “award of just compensation and damages.” The lawsuit was filed not long after the Maryland Board of Public Works in January rejected a request to grant an easement for a segment of the pipeline that would carry fracked natural gas through three miles of western Maryland, after years of environmentalists and neighbors fighting the project. Republican Gov. Larry Hogan and the three-member board’s Democrats – Comptroller Peter Franchot and Treasurer Nancy Kopp – agreed the project would be bad for the environment. In addition, over 60 members of the Maryland General Assembly signed a letter opposing the grant of an easement. Gas company sues Maryland seeking to resurrect pipeline through Western Maryland The pipeline would transport fracked gas from Pennsylvania to a new plant in West Virginia. Its length in Maryland would be 3 miles. The Federal Energy Regulatory Commission granted Columbia Gas a “certificate of public convenience and necessity,” which “nominally gives it the power to condemn property,” Frosh said in a statement. But the Democratic attorney general argued in the motion to dismiss that the “11th Amendment of the U.S. Constitution prevents a federal court from ordering the state to grant the easement.” “We are vigorously defending Maryland’s right to refuse a pipeline company’s efforts to drill under state land,” Frosh said in a statement.

Natural gas production rises from June to July: Dpr -Natural gas production in the seven most prolific basins/plays in the Lower 48 U.S. states is projected to grow by 798 million cubic feet per day (Mmcf/d) from June to July, the Energy Information Administration projects, Kallanish Energy reports. In the just-released June Drilling Productivity Report (Dpr), total gas production is expected to reach 81.36 billion cubic feet per day (Bcf/d) from the seven regions, according to EIA.Five of the seven basins/plays will see a month-to-month increase in gas production, while two will see production slightly slip. Three of the seven basins/plays should see a triple-digit jump in production, led by Appalachia, the combination of the Marcellus and Utica Shale plays. The Dpr expects gas production from June to July in Appalachia to jump by 347 Mmcf/d, to 32.44 Bcf/d, from 32.10 Bcf/d. (All numbers are rounded.)The Permian Basin’s gas production, due to its huge crude oil production, will jump 230 Mmcf/d, to 14.69 Bcf/d, from 14.46 Bcf/d in June.Close behind in third place is the Haynesville Shale, projected to see gas production increase from June to July by 218 Mmcf/d, to 11.52 Bcf/d, from 11.30 Bcf/d, the June Dpr reveals.The Niobrara is expected to see natural gas production rise by 50 Mmcf/d from June to July, to 5.55 Bcf/d, while the Bakken will see gas production increase by 20 Mmcf/d, to 2.98 Bcf/d in July, from 2.96 Bcf/d in June.The Anadarko and Eagle Ford Shale each are projected to see gas production fall from June to July, by 50 Mmcf/d and 17 Mmcf/d, respectively.The Anadarko’s total production will fall to 7.39 Bcf/d, while the Eagle Ford’s production will drop to 36.80 Bcf/d.

Natural Gas Remains Near The Low As Inventories Build – The price of natural gas declined steadily since March and is now trading at a multiyear low. The price action in the natural gas market has been ugly, and the sharp rally last November has faded into the market’s rear view mirror. After trading to the highest price since 2014 at $4.929 per MMBtu last November, the price recently fell to its lowest level since 2016 at $2.3050 per MMBtu this montAs the monthly chart highlights, the price of nearby NYMEX natural gas futures fell to the lowest level since 2016 and posted losses over the past seven consecutive months. Nearby natural gas futures were just under the $2.40 per MMBtu level on Friday, June 14. Price momentum and relative strength metrics were in oversold territory, but monthly historical volatility at 65% reflects the wide price range of $2.624 per MMBtu since November. The price range over the past seven months was higher than the price as of last Friday. As the daily chart illustrates, natural gas is building a wall of resistance around the $2.40 level, but that could give way quickly if weather forecasts turn warmer than average which would increase the demand for natural gas for cooling as it replaced a large percentage of coal-fired power generation. Meanwhile, the technical state of the market could be telling us that a recovery may be on the horizon as price momentum and relative strength display oversold conditions. Another factor that could spark a rally is that open interest, the total number of open long and short positions in the natural gas futures market has increased from 1.264 million contracts in late May to 1.332 million as of the end of last week. As the chart highlights, stocks now stand at 2.088 trillion cubic feet, 10% above last year’s level, but still 9.9% below the five-year average. The injection season began with 1.107 tcf in storage, and at the current rate of injections, we could see them peak at the four trillion cubic feet level by November when the peak season begins to draw down the inventories. Last year, the high in November was at 3.79 tcf, and it is looking likely that we will see a higher number later this year which is another reason why the price is floundering below the $2.40 per MMBtu level. As stocks build at over 100 bcf each week, the market could continue to experience price pressure.

The Nation’s Natural Gas Fill Rate — This May Be A Record-Setting Year — — This is quite incredible: spend some time on this one, from a reader, regarding the nation’s natural gas fill rate: “The 981 billion cubic feet of natural gas that have been added to storage over the past 11 weeks has been the largest injection of gas into storage on record for any similar period this early in the injection season, probably about double the average 11 week build of the past decade, as the 712 billion cubic feet that were added during the same 11 weeks of 2014 was the only year that even appeared close… ” We’ve become accustomed to triple digit injections, but scanning the recent decade’s spreadsheet, I find that in most years we only had one triple digit inventory build all summer, most often in the fall. The only exceptions were 2014 and 2015, and the June curve in 2014 was the only one as steep as the May curve this year … so we may be on our way to a record year… This came in as a comment to the post this past week regarding the NG fill rate.

Weekly storage of natural gas in U.S. increases by 5.5 pct: EIA – (Xinhua) — Working gas storage in the contiguous United States was 2,203 billion cubic feet (about 62.38 billion cubic meters) in the week ending June 14, a net increase of 115 billion cubic feet, or 5.5 percent, from the previous week, the U.S. Energy Information Administration (EIA) said in a report on Thursday. The total working gas storage increased by 10.5 percent from this time last year, or 8.3 percent below the five-year average, but still within the five-year historical range, according to the EIA’s Weekly Natural Gas Storage Report. The storage of working gas usually turns to increase in late April and will continue to grow in early November when heating season starts in the country, according to previous data. Working gas is defined as the amount of natural gas stored underground that can be withdrawn for use.

US natural gas in storage expands by 115 Bcf to 2.203 Tcf- EIA – – US natural gas added 115 Bcf last week to storage, much larger than the market expected, and the NYMEX Henry Hub summer strip collapsed to less than $2.20/MMBtu following the Thursday morning announcement. US natural gas in storage increased to 2.203 Tcf for the week ended June 14, the US Energy Information Administration reported. The injection was much more than an S&P Global Platts’ survey of analysts calling for a 104 Bcf injection. It was just within the survey range as responses spanned 89 Bcf to 117 Bcf. It was also more than the 95 Bcf build reported during the corresponding week in 2018 and the five-year average injection of 92 Bcf, according to EIA data. It was also the seventh triple-digit build. Only two weekly injections have measured more than 100 Bcf over the prior two years. Power demand in the South Central, East and Midwest regions fell by a combined 1.9 Bcf/d, while warmer temperatures across the west drove Pacific and Mountain power demand higher by about 1.3 Bcf/d, paring overall demand declines, according to S&P Global Platts Analytics. Total US supplies were down 0.4 Bcf/d on the week to average 91.2 Bcf/d, with a 0.3 Bcf/d fall in offshore production and a 0.2 Bcf/d fall in Canadian imports countered with a 0.1 Bcf/d increase in US onshore production. Overall, total production came in at an average 86.7 Bcf/d. As a result, stocks were 209 Bcf, or 10.5%, more than the year-ago level of 1.994 Tcf and 199 Bcf, or 8%, less than the five-year average of 2.402 Tcf. The deficit to the five-year average is the smallest it’s been since December 2017 while the surplus to the year prior is the largest since September 2016. The NYMEX Henry Hub July contract sank 9 cents to $2.186/MMBtu following the announcement. The remainder of the summer strip, August through October, fell 9.9 cents to average $2.165/MMBtu by Thursday afternoon trading. Ahead of the storage release, NYMEX Henry Hub July contract was trading about 2 cents higher. At this point, the highest-valued contract over the next year, January 2020, is barely trading above $2.60, a far cry from the $3 it was trading at only a month ago.

More new natural gas combined-cycle power plants are using advanced designs –Lower natural gas prices in recent years have spurred the construction of new natural gas-fired power plants in the United States. Of the new U.S. natural gas capacity added since 2016, 31% use advanced natural gas-fired combined-cycle (ANGCC) units. Greater use of the new, larger ANGCC designs has led to efficiency gains and economies of scale, which have resulted in reduced capital construction costs. These lower costs are likely to substantially increase ANGCC’s share of new U.S. natural gas capacity additions in future years.Natural gas-fired combined-cycle generating technology has evolved over the past few decades. Generators have large, heavy-duty natural gas turbines that are defined by their firing temperatures and unit capacity ratings. Beginning in the early 1960s, 20-megawatt (MW) natural gas-fired turbines became available. By the mid-1980s, the highest natural gas-fired turbine rating reached 100 MW, and it had increased to 200 MW by the late 1990s. With firing temperatures that are more efficient, today’s ANGCC units are rated at 320 MW.The increased output of ANGCC units has resulted in improved economies of scale. The latest generation of largerFrame H natural gas-fired turbines was first installed in 2015 and was incorporated into the design for 45% of the combined-cycle units installed in 2017. Based on EIA’s survey of announced capacity additions, Frame H turbines are expected to be incorporated in 33% of future natural gas combined-cycle power plants through 2020 and in close to 40% of those installed in 2021 and 2022. According to an April 2018 PJM report, the cost per unit of ANGCC installed capacity at PJM’s next capacity auction will be 25% to 30% lower compared with older, conventional natural gas-fired combined-cycle (NGCC) units. With that rate of cost decline, ANGCC generators will cost slightly more than combustion turbines.

US Poised to Approve Shipping LNG by Rail for Export With No New Safety Rules – On June 6, the U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA) announced that the company Energy Transport Solutions LLC had applied for a special permit to transport liquefied natural gas (LNG) in unit trains 100 cars long and for the express purpose of moving LNG to export facilities. The notice in the Federal Register starts a comment period, ending July 8, for the public to weigh in on the proposal, which represents a new mode for transporting LNG and includes no new safety precautions.The permit documentation and environmental assessment from PHMSA suggest that federal regulators – instead of learning from the deadly mistakes of the essentially unregulated oil-by-rail boom – are poised to allow the fossil fuel and rail industries to repeat the same business model with LNG, with potentially even higher consequences for public health and safety.For years, the rail industry has been seeking approval for LNG-by-rail, and in April President Trump issued an allowing LNG-by-rail by 2020.The justification for allowing unit trains of LNG is the same as for unit trains of volatile crude oil. (Unit trains haul primarily a single commodity in trains that can stretch a mile long.) Just like the oil-by-rail industry sprung up to move a glut of North Dakota fracked oil, promoters of LNG-by-rail tout it as necessary due to the flood of fracked natural gas – something PHMSA notes is expected to increase for “decades to come,” according to the Department of Energy.PHMSA asserts that transportation of LNG by rail, compared to currently moving it by tanker truck, would be more cost efficient and reduce its environmental impacts. In addition, the agency claims that “the existing regulatory requirements that govern the movement of cryogenic flammable materials similar to LNG are expected to provide adequate safety measures for LNG shipped in DOT-113C120W tank cars.”Cryogenic materials are “liquefied gases that are kept in their liquid state at very low temperatures,” typically below -238 degrees Fahrenheit, and those which are flammable “produce a gas that can burn in air.” PHMSA’s environmental assessment for the permit is the document currently open for review. It notes several (but not all) of the risks of moving a flammable material in the heaviest train cars in unit trains of 100 cars or more. It then dismisses all of those concerns. Under Trump, deregulation is the rule, and safety measures are voluntary. If past is prologue and the federal government approves unit trains of LNG, expect the same scenes as with oil trains: flames, explosions, and deaths.

Marathon Petroleum MLP MPLX considers NGL project near Houston –A subsidiary of Ohio-based MLPX is considering a project to build an asset worth nearly half a billion dollars south of Houston. The MPLX project would spend $460 million on a new natural gas liquids fractionation plant in Brazoria County, according to an application for tax incentives published by the Texas Comptroller on May 31. MPLX is the midstream master limited partnership under Ohio-based Marathon Petroleum Corp. The project would employ 500 people during peak construction and then 10 full-time jobs after the fractionator enters service, according to the application. Each of the full-time employees would be paid at least $66,000 annually. If the project moves forward as described in the incentive application, it would start construction in the fourth quarter of 2020 and commence operations in April 2022. The company is seeking Chapter 313 incentives, under which school districts can make deals with companies building certain kinds of infrastructure abating some of the property value of the new project for taxation purposes. In this case, the MPLX subsidiary responsible for the project – MarkWest Energy West Texas Gas Co. LLC – is asking Angleton Independent School District to tax the project as though it were worth only $30 million for the 10-year duration of the incentive.

Is Big Oil’s Plastic Bet Going Sour? – OilPrice –While Greenpeace activists were busy planning their occupation of a BP drilling rig, Exxon and Sabic sealed a US$10-billion deal for what is going to be one of the world’s largest petrochemical plants. The deal comes amid increasingly loud opposition to plastics use as the planet’s plastic pollution problem worsens and calls for urgent measures to deal with it intensify. Bans on some single-use plastic products have been a popular way of trying to deal with the problem but it won’t be enough: plastics demand is rising and will continue to rise through the next ten years at least, Axios reported recently, noting that demand for ethane – the largest feedstock for plastics – will hit 1.7 million bpd this year in the US alone, up by 83 percent from 2012. It is this prospect of rising plastics demand that is spurring a lot more investment in petrochemicals in the Big Oil group. Big Oil goes where the profits are and the environmentalist offensive against internal combustion engines will eventually lead to a decline in oil demand from the transportation sector. Plastics, however, will endure. Petrochemicals will come to account for more than 33 percent of oil demand growth globally in the period to 2030. By 2050, they will drive half of the global oil demand growth, raising this demand by 7 million bpd by that year, the International Energy Agency said in a report last October. The problem seems to be recycling. The global average for 2015 was below 20 percent, with the U.S. performing even worse, with a 9-percent rate of recycling. Now, this problem is getting worse after last year China stopped importing plastic waste. Until then, it was the world’s dumping ground, but now large plastic waste producers such as the United States are searching for new destinations for this waste.

Q&A: What happens if state shuts down Line 5 oil pipeline –A permanent shutdown of Enbridge Energy Co.’s Line 5 oil pipeline could have a major downstream impact on trade with Canada, energy supplies for multiple states and the price of jet fuel for airplanes at Detroit Metro Airport and residential propane in the Lower Peninsula.Attorney General Dana Nessel has indicated she may go to court as soon as the end of this month to try to stop the flow of oil through Enbridge’s 66-year-old underwater pipeline in the Straits of Mackinac.Enbridge has separately sought a court order enforcing its deal with former Gov. Rick Snyder to build a tunnel under the environmentally sensitive waterway to house Line 5.The Calgary, Alberta-based company took action after Gov. Gretchen Whitmer wanted to shut down Line 5 within two years – three years before Enbridge says a tunnel sitting 100 feet below the bottom of Lake Michigan could be completed.”The enormous risk (of an oil spill) that we bear alone as the state of Michigan and the Great Lakes is one that I take very seriously, and it was important to me that have a date certain for shutdown,” Whitmer said last week.The increasingly heated rhetoric has set up a showdown between the Canadian oil pipeline giant and two Democratic statewide officeholders who made campaign promises a year ago to their party’s eco-conscious base that they would shut down the underwater pipeline.Here are five questions and answers about Line 5 and the potential impact of permanently shutting down the pipeline.

Enbridge continues $40M in pre-construction work on Line 5 tunnel — Enbridge Energy will continue rock and soil sampling in the Straits of Mackinac this week, moving its previously land-based boring operation onto the actual waterway where the company will drill for the samples from a barge. The start of drilling from the waterway, Enbridge said, “preserves the schedule to complete the tunnel at the earliest possible date,” which is expected to be five years from now in 2024. The geotechnical work is part of the $40 million the Canadian company plans to spend this year in the beginning phases of its construction of a $500 million utility corridor project, an investment made even as the state challenges the agreement to build the tunnel. Democratic Attorney General Dana Nessel in March opined that Enbridge’s agreement with the state to build the tunnel, established under Republican former Gov. Rick Snyder, was unconstitutional. That same month, Democratic Gov. Gretchen Whitmer halted state work on the project and began discussions about a new plan with a shorter timeline for completion. In early June, Enbridge filed legal action in the Michigan Court of Claims asking the court to rule its agreement is valid and enforceable. The company, which has said it could complete its project in five years, said it could not meet the two-year Line 5 decommissioning deadline Whitmer wanted. The governor criticized the decision to choose litigation rather than “negotiate in good faith” and claimed the company was “only interested in protecting its bottom line.” Nessel has said she will take her own legal action to shut down the line if the governor and Enbridge don’t reach a new deal by the end of this month.

Enbridge pipeline project hits another Minnesota obstacle – Enbridge Energy’s plan to replace an aging crude oil pipeline that runs through northern Minnesota hit another obstacle Tuesday when two state agencies said they would hold up approval of the project’s permits until problems with its environmental review are resolved. The Minnesota Pollution Control Agency and Department of Natural Resources said Tuesday that they can’t take final action on the permits for the Line 3 project until the independent Public Utilities Commission addresses the deficiencies cited in a state appeals court ruling this month, including that the project’s environmental impact statement failed to address the possibility of a spill into the Lake Superior watershed. That means the two state agencies won’t release the draft permits as scheduled July 1, though they said they will continue reviewing the applications. Calgary, Alberta-based Enbridge said in a statement that the PUC will have to determine how to address the court’s objections. The commission has not yet laid out a process or timetable for doing that. Procedural delays and other court rulings have pushed back the project schedule several times. “We believe the actions required to address the spill modeling in the Lake Superior watershed can be completed efficiently,” the company said. Winona LaDuke, executive director of the indigenous environmental group Honor the Earth, which is an official party to the case, praised the MPCA and DNR for making “a prudent decision to suspend their permitting process for a new pipeline that was never needed in the first place.” The $2.6 billion replacement pipeline would carry Canadian crude from Alberta across northern Minnesota to Enbridge’s terminal in Superior, Wisconsin, which sits near the westernmost tip of Lake Superior. Enbridge wants to replace the current Line 3, which was built in the 1960s, because it is increasingly subject to corrosion and cracking, and runs at only about half its original capacity for safety reasons. Environmental and tribal groups fighting the project argue that it risks oil spills in pristine areas of the Mississippi River headwaters region where Native Americans gather wild rice, and that the Canadian tar sands oil that the line would carry accelerates climate change. The Court of Appeals actually rejected most of the plaintiffs’ objections to the environmental review, but they have until July 3 to seek further review from the Minnesota Supreme Court.

Exclusive: Enterprise Products explores sale of Texas oil terminal stake – document –(Reuters) – U.S. pipeline operator Enterprise Products Partners LP is looking to sell its 50% stake in a recently-completed South Texas crude export terminal, according to a marketing document viewed by Reuters. Enterprise is weighing an exit from the joint venture with terminal operator Plains All American Pipeline LP after proposing to build its own offshore port near Houston. There are at least eight proposed deepwater oil ports on the U.S. Gulf Coast seeking to handle rising shale exports. The Houston-based pipeline operator has hired RBC Capital Markets LLC to advise on a sale, according to the document, which did not indicate a price. Enterprise declined to comment, referring queries to Plains, which did not respond to requests. RBC Capital Markets declined to comment. The joint venture, Eagle Ford Terminals Corpus Christi, is connected to the two companies’ 660,000 barrels per day (bpd) Eagle Ford JV Pipeline. The pipeline brings crude from the Permian Basin and Eagle Ford shale fields to the U.S. Gulf Coast. The potential sale comes as three new crude pipelines will by mid-2020 begin carrying some 2 million bpd from Texas shale fields to the U.S. Gulf Coast. Enterprise in January filed to build its own deepwater export terminal, Sea Port of Texas (SPOT), at a site 40 miles (64 km) off the coast of Houston.

EPA issues guidance critics say would limit state’s authorities over pipeline projects – The Environmental Protection Agency (EPA) issued a guidance Friday that critics say seeks to limit states’ influence over controversial pipeline projects.Federal law through the Clean Water Act essentially gives states veto power over large projects that cut through their rivers and streams if they believe those projects would negatively impact their water quality.Spurred by an April executive order from President Trump, the EPA’s guidance encourages states to more quickly process project applications, even if they don’t have all the information yet.“This seems to be another attempt by the Trump Administration to limit states, and by extension local communities, ability to protect their own waterways and to give pipeline developers or other project proponents an ability to skip over one of the steps in the process that had been there to protect local waterways,” said Nathan Matthews, a senior attorney with the Sierra Club, one of the environmental groups weighing action against the EPA.The Clean Water Act gives states a year to weigh permits and determine how projects would impact their water, but some feel states have used the process to block major projects. “I welcome this announcement and hope EPA’s new guidance will reduce abuse of the Clean Water Act to block infrastructure needed to provide reliable and affordable energy,” Sen. Lisa Murkowski (R-Alaska) said of the guidance in a press release. “EPA’s updated guidance will maintain vital protections for our water resources while promoting responsible development of our energy resources.”

Mess with a Texas pipeline now and you could end up a felon – Texas now has one of the harshest laws in the country to protect its oil and gas operations from protesters. Damaging a pipeline in the Lone Star State could get you a decade in prison and $10,000 in fines starting in September. Republican Governor Greg Abbott signed the Critical Infrastructure Protection Act into law on Friday, further criminalizing protests of pipelines, oil tanks, and drilling sites. It makes knowingly damaging them a third-degree felony, on par with indecent exposure to a child. Trespassing with the “intent to damage” or “impairing or interrupting operations” will be punishable with up to two years in prison. Texas is the latest state to pass legislation that criminalizes civil disobedience since protests against the Dakota Access Pipeline caught national attention in 2016. Seven other states – Oklahoma, North Dakota, South Dakota, Louisiana, Tennessee, Iowa and Indiana – have adopted similar laws in recent years. They all share a striking resemblance to model legislation proposed by the American Legislative Exchange Council, a conservative think tank that receives funding from oil and gas corporations. Similar bills are pending in some states such as Ohio and Idaho. One recently failed in Illinois. In a statement, Jennifer Falcon, a campaign manager for the Society of Native Nations, said the Texas law “is a fear tactic to dissuade environmental justice movements like Standing Rock from challenging the continued use of fossil fuels.”“We are at a tipping point as our ecosystems decline at accelerated rates and instead of protecting our environment, we are protecting big oil and pipelines,” she said. When the bill was first introduced in the House in March, penalties for protesting included a second-degree felony with a jail term of up to 20 years. But when the bill reached the Senate, an amendment filed by State Senator Juan Hinojosa downgraded the penalties for interfering with pipeline operations from a third-degree felony to a misdemeanor punishable by up to a year in prison. Lawmakers from both chambers then met in conference to reconcile the differences and landed on a version that was harsher than the one passed in the Senate.

Permian Oil Output Set to Keep Growing – The U.S. Energy Information Administration (EIA) has forecasted that Permian oil production will hit 4.226 million barrels per day (MMbpd) next month in its latest drilling productivity report. This marks the first time the EIA has projected oil output in the region to surpass the 4.2MMbpd mark in a drilling productivity report. Permian oil production in June was forecasted to come in at 4.171MMbpd in the EIA’s latest report. Back in May, the EIA anticipated that Permian oil output would be 4.173MMbpd in June. The EIA’s monthly drilling productivity report focuses on the Anadarko, Appalachia, Bakken, Eagle Ford, Haynesville, Niobrara and Permian regions. According to the EIA’s latest report, the Permian is set to see the largest oil output increase from June to July. Permian oil production has more than quadrupled in the last decade, according to EIA data, which indicates that oil output from the region stood at less than 1MMbpd in 2010. According to the EIA, the organization’s drilling productivity report uses recent data on the total number of drilling rigs in operation, along with estimates of drilling productivity and estimated changes in production from existing oil and natural gas wells, to provide estimated changes in oil and natural gas production. The EIA is the statistical and analytical agency within the U.S. Department of Energy. It collects, analyzes, and disseminates independent and impartial energy information to promote sound policymaking, efficient markets and public understanding of energy and its interaction with the economy and the environment, according to the EIA’s website.

US oil, gas rig count drops 13 to 1040 on week: S&P Global Platts Analytics – The US oil and gas rig count dropped 13 to 1,040 week on week, S&P Global Platts Analytics said Thursday, continuing a seesaw behavior that has characterized domestic unconventional activity since oil prices plummeted late last year. Oil-directed activity was the was the hardest hit, down 10 rigs to 832, while gas rigs slid by two to 204. Also, a one-rig decline was seen for rigs not classified as oil or gas, Platts Analytics data showed.In the US’ largest plays, the Permian Basin of West Texas/New Mexico posted the week’s biggest loss — down 14 rigs to 434. All other basins either remained steady or were up or down a rig or two each versus last week. “The rig count continues to grind lower as the horizontal rig count is back to March 2018 levels,” investment bank Evercore ISI said in its annual Mid-Year Spending Outlook last week. “While the declines are shallower than earlier in the year, we are already in June and the rig count has not been able to find a bottom yet.” Click here for full-size graphic “In general, it has been a challenging year for North America, which we best characterize as grinding along,” the bank said. The rig count hit a recent peak in mid-November of 1,233, according to Platts Analytics data, but has since slid. Since February has stayed below 1,100. In recent weeks it has swung between modest gains and losses each week, generally trending south. This month the rig count has reversed course every week, falling 12 the first week, up four the next week, and now down 13. “We’re forecasting the rig count to increase in the Permian, but the remainder of the top oil plays are set to remain flat to declining the rest of the year,” Platts Analytics analyst Taylor Cavey said. In other named basins, rig counts in the Eagle Ford Shale in South Texas, Haynesville Shale in East Texas/Northwest Louisiana, the Wet Marcellus largely in Pennsylvania, and Utica Shale mostly in Ohio stayed the same this week versus last week. Rigs in the Eagle Ford totaled 85; in the Haynesville, 58; in the Wet Marcellus, 22; and in the Utica, 19. In addition, the Williston Basin in North Dakota/Montana rose two rigs to 62, while the Denver-Julesburg basin in Colorado and SCOOP-STACK play in Oklahoma each rose one rig to total 32 and 81, respectively. But the Dry Marcellus, also largely in Pennsylvania, fell by one rig, leaving 29. And the “Other Basins” category, containing rigs outside the other eight named areas, fell by two rigs to 218.

Why The Oklahoma Shale Boom Isn’t Taking Off – Just three years ago it was the new hot spot in U.S. shale, the “Permian Jr.”, and the place where many pinned their hopes for the next oil boom. Now, oil and gas companies are curbing their operations in the STACK/SCOOP plays in Oklahoma, some are selling, and there is little evidence of the enthusiasm from three years ago.The low cost of production and high yields were among the factors that drove the rush to the STACK (Sooner Trend, Anadarko, Canadian, and Kingfisher) and SCOOP (South Central Oklahoma Oil Province) plays. Devon, Continental, and Marathon Oil were among the biggest players present there with the most ambitious plans. Now, Devon has cut its capex for the STACK/SCOOP area, and Continental and Marathon Oil have limited their operations to producing wells only with no exploration in their immediate plans, Reuters’ David French writes. The rock formations have turned out to be a lot more complex than those in the Permian, making productive drilling a lot more challenging in some parts of the STACK/SCOOP.. “As it’s so complex, the hydrocarbon mix changes across the play, and the oil window is limited.”It seems there is a lot more gas than some oil drillers expected in the STACK/SCOOP and times are not too good for investing more in gas: the U.S. market is pretty well supplied and prices are low as the LNG boom has not yet taken off in full, providing an outlet for all the gas produced. Another problem, Reuters’ French notes is the so-called “parent/child” well problem: when secondary wells produce less oil and gas than the primary ones. In light of this problem, it’s no wonder production prices are higher: the average breakeven in the STACK and the SCOOP formations since the start of 2018 has been US$53.15 for the STACK and US$54.53 for the SCOOP. To compare, last year, breakeven prices for horizontal wells of between 4,500 and 10,500 ft in the Permian ranged between US$48 and as little as US$21 per barrel, according toGlobalData.

Is Bakken Oil Production Set For An Unexpected Drop? – North Dakota set an oil production record in January this year, and crude output in the state home to the Bakken shale play held close to that record level in the three months that followed. But is this sustainable in the current oil price environment? The recent oil price slide in May and June is clouding the outlook for oil drillers in North Dakota, who are additionally challenged by diminishing available pipeline takeaway capacity to ship their oil and natural gas to markets. North Dakota’s crude currently trades at around US$40 a barrel, dangerously close to the breakeven price for new wells, according to Lynn Helms, Director at North Dakota’s Department of Mineral Resources. North Dakota’s Bakken play is expected to keep robust output and stable rig count going forward, but production would depend on the price of oil, infrastructure constraints, and workforce availability, Helms said in a press release last week, discussing the April production and future prospects. North Dakota’s oil production in April was 1.3911million bpd, essentially flat on the March output of 1.3917 million bpd, and slightly off the all-time high production of 1.4038 million bpd reached in January this year, data from the Department of Mineral Resources showed. A total of 96 percent of North Dakota’s crude oil production for April came from the Bakken and Three Forks formations, while just 4 percent came from legacy conventional pools. The Energy Information Administration (EIA) predicted in its latest Drilling Productivity Report that Bakken oil production will rise by 11,000 bpd in July from an expected production of 1.428 million bpd in June. In recent months, North Dakota’s rig count has become very stable in the mid-60s, the Department of Mineral Resources’ Helms says, noting that “Operators have shifted from running the minimum number of rigs to incremental increases and decreases based on gas capture, completion crew availability, and oil price. Current operator plans are to hold the rig count steady or perhaps 2-5 fewer rigs second half of 2019 depending on oil price, workforce, and infrastructure constraints.” The drilling rig count continues to be limited by the price of oil, gas capture, workforce, and competition for capital from the Permian and Anadarko basins, according to Helms. Yet, operators continue to keep a drilling permit inventory that will accommodate varying oil prices for the next twelve months, he said. Infrastructure constraints, however, could limit the drilling activity in North Dakota going forward. The pipeline shortage in the Bakken weighs particularly heavily on natural gas.

Dakota Access Pipeline operator plans large capacity expansion – The operator of the Dakota Access Pipeline is planning to nearly double its capacity, to a point where it could transport nearly all of the daily oil production of the nation’s No. 2 producer. The plans include new pumping stations in three states. Energy Transfer Partners informed North Dakota regulators that it plans to expand the pipeline capacity from more than 500,000 barrels per day to as much as 1.1 million barrels. An increase “will allow Dakota Access to meet the growing demand from shippers by optimizing and fully utilizing the existing pipeline infrastructure, without the need to install new pipelines, and without the need for shippers to use less safe and efficient means of transportation, such as rail,” Energy Transfer attorney Lawrence Bender said in a letter to the Public Service Commission dated Wednesday.North Dakota produced 1.39 million barrels of oil per day in April. The record was 1.4 million barrels per day in January. The $3.8 billion pipeline takes oil from the Bakken through South Dakota and Iowa to a connection with the Energy Transfer Crude Oil Pipeline, which transports oil from Illinois to Nederland, Texas. It began operating in June 2017 after years of construction marred by large-scale and prolonged protests in North Dakota by opponents. Energy Transfer Partners CEO Kelcy Warren said last August in Bismarck that the company was working to expand the pipeline’s capacity. At the time, it was carrying about 500,000 barrels per day. It’s now carrying 570,000 barrels daily, according to Energy Transfer spokeswoman Lisa Dillinger. Conditions of the permit through the North Dakota Public Service Commission allow Dakota Access to ship up to 600,000 barrels per day in North Dakota. Companies can expand the capacity of a pipeline by adding additional pumping horsepower or using drag-reducing agents that allow more oil to flow. Energy Transfer plans to use additional horsepower. .

More than 8,400 gallons of oil and gas by-product spilled in Stark County – A pipeline in Stark County, operated by Scout Energy Management, LLC., suffered a leak on Monday, June 17, resulting in more than 8,400 gallons of oil and gas by-product being spilled near the Interstate 94 on-ramp at mile marker 57 near Dickinson. The North Dakota Department of Environmental Quality was notified of the spill and have been on site to monitor the investigation since receiving the report. “In that volume it’s always a little bit of a concern, but due to its location and incident type we wouldn’t say this event is at the top of the list,” Brian O’Gorman, spill investigation program member with the NDDEQ, said about the significance of the incident. “It’s something that is manageable and they should be able to handle the cleanup pretty easily.” According to O’Gorman, initial estimates by the NDDEQ indicate that the produced water impacted a small drainageway on private property and that Scout Energy Management has contained the spill in the drainageway and have recovered approximately 200 barrels of produced water. “The information that I have is that they put up diking in the drainageway and even if it rains that diking should be able to hold it there,” O’Gorman said. “They’re bringing in vac-trucks and are vacuuming that out and disposing of that water. They dug holes so they could get the vac-truck hoses in there and basically remove any water that’s coming into that area.” O’Gorman was unable to provide a status of the cleanup, but did say that Scout Energy is assessing it and will determine what they will do with the produced water.Speaking to the public health concern, O’Gorman said that the threat was minimal. “Until we get the full assessment of what all occurred, it’s really hard to tell if there is any danger to the public on that part of it,” he said. “Unless the public venture onto the private property and roll around in it, and I’m not trying to be funny, there’s probably not going to be any health concerns associated with this spill.”

North Dakota: Feds should stop Washington state’s rail rules (AP) – North Dakota plans to ask the Trump administration to intervene in a dispute over Washington state’s new safety restrictions on oil shipped by rail. Attorney General Wayne Stenehjem told The Bismarck Tribune he plans to petition the Pipeline and Hazardous Materials Safety Administration to tell Washington state that it doesn’t have the authority to require crude shipped by rail through Washington to have more of its volatile gases removed than North Dakota requires. Washington passed the requirement to reduce the chances of massive explosions during derailments. North Dakota officials say the Washington state requirement essentially bans crude-by-rail traffic to refineries throughout the Pacific Northwest and is a potential blow to North Dakota’s energy industry. Stenehjem’s office is also working on a federal lawsuit against Washington alleging that the requirement violates interstate commerce law. Tara Lee, a spokeswoman for Washington Gov. Jay Inslee, says the issue should be settled in court, “not via press release.”

US gasoline demand reaches record high: EIA – US gasoline demand reached a record high last week, US Energy Information Administration data showed Wednesday. In the week ended June 14, implied US gasoline demand — which the EIA measures as product supplied — reached 9.928 million b/d, the highest that figure has ever been in data going as far back as February 1991. The prior record was set in the week ended August 24, 2018, when product supplied reached 9.899 million b/d. US gasoline demand has found support from weaker retail pump prices in June, which have helped encourage drivers to spend more time in their cars and trucks. The EIA says that the average US gasoline pump price fell 6.2 cents/gal from June 10 to June 17. With the national average price now at $2.67/gal, the EIA says pump prices are now 20.9 cents/gal below their levels from one year ago. Andy Lipow, president of Lipow Oil Associates, said weaker prices for crude oil and gasoline are important for explaining stronger US demand and added that the expanding US economy is another key factor. “Economic growth is steady and US unemployment is very low,” he said. Lipow also said it is important to take the weekly EIA implied demand data with a grain of salt. “I have seen the weekly demand statistic fluctuate 10% or more from week to week,” he said. “So I am waiting to see this elevated demand continue in the data for the coming weeks before drawing any conclusions.” After the release of Wednesday’s EIA data, the USGC gasoline cash market rallied higher.

U.S. shale oil output to rise to record 8.52 million barrels per day in July: EIA – The largest change is forecast in the Permian Basin of Texas and New Mexico, where output is expected to climb by 55,000 bpd to a fresh peak at 4.23 million bpd in July. Production in North Dakota and Montana’s Bakken shale basin is also expected to climb by 11,000 bpd to a record 1.44 million bpd, the data showed. Output from the nearby Niobrara basin is expected to rise by 10,000 bpd to a record high of nearly 730,000 bpd. A shale revolution and production increases particularly from the Permian basin and the Bakken have helped make the United States the biggest crude oil producer in the world, ahead of Saudi Arabia and Russia. However, the EIA has revised lower its total U.S. crude oil production growth forecast. It said last week in a monthly report that output will rise 1.36 million bpd to 12.32 million bpd in 2019, 140,000 bpd less than previously forecast. That will top the current all-time high of 10.96 million bpd set in 2018. The rig count, an early indicator of future output, has declined over the past six months as independent exploration and production companies cut spending on new drilling as they focus more on earnings growth instead of increased output. More than half the total U.S. oil rigs are in the Permian basin, the biggest U.S. shale oil play, where active units decreased by five last week to 441, the lowest since March 2018, according to data from General Electric Co’s Baker Hughes energy services firm. The EIA said in Monday’s report that producers drilled 1,318 oil and gas wells, the least since April 2018, and completed 1,395 in the biggest shale basins in May, leaving total drilled but uncompleted wells down 77 at 8,283, according to data going back to December 2013. That was the biggest decline in drilled but uncompleted wells since March 2018 when they fell by 107. Separately, U.S. natural gas output was projected to increase to a record 81.4 billion cubic feet per day (bcfd) in July, the EIA said.

US oil imports from OPEC plunge to 30-year lows. China’s are surging – CNN – America’s long-addiction to oil from OPEC is fading — even as China’s own reliance on the cartel’s crude has soared. US oil imports from OPEC plunged to a 30-year low in March, according to a report published on Thursday by the US Energy Information Administration. The imports, totaling 1.5 million barrels per day, have tumbled by about 75% over the past decade.The declines have been driven by three major factors:blockbuster American oil production, tough US sanctions on Venezuela and Saudi Arabia’s sharp supply cuts.”The broader trend reflects the US shale revolution and Arabian Gulf producers’ desire to shift sales to fast-growing Asian markets,” Bob McNally, president of consulting firm Rapidan Energy Group, said in an email.The United States has long sought to reduce its dependency on foreign oil. Many Americans still recall the long lines at gas stations and skyrocketing prices caused by the OPEC oil embargo in the early 1970s.The news comes as the world’s attention has refocused on the Strait of Hormuz, the critical chokepoint carrying oil produced by Gulf nations to the rest of the world. A pair of tankers were attacked on Thursday near the Strait of Hormuz, briefly sending oil prices rallying. “We’ve reduced our dependency, but we haven’t completely eliminated it,” said Ryan Fitzmaurice, energy strategist at Rabobank. On the other hand, China’s exposure to OPEC has never been higher. The world’s No. 2 economy has imported a record amount of oil from OPEC, according to S&P Global Platts. The cartel has been happy to shift sales to China and other fast-growing Asian economies. China’s oil demand jumped by 3% in 2018, doubling the world’s increase, according to an OPEC report released on Thursday. And it’s expected to rise nearly as much this year, despite the trade tensions and increased usage of electric vehicles.

Energy minister says ‘responsible’ fracking will help transition to green economy – New Brunswick’s minister of energy and resource development suggested the government’s passing of regulatory changes that would allow a partial lifting of the moratorium on fracking is a “responsible” path toward facilitating a transition to a greener economy.Mike Holland said the decision is not irresponsible “if it’s going to be done in a way that gets us to where we need to go and it’s part of an overall plan that is solid toward to the reduction of overall emissions.”The Higgs government quietly passed regulatory changes in May to allow shale gas development to resume in the Sussex area. Holland said the government is putting steps in place to responsibly lift the moratorium in the area.

Canada set to approve hotly-debated pipeline expansion, Trudeau unlikely to benefit (Reuters) – Canada looks set to approve a hotly-debated plan to expand an oil pipeline this week, people familiar with the process told Reuters, but the move is unlikely to help Prime Minister Justin Trudeau rebuild flagging support ahead of an October election. The Liberal government last year took the unprecedented step of buying the Trans Mountain pipeline from Kinder Morgan Canada for C$4.5 billion ($3.4 billion) to ensure the expansion went ahead to help solve crude transportation bottlenecks. If completed, the expansion would nearly triple capacity on the pipeline that runs from the western crude-rich province of Alberta to British Columbia’s Pacific coast. But it has faced increasing protests from environmental activists and aboriginal groups. Trudeau – who came to power promising to improve Canada’s environmental record – faces a difficult decision. If he approves it, he could anger environmentalists and local residents who fear the impact of the project. If he rejects it, he risks further alienating an energy lobby that has accused him of wanting to wreck their industry as he has pressed ahead with plans to strengthen the environmental assessments of major new energy projects at a time of low prices. Two federal government insiders with knowledge of the situation said there was little doubt Ottawa would give the green light.

Canada approves contentious oil pipeline expansion, expects legal challenges – (Reuters) – Canada on Tuesday approved as expected a hotly contested proposal to expand the western Canadian crude oil pipeline it bought last year, providing hope for a depressed energy industry but angering environmental groups. Construction on the expansion of the Trans Mountain pipeline is scheduled to resume this year, Prime Minister Justin Trudeau told a news conference. A senior government official, speaking on condition of anonymity, said earlier that Ottawa expected legal challenges to the approval. The project would triple Trans Mountain’s capacity to carry 890,000 barrels per day from Alberta’s oil sands to British Columbia’s Pacific coast, alleviate congestion on existing pipelines and diversify exports away from the United States. Trudeau, who faces a tough fight in a national election scheduled for October, has been under pressure both from western Canadian politicians who accuse him of doing too little for the oil industry, and from environmental groups, which see the oil sands as a highly polluting source of crude production. “This isn’t an either/or proposition. It is in Canada’s national interest to protect our environment and invest in tomorrow, while making sure people can feed their families today,” he said, adding he knew some people would be disappointed. The Liberal government previously approved the expansion in 2016 but that decision was overturned last year after a court ruled the government had not adequately consulted indigenous groups.

Canada Approves Job Creating TMX Project – The Government of Canada has approved the Trans Mountain Expansion project. The Government of Canada has approved the Trans Mountain Expansion (TMX) project, which will twin the existing Trans Mountain oil pipeline and expand the Westridge Marine Terminal in Burnaby, British Columbia. The project will create thousands of jobs, enable increased production from western producers and generate approximately $12 billion in additional crude oil sales each year, according to the Canadian government. The TMX project will also benefit indigenous communities and groups and the clean economy, the government notes. “We have a responsibility to ensure that the decisions we make today move us toward a cleaner, sustainable economy,” Canadian Prime Minister Justin Trudeau said in a government statement. “Major resource projects can move forward, but only if we do so in a way that protects the environment and respects indigenous rights,” he added. “The TMX project is a significant investment in Canadians and in Canada’s future that will create thousands of good, middle class jobs, maintain the highest environmental standards and fund the clean energy solutions that Canada needs to stay competitive on the global stage,” Trudeau continued. In August 2018, a decision by the Federal Court of Appeal quashed the government’s original approval of the project and provided it with guidance on how it could move forward with the development. This included reconsidering project-related environmental effects and engaging in new consultations with indigenous groups.

On Monday, Canada declared a ‘climate emergency.’ On Tuesday, it approved a pipeline expansion. Canadian Prime Minister Justin Trudeau is an icon of progressive politics who has promised to “put a price on pollution.” Last week, to much applause, he proposed a ban on single-use plastics. On Monday night, his government declared a national “climate emergency.” He is also now the public face of a Canadian plan to expand a pipeline that would triple the amount of crude oil that moves from the Alberta tar sands to the Pacific Coast for shipment around the world. Such is his dilemma – and Canada’s. Trudeau’s Liberal government announced Tuesday it will push ahead with the stalled Trans Mountain Pipeline expansion, $5.5 billion project that has long pitted the country’s energy sector against the concerns of environmental and some indigenous groups. Trudeau, announcing the decision at a news conference in Ottawa, pledged that every dollar earned from the pipeline will be used to fund projects to power Canada’s transition to clean energy.“We need to create wealth today so we can invest in the future,” he said. “We need resources to invest in Canadians so they can take advantage of the opportunities generated by a rapidly changing economy, here at home and around the world.” The move will be welcomed by the country’s struggling oil sector and the many Canadians whose fortunes are tied to it. Landlocked Alberta produces four-fifths of Canadian crude but struggles to get it abroad, and so must settle for selling at steep discounts against global benchmarks – hitting the province hard. But many Canadians have protested the expansion proposal out of concern for oil spills and the continuing promotion of climate-changing fossil fuels. They question whether this is the moment to increase Canadian shipments of oil.

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