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

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 25 January 2020.

This article is a feature every Monday evening on GEI.

Please share this article – Go to very top of page, right hand side, for social media buttons.

Gasoline supplies at a record high; natural gas rigs at a 38 mo low; fracking at a 22 mo low; DUC well backlog is 7 months

Oil prices fell by the most since May on pandemic fears; natural gas prices end at another life of contract low; gasoline supplies rise to a record high; natural gas rigs fall to a 38 month low; fracking falls to a 22 month low; the DUC well backlog is 7 months..

Oil prices fell each day over past week and hence finished lower for a third straight week as the outbreak of a deadly new virus in China led to the lockdown of a city of 11 million people and the cancellation of Chinese New Year festivities, thereby depressing financial markets worldwide…after falling less than 1% to $58.54 a barrel last week on signs of oil oversupply and weak global demand, the benchmark price of US light sweet crude for February delivery opened more than 1% higher on Tuesday after the holiday after two large oilfields in Libya were shut down by rebel forces loyal to CIA backed General Haftar, but pared those gains in early trading as a new virus in China raised fears of an economic slowdown and sent oil prices back down to close 20 cents lower at $58.34 a barrel in the last day of trading for the February oil contract…thereafter quoting prices for the benchmark March US crude contract, which had finished Tuesday at $58.38, oil fell nearly 3% on Wednesday as the International Energy Agency (IEA) forecast an oil surplus while concerns over a potential epidemic depressed the demand outlook and prices settled $1.64 lower at $56.74 per barrel….oil prices opened lower and tumbled to as low as $54.77 a barrel early Thursday after the API reported large crude and product supply increases, but bounced off the lows after the EIA reported a small crude draw, but still ended $1.15, or 2% lower at $55.59 a barrel, the lowest price since Nov 29, on deepening fears that the coronavirus outbreak in China would have a severe impact on oil demand…U.S. crude prices then fell another 2.5%, or $1.40, on Friday to settle at $54.19, after hitting $53.85, the lowest price since Oct. 31, on concern that the Chinese virus would spread, curbing travel and global oil demand…thus, after fourth straight days of losses, the March oil contract finished 7.4% lower on the week in logging the largest one week decline since May…

Natural gas prices also finished lower this week as technical selling and bearish weather forecasts beat down prices….after ending last week 9% lower at a life of contract low of $2.003 per mmBTU on a bearish weather outlook and the EIA’s forecasts of lower demand, the price of natural gas for February delivery fell almost another 9% early Tuesday as a pile of $2 stop loss orders had been triggered over the holiday weekend, sending prices cratering, with prices partially recovering late Tuesday to close 10.8 cents lower, still down more than 5%, at $1.895 per mmBTU…gas prices then rebounded a penny on Wednesday and by 2.1 cents on Thursday, getting a boost “from short-term cold weather and snow” in parts of the U.S. as the natural gas storage report showed inventories fell a bit more than was forecast…but that was not enough to hold prices steady even at these depressed levels, as “dramatically bearish weather” continued to beat down natural gas prices on Friday, as they fell 3.3 cents more to close at $1.895 per mmBTU, thus finishing the week 5.5% lower, at yet another life of contract low…

The natural gas storage report on the week ending January 17th from the EIA indicated that the quantity of natural gas held in storage in the US fell by 92 billion cubic feet to 2,947 billion cubic feet by the end of the week, which left our gas supplies 554 billion cubic feet, or 23.2% higher than the 2,393 billion cubic feet that were in storage on January 17th of last year, and 251 billion cubic feet, or 9.3% above the five-year average of 2,696 billion cubic feet of natural gas that has been in storage as of the 17th of January in recent years….the 92 billion cubic feet that were withdrawn from US natural gas storage this week was a bit more than the average forecast for a 88 billion cubic feet withdrawal by analysts surveyed by S&P Global Platts, but it was much less than the 152 billion cubic feet withdrawal reported during the corresponding week of last year, and less than half of the average 194 billion cubic feet of natural gas that have been pulled from natural gas storage during the second full week of January over the past 5 years….

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending January 17th showed that with little change in the week’s supply and demand factors, we again needed to pull oil out of our stored commercial supplies, in this case for the eighth time in the past nineteen weeks….our imports of crude oil fell by an average of 120,000 barrels per day to an average of 6,730,000 barrels per day, after falling by an average of 179,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 67,000 barrels per day to 3,414,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,018,000 barrels of per day during the week ending January 17th, 53,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was unchanged at 13,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 16,018,000 barrels per day during this reporting week..

US oil refineries reported they were processing 16,857,000 barrels of crude per day during the week ending January 17th, 116,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that an average of 58,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….hence, we can see that 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 782,000 barrels per day less than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+782,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…however, since the media treats these figures as gospel and since they drive oil pricing and hence decisions to drill for oil, we’ll continue to report them, just as they’re watched & believed as accurate by most everyone else (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 slipped to an average of 6,516,000 barrels per day last week, now 15.8% less than the 7,739,000 barrel per day average that we were importing over the same four-week period last year….the 58,000 barrel per day net withdrawal from our total crude inventories was all pulled from our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve was unchanged….this week’s crude oil production was reported to be unchanged at a record 13,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at a record 12,500,000 barrels per day, while a 4,000 barrels per day increase to 484,000 barrels per day in oil production from Alaska still added the same rounded 500,000 barrels per day to the rounded national total….last year’s US crude oil production for the week ending January 18th was rounded to 11,900,000 barrels per day, so this reporting week’s rounded oil production figure was 9.2% above that of a year ago, and 54.2% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 90.5% of their capacity in using 16,857,000 barrels of crude per day during the week ending January 17th, down from 92.2% of capacity the prior week, and a bit below the recent average refinery capacity utilization for the second full week of January…as a result, the 16,857,000 barrels per day of oil that were refined this week were 1.1% below the 17,049,000 barrels of crude that were being processed daily during the week ending January 18th, 2019, when US refineries were operating at 92.9% of capacity….

Even with the modest decrease in the amount of oil being refined, gasoline output from our refineries was still higher, increasing by 254,000 barrels per day to 9,535,000 barrels per day during the week ending January 17th, after our refineries’ gasoline output had increased by 394,000 barrels per day over the prior week…but even after this week’s increase in gasoline output, our gasoline production was still 0.7% lower than the 9,604,000 barrels of gasoline that were being produced daily over the same week of last year….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 251,000 barrels per day to 4,954,000 barrels per day, after our distillates output had decreased by 105,000 barrels per day over the prior week…after this week’s decrease in distillates output, our distillates’ production for the week was 9.0% below the 5,444,000 barrels of distillates per day that were being produced during the week ending January 18th, 2018….

With the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the eleventh week in a row and for the 17th time in 31 weeks, rising by 1,745,000 barrels to an all time high of 260,032,000 barrels during the week ending January 17th, after our gasoline supplies had increased by 6,678,000 barrels over the prior week….our gasoline supplies increased by less this week because the amount of gasoline supplied to US markets increased by 104,000 barrels per day to 8,662,000 barrels per day, and because our exports of gasoline rose by 201,000 barrels per day to 809,000 barrels per day, while our imports of gasoline rose by 120,000 barrels per day to 563,000 barrels per day….after this week’s smaller than seasonal increase, our gasoline supplies were just fractionally higher than last January 18th’s record gasoline inventory level of 259,615,000 barrels, and slipped to roughly 4% above the five year average of our gasoline supplies for this time of the year, which historically has been the annual peak…

With the decrease in our distillates production, our supplies of distillate fuels decreased for the 11th time in 17 weeks and for 26th time in the past 42 weeks, falling by 1,185,000 barrels to 146,036,000 barrels during the week ending January 17th, after our distillates supplies had increased by 8,171,000 barrels over the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 1,204,000 barrels per day to 4,389,000 barrels per day, while our exports of distillates fell by 1,000 barrels per day to 1,054,000 barrels per day, and while our imports of distillates rose by 118,000 barrels per day to 320,000 barrels per day….even after this week’s decrease, our distillate supplies were 2.6% more than the 142,392,000 barrels of distillates that we had stored on January 18th, 2018, but still about 2% below the five year average of distillates stocks for this time of the year…

Finally, with refinery oil demand continuing to exceed the supply from imports and production, our commercial supplies of crude oil in storage fell for the seventeenth time in thirty-one weeks and for the twenty-second time in 52 weeks, decreasing by 405,000 barrels, from 428,511,000 barrels on January 10th to 428,106,000 barrels on January 17th…after that decrease, our crude oil inventories fell to 2% below the five-year average of crude oil supplies for this time of year, but were still more than 34.8% higher than the prior 5 year (2009 – 2013) average of crude oil stocks after the second full week of January, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels….even though our crude oil inventories had generally been rising over the past year, except for during the past summer, after generally falling until then through most of the prior year and a half, our oil supplies as of January 17th were 3.8% below the 445,025,000 barrels of oil we had stored on January 18th of 2018, but were 4.0% above the 411,583,000 barrels of oil that we had in storage on January 19th of 2017, while at the same time fell to 12.3% below the 488,296,000 barrels of oil we had in commercial storage on January 20th of 2016…

This Week’s Rig Count

The US rig count decreased for the 19th time in the past 23 weeks during the week ending January 24th, and is now down by more than 26.7% from the last rig count of 2018…Baker Hughes reported that the total count of rotary rigs running in the US decreased by 2 rigs to 794 rigs this past week, which was also down by 265 rigs from the 1059 rigs that were in use as of the January 25th report of 2019, and 1,135 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business…

However, the number of rigs drilling for oil increased by 3 rigs to 676 oil rigs this week, which was still 186 fewer oil rigs than were running a year ago, and much less than 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 five to 115 natural gas rigs, the fewest natural gas rigs deployed since November 11th 2016, and hence a 38 month low for natural gas drilling, down by 82 gas rigs from the 197 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to the rigs drilling for oil & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Washoe County, Nevada, and one in Lake County, California, compared to a year ago, when there were no such “miscellaneous” rigs deployed..

Offshore drilling activity in the Gulf of Mexico increased by one rig to 21 rigs this week, as a new rig began drilling offshore from Louisiana…the 20 rigs now drilling in Louisiana waters plus the one that was drilling offshore from Texas was one more than the Gulf of Mexico rig count of 20 rigs during the same week of a year ago, when 20 rigs were drilling offshore from Louisiana and none were operating in Texas waters…since there are no rigs deployed off other US shores elsewhere at this time, nor were there a year ago, the current Gulf of Mexico rig count as well as that of last year is the same as the national total in both cases..

The count of active horizontal drilling rigs was up by 1 rig to 710 horizontal rigs this week, the highest horizontal rig count since November 8th, but still 222 fewer horizontal rigs than the 932 horizontal rigs that were in use in the US on January 25th 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 up by 3 rigs to 47 directional rigs this week, but those were still down by 12 from the 59 directional rigs that were operating during the same week of last year….on the other hand, the vertical rig count was down by 6 rigs to 38 vertical rigs this week, and those were down by 31 from the 68 vertical rigs that were in use on January 25th of 2019…

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of January 24th, the second column shows the change in the number of working rigs between last week’s count (January 17th) and this week’s (January 24th) count, the third column shows last week’s January 17th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 25th of January, 2019…

Checking the Texas district details to find where the two rig increase in the Permian basin might have come from, we find that one rig was pulled out of Texas Oil District 8, or the core Permian Delaware this week, while another rig was pulled out of Texas Oil District 7B, an area often shown as east of the Permian but a district which nonetheless has accounted for Permian rig additions in recent weeks…hence, if both of those rigs had been targeting the Permian, then all of the rigs added in New Mexico must have been new Permian rigs, which would be drilling in the far western reaches of the Permian Delaware…elsewhere, the two rig decrease in Wyoming doesn’t match any of our basin counts, so it’s possible that those were conventional rigs pulled out of one of the productive Wyoming basins, such as the Powder River or Salt Creek …meanwhile, the drop of 5 natural gas rigs includes two from the Haynesville, one from West Virginia’s Marcellus, one from the Eagle Ford, and two from basins not tracked separately by Baker Hughes, while a natural gas rig was added in Ohio’s Utica shale at the same time…in the Eagle Ford of south Texas, the gas rig decrease was offset by the addition of one rig targeting oil, leaving the basin with two rigs targeting gas and 67 rigs targeting oil, while the Haynesville decrease could have been the two rigs pulled out of Texas Oil District 6, or one of those plus the rig that was pulled out of northern Louisiana…the Texas Oil District 6 rig count plus the northern Louisiana rig count now adds up to 44 rigs, so all but one of those are targeting the Haynesville shale..

DUC well report for December

Tuesday of this past week saw the release of the EIA’s Drilling Productivity Report for January, which includes the EIA’s December data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions…for the tenth month in a row, this report showed a decrease in uncompleted wells nationally in December, as both drilling of new wells and completions of drilled wells decreased…..for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 50 wells, falling from a revised 7,623 DUC wells in November to 7,573 DUC wells in December, which now represents 6.0% fewer DUCs than the 8,055 wells that had been drilled but remained uncompleted as of the end of December of a year ago…this month’s DUC decrease occurred as 1,036 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during December, down by 33 from the 1,069 wells that were drilled in November and the lowest number of wells drilled since June 2017, while 1,086 wells were completed and brought into production by fracking, a decrease of 115 well completions from the 1,201 completions seen in November and the least completions since February 2018….at the December completion rate, the 7,573 drilled but uncompleted wells left at the end of the month now represents a 7.0 month backlog of wells that have been drilled but are not yet fracked, up from the 6.3 month backlog of a month ago, as the backlog rate is now rising due to falling completions…

Both oil producing and natural gas producing regions saw DUC well decreases in December, even as four of the seven major basins saw small DUC increases…the number of DUC wells remaining in the Oklahoma Anadarko decreased by 54, falling from 686 at the end of November to 632 DUC wells at the end of December, as 58 wells were drilled into the Anadarko basin during November while 112 Anadarko wells were being fracked….at the same time, DUC wells in the Eagle Ford of south Texas decreased by 15, from 1,442 DUC wells at the end of November to 1,427 DUCs at the end of December, as 150 wells were drilled in the Eagle Ford during November, while 165 already drilled Eagle Ford wells were completed….on the other hand, DUC wells in the Bakken of North Dakota increased by 18, from 795 DUC wells at the end of November to 813 DUCs at the end of December, as 100 wells were drilled into the Bakken in December, while 82 of the drilled wells in that basin were being fracked…in addition, the Permian basin of west Texas and New Mexico saw its total count of uncompleted wells rise by 14, from 3,598 DUC wells at the end of November to 3,612 DUCs at the end of December, as 452 new wells were drilled into the Permian, while 438 wells in the region were being fracked….meanwhile, the drilled but uncompleted well count in the Niobrara chalk of the Rockies’ front range increased by 2 to 448, as 151 Niobrara wells were drilled in December while 149 Niobrara wells 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 21 wells, from 448 DUCs at the end of November to 427 DUCs at the end of December, as 81 wells were drilled into the Marcellus and Utica shales during the month, while 102 of the already drilled wells in the region were fracked….however, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 6 wells to 214, as 44 wells were drilled into the Haynesville during December, while 38 Haynesville wells were fracked during the same period….thus, for the month of December, DUCs in the five major oil-producing basins tracked by in this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a net of 35 wells to 6,932 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 15 wells to 641 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas…

State works to draft 10-year forestry plan to include climate change, fracking – The Columbus Dispatch –The Ohio Division of Forestry is in the process of putting together a 10-year plan for the state’s forests. Ohioans can expect some changes. The deadline is March 1 to comment. Ten years ago, most southeastern Ohio landowners had no fracking well pads on their property. Most people had heard of climate change, but it wasn’t built into the social consciousness at the level it is now, As Ohio’s forestry officials prepare to draft a 10-year plan for the state’s forests, those are the kinds of topics that will have to be addressed in more detail. “We do have more information now, and (climate change) will certainly be included in the plan,” said Tom Macy, a forest health program administrator for the Ohio Department of Natural Resources. The 10-year plans only date back to 2010, when they were created through the 2008 Farm Bill as a requirement for state funding through the Cooperative Forestry Assistance Act. “We have a mandate from the U.S. Forest Service to involve other stakeholders,” Macy said.Ohio has 7.9 million acres of forestland. Of that, 85% is privately owned, with the remaining 15% owned by local, state and federal government.“We are facing a climate and biodiversity crisis globally. Our state foresters need to put protections and rejuvenation of existing forest habitats at the forefront of their oversight,” said Loraine McCosker, who volunteers with the Sierra Club and plans to attend one of the state meetings in Athens. “We need forests for clean air, clean water, carbon sequestration, biological diversity, (and) human physical and mental health.”Foresters will have to examine how native tree species will survive in a changing climate and what pests could be moving into Ohio.“We need a new, more science-based trajectory for the state,” McCosker said.The state’s oil and gas commission could convene and sign off on fracking on state-owned land. “Obviously, the impacts of the oil and gas industry in Ohio affect forests. … That’s still a portion of the plan that I want to collect more data on,” Macy said. Ohioans have until March 1 to submit input about the plan, and they have the option of attending upcoming meetings. Macy said a draft of the plan should be completed in time for the first public meeting.

Ohio Valley Residents Respond to Oil And Gas Documentary – — The Ohio Valley citizens group, Concerned Ohio River Residents, made the educational documentary prerelease screening of “The Story of Plastic” available Saturday afternoon at the Grave Creek Mound Historical Site theater in Moundsville. The group invited dozens of invited local “decision makers” and politicians in an effort to showcase the global plastic pollution crisis that the world now faces, according to Bev Reed, an organizer of the group. She said while the 90-minute film still has still not been released to the public by its creator, Deia Schlosberg, she is hopeful the film will be made available to the public as soon as possible.. “The Story of Plastic” focuses on exposing the truth behind the plastic pollution crisis, according to its creators. In the film, footage shot over three continents illustrates the ongoing catastrophe: fields full of garbage, heaps of trash; rivers and seas clogged with waste; and skies choked with the runoff from plastic production and recycling processes. The film shows interviews with experts and activists, and scenes which reveal the impact of the flood of plastic on ecosystems and communities around the world, and the global movement rising up in response. Reed said the film was meant to highlight the risks such industry would pose to the region, if the proposed Dilles Bottom ethane cracker plant would come to fruition. “This cracker plant would create about 3 billion pounds of plastic feed stock pellets per year – much of what would be used for single use plastics. It’s impacting our human health. It’s impacting animal health. “By 2050 plastic will outweigh fish in the world’s oceans so it’s very worrisome,” she added. Reed said another issue is the proposed cracker plant would be built by companies from overseas and the profits would not stay here.

Company linked to EPA chief of staff OKs $3.7M settlement — In July 2013, EPA inspectors found an oil and gas well pad on an Ohio Boy Scout camp was leaking air pollution that could worsen climate change and cause lung damage. Nearly 6 ½ years later, the Trump administration has proposed a $3.7 million settlement agreement with well owner Gulfport Energy, a struggling Oklahoma-based firm with ties to EPA Chief of Staff Ryan Jackson. A former EPA enforcement director and a resident who lives near the leaking pads welcomed the tentative deal, but they both argued it took too long for the settlement to be reached. The agreement, filed yesterday with the U.S. District Court for the Southern District of Ohio, would require Gulfport to pay a $1.7 million penalty and spend around $2 million curbing volatile organic compound (VOC) emissions from the Fort Steuben Scout Reservation well pad and 16 other production sites in eastern Ohio. EPA estimates the required investments would cut 313 tons of VOCs per year. The Department of Justice will accept comments for 30 days on the proposal, which also needs to be approved by a federal judge from the Southern District of Ohio. “Gulfport has agreed to improve its operations to address these issues and to reduce air pollution,” Kurt Thiede, the EPA regional administrator who oversees the Buckeye State, said in a press release that didn’t mention the deal’s climate benefits. “EPA is committed to reducing pollution and improving air quality throughout Ohio, helping residents breathe easier,” Thiede said. The agreement also revealed that EPA had hit Gulfport with three separate notices of violation regarding air pollution from the so-called Boy Scout well pad: first in December 2013, then in December 2016 and again in March 2019. The latter pair of alleged violations also cited Gulfport for excess VOC emissions at more than a dozen other nearby production sites. The 2013 notice warned that “these violations have caused or can cause excess emissions of the greenhouse gas methane,” a planet-warming compound that traps 20 times more heat than carbon dioxide over a century. “The buildup of greenhouse gases can change Earth’s climate and result in dangerous effects to human health and welfare and to ecosystems.” VOCs, the notice added, can also lead to lung-damaging smog. The subsequent notices – issued when Donald Trump was president-elect and then after he’d assumed office – reiterated concerns about VOCs but didn’t list exacerbating climate change as one of the environmental impacts of the alleged violations.

This Problem With Fracked Oil and Gas Wells Is Occurring ‘at an Alarming Rate’ | DeSmog – On February 15, 2018, a fracked natural gas well owned by ExxonMobil’s XTO Energy and located in southeast Ohio experienced a well blowout, causing it to gush the potent greenhouse gas methane for nearly three weeks. The obscure accident ultimately resulted in one of the biggest methane leaks in U.S. history. The New York Times reported in December that new satellite data revealed that this single gas well leaked more methane in 20 days than an entire year’s worth of methane released by the oil and gas industries in countries like Norway and France. The cause of this massive leak was a failure of the gas well’s casing, or internal lining. Well casing failures represent yet another significant but not widely discussed technical problem for an unprofitable fracking industry. Casing failures occur when the steel or cement that’s lining an oil or gas well breaks or cracks, which means the well can’t maintain pressure anymore and creates a pathway for anything inside the well – such as fracking fluids – to leak into the surrounding environment. They can take place, as in the example of Exxon’s gas well in Ohio, at sites where hydraulic fracturing, or fracking, is happening. The results of these failures can be catastrophic, as a 2017 paper published by the Society of Petroleum Engineers spells out: “Outcomes from casing failures include blowouts, pollution, injuries/fatalities, and loss of the well with associated costs.” Wells used to produce oil and gas via fracking are different from what are known as “conventional,” or traditionally drilled, oil wells. While a fracked well is initially drilled vertically like a conventional well, at a certain point, the well bore turns and drills horizontally for distances up to 20,000 feet (that’s nearly four miles). The well’s vertical portion is made up of several layers of steel pipe casing and cement that are designed to protect nearby groundwater from the oil, gas, and fracking fluids that pass through the well. According to the Society of Petroleum Engineers paper, casing failures have been linked to the stresses and high pressures required to complete the fracking process and the industry is grappling with this costly and hazardous problem. This paper identified the problem in depth and used strong language (for engineers), noting, “Incidents of casing failures occurring during fracture stimulation operations are increasing at an alarming rate.”

Columbia Gas investing $33 million in Southeast Ohio – Columbia Gas says it will invest approximately $33 million to upgrade more than 36 miles of natural gas main lines and 2,500 customer service lines in Southeast Ohio in 2020. The Lawrence County community of Coal Grove is one of the locations on the list to receive upgrades. This work is part of an ongoing commitment by the company to enhance customer safety with 21 major gas line replacement projects this year, according to a news release from Columbia Gas. “We are proactively investing in our infrastructure to ensure customers will continue to have safe and reliable service now and long into the future,” Columbia Gas President Dan Creekmur said in the release. Since the gas line replacement program started, the number of leaks throughout Ohio has fallen by 40 percent. The Southeast Ohio projects are part of the company’s larger 25-year program to invest more than $2 billion to replace over 4,000 miles of pipeline across the state. Projects are currently in progress with 21 projects scheduled this year. Along with Coal Grove, construction is scheduled in the following areas:

Editorial: Dont chase cracker-plant jobs at cost of health, environment – The Columbus Dispatch – This editorial represents the opinion of the Dispatch editorial board, which includes the publisher, editor, editorial page editor and editorial writers. As Ohio officials do all they can to make a proposed $5 billion petrochemical plant a reality in Belmont County, we hope they are equally determined – and able – to protect the Ohio Valley’s air, water and health. To people concerned about the environment, climate change and public health, the facility proposed by Thailand-based PTT Global Chemical America is a nightmare. To expect the powers that be to oppose the plant, however, is unrealistic. The word “gamechanging” is used to describe the economic effect it could have on an area of the state that has suffered for decades from the decline of coal. If plans come together, the plant would mean thousands of construction jobs and hundreds of permanent jobs at the plant. The so-called “cracker” plant would take the ethane found in natural gas – produced in abundance via fracking wells in the area – and break the molecules into smaller molecules of ethylene, the root chemical for many plastic products.And the jobs and the building wouldn’t stop with the cracker plant. Its demand for ethane would spur more drilling in the area. There would be processing facilities to separate the ethane from the natural gas, and storage for the ethane destined for the cracker plant. A company called Energy Storage Ventures has said it will begin construction this year on a project to store 2 million barrels of ethane, butane and propane in underground salt caverns near Clarington, Ohio. Tying all that together would be miles of pipeline. With an even-bigger cracker plant under construction in western Pennsylvania and another proposed for West Virginia, a 300-mile stretch of the Ohio River could become a hub of petrochemical and plastics manufacturing. No pollution controls can mitigate the enormous impact a cracker plant, not to mention a built-out petrochemical hub, would have on climate change. One estimate holds that the cracker plant being built in Pennsylvania will essentially replace all the carbon reduction the city of Pittsburgh hopes to achieve by 2030.And what would all these emissions produce? Plastic – the very material that is clogging waterways worldwide. All in all, it seems a high price for Ohio to pay for jobs in an industry known for boom-and-bust cycles.

Beyond Fracking: Oil-and-Gas Industry’s Toxic Waste Is Radioactive – Oil-and-gas wells produce nearly a trillion gallons of toxic waste a year. An investigation shows how it could be making workers sick and contaminating communities across America. In a squat rig fitted with a 5,000-gallon tank, Peter crisscrosses the expanse of farms and woods near the Ohio/West Virginia/Pennsylvania border, the heart of a region that produces close to one-third of America’s natural gas. He hauls a salty substance called “brine,” a naturally occurring waste product that gushes out of America’s oil-and-gas wells to the tune of nearly 1 trillion gallons a year, enough to flood Manhattan, almost shin-high, every single day. At most wells, far more brine is produced than oil or gas, as much as 10 times more. It collects in tanks, and like an oil-and-gas garbage man, Peter picks it up and hauls it off to treatment plants or injection wells, where it’s disposed of by being shot back into the earth. One day in 2017, Peter pulled up to an injection well in Cambridge, Ohio. A worker walked around his truck with a hand-held radiation detector, he says, and told him he was carrying one of the “hottest loads” he’d ever seen. It was the first time Peter had heard any mention of the brine being radioactive. Many industry representatives like to say the radioactivity in brine is so insignificant as to be on par with what would be found in a banana or a granite countertop, so when Peter demanded his supervisor tell him what he was being exposed to, his concerns were brushed off; the liquid in his truck was no more radioactive than “any room of your home,” he was told. But Peter wasn’t so sure. “A lot of guys are coming up with cancer, or sores and skin lesions that take months to heal,” he says. Peter experiences regular headaches and nausea, numbness in his fingertips and face, and “joint pain like fire.” “It’s all over your hands, and inside your boots, and on the cuticles of your toes, and any cuts you have – you’re soaked,” he says. […] “It’s ridiculous that these drivers are not being told what’s in their trucks,” says John Stolz, Duquesne’s environmental-center director. “And this stuff is on every corner – it is in neighborhoods. Truckers don’t know they’re being exposed to radioactive waste, nor are they being provided with protective clothing. “Breathing in this stuff and ingesting it are the worst types of exposure,” Stolz continues. “You are irradiating your tissues from the inside out.” The radioactive particles fired off by radium can be blocked by the skin, but radium readily attaches to dust, making it easy to accidentally inhale or ingest. Once inside the body, its insidious effects accumulate with each exposure. It is known as a “bone seeker” because it can be incorporated into the skeleton and cause bone cancers called sarcomas. It also decays into a series of other radioactive elements, called “daughters.” The first one for radium-226 is radon, a radioactive gas and the second-leading cause of lung cancer in the U.S. Radon has also been linked to chronic lymphocytic leukemia. “Every exposure results in an increased risk,” says Ian Fairlie, a British radiation biologist. “Think of it like these guys have been given negative lottery tickets, and somewhere down the line their number will come up and they will die.”

1982 American Petroleum Institute Report Warned Oil Workers Faced ‘Significant’ Risks from Radioactivity – DeSmog –Back in April last year, the Trump administration’s Environmental Protection Agency decided it was “not necessary” to update the rules for toxic waste from oil and gas wells. Torrents of wastewater flow daily from the nation’s 1.5 million active oil and gas wells and the agency’s own research has warned it may pose risks to the country’s drinking water supplies. On Tuesday, a major new investigative report published by Rolling Stone and authored by reporter Justin Nobel delves deep into the risks that the oil and gas industry’s waste – much of it radioactive – poses to the industry’s own workers and to the public. “There is little public awareness of this enormous waste stream,” Nobel, who also reports for DeSmog, wrote, “the disposal of which could present dangers at every step – from being transported along America’s highways in unmarked trucks; handled by workers who are often misinformed and underprotected; leaked into waterways; and stored in dumps that are not equipped to contain the toxicity.” Additional documents obtained by Nobel and shared with DeSmog show that a report prepared for the American Petroleum Institute (API), the nation’s largest oil and gas trade group, described the risks posed by the industry’s radioactive wastes to workers as “significant” in 1982 – long before the shale drilling rush unleashed new floods of wastewater from the industry – including waste from the Marcellus Shale, which can carry unusually high levels of radioactive contamination. Oil and gas wells pump out nearly a trillion gallons of wastewater a year, Rolling Stone reported. That’s literally a river of waste – enough to replace all the water flowing from the Mississippi River into the Gulf of Mexico for more than two and a half days. Much of that wastewater, often referred to by the industry as “brine,” carries high levels, not of familiar table salt, but of corrosive salts found deep below the Earth’s surface, as well as toxic compounds and carcinogens. That water can also carry serious amounts of radioactive materials. The Rolling Stone report, labeled “sobering” by the Poynter Institute, described levels of radium as high as 28,500 picocuries per liter in brine from the Marcellus Shale, underlying Pennsylvania, Ohio, New York, and West Virginia, levels hundreds of times as much as the Nuclear Regulatory Commission would allow in industrial discharges from other industries.

Radioactive Marcellus, Utica well waste flows through ‘loophole’ – A federal loophole could mean millions of tons and billions of gallons of radioactive natural gas waste are being disposed of as if they were not radioactive. According to the investigation by Rolling Stone, liquid brine from the average Marcellus well contains more than 9,000 picocuries per liter of radium. A picocurie, abbreviated pCi, is equal to the radioactivity of one gram of radium. A nuclear site is not allowed to discharge wastewater above 60 pCi. Melissa Troutman, research and policy analyst for the nonprofit group Earthworks, said the problem is an exemption included in federal law for oil and gas waste decades ago. “It is exempt from hazardous waste law, and has been since the 1980s,” Troutman said. “So for the past 40 years, this waste has been disposed of improperly and has led to water and land contamination as well as public health risks.” Brine is used in commercial de-icing products and spread by municipal de-icing trucks, according to the Rolling Stone investigation. Though the Ohio Department of Transportation uses brine to de-ice state roads, it’s not from brine wells, a spokesperson told Mahoning Matters Friday – rather, a traditional mixture of salt in water.The oil industry argues that naturally occurring radioactivity doesn’t pose a real threat to humans or the environment. And gas drillers’ political allies have said increased regulations would stunt growth at a time when the industry is already troubled by low prices.Troutman said the levels and types of radioactivity in the waste are far more dangerous than what people normally would encounter, particularly when it is concentrated in the processes of production and disposal. She adds there are people in Congress who see this as a serious problem. “At the federal level, there are bills that have been introduced to close the hazardous waste loophole,” she said. “The unfortunate thing is, the political will is not there to do so.”

Marcellus Shale rig counts steady for ’20, way down for ’10 – Pennsylvania’s number of natural gas drilling rigs held steady as it has for the new year, but it’s down sharply from production a year ago. There were 25 drilling rigs operating in Pennsylvania for a second week, according to a tally released weekly by oilfield services company Baker Hughes (NYSE: BKHS). But it shows a big decline from this time a year ago, when there were 48 rigs. The year-to-year drop in the count is due to lower prices for natural gas, which has led to a cut in drilling and related services. Ohio and West Virginia also remained steady, with 10 rigs and 16 rigs respectively. It’s down seven year-over-year in Ohio but West Virginia is up one from a year ago.

OSHA fines Philadelphia refinery for safety violations — Monday, January 20, 2020 — Federal workplace safety authorities fined the Philadelphia Energy Solutions refinery $132,600 for a string of violations related to the fiery explosions that destroyed the plant last summer.

Philly refinery auction said to attract Chicago developer that rehabs industrial properties – The fate of the bankrupt Philadelphia Energy Solutions refinery complex, shut down since a catastrophic fire and explosion last June, hung in the balance on Friday. At least two bidders attended a closed-door auction conducted Friday at a New York City law firm handling the refinery’s bankruptcy. Results of the auction were not immediately disclosed. The bidders included Philadelphia Energy Industries (PEI), a company formed by former refinery chief executive Philip Rinaldi that wants to resume refining petroleum on the 1,300-acre site, the largest refining complex on the East Coast. According to sources, a second bidder, Hilco Redevelopment Partners, a Chicago real estate firm that specializes in developing old industrial sites into new uses, was also in contention. A spokesman for Hilco declined to comment Friday. Hilco is redeveloping the former Sparrows Point steel mill in Baltimore, a 3,100-acre waterfront site with deep-water access, into an industrial site called Tradepoint Atlantic. Hilco is also remediating several sites of shuttered power-generation stations, including the proposed L Street Station mixed-use property in South Boston. Last year Hilco bought two New Jersey closed coal-fired plants, including one near Trenton, and plans to develop them into industrial ventures. The auction may not necessarily result in a sale. If the refinery’s creditors decide the bids are too low, they could “credit bid” up to the amount they are owed and keep the property for themselves. Cortland Capital Market Services LLC is the lead bank on a $699 million term loan.

‘Their timeline is aggressive’: Hilco plans to clean up polluted South Philly refinery site, city says –Hilco Redevelopment Partners, whose $240 million bid won an auction to acquire the bankrupt Philadelphia Energy Solutions refinery site, aims to move quickly to clean up the 1,300-acre South Philadelphia property and redevelop it into a mixed-use industrial facility, according to city officials.“I think their timeline is aggressive, I’ll put it that way,” Brian Abernathy, the city’s managing director, said in an interview Wednesday. “They want to be in the ground quickly.” Abernathy, who headed a four-member city government delegation that attended Friday’s six-hour-long auction, said Hilco had done its homework and came well-prepared for negotiations. The Chicago-based company, which specializes in repurposing industrial properties, did not submit a formal plan for the site, but painted its plans in “broad brushes,” he said. “They’ll probably still keep the tank farm and some of the energy logistics that are on-site, but they don’t intend to operate the refinery,” said Abernathy. He said Hilco is likely to develop the site for multiple users, which he said was “exciting” because the property will be less dependent upon a single industry that is susceptible to boom-and-bust cycles. PES’s plans require the approval of U.S. Bankruptcy Court Judge Kevin Gross, who has scheduled a confirmation hearing for Feb. 6. The deadline for creditors to vote on the plan, and for filing any objections to the plan, is Feb. 3. Hilco was one of two finalists bidding on the refinery, which shut down following a June 21 fire and explosion and declared bankruptcy. The 335,000-barrels-a-day refinery was the largest oil-processing facility on the East Coast and had been in operation for 150 years.

PES creditors fight to reject refinery sale to Hilco – (Reuters) – Creditors of bankrupt Philadelphia Energy Solutions are opposing the sale of its oil refinery to Hilco Redevelopment Partners, saying another developer made a more lucrative bid for the site, according to court documents filed on Thursday. Industrial Realty Group submitted a bid of $265 million during an auction last week to sell the idled refinery site, $25 million more than Hilco’s bid, according to filings by law firm Brown Rudnick LLP in United States Bankruptcy Court for the District of Delaware. PES did not immediately respond to a request for comment. The refiner announced on Wednesday that it agreed to sell its 335,000 barrel-per-day refinery, the largest and oldest on the U.S. East Coast, to Chicago-based real estate developer Hilco, naming Industrial Realty Group as a back-up bidder. PES’s unsecured creditors, which include companies that had supplied contract work to PES, as well as workers’ unions employed by the refinery, have pushed for a buyer that would restart the complex.

Chicago developer Hilco’s $240 million bid wins auction for bankrupt Philadelphia refinery – Bankrupt Philadelphia Energy Solutions has agreed to sell its shuttered South Philly refinery complex to a Chicago development company with experience repurposing old industrial properties for new uses, likely marking an end to the site’s 150-year-old history as a petroleum refinery. Hilco Redevelopment Partners, a Chicago real estate firm that has acquired old power plant sites in Boston and New Jersey, and is building warehouses on a former steel mill site in Baltimore, agreed to pay $240 million to acquire the 1,300-acre refinery site during a closed-door auction Friday, according to a U PES chief executive Mark Smith announced the deal Tuesday in a memo to employees, saying that Hilco’s affiliate, HRP Philadelphia Holdings LLC, would announce its plans for the site at a later date. “We will continue to maintain the refinery complex, remove the hydrocarbon inventory in the facility, protect the facility and prepare for a safe handoff of the facility to HRP Philadelphia Holdings LLC, which is expected to occur within 60-90 days,” Smith said in his memo.

South Philly explosion caused by crack in gas main, officials say – Officials say a crack in a 92-year-old natural gas main led to the explosion that devastated a South Philadelphia block last month, killing two people, destroying five rowhouses, and forcing the evacuation of 60 residents. An investigation by the Pennsylvania Public Utility Commission into the underlying cause of the crack is ongoing, Fire Commissioner Adam Thiel said at a news conference Thursday. By Dec. 23, four days after the explosion, Philadelphia fire marshals had determined a crack in the gas line, causing natural gas to leak, led to the blast, Thiel said. The state commission’s in-depth investigation is now “exploring the cause and circumstances surrounding this incident, along with whether there are any violations of state or federal pipeline safety regulations,” according to a statement from the agency. That investigation could take a year or longer, the commission said.

‘We’re failing to meet many of our goals,’ DEP official says as environmental oversight board passes hefty fee hike – A state environmental oversight board agreed to increase the permit fee for natural gas drilling by 150 percent, arguing that the hike was needed to fund the state’s regulatory program. During a meeting Tuesday, the Environmental Quality Board hiked the fee to $12,500 for any well, up from $5,000 for non-vertical wells and $4,200 for vertical wells.Even as permit applications have declined from the peak of the gas boom, inspections have gone up, according to Department of Environmental Protection oil and gas chief Scott Perry.While the agency has adopted new policies and digitized inspections to cut costs and increase efficiency, Perry said there isn’t much more that can be done under the current budget.“We’re failing to meet many of our goals and we have IT projects that are going unmet,” Perry said.According to the 2012 state law governing the natural gas industry, the permit fee should “bear a reasonable relationship to the cost of administering this chapter.” The department estimates an annual budget of $25 million. The state’s impact fee – a tax on each well drilled, not on the gas extracted – provides $6 million each year to the DEP for oil and gas regulation. That is a small fraction of the $198 million the fee brought in last year.

Pennsylvania board votes to raise shale well permit fees 150% | Pittsburgh Post-Gazette – Permit fees for shale gas wells in Pennsylvania will more than double under a rule change approved by a state environmental board on Tuesday.The fee to drill a new Marcellus or Utica shale well will rise from $5,000 to $12,500 – the highest in the U.S. Regulators with the Department of Environmental Protection said said the hike is necessary to maintain the program that permits and inspects the commonwealth’s vast number of new and old wells.Permit fees are the program’s primary source of funding but applications have declined significantly in recent years.At the increased rate, the fee will amount to 0.16% of the $8 million it costs to drill an unconventional well, DEP said.Critics of the increase say it is high enough to discourage companies from drilling new wells and may only compound DEP’s funding problems by driving permit applications even lower.The increase must still be reviewed by the environmental committees in the state House and Senate and Pennsylvania’s Independent Regulatory Review Commission before it can take effect.The department has received far fewer permits than the 2,600 a year it counted on getting the last time it raised fees in 2014. Companies are seeking to drill fewer wells as gas prices have declined and operations have become more efficient. New wells stretch much farther into rock layers underground and extract much more gas from them. Since 2014, DEP’s oil and gas program has shrunk from 226 to 190 employees and its operating costs have been reduced by 38%, Scott Perry, deputy secretary for the Office of Oil and Gas Management, said at an Environmental Quality Board meeting.Mr. Perry said the fee increase is necessary just to maintain the program in its current, reduced state. He said the program has determined it would need 49 additional positions to meet its goals.The new fees are based on the assumption that DEP will receive 2,000 permit applications a year, but the agency hasn’t hit that target since 2015. Since then, DEP has received an average of 1,750 applications each fiscal year. This fiscal year, it is on track to receive fewer than 1,600. Despite that, Mr. Perry said the program “will have the revenue sufficient to maintain the program at current staffing levels for the next three years.”That is in no small part due to a windfall of $25.6 million that the oil and gas program will get from the $30.6 million fine paid by Energy Transfer Corp. for the September 2018 explosion of the Revolution pipeline in Beaver County.

Veto gas bill, limit pollution – Pollution that flows from conventional gas wells in Pennsylvania is just as toxic as that produced by the newer, deep, fracked wells characteristic of the industry across the Marcellus Shale. Yet, in a case of special interest pandering, many legislators want that pollution to be less lightly regulated than Marcellus Shale pollution. Conventional wells are shallow, vertical wells that were typical prior to the advanced deep-drilling technology that has opened the Marcellus and Utica shales to development. Under a bill sponsored by Senate President Pro Tempore Joseph Scarnati of Jefferson County, shallow well drillers would not face the same requirements as deep-well drillers for reporting spills of polluted brine and crude oil. A 2018 Penn State study of drilling-related brine, which flows to the surface during drilling, usually includes significant amounts of the known carcinogen radium, “often many times above drinking water standards.” It also found that the brine can leach metals, salts and radioactive material into surface or groundwater, soil and air. It makes scant difference to someone affected by groundwater pollution whether the polluting agent generated by a shallow or deep well. Making distinctions based on the depth of the well, or the size of the company responsible for it is not effective environmental regulation, because the regulation is supposed to target the pollution rather than the company. Given what is known and worse, unknown, about drilling-related pollution, it is folly to loosen environmental regulations. Unfortunately, the bill already has passed the Senate and a House committee. Fortunately, Gov. Tom Wolf appears inclined to veto it. “This bill still poses an undeniable risk to the health and safety of our citizens, the environment, and our public resources,” gubernatorial spokesman J.J. Abbott wrote in a statement. The House should reject the bill, but Wolf should follow through on the veto if it passes.

Delaware Riverkeeper seeks rehearing of Adelphia pipeline approval – West Rockhill officials also plan to appeal December’s Federal Energy Regulatory Commission approval of the controversial pipeline project.The Delaware Riverkeeper Network wants a new hearing on the federal approval of an 84-mile natural gas pipeline that has West Rockhill residents and officials riled for nearly two years over concerns about its local impact.The Federal Energy Regulatory Commission approved a Certificate of Public Convenience and Necessity for Adelphia Gateway LLC, in December, giving the OK for a project converting 50 miles of an existing pipeline from oil to natural gas.The project includes a 10,000-square-foot, 5,625-horsepower compressor station on a 1.5-acre property on Rich Hill Road in West Rockhill, a facility that township residents and officials are opposing.The rehearing petition filed by the network asserts FERC took “a narrow view” of the pipeline’s necessity and failed to account for adverse climate, health and safety impacts on the communities the pipeline passes through.

Gov. Justice Reiterates Support For W.Va. Natural Gas Drillers As Industry Struggles – West Virginia’s top official says the state is prepared to do “anything” to help the state’s struggling oil and natural gas industry. Speaking at the annual winter meeting of the Independent Oil and Gas Association of West Virginia on Wednesday, Jan. 22, Gov. Jim Justice told the crowd of drillers and producers that his administration believes the industry is vital to the state’s economic health and that he’s in lockstep with the industry in supporting legislative relief. “I can’t be any more sympathetic,” Justice said. “I do really believe that we’re doing things to make things better.”Justice assured the audience he intended to sign House Bill 4091. The bill, which creates an expedited permitting process for drillers, passed in the House and is under consideration in the Senate. He also expressed support for H.B. 4090, which reduces the severance tax on low-producing wells and siphons some of the proceeds toward plugging orphaned wells. Justice vetoed a version of the bill that passed last session.The governor urged natural gas producers to ride out the current record-low gas prices. “If you can survive for two or three more years, the opportunity to the upside for you, for this is off the chart. It’s off the blooming chart,” he said. “Because the stars have aligned. Now, it maybe took me a little while to catch up, but I’m there. I’m all in.” Justice was light on specifics.

Poll: Most New Jersey voters want to choose their own home energy – A poll released today by a powerful labor union on energy issues might frighten legislators who come out in support of Gov. Phil Murphy’s plan to eliminate fossil fuel and move to 100% electrification. More than seven out of ten New Jersey voters, 71%, say they are less likely to vote for legislative candidates who support increasing energy and utility costs by 30%, according to a McLaughlin & Associates poll conducted for the Engineers Labor-Employer Cooperative 825 and the International Union of Operating Engineers Local 825. The state Board of Public Utilities is expected to release a final version of the New Jersey Energy Master Plan next week. According to the poll, 67% of New Jersey voters disapprove of a plan that would ban the use of natural gas for homes, businesses and transportation. Just 25% approve. When asked if they would approve of replacing natural gas with a “more environmentally friendly” electric form of energy, the number went to 41% approve and 55% disapprove. “Our polling shows one clear and undeniable fact – New Jersey residents want clean, affordable, and reliable Natural Gas. If next week’s Energy Master Plan includes a moratorium or complete phase-out of Natural Gas, it will be at complete odds with the voters of New Jersey,” said Greg Lalevee, the Operating Engineers business manager and the ELEC825 chairman. “Through this poll, respondents tell us that they’re willing to vote out anyone who seeks to eliminate their access to Natural Gas through a government mandate since it only will increase the price of energy for families and businesses large and small across New Jersey.”

Baker budget ups fines for gas utility violations – — The Baker administration is looking to sharply increase the fines it can assess on companies that do work on or near natural gas pipelines and to make utilities establish a timeline for replacing leak-prone pipes. In addition to a $5 million outlay for the Department of Public Utilities’ Pipeline Safety Division to ensure natural gas companies are in compliance with safety regulations, the $44.6 billion spending plan Gov. Charlie Baker filed Wednesday includes seven outside sections dealing with gas pipeline safety requirements and fines. The sections would increase fines for Dig Safe violations, emergency response violations and for violations of the state’s pipeline code. They would also eliminate the exemption municipal water companies have from Dig Safe requirements and add new requirements for gas companies’ gas safety enhancement plans, which were introduced under a 2014 gas leaks law. Baker said Wednesday that the gas safety measures are part of his administration’s attempts to shore up the safety of the state’s natural gas infrastructure after the gas explosions and fires that killed one man, razed several homes and destroyed property across Lawrence, Andover and North Andover in September 2018. “I think from our point of view, there were a series of recommendations that were made in the original report that came out around Columbia [Gas] and I think our view was that making those investments would be an important part of our ability to do the work that we need to do here in Massachusetts to make sure that our grid is safe,” the governor said Wednesday when he unveiled his fiscal 2021 spending plan. A company contracted by the Baker administration to examine the safety of natural gas infrastructure in the wake of the Merrimack Valley disaster, Dynamic Risk Assessment Systems Inc., wrote in its initial report last year that Massachusetts’s gas distribution system is “generally reliable” but is made up of a higher proportion of leak-prone pipes, mains, and services made out of cast iron, wrought iron or unprotected steel. Massachusetts has 21,669 miles of natural gas mains or 1.7 percent of the total main mileage in the United States. But Massachusetts’ 3,049 miles of cast iron mains account for 12.4 percent of the nation’s total. The state’s 1.3 million natural gas service lines represent 1.9 percent of the nationwide total, but Massachusetts has 18 percent of the country’s cast iron services.

America Is Awash With Natural Gas and It’s About to Get Worse – Trump spoke at an industry event of the “astonishing increase” in shale gas production. The Appalachian region has spearheaded a historic expansion, turning the U.S. into the world’s biggest producer while slashing prices for consumers and sounding the death-knell for domestic coal. But the dark side of the boom is increasingly difficult to ignore. Shale drillers are extracting so much gas that it’s overwhelming demand. Prices dipped briefly below $2 per million British thermal units on Friday for the first time since 2016 and traded below the threshold again on Monday. At that level, U.S. producers simply don’t make money. It’s forcing a wave of multibillion-dollar writedowns, layoffs and spending cuts. Still, the industry is powerless to stop a wave of additional gas hitting the market as a byproduct of rising shale oil output in places like the Permian Basin of West Texas and New Mexico. Even exports of liquefied natural gas provide little relief, as the international market is also oversupplied.“The industry is a victim of its own success,” said Devin McDermott, an analyst at Morgan Stanley. “You don’t just have oversupply in the U.S. — you have oversupply in Europe, oversupply in Asia, and really oversupply across the globe.” Futures for February dropped 4.5% to $1.912/MMBtu on Monday. According to McDermott, U.S. producers need gas to be at least $2.50 in order to generate free cash flow. “In the near-term, we don’t think it’s realistic to see a $2.50 price,” he said.

Warm Weather Allows Prompt Month Natural Gas Prices To Sink Under $2.00 –Warm weather continues to take a heavy toll on the natural gas market, with the long weekend bringing even more changes to the warmer side, enough so that, on a Gas-Weighted Degree Day (GWDD) basis, we are now projecting this January to be the 3rd warmest in our historical dataset, behind only 2006 and 1990. The pattern has a very “El Niño-like” look, which without any high-latitude blocking leads to warmth across most of the U.S. outside of parts of the South. Despite the historically low price environment, it is difficult to avoid moving even lower with a high-level warm pattern in the middle of winter. We hit on these points in our “Pre-Close Update” sent out to clients Friday afternoon, taking a slightly bearish stance into the weekend despite Friday’s close being almost dead on $2.00 in mid-January with a market that is already heavily short, citing the likelihood of continued warmth taking us lower. So far, that is exactly what has happened, with prompt month prices currently down in the low $1.90s. All the while, we continue to see production well under the highs from late November, which along with stronger weather-adjusted power burns has helped tighten supply demand balances. In a “normal” scenario, this would be increasingly bullish, but this weather pattern is, as shown above, anything but normal, and will continue to rule price action as long as it stays biased strongly to the warmer side of normal. Can the run of warmth continue well into February, or will we finally see things change enough to stop the natural gas price plunge? We track both weather and fundamentals closely in our daily reports, providing a unique blend of data to present a clearly view of future price action.

Has Natural Gas Hit Rock Bottom? – U.S. natural gas prices fell below $2/MMBtu on Friday for the first time in nearly four years. The gas market is suffering from oversupply, as the shale industry has drilled the market into another bust. The share prices for top gas players were deep into red territory on Friday. Range Resources, for instance, was off by more than 8 percent. The story has been the same for quite a while. Natural gas production has surged more or less for a decade, and much of it was soaked up by new gas-fired power plants, new petrochemical facilities, or otherwise exported via new LNG export terminals. But production continued to climb, and here we are – a mild start to the winter and prices have fallen off a cliff. Part of the problem is the ongoing production increases in the Permian with total disregard to any price signal. Permian drillers are after the oil, leading to continued output increases of associated gas, despite prices often traded at or even below zero. The market has become so depressed that financial pressure in the Marcellus shale is increasing. Chevron took an $11 billion write down in the fourth quarter, much of it the result of its devalued assets in Appalachia. Only days ago, EQT, the largest gas producer in the country, announced a $1.8-billion write down, while Moody’s downgraded the company’s credit rating into junk territory. EQT’s CEO said in December that “a lot of this development doesn’t work as well at $2.50 gas.” Well, if he doesn’t like $2.50 gas, he’s really not going to like sub-$2 gas. Meanwhile, the oversupply issue is not isolated to the United States. The global market for LNG is also increasingly depressed, due to weaker-than-expected demand and the wave of new export capacity that came online in 2019. Spot prices for LNG in Asia – the closely-watched JKM marker – fell below $5/MMBtu, a shockingly low level for winter months. Worse – from the perspective of exporters – prices could fall further still. “JKM is expected to fall close to $3/MMBtu in the months ahead, which would leave the potential for sub-$3/MMBtu assessments on select days this summer,”according to S&P Global Platts Analytics. The problem is that global LNG capacity continues to rise, even as China – who everyone seems to think will gobble up every last cargo – has seen its rate of economic growth slow. Moreover, China is set to see increased volumes of gas imports from the newly started Power of Siberia gas pipeline from Russia. The cycles for the LNG market are slow, which magnifies the boom and busts. The wave of export terminals that came online in 2019 were the result of a wave of investment made earlier in the decade, which itself was an outgrowth of very high prices. LNG supply simply can’t react to short-term swings.

US working natural gas in underground storage decreases by 92 Bcf: EIA | S&P Global Platts – US natural gas working stocks fell by 92 Bcf last week, which was within market expectations, but more than 100 Bcf below the five-year average draw, as Henry Hub winter futures remain below $2/MMBtu. Storage inventories fell to 2.947 Tcf for the week ended January 17, the US Energy Information Administration reported Thursday morning. The pull was more than an S&P Global Platts’ survey of analysts calling for an 88 Bcf draw. The withdrawal was well below the 152 Bcf pull reported during the corresponding week in 2019 as well as the five-year average draw of 194 Bcf, according to EIA data. As a result, stocks were 554 Bcf, or 23%, more than the year-ago level of 2.393 Tcf and 251 Bcf, or 9%, more than the five-year average of 2.696 Tcf. Gas prices staged a small rebound Thursday morning after the EIA reported a slightly larger-than-expected storage withdrawal, with February Henry Hub trading 4 cents higher and the balance of the first half of 2020 trading about 2 cents higher. Mild bullishness notwithstanding, gas prices continue to sell off as weather forecasts anticipate continued mild weather in the near term, against the backdrop of a structurally loose supply-demand balance in the longer term. February Henry Hub sank to a low of just $1.89/MMBtu Tuesday, nearly 30 cents lower from a week before. A forecast by S&P Global Platts Analytics’ supply and demand model calls for a much larger draw of 193 Bcf for the week ending January 24, which would decrease the surplus to the five-year average by 50 Bcf. The US has finally seen some real gains in demand this week as lower temperatures across the eastern half of the county have helped drive a more-than-18 Bcf/d increase in total demand compared with the week that ended January 17. Total demand is averaging 124.6 Bcf/d. More than half the gains occurred in the Northeast, where consumption has risen almost 11 Bcf/d week on week. Upstream, supplies have grown as well, but to a much lesser degree, rising 1.3 Bcf/d on the week, according to Platts Analytics. Embedded within the change are several large movements among individual aspects of supply. Onshore production has fallen by 1.5 Bcf/d week on week, much of which is coming from a dip in Texas. The decline in domestic supply has been offset, though, by a nearly 2 Bcf/d rise in net Canadian imports. Platts Analytics’ currently expects the heating season to finalize on March 31 with 2 Tcf remaining in storage, exactly 300 Bcf more than the five-year average.

SUPREME COURT: Pipeline foes: Congress alone can OK trail crossing — Friday, January 17, 2020 — Does a footpath count as “land” under federal law, or does it simply “traverse land”?

Virginia Senate panel OKs offshore drilling, fracking bans (AP) – A Virginia Senate committee on Tuesday advanced measures that would ban offshore drilling as well as hydraulic fracturing in much of eastern Virginia. Similar versions of both measures have been proposed in previous years but died in what was then a Republican-controlled General Assembly. Democrats who took control of both chambers of the legislature in November’s elections have pledged to enact stricter environmental laws. “I think elections have consequences, and one of the consequences is a cleaner environment for Virginia,” Michael Town, executive director of the Virginia League of Conservation Voters, said after the votes. The Senate Committee on Agriculture, Conservation and Natural Resources approved Democratic Sen. Scott Surovell’s measure prohibiting hydraulic fracturing – or fracking – in the Eastern Virginia Groundwater Management Area on a 10-5 vote. Fracking opponents say the chemicals involved threaten water supplies and public health. Surovell said that the bill was necessary to protect the Potomac Aquifer, a drinking water source for millions of Virginians, because a company has signed leases to frack in the Taylorsville Basin. Surovell also said he wants to prevent any other company that might seek to acquire a lease.

Broken boring pipe in Straits bottom longer than Enbridge first said — A rod-like boring pipe Enbridge left in the Straits of Mackinac bottom after it broke last fall is about five times longer than the Canadian oil transport giant initially told state regulators, according to a Michigan Department of Environment, Great Lakes and Energy official. And whether it poses a hazard – and whether it can be recovered – has not yet been determined, the EGLE official said. Enbridge only last week told EGLE officials that the remaining thin pipe in a collapsed bore-hole on the Straits bottom is about 200 feet long – not the 40 or so feet EGLE says the company told regulators in November. An EGLE official said it was “disconcerting” that Enbridge took two months to tell the state about the incident, and then mischaracterized the pipe piece left in the Straits bottom. “We count on these types of industries to self-report – we don’t have staff and equipment to go out and examine with an ROV (remote-operated vehicle) – we don’t have an ROV,” said Joseph Haas, EGLE’s Water Resources Division district supervisor in Gaylord. “It’s probably not uncommon that this happens in this type of work – you break equipment. It’s the fact that they didn’t immediately report it to us that is disconcerting.” Critics of Enbridge and its twin, 67-year-old, underwater oil and gas pipelines in the Straits say it’s just the latest episode in which the company failed to provide transparency about troubles with its operations to regulators or the public.

Operators continue to find new oil reserves in deepwater Gulf, despite scaled-back drilling campaigns – In this post-downturn era, offshore operators and developers continue to be cautious with their drilling programs in the US Gulf of Mexico. A working rig count in the low-to-mid 20s – a 60% decline since January 2014 – seems to be the new norm. Nevertheless, Gulf operators have pressed forward with their slimmed-down exploration plans. These activities did bring a number of notable discoveries over the past year, most notably in the Miocene and Paleogene plays, in the deepwater Gulf. In April, Shell announced that it had made an oil discovery at the Blacktip prospect in the deepwater Gulf. Located in Alaminos Canyon block 380 in about 6,200 ft (1,890 m) of water, Blacktip is a Wilcox discovery in the Perdido thrust belt, about 30 mi (48 km) from the Perdido platform and Whale discovery. The Blacktip exploration well encountered more than 400 ft (122 m) net oil pay with good reservoir and fluid characteristics. Evaluation is ongoing and appraisal planning is under way to further delineate the discovery and define development options, Shell said. In June, W&T Offshore reported that it had discovered oil at the Gladden Deep prospect in Mississippi Canyon block 800 in the deepwater Gulf. The Gladden Deep well is in about 3,000 ft (914 m) of water and was drilled to a total measured depth of 18,324 ft (5,558 m). It encountered 201 ft (61.3 m) of net oil pay. Based on preliminary analysis of drilling and wireline logging results the recoverable resource is expected to be in line with the pre-drill estimate of 7 MMboe gross, according to partner Kosmos Energy (20% working interest). In August, Talos Energy announced that it had hit oil pay at the Bulleit and Orlov prospects in the deepwater Gulf. At the Bulleit prospect in Green Canyon block 21, the well encountered about 140 ft (43 m) of net true vertical depth (TVD) oil pay in the shallow target, the DTR-10 Sand, and about 110 ft (34 m) of net TVD oil pay in the deeper MP Sand. At the Orlov prospect in Green Canyon block 200, the well initially encountered about 100 ft (30 m) of net true vertical thickness oil pay in the main target Aspen J sand, as well as additional pay sands in shallower zones along the same trap. In October, Hess Corp. announced that it had made an oil discovery at the Esox-1 exploration well on Mississippi Canyon block 726 in the deepwater Gulf. Esox-1 was drilled in 4,609 ft (1,405 m) of water and encountered about 191 net ft (58 m) of high-quality oil-bearing Miocene reservoirs. Esox-1 is about 6 mi (10 km) east of the Tubular Bells production facilities.

U.S. gasoline stocks hit record high – U.S. gasoline stockpiles grew for an 11th consecutive week to an all-time high while crude oil and distillate inventories fell last week, the Energy Information Administration said. U.S. gasoline stocks rose by 1.7 million barrels in the week to a record 260 million barrels, the EIA said, compared with analyst expectations for a 3.1 million-barrel rise. Total motor gasoline inventories were about 4% above the five-year average for this time of year, the EIA said. Distillate stockpiles, which include diesel and heating oil, fell by 1.2 million barrels in the week to 146 million barrels, versus expectations for a 1 million-barrel rise, the data showed. U.S. Gulf Coast distillate inventories rose 71,000 barrels to 46.8 million barrels, their highest since September 2017. Over the past four weeks, gasoline supplied was down by 1.4% from the same period last year, while distillate demand dropped 8.3% year-on-year.

Louisiana greenlights huge pollution-causing plastics facility in ‘Cancer Alley’ – The state of Louisiana has issued a series of key air quality permits for a gargantuan proposed petrochemical complex that would roughly double toxic emissions in its local area and, according to environmentalists, become one of the largest plastics pollution-causing facilities in the world.The $9.4bn facility, owned by the Taiwanese chemicals firm Formosa Plastics, would consist of 14 separate plastics plants across 2,300 acres of land in St James parish, a largely African American community in the already heavily polluted area in southern Louisiana known as Cancer Alley. Activists say the plant could release 13m tonnes of greenhouse gases a year, the equivalent of three coal-fired power plants, and would emit thousands of tonnes of other dangerous pollutants, including up to 15,400 pounds of the cancer causing chemical ethylene oxide.The facility has been forcefully opposed by environmental groups and certain local campaigners.The 16 permits issued by Louisiana’s state environment agency (LDEQ) essentially allow Formosa to begin construction, said the LDEQ spokesman Greg Langley. A spokeswoman for Formosa, which is operating the project under a subsidiary, FG LA, said the company would start “site preparation activities” in the first quarter of 2020. This first phase, including soil testing, could take up to a year to complete, the spokeswoman said.The permits had not been made available to the public by Tuesday afternoon. Langley said this was because of the volume of documents, numbering more than 1,000 pages, which were still uploading to the department’s public website. The announcement was met with derision by local campaigners. “We are fighting to protect our homes and our families from this monster, Formosa. We are not going to stop because of this bad decision by the state to grant air permits,” said Sharon Lavigne, the president of the campaign group Rise St James, in a written statement.

A Surge of New Plastic Is About to Hit the Planet – Companies like ExxonMobil, Shell, and Saudi Aramco are ramping up output of plastic – which is made from oil and gas, and their byproducts – to hedge against the possibility that a serious global response to climate change might reduce demand for their fuels, analysts say. Petrochemicals, the category that includes plastic, now account for 14 percent of oil use, and are expected to drive half of oil demand growth between now and 2050, the International Energy Agency (IEA) says. The World Economic Forum predicts plastic production will double in the next 20 years. “In the context of a world trying to shift off of fossil fuels as an energy source, this is where [oil and gas companies] see the growth,” said Steven Feit, a staff attorney at the Center for International Environmental Law, an advocacy group. And because the American fracking boom is unearthing, along with natural gas, large amounts of the plastic feedstock ethane, the United States is a big growth area for plastic production. With natural gas prices low, many fracking operations are losing money, so producers have been eager to find a use for the ethane they get as a byproduct of drilling. “They’re looking for a way to monetize it,“ Feit said. “You can think of plastic as a kind of subsidy for fracking.” America’s petrochemical hub has historically been the Gulf Coast of Texas and Louisiana, with a stretch along the lower Mississippi River dubbed “Cancer Alley” because of the impact of toxic emissions . Producers are expanding their footprint there with a slew of new projects, and proposals for more. They are also seeking to create a new plastics corridor in Ohio, Pennsylvania, and West Virginia, where fracking wells are rich in ethane. Shell is building a $6 billion ethane cracking plant – a facility that turns ethane into ethylene, a building block for many kinds of plastic – in Monaca, Pennsylvania, 25 miles northwest of Pittsburgh. It is expected to produce up 1.6 million tons of plastic annually after it opens in the early 2020s. It’s just the highest profile piece of what the industry hails as a “renaissance in U.S. plastics manufacturing,” whose output goes not only into packaging and single-use items such as cutlery, bottles, and bags, but also longer-lasting uses like construction materials and parts for cars and airplanes.

Formosa Plant May Still Be Releasing Plastic Pollution in Texas After $50M Settlement, Activists Find – After activist Diane Wilson and the San Antonio Estuary Waterkeeper successfully sued Formosa, the company agreed to no longer release even one of the tiny plastic pellets known as nurdles into the region’s waterways. Their suit against Formosa Plastics Corp. USA resulted in a $50-million-dollar settlement and a range of conditions in an agreement known as a consent decree. Key among the conditions was the company’s promise to halt releasing the nurdles it manufactures into local waterways leading to the Texas Gulf Coast by Jan. 15. The deal, signed by Judge Hoyt in December, represents the U.S.’s largest settlement in a Clean Water Act lawsuit brought by private individuals against an industrial polluter. The settlement mandates that both Formosa and the plaintiffs agree to a monitor, remediation consultant, engineer, and trustee for ongoing monitoring of the plant. Wilson gave an update on how requirements of the consent decree were progressing. The volunteer team of nurdle monitors, who have been collecting nurdles discharged by the plant for the last four years, listened eagerly. Wilson said that Formosa had missed the Jan. 15 deadline to deliver the waivers they needed to sign, which would grant them permission to monitor on the company’s property along the fence line. Instead, they headed for the banks of Cox Creek, where Wilson set off in a kayak to check on one of the plant’s outfalls. Within 10 minutes she collected an estimated 300 of the little plastic pellets. Wilson says she will save them as evidence, along with any additional material the group collects, to present to the official – and yet-to-be-selected – monitor. When Wilson returned from her kayak, she showcased her find: The nurdles she had just collected from the Formosa outfall were bright white, making them easy to distinguish from the older ones littering the bank where she had launched her kayak. She plans to turn them over as evidence of newly discharged nurdles to the official monitor once one is selected in accordance to the consent decree. On that same afternoon, Wilson learned that conservation and community groups in Louisiana had sued the Trump administration, challenging federal environmental permits for Formosa’s planned $9.4 billion plastics complex in St. James Parish. The lawsuit was filed in federal court against the Army Corps of Engineers, accusing the Corps of failing to disclose environmental damage and public health risks and failing to adequately consider environmental damage from the proposed plastics plant. Wilson had met some of the Louisiana-based activists last year when a group of them had traveled to Point Comfort and protested with her outside Formosa’s plastics plant that had begun operations in 1983. Among them was Sharon Lavigne, founder of the community group Rise St. James, who lives just over a mile and a half from the proposed plastics complex in Louisiana.

Oversupply, low prices may turn LNG boom into a bust in 2020 –Liquefied natural gas prices are poised to test record lows this year thanks to an onslaught of new supply and warmer winter temperatures curbing consumption.The startup of new export projects from Australia to the U.S. has flooded the market, while brimming stockpiles in Europe and an expected slowdown in Chinese demand have dumped cold water on consumption prospects. LNG for spot delivery to North Asia is on track to hit an all-time low this summer, while gas prices in Europe and the U.S. are trading at the weakest seasonal levels since 1999.“The global oversupply of LNG has been building and building and building,” said Ron Ozer, founder of gas-focused hedge fund Statar Capital LLC in New York. “The gas market can’t stomach the oversupply and warm weather, and it’s getting both.”U.S. gas exports have surged amid the nation’s shale boom, but plummeting prices may now throttle back shipments or encourage sustained maintenance while firms weather the storm. Producers and companies with off-take agreements may decide not to load cargoes because prices are too low to earn a profit after accounting for shipping costs.With cargoes from the Gulf of Mexico currently priced around $2.65 per million Btu, cash margins are positive only because of weak U.S. benchmark prices, according to Robert Sims, an analyst at Wood Mackenzie Ltd. There’s a chance that production could be reduced if the spread between benchmark Henry Hub and U.S. Gulf LNG narrows 25 cents, he said. After four years of belt-tightening, the amount of investments last year in new production capacity set a record. Companies including Qatar Petroleum, Novatek PJSC and Venture Global LNG Inc. sanctioned new plants from the U.S. to Russia. But the current wave of additional supply and persistent weak global prices is challenging new projects seeking final investment decisions, according to Morgan Stanley. The bank reduced its outlook for the number of projects reaching FID and revised lower its new supply outlook for the middle of the decade. The low price environment will also likely force Qatar to stagger or postpone its planned 64% capacity expansion, currently scheduled by 2027, according to FGE.

US gas exporters fight to survive supply glut – Multibillion dollar gas export projects that are central to the Trump administration’s push for “energy dominance” are locked in a battle for survival as prices fall and the market faces a supply glut. Liquefied natural gas is a critical outlet for the US’s surfeit of cheap natural gas and the country is on track to pull ahead of Australia and become the world’s biggest exporter by 2024, the International Energy Agency has said. Companies ranging from Royal Dutch Shell and Total to utilities and smaller independent groups are racing into the LNG export market, but planned capacity exceeds what is likely to be needed. The consultancy McKinsey predicts that only one in 10 proposed export terminals will ever be built. Last year, global importers received 346m tonnes of LNG – gas condensed to a liquid so it can be loaded on to tankers – according to S&P Global Platts. The volume will rise by 100m tonnes to 446m by 2025, it estimates. Yet in the US alone, 14 unbuilt export terminals with government approval would add 160m tonnes a year of capacity, according to the Federal Energy Regulatory Commission. Another 90m tonnes’ worth of projects are still awaiting approval. Last year, three US projects totalling 30m tonnes in annual capacity received final investment approval from their sponsors. Plunging natural gas prices are also complicating the outlook for companies developing LNG export terminals, as the US benchmark price fell to its lowest level in four years on Monday. Cheaper US gas helps in the intensifying battle for market share, but also makes developers’ projects look less financially viable. Companies are already cutting processing fees, burning cash and letting construction deadlines slip. The global LNG glut has also pushed down prices outside the US as customers use their negotiating power with exporters. The Japan-Korea Marker, a regional benchmark, has been trading at about $5 per million British thermal units, well below the level when most US export projects were conceived. “There’s no question that the marketplace has become increasingly competitive,” said Jeff Martin, chief executive of Sempra Energy, a US company developing LNG terminals. US projects face growing foreign competition from countries including Qatar, the largest and cheapest exporter, which recently confirmed plans to increase output from 77m tonnes to 126m by 2027. Mozambique is entering the market with a 13m tonnes per annum project and Nigeria said in late December that it would raise output from 22.5m tonnes to more than 30m by 2024.

LNG plant explosion raises concerns about federal oversight — Tuesday, January 21, 2020 — Kinder Morgan Inc. is facing a $55,000 fine in connection with a confined explosion in 2018 at its liquefied natural gas export plant near Savannah, Ga., raising safety questions about the facilities as gas exports begin to accelerate.

Trade Deal Impacts the Energy Sector: LNG to Gain the Most? – The Sino-U.S. trade dispute, which threatened the global economy for around two years, has come to an end with the much-anticipated Phase-One trade deal on Jan 15. The signing of the deal was the first tangible indication of de-escalation of the trade brawl between the United States and China, the two largest trading countries. While the Asian giant has agreed to purchase more goods and services from America, Washington has pledged to cut some tariff on Chinese imports. Notably, the U.S. energy sector is poised to gain heavily from this agreement as an export revival is expected. Of the additional $200-billion purchase of U.S. goods over the next two years (keeping 2017 imports as the base level), $52.4 billion will likely come from the energy sector. Per the deal, China will purchase $18.5 billion worth of energy products this year, followed by $33.9 billion imports in 2021. The energy sector stands second only to the manufacturing sector, which will likely witness $77.7 billion of exports. Among the energy products such as liquefied natural gas (LNG), crude oil, natural gas, petroleum products, LNG is expected to gain the most from the deal. Following the U.S. shale revolution, abundance of natural gas in the domestic market and growing demand for cleaner energy sources globally have led to the development of several LNG terminal projects in the past few years. As such, the Washington-Beijing deal can open up a huge market for the U.S. LNG industry. While China is set to become the biggest LNG importer by the end of the decade, the United States is likely to be the largest exporter by 2025, ahead of Qatar and Australia. This makes the two countries a perfect fit even though the whole vision is largely dependent on the fate of the existing 25% Chinese LNG tariff. This was levied during the trade war and its future is still uncertain.

Exclusive: Sinopec to review potential $16 billion U.S. gas deal with Cheniere – sources – (Reuters) – China’s Sinopec, expected to be the next major Chinese buyer of U.S. liquefied natural gas (LNG), is planning to review terms of a potential $16 billion supply deal with Cheniere Energy Inc after a sharp drop in LNG prices, industry officials said. That could delay sign-off on a deal that would help Beijing meet ambitious targets it set for U.S. energy purchases in a Phase 1 trade agreement it signed with the United States on Wednesday. Sinopec, officially named China Petroleum & Chemical Corp, and Houston-based Cheniere had been expected to sign the 20-year deal once a trade truce was reached between Beijing and Washington. However, the LNG market has shifted since news of Sinopec and Cheniere’s negotiations became public early last year. In the intervening period, the U.S.-China trade war sapped Chinese purchases of U.S. LNG, and several other gas suppliers, including Qatar, the lowest-cost producer, decided to build new export plants. That coming supply would add to an existing glut that has caused gas prices to collapse to their lowest levels in years and could keep them suppressed – giving Sinopec additional leverage with Cheniere. Both companies declined to comment. A source familiar with the talks said many items needed to be reviewed as U.S. gas prices have more than halved since 2018. “Sinopec is talking to several other U.S. suppliers,” said a second source. “It’s really not clear at this stage what will come out.” ADVERTISEMENT

Mission Impossible: China can’t meet its commitments on U.S. crude, LNG, coal – Russell – (Reuters) – The more you delve into the details of China’s commitment to buy an additional $52.4 billion in U.S. energy over the next two years, the more it becomes apparent the goal is unachievable, even with the best will in the world. As part of the “Phase 1″ trade truce between Beijing and Washington, China undertook to buy energy over and above a $9.1 billion baseline of U.S. imports in 2017, with a split of an extra $18.5 billion in 2020 and $33.9 billion in 2021. In practical terms this means China’s imports from the United States this year would have to be more than double past record monthly imports of U.S.-sourced crude oil, liquefied natural gas (LNG) and coal. If that already seems difficult, it would take a tripling of the best-ever months to meet the 2021 target. As part of the earlier tit-for-tat tariffs, China imposed a 5% import tax on U.S. crude, 25% on LNG and 25% on coal. These tariffs alone make any imports of U.S. energy uncompetitive, and therefore unlikely unless Beijing is prepared to use its muscle to force state-owned oil refineries, natural gas utilities and steelmakers to pay higher than market rates for U.S. cargoes. There is so far no sign that Beijing is about to remove the tariffs, or issue waivers, and without this the expected ramp-up in purchases of U.S. energy is a non-starter. If China boosted imports of U.S. crude to more than 1 million barrels per day (bpd) – worth around $21.4 billion at the current price of West Texas Intermediate futures – it would present a challenge in physically moving that amount of oil from the U.S. Gulf coast to China. Given that a very large crude carrier (VLCC) holds about 2 million barrels, it would mean 15 of these vessels making the trip every month. While U.S. export terminals may be able to handle this volume, there remain questions over the availability of these vessels and the potential costs of sailing them back empty to the United States to pick up more cargoes. VLCCs are also too big to transit the Panama Canal, likely meaning a longer sea voyage around the bottom of Africa, adding to costs. The economics of shipping crude on smaller vessels that can transit the Panama Canal are also challenging, given such ships can hold only around 600,000 barrels and would have to pay the relatively high canal fees. Then there is the question of whether China’s refineries can use the volumes of U.S. crude that would be required to meet the terms of the deal. Many Chinese refineries are optimized to process heavy, sour grades of crude, such as those from the Middle East, rather than the lighter, sweet oil typically exported by the United States.China does import light crude, taking some 270,000 bpd from the United Kingdom last year, 235,000 bpd from Malaysia, 152,000 bpd from Libya and 44,000 bpd from Nigeria, according to Refinitiv data. If China were to buy more than 1 million bpd of U.S. crude, it would have to stop buying most of the light crude it now gets from other countries. Not only would this disrupt global trade flows and relationships, it also raises the question as to whether Chinese refiners, and U.S. crude exporters, would want to become so reliant on each other, rather than having a diverse range of trading partners.

McDermott Hits Freeport LNG Milestone – The second liquefaction train at Freeport LNG Development, L.P.’s Freeport LNG project on the Texas Gulf Coast has begun commercial operations, McDermott International, Inc. reported Friday. McDermott and Chiyoda International Corp. are members of a Zachry Group-led engineering and construction joint venture developing various phases of Freeport LNG. “We continue to advance the Freeport LNG Project with another significant accomplishment, the commercial operation of Train 2,” Mark Coscio, McDermott’s senior vice president for North, Central and South America, commented in a written statement emailed to Rigzone. “Congratulations to the joint venture project team who has maintained a commitment to safety and quality. Now we turn our full attention to delivery of the final train.” Previously, Zachry and McDermott conducted pre-front-end engineering and design (FEED) and FEED work to support the early development of trains 1 and 2 at Freeport LNG, McDermott stated. It added that Chiyoda later became a co-venturer for the Train 3 project. According to McDermott, the project scope includes:

• Three pre-treatment trains
• A liquefaction facility with three trains
• A second loading berth
• A 165,000-cubic-meter full-containment LNG storage tank.

McDermott noted that Freeport LNG Train 3 is slated to begin producing LNG in the first quarter of this year. Last month it reported that Train 1 had begun commercial operations.

LNG will be much cheaper in 2020. Here’s why and how it affects Texas – Liquified natural gas is forecast to trade for much less in 2020. The U.S. Energy Information Agency said in a report Wednesday it expects lower natural gas prices this year as production is projected to outpace demand. In its January 2020 Short-Term Energy Outlook, the Energy Information Administration predicted average U.S. natural gas prices will be 9% lower in 2020 than in 2019. That’ll be because of continued production growth, the agency says. So, what will that mean for energy-rich South Texas, home to some of the nation’s largest LNG exporters? Increased production of natural gas should meet the growing domestic and global demand for clean natural gas, said Todd Staples, president of the Texas Oil and Gas Association. LNG exports are an important part of the industry’s impact on the state, creating jobs and bolstering local and state economies, while also strengthening the global energy market and helping enhance America’s national security interests, Staples said. “As more pipelines come online connecting the prolific Permian Basin with the Gulf Coast, our capacity to move this high-demand, abundant and affordable resource overseas grows, allowing clean natural gas from the U.S. to replace older, less desirable forms of energy across the globe in places like China and India,” Staples said. Cheniere Energy may be an example of some of that production growth. The Houston company is the largest U.S. producer and exporter of LNG. It has a permit for three production units at its Gregory facility off State Highway 35 and is waiting for a permit to construct seven mid-scale production units, or trains. Together, they will be able to produce 9.5 million metric tons of LNG per year. Last week, Cheniere announced it had been cleared by federal regulators to return one of the two storage tanks at its Sabine Pass LNG export facility back into service. The tank, near Lake Charles, Louisiana, had been offline since a leak there nearly two years ago.

Newly formed Houston pipeline company lands $400 million in financing — A newly formed Houston pipeline company has landed $400 million in financing from San Antonio private equity firm EnCap Flatrock Midstream. Launched just before Thanksgiving and headquartered off Post Oak Boulevard in Houston’s Galleria district, Edgewater Midstream is seeking to build crude oil, refined products and other bulk liquid pipelines.The company plans to use the $400 million to buy, build and operate pipelines and storage terminals in petroleum trading hubs and demand centers in North America where development in the shale basins in Texas and elsewhere has allowed the United States to grow production and exports.“Changing dynamics in the North American petroleum market present attractive opportunities for Edgewater,” the company’s CEO Stephen Smith said in a statement.Joining Smith at Edgewater are former Motiva Enterprises executive oil trader Brian Thomason and Mike Truby, a former senior vice president with the San Antonio pipeline company NuStar Energy.“When forming Edgewater, we recognized that societal, technological and policy trends are reshaping the arena in which traditional oil and gas midstream businesses operate,” Smith said. “Our team embraces new technologies and environmentally sustainable practices.” Headquartered in San Antonio with offices in Oklahoma City and Houston, EnCap Flatrock Midstream manages $9 billion for a broad group of institutional investors.The private equity firm is currently making commitments to new management teams from EFM Fund IV, a $3.25 billion fund.

Schlumberger Posts $10B Loss in 2019 – Schlumberger Ltd. posted a $10.1 billion loss in 2019, despite relatively flat year-on-year revenues, according to the oilfield services giant’s year-end earnings released Friday. Schlumberger CEO Olivier Le Peuch noted 2019 revenues totaled $32.9 billion and called the company’s overall performance positive, namely in the international markets. The company’s revenues for drilling and reservoir characterization benefited from their international market exposure, posting 5 percent and 2 percent year-over-year increases, respectively. But North American revenues fell 10 percent year-over-year to $10.8 billion, driven largely by land market weaknesses. The company began a strategic review of its North American land market in Oct. 2019 after a weak third quarter earnings. “During the year, we recognized material pretax charges driven by market conditions, particularly in North America. As these charges were largely noncash and primarily related to goodwill, intangible assets and fixed assets, they did not impede our ability to generate strong cash flow as we demonstrated in the second half of the year,” Le Peuch said. For fourth quarter of 2019, Schlumberger saw revenues of $8.2 billion, a 4 percent drop from 3Q. International revenue of $5.7 billion grew 2 percent sequentially and 8 percent year-over-year. However, North America revenue was $2.5 billion, a 14 percent sequential decline due to customer budget exhaustion and cash flow constraints. In its North America land market, Schlumberger implemented what it refers to as the “scale-to-fit” strategy, which includes reducing capacity and restructuring the company’s operations.“In North America, we are continuing to scale-to-fit our organization and portfolio by repurposing or exiting underperforming business units, focusing on asset-light operations and expanding our technology access business models,” Schlumberger said it expects the OPEC+ production cuts agreed upon in December to limit investment and activity, namely in Russia and the Middle East, during the first half of 2020. And the slowing growth of North American production is likely to cause tightness in the market and further stimulate international operators to step up their investments in the second half of 2020 and beyond.

Schlumberger lays off 1,400 amid surgical cuts to restore profitability in U.S. shale – The troubled U.S. shale industry is not out of the woods – signaling potential trouble ahead for Houston’s economy. Schlumberger, the largest oil field services company, said Friday it lost $10.1 billion in 2019, laid off 1,400 workers in the fourth quarter, closed facilities, pulled hydraulic fracturing fleets from the field and plans to sell assets. Experts say Schlumberger’s showing sets low expectations for other energy companies preparing to report year-end results and signals that they haven’t adapted to oil prices in the range of $50 to $60 a barrel – too low for many to break even. For the Houston region, which is home to the Paris company’s principal offices, further industry layoffs and spending cuts could put a damper on the local economy. The energy industry’s struggles have already led the Federal Reserve Bank of Dallas to dramatically revise the region’s job growth in the second quarter of 2019 from a robust 4 percent to just a half-percent. More downward revisions are likely. For Schlumberger, the ongoing shale slump resulted in a 10 percent decline in North American revenue in 2019, even as the company saw 8 percent growth internationally. “These macro-conditions will continue,” Schlumberger CEO Olivier Le Peuch said during a Friday morning call with investors. Schlumberger is not alone in feeling the pain as the slowdown in the U.S. shale fields continues. Other oil field service companies are responding by idling equipment and laying off employees. Its Houston competitors Halliburton, National Oilwell Varco and Pumpco Energy Services and the Houston oil field equipment-maker Stewart and Stevenson laid off more than 1,000 employees in November and December. Leaked emails in early January revealed that Houston oil company Occidental Petroleum plans to implement “broad layoffs” in response to its $38 billion acquisition of Anadarko Petroleum. Days later, Houston oil company Apache Corp., oil field services company Enterprise Offshore Drilling and oil equipment-maker Valerus Field Solutions reported that they were cutting a combined 600 jobs. Schlumberger’s 2019 loss follows a $2.2 billion profit in 2018. In the fourth quarter alone, the company’s profit dipped 33 percent, falling to $333 million from $498 million in the previous year while revenue remained steady at $8.2 billion.

IEEFA update: The terrible, horrible, no good, very bad year for oil and gas – Was 2019 the year the music died? 2019 was an especially difficult year for the oil and gas industry. The energy sector (which does not include renewable energy) finished dead last in the S&P 500, the second year in a row it has held that distinction. In a year of improving oil prices, the energy sector still finished firmly in last place, with a 7 percent gain compared to a 29 percent gain overall for the S&P 500. The next worst-performing sector was health care, which posted a 19 percent gain. The industry continued to collapse in value, relative to the broader stock market. The oil and gas sector now comprises 4.3% of the S&P 500 index, compared to 28% in the 1980s. Throughout the year, oil and gas markets remained over-supplied. Oil prices began the year at $55 per barrel and ended the year 24 percent higher, at $68 per barrel. Natural gas prices remained below $3 mmbtu all year long. The oil price increases were not enough to lift investor interest and persistent low prices for natural gas continued as rising supply outpaced rising demand. (detailed chronology follows)

The Great American Shale Oil & Gas Bust: Fracking Gushes Bankruptcies, Defaulted Debt, and Worthless Shares – Following the sharp re-drop in oil and natural gas prices in late 2018, bankruptcy filings in the US by already weakened exploration and production companies , oilfield services companies, and “midstream” companies (they gather, transport, process, or store oil and natural gas) jumped by 51% in 2019, to 65 filings, according to data compiled by law firm Haynes and Boone. This brought the total of the Great American Shale Oil & Gas Bust since 2015 in these three sectors to 402 bankruptcy filings. The debt involved in these bankruptcies in 2019 doubled from 2018 to $35 billion. This pushed the total debt listed in these bankruptcy filings since 2015 to $207 billion. The chart below shows the cumulative total debt involved in these bankruptcies since 2015. But this does not include the much larger losses suffered by shareholders that get mostly wiped out in the years before the bankruptcy as the shares descend into worthlessness, and that then may get finished off in bankruptcy court.The banks, which generally had the best collateral, took the smallest losses; bondholders took bigger losses, with unsecured bondholders taking the biggest losses. Some of them lost most of their investment; others got high-and-tight haircuts; others held debt that was converted to equity in the restructured companies, some of which soon became worthless again when the company filed for bankruptcy a second time. The old shareholders took the biggest losses. The Great American Fracking Bust started in mid-2014, when the price of WTI dropped from over $100 a barrel to below $30 a barrel by early 2016. Then the price began to recover, going over $70 a barrel in September and October 2018. But then it began to re-plunge. By the end of 2018, WTI had dropped to $47 a barrel. Two major geopolitical events in the Middle East – the attack on Saudi Aramco’s oil facilities last September and the US assassination of Iranian Major General Qasem Soleimani – that would have shaken up oil markets before, only caused brief ripples, quickly squashed by the onslaught of surging US production. At the moment, WTI trades at $56.08 per barrel, which is still below where the shale oil industry can survive long-term: And 2020 is starting out terrible for natural gas producers. The price of natural gas has plunged to $1.90 per million Btu at the moment, a dreadfully low price where no one can make any money. Producers in shale fields that produce mostly gas, such as the Marcellus, are in deeper trouble still, because oil, even at these prices, would be a lot better than just natural gas. Producing areas with constrained takeaway capacity (it takes a lot longer to build pipelines than to ramp up production) are subject to local prices, which can be lower still. In some areas, such as the Permian in Texas and New Mexico, the most prolific oil field in the US, where natural gas is a byproduct of oil production, limited takeaway capacity has caused local prices to collapse, and flaring to surge. The chart shows the spot price for delivery at the Henry Hub:

The “Twin Threats” Facing Big Oil — The global oil and gas industry is facing the “twin threats” of the loss of profitability and the loss of social acceptability as the climate crisis continues to worsen. The industry is not adequately responding to either of those threats, according to a new report from the International Energy Agency (IEA). “Oil and gas companies have been proficient at delivering the fuels that form the bedrock of today’s energy system; the question that they now face is whether they can help deliver climate solutions,” the IEA said.The report, whose publication was timed to coincide with the World Economic Forum in Davos, critiques the oil industry for not doing enough to plan for the transition. The IEA said that companies are spending only about 1 percent of their capex on anything outside of their core oil and gas strategy. Even the companies doing the most are only spending about 5 percent of their budgets on non-oil and gas investments.There are some investments here and there into solar, or electric vehicle recharging infrastructure, but by and large the oil majors are doing very little to overhaul their businesses. The top companies only spent about $2 billion on solar, wind, biofuels and carbon capture last year.Before even getting to the transition risk due to climate change, the oil industry was already facing questions about profitability. Over the past decade the free cash flow from operations at the five largest oil majors trailed the total sent to shareholders by about $200 billion. In other words, they cannot afford to finance their operations and also keep up obligations to shareholders. Something will have to change. But, of course, as climate policy begins to tighten, oil demand growth will slow and level off. Most analysts say that it won’t require a big hit to demand in order for the financial havoc to really begin to devastate the balance sheets of the majors. Demand only needs to stop growing. The IEA said there are things the industry can do right now – and should have done a long time ago. Roughly 15 percent of the energy sector’s total greenhouse gas emissions comes from upstream production. “Reducing methane leaks to the atmosphere is the single most important and cost-effective way for the industry to bring down these emissions,” the IEA said. But, the Permian is flaring more gas than ever, and methane leaks at every stage of the extraction and distribution process. Drillers have promises improvements, but the industry’s track record to date is not good. Meanwhile, the IEA also noted that while attention is often focused on the oil majors, national oil companies (NOCs) account for more than half of global oil production. The majors only account for about 15 percent.

Oil and gas firms must invest in clean energy solutions to survive: IEA – Oil and gas companies put their own survival at risk if they fail to adapt to providing clean-energy solutions to the world, the International Energy Agency said in a report Monday. The Paris-based IEA said the largest oil and gas companies spend less than 1 percent of their total capital dollars on renewable energy and clean-energy projects. That trend must change quickly, the agency said in its new report on energy transitions. “No energy company will be unaffected by clean energy transitions,” said Fatih Birol, IEA executive director. “Every part of the industry needs to consider how to respond. Doing nothing is simply not an option.” The biggest and easiest adjustment that oil and gas firms can make is cut down on their methane emissions, which is a big problem in areas such as West Texas’ booming Permian Basin. Methane, the primary component of natural gas, is a potent greenhouse gas that’s often released into the atmosphere – intentionally or not – while producing the more valuable crude oil from wells.”Around 15 percent of global energy-related greenhouse gas emissions come from the process of getting oil and gas out of the ground and to consumers,” Birol said. “A large part of these emissions can be brought down relatively quickly and easily.” Reducing methane leaks is the single most important and cost-efficient way for energy companies to reduce emissions, the report said. The oil and gas industry also has the technical know-how to advance renewable energy worldwide, especially when it comes to areas like offshore wind where energy firms have to most experience operating in deeper waters. Norway-based Equinor, a major oil and gas firm, for instance has become a leader in offshore wind development.

Proposed 626-mile pipeline would transit much of the Concho Valley -Landowners along a 626-mile swath of Texas and Louisiana began receiving letters last month from Houston-based Tellurian Inc. relating to the proposed Permian Global Access Pipeline. The project is being engineered with an eye on transmitting 2-billion cubic-feet of natural gas per day from West Texas to the Lake Charles area by late 2023 or early 2024. According to Joi Lecznar, Tellurian’s vice president for public affairs and communication, the concept was proposed in 2017 as part of the company’s wider strategy to form a $7 billion pipeline network along with the proposed Driftwood Liquified Natural Gas Terminal in Louisiana. The pipeline proposals are expected to create about 15,000 jobs during the construction phases, according to Tellurian. If everything goes according to plan, the pipeline should be a modern marvel of engineering, and Lecznar said planners have carefully selected a path that will have minimal impact on forests, wetlands and developments along the shortest possible route. Along the entire length, the preferred route would cut through 257-miles of open land, 137-miles of agricultural land, 80-miles of developed land, 151-miles of forest and 1 mile of open water with 80 water crossings. According to initial regulatory filings, the proposed route would require 253-miles of new right-of-way while using 373-miles of adjacent existing right-of-way corridors. This path begins at the Waha Gas Hub in northern Pecos County and traverses Crane, Upton, Reagan, Irion, Tom Green, Concho, McCulloch, San Saba, Mills, Lampassas, Coryell, McClennan, Falls, Limestone, Robertson, Leon, Houston, Trinity, Polk, Tyler, Jasper and Newton counties before entering Louisiana. Along the entire length, the proposed route would cut through 257-miles of open land, 137-miles of agricultural land, 80-miles of developed land, 151-miles of forest and 1-mile of open water. This includes, 80 perennial waterbody crossings, 19 of which are major crossings of 100-feet or more. The path includes three designated natural and scenic river crossings, and 24 ponds. The proposed Permian Global Access Pipeline would cross Spring Creek in Irion County just east of US Highway 67 and south of Farm-to-Market Road 72. (The Dove Creek label on the map is a mistake acknowledged by the company.)

Water district joins in fight against natural gas pipeline -A small but determined group of opponents to Kinder Morgan’s Permian Highway Pipeline gathered in downtown Kyle for the first of two protests last week. Carrying signs that said “Safe pipelines don’t exist” and “Clean energy now,” they encouraged passing motorists to honk their support, and many did as they passed the corner of Center and Burleson. At issue is the routing of the 42-inch, natural gas pipeline through some of the most environmentally-sensitive areas of the Texas Hill Country, putting in jeopardy the Edwards and Trinity aquifers, all the springs they produce and species they support. The latest salvo in the ongoing war between the company, landowners, environmental groups and governmental entities came Jan. 16, when the Barton Springs Edwards Aquifer Conservation District (BSEACD) voted to join a lawsuit against Kinder Morgan, the U.S. Fish & Wildlife Service (USFWS) and the U.S. Army Corps of Engineers (USACE) that alleges violations of the Endangered Species Act. Specifically, the legal action argues there “is not a reasonable assurance that the aquifers will be protected during the construction and operation of the pipeline.” The project has met with stiff opposition ever since the energy giant began approaching Central Texas landowners in late 2018. Because they are considered infrastructure, pipelines companies have the power of eminent domain. Because it is completely within the state of Texas, the project does not require approval from any state agency except the Railroad Commission. Plaintiffs in the suit say the actions of Kinder Morgan – which has already begun construction at the west end of the pipeline – is “attempting to avoid” steps including obtaining a biological opinion from USFWS, the preparation of an incidental take permit and the creation of a habitat conservation plan, “both of which are called for when any action – direct or indirect – presents a signifiant threat to a species or its habitat in wetlands under the USACE’s jurisdiction as well as in uplands on private lands.”

Barton Springs group to join legal battle against Kinder Morgan pipeline – The Barton Springs Edwards Aquifer Conservation District has voted to join an endangered species lawsuit that will be filed to halt the construction of a $2 billion natural gas pipeline through portions of the Texas Hill Country. The district is the latest to support the legal action against the U.S. Fish and Wildlife Service, U.S. Army Corps of Engineers and Houston pipeline company Kinder Morgan. With Kinder Morgan’s planned Permian Highway Pipeline routed through part of the district’s territory in Hays County, opponents fear that the project will harm the Edwards Aquifer and endangered and threatened species that depend on its waters such as the Texas blind salamander, Barton Springs salamander, Austin Blind salamander, San Marcos salamander, fountain darter, Comal Springs dryopid beetle and the Comal Springs riffle beetle.Designed to move 2.1 billion cubic feet of natural gas per day from the Permian Basin of West Texas to the Katy Hub near Houston, the proposed route takes the 42-inch pipeline through the picturesque Texas Hill Country, where the project faces stiff opposition. Kinder Morgan declined to comment but has maintained that the pipeline route was carefully chosen to affect the fewest number of landowners. The company said it held several public meetings before moving forward with the project. Under Texas state law, pipelines require an easement that must be kept clear. Kinder Morgan designed the proposed pipeline route to include a 600-foot-wide corridor that allows for some flexibility and adjustments. The company contends the pipeline would generate nearly $1 billion annually to state and county governments and unlock production bottlenecks in the Permian Basin – allowing leaseholders to earn more than $2 billion in annual royalties for landowners, school districts and counties.

Integrity tests done on Arkansas oil pipeline that ruptured (AP) – A company tested the integrity of a segment of pipeline that has been idle since it ruptured in 2013, spilling 5,000 barrels of crude oil in a Arkansas neighborhood and causing more than $57 million in damage. The tests conducted on the Permian Express pipeline from Wednesday through Friday suggest pipeline operator Energy Transfer Partners LLC is considering reopening it for the first time since the spill in the Mayflower. But company officials declined to tell the Hot Springs Sentinel-Record when or if it planned to do so. “We are performing integrity tests to ascertain the status of the pipeline as it has been inactive since 2013,” company spokeswoman Amanda Gorgueiro said in an email. “As with all of our pipelines, these tests are performed per PHMSA (Pipeline and Hazard Materials Safety Administration) regulations.” The Dallas-based company, which acquired the pipeline in 2016 through a joint venture with Exxon Mobil, notified Central Arkansas Water of the inspection, utility CEO Tad Bohannon said Thursday. Energy Transfer is not legally obligated to tell the water utility or the public if it tests or reopens the pipeline, but Bohannon said he has been in constant contact with the company and hopes the process will remain transparent. Faulkner County Judge Jim Baker said the spill greatly affected the Mayflower community, but he believed the pipeline would be regulated enough to ensure safety. “You always have that concern,” Baker said. “I don’t think it would open without it being serviceable and sound.” The pipeline, formerly known as the Pegasus Pipeline, stretches from south Texas to Illinois. It runs through 13 miles of the Lake Maumelle watershed, which is the largest drinking water reservoir in Arkansas and provides drinking water to about half a million people. It also runs through 20 smaller watersheds in communities across Arkansas.

Whole Neighborhoods Destroyed In Houston Plant Explosion- Multiple Fatalities, 1 Still Missing – Houston was rocked by a large explosion in the early dark hours of Friday morning, which could be felt for miles across the city, when a manufacturing facility in the northwest erupted in a massive fireball. Houston police have confirmed that at least two people died in the blast, with one plant employee still missing, and a criminal investigation is underway as to the cause – though there’s no evidence thus far to suggest an intentional act or terrorism was involved. Damage to homes was reported up to a half-mile away after it occurred at about 4:15am, some 18-miles away from the downtown area, though people reported being jolted from their sleep for miles across the city. Later in the morning Friday multiple people were reported hospitalized, and others may still be missing. “We have no evidence at this point … that an intentional act is involved. Having said that, part of our protocol is always to (start) a criminal investigation” Houston police chief Art Acevedo said, who also ruled out terrorism. “It’s going to take days, if not weeks or months, to get a final determination of what’s going on here.” Early reports suggest propylene tanks ignited, which is a common but extremely flammable gas used at manufacturing plants. The explosion occurred at Watson Grinding and Manufacturing where emergency crews are still trying to contain a possible gas leak. Local videos showed a large fireball rising from the site of the plant in the blast’s immediate aftermath. Officials say the blast was so big it appeared on weather radar.

2 people killed in an explosion at a Houston manufacturer that shook the city and damaged homes – Two people were killed in Friday morning’s explosion at a northwest Houston manufacturing business, police said — a blast shook much of the city, damaged buildings up to a half mile away and left some residents at least temporarily displaced. The explosion rocked Watson Grinding and Manufacturing around 4:15 a.m. CT (5:15 a.m. ET), tearing apart several structures while sending debris and shock waves much farther, pushing some nearby homes off their foundations, officials said. “This is, in essence, a disaster area right now,” Houston Police Chief Art Acevedo said of the area roughly an 18-mile drive northwest of downtown.The two men who died in the blast were Frank Flores and Gerardo Castorena, both employees of the company, Houston Fire Chief Samuel Pena said.Pena said Friday evening that 214 homes were damaged in some way and, according to an initial rough estimate, about 50 were destroyed.Responding to reports that the explosion was caused by the gas propylene, a fire department spokeswoman told CNN Friday afternoon: “We don’t know that propylene caused the explosion, only that propylene tanks are on site and were involved in the explosion and fire.” The debris field is so widespread — officials estimated between a quarter-mile to a mile away — police have asked residents for help with a potentially grim task: looking for human remains and other debris in their yards and on roofs.

Two years after five killed Oklahoma well explosion, few changes in safety rules – Two years ago, an oil well near a small Oklahoma town exploded into a fireball that swept through a drilling rig, killing five in an accident deemed a needless catastrophe by federal investigators and casting a short-lived spotlight on a lack of regulation and oversight across the oil and gas industry.The accident involving a Houston drilling company was the industry’s deadliest since the Deepwater Horizon tragedy 10 years ago, but the response to the Oklahoma explosion has been far less urgent. While the Gulf of Mexico explosion, which killed 11, spurred a drilling moratorium and a wave of new regulations, the Oklahoma disaster entered the national headlines for a brief spell and was quickly forgotten – even after the U.S. Chemical Safety and Hazard Investigation Board found widespread failures and a woeful lack lack of safety standards and rules in the onshore drilling sector.What has happened since then? Not much. “There’s not really a whole lot of rules and regulations for safety on the state and federal levels, and that’s what we’re trying to correct.” The safety board’s report was scathing. It found that the companies planned poorly and cut corners, resulting in myriad contributing factors to the five deaths, including a failed blowout preventer, a muted alarm system, lapses in well monitoring, inadequate employee training, and not enough emergency exits in the driller’s cabin, called the doghouse, where the workers were trapped.The Chemical Safety Board also found that state and federal safety laws governing drilling are inadequate, as are the standards adopted by the American Petroleum Institute, the industry’s trade group. Federal and state regulators and API are beginning to consider the safety board’s recommendations, which range from better well control rules to tougher equipment standards to improved employee training, but bureaucracy moves slowly, said Grim. More substantial changes could still be a couple years away or so. “It’s really hard to say how it will turn out until we see all the responses and the end results.”

The Fracking Industry’s Methane Problem Is a Climate Problem – While carbon dioxide – deservedly – gets a bad rap when it comes to climate change, about 40 percent of global warming actually can be attributed to the powerful greenhouse gas methane, according to the 2013 IPCC report. This makes addressing methane emissions critical to stopping additional warming, especially in the near future. Methane is shorter-lived in the atmosphere but 85 times more potent than carbon dioxide over a 20 year period. Atmospheric levels of methane stopped increasing around the year 2000 and at the time were expected to decrease in the future. However, they began increasing again in the last 10 years, spurring researchers to explore why. Robert Howarth, a biogeochemist at Cornell University, recently presented his latest research linking the increase in methane to fossil fuel production, with fracking for natural gas, which is mostly methane, likely a major source. Howarth argued that 3.4 percent of all natural gas produced from shale in the U.S. is leaked throughout the production cycle. Howarth’s research links the increase in methane to the U.S. production of shale gas via fracking. The beginning of the U.S.fracking boom coincides with the beginning of the rise in methane in the past decade, and a 2018 NASA study linked the industry to this methane spike. One thing that is becoming increasingly clear about the U.S. fracked oil and gas industry is that it leaks methane – a lot of methane. About 60 percent more methane than previous Environmental Protection Agency estimates, which relied heavily on industry self-reporting, according to a 2018 study published in the journal Science. While the oil and gas industry makes claims about wanting to reduce methane leaks, it has been aided by two simple facts that help hide the scale of the problem: Methane is odorless and invisible to the naked eye. Difficult to detect, methane leaks in the oil and gas production system weren’t obvious until people like Sharon Wilson at Earthworks began bringing specialized infrared cameras to production facilities and helped make those leaks visible. But it isn’t just unintentional leaks. Much of the methane released is intentionally “vented” to the atmosphere in areas without the processing plants, pipelines, and other expensive infrastructure to make use of it.

IEA warns oil companies doing nothing on emissions is not an option – – In a report with the World Economic Forum presented in Davos, the IEA said oil and gas companies face a critical challenge as the world increasingly adopts clean energy transitions to curb global warming. Around 15% of global energy-related emissions come from the process of getting oil and gas out of the ground and to consumers, the IEA said. Energy-related green house gas emissions rose to a record high in 2018. The Paris-based agency, which advises industrialized nations on energy issues, said oil and gas companies are facing increasing demands to explain how they intend to reduce emissions in line with the 2015 Paris climate agreement. “Every part of the industry needs to consider how to respond. Doing nothing is simply not an option,” IEA’s Executive Director Fatih Birol, said in a statement. The companies are under pressure to cut emissions from their operations and from their products as used by customers, as well as to increase investments in cleaner energies. Targets by oil firms to cut their emissions and switch to cleaner energies vary widely. “The first immediate task for all parts of the industry is reducing the carbon footprint of their own operations,” Birol said, adding that a large part of the emissions from the sector can be brought down relatively quickly and easily, such as reducing methane leaks. The IEA said another key move by the sector would be to boost investments in the cleaner fuels – such as hydrogen, biomethane and advanced biofuels. “Within 10 years, these low-carbon fuels would need to account for around 15% of overall investment in fuel supply if the world is to get on course to tackle climate change,” it said. So far, average investment by oil and gas companies in non-core areas such as renewables, is still limited to around 1% of total capital spending, mostly on solar and wind projects.

Big Oil wants to dump more wastewater into rivers. What could go wrong? –The industry generates mind-boggling quantities of this waste, which is called “produced water” in industry parlance. Oklahoma, Texas, and New Mexico producers alone generated about 270 billion gallons of it in 2017. That’s enough water to fill the New York Giants stadium more than 550 times over. As oil and gas producers face increasing regulation of underground wastewater disposal – in part to limit earthquakes that result from the pressure injection puts on rocks – they’re looking for new ways to get rid of the fluid left behind after fracking and drilling. That pinch is being felt particularly acutely in Oklahoma, Texas, and New Mexico, which have experienced a fracking boom in the last few years and have limited ways to dispose of the substance.Much to the alarm of environmentalists and public health experts, those three states are now exploring expanding avenues for produced water disposal – including discarding the wastewater in streams and rivers.. East of the 98th meridian – an imaginary line that runs down the middle of Kansas, Oklahoma, and Texas – oil and gas operators are allowed to release treated wastewater into rivers, but only if it’s first routed through treatment facilities capable of removing the chemicals contained in the waste. West of the meridian, which includes half of Texas and Oklahoma as well as all of New Mexico, oil and gas companies can discard produced water into rivers without that hurdle, so long as they secure government permits.. Producers say they are time-consuming and cumbersome to obtain. As a result, last year Texas and Oklahoma took steps to take over permitting from the EPA. New Mexico is considering following suit. The EPA has also been considering easing regulations – including the 98th meridian rule – which could further expand the industry’s wastewater disposal options. The agency is set to publish a final report with its findings in the next few months.

How One Utah Community Fought the Fracking Industry – and Won – A sign at the north end of Kanab, Utah, proclaims the town of 4,300 to be “The Greatest Earth on Show.” It’s a rare case of truth in advertising. Kanab sits just seven miles north of the Arizona state line, at the crossroads of some of the Southwest’s most beautiful places. In every direction a geologic wonderland awaits. To the north is Zion National Park with its breathtaking valley of 2,000-foot-tall rust and white sandstone cliffs. The sweeping expanse of Grand Staircase-Escalante National Monument stretches to the east of town, and just to the south you’ll find the Grand Canyon’s North Rim. There, a company called Southern Red Sands LLC had announced plans to build a facility to mine and process massive amounts of sand for use by oil and gas companies conducting hydraulic fracturing. The sand is a lesser-known but substantial aspect of the fracking process. Round grains of silica sand serve as a “proppant” to keep underground fissures in the shale open as oil and gas are pumped out. Fracking a single well can require thousands of tons of sand. “I really wanted to keep an open mind, but the more I learned about the project, the more concerned I got,” Hand told The Revelator when I visited Kanab in September. She had reason to be worried. The first decade of the fracking boom relied heavily on so-called “frac sand” sourced mostly from Midwest states like Minnesota and Wisconsin, where mining reduced verdant green hills to piles of dust. But mining in the Midwest has its limits. Sand is expensive to ship across the country, so as fracking has taken off in Utah, Texas and New Mexico, companies have looked to find more local sources to trim costs. Southern Red Sands, a two-person start-up backed by Utah real-estate developer Kem Gardner, hoped to establish the region’s next frac sand mine in a scenic area of state-owned lands outside Kanab called Red Knoll. Despite public pushback and some legal challenges, though, the frac sand mine seemed to be cruising toward approval as recently as October. It still needed an environmental impact assessment from the Bureau of Land Management, and the two water transfers needed approval from the state engineer. The project definitely wasn’t a done deal, but in industry-friendly Utah, it had a good shot. So it may have come as a surprise to a number of residents when Southern Red Sands announced at the beginning of January that it was abandoning the proposed project. What happened? And are there any lessons that other communities fighting extraction threats can learn? “Speak out, pull together like-minded neighbors, organize and don’t give up,” Hand told me after hearing the news. “But also, try to be nice.”

Iowa wants expert review of Dakota Access Pipeline expansion (AP) – Iowa regulators want owners of the Dakota Access Pipeline to provide expert analysis to back up the company’s claim that doubling the line’s capacity won’t increase the likelihood of a spill, a requirement their counterparts in North Dakota haven’t imposed. Texas-based Energy Transfer wants to double the capacity of the pipeline to as much as 1.1 million barrels daily to meet growing demand for oil shipments from North Dakota, and is seeking permission for additional pump stations in the Dakotas, Iowa and Illinois to do it. Commissioners in a South Dakota county last year approved a conditional use permit for a pumping station needed for the expansion. Permits in the other states are pending. The Iowa Utilities Board last week ordered the company to “provide expert explanation of whether the increased flow will increase the amount of oil that will be released if a spill occurs.” The nonpartisan panel, whose three members all were appointed by a Republican governor, also wants information on pipeline pressure levels currently and if the expansion occurs. The company also must provide “expert explanation” on the effect any additives to the oil would have on the longevity of the pipeline. The $3.8 billion pipeline has been moving oil from the Dakotas through Iowa to Illinois for more than two years. It was subject to prolonged protests and hundreds of arrests during its construction in North Dakota in late 2016 and early 2017 because it crosses beneath the Missouri River, just north of the Standing Rock Sioux Reservation. The tribe draws its water from the river and fears pollution. Energy Transfer insists the pipeline and its expansion are safe. Tribal members are asking the North Dakota Public Service Commission to deny the expansion of the pipeline, saying it would “increase both the likelihood and severity of spill incidents.” The company said in court filings that its $40 million pump station built on a 23-acre site would produce only “minimal adverse effects on the environment and the citizens of North Dakota.” The North Dakota PSC in November held a hearing on the proposed expansion that was overseen by an administrative law judge. The 17-hour-long hearing was held in Linton, a town of 1,000 along the pipeline’s path and near where a pump station would be placed to increase the line’s capacity from 600,000 barrels per day to as much as 1.1 million barrels. A barrel is 42 gallons.

Dakota Access seeks to push more oil through pipeline -Iowa regulators want owners of the Dakota Access Pipeline to provide expert analysis to back up the company’s claim that doubling the line’s capacity won’t increase the likelihood of a spill, a requirement their counterparts in North Dakota haven’t imposed.Texas-based Energy Transfer wants to double the capacity of the pipeline to as much as 1.1 million barrels daily to meet growing demand for oil shipments from North Dakota and is seeking permission for additional pump stations in the Dakotas, Iowa and Illinois to do it. Commissioners in a South Dakota county last year approved a conditional use permit for a pumping station needed for the expansion. Permits in the other states are pending.The Iowa Utilities Board last week ordered the company to “provide expert explanation of whether the increased flow will increase the amount of oil that will be released if a spill occurs.”The nonpartisan panel, whose three members all were appointed by a Republican governor, also wants information on pipeline pressure levels currently and if the expansion occurs. The company also must provide “expert explanation” on the effect any additives to the oil would have on the longevity of the pipeline.The $3.8 billion pipeline has been moving oil from the Dakotas through Iowa to Illinois for more than two years. It was subject to prolonged protests and hundreds of arrests during its construction in North Dakota in late 2016 and early 2017 because it crosses beneath the Missouri River, just north of the Standing Rock Sioux Reservation. The tribe draws its water from the river and fears pollution. Energy Transfer insists the pipeline and its expansion are safe. Tribal members are asking the North Dakota Public Service Commission to deny the expansion of the pipeline, saying it would “increase both the likelihood and severity of spill incidents.” The company said in court filings that its $40 million pump station built on a 23-acre site would produce only “minimal adverse effects on the environment and the citizens of North Dakota.” The North Dakota PSC in November held a hearing on the proposed expansion that was overseen by an administrative law judge. The 17-hour-long hearing was held in Linton, a town of 1,000 along the pipeline’s path and near where a pump station would be placed to increase the line’s capacity from 600,000 barrels per day to as much as 1.1 million barrels.

North Dakota signals no new conditions on pipeline expansion (AP) – North Dakota regulators signaled Thursday that the state would not impose conditions beyond those required by the federal government on a proposal to double the capacity of the Dakota Access Pipeline. Zachary Pelham, an attorney for the three-member, all-Republican North Dakota Public Service Commission told the panel that requiring additional measures could be considered “outside our lane” and “potentially problematic,” drawing a legal challenge from Texas-based Energy Transfer, the pipeline’s owner. The company wants to double the capacity of the pipeline to as much as 1.1 million barrels daily to meet growing demand for oil from North Dakota. It’s seeking permission for additional pump stations in the Dakotas, Iowa and Illinois. Commissioners in a South Dakota county last year approved a conditional use permit for a pumping station. Permits in the other states are pending. Iowa regulators last week said the company must provide expert analysis to back up its claim that doubling the line’s capacity won’t increase the likelihood of a spill. On Tuesday, opponents of the expansion said the Illinois Commerce Commission voted to require the company to provide justification that the additional capacity is needed, including identifying shippers and contracts. The commission did not return telephone calls Thursday to confirm the action. The $3.8 billion pipeline was subject to prolonged protests and hundreds of arrests during its construction in North Dakota in late 2016 and early 2017 because it crosses beneath the Missouri River, just north of the Standing Rock Sioux Reservation. The tribe draws its water from the river and fears pollution. Tribal members are asking North Dakota regulators to deny the expansion, saying it would “increase both the likelihood and severity of spill incidents.” The tribe wants North Dakota regulators to seek a similar analysis to that sought by regulators in Iowa and Illinois.

For North Dakota oil production, it’s ‘steady as she goes’ – North Dakota’s oil production in November was down a tad from a record October, though natural gas output continued to climb. North Dakota, the nation’s second-largest oil-producing state after Texas, pumped out 1.52 million barrels per day in November, down 0.2% from the previous month. “It was pretty much ‘steady as she goes,’ ” Lynn Helms, director of the North Dakota Department of Mineral Resources, said in a webcast with reporters. With winter setting in, Helms said he doesn’t see significant oil and gas production changes ahead. “I’m really expecting these numbers to stay flat the next two or three months.” North Dakota produced 3.13 million MCF per day of natural gas in November, up 2% from a record October. (An MCF is 1,000 cubic feet of natural gas.) Also, North Dakota’s natural gas “capture” rate improved a bit in November, though it’s still below the state’s goals. Oil and gas operators captured 83% of gas production, up from 82% in October. The remainder was burned off in an economically wasteful and carbon-emitting practice called flaring. North Dakota operators are supposed to be capturing 88% of their gas production and flaring only 12%. Helms said gas capture will improve with the December completion of a new gas pipeline and should continue getting better as new gas processing capacity comes online this year. On the negative side, gas and petroleum production this spring could be hurt by extended road restrictions in North Dakota’s oil patch. A wet fall combined with an early cold snap has produced a “very deep frost,” Helms said. “Roads will be soft going into spring.” Heavy-equipment restrictions on county and township roads that normally end around Mother’s Day may not expire until Father’s Day, Helms said.

Keystone XL Inches Forward – TC Energy Corp. plans to begin pre-construction work on the Keystone XL oil pipeline next month, moving the long-delayed project forward even as opponents continue to fight it in court. Heavy construction equipment will be moved to worker campsites and pipeline storage sites in Montana, South Dakota and Nebraska in February, the Calgary-based company said in a filing with the U.S. District Court in Montana on Tuesday. TC then plans to start building the part of the conduit that crosses the U.S.-Canada border in April. The filing shows that TC Energy is pushing the $8 billion project forward despite continued opposition from environmental activists and some landowners. The pipeline is still tied up in a legal battle in Montana, and the company noted that it needs additional authorizations and permits to build the border-crossing segment. The 1,200-mile (1,900-kilometer) pipeline would help carry 830,000 more barrels of crude a day from Alberta’s oil sands to U.S. Gulf Coast refineries, easing a pipeline shortage that has hurt Canada’s oil industry. Environmentalists have opposed the project, arguing that it would contribute to catastrophic climate change by allowing more oil production.

South Dakota board approves Keystone XL water permits – The South Dakota Water Management Board on Tuesday approved five water permit applications for Keystone XL pipeline construction. The hearing was so contentious that it stretched into a dozen days over the course of four months as American Indian tribes and environmental groups argued against their approval. After holding a brief period for public comment in Fort Pierre Tuesday, the board met in a closed executive session before voting to approve the permits, with added requirements for real-time monitoring and weekly check-ins with the state. Opponents can appeal the board’s decision. They didn’t immediately respond to messages from The Associated Press seeking comment. TC Energy, the Canadian company building the pipeline, applied for permits to tap the Cheyenne, White and Bad rivers in South Dakota during construction. The water will be used for drilling to install pipe, build pump stations and control dust during construction. Two ranchers also applied for water permits to supply backup water to worker camps. The board allowed three minutes for each person who wanted to comment before the executive session. Two Native American youths – Tatanka Itancan, age 17, and his sister Zora Lone Eagle, age 13 – with painted handprints on their faces used their three minutes to silently stare at the board in protest. They said they had been refused permission to cross-examine experts during the hearing because they are minors and not represented by an attorney. Itancan said they live within a couple miles of where the pipeline would cross the Cheyenne River.

Trump administration approves Keystone pipeline on US land (AP) – The Trump administration on Wednesday approved a right-of-way allowing the Keystone XL oil sands pipeline to be built across U.S. land, pushing the controversial $8 billion project closer to construction though court challenges still loom. The approval signed by Interior Secretary David Bernhardt and obtained by The Associated Press covers 46 miles (74 kilometers) of the pipeline’s route across land in Montana that’s controlled by the Bureau of Land Management and the U.S. Army Corps of Engineers, said Casey Hammond, assistant secretary of the Interior Department. Those segments of federal land are a small fraction of the pipeline’s 1,200-mile (1,930-kilometer) route, but the right-of-way was crucial for a project that’s obtained all the needed permits at the state and local levels. The pipeline would transport up to 830,000 barrels (35 million gallons) of crude oil daily from western Canada to terminals on the U.S. Gulf Coast. Project sponsor TC Energy said in a court filing that it wants to begin construction on the U.S.-Canada border crossing in Montana in April. Opponents promised to challenge those plans in court. First proposed in 2008, the pipeline has become emblematic of the tensions between economic development and curbing the fossil fuel emissions that are causing climate change. The Obama administration rejected it, but President Donald Trump revived it and has been a strong supporter. The stretch approved Wednesday includes all federal land crossed by the line, Hammond said. Much of the rest of the route is across private land, for which TC Energy has been acquiring permissions to build on. Environmentalists and Native American tribes along the pipeline route say burning the tar sands oil will make climate change worse, and that the pipeline could break and spill oil into waterways like Montana’s Missouri River. They have filed numerous lawsuits.

.