Oil, Gas, And Fracking News Reads: 21July, 2019 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 21 July 2019.

This article is a feature every Monday evening on GEI.

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Oil & gas sell off after Barry clears; DUCs down for a 4th month as drilling slows, uncompleted well backlog at 6 months

Oil prices fell more than 7% this week as Gulf of Mexico production came back on line and tensions between Iran and the US showed signs of easing…after rising nearly 5% to $60.21 a barre last week as tropical storm Barry disrupted production and shipping in the Gulf, the contract price of US crude for August delivery initially moved higher on Monday as Chinese industrial production and retail sales reports beat expectations, but ultimately turned lower and gave back a portion of last week’s storm gains, as Gulf of Mexico operations began to recover, with oil closing down 63 cents at $59.58 a barrel…oil prices were again lower on Tuesday morning as more production facilities returned to operation in the Gulf, and then retreated further on Tuesday afternoon after Secretary of State Mike Pompeo said that Iran was ready to negotiate its missile program, with US crude closing down $1.96 at $57.62 a barrel…oil prices initially rose Wednesday even as API data suggested U.S. crude inventories fell less than expected, but then fell to close 84 cents lower at 56.78 a barrel, after the EIA reported massive increases in oil product inventories and Trump sent Senator Rand Paul as his emissary to mediate with Iran, signalling that Trump is serious about getting a deal done…oil prices moved lower again on Thursday, despite Iran’s claim that it seized a foreign oil tanker in the Persian Gulf, as the International Energy Agency’s latest Oil Market Report forecast that a huge glut of oil would build up next year, with oil prices falling $1.48 to $55.30 a barrel by the close…oil prices then moved higher Friday on reports that Iran had seized a British-flagged oil tanker in the Strait of Hormuz, with US crude briefly touching $56.36 a barrel after the U.S. Navy destroyed an Iranian drone nearby, before falling back to $55.63 a barrel by the end of trading in New York, an increase of just 33 cents on the day…nonetheless, US WTI crude still fell 7% for the week while the international oil benchmark Brent lost about 5.5%, the steepest losses for both oil benchmarks since late May…

Natural gas prices, meanwhile, ended the week more than 8% lower, despite the onset of a heatwave stretching from Colorado to the East Coast and the first lower than average injection of gas into storage in 18 weeks…after finishing the prior week 1.4% higher at $2.453 per mmBTU as hurricane Barry bore down on Louisiana, prices of natural gas for August delivery started the new week by giving up the entire prior week’s gain and then some, falling 4.5 cents as forecasts for the final part of July showed a change to cooler weather….prices then fell 10.2 cents on Tuesday and two-tenths of a cent on Wednesday as the shift to cooler in the weather pattern for the balance of July became more entrenched…prices were quite volatile with the release of the storage report on Thursday, initially jumping more than 5 cents, but then falling back to end down 1.7 cents as traders brushed aside the bullish storage number…the selling of natural gas contracts continued on Friday, as prices slid another 3.6 cents to end the week at $2.251 per mmBTU, thus having fallen every day this week…

The natural gas storage report for the week ending July 12th from the EIA indicated that the quantity of natural gas held in storage in the US increased by 62 billion cubic feet to 2,533 billion cubic feet by the end of the week, which meant our gas supplies were 291 billion cubic feet, or 13.0% greater than the 2,242 billion cubic feet that were in storage on July 12th of last year, while still 143 billion cubic feet, or 5.3% below the five-year average of 2,676 billion cubic feet of natural gas that have been in storage as of the 12th of July in recent years….this week’s 62 billion cubic feet injection into US natural gas storage was a bit below S&P Global Platts’ survey of analysts that forecast a 65 billion cubic feet injection into storage, and it was also lower than the average 63 billion cubic feet of natural gas that have been added to gas storage during the second week of July in recent years, the first below average storage change in 18 weeks….nonetheless, the 1,355 billion cubic feet of natural gas that have been added to storage over the past 16 weeks is still the largest injection of gas into storage on record for any similar period of the injection season…this week was the first time this summer that temperatures over the entire densely populated eastern US were above normal (as you can see on the map from the EIA below), and as a result, natural gas consumption for electric generation averaged 41 billion cubic feet per day during the week, in contrast to the average of just over 38 billion cubic feet of natural gas per day that were used for for electric generation during the same week last year…

(source)

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending July 12th, indicated decreases in our oil imports, our oil exports, our crude oil production and our refining, reflecting the initial impacts of tropical storm Barry which had been building in the Gulf of Mexico that week before making landfall as a hurricane on July 13th…our imports of crude oil fell by an average of 470,000 barrels per day to an average of 6,832,000 barrels per day, after falling by an average of 284,000 barrels per day over the prior week, while our exports of crude oil fell by an average of 514,000 barrels per day to 2,534,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,298,000 barrels of per day during the week ending July 12th, 44,000 more barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells was reported to be 300,000 barrels per day lower at 12,000,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from well production totaled an average of 16,298,000 barrels per day during this reporting week..

US oil refineries were reportedly using 17,267,000 barrels of crude per day during the week ending July 12th, 172,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that a net of 445,000 barrels of oil per day were being withdrawn from the supplies of oil stored in the US….hence, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 524,000 barrels per day short of what our oil refineries reported they used during the week…to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (+524,000) 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”….since the prior week’s unaccounted for crude was at -472,000 barrels per day, indicating unaccounted for oil supply, the week over week metrics we’ve just reported differ to the tune of 996,000 barrels per day, and hence should not be relied on….(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 fell to an average of 7,094,000 barrels per day last week, 16.3% less than the 8,477,000 barrel per day average that we were importing over the same four-week period last year…the 445,000 barrel per day decrease in our total crude inventories was all pulled out of our commercially available stocks of crude oil, while the amount of oil stored in our Strategic Petroleum Reserve remained unchanged…this week’s crude oil production was reported to be 300,000 barrels per day lower at 12,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 400,000 barrels per day lower at 11,500,000 barrels per day, while Alaska’s oil production increased by 28,000 barrels per day to 455,000 barrels per day, which was enough to raise the final rounded national production total by 100,000 barrels per day (that’s the EIA’s arithmetic, not mine)….last year’s US crude oil production for the week ending July 13th was rounded to 11,000,000 barrels per day, so this reporting week’s rounded oil production figure was roughly 9.1% above that of a year ago, and 42.4% 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…

US oil refineries were operating at 94.4% of their capacity in using 17,267,000 barrels of crude per day during the week ending July 12th, down from 94.7% of capacity the prior week, but still a fairly normal refinery utilization rate for this time of year, despite the approaching hurricane….the 17,267,000 barrels per day of oil that were refined this week were also fractionally above the 17,239 ,000 barrels of crude per day that were being processed during the week ending July 13th, 2018, when US refineries were operating at 94.3% of capacity….

With the decrease in the amount of oil being refined, gasoline output from our refineries was much lower, decreasing by 563,000 barrels per day to 9,855,000 barrels per day during the week ending July 12th, after our refineries’ gasoline output had increased by 470,000 barrels per day the prior week….with that big drop in gasoline output, this week’s gasoline production was 4.2% less than the 10,292,000 barrels of gasoline that were being produced daily during the same week last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) rose by 3,000 barrels per day to 5,361,000 barrels per day, after our distillates output had increased by 22,000 barrels per day the prior week….but after that small increase, the week’s distillates production was 3.6% more than the 5,174,000 barrels of distillates per day that were being produced during the week ending July 13th, 2018….

Even with the big drop in gasoline production, our supply of gasoline in storage at the end of the week rose for the first time in 5 weeks and for just the 5th time in twenty-one weeks, increasing by 3,565,000 barrels to 232,752,000 barrels over the week to July 12th, after our gasoline supplies had decreased by 1,455,000 barrels over the prior week….our gasoline supplies increased this week because the amount of gasoline supplied to US markets decreased by 540,000 barrels per day to 9,214,000 barrels per day, and because our exports of gasoline fell by 83,000 barrels per day to 617,000 barrels per day, while our imports of gasoline fell by 19,000 barrels per day to 852,000 barrels per day…after our gasoline supplies had reached an all time record high twenty-three weeks ago, they then fell by nearly 13% over 10 weeks while US Gulf Coast refineries were crippled by the Venezuelan sanctions, and hence they are still 1.3% lower than last July 13th’s inventory level of 235,832,000 barrels, while just 2% above the five year average of our gasoline supplies at this time of the year…

With our distillates production little changed, our supplies of distillate fuels rose for the 7th time in the past 18 weeks, increasing by 5,686,000 barrels to 136,203,000 barrels during the week ending July 12th, the largest increase since January, and coming after our distillates supplies had increased by 3,729,000 barrels over the prior week…our distillates supplies rose again this week because our exports of distillates fell by 339,000 barrels per day to 1,116,000 barrels per day while our imports of distillates fell by 49,000 barrels per day to 132,000 barrels per day, while the amount of distillates supplied to US markets, a proxy for our domestic demand, increased by 14,000 barrels per day to 3,565,000 barrels per day…after this week’s inventory increase, our distillate supplies were 12.3% higher than the 121,311,000 barrels of distillate that we had stored on July 13th, 2018, but still remained 2% below the five year average of distillates stocks for this time of the year…

Finally, with lower oil imports and falling oil production, our commercial supplies of crude oil in storage fell for a fifth week in a row and for the eleventh time in 26 weeks, decreasing by 3,116,000 barrels, from 458,992,000 barrels on July 5th to 455,876,000 barrels on July 12th…but even with that decrease, our crude oil inventories remained roughly 4% above the recent five-year average of crude oil supplies for this time of year, and roughly 35% higher than the prior 5 year (2009 – 2013) average of crude oil stocks for the 2nd week of July, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories have generally been rising since this past Fall, up until the past month, after generally falling until then through most of the prior year and a half, our oil supplies as of July 12th were still 10.9% above the 411,084,000 barrels of oil we had stored on July 13th of 2018, but at the same time were 7.1% below the 490,623,000 barrels of oil that we had in storage on July 14th of 2017, and 6.7% below the 488,830,000 barrels of oil we had stored on July 15th of 2016…

This Week’s Rig Count

The US rig count fell for the 19th time in 22 weeks during the week ending July 19th, and is now down by 12% so far this year….Baker Hughes reported that the total count of rotary rigs running in the US fell by 4 rigs to a new 17 month low of 954 rigs this past week, which was also down by 96 rigs from the 1054 rigs that were in use as of the July 13th report of 2018, and quite a bit below the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market…

The count of rigs drilling for oil fell by 5 rigs to 779 rigs this week, which was also a 17 month low, 79 fewer oil rigs than were running a year ago, and less than half of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 2 rigs to 174 natural gas rigs, which was still down by 13 rigs from the 187 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 August 29th, 2008…however, one of the rigs classified as miscellaneous was shut down this week and now there is only one such active, matching the “miscellaneous” rig count of a year ago…

The rig count in the Gulf of Mexico was down by 1 to 25 rigs this week, as one of the two rigs that had been drilling off the coast of Texas was shut down…that still leaves 24 rigs drilling offshore from Louisiana and a single rig deployed offshore from Texas, an increase of 8 offshore rigs from the 17 rigs that were deployed in the Gulf in the same week a year ago, when 15 rigs were drilling in Louisiana waters and two were deployed offshore from Texas…

The count of active horizontal drilling rigs was down by 2 to 829 horizontal rigs this week, which was the least horizontal rigs deployed since February 2nd, 2018 and hence also a new 17 month low for horizontal drilling…it was also 93 fewer horizontal rigs than the 922 horizontal rigs that were in use in the US on July 20th 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 vertical rig count was down by 1 rig to 56 vertical rigs this week, and that was also down by 1 from the 57 vertical rigs that were operating during the same week of last year….in addition, the directional rig count was down by 1 rig to 69 directional rigs this week, but those were up from the 67 directional rigs that were in use on July 20th of 2018…

The details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of July 19th, the second column shows the change in the number of working rigs between last week’s count (July 12th) and this week’s (July 19th) count, the third column shows last week’s July 12th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 20th of July, 2018…

Note that while the Texas rig count was down by 2, the two major Texas shale basins were both up: the Permian in the west by 3 and the Eagle Ford in the south by 1; moreover, that was as 4 horizontal rigs were pulled out of Texas Oil District 8, or the core Permian Delaware, while two rigs were started up in Texas Oil District 7C, or the southern Permian Midland, which means that rigs in the Texas Permian were down by a net of two…therefore, we can figure that all 5 rigs that were added in New Mexico were in the westernmost extent of the Permian Delaware…meanwhile, the one rig increase in the Eagle Ford also masks a bigger change in that basin, as two Eagle Ford oil rigs were shut down, leaving 58, while three natural gas rigs were started up, bringing the Eagle Ford gas rig count up to 9…elsewhere, natural gas rigs were shut down in West Virginia’s Marcellus and Louisiana’s Haynesville, while another rig targeting natural gas was started up in an “other’ basin not tracked separately by Baker Hughes…we should also note that other than the changes shown for the major producing states above, a rig was also shut down in Alabama this week, where a single rig continues to drill; that single rig is the same number as a year ago, as Alabama has only rarely had more than 2 rigs active at the same time in recent years…

DUC well report for June

Monday of this past week saw the release of the EIA’s Drilling Productivity Report for July, which includes the EIA’s June data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions…for the fourth month in a row, this report showed a decrease in uncompleted wells nationally in June, as drilling of new wells decreased and completions of drilled wells increased slightly….while there continued to be a increase of newly drilled but uncompleted wells (DUCs) in the Permian basin of western Texas and New Mexico, most other regions saw decreases in their DUC inventory, thus more than offsetting the Permian increases…for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 41 wells, from a revised 8,289 DUC wells in May to 8,248 DUC wells in June, which still represents a 19.2% increase from the 6,920 wells that had been drilled but remained uncompleted as of the end of June a year ago…the decrease occurred as 1,342 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during June, down by 33 from the 1,375 wells drilled in May and the lowest in 1 months, while 1,383 wells were completed and brought into production by fracking, an increase of 4 well completions from the 1,379 completions seen in April…at the June completion rate, the 8,248 drilled but uncompleted wells left at the end of the month represent a 6.0 month backlog of wells that have been drilled but are not yet fracked…

Both oil producing regions and natural gas producing regions saw DUC well decreases in June, with only the predominantly oil Permian showing a substantial increase…the number of DUC wells left in the Oklahoma Anadarko decreased by 29, from 968 in May to 939 DUC wells in June, as 127 wells were drilled into the Anadarko basin during June while 156 Anadarko wells were being fracked….at the same time, the drilled but uncompleted well count in the Niobrara chalk of the Rockies’ front range decreased by 22 to 473, as 173 Niobrara wells were drilled in June while 195 Niobrara wells were completed….meanwhile, DUC wells in the Bakken of North Dakota fell by 15, from 709 DUC wells in May to 694 DUCs in June, as 115 wells were drilled into the Bakken in June, while 130 of the drilled wells in that basin were being fracked…

Among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 15 wells, from 447 DUCs in May to 432 DUCs in June, as 124 wells were drilled into the Marcellus and Utica shales during the month, while 139 of the already drilled wells in the region were fracked…in addition, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory decrease by 3 wells to 189, as 50 wells were drilled into the Haynesville during June, while 53 Haynesville wells were fracked during the same period….

On the other hand, the Permian basin of west Texas and New Mexico saw its total count of uncompleted wells rise by 42, from 3,960 DUC wells in May to 4.002 DUCs in June, as 549 new wells were drilled into the Permian, but only 507 wells in the region were fracked….and lastly, DUC wells in the Eagle Ford of south Texas increased by 1, from 1,518 DUC wells in May to 1,519 DUCs in June, as 204 wells were drilled in the Eagle Ford during June, while 203 already drilled Eagle Ford wells were completed…..thus, for the month of June, DUCs in the five oil basins tracked by in this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a net of 23 wells to 7,627 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 18 wells to 621 wells, although as the report notes, once into production, more than half the wells drilled nationally will produce both oil and natural gas…

Abundance of shale makes nuclear plants expendable – Opinion – The Columbus Dispatch – It’s time – past due time – to bury nuclear power. A week doesn’t go by without reports of safety and performance problems at decades-old U.S. nuclear plants. More than one-third of the plants are unprofitable or scheduled to close. Cheap natural gas and renewables are threatening the profitability of nuclear plants around the country – and bringing home the reality that America can do better for its money than bailing out money-losing plants. Using nuclear power to provide one-fifth of the nation’s electricity when cheaper and safer alternatives are available is nonsensical. You don’t need science or economics to know that. Goodness knows how much consumers would benefit from closing financially ailing nuclear plants like the Perry and Davis-Besse reactors in Ohio. The nuclear industry still hopes to persuade state governments to provide billions of dollars in financial assistance to keep plants operating. But to say that such subsidies are counterproductive and jeopardize economic growth is a dramatic understatement.One would be hard-pressed to find a better poster child for the nuclear industry’s problems than Ohio. FirstEnergy Solutions, the Akron-based company which operates the Davis-Besse and Perry plants, has said both units are slated to close by 2021 unless the state government steps in and provides financial assistance. Both plants have a long history of safety violations, the most recent being problems with backup emergency diesels that caused the reactor core meltdowns at the Fukushima plant in Japan. Yet some members of the state legislature want to keep the plants in service. A House committee has approved a bill that would provide about $170 million annually for the Davis-Besse and Perry plants. Households and businesses would pay for the subsidies. The shale revolution has made natural gas so cheap that it is displacing coal and emerging as a winner in competition with nuclear power. This has meant lower costs for consumers. In the past decade, natural gas generation has grown from 1.6% of Ohio’s electricity supply to more than 34% in 2018. Price has tilted the playing field to make gas the preferred source of fuel for generating electricity. There is no excuse for the continued use of coal and nuclear power.

Local pipeline court fights, restoration work continue – Natural gas has flowed for months on the two interstate pipelines built across the region in recent years, but restoration work continues on one of the massive projects, and wrangling continues. The Rover Pipeline and Nexus Gas Transmission pipeline carry natural gas produced by Marcellus and Utica shale wells to users in the United States and Canada. Rover has been in partial or full operation for almost two years, and gas began flowing through Nexus in October of last year. Nexus is a $2.1 billion pipeline backed by Detroit-based DTE Energy and Enbridge, a Canadian company. The 36-inch-diameter pipeline runs 255 miles from Hanoverton in Columbiana County to Michigan and can carry up to 1.5 billion cubic feet of natural gas a day. It crosses Washington, Nimishillen, Marlboro and Lake townships in Stark County and the city of Green in Summit County. The arrival of winter last year delayed work crews for several months from restoring all of the land disturbed by Nexus construction. But last week, restoration crews were working on Easton Street NE in Washington Township and Gans Avenue NE in Lake Township, although other areas remained untouched, or even flooded by recent rains. According to Nexus spokesman Adam Parker, there were crews restoring land in various locations on the pipeline route. “We have developed plans to mitigate the unusual rain conditions and we remain on schedule to complete final restoration activities by the fourth quarter of 2019,” Parker wrote. “Most restoration occurs within the first year following completion of construction. However, the process can take longer, depending on weather and other environmental impacts that may interrupt the restoration process.” As the restoration continues, so do several lawsuits filed by landowners in counties along the Nexus route, including five cases in Stark County. The lawsuits allege Nexus and its construction contractor, Michels Corp.:

• • Pumped or diverted water onto farms and residential properties without permission.
• • Destroyed topsoil and crops on farms and failed to control erosion.
• • Failed to repair damaged drain tiles and properly reclaim land.
• • Caused farmers to lose crops and prevented some landowners from using their properties.

Energy Transfer Weighs Sale of Rover Pipeline Stake – Energy Transfer LP, the U.S. pipeline giant controlled by billionaire Kelcy Warren, is weighing the sale of its 33% stake in a conduit that carries Appalachian natural gas to customers across the Midwest, according to people familiar with the matter. The Dallas-based pipeline operator has hired an adviser to pursue a potential sale of its operated interest in the Rover pipeline, said the people, who asked not to be named because the information isn’t public. The stake could fetch as much as $2.5 billion, one of the people said. No decision has been made and Energy Transfer could opt not to sell, the people said. A representative for the company declined to comment. Energy Transfer rose 0.6% to close at $14.91 a share. Map Rover is 713 miles (1,148 kilometers) long and can shuttle 3.25 billion cubic feet of gas daily to customers across Ohio and Michigan, and as far away as Ontario. The project was originally expected to cost $4.2 billion and entered full service last year after a series of delays and construction missteps, including the bulldozing of a historic house in Ohio that the company had said it was buying for office space. When the project came online, gas drillers got relief from bottlenecks that had plagued the Marcellus and Utica shale fields in Appalachia, where a production boom aggravated shipping constraints. Rover can handle as much as 10% of total Appalachian gas output. Energy Transfer sold a 32% stake in Rover to funds managed by Blackstone for about $1.57 billion in 2017. Together, Energy Transfer and Blackstone control 65% of Rover through an entity called “HoldCo,” according to a regulatory filing. Traverse Midstream, formed in 2014 by a former affiliate of private equity firm NGP Energy Capital Management, owns the remaining 35%. Proceeds from a sale of the Rover stake could be used by Energy Transfer to make an acquisition. The company is among those looking at a 20% stake in a crude-oil export project in Corpus Christi, Texas, a person familiar with the matter said last month. “We kiss a lot of frogs looking for a prince,” Warren said during a conference call in November. “We are working it hard. I will tell you, though, we are not finding any deals.”

Manchin, environmental activists seek more details on China Energy deal – Normally butting heads, environmental activists and U.S. Sen. Joe Manchin, D-W.Va., are both on the same page when it comes to asking for more details on the multi-billion dollar “deal” with a Chinese company to further develop West Virginia’s natural gas infrastructure. During a hearing Thursday of the U.S. Senate Energy and Natural Resources Committee regarding liquified natural gas exports, Manchin, the ranking minority member of the committee, raised concerns about the memorandum of understanding between the state Commerce Department and the China Energy Investment Group. “What would be their interest? We cannot find out one iota of what the MOU is,” Manchin said. “I have asked them directly and cannot get a direct answer about their investments.” Manchin isn’t the only one wanting to see what’s in the memorandum of understanding between the state and China Energy. Appalachian Mountain Advocates, on June 24, filed an appeal with the state Supreme Court of Appeals of a lower court decision denying a Freedom of Information Act request to the West Virginia University Energy Institute, one of the partners with the commerce department, for the memorandum. On Nov. 9, 2017, Gov. Jim Justice announced the state had entered into an agreement with China Energy valued at $83.7 billion. China Energy committed to investments in Marcellus Shale natural gas production, infrastructure and downstream industries, such as chemical manufacturing interests. The deal was part of a $250 billion trade deal negotiated between China and the U.S. Department of Commerce, with former Commerce Secretary Woody Thrasher traveling to China twice to secure a memorandum of understanding with China Energy officials. “Do you all know about this deal they want to make with West Virginia, my state? They’ve said they’re going to invest $83 billion over 20 years,” Manchin said during Thursday’s committee meeting. “You can imagine that kind of carrot being swung out there, it’s tremendous for a small state. Our budget is only $4 billion a year, and they’re going to invest $83 billion.”

Senate Energy and Natural Resources Committee passes bills aimed at Appalachian natural gas and coal – On Tuesday, the U.S. Senate’s Energy and Natural Resources Committee passed numerous bills centered around Appalachian natural gas and coal. Of note was the Appalachian Energy for National Security Act, which if passed by Congress and signed by the president, would require the U.S. Department of Energy to study national security and economic benefits to a proposed natural gas storage hub along the Ohio River Valley. “An Appalachian Storage Hub would have immeasurable benefits for the Appalachian region and our country as a whole,” said U.S. Sen. Joe Manchin, D-W.Va., in a news release. “Not only would it be an economic driver for the region but it would also increase our national and economic energy security,” Manchin said. “With countries like Russia and China continuing to leverage their energy resources for political influence, it is more important than ever for the United States to secure energy independence. “In West Virginia we have been blessed with an abundance of natural resources and are well-suited to provide this energy security for the rest of the nation.” The act, introduced by Manchin who is the ranking Democrat on the committee, would also require the study to look at possible negative impacts of foreign ownership of domestic petrochemical resources and the needed infrastructure to locate such a hub in Appalachia. Along with that bill, Manchin saw eight other bills he sponsored or co-sponsored make it out of committee. Of particular note to southern West Virginia was the Rare Earth Element Advanced Coal Technologies, or REEACT, Act of 2019. REEACT would continue funding to the U.S. Department of Energy in the form of $23 million a year through FY 2027 for the study of the extraction of rare earth elements from coal and coal byproducts.

State Supreme Court says Antero Resources can continue drilling for Marcellus shale – The West Virginia Supreme Court of Appeals sided with the Mass Litigation Panel in an appeal involving Marcellus shale litigation. The appeal arose from claims by surface owners of several tracts of land who argued their use and enjoyment of their land was improperly and substantially burdened by horizontal wells used to develop the Marcellus shale underlying their properties, according to a recent opinion. Justice Evan Jenkins authored the majority opinion. Justice Beth Walker concurred and filed her own opinion. Justice Margaret Workman and Judge Russell Clawges, who was sitting by temporary assignment, dissented. “The MLP resolved the claims based upon property rights arising from relevant severance deeds, and granted summary judgment in favor of the defendants below, who are the leaseholder of the gas and oil estates and the company who is conducting the drilling,” Jenkins wrote in the majority opinion.The MLP concluded that the effects on the surface owners resulting from the horizontal drilling were within the implied rights to use the surface granted by virtue of the severance deeds, and did not impose a substantial burden on the surface owners. “Thus, to overcome summary judgment on this issue, the surface owners were required to establish the existence of a genuine issue of material fact as to whether the effects on their surface estates were reasonably necessary to develop the mineral estate, or whether such effects substantially burdened the owners of the relevant surface estates,” Jenkins wrote. “Having considered the briefs submitted by the parties and by Amici Curiae,2 the appellate record, the oral arguments presented, and the relevant law, we find no genuine issues of material fact were established in this particular case, and we, therefore, affirm the order of the MLP.”

2 pipeline protesters arrested in Montgomery County — A Giles County man was charged with assaulting a Mountain Valley Pipeline worker during a protest at a construction site Monday. Virginia State Police were called to an area in eastern Montgomery County near where the natural gas pipeline crosses Flatwoods Road and found about 15 protesters blocking access to a worksite, Sgt. Rick Garletts said. The demonstrators were advised they were breaking the law by obstructing the roadway and were told to leave. “After some discussion,” Garletts wrote in an email, “all complied.” Jammie Hale, 46, was charged with assaulting a Mountain Valley employee, a misdemeanor. He was later released on a $2,500 bond. Hale, who said the water system on his farm failed after Mountain Valley began to dig trenches to bury a 42-inch diameter steel pipe nearby, is a regular participant in pipeline protests. “I’ve had to sell my cattle and now I’m watching my friends go to jail,” Hale said. Hale is the latest of more than 40 opponents charged in Virginia and West Virginia along the path of the 303-mile pipeline, which is in its second year of construction and is expected to be completed next year. On Saturday, a man who had previously been in one of the trees at Yellow Finch Lane locked himself to a concrete structure in the pipeline’s right of way, blocking work for about seven hours, according to a news release from Appalachians Against Pipelines. Phillip Flagg, 24, of Austin, Texas, was charged with misdemeanor obstruction and freed on a $1,000 bond. In a statement released by Appalachians Against Pipelines, Flagg said he cherished the several months he spent living about 50 feet off the ground on a wooden platform hanging from a chestnut oak. “But I’m not too proud to admit that the time I spent in the oak simply isn’t enough to stop this pipeline,” he said. “Each of us has our piece to contribute – when one person steps up, others will follow.”

Protester arrested for blocking path of Mountain Valley Pipeline – A protestor has been arrested after blocking the path of the Mountain Valley Pipeline, according to Appalachians Against Pipelines. Around noon on Thursday, Violet, whose last name is unknown, locked herself into her camping spot, blocking the intended path of the pipeline near Elliston in Montgomery County. Police say Ugur had affixed himself to a device buried in the ground using a common protest device called a “sleeping dragon.” Ugur blocked the pipeline easement for five hours before being extracted and arrested. State police made repeated attempts requesting Ugur to voluntarily release himself from the device and offered medical service. He refused all requests. Police charged Ugur with one misdemeanor count of obstructing the right of passage of another and one misdemeanor count of obstruction of justice. Ugur has since been released on $2,500 bail. The spot where Violet locked herself in is not far from where another pipeline protestor, Phillip Flagg, was arrested on July 13. Violet is the seventh person in 2019 to be arrested for locking into the path of the pipeline, according to Appalachians Against Pipelines.

Organic Farm in W.Va. Imperiled by Gas Pipeline Construction – In the four years since finding stakes mysteriously implanted in the ground of their newly acquired farm, Neal LaFerriere and his family have worked as best they could with Mountain Valley Pipeline representatives to preserve the integrity of their organic farm. Having no choice but to sign an easement to allow the gas pipeline to go through their land, LaFerriere and his wife Beth have tried to hold MVP to the management plan it filed with a federal agency.“We have always been willing to sit down at the table and meet with them to try to work out the issues,” LaFerriere said. But even before clearing for construction started on the right-of-way on Monday, the effects of MVP’s actions on the family’s business have been catastrophic, he said, threatening the farm’s organic certification and bringing such financial hardship that their ownership of the farm is in jeopardy. And, already this week, a clumsy accident involving heavy machinery has resulted in a spill of contaminating fluids on the organic farm. . One day last September, he, his wife, four of their children and an intern were harvesting ginseng about a quarter mile away from the right-of-way, when suddenly, a helicopter flew overhead. Little blue pellets started raining down on them, and they were struck on the face and head, resulting in contusions and lacerations on his two daughters’ faces. He called MVP, but the helicopter continued to make several more passes over the farm. The blue pellets were an erosion control product called Earth Guard Edge. He also called state agencies in addition to MVP, but they were unwilling to hold the pipeline company accountable, he said. Someone at the Federal Energy Regulatory Commission (FERC) called him back 8 days later, and a few days after that, FERC and MVP representatives finally came to the farm bringing MVP’s environmental specialist. The specialist said there was nothing they could do to mitigate the damage. Once the pellet gets wet, it gets into the soil.

Construction materials for pipeline washed into Smith Mountain Lake –Large wooden mats, used as temporary roadways for construction equipment building the Mountain Valley Pipeline, have been swept down the Blackwater River by heavy rains in recent weeks. At least two of the so-called timber mats made it into Smith Mountain Lake, where critics say they posed a public safety risk. If a boat were to hit one of the sections of wood floating in the water, “that could be a major catastrophe,” said Mike Carter, a member of the Franklin County Board of Supervisors. At least a dozen of the timber mats placed on construction sites in the county were washed downstream by floodwaters in late June, according to an environmental compliance monitoring report filed this week with the Federal Energy Regulatory Commission. Two of the mats were found in the Blackwater channel, not far from the W.E. Skelton 4-H Educational Conference Center near Union Hall. A contractor using a barge to remove floating debris for Appalachian Power Co. disposed of the mats, spokesman John Shepelwich said. It was the first time officials could recall seeing such materials in the lake. The mats were “not extremely unusual or outsized” compared to some of the tree trunks and other debris the Smith Mountain Project routinely removes from the water to protect its two dams and the public, Shepelwich said. But for pipeline critics – who in the past have raised concerns about sediment being washed from work sites into streams and rivers – the mats were a different kind of problem. “We are concerned,” said Lorie Smith, president of the Smith Mountain Lake Association. “We’re watching as vigilantly as we can.” Natalie Cox, a spokeswoman for Mountain Valley, said as much as five inches of rain swamped a temporary construction bridge that spanned the Blackwater. The bridge had been in place for more than a year, following the suspension of the company’s stream-crossing permit. “Several mats, either 18 feet by 6 feet, or 40 feet by 6 feet, used to build the crossing over the waterbody were subsequently carried away by the current,” Cox wrote in an email.

Virginia legislators seek halt to Atlantic Coast line – Eighteen Virginia legislators have asked the Federal Energy Regulatory Commission to halt construction on the delayed Atlantic Coast natural gas pipeline, Kallanish Energy reports. They have also asked the federal agency to suspend the project’s certificate of need and convenience and urged Ferc to reassess the need for the $7.8 billion pipeline. The three-page letter was signed by four state senators and 14 state delegates. The state has 140 legislators. They cited the increasing project price tag and said the companies behind the project “have never demonstrated public need“ for the pipeline. They added there is “growing evidence that the developers have overstated the demand for gas.” The pipeline is also facing numerous legal challenges, the legislators said. A similar letter signed by 22 North Carolina legislators was sent to Ferc in May with similar requests. Dominion Energy has asked the U.S. Supreme Court to overturn a federal appeals court decision blocking the company from building the pipeline across the Appalachian Trail in Virginia. Last December, the Fourth U.S. Circuit Court of Appeals vacated a permit that had allowed the pipeline to cross the Appalachian Trail on national forest lands. The court ruled the U.S. Forest Service lacks the authority to approve a pipeline right-of-way across the trail. Dominion Energy argues 56 other pipelines have crossed the trail, that stretches from Georgia to Maine. The company has said it hopes to be able to resume construction of the pipeline by Oct. 1, and to complete it by early 2021. Reuters reported some analysts think Dominion could cancel the pipeline if the Supreme Court does not hear the case because of increasing costs due to legal and regulatory delays.

Representing himself, Cumberland County resident battles Sunoco attorneys over pipeline concerns -A Pennsylvania Public Utility Commission hearing Wednesday on a challenge to Sunoco’s Mariner East pipelines revealed few answers about the controversial project, but continued to show the frustration many Pennsylvania residents have with the petroleum giant. It was an unusual matchup. On one side is Wilmer Baker, a Cumberland County resident and former steel worker, representing himself in a legal fight over the safety of the three pipelines Sunoco is operating or constructing across the state. On the other is a trio of lawyers representing Sunoco Pipeline LP, which has been building an intrastate pipeline from Pennsylvania’s western shale fields to ports on the Delaware River for export. In a day-long hearing in front of Administrative Law Judge Elizabeth Barnes, Baker tried to press his case through a cascade of objections from Sunoco and delays to work through procedure. “What I wanted was an alarm system … and better public outreach, including American-made steel instead of foreign steel dumped into this country,” Baker said as he testified as his own witness. In his own handwritten pre-hearing memo, Baker also said he wants an odor added to the pipelines’ combustible cargo – natural gas liquids, such as ethane, butane, and propane – as well as more outreach between Sunoco and emergency response services near the pipeline.

Refinery Explosions Raise New Warnings About Deadly Chemical : NPR – In the predawn hours of June 21, explosions at the Philadelphia Energy Solutions refinery in South Philadelphia shook houses, sent fireballs into the air and woke up nearby residents. “Three loud explosions, one after the other, boom, boom boom!” says David Masur, who lives about two miles from the plant and has two young kids. “It’s a little nerve-wracking.” Masur watched as the refinery spewed black smoke above the city, easily visible from his home. But what he didn’t know at the time was just how close he and his family came to getting exposed to hydrogen fluoride, one of the deadliest chemicals used by refiners and other industrial manufacturers. Philadelphia Energy Solutions knows that’s a possibility. Its worst-case disaster scenario includes 143,262 pounds of hydrogen fluoride released over 10 minutes, which could travel as a toxic cloud for more than 7 miles and impact more than a million people, including in schools, homes, hospitals, prisons, playgrounds, parks and a wildlife sanctuary. City, state and federal officials say none of the air monitors in or around the refinery – or the air samples collected by the city’s health department – detected the chemical, often referred to as HF. And a spokeswoman for Philadelphia Energy Solutions says no workers were exposed. But two other refineries in the Philadelphia region also use HF, as do some four dozen around the country. The Philadelphia explosions, along with similar accidents in the past four years, are reviving concerns about inadequate safety measures and calls to end the use of the deadly chemical.

Shutdown from Refinery Explosion Impacting East Coast Supply Chain –Last month the largest oil refinery complex on the east coast, Philadelphia Energy Solutions, experienced a major explosion and fire. The site produced 335,000 barrels per day before announcing that it would be shut down, leaving 1,000 workers without jobs. The closure leaves the East Coast with seven total refineries and an operating capacity of 889,000 b/d. The Energy Information Administration estimates that closing the refinery will not only reduce East Coast gasoline supplies but is also likely to reconfigure petroleum product supply chains in the Central Atlantic. The U.S. East Coast is the largest regional consumer of petroleum products in the United States. Because this region consumes significantly more petroleum than regional refineries can produce, it relies on product brought in by a pipeline from the Gulf Coast. In addition to tapping reserves, replacement supplies for these markets will come from various sources. This includes the other refineries around Philadelphia that produce transportation fuels – the Monroe Energy Trainer refinery, the PBF Delaware City refinery, and the PBF Paulsboro refinery. Markets in Western Pennsylvania will also draw on supplies provided by refineries and distribution systems in Ohio and the rest of the Midwest. Markets in upstate New York may resupply from terminals in southern New York and refineries in Canada, although the logistics are more challenging than via a pipeline from Philadelphia. However, most of the lost supply to these markets and the region as a whole is likely to be replaced through imports and increased shipments on the Colonial Pipeline. The East Coast can also import gasoline supplies from the Atlantic Basin, which is supplied by refineries in Northwest Europe, Eastern Canada, India, and the Mediterranean. In 2018, this region imported 586,000 b/d of gasoline. Additionally, increased shipments from refineries in the Gulf of Mexico via pipeline may be possible, but also carry limitations. The Colonial Pipeline, for example, is already at capacity.

PES refinery expected to shut remaining units as crude dwindles: sources – (Reuters) – The Philadelphia Energy Solutions refinery, the oldest and largest on the U.S. East Coast, is expected to shut its remaining units on Monday as the plant uses up the last of its crude supplies, sources said on Wednesday. The refinery is still weighing the economics of running more crude oil to keep the units active for an extended period, the sources said. Crude shipments destined for PES have been diverted in the weeks after the June 21 fire and explosion at the 335,000-barrel-per-day refinery, according to data and trade sources. The fire, which started in an alkylation unit in the Girard Point section of the Philadelphia complex caused PES to begin closing the facility without an intended restart. Roughly 1,000 workers are expected to be laid off and contractors who do business with the refinery will also be affected by the shutdown. PES, which emerged from bankruptcy last year, has multiple owners, including investment bank Credit Suisse and investment firm Bardin Hill. Refinery officials were not immediately available for comment. PES has long been a steady buyer of imported crude oil, particularly from West Africa. Its loss as a buyer threatens to shrink the last steady U.S. market for West African crude. Last year, U.S. refiners imported 180.7 million barrels of crude oil from Africa, according to U.S. Energy Information Administration figures. The PES refinery imported 43.1 million barrels from Africa in 2018, second only to the Phillips 66 refinery in Linden, New Jersey among U.S. refineries.

Delaware refinery hit with nearly $1 million penalty for a decade of air pollution violations – The Delaware City Refining Company, LLC has agreed to pay a $950,000 penalty to the Delaware Department of Natural Resources and Environmental Control for violations of the Clean Air Act that date back to 2010. The settlement also addresses appeals the company made to DNREC-issued air quality permits. The violations include releases of volatile organic compounds, hydrogen sulfide, and sulfur dioxide – pollutants that are known to cause breathing problems, skin irritation, and in some cases nausea, vomiting, and neurological effects such as dizziness. The refinery has also been cited for releases of methane, one of the most powerful heat-trapping gases that contributes to global warming.DNREC has agreed to revise the permit language regarding emissions caps on certain units at the refinery. There is an annual cap on the facility’s emissions, but certain units have shorter-term limits that prevent large releases all at once. The new language allows the company more flexibility on some units under certain circumstances, such as when equipment is malfunctioning. The revised permits will now enter a comment period. Once the comment period closes and the revised permits are issued, pending no major changes, the company has agreed to dismiss its appeals. DNREC has been fighting the refinery over outstanding air and water violations since the facility’s restart in June 2010. DNREC Secretary Shawn Garvin told WHYY that the agency decided to separate the two issues due to the complicated nature of the air quality permit appeals.

Natural Gas Prices Start The Week With A Slide – After initially jumping up at the Sunday evening open, natural gas prices quickly began facing downward pressure, which continued into the day today, with the August contract settling a few cents lower compared to Friday’s close. Why the weakness in the face of such strong heat on the way this week? Part of that answer lies in the move cooler in the forecast as we look into the final portion of July, which is expected to bring demand down to at least near normal levels. Here is the forecast demand chart (GWDDs), showing this week’s strong cooling demand, followed by the late month weakening: In map form, we see the “blues” introduced in today’s 11-15 day outlook for the first time in awhile in the eastern half of the nation. While July is still set go down as a hot-dominated month, this late month cooler move is not a surprise. We highlighted the potential for a weaker 11-15 day in our Pre-Close Update to clients back on Friday. We will have to see now if this is a lasting change, or if we soon migrate back in the hotter direction, offering more chances to boost cooling demand and perhaps lend natural gas prices more support.

It Might Be Too Early For A Significant Rise In Natural Gas – The price of natural gas was at over the $2.45 level at the end of last week, as it recovered from recent lows at below the $2.20 per MMBtu level. The peak of the summer season began following the recent July 4th holiday and will run through Labor Day at the beginning of September. Hotter than average temperatures over the coming weeks will increase demand for cooling power, which would cause the amount of natural gas flowing into storage to decline. However, output remains at record levels given the massive reserves in the Marcellus and Utica shale regions of the US and the technological advances that lowered the cost of production. At the same time, investments in production efficiency and the expansion of pipelines and storage have expanded the US natural gas business. Additionally, regulatory reforms have served to increase production in the US. As natural gas can now flow beyond the pipelines and travel around the globe in liquid form, the addressable market for the energy commodity from the US continues to expand. The growth of both the supply and demand side of the fundamental equation for natural gas has caused the market to mature. Meanwhile, the price remains below the level it broke down from in May and June at just above the $2.50 per MMBtu level. Even though the price recovered from the recent lows, it has yet to challenge the support level that has transformed into technical resistance in the natural gas futures market. The first attempt to move above that level will likely attract selling. The Velocity Shares 3X Inverse Natural Gas ETN product (DGAZ) is a short-term tool for those looking for the price of the energy commodity to move lower. We have witnessed lots of volatility in the natural gas futures market since late last year. As the monthly chart shows, the price rose to a high at $4.929 per MMBtu in November as the amount of natural gas in storage going into the peak season of demand was at the lowest level in years at 3.247 trillion cubic feet late last year. The price moved to the highest level since 2014 when natural gas traded to just under $6.50 per MMBtu. While stocks fell to a low at 1.107 tcf at the end of the winter withdrawal season, the price continued to drop from the late 2018 high. In April, natural gas futures fell below the 2017 and 2018 lows at just over the $2.50 level reaching a bottom at $2.159 on the continuous contract, and $2.134 on the active month August futures contract.

The Role Of Weather In This Summer’s Natural Gas Price Action Today was a relatively quiet day on the natural gas front, with the August contract closing just two ticks lower than yesterday. The weekly move has been decidedly lower, however, thanks in large part to the shift cooler in the weather pattern for the balance of July, bringing “blues” to the 6-15 day forecast maps. This is stark contrast to the heat we’ve seen much of this month, which prompts us to take a look at how weather has played a role in the price action of natural gas so far this summer. Typically, the “weather factor” carries much more weight in winter than in summer. This is because of much higher gas demand in the winter months. The difference between a very cold winter and a very warm one can account for roughly 2 tcf in terms of natural gas demand, while in summer, the difference in demand between a cool summer and a top-end hot summer is only around 25% of that, in the realm of 500-600 bcf. This summer, at least so far, has been a case where weather’s influence has been more evident in price action, which can happen in cases where we do not have a notable paradigm shift in the supply / demand picture in the middle of the season. Here is the demand profile since 5/15/19, using the departure from normal in Gas-Weighted Degree Days (GWDDs) as the measure. This includes our 15 day forecast as well. We’ve highlighted the period where demand ran consistently below normal, as well as the recent weeks where demand has been consistently above normal. As we look at prices, we see that, sure enough, when demand was consistently below normal, the direction of price action was generally lower, and as demand has remained consistently above normal, the direction of price action has generally been upward. Of course, we do have the big drop this week while the pattern is still hot, but as we mentioned, that is the market pricing in the cooler forecast changes for the balance of July. Now, we are not making the case that one should base trades only around weather-based strategies in summer. as results will not be this clean, typically. But is definitely an important piece of the puzzle.

US natural gas in underground storage rises by 62 Bcf: EIA – The US Energy Information Administration reported a 62 Bcf build to US natural gas storage for the week ending July 12, marking the first bullish report from the agency during this injection season. US gas in storage increased to 2.533 Tcf as a result, leaving stocks 291 Bcf, or 13%, above the year-ago level of 2.242 Tcf and 143 Bcf, or 5.3%, below the five-year average level at 2.676 Tcf. Following 15 consecutive above-average builds reported by the EIA, last week’s injection was the first of this injection season to undershoot the five-year average storage addition of 63 Bcf. Last week’s injection was less than an S&P Global Platts’ survey of analysts calling for a 65 Bcf build. Responses to the survey ranged from 56 Bcf and 72 Bcf. The injection was also less than the 68 Bcf and 70 Bcf builds predicted by S&P Global Platts Analytics’ supply-demand model and storage report, respectively. Following Thursday’s announcement from the EIA, the prompt-month NYMEX Henry Hub contract briefly climbed to about 2 cents to $2.35/MMBtu, before edging downward to a settlement at $2.29/MMBtu. Last week’s bullish injection to gas storage comes following a net 1.1 Bcf/d tightening in the US supply-demand balance, according to Platts Analytics. During the week, more seasonal summer temperatures lifted gas-fired power burn by an estimated 900 MMcf/d, which was partially offset by declines in residential-commercial and LNG-feedgas demand. Over the same reference period, US production from offshore fields in the Gulf of Mexico declined by about 500 MMcf/d as Hurricane Barry shuttered operations near the Louisiana and Mississippi coastlines. Weekly gains in onshore production partially offset that decline. For the week ending Friday, Platts Analytics’ storage report and supply-demand model are forecasting bullish injections of 29 Bcf and 30 Bcf, respectively. If realized, a build around that level would undershoot the five-year average injection by 14 to 15 Bcf, according to EIA data. Gas-fired power burn has continued to strengthen through mid-July, helping to tighten this summer’s supply-demand balance. Month to date, burns have averaged 40.6 Bcf/d or about 1.1 Bcf/d above last year’s month-to-date average. On Wednesday, power burn set a new record-high level at 44.6 Bcf/d. For the week ending Friday, aggregate US balances look to be about 4.2 Bcf/d tighter compared with last week. Power burn and LNG feedgas demand are up by 2 Bcf/d and 2.1 Bcf/d, respectively. On the supply side, continuing production declines related to Hurricane Barry have led an overall 2.2 Bcf/d drop in output this week compared with last week.

Market Brushes Aside EIA Number To Continue This Week’s Selloff – Natural gas prices extended this week’s downward move today, with the prompt month August contract settling 1.7 cents down on the day, breaking below the 2.30-2.32 support zone. Today’s move lower came in spite of the EIA report that showed an injection of 62 bcf for last week, which was actually on the lower end of the range of market estimates. This reflected tighter supply/demand balances that were tighter (more bullish) week over week, but that along does not tell the full story. Balances remained on the loose side of the trend line when looking at the same gas week over the last several years, much looser than last year. Also, production declines started in the middle of last week ahead of Hurricane Barry’s arrival along the Gulf of Mexico coastline. As a result, the market can more easily discount this number, with the thinking that it would have been higher if not for Barry, hence the tightening may be somewhat artificial. Add in the lack of strong heat in the weather forecasts beyond this weekend, and the bearishness makes a little more sense. One thing is certain, however. This season has not had a shortage of solid price moves, despite fears to the contrary, and it is likely that there will be more to come.

Selling Continues In Natural Gas, With Prices Closing Lower Every Day This Week – This week brought quite the sea of “red” to the natural gas world, and we don’t mean the kind on weather maps that is bullish. Prices closed lower every single day this week. The week began with cooler weather changes to the balance of July, a risk that we had highlighted in last Friday’s Pre-Close Update. This brought “blues” (cooler than normal temperatures) to our 11-15 day forecast back on Monday for the first time in quite awhile. Monday’s forecast: While the bulk of these cooler changes came early in the week, by Wednesday, the cooler weather along with our analysis of supply / demand balances led us to mention the risk of a move to the 2.25 level in the August contract, highlighted in Wednesday’s Morning Report. Two days later, here we are, right at the 2.25 level, still with significant cooling on the way next week, but coverage of below normal temperatures had lessened in today’s 11-15 day forecast, as seen on today’s maps. After falling almost 25 cents from the highs of last week, is this enough to end the selling pressure?

Agency Mulls Review of LNG Terminal Application for Delaware River Basin – NJ Spotlight – The Delaware River Basin Commission said Monday it is reviewing a request to reconsider its approval of plans for a controversial liquefied natural gas terminal at Gibbstown, Gloucester County. The interstate water regulator last month unanimously approved the proposed expansion of an energy-export terminal on a former DuPont explosives site in the face of criticism by environmentalists who say the LNG component of the project would risk major explosions, stimulate the production of climate-altering natural gas, and endanger the water resources that the DRBC is required to protect. The environmental group Delaware Riverkeeper Network previously accused DRBC and other agencies of trying to cover up the plan by Delaware River Partners to transfer LNG produced in Pennsylvania’s Marcellus Shale from trucks or railcars on to ships bound for overseas ports. Now, DRN has formally asked the commission to re-examine the plan at a public hearing. DRN argues that the LNG terminal would violate the “Compact,” a 1960s document that requires it to protect the basin’s water resources, which would be at risk because of dredging to build the port, and because the project could stir up many contaminants at the site. The critics also say that DRBC failed to consider the views of other agencies when it approved the project and has not given the public enough time to discuss it. “The DRBC violated its governing Compact and regulations when it approved the project without having full information on impacts on water resources to the Basin,” DRN said in a letter to the commission on July 11. The agency did not include any mention of the LNG plan in its draft docket on the project, known as the Gibbstown Logistics Center, depriving the public of an opportunity to comment, DRN said. .

LNG export terminal would take 360 trucks a day, 24/7, Army Corps says – NJ Spotlight — The U.S. Army Corps of Engineers divulged new details yesterday about plans for New Jersey’s first export terminal for liquefied natural gas, showing it would be supplied by as many as 15 trucks an hour – around the clock – to fill an ocean-going tanker every two weeks. The previously unpublished information about the proposed terminal at Gibbstown in Gloucester County, the Army Corps said Tuesday, came from new details it had received about the plan by the developer, Delaware River Partners, since the agency published an earlier notice on the project in April. The new document said LNG – a super-cooled form of natural gas that can explode if its vapor is mixed with air in an enclosed space – would not be processed or stored on site but would be pumped directly from trucks into ships. To limit the impact of the heavy truck traffic on residential areas, Gloucester County is proposing a new access road to a port that would be expanded to accommodate the terminal, the document said. The new road would be about 110 feet from the nearest residential area; the terminal’s loading area would be built at least a mile away from those homes. The developer has also proposed carrying the LNG to the terminal by rail but that idea hasn’t yet been approved by the U.S. Department of Transportation, the Army Corps report said. Disclosure of the new detail may fuel critics who say that DRP and some government agencies have not been fully transparent about a project that would bring explosive materials to a residential area, and which would stimulate the production of fracked natural gas, boosting climate-changing carbon emissions. The gas, harvested from Pennsylvania’s Marcellus Shale would be liquefied at a proposed plant in Bradford County, Pa., built by New Fortress Energy, a LNG company.

National Grid to NYC customers: Support the Williams Pipeline or no new service – On Monday, the leading distributor of natural gas in the Northeast, National Grid, sent an urgent-sounding email to many of its New York customers – not about summer energy savings, but about why they should contact government officials to voice support for a major fracked gas pipeline.“Natural gas supplies are at risk in downstate New York,” the subject line read.In the energy company’s email, National Grid said it will not be able to fulfill requests to expand natural gas service in Brooklyn, Queens, and Long Island unless the Northeast Enhancement Supply Project, a new pipeline that would bring in an additional 400 million cubic feet a day of fracked natural gas to the region, moves forward. The proposed project would span 23.5 miles from Pennsylvania, through New Jersey, to Rockaway Peninsula in New York. If completed, National Grid says it would the company’s capacity by 14 percent.Earlier this year, both New York and New Jersey denied permits for the project, locally called the Williams Pipeline after the entity that would operate it, citing the project’s potential environmental impact on water quality and marine life. Since then, the Williams Companies has adjusted their proposal and reapplied (via a subsidiary) for permits in both states. New York is accepting comments from residents until July 13 – a fast-approaching deadline which may have prompted the email to National Grid customers.“Approval of the Northeast Supply Enhancement (NESE) Project is needed to access the additional natural gas supplies required to support our region,” the company told Grist via email. “Without NESE, National Grid will not be able to supply natural gas to new commercial, industrial and residential customers to heat their homes or run their businesses, putting the region’s economic growth at risk, as well as impeding state and city carbon emission goals.”

Refinery impacts if Enbridge’s Michigan crude oil pipeline is shut down — Line 5 – The battle over the future of Enbridge’s Line 5 light crude oil pipeline through Michigan is heating up. In recent weeks, Michigan’s new attorney general filed suit to throw out the 1953 easement the state granted to allow the pipeline to be laid under the Straits of Mackinac – the narrow waterway between Michigan’s upper and lower peninsulas – and to block implementation of an agreement Enbridge and the state’s then-governor reached last fall to replace the section of Line 5 under the straits by the mid-2020s. Enbridge is pressing ahead, maintaining that the existing pipeline is safe and the 2018 agreement is legal and fully enforceable. All that raises two questions: just how important is Line 5 to the Michigan and Eastern Canadian refineries, and what would those refineries do if the pipeline were to cease operations? Today, we discuss recent developments and examine the issues at hand. Enbridge’s Line 5, part of the Canadian midstream company’s much larger Mainline/Lakehead crude oil pipeline system, has been an important conduit for moving Western Canadian and Bakken crude oil and NGLs across Michigan’s upper and lower peninsulas – and into Ontario – for more than 65 years. Line 5 (purple line in Figure 1) is one of multiple Enbridge pipelines out of the company’s terminal in Superior, WI. The 540-Mb/d pipeline transports “batches” of either light crude, light synthetic crude or mixed NGLs 645 miles east/southeast through Michigan to Sarnia, ON. The crude oils and NGLs are sourced primarily in Western Canada (but also in the Bakken) and are bound for Michigan, Ontario and Quebec. At the Straits of Mackinac (dashed red oval) – the four-mile-wide water passage between Michigan’s upper and lower peninsulas (and Lake Michigan and Lake Huron) – the 30-inch-diameter, single-pipe Line 5 splits into two 20-inch-diameter, parallel pipes that are anchored along the straits’ lakebed.

Indigenous leader of Line 5 opposition is now consulting for Enbridge – Indigenous governments and activists in the Great Lakes have been leaders in the movement to shut down the twin oil pipelines that run under the Mackinac Straits. Now, one of the most visible people in that movement has left his tribal government job and set up his own consulting firm. One of his clients? The pipelines’ owner, Enbridge Energy. This sudden change has upset indigenous communities in the region, and some worry it’s a “divide-and-conquer” tactic. Up until this spring, Desmond Berry directed the Natural Resources Department for the Grand Traverse Band of Ottawa and Chippewa Indians. His tribe has treaty rights in Lakes Michigan and Huron, in and around the Straits of Mackinac. He’s been a fixture at rallies opposing Line 5. At an event in the Straits of Mackinac in 2017, he spoke about the Grand Traverse Band’s interest in shutting down the pipeline: “The twin oil pipeline threatens both our ability to exist as Anishinaabek, and it threatens our ability to harvest fish,” he said then. So, Andrea Pierce was surprised when he quit his job, started a consulting business with a colleague, and picked up Enbridge as a client. “You know, I felt betrayed, hurt, all of the normal things,” said Pierce. Pierce is a citizen of the Little Traverse Bay Bands of Odawa Indians. She collaborated with Berry on Line 5 protest events for years. She also co-chaired the Anishinaabek Caucus for Michigan’s Democratic Party with him. He has since resigned from the caucus. Pierce said his decision was a shock, and created a lot of distrust. She said some people have even been suspicious of her, because of how close she was to Berry. So, she’s adamant about putting it on record that she would never support or work for Enbridge. “We’re gonna second-guess a lot of people and a lot of things that happened, but that’s what they want and we have to move past that,” said Pierce.

Duluth leaders push for closer look at toxic refinery chemical –Duluth Mayor Emily Larson won’t easily forget the day in April 2018 when amassive explosion and fire rocked the Husky Energy oil refinery in neighboring Superior, Wis., sending a towering plume of thick, black smoke into the sky, and forcing the evacuation of much of the city across the St. Louis River.”It was a horrifying feeling,” she recalls.Luckily, the worst fears of emergency responders were not realized. The explosion sent shrapnel flying, piercing an enormous asphalt tank, which caused the fire. But it missed a nearby tank storing hydrogen fluoride, a highly toxic chemical compound used to make high-octane gasoline. Hydrogen fluoride can be fatal if it’s inhaled.The near-miss prompted calls from Larson and Superior Mayor Jim Paine for Husky to discontinue use of hydrogen fluoride. On Monday, the Duluth City Council plans to vote on a resolution asking the federal Environmental Protection Agency to study the use of hydrogen fluoride in refineries to ensure the safety of communities like Duluth and Superior. Larson, who backs the resolution, said the explosion at the Husky refinery was a call to action. Husky officials in April said they planned to continue to use the substance when they rebuild the facility, after an analysis concluded that “alternatives were not commercially viable or introduced significant risks for the Superior Refinery,” according to Husky spokesperson Mel Duvall.

Barry Shuts in 69 Percent of GOM Oil Output – Approximately 69.08 percent of oil production in the Gulf of Mexico (GOM) was shut in as of 11:30 a.m. CDT Monday due to Tropical Storm Barry. That’s according to estimates from the Bureau of Safety and Environmental Enforcement (BSEE), which were based on data from company reports. The figure equates to 1.31 million barrels of oil per day according to BSEE, which also estimated that around 60.58 percent of natural gas production in the region, or 1.68 billion cubic feet, had been shut in. As of Monday, personnel had been evacuated from a total of 267 production platforms, or 39.9 percent of the 669 manned platforms in the GOM, BSEE highlighted. The organization also pointed out that personnel had been evacuated from 10 non-dynamically positioned DP rigs, equivalent to 47.6 percent of the 21 rigs of this type currently operating in the GOM. “The team will continue to work with offshore operators and other state and federal agencies until operations return to normal and the storm is no longer a threat to Gulf of Mexico oil and gas activities,” BSEE said in an organization statement on Sunday. On July 14 at 8 a.m. PDT, Chevron revealed that it had begun to redeploy personnel and restore production at its Big Foot, Blind Faith, Genesis, Jack St. Malo, Petronius and Tahiti platforms that were shut-in as a result of Barry. The company added that, at its onshore facilities, including in Pascagoula, Mississippi, and Pasadena, Texas, it was following its storm preparedness procedures and paying “close attention” to the forecast and track of the system. Shell said yesterday that its offshore crews and assets had “weathered the storm well”. “However, we have shut in the Auger, Salsa and the Enchilada assets in the Gulf of Mexico and curtailed production in the Mars Corridor as a result of the effects of this storm,” the company added. “Downstream third-party facilities have experienced weather-related issues, including power loss, that are limiting, restricting or halting some or all of their operating capabilities. We continue to monitor and work with those third-party providers in order to resume normal production as soon as is safely possible,” Shell continued.

Storm Barry cuts 73% of U.S. offshore oil production: U.S. government (Reuters) – Tropical Storm Barry has cut 73%, or 1.38 million barrels per day (bpd), of crude oil production in the U.S.-regulated areas of the Gulf of Mexico, the U.S. Bureau of Safety and Environmental Enforcement (BSEE) said on Sunday. Natural gas output from the northern Gulf of Mexico is down 62%, or 1.7 billion cubic feet per day, BSEE said. A total of 283 production platforms, or 42%, remain shut in the Gulf of Mexico, BSEE said.

Oil and gas producers in the Gulf of Mexico restart after Barry — U.S. oil companies on Monday began restoring some of the more than nearly 74% production shut at U.S. Gulf of Mexico platforms ahead of Hurricane Barry, the U.S. offshore drilling regulator said. There was 1.3 million barrels per day (bpd) of oil production off line in the U.S.-regulated areas of the Gulf of Mexico on Monday, about 80,000 barrels less than on Sunday, according to the U.S. Bureau of Safety and Environmental Enforcement (BSEE). Workers also were returning to the more than 280 production platforms that had been evacuated. It can take several days for full production to be resumed after a storm leaves the Gulf of Mexico. Anadarko Petroleum, BHP Group, Chevron and Royal Dutch Shell on Monday said they had begun returning staff to evacuated platforms and were in the process of restoring operations. “Redeployment and crew-change flights to some of our assets have begun now that weather conditions in the Gulf and onshore have improved,” said Shell spokeswoman Cynthia Babski. Three Shell platforms remained shut and another at limited production on Monday, she added. Barry came ashore in central Louisiana as a category one hurricane with at least 74-mile-per-hour (119-km-per-hour) winds on Saturday after emerging into the gulf from Florida earlier in the week. By late Monday afternoon, it was a post-tropical cyclone and dropping up to 4 inches (10 cm) of rain on Arkansas. In its wake, offshore natural gas production in the Gulf of Mexico was down 61%, or 1.7 billion cubic feet per day (cfd), on Monday, BSEE said. The amount of gas flowing to Cheniere Energy Inc’s Sabine Pass liquefied natural gas (LNG) export facility in Louisiana, rose to a one-week high of 3.7 billion cfd. Last week, the amount of gas flowing to Sabine fell to a 13-week low of 2.9 billion cfd on Thursday, according to Refinitiv. Most refineries in southeastern Louisiana kept running through the storm except for Phillips 66′s 253,600-bpd Alliance, Louisiana, refinery, which the company began restarting on Monday.

77.8M acres in Gulf of Mexico for August oil, gas lease sale (AP) – The federal government will offer 77.8 million acres (31.5 million hectares) in the Gulf of Mexico for oil and gas exploration and development on Aug. 21. An Interior Department statement says the lease sale will include 14,585 tracts. They’re in water 3 to 231 miles (5 to 370 kilometers) offshore and in water from 9 feet to more than 2 miles (3 to 3,400 meters) deep. Until August 2017, the Interior Department held separate lease sales for the Gulf’s most active area and tracts off Texas. They were consolidated under an Obama administration plan created because bidder numbers were dwindling. In March , 78.5 million acres (31.7 million hectares) were offered and about 1.3 million acres (0.5 million hectares) drew $244.3 million in high bids. The high bid total was about 37% above the previous sale’s and nearly double the March 2018 figure.

Coast Guard responds to oil slick near Port Aransas, Texas – Coast Guard crews responded to a report of oil that washed ashore at the Port Aransas Municipal Boat Ramp in Port Aransas, Texas, Wednesday. At 7:15 a.m., Sector/Air Station Corpus Christi Incident Management Division received notification from the Texas General Land Office of an oil slick at the Port Aransas Municipal Boat Ramp. A Sector/Air Station Corpus Christi IMD duty team responded and estimated the oil slick at 40 gallons. The IMD duty team accessed the Oil Spill Liability Trust Fund and partnered with the Texas General Land Office, the Port Aransas Harbor Master and contractors to remove the oil from the water and decontaminate structures around the boat ramp using a pressure washer, VAC truck, active skimming and absorbents. The cause of the oil slick is under investigation.

Kinder Morgan’s newest Permian Basin pipeline headed to East Texas – Houston pipeline operator Kinder Morgan said it will route its newest natural gas pipeline project from West Texas to East Texas, where it will support the burgeoning liquefied natural gas industry expanding along the Texas and Louisiana Gulf Coasts. In a call with investors, Kinder Morgan CEO Steven Kean said the exact route for the proposed Permian Pass Pipeline is still being researched, but it will begin in the Permian Basin and move 2 billion cubic feet of natural gas per day to LNG export terminals along the Sabine River. The Houston LNG company Cheniere Energy owns and operates an export terminal on the Louisiana side of the Sabine River. The San Diego utility Sempra Energy is building an export terminal in nearby Port Arthur while a joint venture between Exxon Mobil and Qatar Petroleum is redeveloping an import terminal on the Texas side of the Sabine River into an export terminal. “The supply growth out of the Permian Basin and the expected demand growth primarily as a function of demand from the LNG industry is still very robust and should translate itself into a firm, long-term commitment,” Kean said. Natural gas is a byproduct of oil drilling. In the Permian, the natural gas produced with oil is so abundant and pipeline capacity so constrained that most of it is burned off, or flared. Kinder Morgan has three pipeline projects that will move it from the West Texas shale play to customers along the Gulf Coast and in Mexico. Kinder Morgan’s Gulf Coast Express Pipeline is expected to begin moving 2 billion cubic feet of natural gas per day in late September from the Permian to the Agua Dulce Hub near Corpus Christi, where it can be used by customers along the Coastal Bend and in Mexico.

U.S. shale firms put up $16.5 million to build West Texas charter schools (Reuters) – Twenty top U.S. energy companies agreed to contribute $16.5 million to open new schools in West Texas, where an influx of oil and gas workers have strained schools, roads and other civic services. This is the first initiative by the Permian Strategic Partnership, a consortium of shale producers which has pledged to raise $100 million to address civic strains, a spokesman for the group said. The companies all operate in the Permian Basin, the top U.S. shale field. Another $22 million will be donated by local foundations and philanthropists. The funds are earmarked to bring IDEA Public Schools, a national tuition-free charter school, to the region, the group said. The Permian Strategic Partnership aims to address labor and housing shortages, school overcrowding, healthcare and traffic congestion in the Permian Basin. Its founding members are oil and gas producers and suppliers which aim to pump millions of barrels of oil and gas in coming decades. The shale boom has lifted Permian oil production to 4.2 million barrels per day, and made the United States the world’s biggest oil producer and fifth largest exporter, according to the International Energy Agency, a group of major oil consuming nations.

This Shale Fracker’s Decision to Sell Says It All – A big deal in the Permian basin should be cause for fanfare in oil and gas circles. And yet, a distinct sad-trombone note sounds as Carrizo Oil & Gas Inc. falls into the arms of Callon Petroleum Co. Callon is offering a 25% premium in an all-stock acquisition, based on Friday’s closing prices. But it’s the absolute price that tells the real story. Carrizo is selling out for $13.12 a share, getting it back to where it traded just less than three months ago – and way below the $23 level where it sold a slug of new shares last August. If Callon is engaging in some bottom-fishing, Carrizo is nonetheless grabbing eagerly at hook, line and sinker. Carrizo’s decision to sell with its stock trading close to its lowest levels in a decade is the salient fact here. It is being paid with stock and its shareholders will own 46% of the enlarged Callon, so they can participate in any gains once the deal is done. They’re better off not looking too closely at their screens on Monday, though: Callon’s stock slumped by as much as 17% Monday morning, wiping out the implied premium. Even so, there is a compelling logic to shale consolidation. A decade of breakneck expansion has left the onshore U.S. exploration and production business overcapitalized, with a long tail of inefficient smaller companies offering lackluster returns (see this). Carrizo is a prime example. Its total return over the past five years is negative 84%, which makes the sector’s negative 64% look good (the S&P 500 has returned a positive 69% in that time). Indeed, activist firm Kimmeridge Energy Management Co. tried last year to nudge the company into streamlining or selling itself to address this. Carrizo, which was trading at about $17 a share back then, disagreed. It is telling that up to $45 million of Callon’s synergies target relates to cutting general and administrative overhead. That is equivalent to more than two-thirds of Carrizo’s G&A line, reinforcing one of Kimmeridge’s lines of argument about the inefficiency inherent in such a fragmented industry. Those cash savings also speak to the other key point in Callon’s marketing push, namely an implied free cash flow number north of $200 million in 2020. Based on Callon’s current price, that implies a pro forma free cash flow yield of about 10%, which may be enough to tempt some investors back into the stock when the smoke clears – although pro forma net debt of two times Ebitda (including synergies) means some of that will have to go toward reducing leverage.

EIA forecasts U.S. shale oil output to climb by 49,000 barrels a day in August – Crude-oil production from seven major U.S. shale plays is forecast to climb by 49,000 barrels a day in August to 8.546 million barrels a day, according to a report from the Energy Information Administration released Monday. Oil output from the Permian Basin, which covers parts of western Texas and southeastern New Mexico, is expected to see an increase of 34,000 barrels a day in August from July. Shale oil output from the Anadarko and Eagle Ford regions, however, are expected to see slight monthly declines, the report showed. The August contract for West Texas Intermediate oil was trading down 64 cents, or 1.1%, at $59.57 a barrel ahead of its settlement on the New York Mercantile Exchange.

The crude oil adjustment accounts for differences in supply and disposition – The U.S. Energy Information Administration’s (EIA) Weekly Petroleum Status Report (WPSR) provides weekly estimates of U.S. crude oil supply, including a measure of how well the supply of crude oil and the disposition of crude oil balance with each other. This measure – referred to as the adjustment – is a derived term equal to the difference between supply and disposition. If the reported supply and disposition of crude oil balanced perfectly each week, the adjustment would equal zero. For several reasons, however, this is rarely the case. Weekly U.S. crude oil supply and disposition data are based on a combination of EIA survey data, U.S. Customs and Border Protection data, and modeled estimates. All statistical samples using survey data have small but unavoidable imprecisions, and model estimated data’s precision can vary. This imprecision in estimating each element of the crude oil balance can result in some over- and under-estimation in both supply and disposition. In recent weeks, the crude oil adjustment has been growing in absolute value, as high as 881,000 barrels for the week ending May 24. However, this is still relatively small, when compared with the entire U.S. crude oil balance, less than 2.5% on a rolling four-week average basis (the sum of production, imports, exports, and refinery inputs) (Figure 1). Although an increased adjustment is, in some part, the result of the inherent challenge of estimating perfectly each reporting period, increasing volumes of U.S. crude oil production and exports and other factors may also play a role. EIA will continue to evaluate crude oil data to identify possible sources of the higher crude oil adjustment. (NB should real 881,000 barrels per day)

Shale Investors Fear Bloodbath As Earnings Season Kicks Off – The oil majors and shale E&Ps will soon begin publishing second quarter results, which will round out a picture of how the industry fared in the first half of 2019. Shale drillers find themselves at a troubling crossroads. Since 2012, North American oil and gas companies have eviscerated $187 billion in cash flow. Production has soared but the profits have not materialized. For years investors shoveled more capital their way, and the money was dutifully injected into the ground. More oil came up, but again, the financial returns did not follow. Wall Street is losing patience. “Investor sentiment continues to be negative heading into 2Q,” Goldman Sachs wrote in a note. “Meetings with investors this week indicated that generalist portfolio managers are largely hiding and not seeking.” By “hiding,” the bank said that investors were sticking with midstream and integrated companies, and also clean energy. They are “not seeking” oilfield services companies, which are particularly out of favor. That doesn’t mean that they are shunning shale altogether, but Goldman’s assessment was that most investors are sticking with “quality,” and the bank cited EOG Resources, Pioneer Natural Resources, as well as the majors, including Chevron and ExxonMobil, as examples. More notably, Goldman said that while analysts have a wide variety of opinions on things like oil production growth levels, “increasingly specialists are not debating whether stocks go up or down but are flat vs. go down.” In other words, if shale drillers do everything right – they keep capex in check and still produce as much as expected – their share prices will merely stay flat.Related: Fracking Under Fire In California On the other hand, if companies need fresh capital injections, decide to spend more, or report disappointing production figures, then their stocks will sink, Goldman warned. There isn’t a huge upside to shale stocks; at best they will tread water. The industry is in the midst of a wave of consolidation. The decision by Callon Petroleum to buyCarrizo Oil & Gas is a telling example of the trouble that some shale drillers find themselves in. As Liam Denning at Bloomberg Opinion noted, Carrizo’s decision to sell out at a time when its share price was at a multi-year low suggests that it saw little chance that it would be able to drill its way out of its financial predicament. That’s a departure from the past, when companies sought fresh capital and another round of drilling.

Finance Costs are Killing the Shale Industry – If the rapid decline rate or the massive debt doesn’t destroy the U.S. Shale Industry, the finance costs most certainly will. The amount of interest expense the shale companies have paid to finance business and increase production is stunning, to say the least. But, the real problem for the shale industry, isn’t the interest expense that they have already paid, but the staggering amount owed in the future. Actually, I was quite shocked by some of the figures I was coming across during my research. You see, many articles on the Shale Industry have focused on the tremendous amount of debt saddling the companies’ balance sheets. However, one surprising statistic that is not mentioned is the “Total Interest Expense” due on all this debt to maturity (or in the future). While I have posted some graphs showing much much the shale companies were paying in interest expense each quarter or annually, I never considered how much their “Total Finance Cost” would be over the life of their loans (debts). For example, one company that I keep track of is Oasis Petroleum. Oasis has focused most of its drilling and production in the Bakken Field in North Dakota. I believe Oasis is in real trouble because their stock price is very close to a critical $5.00 support level: You will notice that Oasis was trading more than ten times its present value at $55 a share in 2014. Currently, Oasis is trading at $5.20 a share, and a significant-close below $5.00 on the monthly chart spells big trouble for the company. Last year, Oasis paid $159 million in interest expense just to finance its debt. Which is terrible news, because the company’s free cash flow was a negative $155 million in 2018. Thus, if Oasis did not have to pay this high-interest expense, it would have been free cash flow positive. But, as I stated, you should see how much Oasis owes in total interest on its remaining debt:

What Looms Behind – Kunstler – Don’t hold your breath waiting for a coherent pre-election debate about the mother-of-all-issues facing this republic, namely, that we can’t afford the living arrangements Americans think of as “normal” anymore. This quandary has stalked us since the millennium turned. It thunders through all the activities of daily life, and the tensions emanating from it are so agonizing and difficult to face that our politics have deflected off into the kind of hysteria spawned by bad dreams. As the great Wendell Berry pointed out years ago, this is about the nation’s home economics: energy and resources in, production out, surplus wealth saved. The shale oil miracle “solved” the energy-in problem.. Shale oil was a neat stunt. Turns out you can produce a helluva lot of it by paying more to pull it out the ground than you get from selling it. You can goose the process nicely by paying for it with borrowed money. And so it has gone. America now produces a new record of over 12 million barrels a day, and most of the companies doing it can’t make a red cent. And since it is increasingly obvious that they won’t ever pay back the money they borrowed before, they are unlikely to get new loans to continue their profitless operations. Notice how rapidly shale oil production shot up after 2008. It’s worth a peek at analyst Steve St. Angelo’s latest essay on shale oil company debt (Finance Costs Are Killing the Shale Industry) to understand just how this stunt worked. As blogger Tim Morgan at Surplus Energy Economics points out, the dis-economics of energy production – and shale oil in particular – are stealthily damaging everyday life: “…the world economy is already suffering from these effects, and these have prompted the adoption of successively riskier forms of financial manipulation in a failed effort to sustain economic ‘normality.’” That tells you exactly why the stock markets are at record highs now, along with US shale oil production. What the nation doesn’t get is that the shale oil industry is sure to collapse, and at least as rapidly as it shot up. So, expect the stock markets to collapse with it, along with tremendous collateral damage to all the other instruments that represent “money” – bonds, currencies, and their derivatives. It will make the 2008 episode look like a mere overturned poker table when it happens. In the meantime, many of the activities enabled by the oil industry are wrecking the planet, not just CO2 emissions, but the plastics and chemical industries especially. So, the oil quandary bites at both ends: damned if it quits on us and damned if it keeps going.

Oil service firms eye new survival tactics amid weak U.S. market (Reuters) – Packers Plus Energy Services, a company built on the North American shale oil boom, is turning to the Middle East to weather a new round of spending cuts by producers amid warnings of a looming oil glut. Oil production has outpaced demand by 900,000 barrels per day (bpd) this year, according to the International Energy Agency, which expects increases to add a net 136 million barrels to the global surplus by March. Spending cuts by producers also have sharply cut service providers’ margins, a June survey of 60 providers by the Dallas Federal Reserve Bank revealed. The last time supplies overwhelmed demand, oilfield service suppliers cut 100s of thousands of jobs and top firms gushed red ink. Memories of that sharp downturn in late 2014 have executives such as Ian Bryant, chief executive officer of privately-held, Calgary-based Packers Plus, again cutting jobs, seeking safe harbors, mergers, or putting business units on the market. These defensive strategies comes as oil and gas drillers are producing vastly more oil with less investment. On average, analysts expect the top 50 U.S. independent oil producers will cut spending by 20% this year, with some by as much as 60%, according to review by researcher DrillingInfo. That drop has Bryant’s Packers Plus, which historically catered to North American onshore producers, looking beyond shale and toward markets in the Middle East for future business. “There are obviously geopolitical risks, but the cycles are not as vicious as they are in North American land,” “Service pricing is unsustainable at present levels.” Weatherford International, once a top four oilfield service provider, filed for protection from creditors this month and has been cutting staff, citing “market headwinds” and lack of access to financing. In the last 18 months, other top service firms, including the world’s top oilfield services company Schlumberger (SLB.N), added or acquired new hydraulic fracturing fleets in a bet that a backlog of uncompleted shale wells would grow their businesses. But across the U.S. the number of yet-to-be-fracked wells hit 8,289 in May, up 22% in a year, according to the U.S. Energy Information Administration.

Oilfield wastewater may trigger earthquakes for ‘decades’ – The United States is undergoing a boom in oil and gas production as well as fracking, the process of shooting water mixed with sand and chemicals deep into the earth to bring up hydrocarbons trapped inside rock. Wastewater from fossil fuel production has long been associated with tremors, as producers dispose of it by injecting jets into separate wells dug below ground. The United States Geological Survey says that wastewater disposal from oil and gas production is the number one cause of human-induced earthquakes in the central and eastern US. A team of experts from Virginia Polytechnic and State University now believe that the wastewater, due to its higher density, can pose an earthquake risk for years to come, since it displaces existing groundwater stocks that keep the ground stable. They developed a model based on the wastewater flows in two fracking-heavy states, Kansas and Oklahoma. The team found that the wastewater altered the subterranean fluid pressure to such an extent that it posed a quake risk for decades. “That has some very interesting and I think important consequences for how we understand the hazard posed by oilfield wastewater disposal,” said Ryan Pollyea, lead author of the study, published in Nature Communications. Tremors of magnitude 3 or greater used to be relatively rare in the central United States. But in the wake of vast fossil fuel exploration, their numbers have skyrocketed from around 20 a year in 2008 to more than 400 annually. One particularly strong quake struck Oklahoma in September 2016, measuring 5.6 magnitude – large enough to be felt in seven states, from Texas to Iowa. A peer-reviewed study a few months later suggested that four of the most five powerful Los Angeles Basin quakes of the early 20th-century oil boom may have been caused by oil and gas production. Pollyea and the team found that the earthquakes were also getting stronger: in the two states analysed the number of magnitude 4 quakes increased 150 percent since 2016, while the number of 2.5-magnitude tremors went down by over a third. They are also getting deeper. “We have found a new mechanism to explain how fluid pressure causes and increases earthquakes deep under ground,” Pollyea said.

Trump’s Drilling Leases on Public Lands Could Lead to 4.7B Metric Tons of Carbon Emissions – A national conservation group revealed Wednesday that President Donald Trump‘s drilling leases on public lands could lead to the release of more carbon emissions than the European Union contributes in an entire year. The Wilderness Society estimates that U.S. companies will emit at least 854 million and as much as 4.7 billion metric tons of carbon if they develop leases in public waters and lands. “Taking into account the potency of shorter-lived climate pollutants like methane, lifecycle emissions resulting from the development of these leases could be as high as 5.2 billion metric tons,” the group’s new reportr eads. The 28 countries in the EU released four billion metric tons in one year, according to the most recent available data. Regardless of exactly how many leases are put to use by oil and gas companies, the Wilderness Society reports, “These leasing decisions have significant and long-term ramifications for our climate and our ability to stave off the worst impacts of global warming.” Since taking office in 2017, Trump has offered up 378 million acres of public land to oil and gas companies and has sought to overturn the Obama administration’s ban on coal leases.

SMLP Announces Start-Up of DJ Basin Processing Plant – Summit Midstream Partners announced today the successful commissioning of its new 60 MMcf/d cryogenic processing plant in the DJ Basin. The new facility, which substantially increases SMLP’s prior processing capacity in the DJ Basin, delivers residue gas to Colorado Interstate Gas and Trailblazer Pipeline and processed NGLs to the Overland Pass Pipeline. In addition, SMLP expects the new plant to operate more efficiently and to generate substantially higher NGL recoveries compared to SMLP’s legacy 20 MMcf/d processing facility. Volumes at this new plant are expected to ramp considerably throughout the balance of 2019 based on existing production behind our system and new production associated with our customers’ drilling and completion schedules. SMLP’s capital investment in the new processing plant was underpinned with monthly demand payments from certain of our customers, and the commissioning of the plant enables SMLP to earn those monthly demand fees, beginning in the third quarter of 2019. SMLP estimates that the new facility will enable annualized DJ Basin segment adjusted EBITDA for the second half of 2019 to more than triple the $7.6 million of DJ Basin segment adjusted EBITDA reported in all of 2018.

North Dakota sues feds over pipeline protest police costs (AP) – North Dakota sued the federal government Thursday to recover the $38 million the state spent policing protests against the Dakota Access oil pipeline. Attorney General Wayne Stenehjem said he filed the claim in Bismarck federal court after the Army Corps of Engineers ignored an administrative claim he filed one year ago. The agency did not immediately return telephone calls seeking comment Thursday. It has 60 days to respond to the state’s 37-page lawsuit. Thousands of opponents of the $3.8 billion pipeline that’s been moving North Dakota oil to Illinois for two years gathered in southern North Dakota in 2016 and early 2017, camping on federal land and often clashing with police, resulting in 761 arrests over six months. Stenehjem said the Corps “allowed and sometimes encouraged” protesters to illegally camp without a federal permit. The Corps has said protesters weren’t evicted due to free speech reasons. The Corps’ inaction required North Dakota to provide law enforcement to prevent deaths and protect property, including that of the protesters, Stenehejem said. “When the protesters finally left, they left behind a spoiled environment and a vast quantity of dangerous waste, garbage and debris that had to be cleaned up by the state at considerable cost,” Stenehjem told reporters.

Pipe spills oilfield wastewater in Missouri River tributary — Cleanup is underway after 21,000 gallons of brine oilfield wastewater leaked from an underground pipeline in western North Dakota and into an unnamed tributary of the Missouri River, the state Health Department said Monday. State environmental scientist Bill Suess said the pipeline operator, Polar Midstream LLC, on Sunday reported the spill of produced water, a byproduct of oil production that contains saltwater and oil, and sometimes chemicals from hydraulic fracturing operations. The spill occurred about 20 miles (32 kilometers) east of Williston and about a mile from Lake Sakakawea, the largest reservoir on the Missouri River. Suess said Monday it did not appear the spill reached the lake. The cause of the spill was not known Monday. Polar Midstream is a unit of Woodlands, Texas-based Summit Midstream Partners LLC, which was responsible for a 3 million-gallon (11.4 million liter) produced water leak from a pipeline in 2014, the largest of its kind in the state. The company did not immediately return a telephone call Monday. Suess said Sunday’s spill from the underground pipeline affected an area around a drilling site and a nearby tributary, which has been dammed. “We’ve seen some saltwater impacts (to the tributary) but no oil,” he said. “We will make sure any impacted water is pumped out.” The company also will dig up the pipeline and replace it, he said.

Montana, North Dakota push against Washington state rail law — Attorneys general for North Dakota and Montana asked the Trump administration on Wednesday to overrule a Washington state law that imposed new restrictions on oil trains from the Northern Plains to guard against explosive derailments.In a legal petition to the U.S. Department of Transportation, Montana Attorney General Tim Fox and North Dakota’s Wayne Stenehjem said federal authority over railroads pre-empts the state law.Washington Gov. Jay Inslee, a Democrat, in May signed the measure that requires oil shipped by rail through the state to have more volatile gases removed to reduce the risk of explosive and potentially deadly derailments.The move followed a string of fiery and explosive oil train derailments over the past decade, including a 2013 accident in Lac-Megantic, Quebec, that killed 47 people. The explosions drew widespread public attention to the volatile nature of Bakken crude shipments. But opponents say the new restrictions would make Pacific Northwest refineries effectively off-limits to crude from the Bakken region, one of the nation’s most productive oil fields straddling the North Dakota-Montana border. That’s because the process of treating the oil to make it less volatile would be too expensive to justify, they said.”It’s pretty clear in this the state of Washington overstepped its bounds,” Fox said. “The effect would be terrible, both on the economies of North Dakota and Montana and also how it offends the rule of law.”

Chevron Has Spilled 800,000 Gallons of Crude Oil and Water Into a California Canyon Since May –California officials ordered Chevron Friday “to take all measures” to stop a release that has spilled around 800,000 gallons of water and crude oil into a dry creek bed in Kern County, KQED reported. The order, issued by the new acting head of the state’s Division of Oil, Gas and Geothermal Resources (DOGGR) Jason Marshall, also said the fossil fuel company had not done enough to stop the spills that had begun May 10. The order came a day after California Gov. Gavin Newsom fired former DOGGR head Ken Harris after a significant rise in fracking permits. “The Chevron spill clearly shows that California needs stronger climate leadership from the governor,”Greenpeace USA Executive Director Annie Leonard said in a statement reported by KQED. “Oil and gas infrastructure will never be free from spills and leaks or from spewing climate pollution. We face a growing public health crisis and climate emergency stoked by rampant oil and gas development.”DOGGR had initially issued Chevron with an order of violation and ordered it to stop some extraction in the area. Friday’s order upped the ante by mandating the company completely stop the releases and take steps to prevent future ones.”Chevron takes these matters seriously,” the company said in a statement Saturday. “We will review the order and continue working in a collaborative manner with the involved agencies.” Officials began Friday to clean the spill, The Associated Press reported, which is the largest of California’s recent oil spills. However, while the spill is larger than both the 2015 spill that dumped 140,000 gallons of crude oil onto Refugio State Beach and the 2007 spill of 54,000 gallons of oil into San Francisco Bay, it has been less devastating since it was not near an active waterway and has not significantly impacted wildlife, both company and state officials said.

California governor orders firing of oil, gas regulator (AP) – Gov. Gavin Newsom ordered the firing of California’s top oil and gas regulator Thursday over an increase in state permits for hydraulic fracturing and allegations of conflicts of interest among senior government officials. Newsom’s chief of staff asked the state’s natural resources secretary to dismiss Ken Harris, who was appointed to lead the Division of Oil, Gas and Geothermal Resources in 2015. She also told Secretary Wade Crowfoot to continue an investigation into reports that employees at the agency own stock in companies that they regulate. Ann O’Leary’s request came hours after advocacy groups Consumer Watchdog and FracTracker Allliance released data showing regulators have been issuing permits for hydraulic fracturing at twice the rate this year when compared to 2018. The number of permits granted for drilling new wells also increased by 35% from January 1 to June 3 when compared to the rate last year, according to the groups’ data. The organizations said that of the 2,365 well permits issued in those months, 45% benefited oil companies in which division officials owned stock. Newsom took office in January and O’Leary told Natural Resources Secretary Wade Crowfoot in an email shared with the Associated Press that the number of hydraulic fracturing permits had increased without his knowledge. “The Governor has long held concerns about fracking and its impacts on Californians and our environment, and knows that ultimately California and our global partners will need to transition away from oil and gas extraction,” O’Leary wrote. “In the weeks ahead, our office will work with you to find new leadership of (the division) that share this point of view and can run the division accordingly.” Consumer Watchdog and FracTracker Alliance noted a deputy director at the division disclosed owning stock in ExxonMobil worth as much as $100,000.

California governor criticizes increase in fracking permits – (AP) – California Gov. Gavin Newsom said Friday he wants to move the nation’s most populous state away from hydraulic fracturing, a day after he fired the state’s top oil and gas regulator for issuing twice as many fracking permits this year compared to last. “I don’t think anyone that was paying attention, including the individual that’s no longer there, is unaware of my position on fracking,” Newsom told reporters. “I’ve been very explicit about it. The fact that they did not exercise consistency with that is one of the reasons he’s not there.” He fired state Oil and Gas Supervisor Ken Harris following reports the state Division of Oil, Gas and Geothermal Resources had doubled the fracking permits it issued in the first half of 2019, and that senior officials at the division held stocks in oil companies they were responsible for regulating. Newsom said he doesn’t have the authority to put a moratorium on fracking, but that he wants to transition the state away from its use and, more broadly, reliance on oil and gas. Several environmental groups disputed his claim that he can’t ban fracking himself and noted the Legislature can ban it. “The governor definitely has the power to instruct the agency to ban fracking, to stop issuing permits for new wells, to stop the expansion of the industry and to protect public health,” said Kassie Siegel, director and senior counsel of the Climate Law Institute at the Center for Biological Diversity. Beyond increasing permits for fracking, the process of extracting oil and natural gas from rock, records show the number of permits for drilling new wells has increased. The advocacy organizations Consumer Watchdog and FracTracker Alliance found of the 2,365 oil well permits issued this year, 45% benefited oil companies in which division officials owned stock.

After 800,000-gallon spill, Chevron site is still leaking oil – On the same day Sen. Dianne Feinstein chastised Chevron Corp. for keeping an 800,000-gallon spill outside Bakersfield “under wraps,” California officials confirmed Thursday that the site was once again seeping a hazardous mix of oil and water. The new leakage occurred in a surface expression vent in the Cymric oil field, near the Kern County town of McKittrick, according to the state Division of Oil, Gas and Geothermal Resources. The vent is one of the locations where three previous leaks released about 800,000 gallons of oil and water. Field inspectors from the agency identified the latest seepage at 3 p.m. Wednesday and released information about the latest spill Thursday. The agency is working to address what they are describing as a large oil release. The leak potentially resulted from a high-intensity steam injection intended to release oil. According to the agency, the first leak occurred on May 10 and was stopped that day. New seepage occurred on June 8 and continued to flow intermittently for a span of five days. The persistent seepage was again recorded June 23 and Wednesday, the agency said. On Thursday, Feinstein (D-Calif.) issued a news release accusing Chevron of failing to inform the public about the leak. “This is something the public should have been alerted to earlier,” she said. “Proper oversight can’t occur if incidents like these are kept under wraps.” Feinstein said that although the company said it had recovered most of the oil, “the full toll to the area is not yet known.” She said it was fortunate that the leak did not occur “during a rainy period or the effects on our environment and wildlife would have been even more tragic.” The Kern County Environmental Health Services Department reports that the Division of Oil, Gas and Geothermal Resources is the lead agency addressing the spill. Kern County Public Health is not legally permitted to enter the site until it is deemed safe. After that time, the county will work alongside appropriate agencies to begin the cleanup. On Thursday, the Natural Resources Defense Council echoed Feinstein’s concerns. “This is not the time for Chevron to keep details about this destructive oil spill from the public,” said Damon Nagami, the council’s senior attorney. “Time and time again, we’ve seen the devastating effects of oil spills on our wildlife, water and communities. Multiple notices of violation signal that is a serious problem, and we expect DOGGR to hold Chevron fully accountable.”

Chevron Aims to Turn Canada LNG Plan Into Electric Design – — Chevron Corp. is seeking approval to modify its plans for a liquefied natural gas export facility on Canada’s Pacific Coast to an all-electric design that it says will result in the lowest greenhouse-gas emissions per ton of LNG of any large project in the world. Chevron and its partner Woodside Petroleum Ltd. earlier this year had announced they’d applied to expand the capacity of their LNG project in Kitimat, British Columbia, by as much as 80% to 18 million metric tons a year. That triggered a new federal screening of the project that’s expected to “commence shortly,” according to a July 8 letter filed by Chevron to the provincial environmental assessment office. As part of the fresh round of approvals sought, the project is proposing to become an “all-electric plant” powered by hydroelectricity, allowing expanded capacity without the corresponding increase in emissions of a traditional LNG facility, the letter said. LNG is created by cooling gas to minus 260 degrees Fahrenheit (minus 127 degrees Celsius) in an energy-intensive process typically powered by burning natural gas. Kitimat LNG instead proposes electric motor drives totaling 700 megawatts to run all liquefaction, utility compressors, pumps and fans with hydropower bought from the provincial utility, according to its revised project description dated July 8. It will have backup diesel power generators onsite for emergencies. The proposed plant “will achieve the lowest emissions intensity of any large-scale LNG facility in the world,” according to the project description. Kitimat LNG will produce less than 0.1 ton of carbon dioxide equivalent for every ton of LNG compared with a global average of more than 0.3 ton of CO2 equivalent, according to the document.

12,000 L of oil spilled into ocean off Newfoundland… Production has stopped aboard the Hibernia oil platform off the coast of St. John’s after an estimated 75 barrels, or 12,000 litres, of oil spilled from a storage cell into the water. An oil sheen was spotted Wednesday, and the company said in a news release that the spill was an “isolated activity.” The mixture of oil and water was discharged from one of the six storage cells, which contain oil and water and are always full, on the platform, said Scott Sandlin, president of Hibernia Management and Development Company (HMDC). An “oily water discharge was released during a routine operation associated with lowering the water levels in those cells,” Sandlin said. The investigation is continuing, but it’s suspected that the discharge was related to an issue with the sensors in the storage cells that indicate the levels of oil and water, he said.

Canadian platform spills 3,200 gallons of oil-mix into Atlantic An oil platform off the Canadian island of Newfoundland spilled nearly 3,200 gallons of an oil-water mix into the Atlantic Ocean, and efforts were underway to minimize the environmental impact, ExxonMobil said Thursday. The spill occurred a day earlier during “routine activities related to removing water” from a platform storage cell, the American oil giant said earlier. “The estimated volume of oil released from the Hibernia platform was 75 barrels of oil, equivalent to approximately 12,000 liters (3,170 gallons),” according to aerial surveillance, the Hibernia Management and Development Company (HMDC) said in a statement released by ExxonMobil. That area of the North Atlantic is rich in marine life, including species of whales, but HMDC said “no wildlife has been observed in the area” by specialists who were sent out. “We’re disappointed the discharge occurred, but we are working diligently to minimize impacts on the environment,” the statement quoted Scott Sandlin, HMDC’s president, as saying. On Wednesday the company said it temporarily shut the oil platform after discovering the oil-water spill into the ocean. It was using a range of clean-up measures including a boom-type system deployed over the side of a vessel, assisted by a skimmer. HMDC said it was monitoring a sheen on the ocean surface with an approximate radius of three nautical miles (3.5 miles, 5.6 kilometers), about 204 miles east of St John’s Newfoundland. “Vessels have been tasked with monitoring and clean-up of the sheen and requests that all mariners keep a 10 nautical mile berth from this area,” it said. Hibernia — which opened for production in 1997 and is located about 196 miles east of St John’s — is jointly owned by Chevron, Suncor and Equinor (formerly Statoil) in addition to ExxonMobil, which holds the majority share. The oil deposit below Hibernia — accessed via underwater drilling — is estimated to contain more than 1.2 billion barrels of oil.

Kirby Corp fined $2.9 million for British Columbia oil spill A fine of $2.9 million was levied against Texas-based Kirby Corp for the October 2016 spill of 110,000 liters of diesel and other heavy oils on the fishing grounds of the Heiltsuk Nation when it ran aground and sunk. The nation says that the fine is “along way from justice,” and is demanding proper restitution and says that the corporation should be banned from territorial waters until it does so. The corporation pleaded guilty to violations of the Migratory Birds Convention Act and the Pilotage Act in may of this year. Birds and fish were affected and the tug did not have a pilot aboard as required. Kirby Corp issued a statement apologizing for the spill and says that they are amending their operating procedures, training and equipment to reduce the chances of a similar event re-occurs in the future.

Ecopetrol’s plan for fracking project hits new snag in Colombia (Reuters) – Colombia’s environmental authority said on Friday that it was suspending its evaluation of Ecopetrol’s request to start a fracking pilot project until an administrative court reinstates rules for tapping unconventional crude deposits. The decision was a new snag in the state-owned oil company’s plan to spend $500 million on exploring unconventional deposits. Last year, the Council of State – tasked with ruling on administrative matters – decided to suspend regulations for tapping unconventional deposits, typically shale formations that contain oil and gas. While the court holds hearings on the regulations, the National Authority for Environmental Licenses (ANLA) will suspend its evaluation of Ecopetrol’s request for an environmental license for the massive unconventional crude deposit Guane-A, ANLA said in a statement. The decision will likely mean a longer wait if and when the Council of State authorizes the regulations.

WA fracking ban to be lifted next month – A moratorium on gas fracking in parts of Western Australia is expected to be officially lifted next month. In November, the state government announced its election promise banning the controversial practice in the South West, Peel and Perth regions would remain, but fracking would be allowed on existing petroleum titles in other parts of WA. Its implementation plan, released late on Friday, shows the completion date for lifting the moratorium is August. The Australian Petroleum Production and Exploration Association applauded, saying it would help boost confidence in the sector, and deliver much-needed jobs and economic growth. The state government has been at pains to stress the petroleum titles where fracking will be allowed cover just two per cent of the state. It also says fracking will not be allowed in sensitive areas including the Dampier Peninsula, but has not yet defined the boundary and expects that will be complete by October. “There is still so much work to do,” The Wilderness Society’s acting state director Kit Sainsbury said on Monday. “Many of the regulations it intends to implement run through to December 2020 before their conclusion.”

Traditional owner fracking veto right won’t extend to exploration in WA – Traditional owners’ right to veto hydraulic fracturing projects will not apply to exploration applications, the WA Department of Mines, Industry Regulation and Safety has confirmed. On Friday the WA government released an 18-month ‘implementation plan’ that would see the ban on fracking on existing onshore petroleum titles lifted in the state next month. In WA, most fracking activities would target gas between two to three kilometres underground in tight and shale rocks. The lifting of the ban will apply to about 2 per cent of the state. The plan also outlined the heavy regulations companies must meet before they can begin fracking. Companies will need consent from traditional owners and private landowners before production is permitted, but Wilderness Society WA acting state director Kit Sainsbury is worried this would not apply to exploration applications. “The government made a lot of noise about the traditional owner veto, however, the devil is in the detail with these matters and the implementation plan doesn’t effectively review this point,” he said.

Frantic Friday hell as 8-mile oil spill closes M5. THE M5 has been closed in both directions for eight miles this morning due to a massive an oil and diesel spill. The closure is in place between J26 (Wellington) to Junction 24 (Huntsworth). Drivers have been advised to take the diversion route via the A38. There is also heavy traffic on the M5 near Bristol following the outbreak of an industrial fire. It comes as Brits are warned to brace for “Frantic Friday” carnage as 13.4 million of us hit the road for the great summer getaway. Motorists have been warned to face gridlock on major roads this weekend as the busiest summer getaway in five years begins. Today is dubbed “Frantic Friday” as Brits across the country ready to kick off their summer holidays. Research by the RAC and traffic information supplier Inrix indicates that 13.4 million leisure trips will take place by car between Friday and Sunday. This is around four million more than the same weekend last year and would represent the largest summer getaway since 2014, according to the analysis. Motorists have been warned to face gridlock on major roads this weekend as the busiest summer getaway in five years begins.

Oil, Gas Companies Target of Germany’s Carbon Levy Plan — Oil and gas companies that supply Europe’s biggest energy market fuels for cars, trucks and heating may be soon be required to pay for carbon pollution allowances if a panel advising the government gets its way. Chancellor Angela Merkel this month started talks on how to force the transport and building industries to pay for their pollution, widening the number of sectors required to participate in the European Emissions Trading System, or ETS. Merkel hasn’t decided yet whether to push for extending the ETS to those industries or to impose a new tax on carbon. A panel advising Merkel and her ministers favors using the cap-and-trade market. Germany should copy Europe’s ETS and apply it nationally to heating and road emissions, Klaus Schmidt, the group’s co-chairman told reporters on Monday. Setting up separate platforms for trading permits in those sectors would enable the market to squeeze out polluting technologies like road and heating fuels. That’s provided floor and ceiling prices are set, he said. By compelling oil and gas companies like Royal Dutch Shell Plc, BP Plc, Total SA, Wintershall AG and Gazprom PJSC or their German units to buy pollution certificates, Merkel’s coalition would potentially retain the ability to steer CO2 reduction with precision by controlling auction volumes. While Germany has cut emissions from power production, pollution from automobiles, trucks and aircraft remain stubbornly high. Merkel, who as environment minister in the 1990s sketched some of the first international climate deals organized by the United Nations, in 2007 pledged her nation will cut emissions 40% by 2020 from 1990 levels. Germany is set to miss the target, senior ministers have said. In order to hasten carbon dioxide emission reductions, the group envisages forcing oil and gas companies to engage in “upstream permit auctions,” said Schmidt. The group declined to comment on envisaged floor prices for CO2 permits in transport or heating. The proposals “were very well received” by the government, Friedrich Breyer, the group’s co-head, told Bloomberg.

Russia’s Transneft, oil firms clash over pipeline system clean-up (Reuters) – Major Russian oil companies have challenged a plan by Transneft that aims to resolve a problem of tainted oil stuck in Russia’s pipeline and storage system by diluting it with clean crude, four company sources said on Wednesday. They said mixing the crude would undermine the quality and price of Russian exports for longer, as it might take until mid-2020 to fully flush out Transneft’s pipeline network, rather than emptying it now and selling the tainted crude at a big discount. The pipeline monopoly’s preliminary plan was discussed at a meeting at the Russian Energy Ministry on Tuesday, the sources said, adding it was unlikely the objections raised by the major oil firms would halt Transneft’s plans to proceed next week. “It is not a good idea to mix clean and dirty barrels. It is a waste of the product. There are other options to get rid of contaminated barrels and we will make our proposals,” one of the four sources told Reuters, asking not to be named. Another source said selling dirty barrels at a steep discount was the best way to swiftly resolve the issue. Russia’s oil industry was plunged into crisis after about 5 million tonnes of oil for export was found in April to be contaminated with organic chloride, a chemical used to help boost oil extraction but which can damage refining equipment. Exports through the Druzbha pipeline that transports oil as far west as Germany were halted and have only partially resumed. Buyers have demanded compensation. Tainted crude has been stuck in pipelines in Belarus and branches further west in Poland, Germany, Ukraine, Slovakia, Hungary and the Czech Republic. About 2 million tonnes have been pumped back from Belarus to Russia, where it is being stored. Russia allows no more than 6 parts per million (ppm) of organic chloride content in oil, while the levels in the pipeline had soared to 150-250 ppm. Before the contamination, levels rarely exceeded 1-3 ppm. Many consumers in Europe and Asia reject oil with organic chloride content above 1 ppm.

EU Agrees To Sanction Turkey For Drilling In Cypriot Waters – A surprisingly muscular response beyond mere threatening rhetoric out of the European Union over Turkey’s violations of Cypriot territorial waters related to offshore drilling operations: the EU has agreed to bring financial and political sanctions against Turkey after repeat warnings of the past weeks. European Union officials on Monday agreed political and financial sanctions against Turkey after Ankara went ahead with drilling operations off Cyprus despite repeated warnings, European diplomats said. – AFP“The conclusions on Turkey have been adopted and they will be made public in the coming hours,” the EU’s foreign policy chief Federica Mogherini told reporters following a meeting of foreign ministers. Austrian Federal Minister for Europe, Integration and Foreign Affairs Alexander Schallenberg also announced prior to Mogherini’s remarks Monday from Brussels:“Today, we will adopt a number of measures against Turkey – less money, fewer loans through the European Investment Bank, freeze of aviation agreement talks. Naturally, other sanctions are possible.”“We [the] are fully behind Cyprus,” Schallenberg added while addressing the crisis, which has involved Turkey laying claim to a waters extending a whopping 200 miles from EU member Cyrprus’ coast, brazenly asserting ownership over a swathe of the Mediterranean that even cuts into Greece’s exclusive economic zone.Last week the Turkish drilling vessel Yavuz sailed to an area off Cyprus’ east coast – the second to follow a first drilling vessel, Fatih, which had already been exploring in Cypriot waters. Notably, the vessels have been accompanied by the Turkish military, including drones, F-16 fighters, and warships.Cyprus has long condemned Turkey’s ag gressive oil and gas explorations as a “second invasion” in reference to the creation in 1974 of the breakaway Turkish Republic of Northern Cyprus after a military takeover.

Turkey Rejects EU Sanctions As Not Serious – Will Send 4th Drilling Ship Near Cyprus – Perhaps to be expected, Turkey’s response to yesterday’s EU announcement of impending economic and political sanctions to be brought against Ankara has been to swiftly and immediately double down on drilling, while dismissing the crisis as “not serious”. Turkey has now sent its fourth oil and gas exploration ship to the eastern Mediterranean after European leaders condemned its drilling in EU-member Cyprus’ territorial waters. Turkish Foreign Minister Mevlut Cavusoglu responded: “Calling the EU’s decision sanctions means taking it seriously. You shouldn’t do that, the decision was made to satisfly Greek Cypriots. These things don’t have any effect on us.”Turkey’s Anadolu Agency reports, “Turkey will send its fourth ship to the Eastern Mediterranean region to continue its exploration and drilling, the country’s energy and natural resources minister said on Tuesday. It will join the Fatih and recently deployed Yavuz, and the seismic vessel the Barbaros Hayrettin Pasa which has conducted exploration in the Mediterranean since April 2017.”The MTA Oruc Reis seismic research ship, which has been conducting seismic surveys in the Black Sea and Marmara since August 2017, will be sent to conduct seismic surveys in the Mediterranean Sea,” Energy minister Fatih Donmez announced.This was accompanied by FM Cavusoglu warning the EU that Turkey plans to increase its drilling and exploration activities in the East Mediterranean while “protecting the rights” of Turkish Cypriots. Ankara’s position is that it has the same rights as the Greek Cypriot government to drill in the region, which Turkey interprets as including waters that expand 200 miles from EU member Cyrprus’ coast, brazenly asserting ownership over a swathe of the Mediterranean that even cuts into Greece’s exclusive economic zone. On Monday, following a meeting of EU foreign ministers in Brussels, the European Union announced that it will bring sanctions against Turkey for violating Cyprus’ waters, which has also involved Turkey sending drones, F-16 fighters, and warships to escort the few drilling ships it’s already deployed off Cyprus.

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