Oil, Gas, And Fracking News Reads: 02June, 2019 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 02 June 2019.

This article is a feature every Monday evening on GEI.

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Oil price drop of 16% in May tests exploitation companies’ profitability.

Oil prices dropped nearly 9% this week as an already falling market sold off on Friday after Trump threatened new tariffs on Mexico in retaliation for their lax control of immigration, raising fears of further trade turmoil… after falling more than 6% to $58.63 a barrel last week on a worsening impasse in the US-China trade war, the benchmark price of US crude for July delivery steadied in overseas and off-market trading on Memorial Day and then moved higher on Tuesday, gaining 51 cents to $59.14 a barrel, even as oil traders remained caught between concerns over global supply and fears that the U.S.-Chinese trade conflict would hurt demand…the trade war fears moved to the forefront of concerns on Wednesday and oil prices fell more than 2% after China signaled it might restrict rare earths sales to the US, but perked up near the close after the American Petroleum Institute (API) reported a large draw in crude oil inventory, with oil ending the session just 33 cents lower at $58.81 a barrel…however, prices fell almost 4% to a two month low on Thursday after the EIA failed to confirm the API inventory draw and trade war fears returned, with the benchmark US price closing $2.22 lower at $56.59 a barrel…oil prices then plunged unimpeded on Friday after Trump stoked trade fears by threatening tariffs on Mexico and ended $3.09 or 5.5% lower at $53.30 a barrel, the lowest close since February 12th…oil prices thus ended 8.7% lower for the week and finished May more than 16% lower in their first monthly loss of the year…

With oil prices suddenly in free fall, it seems it would be an appropriate time for us to check what levels of oil prices are needed for oil producing companies to cover their expenses, and what levels of oil prices the exploitation companies need to drill a new well…every quarter the Dallas Fed conducts a survey of more than 200 oil and gas companies headquartered in or operating in their district, which forms the basis of their economic research on the oil & gas industry, and which also includes a set of different questions each quarter…in addition to the usual quarterly survey, the First Quarter Dallas Fed Energy Survey included a set of special questions to update to their data on breakeven oil prices by basin….160 oil and gas firms responded to the special questions survey, and in an overview, they present the results of that survey graphically, and that’s what we’ll look at today…

As the heading on this first graphic indicates, the first special question the Dallas Fed asked the oil executives was what WTI oil price they needed to cover their expenses on existing wells, and the range of their responses are indicated in a bar graph format below…

In the above graph, the blue, brick, yellow, orange, green, purple, and turquoise colored bars represent the range of oil price responses to that operating expenses question given by oil company executives with operations in the Permian Midland shale of western Texas, the Eagle Ford of south Texas, other US oil producing shale basins outside of those graphed, the SCOOP/STACK of Oklahoma, the Permian Delaware of far west Texas and New Mexico, other non-shale oil producing areas, and other Permian shale wells respectively, as the headings above the colored bars indicate…in addition, under each of those bars, they’ve indicated the number of oil executives that responded to that headline question for each of those basins or collectives…thus, what the first blue bar tells us is that for 19 oil company executives with wells in the Permian Midland shale, at least one company needs oil priced at $45 a barrel to cover its operating expenses, at least one oil company could cover their Midland basin expenses at $9 a barrel oil, and the average price needed to cover operating expenses for all oil companies producing oil in that basin is $27 a barrel…similarly, in the brick colored bar, we can see that at least one oil company with wells in the Eagle Ford can cover it’s expenses with oil at $6 a barrel, while another company needs as much as $55 a barrel to cover their operating expenses in the same basin, while the average oil price the 11 companies with wells in the Eagle Ford needs is $28 a barrel…meanwhile, the yellow bar indicates responses from companies operating in ‘other’ shale basins, presumably such as the Bakken of North Dakota and the Niobrara chalk of the Rockies front range; it appears a company operating in one of those basins can meet their expenses with $5 a barrel oil, while the average prices needed to cover expenses by the 11 companies surveyed is again $28 a barrel, again with at least one company needing as much as $50 oil to cover their expenses in that basin…

As we can also see in the other bars on that graph, there is at least one company operating in the Permian Delaware who needs $60 oil to cover their expenses, while there is also at least one company operating in another part of the Permian who needs $65 a barrel oil to cover their operating expenses…hence, with this week’s WTI oil price closing at $53.50 a barrel, those companies are losing money with every barrel of oil they produce…

Next we have a similar graphic showing what oil price each of the survey respondents said they needed to profitably drill a new well:

Like the first graphic, the colored bars in this 2nd graphic outline the range of responses to the Dallas Fed question as to what oil price each of the executives says they need to profitably drill a new well, with the basin bars arranged left to right from the lowest average oil price to the highest, ie, in a slightly different order than for the operating expenses question…hence, we can see that among the 17 oil executives with operations in the Permian Midland shale who answered this question, at least one can drill a new well and make a profit with $23 oil, while at least one other company needs $65 oil to cover his costs of drilling a new well, while the average oil price needed to turn a profit for all those operating in the Permian Midland taking part in the survey was $47 a barrel…similarly, for the 13 oil execs who might be drilling new wells in one of the other shale basins outside of those graphed (yellow), responses ranged from those who could profit with oil price of $35 a barrel to those who need a price of $60 a barrel, with the average response for those drilling in those basins at $49 a barrel…drillers in the Permian Delaware (green) and in non shale areas (purple) also need an average of $49 a barrel to profitably drill, but we can see the range of answers for the 13 companies in the Permian Delaware is much narrower ($40 to $65) than for the 45 responders operating in non-shale areas, where the profitability threshold for new wells ranges from $20 to $75 a barrel oil…average breakeven prices for new drilling are higher still in the Eagle Ford and Oklahoma’s SCOOP/STACK, but notice that even on the far right of the graphic, where other Permian wells have the highest average for profitability at $54 a barrel, above Friday’s closing price, there are still drillers who say they can profit with $40 oil, even as some need as much as $70 a barrel to turn a profit….

So the major takeaway from this survey is that there is no single breakeven price, or even a narrow price range, either for operating existing wells, or for drilling new ones, and hence almost every move in the price of oil has the potential to impact the decisions being made in any basin across the US…however, the decisions to drill or not are not made on a daily or weekly basis; oil companies will usually set their budget once a quarter or once a half year, and most will enter into a futures contract to sell all or part of their expected production at a given price well in advance of heading out to the oil patch…still, for those who are not fully hedged and who’s breakeven price is in the upper half of the range we see here, a price move like we’ve seen over the past month might be enough to provide the impetus to cancel or delay a project that they had planned…

Meanwhile, natural gas prices also fell this week, albeit not as sharply as those of oil, as demand for air conditioning failed materialize to the degree anticipated and a larger increase of natural gas in storage than traders expected sent prices tumbling…after falling 3.3 cents to $2.598 per mmBTU last week, the contract for June natural gas increased 3.5 cents over Tuesday and Wednesday to finish trading at $2.633 per mmBTU…meanwhile, natural gas for July delivery, which had ended last week at $2.611 per mmBTU, rose just 1.3 cents over those first two days of trading this week before falling 7.7 cents on Thursday and 9.3 cents on Friday to end the week 6% lower at $2.454 per mmBTU…

The natural gas storage report from the EIA for the week ending May 24th indicated that the quantity of natural gas held in storage in the US increased by 114 billion cubic feet to 1,867 billion cubic feet by the end of the week, which meant our gas supplies were 156 billion cubic feet, or 9.1% more than the 1,711 billion cubic feet that were in storage on May 25th of last year, while still 257 billion cubic feet, or 12.1% below the five-year average of 2,124 billion cubic feet of natural gas that have typically been in storage as of the fourth weekend in May in recent years….this week’s 114 billion cubic feet injection into US natural gas storage was well above the median forecast for a 98 billion cubic foot increase in supplies in surveys by Bloomberg and Natural Gas Intelligence, and likewise higher than the average 97 billion cubic feet of natural gas that have been added to gas storage during the same week of May in recent years….moreover, the 760 billion cubic feet of natural gas that were added to storage over the past 9 weeks has been the largest injection of gas into storage on record for any similar period this early in the injection season; injections for the same 9 weeks over most recent years aren’t even close…

The Latest US Oil Supply and Disposition Data from the EIA

This week’s US oil data from the US Energy Information Administration, reporting on the week ending May 24th, showed that an increase in our oil exports and an increase refinery throughput meant that we needed to pull oil out of commercial crude storage for the third time in ten weeks…our imports of crude oil fell by an average of 81,000 barrels per day to an average of 6,862,000 barrels per day, after falling by an average of 669,000 barrels per day over the prior week, while our exports of crude oil rose by an average of 395,000 barrels per day to 3,317,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,545,000 barrels of per day during the week ending May 24th, 476,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells was reported to be 100,000 barrels per day higher at a record 12,300,000 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 15,845,000 barrels per day during this reporting week…

Meanwhile, US oil refineries were using 16,767,000 barrels of crude per day during the week ending May 24th, 189,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that a net of 41,000 barrels of oil per day were being pulled out of the oil that’s in storage in the US….hence, it’s pretty obvious that this week’s crude oil figures from the EIA seems to indicate that our total working supply of oil from net imports, from oilfield production and from storage was 881,000 barrels per day short of what the 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 (+881,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”….with that much oil unaccounted for, we have to figure one or more of this week’s crude oil metrics are off by a statistically significant amount…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports fell to an average of 7,028,000 barrels per day last week, 8.5% less than the 7,679,000 barrel per day average that we were importing over the same four-week period last year…the 41,000 barrel per day decrease in our total crude inventories all pulled out of our commercially available stocks of crude oil, as the amount of oil stored in our Strategic Petroleum Reserve was unchanged…this week’s crude oil production was reported to be 100,000 barrels per day higher at a record 12,300,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at a record 11,800,000 barrels per day, while a 3,000 barrel per day decrease to 474,000 barrels per day in Alaska’s oil production was not enough to impact the final rounded national total…last year’s US crude oil production for the week ending May 25th was at 10,769,000 barrels per day, so this reporting week’s rounded oil production figure was 14.2% above that of a year ago, and 45.9% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 91.2% of their capacity in using 16,767,000 barrels of crude per day during the week ending May 24th, up from 89.9% of capacity the prior week, but still a bit below the recent historical refinery utilization rate for this time of year….likewise, the 16,767,000 barrels per day of oil that were refined this week were 2.3% below the 17,155,000 barrels of crude per day that were being processed during the week ending May 25th, 2018, when US refineries were operating at 93.9% of capacity…

Even with the increase in the amount of oil being refined, gasoline output from our refineries was a bit lower, decreasing by 20,000 barrels per day to 9,863,000 barrels per day during the week ending May 24th, after our refineries’ gasoline output had decreased by 29,000 barrels per day the prior week….with that decrease in gasoline output, this week’s gasoline production was 5.5% below than the 10,433,000 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) slipped by 24,000 barrels per day to 5,182,000 barrels per day, after our distillates output had decreased by 58,000 barrels per day the prior week…with this week’s decrease, the week’s distillates production was 2.2% less than the 5,296,000 barrels of distillates per day that were being produced during the week ending May 25th, 2018….

Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week rose for the third time in 15 weeks, increasing by 2,204,000 barrels to 230,944,000 barrels over the week to May 24th, after our gasoline supplies had increased by 3,716,000 barrels over the prior week….our gasoline supplies rose by less this week than last because our imports of gasoline fell by 263,000 barrels per day to 1,087,000 barrels per day, and because our exports of gasoline rose by 301,000 barrels per day to 717,000 barrels per day, while the amount of gasoline supplied to US markets decreased by 35,000 barrels per day to 9,394,000 barrels per day….after having reached an all time record high seventeen weeks ago, our gasoline supplies have since fallen 12% are still 1.5% lower than last May 25th’s inventory level of 234,431,000 barrels, while they now are back to 1% above the five year average of our gasoline supplies at this time of the year…

Meanwhile, with the modest decrease in our distillates production, our supplies of distillate fuels fell for the 8th time in 11 weeks, decreasing by 1,615,000 barrels to 124,800,000 barrels during the week ending May 24th, after our distillates supplies had increased by 768,000 barrels over the prior week….our distillates supplies fell because the amount of distillates supplied to US markets, a proxy for our domestic demand, rose by 495,000 barrels per day to 4,282.000 barrels per day, while our imports of distillates rose by 75,000 barrels per day to 177,000 barrels per day, and while our exports of distillates fell by 103,000 barrels per day to 1,308,000 barrels per day …even after this week’s inventory decrease, our distillate supplies were still 8.9% higher than the 114,629,000 barrels of distillate that we had stored on May 25th, 2018, even as they are now roughly 5% below the five year average of distillates stocks for this time of the year…

Finally, with higher oil exports and an increase in refining, our commercial supplies of crude oil in storage decreased for the sixth time in 19 weeks, slipping by 282,000 barrels from 476,775,000 barrels on May 17th to 476,493,000 barrels on May 24th….even with that decrease, our crude oil inventories were 5% above the recent five-year average of crude oil supplies for this time of year, and remained more than 35% higher than the prior 5 year (2009 – 2013) average of crude oil stocks as of the fourth weekend in May, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories have generally been rising since this past Fall, after generally falling until then through most of the prior year and a half, our oil supplies as of May 24th were 9.7% above the 434,512,000 barrels of oil we had stored on May 25th of 2018, but at the same time still 6.6% below the 509,912,000 barrels of oil that we had in storage on May 26th of 2017, and 5.5% below the 504,205,000 barrels of oil we had stored on May 27th of 2016…

This Week’s Rig Count

The US rig count inched up for just the 2nd time in fifteen weeks this past week, but remained close to a 14 month low….Baker Hughes reported that the total count of rotary rigs running in the US increased by 1 rig to 984 rigs over the week ending May 31st, which was still down by 76 rigs from the 1059 rigs that were in use as of the June 1st report of 2018, and quite a bit below the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market…

The count of rigs drilling for oil rose by 3 rigs to 800 rigs this week, which was still 61 fewer oil rigs than were running a year ago, and less than half of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations fell by 2 rigs to 184 natural gas rigs, which was also down by 13 rigs from the 197 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008…

Offshore drilling in the Gulf of Mexico increased by 1 rig to 23 rigs this week, as another rig was added offshore from Texas, where there are now 3 rigs deployed, with the other 20 all offshore from Louisiana….that’s up from the 18 rigs that were deployed in the Gulf in the same week a year ago, when 17 rigs were drilling in Louisiana waters and one was offshore from Texas, and up from the national total of 19 rigs offshore a year ago, as a rig was also set up in the waters offshore from Alaska at that time…

The count of active horizontal drilling rigs was down by 1 to 862 horizontal rigs this week, which was another 14 month low for horizontal drilling, with 67 fewer horizontal rigs running this week than the 929 horizontal rigs that were in use in the US on June 1st of last year, which was also well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…on the other hand, the directional rig count was up by 1 rig to 70 directional rigs this week, and those were up by 5 rigs from the 65 directional rigs that were in use during the same week of last year…at the same time, the vertical rig count was also up by 1 rig to 52 vertical rigs this week, but those were still down from the 66 vertical rigs that that were operating on June 1st 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 May 31st, the second column shows the change in the number of working rigs between last week’s count (May 24th) and this week’s (May 31st) count, the third column shows last week’s May 24th 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 1st of June, 2018…

The two rigs that were added in New Mexico were both in the Permian Delaware, because the Texas Permian experienced a net loss of 1 rig, with single rigs shut down in Texas Oil District 8, the core Permian Delaware, and in Texas Oil District 7C, or the southern Permian Midland basin, while a rig was added in Texas Oil District 8A, or the northern part of the Permian Midland basin…the Louisiana rig increase was a natural gas rig added in the Haynesville shale in the northwest part of the state, but natural gas drilling activity still fell by 2 rigs nationally with rig removals in Ohio’s Utica shale, West Virginia’s Marcellus, and the Eagle Ford of southern Texas; note that the Eagle Ford shows no net change above because a rig drilling for oil was started up at the same time, leaving the current Eagle Ford deployment at 68 oil rigs and 7 natural gas rigs…we should also note that other than in the major producing states above, Mississippi drillers added two rigs last week and are now running four, up from two rigs a year ago, but not an unusual deployment in the state, which has seen as many as six rigs active at times over the past year…

Ohio’s Utica Shale oil and gas production dips in first quarter – During the first quarter of 2019, Ohio’s horizontal shale wells produced 5,073,536 barrels of oil and 609,452,391 Mcf (609 billion cubic feet) of natural gas, according to figures released June 1 by the Ohio Department of Natural Resources Division of Oil and Gas Resources Management. (Scroll down to see lists of the top 10 producing wells.) Natural gas production from the first quarter of 2019 was down 8.8% from the final quarter of 2018, but showed a 14.57% increase over the first quarter of 2018. Oil production from Ohio’s horizontal wells in the first quarter of 2019 was also down from the previous quarter, dropping 12% from the fourth quarter of 2018. Compared to the first quarter of 2018, however, oil production increased 28.69%. The ODNR quarterly report lists 2,277 horizontal shale wells, 2,228 of which reported oil and natural gas production during the quarter. There were 2,241 wells with reported oil and natural gas production during the fourth quarter of 2018. Of the wells reporting oil and natural gas results:

• The average amount of oil produced was 2,277 barrels.
• The average amount of natural gas produced was 273,542 Mcf.
• The average number of fourth quarter days in production was 86.

All horizontal production reports can be accessed at oilandgas.ohiodnr.gov/production. Oil and gas reporting totals listed on the report include Natural Gas Liquids (NGLs) and condensate.

EPA Declines to Regulate Waste as Ohio Valley Fracking Booms – The U.S. Environmental Protection Agency last week said it will not strengthen regulations on waste created by oil and gas production, a move that could affect communities across the Ohio Valley where the oil and gas industry is booming in the Appalachian Basin. No federal agency fully regulates oil and gas drilling byproducts – which include brine, or salty water laced with chemicals and metals, as well as similarly-contaminated sludge, rock and mud – leaving tracking and handling to states. EPA’s decision released last week stems from a 2016 lawsuit filed by environmental groups, who had petitioned the agency to make new rules for how it regulates oil and gas waste. When the agency failed to respond, a federal judge required EPA to formally respond by this spring. The decision reaffirms that states are in charge of regulating the disposal of chemical-laced and often radioactive liquids and solids created by the oil and gas industry. Environmental advocates decried the move. They argue regulations for both onsite storage of waste and offsite disposal vary widely from state to state. A 2016 report from the Center for Public Integrity calls the radioactive waste stream from horizontal oil and gas operations “orphan waste” because no single government agency is fully managing it. Each state is left to figure out its own plan. Advocates say EPA rules would create a baseline for how millions of tons of liquid and solid waste should be disposed. “In a word or a sentence, the Trump administration hung out to dry communities that host oil and gas development,” said Aaron Mintzes with Earthworks, one of the group’s that pursued this issue in court. Mintzes said a loophole in the Resource Conservation and Recovery Act, a federal law that governs how solid waste should be disposed, allowed EPA in 1988 to classify waste from oil and gas operations as “non-hazardous.” This gives operators wide latitude in how to dispose of it.

Ewing Sarcoma – What’s Causing These Occurrences? – Rare cancers have been striking children and young adults in some of the rural areas outside of Pittsburgh in alarming numbers, sometimes fatally, in Fayette, Greene, Washington and Westmoreland counties. So far, health authorities have provided little insight into what is happening. They should be developing a plan for getting to the bottom of this health scare. Carrie Simkovic, a Greene County resident who founded a foundation to help young cancer patients after her own son’s diagnosis, had it right when she told the Post-Gazette: “When you have a little town like ours and have so many cancers, you have to ask, ‘What’s going on here?'” Ewing sarcoma – a cancer of the bone and tissue – is so rare that the nation sees only 200 to 250 cases a year. But there have been at least 27 cases in Fayette, Greene, Washington and Westmoreland counties since 2008. The Post-Gazette also has documented other rare cancers among dozens of children and young adults in those counties – 10 in Washington County’s Canon-McMillan School District alone. The PG has documented 13 childhood and young adult cancer deaths in these counties since 2011, including three since 2015 in the West Greene School District. Because the counties are a center of natural gas production, residents worry about environmental pollution as the source of the cancers. The Marcellus Shale Coalition, a trade group, has said there is no known link between fracking and childhood cancer. The operative word is “known.” The fracking process involves carcinogenic chemicals, and some academic studies have linked low birth weights, birth defects and asthma to fracking. But that’s surprisingly little information given the high stakes. Much more needs to be learned about rare childhood cancers and the possible role that environmental factors play in them. Southwestern Pennsylvania – home to a robust shale gas extraction industry, various sources of pollution and a frightening number of childhood cancers – is the right place to carry out that research. Cheryl Potter, a Fayette County resident whose son Joshua died of Ewing sarcoma in 2016, put it this way: “You never get solid answers, and that’s the worst part.”

Appalachian gas storage hub seeks federal clean energy loan guarantee – Several environmental groups are considering legal options if the Trump administration approves $1.9 billion taxpayer-backed guarantee.A development corporation is seeking a $1.9 billion federal loan guarantee to help build an Appalachian storage hub for natural gas liquids.The financing guarantee would come from a U.S. Department of Energy program meant to support projects that “avoid, reduce, or sequester” air pollutants or greenhouse gas emissions and feature “new or significantly improved technologies.”The Title XVII program has never been used to finance a fossil fuel storage project, but environmental groups fear the Trump administration will bend criteria to approve the project.”It just does not fit the legal criteria” of the federal law, said Alison Grass, research director at Washington, D.C.-based Food & Water Watch, one of several environmental groups that is considering legal options.The proposal from Appalachia Development Group, LLC, calls for an underground storage facility to hold natural gas liquids from “wet gas,” such as ethane, which are used to make plastics and other products. The storage facility’s site in Ohio, West Virginia or Pennsylvania hasn’t been finalized. The hub would have a web of pipelines and other infrastructure to collect and distribute feedstocks from all three states, plus possibly Kentucky. Steve Hedrick, CEO of Appalachia Development Group, said the project would “significantly” reduce emissions by minimizing the distances the liquids are transported before they are turned into plastic products. “With over half of the North American plastics converter market within 500 miles of Appalachia, the need for redundant transport is minimized while maximizing the value creation from the American resource,” Hedrick said via email. “In other words, we can significantly avoid or reduce anthropogenic emission of greenhouse gases merely through conversion of these raw materials closer to their production locations.” He did not offer a source or calculations of the amount of presumed emissions cuts resulting from transporting materials over fewer miles.

AG investigating wastewater case from landfill that accepts fracking waste –The Pennsylvania Attorney General’s office is investigating the disposal of contaminated water from a landfill that accepts fracking waste to a sewage treatment plant in Fayette County.The investigation comes a week after a judge barred the Westmoreland Sanitary Landfill in Rostraver Township from sending its wastewater to the nearby Belle Vernon Municipal Authority waste treatment plant for 90 days.The issue involves the landfill’s leachate – water that percolates through the landfill and gets collected for disposal. The landfill is permitted to send 50,000 gallons of the leachate per day to the treatment plant. But, according to a complaint filed by district attorneys in Washington and Fayette counties, the landfill had been sending 100,000 to 300,000 gallons of leachate per day. Beginning last spring, the treatment plant started seeing levels of pollution in its discharge to the Monongahela River go up and exceed state and federal limits. The treatment plant determined the contamination was coming from the landfill, which accepts fracking waste like drill cuttings. “That water was contaminated with diesel fuels, it’s alleged, carcinogens and other pollutants,” said Rich Bower, Fayette County District Attorney. Bower and Washington County District Attorney Gene Vittone petitioned Fayette County Court of Common Pleas Judge Steve P. Leskinen for a 90-day injunction against the landfill. The judge agreed and issued the injunction on May 17. “We saw a serious problem with all of this because of the fact that the Monongahela River is a great source for drinking water around for all downstream,” Bower said. According to court documents filed with the case, the municipal authority’s supervisor, Guy Kruppa, notified the Department of Environmental Protection about the problems with the landfill’s leachate. The DEP responded by giving the landfill a permit to operate a “pretreatment” system to deal with contaminants in its waste. Under the arrangement, the landfill would “pay any penalties for effluent violations at the Belle Vernon plant” while the landfill came up with a better way to clean up its waste. “In turn Belle Vernon would need to let the landfill stay connected to their system.” This arrangement stuck out to the two local prosecutors. “It was troubling that the DEP had indicated (to the authority) to keep on discharging contaminated water and that the municipal authority should work out a deal for the landfill to pay the fines,” Bower said. The landfill accepted 4,600 tons drilling waste in March, the latest month for which data are available, according to the DEP. This waste is mostly drill cuttings, which can contain naturally occurring radioactive materials, salts, and metals.

GOP counters Wolf’s capital plan with drilling (AP) – Republicans who control the Pennsylvania Senate are preparing an alternative to Gov. Tom Wolf’s proposal for a multibillion-dollar capital plan, funding it by removing restrictions on natural-gas drilling underneath state-owned forest land rather than taxing natural-gas production. The chief sponsors, state Sens. Camera Bartolotta and Pat Stefano of southwestern Pennsylvania, said Tuesday that they expect the legislation to be unveiled this week, ahead of June’s budget negotiations between the Republican-controlled legislature and Wolf, a second-term Democrat, in the country’s No. 2 gas-producing state. The GOP plan could open up more potentially lucrative state-forest acreage that has been off-limits to exploration companies since Wolf took office. It would allow the Department of Conservation and Natural Resources to decide whether to enter into new gas leases, but not require it to add acreage. The plan envisions allowing exploration companies to reach below tracts of state-forest land using underground horizontal laterals from wells drilled on privately owned acreage adjacent to it, Bartolotta said. She said it doesn’t envision allowing new well sites on newly leased tracts of state-forest land. Drilling under another 781 square miles of state-forest land could yield $1 billion or more in upfront payments to finance a range of community projects, Stefano said. The Senate GOP plan is about one-fourth the size of Wolf’s “Restore Pennsylvania” program, and has another key difference: It doesn’t envision borrowing. Wolf proposed a $4.5 billion bond in January to be repaid over perhaps 20 years, including interest, by a new severance tax based on volume and floats with the price of natural gas. The goal, he said, is to fix critical infrastructure and revitalize communities. Using estimates of 2018 production and a price of less than $3, the tax would yield about $550 million in a year. At a price of more than $6, the tax would yield about $940 million. It would not change a 7-year-old per-well “impact fee” that Pennsylvania imposes on exploration firms.

Newspaper seeks to intervene in natural gas impoundment case – Attorneys for the Pittsburgh Post-Gazette and the natural gas industry tangled Tuesday afternoon in Washington County Court over the newspaper’s attempt to intervene in a long-standing legal dispute over the effects of an Amwell Township impoundment that was settled and made confidential in 2018. Newspaper attorney Frederick N. Frank said the Post-Gazette was acting as the public’s representative in seeking access to the sealed court case. “In most cases when the records are sealed, there’s no public notice,” Frank told President Judge Katherine B. Emery. “We always learn after the fact. A reporter would have to scour, on a daily basis, every docket to make sure the right to access was not being violated.” Kimberly A. Brown, an attorney representing Range Resources Appalachia Inc., used several arguments to attack the Post-Gazette’s request to intervene, one of which was that the Post-Gazette is not a legal entity registered with the Pennsylvania Department of State. A search of the web’s database of business entities within the state lists Post-Gazette Co. as “withdrawn and inactive.” Frank told the judge the Post-Gazette is “one of the oldest newspapers in the nation. Your honor, if that’s an issue, we can amend” court documents to Block Communications. The newspaper, which traces its origins to 1786 – long before business entities were required to register with the state – publishes a print edition five days a week and seven days online. Brown contends it’s too late to do that, and she also claimed the newspaper is tardy in its petition to intervene, citing news articles published in the Post-Gazette that referred to a settlement and non-disclosure that were published last year. Frank also argued that the Post-Gazette does not have to present a motive for wanting access to the settlement with Stacey Haney of a 2012 case which she brought on her own behalf and that of her children.

Produced Water Management: Is EPA Laying the Foundation for More Options or More Regulation? – In mid-May 2019, the Environmental Protection Agency (EPA) released for public comment its draft Study of Oil and Gas Extraction Wastewater Management under the Clean Water Act. The purpose of the study was to document EPA’s interactions since the spring of 2018 with various stakeholder groups as EPA sought to determine whether existing waste water management approaches permitted under the Clean Water Act for the onshore oil and gas extraction industry adequately meet current and future state and tribal requirements and policies. In particular, EPA sought input regarding whether support existed for potential federal regulations that would permit a broader discharge of treated produced water to surface waters. EPA is accepting public comment until July 1, 2019, and intends to finalize the study and announce future actions regarding the subject matter later in 2019. The oil and gas production industry uses large amounts of water, particularly in unconventional drilling, with much of the water coming from existing or potential useable water sources. Similarly, the industry generates significant wastewater volumes that are expected only to increase over time. Most produced water is currently managed by disposal in underground injection wells, where the water is disposed at depths below geologic units containing useable groundwater, thus, at least in part, removing water what was once a potential resource from the available water cycle. With water scarcity representing a growing concern for dozens of states, EPA is asking whether current wastewater management options sufficiently meet states’ and tribes’ policy needs, and whether produced water should be viewed more as a potential resource and not only as a waste requiring disposal.

Analysis: Pipeline project slowdown may challenge Northeast production growth – The Appalachian basin has effectively become “de-bottlenecked” following a wave of pipeline project start-ups. But with virtually no new production-takeaway capacity expected to come online in the next year, the Northeast could be on a path to becoming “re-bottlenecked” as rising production fills existing capacity. In 2018 roughly 8 Bcf/d of producer-backed pipeline capacity was added to the Northeast region as a handful of high-volume expansion projects that had been years in the making finally came online. Last year saw the full start-up of the greenfield Rover Pipeline and Nexus Gas Transmission systems, as well as expansions on existing pipelines including the Atlantic Sunrise project on Transcontinental Gas Pipe Line, and the WB XPress and Leach XPress projects on Columbia Gas Transmission. This wave of new capacity installations in 2018 helped drive the largest single year-over-year Northeast production gain on record, with output rising by 21% year on year to an average 28.6 Bcf/d. And this mis-match between capacity added (8 Bcf/d) and production grown (4.9 Bcf/d) is the underlying driver behind huge improvements in basis prices across Appalachia, which went from being valued at a significant discount to Henry Hub to now trading, at times, within variable costs of transport to the Gulf. But the pipeline buildout has already slowed dramatically, and the next several years combined are expected to see less new capacity enter service than came online in 2018 alone. The two main projects under construction, the 2 Bcf/d Mountain Valley Pipeline and the 1.5 Bcf/d Atlantic Coast Pipeline, have faced significant construction delays and cost increases, and their in-service dates remain uncertain. Besides those, there are very few new expansion proposals before the Federal Energy Regulatory Commission that would support higher production and outflows in the years ahead. Furthermore, new pipeline projects can take anywhere from three to five years to go from open season to commercial service. In short, the pipeline that’s in the ground now is essentially all the Northeast region has to work with, capacity-wise, for the foreseeable future.

Delaware Riverkeeper Network Claims LNG Cover Up – In a scathing letter sent to the Federal Energy Regulatory Commission (FERC), Delaware River Basin Commission (DRBC), Army Corps of Engineers (Army Corps), US Coast Guard, and state environmental regulatory agencies, the Delaware Riverkeeper Network asserts there has been a failure to disclose to the public a proposal, currently being reviewed and approved by multiple agencies, to export Liquefied Natural Gas (LNG) from the Gibbstown Logistics Center located in Gibbstown, Greenwich Township, New Jersey. According to the letter the Delaware Riverkeeper Network learned of the LNG export proposal by communicating with various agency staff, but that no documents or permit applications discussing development of the site since 2016 mentions the site is intended to be used for LNG export, including recent permit applications dated March 2019 that have been submitted to the state of New Jersey and the DRBC. Original proposals and documents propose a multi-use Marine Terminal, including for exporting Natural Gas Liquids (NGLs) but none discussing the export of Liquefied Natural Gas. The letter describes multiple efforts to learn about, and comment upon, the proposed site uses; including outreach to FERC that has no information on the LNG export proposal. “This looks to us like a deliberate cover-up. LNG export facilities are under increasing scrutiny because of the significant environmental and safety concerns they generate. There would be no reason not to disclose this critical body of information other than to evade full and fair review by agencies and the public and to avoid the public outcry of opposition that such news would be sure to generate,” said Maya van Rossum, the Delaware Riverkeeper and leader of the Delaware Riverkeeper Network. “Delaware Riverkeeper Network has participated in the public review process for this facility in good faith since 2016 only to find out that apparently there was a hidden purpose for the Gibbstown terminal. New Fortress Energy and Delaware River Partners may have thought they could avoid public scrutiny by sneaking in their intended use but they are dead wrong; we are demanding the comprehensive and public process this exceedingly dangerous proposal requires,”

The Trump administration is calling natural gas “molecules of freedom” now – It seems the US Department of Energy has made a linguistic decision to rebrand natural gas as “freedom gas,” and refer to its chemistry as “molecules of freedom.”In an agency press release touting the approval of a plan to increase exports of US natural gas shipped out of Texas, two Department of Energy officials offered quotes that included those zany monikers.”Increasing export capacity from the Freeport LNG project is critical to spreading freedom gas throughout the world,” US Under Secretary of Energy Mark W. Menezes said in the release. Menezes had a long career in the energy industry before joining the Trump administration.Just below him, Steven Winberg, also a longtime energy industry professional whose title with the Trump administration is listed as the “assistant secretary for fossil energy,” echoed his rhetoric:”I am pleased that the Department of Energy is doing what it can to promote an efficient regulatory system that allows for molecules of US freedom to be exported to the world,” Winberg said in the release. On Monday, meanwhile, the New York Times reported that the Trump administration had moved to stop its own scientists from modeling the long-term effects of climate change.

Nessel vows to move on shutting down Enbridge’s Line 5 pipeline in 30 days – Attorney General Dana Nessel said is vowing to take legal action to shut down Enbridge Energy’s controversial Line 5 within 30 days if Gov. Gretchen Whitmer is unable to reach a deal with the company to decommission the 66-year-old oil pipeline. “If there is a not a resolution sometime very soon, then I have every intention of moving forward on this. … In the next month,” Nessel said Tuesday in a podcast interview with Crain’s at the Detroit Regional Chamber’s Mackinac Policy Conference. Whitmer, a fellow Democrat, has been trying to negotiate a faster timeline for Enbridge to shut down the twin 20-inch oil pipelines laying on the bed of Lake Michigan west of the Mackinac Bridge, just a short distance from the Grand Hotel where business, political and nonprofit leaders are gathered for this week’s annual confab. On Wednesday, the governor told Crain’s she is on board with the one month deadline. “I’ve been keeping the attorney general very close and up to speed on where that is headed and I don’t think that’s an unreasonable thing for her to suggest that we need to have a strategy that’s public within the next month or so,” Whitmer said in a podcast interview at the Mackinac Island conference. “We’re moving forward and if we don’t have a resolution, it’s going to play out, I think, in court. I don’t think that’s a good thing. But, ultimately, that might be where it’s headed.” The governor has said she’s still open to allowing Enbridge to build a utility tunnel in the bedrock of Lake Michigan to house a new pipeline, but wanted to get the oil transportation giant to complete the project and decommission the existing pipeline faster than the projected seven- to 10-year timeline.

Update: Gas Storage Tank Fire That Prompted State Assistance Is Out — A massive natural gas storage tank fire in West Virginia is out. News outlets report the West Virginia Division of Homeland Security and Emergency Management said in a statement that the blaze was extinguished around 5 a.m. Sunday after all-night efforts by local fire departments and state agencies. The tank is owned by Dominion Resources and is near the town of Friendly in Tyler County. No injuries were reported and Dominion Energy says there’s no threat to public safety. Justice’s office says the West Virginia Department of Environmental Protection will assist with cleanup. Previous Story: West Virginia Gov. Jim Justice has ordered that all necessary state resources be used to battle a natural gas storage tank fire. In a news release, Justice’s office said the fire began Saturday afternoon when lightning struck a storage tank that holds 1 million gallons of natural gas condensate. The tank is owned by Dominion Resources and is near the town of Friendly in Tyler County. Although the tank is on fire, the natural gas product had not been released as of Saturday evening. Fire departments have been working to extinguish the flames. Justice ordered the West Virginia National Guard and West Virginia Division of Homeland Security and Emergency Management to assist. No injuries have been reported and Dominion Energy says there’s no threat to public safety.

US Supreme Court declines to take case on eminent domain practice for gas pipelines – Landowners’ arguments that pipeline companies improperly gain quick access to properties well ahead of compensating owners will not get a hearing before the US Supreme Court. The high court on Tuesday declined to take up a case brought by landowners whose properties were condemned to allow for construction of Transcontinental Gas Pipe Line’s 1.7 Bcf/d Atlantic Sunrise Project. At issue is one of a series of cases that challenged implementation of eminent domain powers under the Natural Gas Act and which, if successful, could have affected pipeline projects’ ability to meet in-service schedules. Federal appeals court rulings thus far generally have favored current practices, but another appeal arising from the Mountain Valley Pipeline project is expected.In Lynda Like, et al., v. Transcontinental Gas Pipe Line (18-1206), landowners asked the high court to overturn a 3rd US Circuit Court of Appeals ruling that upheld a district court’s preliminary injunction that allowed the pipeline company to take immediate possession of property before a final judgment on the NGA condemnation. The landowners argued the case had important implications because “over the past 20 years, district courts have entered hundreds of preliminary injunctions granting private companies immediate possession of thousands of acres of private land.” In this case, they argued that 18 months after the preliminary injunction, the petitioners had yet to receive compensation. District courts have created a system that is “far harsher and far more burdensome to property owners than any process actually authorized by Congress,” they argued. Injunctions rearrange who can do what with the property and when, they said. Transco, in a brief to the Supreme Court, emphasized that the process it followed has been approved by courts of appeals in the 3rd, 4th, 6th, 8th, 9th and 11th circuits. It pointed to the 3rd Circuit finding that the NGA does not preclude federal courts from granting equitable relief in the form of a preliminary judgment when the gas companies have obtained a substantive right to condemn and otherwise qualify for equitable relief. Only after the district court granted summary judgment in Transco’s favor did it grant injunctive relief, it said. It countered argument that the practice amounted to a “quick take,” citing the 3rd Circuit finding that the preliminary injunction merely hastened the enforcement of an existing substantive right.

How eminent domain is blighting farmers in path of gas pipeline – Under eminent domain, private property is seized from owners for public use. But for many landowners along the Mountain Valley pipeline route the forced loss of some of their land was not the end of their woes. Many suffered damages to the rest of their property after agreeing to land easements or fighting the pipeline’s invocation of the eminent domain law. On 7 September 2018, Neal Laferriere was out on his farm harvesting ginseng and planting seeds with two of his children when they noticed a helicopter flying low over the property. “A few seconds later we started getting pelted by these little blue pellets. Two of my children sustained lacerations to the face,” he said. He was informed the pellets were a product called EarthGuard Edge, meant for erosion control, and there was nothing to be done to clean up the product on the farm for which he had only recently obtained organic certification. “The land agent said they were sorry and they would make sure it wouldn’t happen again. The next two days, a helicopter flies over again and covers the rest of my property with these pellets,” added Laferriere. “We’ve lost a ton of business because of this. I can’t sell that product as certified organic, and I can’t sell it at all because I don’t feel like I can offer a product that is pure. I’m afraid of having somebody get sick,” explained Laferriere. “Our business, our life, our farm, is utterly ruined right now because of these people. Our livelihood has been shot. What we worked so hard for on the farm to get certified organic and start a profitable business, it’s not there any more.” In Rocky Mount, Virginia, part of Dave and Betty Werner’s property was taken via eminent domain for the pipeline route and it has devastated their farm. On the Werners’ 58-acre farm, their best pasture, where they raise cows, chickens, pigs and turkeys, was seized for the pipeline. “As a result of the Mountain Valley pipeline taking over that lower pasture, it put us out of business. We can’t live and operate without that pasture and the water sources down there,” said Dave Werner. Construction began on their property in May 2018, which included blasting rock to clear trenches for the pipeline. “If they could either go away or finish this job, we could put our farm up for sale because we don’t want it any more in this condition, but we can’t even do that because of the mess.”

Lawyers for Mountain Valley Pipeline urge judge to remove tree-sitters by Friday – After staying up in the trees for nearly nine months, blockers of the Mountain Valley Pipeline are facing an attempt to bring them down. Lawyers for the company said in a recent court filing that it needs to have two tree-sitters removed by Friday so workers can finish clearing a path for the massive natural gas pipeline. On Sept. 5, 2018, two protesters took up residence in a white pine and a chestnut oak that stand in a construction easement for the pipeline in eastern Montgomery County. While the tree stands have switched occupants a number of times, they remain standing – in what is now the longest active blockade of a pipeline on the East Coast, according to Appalachians Against Pipelines. In December, lawyers for Mountain Valley asked federal Judge Elizabeth Dillon to issue a preliminary injunction against the tree-sitters, which would allow their removal by U.S. Marshals. Dillon had yet to rule on the request by 6 p.m. Wednesday. Mountain Valley said in mid-May it would like to have the tree-sitters removed by the end of the month “in order to avoid additional costs.” Lawyers for the company filed a notice in U.S. District Court in Roanoke, including an affidavit from Jeffrey Klinefelter, director of construction engineering for Mountain Valley. Klinefelter said that later in the month, Mountain Valley would have a crew of tree-cutters near the protest off Yellow Finch Lane in the Elliston area. The company asked that the two occupied trees be cleared of protesters so they could then be timbered “from an efficiency standpoint,” Klinefelter said. If Mountain Valley is forced to wait, it would cost an additional $22,000, he said.

Federal pipeline safety regulators issue warning on floods and subsidence – Citing a number of recent incidents, including one in Pennsylvania, the Pipeline and Hazardous Materials Safety Administration, or PHMSA, sent a warning to natural gas and hazardous liquids pipeline operators earlier this month detailing the dangers of flooding and heavy rain events. The advisory points to “land movement, severe flooding, river scour, and river channel migration” as causes of the type of damage that can lead to leaks and explosions. It outlines current regulations, and details requirements for insuring safe pipeline construction and continued monitoring once a pipeline is in operation. The agency issues these types of advisories if it sees a trend, they do not necessarily lead to further rulemaking. In this case PHMSA says earth moving incidents have increased across the country, particularly in the east. Lynda Farrell, director of the Pipeline Safety Coalition, says it’s an indication that PHMSA officials are worried about recent events that have led to spills. “They’re saying ‘it’s a bad idea to put pipelines in areas where damage to the pipeline could be caused by earth movement,'” she said. “If you know there’s potential damage, don’t put them there.” The advisory does not have the weight of a regulation, it simply sounds an alarm and reiterates regulations associated with pipeline safety. PHMSA lists seven incidents that have occurred in the past several years, including the release of more than 1,238 barrels of gasoline into the Loyalsock Creek from a Sunoco/Energy Transfer pipeline in Lycoming County in October, 2016. Although not listed in the PHMSA bulletin, officials also suspect that heavy rains and landslides caused the explosion of Energy Transfer’s natural gas liquids Revolution Pipeline in Beaver County last September. The explosion destroyed a house and knocked down power lines. Following the explosion, DEP inspectors also discovered Energy Transfer illegally eliminated 23 streams and 17 wetlands, and shortened the length of 120 streams while altering 70 wetlands during construction.

Protest planned at jobs fair for Robeson County gas facility – Piedmont Natural Gas has scheduled a job fair for Thursday afternoon as it plans to hire 150 people to begin building a $250 million natural gas storage plant in northwest Robeson County – and at the same time, activists plan to hold a protest and rally against it just outside. The conflict is set to happen from 5:30 p.m. to 8 p.m. at Oxendine Elementary School at 5599 Oxendine School Road, which is a Maxton address even though Maxton is miles away. The school is in Robeson County’s Wakulla community about 5 miles west of Red Springs. The project is to be built close by on 65 acres of a 685-acre tract on N.C. 71 at Rev. Bill Road. The project will be a property tax boon and economic driver for Robeson County, said Channing Jones, the county economic development director. The plant will endanger the community and damage the environment, said Mac Legerton, a long-time community activist Legerton is leading opposition to the gas storage plant and a separate project, the Atlantic Coast Pipeline, which is supposed to pipe natural gas from West Virginia to eastern North Carolina, terminating about 6 miles away in the Prospect area. But the Atlantic Coast Pipeline doesn’t yet exist. The new storage plant is set to get its gas from the Transcontinental Pipeline, which has 10,000 miles of pipe that carries gas from Texas and Louisiana on the Gulf Coast to the East Coast and Northeast. Piedmont Natural Gas intends to use the Wakulla storage plant to help the company keep sufficient gas supplies on hand to handle demand spikes during cold weather, spokeswoman Tammie McGee said.

Editorial: Keep offshore drilling away from Georgia’s coast – Opinion – Savannah Morning News – Many Georgians don’t like the idea of oil rigs dotting the horizon along their share of the South Atlantic Bight, that sinuous, concave coastline running from Cape Fear, North Carolina, to Cape Canaveral, Florida. Many in Carolina and Florida have also rejected this vision of the future.Governors of these states – and all other states along the Eastern seaboard – have loudly stated their opposition to lifting the Obama-era ban on drilling in U.S. coastal waters. Coastal, or territorial, waters extend out 12 nautical or 13.8 standard miles from the low tide line.Despite the outcry, the Trump administration was set to expand offshore drilling along the coast. A draft of a plan to do so was released last year and a final plan that would outline how oil lease sales would proceed was expected to be released this month. But a court decision got in the way. So where does all this leave offshore drilling in coastal waters? That is perhaps as difficult to predict as it is to say how much oil is in those waters and what having it on hand would mean. With more than 40 million acres along the outer continental shelf already available for oil exploration, opening near shore waters would be a terrible idea, putting the coastal Georgia ecosystem at risk. The Energy Information Administration estimates that the current off-limits coastal waters in the lower 48 states might hold about 18 billion barrels of recoverable crude oil. However, up-to-date, comprehensive assessments have not been made in many years.Since the U.S. consumes about 7.5 billion barrels of oil each year, the untapped nearshore sea floor might supply the country’s energy needs for a little more than two years, if the estimates are correct.It’s simply not worth the risks, which can potentially include environmental damage, destruction of fishing economies and devastation of tourism in oil-soaked coastal areas. Meanwhile, other sources of energy like natural gas, wind and solar power continue to come online, reducing the nation’s overall dependence on oil.

2,100-gallon oil spill reported in marsh near Galliano – The U.S. Coast Guard, state and federal agencies are responding to an oil spill into marshland near Galliano, Louisiana, according to a news release. Authorities were alerted that approximately 2,100 gallons of crude oil poured into the area due to a mechanical failure at the Bowley Cap Facility in Lake Bully Bonds Sunday (May 26), the release stated. The leak has since been secured. A pollution response team, including the Coast Guard Houma’s Marine Safety Unit, Louisiana Department of Wildlife and Fisheries, Louisiana Oil Spill Coordinator’s Office and the National Oceanic and Atmospheric Administration, responded to the spill with hard boom and sorbents, the Coast Guard said. Three drum skimmers were also used. The cause of the mechanical failure is still under investigation, the release stated. Clean-up efforts will continue until sunset Saturday and resume Monday morning.

Oil spill in Galliano caused by mechanical failure – On Sunday, the Coast Guard responded to a crude oil discharge from the Bowley Cap Facility in Lake Bully Bonds near Galliano. Watchstanders at Coast Guard Marine Safety Unit Houma received a National Response Center report of approximately 2,100 gallons of crude oil going into a marshy area near the Bowley Cap Facility due to a mechanical failure at the facility.A pollution response team from Marine Safety Unit Houma and a Louisiana Oil Spill Coordinator’s Office representative deployed to the facility to work with other responding agencies to coordinate clean-up operations.The source of the discharge has been secured and clean-up operations are underway to recover the spilled product.Containment boom, lined with sorbent boom, has been deployed to contain the spill.Three drum skimmers are engaged in skimming operations.Recovery operations are scheduled to finish on Tuesday morning.

Federal judge sends Plaquemines oil and gas damage suit back to state court – – A lawsuit charging six oil and gas firms with damaging wetlands and land within the Potash Oil & Gas Field in Plaquemines Parish in violation of Louisiana’s coastal zone management laws should be heard in state 25th Judicial District Court in Plaquemines, a federal judge ruled Tuesday (May 28).The order is the first to return to a state court of 42 lawsuits charging that the historic operation of oil and gas companies in six parishes along Louisiana’s coastline — including the construction of service canals, the improper disposal of hazardous wastes and saltwater, and other operations — caused damage to wetlands that state law requires the companies to either pay compensation for or repair. There’s a good chance that the opinion issued by U.S. District Judge Martin L.C. Feldman of New Orleans will be followed in returning other suits to state courts that are under consideration by other federal judges in New Orleans. A similar ruling might also follow for the suits that were removed to the federal court in Lafayette. “The governor is pleased that the judge approved the Department of Natural Resources’ motion, which is also supported by Attorney General Jeff Landry and simply says that these Louisiana claims should be heard in a Louisiana court,” said a statement issued by the office of Gov. John Bel Edwards. Edwards, Landry and the state Department of Natural Resources have intervened in all the suits in an effort to assure that any restoration or money coming from an ultimate ruling on behalf of the parishes will be used in compliance with the state’s coastal Master Plan.

$1.3B Pledged for Louisiana LNG Project – Stonepeak Infrastructure Partners will exclusively provide a $1.3-billion equity investment in Venture Global LNG, Inc.’s Calcasieu Pass LNG export facility in Cameron Parish, La., the companies reported Tuesday in a joint statement emailed to Rigzone. According to the companies, total committed capital to fund the construction of Calcasieu Pass – along with ongoing development of Venture Global’s Plaquemines LNG and Delta LNG projects – now totals $2.2 billion. More than $250 million has already been spent on Calcasieu Pass’ site preparation work, final engineering and equipment purchases and fabrication, the firms noted. “We are happy to announcement this important milestone for Calcasieu Pass and very proud to partner with a world-class investor like Stonepeak,” Mike Sabel, co-CEO of Venture Global, stated. “Their team brings a great depth of LNG knowledge and a track record of investing in exceptional infrastructure projects throughout North America.” Venture Global Co-CEO Bob Pender added that $855 million had previously been raised for the 10-million tonne per annum (mtpa) Calcasieu Pass project, which he said is “already significantly advanced” in regard to site construction as well as module manufacturing. “We are finalizing the balance of our Calcasieu Pass financing with our consortium of project finance lenders, and we look forward to providing LNG to our global customers – Shell, BP, Edison S.p.A., Galp, Repsol and PGNiG – in 2022,” Pender noted. Calcasieu Pass will use mid-scale, modularly, factory-fabricated liquefaction trains from Baker Hughes, a GE company, Venture Global and Stonepeak stated. Also, they noted that Kiewit is designing, engineering, constructing, commissioning and guaranteeing the facility, which has secured all necessary permits.

US Refiners Face Summer Snags | Rigzone — A global shortage of heavy crude will create hurdles for America’s key refining belts just as they ramp up gasoline production for summer driving season.In the Gulf Coast, dwindling heavy oil supplies have suppressed refining margins, while Midwest refiners may not reach the high run rates seen last summer. Gulf Coast profits from coking — a process where heavy crude is broken down into fuels such as gasoline and diesel — are already at their lowest levels in nearly a decade, according to data from Oil Analytics Ltd.The decline comes as a loss of crude supply from sanctions-hit Venezuela and Iran, as well as production cuts by Canada and OPEC, have driven up the price of fuel oil, which is used to make gasoline through the coking process. Gulf Coast fuel oil, a byproduct of heavy crude, reached a six-month high in late April.Gulf gasoline prices in the run-up to summer are also below the five-year average. Still, slimmer profits won’t necessarily mean less production. Margins are weak, but “we don’t expect any run cuts,” said Jan-Jacob Verschoor, director of Oil Analytics Ltd., which studies refinery economics.For June through August, runs are expected to be around 9.3 million barrels a day, similar to utilization to last year, Chris Barber, head of refining biofuels analysis for ESAI Energy, said by phone.In the Midwest, it’s a different story. Refineries in the region rely on Western Canadian Select, a heavy crude that’s recently gotten cheaper after Alberta’s government eased some production limits. The inexpensive oil supply has driven up coking margins for area refiners — but supply remains tight as Alberta won’t lift its mandatory output curbs until the end of the year. The supply crunch will likely push Midwest refinery runs to about 3.85 million barrels a day during June-August, lower than 3.95 million last year, Barber said.

Texas eminent domain reform died this session – Texas state lawmakers looking to reform the eminent domain process were unable to find common ground this session, despite hundreds of hours of negotiation. State Sen. Lois Kolkhorst’s Senate Bill 421 sought to better protect property owners when private companies condemn their land – a nod to landowners in Texas who’ve grown accustomed to encroaching oil and gas pipelines. The bill would’ve required public meetings between property owners and industry groups and instituted measures to prevent low-ball offers to property owners, among other reforms. But after the bill was markedly watered down in a House committee and approved in that chamber – a charge led by state Rep. Tom Craddick, R-Midland – the legislation couldn’t make it out of a joint House-Senate conference committee. The House version of the bill removed too many of the provisions Kolkhorst believed were critical, including measures aimed at restoring condemned land to as close to its original condition as possible. “The language of the House version would have turned back the clock for landowners and greatly harmed them,” Kolkhorst, a Brenham Republican, said in a statement Sunday. “I cannot agree to the Craddick proposal, which would do the opposite of what we set to do: help level the playing field for landowners in the taking of their property.” Th

Exxon, Others Leading High-Impact Drilling Rebound | Rigzone – Large oil and gas companies are commanding a greater role in high-impact exploration, but a lack of depth in the quality of global drilling opportunities diminished their performance in 2018, Westwood Global Energy Group reported Friday.”The competitive landscape is changing with the largest companies like Total, Equinor and Exxon now leading the way on conventional high-impact drilling, which is forecast to increase by 20 percent this year,” Keith Myers, president for research with Westwood Global Energy Group, said in a written statement emailed to Rigzone. “At the same time, mature regions such as North West Europe are seeing a renaissance, as explorers focus on trying to find more hidden gems.”Westwood’s findings stem from the research, data analytics and consulting services firm’s latest“State of Exploration” report, which examined global conventional exploration over the past five years and previews prospects for 2019. According to Westwood, a “twin track strategy” driving the industry comprises:

• Increasing short-cycle exploration over the period in mature basins with existing infrastructure
• Continuing to hunt for new petroleum provinces, particularly in deep water.

Also, Westwood noted that companies are moving away from sub-Saharan Africa and other onshore frontier drilling opportunities that can take considerable time – in some cases upward of 16 years – to commercialize. Challenges above-ground include lack of infrastructure and political/regulatory hurdles, the consultancy added. Other report findings include:

• Compared to the previous year, exploration drilling in 2018 was up nearly 30 percent but yielded poorer performance with fewer big discoveries and a lower commercial success rate.
• From 2014 to 2018, high-impact drilling discovered volumes were down 50 percent overall against results from the preceding five-year period.
• High-impact drilling should increase 20 percent in 2019 to approximately 80 wells, with more wells planned in maturing and mature plays such as North West Europe and Mexico.
• More than 50 percent of high-impact wells for 2018 and more than 70 percent for 2019 involve supermajors; in contrast, the supermajor participation rate for 2015 was 34 percent.

Frac sand expected to remain cheap as supplies outpace demand – Sand prices for oil and gas fracking and for the valuations of sanding mining companies are expected to remain depressed as growing supplies continue to outpace rising demand, research reports say. Even as more sand mines shutter up North that produce the highest qualities of sand, they’re more than outpaced by the growth of new mines in West Texas and even in South Texas’ Eagle Ford shale that offer sand at more modest qualities, but at cheaper prices and much nearer to the oil and gas production. Even some Central Texas sand mines have closed in recent months. Energy companies have used increasingly larger supplies of sand and water per well in the hydraulic fracturing process to help crack open the shale rock and release greater volumes of oil and gas. A report in Moody’s Investor Services said “frac sand castles may crumble” as prices stay low. Sand prices have plunged 20 percent in the last 12 months, Moody’s said. Just this week, Houston sand mining firm Hi-Crush Partners LP said it is converting from a partnership structure to a traditional corporation under the name Hi-Crush Inc. to potentially help stabilize its finances. Hi-Crush’s stock has plunged from more than $20 per unit in early 2017 down to just more than $2 t0day. Likewise, Fort Worth-based Emerge Energy Services, which is trading below $1, said it received a delisting warning from the New York Stock Exchange. Emerge said back in April it is considering filing for bankruptcy under a pre-structured plan with many of its creditors. In an already over-supplied sand market, the Norwegian research firm Rystad Energy said U.S. oil and gas sand demand will grow by 10 percent this year and by 17 percent in 2020. However, frat sand supplies also will grow by 10 percent this year.

Permian Cash Gains; Big Bearish Miss for EIA Sees Natural Gas Futures Slide – A large bearish miss in the latest U.S. government inventory data and forecasts showing underwhelming levels of June cooling demand had natural gas futures bulls in retreat Thursday. In the spot market, Midcontinent and West Texas prices clawed their way higher as much of the eastern two thirds of the Lower 48 saw modest declines; the NGI Spot GasNational Avg. added 2.0 cents to $2.080/MMBtu. The Nymex July futures contract settled at $2.547, down 7.7 cents after venturing as low as $2.534. Selling was of a similar magnitude further along the strip. August dropped 7.5 cents to settle at $2.557, while September settled at $2.549, off 7.4 cents. The bears may have been waiting for the June contract’s expiration Wednesday, as they “quickly pounced right at expiration time and haven’t looked back,” observed NatGasWeather. Adding to the bearish momentum that had developed in the market overnight, the Energy Information Administration (EIA) on Thursday reported a much larger-than-expected 114 Bcf injection into U.S. natural gas stocks. The 114 Bcf build, reported for the week ended May 24, overshot estimates by a wide margin, and the number easily tops both the 95 Bcf build recorded in the year-ago period and the five-year average 97 Bcf injection. Prior to the EIA report, consensus had formed around a build in the high 90s to low 100s Bcf. A Bloomberg survey had pointed to a median prediction of 98 Bcf, based on estimates ranging from 94 Bcf to 104 Bcf. The 114 Bcf figure topped even the highest estimate submitted to this week’s Reuters survey, which had called for a 101 Bcf injection based on a range from 91 Bcf to 110 Bcf. Intercontinental Exchange EIA Financial Weekly Index futures settled Wednesday at 100 Bcf, while NGI’s model predicted a 98 Bcf build. Shah pointed to the Midwest and South Central regions as the areas where estimates missed the mark this week. “I think it’s the timing of the heat that threw off the number,” Shah wrote. “This late-May heat resembled something we’d see in late June.” Total Lower 48 working gas in underground storage stood at 1,867 Bcf as of May 24, 156 Bcf (9.1%) higher than year-ago levels but 257 Bcf (minus 12.1%) below the five-year average, according to EIA. By region, EIA recorded a 35 Bcf build in the Midwest and a 30 Bcf injection in the East. Further west, the Mountain region refilled 4 Bcf for the week, while 12 Bcf was injected in the Pacific. The South Central region posted a 31 Bcf weekly build, including 27 Bcf injected into nonsalt and 4 Bcf into salt stocks, according to EIA.

Industry celebrates Trump’s limits on states’ regulation rights – Obama-era regulations that put the brakes on oil and gas development continue to fall by the wayside under the current administration. Two executive orders signed April 10 by President Donald Trump sought to limit the power of states to delay natural gas, coal and oil projects. The announcements were applauded by those in the Louisiana and Texas oil and gas industry, where an abundance of supply and increasing consumption are fueling heightened demand for pipelines. The orders essentially make it harder for states to block new pipeline development on environmental grounds, calling on the Environmental Protection Agency to review a section of the Clean Water Act requiring applicants to get certification from affected states. Absent the edicts, economist Loren Scott, of Loren C. Scott & Associates in Baton Rouge, says future pipelines coming out of the oil- and gas-rich Permian Basin could have run the risk of local interference as projects neared metropolitan areas in Texas on the way to the Gulf Coast. Nonetheless, laying pipeline has traditionally met minimal local resistance in the oil- and gas-friendly Southern states – with the notable exception of the recently completed Bayou Bridge Pipeline running from Nederland, Texas, to St. James Parish. “You’re going across two states,” says Scott, “that are not generally afraid of pipelines.” Gifford Briggs, president of the Louisiana Oil and Gas Association, says Trump is simply continuing his administration’s policy of gradually removing the regulatory hurdles to progress. “He has also taken some actions at FERC (Federal Energy Regulatory Commission) to speed up the approval process for Liquefied Natural Gas projects, so it’s not surprising that he’s doing the same thing with pipelines.” Briggs hopes the recent orders will facilitate the extraction of oil and gas out of the shale plays, adding that the cheap and abundant supply is the primary reason for the surge of industrial and LNG projects along the Gulf Coast. In southwest Louisiana’s LNG market, demand for natural gas is expected to reach 14 billion cubic feet a day by 2025.

Bechtel Bags Rio Grande LNG Deals Worth $9.5B+ – NextDecade Corporation revealed Tuesday that it has awarded two contracts worth more than $9.5 billion to Bechtel Oil, Gas and Chemicals for the engineering, procurement and construction of its Rio Grande LNG project in Brownsville, Texas. The contracts are for the first phase of the project, which consists of three liquefaction trains, two 180,000 cubic meter storage tanks and two marine berths. Each liquefaction train is expected to have up to 5.87 million tons per annum of LNG capacity. NextDecade said it anticipates making a “positive final investment decision” on up to three trains of the Rio Grande LNG project as early as the end of the third quarter of 2019 and commencing operations in 2023. According to NextDecade’s website, Rio Grande LNG is located in an uncongested deepwater port with access to a skilled labor force and in close proximity to abundant, low-cost recoverable gas resources in the Permian Basin and Eagle Ford Shale. NextDecade, which is headquartered in Houston, Texas, is an LNG development company focused on LNG export projects and associated pipelines in Texas

Hearings Begin in Lawsuit to Stop Permian Highway Pipeline — A lawsuit to stop construction of the Permian Highway Pipeline began with hearings Tuesday. Hays County, the city of Kyle and property owners affected by the pipeline signed onto the lawsuit against energy infrastructure company Kinder Morgan and the Texas Railroad Commission. The pipeline would stretch 430 miles from West Texas to Houston. More than 1,000 land owners would be affected. Plaintiffs of the lawsuit claim that Kinder Morgan cannot claim eminent domain over their property without following Texas Railroad Commission rules for project approval. Under the rules of the commission, private companies aren’t required to follow the same rules as government entities for these types of projects, but classifying the pipeline as a “gas utility” gives the company condemnation and eminent domain rights. Andrew Sansom said those rules aren’t fair to landowners like him. He’s the owner of the Hershey Ranch, a privately owned ranch dedicated to conserving wildlife. The property received a conservation easement to protect it from certain government projects. “Private land owners affected by this pipeline have not been given due process. If you look at Article 5 of the U.S. Constitution it says that the government cannot take private property without due process.” Kinder Morgan held five public meetings to discuss the pipeline with affected communities, despite not being required to do so. Kinder Morgan Vice President Allen Fore said they readjusted the pipelines route in over 150 personal cases with land owners along the route. He said his company is only following the rules as they’re written and land owners are disputing rules that can only change through legislation.

In court, opponents to pipeline through Hays county call for more oversight – A judge finished hearing arguments Wednesday in a case brought forth by local governments and property owners who oppose the intended route of a natural gas pipeline through the Hill Country. Now she says she will spend several weeks working to make a decision about whether there should have been more regulation or oversight for the process. The judge expects to have a decision ready in two to three weeks and an attorney for Kinder Morgan stated that the company would hold off from making any foreclosure proceedings against the plaintiffs until she makes her decision. Is this case goes to trial, the attorneys involved would want a trial in July or August. It is likely that no matter the outcome of this case, the outcome will be appealed. In a Travis County Courtroom Wednesday, Judge Lora J. Livingston heard two more witnesses brought forward by the defendants in this case: the pipeline company Kinder Morgan and the Texas Railroad Commission. The plaintiffs – the City of Kyle, Hays County and three landowners – brought forward all their witnesses at a hearing Tuesday. These parties have expressed concerns about the safety, environmental and economic repercussions of the Permian Highway Pipeline project. They object to the way Kinder Morgan set the route for the pipeline before seeking public input. They are hoping the judge will agree with them that the Railroad Commission has not carried out the public oversight with Kinder Morgan required by the Texas constitution These Hays County plaintiffs are hoping the judge establishes a temporary injunction that prohibits any exercise of eminent domain on this pipeline –at least in Gillespie, Blanco, and Hays Counties — until a final “trial of merit” happens or guideline standards for gas pipeline oversight are established by the Railroad Commission. Such a ruling would call into question the ways that pipelines have been setting routes in Texas or more than a century. Kinder Morgan and the Texas Railroad Commission are trying to dismiss this lawsuit related to the state’s eminent domain process. The Texas Railroad Commission is asking to be dismissed from this lawsuit entirely.

EIA’s new liquids pipeline projects database shows new U.S. crude oil pipeline capacity – EIA recently launched a new liquids pipeline projects database that tracks more than 200 crude oil, hydrocarbon gas liquids (HGL), and petroleum products pipeline projects. Rising domestic crude oil production has led to several changes in Gulf Coast crude oil supply and demand patterns, creating a need for more pipeline capacity. Crude oil pipeline capacity additions originating in the Gulf Coast region represent most of the scheduled pipeline capacity growth over the next few years. EIA’s new database provides an improved capability to track this growth. The database contains project information such as project type, start dates, capacity, mileage, and geographic information for historical pipeline projects (completed since 2010) and future pipeline projects. The information in the database is based on the latest public information from company documents, government filings, and trade press, and it does not reflect EIA’s assumptions on the likelihood or timing of project completion. U.S. crude oil production doubled between 2010 and 2018, with about 70% of that growth coming from the Gulf Coast region. U.S. Gulf Coast crude oil production grew from 5.2 million barrels per day (b/d) in 2014 to 7.1 million b/d in 2018, driven by production in the Permian Basin in western Texas and southeastern New Mexico. As U.S. crude oil production increased, imports dropped off significantly. Previously, Gulf Coast crude imports were shipped to refineries in the region, and they also moved north by pipeline to refineries in the Midwest. But as import volumes declined, less pipeline capacity was needed from the Gulf Coast to the Midwest. New pipelines and reversals of existing pipelines originating in the Midwest are increasingly moving crude oil south from the Bakken region in Montana and North Dakota, as well as from Canada, to the Gulf Coast. As a result, the Gulf Coast transitioned from being a net shipper to a net recipient of crude oil from elsewhere in the country in 2015. More recently, increasing Permian crude production has outpaced pipeline takeaway capacity to bring the crude oil to market. The increasing crude oil production and need for more pipeline transportation capacity prompted a large expansion of crude oil pipeline infrastructure. In the region, nine intrastate crude oil pipeline projects have been announced or are under construction with in-service dates between 2019 – 2021. These projects are planned to move crude oil throughout Texas and Louisiana to further alleviate regional constraints.

Pipeline Security Systems Market is Projected to Grow at a CAGR of 8.59% – The global pipeline security systems market was valued at USD 6.1 billion in 2017, and is expected to reach a value of USD 10.07 billion by 2023, at a CAGR of 8.59 %, during the forecast period (2018 – 2023). Pipeline systems have evolved to become the primary solution for the commercial activities. The market for the pipeline security has been boosted by the demand for sustainable use of resources and the rising frequency of breaches and theft of small quantities of the product being transported. The pipeline established for transport of commodities is estimated to span across 3.5 million kilometers across 120 countries across the world. Oil & gas, natural gas has been estimated to be the most vulnerable to attacks, and hence, the increased spending by the oil and gas corporation to install robust security infrastructure to ensure security to the pipelines has been the primary reason for the growth of the market globally. Oil & gas industry is estimated to be the largest to commit to the use of existing pipeline networks for transport across the world. According to a study conducted by IT security firm Tripwire, more than 80% of the oil & gas companies have registered an increase in the number of cyber-attacks on their respective firms. The survey further reveals the lack of confidence in the present and existing security framework installed within the organization. The need for integrated and exhaustive security solutions has been emphasized by leading industry experts.The number of cyber-attack incidents has been growing continuously for the last few years, with the industry (along with BFSI) quoted to be the most vulnerable sector. The sector has also been found to be the most impacted by the robust state-sponsored cyber-espionage campaigns, which can affect the physical infrastructure as well. These vulnerabilities have forced the industry players to divert significant amounts of funds for security. The implementation of holistic security solutions to provide comprehensive security and to protect the system by reducing the number of threat actors or points of entry to the infiltrators is the need of the hour in this industry. The rising number of illegal connections to petroleum and oil products pipeline is a major factor affecting the market for crude oil in the global pipeline security market. This trend is particularly very severe in several regions in Eastern Europe. Due to lack of an effective system for monitoring and compliance to design specifications, there have been several major hazardous accidents in the past. Pipelines are major target for extremist groups, as even a simple explosion can lead to a blackout, affecting supply for several weeks in some cases. Hence, crude oil companies are increasingly looking for robust security systems to enhance their existing mechanism. Particularly, the use of supersensitive seismic monitoring devices, could provide early warnings if saboteurs were to approach a protected area.

Newly Added Shale Plays — May 26, 2019 – EIA added new shale plays to their database earlier this year. For now they will be linked at the sidebar as “Emerging Shale Plays.” EIA recently updated its methodology and production volume estimates for U.S. shale gas and tight oil plays to include seven additional plays, increasing the share of shale gas by about 9% and tight oil by 8% compared with previously estimated shale production volumes. The update captures increasing production from new, emerging plays as well as from older plays that had been in decline but are rebounding because of advancements in horizontal drilling and hydraulic fracturing. The selected plays are identified by examining the reservoir names reported by operators to state agencies. EIA uses the third party data source, Drillinginfo, which collects and distributes well level data gathered by the states. The most productive of the newly added plays is the Mississippian formation, which is located mainly in Oklahoma within the Anadarko Basin. The mainly carbonate rock type lies above the Woodford play and has produced liquids and natural gas for some time, but newer completion techniques have driven recent production gains.

The remaining six plays are smaller and are included in the rest of U.S. tight oil and shale gas categories.

• The Burket and Geneseo formations in the Appalachian Basin of Pennsylvania and West Virginia increased production in recent years. These dry shale gas formations lie above the Marcellus Shale but are thinner and do not cover as large an area as the Marcellus.
• The Uteland Butte member of the Green River Formation in the Uinta Basin of Utah is composed primarily of limestone, dolostone, and organic rich mudstones and siltstones.
• The Turner, Frontier, Sussex-Shannon, and Teapot-Parkman formations are located in the Powder River Basin of Wyoming and lie below and above the Niobrara formation, the basin’s primary hydrocarbon-bearing formation. They are mainly fine-grained sandstone with interbedded silt and shale

Only 10% Of US Shale Drillers Have A Positive Cash Flow – Nine in ten US shale oil companies are burning cash, according to Rystad Energy. Rystad has studied the financial performance of 40 dedicated US shale oil companies, focusing on cash flow from operating activities (CFO). This is the cash that is available to expand the business (via capital expenditure, capex), reduce debt, or return to shareholders.Only four companies in our peer group reported a positive cash flow balance in the first quarter of 2019, bringing down the share of companies with a positive cash flow balance from the recent norm of around 20% to just 10%. Total CFO fell from $14 billion in the fourth quarter of 2018 to $9.9 billion in the first quarter of 2019.”That is the lowest CFO we have seen since the fourth quarter of 2017,” says Alisa Lukash, Senior Analyst on Rystad Energy’s North American Shale team.”The gap between capex and CFO has reached a staggering $4.7 billion. This implies tremendous overspend, the likes of which have not been seen since the third quarter of 2017.”With negative cash flows, shale companies have historically relied on bond markets to finance their operations. Without additional funding and any debt refinancing, capex would have to be cut.However, no US shale company has made a public offering since the sharp fall in oil prices – and subsequent share price slide – late last year, marking the longest gap in public capital issuance since 2014.March and April 2019 saw a few of the more indebted operators issue bonds, intended to partly cover outstanding obligations for the coming year. However, pricing for this type of issuance has risen substantially due to the increased Fed Rate and the overall increased risk associated with US oil companies from a market perspective. “Recently released data, which confirmed dismal first quarter earnings, only served to cement negative market sentiment,” Lukash said. “While shale operators continue to focus on improving capital efficiency, investors are putting the industry under extreme pressure, leaving no room for undisciplined spending in 2019.” Many operators are building production momentum now after a seasonal dip during the winter months. As oil prices improve Rystad Energy expects the second quarter will see a significant increase in CFO while capex remains stable.The majority of US shale oil producers have slightly reduced their long-term debt by paying down obligations which will soon reach maturity.

Pioneer CEO says the natural gas company avoided a downturn in prices by shipping out to California – Windmills are bringing some of the cheapest electricity to the Permian Basin, pushing natural gas prices into the negative, Pioneer Natural Resources CEO Scott Sheffield told CNBC Thursday. “Pioneer has taken our gas to California, so we’re not seeing any of the negative prices,” he said in a one-on-one with “Mad Money’s” Jim Cramer. “But a lot of the independents are seeing negative.”In order to address challenges in natural gas, Sheffield said the company will need to add as many as five additional natural gas lines to its operations in the southwestern basin.Pioneer has about six crude oil lines that run from the Permian to the Gulf Coast, he said. The company only has one pipeline for natural gas there, he added.”What’s gonna solve our natural gas industry is get more [liquefied natural gas] projects,” said Sheffield, who returned to lead the company after Tim Dove retired in February. “We need to ship it out, just like we are crude oil; just like we are propane, butane [and] ethane end products.” Liquefied natural gas, or LNG, is natural gas that has been cooled for shipping and storage purposes.

Midwest Flooding Disrupts Crude, Fuel Cash Markets – Unexpected pipeline outages and refinery shutdowns over the past week – in part caused by bad weather in the U.S. Midwest – has roiled cash markets for both crude oil and refined products, traders said on May 28.Volatile trading was seen both in crude markets in the Cushing, Okla., hub and for gasoline and diesel traded in the Tulsa, Okla., region.The Ozark pipeline, which flows up to about 360,000 barrels per day (bbl/d) of crude oil, was shut, market intelligence firm Genscape said in a notice on May 28. It was not immediately clear whether flooding had caused the outage on Ozark, though the rains have caused other pipelines in the region to shut in recent days.The Ozark line flows northeast from Cushing to the Phillips 66 Wood River refinery in Roxana, Ill., according to Genscape. The outage had an immediate effect on the U.S. West Texas Intermediate crude cash roll – the three-day period after the front-month futures contract expires, when traders rebalanc