Oil, Gas, And Fracking News Reads 09June 2018 – Part 1

Written by rjs, MarketWatch 666

Here are some selected new articles from the week ended 09 June 2018.

This article is a feature every Monday evening on GEI.

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US oil prices were again quite volatile this week, rising on threats to oil supplies, then falling when news showed supplies were more than adequate, but ultimately ending the week just a few cents below where they started, in the 3rd weekly decrease in a row…after sliding $2.07 or 3% to $65.81 a barrel last week, benchmark US crude prices for July fell another $1.06 to $64.75 a barrel on Monday to their lowest level in nearly two months, driven lower by growing U.S. oil production, international trade tensions, and expectations that OPEC would raise global supplies…but prices turned around on Tuesday, rising 77 cents to finish at $65.52 a barrel, after 12 of 13 analysts in a Bloomberg survey said Wednesday’s weekly EIA report would show US oil stockpiles decreased the prior week…however, when that EIA report surprised the pundits and showed an increase in crude supplies, oil prices fell back to below their Monday close, shedding 79 cents and ending the day at $64.73 a barrel….but oil prices turned around again on Thursday, rising $1.22 to $65.95 a barrel, on a steep drop in oil exports from Venezuela and word from Algeria’s oil minister that OPEC might not raise output at its meeting later this month…however, that rally reversed again the next morning on a drop in Chinese demand, and prices then fell as low as $65.15 a barrel after JP Morgan cut its 2018 US crude price forecast by $3 to $62.20 a barrel, before steadying near the close to end at $65.74 a barrel, for a loss of 21 cents on the day but just 7 cents, or 0.1%, for the week overall…

international oil prices, meanwhile, followed a similar trajectory, but maintained a premium of over $10 a barrel over US prices throughout the week…the front month of the international benchmark, North Sea Brent crude for August, was down $1.50 on Monday to $75.29 a barrel, its lowest in two months, on growing expectations that OPEC would increase production at their upcoming meeting, but then was little changed over Tuesday and Wednesday while US crude prices were being jacked up and down by the EIA report on US oil supplies…however, Brent prices were up nearly $2 to $77.32 a barrel on Thursday as the drop in exports from Venezuela and concern that OPEC might not raise production had a greater impact on international oil prices…Brent prices then fell 86 cents to end the week at $76.46 a barrel, for a loss of 23 cents or 0.3% on the week, but still $10.79 a barrel more than the similar grade of US crude for August delivery…with a price spread of that magnitude, we can almost guarantee that we’ll be seeing record levels of crude exports this summer and beyond, any hurricane disruptions to port traffic notwithstanding…

natural gas prices, meanwhile, also ended lower this week, as forecasts for cooler weather dashed the bulls’ hopes for an early summer gas-consuming air conditioning power burn…natural gas prices for July delivery were down 3.2 cents on Monday and 4 cents on Tuesday and despite a 3.4 cent gain on Thursday’s natural gas storage report, fell another 4 cents on Friday to end the week 2.4% lower at $2.890 per mmBTU…that natural gas storage report from the EIA for the week ending June 1st indicated that natural gas in storage in the US rose by 92 billion cubic feet to 1,817 billion cubic feet over the week, which still left our gas supplies 799 billion cubic feet, or 30.5% below the 2,616 billion cubic feet that were in storage on June 2nd of last year, and 512 billion cubic feet, or 22.0% below the five-year average of 2,329 billion cubic feet of natural gas that are typically in storage at the beginning of June…the market was anticipating a 97 billion cubic foot addition to gas storage, so this week’s 92 billion cubic foot addition was a bit short of expectations, and was also below the average 104 billion cubic foot weekly surplus of natural gas that is typically added to storage at this time of year…again, we’re watching these supplies to see if they can be adequately rebuilt before next winter; as we noted, last year natural gas supplies rose to 3,790 billion cubic feet by the first week of November before withdrawals for heating began, so at today’s levels we’d have to add 1,973 billion cubic feet over the next 22 weeks, or nearly 90 billion cubic feet per week, to match that pre-winter level by November, which will become increasingly difficult as we move into the warmer part of the summer, when demand for air conditioning is strongest…

The Latest US Oil Data from the EIA

this week’s US oil data from the US Energy Information Administration, covering the week ending June 1st, indicated that due to a big jump in our oil imports and and a corresponding drop in our oil exports, we had surplus oil to add to our commercial crude supplies for the eleventh time in the past nineteen weeks…..our imports of crude oil rose by an average of 715,000 barrels per day to an average of 8,346,000 barrels per day during the week, after falling by 528,000 barrels per day over the prior week, while our exports of crude oil fell by an average of 465,000 barrels per day to an average of 1,714,000 barrels per day during this week, which meant that our effective trade in oil over the week ending June 1st worked out to a net import average of 6,632,000 barrels of per day during the week, 1,180,000 barrels per day more than the net of our imports minus exports during the prior week…at the same time, field production of crude oil from US wells rose by 31,000 barrels per day to a record high of 10,800,000 barrels per day, which means that our daily supply of oil from our net imports and from wells totaled an average of 17,432,000 barrels per day during the reporting week…

meanwhile, US oil refineries were using 17,369,000 barrels of crude per day during the week ending June 1st, 214,000 barrels per day more than they used during the prior week, while at the same time 209,000 barrels of oil per day were reportedly being added to oil storage in the US….hence, we can see that this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 146,000 fewer barrels per day than what was reportedly added to storage plus what refineries reported they used during the week…to account for that disparity, the EIA needed to insert a (+146,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as “unaccounted for crude oil”… (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) show that the 4 week average of our oil imports rose to an average of 7,934,000 barrels per day, which was still 4.4% less than the 8,303,000 barrel per day average we imported over the same four-week period last year…the 209,000 barrel per day increase in our total crude inventories included a 296,000 barrel per day addition to our commercially available stocks of crude oil, which was partially offset by a 87,000 barrel per day decrease of the oil in the oil stored in our Strategic Petroleum Reserve, likely part of a sale of government owned oil mandated by this year’s federal budget…this week’s 31,000 barrel per day increase in our crude oil production included a 35,000 barrel per day increase in output from wells in the lower 48 states, which was slightly offset by a 2,000 barrel per day decrease in oil output from Alaska, with no explanation as to why those rounded figures don’t add up…the 10,800,000 barrels of crude per day that were produced by US wells during the week ending June 1st were again the highest on record, 15.9% more than the 9,318,000 barrels per day that US wells were producing during the week ending June 2nd of last year, and 28.1% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

US oil refineries were operating at 95.4% of their capacity in using 17,369,000 barrels of crude per day during the week ending June 1st, up from 93.9% of capacity the prior week, as refineries will usually try to run flat out through the summer driving season…however, the 17,369,000 barrels of oil that were refined this week were still down 1.4% from the off-season high of 17,608,000 barrels per day that were being refined during the last week of December 2017, even as they have finally topped the 17,227,000 barrels of crude per day that were being processed during the same week a year ago, when US refineries were operating at 91.5% of capacity….

even with the increase in the amount of oil that was refined this week, gasoline output from our refineries was considerably lower, falling by 775,000 barrels per day to a 4 year seasonal low of 9,658,000 barrels per day during the week ending June 1st, after our refineries’ gasoline output had increased by 381,000 barrels per day during the week ending May 25th....that big decrease meant our gasoline production was 2.8% lower during the week than the 9,934,000 barrels of gasoline that were being produced daily during the week ending June 2nd of last year, an otherwise slow refining week……meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) rose by 28,000 barrels per day to a seasonal high of 5,324,000 barrels per day, after rising by 358,000 barrels per day the prior week…as a result, this week’s distillates production was 7.4% higher than the 4,956,000 barrels of distillates per day than were being produced during the week ending June 2nd, 2017….

however, even with the big drop in our gasoline production, our supply of gasoline in storage at the end of the week still rose by 4,603,000 barrels to 239,034,000 barrels by June 1st, the sixth increase in 14 weeks, and the largest increase since December….our gasoline supplies increased primarily because the amount of gasoline supplied to US markets fell by 713,000 barrels per day to 8,976,000 barrels per day, and because our exports of gasoline fell by 118,000 barrels per day to 538,000 barrels per day, while our imports of gasoline fell by 182,000 barrels per day to 777,000 barrels per day….but even after this week’s increase, our gasoline inventories finished the week fractionally lower than last June 2nd’s level of 240,348,000 barrels, even as they were still roughly 8.6% above the 10 year average of gasoline supplies for this time of the year…

meanwhile, with this week’s increase in distillates production, our supplies of distillate fuels rose for the second time in 9 weeks, increasing by 2,165,000 barrels to 116,794,000 barrels during the week ending June 1st…our distillate inventories increased because the amount of distillates supplied to US markets, a proxy for our domestic consumption, dropped by 817,000 barrels per day to 3,502,000 barrels per day, after increasing by 682,000 barrels per day the prior week, as wholesalers built supplies in advance of the holiday weekend…meanwhile, our exports of distillates rose by 536,000 barrels per day to a near record 1,659,000 barrels per day while our imports of distillates decreased by 91,000 barrels per day to 149,000 barrels per day…however, because our distillate supplies fell by 14,452,000 barrels over six weeks to May 18th, our distillate supplies still ended the week 21.5% below the 148,768,000 barrels that we had stored on June 2nd, 2017, and roughly 15.2% lower than the 10 year average of distillates stocks for this time of the year…

finally, with our oil exports down and our oil imports much higher, our commercial supplies of crude oil increased for the 12th time in 2018, but just for the 18th time in the past year, as our commercial crude supplies rose by 2,072,000 barrels during the week, from 434,512,000 barrels on May 25th to 436,584,000 barrels on June 1st…however, after falling most of the past year, our oil inventories as of June 1st were still 14.9% below the 513,207,000 barrels of oil we had stored on June 2nd of 2017, 13.0% below the 501,844,000 barrels of oil that we had in storage on June 3rd of 2016, and fractionally below the 438,447,000 barrels of oil we had in storage on June 5th of 2015, during a period when the US glut of oil had already begun to build from the nearly stable supply levels of the prior years…

before we move on, i want to take a look an anomalous increase in our total inventories in this week’s report that was pointed out by Zero Hedge…as it turns out, those increases in our inventories of gasoline, distillates and crude that we’ve discussed above, when combined with increase in inventories of jet fuel, bunker fuel, propylene, and other oil products, was the largest increase in our total oil and oil products inventories since October of 2008…by way of showing you what happened, we’ll include the graph showing that increase from the post at zero hedge:

the above graph of our total oil + oil products inventories comes from the Zero Hedge review of this week’s EIA release, wherein the graph shows the end of the week supply in billions (not millions) of barrels of crude oil and petroleum products (excluding what’s in the SPR) from mid-2006 to the current report…also shown below the graph as red spikes above or below a zero line is the weekly change in crude oil and petroleum products in thousands of barrels…hence, as they point out with the green dashes, this week’s 15,756,000 barrel increase in our total inventories was the largest upward spike, and hence the largest increase in our total inventories since 19,673,000 barrels of oil and products were added to our supplies during the week ending October 3rd 2008…

while i can’t venture a guess why supplies had jumped that much during that week nearly 10 years ago, this week’s inventory jump appears to be an artifact of how our oil product supplies are distributed around the holidays…as we noted earlier, the amount of gasoline supplied to US markets, often seen as an indicator of our consumption, fell by 713,000 barrels per day during the week ending June 1st, while the amount of distillates supplied to US markets dropped by 817,000 barrels per day over the same period…checking other “product supplied” metrics, we find that jet fuel supplied to US markets fell by 163,000 barrels per day, that propane/propylene supplied to US markets fell by 326,000 barrels per day, that residual oil supplied to US markets fell by 12,000 barrels per day, and that other oils supplied to US markets fell by 400,000 barrels per day…with deliveries to US wholesalers down, inventories held by the oil product producers, whose refineries continued to operate, naturally rose…but again, this appears to be a function of product distribution around the holiday; gasoline, diesel fuel, and jet fuel wholesalers and retailers built their inventories in the weeks before the holiday, and hence their deliveries of product were slack during the holiday week…this is evident in the historical record, when for instance, the largest weekly increase in oil and oil products inventories last year was also during the week of Memorial Day, when inventories increased by 15,471,000 barrels, which was nearly a 9 year high at that time…holiday weeks in prior years also show similar anomalous inventory increases, but usually not so extreme as the past two years, and in no case have those increases been evidence of a trend…

This Week’s Rig Count

US drilling activity increased for the 15th time in the past sixteen weeks and for 24th time in the past 31 weeks during the week ending June 8th, a period of higher oil prices that has seen rig increases far exceed the few decreases…Baker Hughes reported that the total count of active rotary rigs running in the US increased by 2 rigs to 1062 rigs over the week ending on Friday, which was also 135 more rigs than the 927 rigs that were in use as of the June 9th report of 2017, while it was still down from the recent high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC officially began their attempt to flood the global oil market…

the count of rigs drilling for oil was up by 1 rig to 862 rigs this week, which was also 121 more oil rigs than were running a year ago, while it was still well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014…at the same time, the number of drilling rigs targeting natural gas formations also rose by 1 rig to 198 rigs this week, which was only 13 more gas rigs than the 185 natural gas rigs that were drilling a year ago, and way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008…in addition, there continues to be two rigs operating that are considered to be “miscellaneous”, compared to the 1 “miscellaneous” rig that was running a year ago….

with the addition of a second drilling platform offshore from Texas, drilling activity in the Gulf of Mexico increased by 1 rig to 19 rigs this week, which was still 2 fewer rigs than were drilling in the Gulf of Mexico a year ago, at which time all Gulf of Mexico rigs were in Louisiana waters…there was also a rig drilling offshore from Alaska this week, as there also was during the week ending June 9th a year ago, so the total US offshore count is now at 20 rigs, also down by 2 from last year’s offshore total of 22 rigs….in addition, another platform was set up to drill through an inland lake in southern Louisiana this week, so now there are 3 such ‘inland waters” rigs operating, same as the number of inland waters rigs that were operating going into the same weekend a year ago…

the count of active horizontal drilling rigs increased by 5 rigs to 934 horizontal rigs this week, which was 154 more horizontal rigs than the 780 horizontal rigs that were in use in the US on June 9th of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…in addition, the directional rig count increased by 2 rigs to 67 directional rigs this week, which was also up by 1 from the 66 directional rigs that were in use during the same week of last year…on the other hand, the vertical rig count was down by 5 rigs ti 61 vertical rigs this week, which was also down from the 81 vertical rigs that were deployed on June 9th of 2017…

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 producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of June 8th, the second column shows the change in the number of working rigs between last week’s count (June 1st) and this week’s (June 8th) count, the third column shows last week’s June 1st active rig count, the 4th column shows the change between the number of rigs running on Friday and those of the equivalent weekend report 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 on Friday the 9th of June, 2017…

except for the three rig decrease in Oklahoma’s Cana Woodford, which has often been touted as a hot play, there’s not much particularly noteworthy in this week’s changes…there was another 3 rig increase in the Permian, apparently all in west Texas this week, which has now seen 112 rigs added this past year, all but one of them drilling for oil, and hence those additions account for the lion’s share of the oil rig increases over the past year…drilling in all the major natural gas basins, meanwhile, was again unchanged, with the one rig increase in natural gas rigs occurring in one of those “other” basins not tracked separately by Baker Hughes…we should also note that in addition to the changes shown in the major producing states in the top table above, this week also saw a rig added in Alabama, as well as one in Mississippi…hence, in Alabama, there are now 2 rigs operating, down from 3 a year ago, while the 3 rigs now operating in Mississippi is back to the same number as a year ago…in addition, the only rig that had been drilling in Florida was shut down this week, so Florida is now free of any drilling, same as they were a year ago…

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FirstEnergy’s request for Trump relief draws more critics – Toledo Blade – The Trump Administration plan to bail out struggling nuclear and coal-fired power plants comes two months after FirstEnergy Solutions filed what many experts see as a historic and potentially landmark petition for relief under Chapter 11 bankruptcy laws.FirstEnergy is a subsidiary of Akron-based FirstEnergy Corp. The FirstEnergy bankruptcy filing includes FirstEnergy Nuclear Operating Co., which oversees the Davis-Besse nuclear plant east of Toledo, the Perry nuclear plant east of Cleveland, and the twin-reactor Beaver Valley complex west of Pittsburgh.The case has become a high-profile one nationally because FirstEnergy is one of America’s largest utilities.Those nuclear plants – in addition to numerous coal-fired power plants under FirstEnergy – represent a huge chunk of electricity for the regional electric grid Pennsylvania-based PJM Interconnection operates in 13 states, including Ohio. That grid, which serves 65 million people, is the nation’s largest.Because nuclear and coal-fired plants have become so unprofitable – unable to compete against record-low natural gas prices – FirstEnergy appealed to U.S. Department of Energy Secretary Rick Perry for help when it filed for bankruptcy in March. It called upon him to exercise emergency authority under a pair of federal laws typically reserved for wars or natural disasters.Now, with administration spokesman Sarah Huckabee Sanders announcing on Friday that President Trump has directed Mr. Perry to prepare “immediate steps” to keep such plants open, the utility appears to be getting its wish.

Letter: Studies on fracking, methane show mixed results – Columbus CEO — Clarke Owens – Jon Baker’s recent front-page article, “Study: East Ohio water unaffected by drilling,” devotes its last two paragraphs to the words of Jackie Stewart, a public relations spokesperson for a group launched by the Independent Petroleum Association of America. She claims the study finds that “fracking is not a major threat to groundwater.” Another, online article about the same study (www.sciencedaily.com) says: “Researchers hypothesized that methane concentrations in the drinking-water wells they sampled would increase over time with the growth of natural gas drilling in the area. This is a correlation researchers observed in Pennsylvania’s Marcellus region.” Instead, the study found that methane in groundwater was naturally occurring. The Pennsylvania researchers attributed the contamination to failed well casings, which hadn’t happened “with the wells of homeowners we worked with for our study.” The study was limited to new wells. “Researchers did find wide variability in methane concentrations in the drinking water, ranging from 0.2 micrograms per liter to 25.3 milligrams per liter, which is strong enough to catch fire in enclosed spaces. But researchers found no relationship between the methane observed in drinking water and the new gas wells.” The study concluded: “Clearly, additional monitoring is needed to determine whether methane concentrations and source signals in this region change as the number of oil and gas wells continues to increase.” Google the issue and you get a mixed result. But a Cornell University professor did a study in 2014 showing that nine percent of unconventional wells in Pennsylvania since 2009 have structural integrity issues. He was concerned the problem will grow as wells age, and tens of thousands of them are bored.

Gas Pipeline Growth For TransCanada – Two years ago, TransCanada Corporation (TRP) acquired the enormous Columbia Gas pipeline network. Columbia Gas Transmission LLC owns the various pipelines that make up the Columbia Gas system, and TransCanada Corporation owns 100% of that subsidiary. Let’s take a look at how TransCanada Corporation is growing its massive gas pipeline division. Now that the Leach Pipeline is operational (came online in early January) the Columbia Gas system runs for 12,000 miles. Primarily, the pipeline transports Appalachian gas supplies to buyers in the Northeast, but that is changing as the network gets larger and larger. Operations are supported by Columbia Storage, which has 285 billion cubic feet of natural gas storage capacity (entirely or almost entirely owned by TransCanada). The company also owns half of the 12 Bcf Hardy Storage facility in West Virginia.When it comes to natural gas Appalachia is brimming with supply, and production growth out of the Marcellus and Utica shale plays show no signs of letting up. To grow, TransCanada needs to make sure that ever rising Appalachian gas supplies can reach end buyers.That isn’t as easy a task as it seems due to the risks posed by construction cost overruns, regulatory hurdles, political concerns, financing costs, and competition from other pipeline operators. Midstream firms have a preference for expanding existing pipelines rather than building new ones. Generally speaking, expansions of existing pipeline systems are an easier sell to both the public and regulators than building a new one from scratch. Let’s go over some of those expansions. The Mountaineer Xpress project is a 171-mile endeavor that involves constructing a pipeline from Marshall County in the northern part of West Virginia down to Cabell County in the southwestern portion of the state. Gas will be supplied through receipt points in Pennsylvania and West Virginia, and with 2.7 Bcf/d of gas takeaway capacity, this is quite a large endeavor. On top of putting pipe in the ground, TransCanada is upgrading three existing compression stations and building three new ones as part of the Mountaineer Xpress project. When operational, the system will send 1.8 Bcf/d of gas supplies to the TCO Pool and the remaining 0.9 Bcf/d will go to either the TCO Pool or the Leach Interconnect. Through the Leach Pipeline, those gas supplies can ultimately reach Southern US markets. The pipeline can carry up to 1.5 Bcf/d of gas across 160 miles from Marshall County in West Virginia down to Leach, Kentucky. From there, the Leach Pipeline connects with the Rayne Pipeline which runs to Rayne, Louisiana. In conjunction with the Mountaineer Xpress project, TransCanada launched the Gulf Xpress endeavor. The Gulf Xpress project involves building seven new compression stations and upgrading an existing one along an existing pipeline built a while ago. When completed, this $800 million development will add roughly 875 MMcf/d to the Columbia Gulf pipeline system’s transportation capacity.

Here’s mud in your eye – It’s been a bad two weeks for the Mountain Valley Pipeline, and a time of hope for opponents. On Tuesday, a proposal by the pipeline to pay Franklin County up to $300,000 to lease 10 acres of public land to store equipment during construction failed on a tie vote of the seven-member Board of Supervisors, with one abstention. The supervisor’s vote wasn’t the first blow to the project this month, either locally or nationally. On May 17-18 earth destabilized by tree cutting and land clearing along the pipeline route buried both lanes of Cahas Mountain Road under nearly 8 inches of mud. The flooding and erosion was just the type of thing protesters had been claiming would happen and gave some weight to their warnings. State regulators ordered a temporary stop to pipeline work until better sediment control measures were put in place. On Wednesday, The Roanoke Times reported that six county landowners affected by the mudslide had filed a lawsuit against the pipeline, claiming the sediment swamped their hayfields and made its way into nearby streams. More seriously for the pipeline, on Tuesday Reuters reported that the U.S. Army Corps of Engineers had pulled its nationwide permit and “could delay the $3.5 billion project’s expected late 2018 in-service date. “The Army Corps said in a filing made available on Thursday that it pulled the permit on May 22 to determine if it is at odds with West Virginia environmental rules,” according to Reuters. If the pipeline is found to be in violation, construction will be rerouted around three West Virginia rivers, Reuters reported. But it’s likely to go forward anyway, despite sometimes obsessive hostility towards it.

Regulators cite Mountain Valley Pipeline a second time for erosion problems — For the second time since work began on the Mountain Valley Pipeline, regulators have put the company on notice that it is breaking rules meant to protect the environment. Crews building the natural gas pipeline failed to prevent sediment-laden water from running off at a work site in Wetzel County, West Virginia, according to a notice of violation issued last week by the state’s Department of Environmental Protection. Opponents of the project have long argued that clearing land and digging ditches along steep mountain slopes for the massive buried pipeline will invite problems with erosion, leading to contamination of streams that feed public and private water supplies. Those fears were corroborated April 25, when West Virginia environmental regulators issued their first notice that Mountain Valley was using inadequate erosion and sediment control devices. Ann Rogers, director of development for the Blue Ridge Environmental Defense League, said she was “grievously concerned” to learn of a second notice – especially coming so soon in a construction process that is only a few months old. “People need to understand that we’re just getting started,” she said. “If you think this is bad, wait until they start digging deeper into the ground.” After receiving their first notice of violation, pipeline officials wrote in a letter to regulators that the issues had been “fully addressed and resolved.” Yet just a few weeks later, they were facing more problems in Wetzel County, the starting point for a 303-mile buried pipeline that will pass through Southwest Virginia. One trouble spot was in a “known flood plain,” according to written reports, and in another construction area water was seen running through a silt fence meant to curb erosion. “Sediment deposits were observed in stream, causing conditions not allowable,” an inspection report stated.

Mountain Valley Pipeline protesters lock themselves to drilling equipment – Opponents of the Mountain Valley Pipeline tried a new tactic Monday: chaining themselves to construction equipment. West Virginia state police arrested three people who were trying to slow down workers in Lindside, a community in Monroe County, West Virginia. They delayed construction for a few hours on Route 219. Police cut them out around 10 a.m., about two hours after they received a call. Police said Maxwell Shaw, 24, Evin Ugur, 21, and Sydney White, 18, are all from Massachusetts and are out on bond. Court documents showed they’re each facing three misdemeanors, one each for trespassing, obstructing and resisting arrest. That could mean up to two and a half years in jail. Witnesses say about 25 other pipeline opponents came out to watch. One of them was Jammie Hale, who lives in Giles County. “Very humbling. You see somebody willing to put their life and limb in jeopardy to save my farm, my land, my community. Oh yeah, it’s very humbling,” he said. He described a tense atmosphere. Witnesses said police threatened to use tasers, pepper spray and batons. “There’s people going every which way and then police, law enforcement pulling in and you don’t know what to expect or exactly what’s going to happen,” he said. He’s encouraged by the efforts. “Nowadays people are scared to stand up and take a stand and to see especially some young people,” he said. This comes just three days after the last sitter in Virginia came down from a spot blocking construction in Giles County. “I hope a lot of people get involved and say ‘I’m going to stick up for my neighbor, for their rights, for our constitutional rights,’” Hale said.

W.Va. DEP suggests pulling or changing part of MVP permit The West Virginia Department of Environmental Protection suggested last week it might modify or waive a condition on a river-crossing permit issued to pipeline developers.The federal Clean Water Act permit, called the Nationwide 12, is at the center of a legal challenge against the U.S. Army Corps of Engineers, which approved the permit for the pipeline.The 300-mile line is designed to run natural gas from Wetzel County, W.Va., to Pittsylvania County, Va., crossing 600 streams and 400 wetlands, Kallanish Energy understands.The Mountain Valley Pipeline is ineligible for the Nationwide 12 permit because four major river crossings don’t comply with one of the permit’s conditions, lawyers for the Sierra Club, the West Virginia Rivers Coalition, the Indian Creek Watershed Association and others argued in a motion for preliminary relief filed May 22, the Charleston (W.Va.) Gazette-Mail newspaper reported.The “Special Condition C,” added to the Nationwide 12 permit by the DEP, stipulated stream crossings be completed within 72 hours. But developer Mountain Valley Pipeline LLC told the Army Corps in 2017 construction on the Elk, Gauley, Greenbrier and Meadow river crossings could take between four and six weeks to complete. After the lawyers challenged the permit, arguing that Mountain Valley Pipeline wasn’t eligible for the permit because construction would take longer than 72 hours, the Army Corps blocked construction on crossings of the four rivers.Wednesday, the Army Corps of Engineers wrote to the DEP, asking for information about construction methods, and whether the DEP planned to take additional action on the Special Condition C, or its application to the four river crossings.On Thursday, Scott Mandirola, director of the DEP’s division of water and waste management, wrote: “Yes, the WVDEP intends to take whatever action is necessary to make it clear that the most environmentally protective methods are used for the stream crossings detailed in your letter,” the Gazette-Mail reported.

TransCanada Pipeline Explodes in West Virginia – A newly installed TransCanada natural gas pipeline exploded early Thursday in the remote Nixon Ridge area of Marshall County in West Virginia. No injuries were reported but flames and smoke from the blast could be seen as far as 20 miles away , residents told local media. Area police told CBS News the fire was “very large – if you can see it from your house, evacuate.” “It sounded like a freight train coming through, or a tornado, and the sky lit up bright orange, and then I got up and looked out the window and flames were shooting I don’t know how far into the sky,” Tina Heath-Chaplin, of Moundsville, told WPXI . TransCanada – the same company behind the Keystone pipeline – said the explosion has been contained and an investigation is underway. “As soon as the issue was identified, emergency response procedures were enacted and the segment of impacted pipeline was isolated. The fire was fully extinguished by approximately 8:30 a.m,” the company commented Thursday. “The cause of this issue is not yet known,” TransCanada continued. “The site of the incident has been secured and we are beginning the process of working with applicable regulators to investigate, including the Pipeline and Hazardous Materials Safety Administration.”

Gas line explosion rocks Moundsville area of northern West Virginia, sends flames high in air — A powerful gas line explosion sent flames shooting into the sky early Thursday in the Nixon Ridge area of Marshall County, West Virginia, reports CBS Wheeling affiliate WTRF-TV. The flames could be seen for miles around.The blast, in a TransCanada pipeline, was felt around 4:20 a.m., the station says.One person told WTRF it shook his house so badly it felt like a tornado was ripping through the area. Moundsville, W. Va. police told CBS News the fire was “very large — if you can see it from your house, evacuate” Ohio County, W. Va. Ohio County Emergency Management Agency Director Lou Vargo said they were getting dozens of 911 calls from people who could see the flames and were very alarmed.In addition:BREAKING: @MarshallCoWVOEM says they have received calls from Ohio, Belmont, Marshall, and Wetzel Counties that people can see this explosion. Hart says he could see if from Cameron @WTRF7News pic.twitter.com/WMPQjrTllo – Tessa DiTirro (@TDiTirroWTRF) June 7, 2018

TransCanada’s New ‘Best-In-Class’ Gas Pipeline Explodes in West Virginia, Causing Fiery Blast — This morning, residents of Marshall County, West Virginia, awoke at 4:15 a.m. to a major natural gas rupture and explosion on TransCanada’s Leach XPress pipeline on Nixon Ridge – a quickly built pipeline only half a year old. The fire was visible for miles, local TV news reported. Police warned anyone who could see the flames to evacuate – and the Emergency Management Agency director of neighboring Ohio County said officials had received dozens of 911 calls from locals able to see the fire, which was extinguished roughly four hours later. The blast was so powerful that one resident told a local CBS affiliate it felt like a tornado was passing through. No one was injured, and no property damage was reported, TransCananda said in a statement released today, adding that the cause of the explosion was not yet determined. The Leach XPress pipeline is just six months old, having been put into service on January 1, 2018. At the time, TransCanada emphasized that it was built quickly – but safely. “Leach XPress was done in less than a year,” Scott Castleman, manager of U.S. Gas Communications for TransCanada, said in a January statement. “We’re looking forward to generations of safe operations,” he added. “This is truly a best-in-class pipeline and we look forward to many years of safe, reliable, and efficient operation on behalf of our customers.”

Appalachian natural gas market reacts to explosion,force majeure – An explosion early Thursday morning in Marshall County, West Virginia, on TransCanada’s Columbia Gas Transmission system caused a force majeure on the pipeline’s Leach XPress and put prices in the region on a roller-coaster. In Thursday trading at Columbia Gas, Appalachia saw an 11-cent climb to $2.77/MMBtu, according to Platts preliminary pricing data, changing direction from other points in the area, as Texas Eastern Transmission M-2 plunged 21 cents and the Dominion Transmission South Point dropped 26-cents. This is the first time in seven trading sessions that Columbia Gas, Appalachia has moved opposite of both Tetco M-2 and Dominion South. Balance-of-the-month gas prices could also see opposite movement for Columbia Gas, Appalachia versus Tetco M-2 and Dominion South as no return-to-service date for the pipeline has been announced.For gas day Friday, timely cycle, and until further notice, LXPSEG MA41 capacity was set to zero. This month, flows through the affected segment (LXPSEG MA41) were averaging 1.46 Bcf/d while Leach XPress-related production receipts were averaging 1.24 Bcf/d. Platts estimates approximately 0.5 Bcf/d of production could be lost because of the outage. In a notice to shippers, Columbia said, based on current nominations, the potential impact to firm service was 1.3 Bcf. The impact on production is expected to be well below that, however, as gas is routed to alternative pipelines. There are several alternatives for routing production around the outage, including to Rover Pipeline, Rockies Express Pipeline, and Texas Eastern Transmission. During a previous restriction on the LXPSEG MA41 segment in late May, flows through LXPSEG MA41 fell May 22 and May 24-25, the bulk of production was routed to Texas Eastern, Rover and Equitrans, with smaller volumes to Rockies Express.

No natgas flows through West Virginia Leach Xpress, producers use other pipes (Reuters) – TransCanada Corp said on Friday it cannot move natural gas until further notice through the section of its Leach Xpress pipeline in West Virginia that ruptured early Thursday until, prompting customers to seek other pipelines to ship their gas. Alternative pipelines to route production around the outage included Energy Transfer Partners LP’s Rover, Tallgrass Energy Partners LP’s Rockies Express (REX), EQT Midstream Partners LP’s Equitrans and Enbridge Inc’s Texas Eastern Transmission (Tetco), analysts at S&P Global Platts said in a note. The blast that shut the pipe did not cause any injuries and was contained Thursday morning, TransCanada said. Columbia Gas Transmission (TCO), the TransCanada subsidiary that operates the pipe, declared a force majeure on Thursday and said the damaged section of pipe could affect movement of about 1.3 billion cubic feet per day (bcfd). One billion cubic feet a day is enough gas for about 5 million U.S. homes. Despite the pipeline shutdown, overall output in the Marcellus and Utica shale gas region of Appalachia increased to 27.4 bcfd on Thursday from 27.3 bcfd on Wednesday, according to Thomson Reuters data. U.S. oil and gas exploration company Range Resources Corp, which uses the Leach pipeline to transport its gas to market, said on Thursday it expects to temporarily lose access to its 0.3 bcfd of capacity on the pipe. As it reroutes gas to other pipes, Range said it does not anticipate impacts to production volumes and also said it currently expects the impact to second quarter cash flow to be minimal. S&P Global Platts said several gas producers whose gas normally flows on the Columbia system reported just minor impacts, including Southwestern Energy Co, which like Range said it was utilizing a variety of pipelines in the area to get its production to market. The Leach shutdown caused Appalachia prices to trade in opposite directions on Thursday, with TCO up about 11 cents, while Dominion South dropped about 39 cents, according to data from SNL, another unit of S&P Global. The 1.5-bcfd Leach Xpress in West Virginia and Ohio, which entered full service at the start of this year, transports gas from the Marcellus and Utica shale formations in Pennsylvania, Ohio and West Virginia to consumers in the U.S. Midwest and Gulf Coast.

WVU researcher receives NIH grant to explore effects of fracking on cardiovascular health — Building and operating a hydraulic fracturing well site can emit airborne particles in multiple ways. But scientists still don’t fully understand how these particles impact human health.Travis Knuckles, assistant professor in the West Virginia University School of Public Health, has received $450,000 from the National Institutes of Health to investigate these questions.Hydraulic fracturing is a process in which oil and gas are extracted from rock by injecting mixtures of water, sand and chemicals underground. Over three years, Knuckles will explore how particulate matter in the air from fracking sites can make it harder for the body to control how much blood enters the capillaries, the narrowest blood vessels, and turn oxygen into ATP, a chemical that is a primary energy source for cells.The particulate matter at the center of Knuckles’ study is especially fine. Each particle has a diameter of less than 2.5 micrometers. That’s smaller than a particle of talcum powder – even smaller than a red blood cell. Particles that small have been shown to cause cardiovascular disease, worsen its symptoms and make it more deadly. “We have a pretty good idea of what particulate matter does in general,” said Knuckles, who is part of WVU’s Department of Occupational and Environmental Health Sciences and the WVU Health Sciences Center Toxicology Working Group. “The issue is that we have not looked at particulate matter from these gas wells as a toxicant unto itself. How is that emission different from a typical emission near a roadway? Is it more toxic than ambient particles in a broad sense?” He and his research team will compare how airborne-particulate samples collected from the Marcellus Shale Energy and Environment Laboratory near Morgantown and from downtown Morgantown influence microvascular tissue.

Livestock Maybe Affected by Fracking via Unknown Mechanism in Fayette County, PA — After years of seeing reproductive issues among his yearling heifers that grazed in the pasture, Broadwater is convinced that a shale gas well there damaged the health of those cows via a seep that formed at the bottom of the slope on the well’s south side. “They don’t care about the farmer,” Broadwater said of Chevron and the state Department of Environmental Protection as he stood between the seep and the gas well. In 2010, Atlas Energy developed the National Mines 26H natural gas well site on Broadwater’s property, and Chevron acquired it in 2011. Broadwater began to have problems with his herd almost immediately. The first two to three years after the well was drilled, only half of the heifers were pregnant, which struck him as highly unusual. Broadwater bought a new bull, recalling that Chevron blamed his herd’s reproductive issues on the bull. The heifers continued to have trouble breeding, though, and about three years ago, Broadwater stopped making the pasture near the well available to his cattle. He saw an increase in births right away. This year, the yearling heifers have had a 100 percent calving rate, having not been exposed to the 26H seep water. But all of the cows that previously grazed in the pasture have continued to struggle with infertility issues and disappointing breeding rates, Broadwater said. He recounted with exasperation that his 3-, 4-, and 5-year-old cows, having been exposed to the seep water, have this year had four stillborn calves and one that was born with a cleft palate and died hours later. Broadwater has no doubt that the seep is a direct result of the gas well, noting that the seep had killed grass below it for more than 300 feet below. A lifelong farmer, Broadwater, 68, recalled the veterinarian for his herd saying that whatever is killing the grass can’t be good for his cows, especially since the grass is their primary food source.

Study shows vigilance vital – The state Department of Environmental Protection is the last word in Pennsylvania on most industrial processes that affect the environment, A recent disturbing case from Western Pennsylvania demonstrates, however, why residents themselves should be wary beyond the scope of the DEP’s official pronouncements. For decades, until a few weeks ago, the DEP had allowed local governments to use brine – wastewater from gas and oil drilling – to control dust on dirt and gravel roads. As reported by StateImpact Pennsylvania, researchers William Burgos and Nathaniel Warner of Penn State University looked into the practice after discovering it in a DEP database about the use of drilling wastewater. They collected brine from 14 townships and reported, in the journal Environmental Science and Technology, that lead and radium in the wastewater washed out of the road material in simulated rainstorms. The researchers said that some of the lead and radium is carried into the air as dust when the roads dry. Burgos and Warner reported that between 2008 and 2014, the use of oil and gas wastewater on state roads released four times the amount of radium into the environment than from specialized treatment plants that handle brine, and 200 times the amount released from spills. DEP suspended permits for brine last week, following a lawsuit filed last year against the agency for allowing the spread of pollution. State lawmakers should find out why the DEP allowed the use of toxic materials for dust control. And citizens facing environmental issues should not hesitate to demand answers from the agency beyond its minimum regulatory requirements.

Penn township fracking battle continues in court – The battle over fracking in Penn Township returned to a Westmoreland County courtroom Monday with residents discussing their experiences and fears about unconventional gas well drilling. “We were told that we would not be affected by drilling,” said Tracey Mason, who lives near Apex Energy’s Quest well pad in the northeast corner of the township. She described noise like a “jet engine” keeping her family up at all hours and driving through a fog of dust kicked up by drilling. This week’s testimony is expected to conclude Tuesday. Experts on both sides of the issue testified before Westmoreland County Judge Harry Smail last month. Local environmental group Protect PT challenged the township’s zoning ordinance, which allows hydraulic fracturing wells in both industrial and rural-zoned areas. The anti-fracking group contends wells should be limited to industrial zones. Protect PT called 10 of its members as witnesses Monday to talk about why they oppose fracking. All live in or near the township, many near the Poseidon and Quest well pads, which are currently operating. Other well pads are in various planning stages. Noise, pollution and decreasing property values were top concerns. Resident Larry Irr said he’s worried the sound-blocking barriers won’t be enough to deaden the noise of drilling. “It’s like trying to stop the green giant with a playpen,” he said. In addition to its own solicitor, the township is being represented by lawyers from Apex Energy and Huntley and Huntley Energy Exploration, which own the current and proposed fracking wells. The township and energy companies are expected to call six witnesses Tuesday, including township employees who will focus on how the zoning ordinance was created.

Testimony concludes in Penn Township fracking case – The fate of fracking in Penn Township is in a judge’s hands after four days of testimony featuring more than 20 witnesses and more than 100 documents presented as evidence. Local activist group Protect PT challenged the township’s mineral extraction overlay in court before Westmoreland County Judge Harry F. Smail. The overlay allows unconventional gas well drilling in rural and industrial zones. The court heard from anti-fracking residents Monday. On Tuesday the township and the gas companies that do business there presented their side. Township Community Development Director Bill Roberts said the township’s zoning ordinance was developed over about seven years, in accordance with changing state and federal rules. The township started working on a new zoning ordinance in 2009, updating regulations that remained largely unchanged since the ’90s. In 2012 state legislators passed Act 13, which limited municipalities’ ability to restrict natural gas drilling. Parts of the law were overturned by the Pennsylvania Supreme Court in 2013. The changing standards delayed implementation of Penn Township’s ordinance, Roberts testified. “We just kept adjusting as we moved along, until we ended up with the ordinance you see in front of you,” he said. The ordinance includes limitations on sound, noise and traffic generated at drill sites, he said. Protect PT questioned whether the gas companies influenced the development of the ordinance. Ryan Hamilton, Protect PT’s lawyer, asked Roberts numerous questions about township Commissioner Jeff Shula, whose son works as a geologist for Huntley and Huntley Energy Exploration, which has one active fracking well in the township and has several more in development. Shula recused himself from voting on the final ordinance but was involved in shaping some of the earlier drafts.

State legislators ask feds to support ethane storage hub in Pennsylvania — Two legislators from southwestern Pennsylvania have filed a resolution calling for federal legislation and policies to support the construction of an ethane storage hub in the Appalachian region. State Rep. Jim Christiana, R-Monaca, and state Sen. Camera Bartolotta, R-Canonsburg, spoke Tuesday in favor of the storage hub at a news conference in Harrisburg. “Pennsylvania is one of the nation’s leading states in terms of natural gas production, manufacturing and the petrochemical industry,” Bartolotta said. “Building an ethane storage and distribution hub would help our state capitalize on its existing infrastructure and natural resources, giving us an opportunity to create more quality jobs and drive business growth throughout the region.” Bartolotta said among the “strategic steps” necessary for the hub’s development is the passage of several bills by Congress. Such a hub could be used for the storage and distribution of ethane feedstock to petrochemical facilities such as the one being built by Shell Chemical Appalachia LLC in Beaver County, said Abby Foster, president of the Pennsylvania Chemical Industry Council. “The development of ethane storage facilities would drive additional investments to grow the supply chain and solidify this market for Pennsylvania,” Foster said. A 2017 study commissioned by the Pennsylvania Department of Community and Economic Development forecasted that, from 2026 to 2030, the expected ethane output from the Marcellus and Utica Shale plays will be enough to support up to four additional ethane steam crackers in the region. Shell Chemical is building the $6 billion facility on the Ohio River with a view toward using ethane from the Marcellus Shale and processing it into ethylene and, finally, polyethylene pellets for the plastics industry. It has begun hiring for production operator positions and anticipates up to 600 jobs.

How Sunoco’s Mariner East pipeline is affecting real estate prices in Pa.’s Chester and Delaware Counties – Two months after Angela and Matthew Cibelli moved into their family’s dream home in Uwchlan Township in 2016, a representative of Sunoco Pipeline LP stopped by their house to outline upcoming construction plans for the Mariner East project. “What construction?” replied Angela, unaware that the previous owner had signed an easement allowing Sunoco to occupy their backyard to build two new underground pipelines across their Marchwood property. Shannon Healey experienced a similar sinking feeling when she learned Sunoco planned to dig up the property that she and fiance Kevin Bullman bought last year on Lenni Road in Middletown Township. Sunoco had paid the previous owner for the easement.“We wouldn’t have bought here if we had known,” said Healy.The $5.1 billion Mariner East project, which aims to deliver 675,000 barrels a day of propane and other highly volatile gas liquids across Pennsylvania to Marcus Hook through three pipelines, has produced considerable anxiety in some neighborhoods in Chester and Delaware Counties, the most densely populated areas along its 350-mile route.The project has unsettled the residential real estate market, as some fearful homeowners sold out ahead of construction, and some buyers moved in unaware of the forthcoming disruption. Many who remained are basically stuck until the dust settles, uncertain of the value of their homes.“I’m scared of it,” said Kate White, 57, whose house on Lenni Road in Middletown is less than 10 feet from the pipelines. “I would love to move, but who would buy my house now?” “When I found this house, I thought it was perfect,” said Ray Magliano, who paid $300,000 at the end of 2015 for a three-bedroom house on Wildwood Avenue in Glen Riddle, not knowing that Sunoco had paid the previous owner to expand its easement. The new pipelines run 36 feet from his front door. He said a lawyer advised him it would cost more than it was worth to challenge the sale. Zillow, the real estate website, now estimates his home is worth 10 percent less than what he paid for it.

Pennsylvania adopts new controls for cutting methane from shale gas wells – New shale gas wells in Pennsylvania will have to meet permit conditions that directly control emissions of the greenhouse gas methane for the first time, the Wolf administration announced Thursday as it released final versions of contentious air quality permits that had been under development for two years.The two general permits will apply to new natural gas wells tapping the Marcellus and Utica shales, and new compression and processing stations built along pipelines. Both permits will go into effect on Aug. 8.Department of Environmental Protection Secretary Patrick McDonnell said the permits “are some of the first in the nation to comprehensively address methane emissions from all equipment and processes, and they also address other types of air pollution that contribute to poor air quality.”Methane is the second-most prevalent greenhouse gas released from human activities after carbon dioxide, but it is more potent at trapping heat in the atmosphere over the short term. Natural gas is mostly made up of methane, so minimizing leaks means companies keep more of their product to sell.That was the point emphasized by Marcellus Shale Coalition President David Spigelmyer, who said Thursday that the industry is already “focused on ensuring methane and related emissions are managed safely and effectively.” “We remain concerned about imposing additional requirements through operating permits, particularly those that exceed DEP’s statutory authority,” he said.

Fact of the Matter: Dominion’s Pipeline Jobs Claim “Deceptive” — Dominion Energy has taken to the airwaves to gain public support for the Atlantic Coast Pipeline, a controversial 600-mile project that will send natural gas from West Virginia to Virginia and North Carolina. One much-televised ad features Brian Simpson, a heavy equipment operator and member of the International of Operating Engineers, Local 147. “For me, the Atlantic Coast Pipeline means a good, steady job with benefits,” he says. “The scene shifts to footage of Simpson talking to two colleagues at a construction site. A narrator says, “The Atlantic Coast Pipeline: 17,000 jobs.” The logo of the pipeline appears on the screen with white print underneath it saying, “17,000 JOBS..” That’s a lot of jobs and the figure, as it’s cited in the commercial, is greatly exaggerated and misleading. The source of the number, according to a Dominion spokesperson, is a 2014 report prepared for the energy corporation by Chmura Economics and Analytics, a Richmond-based company. The report contains some major qualifications about its job estimates that Dominion doesn’t share in its commercial. Chmura estimated the pipeline would support 17,240 “cumulative jobs” in Virginia, West Virginia and North Carolina during its six-year development and construction phase from 2014 through 2019. That doesn’t mean 17,240 people will find pipeline-related work during those years, as the ad implies. “Cumulative jobs” is a measure of the number of people projected to have pipeline jobs each year multiplied the number of years the development and construction phase is expected to last. In other words, if someone was hired for a job that lasted for six years, that would count as six cumulative jobs. Chmura estimated that the pipeline will spur an annual average of 2,873 actual jobs during its development and construction phase. Multiply that number by the six-year duration of phase, and you come up with 17,238 “cumulative jobs” which, when rounded off, matches Dominion’s ad claim.

FERC splits again on affiliates, climate in Florida pipeline approval – FERC’s latest split pipeline decision highlights a growing partisan divide over pipeline approvals at the commission. LaFleur and Glick, the two Democratic commissioners at FERC, have regularly issue dissents or concurrences based on affiliate relationships and carbon impacts since the agency’s quorum was restored last year. The three Republican commissioners, meanwhile, typically vote to approve applications. That divide will likely influence FERC’s ongoing review of its pipeline certification policies, announced by Chairman Kevin McIntyre in December 2017. In this case, Glick took aim at the relationship between Florida Southeast Connection, owner of the proposed 5-mile pipeline, and Florida Power & Light, which owns the natural gas plant that would be the sole recipient of its gas. Florida Southeast says it has contracts for capacity on its proposed pipeline, called precedent agreements, with FP&L, but both companies are owned by NextEra Energy, which Glick said should raise questions over whether the pipeline is actually needed. “Although precedent agreements generally can be one measure for determining whether a pipeline is needed, precedent agreements among affiliates are less valuable for this purpose because they are not necessarily the product of arms-length negotiations,” Glick wrote. “Instead, under such circumstances, the Commission must look behind the precedent agreements and consider other indicia of need … including projections of the demand for natural gas, analyses of the available pipeline capacity, and assessments of the cost savings that the proposed pipeline would provide to consumers.” The FERC majority dismissed this argument, writing that it is “current Commission policy to not look behind service agreements to make judgments about the needs of individual shippers.” “The mere fact that Florida Power & Light is an affiliate of Florida Southeast does not call into question the need for the project or otherwise diminish the showing of market support,” the majority wrote.

Oil Hunt Damages Everglades’ Big Cypress National Preserve – New oil development has no place in sensitive wetland habitats in the Florida Everglades. The Burnett Oil Company, based in Texas, claimed it could explore for oil in the Big Cypress National Preserve with no significant, long-term impacts to sensitive wetlands. But these claims have been refuted, as Burnett Oil has caused significant damage.As NRDC previously reported , the fossil fuel industry targeted the Big Cypress National Preserve in the western Everglades for oil development, beginning the first of four planned phases of seismic survey activities in 2017. However, heavy rains forced the oil company out of the preserve before the seismic activities were complete.Even after damaging wetland soils and vegetation last year, the oil company returned to the preserve this spring to continue its hunt for oil.NRDC and its partners retained environmental professionals to inspect and document the damage these activities are causing. Here’s a report outlining the damage along with recommendations for restoration, mitigation and long-term monitoring. The consultants observed extensive soil rutting, which will have long-term adverse effects on the preserve’s hydrology, soils and vegetation. Nonetheless, there were no signs that the oil company attempted to restore the wetland impacts, as its state and federal permits require. For example, the 33-ton “vibroseis” vehicles compacted and deeply rutted soils due to their sheer weight. These ruts are almost 2 feet deep in places. The vibroseis vehicles created seismic survey lines that are up to 15 feet wide. In several locations where vibroseis vehicles turned around or were rerouted, consultants observed even wider paths of soil disturbance.

Gas pipeline firms appeal federal judge’s order to pay for canal erosion — Four natural gas pipeline companies that were ordered to repair some erosion along pipeline canals in Plaquemines Parish by a federal judge in August 2017 and May of this year have appealed their case to the U.S. 5th Circuit Court of Appeals.The notice of appeal does not contain an explanation of why the rulings by U.S. District Judge Jane Triche Milazzo were being challenged.”We are appealing because while the court awarded only $1,100 in money damages and ordered less than a third of the specific relief requested by the plaintiffs, important issues were wrongly decided and should be reversed on appeal,” said Dave Conover, a spokesman for Kinder Morgan, the parent company for two of the pipeline firms.Attorneys representing New Orleans-based Vintage Assets Inc. and other landowners who filed the suit against the pipeline companies did not immediately respond to a request for comments.In August 2017, Milazzo found that Tennessee Gas Pipeline Co. LLC and Southern Natural Gas. Co. LLC, both subsidiaries of Kinder Morgan, and the privately owned High Point Gas Transmission LLC and High Point Gas Gathering LLC, had to repair some of the erosion that had occurred since 1953 along the paths of their canals through property largely owned by New Orleans-based Vintage Assets Inc. in the Breton Sound basin in Plaquemines Parish.After a September 2017 bench trial aimed at determining what should be repaired, Milazzo ruled in May that the companies had to restore 9.6 acres of wetlands that she found they had allowed to erode, and must pay $1,102 in damages. The cost of restoring the wetlands could be significant, and a permanent injunction Milazzo issued with her ruling required the companies to maintain the wetlands adjacent to the canals for as long as right-of-way agreements allowing the pipelines to be there are in force.

Oil vs wild rice: Enbridge, opponents gear up final US pipeline push (Reuters) – Canada’s Enbridge Inc (ENB.TO) faces an indefinite delay to its biggest-ever capital project if a U.S. state regulator denies its preferred pipeline route through Minnesota, but a victory would spell relief for Canadian oil shippers and northern U.S. refiners. Some pipeline opponents, which include environmental and Native American groups, are trying to convince the Minnesota Public Utilities Commission (PUC) to kill the project. Others oppose only Enbridge’s proposed new pipeline route, saying it would consume more land and threaten Native Americans’ traditional harvest of wild rice from wetlands. Enbridge wants to replace the aging 1,031-mile (1,660-km) Line 3 pipeline that runs from Alberta to Wisconsin. Worsening bottlenecks in Alberta have steepened a price discount for its heavy crude, and several pipeline projects that could ease the situation face stiff opposition. Line 3, placed into service in 1968, operates at half its capacity due to integrity concerns. Its replacement would allow it to return to approved capacity of 760,000 barrels per day. The PUC is set to decide late this month whether the total $7 billion project is necessary and if so, what route it should take. An administrative law judge recommended in April the expanded pipeline should follow the existing route. Enbridge prefers a new route that bypasses an indigenous reservation, avoids some ecologically sensitive areas and prevents a pipeline shutdown of up to one year. A different route would require a detailed evaluation that would set back plans to start the added oil flow by late 2019, said Guy Jarvis, Enbridge’s executive vice-president of liquids pipelines and major projects.

Shale Country Is Out of Workers and Dangling 100% Pay Hikes -Jerry Morales, the mayor of Midland, Texas, and a local restaurateur, is being whipsawed by the latest Permian Basin shale-oil boom. It’s fueling the region and starving it at the same time. Sales-tax revenue is hitting a record high, allowing the city to get around to fixing busted roads. But the crazy-low 2.1 percent unemployment rate is a bear. As a Republican first elected in 2014, he oversees a government payroll 200 employees short of what it needs to fully function. “This economy is on fire,” he said. Fire, of course, can be dangerous. In the country’s busiest oil patch, where the rig count has climbed by nearly one third in the past year, drillers, service providers and trucking companies have been poaching in all corners, recruiting everyone from police officers to grocery clerks. So many bus drivers with the Ector County Independent School District in nearby Odessa quit for the shale fields that kids were sometimes late to class. The oil industry has such a ferocious appetite for workers that it’ll hire just about anyone with the most basic skills. “It is crazy,” said Jazmin Jimenez, 24, who zipped through a two-week training program at New Mexico Junior College in Hobbs, about 100 miles north of Midland, and was hired by Chevron Corp. as a well-pump checker. “Honestly I never thought I’d see myself at an oilfield company. But now that I’m here — I think this is it.” That’s understandable, considering the $28-a-hour she makes is double what she was earning until December as a guard at the Lea County Correctional Facility in Hobbs. When the boom goes bust, as history suggests they all do, shale-extraction businesses won’t be able to out-pay most employers anymore. Jimenez said she’ll take the money as long as it lasts.

Why Aren’t Permian Oil Producers Profitable? – The Wall Street Journal recently reported that only five of the Top 20 U.S. oil companies focused mostly on hydraulic fracking generated more cash than they spent in the first quarter of this year. This continues a trend that has been ongoing throughout the fracking boom. The article doesn’t list the cash flow picture for the entire Top 20, nor did it explain how it calculated cash flow. But based on the numbers they reported and my own analysis, it appears they are defining cash flow as simply the amount of cash generated from operations minus capital expenditures.The story indicated that overall, companies spent $1.13 for every $1 they took in. It further noted that “Oasis Petroleum Inc. spent $3.27 for every $1 it made in cash, while Parsley Energy Inc. spent almost $2 for every $1 it made in cash.”Hedging was blamed for the underwhelming cash flow. The article noted that many producers hedged oil prices at $50 to $55 a barrel, and were therefore unable to cash in on the rally in oil prices. Of course, that makes you wonder why a company would hedge at a price that they should have known would result in negative cash flow. Continental Resources infamously ditched its hedges in 2014 after oil prices declined to $75/bbl. The company expected prices to bounce back quickly. Continental hasn’t yet resumed hedging but expects to do so at some point. Notably, Continental was reported to have the highest cash flow among its peers at $258 million for Q1. EOG Resources was also highlighted for generating a $110 million cash surplus for the quarter.

Natural Gas Basis Implications Of Permian Production And Takeaway Capacity – Gas producers in the Permian are facing the prospect of severe transportation constraints over the next year or so before additional gas takeaway capacity comes online. Left unchecked, continued production growth could send gas at Waha spiraling to devastatingly low prices for producers. However, there are a number of ways producers and other industry stakeholders could mitigate the growing supply congestion in West Texas, at least in part, and possibly dodge the proverbial bullet. The longer-term solution will come in the form of new pipeline capacity, which will shift vast amounts of Permian gas east to the Gulf Coast and potentially create a new problem – supply congestion and price weakness along the Gulf Coast, at least until sufficient export capacity is built there to absorb the excess gas. Today, we wrap up our Permian gas blog series, with our analysis of how these events will unfold, including an outlook for Waha basis. In Part 1 of this series, we discussed the meteoric rise of Permian gas production as a byproduct of the crude-focused drilling boom in the basin. The supply growth has happened much faster than many market participants expected and both crude oil and gas production growth is now facing prolonged periods of takeaway constraints and constraint-driven supply price discounts unless either producers slow down or more takeaway capacity is built (see All Dressed Up With Nowhere to Go for more on the crude takeaway). In Part 2, we took a closer look at the effects of rising production on outbound gas flows, pipeline utilization and prices. . As we detailed in Part 3, there are six publicly announced pipeline projects vying to relieve Permian constraints, all with routes that move gas east to where the demand is growing the most – at the Gulf Coast.

Gas Glut in Permian Sparks Dilemma Over How Much to Burn – — Texas is facing a burning question that’s pitting the state’s economy against its environment, and oil drillers against each other.With natural gas pipelines in the Permian Basin reaching 98 percent of capacity, Texas is weighing whether to keep intact or loosen strict state regulations that limit flaring, the process used by drillers to burn off excess gas pumped up along with their oil. Now the limit for individual wells is 45 days. After that, without a rare-granted exemption, the gas must be piped away or the well must close.Shut wells mean less revenue for companies and the state at a time when oil prices and production are surging while regional gas prices are in a tailspin. Ending or expanding the cap solves the problem. But it also gives drillers that haven’t paid for space on existing pipes a competitive edge over those that have, and could spark environmental protests.“This is not a simple thing we’re talking about,” “It’d be a pretty big policy shift and we want to be very thoughtful about what the ramifications could be.”Sitton said he’s meeting with producers across the Permian, and hopes to have a decision within six months, when he believes the dilemma will come to a head. The gas associated with that boom has filled up all but two percent of pipeline capacity as of the end of April, according to RBN Energy LLC, and Rystad Energy AS suggests oil output may grow 10 percent more by the end of 2018.Natural gas prices in the Permian, meanwhile, are the cheapest in the nation. The region is “ground zero for the oversupply caused by associated gas production,” said John Kilduff, a partner at Again Capital LLC in New York, by email. If oil output continues to boom, gas prices “could certainly go to zero.”

Permian drilling activity drives diesel demand and projects to supply more of it. Drilling and completion activity in the Permian Basin doesn’t only produce vast quantities of energy, it consumes a lot of energy too, mostly in the form of diesel fuel to power the trucks, drilling rigs, fracturing pumps, compressors and other equipment needed to keep the oil patch humming. And while refineries within or near the Permian meet a portion of the region’s needs, rising demand for diesel there is spurring the development of new infrastructure – and the repurposing of existing assets – to bring additional fuel into the Permian from refineries along the Gulf Coast. Today, we discuss efforts to move more diesel to the oil fields of West Texas. Texas consumes far more distillate – most of it ultra low sulfur diesel (ULSD) – than any other state: an estimated 485 Mb/d (or 20.4 million gallons a day) in 2016, the most recent year that state-by-state statistics are available from the Energy Information Administration (EIA). That was 82% more than California, and more than triple the distillate consumption of other high-population states like New York, Pennsylvania and Florida. Four-fifths of Texas’s distillate/diesel consumption is by the transportation sector, the vast majority of it by tractor trailers and other trucks that transport everything from petrochemicals to corn chips across the Lone Star State. In the past few years – and especially in the past two or three – diesel consumption has been on the rise in the red-hot Permian Basin in West Texas, and in neighboring counties in southeastern New Mexico. There, diesel is the king of fuels. It powers almost everything: the trucks that haul oilfield equipment, frac sand and water to well sites, the trucks that haul produced water from the lease to disposal wells, and, increasingly in recent months as takeaway pipelines out of the Permian have filled up (see No Time), the trucks that transport crude oil long distances to downstream pipeline injection points (and sometimes all the way to Corpus Christi and Houston).

Permian tracker: Pipeline build-out to support increased production – Production from the US’ fastest growing oil play continues to rise, but infrastructure has lagged the surging output leading to steep discounts at the region’s pricing hub. New pipelines in development should alleviate the regional bottleneck and support further production growth, particularly with the backdrop of a firmer global market. The Midland WTI discount to Cushing WTI averaged $10.26/b in May, widening from a $5.96/b discount in April, S&P Global Platts data shows. The Midland discount to Houston averaged $14.28/b, nearly doubling the $7.79/b average discount in April. In May 2017, the discount was just $2.28/b. While Midland WTI prices have been pressured lower because takeaway capacity is lagging production growth, crude prices on the Gulf Coast have been lifted by strong export demand for US crudes. Weekly US crude exports hit a record high 2.57 million b/d the week ending May 11, according to the US Energy Information Administration. Current pipeline takeaway capacity out of the Permian is roughly 3.1 million b/d, which combined with local refinery demand for Permian crude at just under 300,000 b/d falls short of production.Current price discounts have made moving crude by rail economical, although there is limited rail capacity. There is roughly 315,000 b/d of Permian Basin rail capacity, but much of that is now being used to move other commodities like frac sands.Plains All American, which is already trucking volumes from the Permian, said it sees limited opportunities for offering CBR services from its McCamey, Texas terminal, which can move up to 15,000 b/d as transloading facilities in the basin are geared more towards handling frac sand. Murex, along with Cetane Energy, said it will expand Cetane’s transloading facility at Carlsbad, New Mexico, boosting its CBR capacity by 40,000 b/d to 75,000 b/d in the third quarter. To meet the growing output, two waves of pipelines are being planned across Texas, offering a total of 3.1 million b/d of new takeaway capacity by mid-2020.

• **Gray Oak (Q3 2019 completion): Phillips 66 (75%) owner and Andeavor (25%) said in late April it has received shipper support to move ahead with the 700,000 b/d pipeline, and also launched an open season that could increase throughput on the line to 1 million b/d. The pipeline will move crude to Corpus Christi and to Sweeny/Freeport along the Houston Ship Channel and is targeted for start up in third quarter 2019.
• **EPIC Midstream (Q3 2019): The San Antonio-based company is working to bring on more shippers on its Eagle Ford Permian Ingleside and Corpus Christi pipeline for which it secured 75,000 b/d and 100,000 b/d of firm capacity, respectively, from Apache and Noble Energy. The pipeline is due for start up by the third quarter of 2019 and has increased capacity in the line to 675,000 b/d from 590,000 b/d. That figure may increase further to 825,000 b/d.
• **Cactus II (Q3 2019): Plains All American is moving ahead with the permitting, right of way and procurement process for the 650,000 b/d pipeline that it plans to bring into service in third quarter 2019. Cactus II will ship barrels from the Delaware Basin to the Port of Corpus Christi, and the adjacent Ingleside Terminal on the Texas Gulf Coast,
• **Midland to Nederland (2020): Energy Transfer Partners, which is in talks with shippers, said mid-May it will announce “very soon” strategic partners for the 600,000 b/d pipeline that will ship crude from Midland to Nederland on the USGC.
• **Jupiter (2020): An open season will be launched late summer by Dallas-based Jupiter Midstream for the pipeline, which will have a capacity of up to 500,000 b/d and will move barrels from the Permian to Brownsville on the southernmost tip of the Texas Gulf Coast.

New Mexico official says Texas landowners are “stealing” millions of gallons of water and selling it back for fracking – After you head northeast on Ranch Road 652 from tiny Orla, it’s easy to miss the precise moment you leave Texas and cross into New Mexico. The sign just says “Lea County Line,” and with 254 counties in Texas, you’d be forgiven for not knowing there isn’t one named Lea. But the folks who are selling water over it know exactly where the line is. That’s because on the Texas side, where the “rule of capture” rules groundwater policy, people basically can pump water from beneath their land to their heart’s content. But on the New Mexico side, the state has imposed tight regulations on both surface and groundwater that restrict supply. Here’s the rub – or the opportunity, depending on your perspective: With an oil fracking boom driving demand for freshwater on both sides of the state line in these parts, Texas landowners are helping to fill the void with water from the Lone Star State – including from at least one county in which Gov. Greg Abbott has declared a drought. Now a top New Mexico politician is crying foul, saying that unregulated pumping from wells next to the state line is depleting the shared aquifers that supply water to southern New Mexico. “Texas is stealing New Mexico’s water,” said New Mexico State Land Commissioner Aubrey Dunn. “If you put a whole bunch of straws in Texas and you don’t have any straws in New Mexico, you’re sucking all the water from under New Mexico out in Texas and then selling it back to New Mexico.” The difference in ownership of land in the two states contributes to the divergent water policies. In Texas, more than 90 percent of the land is privately owned. In New Mexico, by contrast, only 43 percent is owned by individuals, while 57 percent is in government or tribal hands.

Watchdog: Government isn’t sufficiently tracking costs from ‘orphaned’ oil, gas wells | TheHill: Costs to the government from dealing with “orphaned” oil and natural gas wells on federal land are likely increasing, the Government Accountability Office (GAO) said. But the Bureau of Land Management (BLM) doesn’t track the costs of dealing with such in an effective, agencywide way, the GAO concluded in a Tuesday report. “Precisely how the agency’s actual reclamation costs and potential liabilities have changed is unclear because BLM does not systematically track them at an agency-wide level,” GAO auditors wrote in their report.“BLM headquarters officials we interviewed told us that they did not have any information on actual costs incurred to reclaim orphaned wells and stated that BLM’s data systems were not designed to track incurred reclamation costs,” the auditors wrote. Orphaned wells are old oil and gas wells whose driller is unable to pay to reclaim them, usually due to bankruptcy. Auditors gathered data from 13 of the BLM’s 33 field offices to try to get their own estimate of orphaned well costs. That exercise found that those offices spent about $2.1 million between 2010 and 2017 on orphaned wells. The average cost were well was $267,600, compared with a $171,500 per well cost when GAO examined the issue in 2010. The total cost of reclamation for orphaned wells those offices knew about was $46.2 million. The GAO also found that the number of known orphaned wells across BLM lands has increased to 219 in 2017, from 144 in 2010.

Trump’s BLM Ready to Sacrifice Ancient Rock Art for Gas Drilling – While the Ancestral Puebloan people of the Southwest were building citadels like Chaco Canyon , the Fremont people were carving mysterious petroglyphs depicting horned, broad-shouldered triangular men and sweeping carvings of desert snakes. Nowhere is their legacy more apparent than in eastern Utah’s Molen Reef. Fremont artifacts dominate this cultural heritage site, but its rock art ranges from 3,000-year-old panels from the Barrier Canyon tradition to etchings by Mormon pioneers crossing the Utah desert. They aren’t easy to see, but that’s not a bad thing. You won’t find these cultural treasures on a map, and Jonathan Bailey, a Ferron, Utah-based photographer and author of Rock Art: A Vision of a Vanishing Cultural Landscape , thinks it should stay that way. “There are hundreds of rock art panels in the Molen Reef, and maybe a dozen are known,” he said. “They are mostly pristine, unexcavated sites that have very little vandalism.” Bailey worries about the resources being compromised by human activity before they can be cataloged and protected. But the Bureau of Land Management (BLM) has different plans for the area. In January 2018, the agency approved the leasing of 32,000 acres for mineral exploration between the San Rafael Swell and Molen Reef – just as it has in many other places in Utah . In Molen Reef, instead of highly publicized conservation efforts led by environmental organizations, tribal groups, or multibillion-dollar outdoor recreation outfitters, the resistance is being led by a scrappy group of rock art enthusiasts fighting to save the sites they love to explore. The Utah Rock Art Research Association (URARA) has been protesting oil and gas leasing in the area for years. The group works with environmental organizations and others because “wilderness concerns cross over with rock art concerns.” But it avoids taking partisan stances. “We’re an organization of both Republicans and Democrats,” said Diane Orr, cochair of URARA’s conservation and preservation committee. “Our concern with oil and gas leases is when the leasing process does not carefully look at all the resources in the area and really evaluate what needs to be protected.”

How Weakened Fossil Fuel Regulation Hurts Small Towns – From the start, President Donald Trump’s administration has made dismantling regulations, especially for the oil, gas, and coal industries, a top priority. Environmental Protection Agency Administrator Scott Pruitt, Interior Secretary Ryan Zinke, and Trump have teamed up with the Republican-led Congress to get federal agencies on the case, by streamlining environmental permitting and attempting other sweeping changes. As an environmental sociologist who has spent hundreds of hours researching communities directly affected by oil and gas production, I find that many people living in these places feel that fossil fuel industries already had the upper hand before Trump took office. Companies enjoyed significant exemptions from federal environmental regulations that date back to George W. Bush’s presidency and remained on the books throughout the Obama administration. After the enactment of the 2005 Energy Policy Act, the law that codified many of these exemptions, states became responsible for creating their own policies, procedures, budgets and enforcement plans – most of which weren’t in place before the boom got underway. The government exempted fracking from federal environmental regulations like the Safe Drinking Water Act and the Clean Water Act. States could decide rules like setbacks from homes, zoning, water acquisition and disposal, and most other aspects of drilling. This made it easier and quicker to permit hydraulic fracturing, but the states had to scramble to determine how to regulate it. As fracking spread into more densely populated areas, wells ended up within a few hundred feet of homes, schools, hospitals, and other buildings in states like Colorado, Texas, Pennsylvania and North Dakota. That made a big impact on people’s quality of life.But in places like Denton, Texas, and Colorado’s Front Range, the people who live in places most affected by these types of changes have no seat at the table. They live alongside oil fields and gas patches but have little power to affect what happens around them.

Journalist Cleared of Trespassing at Pipeline Protests (AP) – A journalist arrested last year while covering protests over the Dakota Access oil pipeline has been cleared of criminal trespass charges in North Dakota. Judge Thomas Schneider ruled Friday that Jenni Monet complied with police orders while reporting on the demonstration, the Bismarck Tribune reported . “It’s a great day for journalism and for North Dakota in recognizing the essential role that reporters play in shaping our democracy,” Monet said. “Today the court upheld our constitutional right to press freedom, which has never been more important than right now.” Monet was reporting for Yes! Magazine on police clearing a protest camp in Morton County when she and 75 others were arrested on Feb. 1, 2017, according to court records. Police testified the Last Child Camp sat on Dakota Access-owned property across from the main camp, but demonstrators alleged it was treaty land. Prosecutor Chase Lingle alleged Monet was guilty of criminal trespass for remaining on the property after police ordered the group to leave. “Journalists have no special right to accessing private property,” Lingle said. Lt. Tom Iverson of the North Dakota Highway Patrol had asked Monet and some others who said they were journalists for their press credentials, Monet said. She said she was the only one who displayed credentials and believed Iverson had consented to allowing her to remain on-site and report. A Beulah officer later arrested her. Schneider said Monet didn’t knowingly break the law when she stayed on the property. “I believe she thought she was licensed or privileged to be there,” he said. Monet said Friday that journalism is vital in “shining a light where there’s darkness, especially in marginalized communities like Standing Rock.”

Taxpayers Still Shelling Out Billions Annually in Fossil Fuel Subsidies – The world’s richest countries continue to subsidize at least $100 billion a year in subsidies for the production and use of coal , oil and gas , despite repeated pledges to phase out fossil fuels by 2025.The Group of Seven, or G7, consists of Canada, France, Germany, Italy, Japan, the UK and the U.S. The group, as well as the larger G20, agreed as early as 2009 to phase out fossil fuels in order to combat climate change .But a new report from Britain’s Overseas Development Institute (ODI) reveals that on average per year in 2015 and 2016, the G7 governments supplied at least $81 billion in fiscal support and $20 billion in public finance, for both production and consumption of oil, gas and coal at home and overseas.”With less than seven years to meet their 2025 phase-out deadline, G7 governments continue to provide substantial support the production and use of oil, gas and coal,” the authors stated .The study, co-authored by Oil Change International , the International Institute for Sustainable Developmentand the Natural Resources Defense Council , was issued Monday ahead of the G7 summit in Canada. For the study, each G7 member was rated on the following measures: transparency; pledges and commitments; ending support for fossil fuel exploration; ending support for coal mining; ending support for oil and gas production; ending support for fossil fuel-based power; and ending support for fossil fuel use. France ranked the highest overall, with 63 out of 100 points. While the country is lagging behind in its support for fossil fuel use, France earned the top spot for making early progress in ending fossil fuel exploration and production and ending coal mining, the researchers determined. Germany (62 points) and Canada (54 points) rounded out the top three in the dubious list.

New U.S. pipeline expected to lower natural gas prices in Central Canada: – Consumers in Ontario and Quebec can expect to pay less for natural gas to heat their homes as a new pipeline connects shale gas from the northeastern United States to the Dawn storage hub near Sarnia in southwestern Ontario. The Rover Pipeline last week won approval from the U.S. energy regulator to increase shipping to its capacity of 3.25 billion cubic feet per day of natural gas, transporting the fuel from Marcellus and Utica shale wells in the northeastern U.S. to American markets and, via the Vector Pipeline connection, to the Dawn hub for distribution in Central Canada. “Prices are as low as they’ve been in the last 10 years and there’s more downward pressure, because of the incremental supply, than there would be upward pressure,” said Chris Shorts, director of storage, transportation, marketing and utilization for Union Gas Ltd., operator of the Dawn hub. He said he couldn’t estimate what that will do to an average bill – consumer natural gas rates in Ontario and Quebec are affected by market gas prices but also take into account transmission and management costs. Union Gas last year increased its capacity to accept gas on the Vector connection by about 300 million cf/d to about 1.8 billion cf/d, he said, adding the actual amount delivered each day will vary according to sales contracts between shippers in the U.S. and buyers in Canada. Natural gas volumes arriving at Dawn are already being affected by about 1.4 billion cf/d in western Canadian natural gas added late last year after TransCanada Corp. brought in discount tolls to increase the use of its poorly utilized Canadian Mainline gas system, he said.

Canada promises climate progress and buys a pipeline instead – The Canadian government’s decision to buy a controversial oil pipeline project is drawing intense criticism from environmental groups and could open the door to legal challenges over its ability to meet the emissions reduction target the country promised to the Paris Climate Agreement.The Trudeau administration announced last week it would buy the Trans Mountain Pipeline from Houston-based Kinder Morgan for $3.5 billion. Kinder Morgan had threatened to walk away from a planned expansion of the pipeline, which has been mired in lawsuits, if the government could not assure the company it could proceed. Instead of providing assurance, Prime Minister Justin Trudeau decided to buy the whole pipeline and proceed with the expansion. Kinder Morgan secured federal permits in 2016 to build a pipeline parallel to its existing, 65-year-old one. It would increase the volume of crude it could move from the oil sands of Alberta to the coast of British Columbia from 300,000 barrels to 890,000 barrels per day, most of which will be shipped overseas. Kinder Morgan estimated that the new 715-mile pipeline will cost $5.72 billion to build.The government’s plan to own Trans Mountain is heightening the already intense criticism of Trudeau and his oft-repeated claim that the country can both boost oil production and reduce emissions by 30 percent from 2005 levels by 2030, the country’s commitment to the Paris Agreement.“Trudeau has beautiful speeches and a great reputation as environmentally progressive. But his actual policies involve taking actions on climate change as long as it doesn’t touch the oil industry,” said Keith Stewart, a senior energy strategist with Greenpeace Canada.

Canada pushes Trans Mountain pipeline to sell oil to China far beyond US shores – As it battles over trade with its big southern neighbor, Canada is looking westward for new markets for its oil.In the thick of a bitter trade dispute with the United States, the only customer for its crude oil, the Canadian government has opted to buy a pipeline project that will more than double the oil it can send to the West Coast – and then on to new markets in Asia.While the pipeline project has been moving on its own timeline, the purchase coincidentally comes during one of the thorniest periods in U.S.-Canadian trade relations. Analysts say ironically that should in fact help Canadian Prime Minister Justin Trudeau find some support for thecontroversial project, which has pit the province of British Columbia against Alberta and has prompted protests across the country.The construction is slated to begin this summer, but it is opposed by the British Columbia government, local governments, environmental interests and even groups in Washington state. Canada has long sought a pipeline solution, both to the east and west coast, and has so far failed. There is a lot to gain from moving its oil resources outside of North America, including much higher prices and access to the world’s fastest growing market.Trudeau‘s government late last month announced it would buy Trans Mountain pipeline, its British Columbia terminal and expansion project for about $3.5 billion, after owner Kinder Morgan Canada found the project too risky. Trudeau has said he wants to make sure the pipeline expansion gets built and then sold to a new operator so Canada can send oil on to new customers in Asia.”We are going to ensure that it gets built so that we can get our resources to new markets,” Trudeau told Bloomberg News.