Oil, Gas, And Fracking News Reads: 27October 2019 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 26 October 2019.

This article is a feature every Monday evening on GEI.

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

Largest drop in drilling activity in 6 months leaves oil rigs at a 30 month low, natural gas rigs at a 33 month low

Oil prices rose more than 5% over the past week on a surprise drop in US crude supplies, a promise of deeper output cuts from OPEC, and hopes for a U.S.-China trade deal…after falling 92 cents or 1.7% to $53.78 a barrel last week on a trade talks letdown and on a big jump in US oil supplies, the contract price of US light sweet crude for November delivery continued lower on Monday, after Commerce Secretary Wilbur Ross said a trade deal with China need not be finalized next month, feeding into worries that deepening global economic weakness would hurt demand for oil, prices for which ended down 47 cents, or 0.9%, at a two week low of $53.31 a barrel…but oil prices rebounded on Tuesday on a sentiment shift of concerns on both the UK’s Brexit and the U.S.-China trade war, and finished 85 cents higher at $54.16 a barrel, buoyed by a report that OPEC would consider deeper production cuts when they meet in December, as trading in the November oil contract expired…while the price of oil for delivery in December, which had risen 97 cents to $54.48 a barrel on Tuesday, initially started lower on Wednesday on an API report of a larger than expected build of US oil inventories, it quickly reversed and surged higher after the EIA’s data showed a surprise draw from U.S. crude stocks, and ultimately closed $1.49, or 2.7% higher at $55.97 per barrel….oil prices then extended that gain on Thursday, with US light sweet crude rising 26 cents to $56.23 a barrel, as the surprise drop in U.S. crude inventories and the prospect of further OPEC cuts offset the demand uncertainty stemming from the trade war and Brexit….oil prices continued rising on Friday after administration officials said they were close to finalizing the first part of a trade deal with China after months of a tariff war and finished the day 43 cents, or 0.8%, higher at $56.66 a barrel, thus ending up over 5% for the week as the news of progress on the so-called ‘phase one’ of a U.S.-China trade deal eased concerns over a slowdown in economic growth and energy demand…

Natural gas prices, on the other hand, fell for a fifth week in the past six as last week’s forecasts for a cold weather outbreak moderated and shifted west….after rising 4.8% to $2.320 per mmBTU last week on forecasts for colder than normal temperatures for the broad midsection of the country, the contract price of natural gas for November delivery gave up most of those gains on Monday as the cold forecast by the weather models weakened over the weekend and withdrew to the Rockies, leaving the large population centers in the East and the Midwest near normal, as natural gas prices fell 8.2 cents…gas prices recovered 3.4 cents on Tuesday and another penny on Wednesday as the 6 to 10 day forecast indicated the cold would spread to the south central states, and then gained another 3.4 cents on Thursday after the natural gas storage report showed a smaller inventory increase than analysts had expected…however, natural gas prices then slipped back 1.6 cents on Friday to end the week at $2.300 per mmBTU, down 2 cents or less than 1% for the week…

The natural gas storage report for the week ending October 18th from the EIA indicated that the quantity of natural gas held in storage in the US increased by 87 billion cubic feet to 3,606 billion cubic feet by the end of the week, which meant our gas supplies were 519 billion cubic feet, or 16.8% more than the 3,087 billion cubic feet that were in storage on October 18th of last year, and 28 billion cubic feet, or 0.8% above the five-year average of 3,578 billion cubic feet of natural gas that have been in storage as of the 18th of October in recent years….this week’s 87 billion cubic feet injection into US natural gas storage was somewhat lower than the average forecast for a 92 billion cubic feet injection from analysts surveyed by S&P Global Platts, but it was well above the average 73 billion cubic feet of natural gas that have been added to gas storage during the third week of October over the past 5 years, the 30th such average or above average storage build in the last 32 weeks…the 2,428 billion cubic feet of natural gas that have been added to storage over the 30 weeks of this year’s injection season is the second most for the same period in the modern record, eclipsed only by the record 2482 billion cubic feet of natural gas that were injected into storage over the same 30 weeks of the 2014 natural gas injection season, a cool summer when there were no injections below 76 billion cubic feet….

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending October 18th showed that because of a decrease in our oil imports, an increase in our oil exports, and a pickup in our oil refining, we needed to withdraw oil from storage for the first time in 6 weeks…our imports of crude oil fell by an average of 438,000 barrels per day to an average of 5,857,000 barrels per day, after rising by an average of 70,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 435,000 barrels per day to an average of 3,683,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,174,000 barrels of per day during the week ending October 18th, 873,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, the production of crude oil from US wells was reported to be unchanged at a record 12,600,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from well production totaled an average of 14,774,000 barrels per day during this reporting week..

US oil refineries were reportedly processing 15,865,000 barrels of crude per day during the week ending October 18th, 429,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that a net average of 385,000 barrels of oil per day were being withdrawn from the supplies of oil stored in the US….hence, we can see that this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 706,000 barrels per day less than what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA inserted a (+706,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”….with that much oil unaccounted for again this week, it means that one or all of the oil metrics that the EIA has reported and that we have just transcribed have to be seriously off the mark…however, since the media treats these figures as gospel and since they drive oil pricing and hence decisions to drill, we continue to report them as they’re seen & believed by everyone else (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports fell to an average of 6,167,000 barrels per day last week, now 19.5% less than the 7,664,000 barrel per day average that we were importing over the same four-week period last year….the 385,000 barrel per day net withdrawal from our total crude inventories included 242,000 barrels per day that were pulled out of our commercially available stocks of crude oil and a withdrawal of 143,000 barrels per day from our Strategic Petroleum Reserve….this week’s crude oil production was reported to be unchanged at a record 12,600,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at a record 12,100,000 barrels per day, and because Alaska’s oil production was unchanged at 485,000 barrels per day…last year’s US crude oil production for the week ending October 19th was rounded to 10,900,000 barrels per day, so this reporting week’s rounded oil production figure was 15.6% above that of a year ago, and 49.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 85.2% of their capacity in using 15,865,000 barrels of crude per day during the week ending October 18th, up from 83.1% of capacity the prior week, but still somewhat below the normal, even for a refinery maintenance season…hence, the 15,865,000 barrels per day of oil that were refined this week was 2.5% below the seasonal low 16,268,000 barrels of crude per day that were being processed during the week ending October 19th, 2018, when US refineries were operating at 89.2% of capacity….

With the increase in the amount of oil being refined, gasoline output from our refineries was also higher, increasing by 100,000 barrels per day to 10,098,000 barrels per day during the week ending October 18th, after our refineries’ gasoline output had decreased by 68,000 barrels per day the prior week….with that increase in gasoline output, this week’s gasoline production was 4.1% lower than the 10,028,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) rose by 77,000 barrels per day to 4,765,000 barrels per day, after our distillates output had decreased by 147,000 barrels per day over the prior week…since our distillates production is still down by a total of 567,000 barrels per day over the past 5 weeks, our distillates’ production this week was still 3.9% below the 4,960,000 barrels of distillates per day that were being produced during the week ending October 19th, 2018….

Even with the modest increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 12th time in 18 weeks and for the 26th time in thirty-three weeks, falling by 3,107,000 barrels to 223,094,000 barrels during the week to October 18th, after our gasoline supplies had decreased by 2,562,000 barrels over the prior week….the decrease in our gasoline supplies was larger this week because the amount of gasoline supplied to US markets increased by 236,000 barrels per day to 9,590,000 barrels per day, while our imports of gasoline rose by 44,000 barrels per day to 697,000 barrels per day and while our exports of gasoline fell by 156,000 barrels per day to 625,000 barrels per day….after this week’s decrease, our gasoline supplies were 2.7% lower than last October 19th’s inventory level of 229,330,000 barrels, and but remained roughly 2% above the five year average of our gasoline supplies for this time of the year…

Likewise, with the increase in our distillates production, our supplies of distillate fuels fell for the 20th time in the past 30 weeks, decreasing by 2,715,000 barrels to 120,786,000 barrels during the week ending October 18th, after our distillates supplies had decreased by 3,823,000 barrels over the prior week…our distillates supplies fell by less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, decreased by 290,000 barrels per day to 4,076,000 barrels per day, while our exports of distillates rose by 144,000 barrels per day to 1,209,000 barrels per day while our imports of distillates fell by 64,000 barrels per day to 133,000 barrels per day…after this week’s inventory decrease, our distillate supplies were down by 7.4% from the 130,376,000 barrels of distillates that we had stored on October 19th, 2018, and fell to around 12% below the five year average of distillates stocks for this time of the year…

Finally, with this week’s refinery pickup coupled with the decrease in our net oil imports, our commercial supplies of crude oil in storage fell for the twelfth time in nineteen weeks and for the seventeen time in 39 weeks, decreasing by 1,699,000 barrels, from 434,850,000 barrels on October 11th to 433,151,000 barrels on October 18th….that decrease knocked our crude oil inventories back to the five-year average of crude oil supplies for this time of year, and back to around 30% higher than the prior 5 year (2009 – 2013) average of crude oil stocks as of the third weekend of October, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories had generally been rising over the past year up until July, after generally falling until then through most of the prior year and a half, our oil supplies as of October 18th were still 2.5% above the 422,787,000 barrels of oil we had stored on October 19th of 2018, but at the same time were 5.3% below the 457,341,000 barrels of oil that we had in storage on October 20th of 2017, and 7.5% below the 468,158,000 barrels of oil we had in commercial storage on October 21st of 2016…

This Week’s Rig Count

The US rig count fell for the 9th time in 10 weeks and for the 32nd time in 36 weeks over the week ending October 25th, and is now down by 23.4% since the end of last year….Baker Hughes reported that the total count of rotary rigs running in the US fell by 21 rigs to a 30 month low of 830 rigs this past week, the largest drop in 6 months, down by 238 rigs from the 1068 rigs that were in use as of the October 26th report of 2018, and well less than half of the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began their attempt to flood the global oil market…

The count of rigs drilling for oil decreased by 17 rigs to a 30 month low of 696 oil rigs this week, which was also 179 fewer oil rigs than were running a year ago, and quite a bit below the recent high of 1609 rigs that were drilling for oil on October 10th, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations fell by 4 rigs to 133 natural gas rigs, the least natural gas rigs since December 30 2016 and hence a 33 month low for gas rig drilling activity, down by 60 rigs from the 193 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition, a vertical rig classified as miscellaneous continued to drill on the big island of Hawaii this week, in contrast to a year ago, when there were no such “miscellaneous” rigs deployed..

Gulf of Mexico offshore drilling activity decreased by 1 rig to 20 Gulf rigs running this week, as a rig that had been drilling offshore from Louisiana was shut down…that still left 20 rigs drilling in Louisiana’s offshore waters, 2 more rigs than the Gulf of Mexico rig count of 18 a year ago, when 17 rigs were drilling in Louisiana waters and one was drilling offshore from Texas…in addition to the Gulf, one rig continues to drill offshore from the Kenai Peninsula in Alaska, which matches the offshore Alaska count of a year ago…hence, the national total of 21 offshore rigs is up by 2 rigs from the 19 rigs that were deployed offshore a year ago…

The count of active horizontal drilling rigs was down by 17 rigs to 728 horizontal rigs this week, which was the least horizontal rigs deployed since April 28th, 2017 and hence is a new 30 month low for horizontal drilling…that was also 199 fewer horizontal rigs than the 927 horizontal rigs that were in use in the US on October 26th of last year, and also well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….in addition, the directional rig count was down by 4 rigs to directional rigs this week, and those were down by 22 from the 72 directional rigs that were operating during the same week of last year…on the other hand, the vertical rig count was unchanged at 51 vertical rigs this week, while those were down by 17 from the 68 vertical rigs that were in use on October 26th of 2018…

The details on this week’s changes in drilling activity by state and by major shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of October 25th, the second column shows the change in the number of working rigs between last week’s count (October 18th) and this week’s (October 25th) count, the third column shows last week’s October 18th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 26th of October, 2018…

We again have a problem with the Permian basin rig count this week, since the Rigs by State – Current and Historical excel file from Baker Hughes appears to show a drop of 7 rigs in the Texas Oil Districts that encompass the Texas portion of that basin…. Texas Oil District 8, or the core Permian Delaware, shows 266 rigs deployed, a drop of 3 from last week; Texas Oil District 8A, or the northern Permian Midland, shows 13 rigs remaining active, a drop of two from a week ago, while Texas Oil District 7C, or the southern Permian Midland, has 26 rigs remaining, also a drop of two rigs from a week ago…last week we had rig additions in those districts that were two greater than the Permian basin increase, and we assumed that those 2 additional rigs were in the same region but not targeting the Permian…however, since we hadn’t seen that happen before, and since it has been reversed this week, it’s possible that last week’s Permian count was in error and this week’s count corrected it…as i noted last week, one could search the North America Rotary Rig Count Pivot Table (xls), which has individual well records going back to February 2011, to see what the actual changes were, but unless one knew offhand which counties were in each of those Texas oil districts. it would likely be an all day chore…

At any rate, with the Texas Permian basins showing a 7 rig decrease this week, it seems likely that the rig that was pulled from New Mexico was not a Permian rig…meanwhile, the 6 rig decrease in Oklahoma appears to include the 2 oil rigs pulled out of the Cana Woodford, the single oil rig pulled out of the Ardmore Woodford, 2 rigs pulled out of basins not tracked separately by Baker Hughes, and an oil rig that had been drilling in the Granite Wash, since Texas Oil District 10, or the Texas side of that basin, saw a 1 rig increase….elsewhere, the 2 oil rigs pulled out of the Williston basin match the North Dakota count, and the rig pulled out of the Gulf of Mexico accounts for 1 rig decrease in Louisiana…however, the two rig decrease in Wyoming probably includes a rig that had been drilling in the Denver-Julesburg Niobrara chalk, since Colorado saw a one rig increase….meanwhile, among rigs targeting natural gas, this week saw two rigs pulled out of the Marcellus, one each from Pennsylvania and from West Virginia, and two rigs removed from those “other basins” not tracked separately by Baker Hughes…we would also note that other than the major producing states listed in the table above, both Alabama and South Dakota saw single rigs removed this week, leaving both states with no drilling at this time…a year ago, Alabama had one rig deployed, while South Dakota had none…

Environmentalists question use of radioactive brine waste to treat roads – – As temperatures continue to dip, it will only be a matter of time before road crews across the state head out in the wee hours to pre-treat roads for snow and ice. Many will use processed brine waste from an oil and gas drilling practice known as fracking. That concerns environmentalists, who say the practice could raise levels of radium, a radioactive metallic element found in the brine, in soil and groundwater. “This is just not something that should be spread around our communities haphazardly. It needs to be stopped, period. If you can’t find something better to do with this waste, then stop producing it,” said Teresa Mills, a member of the Buckeye Environmental Network, a nonprofit environmental-justice group. Radium-226 and radium-228, both found in brine waste, are known human carcinogens and can lead to bone, liver, and breast cancer if levels are high enough, according to the U.S. Centers for Disease Control and Prevention. Ohio law allows only brine produced from vertical wells, or conventional wells, to be spread as a de-icer. “The (Ohio Department of Natural Resources Division of Oil & Gas Resources Management) has collected brine samples from both brine hauler trucks and wells. These samples are helping the division to establish baseline radiological data on naturally occurring radioactive material in produced brine from different geological formations.” said ODNR spokesman Adam Schroeder. Data from state testing shows that in at least one case there were 9,602 picocuries per liter for combined amounts of radium-226 and radium-228. The lowest level was 66. Ohio law allows no more than 0.005 picocuries of radium per liter of oil and gas waste placed in landfills. Yet the law allows for processed brine waste to be spread on Ohio’s roadways, and because it is a naturally occurring byproduct of drilling the state does not cap radiation levels. Despite the high radiation levels in some cases, state agencies and others don’t see a problem with its use. “Recent models from both the Ohio Department of Health and the Pennsylvania Department of Environmental Protection show that controlled application of brine containing naturally occurring radioactive material offers a negligible risk to human health,” Schroeder said.

Heaven Sensky: How many more of my friends have to die before Pa. takes action? – Nearly 2,000 deep shale gas wells have been drilled and fracked in Washington County. Earlier this month, the Pennsylvania Department of Health held a public meeting at Canon-McMillan High School to defend its claim that there is no cancer cluster in our region. Twelve children and young adults have been diagnosed with rare Ewing sarcoma cancers between 2011 and 2018, and many affected parents have expressed grave concern over the impacts of oil and gas development. As a 2015 graduate of Canon-McMillan, this issue is close to my heart. I have watched my friends and classmates suffer. I have had to deal with more cancer diagnoses than anyone should have to. I feel so wholeheartedly that what is happening in our backyards is the issue of our time here in southwestern Pennsylvania that I changed my career path and sought work in environmental justice. Parents whose children have been affected by the high occurrence of rare tumors want the state to take a closer look to see if the natural gas industry or other environmental causes could be to blame. Residents across the community have been tirelessly making the case to our elected officials that it’s their duty and responsibility to seek answers.For centuries, we have systematically been swallowed up and spit back out by fossil-fuel companies extracting oil and gas from our land. The industry takes and takes from us until there is nothing left but death and destruction. When we are no longer deemed “profitable,” it’s on us to clean up the mess industry has made. We suffer the consequences of the predictable economic bust. All the while, our elected officials serve the industry in the name of “economic prosperity,” aiding hedge-fund companies that always have and always will prioritize profits over people. And now, the mess the industry is leaving us includes dying children. What Department of Health representatives didn’t say is that not all of the cases present in Canon-McMillan were considered in its study. What they didn’t say is that the two state representatives who commissioned the study are supported financially by the oil and gas industry. The natural gas industry continues to expand – now with even fewer regulations – right in our backyards. Chemicals and radium are being spewed into our drinking water sources and into our air. We do not have time for 20 more years of research before we acknowledge that something is wrong. How many more families have to suffer before we take this impact seriously? How many more of my friends have to die before Gov. Tom Wolf stops trading political deals to protect the natural gas industry at the expense of my community?

Third Sink Hole Discovered on Mariner East Pipeline 4 Feet Wide & 30 Feet Deep – A third “sinkhole” has opened up along the Mariner East pipeline construction route in Middletown Township in Sleighton Park. A Middletown Township release reads that at 3:30 p.m. Thursday, township staff was contacted by Delaware County emergency services staff regarding a potential “subsidence” at Sleighton Park. It is believed that an 18-inch hole developed at the site, which was quickly filled in by workers with concrete. It marks the second sinkhole at Sleighton Park, with a third which developed near the state police barracks on US Route 1. Township staff responded within 15-minutes to discover an 18-inch diameter hole formed north of Forge Road, south of the existing sound barriers, that “may have been from previous potholing completed by Sunoco for the 16-inich pipeline,” reads a township release. The void was filled with flowable fill by the time township staff who arrived on scene; it was reported that 48 yards of material was used to fill the void. Nils Hagen-Frederiksen, of the Public Utility Commission, said the uncovered pipeline was active at the time of the repairs but was not necessarily moving product. The 18-inch hole was the opening of a subsidence that fanned out to approximately 4 feet in width and 30 feet in depth, as it was reported to the township. The PA-PUC was on site prior to the subsidence being filled to confirm its condition, reads the township report. “The PUC viewed the situation as not an immediate threat, but it is an open and ongoing investigation.” The PA-DEP was also on site and determined the situation was not an immediate threat. A 12-inch pipe that was likely active was partially exposed within the subsidence or “sinkhole;” It was reported that approximately 18-36 inches of the pipe was exposed and unsupported. County emergency services staff completed air monitoring for gas at the location of the subsidence and within the immediate surrounding area. Results were negative, reads the township report. Township staff departed the site as the respective agencies did not find any breach in the pipeline(s), no immediate threat was present, the void was filled, and restoration completed at this time.

In court, seven people who live near Mariner East pipelines will urge a regulator to stop the project for good. It might be their last chance | StateImpact Pennsylvania – Almost a year after Sunoco started pumping natural gas liquids through the controversial and still unfinished Mariner East pipelines, and less than two months after Gov. Tom Wolf publicly ruled out stopping the lines, seven residents of Chester and Delaware counties are preparing to argue in court that the Public Utility Commission should halt the project. The plaintiffs will appear before Elizabeth Barnes, a PUC administrative law judge, in a West Chester courtroom on Oct. 23 and 24 to try to convince her that the pipeline project remains a danger to public safety, and that Sunoco has failed to help the public understand how to ensure their safety if there is a leak or explosion. It could be the last chance for pipeline opponents to stop the project, which has been plagued with technical, environmental and legal problems since it started construction in February 2017. It was temporarily shut down once by Pennsylvania’s Environmental Hearing Board and twice by the PUC – including once by Barnes, following the appearance of sinkholes in West Whiteland, Chester County in May 2018. But it has always been allowed to restart. Sunoco admitted in February 2019 that it made mistakes during construction, and pledged to put them right, but has insisted throughout that the project meets all state and federal regulatory requirements. The plaintiffs’ attorney, Michael Bomstein, said his clients believe that their safety, and that of their neighbors, is being put at risk in part by the eight-inch Mariner East 1 line, a 1930s-era pipe that once carried gasoline across Pennsylvania from east to west, and was repurposed in 2014 to carry highly volatile natural gas liquids in the opposite direction. They are also worried by Sunoco’s use of a repurposed 12-inch line as part of the Mariner East network until its new 16- and 20-inch lines are complete, Bomstein said. Both of the repurposed lines are “dangerously corroded and should be shut down,” he said. The PUC’s Bureau of Investigation and Enforcement concluded that a leak of natural gas liquids from Mariner East 1 at Morgantown, Berks County in April 2017 was caused by corrosion in the 1930s-era pipe. In September 2018, the federal Pipeline and Hazardous Materials Safety Administration said that the 12-inch line leaked 33,000 gallons of gasoline into a creek near Philadelphia. The line, installed in 1937, had leaked at least twice before, records show.

Several Chester, Delaware county residents urge PUC judge to shut down Mariner East pipelines, citing fears of leak or explosion –Seven residents of Chester and Delaware counties took their long-running fight against the Mariner East pipelines to a West Chester court on Wednesday, saying the Public Utility Commission should shut down the lines on the grounds that they are a danger to public safety. They are urging a PUC administrative law judge to halt the operation and remaining construction of Sunoco’s still-unfinished pipeline project, on the grounds that any leak or explosion of natural gas liquids from the pipelines in densely populated suburbs like the two counties could result in mass casualties. The plaintiffs are also seeking a court order that would require Sunoco to clarify its instructions on how residents should protect themselves in the event of a pipeline accident. The hearing, taking place almost a year after Sunoco started operating a hybrid version of the new line, was the latest opportunity for the plaintiffs to argue their case in a judicial setting, and may represent their last chance to halt the project. During 3 1/2 hours of hearing on Wednesday morning, Judge Elizabeth Barnes rejected a request by Sunoco attorneys to limit the testimony of lay witnesses on the grounds that they were not qualified to offer expert opinions on issues like the impacts of a pipeline explosion. “In general, my ruling is a lay person can testify on their opinion,” the judge said. But she said those witnesses would not be allowed to use hearsay reports on matters that they are not experts on. Lawyers for Sunoco repeatedly accused Eric Friedman, a witness for the plaintiffs, of offering expert evidence that he was not qualified to give, but Barnes overruled several of their objections. Under questioning from the plaintiffs’ attorney, Michael Bomstein, Friedman said a consultant’s projection on the impact of an explosion of NGLs showed that there would be fatalities within a radius of 800 feet. Under that scenario, all 39 houses in his Andover subdivision in Delaware County would be affected by any leak of natural gas liquids, Friedman said. Using proprietary software, the consultant, Quest, showed that there would be fatalities caused by a shock wave and thermal radiation, Friedman said. Robert Fox, an attorney for Sunoco, argued unsuccessfully that Friedman’s comments on the modeling amounted to expert testimony. “We’ve been clear from the beginning, this is lay witness testimony.

Will the Public End up Paying to Clean up the Fracking Boom? -Increasingly, U.S. shale firms appear unable to pay back investors for the money borrowed to fuel the last decade of the fracking boom. In a similar vein, those companies also seem poised to stiff the public on cleanup costs for abandoned oil and gas wells once the producers have moved on.“It’s starting to become out of control, and we want to rein this in,” Bruce Hicks, Assistant Director of the North Dakota Oil and Gas Division, said in August about companies abandoning oil and gas wells. If North Dakota’s regulators, some of the most industry-friendly in the country, are sounding the alarm, then that doesn’t bode well for the rest of the nation.In fact, officials in North Dakota are using Pennsylvania as an example of what they want to avoid when it comes to abandoned wells, and with good reason.The first oil well drilled in America was in Pennsylvania in 1859, and the oil and gas industry has been drilling – and abandoning – wells there ever since. Pennsylvania’s Department of Environmental Protection (DEP) says that while it only has documentation of 8,000 orphaned and abandoned wells, it estimates the state actually has over a half million.“We anticipate as many as 560,000 are in existence that we just don’t know of yet,” DEP spokesperson Laura Fraley told StateImpact Pennsylvania. “There’s no responsible party and so it’s on state government to pay to have those potential environmental and public health hazards remediated.” According to StateImpact, “The state considers any well that doesn’t produce oil and gas for a calendar year to be an abandoned well.” The Government Accountability Office (GAO) released a report this September about the risks from insufficient bonds to reclaim wells on public lands. It said, “the bonds operators provide as insurance are often not enough to cover the costs of this cleanup.” The report cited a Bureau of Land Management (BLM) official’s estimate of $10 a foot for well cleanup costs. StateImpact Pennsylvania noted that costs to reclaim a well could add up to $20,000, and DEPspokesperson Fraley said they could be “much, much higher.” The GAO report noted that “low-cost wells typically cost about $20,000 to reclaim, and high-cost wells typically cost about $145,000 to reclaim.”

Pa. Health department has collected just 160 complaints on oil and gas production in nearly a decade – Despite a natural gas boom and health concerns over drilling from environmentalists, the state Department of Health has received just 160 complaints related to drilling over the last decade. On Thursday, Stephanie Hasanali, of the department’s Bureau of Epidemiology, briefed a state oversight committee charged with approving environmental regulations on the data the agency has collected since 2011. The state Department of Environmental Protection, meanwhile, received 9,000 complaints about environmental issues between 2004 and 2016, Hasanali told the Air Quality Technical Advisory Committee, which is part of DEP. At least early on, the Department of Health wasn’t responding to complaints, according to StateImpact, an NPR project covering natural gas development. The outlet found in June 2014 that department managers under former Gov. Tom Corbett advised employees not to talk to anyone who called and mentioned fracking-related keywords.The process was updated soon afterwards to send return letters to complainants acknowledging their call. Hasanali added Thursday that next steps for the department could include outreach to increase awareness of the complaint process.

Viewpoints: The natural gas pipeline approval sham – The Federal Energy Regulatory Commission (FERC) in 2017 granted National Fuel Gas Supply Corp. Section 7, National Gas Act, certificate of public convenience and necessity to build a new, 99-mile long, natural gas pipeline – the Northern Access Project – linking the company’s western Pennsylvania gas fields and existing pipelines in the Buffalo area. Since then, landowners and public officials in New York communities located along the proposed pipeline’s route have charged that the Northern Access pipeline is neither a public convenience nor a public necessity; that National Fuel, not the American public, desperately needs the added pipeline capacity for export purposes. Necessity for whom? They ask, how can FERC declare this pipeline in America’s public interest when National Fuel has contracted to sell 72% of the gas to Canadian customers? Environmental, wildlife and property risks during construction of a 75-foot wide right-of-way from Pennsylvania to Buffalo, and burying a 24-inch pipeline, will be borne here at home while the gas will benefit foreign customers. Directing its attention to this very issue, a Sept. 6, 2019, opinion issued by the U.S. Court of Appeals for the District of Columbia Circuit, involving a pipeline-for-export case in Ohio, The court pointed out that Section 7 of the Natural Gas Act grants FERC authority to issue certificates of public convenience and necessity for “the transportation in interstate commerce” and that the courts have not interpreted interstate commerce to include foreign commerce. Federal and state governments, according to the eminent domain “taking clause” of the U.S. Constitution, may only condemn private property for public purposes, like building public schools and roads. FERC’s certificate, however, conveys to National Fuel the federal eminent domain powers to use condemnation courts for corporate purposes. Landowners along the pipeline’s route argue that giving the power to seize land to a private company for the purpose of profiting from the sale of American natural gas to foreign customers is not in the public’s interest.

Trump promotes ‘pro-energy’ policies in Pittsburgh – President Donald Trump took credit for Pennsylvania’s booming oil and gas industry on Wednesday.Speaking to a crowd of industry professionals and political supporters at the David L. Lawrence Convention Center in Pittsburgh, Trump applauded his administration’s support for domestic energy production at the Shale Insight Conference. A fervid supporter of deregulation, Trump took responsibility for a thriving fossil fuels industry and historically low unemployment in the region. By rolling back “job-killing” climate policies and greenhouse gas emission standards, he said his administration has restored energy dominance in the United States.“I promised that, as president, I’d unleash American energy like never before, because our natural resources do not belong to the government,” he said. “They belong to the people of this country. And I am proud to declare that I have delivered on every single promise I made.” During his time in office, Trump has revoked former-President Barack Obama’s Clean Power Plan and Stream Protection Rule, approved the controversial Dakota Access and Keystone XL pipelines and pledged to pull out of the Paris Climate Accord. On Wednesday, he renewed his commitment to leaving the climate agreement. “My job is to represent the people of Pittsburgh, not the people of Paris,” he said. It was the president’s second appearance at the conference since 2016 and his second visit to western Pennsylvania since August, when he toured Shell Chemicals’ ethane cracker plant in Potter Township. “Shell’s gigantic new petrochemical plant is one of the biggest in the world,” he said. “It will create more than 600 new Pennsylvania jobs, thousands of construction jobs and provide a tremendous boost to the local economy.” The complex will produce more than a million tons of plastic annually using ethane from nearby Marcellus and Utica shale reservoirs. The Marcellus Shale is the country’s largest natural gas field, stretching from New York to West Virginia and parts of Ohio. More than 70 percent of all Marcellus-related jobs are filled by Pennsylvanians, Marcellus Shale Coalition representatives said.

Pennsylvania’s gas politics churn as Trump embraces industry – Star Tribune – President Donald Trump promoted his support for the natural gas industry Wednesday, making clear on his second visit to Pennsylvania in the past three months that he sees his pro-industry policies as a boost to his chances of winning the battleground state in 2020. As some of his leading Democratic opponents call for a fracking ban, Trump has been eager to cut a contrast, touting his support for a sector he says brings economic benefits to rural pockets and jobs to construction union workers. But pipeline politics might not be so clear-cut. In the suburbs that might be key to his path to victory, Pennsylvania voters have shown a growing opposition to the drilling and massive pipelines required to move its product across the state. Candidates in state and local races are increasingly hardening their stances on the industry. National polling shows growing skepticism of fracking, the process used in extraction. While the issue is unlikely to be the one that turns a race already dominated by Trump’s strong personality, a looming impeachment fight and accusations of racism, Trump’s eagerness to promote the industry underscores his tight focus on shoring up his base of rural voters, even at the risk of alienating others. “Today, I’m proud to declare that I’ve delivered on every single promise I made to this conference three years ago and much, much more,” Trump said at an energy conference in Pittsburgh, a corporate hub of activity in the Marcellus Shale, the nation’s most prolific natural gas reservoir. Trump reminded the audience that he overturned the Clean Power Plan, put forward by his predecessor, former President Barack Obama, to fight climate change. “Sounds nice but it wasn’t nice,” Trump, a climate change skeptic, said of the plan. “It was a disaster.” The president also highlighted his decision to pull the U.S. out of the Paris climate agreement, a multinational pact designed to reduce the emission of gases that contribute to global warming. Trump has argued that the agreement entered into during the Obama years would have restricted the U.S. but allowed foreign producers to “pollute with impunity.” “My job is to represent the people of Pittsburgh, not the people of Paris,” the president said as the audience cheered.

‘Unleash American energy’: Trump touts administration’s moves during Pittsburgh stop The Star Beacon – Speaking to a mixed crowd of natural gas industry representatives and rank-and-file western Pennsylvania supporters on Wednesday, President Donald Trump said he is bringing an end to “the war on American energy.”He made the comment during the annual Shale Insight convention inside Pittsburgh’s David L. Lawrence Convention Center.Trump, a Republican, recalled when he addressed the same conference during his 2016 campaign. Since then, Trump’s administration has issued permits for the Keystone XL Pipeline and Dakota Access Pipeline, rolled back the Clean Power Plan, opposed participation in the Paris Agreement, repealed the Stream Protection Rule, revoked Waters of the United States, and opened offshore federal lands and the Arctic National Wildlife Refuge for oil and gas exploration.“Today, I’m proud to declare that I delivered on every single promise I made to this conference three years ago and much, much more,” Trump said.He called 2016 a time when “American energy was under relentless assault from the previous administration.”Trump continued: “Federal regulations and bureaucrats were working around the clock to shut down vital infrastructure projects, bankrupt producers and keep America’s vast energies and treasures buried deep under ground. They didn’t want to let you go get them. So, good for the American people in so many ways. I promised that as president I’d unleash American energy like never before because our natural resources do not belong to the government, they belong to the people of this country.”He focused on several specific issues, including the 2015 Paris Agreement – a plan, adopted by the United Nations Framework Convention on Climate Change, to deal with greenhouse gas emissions – that has the support of more than 180 nations. President Barack Obama, a Democrat, backed the accord.Trump opposed what he considered to be a “terrible, one-sided” plan. The administration can submit notice on Nov. 4 to begin the one-year clock to formally withdraw from the climate pact. “What we won’t do is punish the American people, while enriching foreign polluters,” Trump said. “Because, I can say it, right now, and I’m proud to say it, it’s called ‘America first’ – finally. My job is to represent the people of Pittsburgh, not the people of Paris.”

Remarks by President Trump at 9th Annual Shale Insight Conference | Pittsburgh, PA – Whitehouse.gov (speech transcript)

Trump hails U.S. oil and gas industry, blasts Democrats as ‘anti-energy zealots’ – President Trump promoted his record on U.S. energy production Wednesday during a trip to Pittsburgh that sounded more like a campaign rally than a policy discussion.Speaking at the annual Shale Insight Conference, Mr. Trump told oil and gas industry workers that Democrats “want to ban shale energy.”“Anti-energy zealots are blinded by ideology,” Mr. Trump said, referring to liberals’ proposed Green New Deal. “The radical policies of Democrats in Congress would result in massive layoffs.”Pennsylvania has experienced an energy boom in recent years through the production of natural gas from shale fracking, a process of hydraulic drilling. Mr. Trump won the state narrowly in 2016, but is trailing Democratic front-runner Joseph R. Biden by about 10 percentage points in polls of head-to-head matchups.At a campaign appearance in his native Scranton Wednesday, Mr. Biden accused the president of having forgotten America’s “forgotten people.” The president said his plans will bring even more jobs to the energy-rich landscape of Ohio, West Virginia and Pennsylvania. “Our goal is to bring 100,000 energy jobs to Appalachia and to rebuild this magnificent region … which was forgotten too long by the Democrats,” Mr. Trump said.

Marcellus Fracking Means Farewell to Dems in 2020 – With Quid Pro Joe Biden’s confession to using U.S. resources to pressure a foreign government to benefit his son, maybe in the next Democrat debate, one of the questions will be why, if fossil fuels are evil, the Democrats are committed to ending their use, and we have a decade or so to live before we freeze our hoohahs to death, it was okay for Hunter Biden to sit on the board of Burisma, a Ukrainian natural gas holding company. Seems Hunter had his very own greenback new deal.As President Trump’s speech at the Shale Insight Conference in Pittsburgh, Pennsylvania on Wednesday noted, Joe Biden’s mythical claim that Trump inherited a booming economy from President Obama falls flat in the face of the reality that this is Trump’s economy, fueled by deregulation, tax cuts, cutting of EPA shackles, and a booming energy industry allowed to use the latest technology to free a seemingly endless supply of oil and natural gas from the earth under our feet. The conference was staged by some very appreciative energy groups such as the Marcellus Shale Coalition, the Ohio Oil and Gas Association, and the West Virginia Oil and Natural Gas Association.This energy abundance has put downward pressure on energy costs for consumers and industry and made us energy independent and immune from Middle East instability, quite possibly preventing a global oil recession or major war with the likes of a belligerent and aggressive Iran.While noting that he has opened up ANWR in Alaska for exploration and development, exited the job-killing and economy-choking Paris Climate Accord, and green-lighted the Keystone XL and Dakota Access pipelines, Trump pointed out the economic benefits shale development in general and the Marcellus shale formation stretching beneath Pennsylvania in particular as most significant, noting that the Dems have promised to ban fracking of shale rock to release the vast quantities of oil and natural gas within. Trump warned that the Democrats want to take away our energy as well as our guns and that the current prosperity spawned by shale and facking could end.

Trump administration pushing LNG rail shipments » The Trump administration wants to allow the transportation of liquefied natural gas (LNG) by rail tank cars, Kallanish Energy reports. The U.S. Department of Transportation and its Pipeline and Hazardous Materials Safety Administration is proposing LNG rail shipments be allowed in DOT-113 specification refrigerated tank cars.PHMSA is working with the Federal Railroad Administration. The two agencies last Friday filed a 55-page notice of proposed rulemaking. They called such rail shipments a “potentially viable alternative to pipelines.”The plan is supported by the railraod trade grtoup Association of American Railroads.The proposed rule to allow such shipments will be the subject of a 60-day public comment period on changes to the Hazardous Materials Regulations to allow such shipments, after the notice appears in the Federal Register. The notice is available at www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/news/72636/lng-rail-nprm-2137-af40.pdf. The notice is a result of President Trump’s April 2019 executive order on LNG and rail, mandating a federal rule by 2020.The proposal has come under fire from critics who say such shipments pose a major safety risk to local communities.Currently, LNG may only be transported via rail in a portable tank with approval from the federal rail agency. However, federal rules do allow the DOT-113 tank car to be allowed to carry other flammable cryogenic liquids. “This major rule will establish a safe, reliable and durable mode of transportation for LNG while substantially increasing economic benefits and our nation’s energy competitiveness in the global market,” said agency administrator Skip Elliott, in a statement. One company, New Fortress Energy unit Energy Transport Solutions, is seeking a special federal permit to run 100-car unit trains filled with LNG to a proposed LNG export facility on the Delaware River in New Jersey. That request was filed last summer with PHMSA. The LNG would be moved from liquefaction facilities in the Marcellus Shale of northeast Pennsylvania. The U.S. House of Representatives last summer approved an appropriations bill amendment that blocked such a permit.

Natural gas usage climbs as distributors replace lines – Natural gas usage for one local distribution company operating in Pennsylvania and Maryland said Wednesday has increased 17% in the last two years, primarily in the commercial and industrial sectors. Michael Huwar of Columbia Gas of Pennsylvania and Maryland said his company has been replacing old cast iron gas lines with new plastic lines. It has been changing roughly 100 miles per year at a cost of $300 million, he said. Huwar made his remarks at the 9th Annual Shale Insight conference, in Pittsburgh. Pipeline leakage has also been reduced 86% in the last 10 years, he said. Justin Macken of Equitrans Midstream defended the again-stalled Mountain Valley Pipeline from West Virginia to the Virginia-North Carolina border. The company is already eying several expansion projects along the line that runs 300 miles to deliver Marcellus and Utica Shale natural gas to markets. Those projects include expanding capacity on the pipeline by 500 million cubic feet per day from the current 2 billion cubic feet per day, he said. In other comments, Pennsylvania Speaker of the House of Representatives Mike Turzai hailed the natural gas success in the Appalachian Basin. Pennsylvania is the No. 2 gas producer in the U.S. behind only Texas. Ohio is No. 5. If Pennsylvania, Ohio and West Virginia were a foreign country, it would be No. 3 for natural gas production in the world. Turzai said Pennsylvania intends to stay away from bad policy decisions and actions that would hurt shale drilling and damage Pennsylvania’s booming economy. Pennsylvania could have been like New York state and blocked drilling, but that has not happened, he said.

EQT to grow Appalachian Basin natural gas with combo drilling – EQT will rely heavily on combo drilling in the Appalachian Basin as it moves forward, Kallanish Energy reports. The Pittsburgh-based company, the No. 1 natural gas producer in the U.S., expects to begin drilling in perhaps a dozen new areas, said president and CEO Toby Rice Wednesday, at the 9th annual Shale Insight conference in Pittsburgh. The conference drew about 1,450 attendees and was staged presented by the Marcellus Shale Coalition, the Ohio Oil and Gas Association and the West Virginia Oil and Natural Gas Association. Much of EQT’s planned drilling will occur at multiple levels from the same well pads with longer laterals, Rice told the audience. That could include Marcellus, Utica or Upper Devonian play drilling. He did not identify the areas of new drilling, but said such drilling is more complicated and complex and requires additional corporate planning. The company has lots of underground options in western Pennsylvania, Ohio and West Virginia, Rice said. And there are plenty of ways the company can improve. Technology is being added to drive efficiencies and to change the way that the company operates, Rice said. He said he’s working to create a connected organization with digital technology and a digital workplace. EQT has also cut the number of complaints filed via its hotline telephone call in half in the 100 days since Rice took over. There were 1,100 complaints when he took over. Rice said his company will likely be able to produce free cash flow in the near future because of its high-quality inventory. Low natural gas prices hurt, but those prices are building demand for natural gas and are being relied on by customers, he said. Rice said natural gas production growth is expected to jump by 10 billion cubic feet per day (Bcf/d) in the next 10 years, with 7 Bcf/d going to LNG exports. There are sufficient pipelines at least for the next few years to get Appalachian Basin natural gas to markets, Rice said. He noted the stalled Mountain Valley and Atlantic Coast pipelines would boost such shipments. Natural gas is having a big impact in Pennsylvania where natural gas bills have dropped 70% in the last 10 years and where $13 billion is being spent on gas-fired power plants, Rice said. Natural gas will complement renewables such as wind and solar in the future, he added..

Equitrans files for approval to connect Rover pipeline to West Virginia power plant — Equitrans recently filed an official request with the Federal Energy Regulatory Commission (FERC) for approval to construct an approximately 17-mile pipeline from southwest Pennsylvania to West Virginia. If approved, the Tri-State Corridor Project will include a line connected to the Rover pipeline to provide natural gas liquids to West Virginia’s first natural-gas-fired electric power plant. The project would connect the Rover Pipeline along with two “non-jurisdictional” pipelines at the Trinity Interconnect site. The majority of the line would be a 16-inch pipe carrying shale gas to ESC Brooke County I, which is being built by Energy Solutions Consortium. The project would be the sole source of fuel for the plant. Equitrans, LP, a subsidiary of EQM Midstream Partners based in Canonsburg, Pennsylvania, would operate the pipeline. “Energy infrastructure in Pennsylvania is crucial for the state’s economic,” the Pennsylvania Energy Infrastructure Alliance said in a blog post. “Pennsylvania is now the second-largest natural gas producer in the country and the industry has generated countless benefits for the commonwealth through jobs and increased access to energy resources for consumers – both have produced great economic benefit. Sustained investment in projects like the Tri-State Corridor Project will continue to provide the citizens of Pennsylvania with jobs to support Pennsylvania’s working families, lower energy costs, and economic stability.”

Longview Power expansion project in Maidsville, WV, to be built by union labor – The planned expansion at Longview Power, which will add solar and gas energy generation capabilities to one of the nation’s most efficient coal-fired power plants, will be built by union labor, according to officials. The project will directly and indirectly support around 5,000 construction jobs throughout the 36-month construction process, said Longview Power COO Steve Nelson. Longview officials invited representatives of local construction unions to the facility on Wednesday for a presentation on the expansion project and a guided tour of the existing operation. Natalie Stone, executive secretary for the North Central Building Trades, said the decision to use union labor is welcome news for her organization’s members and for West Virginia as a whole. “It’s a huge boost for us,” she said. “We built the original plant when it was first brought online. They met with us several months and expressed interest in having us build their new plant. We’re very excited. It’s going to be huge for our members and their families…great wages, great benefits for everybody. It’s a great boost for the economy.” The proposed facility, called the Longview Power Clean Energy Center, will house a pair of new power plants, one gas-fired and one solar. The proposed combined cycle gas-fired power plant will incorporate advanced turbine technology and existing infrastructure to produce low-cost electricity, Nelson said. The utility-grade solar facility will use over 185,000 solar panels on 300 acres in both West Virginia and Pennsylvania. Once fully operational, the Clean Energy Center is anticipated to produce over 2,000 MW of electricity, serving nearly 2 million homes in Northern West Virginia and Southwest Pennsylvania.

Work on Mountain Valley Pipeline is winding down – Winter is coming early for the Mountain Valley Pipeline. Although construction is winding down for the season, it’s not just because of the coming freezing temperatures that will make it difficult to dig trenches along mountain slopes for the buried natural gas pipeline. Even if it was being built in the tropics, this project would be stalled. Mountain Valley has lost three sets of key permits – all suspended because of the pipeline’s impact on the environment – that have fallen like slow-motion dominoes for a project that was supposed to be done by now. The most recent blow came last week, when the Federal Energy Regulatory Commission ordered the company to “cease immediately” all work on the interstate pipeline, at least until questions raised by the latest legal challenge are resolved. While the courts consider that case, the U.S. Army Corps of Engineers is likely months away from making a decision on whether to re-issue permits that allowed the pipeline to cross more than 1,000 streams and wetlands in Virginia and West Virginia. Those permits were revoked or suspended a year ago, and Mountain Valley had hoped to have them restored by now – until a legal challenge, filed in August, took issue with a determination from the U.S. Fish and Wildlife Service that the pipeline would not jeopardize endangered species of fish and bats. And a decision on a third set of permits for the pipeline to pass through the Jefferson National Forest, thrown out in July 2018, remains in limbo while the U.S. Supreme Court considers a case that could impact the pipeline’s crossing of the Appalachian Trail. With three federal agencies – the Army Corps, the Fish and Wildlife Service and the U.S. Forest Service – all back at the drawing board to redo their respective permits, there’s not a lot of work that can be done along the pipeline’s 303-mile route from northern West Virginia to Chatham.

EQM delays WV-VA Mountain Valley natgas pipe, boosts costs again (Reuters) – EQM Midstream Partners LP said on Tuesday it pushed back to late 2020 the expected completion of its long-delayed Mountain Valley natural gas pipeline from West Virginia to Virginia, and boosted the estimated cost to $5.3-$5.5 billion. Previously, the company had targeted a mid 2020 full in service date at a cost of $4.8-$5.0 billion. When EQM started construction in February 2018, it estimated Mountain Valley would cost about $3.5 billion and be completed by the end of 2018. But successful legal challenges by environmental and other groups to federal permits have resulted in lengthy delays and higher costs for Mountain Valley and another gas pipeline under construction in the Mid Atlantic region: Dominion Energy Inc’s Atlantic Coast from West Virginia to North Carolina. “While the temporary setbacks have caused schedule delays and cost overages, completion of the project is critical to serving the growing demand for domestic natural gas in the mid-Atlantic and Southeast regions of the United States,” Diana Charletta, EQM president and chief operating officer, said in a release.

Another delay, cost increase for Mountain Valley Pipeline – The projected cost of building the Mountain Valley Pipeline has gone up by another half a billion dollars. And the expected completion date, most recently slated for mid-2020, has been pushed back to the end of that year. In an announcement Tuesday, Mountain Valley attributed the latest delay and revised cost estimate – now at between $5.3 billion and $5.5 billion – to “various legal and regulatory challenges.” The Pittsburgh-based company has lost three sets of federal permits, following legal challenges by environmental groups that argued the buried natural gas pipeline would pose risks to the water, land and wildlife along its 303-mile route. “We have encountered unforeseen development challenges; however, we continue to make progress towards ultimate completion,” Diana Charletta, president and chief operating officer of EQM Midstream, the lead partner in the project, said in a statement. “While the temporary setbacks have caused schedule delays and cost overages, completion of the MVP project is critical to serving the growing demand for domestic natural gas in the mid-Atlantic and Southeast regions of the United States,” Charletta said. When work began in February 2018, Mountain Valley said it would be done by the end of that year at a cost of $3.7 billion. Several delays and cost increases have been announced since then. As costs have risen steadily, some opponents have voiced hopes that investors will pull out of the joint venture, made up of five energy companies. But considering the amount of work that has already been completed on the pipeline’s route through West Virginia and Southwest Virginia, one financial analyst who has followed the project closely saw a “very low probability” of that happening.

Investigators plan Atlantic Coast Pipeline questioning in November :: WRAL.com – The Atlantic Coast Pipeline will take center stage again at the statehouse next month when private investigators plan a public questioning of key Cooper administration officials about the pipeline permitting process. It’s been a back-and-forth political fight to get here, with Gov. Roy Cooper and his leadership team accusing the Republican-controlled legislature of dragging out a sham investigation to score political points. Republicans say they want to know what the administration promised Duke Energy and other pipeline partners before announcing, on the same day, the pipeline’s key state permit and a $58 million fund the governor would have controlled. Cooper Chief of Staff Kristi Jones sent the legislature an open records request Thursday, seeking communications between lawmakers and the private investigators they hired to dig into the administration. She asked for the records by next Friday, which would be a surprisingly quick turnaround for a large cache of records from the Cooper administration itself. She also said lawmakers should set aside legislative privilege, which is a large, but not fully defined, carve out in the state’s open records law allowing lawmakers to avoid releasing documents. “A legislative inquisition should not be allowed to hide behind a self-serving exception to the state’s public records laws that protects legislators and their activities from public scrutiny while requiring every other governmental body and public official in North Carolina to make their records and communications public,” Jones wrote.

Report finds that users saved $1.1T due to natural gas production in Shale Crescent USA region – Shale Crescent USA (SCUSA) and the Ohio Oil & Gas Energy Education Program (OOGEEP) recently released an economic analysis that highlights users’ energy savings due to increased natural gas production in the Shale Crescent USA region. According to the report, end-users of natural gas, which include households, businesses, manufacturers, and electric power generators, have seen $1.1 trillion in energy savings since 2008 due to the significant natural gas production in the region, which includes Pennsylvania, Ohio and West Virginia.According to the report, U.S. households saved an average of $4,000 over 10 years, and the energy savings amounted to approximately a 2.7 percent increase in income for low-income families. The savings included over $90 billion for all natural gas users in the Shale Crescent Region. The report found that Shale Crescent region manufacturers and industrial users saved approximately $25 billion, and consumers in the Shale Crescent region realized savings approximately 30 percent higher than the national average.

‘The Empowerment Alliance’ and Other New Dark Money Groups Sound a Lot Like the Natural Gas Industry – DeSmog – Amid the crescendo of calls for climate action and rising rage directed at the fossil fuel industry, petroleum producers and their allies are engaging in an aggressive promotional push focused on natural gas. The same month that the American Petroleum Institute (API) started running ads emphasizing gas’s role in reducing carbon emissions, a new dark money group has launched under the patriotic guise of promoting “America’s energy independence” by promoting, you guessed it, natural gas. That group, called The Empowerment Alliance (TEA), is a registered 501(c)4 that does not disclose its donors (and is not required to under law). TEA launched on September 30 with a news release filled with natural gas industry talking points and attacks on the Green New Deal. The organization describes natural gas as “essential to our shared prosperity” in terms of jobs, national security, energy costs, and even air quality, while the Green New Deal is labeled as “radical and unachievable” and a “risky tax scheme.” This anonymously funded organization, from its leaders to its messaging, is part of a broader chorus of misleading talking points that goes beyond the “natural gas and oil” industry (as the API ads say) to conservative media pundits and top strategists and officials within the Trump administration and the GOP. The Empowerment Alliance is known to be run by two top figures and lobbyists for the Republican Party. James Nathanson, the executive director, is a longtime Republican operative and apparent dark money extraordinaire. Nathanson’s business consulting firm in Dayton, Ohio, James S. Nathanson & Associates, has funded various conservative candidates and Republican Party groups and SuperPACs. But while these donations are transparent, Nathanson has also headed a group called Freedom Vote, Inc. – another 501(c)(4) dark money organization. Freedom Vote (FV) has been accused of failing to report more than $1.1 million spent on political attack ads during the 2016 U.S. Senate race in Ohio. Watchdog group Citizens for Responsibility and Ethics in Washington (CREW) filed official complaints against Freedom Vote to the IRS and Federal Election Commission (FEC), and even filed a lawsuit in June seeking to compel the FEC to take enforcement action against the organization. Nathanson was also a central subject to a 2004 complaint to the FEC for violating campaign finance law in Ohio election campaigns.

Natural gas inventories surpass five-year average for the first time in two years -Working natural gas inventories in the Lower 48 states totaled 3,519 billion cubic feet (Bcf) for the week ending October 11, 2019, according to the U.S. Energy Information Administration’s (EIA) Weekly Natural Gas Storage Report (WNGSR). This is the first week that Lower 48 states’ working gas inventories have exceeded the previous five-year average since September 22, 2017. Weekly injections in three of the past four weeks each surpassed 100 Bcf, or about 27% more than typical injections for that time of year.Working natural gas capacity at underground storage facilities helps market participants balance the supply and consumption of natural gas. Inventories in each of the five regions are based on varying commercial, risk management, and reliability goals.When determining whether natural gas inventories are relatively high or low, EIA uses the average inventories for that same week in each of the previous five years. Relatively low inventories heading into winter months can put upward pressure on natural gas prices. Conversely, relatively high inventories can put downward pressure on natural gas prices.This week’s inventory level ends a 106-week streak of lower-than-normal natural gas inventories. Natural gas inventories in the Lower 48 states entered the winter of 2017 – 18 lower than the previous average. Episodes of relatively cold temperatures in the winter of 2017 – 18 – including a bomb cyclone – resulted in record withdrawals from storage, increasing the deficit to the five-year average.In the subsequent refill season (typically April through October), sustained warmer-than-normal temperatures increased electricity demand for natural gas. Increased demand slowed natural gas storage injection activity through the summer and fall of 2018. By November 30, 2018, the deficit to the five-year average had grown to 725 Bcf. Inventories in that week were 20% lower than the previous five-year average for that time of year. Throughout the 2019 refill season, record levels of U.S. natural gas production led to relatively high injections of natural gas into storage and reduced the deficit to the previous five-year average. The deficit was also decreased as last year’s low inventory levels are rolled into the previous five-year average. For this week in 2019, the preceding five-year average is about 124 Bcf lower than it was for the same week last year. Consequently, the gap has closed in part based on a lower five-year average.

BOOM: Natural gas reserves, output defying previous estimates nationwide – Oil and gas production in several regions of the country continue to defy previous estimates, in some cases tripling them, according to new estimates released by the U.S. Geological Survey.This month, the USGS reported that the Marcellus Shale and Point Pleasant-Utica Shale formations of the Appalachian Basin contain an estimated mean of 214 trillion cubic feet (Tcf) “of undiscovered, technically recoverable continuous resources of natural gas.”The Marcellus Shale and Point Pleasant-Utica Shale estimates represent a significant increase from the previous USGS assessments of both formations. In 2011, the USGS estimated a mean of 84 Tcf of natural gas in the Marcellus Shale, and in 2012, 38 Tcf of natural gas in the Utica Shale.The Marcellus, Point Pleasant and Utica formations cover parts of Kentucky, Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Last month, the USGS released a new assessment of the Alaska North Slope, which is estimated to contain 53.8 Tcf of natural gas hydrate resources, according to 3D seismic mapping and “a greater understanding of gas hydrate reservoir properties.” The estimate pertains to undiscovered, technically recoverable natural gas resources stored within gas hydrate formations. The 2008 report estimated 85 Tcf, which was the first-ever estimate of technically recoverable gas resources within gas hydrate, according to the report.In North Dakota, the Bakken shale now produces annually an amount that is more than three times what the USGS estimated 25 years ago it could ever produce in total. In West Texas and New Mexico, the Permian Basin is the largest continuous oil field and second largest gas field in the U.S.The Wolfcamp Shale and overlying Bone Spring Formation in the Delaware Basin portion of Texas and New Mexico’s Permian Basin region contain an estimated mean of 46.3 billion barrels of oil, 281 Tcf of natural gas, and 20 billion barrels of natural gas liquids, the USGS reports.

Natural Gas Glut Drags Down Prices — Natural gas prices have sunk this year, falling due to record production and swelling stockpiles. Low prices are putting a strain on shale gas drillers, with Appalachia in particular feeling the effects. Globally, the market for gas is also suffering from a bout of oversupply that could take several years to clear up. At the same time, some industry executives are starting to exhibit concern regarding the growing public pressure to place restrictions on gas due to its impact on climate change. Last year, the U.S. market for natural gas tightened up, squeezed by swings in temperatures, rising exports and structural increases in demand due to more gas-fired power plants. Henry Hub prices topped $4/MMMBtu in November 2018, just ahead of the peak winter demand season as the market grew concerned about supply. But the price spike was temporary, and the gas industry continued to break production records. Both the Marcellus and Utica shales in Appalachia, and the Permian basin in West Texas, exhibited blistering growth. As winter came to an end, depleted inventories were quickly restored.In fact, Henry Hub prices entered a steep slide this past summer, as gas output continued to rise. Producers in the Permian and the Bakken are flaring at record rates, and regulators have done little to rein them in. But drillers in Texas, New Mexico and North Dakota are mainly focused on producing oil, and the gas comes out of the ground as a byproduct. Low prices do not necessarily alter their drilling calculations. Meanwhile, in Appalachia, where E&Ps are mainly focused just on producing gas, low prices are causing deeper problems. Pittsburgh-based EQT, the largest natural gas producer in the country,announced that it would lay off 23 percent of its workforce as part of a corporate restructuring.

Natural Gas Prices Reverse Most Of Last Week’s Rally – Last week felt a little more promising for natural gas bulls, as prices rose to around $2.35 at the end of electronic trading back on Friday, flirting with key resistance levels that seemed at risk to be broken thanks to colder weather from the end of this month into the start of November. It was not to be, however, as prices were crushed in today’s session. The prompt month November contract settled down more than 8 cents on the day, reversing most of last week’s entire rally with a closing price of $2.238. Why such a sharp decline? There are a couple of reasons. One is that the amount of cold forecast by the weather models weakened over the weekend. Notice how cold the GEFS was, for example, when we woke up Friday morning in the 11-15 day time frame: Checking what it showed this morning valid the same dates, the change is quite obvious to the warmer side in the key eastern half of the U.S. Yes, there is still plenty of cold on the map, but it is focused in areas where there are fewer people, resulting in lower demand for natural gas consumption. But weather was not the only driver of today’s price action, and arguably not even the most important one, despite being near the time of year when we often look to the weather forecasts as the primary driver of natural gas price volatility. We saw a rather large jump up in natural gas production in the weekend data. The data shows that Friday and Saturday’s production total was around 95.1 bcf, blowing away the previous high mark of 94.2 bcf in our dataset. At a time when supply demand balances are already running loose despite low prices, more supply is definitely not something that is friendly to the bulls, what few that still exist, given the market’s already extreme short position. The length in the market is at its lowest level in years, but until the aforementioned supply / demand balances can tighten, it is difficult to put together a rally unless strong cold hits and is able to have some durability. This week’s EIA report seems unlikely to change the landscape much, as it will take quite a miss vs our expectation in order to avoid again reflecting loose S/D balances. For now, it is up to weather to deliver enough of a punch to turn this market around, and we cannot rule that out. Even with the warmer change, the medium range guidance still projects a pattern that often brings cold into the U.S, with upper level ridging around Greenland (negative NAO), and another upper level ridge along the west coast of North America, poking up toward Alaska (negative EPO).

US natural gas storage volume rises by 87 Bcf to 3.606 Tcf: EIA – US working natural gas volumes in underground storage added 87 Bcf last week, increasing by more than the five-year average for the 13th consecutive week, as the NYMEX Henry Hub winter strip trades near two-month lows. Storage inventories increased to 3.606 Tcf for the week ended October 18, the US Energy Information Administration reported Thursday morning. The injection was less than an S&P Global Platts’ survey of analysts calling for a 92 Bcf addition. Survey responses ranged for an injection of 80 Bcf to 101 Bcf. The build was more than the 62 Bcf injection reported during the corresponding week in 2018 as well as the five-year average addition of 73 Bcf, according to EIA data. As a result, stocks were 519 Bcf, or 16.8%, more than the year-ago level of 3.087 Tcf and 28 Bcf, or 0.8%, more than the five-year average of 3.578 Tcf. The NYMEX Henry Hub November contract added 1.7 cents to $2.299/MMBtu following the announcement. The winter strip, November through March, gained less than 1 cent to average $2.434/MMBtu, down 8 cents from the week prior. The $2.43/MMBtu price marker has proved to be a low-side support level. Prices bottomed out there on three previous occasions in the last two months following higher trading. US balances are trending tighter by about 0.8 Bcf/d for the week in progress, as notable gains in onshore production still fall short of a boost in demand driven by higher home heating loads, according to S&P Global Platts Analytics. A forecast by Platts Analytics’ supply and demand model has storage volumes increasing by 83 Bcf for the week ending October 25, which would increase the surplus to the five-year average to 46 Bcf with at least two more net injections remaining before withdrawal season begins. Forecasts for the end-of-season peak before the flip to net withdrawals have continued to increase throughout the injection season as supply continued to outpace demand. The most recent estimate by Platts Analytics now has storage peaking at 3.749 Tcf.

PA Chamber calls New Jersey’s denial of PennEast pipeline permits “troubling news” – Pennsylvania Chamber of Business and Industry President and CEO Gene Barr issued a statement Wednesday criticizing New Jersey Gov. Phil Murphy’s administration’s denial of permits for the proposed Penn East pipeline project. “New Jersey Governor Phil Murphy’s announcement last week that his administration will refuse to issue permits to the Penn East pipeline project is troubling news for the region’s economy and its environment and is, at best, legally questionable,” Barr said. “The project would have served to deliver gas to thousands of homes and businesses in Pennsylvania and New Jersey helped keep energy prices low for the entire region and would have supported energy, manufacturing, and supply chain jobs throughout Pennsylvania.” Murphy said in a tweet on Friday that the New Jersey Department of Environmental Protection (DEP) denied a permit that PennEast Pipeline Co needed to build the proposed natural gas pipeline from Pennsylvania to New Jersey. In September, a U.S. appeals court issued a ruling that prevented PennEast from using federal law to gain access to properties along the route in New Jersey. “My Administration fought and won in court to stop the proposed 116-mile Penn East natural gas pipeline,” Murphy said in the tweet. “This week, @NewJerseyDEP denied and closed the application. We are committed to transitioning New Jersey to 100% clean energy by 2050.”

Three State Agencies Challenge PennEast’s Effort to Overturn Adverse Court Ruling on Pipeline New Jersey is opposing efforts by the PennEast Pipeline Company to have a federal agency reverse a court ruling blocking the developer’s $1 billion, 116-mile natural gas pipeline project through parts of the state and Pennsylvania. In protest petitions filed with the Federal Energy Regulatory Commission on Friday, a trio of state agencies and the Delaware and Raritan Canal Commission challenged PennEast’s decision to ask the agency to overturn a ruling by the U.S. Court of Appeals for the Third Circuit. Essentially, the state is characterizing PennEast’s request as an attempt to relitigate an issue decided authoritatively by a federal court, a course of action two state agencies (the Department of Environmental Protection and Board of Public Utilities) described as unprecedented. The federal court last month blocked the company’s bid to condemn state-owned properties as part of its plan to build a pipeline from Luzerne County, Pa., across the Delaware River, and ending in Mercer County. The court found that a private company lacked legal authority to seize or condemn state lands under the 11th Amendment of the U.S. Constitution. “PennEast, by its own terms, is pursuing an action that is wholly inappropriate after losing a question of statutory interpretation before the Third Circuit (a loss informed by the court’s view of the relevant constitutional law), the company has come to FERC for a do-over,’’ the state argued in its brief. Legal doctrine of sovereign immunity New Jersey’s Division of Rate Counsel agreed, calling PennEast’s petition both procedurally unsound and substantively meritless. “The determination PennEast seeks is squarely contrary to the Third Circuit’s decision, which held that the National Gas Act had not abrogated states’ sovereign immunity,’’ according to Rate Counsel. Under the legal doctrine of sovereign immunity, a state cannot be sued by a private company without its consent.

Environmental Group Appeals ‘Arbitrary’ DEP Permit for South Jersey LNG Terminal – The Delaware Riverkeeper Network said Monday it appealed a permit issued by New Jersey’s Department of Environmental Protection for construction of the state’s first liquefied natural-gas export terminal at Gibbstown on the Delaware River. The DRN said officials had failed to consider all the ways the project would impact people and the environment.The environmental group called DEP’s approval “arbitrary, unreasonable, and contrary to law.” It said officials didn’t have enough evidence to determine whether the project would hurt water quality and did not require a stormwater permit or an investigation by the developer into contamination on the 370-acre Superfund site that was used by DuPont for making explosives and chemicals.The appeal says the DEP’s waterfront development permit violates regulations on coastal zone management that are intended to protect coastal and water resources. In an appeal filed with the New Jersey Superior Court on Oct. 18, the DRN said the potentially explosive LNG that would be trans-shipped at the terminal could do “catastrophic harm” to people and that dredging and riverfront development for the new port would harm the natural environment.It said the permit represented “an egregious failure by NJDEP to implement required protections.” The LNG plan by Delaware River Partners, a developer, would expand an original proposal for a dock and one berth for ships that carry cars and dry and perishable cargo, creating a facility called Gibbstown Logistics Center. In addition, bulk liquids such as propane and butane would be stored on site using a cavern built by DuPont. The expanded project would load LNG onto oceangoing tankers after trucking it from a planned liquefaction plant in Bradford County, PA, one of the “sweet spots” of the state’s natural gas-rich Marcellus Shale. Delaware River Partners is affiliated with New Fortress Energy, which plans to build the liquefaction plant. The plan has drawn strong opposition from DRN and other environmental groups who argue that it would endanger people living in Gibbstown and along a 175-mile route from Wyalusing in northeastern Pennsylvania to the new terminal. The critics also say the project will boost fossil-fuel production as states including New Jersey and Pennsylvania set aggressive goals for cutting carbon emissions.

Williams CEO Says Its Gas Pipe Can Help Cuomo’s N.Y. Green Goals – A natural gas pipeline that has been held up by New York could help Governor Andrew Cuomo meet his ambitious clean energy goals if he approves it, according to the developer behind the $1 billion project. “It really does align well with Governor Cuomo’s efforts to both continue to grow the economy as well as reduce emissions pretty dramatically,” Alan Armstrong, chief executive officer of Williams Cos., said about the Northeast Supply Enhancement project. Earlier in 2019, New York rejected the company’s application for a key permit, setting off a clash between Cuomo and National Grid Plc, which froze new gas hookups in some communities. The utility said the pipeline needed to be approved and encouraged customers to write to the governor’s office in support of the project. Cuomo fired back this month and ordered it to immediately resume connections to some customers. While environmentalists argue such projects only serve to increase reliance on fossil fuels, Armstrong said the pipeline would reduce emissions to the equivalent of taking half a million cars off the road because the majority of the gas would go to displace heating oil. The end result of such projects being rejected would mean that gas supplies will have to be transported in by truck or heating oil use will rise — both at the expense of higher emissions, the CEO said in an interview at an energy conference in Kentucky on Monday. Cuomo in July signed the most stringent clean energy goal in the U.S., seeking to get all of New York’s electricity from emission-free sources by 2040, and an 85% reduction in economy-wide carbon emissions by 2050 from a 1990 baseline.

Cuomo threatens to pull plug on National Grid as he rails against utility company’s power – – Gov. Cuomo wants to know why National Grid has so much power. The governor threatened Thursday to pull the plug on the energy giant if it doesn’t cooperate with state officials seeking answers about its recent moratorium on natural gas hook-ups and its battle over a natural gas pipeline. “National Grid has a gun to the head of the people of the State of New York,” Cuomo said during an appearance on Long Island News Radio with Jay Oliver. For months, National Grid denied service to new and returning customers as the state Department of Environmental Conservation rejected a permit for a controversial pipeline slated to run across New York Harbor. New Jersey also denied a permit for the project. The governor came to the rescue of shut-out customers last week when he vowed to impose millions of dollars in fines unless the company provided natural gas to more than 1,100 customers who were denied service re-connections. The governor came to the rescue of shut-out customers last week when he vowed to impose millions of dollars in fines unless the company provided natural gas to more than 1,100 customers who were denied service Cuomo also turned the heat up on the Public Service Commission, which regulates the state’s utility companies, with a letter Thursday asking why the agency and National Grid failed to explore alternatives to the pipeline and as a contingency to a stalled pipeline. The scathing missive is addressed to John Rhodes, the PSC chairman, a Cuomo appointee and the former CEO of the New York State Energy Research and Development Authority. “The fact that National Grid has consumers in a position whereby National Grid gets what it wants or consumers are punished is unconscionable,” the governor wrote. “A utility does not have license to harm customers because it believes it has an irrevocable franchise and is immune from effective regulatory oversight. I will not allow that situation to continue.”

Planned natural gas release angers compressor station opponents – – A planned release of natural gas in Weymouth and Braintree this week has raised the ire of neighbors who have been fighting the construction of a proposed natural gas compressor station in the Fore River Basin. Algonquin Gas Transmission, a subsidiary of Enbridge, sent a letter to some residents this week stating the company will “intermittently” release odorized natural gas from 7 a.m. to 5 p.m. on Thursday and Friday at its valve site at the Fore River Power Generation site off of Bridge Street, and at the Potter Meter Station site off of Potter Drive in Braintree. A spokesman for Enbridge told The Patriot Ledger the release is part of “planned, routine maintenance.” “There is no cause for alarm and there will be no danger whatsoever to persons or property in the area,” the letter to residents reads. “Portable deodorizing equipment and monitors that constantly measure the levels of natural gas will be used and Algonquin will make every effort to minimize the volume of gas released.” Algonquin Gas Transmission has proposed building a 7,700-horsepower compressor station on the banks of the Fore River. The proposal is part of Spectra’s Atlantic Bridge project, which would expand the Houston company’s pipelines from New Jersey into Canada. Alice Arena, of the Fore River Residents Against the Compressor Station, said fracked gas has volatile compounds and heavy metals that are toxic and carcinogenic. Residents don’t believe that Enbridge has evaluated the health risks posed by blowdowns, or plan to test for harmful substances. “There are people in the basin with heart disease, COPD, asthma and cancer, and these people are already compromised,” Arena said. “But Enbridge is so cavalier and basically pat you on the head and says, ‘it’s fine.’” Max Bergeron, a spokesman for Enbridge, would not say how much natural gas would be released during the blowdown.

DTE Energy’s natural gas midstream unit to buy Louisiana gathering pipeline, system in $2.65 billion deal –DTE Energy Co. unit DTE Midstream agreed to buy a natural gas gathering system and gathering pipeline in the Haynesville Shale rock formation in Louisiana for $2.25 billion in cash, plus another $400 million at a 2020 milestone. Detroit-based DTE will take on all assets from Momentum Midstream and Indigo Natural Resources, the main natural gas producer supplying the system, including a 150-mile, under-construction pipeline and an existing gathering system. DTE made the announcement in a news release Friday morning. It gives DTE access to growing markets around the Gulf Coast, the release said.DTE Midstream is the utility company’s natural gas storage, pipeline and gathering provider in the Midwest, Appalachian area, the Northeast and in Ontario. It said in May it would acquire an additional 30 percent of Stonewall Gas Gathering in West Virginia for $275.3 million. DTE wants to spend $4 billion-$5 billion in its midstream business between this year and 2023.

After Vowing to Cut Carbon, Utility Makes $2 Billion Gas Bet – DTE Energy Co. vowed last month to eliminate all its emissions from generating electricity. Now it’s betting big on natural gas. The Detroit-based utility agreed to buy a gas-gathering system and pipeline in Louisiana for $2.25 billion in cash, according to a statement Friday. The acquisition, from Momentum Midstream and Indigo Natural Resources, will deepen DTE’s existing gas network and boost its capacity to supply the Gulf Coast. Closely-held Indigo Natural Resources is the primary supplier of gas to the assets being sold to DTE. The fact that DTE is pushing to cut emissions on one side of its business while doubling down on fossil fuel with the other underscores how utilities continue to see gas as core to their business even as they pledge to fight climate change. While wind and solar have become cheap enough to compete with fossil fuels, utilities say they will need gas to heat homes and keep power grids stable for years to come. “The U.S. is undergoing a fundamental shift toward clean energy, and natural gas will play a large role in that,” DTE President and Chief Executive Officer Jerry Norcia said on a conference call. “Large investments in renewable resources and natural gas infrastructure enable the shift to a cleaner energy future.” Investors were less than enthusiastic about the acquisition, with shares falling as much as 2.9%, the most since February on an intraday basis. The deal raised concerns about DTE’s exposure to Indigo, a primary supplier of natural gas on the system, and investors are taking a cautious approach, Fitch Ratings placed DTE’s credit rating on watch negative due to the Indigo exposure..

ENERGY TRANSITIONS: World’s biggest wind, solar developer bets on gas pipeline — Wednesday, October 23, 2019 — A unit of NextEra Energy Inc. has agreed to build a 50-mile pipeline into Alabama to supply a natural gas plant set to stand where a coal plant once did.

6 Years After Exxon’s Oil Pipeline Burst in an Arkansas Town, a Final Accounting – It was March 29, 2013. Few in Mayflower will ever forget it. As Hays ran her errands, ExxonMobil’s Pegasus pipeline, which ran beneath this small town, burst without warning along a defective 22-foot seam, spewing 210,000 gallons of heavy Canadian crude oil diluted with large quantities of harmful solvents onto quiet residential streets. Hundreds of people in this working class community of about 2,000 near Little Rock reported being sickened by an odor that was almost thick enough to feel. Residents soon began to complain about grinding headaches, diarrhea, swollen eyes, dry heaves and burning lungs. “I started feeling kind of sick,” Hays said later in a deposition as one of the lead plaintiffs in a class action lawsuit against Exxon alleging negligence in its maintenance of the 69-year-old oil artery. “And I just couldn’t tolerate the smell.” The smell got into her house, she said, and for a year she couldn’t shake a malaise triggered by coughing, congestion and migraines. “I was just constantly sick,” she said. Hays is among more than two dozen Mayflower residents who described their symptoms and their anxiety in depositions that were sealed as part of a 2017 settlement with Exxon but obtained by InsideClimate News. The depositions, along with other court documents, provide the most complete account to date of the health impacts of the oil spill, which in some respects has remained shrouded in secrecy because the federal agency in charge of pipeline oversight restricted the public’s access to the information, and because of the confidentiality agreements Exxon demanded in exchange for the settlements. An environmental consultant hired by the plaintiffs’ lawyers, whose report is part of the court file, concluded that those nearby residents faced “significant risks” after being exposed to a cocktail of chemicals, including benzene, a known carcinogen; cyclohexane; naphthalene; and toluene. His findings have not previously been reported. The chemicals he cited had been used to dilute the heavy crude extracted from the tar sands fields of Alberta that leaked from the ruptured Pegasus pipeline, according to court documents. The consultant faulted Exxon for limited air sampling after the spill and for using the wrong health risk standard for assessing potential damage. Despite the confidentiality agreements, several plaintiffs said that compensation ranged from $2,000 to $15,000, depending on the proximity of the residents to the oil spill.

Oil company settlement over environmental suit could be first of many – An oil company accused of polluting and destroying parts of Louisiana’s quickly-dissolving coastline has agreed to a multi-million dollar settlement, a potential watershed moment that could help the state combat land loss and lead similarly accused energy titans to follow suit. Freeport-McMoRan is one of 98 oil and gas companies named in 42 lawsuits seeking reparations for environmental damage. Six years after the first suits were filed by several coastal Louisiana parishes, Freeport-McMoRan is the first to settle. “I’m pleased that other oil companies are calling, talking resolution,” said John Carmouche, the attorney representing the parishes. “I’ve been very vocal that the first companies to come, get the better deal. I think Freeport started something I think can be very great for Louisiana.” Freeport-McMoRan did not admit liability but has agreed to pay up to $100 million, much of which could be reimbursed by environmental credits, said Linda Hayes, the company’s vice president of communications. “While we believe the plaintiffs’ theories of liability are unfounded, we recognize the importance of coastal restoration regardless of its cause,” Hayes said via email. “As a result, we decided to make an early investment in a creative solution rather than continue to engage in years of litigation.”The deal could take decades to be paid in full and still requires approval from 12 parishes that will receive the funds. Carmouche and environmental law experts believe Freeport’s decision will set off an avalanche of similar agreements by companies who want to keep details of their operations out of the courtroom and off public record.

Cameron LNG natural gas facility officially opens today – The $10 billion Cameron LNG natural gas liquefaction and export facility was officially dedicated today. Gov. John Bel Edwards and CEO Farhad Ahrabi of Cameron LNG dedicated the facility. Cameron LNG became the second Louisiana company to export LNG to international destinations earlier this year. Also participating in the event with several hundred attendees were Japanese Ambassador Shinsuke Sugiyama and Masafumi Nakada, president of Nippon Export and Investment Insurance, the export credit agency of Japan also known as NEXI. The company is creating more than 200 permanent direct jobs, and Louisiana Economic Development estimates the project will result in an additional 657 new indirect jobs in Southwest Louisiana. One of the largest industrial construction projects in Louisiana’s booming Southwest Region, the Cameron LNG project employed over 11,000 construction workers during the peak year of construction as the facility took shape at Hackberry. Cameron LNG’s first production unit, or train, was completed earlier this year and shipped its first LNG cargo in May. The plant’s second and third trains are expected to begin producing LNG in the first quarter and second quarter of 2020, respectively. At full production, the company estimates its LNG exports could create an annual trade balance surplus of $8.6 billion, by commodity value, with foreign markets, and Cameron LNG is considering adding two more trains at the Hackberry site in the future.

Gulf Oil Production to Set Records Through 2020 – Annual oil production in the Gulf of Mexico is expected to jump to 1.9 million bpd in 2019. Oil production in the Gulf of Mexico (GOM) hit a new annual record of about 1.8 million barrels per day (bpd) in 2018, and the U.S. Energy Information Administration (EIA) anticipates additional production records in 2019 and in 2020 from the region. This is despite the shut-ins tied to Hurricane Barry in July and includes adjustments for hurricane-related shut-ins for the rest of this year and 2020. Annual oil production in the GOM is expected to jump to 1.9 million bpd in 2019 and reach 2 million bpd the following year, the agency reported. Despite the growth projections, GOM crude oil production will account for a smaller portion – just 15 percent – of the total in the U.S. This figure was 23 percent back in 2011, but since then onshore production growth has been outpacing offshore. Eight new deepwater projects are expected to come online this year while four should come online in 2020. Majority operators for the 2019 starts include LLOG, Shell, Oxy, Murphy Oil and W&T Offshore. Talos Energy, BP, Murphy Oil and Fieldwood Energy are majority operators for the 2020 starts. The agency expects these projects in total to add around 44,000 bpd this year and approximately 190,000 bpd in 2020 as their production ramps up. In 2019, oil production in the GOM slipped from 1.9 million bpd in June to 1.6 million bpd the following month because of Hurricane Barry-related platform evacuations. However, production recovered fairly quickly, as GOM oil production hit 2 million bpd in August 2019. Oil price spikes in 2017 and 2018 (compared to the lows in 2015 and 2016) haven’t yet had a marked effect on operations in the GOM, but they have the potential to contribute to higher rig counts and field discoveries in the coming years, according to the EIA.

Deepwater Transformation Sparking New Interest – Changes have revived interest in deepwater projects and enabled new ones in regions including the North Sea, the Gulf of Mexico and China Seas. Traditionally, deep-water exploration and production projects are not known for being small scale, fast or budget-friendly. The price crash of 2014 forced big oil to become cost conscious and make changes that are detailed in Wood Mackenzie’s report,The Deepwater Cost Curve: revisited in November 2018. Notable reforms include adopting an industrial approach to field development, in which standardization and modularization replaced customization, and automation introduced additional speed in the deepwater sector. Design changes, including greater use of subsea tiebacks, and reformed work practices have reinvented this sector by sharply reducing costs, increasing productivity and field development speed. In the process the closer collaboration between operators and field service contractors has generated environmentally-friendly technology solutions. These major reforms have revived interest in deepwater projects and enabled new projects in high cost oil-producing regions including the North Sea, the Gulf of Mexico and China Seas. The return to deep waters is characterized by projects that are simpler, have lower upfront costs and operating expenses, higher productivity and allow projects to come in within budget and on schedule. To illustrate this, Wood Mackenzie’s report shows that compared with 2013, 2018s deepwater cost curve is lower and longer and unit costs are down by over 50 percent. Consequently, a growing number of what were previously considered uneconomic projects are now considered viable at $50 a barrel, including new low-breakeven developments in Angola, West Africa, the Gulf of Mexico and the North Sea. As remarkable as these developments are deepwater still trails shale in the time it takes investors to recover their initial investment: offshore is down from 10 years to seven while shale is now under two. Financial recovery times perhaps explain the dominance of big oil in deepwater projects. The report shows that 74 percent of the projected US$250 billion of pre-FID spend sits on the books of just eight companies: Petrobras, Shell, Exxon, Chevron, BP, Eni, Total, Equinor, Anadarko and Woodside. However, there are some smaller players in the mix including LLOG in the Gulf of Mexico, Cairn Energy off Senegal and Tower Resources off Cameroon.

Government Loophole Gave Oil Companies $18 Billion Windfall – New York Times – The United States government has lost billions of dollars of oil and gas revenue to fossil-fuel companies because of a loophole in a decades-old law, a federal watchdog agency said Thursday, offering the first detailed accounting of the consequences of a misstep by lawmakers that is expected to continue costing taxpayers for decades to come. The loophole dates from an effort in 1995 to encourage drilling in the Gulf of Mexico by offering oil companies a temporary break from paying royalties on the oil produced. However, the rule was poorly written, the very politicians who originally championed it have acknowledged, and the temporary reprieve was accidentally made permanent on some wells. As a result, some of the biggest oil companies in the world, including Chevron, Shell, BP, Exxon Mobil and others, have avoided paying at least $18 billion in royalties on oil and gas drilled since 1996, according to a new report from the Government Accountability Office, a nonpartisan agency that works for Congress. The companies, which hold government leases to drill in the Gulf, continue to extract oil and gas from those wells while not being required to pay royalties, a right the industry has gone to court to defend. The National Ocean Industries Association, which represents the offshore industry, defended the arrangement. “There was no mistake in the law,” said Nicolette Nye, vice president at the association. If not for the law, she said, “we likely would not be producing U.S. oil offshore in record amounts today.” But in an interview, the program’s original architect said he was surprised by the outcome. “That wasn’t our intent,” said J. Bennett Johnston, a former Democratic senator from Louisiana who had pushed for the original reprieve on royalties. “There should have been a provision that said it didn’t apply above a certain threshold” for oil prices, he said. You have 4 free articles remaining. Subscribe to The Times The loophole continues to cut into federal coffers. Royalties from offshore oil and gas are a significant source of revenue, bringing in almost $90 billion from 2006 through 2018, according to the agency. Frank Rusco, a director of the G.A.O.’s Natural Resources and Environment team and the report’s author, said the findings are an extreme example of the Department of Interior failing to ensure that American taxpayers received a fair market value for the oil and gas extracted from public property. “These leases sold 20 years ago might keep producing for decades. The amount of forgone royalties is going to continue to increase,” Mr. Rusco said in an interview. “It’s a strong case for Interior to review how it collects revenues on oil and gas.”

BPL- 10,000 gallons spilled from ruptured pipeline – Bahamas Power and Light (BPL) lost 10,000 gallons of diesel fuel when a contractor ruptured a major pipeline last week. BPL Communications # Quincy Parker said approximately 235 gallons of clean diesel fuel was recovered from the damaged pipeline, and 21,660 gallons of oil/water mixture was recovered from the ground. He told Eyewitness News Online repairs on the pipe are expected to be completed today amid ongoing clean-up efforts to address outstanding contamination. The clean diesel fuel has been added to the storage diesel at Clifton for generation use. Parker said the oil/water mixture is also currently being stored at Clifton Pier, but will ultimately be disposed of. According to BPL, the spill was reported at 12.30pm after the contractor’s equipment made contact with a fuel line that runs from BHPS to Clifton Pier Power Station (CPPS). Parker said the pipe was immediately shut off, adding the damaged sections have been isolated and removed. “The line was shut down subsequent to the spill,” read a statement last week. It continued: “A BPL Security Supervisor received a call from the security guards posted at BHPS. Those officers reported that a trucking and excavation contractor had come to the security booth and reported that while excavating a property on Carmichael just west of Carmichael Primary School, his equipment came into contact with a BPL fuel line, which resulted in an oil spill.” In the initial statement, the company stated it has filed a police report over the incident. .

The U.S. Smashes Another Oil Export Record – Growing U.S. crude oil production and exports have resulted in America selling oil to more destinations around the world than the number of countries from which it imports crude oil, the Energy Information Administration (EIA) said on Tuesday. A decade ago, the United States was importing crude oil from as many as 37 foreign sources per month, and its exports were restricted almost exclusively to Canada. After the lifting of those restrictions at the end of 2015, U.S. crude oil exports have been on the rise and reaching more destinations. Between January and July 2019, the largest number of sources of America’s oil imports fell to 27 in any of those months, the EIA has estimated. On the other hand, the number of destinations for U.S. crude oil exports rose, with exports to as many as 31 destinations per month in the first seven months this year. Thanks to its growing domestic production – which increased by 2.6 million bpd between January 2016 and July 2019 – the U.S. has been importing crude from fewer sources. The domestic production increase has been mostly light sweet crude, which U.S. refiners have accommodated by displacing imports of light and medium crude from countries other than Canada and by raising refinery utilization rates, EIA says. On the other hand, expanding export terminals in the U.S. and global demand for light sweet crude have allowed the U.S. to export oil to more destinations. U.S. crude oil exports jumped by nearly 1 million bpd in the first half of 2019 from the same period in 2018 to average 2.9 million bpd between January and June this year, the EIA said earlier this month. Average U.S. exports of crude oil rose by 966,000 bpd in the first half of 2019, compared to the first half of 2018. In June this year, the U.S. set a monthly average record of 3.2 million bpd of crude oil exports, EIA data showed.

The United States now exports crude oil to more destinations than it imports from — As U.S. crude oil export volumes have increased to an average of 2.8 million barrels per day (b/d) in the first seven months of 2019, the number of destinations (which includes countries, territories, autonomous regions, and other administrative regions) that receive U.S. exports has also increased. Earlier this year, the number of U.S. crude oil export destinations surpassed the number of sources of U.S. crude oil imports that EIA tracks. In 2009, the United States imported crude oil from as many as of 37 sources per month. In the first seven months of 2019, the largest number of sources in any month fell to 27. As the number of sources fell, the number of destinations for U.S. crude oil exports rose. In the first seven months of 2019, the United States exported crude oil to as many as 31 destinations per month. This rise in U.S. export destinations coincides with the late 2015 lifting of restrictions on exporting domestic crude oil. Before the restrictions were lifted, U.S. crude oil exports almost exclusively went to Canada. Between January 2016 (the first full month of unrestricted U.S. crude oil exports) and July 2019, U.S. crude oil production increased by 2.6 million b/d, and export volumes increased by 2.2 million b/d. The United States has also been importing crude oil from fewer of these sources largely because of the increase in domestic crude oil production. Most of this increase has been relatively light-sweet crude oil, but most U.S. refineries are configured to process medium- to heavy-sour crude oil. U.S. refineries have accommodated this increase in production by displacing imports of light and medium crude oils from countries other than Canada and by increasing refinery utilization rates. Conversely, the United States has exported crude oil to more destinations because of growing demand for light-sweet crude oil abroad. Several infrastructure changes have allowed the United States to export this crude oil. New, expanded, or reversed pipelines have been delivering crude oil from production centers to export terminals. Export terminals have been expanded to accommodate greater crude oil tanker traffic, larger crude oil tankers, and larger cargo sizes.

U.S. petroleum product exports rose slightly in the first half of 2019 –In the first half of 2019, the United States exported an average of 5.47 million barrels per day (b/d) of petroleum products, an increase of 19,000 b/d (0.3%) from the first half of 2018 and the slowest year-over-year growth rate for any half year in 13 years. Two factors that likely contributed to lower exports were lower U.S. refinery runs in the first half of 2019 compared with the first half of 2018 and slowing global economic growth, which is limiting demand for petroleum products. In the first half of 2019, increased exports of propane and distillate offset decreased exports of all other petroleum products.Distillate remained the largest U.S. petroleum product export in the first half of 2019, averaging 1.3 million b/d, an increase of 60,000 b/d (5%) compared with the first half of 2018. Distillate has many uses, including transportation, manufacturing, agriculture, residential, and commercial activities.Mexico was the largest destination for U.S. distillate exports during the first half of 2019, receiving 290,000 b/d, or 22% of total U.S. distillate exports. Aside from Mexico, U.S. distillate exports go mostly to Central and South America, including Brazil (13%), Chile (7%), and Peru (5%). U.S. distillate exports also go to Europe, mostly to the Netherlands (4%), which is a transshipment country for some of the U.S. distillate volumes.Propane was the second-largest U.S. petroleum product export in the first half of 2019, at 1.03 million b/d, an increase of 142,000 b/d (16%) from the first half of 2018. Propane is used as a space heating and transportation fuel and as a petrochemical feedstock. Most U.S. exports of propane are destined for use as a petrochemical feedstock, mainly at facilities in Asia and Europe. U.S. residual fuel exports declined the most between the first half of 2019 and the first half of 2018, falling by 74,000 b/d to average 258,000 b/d. In the first half of 2018, Singapore was the top destination for U.S. residual fuel exports, most likely to supply Singapore’s marine bunkering market. However, in the first half of 2019, trade press reported that Singapore’s bunker market was preparing for new international regulations that limit the sulfur content of marine fuels by drawing down higher sulfur residual inventories to make room for inventories that are lower in sulfur. As a result, average U.S. exports of residual fuel oil to Singapore decreased 68,000 b/d (80%) in the first half of 2019 compared with the first half of 2018.

Carlyle Group quits $1 billion U.S. oil export project – (Reuters) – Carlyle Group (CG.O) said on Friday it had dropped out as a stakeholder in Lone Star Ports LLC, which proposed a $1 billion crude oil export terminal near Corpus Christi, Texas. Sean Strawbridge, chief executive of the Port of Corpus Christi, said Carlyle notified the port on Oct. 8 it would no longer proceed with its investment. That left construction company Berry Group as the sole backer. Carlyle said in a statement Berry Group was “now the sole owner of Lone Star,” but did not comment on why it dropped out of the project, which it said continues to be actively developed. Lone Star in September filed a lawsuit against Carlyle in a Texas state court, alleging the private equity firm breached its contract to jointly pursue the project and asking the court to award it full ownership. The lawsuit also sought unspecified damages. The project was one of at least nine crude oil export terminals proposed for the U.S. Gulf Coast to load U.S. shale oil onto supertankers that carry around 2 million barrels apiece. Carlyle was competing with projects in the same area proposed by commodities trader Trafigura AG and refiner Phillips 66.

Natural gas exports to Mexico swell, but is a tidal wave coming? – For some time now, natural gas producers in the Permian and the Eagle Ford have been counting on rising pipeline exports to Mexico to help absorb a lot of the incremental production in their plays. Their hopes have been bolstered in the past couple of years by the build-out of a number of new pipelines from the Waha and Agua Dulce gas hubs to the U.S.-Mexico border. Gas pipeline development south of the border hasn’t kept pace, though, mostly due to regulatory and construction delays. Also, a recent dispute over tariffs on a newly completed large-diameter pipeline, extending from the southern tip of Texas to key points along Mexico’s Gulf Coast, had left the pipe sitting empty this summer. That tiff has since been resolved and gas is flowing on the new pipeline, allowing those piped southbound exports to hit a daily record high near 5.9 Bcf/d earlier this month and average above 5.5 Bcf/d this month to date. Plus, progress is being made on other planned Mexican pipes too. This all leads us to ask, is the long-promised surge in U.S. gas exports to Mexico just around the corner? Today, we look at the latest developments regarding Mexico’s natural gas pipeline infrastructure additions. We’ve covered the natural gas pipeline infrastructure build-out in Mexico from almost every angle, from initial planning to pipeline-by-pipeline reviews, to a look at Mexico’s increasingly open gas market. Today, we’ll provide an overdue update, including a discussion about what’s been happening with one of the biggest long-haul pipeline additions: TC Energy and IEnova’s 2.6-Bcf/d Sur de Texas-Tuxpan Pipeline (STP), whose in-earnest start-up was set back for months by a stand-off between the Mexican government’s then-new administration and the project’s developers over the pipeline’s rates – the government said they were too high, and TC Energy and IEnova said a deal’s a deal. (More on this in a moment.) First, let’s take a big-picture look at the current status of gas pipeline development down Mexico way.

Unlikely alliance fighting pipeline in Texas Hill Country (AP) – One of the longest proposed new natural gas pipelines in the U.S. is set to run through Heath Frantzen’s property in the Texas Hill Country, where more than 600 white-tailed and trophy axis deer graze on a hunting ranch his family has owned for three generations. Fearing financial ruin and conservation risks, Frantzen and dozens of other landowners in central Texas have banded together with environmental groups and conservative-leaning city governments in opposing the route of pipeline giant Kinder Morgan’s 430-mile (690-kilometer), $2 billion natural gas expressway. “We know a lot more today about the aquifers, we know a lot more today about the endangered species, we know a lot more today about the sensitivity of the environment,” Frantzen said. “And putting a pipeline project through an area such as this, especially when you can compare it to some of the other places where they could put it even less expensively and with much greater ease – this is an idiotic idea.” But Kinder Morgan has defended its proposal, stating it’s looking to ease a pipeline shortage and help drillers transport gas trapped in West Texas’ thriving Permian Basin to refineries on the Gulf Coast. Now, the company is exercising eminent domain as a nasty legal battle over the path of the pipeline threatens to jeopardize future projects passing through central Texas. Opponents of the route are also challenging state regulators at the Texas Railroad Commission who gave Kinder Morgan the green light while accepting millions of dollars from the oil and gas industry.

Landowners Got One Hill Country Oil Pipeline Moved. But Can They Do It Again? – The Texas Observer A month after news surfaced that a pipeline proposed by a Texas-based petroleum juggernaut would run across the Edwards Aquifer, the primary source of water for San Antonio and other cities, the company said it would shift the pipeline’s path. It was a difference of only four miles, but Hill Country residents opposing the project cheered the change – a major victory given that the oil and gas industry typically doesn’t kowtow to landowners’ concerns.So why the monumental move by Enterprise Product Partners, a $5 billion oil and natural gas company headquartered in Houston?The controversy started last month, when Bandera County landowners began receiving letters from the company informing them that they were in the path of the pipeline stretching from Midland to just southeast of San Antonio. The Rivard Report, which broke the news, pointed out that the pipeline would also cut through the Edwards Aquifer’s recharge zone – and that a spill in the area could taint a crucial Texas drinking water supply. “This is extremely troubling news to all of us in the Bandera Canyonlands, especially the affected landowners,” one resident told reporter Brendan Gibbons.Landowners implored Enterprise executives to listen to their concerns, and in an unlikely twist, the execs raced down to the Hill Country to listen. The company capitulated; it would move the pipeline out of the recharge zone. Don’t chalk the about-face up to the company’s benevolence, though. It might have helped that among the contingent of rankled landowners was Dan Hord III, a Midland oil and gas executive whose family owns ranchland in the county. Hord is a partner at HEDLOC Investment Co. LLC, a petroleum investment firm; he also sits on Baylor University’s board of regents. His wife, Jenni Hord, operates a property development and leasing firm and wasappointed by Governor Greg Abbott to the board of Humanities Texas in 2015. It’s impossible to know exactly how much sway the Hords held in the meeting, but after the path had been shifted, Dan Hord was clearly appreciative, telling the Rivard Report, “Enterprise has done a great job of evaluating it and doing the right thing.” He did not respond to an Observerrequest for comment. Enterprise’s proposal is not the only hotly contested pipeline project scheduled to bisect the Hill Country in coming years: Kinder Morgan’sPermian Highway Pipeline will carry natural gas from West Texas to the Gulf of Mexico, slicing through water supplies and the habitats of endangered species on its way. The damage, both to property values and wildlife, could be astronomical, which is why treehuggers and private property types are banding together against the project. Thus far, Kinder Morgan hasn’t budged. So what are the chances that the relative success against one pipeline project could translate into success against another?

Texas Supreme Court to decide epic legal battle between Enterprise, Energy Transfer – – For one side it was a partnership; for the other, it was simply “a feasibility study.” Now, two of the state’s biggest pipeline companies are near the culmination of an eight-year court battle that legal experts say is one of the most important business disputes to be decided by the Texas Supreme Court since the epic fight between Pennzoil and Texaco in the 1980s. That case, which turned on the question of whether a handshake agreement constituted a binding contract, ended with Pennzoil winning a jury award of nearly $10.4 billion award and Texaco in bankruptcy. This case pits the Dallas company Energy Transfer Partners against Enterprise Products Partners of Houston and revolves around the issue of whether they legally formed a joint venture to develop $1 billion pipeline to transport oil from the storage hub in Cushing, Okla. to Houston. Enterprise ulitmately bolted the arrangement and teamed up with the Canadian pipeline company Enbridge to build a similar project, which was completed in 2014.Energy Transfer sued in 2011 and won a verdict of $535 million three years later when a Dallas jury found that Enterprise breached its fidcuiary duty. The verdict, however, was overturned on appeal. Earlier this month, the Texas Supreme heard arguments in the case. A decision is expected over the next several months. The dispute has similarities to the Pennzoil case in that both center on what constitutes a binding agreement between businesses. In the earlier case, Pennzoil reached agreement to acquire Getty Oil, shook hands on it and put out a press release announcing the deal. Texaco then swept in with more money to snatch Getty from Pennzoil, which sued Texaco, claiming it had intentionally interfered with a contract. Texaco argued that no contract was signed, so claims of interference didn’t hold. The jury and appellate courts sided with Pennzoil. No contract was signed in the Energy Transfer v. Enterprise Products case, either. But Energy Transfer argues that after months of working together, the companies, under Texas business law, had entered into what was essentially a common law marriage, as binding as formal one. Enterprise, however, says the companies never finalized the joint venture and neither company’s board of directors approved such a venture.The dispute dates back to the spring of 2011, when demand for transporting oil and natural gas from Cushing to Houston was strong. Executives at Energy Transfer and Enterprise entered into a non-binding agreement to build a pipeline, which they called the “Double E.” Both companies started marketing the pipeline and even reached a tentative deal in August 2011 with Chesapeake Energy to transport 100,000 barrels a day to Gulf Coast refineries A month later, however, Enterprise announced it was breaking up with Energy Transfer to do a separate pipeline deal with Enbridge. Energy Transfer sued Enterprise, claiming the two competitors illegally conspired to cut it out of a profitable project. Enterprise responded that it never formed a legally binding partnerhship.

Texas Municipal League adopts resolution seeking state legislation on pipeline routing – The Texas Municipal League has adopted a resolution that formally asks the state of Texas to pass legislation that would mandate greater oversight of oil and gas pipeline routing.The vote took place Oct. 10 at the annual TML conference.Resolutions that share some similar themes have been passed by local jurisdictions – including the cities ofSan Marcos, Buda, Kyle and Austin as well as Hays County and Hays CISD – over the course of 2019 in the face of the Permian Highway Pipeline, a 430-mile natural gas pipeline that Kinder Morgan plans to build through the Hill Country.The TML resolution asks for a state regulatory process that would require public input during routing, enable negotiation on the routes, and mandate compliance with economic and environmental study standards, among other items.Lack of transparency in the exercise of eminent domain by private pipeline companies as well as thepotential environmental impact of pipelines on sensitive regions have both been the topic of legal challenges to Kinder Morgan and federal and state agencies over the Permian Highway project.

Layoffs Hit Stevens Tanker, Amazon Contractors – Closures and layoffs continue to vex the trucking industry in 2019, but three recent downsizings were attributed by the companies involved more to the vicissitudes of the energy, retail and final-mile industries than to a slowdown in the overall freight market. Stevens Transport of Dallas notified employees on Sept. 25 that it is shuttering its tanker division due to weakened demand from hydraulic fracturing, or fracking, activity in the Southwest. The carrier will lay off 586 employees as a result, according to records filed with the Texas Workforce Commission. The company said in a letter that it would cease all tanker business on Oct. 15.Clay Aaron, president of Stevens Transport, confirmed the closure in an email to Transport Topics.“The decision to close Stevens Tanker Division came only after a careful analysis of the volatility in the oil and gas sector combined with the near-and-long-term forecasts regarding return on invested capital,” Aaron said. “We believe this course of action allows us to focus on our legacy refrigerated service business in the truckload, intermodal, dedicated, regional and logistics segments.”Stevens established its tanker division in 2011 to serve oil and gas drilling operations in Texas, New Mexico, Oklahoma and Louisiana.

US oil, gas rig count rises by two amid market uncertainty: Enverus – The US oil and gas rig count inched up by two to 902 this week, rig data provider Enverus said Thursday, amid what is shaping up as a dispirited earnings season characterized by uncertainty on several fronts. Oil-directed rigs rose by four to 728, while gas-chasing rigs were down two to 169. The rig count is currently at 2017 levels, although at the time it was rising. It reached 1,233 in mid-November 2018 before heading back down. The most notable change for the week came from the Eagle Ford Shale in South Texas, which rose five rigs to total 75. The Eagle Ford basin has enjoyed renewed activity in the past year or so, although the gorilla among US plays is the nearby Permian Basin of West Texas/New Mexico where the rig count this week dropped by two to 407. Also rising this week was the gas-prone Haynesville Shale in Northwest Louisiana/East Texas, which was up two to 57. Otherwise, both the Williston Basin of North Dakota/Montana and the Denver-Julesburg Basin, mostly in Colorado, held steady this week at 55 and 24 rigs, respectively. But the SCOOP-STACK play in Oklahoma fell by four rigs, leaving 46. The Dry and Wet Marcellus shales, both mostly in Pennsylvania, each lost rigs. “Dry” fell by three to total 20, while “Wet” fell by one, leaving 16. The Utica Shale, mostly in Ohio, also declined by two rigs, to 15. Tamped-down North American activity characterized initial third-quarter earnings of large oil service giants Schlumberger and Halliburton to kick off the earnings reporting season this past week, setting a glum mood as larger oil-focused exploration-and-production companies prepare to report in the next few weeks. Jeff Miller, CEO of oil service giant Halliburton, said earlier this week in his company’s Q3 call that the US land rig count declined 11% from Q2 to Q3 for the first time in a decade. And Q3, historically the busiest quarter of the year for US hydraulic fracturing, saw stage counts — that is, fractured intervals — decline every month in Q3. Drilling and completions are not only softening, but “the cadence of activity will likely remain the same over the near term,” Miller said. Analysts say operators are widely basing their budgets on $50/b oil or lower, based on recent oil price volatility and macro uncertainty. Meanwhile, the buzz words of the big E&Ps during upcoming calls will be capital discipline, liquidity, and free cash flow. “We see a number of E&Ps walking down 2020 expectations this earnings season,”

US Rig Count Plummets by 21 | Rigzone – The U.S. has seen its rig count decline for the second week consecutive week, after snapping an almost two-month streak of declines. The nation dropped 17 oil rigs and four gas rigs for a net loss of 21 rigs, according to weekly data from Baker Hughes Co. Twenty of them were land rigs and one was an offshore rig. This brings the U.S.’ total number of active rigs to 830, down 238 from the count of 1,068 one year ago. Oklahoma led all states in losses with a drop of six rigs. The following states also idled rigs this week: Texas (-5) North Dakota (-2) Wyoming (-2) Louisiana (-1) New Mexico (-1) Pennsylvania (-1) Utah (-1) and West Virginia (-1). Colorado added one rig. Among the major basins, the Permian dropped five rigs. The Permian’s number of active rigs now sits at 417, which accounts for more than half of the nation’s total. The Cana Woodford, Marcellus and Williston dropped two rigs each and the Ardmore Woodford and Granite Wash dropped one rig apiece. The Eagle Ford and the Mississippian gained three rigs and one rig, respectively.

Fracking Operations Moving Forward Near El Reno School Despite Opposition From Parents, Neighbors – Operations are moving forward at a fracking site near the Banner School in Canadian County. That’s despite the adamant and vocal opposition by both parents and neighbors. Parents and neighbors currently have a protest pending in front of the Oklahoma Corporation Commission. In general, the commission does not have authority on well locations, but parents are trying every avenue they can to stop the drilling. Still, students and administrators came back from fall break to find the rig erected about 200 feet from the back fence of the school property. “When we came back on Monday, we saw what you see right now,” said Superintendent Michael Prior. Prior and parents said they are concerned about the possibility of an accident or explosion, the noise, traffic, dust and chemicals a fracking operation emits into the air. “It’s an elementary school, there’s dozens of kids here, so I don’t know why they didn’t just go down the road a little bit,” said Kelsey Bell. Chaparral Energy said it has gone to considerable expense to be a good neighbor. The company has erected sound barriers, is spraying the site to keep dust down, and is instructing trucks to avoid the road in front of the school.

What We Know About the Health Impacts of Colorado’s Fracking Boom — Wading through the 380-page report on the health risks of oil and gas drilling released by the Colorado Department of Public Health and Environment on Thursday, October 17, requires parsing a lot of highly technical, carefully phrased findings. “Benzene and 2-ethyltoluene were of primary concern, showing acute HQs above 10 at the selected receptors 500-ft downwind during development activities,” wrote the study’s authors, air-quality scientists with the consulting firm ICF International. “Maximum HQs were between 1 and 10 at the selected 2,000-ft receptor for benzene at all three sites (HQ=1.8 – 5.3; during all activities except for flowback at the Garfield County valley site and fracking at the NFR site, where HQs were below 1).” In an article summarizing their findings in the peer-reviewed Journal of the Air & Waste Management Association, researchers distilled their conclusions into slightly more readable language: “Acute exposures were of greatest concern, primarily during O&G development and for a limited set of VOCs and critical-effect groups, sometimes at distances out to 2,000 feet from the well pad.” Or, simplest of all, in the words of Colorado health officials: “The study found that there is a possibility of negative health impacts at distances from 300 feet out to 2,000 feet.” The study released Tuesday analyzed more than 5,000 air samples collected by researchers from Colorado State University in a pair of emissions studies completed in 2016. At the time, researchers and state health officials hailed the CSU data as one of the comprehensive sets of oil and gas emissions measurements ever recorded. Using modeling tools developed by the Environmental Protection Agency, the CDPHE’s new study extrapolated the measured data into millions of potential exposure scenarios – “many more than can be reasonably observed with monitoring,” its authors note. The result is one of the most robust assessments of the health effects of oil and gas drilling yet completed – and specifically, one that raises the possibility that current “setback” distances mandated by the state aren’t enough to protect many Coloradans from short-term health risks. But while the study is a major development – it’s been the object of a lot of anticipation and speculation since it was first announced three years ago – it’s far from the first attempt to settle the question of whether fracking threatens public health and the environment. These latest findings are best understood in the full context of what we knew long before Thursday’s announcement. Here are three of the most important things to recognize about the impacts of fracking in Colorado and beyond.

• 1. Modern drilling technologies have led to much greater impacts.
• 2. Residents near Colorado drilling sites have reported health impacts for years.
• 3. Hundreds of studies have found links between oil and gas development and health and environmental risks.

Thousands of ‘orphan wells’ spark safety, cleanup fears – Across the West, thousands of oil and gas wells sit idle on federal lands. Some are on hold for better pricing. Others have been left to sit for so long that the risk of abandonment is high. And many are orphaned, the companies that drilled them now defunct. How many of these abandoned wells are out there is unclear. They pose environmental and safety hazards, but, as critics note, the Bureau of Land Management doesn’t have a good way of tracking them. Yet there’s not nearly enough money set aside to plug the ones that are known. Years after a gas price bust in the early 2000s forced oil and gas companies to shutter, federal officials have yet to remove the nonproducing wells from perpetual limbo. “It does pose a risk,” said Frank Rusco, natural resources and environment director at the Government Accountability Office. “Will they be able to reclaim all those wells?” The abandonment challenge continues to expand. The federal government counted 89 wells in the last two years that were newly orphaned on public lands. Each represents a cost to the taxpayer and a risk of hydrocarbons migrating into groundwater resources from decaying infrastructure. BLM, which oversees federal oil and gas leasing and drilling, has been scolded by oversight bodies for not keeping better track of orphans. The agency notes wells that aren’t producing, but critics say it’s slow to affirm that nonproducing wells have just been abandoned. Data revealing the number of orphan wells that should be plugged by BLM doesn’t precisely exist, said Rusco.”They don’t keep the right records to be able to answer that question,” he said of the Interior Department. GAO included the federal oil and gas program on its 2011 “high risk” list of programs that are vulnerable to fraud, abuse and mismanagement in part because the office said it didn’t have a robust system for tracking wells – or demanding money to clean up after an oil firm’s collapse.Earlier this year, GAO reported that 84% of bonds for federal oil and gas development were likely insufficient to cover cleanup costs.

Developer of proposed ‘Bridger Expansion’ pipelines releases new project info – The proposed Bridger Expansion project will entail building two separate oil pipelines: one that straddles North Dakota and Montana, and another in Wyoming. Developer Bridger Pipeline LLC revealed more details about the project this week, launching a website at www.bridgerexpansion.com with information for landowners and others. The 16-inch North Dakota-Montana line will be called “South Bend” and will carry up to 150,000 barrels of oil per day from Johnsons Corner in McKenzie County to Baker, Mont. It will extend for 137 miles across the two states. The Wyoming line will be known as “Equality” and will transport up to 200,000 barrels of oil per day from Hulett, Wyo., to Guernsey, Wyo. From there, oil will be taken to market on other pipelines, including the proposed Liberty line, which is a separate project by Bridger and Philips 66 that’s slated to run to Cushing, Okla. Cushing is a major oil hub. It offers storage space for crude and serves as a starting or ending point for many pipelines. Some of those lines carry oil to Gulf Coast refineries or ports, where American oil is then shipped overseas. “It’s all about access to national and international markets,” Bridger spokesman Bill Salvin said. Bridger operates several gathering and transmission pipeline systems in North Dakota, Montana and Wyoming. The company already has lines that run between Montana and Wyoming to connect the two new lines it’s proposing as part of its expansion. “Those are adequate for us to carry existing barrels and the new barrels we’re going to carry,” Salvin said. Bridger has not disclosed the cost of the expansion project. Salvin said the new lines will help increase the value of oil produced in North Dakota, as they will add more pipeline capacity to carry the state’s oil to market. Some Bakken oil still travels on train, which tends to be a more expensive method of transportation.

South Dakota Backs Off Harsh New Protest Law and Its ‘Riot-Boosting’ Penalties – South Dakota officials have agreed to walk back parts of the state’s new anti-protest laws that opponents say were meant to target Native American and environmental advocates who speak out against the proposed Keystone XL crude oil pipeline.Gov. Kristi Noem and state Attorney General Jason Ravnsborg agreed in a settlement Thursday with Native American and environmental advocates that the state would never enforce portions of the recently passed laws that criminalize “riot boosting” – which it applied, not just to protesters, but to supporters who encourage but never take part in acts of “force or violence” themselves. The settlement, which makes permanent a temporary ruling issued by a federal judge in September, has immediate implications for opponents of the Keystone pipeline in South Dakota and could challenge the validity of similar laws targeting pipeline and environmental protestors in other states. “People can continue to organize and show up in public places and speak out against these projects without any fear of retribution or being identified as rioters and face potential felonies,” said Dallas Goldtooth, an organizer with the Indigenous Environmental Network and a plaintiff in the lawsuit that challenged the rules. “I think it’s immense,” he said. “We have legal precedent that is shooting down these anti-protest laws that are being replicated across the country.” At least seven other states have passed harsh penalties for protesting near oil or gas pipelines or interfering with the infrastructure since the start of the Trump administration, according to the International Center for Not-for-Profit Law, which tracks the legislation. Several of those laws were based on a model bill promoted by the American Legislative Exchange Council, an industry-backed group. In September, a group of Greenpeace activists in Texas who shut down the Houston Ship Channel by dangling from a bridge became the first group charged under any of the new protest laws. The joint settlement agreement in South Dakota does not repeal the state’s anti-riot laws. Instead, the governor and attorney general agree never to enforce sections of the laws focusing on speech. For example, the state will no longer enforce part of an existing law that says a person who does not personally participate in a protest “but directs, advises, encourages, or solicits other persons to acts of force or violence” can be found liable for riot boosting.

The connection between pipelines and sexual violence – In 2017, 5,646 Native women were reported missing in the United States. Nationwide, the murder rate for Native women is ten times that of the average American; in Montana, Native citizens are 6.7 percent of the population, yet between 2016-2018, they made up 26 percent of the state’s missing persons reports. Some of the factors are easy to identify: jurisdictional confusion between local state-run police, the FBI, and tribal or Bureau of Indian Affairs police departments routinely leads to slow response times; slow response times allow for bodies, and thus the perpetrator’s DNA, to decompose and disappear; and slow response times lead to cold trails and dead-end cases, which make local law enforcement hesitant to undertake new cases. In 2017, U.S. attorneys declined to prosecute 37 percent of Indian Country cases, citing lack of evidence in 70 percent of the cases they dropped. But who, exactly, is responsible for these Native women disappearing? That answer is much more complex. Sometimes, as in the case of Northern Cheyenne woman Hanna Harris, it’s a pair of non-tribal citizen transients; other times, it’s a member of the tribal community; and still other times, it’s a trucker or a passerby temporarily stopping through the reservation, dipping in and out of up to three different law enforcement jurisdictions before the community can even realize someone is missing. Man camps, also described as “work-camp modular housing,” are temporary housing communities set up for the well-paid, typically male laborers that are tasked with constructing pipelines snaking their way above, across, and below our nation’s waterways and lands. More often than not, these routes, and as a result the man camps, find themselves cutting through or just outside of rural tribal nation lands and other marginalized communities. A number of studies, reports, and congressional hearings now connect man camps – which can be used in mines and other extractive efforts as well – with increased rates of sexual violence and sex trafficking. The most well-documented cases thus far have occurred in the Tar Sands region of Alberta, Canada, as well as in western North Dakota and eastern Montana – an area known otherwise as the Bakken oil fields – though such activity is in no way exclusive to the region. Because pipelines are typically routed through rural communities, local law enforcement, often times already stretched thin, are left trying to police a sudden, months-long influx of hundreds of outsiders. This was among the many points underscored in June, when Canada’s federal government released its MMIWG report, a years-long study undertaken by the federal government that declared the missing and murdered indigenous women epidemic a state-induced genocide. Among the findings presented in the 1,200-page document, the Canadian government pinpointed extractive industries and man camps as hotbeds of violence.

Oil pipeline fuels fears in Native American reservations – It’s been three years since thousands of protesters, environmentalists and more than 95 Native American nations gathered in a field-turned-campsite on the fringes of Standing Rock reservation, attempting to stop the Dakota access pipeline from being built a short distance from the reservation’s land. Their efforts mostly proved in vain. Since June 2017, the pipeline – known as DAPL – has been carrying about 570,000 barrels of crude oil from the Bakken Formation in northwest North Dakota to Illinois every day. And although Standing Rock’s remote expanses across North and South Dakota have since turned quiet, local residents find themselves facing a new dilemma. Not only is the pipeline now set firmly underground, its parent company, Energy Transfer Partners (ETP), in June announced plans to double DAPL’s capacity. Currently the pipeline carries crude oil on a route running within a mile of Standing Rock and under the nearby Missouri river, an important water source for communities and businesses across the reservation. The proposed increase would result in the equivalent of more than 70 Olympic-sized swimming pools of oil pass through the pipeline every day. Tribal leaders fear the heightened capacity could further increase the possibility of a major oil leak or spill, with the pipeline section buried deep under the Missouri river of particular concern. “That’s greatly increasing the risk, and the harm from a potential release,” says Elliott Ward, the Standing Rock Sioux Tribe’s emergency manager. “They [the operating company] say they have [leak] detectors, but we know their spill detection track record is grossly inefficient. If there’s a spill that’s less than one per cent, it won’t detect it at all. That’s still 6,000 gallons [a day] that could be leaking that their sensors won’t detect.” A judge in North Dakota has granted the tribe a request to intervene in the increased capacity plan, and it will take part in a public hearing scheduled for November 13th.

Corps: No more Dakota Access Pipeline study needed (AP) – An attorney for the Army Corps of Engineers is asking a judge to sign off on the Corps’ conclusion that the Dakota Access oil pipeline doesn’t harm American Indian tribes. The Corps wants U.S. District Judge James Boasberg to rule in favor of its August 2018 finding that no more environmental study is needed on the $3.8 billion pipeline. The pipeline has been moving North Dakota oil through South Dakota and Iowa to Illinois for more than two years. The Standing Rock Sioux want the pipeline shut down and more study done. The tribe fears an oil spill could contaminate the Missouri River. The Bismarck Tribune reports that a Justice Department attorney argues that the Corps “carefully and reasonably considered the environmental impacts” before it permitted the pipeline. Pipeline developer Texas-based Energy Transfer says the line is safe.

Living In The Plastic Age – More Propane-Consuming PDH Plants Are On The Way — The ready availability of low-cost propane, the expectation of renewed growth in global propylene demand and other factors are spurring development of another round of propane dehydrogenation plants in North America. Three PDH plants – two in Alberta and one in Texas – already are under construction and scheduled to come online in the 2021-23 period. Now, Enterprise Products Partners has committed to building a second PDH plant at its NGL/petchem complex in Mont Belvieu, TX, and PetroLogistics – which completed the U.S.’s first PDH plant in 2010 – has selected the technology it will use for a new facility it now plans to build along the Gulf Coast. Today, we discuss planned PDH capacity additions in the U.S. and Canada and what’s driving their development. As we said in our On Purpose blog a few months ago, propylene is a particularly useful chemical building block. About two-thirds of the propylene produced is used to make polypropylene (PP) – one of the best-selling plastics, second only to polyethylene – which is used to make (among other things) automotive parts, reusable shopping bags and plastic storage containers. Most of the rest is used to produce acrylonitrile, propylene oxide, oxo alcohols, cumene and isopropyl alcohol, which are used to make polyurethanes, polycarbonates and other materials that are part and parcel of a myriad of everyday products. Global demand for propylene has been increasing at an average of about 5.2 million metric tons per annum (MMtpa) – a 3.6% compound annual growth rate (CAGR) – while North American demand is growing at a more modest average of 390,000 metric tons per year (Mtpa), for a CAGR of 2.2%. The problem is that the traditional “co-product” sources of propylene supply (steam crackers and refineries) have not kept up with demand. This is largely due to two Shale Era-related changes. First, refineries have been shifting their crude slates to lighter oils. And second, the steam-cracker sector has been shifting from old-standby feedstocks like propane, normal butane and naphtha, each of which produce 40 pounds or more of propylene for every 100 pounds of ethylene (the primary product of steam crackers), to ethane, which typically produces only 4 pounds of propylene for every 100 pounds of ethylene.

US Leads World in Oil Production – But for How Long? – The United States now leads the world in oil production and is, to a large extent, energy independent. The United States still imports 11 percent of its oil, the lowest percentage since 1957. But how long will the United States’ top position in oil and natural production last? It’s not as clear cut at it may appear to be at the moment. Much of the United States’ new oil and natural gas production comes from a controversial extraction process known as hydraulic fracking. Hydraulic fracking was first widely used in the 1960s, and yet had been invented a century earlier. Unlike traditional oil production, which involves drilling holes into the earth until reaching enormous underground oceans of oil (the Middle East), fracking extracts oil from shale rock by forcing high-pressure liquid into layers of the shale deep underground. But hydraulic fracking is controversial for several reasons.Critics say fracking depletes local drinking water supplies, pollutes the air, has toxic impacts on people in the area, and contributes to greenhouse gases. But perhaps most well-known is the suspicion that fracking is causing earthquakes where they haven’t historically occurred. Scores of tremors have been felt in places such as Oklahoma, Texas, Arkansas, Ohio, West Virginia, and other locations that scientists attribute to the fracking process.But there’s another, lesser-known controversy about fracking that’s alarming oil and gas industry experts. Fracking wells are drying up much faster than traditional wells. According to industry analyst Alex Beeker, “In the first years of production, there is a rush of oil and gas that declines rapidly.” In order to keep up with demand, more fracking wells have to be drilled quicker because they run dry quicker. Some analysts think hydraulic fracking may not be the long-term foundation for the United States’ energy independence. Scott Forbes, an industry analyst and vice president of the Lower 48 for Wood Mackenzie, believes the current fracking model is unsustainable and, therefore, may be a short-lived phenomenon. Paradoxically, the fracking industry could actually become a victim of its own success. The political and economic need to keep fuel prices low could actually result in hydraulic fracking companies crashing and burning, at least under the current operating model. Rapid and continuous drilling is expensive and often doesn’t deliver positive results, which is why Wall Street isn’t investing in the industry the way it used to. But without sufficient profit margins, those costs may eventually outpace the revenues.

Elizabeth Warren’s policies could drive oil prices higher and help Exxon – Democratic presidential candidate Elizabeth Warren has sent chills through the oil sector with her comments about banning fracking and off shore drilling, but her policies could drive oil prices higher if she were elected, according to Strategas Research.As the prospects of a Warren nomination have grown, so has fear that the Massachusetts Senator would take action to curb the U.S. oil industry which has turned the U.S. into the world’s largest oil producer over the last decade. The U.S. now produces about 12.6 million barrels a day, more than either Saudi Arabia or Russia.In a Sept. 6 tweet, Warren said on her first day as president, she would sign an executive order putting a total moratorium on all new fossil fuel leases for drilling offshore and on public lands. She also said she would ban fracking everywhere.“What we’re arguing is if there is a tax placed on carbon production, or there are limits on drilling, it increases the price of the commodity,” said Dan Clifton, head of policy research at Strategas. “What’s happening here is the beneficiaries are going to be large, integrated oil companies, like Exxon Mobil, which pays a very large dividend and can withstand regulation.” If U.S. drilling were to slow, so would U.S. exports which were first permitted during the end of the Obama administration. The U.S. exported about 3.2 million barrels of oil two weeks ago, according to the latest U.S. government data. The loss of U.S. oil both at home and abroad would mean higher prices, something OPEC and Russia have been trying to achieve through production cuts.

Halliburton stacks more frack crews amid weak third quarter demand — Declining activity in U.S. shale fields continued to sting Houston oilfield service company Halliburton during the third quarter where the company stacked more hydraulic fracturing crews and deployed other cost-cutting measures. The company reported a $295 million profit on nearly $5.6 billion revenue during the third quarter. The figures were down compared to the $435 million profit on $6.2 billion revenue during the third quarter of 2018. Halliburton’s third quarter profit translated into earnings per share of 34 cents, down compared to earnings per share of 50 cents during the same time period last year. The company’s third quarter earnings were down compared to Wall Street expectations of $5.8 billion in revenue and earnings per share of 34 cents. Service Sector: Schlumberger posts $11.4 billion loss amid hefty pretax charges Although revenue grew in Latin America, Europe, Africa, the Middle East and Asia, Halliburton’s third quarter revenue from North America declined by $790 million when compared to the same period last year. During a Monday morning investors call, Halliburton CEO Jeff Miller said the company has stacked hydraulic fracturing crews and deploying cost-cutting technology. “In the third quarter, we stacked more equipment than the previous six months combined,” Miller said. “While this impacts our revenue, we would rather err on the side of stacking than work for insufficient margins and wear out our equipment.” Looking ahead, Halliburton expects demand from North America to remain weak. Alongside the holidays and colder weather, the company anticipates current crude oil prices – which are in the low $50 per barrel range – will continue to result in decreased customer spending. Deploying cost-cutting measures that will save the company $300 million of savings over the next three quarters, Miller believes the company will be able to weather the storm. “Regardless of the cuts and idling of equipment, our size and scale of our business North America gives us the ability to drive a sustainable model without sacrificing our leadership position,” Miller said.

Halliburton vows more cost cuts as shale demand dwindles, shares rise – (Reuters) – Halliburton Co on Monday promised more cost cuts after reporting a bigger-than-expected drop in quarterly revenue as the oilfield services looks to counter weak demand from North American shale producers, sending its shares up about 7%. The biggest hydraulic fracking services provider, which earlier this month cut 650 jobs in North America, said it would take steps over the next few quarters that will lead to $300 million in annualized cost savings. Oilfield service providers are struggling with reduced spending by oil and gas producers as investors push for higher buybacks and dividends rather than growth in a weak oil price environment. Larger rival Schlumberger NV said on Friday it had recorded a $1.58 billion goodwill impairment charge related to its pressure pumping business in North America. “HAL is taking costs out more aggressively than the Street forecast, which it expects to lead to strong Q4 operating margin improvement in the Drilling & Evaluation segments despite falling revenue,” said Anish Kapadia, founder of London-based oil and gas consultancy firm AKap Energy. Halliburton warned of further activity declines in North America, with fourth-quarter revenue for its hydraulic fracturing business declining by low double digits and margins by 125 basis points to 175 basis points.

Schlumberger takes $12 billion charge as CEO charts new course – Schlumberger’s new chief executive wielded an axe to the company’s asset-heavy businesses, taking a $12.7 billion charge in the face of weaker shale drilling and sliding profits. The move, by Olivier Le Peuch, writes down his predecessors’ big investments that took the world’s largest oilfield services company deeper into shale and oilfield operations and shows that he intends to shift the company toward more asset-light software and services-driven businesses. The charge, amounting to nearly 18% of value of the company’s assets, drove an $11.4 billion loss, the largest in the company’s history. However, shares rose 2% to $32.53 in mid-day trading as investors looked past the writedowns and focused on improved international operations and adjusted profits that topped Wall Street estimates. Excluding the charges, Schlumberger earned 43 cents a share, above the 40 cents estimated by analysts. While revenue, at $8.5 billion, was flat compared with the same period a year earlier, sales rose in all regions except for North America.

Schlumberger Rips Off Band-Aid With $12.7B Writedown — Wall Street guessed that writedowns from Schlumberger Ltd. were coming, but some analysts were taken aback by the sheer size of the $12.7 billion in pretax charges reported by the oil services company on Friday. The company’s earnings report was its first since Chief Executive Officer Olivier Le Peuch took the reins in August. The writedowns led the company to post its largest net quarterly loss in at least a decade. Schlumberger said on its earnings conference call that the writedowns were part of the new CEO’s strategy. The size of the charges was “eyebrow-raising,” analysts at Tudor, Pickering, Holt & Co. said in a note after the report was released. “Better to rip Band-Aid off sooner vs. later.” Most of the charges — $8.8 billion — comprised writedowns on goodwill, the intangible asset on a corporate balance sheet that typically arises after the acquisition of another company. Schlumberger cited its 2010 purchase of Smith International Inc. and its takeover of Cameron International Corp. in 2016, and the subsequent deterioration in market conditions. Schlumberger Sees Foreign Revival as U.S. Oil Drilling Slows Schlumberger also reported a $1.58 billion charge related to its pressure-pumping business in North America, where the fracking industry is slowing. Citing “ongoing economic challenges in Argentina,” it recorded $127 million of charges due to its activities in the country. It also had $62 million of severance costs in the quarter.

UBS, Simmons Energy pare bankers as shale M&A slows: sources – (Reuters) – UBS Group AG and the energy arm of Piper Jaffray Companies have cut staff in their oil and gas investment banking teams, three people familiar with the matter said on Monday, as U.S. dealmaking continues to dry up. Mergers and acquisitions activity within the shale business is at its lowest level in a decade, excluding Occidental Petroleum Corp’s purchase of Anadarko Petroleum Corp, as shareholders squeeze producers to focus on returns and develop existing acreage rather than expansion. The decline has left investment bankers that advise on such transactions without enough work. UBS declined to comment. Simmons Energy, which is a division of Piper Jaffray, did not reply to requests for comment. Those departing UBS and Simmons Energy were focused on sales of acreage and smaller assets, known in the industry as the acquisitions and divestitures (A&D), and left in the last couple of weeks, according to the sources, who spoke on condition of anonymity as the information is not public. Among those departing the Swiss bank are Managing Directors David Edwards and Miles Redfield, among the most senior names in the unit. Around half of the A&D team at UBS was dismissed, which previously consisted of around a dozen bankers, according to one of the sources. A second source said the number who left was fewer than 10.

Investors starve US shale drillers of capital – The money pipeline is running dry for large portions of the US shale oil sector, tipping drillers into bankruptcy and threatening the industry’s breathtaking growth in oil production. Spooked by lower oil prices, equity and bond investors are now shunning the smaller, independent shale explorers that lifted the US to the top rank of global oil producers. Meanwhile, say analysts, banks have pulled in their horns, and are likely to further restrict companies’ capacity to borrow when they begin their twice-annual reviews of loans secured by oil and gas reserves. Market-watchers expect this financing squeeze to trigger a wave of mergers among smaller companies in the Permian Basin and other shale-oil regions. Public investors believe the sector has “five to 10 too many” companies and want to see a consolidated industry with greater scale, less debt and better control of capital spending, said Matt Portillo, managing director for upstream research at investment bank Tudor, Pickering, Holt & Co. The financial reckoning has been a long time coming. In the aftermath of the 2014-15 oil price crash, US oil and gas producers managed to raise $56.6bn from equity and debt capital markets in 2016, according to Dealogic. This year they have raised just $19.4bn, even though US oil production has grown by more than a third in the past three years. As funding becomes scarce, bankruptcy filings are on the rise this year. Haynes and Boone, a law firm, counted 33 by the end of September, 27 of them since May, which is almost as many as in the whole of 2018. This month EP Energy filed for bankruptcy with $4.6bn in debt, citing “challenging dynamics as a result of depressed commodity prices.” Bankruptcies have turned off fund managers. Among 240 high-yield mutual funds tracked by data provider Morningstar, about three-quarters have less than 10 per cent of their assets invested in energy – much less than a neutral weighting of 14 per cent. “It feels like the beginnings of high-yield throwing in the towel on energy companies,” said John McClain, a portfolio manager at Diamond Hill Capital Management in Columbus, Ohio. Banks are currently reappraising the value of oil and gas reserves underpinning loans to producers. As the twice-annual review gets under way, they are using more conservative assumptions for future oil and gas prices. Mr Portillo at Tudor, Pickering, Holt estimates this shift will lead to a 10-25 per cent reduction in loan facilities extended to weaker producers in 2020.

Frackers Float ‘Shale Bonds’ as Traditional Investors Flee – WSJ –Desperate for cash, shale companies are trying to court investors with a new and potentially risky financial instrument that resembles mortgage bonds. The companies are floating a type of asset-backed security that involves existing oil and gas wells. Producers transfer ownership interests in the wells to special entities that then issue bonds to be paid off by the output from the wells over time.

UK government ‘uncertain’ on shale gas decom costs – The UK’s shale struggling gas industry faces a challenge of defining who is liable for decommissioning costs, with the government unable to provide answers at present, according to a report.The report, “Fracking for shale gas in England”, by the UK’s Comptroller & Auditor General and published by the National Audit Office (NAO) on Wednesday, also highlights the rise in opposition to shale gas hydraulic fracturing in England in recent years.The report, which is not intended to examine the merits of government’s support for fracking, acknowledged that “progress in establishing a shale gas industry in England has been slower than government planned”. A core thrust of the report is laying out the costs associated with the government’s backing for shale gas extraction to date, while looking at potential future costs.“Fracking has already placed financial pressures on local bodies, including local authorities and police forces, and other costs have been borne by a range of government departments and regulators,” a statement accompanying the report read. “The full costs of supporting fracking to date are not known by the Department [for Business, Energy and Industrial Strategy], but the NAO estimates that at least £32.7 million [$42.3 million] has been spent by public bodies since 2011.” Although the costs are relatively miniscule, the report raises the issue of decommissioning costs, pointing out that the UK’s onshore shale sector does not have the same level of regulation in place for such costs as its mature offshore sector. “The Department recognises its responsibility for decommissioning offshore oil and gas infrastructure, but not for onshore wells, including shale gas wells,” the statement continued. The report points out that some landowners may take out insurance as part of their lease negotiations with operators, although there is an acknowledgement from the Department that landowners may not fully understand the liability they are taking on.

Fracking farce: Industry fails to live up to its promise with just three of 20 wells drilled, says spending watchdog — Hopes that fracking would rival North Sea gas have failed to materialise, according to the National Audit Office. David Cameron’s government had predicted the development of a £33billion industry with 64,500 jobs. The Cabinet Office said in 2016 that 20 wells would be in operation by mid-2020. But the NAO reported that only three had been drilled. All three wells have been made by Cuadrilla at Preston New Road in Lancashire. Fracking has ceased there however after drilling triggered an earthquake that breached environmental regulations. Operators have complained that UK rules are stricter than in other countries, which would permit larger tremors than the 2.9 magnitude tremor at the Cuadrilla site. The NAO report said ministers do not expect fracking to lead to lower energy prices. Instead the emphasis is on ‘energy security’ with less reliance on foreign states and gas imports expected to rise as North Sea reserves run down. The NAO said fracking has proved costly for local authorities and police forces, which manage protests at the sites. The report estimated that at least £32.7million has been spent by public bodies since 2011, although the full costs are not known. A combined bill of £13.4million has been picked up by Lancashire Constabulary, North Yorkshire Police and Nottinghamshire Police. The NAO said public support for fracking was lower than for other energy sources and has fallen over time. The Government attributes the slow progress of fracking to low public acceptance. Concern about fracking operations centres around greenhouse gas emissions, groundwater pollution and fracking-induced earthquakes. The report says landowners may be liable for the decommissioning costs of sites should an operator be unable to cover them – but arrangements are ‘unclear and untested’.

UK to use £1bn meant for green energy to support fracking in Argentina – The UK is planning to invest in Argentina’s controversial oil shale industry using a £1bn export finance deal intended to support green energy, according to government documents seen by the Guardian. UK Export Finance, the government’s foreign credit agency, promised in 2017 to offer loans totalling £1bn to help UK companies export their expertise in “infrastructure, green energy and healthcare” to invest in Argentina’s economy. Instead official records, released through a freedom of information request, have revealed the government’s plan to prioritise support for major oil companies, including Shell and BP, which are fracking in Argentina’s vast Vaca Muerta shale heartlands. One government memo, uncovered by Friends of the Earth, said that while Argentina’s clean energy sector was growing, it was “Argentina’s huge shale resources that offer the greatest potential” for the UK. The briefing note was prepared before a key meeting between the UK government’s trade envoy to Latin America, the UK ambassador to Argentina and Argentina’s energy minister in February this year. Tony Bosworth, a campaigner at Friends of the Earth, said: “With the world hurtling towards catastrophic climate change, and parliament declaring a climate emergency, it’s outrageous that the UK government is continuing to back huge fossil fuel developments abroad.”

Gas Demand in Europe – Is There a Place for LNG? – In 2018, the European market(s) represented almost 16 per cent of the global LNG market (GIIGNL 2019 Report). Volumes imported to the region vary greatly from one year to another. This is because Europe is acting as the swing market for LNG. As a result, the region is expected to help balance the market at times of high Asian demand, as seen after 2011 following the Fukushima disaster, but also help to absorb any LNG surplus coming on to the market, as expected in the 2020s. With regasification terminals only being used at about 28 per cent of their capacity, Europe could import a lot more LNG relying only on its existing infrastructure. But is there a place for LNG in Europe, especially up to 2030? Europe is not an LNG market per se – it is a market with a demand for gas, which can come in the form of indigenous production, imports via pipelines, or LNG. After a continuous decline between 2010 and 2014, natural gas demand in Europe started to rise again in 2015 – 17. This was due to a combination of colder than average months in winter (higher energy consumed for heating), economic recovery, and increasing gas deliveries to the power sector because of coal-to-gas switching.The future place of natural gas in Europe’s energy system will determine the need for imports, including of LNG. But this future faces major uncertainties as a result of climate change policies.The decarbonization of energy systems is a major part of the European Union’s (EU’s) policy agenda; it is committed to reducing its greenhouse gas (GHG) emissions to 80 – 95 per cent below 1990 levels by 2050. The decarbonization of the electricity sector through the integration of renewables has been regarded as the first step in a wider strategy. Between 2007 and 2017, the share of renewables grew from 5 to 18 per cent (excluding hydro), with the largest increase in the form of onshore wind and solar. Both are intermittent sources of power generation, and one of the key challenges posed by this rapid evolution was how to integrate a large and growing share of intermittent generation into the power system. This approach has catalysed disruptions in the traditional structure of the electricity sector, and by extension the role of gas in the electricity mix. While in the past, combined cycle gas turbines (CCGTs) were traditionally run on baseload power, they are increasingly required to provide backup for variable renewable resources.

Rosneft switches contracts to euros from dollars due to U.S. sanctions – (Reuters) – Russia’s largest oil company Rosneft has fully switched the currency of its contracts to euros from U.S. dollars in a move to shield its transactions from U.S. sanctions, its Chief Executive Igor Sechin said on Thursday. Photo Rosneft’s switch to the euro is seen as part of Russia’s wider-scale drive to reduce dependence on the dollar, but it is unlikely to quickly boost the euro’s role for Russia given the negative interest rates it carries. “All our export contracts are already being implemented in euros and the potential for working with the European currency is very high,” Sechin told an economic forum in Italy’s Verona. “For now, this is a forced measure in order to limit the company from the impact of the U.S. sanctions.” Reuters reported earlier this month that state-controlled Rosneft set the euro as the default currency for all its new export contracts.

.