Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 28 April 2019.
This article is a feature every Monday evening on GEI.
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Oil prices fall on Trump’s BS; natural gas injection matches last week’s record; rig count drops to 13 month low
Oil prices ended the week lower for the first time in eight weeks, largely on a big Friday selloff that began after Trump told reporters he had “called up” OPEC and told them to bring down fuel costs, even as no-one at OPEC knew anything at all about the alleged “call” from Trump….after oil prices eked out an 11 cent increase to $64.00 a barrel last week, this week began with the last day of trading for US crude for May delivery, which spiked $1.70 or 3% higher to expire at $65.70 a barrel, after the US announced an end to waivers on Iran sanctions, demanding that buyers of Iranian oil stop purchases by May 1st…at the same time, contracts for US WTI crude for June delivery, which had ended last week priced at $64.07 a barrel, rose $1.48 to $65.55 a barrel on Monday and became the front month, or widely quoted ‘price of oil’….in an ongoing Iran sanctions rally, that June oil price rose another 75 cents to a 6 month high of $66.30 per barrel on Tuesday, after Iran said they’d close the Strait of Hormuz, the conduit for a fifth of the world’s oil, if they were prevented from using it and oil traders expressed skepticism that Saudi Arabia would replace the lost Iranian barrels…however, oil prices opened lower on Wednesday, after a Tuesday night industry report indicated a much larger than expected build of US crude supplies, and went on to settle 41 cents lower at $65.89 a barrel after the EIA confirmed that US oil supplies had in fact risen by much more than traders had expected…after trading higher Thursday morning on the suspension of Russian crude exports to Europe due to pipeline contamination, oil prices turned sharply lower heading into Thursday’s settlement, after a number of reports convinced traders that OPEC could easily replace sanctioned Iranian crude, with oil prices ending down 68 cents at $65.21 a barrel…oil prices then fell steadily on Friday after Trump said he called OPEC and told them to bring oil prices down, with June US crude falling to as low as $62.28 a barrel before recovering a bit before the close to end the session down $1.91 at $63.30 a barrel, thus ending the week down 1.1% and derailing the longest run of weekly gains since the first half of 2015...
Meanwhile, natural gas prices, which had been down 5 out of the past six weeks while falling to a 34 month low last week, managed to stage a modest rally after new 34 month lows were set again on Tuesday, and finished 3% higher on the week…quoting natural gas for May delivery all week, prices rose 3.4 cents to $2.524 mBTU on Monday, the first gain in seven sessions, on strong cash prices and the first signs of demand for cooling in the South…that brief move higher didn’t hold, however, as natural gas prices fell 6.9 cents to a new 34 month closing low of $2.455 per mmBTU on Tuesday…prices managed a seven-tenths of a cent rebound on Wednesday, and then turned decidedly higher despite another record injection being logged on Thursday, as forecasts indicated colder than normal temperatures for the northern tier of states, and forecasts warm enough for those in the South to crank up the air conditioning…with that forecast indicating natural gas demand increasing both north and south, natural gas prices posted identical 5.2 cents gains on both Thursday and Friday to end the week at $2.566 per mmBTU, 7.6 cents higher than the prior week’s close…
The natural gas storage report for the week ending April 19th from the EIA indicated that the quantity of natural gas held in storage in the US had again increased by an April record 92 billion cubic feet, now up to 1,339 billion cubic feet by the end of the week, which meant our gas supplies were 55 billion cubic feet, or 4.3% more than the 1,284 billion cubic feet that were in storage on April 20th of last year, while remaining 369 billion cubic feet, or 21.6% below the five-year average of 1,708 billion cubic feet of natural gas that have typically remained in storage as of the third weekend in April in recent years….this week’s 92 billion cubic feet injection into US natural gas storage was in line with market expectations, while it was quite a bit more than the 47 billion cubic feet of natural gas that are normally added to gas storage during the third week of April…over the past 4 weeks, 232 billion cubic feet of natural gas have been added to storage in the lower 48 states; that is in sharp contrast to the same four weeks of 2018, when a cool end to winter meant that 96 cubic feet of natural gas had to be withdrawn from storage over the same 4 week period…
The Latest US Oil Supply and Disposition Data from the EIA
This week’s US oil data from the US Energy Information Administration, reporting on the week ending April 19th, showed that due to a large increase in our oil imports, we had surplus oil left to add to our commercial supplies of crude for the fourth time in five weeks…our imports of crude oil rose by an average of 1,157,000 barrels per day to an average of 7,149,000 barrels per day, after falling by an average of 607,000 barrels per day the prior week, while our exports of crude oil rose by an average of 280,000 barrels per day to 2,681,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,468,000 barrels of per day during the week ending April 19th, 877,000 more barrels per day than the net of our imports minus exports during the prior week…over the same period, field production of crude oil from US wells was reported to be up by 100,000 barrels per day to 12,200,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from well production totaled an average of 16,668,000 barrels per day during this reporting week…
Meanwhile, US oil refineries were using 16,583,000 barrels of crude per day during the week ending April 19th, 550,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that 783,000 barrels of oil per day were being added to the oil that’s in storage in the US…..therefore, this week’s crude oil figures from the EIA would seem to indicate that our total working supply of oil from net imports and from oilfield production was 698,000 barrels per day short of what was added to storage plus what the oil refineries reported they used during the week…to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (+698,000) 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 is labeled in their footnotes as “unaccounted for crude oil”….with that much oil unaccounted for, we have to figure that one or more of this week’s oil metrics is in error by a statistically significant amount.. (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicated that the 4 week average of our oil imports rose to an average of 6,626,000 barrels per day last week, still 19.6% less than the 8,237,000 barrel per day average that we were importing over the same four-week period last year…the 783,000 barrel per day increase in our total crude inventories was all added to our commercially available stocks of crude oil, as the oil stored in our Strategic Petroleum Reserve remained unchanged……this week’s crude oil production was reported to be 100,000 barrels per day higher at a record 12,200,000 barrels per day because the rounded estimate for output from wells in the lower 48 states was 100,000 barrels per day higher at 11,700,000 barrels per day, while a 1,000 barrel per day decrease to 477,000 barrels per day in Alaska’s oil production was not enough to make a difference in the rounded national total…last year’s US crude oil production for the week ending April 20th was at 10,586,000 barrels per day, so this reporting week’s rounded oil production figure was 15.2% above that of a year ago, and 44.8% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 90.1% of their capacity in using 16,583,000 barrels of crude per day during the week ending April 19th, up from 87.7% of capacity the prior week, but still a bit below the normal refinery utilization rate for the middle of April….similarly, the 16,583,000 barrels per day of oil that were refined this week were still a bit less than the 16,621,000 barrels of crude per day that were being processed during the week ending April 20th, 2018, when US refineries were operating at 90.8% of capacity…
Even with the large increase in the amount of oil being refined, gasoline output from our refineries was still somewhat lower, decreasing by 136,000 barrels per day to 9,781,000 barrels per day during the week ending April 19th, after our refineries’ gasoline output had decreased by 252,000 barrels per day the prior week….with that decrease in gasoline output, this week’s gasoline production was 1.1% less than the 9,886,000 barrels of gasoline that were being produced daily during the same week last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) rose by 241,000 barrels per day to 5,064,000 barrels per day, after that distillates output had decreased by 215,000 barrels per day the prior week…and after this week’s increase, the week’s distillates production was 1.7% more than the 4,977,000 barrels of distillates per day that were being produced during the week ending April 20th, 2018….
With the decrease in our gasoline production, the supply of gasoline left in storage at the end of the week fell for the 10th week in a row, decreasing by 2,129,000 barrels to 225,826,000 barrels over the week to April 19th, after gasoline supplies had fallen by 1,174,000 barrels over the prior week….that was as the amount of gasoline supplied to US markets decreased by 11,000 barrels per day to 9,409,000 barrels per day, after decreasing by 386,000 barrels per day the prior week, and as our imports of gasoline fell by 85,000 barrels per day 905,000 barrels per day, while our exports of gasoline fell by 53,000 barrels per day to 546,000 barrels per day…after having reached an all time record high thirteen weeks ago, our gasoline inventories are now 4.6% lower than last April 20th’s level of 236,807,000 barrels, and have now fallen to roughly 2% below the five year average of our gasoline supplies at this time of the year…
Even with the increase in our distillates production, our supplies of distillate fuels fell for the 23rd time in thirty weeks, decreasing by 662,000 barrels to 127,029,000 barrels during the week ending April 19th, after our distillates supplies had decreased by 362,000 barrels over the prior week…the draw on our distillates supplies was a bit greater this week because the amount of distillates supplied to US markets, a proxy for our domestic demand, rose by 443,000 barrels per day to 3,796,000 barrels per day, while our exports of distillates fell by 62,000 barrels per day to 1,608,000 barrels per day, and while our imports of distillates rose by 107,000 barrels per day to 245,000 barrels per day…but even after this week’s inventory decrease, our distillate supplies were still 3.5% higher than the 122,729,000 barrels of distillate that we had stored on April 20th, 2018, even as they fell to roughly 6% below the five year average of distillates stocks for this time of the year…
Finally, with that big jump in our oil imports, our commercial supplies of crude oil in storage increased for the tenth time in 14 weeks, rising by 5,479,000 barrels over the week, from 455,154,000 barrels on April 12th to 460,633,000 barrels on April 19th…that increase was enough to bring our crude oil inventories back to the recent five-year average of crude oil supplies for this time of year, while they also were also a third higher than the prior 5 year (2009 – 2013) average of crude oil stocks after the third week of April, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories have mostly been rising since this past Fall, after generally falling until then through most of the prior year and a half, our oil supplies as of April 19th were 7.2% above the 429,737,000 barrels of oil we had stored on April 20th of 2018, but at the same time still 12.9% below the 528,702,000 barrels of oil that we had in storage on April 21st of 2017, and 9.6% below the 509,311,000 barrels of oil we had in storage on April 22nd of 2016…
Since our recent crude inventory increases have concurrently been accompanied by rapidly falling oil product inventories, i’d like to include a set of bar graphs to show you what that looks like graphically…this set of inventory bar graphs was copied from the Zero Hedge report of this past week that reviewed the weekly EIA report:
Above we have 4 similar bar graphs stacked one on top of another; from the top, the first shows the weekly change in US crude oil inventories, then the weekly change in oil inventories at the Cushing Oklahoma storage depot, then the weekly change in gasoline inventories, and lastly the weekly change in inventories of distillates…each graph has the same format: inventory increases for a given week are shown as a green bar above the zero line, whereas inventory decreases are shown as a red bar pointing down from the zero line, wherein the size of the bar in both cases is indicative of the size of the inventory increase or decrease…thus we can see in the top graph that US crude inventories have increased substantially in 4 out of the last 5 weeks, as Zero Hedge has boxed in green, and in a broader look they’ve increased in 10 out of the past 14 weeks…but then look at the last two graphs, which show inventories of gasoline and distillates decreasing; in the case of distillates, they’re now down 6 weeks in a row and 12 weeks out of the last 14, sliding from 143 million barrels to 127 million barrels over that span, and in the case of gasoline, they’re now down 10 weeks in a row, dropping all the way down to 225,826,000 barrels, from 258,301,000 barrels on February 8th, ie, heading in the wrong direction only a month before Memorial Day….many are writing off these decreases to normal spring refinery maintenance, but as we’ve been pointing out, refinery utilization over this period has been quite a bit below that of the same season in recent years…and as we’ve also been pointing out, the beginning of this sharp refinery slowdown coincides to the date with the imposition of Trump administration sanctions on importation of heavy sour Venezuelan crude, which many US Gulf Coast were optimized to use….and it has taken until this week for us to see US oil imports return to the pre-sanction level, likely heralding the first arrivals of comparable grades of heavy sour crude from the Middle East…
This Week’s Rig Count
US drilling rig activity decreased for the ninth time in ten weeks, and has now slowed to a 13 month low, 3% below year ago levels, with both oil and gas drilling down by similar percentages….Baker Hughes reported that the total count of rotary rigs running in the US fell by 21 rigs to 996 rigs over the eight days ending April 26th, which was also down by 30 rigs from the 1021 rigs that were in use as of the April 27th report of 2018, and quite a bit below the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market…note that this week’s rig count is for 8 days, after last week’s count was released on the Thursday before Good Friday…
The count of rigs drilling for oil fell by 20 rigs to 805 rigs this week, which was also 20 fewer oil rigs than were running a year ago, and was only half of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations decreased by 1 rig to 186 natural gas rigs, which was also down by 9 rigs from the 195 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008…
Drilling activity offshore in the Gulf of Mexico was down by 2 rigs to 21 rigs this week, which was still 1 more rig than the 18 rigs active in the Gulf a year ago…however, the week also saw the startup of a platformed rig drilling on an inland body of water in southern Louisiana, where there are now 4 such ‘inland waters’ rigs running, down from the 5 ‘inland waters’ rigs deployed a year ago…
The number of active horizontal drilling rigs decreased by 13 rigs to 873 horizontal rigs this week, which was 28 fewer horizontal rigs than the 901 horizontal rigs that were in use in the US on April 27th of last year, and well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…..at the same time, the directional rig count decreased by 4 rigs to 71 directional rigs this week, but that was still up by 3 rigs from the 68 directional rigs that were in use during the same week of last year….in addition, the vertical rig count decreased by 4 rigs to 47 vertical rigs this week, which was down from the 52 vertical rigs that were operating on April 27th of 2018…
The details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of April 26th, the second column shows the change in the number of working rigs between last week’s count (April 18th) and this week’s (April 26th) count, the third column shows last week’s April 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 27th of April, 2018…
As you can see, this week’s drilling pullback was fairly widespread, with all of the major oil basins seeing rig reductions…while this was happening even as oil prices were at a 6 month high, we have to realize that there’s quite a lag – maybe an average of 3 or 4 months – between the time when a exploitation company makes the decision to drill and the time they contract a drilling rig and get it deployed in the field…so it’s likely that the decisions to curtail drilling that we’ve seen over recent weeks were probably made at a time when oil prices were $10 to $15 a barrel below where they were at this week…
Of the 9 rigs pulled out in Texas, five came out of Texas Oil District 1 in the southeast, which would include the 4 shut down from the Eagle Ford; another 2 rigs were removed from the panhandle region Texas Oil District 10, which would be the Granite Wash, and which could have thus included a rig added back in that basin on the Oklahoma side of the border…in the Permian, two rigs were removed from Texas Oil District 8, or the core Permian Delaware, and two rigs were pulled out of Texas Oil District 7C, or the southern Permian Midland basin, while two rigs were added in Texas Oil District 8A, or the northern Permian Midland basin…with a Permian reduction of 3 rigs nationally, those Texas changes suggest that the rig that was shut down in New Mexico had also been operating in the Permian Delaware…
Among rigs targeting natural gas, one was removed from Ohio’s Utica shale, while one was also pulled out of the Eagle Ford in south Texas, where 8 natural gas rigs remain deployed along side of 65 rigs drilling for oil…at the same time, a natural gas rig was started up in the Rockies’ Niobrara chalk for the first time in over a year, where an oil rig was concurrently shut down, but 28 oil directed rigs still continue to drill….we should also note that the lone rig which had been drilling in Indiana was also shut down this week, leaving Indiana without drilling activity for the first time since last April 20th..
Spill released 1,000 gallons – City officials said 1,000 gallons of oil were released into Conneaut’s sewer system during last week’s spill. “It was a catastrophic failure of the oil-water separator at Love’s Truck Stop,” Sewer Superintendent Brian Bidwell told city council members Monday. On April 14, a storm hit Conneaut and the power went out at Love’s Travel stop. The tank of Love’s oil water separator filled up, and when the separator’s pump restarted, it emptied both the oil and the water into the city’s sewer system, Bidwell said. Oil reached the city’s wastewater treatment plant, where it started disrupting the micro-organisms the plant uses to treat water. “There’s no permanent damage to anything,” Bidwell said. Last week, there was some concern the oil would kill all the micro-organisms in the plant. After testing, officials know at least some of the micro-organisms are still alive. “It was impacted, but it’s not completely gone,” Bidwell said. To help keep the micro-organisms alive, the plant will be cleaned. The plant has six tanks and a clearing basin, and all six tanks will be cleaned. Cleaning the plant is expected to take three to four weeks, City Manager Jim Hockaday said. Bidwell said the wastewater department put oil-eating micro-organisms into the lift stations to help the cleaning process. They will help clean affected areas of the sewer as they were pumped through the system. . There was a light sheen on the lake after the spill, but no massive discharge of oil into the lake, Bidwell said. “The plant was very effective at capturing most of everything that came to the plant,” he said. Officials couldn’t take samples from the lake on the day of the spill because of the weather conditions, Hockaday said. People might smell oil or gas near the wastewater station, Hockaday said. They should still report it, but tests currently show the air quality is safe. In addition to the oil spill, 20 feet of sewer main under Lake Road collapsed Friday, forcing Lake Road to close for a time and creating additional work for Bidwell and his team.
Ohio shale investment hits $74 billion since 2011 Investment in the energy-rich shale sector in eastern Ohio continues to grow, reaching $74 billion since 2011, according to a report commissioned by JobsOhio. Investment in the energy-rich shale sector in eastern Ohio continues to grow, reaching $74 billion since 2011, according to a report commissioned by JobsOhio. The quarterly report, done by Cleveland State University’s Energy Policy Center at the Maxine Goodman Levin College of Urban Affairs, shows that about two-thirds of that investment has been in drilling, land acquisition, building roads and other expenses tied to the “upstream” portion of oil and gas production. The rest has been spent on activities such as collecting and gathering the oil and gas along with transmission lines and investments in natural-gas power plants and other uses. The study represents investment through the first half of 2018. It comes just weeks after researchers at IHS Markit released estimates that show by 2040, the Utica and Marcellus shale regions in Ohio, West Virginia and Pennsylvania will supply 45% of U.S. natural gas production. That’s up from 31% this year. Production of natural-gas liquids ethane, propane and butane is expected to double during this period, accounting for 19% of the nation’s total. The latest data shows production from the region, which is primarily natural gas, continues to surge. Oil production in the final three months of 2018 was 5.8 million barrels, a 38.6% increase from the same period in 2018, according to the most recent report from the Ohio Department of Natural Resources. Gas production hit 663.5 million cubic feet, a 32 percent increase from the final three months of 2018.
Utica Shale oil, natgas production expected to grow in ’18 – – Martin Shumway and Tim Knobloch used an array of drilling data to paint pictures of Ohio’s Utica Shale and the entire Appalachian Basin in twin presentations Thursday at the 72nd annual Ohio Oil and Gas annual meeting, sponsored by the Ohio Oil and Gas Association, with roughly 700 attendees in Ohio’s capital city. Oil production in 2018 is expected to increase by 20% from 2017, reaching 23.4 million barrels (Mmbbl), and reversing a declining trend from 2015 to 2017, he said. Ohio’s all-time oil production record was set in 1897, at 23.9 million barrels, and Ohio is likely to smash that record very soon, Shumway said. Natural gas production is projected to increase 34% from 2017 to 2018, he said, from 1.8 trillion cubic feet (Tcf), to 2.4 Tcf in 2018. Those 2018 totals are based on production totals for three quarters and estimates for Q4 2018. In 2018, Ohio’s Belmont County had the most well completions with 98. Monroe County had 95 and Jefferson County had 42. Ohio had 408 well completions in 2018, a drop of 9% from 2017. Of that total, 336 wells were producing in 2018. In addition, a total of 493 permits were issued by the state, a drop of 47% from 2017. Of those completions, 70 were by Ascent Resources, 45 were by Gulfport, 39 by Antero Resources, 36 by Rice and 35 by Chesapeake. Antero’s wells drilled increased by 77% in 2018, while most other companies showed declines, he said. To date, Chesapeake has drilled the most Utica wells in Ohio with 688, followed by Ascent with 378, and Gulfport with 304. The most linear feet were drilled in Belmont County: 1.85 million feet. It was followed by Monroe and Jefferson counties. In 2018, energy companies drilled 6.5 million feet on 371 wells. That compares to 6.03 million feet drilled on 378 wells in 2017. The top year for linear feet drilled in Ohio was 2016 with 7.95 million feet.Ascent drilled the most linear feet in Ohio in 2018: nearly 1.3 million feet. Second was Rice with 775,323 feet, Gulfport with 764,456 feet, Eclipse with 716,216 feet and Chesapeake with 644,424 feet. Ohio has 328 wells with laterals that exceed 10,000 feet, with the greatest number in Belmont, Monroe and Jefferson counties, he said.Pennsylvania has 346 laterals that exceed 10,000 feet, with the greatest number in Washington, Greene and Susquehanna counties. West Virginia has 170 laterals that exceed 10,000 feet with most in Doddridge, Ritchie and Tyler counties.Eclipse has drilled an Ohio well in Monroe County with a 20,720-foot lateral that’s the longest in Ohio
Studies link earthquakes to fracking in the central and eastern US – Small earthquakes in Ohio, Pennsylvania, West Virginia, Oklahoma and Texas can be linked to hydraulic fracturing wells in those regions, according to researchers speaking at the SSA 2019 Annual Meeting. While relatively rare compared to earthquakes caused by wastewater disposal in oil and gas fields in the central United States, Michael Brudzinski of Miami University in Ohio and his colleagues have identified more than 600 small earthquakes (between magnitude 2.0 and 3.8) in these states. Brudzinski said these earthquakes may be “underappreciated” compared to seismicity related to wastewater disposal since they appear to happen less frequently. He and his colleagues are studying the trends related to the likelihood of induced seismicity from hydraulic fracturing or fracking, which could help industry and state regulators better manage drilling practices. The numerous fracking wells in eastern Ohio prompted Brudzinski and his colleagues to take a closer look at whether small earthquakes in the region could be connected to fracking operations. “The wells are more widely spaced when they’re active, and there isn’t as much wastewater disposal going on,” Brudzinski explained, “so you can see a bit more specifically and directly when wastewater disposal is generating seismicity and when hydraulic fracturing is generating seismicity in the Appalachian Basin.” The scientists used a technique called multi-station template matching, which scans through hundreds of seismic signals to find those that match the “fingerprint” of known earthquakes. The technique allowed them to detect small earthquakes that might have otherwise been overlooked, and to compare the more complete earthquake catalog in a region to information on the timing and location of regional fracking well operations. Seismologists identify earthquakes as being caused by hydraulic fracture wells when they are tightly linked in time and space to fracking operations. Fracking-related seismicity also tends to look different from seismicity caused by wastewater disposal, Brudzinski said. “The [fracking] seismic signature when you look at it in a sort of timeline shows these bursts of seismicity, hundreds or sometimes thousands of events over a couple of days or weeks, and then it’s quiet again. You don’t tend to see that pattern with wastewater disposal,” he explained.
GOP Legislator Criticizing Company Behind Mariner East Pipelines As It Faces Criminal Investigation – Few legislators are more supportive of Pennsylvania’s natural gas industry than state Sen. Gene Yaw (Bradford), who serves as the Republican chair of the Senate Environmental Resources and Energy Committee.However, when he addressed oil and gas industry representatives Wednesday at the Upstream PA Conference in State College, Yaw called out Energy Transfer for being irresponsible. It’s the company behind the embattled Mariner East project – a set of export pipelines moving natural gas liquids through the southern part of the state.“This particular company, in my opinion, rode roughshod over people,” Yaw said in his remarks. “They haven’t explained what’s gone on. They haven’t addressed issues.”The Mariner East project has resulted in dozens of violations for spills of drilling mud, which has contaminated private well water. Last year, state utility regulators temporarily shut down one of the pipelines, after sinkholes opened up in a Chester County neighborhood. Energy Transfer is now under criminal investigation by the attorneys general of Chester and Delaware counties, as well as State Attorney General Josh Shapiro.Yaw said Energy Transfer is damaging the reputations of more responsible pipeline operators, citing Williams, which recently completed the Atlantic Sunrise pipeline, an expansion of its natural gas transmission line system.“You have one company in Pennsylvania that is probably being counterproductive to your interests,” Yaw said, referring to Energy Transfer. “I’ve talked to these people until I was blue in the face. I know Williams isn’t happy, because they get tarred with the same brush.” Energy Transfer did not respond to a request seeking comment Thursday, but it has previously said there is no basis for a criminal investigation. In a February conference call with investors chief executive, Kelcy Warren, acknowledged the company has “made mistakes” with its Mariner East project adding, “we are correcting those mistakes and will not make those mistakes again.”
Sunoco sends notice that it plans to restart Mariner East 1 pipeline – The Bureau of Investigation and Enforcement (I&E) – the independent investigation and enforcement bureau of the Pennsylvania Public Utility Commission (PUC) – on Friday received notice from Sunoco Pipeline LP, a/k/a Energy Transfer Partners (SPLP or Sunoco), of Sunoco’s intent to restart the Mariner East 1 (ME1) pipeline. Sunoco also will take a series of additional steps to address safety concerns regarding the Mariner East pipelines, according to a press release. Mariner East 1 (ME1) has been out of service since Jan. 20, 2019, as engineers from I&E’s Pipeline Safety Division monitored stabilization and remediation efforts undertaken by SPLP following a subsidence event or “sinkhole” that exposed a small segment of the pipeline along Lisa Drive in West Whiteland Township, Chester County, the release said. Enhanced safety actions to be undertaken by Sunoco include:
- I&E and Sunoco have agreed upon a plan to further remediate the Lisa Drive area surrounding ME1. The site remediation plan will contain a going-forward approach based on all data collected to date. The site remediation plan will also consider the impact of the planned or anticipated open trench excavation of the 20-inch Mariner East 2 line, and the plan will be submitted to I&E for review by I&E’s consultants.
- SPLP will commit personnel to walk the Lisa Drive section of ME1 daily, except where inclement weather would put personnel in danger, until the grouting along ME1 is complete. SPLP will further provide I&E with summary reports describing the observations recorded during each visual inspection.
- Sunoco will perform geophysical tests in the right-of-way area behind Lisa Drive every six months for two years, and report the findings to I&E.
- SPLP will maintain the existing top-of-pipe elevation survey locations and strain gauges on this section of ME1 and will continuously monitor strain gauge data in its control room that is staffed 24/7, and routinely provide reports to I&E.
Energy Transfer- Mariner East 1 Pipeline Back in Service – Energy Transfer LP announced that effective today, Mariner East 1 pipeline has resumed operations. The 350-mile, 8-inch natural gas liquids (NGL) pipeline transports NGLs across Southern Pennsylvania to Energy Transfer’s Marcus Hook Industrial Complex in Delaware County, PA. Energy Transfer worked closely with the Pennsylvania Public Utility Commission Bureau of Investigation and Enforcement (BI&E) throughout an extensive three-month investigation, through which Energy Transfer confirmed the integrity of the pipeline in the area of West Whiteland Township, Chester County, PA. The investigation also confirmed that at no time was Mariner East 1 ever destabilized in this area. Mariner East 1 is part of Energy Transfer’s Mariner East system of pipelines designed to provide much-needed NGL takeaway capacity for the Marcellus and Utica Shale production areas in Eastern Ohio, West Virginia and Western Pennsylvania.
Sinkhole opens up along ME2 route in Delaware County; no leaks or injuries – A sinkhole opened up on Wednesday along a Sunoco pipeline route in Middletown, Delaware County, state, county and township officials said. The sinkhole – called a “subsidence” by the Public Utility Commission – was in the right-of-way for a 12-inch pipeline that is part of the Mariner East system to carry highly volatile natural gas liquids and petroleum products, the PUC said in a statement late Wednesday. No leaks or injuries were reported, and Sunoco officials have been working to “stabilize and monitor” the situation, the PUC said. The regulator said its Bureau of Investigation and Enforcement has launched a safety investigation. Earlier this week, Sunoco restarted the Mariner East 1 pipeline which had been shut down for three months because another sinkhole exposed a section of the pipe on a construction site at Lisa Drive, a suburban development in West Whiteland Township, Chester County. Sunoco confirmed that the new sinkhole had opened up but said Thursday morning that the hole has been filled and that there was no interruption to pipeline operations. “A subsidence feature did occur yesterday along our right of way,” said Vicki Granado, a spokeswoman for Sunoco’s parent, Energy Transfer. “The appropriate regulatory agencies were notified and an investigation determined our pipelines in the area are safe and secure. Nothing was exposed. The area was immediately contained and grouted. We placed our personnel in the area to continue to monitor the area. Our pipelines remain in service.”
Underground wastewater pipelines can be a big, unregulated business in Pennsylvania – Pittsburgh Post-Gazette — Equitrans Midstream Corp. is in the gas pipeline business and a little bit in the water pipeline business. There are lots of reasons to grow that little bit, promised Thomas Karam, the CEO of the Pittsburgh-based midstream firm. He was previewing a strategy that he said would be fleshed out later this year to take advantage of shale gas’s extreme thirst for water. “Produced water services are particularly exciting because the Appalachian Basin needs a solution,” Mr. Karam said in March while announcing a $1 billion deal for control of two Ohio gas pipeline systems. Produced water is a kind of catch-all term for wastewater that comes back out of a well after chemical-laced frack fluid is pumped into it. Once fracking is over and the well starts producing gas, it also brings to the surface a salty and often radioactive brine that is now mostly trucked around Pennsylvania. There are at least several hundred miles of produced water pipelines buried in Pennsylvania, but they are largely unregulated and untracked. Environmental regulators say they’ve been hesitant to push for regulations because the pipelines haven’t been known to cause problems and because the technology – both how they’re built and how they’re inspected – has been changing faster than they can regulate. So for now, Pennsylvania has had a hands-off approach, happy that at least some wastewater trucks are taken off the roads due to pipelines. Mr. Karam didn’t harp on the reduced truck traffic. Produced water pipelines, he told investors last month, are a juicy business opportunity. They are a service, with predictable product volumes and the potential for long-term contracts, just like gas gathering lines. “We don’t have to re-create the wheel,” he said. “Produced water is piped in other basins, so that what we’re going to try to do is introduce that to the Appalachian Basin with similar contractual characteristics.” It wasn’t clear if Mr. Karam was speaking specifically of buried produced water pipelines. After requesting a list of questions, Equitrans did not respond.
Shale Wastewater Pipelines in PA – The Next Big Thing? –Are underground shale wastewater pipelines the “next big thing” for the Pennsylvania midstream (i.e. pipeline) industry? According to Thomas Karam, CEO of Equitrans Midstream Corp., they just may be. Most of Equitrans’ pipeline business is flowing natural gas. A little bit of their business is dedicated to flowing wastewater. Karam wants to grow that little bit into a much bigger bit.The Pittsburgh Post-Gazette ran a major story yesterday on the developing market for underground wastewater pipelines for the PA shale gas industry. The story’s spin is that these types of pipelines are not currently regulated by the state, and therefore are somehow dangerous. Anything unregulated is “dangerous” for leftists. They can’t conceive of an industry self-regulating. So what if there is a leak or spill? It’s salty water.The Post-Gazette article talks about water that’s “radioactive” and “laced with chemicals” from frack fluid. Yes, if you spill a bunch of produced water on the ground – which is water from the depths full of minerals making it super salty – the grass might die. And then a month later the grass will grow back. Produced water is not some highly contaminated hazardous substance. It’s water! With some minerals in it! And it’s not radioactive – at least not at any level that harms humans or the environment. Water itself has natural radioactivity in it – did you know that?One of the big positives with pipelines is that it removes thousands of truck trips from our roads – reducing traffic resulting in fewer accidents that spill produced water, and making for cleaner air (apologies to our trucking company friends, but facts are facts).At any rate, the wastewater pipeline industry in the Marcellus/Utica didn’t even exist five years ago, but does today. Big midstreamers like Equitrans are taking notice.
Study tracks Pennsylvania’s oil and gas waste-disposal practices – More than 80 percent of all waste from Pennsylvania’s oil and gas drilling operations stays inside the state, according to a new study that tracks the disposal locations of liquid and solid waste from these operations across 26 years. Numerous human health hazards have been associated with waste from oil and gas extraction, including potential exposure to compounds known to cause cancer. The study is the first comprehensive assessment of Pennsylvania’s waste-disposal practices, tracking from 1991 – when the state began collecting waste-disposal information – through 2017. In southwestern Pennsylvania, most solid waste goes to landfills in the county where it was produced, the study also found, while in northern counties along state borders, solid waste generally moves to neighboring states of Ohio and New York. Oil and gas development produces high-salinity water that can contain strontium and radium – substances classified as known human carcinogens. Solid waste includes cuttings from drilling that can bring naturally occurring radioactive materials including uranium, radium, and thorium, up from the subsurface to the surface, creating the potential for human and environmental exposures to these toxic compounds. Previous studies have tracked only subsets of oil and gas waste-disposal data. For example, many past studies have focused just on waste from high-volume hydraulic fracturing, the process used at scale since 2008 to extract oil and gas from Pennsylvania’s Marcellus Shale formation. But the PSE-led study also tracks waste from conventional oil and gas development, which has taken place in Pennsylvania since records have been kept and continues today. Conventional drilling operations accounted for nearly one third of all waste, the data showed.
EPA Decides Not to Regulate Fracking Wastewater as Pennsylvania Study Reveals Recent Spike – On April 23, the U.S. Environmental Protection Agency (EPA) told two environmental groups that it had decided it was “not necessary” to update the federal standards handling toxic waste from oil and gas wells, including the waste produced by fracking. State regulators have repeatedly proved unable to prevent the industry’s toxic waste from entering America’s drinking water supplies, including both private wells and the rivers from which public drinking water supplies are drawn, the Environmental Protection Agency concluded in a 2017 national study. The corrosive salt-laden wastewater from fracked wells has been spread on roads as a de-icer. It’s been sprayed into the air in the hopes of evaporating the water – a practice that spreads its blend of volatile chemicals into the air instead. Oil industry wastewater has even been used to irrigate crops – in California, where state regulators haven’t set rules to keep dangerous chemicals like the carcinogen benzene out of irrigation water. If equally contaminated waste came from other industries, it would usually be designated hazardous waste and subject to strict tracking and disposal rules designed to keep the public safe from industrial pollution. But in July 1988, after burying clear warnings from its own scientists about the hazards of oilfield waste, the EPA offered the oil and gas industry a broad exemption from hazardous waste handling laws. The decision comes as a new study, published in the peer-reviewed journal Science of the Total Environment, calls attention to the oil and gas waste produced in Pennsylvania for nearly that entire time. The oil and gas industry has flooded Pennsylvania with over 380 million barrels of liquid waste from 1991 to 2017, that study found – enough to fill an area the size of a standard city block with a column of wastewater over 200 feet tall. “Pennsylvania also has the third highest cancer incidence rate of all U.S. states,” Environmental Health News reported, citing data from the Centers for Disease Control and Prevention. “Approximately half of all Pennsylvanians will be diagnosed with cancer at some point in their lifetime, and about one in five Pennsylvanians will die of cancer.” Fifty-five known chemicals that fracked oil and gas operations release into the air and the water can cause cancer, a Yale Public Health analysis found last year. Oil and gas workers are routinely exposed to dangerous levels of cancer-causing chemicals like benzene, a 2014 National Institute for Occupational Safety and Health found.
Years after record Marcellus Shale fine was dropped, gas leak continues in Lycoming County – Josh Woda, wearing fishing waders, trudged through sparse winter woods near an ice-glazed stream and pointed to a spot where the ice had curved into a dome the width of a salad plate.Beneath it, methane gas rose from the stream bed as it had for seasons, in bubbles so frequent and persistent that it bowed the frozen water.“If you broke a hole, you could probably light it,” he said. Three years ago, the Pennsylvania Department of Environmental Protection dropped its pursuit of the largest fine it had ever tried to collect against an oil and gas drilling company – $9 million. Regulators said the methane bubbling up in this stream in Lycoming County, called Sugar Run, came from a leaking Marcellus Shale well that also damaged water quality at a dozen homes and created dead zones in farm fields.The fine was meant to send a message – to make it “clear that we take seriously our responsibility to protect residents and Pennsylvania’s natural resources,” then-DEP Secretary John Quigley said at the time. But in 2016 the well’s owner, Range Resources, had become more cooperative with DEP’s directions to fix the well – even as the Texas company maintained it was not the source of the problem – and the way that the state had proposed the fine meant its legal foundation was rickety. DEP’s reversal caused outrage. The outrage faded. Eight years after it was first detected, the leak has not been plugged and deep gas is still finding a path to the surface. New research out of Pennsylvania State University led by Mr. Woda, a geosciences graduate student, suggests a methane plume is moving through the aquifer and causing cascading effects: feeding bacteria that interact with other elements in the water, giving the water a rotten-egg odor, and turning stream sediment and residents’ plumbing fixtures orange. Even as the years-long leak indicates a series of failures, mechanical and human, it has offered researchers a rare, prolonged look at how new sources of methane affect aquifers and the surrounding landscape. It has also meant a drawn-out ordeal for the affected homeowners. Nancy DeWire, a 76-year-old sheep farmer and recent widow, can describe a personal timeline: the day her family discovered bubbling in the creek, the day an oily looking sheen of iron bacteria appeared on the water in a dish pan, the day installers put a complex water treatment system in the basement at Range Resources’ expense and ran a white pipe up the side of the red brick house. In January, she was one of seven area homeowners to receive a letter from DEP confirming the changes in her water were caused by gas drilling. She had been waiting for the letter since 2015, when she and her husband first noticed dead spots in their field.
Shell hires global firm for maintenance, repair work at cracker plant –– – Shell Chemicals’ ethane cracker plant project hit another milestone Thursday as the company hired a firm to perform maintenance work on the plant when it becomes operational in several years. Shell announced it has awarded a contract to AECOM Energy and Construction, which will provide “skilled mechanical craft labor and supervisory maintenance” work once the plant moves into an operational phase sometime early next decade. Financial terms of the contract were not disclosed. AECOM, which has its headquarters in Los Angeles, is a global company with about 87,000 employees, including about 1,200 people in Pennsylvania. AECOM’s employees will perform maintenance on the plant to ensure it is “running safely and efficiently while minimizing downtime,” Shell said in a news release. Duties will include changing out pumps, tightening flanges, and other general repairs and maintenance. “This routine preventative maintenance will create a plant which runs more efficiently, minimize potential for downtime and preserve the asset for the long term,” Shell said. Shell said AECOM’s role will be “essential to the planning and execution of maintenance once we move into operations.” The company also called the contract agreement an “important milestone” in the project’s history.
Appalachian producers expected to report modest production gains in Q1 – Appalachian-focused oil and gas producers are expected to report only modest gains in gas production in the first quarter of 2019 as they seek to hold the line on capital spending. In guidance issued toward the end of last year and earlier in 2019, most of the larger Appalachian Basin producers announced plans to scale back on capex spending on drilling, with an eye toward living within cash flow and increasing investor returns. Southwestern Energy said it had reduced planned capital investment by $200 million compared with 2019 guidance, which the company had released when it announced the sale of its assets in the Fayetteville shale last September. The company’s projected 2019 capex is also $120 million lower than 2018 capex. In February, Range Resources announced a 2019 capex budget of about $756 million — about 83% of its 2018 estimated capex budget. The company said it expects its full-year 2019 production to average between 2.32 Bcfe/d and 2.35 Bcfe/d, up only slightly from the 2.2 Bcf/d reported in 2018. Appalachian producer CNX in recent guidance said it expects 2019 average production volumes of between about 5.5 Bcfe/d and 5.7 Bcfe/d, an annual increase of about 5%, compared with 2018 volumes from retained assets of about 5.3 Bcfe/d. “Most of the companies said they expect to grow production at a modest pace while living within cash flow,” Pennsylvania issued 35% fewer permits to drill wells in Q1 2019 compared with the same period of 2018. The state Department of Environmental Protection reports that 491 permits were issued in Q1 2019 versus 758 in Q1 2018. However, the move to slow down drilling in the basin in 2019 is not yet being reflected in the rig count, particularly the number targeting the dry gas Marcellus shale play of northeastern Pennsylvania, data from S&P Global Platts Analytics shows. Producers in that region have been increasing the number of operated rigs fairly aggressively since the beginning of the new year, averaging 65 rigs year to date compared with 54 in 2018, Platts Analytics finds. This contrasts with rig activity in the Utica Shale play, where the total number of rigs has been on the decline throughout most of 2018, with the trend continuing into the current year. The number of Utica rigs averaged 19 in 2018 and has averaged just 16 in 2019 year-to-date.
PennEast pipeline: NJ says dozen historic sites on proposed route – The state Department of Environmental Protection’s Historic Preservation Office (HPO) has identified nine properties in path of the proposed PennEast pipeline that could qualify for historic preservation. The sites include the Belvidere-Delaware Railroad Historic District along the Delaware River, an 1850 house at 1155 Frenchtown-Flemington Road in Kingwood, the Hoagland Farmstead on Route 179 in West Amwell which has a stone farmhouse dating back to 1807, and farm buildings at 327 Milford-Warren Glen Road, Holland Township; 177 Gallmeier Road, Alexandria; 48 Spring Hill Road, Kingwood; 60 Stanford Road, Delaware Township; 56 Lambertville Headquarters Road, Delaware Township and 1431 Route 179, West Amwell. The HPO is recommending that more intensive research be conducted on the properties to determine their historic value. According to the HPO, the properties contain farmhouses that date back to the early to mid-19th century and most have outbuildings more than 50 years old. “PennEast has requested a meeting with the Historic Preservation Office (HPO) to gain a better understanding of the sites in question, as well as the information HPO is seeking,” said Patricia Kornick, a PennEast spokesperson. The HPO’s decision was seen was pipeline opponents as a welcome delaying tactic for the $1 billion project. “PennEast is trying to run around historic preservation requirements and New Jersey will not let them,” Jeff Tittel, executive director of the New Jersey Sierra Club, said in a statement. “PennEast tried to get off easy by claiming only three properties in its path might be eligible for historic preservation. Now the HPO has stepped in to say that potentially nine sites in PennEast’s path should be saved.”
This proposed pipeline is fracturing New York’s green new image – Rockaway peninsula is a sliver of land roughly 10 miles long and half a mile wide that juts out from the New York City borough of Queens. Locally, it’s known for its beautiful beaches, its isolation from the rest of the city, and for being especially hard-hit by Hurricane Sandy in 2012. Today, the Rockaways are in the news for a different reason – they are the proposed end-site of a new 23-mile pipeline that would run beneath lower New York Bay, carrying fracked natural gas from Pennsylvania to New York City. Controversy over the Williams Pipeline has sparked something of a region-wide identity crisis. New York state is in the middle of a green makeover. Earlier this year, it was the first state to formulate its own Green New Deal. New York City is leading the U.S. in a green overhaul, passing a carbon pricing fee charging drivers in some of the most traffic-choked neighborhoods. Last week, the city council voted to pass aClimate Mobilization Act that includes bills to make infrastructure more energy-efficient. Many activists say that, given New York’s new, greener identity, the state going forward with the Williams Pipeline doesn’t quite seem to compute. Fracking is a controversial process that involves shooting high-pressured water and chemicals deep into the earth to release hard-to-reach natural gas. It’s associated with public health threats including soil, water, and air contamination. Critics of the project say construction of the underwater pipeline could dredge up arsenic, lead, and other dangerous metals from the seafloor. They also argue that the release of methane during fracking is a powerful contributor to a warming climate. Proponents, on the other hand, say natural gas is a cleaner source of energy than oil, and that the pipeline is needed to address the state’s energy needs. Either way, the project is difficult to reconcile with the state’s own environmental policies on sourcing natural gas – Governor Andrew Cuomo imposed a statewide fracking ban back in 2014. “It’s incredibly hypocritical for us to ban fracking [in New York state] but then frack people in Pennsylvania,” said Lee Ziesche, Community Engagement Coordinator for Sane Energy Project, one of the New York-based groups leading a coalition to stop the pipeline from being built. “To be pushing for new fracked gas infrastructure, it’s the same as climate denialism really,” she contends, “You can’t say you’re a climate leader and then push these fracked gas projects.”
NYC vs Another Fracked Gas Pipeline: Notes From Activists On The Ground – The same industry that coined the term “natural” gas to package it as a “clean bridge fuel” are pushing a massive buildout of pipelines, compressor stations, power plants and export facilities to move fracked gas from shale plays like the Marcellus Shale to new markets as seen here on the interactive You Are Here map.But just as there never was a safe cigarette, there’s no safe consumption of fracked gas when it comes to our climate and health. Methane, the main component of fracked gas, is an even more potent a greenhouse gas than C02 for the first 20 years it’s in the atmosphere and if just a small percentage leaks, it’s worse for the climate than coal.(Marcellus shale map courtesy of geology.com)By May 16, New York State Governor Andrew Cuomo will have to make a decision whether he stands with climate science or fossil fuel industry propaganda when his administration’s Department of Environmental Conservation (DEC) will decide to approve or deny permits for theWilliams NESE fracked gas pipeline. And to thicken this plot, Donald Trump recently declared he will issue executive orders – to destroy the political power that anti-fossil fuel infrastructure communities have built – to demand that Williams NESE Pipeline gets built.The proposed 23-mile long pipeline would bring fracked gas from Pennsylvania through New Jersey and NY Harbor and into New York City through an existing pipeline off the coast of the Rockaways, still working to rebuild after Superstorm Sandy 6 years ago.Construction of the pipeline would dredge up industrial toxins and heavy metals that have sunk below the seafloor threatening wildlife that has seen a rebirth since the creation of Gateway National Park in 1971 to address the New York Harbor Pollution. Locking New York into several generations of fossil fuels with the Williams NESE Pipeline is not a risk we can afford to take right now. National Grid, whose current business model is dependent on fracked gas expansion, claims the pipeline is necessary to meet growing gas demand. However, a new report, False Demand: The Case Against the Williams Fracked Gas Pipeline, proves there’s no need for it, especially when energy efficiency efforts to reduce gas usage are taken into account.
WVDEP investigates oil spill at Stonecoal Lake – An oil spill was discovered by canoers at Stonecoal Lake on the morning of April 18. The West Virginia Department of Environmental Protection was contacted, and an environmental cleanup company was contracted to contain and clean up the spill. Initial response began on Thursday, April 18, said Casey Korbini, acting chief communications officer, deputy director for DEP remediation programs. Korbini said officials think the spill came from a leaking residential gas line that was connected to a gathering line of a well operated by Ross and Wharton Gas Company Inc. The cause of the leak was a coupler that came apart, Korbini said. The WVDEP does not know how long the line had been leaking or the amount of oil spilled. No wildlife has been identified as exhibiting effects from the spill. The WVDEP will contact the responsible party or parties and will oversee remediation of the spill, Korbini said. As of April 18, the party had not been determined. On Tuesday, Korbini provided an update on the spill, saying that cleanup efforts are continuing on land in the area where the line separation occurred. She added that oil is being removed from the surface of the lake that ponded at the dam. “Booms have been placed in the outlet below the dam for precaution; however, these remain clean (oil free), with no indication that oil has left the lake.
DEP: ‘Security concerns’ hampered plans for hearing on pipeline permit — The West Virginia Department of Environmental Protection scheduled a public hearing for a pipeline permit in Jefferson County, but then canceled the hearing over “security concerns” and quietly issued the permit. Residents and lawmakers in Jefferson County had requested a public hearing for the 4.85-mile-long natural gas pipeline, which would be built by Mountaineer Gas and deliver gas to Rockwool, a controversial 460,000-square-foot coal- and gas-fired manufacturing plant being built in the City of Ranson, off Route 9. The DEP had initially scheduled a public hearing for the extension project for Feb. 21 at the Ranson Civic Center, in Jefferson County. Five days before the event, the DEP issued a press release citing logistical concerns “raised by local officials.” “The WVDEP was aware that citizens had concerns and planned a discretionary hearing accordingly. However, upon notification of security concerns, the WVDEP canceled the hearing for the safety of all anticipated attendees,” Casey Korbini, deputy director for remediation programs for the DEP, said in an email. Korbini did not answer questions about what kinds of concerns were raised. The City of Ranson also didn’t respond to questions about the concerns. In the public notice, the DEP asked that comments be addressed to the DEP’s Charleston office, and said the public comment period would span from Jan. 25 to Feb. 25. The notice said a public hearing was scheduled for Feb. 21 at the Ranson Civic Center. A week before the hearing, the DEP issued a press release, canceling the event. Residents wrote to the DEP asking that the meeting be rescheduled. Regina Hendrix, chair of the Eastern Panhandle Sierra Club, said in a prepared statement. “The WV Department of Environmental Protection has utterly betrayed Eastern Panhandle residents with their approval of the permit for the Rockwool Pipeline Extension,” she said.
Mountain Valley Pipeline gets good and bad news on court challenges – A state regulation that delayed a key part of work on the Mountain Valley Pipeline – the crossings of more than 1,000 streams and wetlands in the two Virginias – has been revised in a way likely to benefit the project. The West Virginia Department of Environmental Protection wrote in a letter Wednesday to federal regulators that it has modified about 50 conditions to permits issued by the U.S. Army Corps of Engineers. One of the conditions was that the pipeline needed to be built across four major rivers in West Virginia within 72 hours. The Army Corps improperly bypassed that rule when it issued what’s called a Nationwide Permit 12 to the natural gas project, the 4th U.S. Circuit Court of Appeals ruled in throwing out the authorization in October. Although several more steps need to be taken before water body crossings can resume, a revised condition doing away with the time restriction in certain cases was seen as a victory for Mountain Valley. However, complications from another court challenge involving a different pipeline in Virginia led one of the five partners in the joint Mountain Valley venture to say this week that completion of the project by the end of this year now “appears unlikely.” Rebecca Kujawa, chief financial officer of NextEra Energy Inc., made her comments in a report on first quarter results posted to the company’s website. Construction of Mountain Valley, which began last year, is expected to ramp up in the coming months following a winter lull, Kujawa said. But she expressed concerns about a 4th Circuit decision last year that prohibited the Atlantic Coast Pipeline from crossing the Appalachian Trail. The Mountain Valley pipeline would also cross the scenic footpath, and backers worry that the project could be jeopardized by the Atlantic Coast ruling. Natalie Cox, a spokeswoman for Mountain Valley, said Thursday that there have been no announced changes to the company’s most recent goal of a late 2019 completion date. When work on the 303-mile pipeline began a year ago, plans were to have it done by late 2018. As for the Nationwide Permit process, Cox said, the next step will be for the U.S. Environmental Protection Agency to review the modified conditions from West Virginia. Then the Army Corps will do the same. Mountain Valley still hopes to receive a new permit from the Army Corps in time to compete the project this year, she said.
Living in the trees to protest the pipeline – Phillip Flagg pokes his head out from the tarps that make up his treetop home and looks down. He carefully lowers an empty paint bucket the 50 feet to the ground. A friend puts a Tupperware container with pigs-in-a-blanket (made with fake meat) into the bucket and Flagg pulls it back up. It’s his lunch. “Are you bored up there?” the friend – his ground support – calls. He laughs, then says no. His platform is slightly larger than a double-size mattress with 14 buckets hanging beneath, each with a purpose: food, books, water and other essentials. A solar panel charges Flagg’s phone. The ground crew says that he gets a better signal in the treetops than they do. The protesters took to the treetops in early September 2018, and seven months later they’re still there. “At this point we’re kind of mentally preparing for the long haul,” Flagg said. Flagg hasn’t touched the ground in more than five months, since he climbed the tree on Oct. 12 to block construction of the Mountain Valley Pipeline, a 303-mile line running from northern West Virginia to the border of North Carolina. With the announcement of a 70-mile extension into Rockingham and Alamance counties in North Carolina, called Mountain Valley Pipeline Southgate, the protesters’ role has taken on new importance to North Carolinians. The protesters sit just outside of Elliston, Virginia, 25 miles west of Roanoke in the foothills of the Blue Ridge Mountains. The camp is about a mile back along the gravel road that gave them their name – Yellow Finch. They’re part of Appalachians Against Pipelines, a loose group of individuals with the same mission: fighting pipelines through the mountains they call home. The organization uses nonviolent direct action – physically blocking construction with their campsites, tree sits, and their bodies. Their goal is to delay or even stop the pipeline.
FERC Report: Still More Demand than Supply for NatGas in 2018 – Last week the Federal Energy Regulatory Commission (FERC) released its annual State of the Markets report – for 2018. The report summarizes FERC’s assessment of natural gas, electric, and other energy market developments during the past year. The revelation (for us) coming from the report was in reading that although the U.S. had record high natural gas production and demand last year (from electric generation and LNG exports), the growth in demand for natgas outpaced the growth in production. A few other tidbits: Gas production averaged 80.7 billion cubic feet per day, up 12% from 2017. And of course the Marcellus Shale was the most productive basin, averaging 19.4 Bcf/d in 2018, up 13.5% from 2017. The following article from RTO Insider does a great job summarizing the report. The FERC report follows the article. Record high natural gas demand and production highlighted FERC’s 2018 State of the Markets report, released last week. The report by the Division of Energy Market Oversight said gas demand was driven by electric generation and growing LNG exports. Despite big jumps in the Marcellus Shale and the Permian Basin regions, demand growth outpaced production increases. As a result, storage levels were lower than average and “at times were the lowest in more than a decade,” FERC said, contributing to higher gas and power prices. The Henry Hub benchmark averaged $3.12/MMBtu for the year, up 5% from 2017. Reduced storage inventories pushed Henry Hub prices up 31% in the fourth quarter over a year earlier. Although gas prices remained relatively low, there was increased price volatility because of storage constraints, extended winter cold and infrastructure constraints in the West. In January 2018, an East Coast cold snap pushed gas prices to $140.85/MMBtu in New York and $128.39/MMBtu in the Mid-Atlantic, with prices peaking at $78.88/MMBtu in Boston. In contrast, New York’s spot price never reached $21/MMBtu in 2017.Gas production averaged 80.7 Bcfd, an increase of 12% from 2017. The Marcellus Shale was the most productive basin, averaging 19.4 Bcfd for 2018, up nearly 13.5% from 2017.Haynesville Shale production jumped to an average of 6.5 Bcfd, a 46% increase that FERC attributed to higher gas prices and lower production costs. Rising crude oil prices were a factor in the 2.1-Bcfd increase in associated natural gas production in the Permian, a jump of 41%. More than 689 miles of commission-jurisdictional pipelines, representing 13 Bcfd of capacity, went into service during 2018, much of it connecting Marcellus and Utica supplies to markets in the Midwest, Northeast and Southeast. There was no capacity increase in New England. *RTO Insider (Apr 22, 2019) – Record Gas Demand, Production Highlights FERC Markets Report
Why Are Natural Gas Prices Crashing? — Shrugging off low levels of storage, natural gas prices have continued to plunge. The U.S. entered this past winter with natural gas supplies at a 15-year low. Paltry levels of gas in storage, just ahead of the peak winter demand season, pushed prices up to the highest level in four years. A cold snap in November led to a jump of around 30 percent in a week, an increase so fast and so quick that it forced at least one trading firm out of business. By mid-November, prices had climbed as high as $4.80/MMBtu. Gas supplies in storage were at their lowest levels in a decade and a half, and demand had steadily increased year-after-year as gas-fired power plants replaced shuttered coal plants. The surge in LNG exports and petrochemicals also amounted to a new source of demand that didn’t exist in its current form only a few years ago. To top it off, there were several rounds of extreme cold that swept across the North American continent, forcing millions of people to crank up the heat. Yet, despite that backdrop, prices shockingly fell back rather quickly. A few weeks after the November price spike, Henry Hub spot prices dropped below $4/MMBtu. By February, prices fell below $3/MMBtu and remained there, with the market eyeing the end of the winter demand season. Now, with temperatures rising, prices recently plunged as low as $2.50/MMBtu. However, the price decline comes even as storage remains remarkably tight. Natural gas inventories stood at 1,247 billion cubic feet (Bcf) as of April 12. Notably, despite the large increase of 92 Bcf from the week earlier, gas inventories were still 414 Bcf below the five-year average, and also at multi-year lows for the time of year. Why are prices hovering close to their lowest levels in years, even though inventories have been decimated? The answer largely comes down to record levels of production, with output continuing to rise on an ongoing basis. Analysts and gas traders have largely shrugged off low storage levels, expecting that the “injection season” – the months between April and November when demand is seasonally soft – will see storage levels fill up quickly, replenishing depleted stocks.
Firm Cash And Slightly Higher Demand Allow Natural Gas Prices To Rise – After quite a decline in recent sessions, May natural gas prices were able to close just over 3 cents higher on the day today. The strength, however, was limited mostly to the front of the curve, with later-dated contracts unable to move. The rise in the front came as a result of firmer cash prices, as well as a bump up in weather demand compared to the forecasts from back on Thursday. In terms of absolute demand, the pattern remains weak, however, despite the increase that showed up over the weekend. There is still a lot of warmth indicated on the forecast maps, with cooling confined to the far northern parts of the U.S. This is warm enough to generate some cooling demand across the South, though nothing major yet at this early stage of the season. Fundamentals data was mixed over the weekend, with both production as well as LNG exports climbing back to near-record high levels. These factors essentially negated one another, which is why the later-dated contracts were unable to move today.
Natural Gas Prices Remain Stuck In Shoulder Season Rut For Another Day – After an early rally that saw May natural gas prices up as much as 3 cents on the day, much of the rally reversed, with the May contract finishing up only 7 ticks on the day. Yesterday, cash prices were the culprit in triggering widespread selling, though today’s cash prints were a little firmer. So, if not cash, then what halted today’s attempt at a rally? It was continued pressure on later-dated contracts, from summer through next winter, which then bled into the front of the curve. The relentless selling in the later-dated contracts has not allowed us to have a true “Spring rally”, which has historically been common, making this year a big outlier in recent seasonality trends. On the weather side, we have seen some colder adjustments in the northern half of the nation, along with some warmer changes in the southern U.S. This pattern leads to more heating demand in the north, and some early season cooling demand in the south, boosting GWDD levels back closer to normal for this time of year. For the first time in several weeks, we also now finally see forecast GWDDs (weather demand) higher than the same dates from last year. Is all of this enough to finally spark a rally in natural gas prices, or are the robust supply levels too much to overcome?
Trump Considering Waiving Jones Act Mandate for Natural Gas, Sources Say – President Donald Trump is seriously considering waiving the requirement that only U.S.-flagged vessels can move natural gas from American ports to Puerto Rico or the Northeast, according to people familiar with the deliberations. The issue was debated during an Oval Office meeting on Monday, following requests from Puerto Rico and pressure from oil industry leaders to ease the nearly 100-year-old Jones Act requirements, according to three people. Although top administration officials are divided on the issue, Trump is now leaning in favor of some kind of waiver, said two of the people, who asked for anonymity to discuss the private deliberations. The move — which would be fought by U.S shipbuilding interests and their allies on Capitol Hill — has been promoted as essential to lower the cost of energy in Puerto Rico and ease the flow of American natural gas to the U.S. Northeast, where there aren’t enough pipelines to deliver the product from Pennsylvania. But even inside the Trump administration, there are fierce defenders of the Jones Act, a 1920 law requiring that vessels moving cargo between two U.S. ports be U.S.-built, -owned and -crewed. The law was originally designed to protect the domestic shipping industry and the country’s maritime might, and supporters argue that it’s just as essential today to ensure ships are made in the U.S. Any move to weaken or waive the requirements threatens the U.S. shipbuilding industry and the jobs tied to it, they argue. That divide was apparent during Monday’s White House meeting, where Jones Act supporters included Trump trade adviser Peter Navarro and Transportation Secretary Elaine Chao. Larry Kudlow, the director of the National Economic Council, pushed for waiving the Jones Act, three of the people said. Even as the White House weighs waivers, a handful of Trump administration officials have pushed to expand the Jones Act’s reach, two of the people said. They are aiming to effectively revive a Customs and Border Protection bid to revoke rulings allowing foreign vessels to transport some equipment to offshore oil rigs. The agency withdrew the formal proposal in 2017, after the oil industry warned it could cripple production in the Gulf of Mexico. The White House press office did not respond to a request for comment. Trump faces increasing pressure to relax the shipping requirements. Puerto Rico is seeking a 10-year waiver to allow liquefied natural gas to be delivered to the island on foreign-flagged vessels.
Natural Gas Storage Stocks Move Above Year-Ago Levels After EIA Reports 92 Bcf Build – The Energy Information Administration (EIA) reported a 92 Bcf injection into U.S. natural gas storage for the week ending April 19, pushing inventories to a 55 Bcf surplus over year-ago levels. The reported build was in line with market expectations and compares to last year’s 20 Bcf withdrawal and the five-year average injection of 47 Bcf. Natural gas futures prices had a muted initial response to the reported injection, shifting about a penny higher after the print hit the screen, although pushing the prompt month into positive territory. By 11 a.m. ET, the May Nymex gas futures contract had tacked on additional small gains as it traded at $2.481, up 1.9 cents on the day. Ahead of the report, a Bloomberg survey of 17 analysts showed a build ranging from 69 Bcf to 98 Bcf, with a median of 92 Bcf. A Wall Street Journal poll of 13 market participants had estimates ranging from an increase of 82 Bcf to 94 Bcf, with an average build of 89 Bcf. A Reuters survey of 19 analysts ranged from a 69 Bcf to 95 Bcf build, with a median of 91 Bcf. Intercontinental Exchange EIA Financial Weekly Index futures settled Wednesday at a build of 90 Bcf. NGI’s model predicted an 82 Bcf build, slightly below consensus. The South Central continued to surprise to the upside this week, with the EIA reporting a 45 Bcf build in that region. IAF Advisors’ Kyle Cooper questioned whether part of that storage build could be attributed to local distribution companies in the Midwest and Northeast indexing gas now for the upcoming winter and passing on the cost to ratepayers. “Obviously, things have changed a lot over the years,” Cooper said on Enelyst, a chat room hosted by The Desk. “From a long-term plan, buy April/May South Central, then buy the Northeast local gas in the summer, maybe when Texas gets hot … just a theory.” Broken down by region, the EIA reported a 23 Bcf injection in the East, a 10 Bcf build in the Midwest and a 45 Bcf injection in the South Central region. Salt facilities added 17 Bcf, while nonsalts added 29 Bcf to inventories, according to EIA. Total working gas in storage as of April 19 was 1,339 Bcf, 55 Bcf above last year and 369 Bcf below the five-year average.
Natural Gas Prices Finally Halt Their Slide – After quite the decline in recent weeks, natural gas prices were finally able to put together a noteworthy upward move today, with May prices rallying over 2% on the day. The move came after being down initially in morning trading. In our morning report, we had warned of some upside risk in prices, with our sentiment being “slightly bullish” for the day. That worked out well, with the entire curve finishing the day with gains. Helping to spark today’s rally appeared to be alleviating fears that today’s EIA Report would show an injection around 100 bcf for the week ending 4/19/19. The number wound up coming in right at our estimate of 92 bcf. While still a much larger build compared to the 5-year average, it did not represent quite as weak of a supply / demand balance as the prior two weeks. We also have continued to see gains in forecast weather demand over the next couple of weeks, with our forecast running a little higher than normal demand levels, and much higher than demand levels on the same dates one year ago. At this time of year, weather isn’t typically as much of a player in the natural gas world, but this setup is rather unique, with enough cold weather in the north for heating demand to be enhanced, but also some heat in the southern U.S. to enhance cooling demand, as shown in the GFS Ensemble projection for the 6-10 day period. Forecast high temperatures even this weekend are rather chilly for this time of the year from the Upper Midwest to New England. By the middle of next week, focus shifts quickly to the South, where we will see numerous high temperatures in the 85-90 degree range, definitely enough for folks to crank up the air-conditioning.
Catch A Wave, Part 2 – More U.S. LNG Export Projects Moving Toward FID — 2019 is slated to be a watershed year for U.S. LNG export projects vying to catch the second wave – the first wave being the slew of liquefaction trains already operational or in the process of being commissioned or constructed. As expected, regulatory and commercial activity has heated up around the two dozen or so longer-term proposals to add liquefaction capacity along the U.S. coastlines over the next decade. Last week, the Federal Energy Regulatory Commission (FERC) approved two of those projects – Tellurian’s Driftwood LNG and Sempra’s Port Arthur LNG – and several others, including Driftwood and NextDecade’s Rio Grande LNG, also have made progress on the commercial front. Many of these projects are targeting a final investment decision (FID) this year. Today, we continue a series highlighting the second-wave projects’ latest developments. We started our update of the “second-wave” LNG export projects in Part 1 with a discussion of the key hurdles that LNG export projects must clear before developers will take FID, i.e., make the full financial commitment to build these multibillion-dollar terminals. It’s not a quick or linear process, with different projects taking different routes to reach that point depending on their location and business model, but, generally speaking, conditions must align in two or three areas in order for project developers to pull the financial trigger: regulatory approvals, commercial agreements, and supply or pipeline capacity arrangements. On the regulatory front, U.S. projects must secure environmental approval from FERC, in addition to approvals from the Department of Energy (DOE) for exporting to free-trade-agreement (FTA) and/or non-FTA countries (or, in the case of Canadian projects, for example, from the National Energy Board or NEB). And when it comes to offshore projects, approvals from the U.S. Maritime Administration (MARAD) also come into play. On the commercial front, developers look to lock in third-party financial commitments to help finance the terminal and spread the risk. This may come in the form of offtaker sales and purchase agreements (SPAs) for LNG supply, project financing and/or equity partnerships. (As a general rule of thumb, developers aim to “pre-sell” about 75% of their liquefaction capacity, which can then attract additional investors to join the project.) And, finally, the projects (or their offtakers) must be able to secure the feedgas supply and the firm pipeline capacity to physically move it to the terminal for liquefaction and export. This may involve signing up for firm transport on existing or new third-party pipeline routes or developing their own pipeline to supply the terminal. Some may also opt to underpin their projects with upstream positions.
US exports transform NGL markets – – U.S. propane is fanning out across the planet, with export volumes now triple those of any other country. The global LPG market today is dominated by cargoes shipped from U.S. ports. Buyers from Mexico to South Korea can’t make a move without considering conditions on the Houston Ship Channel or pipeline constraints in Pennsylvania. But an interconnected market is a two-way street. U.S. propane prices are now influenced more by the weather in Europe and Asia than by the weather in Wisconsin or New Hampshire. And it’s not only propane. All NGLs are experiencing growth in U.S. export volumes, with huge implications for infrastructure, capacity constraints and, of course, prices. Today, we preview the deep dive into these issues on the agenda at RBN’s upcoming xPortCon conference. NGL exports have been a frequent topic in the RBN blogosphere, with our most recent series on the subject titled Between Mont Belvieu and the Deep Blue Sea posted earlier this year. We also considered the impact of all of these exports on the U.S. domestic NGL market in Complicated – Petchem Demand, Exports. But these blogs only scratched the surface of what’s going on with U.S. NGL exports. Figure 1 puts the magnitude of U.S. LPG (propane and butane) exports to overseas markets in perspective. From less than 100 Mb/d 10 years ago (for those of you that think in metric, that’s about 3 million metric tons per annum, or MMtpa), U.S. exports have soared to more than 1.1 MMb/d (about 33 MMtpa) – an 11-fold increase. In recent years, 60% of LPG exports have been sourced from the two docks located on the Houston Ship Channel: Enterprise and Targa. Another 30% came from two other Gulf Coast facilities: Energy Transfer at Nederland and Phillips 66 at Freeport. Only about 5% moved out of the Energy Transfer dock at Marcus Hook, PA, but that is changing fast. With the completion of the Mariner East 2 pipeline in December 2018 (see It’s All Wrong, But It’s Alright), Marcus Hook export volumes have been hitting all-time records in early 2019.
No emergency plan for Bayou Bridge Pipeline violates permit: environmental group – The controversial – but now complete – Bayou Bridge Pipeline has drawn another legal challenge from the Atchafalaya Basinkeeper environmental group, which questions why the pipeline was allowed to begin operating on April 1 without having an approved emergency response plan. The state Department of Natural Resources said it would investigate the complaint, but said the pipeline’s operation falls under federal law, and the federal Pipeline and Hazardous Materials Safety Administration say the pipeline is complying with federal regulations. The 163-mile Louisiana segment of the pipeline that is transporting oil from Texas to St. James Parish has been the subject of of numerous legal challenges by environmentalists concerned about its effects on swampland in the Atchafalaya Delta and by landowners whose property was crossed without their permission. The pipeline is operated by Houston-based Energy Transfer Partners, its majority owner. Phillips 66 Partners owns 40 percent of the pipeline. On Friday (April 19), the Basinkeeper filed a “citizen complaint” asking the state Department of Natural Resources to enforce a condition included in the pipeline’s state coastal use permit that the group says requires a “facility response plan” to be in place before it transports oil. A spokesman for DNR said Monday that the agency actually relies on the federal pipeline agency to regulate the day to day operations of pipelines, but that it was looking into the Basinkeeper complaint. The Basinkeeper complaint pointed out that the federal pipeline agency had informed it on April 11 that Bayou Bridge had not yet submitted the response plan. But in an April 16 letter submitted as part of motions on behalf of DNR in a state Supreme Court case involving the pipeline, a PHMSA official said that Energy Transfer Partners had submitted a similar “Integrated Contingency Plan” that includes the 162-mile Bayou Bridge segment, but that PHMSA had not yet approved that plan.
Trump is shelving plans to open virtually all federal waters to offshore drilling – The Trump administration will not move forward with plans to open virtually all federal waters to offshore drilling, according to recently confirmed Interior Secretary David Bernhardt.The administration is putting the expansion on hold after a federal judge shot down its attempt to overturn President Barack Obama’s Arctic drilling ban, Bernhardt told The Wall Street Journal. The ruling could lead to a prolonged appeals process that delays the Interior Department’s decision on which offshore areas it will put up for auction, Bernhardt said.“By the time the court rules, that may be discombobulating to our plan,” Bernhardt said in an interview with the Journal. He said he’s not sure it’s “a very satisfactory and responsible use of resources” to offer offshore blocks that may get tied up in legal proceedings.Last month, Judge Sharon Gleason for the District Court of Alaska ruled that President Donald Trump’s executive order overturning Obama’s Arctic drilling ban was unlawful and invalid. In doing so, Gleason ruled in favor of environmental groups, who argued that Congress gave the U.S. president the power to remove federal waters from consideration under the Outer Continental Shelf Lands Act, but not the authority to overturn a previous president’s withdrawal.
Interior abruptly pauses offshore drilling action following legal setbacks and bipartisan opposition – Interior Secretary David Bernhardt said the agency has abruptly paused its controversial plans to open virtually all U.S. waters to offshore drilling, a stunning reversal following more than a year of bipartisan uproar from coastal communities.The news comes as some Democratic presidential candidates have started to speak out on the issue. Sen. Elizabeth Warren (D-MA) recently took a strong stand against offshore drilling in South Carolina, a key primary state that has largely revolted against President Donald Trump’s coastal fossil fuel ambitions. Several others have since joined in calls against the expansion of offshore drilling.In an interview Thursday with the Wall Street Journal, Bernhardt said the administration’s long-anticipated five-year leasing plan targeting the Outer Continental Shelf (OCS) has been sidelined following a federal court decision in Alaska earlier this month. U.S. District Court Judge Sharon Gleason blocked Trump administration efforts to reverse the Obama-era ban on oil and gas leasing in both the Arctic Ocean and parts of the Atlantic Ocean, determining that Trump had “exceeded” his authority in challenging the limits on drilling. The decision left DOI officials unsure of how to proceed on broader offshore drilling efforts. “By the time the court rules, that may be discombobulating to our plan,” Bernhardt said, pointing to the limits of any future efforts to expand offshore drilling in the area. DOI acknowledged Bernhardt’s comments but said there were no more updates available on the department’s offshore drilling plans. Opponents, however, cautiously greeted the news with optimism.
Houston suffers a petrochemical disaster every 6 weeks – In the past month, Houston area-residents faced three major disasters related to oil and gas infrastructure. As a Houston resident, I was alarmed to see weekly news reports presenting the unknown dangers each fire posed to the community members living next door, and to those of us living just a few miles away. These facilities store and process various types of petrochemical products including feedstocks for plastics. Ethane, a fracked natural gas liquid, is one of the primary building blocks for plastics. In places like Houston, petrochemical facilities first crack (process) the ethane molecule into ethylene, using it to create polyethylene, today’s most commonly used plastic. Above is a map of the three locations where fires associated with oil and gas infrastructure were located. On March 16th, Exxonmobil’s Baytown refinery caught fire for over four hours. A plume was visible over the skyline Saturday afternoon. Although dark smoke came from the facility, no shelter-in-place was issued for surrounding residents. According to historical documents on the facility, this was the 9th major incident at the site in the last 10 years. On March 17th, a fire erupted in Deer Park, Texas at the Intercontinental Trading Company (ITC) site, which created a plume that spread over 100 miles. ITC is a storage facility for the US Gulf Coast containing 242 storage tanks that store petrochemical liquids and gasses, as well as fuel oil, bunker oil, and distillates. Ten storage tanks were on fire for almost a week, resulting in days of closed schools for thousands of students, shelter-in-place orders for several surrounding communities due to elevated benzene levels, and a breach in a dike wall leading to thousands of toxic chemicals spilling into the ship channel. On, April 2nd, just three weeks after the Exxon and ITC fires, another fire broke out at the KMCO plant in Crosby that left one person dead and two others injured. Located just a 30-minute drive north of the previous fires, the facility caught fire and spread more toxic fumes over the Deer Park neighborhood previously contaminated by the fire at ITC. According to officials, a gas line caught fire near a tank full of isobutylene, a flammable gas used for rubbers, plastics, fragrances in fuels or pharmaceuticals. The fire resulted in emissions of over 2,300 pounds of toxic chemicals including isobutylene, toluene, and other volatile organic compounds known to cause many health issues. Crosby residents suffer from a poverty rate twice that of the US at large and live in a region with elevated cancer risks. KMCO is one of the many contributors to cancer-causing agents in the region. And, similar to ITC, has repeatedly violated the Clean Air and Clean Water Act.
Oil Producers Are Burning Enough ‘Waste’ Gas to Power Every Home in Texas – America’s hottest oil patch is producing so much natural gas that by the end of last year producers were burning off more than enough of the fuel to meet residential demand across the whole of Texas. The phenomenon has likely only intensified since then. Flaring is the controversial but common practice in which oil and gas drillers burn off gas that can’t be easily or efficiently captured and stored. It releases carbon dioxide and is lighting up the skies of West Texas and New Mexico as the Permian Basin undergoes a massive production boom. Oil wells there produce gas as a byproduct, and because pipeline infrastructure hasn’t kept pace with the expansion, energy companies must sometimes choose between flaring and slowing production. The amount of gas flared in the Permian rose about 85 percent last year reaching 553 million cubic feet a day in the fourth quarter, according to data from Oslo-based consultant Rystad Energy. Local prices that are hovering near zero will remain “under stress” until more pipelines come online, Moody’s Investors Service said in a note Thursday. There will always be a “mismatch” between the amount of gas produced and pipeline capacity, so some flaring is inevitable, according to Ryan Sitton, the head of the Railroad Commission of Texas. Despite what its name suggests, his agency oversees the oil and gas industry in the state and regulates flaring, allowing companies to burn gas for limited periods, or in times of emergency. Some 4 billion cubic feet of pipelines are expected come online in the next year or so, which will likely reduce, but not eliminate, the need to flare, the commissioner said in an interview. Right now, there’s about 9.5 billion feet a day of gas pipeline capacity in the basin that can reach markets that need the heating and power plant fuel, according to RS Energy Group. That’s not enough to carry the more than 13 billion cubic feet a day of gas that’s being pumped out of wells in the region. Unsurprisingly, with such an abundance of gas but also real difficulties in getting it to consumers, prices for the fuel in Permian have been cheaper than in other parts of the U.S., and earlier this month they went negative, meaning producers had to pay customers to take their gas.
Apache Shuts In Permian Gas Production As Prices Crash — Apache Corporation said on Tuesday that it had temporarily started to delay natural gas production at its Alpine High play in the Permian in late March to mitigate the impact of the extremely low prices at the Waha hub in West Texas. Currently, the company is deferring around 250 million cubic feet (MMcf) per day of gross gas production. Natural gas prices at the Waha hub plummeted to record low negative levels in early April, as pipeline constraints and problems at compressor stations at one pipeline stranded gas produced in the Permian. Spot prices at the Waha hub plunged to a record low of minus $4.28 per million British thermal units (MMBtu) in the first week of April. Gas production in the Permian has been rising in lockstep with crude oil production, and even though gas takeaway capacity has attracted less media attention, pipeline constraints for natural gas are similar to those of crude oil pipeline capacity. The natural gas takeaway capacity constraints have resulted in more gas flaring in the Permian on the one hand, and in a record-high spread between the Waha gas hub price and the U.S. benchmark Henry Hub in Louisiana, on the other hand. “We will closely monitor daily pricing and return our gas to sales when it is profitable to do so. We are carefully managing these actions so there is no adverse impact on long-term wellbore integrity or reservoir productivity and look forward to returning this production to market as soon as practical,” John J. Christmann IV, CEO and president of Apache Corporation, said in a statement today. Apache contracted two years ago more than 1 billion cubic feet (Bcf) per day of long-term, firm takeaway capacity from the Permian Basin on Kinder Morgan’s pipeline projects Gulf Coast Express and Permian Highway, Apache said, noting that Gulf Coast Express is expected to be in service later this year, while Permian Highway is set to start operations next year.
Permian Oil Now Selling At A Discount – Gulf Coast refiners are having trouble swallowing up all of the ultralight oil coming out of the Permian. The Permian continues to add production, even as drilling activity slows down in Texas and elsewhere. According to the EIA, the Permian could add another 42,000 barrels per day in May, with output now well above 4 million barrels per day (mb/d). That comes even as the rig count has declined sharply from fourth quarter highs last year. The record levels of production present new challenges. The pipeline bottleneck that really became an acute problem a year ago has eased somewhat. New capacity came online in recent months, while larger pipeline projects are expected to reach completion later in 2019. That will allow more oil to reach the Gulf Coast. But from there, the flow of oil runs into other bottlenecks. U.S. oil exports continue to break new records. Although the numbers bounce around from week to week, U.S. crude exports now routinely top 2 mb/d, and even exceeded 3 mb/d at times this year. A year ago, exports above 2 mb/d would have been considered exceptionally high, and only occurred on rare occasions. As recently as 2017, exports tended to hover below 1 mb/d. Still, Gulf Coast ports are bumping up against their limits, unable to export every last barrel. That leads to another bottleneck: Gulf Coast refiners are not equipped to handle huge volumes of ultralight oil. Refineries built years ago were done so with the intention that they would import medium and heavy barrels from abroad. They can’t simply switch over to light and ultralight oil without problems. Growing supplies of light and ultralight oil come at a time when medium and heavy blends around the world are in shorter supply. Iran sanctions, Venezuela sanctions, Canadian pipeline woes, declines in Mexican heavy oil, and the OPEC+ cuts have all cut into the supply of medium and heavy oil. Light oil was already coming under pressure from soaring production at a time when medium and heavy blends were tight, but now the increasing volumes of ultralight oil have made it difficult to even put together the right specs for what is commonly known as WTI. As such, the surplus of ultralight oil has led to discounts of a few dollars per barrel below WTI, according to Reuters. “For the past 10 years, US traders have been able to manage the wide range of crude oils coming from the various shale basins to create marketable, WTI quality barrels,” Bank of America Merrill Lynch wrote in a report on April 18. “Recently though, this task has become more difficult due to surging output of superlight crude in the Permian.”
Is the Permian Played Out? – The Permian is not played out, according to Regina Mayor, global sector head of energy and natural resources for KPMG, who made the statement in a recent television interview with Bloomberg.“What the industry is proving is that the Permian is not played out yet,” Mayor said in the interview, which was published on Friday last week.“I keep getting asked ‘is the Permian played out?’ and I keep saying no. Permania is alive and well and I think it’s here to stay,” Mayor added.In a separate television interview with Bloomberg earlier this year, Fatih Birol, executive director at the International Energy Agency, said “we have not seen the full impact of the shale revolution yet“.“[There is] more to come both for oil and gas and it will have huge implications for the oil industry, gas industry and the markets,” Birol told Bloomberg in the interview.“There was a major problem in [the] United States in the Permian basin. It is a logistical problem, the pipe capacity was not enough to bring the oil to the markets. And now, as of end of 2019 this problem will be solved with the new construction of the pipelines,” he added.Last month, Texas Independent Producers & Royalty Owners (TIPRO) Association President Ed Longanecker told Rigzone “we will continue to see oil and natural gas employment growth in the Permian basin this year”. As of March, TIPRO was tracking over 1,000 open positions in the upstream sector in the Permian, including Texas and New Mexico. The full oil and natural gas industry in the Permian – including upstream, midstream and downstream – had approximately 2,700 open positions as of March, according to TIPRO.
Railroad Commission, Kinder Morgan sued over route of Permian Highway Pipeline – Hays County, the city of Kyle and a coalition of Hill Country landowners have filed a lawsuit to fight the route of Kinder Morgan’s proposed Permian Highway Pipeline and challenge how the state agency that regulates the oil and gas industry allows companies to use eminent domain laws.During a Monday morning news conference at Kyle City Hall, the coalition released copies of a 19-page lawsuit against the Texas Railroad Commission, five agency executives, pipeline operator Kinder Morgan and a subsidiary of the Houston company overseeing the project. The lawsuit, filed in state District Court in Travis County, asks a judge to block construction of the 42-inch pipeline designed to move 2 billion cubic feet of natural gas per day from the Permian Basin of West Texas to the Katy Hub near Houston. That’s roughly enough gas to fuel about 10 million U.S. homes per day.Opponents claim that the Railroad Commission is allowing the 423-mile pipeline to run through residential areas of Kyle, about 20 miles south of Austin, near the Lyndon B. Johnson National Historical Park in Stonewall and less than a mile away from Jacob’s Well, a popular summertime swimming hole near Wimberley.”A lawsuit is a regrettable event,” said Clark Richards, an attorney for the project opponents. “But we believe that the Texas Constitution affords more protection to our clients than is being provided to them in the current process, and we look forward to the opportunity to present that to the court.” Legal fees for the lawsuit are being paid for by the Texas Real Estate Advocacy and Defense Coalition, or TREAD, which represents landowners. The nonprofit advocacy organization was founded last year in response to concerns over property taxes, water rights and eminent domain issues.
Texas House panel considers controversial eminent domain reforms – Lawmakers, lobbyists and landowners sparred at a Capitol committee hearing on Thursday over a batch of bills designed to protect property owners whose land may be seized by private companies to build oil and gas pipelines.A bipartisan – though largely Republican – group of House and Senate legislators whose districts have been targeted for pipeline construction amid a historic oil and gas boom have proposed several measures this year aimed at helping landowners and local officials negotiate with deep-pocketed energy companies eager to move fossil fuels to processing and export facilities on the Gulf Coast.The reform push has put some Republicans at odds with an industry they typically champion – and one that donates significant dollars to their political campaigns – as well as members of their own party.Perhaps the most controversial legislation – proposed by Republican state Sen. Lois Kolkhorst of Brenham – would require companies to include specific provisions in agreements with landowners explaining exactly where they plan to construct pipelines and a promise that they will repair fences, gates or other infrastructure if they damage them. Senate Bill 421 – one of 11 eminent domain-related bills that the House Land and Resource Management Committee considered on Thursday – also would require private companies to offer to pay landowners fair market value and to hold public meetings if they plan to seize 25 or more tracts of land. “It’s well known that Texas property owners continue to struggle with the eminent domain process in a variety of ways and it’s paramount that Texas property owners have greater assurance that the eminent domain process be fair, transparent, respectful,” state Rep. DeWayne Burns, a Republican from Cleburne who filed a similar bill in the House, told the committee on Thursday.
Bill Being Considered by Texas Senate Would Let Companies Dump Fracking Waste Into Waterways – Environmental groups are warning that a bill passed by the Texas House and now awaiting discussion in the Texas Senate would give fracking companies a license to pollute the state’s waterways. House Bill 2771, which received an affirmative vote yesterday afternoon, would allow the Texas Commission on Environmental Quality to grant permits to let oil and gas companies discharge water used at fracking sites into rivers and streams. The Senate is expected to take up companion legislation, Senate Bill 1585, early next week. The bill requires energy companies to treat the water before it can be discharged, but environmental groups caution that the bill is vague about what that means. What’s more, Texas law allows companies to keep the ingredients of their fracking fluids secret, making testing and follow-up tricky to say the least. “We have no ability to confirm what chemicals are in the water,” said Adrian Shelley, director of watchdog group Public Citizen’s Texas office. “Without that, there’s no assurance you’re correctly catching everything when you test for it.” According to a recent study, wastewater from fracking sites is on the rise. Companies used 770 percent more water per well in 2016 than in 2011 across all major gas- and oil-producing regions in the United States, the peer-reviewed journal Science Advances found.
Texas-based company to address oilfield waste in the Permian – Waste from the oilfield could be addressed as a Texas-based company secured permits to develop multiple landfills in the Permian Basin of southeast New Mexico and West Texas. Milestone Environmental Services announced on April 9 that it received a landfill permit from the Railroad Commission of Texas to build its second landfill in the area. The 7.8 million cubic yard landfill will be situated about 34 miles sound of Midland, off Texas State Highway 34, about 8.5 mils sound of the company’s existing South Midland slurry injection facility.The landfill will sit on 93 acres, serving customers in the southern portion of the Midland Basin, the Texas side of the Permian, and will accept cuttings, contaminated soil and other solid waste from oil and gas operations. Milestone President and Chief Executive Officer Gabriel Rio said the asset will allow Milestone to accept and dispose of a broader variety of waste.“The Midland Basin continues to have some of the highest density of drilling, completion, and production activity in the world, and responsible development of this important play requires a world-class oilfield waste management solution,” he said. “Located near our South Midland slurry injection facility, the addition of the Upton landfill will allow us to accept the entire spectrum of oilfield wastes from customers in the Midland Basin.”
Neighbors sue 2 Trempealeau County frac sand mines over pollution, nuisance complaints – More than three dozen western Wisconsin residents are suing subsidiaries of a frac sand mining company that spilled 10 million gallons of wastewater into the Trempealeau River last spring. In four separate complaints filed Monday by the same attorney, neighbors of Hi-Crush mines in Whitehall and Blair allege ongoing air, water, noise and light pollution from the mines. According to complaints filed in Trempealeau County Circuit Court, silica dust from the mines regularly blows onto their property, violating air-quality standards, and their well water is undrinkable because of dangerous levels of arsenic and other particles. Plaintiffs say they can’t open their windows and are subject to constant noise and light. According to the complaints, living near the mines has led to marital strife, anxiety, depression and high blood pressure. “Hi-Crush strives every day to adhere to all applicable rules, regulations and agreements with local jurisdictions,” company spokesman Steve Bell said in a written statement. “As a Green Tier company, we recognize the importance of environmental stewardship and being a good neighbor. We take these matters seriously and will present a vigorous defense based on the facts and the law.” Attorney Tim Jacobson of La Crosse said he believes these to be the first such lawsuits against Wisconsin frac sand mines, although he represented clients who sought to block two proposed mines on the grounds that they would create similar nuisances. “Our clients have had their quality of life severely diminished by the nearby presence of the frac sand operations,” Jacobson said. “It is difficult for them to live there every day.” The 40 plaintiffs are seeking unspecified damages and penalties stiff enough to “punish Hi-Crush and to deter it and others … from engaging in similar wrongdoing.”
Pipeline spill in Lyon County, Minnesota — Crews are working to cleanup a pipeline spill near Cottonwood in Lyon County, Minnesota Thursday morning. According to Magellan Midstream Partners, an oil pipeline company, the spill was confirmed around 8:30 p.m. Wednesday night. The leak was diesel fuel and an estimated 200 barrels or 8,400 gallons of fuel leaked. By 10:30 p.m., the leaking had stopped. Cleanup efforts are underway Thursday to contain the fuel, which has entered a drainage ditch, from entering lake waters in the area. The cause of the leak is under investigation and all regulatory agencies have been notified. The have been no injuries, evacuations or road closures associated with the incident.
Ruptured southwestern Minn. pipeline may have been intentionally damaged – A broken pipeline that caused an undetermined amount of diesel fuel to flow into a drainage ditch and the Yellow Medicine River may have been intentionally damaged. The Lyon County Sheriff’s Office said a suspect has been identified for allegedly damaging the pipeline Wednesday night near Cottonwood and causing diesel fuel to leak into downstream waters. The issue has been turned over to the Lyon County Attorney’s Office for consideration of charges. The ruptured pipeline was reported at 8:30 p.m. Wednesday when operators at Magellan Midstream pipeline control center observed a pressure drop associated with their eight-inch refined products pipeline near Cottonwood. Representatives from Magellan Midstream, based in Tulsa, Oklahoma, closed the valves on the system Wednesday night and fuel was found to be leaking from a small hole in the pipeline. The leak was stopped around 10:30 p.m. and crews began working to recover the product. In a news release issued Thursday afternoon, Bruce Heine, media contact with Magellan Midstream, said crews at the scene are focused on containment and recovery operations along the drainage ditch. “We have made significant progress recovering a high percentage of the available diesel fuel in the drainage ditch, which ultimately flows into the Yellow Medicine River,” he said. Heine said, however, that “minor remnants of a petroleum sheen have passed through the containment areas along the drainage ditch into the Yellow Medicine River. We are continuing cleanup operations on the drainage ditch.”
New Colorado Law Requires State to Consider Health Impacts of Oil Drilling – Colorado has passed a law requiring state regulators to prioritize public health and the environment in regulating oil and gas operations, drawing sharp criticism from the fossil fluel industry and praise from a group of young people who had unsuccessfully sued the state trying to force those regulations. Gov. Jared Polis signed the law on Tuesday, requiring the Colorado Oil and Gas Conservation Commission (COGCC) to prioritize protecting public health, the climate and environment in issuing permits for oil and gas operations. The youth-led lawsuit Martinez v. COGCC had sought exactly that, but the Colorado Supreme Court rejected that argument in dismissing the case in January. Since then, Polis, a Democrat who ran on a pro-climate platform, took office and the legislation was quickly passed. As stated in the bill, Section 11 “requires the commission to protect and minimize adverse impacts to public health, safety, and welfare, the environment, and wildlife resources and protect against adverse environmental impacts on any air, water, soil, or biological resource resulting from oil and gas operations.” The law also establishes local governments’ authority to regulate siting of oil and gas development to minimize adverse impacts. The youth lawsuit, which was supported by the legal advocacy nonprofit Our Children’s Trust, was unsuccessful because the Supreme Court said previous regulations were unclear about how to balance public health concerns with the development of resource. The new law addresses this perceived ambiguity, acknowledging that the “[Oil and Gas Conservation] Act has been construed to impose a balancing test between fostering oil and gas development and protecting the public health, safety, and welfare.” But the new law clarifies that instead of a balancing test, the commission must protect public health, welfare and the environment.
EPA, Colorado reach $3.6M settlement with oil and gas company over alleged failure to control toxic emissions from storage tanks – The U.S. Environmental Protection Agency and state health officials have reached a $3.6 million settlement with an oil and gas company that regulators allege has failed to minimize toxic emissions from storage tanks at its operations along Colorado’s Front Range. The EPA and Colorado on Friday filed a lawsuit against HighPoint Operating Corporation and a proposed settlement agreement in U.S. District Court in Denver in which the company agrees to spend $3 million improving pollution controls and pay civil penalties of $550,000 – $220,000 of which would be devoted to project to improve the environment. “We remain committed to reducing the emissions of volatile organic compounds that contribute to high levels of ground-level ozone and so endanger the public health,” Assistant Attorney General Jeffrey Bossert Clark said in a statement from Washington, D.C. The case arose after air pollution inspectors from the Colorado Department of Public Health and Environment equipped with infrared cameras detected the emissions at multiple clusters of storage tanks, according to the lawsuit. The 27-page lawsuit accused HighPoint of failing to control volatile organic compounds (VOCs), precursors of ozone smog, as well as benzene, toluene, xylene and other pollutants identified under the Clean Air Act as hazardous. Storage tanks at more than a dozen sites north of Denver in Adams and Weld counties – including many that HighPoint’s predecessor the Bill Barrett Corporation had certified to the CDPHE as “controlled” – have emitted excessive pollutants since April 2014, according to the lawsuit. RELATED: Colorado’s unannounced air-pollution inspections at oil and gas sites are showing results – yet emissions are up as production increases This happened in a Front Range area where air quality for years has flunked federal air quality health standards, worsening the problem, the EPA and state attorneys said. HighPoint failed to design, run and maintain pollution control systems as required by the state to minimize leakage of the volatile organic and other chemicals to the maximum extent “practicable,” the attorneys said. “HighPoint’s failure to comply with these requirements has resulted in excess VOC emissions, a precursor to ground-level ozone. … HighPoint’s unlawful emissions of VOC into the atmosphere contribute to this exceedance of the ozone NAAQS (National Ambient Air Quality Standards) in this area,” the lawsuit said.
Report: Oil and gas leasing under Trump bleeding into protected habitats – About one-quarter of the Western land offered in auctions to oil and gas companies under the Trump administration so far has been in state-designated priority habitat or migration corridors for big game, according to a review of public lease sales by the Center for American Progress. In Wyoming, 20 percent of leases offered in 2017 and 2018 coincided with protected areas, the reports states. The study used publicly available data to overlap parcels offered in lease sales in the last two years with acres under a number of state protections – from state-designated migration corridors to big-game winter ranges as identified in state action plans written in accordance with a secretarial order from then-Interior Secretary Ryan Zinke last year. Lease sales that overlap with key habitat has become a point of discord between industry development and the environment under President Donald Trump’s “energy dominance” agenda, with persistent disputes over whether more land is going to oil and gas interests as a result of the president’s federal land policy in the West. Environmental groups have pointed out that the amount of acreage leased in recent years is higher than the norm over the last decade and that leasing is happening in some of the best habitat for wildlife. Industry has downplayed the environmentalists’ point of view, arguing that federal policies – like the tighter timelines on public review of environmental analysis implemented under Trump – have helped streamline the process of development on federally managed lands. There is not a sudden or overwhelming drilling presence on public land to the detriment of other concerns, they argue. Since 2017, the administration has sold 4,500 leases in the West. In 2018, the administration leased 450 percent more acres to industry than it had in 2016, according to the report. The leasing story across the West hasn’t been uniform. In New Mexico, lease sales offering part of the Permian for oil and gas development helped drive a record $1 billion sale in September. That same month in Nevada a BLM auction of 300,000 acres sold nothing. Industry had proposed the land for sale, but none bid on it.
Produced water spill near Tioga – Nearly 400 barrels of produced water spilled near Tioga on Saturday, April 20, according to the North Dakota Department of Health. The spill happened because of a mechanical failure at a salt water disposal site owned by Hess Bakken Investments II LLC about 8 miles south of Tioga. The initial estimate is that 390 barrels of saltwater spilled, and an agricultural field was affected, according to a news release. The spill was reported on Sunday and personnel from the Health Department are inspecting the site and will continue to monitor the investigation and remediation. Produced water is a byproduct of oil and gas production.
Officials discuss parameters of North Dakota oil study (AP) – A federal estimate of recoverable oil in North Dakota and the surrounding area needs to factor in more geologic formations and rapidly advancing technology, state and energy industry officials said Wednesday. The U.S. Geological Survey has begun updating its estimate of recoverable oil and gas resources in the Williston Basin in North Dakota, eastern Montana and northwestern South Dakota. It expects to wrap up the effort by the end of the year, Energy Resource Program Coordinator Walter Guidroz said during a meeting with the officials to map out the best strategy for compiling the new estimate. The USGS in 2013 estimated 7.4 billion barrels of oil could be recovered from the basin’s Bakken and underlying Three Forks shale formations, which encompass about 25,000 square miles within the Williston Basin. However, there are 17 other, smaller geologic formations that also show “significant” potential with new drilling and hydraulic fracturing technology, according to state Mineral Resources Director Lynn Helms. Five have already been studied by state officials. “They’ve identified maybe a billion barrels of oil potential,” Helms said. North Dakota is already the nation’s second-leading producer of crude behind Texas, accounting for about 12 percent of U.S. production. The state saw record production in January of 1.4 million barrels daily. Almost all of that came from the Bakken and Three Forks, where technology advancements are enabling companies to extract more oil “than we ever thought possible,” Continental Resources Geologic Manager Tony Moss said. “We’ve completely replaced our top 10 (producing) wells within about the last year and a half,” he said. “We’re really just getting to the point where we feel like we’re really starting to optimize development.” Continental estimates as much as 40 billion barrels of recoverable oil from the Bakken and Three Forks alone.
Dakota Access Company Bought Up Dozens Of Anti-Pipeline URLs — Texas-based pipeline giant Energy Transfer Partners went on a website-buying spree after months of fierce public protest over its Dakota Access Pipeline, nabbing dozens of URLs it expected pipeline opponents might use to target the company’s other projects. The damage-control effort is related to several ongoing operations, including the company’s $4.2 billion Rover natural gas pipeline in Ohio, the $670 million Bayou Bridge Pipeline in Louisiana, and the Trans-Pecos and Comanche Trail pipelines in West Texas. Energy Transfer Partners purchased at least 102 anti-pipeline websites between January and June 2017, according to a list compiled by the nonprofit Climate Investigations Center and shared with HuffPost. Those domain names, purchased mostly through web hosting company GoDaddy, include addresses like “energytransfer.sucks,” “stopetppipelines.net,” “antiroverpipelinealliance.org,” “bayoubridgeresistance.com,” “gulfresidentsagainstbayoubridgepipeline.org,” “nocomanchetrailpipeline.org” and “nowahatranspecospipeline.org.” When a company buys the .sucks website for their own name, you know they have problems.Kert Davies, director of the Climate Investigations CenterEnergy Transfer Partners spokeswoman Alexis Daniel told HuffPost this website buying is “standard brand management practice for our company before we begin any major project in order to protect the brand of the project.”“During the time we had multiple projects under construction or beginning construction, all of which have been successfully completed and are operating today,” Daniel said in an email. She did not respond to questions about whether the effort was motivated by protests on the Standing Rock Indian Reservation in North Dakota or for how long the company plans to hold on to the sites. Kert Davies, director of the Climate Investigations Center, called the company “paranoia incorporated.” “Every one of ETPs recent pipeline projects has created major scandal and controversy across the country – from North Dakota to Pennsylvania to Louisiana,” Davies told HuffPost via email. “This preemptive GoDaddy website effort shows that ETP is pretty self conscious and paranoid about their social license. When a company buys the .sucks website for their own name, you know they have problems.”
Will Newsom end oil drilling in California? Many environmentalists are betting yes – California’s legacy of oil drilling should be just that, many environmentalists argue – relegated to the history books. They are urging Gov. Gavin Newsom to ban new oil and gas drilling in California and completely phase out fossil fuel extraction in one of the nation’s top petroleum-producing – and gasoline-consuming – states. At the least, they want the state to impose buffer zones prohibiting new oil and gas wells near schools, hospitals and residential neighborhoods and also require monitoring for potentially hazardous emissions from abandoned or plugged wells, proposals already being considered by state lawmakers. “It sure would make us happy if he made a big splash about this. It’s month four. People are being very patient. By month six, patience may wear thin,” said Sierra Club California Director Kathryn Phillips. Phillips said her organization and other groups that support curtailing oil production in California have met informally with Newsom administration officials. While Newsom has not made any promises, expectations remain high, she said. Newsom, who served on the state lands commission for eight years, says he’s well versed in the issues surrounding on-shore and off-shore oil drilling in California and said he would announce his administration’s detailed strategy on energy policy in the next few weeks. The governor was coy about core aspects of that policy, and declined to say if it would ban the controversial practice of hydraulic fracking, a process that uses drilling and large volumes of high-pressure water to extract gas and oil deposits. “I’m taking a very pragmatic look at it, in scoping this,” Newsom told The Times last week. “It’s also an inclusive scoping because it includes people in the industry, that have jobs; communities that are impacted from an environmental justice prism but also from an economic justice prism. It’s a challenging issue. There’s a reason Gov. Brown used a lot of dexterity on this issue.”
Trump fracking plan targets over 1 million acres in California – LA Times – The Trump administration on Thursday detailed its plan to open more than a million acres of public and private land in California to fracking, raising environmental concerns at a time when opposition to oil and gas drilling in the state is intensifying. The action would end a five-year moratorium on leasing federal land in California to oil and gas developers. That pause came after a federal judge ordered the Obama administration to halt similar leasing efforts until it could better evaluate the environmental risks of hydraulic fracturing, also known as fracking. Trump’s plan – first proposed by the administration in 2018 – targets public and private land spread across eight counties in Central California: eastern Fresno, western Kern, Kings, Madera, San Luis Obispo, Santa Barbara, Tulare and Ventura. The move drew immediate criticism from environmentalists, who said it would pose health risks and worsen air quality in a part of the state notorious for pollution. “The Central Valley has some of the worst air quality in the nation, and we know fracking and drilling make air quality worse,” said Clare Lakewood, a senior attorney at the Center for Biological Diversity, an environmental advocacy group. Lakewood said Trump’s plan would unleash a “fracking frenzy” that would endanger people and wildlife alike. Once a plan is finalized and approved, environmental groups are expected to sue to block it, as they have in the past. Proposed by the Bureau of Land Management, the plan is only the latest in a series of attempts by the federal government to open public land in Central California to fracking. In 2013, a federal judge ruled that the government had violated the National Environmental Policy Act when it issued oil leases in Monterey County without analyzing the environmental dangers of fracking. Three years later, another federal judge reached a similar conclusion.
In letter, Alaska governor asks Trump for help on oil, mining and other issues – In a letter to President Donald Trump last month, Alaska Gov. Mike Dunleavy seeks fewer federal restrictions and changes he says will boost the state’s economy and efforts to mine, drill and sell timber. The governor also lays out concerns about Alaska’s relationship with the federal government, asserting that U.S. Fish and Wildlife Service “career employees” are sabotaging the goal that both leaders share of drilling in the Arctic National Wildlife Refuge. The March 1 correspondence, highlighting matters of “great importance to Alaskans,” suggests the state and federal government work together to achieve “economic growth and energy dominance.” The letter was obtained by the Daily News through a public-records request. One request – that Trump help Alaska become the first state to receive Medicaid dollars as a block grant – made headlines earlier this month as advocacy groups in Alaska criticized the idea. “We continue to work with the Trump administration on a long list of priorities, including those identified” in the letter, he said in a prepared statement. In the letter, the governor suggests the Environmental Protection Agency should “officially announce” that it will not use a pre-emptive veto under the Clean Water Act to stop any proposed development in Alaska. The EPA has been blamed for wielding that authority in 2014 to hobble the Pebble copper and gold prospect in the Bristol Bay region. “The Pebble Mine Project is the poster child, but every potential investor must evaluate whether that pre-emptive veto could be used against their project; which results in a serious brake that chill(s) potential resource development opportunities,” Dunleavy wrote.
Polar opposites: the remote Alaskan village divided over oil drilling – Reuters – In 1968, the largest proven oil reserve in U.S. history was discovered about 175 km (110 miles) west of Kaktovik in Prudhoe Bay on Alaska’s North Slope. With the completion of the Trans Alaska Pipeline in 1977, the region became a key energy source. In 1971, the U.S. government passed the Alaska Native Claims Settlement Act, which paid nearly $1 billion at that time to Native Alaskans and transferred about 44 million acres of public land to indigenous-controlled corporations. With the Kaktovik Inupiaq Corporation, the two indigenous companies own 92,000 acres of surface and subsurface rights in ANWR which contains some of North America’s wildest territory. Within the refuge borders, there are no roads, established trails, or buildings of any type, and no cell phone service, according to the Fish and Wildlife Service. “This is a true wilderness refuge,” the Arctic park’s website states. In the 1980s oil major Chevron drilled the only exploratory well in ANWR, the most significant step toward petroleum development in a decades-long debate about whether oil could be drilled safely in the refuge, without affecting wildlife. That debate took a new turn in December 2017 when Congress passed a tax-overhaul bill with a provision mandating two oil lease sales in the 1002 area, each offering at least 400,000 acres, within seven years. Environmental and Native groups criticized the Department of the Interior (DoI) for moving too swiftly on readying a lease sale for later this year, saying more time was needed to consult with tribes and other locals. Last December, the U.S. Army Corps of Engineers released a draft environmental impact statement outlining four possible scenarios for oil drilling. In February, the DoI’s Bureau of Land Management held public meetings in several Alaskan cities and villages, including Kaktovik, as well as in Washington, D.C., the nation’s capital. Both steps are part of the standard procedure to move ahead with selling an oil lease, said Kara Moriarty, president of the Alaska Oil and Gas Association, furthering her hopes that drilling will proceed under the Trump administration. “According to the schedule released by the Department of Interior, they plan to issue a final environmental impact statement later this summer or early fall,”
US total oil, natural gas rig count falls 10 on week to 1066 – The combined US oil and natural gas rig count fell by 10 to 1,066 this week, S&P Global Platts Analytics data showed Thursday. The decline pushed the total number of active rigs to the lowest level seen since January 2018, and down 13.5% from the recent high of 1,233 in mid-November. The number of active oil rigs fell by eight to 846, a 14-month low, while the active gas rig count dipped by three to 215. The addition of a single cyclic steam rig pared the overall decline. The Permian Basin led the decline, falling by seven to its early March level of 462. The number of active rigs in the Eagle Ford play dipped by two to 84, a 15-month low, and drillers in the Denver-Julesburg Basin idled three rigs, taking the total number active there down to 28. The Bakken Shale rig count ticked one higher to 60, continuing a rangebound trend there that has held for most of 2019. While overall rig counts have steadily declined since last fall, Permian counts have stabilized in the 460-470 range in recent weeks. Active rigs have held in this range even as discounts for Permian crude have widened. WTI at Midland, Texas has fallen to as much of a $5.50/b discount to WTI at Cushing, Oklahoma in the back half of April. WTI Midland was priced at a premium to Cushing briefly in early March. The Marcellus Shale play rig count fell by two to 62, while operators in the Utica Shale play added four rigs for a total of 15. In the SCOOP-STACK, the rig count edged down by three to 83, the lowest since February 2017. The number of active drilling rig permits was broadly stable week on week, with the total count edging up by 13 to 1,269. But counts were significantly more volatile at the basin level. The number of active Denver-Julesburg permits plunged 165 to 83 this week while Bakken and Permian basin permits fell by 26 and 25 to 6 and 162, respectively. Eagle Ford permits were up 22 at 49 and Marcellus permits climbed by 24 for a total of 51.
US Crude Oil Inventories Up A Whopping 5.5 Million Bbls — April 24, 2019 – EIA weekly petroleum report, link here. API reported a whopping increase of almost 8 million bbls of crude oil in its report yesterday.
- US crude oil inventories: increased by a whopping 5.5 million bbls
- US crude oil inventories: total inventories now stand at 460.6 million bbls; at the 5-year average, but the average has been increasing ever since the Saudi surge, 2014 – 2016;
- refineries: operating at 90.1% capacity; much better than previous few weeks, but still very, very low;
- but look at this: imports increased by 1,157,000 bopd from the previous week
- imports now average 6.6 million bopd, almost 20% less than the same four-week period last year, so the increase had to occur sooner or later, I suppose
North American drilling boom threatens big blow to climate efforts, study finds – More than half of the world’s new oil and gas pipelines are located in North America, with a boom in US oil and gas drilling set to deliver a major blow to efforts to slow climate change, a new report has found. Of a total 302 pipelines in some stage of development around the world, 51% are in North America, according to Global Energy Monitor, which tracks fossil fuel activity. A total of $232.5bn in capital spending has been funneled into these North American pipeline projects, with more than $1tn committed towards all oil and gas infrastructure. If built, these projects would increase the global number of pipelines by nearly a third and mark out a path of several decades of substantial oil and gas use. In the US alone, the natural-gas output enabled by the pipelines would result in an additional 559m tons of planet-warming carbon dioxide each year by 2040, above 2017 levels, according to Global Energy Monitor, citing International Energy Agency figures. This surge in emissions is set to take place at a time when scientists havewarned of punishing heatwaves,floods and economic damage ifgreenhouse gases are not drastically cut. A landmark UN report released last year warned that global emissions must be halved by 2030 and essentially nullified by 2050 to avoid the worst impacts of climate change. “This is a whole energy system not compatible with global climate survival,” said Ted Nace, co-author of the Global Energy Monitor report. “These pipelines are locking in huge emissions for 40 to 50 years at a time, with the scientists saying we have to move in 10 years. These pipelines are a bet that the world won’t get serious about climate change, allowing the incumbency of oil and gas to strengthen.” New gas pipelines outnumber oil pipelines by about four to one, bolstered by a glut of abundant natural gas that is swiftly replacing coal as the leading electricity source for US homes and businesses. The most active area for pipelines is the Permian basin in west Texas, a sprawling formation that contains huge deposits of oil and gas. Other active zones include the shale formations in Pennsylvania, Ohio and West Virginia, and the Canadian tar sands of Alberta. Several of these pipeline projects have spurred bitter protests from climate andindigenous activists, such as the Dakota Access project, which resulted inviolent clashes at the Standing Rock reservation in North Dakota. The extension to the Keystone pipeline, which would link the Alberta tar sands to refineries on the Gulf of Mexico, has also aroused opposition that Donald Trump has vowed to sweep aside by pushing the project forward.
Exxon Mobil’s quarterly profits tumble on poor refining and chemicals results – Exxon Mobil reported on Friday that its first-quarter profits fell nearly 50% from a year ago, hit by poor results in its refining and chemicals segments. Shares of the oil giant were down more than 2% on Friday. Exxon reported a quarterly loss in its downstream business, which focuses on refining oil into fuels like gasoline and diesel. The company said brimming stockpiles of gasoline led to weak fuel margins during the quarter. It also continued a heavy slate of refinery maintenance. That maintenance has weighed on downstream profits in recent quarters, and Exxon warned analysts on Friday that it will continue in the second quarter of 2019. Profits in the chemicals business also tumbled $219 million from a year ago. While Exxon sold more chemicals, profit margins came under pressure because the industry has recently added capacity. The oil major’s output of crude, natural gas and other fossil fuels reached 4 million barrels of oil equivalent, up 2% from last year. Still, income in the upstream exploration and production unit fell by $621 million from last year. While crude oil prices strengthened, they still remained relatively weak, Exxon said. “Solid operating performance in the first quarter helped mitigate the impact of challenging Downstream and Chemical margin environments,” Exxon Chairman and CEO Darren Woods said in a statement.
Lower hydraulic fracturing prices continue to sting Halliburton in first quarter – Lower prices for hydraulic fracturing services in North America continue to sting Houston-based Halliburton, the second largest oilfield service company in the world. Halliburton posted a $152 million profit and earnings per share of 17 cents on $5.7 billion of revenue during the first quarter, the company reported early Monday morning. The company’s first quarter earnings fell in line with Wall Street expectations of earnings per share of 22 cents and beat expectations of $5.52 billion of revenue First quarter figures also marked a dramatic improvement over the $46 million profit and earnings per share of 5 cents on $5.7 billion of revenue during the first quarter of 2018. With 58 percent of its revenue coming from onshore activities in the United States, Halliburton has high risk exposure to fluctuations in demand for horizontal drilling and hydraulic fracturing services in U.S. shale basins. Crude oil prices fell dramatically during the fourth quarter of 2018 sending demand and prices for hydraulic fracturing services falling through most of the first quarter. Halliburton CEO Jeff Miller believes that the worst pricing declines are over. Earlier this year, Miller predicted that new pipelines coming into service in the Permian Basin of West Texas during the second half of this year would eventually result in higher demand and prices for drilling and completion activities. “As expected, the first quarter activity levels in North America were modestly higher compared to the first quarter of 2018, and we experienced pricing headwinds throughout the quarter,” Miller said. “We believe the worst in the pricing deterioration is now behind us. For the next couple of quarters, I see demand for our services progressing modestly.”
Occidental Petroleum bids $76 a share for Anadarko, trumping Chevron offer for the oil and gas driller – Occidental Petroleum bid $76 a share for Anadarko Petroleum on Wednesday, higher than a previous offer by Chevron for the oil and gas driller.The new Occidental offer, which was sent via a letter to Anadarko’s board on Wednesday, is half cash and half stock, specifically $38 in cash and 0.6094 Occidental shares. It values Anadarko at $57 billion, including debt. Chevron announced an agreement on April 12 to buy Anadarko for $33 billion in cash and stock, valuing the company at $65 a share. CNBC later reported there was another bidder for Anadarko, Occidental, which was offering mid-$70s per share before Chevron stepped in with its offer.After the new Occidental bid, Anadarko shares surged 10% in Wednesday’s premarket trading, to above $70.The Chevron offer is a 75% stock and 25% cash transaction. The breakup fee for the Chevron-Anadarko deal is said to be 3% of the deal, sources said.“Anadarko has great assets,” Occidental CEO Vicki Hollub said in a interview on CNBC’s “Squawk Box ” on Wednesday. “We are the right acquirer … because we can get the most out of the shale.”Hollub said she considers this a friendly offer, even though Anadarko may not see it that way. The offer is 20% above where Anadarko was trading on Tuesday. Occidental shares fell more than 7 percent in Wednesday’s premarket. Chevron, whose stock was flat, did not immediately return a call for comment.
Occidental CEO says she will prevail in bidding war for sought-after oil driller Anadarko. – Occidental Petroleum CEO Vicki Hollub said Wednesday her company can squeeze the best results out of Anadarko Petroleum’s wells in the top U.S. shale basin, making Occidental a better acquirer than Chevron. Earlier Wednesday, Occidental launched a rival bid for Anadarko, which agreed to sell its business to Chevron in a deal valued at $33 billion earlier this month. Occidental is offering $76 a share for Anadarko, representing a roughly 20% premium to Chevron’s $65-per-share offer. Hollub says 75 percent of Anadarko’s value lies in its assets in the Permian Basin, the shale oil region underlying western Texas and eastern New Mexico. The Permian is the epicenter of a boom in U.S. oil production. “We are the right acquirer for Anadarko Petroleum because we can get the most out of the shale,” Hollub told David Faber on CNBC’s “Squawk Box.” “We have a lot more experience there. We are performing really, really well, and what hasn’t been talked about very much is that the upside in this deal is the shale play, is the shale development.” Shares of Occidental fell about half a percent on Wednesday, while Chevron’s stock price slumped 3.1%. Meanwhile, Anadarko shares surged 11.6% for the biggest daily gain in the S&P 500 stock index. Anadarko confirmed on Wednesday that it had received Occidental’s unsolicited bid. The company said its board will carefully review the proposal to determine the best course of action for shareholders. “The Anadarko board has not made any determination as to whether Occidental’s proposal constitutes, or could reasonably be expected to result in, a superior proposal under the terms of the Chevron Merger Agreement,” the Company said in a statement. Chevron is also pitching itself as an ideal steward of Anadarko’s Permian assets. The oil major says the deal stitches together a 75-mile-wide strip of continuous land in the Delaware Basin, a sweet spot within the larger Permian. That allows Chevron to bring efficient, industrial-scale production to the shale field, the company says. “We are confident the transaction agreed to by Chevron and Anadarko will be completed,” said Kent Robertson, manager for global external affairs for Chevron.
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