Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 28 July 2019.
This article is a feature every Monday evening on GEI.
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Natural gas prices testing a 3 year low; natural gas drilling activity at a 20 month low
Oil prices eked out a small increase this past week, as ongoing oil tanker trouble in the Persian Gulf and a large US inventory withdrawal outweighed the impact of falling demand from a global economic slowdown… after falling 7% to $55.63 a barrel last week as Gulf of Mexico production returned and tensions between the US & Iran and the US showed signs of easing, prices of US crude for August delivery rose on Monday on concerns that Iran’s reciprocal seizure of a British tanker could lead to further supply disruptions in the Gulf, with trading in the August oil contract expiring 53 cents higher at $56.22 a barrel, while at the same time the more-active September WTI oil contract price rose 46 cents to end the session at $56.22 a barrel…after opening lower, oil prices continued higher on Tuesday, as expectations of lower U.S. crude supplies were only partially offset by weaker demand forecasts and the full restart of Libya’s largest oil field, with the price of September oil ending 55 cents higher at $56.77 a barrel…oil prices spiked higher early Wednesday on the the American Petroleum Institute report of the largest oil inventory draw so far this year and extended those gains when the EIA confirmed the big crude draw and also reported lower crude production, with oil rising to as high as $57.64 a barrel before traders turned their attention back to concerns about weaker energy demand and quickly pushed oil prices more than 4% lower, before they recovered a bit to close down 89 cents at $55.88 a barrel…oil prices recovered a bit on on Thursday amid ongoing Middle East tensions, but a manufacturing slowdown indicated by purchasing managers reports from Europe & the US capped the gains and US crude finished up just 14 cents, or 0.3%, at $56.02 a barrel…oil prices continued modestly higher on Friday after a stronger-than-expected U.S. GDP report and concerns over the safety of Persian Gulf oil transport, and finished the session up 18 cents at $56.20 a barrel, with September oil thus ending the week with a gain of just under 1%..
Natural gas prices, on the other hand, again trended lower, and ended the week just a fraction above the multi-year low seen in June…after falling more than 8% to $2.251 per mmBTU on the recovery of Gulf production last week, prices of natural gas for August delivery moved up 6.1 cents on Monday and closed with their first increase in 6 sessions, as forecasts indicated above normal temperatures would become more widespread at the end of July and to start August…prices then slipped 1.2 cents on notably lower trading volume on Tuesday, and then fell 8 cent on Wednesday as traders positioned against a possible bearish storage report…when the storage report came in line with expectations, natural gas prices recovered 2.4 cents on Thursday, but they sold off again on Friday on a forecast of cooler weather and a dip in demand in the 11-15 day time frame and ended down 7.5 cents on the day at $2.169 per mmBTU, just a penny higher than the lowest front month quote of the last three years, and only three-tenths of a cent above the June 20th lowest closing quote for this August contract..
The natural gas storage report for the week ending July 19th from the EIA indicated that the quantity of natural gas held in storage in the US increased by 36 billion cubic feet to 2,569 billion cubic feet by the end of the week, which meant our gas supplies were 300 billion cubic feet, or 13.2% greater than the 2,269 billion cubic feet that were in storage on July 19th of last year, while still 151 billion cubic feet, or 5.6% below the five-year average of 2,720 billion cubic feet of natural gas that have been in storage as of the 19th of July in recent years….this week’s 36 billion cubic feet injection into US natural gas storage was in line with the consensus market expectation, but it was lower than the average 44 billion cubic feet of natural gas that have been added to gas storage during the third week of July in recent years, the second straight below average storage build, following 17 weeks of above seasonal stock changes…. nonetheless, the 1,391 billion cubic feet of natural gas that have been added to storage over the past 17 weeks has still been the largest injection of gas into storage on record for any prior similar period of the gas injection season…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending July 19th, indicated that a jump in our oil exports and a drop in our crude oil production resulted in the the 9th withdrawal withdrawal of crude from our supplies in 17 weeks, in a week where the effects of tropical storm Barry on the oil data are still quite evident…our imports of crude oil rose by an average of 194,000 barrels per day to an average of 7,028,000 barrels per day, after falling by an average of 470,000 barrels per day over the prior week, while our exports of crude oil rose by an average of 758,000 barrels per day to 3,292,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,736,000 barrels of per day during the week ending July 19th, 562,000 fewer barrels per day than the net of our imports minus exports during the prior week…over the same period, storm impacted production of crude oil from US wells was reported to be 700,000 barrels per day lower at 11,300,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from well production totaled an average of 15,036,000 barrels per day during this reporting week..
Meanwhile, US oil refineries were reportedly using 17,034,000 barrels of crude per day during the week ending July 19th, 233,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA reported that a net of 1,548,000 barrels of oil per day were being withdrawn from the supplies of oil stored in the US….hence, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 450,000 barrels per day short of what our oil refineries reported they used during the week…to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (+450,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”….(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 7,187,000 barrels per day last week, which was still 13.7% less than the 8,331,000 barrel per day average that we were importing over the same four-week period last year…the 1,548,000 barrel per day decrease in our total crude inventories was all pulled out of our commercially available stocks of crude oil, while the amount of oil stored in our Strategic Petroleum Reserve remained unchanged…this week’s crude oil production was reported to be 700,000 barrels per day lower at 11,300,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 700,000 barrels per day lower at 10,800,000 barrels per day, largely due to shut-in wells in the Gulf of Mexico, while a 4,000 barrels per day increase to 459,000 barrels per day in Alaska’s oil production was not enough to impact the final rounded national production total…last year’s US crude oil production for the week ending July 20th was rounded to 11,000,000 barrels per day, so this reporting week’s rounded oil production figure was still 2.7% above that of a year ago, and 34.1% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
US oil refineries were operating at 93,1% of their capacity in using 17,034,000 barrels of crude per day during the week ending July 19th, down from 94.4% of capacity the prior week, a drop that can largely be attributed to hurricane Barry….the 17,034,000 barrels per day of oil that were refined this week were almost 1.5% below the 17,285,000 barrels of crude per day that were being processed during the week ending July 20th, 2018, when US refineries were operating at 93.8% of capacity….
Even with the decrease in the amount of oil being refined, gasoline output from our refineries was still higher, increasing by 234,000 barrels per day to 10,089,000 barrels per day during the week ending July 19th, after our refineries’ gasoline output had decreased by 563,000 barrels per day the prior week….but even with that increase in gasoline output, this week’s gasoline production was still 1.6% less than the 10,255,000 barrels of gasoline that were being produced daily during the same week last year….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 142,000 barrels per day to 5,219,000 barrels per day, after our distillates output had increased by 3,000 barrels per day the prior week….but even after that decrease, the week’s distillates production was 1.2% more than the 5,157,000 barrels of distillates per day that were being produced during the week ending July 20th, 2018….
Despite the increase in gasoline production, our supply of gasoline in storage at the end of the week still fell for the fifth time in 6 weeks and for the 17th time in twenty-two weeks, slipping by 226,000 barrels to 232,526,000 barrels over the week to July 19th, after our gasoline supplies had jumped by 3,565,000 barrels over the prior week….our gasoline supplies decreased this week because the amount of gasoline supplied to US markets increased by 459,000 barrels per day to 9,673,000 barrels per day, while our exports of gasoline fell by 59,000 barrels per day to 558,000 barrels per day, and while our imports of gasoline rose by 133,000 barrels per day to 985,000 barrels per day…after our gasoline supplies had reached an all time record high twenty-four weeks ago, they then fell by nearly 13% over 10 weeks while US Gulf Coast refineries were crippled by the Venezuelan sanctions, and as a result they are still fractionally lower than last July 20th’s inventory level of 233,504,000 barrels, while just 2% above the five year average of our gasoline supplies at this time of the year…
Even with the decrease in our distillates production, our supplies of distillate fuels rose for the 8th time in the past 19 weeks, increasing by 613,000 barrels to 136,816,000 barrels during the week ending July 19th, after our distillates supplies had increased by 5,686,000 barrels over the prior week…the increase in our distillates supplies was smaller this week because the amount of distillates supplied to US markets, a proxy for our domestic demand, increased by 699,000 barrels per day to 4,264,000 barrels per day, while our exports of distillates fell by 144,000 barrels per day to 972,000 barrels per day and while our imports of distillates fell by 27,000 barrels per day to 105,000 barrels per day….after this week’s inventory increase, our distillate supplies were 12.9% higher than the 121,210,000 barrels of distillates that we had stored on July 20th, 2018, and returned to near the five year average of distillates stocks for this time of the year…
Finally, with our oil exports rising while our oil production was interrupted by tropical storm Barry, our commercial supplies of crude oil in storage fell for a sixth week in a row and for the twelfth time in 27 weeks, decreasing by 10,835,000 barrels, from 455,876,000 barrels on July 12th to 445,041,000 barrels on July 19th …but even with that big decrease, our crude oil inventories remained roughly 2% above the recent five-year average of crude oil supplies for this time of year, and roughly 33% higher than the prior 5 year (2009 – 2013) average of crude oil stocks for the 3rd week of July, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels…since our crude oil inventories had generally been rising since this past Fall until the recent 6 weeks, after generally falling until then through most of the prior year and a half, our oil supplies as of July 19th were still 9.9% above the 404,937,000 barrels of oil we had stored on July 20th of 2018, but at the same time were 7.9% below the 483,415,000 barrels of oil that we had in storage on July 21st of 2017, and 9.3% below the 490,501,000 barrels of oil we had stored on July 22nd of 2016…
This Week’s Rig Count
The US rig count fell for the 20th time in 23 weeks during the week ending July 26th, and is now down by nearly 13% for this year so far….Baker Hughes reported that the total count of rotary rigs running in the US fell by 8 rigs to a new 17 month low of 946 rigs this past week, down by 102 rigs from the 1048 rigs that were in use as of the July 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…
The count of rigs drilling for oil fell by 3 rigs to 776 rigs this week, which was also a 17 month low for oil rigs, 85 fewer than were running a year ago, and less than half of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014…at the same time, the number of drilling rigs targeting natural gas bearing formations decreased by 5 rigs to 169 natural gas rigs, which was a twenty month low for natural gas rigs, down by 17 rigs from the 186 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 rigs targeting natural gas that were deployed on August 29th, 2008…in addition, a rig classified as miscellaneous continued to drill this week, matching the “miscellaneous” rig count of a year ago…
The rig count in the Gulf of Mexico was down by 2 to 23 rigs this week, as two rigs that had been drilling off the coast of Louisiana were shut down…that still left 22 rigs drilling offshore from Louisiana and a single rig deployed offshore from Texas, an increase of 8 rigs from the 15 rigs that were deployed in the Gulf of Mexico in the same week a year ago, when 13 rigs were drilling in Louisiana waters and two were deployed offshore from Texas…however, another rig started drilling off the coast of Alaska this week, where there are now two rigs deployed, up from the one rig drilling off the Alaskan shore a year ago…hence, the total US offshore rig count is now at 25, an increase of 9 offshore rigs from a year ago..
However, both of the rigs that had been drilling through inland bodies of water in southern Louisiana were shut down this week, leaving no such inland waters rigs active in the US this week, the first time in my memory that the US inland waters rig count has gone to zero; a year ago, there were two such inland waters rigs deployed..
The count of active horizontal drilling rigs was down by 6 to 823 horizontal rigs this week, which was the least horizontal rigs deployed since February 2nd, 2018 and hence also a new 17 month low for horizontal drilling…it was also 99 fewer horizontal rigs than the 922 horizontal rigs that were in use in the US on July 27th of last year, and also well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…at the same time, the directional rig count was down by 2 rigs to 67 directional rigs this week, but those were up from the 64 directional rigs that were operating during the same week of last year… meanwhile, vertical rig count was unchanged at 56 vertical rigs this week, but that was down by 6 from the 62 vertical rigs that were in use on July 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 July 26th, the second column shows the change in the number of working rigs between last week’s count (July 19th) and this week’s (July 26th) count, the third column shows last week’s July 19th 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 July, 2018…
In contrast to the recent weeks where most of the variances have been in the Texas Permian, there were quite a few unusual changes elsewhere this week…as you can see, the entirety of this week’s national rig count drop could be accounted for by the 8 oil rigs that were pulled out of the Bakken shale in North Dakota’s Williston basin, the largest such drop in the Bakken since February 2015…in addition, we’ve already accounted for the 4 rig decrease shown for Louisiana, with the 2 offshore and 2 inland waters rigs from that state that were shut down…on the other hand, Wyoming saw an addition of 4 rigs, including 1 in the Denver-Julesburg Niobrara chalk and three in other basins not shown above, the largest jump in the Wyoming rig count yet this year….also note that the Permian basin saw a three rig increase while the Texas rig count showed no change; that was as one rig was pulled out of Texas Oil District 8, or the core Permian Delaware, while single rigs were started up in Texas Oil District 7C, or the southern Permian Midland basin, and in Texas Oil District 8A, or the northern part of the Permian Midland…hence, that means the other two Permian rigs were added in New Mexico, in the western Permian Delaware…
For rigs targeting natural gas, two rigs were shut down in Ohio’s Utica shale, two were shut down in the West Virginia Marcellus, and two were shut down in basins not itemized separately by Baker Hughes, while a natural gas rig was started up in Oklahoma’s Arkoma Woodford…you might note that West Virginia’s rig count is only down by 1; that’s because a conventional rig began drilling in Monroe county, W Va, targeting natural gas at a depth of less than 5,000 feet; across most of West Virginia, the Marcellus lies more than 15,000 feet below the surface..
Also note that in addition to the changes in the major producing states shown above, the only rig that had been drilling in Alabama was also shut down this week, the first time since April that Alabama has had no drilling activity, and down from 1 rig a year ago; at the same time, a sixth rig began drilling in Mississippi this week, the first time this year that Mississippi had that many rigs deployed; a year ago, there were three rigs drilling in Mississippi…
In America’s Shale Country, Nukes and Gas Are Duking It Out – Subsidizing nuclear power to fight climate change is one thing in liberal states like New York and New Jersey. It’s quite another in the natural gas bastions of Pennsylvania and Ohio. Drillers and gas-fired power plant operators are girding to fight measures to save money-losing reactors in the Keystone and Buckeye states, saying they’ve learned from past defeats and are better positioned to win.The looming debates are a key test of how far lawmakers in shale gas country are willing to go to fight climate change. Four left-leaning states have already approved bailouts for reactors, in step with aggressive targets to replace coal and gas with clean energy. This time fossil-fuel proponents are fighting on their home turf.“Natural gas is very, very strong” in Pennsylvania, said state Sen. Ryan Aument, who supports subsidizing reactors. “Those interests are well represented.” In Pennsylvania, a Republican lawmaker introduced a bill Monday to support the state’s five plants, owned by Exelon Corp., FirstEnergy Solutions and Riverstone Holdings LLC’s Talen Energy Corp. Ohio legislators are preparing their own measure. Time is critical for nuclear plants. Reactors are struggling to stay solvent as the fracking boom has made gas cheap and abundant, pushing down wholesale electricity prices. At least six have closed since 2013, including in New Jersey and Vermont. FirstEnergy Solutions said it will close its Davis-Besse and Perry nuclear plants in Ohio without subsidies. Exelon needs to order a new reactor core by May for its Three Mile Island plant — site of the infamous 1979 meltdown — making it crucial for lawmakers to pass legislation this spring, Chief Executive Officer Chris Crane said on call with analysts last month. “If we can get this through in that period of time, we will be able to save the unit,” Crane said.
Two Well Permits Awarded in Columbiana County – – Hilcorp Energy Co. has secured two new permits for horizontal wells in Columbiana County, according to the most recent data posted by the Ohio Department of Natural Resources. Both wells are targeted for Elk Run Township on the Johnston pad, and are the first permits awarded in Columbiana County since August 2018, according to records. No new well permits were reported for Mahoning or Trumbull counties in the northern tier of the Utica. Nor were there new permits issued in nearby Lawrence or Mercer counties in the northern Utica’s western Pennsylvania footprint, according to the Pennsylvania Department of Environmental Protection. ODNR issued a total of 15 permits for the week ended Feb. 9, the agency reported. Aside from Hilcorp’s two Columbiana County wells, Ascent Resources LLC secured six new permits – two for wells in Belmont County, three for wells slated for Guernsey County, and a single permit for a well in Harrison County. Equinor USA Onshore Properties Inc. was awarded four permits for wells in Monroe County, while Chesapeake Exploration LLC secured three permits to drill wells in Harrison County. To date, ODNR has issued 3,000 permits to oil and gas companies that use horizontal drilling methods to explore the Utica/Point Pleasant shale formation in Ohio. These companies have so far drilled 2,531 wells in the shale play, while 2,141 of these wells are in production. The majority of wells drilled are located in the southeastern portion of the state, where higher geological pressure in the shale allows for more production. ODNR reported that there were 14 rigs in operation during the week.
Fracking in Ohio: Amid industry activity, residents start their own shale gas-related health registry -A dozen people are scurrying around a church basement in Youngstown, Ohio. They’re arranging tables and chairs, setting up paperwork, and hanging up signs that read, “Ohio Health Registry.” “The Ohio Health Registry is really an attempt to collect the contacts of people who live close enough to any aspect of shale development, that they might be affected,” said Dr. Deborah Cowden, a family physician from the Dayton area, who started the effort.Cowden drove three and a half hours east this morning to organize the registration, while others came in from Oberlin, Cleveland and Lake County to register people in Youngstown.“This is the medical questionnaire, and I’m going to read some instructions,” a registrar tells one person who has shown up to fill out the forms, which take about 15 minutes to fill out.Participants are asked their proximity to gas development, and about any current health symptoms – everything from levels of fatigue, nausea, and asthma, to whether they have a diagnosis of cancer, their mental health, and their family health history. Martin Senganec, age 60, who is a truck-driver, filled out the registration forms at a similar event in nearby Lowellville. He’s heard about a new frack waste injection well being permitted near his home. “I live less than a mile from what they’re building there, and I’m worried about it,” he said. Sengenec remembers the magnitude 3.0 earthquake near here five years ago, that Ohio regulators linked to fracking. He’s also concerned that this area has become a dumping ground for fracking wastewater, a high salinity, chemical-laced brine. Sengenic doesn’t think the state is ensuring that his drinking water well will be protected from contamination.“They say it’s not going to harm. I have well water, all the people around here have well water, and that’s what I’m worried about. If that hurts that…once the well is contaminated, you can’t do nothing with it,” he said.
Hot, Toxic Mess: Fracking Waste, Injection Wells, and De-Icing “Brine” – Randi Pokladnik – On July 1, I attended an environmental community science meeting at the Ohio University Campus Eastern in St. Clairsville, Ohio. The meeting was to provide local citizens with scientific information regarding a proposed oil and gas waste Class II injection well to be located at the intersection of U.S. 40 and Ohio 331. This Class II injection well would accept produced water wastes from high pressure hydraulic fracking. This waste contains flowback water, the fluid used to frack a well. This fluid is a chemical cocktail that can contain benzene, arsenic, formaldehyde, lead, mercury, and many other proprietary chemicals.The liquid waste also contains toxic metals, radioactive materials, and brine resulting from contact with the ancient rock formation that is being fracked. As a well is fracked, millions of gallons of fracking fluids are injected deep into the rock strata. According to a 2018 study out of Dartmouth College, in just hours, radioactive Radium 226 and Radium 228 can be leached out of the rock and into the saline solution. As the brine is pulled to the surface to be disposed of, the water-soluble radioactive isotopes hitch a ride as well. “More than 18 billion gallons of waste fluid from oil and gas is generated annually in the USA” according to the American Petroleum Institute. The waste is often referred to as Technically Enhanced Naturally Occurring Radioactive Materials or TENORM. A Pennsylvania study found that produced water from a horizontal unconventional well can contain water soluble Radium-226 in concentrations ranging from 40- 26,000 pCi/L. The safe drinking water standard for Ra-226 and RA-228 is 5 pCi/L. This toxic radioactive waste is what is pushed down injection wells in Ohio. In addition, much of the waste injected into Ohio’s Class II wells comes from out of state sources (Pennsylvania and West Virginia).According to a study done by our allies at FrackTracker Alliance, Ohio has 226 active Class II injection wells. These wells dot Ohio’s landscape in and along the area of Utica and Marcellus drilling, as well as expand into Ashtabula, Trumball, and Portage counties to the north and Washington, Athens, and Muskingum counties to the south.FracTracker data shows that the top twenty wells within these 226 are accepting more waste each year, at least 24,822 barrels more annually. This is due in part to an increase in the horizontal distances drilled to frack a well. In the beginning of the fracking boom, most lateral lengths were approximately two miles, now they have increased to three to three and a half miles. These “super laterals” require more water to frack and therefore create more wastes or “produced water”.
As Risky Finances Alienate Investors, Fracking Companies Look to Retirement Funds for Cash – DeSmog A year ago, Chesapeake Energy, at one time the nation’s largest natural gas producer, announced it was selling off its Ohio Utica shale drilling rights in a $2 billion deal with a little-known private company based in Houston, Texas, Encino Acquisition Partners. For Chesapeake, the deal offered a way to pay off some of its debts, incurred as its former CEO, “Shale King” Aubrey McClendon, led Chesapeake on a disastrous shale drilling spree. Shares of Chesapeake Energy, which in the early days of the fracking boom traded in the $20 to $30 a share range, are now valued at a little more than $1.50. Chesapeake, of course, is not alone in discovering that shale drilling can be financially disastrous for investors. In 2018, the top 29 shale producers spent $6.69 billion more than they earned from operations, an April report by Reuters concluded – a spending record racked up two years after investors began pushing shale drillers to start turning a profit. In December 2017, the Wall Street Journal found that shale producers had spent $280 billion more than the oil and gas they sold was worth between 2007 and 2017, the first 10 years of the shale drilling rush. “We lost the growth investors,” Pioneer Natural Resources CEO Scott Sheffield recently told the Journal. “Now we’ve got to attract a whole other set of investors.”Encino, which bought up Chesapeake Energy’s 900,000 acres of drilling rights in Ohio’s Utica shale in that $2 billion deal, may have found its “other” investors: the Canada Pension Plan Investment Board(CPPIB), which manages retirement funds on behalf of the Canada Pension Plan. “We’re not your typical private equity company in that the Canada pension plan is I think the third largest pension plan in the world,” Ray Walker, Encino’s chief operating officer, told attendees at last month’s DUG East shale industry conference in Pittsburgh. “They have a long-term view on capital and they don’t expect their funds to start declining – in other words more people [in Canada] are putting in today than will be taking out, and they don’t expect that to flip til 2050-plus.”
Speakers cite health hazards linked to petrochemical industry — Matthew Mehalik, executive director of the Breathe Collaborative in Pittsburgh, and Dr. Ned Ketyer, a pediatrician from Washington County, Pennsylvania, addressed a large audience at Lunch With Books at the Ohio County Public Library. Wheeling is in the bull’s-eye for harmful effects from the petrochemical industry, Ketyer said, with fracking well pads expanding greatly and compressor stations growing rapidly in size and number. Citing potential dangers of the industry, they said an ethane cracker plant now under construction in Beaver County, Pennsylvania, and proposed cracker plants in Belmont and Wood counties are expected to create significant negative health care impacts. For example, Mehalik said experts predict health care costs in Ohio County would increase $1.3 to $3.1 million annually, or $46-94 million over 30 years, as a result of the three plants. He said 30-year costs nationally are projected at $3.6-8.4 billion. The Ohio River will be “a conduit for pollution” from the Royal Dutch Shell cracker plant in Beaver County, Ketyer said, adding that air pollution exposures “are going to be significant” in areas downwind from the plant. Ketyer said people in an area 1 to 4 miles from the plant face extreme exposure, with potential health problems such as upper respiratory irritation, shortness of breath, higher blood pressure and changes in cognitive function.
DOE Official Tells W.Va. Lawmakers Petrochemical Development is a Top Priority – West Virginia lawmakers heard testimony Tuesday from a top Department of Energy official that the federal government is prioritizing building out a petrochemical industry in Appalachia. Speaking in front of the Joint Committee on Natural Gas Development, Steven Winberg, DOE’s assistant secretary for fossil energy, told lawmakers his agency and the Trump administration believe the Ohio Valley is “on the cusp of an Appalachian petrochemical renaissance.” “Federal efforts are strong and continue to gain momentum,” Winberg said. “We also recognize that others are doing a lot and we believe that together we can make this Appalachian petrochemical Renaissance happen for the benefit of the industry, the region and the country.” West Virginia, Pennsylvania and Ohio sit on top of some of the country’s largest reserves of ethane-rich natural “wet” gas, which can be processed into the chemical and plastics feedstocks. According to a 2017 U.S. Department of Energy report, U.S. natural gas liquids production in the region is projected to increase over 700 percent in the 10 years from 2013 to 2023. Winberg said the federal government is devoting resources into ensuring pipelines, ethane storage and cracker plants are built in the region, including to get final investment in a proposed cracker plant in Belmont County, Ohio. Thailand-based PTT Global Chemical, and its partner South Korea’s Daelim Industrial Co., have applied for permits and purchased 500 acres of land in Dilles Bottom, just a few miles from both Shadyside, Ohio, and Moundsville, West Virginia, just across the Ohio River. About 30 miles northwest of Pittsburgh, Shell’s Monaca cracker plant is already under construction. It’s slated to produce 1.6 million tons of ethylene each year and permanently employ about 600 workers when done, according to the company. Winberg urged West Virginia lawmakers to invest now in preparing sites for possible cracker development. “What we need, ladies and gentlemen, is one of these crackers in West Virginia,” he told the committee. “These crackers are the anchor facilities that will drive job growth in this region.”
Braskem abandons proposed petchem project in West Virginia; will sell site | S&P Global Platts – Brazilian petrochemical producer Braskem is no longer pursuing a petrochemical project, which would have included an ethane cracker, in West Virginia, and is seeking to sell the land that would have housed it, the company confirmed Thursday. “Due to a number of recent inquiries about its site in Parkersburg, Braskem has engaged a financial advisor to help evaluate strategic alternatives for the site,” the company said, declining further comment. The decision is the latest reversal seen by proponents of the Appalachian Basin region’s natural gas industry, who are seeking to attract international investment in the energy and petrochemical industries to the Mountain State. The project, announced in 2013, has been on Braskem’s back burner for several years. In May last year Mark Nikolich, CEO of Braskem’s US arm, Braskem America, said the project remained on hold pending progress on infrastructure, such as pipelines. The company had not found the right risk profile by that time, he said last year. Since then, Braskem has faced multiple other challenges. The company is facing fallout from a government report that linked its salt mining operations in Brazil to geological damages, leading to one cash freeze of R$3.7 billion ($973 million) and a lawsuit seeking a second freeze of R$2.5 billion ($657 million). Braskem’s failure to file a required annual report for 2017 with the US Securities and Exchange Commission on time and uncertainty about an extension of a naphtha supply contract with Braskem co-owner Petrobras were among issues that held up a conclusion for more than a year, market sources said. Odebrecht has since filed for bankruptcy protection. .
‘Game-changer’ cracker plant in Wood County is off, but another developer could step up – WV MetroNews – The developers of a proposed petrochemical cracker plant that generated buzz several years ago have officially withdrawn, state officials said, but they’re still working to encourage other possible developers.Then-Gov. Earl Ray Tomblin announced the possibility of a petrochemical complex in 2013, calling it a “game changer.”The site was a long-time chemical plant location south of Parkersburg. The site, most recently held by a company called SABIC was more than 300 acres.But the $4 billion cracker plant has never come to be as complications arose with the Braskem and Odebrecht companies that were behind it. The companies in 2015 said the project wasbeing reevaluated. Mike Graney, director of the West Virginia Development Office, was updating a group of lawmakers about recent contacts with natural gas developers when he described the status of the cracker project. “Braskem, who owned 380 acres, I think, in Washington Works, has agreed they are not going to build a cracker and they are quietly marketing that property,” Graney said. “And they really want to guide that decision because they’d like to see another cracker built so they’re marketing to that group of companies that could make that investment. So that’s big news. Big news because that’s sort of moving this thing forward.” A cracker plant separates ethane from natural gas into components for the polymer industries. “I think that site probably is one of the best opportunities for a cracker or other investment in the state of West Virginia,” “It has everything on that site that you need. You have close to highways, we have rails, we have river transportation and naturally we have the airport, which doesn’t do anything for product but it does get executives in and out of the area.”
Babies Born Near Oil and Gas Wells Are 40 to 70% More Likely to Have Congenital Heart Defects, New Study Shows – Proximity to oil and gas sites makes pregnant mothers up to 70 percent more likely to give birth to a baby with congenital heart defects, according to a new study. Led by Dr. Lisa McKenzie at the University of Colorado, researchers found that the chemicals released from oil and gas wells can have serious and potentially fatal effects on babies born to mothers who live within a mile of an active well site – as about 17 million Americans do. The researchers studied more than 3,000 newborns who were born in Colorado between 2005 and 2011. The state is home to about 60,000 fracking sites, according to the grassroots group Colorado Rising. In areas with the highest intensity of oil and gas extraction activity, mothers were 40 to 70 percent more likely to give birth to babies with congenital heart defects (CHDs). “We observed more children were being born with a congenital heart defect in areas with the highest intensity of oil and gas well activity,” said McKenzie in a statement. The study was more precise than previous reports about the link between oil and gas extraction and CHDs. The researchers studied families in which the pregnant mother lived near an active oil or gas well up to the second month of pregnancy, when fetal cardiac development takes place. They also estimated the level of intensity of the oil and gas activity, determined exactly how close the pregnant mothers lived to the well sites, and ensured there were no other significant air pollution sources which could skew their results. One science journalist, on social media, called the study “extremely convincing.” This study that found a 40-70% increased risk of congenital heart defects in children born close to oil and gas infrastructure is extremely convincing. They adjusted for all the things I wondered about when I first saw the headlines.https://t.co/Unccpzi9MD – Dave Levitan (@davelevitan) July 19, 2019 Biologist Sandra Steingraber was among the experts on the dangers of fossil fuel extraction who pointed to the study as the latest evidence that allowing oil and gas wells to operate, especially near communities, is a public health hazard. “It’s a strong study,” Steingraber wrote on Twitter after reading the paper, noting that the researchers built on knowledge scientists already have about chemicals that are known to be harmful to prenatal health and that are released during fracking.
Joint W.Va. Legislative Committee Urged to Find Fix for Plugging ‘Orphan’ Wells | West Virginia Public Broadcasting – Members of the West Virginia Legislature heard testimony Monday in support of reviving policy solutions to address the state’s growing number of abandoned and unplugged natural gas wells. In an afternoon hearing in front of the Joint Standing Committee on Energy, representatives from an industry trade group, the West Virginia Department of Environmental Protection and the West Virginia Surface Owners’ Rights Organization urged lawmakers to provide more resources to the WVDEP. There are more than 14,000 abandoned wells across the state. More than 4,500 are classified as “orphan,” which means they don’t have an operator. Sealing orphan wells falls on state regulators. Plugging one well can cost upwards of $60,000. “It’s a big number, and we haven’t done a very good job, I think, as a state and as an industry addressing those,” said James Martin, director of WVDEP’s Office of Oil and Gas. One challenge is money. WVDEP gets funding for well plugging from a portion of each $150 well work permit application fee as well as any forfeited bonds. Martin said those funding streams generage, on average, $80,000 a year. In 2018, the Legislature passed the natural gas “co-tenancy” law, which governs oil and drilling on properties owned by multiple people. It includes a provision with the potential to funnel millions of dollars into the state’s orphan well fund, but not for a few years. “For orphan wells specifically, we need significant and sustained funding to necessitate an appreciable level,” Martin said. “ At $80,000 a year we can plug one well here. So that’s not going to address the 4,600 anytime soon.”
Philadelphia Energy Solutions files for bankruptcy after refinery fire– (Reuters) – Philadelphia Energy Solutions filed for Chapter 11 bankruptcy protection, the company said on Monday, its second such filing in less than two years, after a fire last month prompted it to close the largest refinery on the U.S. East Coast. Following the June 21 explosions and blaze, PES started shutting down the 335,000 barrel-per-day Philadelphia plant without a planned restart. Some 1,000 workers are being laid off. The company’s lenders agreed to provide up to $100 million in new financing to PES to usher it through the bankruptcy, it said. The agreement allows PES to “safely wind down our refining operations and, with the support of our insurers and stakeholders, best position the company for a successful reorganization, the rebuilding of our damaged infrastructure, and a restart of our refining operations,” Mark Smith, chief executive officer of PES Energy, said in a statement. PES could receive payouts of $1.25 billion in insurance claims connected to the fire and business closure, according to two sources briefed on the company’s policies. The potential payouts include $1 billion for property damage and $250 million for loss of business, the sources said. The insurance payouts were expected to be used as collateral for the new bankruptcy financing, the sources said. The refinery has struggled financially for years, slashing worker benefits and scaling back capital projects to save cash. PES filed for bankruptcy in January 2018 to reduce debt, but cash on hand dwindled even after the company emerged from the process later in the year.
Shipping companies sue Philadelphia Energy Solutions for $600,000 in unpaid bills (Reuters) – Three Greek shipping companies sued U.S. refiner Philadelphia Energy Solutions Inc (PES) for about $600,000, claiming the company did not pay them for fees incurred by crude oil tankers chartered earlier this year, court documents showed. The lawsuit, entered into New York Southern District Court on Friday, just days before PES, the largest refinery in the East Coast, filed for Chapter 11 bankruptcy protection following a fire that damaged its 335,000 barrel-per-day refinery. PES exited bankruptcy in August and has struggled financially for several years. Bayview Shipping Co S.A., Skyview Marine Co S.A., and Gulfview Shipping Co S.A. are seeking a total of $605,160, chartering crude vessels, interest, legal fees and other costs they say PES was responsible for under the charter agreements. The cargoes, chartered between February and April, were loaded with N’Kossa crude oil, according to the lawsuit. N’Kossa crude is produced in the Republic of the Congo and is typically lifted as N’Kossa Blend which is a blend of N’Kossa and Kitina crude grades. At least two of the cargoes were loaded from the Djeno Terminal, according to the lawsuit, which is operated by French oil and gas company Total. PES was not immediately available for comment.
Pennsylvania court issues split decision on Marcellus Shale natural gas drilling rules – – A state court on Monday upheld portions of Pennsylvania regulations that address Marcellus Shale natural gas drilling, although the judges also sided with some of the arguments made by an industry group. The seven-judge Commonwealth Court panel’s 91-page decision concerns a lawsuit brought by the Marcellus Shale Coalition against the state Department of Environmental Protection and the Environmental Quality Board. The judges said state officials were not authorized to require restoration of sites to their approximate original conditions within nine months of when drilling has ended. The agencies did not persuade the judges that they have the power to require well operators to monitor wells near their drilling operations, even if they do not have the right to go on those properties and plug them if needed, Judge Kevin Brobson wrote for the unanimous court. But the judges sided with DEP and the board in other respects, including on rules for liquid impoundment ponds and how drillers must respond when nearby wells are affected by their activity.
US Gas Economics Set to Fall Below $3 – U.S. natural gas economics will reach below $3 per million British thermal units (MMBtu) within the next decade, McKinsey Energy Insights reported Tuesday. According to McKinsey’s newly released 2019 North American Gas Outlook, North American gas demand will increase approximately 32 percent by 2030 – from 95 billion cubic feet per day (bcfd) to 125 bcfd. The firm contends the period will be marked by ample supply, escalating gas exports from North America and new domestic gas demand growth. McKinsey’s report also predicts that 20 bcfd of North American gas demand growth will come from gas and liquefied natural gas (LNG) exports. It also anticipates that coal-fired plant retirements will help gas’ share of the power mix to grow by 5 bcfd; however, it includes the caveat that renewables will start to displace gas after 2025 amid power sector decarbonization. “North American is endowed with abundant gas resources, which will play a major role in the energy mix domestically and provide security of supply through LNG to Europe and Asia,” Dumitru Dediu, partner at McKinsey, said in a written statement emailed to Rigzone. “We see over 1,000 trillion cubic feet of gas resources – which is sufficient to meet demand for the next two decades – at cost economics well below $3 per MMBtu.” The report assumes that gas production from Appalachia will grow to approximately 55 bcfd and supply roughly 40 percent of the North American market by 2030. Consequently, it projects that Appalachian gas output will displace the Western Canadian Sedimentary Basin and Rockies in the Midwest and supply the southern Mid-Atlantic region. “The building of pipeline infrastructure post-2023 will ensure Appalachian supply will continue to grow and limit price fly-up potential,” McKinsey stated. Also, the firm expects associated gas production – primarily from the Permian Basin – to increase by approximately 12 bcfd and supply one-quarter of the North American market by 2030. It pointed out that Permian production will limit southward gas flows from Appalachia, helping to meet LNG export demand on the U.S. Gulf Coast.
Listen: How fears of a US recession could impact spending in the US natural gas midstream sector – podcast – S&P Global Platts senior natural gas writer Harry Weber and Americas natural gas managing editor Joe Fisher discuss the outlook for the US midstream sector as fourth-quarter 2018 earnings reporting season begins, from the appetite for further major pipeline projects to the markets that will be served by increasing gas production to the impact LNG export growth will have on the industry.
Hotter Weather Trends End Natural Gas’ Losing Streak – After closing lower every day last week natural gas prices ended the streak of down days today, with the prompt month August contract moving around 6 cents higher on the day. Hotter weather trends were the primary reason for the move higher. This was precisely the risk that we alerted clients to in our Pre-Close Update back on Friday. Indeed, after tagging our 2.25 target in Friday’s session, buyers stepped back into the market after weekend weather models revealed that cooler weather would be confined to the current week, with above normal temperatures becoming more widespread again to end July and start the month of August. This gives us just a handful of days that are projected to be below normal in terms of weather demand (GWDDs). In terms of forecast changes, here is the change in GWDDs compared to the forecast back on Friday:
Natural Gas Futures Post Small Gain as EIA Report Seen ‘Failing to Move the Needle’ – An on-target storage report from the Energy Information Administration (EIA) gave neither the bulls nor the bears much to feast on Thursday as futures gained slightly on the day. In the spot market, prices pulled back somewhat in the hot Southwest, while milder temps accompanied small adjustments in the Midwest and East; the NGI Spot Gas National Avg. added 3.5 cents to $2.080/MMBtu. The August Nymex futures contract, set to expire Monday, added 2.4 cents to settle at $2.244 after trading in a range from $2.222 up to $2.261. September settled at $2.227, up 2.5 cents, while October gained 2.6 cents to $2.253. The relatively tight trading range coincided with daily fundamentals data that offered little in the way of new information to change the market’s outlook, Liquefied natural gas (LNG) demand “remains off its highs as well, and burns showed little change” compared to Wednesday, “still running a little stronger than last week on a weather-adjusted basis” but lower in absolute terms given milder temperatures, The EIA on Thursday reported an on-target 36 Bcf injection into U.S. natural gas stocks for the week ended July 19, versus a 27 Bcf injection recorded in the year-ago period and a five-year average 44 Bcf build. After a long string of above-normal builds earlier in the injection season, this week marks the second straight EIA report to come in below the five-year average. Prior to Thursday’s report, estimates had been pointing to an injection in line with the actual figure. A Bloomberg survey had showed a median 37 Bcf, while Intercontinental Exchange futures had settled at 35 Bcf. NGI’s model predicted a 33 Bcf injection.Total Lower 48 working gas in underground storage stood at 2,569 Bcf as of July 19, 300 Bcf (13.2%) higher than last year but 151 Bcf (minus 5.6%) lower than the five-year average, according to EIA. By region, the Midwest injected 23 Bcf on the week, while the East saw a net injection of 14 Bcf. Farther west, the Mountain region refilled 4 Bcf, while the Pacific on net grew its inventories by 3 Bcf. In the South Central, a 17 Bcf withdrawal from salt stocks was partially offset by a 9 Bcf injection into nonsalt, EIA data show. A combination of higher LNG feed gas demand and stronger power burns has seen injections “begin to normalize” during the last two report weeks, according to analysts with Jefferies LLC. “From the end of March until two weeks ago, 1.4 Tcf of gas was injected into storage, 45% above the five-year average of 0.9 Tcf,” the Jefferies analysts said. “…Lower prices are clearly impacting power burn, as July has averaged 40.4 Bcf/d, a new monthly record and up 1.1 Bcf/d year/year.” This year “has already seen 11 days of 40-plus Bcf/d power burn versus only nine in all of 2018. Power burn continues to exceed prior year levels despite” cooling degree days (CDD) coming in about 10% lower summer-to-date. “Even with this month’s hot weather, CDDs are still down around 2% year/year in July.”
Breaking Down Today’s In-Line EIA Report – Natural gas prices trade in a fairly tight range of just under 4 cents today, despite being an “EIA report” day. The August contract settled just over 2 cents higher on the day. One reason for the lack of significant movement? Today’s EIA report, despite the uncertainty around how much influence Hurricane Barry would have on the number, wound up almost dead on with the consensus market estimate, with last week’s build being 36 bcf. The draw in the salts was very impressive, but the overall report, while a lower build than the 5-year average, was reflective of supply demand balance that are still too loose to support a move higher, as seen when looking at the trend line of this same gas week in recent years. In fact, despite prices still being at historically low levels and a July that turned out to be a top-tier hot month in terms of national demand, end-of-season storage forecast have still not made a move lower, as the supply / demand balance has not tightened like what typically is observed with prices this low. As the saying goes, “low prices is the cure for low prices”, and at some point that will again be true, but we have not reached that point as of this writing. Recent weather trends are introducing another potential cooler push in the medium range, placing some “blues” back in our 11-15 day forecast today. That will not help the bullish case as long as cooler trends persist. Having said all of that, it is just the 25th of July, meaning there is plenty of time between now and the end of injection season, and as we know here in the world of natural gas, things can change quickly.
Natural Gas Prices Move Closer To Last Month’s Multi-Year Lows – Natural gas prices continue to take a beating, with the August contract closing just a penny higher than last month’s multi-year low for prompt month price. The contract was down 7.5 cents on the day today, settling at $2.169. As we mentioned in yesterday’s post, while the EIA number in yesterday’s report was almost exactly on par with market expectations, it was reflective of supply / demand balances that are still insufficient to allow prices to rally. The weather forecasts have been moving cooler as well, lowering forecast natural gas demand. We had outlined in our reports yesterday that we could see a continuation of that trend into today, and that proved to be correct, with our forecast moving 4.5 Gas-Weighted Degree Days cooler / lower. There are still some hotter than normal days on the way, but the dip in forecast demand is quite evident out in the 11-15 day time frame. In map form, it shows up even better, with larger coverage of below normal forecast temperature anomalies. The question is, how long will the cooler weather pattern hold? And will the lower price change supply / demand balances such that we can put in a price floor even with cooler weather trends? We can help answer these questions and more. Sign up for a 10-day free trial here and take a look at what our latest research indicates.
Energy regulators divided over natural gas and climate change – Regulatory decisions about America’s bounty of natural gas are in the hands of an obscure and understaffed federal agency with a limited mandate to think about climate change. With America’s production of oil and natural gas soaring and Congress not acting on climate change, the once-sleepy Federal Energy Regulatory Commission is finding itself at the center of protests and lawsuits. Interviews with all 4 FERC members illustrate their division over how to handle greenhouse gas emissions. Democratic FERC Commissioner Richard Glick wants to require companies seeking approval for pipelines and liquefied natural gas (LNG) export terminals to offset significant greenhouse gas emissions, similar to the way companies compensate for more traditional environmental impacts like creating wetlands. Natural gas is cleaner than coal and oil, but as a fossil fuel it still emits heat-trapping emissions. “I just fundamentally disagree with Commissioner Glick on this matter,” said Neil Chatterjee, the panel’s Republican chairman. “The approach the commission has been taking is what we are statutorily obligated to do.” Chatterjee pointed to the commission’s February approval of a gas export terminal, calling it a “breakthrough” because it was the first in two years and because it listed the greenhouse gas emissions associated with the project. (Glick dismissed the move as “window dressing.”) The FERC’s relatively limited legal authority is in the economic realm and rests largely on 2 nearly century-old laws – the Federal Power Act and the Natural Gas Act – that aren’t environmentally focused. It’s also short-staffed. Normally, it should have 5 commissioners; today it’s at 4 and it’s about to drop to 3. Democratic Commissioner Cheryl LaFleur is resigning next month (against her will). LaFleur has struck the most centrist position and often cast the commission’s tie-breaking votes. She supports Glick’s idea. “Certainly it’s potentially within our legal bounds,” LaFleur said. “I think ultimately the courts are very likely to decide that.” Indeed, recent court rulings have indicated FERC should do more to contend with the emissions associated with fossil-fuel projects; currently, the agency requires most companies to list them but nothing more. “If you listen to what’s going on in the courts, we’re going to have to have carbon offsets or something like that at some point soon,” said one natural-gas executive who works closely with the agency. Experts say Glick’s idea is unlikely to go anywhere, at least under GOP leadership in Washington.
Fracking likely to result in high emissions – Natural gas releases fewer harmful air pollutants and greenhouse gases than other fossil fuels. That’s why it is often seen as a bridge technology to a low-carbon future. A new study by the Institute for Advanced Sustainability Studies (IASS) has estimated emissions from shale gas production through fracking in Germany and the UK. It shows that CO2-eq. emissions would exceed the estimated current emissions from conventional gas production in Germany. The potential risks make strict adherence to environmental standards vital.In the last ten years natural gas production has soared in the United States. This is mainly due to shale gas, which currently accounts for about 60 per cent of total US gas production. Shale, a fine-grained, laminated, sedimentary rock, has an extremely low permeability, which in the past made it difficult – and uneconomical – to extract.However, recent advancements in horizontal drilling and hydraulic fracturing have opened up previously unrecoverable shale gas reserves to large-scale, commercial production.In light of experiences in the US and dwindling conventional gas reserves, the debate on shale gas has also taken centre stage in Europe. The purported climate advantages of shale gas over coal and the implications for domestic energy security have made fracking in shale reservoirs an interesting prospect for many European countries. IASS researcher Lorenzo Cremonese led a study that investigated the greenhouse gas and air pollutant emissions (including carbon dioxide, methane, carbon monoxide, nitrogen oxides, particulates and other volatile organic compounds) expected to result from future shale gas production in Germany and the UK. While methane leakage rates for the optimistic scenario approximate official figures in national inventories, the rates for the realistic scenario exceed them by a large margin. The emission intensity of shale gas in electricity generation is up to 35 per cent higher than estimates of the current emission intensity of conventional gas in Germany. The study also questions the accuracy of methane leakage estimates for current conventional gas production.
Zoning ordinance tabled over hazardous pipeline concerns –A major update to Boyle County’s zoning ordinance was tabled again this week, after the grassroots group Citizens Opposed to the Pipeline Conversion raised concerns over how it would alter regulations for hazardous pipelines. “I think there are shortcomings in the proposed ordinance that were not thoroughly considered,” said Mark Morgan, a Danville attorney who has been a leader in the COPC. Boyle County’s P&Z regulations concerning hazardous materials in pipelines dates back to 2015. That’s when the COPC got the P&Z Commission to require any company wishing to pipe hazardous materials through the county to get a conditional-use permit. The move was intended to protect against a plan from Houston-based energy giant Kinder Morgan, which intended to use Tennessee Gas Pipeline No. 1 to transport “natural gas liquids” – highly explosive byproducts of oil fracking – from northern Ohio to the Gulf Coast. A Kinder Morgan representative admitted to COPC members and other local residents that it had chosen Pipeline No. 1 rather than trying to pipe the fracking byproducts along the eastern coast because the company thought it would face less opposition from a less educated, less activist population, Morgan alleged during Wednesday’s hearing. Instead, they ran into far more opposition than they imagined in Boyle County. Ultimately, Kinder Morgan abandoned its plan to repurpose the pipeline, which currently carries natural gas. “They said it was due to economic reasons, which I think is absolutely correct,” Morgan said. “I think we were one of the economic reasons.”
Green’ Coalition Asks Burlington Freeholders to Block SRL Pipeline – Foes of the Southern Reliability Link are turning to the Burlington County board of freeholders to put a stop to the project by denying the pipeline project a permit to build along its county roads. New Jersey Natural Gas is already building the nearly 30-mile pipeline through parts of the 1-million-acre Pinelands National Preserve, even though the issue is still tied up in ongoing litigation by opponents. A coalition of 23 conservation groups led by the Pinelands Preservation Alliance is asking the board to exercise its authority to deny any permit, in this case a construction approval, in the interest of public safety. “If the freeholders conclude that the proposed route is unsafe and unnecessary, it is entirely within the board’s authority to reject a permit and easement for the job,’’ the letter from the groups argued. The pipeline, initially approved back in 2016 by the state Board of Public Utilities and challenged in court, is designed to provide more dependable gas delivery to New Jersey Natural Gas customers should there be major disruptions in other pipelines crisscrossing the state.The issue has become increasingly heated and a major headache for the Murphy administration, as most of the state’s most prominent environmental groups are urging a moratorium on new fossil-fuel projects to curb significantly greenhouse-gas emissions in New Jersey. There are about nine gas-pipeline projects pending, as well as four proposed natural-gas power plants. Critics contend those projects are not needed, given the administration’s goal to transition to 100 percent clean energy by 2050.
Federal appeals court hears arguments in South Portland pipeline case – The city of South Portland is blocking the Trump administration’s push to promote cross-border transmission of crude oil from Canada to the coast of Maine, a lawyer for the Portland Pipe Line Corp. argued Tuesday in federal appeals court in Boston. The city’s attorney argued that if the court backs the company’s appeal, it would effectively create a nationwide exemption from zoning restrictions for any new oil pipelines installed anywhere, including in residential areas. The 1st U.S. Circuit Court of Appeals heard oral arguments Tuesday in the pipeline company’s effort to overturn a 2018 federal district court ruling that upheld South Portland’s 5-year-old Clear Skies ordinance. A ruling is expected in the coming weeks or months. The ordinance, approved by the South Portland City Council on July 21, 2014, effectively blocked the company from potentially reversing the flow of its pipeline to bring crude oil from western Canada to its shipping terminals on Portland Harbor. Since the company filed its lawsuit in February 2015, the city has spent $2.4 million defending the ordinance and received $173,603 in donations to its Clear Skies Legal Defense Fund. The company contends that the ordinance is preempted by state and federal law, violates the Commerce Clause of the Constitution and adversely impacts national and international oil trade. The clause gives Congress the power to regulate interstate and foreign trade. The company’s lawyer argued Tuesday that the city should not be allowed to block the Canadian-owned subsidiary of ExxonMobil, Shell and Suncor Energy from bringing crude into the United States from the pipeline’s northern terminus in Montreal.
Southbridge hires lawyer to address LNG plant proposed in Charlton – The Town Council has hired a lawyer to represent the town’s interest in a proposed and controversial $100 million liquid natural gas plant along Charlton’s energy corridor on Route 169. Liberty Energy Trust, operating under Northeast Energy Center LLC, seeks to construct an LNG plant on 12 acres at 304 Southbridge Road, Charlton, near Millennium Power, close to the Southbridge town line. The company wants to develop a plant that will liquify, store and load natural gas into trucks. The company is seeking exemptions from Charlton zoning bylaws. Approval has been sought from the state’s Energy Facilities Siting Board, an independent board that reviews proposed large energy facilities. On July 15, Town Council voted to appoint lawyer David McKay, an environmental specialist from the firm Mirick O’Connell. Mr. McKay will represent Southbridge as an intervener during the siting process.In an interview, Town Manager Ronald San Angelo said that councilors have been discussing just how involved the town wants to be in the case. “Southbridge has an interest because, even though the facility is not in Southbridge, God forbid something bad ever happened at that facility. We would be called to provide police and fire backup, and, because it’s so close to the line, it could have an impact on our residents,” Mr. San Angelo said. “The council wants to understand what the issues are in this case.”
Trump LNG rule: Will it address ‘catastrophic’ risks? — For years, researchers have warned that stored materials at liquefied natural gas export facilities could pose a risk of catastrophic explosions and potentially be a threat to the public. But the issue is unlikely to be addressed when the Trump administration publishes a proposed revamp of the regulations governing LNG safety this September, according to industry watchers.Instead, the upcoming proposed rule from the Pipeline and Hazardous Materials Safety Administration (PHMSA), which oversees LNG facilities, is likely to focus on streamlining U.S. regulations and harmonizing them with those in other countries (Energywire, April 11).Additionally, a PHMSA-led working group on LNG safety in Baltimore last fall suggested it could take two years to fully assess an “evaluation protocol for non-LNG release hazards,” according to a presentation on the agency’s research and development priorities. That timeline would put action on the issue far beyond the intended release of updated rules.”There is no process in place to evaluate the suitability of the software models to calculate these hazards,” and work should be done to figure out how to assess the accuracy of such models, attendees at the Baltimore meeting concluded.The details of the rule could have long-lived safety implications, considering that multiple LNG terminals now on the drawing board in the United States will likely remain in service for decades.The United States has a dozen LNG import facilities that have been built over decades of domestic natural gas use, but the shale gas boom of the last 10 years has triggered a flurry of development around new export facilities. The first of those, Cheniere Energy Inc.’s Sabine Pass LNG terminal, began commercial operations in 2016, and by the end of this year, five more are expected to be up and running. Another six export projects are fully permitted, but developers have yet to announce plans to build.The PHMSA rule overhaul comes at the direction of an April executive order, in which President Trump highlighted the complete turnaround in the U.S. LNG industry.”New LNG export terminals are in various stages of development, and these modern, large-scale liquefaction facilities bear little resemblance to the small peak-shaving facilities common during the original drafting of [the LNG rules] nearly 40 years ago,” the executive order said.PHMSA’s mandate for the overhaul is vague, saying only that the regulator should “update” the relevant portion of the federal codes and that the process “shall use risk-based standards to the maximum extent practicable.” While it’s uncertain what the agency will do to address explosion risk, it has acknowledged the issue.
NATURAL GAS: Cheniere to feds: Cold weather contributed to spill — E&E News — – Cheniere Energy Inc. says unusually cold temperatures on the Louisiana Gulf Coast in January 2018 played a role in leaks from its liquefied natural gas tanks discovered a few days later.
Offshore GOM Operators Returning to Normal – Offshore oil and gas operators in the Gulf of Mexico (GOM) are resuming normal operations following tropical storm Barry, according to the Bureau of Safety and Environmental Enforcement (BSEE). Of the 669 manned platforms in the GOM, a total of 20, or 2.99 percent, remained evacuated as of Saturday, BSEE revealed, citing data from offshore operator reports. This figure stood as high as 42.3 percent, or 283 platforms, on July 14. Personnel have returned to all previously evacuated non-dynamically positioned DP rigs in the region, according to BSEE. The organization estimates that approximately 3.32 percent of oil production and 7.35 percent of gas production in the GOM remained shut-in as of Saturday. On July 14, BSEE estimated that approximately 72.82 percent of GOM oil production and approximately 61.68 percent of GOM gas production was shut-in. “Now that the storm has passed, facilities will continue to be inspected,” BSEE said in a statement posted on its website on July 20. “Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back on line,” BSEE added.
Deepwater GOM Pipeline System Starts Up – Williams reported Wednesday afternoon that it has acquired and placed into service the 16-inch Norphlet deepwater gathering pipeline system constructed by Shell Offshore Inc. and CNOOC Petroleum Offshore U.S.A. Inc. According to a written statement from Williams, the Norphlet system extends 54 miles (87 kilometers) from the Shell-operated Appomattox Floating Production System (FPS) in 7,400 feet (2,256 meters) of water to the Transco Main Pass 261A junction platform. The Transco platform is located approximately 60 miles (97 kilometers) south of Mobile, Ala., and first gas delivery occurred on June 22, 2019, added Williams. “We are excited to participate in this Jurassic development with Shell and CNOOC,” Williams President and CEO Alan Armstrong said on his company’s behalf. “Shell has exhibited a tremendous history of successful large-scale developments across the Gulf of Mexico and early indications here are for that to continue in the Jurassic play with their additional discoveries.” Shell reported in May of this year that it had begun production from the Appomattox FPS, noting that the milestone heralded a “new frontier” for the deepwater U.S. Gulf of Mexico. The Norphlet system can gather an estimated 261 to 291 million cubic feet per day of natural gas and connects more than 33,000 acres of dedicated leases to Williams’ Mobile Bay processing facility via the Transco lateral at the Main Pass 261A platform, Williams stated. Also, the company noted the system features a spare subsea connector for additional FPS volumes and modifications at the Mobile Bay facility that expanded slug handling capacity by 118 percent and stabilizing capacity by 329 percent.
US GOM Drillship Market Picking Up Steam – The U.S. Gulf of Mexico drillship market is picking up steam, according to Westwood Global Energy Group. As of mid-July, marketed utilization of the 25-rig fleet stood at 96 percent, with 24 units either working or committed to begin contracts in the next few months, Westwood highlighted on its website. Contracted utilization in July 2018 stood at 76 percent. Westwood has predicted that utilization will remain in the 95-100 percent range, “assuming rig owners do not shoot themselves in the foot by mobilizing a large number of rigs to the region on speculation, something that has occurred a time or two in the past”. Last month, Westwood outlined that the global offshore rig market appears to have emerged from “one of the worst” downturns in its history. “Over the coming months and years, demand is expected to continue to increase as a backlog of delayed projects continues to be worked through and aging, under-spec rigs continue to be retired,” Westwood said in a statement posted on its website at the time. “Whilst, even in the most optimistic scenario, it seems unlikely that the offshore rig market will return to the heights of the previous upturn, there should no-doubt be cautious optimism,” Westwood added.
Oil, gas drilling plans for Gulf of Mexico concerns local representatives – More oil and gas drilling could start to happen in the Gulf of Mexico. The Department of the Interior says it plans to lease millions of acres for oil and gas exploration. While the Trump administration says it’s a safe way to make use of what the country has, critics say it brings the Gulf closer to an oil disaster. It’s been almost 10 years since the Gulf oil spill, but even now some are leery about allowing more drilling even though the administration says it’s safe and economically sound. Sail into the Gulf of Mexico and you may soon see more of oil rigs. The Department of the Interior says it plans to lease 77.8 million acres for oil and gas drilling starting in August. “It is a threat anywhere because you cannot ensure those rigs will be safe,” said U.S. Rep. Kathy Castor. The Florida Democrat isn’t happy with the announcement. “The BP deepwater horizon disaster proved the point that a spill anywhere in the Gulf of Mexico is detrimental,” Castor said. But in a statement, Secretary of the Interior David Bernhardt says the Trump administration “is laser-focused on developing our domestic offshore … resources in an environmentally conscious manner.” The department says any projects will have measures “to protect biologically sensitive resources (and) mitigate potential adverse effects on protected species.” “We don’t think the Trump administration is paying close attention to how the oil and gas industry operates in sensitive areas,” said Athan Manuel, director of the Sierra Club’s Lands Protection Program.
Industry group says jurisdiction battles steal resources from taxpayers, oil and gas companies – For several years, the state of Louisiana has been faced with numerous battles between parishes and the oil and gas companies over the topic of climate and coastal erosion; now, one judge’s decision has moved one of these lawsuits back to state court. Tyler Gray, president and general counsel of the Louisiana Mid-Continent Oil & Gas Association, believes the forum shopping by plaintiffs within the legal system is a flawed strategy that will only end in more damages to the state’s business climate and residents.“The ruling is another procedural step in the judicial process, which unfortunately takes time and resources away from what could be collaborative efforts working towards real solutions for our coast,” Gray told Louisiana Record. “As we’ve learned from the Levee Board lawsuit and many years of litigation involving this case, the solutions to securing our coast will not be found in the courtroom.” According to ClimateLiabilityNews.org, Judge Martin L.C. Feldman recently decided that the Plaquemines Parish’s lawsuit against the oil and gas industry should be returned to state court rather than being heard in federal court. Based on the parish’s allegations, the oil and gas industry has violated the Louisiana State and Local Coastal Resources Management Act by failing to repair the wetlands they have disrupted following industry operations. Following Feldman’s announced decision, the oil and gas industry has already decided that they will appeal it, in the hopes of returning to federal court. The situation as a whole is highly controversial, with some groups believing that this is a state matter that should be sorted within Louisiana jurisdiction, while others are fighting for a federal hearing, claiming that it has wider-spreading implications.
SOWELA receives $1 million for new TC Energy Pipeline Academy (KPLC) – A big announcement from SOWELA Technical Community College where they are getting a million-dollar donation and a new oil and gas pipeline training academy.It will be the first in the state and only the third in the nation.From process technology to nursing, SOWELA plays a major role in training the workforce for Southwest Louisiana. Now, SOWELA will have an outdoor training pipeline and academy for students to learn all facets of the industry. TC Energy has donated $1 million to fund it.“They actually will build an actual pipeline training loop. This is an actual real pipeline, it carries no material, but it will be built on campus so individuals can come and train on actual pipeline. There’s classroom equipment, they provide funding for the instructor, and some of the planning that million dollars will be used for,” said SOWELA Chancellor Neil Aspinwall. “Most of the petrochemical industries, the huge pipelines that enter and exit those facilities–someone has to maintain them, someone has to design them, someone has to fix them if something’s wrong. So, there’s wonderful jobs there, good paying jobs. So, this program will help train the workforce for this industry,” said Aspinwall.
Permian Fracking Activity Underreported in 2018 – Operators in the Permian have been failing to report the completion of some oil wells, according to one data analytics company. Hydraulic fracturing (fracking) activity was underreported by 21 percent in the U.S.’ most prolific basin in 2018, according to Kayrros, a data analytics company serving the energy markets. In findings released Tuesday, Kayrros claims that more than 1,100 wells were completed in the Permian Basin but not reported through state commissions or FracFocus – a public repository for information on chemicals used during fracking. Kayrros said it uses optical and synthetic aperture radar imagery tracking along with proprietary algorithms to identify rigs and frack crews. Using those methods, they counted a total of 6,394 completed wells in the Permian in 2018 – a 21 percent increase from the FracFocus estimate of 5,272 wells as of June 20, 2019. The discrepancy in the reported wells means the industry has failed to capture the full scale of fracking, Kayrros contends. This implies two things:
- Oil inventory is smaller than believed – Kayrros estimates the Permian’s drilled but uncompleted (DUC) wells inventory is 1,000 wells each month with most of the rolling inventory coming from regular drilling and completions operations. Over time, the number of drilled wells matches completed wells, leaving DUC inventories unchanged. The belief that shale operators have a large backlog of DUCs that can quickly be brought to production in the event of an oil crisis without further drilling is misleading
- Transformation of perception of light tight oil economics – Based on Kayrros’ measurements, the average well is less productive and of higher cost than what is reflected in public data
“For all its revolutionary impact on the oil industry, shale remains poorly understood,” Kayrros chief analyst and cofounder Antoine Halff said in a release sent to Rigzone. “Publicly available data based on old-fashioned company reporting have their limits. Hard measurements unlocked by new data technologies show that contrary to public belief, there is no great buildup of DUCs just waiting to be brought online. The whole idea that the market can rely on this sort of de facto spare production capacity is an illusion. The industry is actually running on a much tighter leash than that.”
Historic horizontal well in Permian Basin completed (AP) – Drilling of the longest horizontal oil and gas well in the history of the Permian Basin has been completed as booming oil production in the region continues to center around shale in southeast New Mexico and West Texas. The Fort Worth, Texas-based Basic Energy Services recently announced the well was completed in the Wolfcamp, The Carlsbad Current-Argus reports . Wolfcamp is shale of the Delaware Basin, which sits below most of New Mexico’s Eddy County and the southern half of the state’s Lea County. Records show the well also encompasses portions of Culberson, Reeves and Loving counties in Texas. The job was completed for Houston-based Surge Energy, and frac plugs were drilled out to around 3.4 miles (5.4 kilometers). “We are honored to partner with an innovative (exploration and production) company like Surge to deliver these record-setting results,” said Brandon McGuire, vice president of Basic’s Permian operations. “Reaching this milestone with our customer displays our leadership in well servicing for complex, long lateral completions in the Permian Basin.”
Electric Fracking Could Take Over The Permian — Shale production in West Texas continues to boom–so much so that shale oil and gas producers in the Permian Basin have more than they know what to do with. As production continues to outpace the expansion of sorely needed pipeline infrastructure, local operators in the Permian are letting approximately 104 billion cubic feet of natural gas go to waste each year by flaring, what is essentially just burning the gas away, instead of putting it on market. For many producers in the Permian, this has led to diminishing profits. One such company is Houston-based oilfield service company Baker Hughes. The company’s first quarter profit also took a nosedive, clocking in at $32 million–less than half of its profits for the same period a year earlier, when Baker Hughes reported a profit of $70 million. On top of this major decline in profits, last month the company “ reported negative free cash flow for the first quarter at a time energy investors have been pushing companies to aggressively shore up capital for dividends and buybacks, sending its shares down as much as 8.5 percent” according to Reuters. However, despite these dismal numbers, things are looking up for Baker Hughes. CEO Lorenzo Simonelli told investors in a call on Tuesday that he sees all of the burned off natural gas wasted by his company and so many others as a byproduct of their oil drilling as a major business opportunity. The company is debuting a new, cutting-edge technology that will harness this otherwise wasted gas to power their hydraulic fracturing equipment in the Permian Basin in West Texas. Simonelli announced to investors this week that his company will be forging a new path in fracking by introducing a revolutionary fleet of “electric frack” turbines that will “use excess natural gas from a drilling site to power hydraulic fracturing equipment – reducing flaring, carbon dioxide emissions, people and equipment in remote locations” according to reporting by the Houston Chronicle. During a Tuesday call with investors Simonelli characterized the new strategy as an across-the-board win for their customer base, saying, “We’re solving some of our customers’ toughest challenges such as logistics, power and reducing flare gas emissions with products from our portfolio.”
Second Round of Lawsuits Targets Permian Highway Pipeline – A second round of lawsuits are underway in an effort to stop a massive natural gas pipeline from running right through the Texas hill country. Hays County is teaming up with landowners and conservation groups, threatening to sue the U.S. Army Corp of Engineers, the U.S. Fish and Wildlife Service and Kinder Morgan. Now, the energy giant behind the project is firing back. San Marcos resident Rachel Haggard is worried the proposed Permian Highway Pipeline could threaten her favorite, natural swimming spot. “No matter what kind of precautions you take, there’s always a risk of pollution,” said Haggard. The worry extends beyond the banks of the river. Signs protesting the project can be found all around town. A failed round of lawsuits by opponents have inspired a second round. This time, Attorney David Smith is representing groups targeting Kinder Morgan’s permitting process. “They’re doing less than the bare minimum,” said Smith. Smith claims the energy giant behind the project has applied for permits that only cover about three percent of the 430-mile natural gas pipeline. “What Kinder Morgan wants to do, is they want to get Fish and Wildlife Service’s blessing, coverage, if you will, for the entire pipeline,” said Smith.
Pipeline operator sues to block Kyle regulations – – Kinder Morgan, a pipeline operator working to build a 430-mile natural gas line slicing across Hays County, has asked a federal judge to block a Kyle ordinance that regulates the construction and operation of pipelines in the city.The lawsuit argues that the Kyle regulations, enacted three weeks ago, violate federal and state law and should be struck down. ″(Kyle officials) passed the ordinance that runs roughshod over federal and Texas law, ignores the regulatory schemes that have been in place for decades, and imposes criminal penalties for alleged violations,” said the lawsuit, filed Monday in Austin. Houston-based Kinder Morgan also filed a complaint with the Texas Railroad Commission, a state agency that regulates pipelines, arguing that the Kyle ordinance subjects pipeline operators to excessive fees and should be invalidated. The lawsuit, the latest in a series of legal battles over the Permian Highway Pipeline, was “not unexpected,” Kyle Mayor Travis Mitchell said. “We will confer with our legal team in the coming days and decide the best course of action,” Mitchell said.Last week, Hays County, the Travis Audubon Society and three landowners notified Kinder Morgan that they intend to file a federal lawsuit seeking to stop construction of the Permian Highway Pipeline, a $2 billion project designed to transport natural gas from the Permian Basin to the Gulf Coast.The 60-day notice of a potential lawsuit, required by federal law, argued that Kinder Morgan failed to obtain permits needed under the Endangered Species Act and other U.S. laws to run a 42-inch pipeline – expected to move 2 billion cubic feet of natural gas a day – through environmentally sensitive areas in Central Texas and the Hill Country. In addition, a separate lawsuit filed in state court argued that the pipeline will be dangerous and that the Railroad Commission failed to create a proper permitting process before allowing land to be condemned for the project.
Wisconsin tribe sues Enbridge, claims Line 5 trespassing on reservation – – A Wisconsin tribe wants a federal judge to remove Enbridge Energy’s Line 5 from their reservation on claims the Canadian company is trespassing and endangering their lands. The Bad River Band of Lake Superior Chippewa filed the lawsuit against Enbridge on Tuesday, July 23, in federal court in Madison, Wisconsin. The suit seeks a court order for Enbridge to stop using the pipeline and remove it from their lands. The tribe claims in the suit that Enbridge continues to operate its Line 5 oil and gas pipeline on the reservation with easements that expired in 2013. The 125,000-acre Bad River Reservation is located about 20 miles west of Ironwood, Michigan. Built in 1953, Line 5 runs 645 miles from Superior, Wisconsin, to Sarnia, Canada, by way of Michigan. The potential environmental dangers by its crossing in the Straits of Mackinac has been the continued focus of activists, Gov. Gretchen Whitmer and Attorney General Dana Nessel. In late June, Nessel filed a lawsuit to shut down the Straits’ crossing. In January 2017, Bad River Band leaders passed a formal resolution not to renew Enbridge’s right-of-way easements for Line 5 and called for the pipeline’s removal. The tribe says that 15 right-of-way easements for Line 5 expired in 2013. They own interest in 11 of those 15 properties that the pipeline crosses. Since early 2017, the tribe “has been collecting and reviewing environmental, water and pipeline data to further assess the danger posed by the pipeline,” according to a statement. They also engaged Enbridge in a “failed multi-year mediation process.”The tribe discovered that the Bad River is migrating quickly toward an area where a portion of Line 5 is buried, presenting a “looming disaster.” “The river is carving away the banks and soils that stabilize and support the aging pipeline,” the tribe’s lawsuit states. “This relentless process will soon expose Line 5 to the full force of the river’s currents and the load of fallen trees and other debris conveyed by the river.”
PUC asks Minnesota Supreme Court to deny Line 3 challenges (AP) – Minnesota regulators have urged the state Supreme Court to deny challenges by opponents of Enbridge Energy’s proposed Line 3 oil pipeline replacement who say the project’s environmental review was flawed.The Public Utilities Commission told the Supreme Court Tuesday it believes the review was “adequate in all respects.”Enbridge wants to replace its existing Line 3 across northern Minnesota, which dates from the 1960s, because it’s deteriorating and runs at only half its original capacity. The Minnesota Court of Appeals upheld most of the environmental impact statement last month, but sent the case back to the PUC for further proceedings because the review did not address a possible spill in the Lake Superior watershed.
New Study Suggests Living Near Oil Fields Could Cause Birth Defects In Babies – A new study has determined that families living near oil and gas fields have a 40 to 70% higher probability of having their children develop congenital heart defects (CHDs) compared to those living at greater distances, reported CU Anschutz Today.“We observed more children were being born with a congenital heart defect in areas with the highest intensity of oil and gas well activity,” said the study’s lead author Lisa McKenzie, Ph.D., MPH, of the Colorado School of Public Health at the University of Colorado Anschutz Medical Campus. More than 17 million Americans and 6% of Colorado’s total population live within one mile of an active drilling rig. The study was published last Thursday in the peer-reviewed journal Environment International, studied 3,324 infants born in Colorado between 2005 to 2011. Researchers studied infants with several types of CHDs. CHD is one of the most common birth defects in the country and a leading cause of death among infants. Infants with CHD have low rates of survival due to severe developmental problems and are more vulnerable to brain injury. McKenzie’s study comes after a paper that analyzed 124,842 births in rural Colorado between 1996 to 2009 and discovered that CHDs occured near oil and gas drilling facilities. Another study in Oklahoma studied 476,000 births, found several variants of CHDs near oil wells. Anschutz Today noted that the studies had several issues, including not being able to identify correctly if an oil and gas facility was in the development or production phase, and researchers didn’t confirm specific CHDs by reviewing all medical records.“We observed positive associations between odds of a birth with a CHD and maternal exposure to oil and gas activities…in the second gestational month,” the study researchers said.The new study discovered that rural areas with high active oil and gas activity are the epicenter of CHDs rather than in urban areas. What’s not entirely understood by researchers are how toxic chemicals lead to CHDs. McKenzie said the study doesn’t exactly prove a causal relationship between the various stages of an oil and gas drilling rig and that another study will be completed soon.
Cause of pipeline produced water spills unknown (AP) – North Dakota health officials still don’t know the cause of a pair of pipelines spills last week that leaked oilfield wastewater into a tributary of the Missouri River and another that spread over pastureland. high levels of lead, ammonium and other contaminants in surface waters affected by recent wastewater spills in the Bakken oilfield region. (AP Photo/Tyler Bell, File)State environmental scientist Bill Suess (sees) says Tuesday that cleanup of the “produced water” is ongoing at the two spill sites.The spills were reported by Polar Midstream. The company on July 14 reported a 20,000-gallon spill east of Williston and about a mile from Lake Sakakawea, the largest reservoir on the Missouri River.Suess says investigators don’t think the spill reached the river.The second spill leaked more than 12,000 gallons of wastewater, impacting an unknown amount of pastureland. Company spokesman Zak Covar says the cause isn’t known. He says the focus is on cleanup.
Company says work on old well may have caused spill (AP) — Chevron says an 800,000-gallon oil spill in Central California may have started when crews tried to recap an abandoned well. KQED News says the company held a briefing Friday about the seepage that began in May in a Kern County oil field west of Bakersfield. Chevron says it believes the spill stemmed from efforts to remove aging cement plugs from its non-producing wells and replace them. The company says that the initial flows came from a previously damaged well that was being re-entered. Chevron says more oil spilled in June when crews did pressure tests and later tried to complete the job of replacing cement in the well. Chevron says the oil has only fouled about an acre of land and 90 percent of the spilled material has been recaptured.
Chevron injected steam near well work before oil leak…– Chevron records show the large, McKittrick-area oil leak that has shone an unflattering light on Kern County petroleum production probably originated with an idle well being worked on at the same time the company was injecting high-pressure steam just 360 feet away, a combination that industry people say should not have been performed simultaneously in such close proximity and which possibly contributed to the release. The San Ramon-based oil producer told state regulators in a recent written analysis that a well it was using to put steam into the Cymric Oil Field was not switched from injections to production mode until 7½ hours after the company noticed oil seeping to the surface at 5:30 a.m. on May 10. Observers within the industry said that timeline suggests steam injection activity was happening at the same time Chevron had opened up and was “re-abandoning,” or resealing, a well idled in 2004. The problem with steaming a well near concurrent work on another well, people familiar with local oil fields say, is that there’s a chance steam will make its way through uncharted channels underground before coming to the surface in an area not outfitted to receive oil. Several people interviewed said Chevron should have “shut in” – meaning turned off – the steam injection well that state maps show lies 360 feet from the surface of a well the company blames for several thousand barrels of oil ending up in a dry creek bed during a series of uncontrolled releases near McKittrick. “I definitely would say they need a 600-foot shut-in radius if they are doing a re-abandonment,” said Bakersfield geologist Burton R. “Burt” Ellison, former district deputy at the California Division of Oil, Gas and Geothermal Resources, the state’s primary oil regulatory agency. Others, noting the complexity of subsurface conduits in western Kern oil fields, said it’s hard to say what a safe distance would have been in this case, and that additional nearby wells may have played a role in the leak. But they still questioned the wisdom of steaming so close to a well undergoing work.
US Oil Exports Reach New All-Time High – U.S. crude oil exports reached a new all-time high of 3.3 million barrels per day (MMbpd) in June.That’s according to the American Petroleum Institute’s (API) latest monthly statistical report released Thursday, which highlighted that the record exports helped reduce U.S. net petroleum imports to 1.3MMbpd.Total U.S. petroleum exports for the month were at 8.4MMbpd, according to the report, which noted that this was a record for June. This was said to be an increase of 3.6 percent from May and 7.9 percent from June last year.Record U.S. crude oil production of 12.2 MMbpd was sustained in June “despite less drilling”, according to the report.“The U.S. appears to be making substantive progress towards becoming a net energy exporter in 2020, as projected by the EIA, with production continuing to sustain its upward climb despite oil prices having declined 10 percent between May and June,” API Chief Economist Dean Foreman said in an organization statement.“This trend has been driven in part by increasingly low breakeven prices, strong productivity gains in key production regions and the incremental additions of new pipeline infrastructure needed to bring these resources to market,” he added.Back in June, the API revealed that in May, U.S. petroleum exports and crude oil productionsaw records. In its second quarter industry outlook report, also released in June, the API said the United States was poised for a continuation of record oil production. This report also highlighted that while U.S. crude oil export capacity has been “sufficient”, some capacity estimates suggest “some urgency to plan forward”. The API describes itself as the only national trade association representing all facets of the natural gas and oil industry. The organization, which was formed in 1919, has more than 600 members.
Despite Shale Success US Oil Imports Remain High – U.S. oil demand over the past decade has remained in the 19-21 million b/d range. Crude oil production, meanwhile, has soared 150 percent to ~12.3 million b/d. As such, it would seem safe to assume that U.S. oil imports have plummeted in the shale-era since 2008. Interestingly though, this has not exactly been the case. Although declining, the U.S. still imports huge amounts of oil. In 2018, for instance, the U.S. imported 9.9 million b/d of crude oil and petroleum products from nearly 90 countries, albeit down from ~13 million b/d in 2008. Imports of crude over that time have fallen from 10 million b/d to 7 million b/d so far this year. So despite domestic production continuing to break records, the U.S. still imports 10 percent of the world’s total oil consumption. There are a variety of reasons why the U.S. still imports high volumes of petroleum. The primary reason is that the U.S. shale oil boom has yielded loads of high-quality, light, and sweet oil that has a higher API gravity. The U.S. refining system, however, is generally configured to process the lower quality, heavier, and sourer oil that the country has been importing from Canada, Venezuela, and Mexico for many decades. It would therefore be uneconomical to run refineries solely on the domestic tight oil that has been flowing from U.S. shale plays. In addition, the U.S. needs a variety of oil types to make different products. The boom in domestic oil production is not precisely yielding all those required to make all of the products that Americans use. Further, oil production, access, refining, and demand differ geographically. There are numerous parts across the country that lack pipeline access to the booming U.S. production zones, such as the Bakken play in North Dakota and the Permian in West Texas. They are removed from most of the infrastructure to access oil, as well as refine and transport liquid fuels, located in the mid-continent and Gulf Coast regions. Distant California, for instance, which now imports 60 percent of its crude, retains Saudi Arabia, Ecuador, Colombia, and Iraq supplying nearly 75 percent of imports.
Halliburton’s Profits Take a Hit in 2Q – Halliburton Company saw its second quarter profits take a dip as its international operations saw improvements. Net income attributable to the Houston-based oilfield services company dropped to $75 million in the second quarter (equivalent to nine cents per share), down from $511 million one year earlier and $152 million in the first quarter of 2019. Revenues for second quarter were $5.93 billion, down from $6.15 billion one year earlier, but up from $5.74 billion in the first quarter of 2019. North America is Halliburton’s largest market and it had $3.33 billion in revenue for the quarter. This is down from $3.83 billion from one year earlier. Bloomberg reported on Monday that Halliburton cut its North American workforce by eight percent in the second quarter. The company saw revenue gains in the second quarter from its international markets. Revenues for Latin America were $571 million, up from $479 million one year ago; Europe/Africa/CIS revenues were $823 million, up from $726 million one year ago and Middle East/Asia revenues were $1.21 billion, up from $1.11 billion one year ago.
US Drops Eight Oil, Gas Rigs – The U.S. dropped five oil rigs and three gas rigs for a net loss of eight rigs this week. The U.S. dropped five oil rigs this week and three gas rigs for a net loss of eight rigs, according to weekly data from Baker Hughes, a GE Company.This week’s declines bring the nation’s total number of active rigs to 946 – down 102 from the count of 1,048 one year ago. North Dakota saw the most declines this week, dropping eight rigs. Several other states experienced their rig counts drop. They are:
- Louisiana (-4)
- Ohio (-2)
- Oklahoma (-2)
- Alaska (-1)
- West Virginia (-1)
Wyoming added four rigs, while New Mexico added two and California, Colorado, Kansas and Utah each added one rig. Among the major basins, the Williston led this week in declines with eight rigs. The Marcellus and Utica each dropped two rigs while the Eagle Ford dropped one rig.The Permian added three rigs. Currently, the Permian has 443 active rigs, which accounts for almost half of the nation’s active rigs. The DJ-Niobrara added two rigs while the Ardmore Woodford and Arkoma Woodford added one rig apiece.
CEO of Major Shale Oil Company ‘Has Second Thoughts’ on Fracking Rush, Wall Street Journal Reports – On Monday, the Wall Street Journal featured a profile of Scott Sheffield, CEO of Pioneer Natural Resources, whose company is known among investors for its emphasis on drawing oil and gas from the Permian basin in Texas using horizontal drilling and hydraulic fracturing, or fracking.Back in 2014, Sheffield told Forbes that he expected Pioneer could produce a million barrels of oil a day from the Permian basin by 2024 – up from 45,000 barrels a day in 2011.Now, Sheffield, who left the helm of Pioneer in 2016 and returned this February, says that those million-barrel-a-day plans are looking increasingly doubtful as the industry has struggled to prove to investors that it’s capable not only of producing enormous volumes of oil and gas, but that it can do so while booking profits rather than losses.“We lost the growth investors,” Pioneer CEO Scott Sheffield told the Journal. “Now we’ve got to attract a whole other set of investors.”Sheffield’s comments on the shale oil industry’s fiscal difficulties come on the heels of a warning from the former CEO of the country’s largest natural gas producer about the shale gas industry’s financial distress.Steve Schlotterbeck, former CEO of America’s largest producer of natural gas, described the impact over a decade of fracking on Marcellus shale drilling companies at a recent petrochemical industry conference.“In a little more than a decade, most of these companies just destroyed a very large percentage of their companies’ value that they had at the beginning of the shale revolution,” he said, in remarks reported by DeSmog on Sunday. “Excluding capital, the big eight basin producers have destroyed on average 80 percent of the value of their companies since the beginning of the shale revolution.”Doubts about the shale drilling industry’s financial prospects have simmered nearly as long as the industry has been producing oil and gas. “There is undoubtedly a vast amount of gas in the formations,” the New York Times reported in 2011, citing concerns among industry insiders dating back to 2009. “The question remains how affordably it can be extracted.”In the years since, shale drillers churned out massive volumes of fossil fuels, first shale gas then shale oil, pushing American oil production up 12 million barrels a day, according to Energy Information Administration figures cited by The Journal. At the same time, they have spent hundreds of billions of dollars more than they’ve earned from selling the fossil fuels they drew from the ground.
Shale Drilling’s Worst Yet to Come— America’s biggest owner of drilling rigs fell the most in seven months after the chief of Helmerich & Payne Inc. said he called the bottom too soon. Three months ago, when Helmerich had 220 of its rigs hired out, Chief Executive Officer John Lindsay told investors the second quarter would be the nadir for his fleet. But after the number of Helmerich rigs at work shrank to 214 a few weeks ago, Lindsay says his earlier projection was “premature.” “The full effect of the industry’s emphasis on disciplined capital spending continues to reverberate through the oil field services sector,” he said in a Wednesday statement. “We are reluctant to predict another bottom and see further softening during our fourth fiscal quarter as our guidance would indicate.” The hired hands of the shale patch who drill and frack wells are suffering from a slowdown in North American spending brought on by investor demands for higher returns. The U.S. oil rig count has fallen 11% this year, according to Baker Hughes. Fracking giant Halliburton Co. is eliminating jobs and warehousing equipment no one wants to rent. Superior Energy Services Inc. said earlier this week that it’s looking for ways to cut costs and may sell assets to raise cash. On Thursday, 28 of the 29 oil and gas industry stocks in the S&P 500 Index were falling. The frack market “is a mess,” Brad Handler, an analyst at Jefferies LLC, wrote in a note to clients. “With every passing datapoint/call, there is little to suggest this market gets any better, and so we hack away at numbers again.” Helmerich’s smaller rival Patterson-UTI Energy Inc. also cut its forecast. The Houston-based contractor said in an earnings statement it expects to run 142 rigs on average during the third quarter, down 10% from the previous three-month period.
U.S. Shale Is Doomed No Matter What They Do – With financial stress setting in for U.S. shale companies, some are trying to drill their way out of the problem, while others are hoping to boost profitability by cutting costs and implementing spending restraint. Both approaches are riddled with risk. “Turbulence and desperation are roiling the struggling fracking industry,” Kathy Hipple and Tom Sanzillo wrote in a note for the Institute for Energy Economics and Financial Analysis (IEEFA). They point to the example of EQT, the largest natural gas producer in the United States. A corporate struggle over control of the company reached a conclusion recently, with the Toby and Derek Rice seizing power. The Rice brothers sold their company, Rice Energy, to EQT in 2017. But they launched a bid to take over EQT last year, arguing that the company’s leadership had failed investors. The Rice brothers convinced shareholders that they could steer the company in a better direction promising $500 million in free cash flow within two years. Their bet hinged on more aggressive drilling while simultaneously reducing costs. Their strategy also depends on “new, unproven, expensive technology, electric frack fleets,” IEEFA argued. “This seems like more of the same – big risky capital expenditures.” EQT’s former CEO Steve Schlotterbeck recently made headlines when he called fracking an “unmitigated disaster” because it helped crash prices and produce mountains of red ink. “In fact, I’m not aware of another case of a disruptive technological change that has done so much harm to the industry that created the change,” Schlotterbeck said at an industry conference in June. IEEFA draws a contrast between Schlotterbeck and the Rice brothers. While the latter wants advocates a strategy of stepping up drilling in an effort to grow their way out of the problem, the former argues that this approach has been tried over and over with poor results. Instead, Schlotterbeck said that drillers need to cut spending and production, which could revive natural gas prices. But while the philosophies differ – relentless growth versus restraint – IEEFA argues that “neither of these strategies seem viable.” On the one hand, natural gas prices are expected to stay below $3 per MMBtu, a price that is unlikely to lead to profits, IEEFA says. That is especially true if shale companies aggressively spend and produce more gas. However, a strategy of restraint may not work either. “[E]ven if natural gas producers coordinate their activities and reduce supply – a highly unlikely prospect – Schlotterbeck’s expectation that natural gas prices would inevitably rise is questionable,” IEEFA analysts wrote.
Is a Mature Mexican Gas Market Within Reach? –Once providing over 40 percent of federal revenues, oil production has been cut in half to below 2 million barrels per day since peaking in 2004. Longtime oil-based Mexico is increasingly turning to natural gas to meet its rising energy needs. The goal has been to displace higher cost oil in both the power and industrial sectors. Once providing over 40 percent of federal revenues, oil production has been cut in half to below 2 million b/d since peaking in 2004. Mexico per capita uses just a third of the electricity that OECD partners use, so more generation is a national priority. For example, despite having 40 percent of the population that the U.S. has, Mexico uses just 10 percent of the gas. Mexico already uses gas for nearly 65 percent of its power generation, and the majority of new builds will be gas. Meanwhile, the sudden cancelation of the 4th long-term power auction in February signifies a fading focus on renewables from the AMLO administration that took office in December. With 75 percent of Mexico’s gas production coming as associated to crude, the domestic gas supply has also been plummeting. In turn, excluding that used by state-owned oil company Pemex, over 90 percent of the gas consumed in Mexico is imported, the vast majority of which comes from the U.S. And this can only increase: for a variety of technical, political, and security reasons, the development of Mexico’s 550 Tcf of EIA-reported recoverable shale gas remains many years away.
Venezuela’s Oil Production Could Soon Fall Below 500,000 Bpd – Venezuela, the country sitting on the world’s largest oil reserves, could be pumping as little as below 500,000 bpd of crude oil next year amid the economic and political crisis, IHS Markit said in an analysis on Tuesday.The sweeping sanctions that the United States imposed on Venezuela’s oil industry have failed to result in a regime change nearly six months after opposition leader Juan Guaidó declared himself interim president and won the support of the U.S. and many other western nations.According to IHS Markit, Venezuela’s oil industry has deteriorated so much since 2014 that any recovery would be a long time coming. The protracted political crisis also means that the military and Maduro’s regime will intensify the stick-and-carrot approach to foreign investors, with whom Venezuela’s state oil firm PDVSA has joint ventures to produce heavy oil, Ford Tanner, a Principal Analyst at IHS Markit, says.“The official use of hostility and inducement toward foreign E&P companies is expected to intensify amid a new phase of collapsing oil production,” Tanner said.The U.S. sanctions on diluents that Venezuela needs to dilute its super heavy crude to make it flow for exports, as well as the U.S. pressure on buyers of Venezuelan oil, are expected to further constrain production, exports, and oil revenues in Venezuela, and crude oil production could drop below 500,000 bpd in 2020, according to Tanner. In the latest Monthly Oil Market Report, OPEC’s secondary sources – the ones the cartel considers the official production figures – point that Venezuela’s crude oil production in June dropped by 16,000 bpd from May to stand at 734,000 bpd. To compare, Venezuela’s crude oil production in 2017 averaged 1.911 million bpd. Despite the economic collapse, Venezuela’s crude oil and refined oil products exports rose by 26 percent in June compared to May, thanks to higher shipments under oil-for-loan deals with China.
Chevron Gets Approval to Keep Producing Oil in Venezuela — Chevron Corp. and four oil services companies won U.S. government approval to continue producing oil in Venezuela despite sanctions placed on the crisis-stricken country. The extension of a waiver from sanctions will keep San Ramon, California-based Chevron’s joint venture with state-owned Petroleos de Venezuela SA running for another three months, the U.S. Treasury Department’s Office of Foreign Assets Control said in a statement Friday. The waiver, previously due to end on July 27, will now last until Oct. 25. Oilfield service companies Schlumberger Ltd., Halliburton Co., Baker Hughes and Weatherford International Plc were also allowed to continue their work in Venezuela for three months. While Venezuela only accounted for 1% of Chevron’s global crude production last year, it remains strategically important. The company is the only major U.S. producer still operating in the country, which has the world’s largest oil reserves. In recent months, Chevron made the case to the Trump administration that if it were to leave, its Venezuelan assets could be turned over to another operator. That could mean the state, or even Russian or Chinese interests. The U.S. has refused to recognize Nicolas Maduro as Venezuela’s president after an election last year. Financial sanctions have become its main tool for depriving Maduro of cash and pressuring the military to turn against him. Earlier this week, Venezuela’s opposition-led National Assembly issued a decree that guaranteed Chevron’s assets in the country would be protected under a new government led by Juan Guaido. Oil purchases from Venezuela have become complicated since the U.S. expanded its sanctions regime to include any business done with PDVSA, as the national oil company is also known. Other companies, including Spain’s Repsol SA and Italy’s Eni SpA, continue to do business with Venezuela. Chevron has operated in Venezuela for almost a century, since the discovery of the Boscan field in the 1920s. It has outlasted Exxon Mobil Corp., which left the country after a series of industry nationalizations during Hugo Chavez’s tenure as president.
Petrobras Ordered to Fuel Stranded Iranian Ships— A Brazilian top court justice ordered Petroleo Brasileiro SA to refuel two Iranian ships stranded off the country’s cost after the state-controlled oil company refused to do so for fear of U.S. sanctions. Petrobras, as the Rio de Janeiro-based oil giant is known, will comply with the decision, a person close to the company said. The producer has said it may face “significant losses” if included under U.S. sanctions. A spokesman for Justice Dias Toffoli, who ruled on the matter, declined to comment because the case was filed under seal. The two ships have been floating since early June off the port of Paranagua, about 450 kilometers (280 miles) south of Sao Paulo, one of them loaded with corn bound to Iran. The Islamic republic, which buys one third of all of Brazil’s corn exports, had threatened to cut its imports from the country unless the ships were refueled. While Brazil has a long history of good relations with Tehran, President Jair Bolsonaro’s commitment to ripping up the country’s traditional foreign policy to side with U.S. President Donald Trump has put those ties in doubt. On Sunday, Bolsonaro told reporters Brazil was “aligned” with the U.S. policies, including on Iran. Iran and the U.S. have been at loggerheads since last year, when Trump withdrew the U.S. from a 2015 nuclear agreement with the Islamic republic, calling it the “worst deal ever.” The fate of the vessels is the latest evidence of how the Trump administration’s policies are affecting other countries and rattling commodities markets across the globe.
YPF Makes Deal to Ship Argentine LNG — YPF has reached a preliminary agreement with Excelerate Energy L.P. to charter a second liquefied natural gas (LNG) carrier to transport Argentine LNG to the global market, Excelerate reported Thursday. Excelerate stated that its carrier Excalibur will transport LNG from the Tango floating LNG (FLNG) unit – located at the port of Bahia Blanca, Argentina – to the world market. The company added that it will be executing the final agreement with YPF “in the coming days” and that operations should start in early September. “We continue progressing in our ambition to add value to Argentine natural gas and to export surpluses during these months of low local consumption, to fully extract the potential as producer and exporter of Argentine natural gas,” Marcos Browne, executive vice president of Gas and Energy at YPF, said in a written statement distributed by Excelerate. The majority of the natural gas processed by Tango FLNG will originate from Argentina’s Vaca Muerta shale formation. After processing, it will be transported to the Excalibur LNG carrier for export. Excelerate noted that loading YPF’s product onto Excalibur will take approximately 45 days and that the vessel will be in the service of YPF until May 2020.
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