Oil, Gas, And Fracking News Reads 02June 2018 – Part 1

Written by rjs, MarketWatch 666

Here are some selected new articles from the week ended 02 June 2018.

This article is a feature every Monday evenung on GEI.

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Contracts for US oil traded lower for the second week in row this week, but the more significant story was likely that global oil prices traded higher at the same time…as you’ll recall, US benchmark crude prices fell nearly 5% to $67.88 a barrel last week, wiping out their May gains, after OPEC and Russia indicated they’d make up any global oil shortfall caused by reduced output from Venezuela and Iran…while US markets were closed for the holiday, US crude for July continued falling another 1.7% to $66.75 a barrel in overseas trading on Monday, while Brent, the international benchmark price fell, 1.4% to $75.39, again on concerns that OPEC and Russia would be increasing supply…with US markets open on Tuesday, the US traded contract was thus reported down $1.15 to $66.73 a barrel, largely reflecting its Monday losses, while Brent prices rose 9 cents to close at $75.39 a barrel….US oil prices then rose $1.48 to $68.21 a barrel on Wednesday, notching their first increase in 6 trading sessions, as oil traders anticipated a drop in U.S. oil supplies in the next day’s delayed report, while July Brent rose $2.11 a barrel, or 2.8%, to end at $77.50 a barrel on the ICE exchange in Europe…however, even though the EIA report showed the largest draw from US crude inventories since March, US oil fell nearly 2 percent to $67.04 on Thursday, while the expiring July Brent oil contract rose 9 cents to $77.59, as oil traders focused on increasing US oil production, and worried that the US had inadequate infrastructure to move that production to international markets…the discount for US crude continued to widen on Friday, with the price spread between US WTI oil and Brent reaching $11 a barrel for the first time since 2015, as US oil prices fell $1.23 to $65.81 a barrel, while August Brent only fell 77 cents to $76.79 a barrel, as positive US economic news strengthened the dollar, sparking selling in dollar-denominated commodities…US oil prices thus ended the week 3% lower, at their lowest level since early April, while Brent crude for August, which had stated the week at $76.47, managed a small increase of 32 cents, or less than half a percent…

There’s something that isn’t right about this wide price spread. the reason that’s usually given for the wide discount on US crude is that we are lacking adequate pipeline infrastructure to move our crude from the wells where it is produced to the ports, and that our ports are incapable of handling the volume of crude that supposedly needs to be exported, and hence a glut of US crude is developing stateside…however, a year ago we were exporting less than half of what we’re exporting now, our domestic crude supplies were 15% greater, and there was no big discount on US crude…moreover, the widely quoted WTI price for US crude is based on oil prices at the storage depot in Cushing Oklahoma, the virtual center of US pipeline infrastructure, with plenty of takeaway capacity to the coasts; the oil in the inland oil basins of western Texas, Colorado, and North Dakota is already priced as much as $10 lower than the WTI benchmark price, and is thus $20 below global prices…and remember, even as we are now exporting 2 million barrels of oil per day, twice as much as a year ago, we are still importing an average of 8 million barrels per day to meet our needs…(some of that is because most US refineries are optimized to process heavy, sour oil, and the production from the new wells is exceptionally light and sweet; so we export our high quality oil at a discount, and import the crap our refineries use to make our products at a premium)…still, if there was that much of an oversupply of crude in the US, we would certainly be reducing our oil imports, instead of continuing to import at the same pace…it’s almost as if someone is fixing the price so that we get screwed on every barrel, coming and going, but who could that be?

At any rate, natural gas prices also ended slightly lower this week, but not before hitting $3.00 per mmBTU for the first time since January on Tuesday, a day that prices actually ended 6 cents lower at $2.903 per mmBTU…forecasts that were indicating somewhat cooler trends by the second week of June, implying lower power burn for air conditioning, served to drive prices lower, but a smaller than expected addition to storage resulted in a 6.7 cent rally on Thursday, and gas prices added another penny on Friday to close the week at $2.962 per mmBTU, just 1.6 cents below their prior Friday close…the natural gas storage report from the EIA for the week ending May 25th indicated that natural gas in storage in the US rose by 96 billion cubic feet to 1,725 billion cubic feet over the week, which still left our gas supplies 788 billion cubic feet, or 31.4% below the 2,513 billion cubic feet that were in storage on May 26th of last year, and 500 billion cubic feet, or 22.5% below the five-year average of 2,225 billion cubic feet of natural gas that are typically in storage on the fourth weekend in May…the consensus forecast was for a 102 billion cubic foot addition to storage, so while this week’s 96 billion cubic foot addition fell short of expectations, it was pretty much in line with the average 97 billion cubic foot surplus of natural gas typically added to storage during the fourth week in May…again, we’re watching these supplies to see if they can be adequately rebuilt before next winter; last year, natural gas supplies rose to 3,790 billion cubic feet by the first week of November before withdrawals began, so at today’s levels we’d have to add 2,065 billion cubic feet over the next 23 weeks, or nearly 90 billion cubic feet per week, to match that level by November, which will become increasingly difficult as we move into the warmer part of the year, when demand for air conditioning is strongest…

The Latest US Oil Data from the EIA

This week’s US oil data from the US Energy Information Administration, covering the week ending May 25th, indicated that due to a big increase in our oil exports, a sizable drop in our oil imports, and a considerable increase in our oil refining, we had to pull oil out of our commercial crude supplies to meet those refinery needs for the eighth time in the past eighteen weeks….our imports of crude oil fell by an average of 528,000 barrels per day to an average of 7,631,000 barrels per day during the week, after rising by 558,000 barrels per day over the prior week, while our exports of crude oil rose by an average of 431,000 barrels per day to an average of 2,179,000 barrels per day during this week, which meant that our effective trade in oil over the week ending the 25th worked out to a net import average of 5,452,000 barrels of per day during the week, 959,000 barrels per day less than the net of our imports minus exports during the prior week…at the same time, field production of crude oil from US wells rose by 44,000 barrels per day to a record high of 10,769,000 barrels per day, which means that our daily supply of oil from our net imports and from wells totaled an average of 16,221,000 barrels per day during the reporting week…

Meanwhile, US oil refineries were using 17,155,000 barrels of crude per day during the week ending May 25th, 527,000 barrels per day more than they used during the prior week, while at the same time 597,000 barrels of oil per day were reportedly being withdrawn from oil storage in the US….consequently, this week’s crude oil figures from the EIA seem to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 337,000 fewer barrels per day than what refineries reported they used during the week…to account for that disparity, the EIA needed to insert a (+337,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as “unaccounted for crude oil”… (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)…

Further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports fell to an average of 7,679,000 barrels per day, which was 5.5% less than the 8,122,000 barrel per day average we imported over the same four-week period last year…the 597,000 barrel per day reduction in our total crude inventories included a 517,000 barrel per day withdrawal from our commercially available stocks of crude oil, and a 80,000 barrel per day decrease of the oil stored in our Strategic Petroleum Reserve, likely part of a sale of government owned oil mandated by this year’s federal budget…this week’s 44,000 barrel per day increase in our crude oil production included a 20,000 barrel per day increase in output from wells in the lower 48 states, and a 24,000 barrel per day increase in oil output from Alaska…the 10,769,000 barrels of crude per day that were produced by US wells during the week ending May 25th were again the highest on record, 15.3% more than the 9,342,000 barrels per day that US wells were producing during the week ending May 26th of last year, and up by 27.8% from 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 93.9% of their capacity in using 17,155,000 barrels of crude per day during the week ending May 25th, up from 91.8% of capacity the prior week, in the first sign this year that refineries were finally ramping up for the summer driving season…however, the 17,155,000 barrels of oil that were refined this week were still down 2.6% from the off-season high of 17,608,000 barrels per day that were being refined during the last week of December 2017, and 2.0% less than the 17,510,000 barrels of crude per day that were being processed during the week ending May 26th, 2017, when US refineries were already operating at 95.0% of capacity….

With the big jump in the amount of oil that was refined this week, gasoline output from our refineries was considerably higher, increasing by 381,000 barrels per day to 10,433,000 barrels per day during the week ending May 25th, after our refineries’ gasoline output had decreased by 410,000 barrels per day during the week ending May 18th....however, this week’s increase only served to bring our gasoline production back to the same level as the 10,430,000 barrels of gasoline that were being produced daily during the week ending May 26th of last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) rose by 358,000 barrels per day to a seasonal high of 5,296,000 barrels per day, after falling by 93,000 barrels per day the prior week….hence, that jump meant this week’s distillates production was 1.3% higher than the 5,226,000 barrels of distillates per day than were being produced during the week ending May 26th, 2017….

With the big jump in our gasoline production, our supply of gasoline in storage at the end of the week rose by a comparably modest 534,000 barrels to 234,431,000 barrels by May 25th, just the fifth increase in 13 weeks, but the 20th increase in 29 weeks, as gasoline inventories, as usual, were being built up over the winter months…the increase in our gasoline supplies was limited because our exports of gasoline rose by 300,000 barrels per day to 656,000 barrels per day, and because our imports of gasoline fell by 104,000 barrels per day to 959,000 barrels per day, while our domestic consumption of gasoline was unchanged from the prior week at 9,689,000 barrels per day…so even after this week’s increase, our gasoline inventories finished the week 1.1% lower than last May 26th’s level of 237,024,000 barrels, even as they were still roughly 8.8% above the 10 year average of gasoline supplies for this time of the year…

meanwhile, with this week’s sizable increase in distillates production, our supplies of distillate fuels rose for the first time in 8 weeks, increasing by a modest 634,000 barrels from last week’s four year low to 114,629,000 barrels during the week ending May 25th…that was just the 2nd increase in twelve weeks, and came after distillates supplies had fallen by 14,452,000 barrels over the prior six weeks, during a time of year when distillates supplies are usually increasing…our distillate inventories only managed a small increase despite the jump in production because the amount of distillates supplied to US markets, a proxy for our domestic consumption, jumped by 682,000 barrels per day to 4,319,000 barrels per day, possibly as wholesalers built supplies in advance of the holiday weekend… meanwhile, our exports of distillates fell by 238,000 barrels per day to 1,123,000 barrels per day and our imports of distillates increased by 213,000 barrels per day to 237,000 barrels per day…however, even after this week’s inventory increase, our distillate supplies still ended the week 21.9% below the 146,733,000 barrels that we had stored on May 26th, 2017, and roughly 15.5% lower than the 10 year average of distillates stocks for this time of the year…

finally, with our oil exports rising and our oil imports falling while our refineries were using more oil, our commercial supplies of crude oil decreased for the 10th time in 2018 and for the 34th time in the past year, as our commercial crude supplies fell by 3,620,000 barrels during the week, from 438,132,000 barrels on May 18th to 434,512,000 barrels on May 25th…hence, after falling most of the past year, our oil inventories as of May 25th were therefore 14.8% below the 509,912,000 barrels of oil we had stored on May 26th of 2017, 13.8% lower than the 504,205,000 barrels of oil that we had in storage on May 27th of 2016, and 2.2% below the 444,464,000 barrels of oil we had in storage on May 29th of 2015, during a period when the US glut of oil had already begun to build from the nearly stable supply levels of the prior years…

This Week’s Rig Count

US drilling activity managed to increase for the 14th time in the past fifteen weeks and for 23rd time in the past 30 weeks during the week ending June 1st, a period of higher oil prices that has generally seen the rig increases far exceed the few decreases…Baker Hughes reported that the total count of active rotary rigs running in the US increased by just 1 rig to 1060 rigs over the week ending on Friday, which was also 144 more rigs than the 915 rigs that were in use as of the June 2nd report of 2017, while it was still down from the recent high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC officially began their attempt to flood the global oil market…

the count of rigs drilling for oil was up by 2 rigs to 861 rigs this week, which was also 128 more oil rigs than were running a year ago, while it was still well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014…at the same time, the number of drilling rigs targeting natural gas formations fell by 1 rig to 197 rigs this week, which was only 15 more gas rigs than the 182 natural gas rigs that were drilling a year ago, and way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008…in addition, there continues to be two rigs operating that are listed as “miscellaneous”, compared to the 1 “miscellaneous” rig that was running a year ago….

drilling activity in the Gulf of Mexico was unchanged at 18 rigs this week, which was 5 fewer rigs than were drilling in the Gulf of Mexico a year ago…since there is also a rig drilling offshore from Alaska at this time, the total US offshore count stands at 19 rigs, down by 4 from last year’s offshore total of 23 rigs….however, 2 of the platforms that had been drilling through inland lakes in southern Louisiana were shut down this week, leaving just 2 such ‘inland waters” rigs still operating, down from the 4 inland waters rigs that were operating going into the same weekend a year ago…

the count of active horizontal drilling rigs increased by 3 rigs to 929 horizontal rigs this week, which was 158 more horizontal rigs than the 771 horizontal rigs that were in use in the US on June 2nd of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…on the other hand, the directional rig count decreased by 2 rigs to 65 directional rigs this week, which was also down from the 68 directional rigs that were in use during the same week of last year…meanwhile, the vertical rig count was unchanged at 66 rigs this week, which was still down from the 77 vertical rigs that were deployed on June 2nd of 2017…

the details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of June 1st, the second column shows the change in the number of working rigs between last week’s count (May 25th) and this week’s (June 1st) count, the third column shows last week’s May 25th active rig count, the 4th column shows the change between the number of rigs running on Friday and those of the equivalent weekend report of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was on Friday the 2nd of June, 2017…

as we’ve pointed out several times, most of this year’s drilling increase has been in the Permian, and when we hit a week such as this one where Permian activity doesn’t increase, the national rig count change is subdued as well….but notice that the total basin count (at +5) is more positive than the summary data would account for; that’s because a net of 4 rigs – 3 oil and 1 natural gas – were shut down that had been operating in recently active basins that Baker Hughes doesn’t track separately, such as the Unita in Utah, the San Juan in New Mexico, the Powder River in Wyoming, and others whose names escape me right now…that natural gas rig shut down in an unnamed basin appears to be the only natural gas change this week, as all the changes noted on the table above were drilling for oil…

Utica Shale Academy graduates 22 – The Utica Shale Academy graduated 22 of its newest alumni during it commencement ceremony on Thursday. Seniors from the main site at Southern Local High School and the satellite location at Columbiana High School joined family, friends and school leaders for the event at Salineville. USA Director Eric Sampson welcomed the crowd to the fourth annual exercise and thanked officials at both schools for partnering with academy and benefiting the students. “I would like to thank each and every one of you for being here this evening as we celebrate this one brief moment in time that, for these graduates, has been many years in the making,” Sampson said. “Tonight is a celebration of accomplishments of the individuals that sit here before us. Graduates, each of you have traveled a path that has brought you to this destination. Some of those paths may have been very similar, and some probably couldn’t be more different. But each of those paths brought you to this point in time to celebrate the accomplishments of the last 13 years of your journey in education. We are proud of you and we wish you nothing but great things going into the future.” Keynote speaker for the evening was Amanda Greathouse, operator of Safety Pro Training and Consulting of Lisbon. Greathouse encouraged the graduates to leave their comfort zones and take advantage of opportunities before them. She noted her own initial anxieties about taking her knowledge into schools and working with students but said it has been a rewarding experience.“It was very exciting and I was so glad that I did that,” she said. “I’m very proud of all of you. Over the past couple of years we’ve gotten to know each other and I?m grateful for you attentiveness, patience and eagerness to learn.”She added that while it was easy to be caught up in being comfortable, people should take advantage of opportunities because they can be very exciting. Greathouse added that the grads should also have a plan of where they want to be in the future.Sampson and Utica Shale Academy Board President Dr. Charles Joyce then presented diplomas to graduates Hailey Brock, Alexis Campbell, Chase Cook, Zackery Cox, James Downie, Joshua Hanshaw, Alante Jones, Kaitlyn Jones, Joseph Matheson, Dylan Mercer, Hanna Oates, Kevin Reaves, Zachary Robinson-Hunley, Nicholas Scott, Logan Snay and Kristy Soos. At the conclusion, Soos presented her peers as the latest graduating class.

Top of the List: Ohio’s largest oil and gas producers from fracking wells – This year’s list of the most productive Ohio oil and gas producers ranks operators by amount of natural gas produced from Ohio horizontal shale wells in 2017. The five largest natural gas producers are included in the attached gallery. Subscribers can see the online list by clicking the link below. Information also includes horizontal shale oil production, drilling permits issued in 2017 and top counties for producing wells. Most Productive Oil and Gas Producers Ranked by Total 2017 horizontal shale gas production, MCF Rank Operator Name Total 2017 Horizontal Shale Gas Production, MCF

• 1 Gulfport Energy Corp. 380.18 million
• 2 Ascent Resources Utica LLC 309.34 million
• 3 Chesapeake Exploration LLC 278.09 million
• 4 Rice Drilling D LLC 5
• 5 Antero Resources Corp.

View This List. (paywalled) All data used in the list comes from the Ohio Department of Natural Resources Division of Oil and Gas Resources Management.

EIA: Longer wells, higher productivity increase Utica gas output and rig count fluctuation — In April 2018, natural gas production from the Utica formation, located primarily in Ohio, averaged 5.8 Bcfd, or about 7% of total U.S. dry natural gas production. Utica natural gas production has increased relatively steadily since 2011, and in 2017, natural gas production from the Utica formation reached a new annual high of 4.9 Bcfd, 23% higher than 2016 levels. Despite steadily increasing production, Utica’s rig count and prices in the region have fluctuated. From 2011 – 2014, as Dominion South and other nearby hub prices remained higher than $2.75/MMBtu, the average yearly rig count kept rising, reaching an average of 43 rigs in 2014. However, by 2016, the rig count fell to 14 rigs, and prices declined to $1.50/MMBtu. New pipeline projects added takeaway capacity from the region in 2017 and both rigs and prices rose, though they remain lower than previous levels.Utica’s natural gas production increase has been supported by higher per-well production from new wells. Similar to production activity in other regions, such as the Marcellus and the Haynesville, drilling operators have increased the lateral length of horizontal wells. From 2011 to 2017, the average length of laterals increased from 4,649 ft to 8,628 ft, according to DrillingInfo. As production has grown, well productivity has also risen. EIA uses three-month cumulative production as a proxy for initial productivity (IP) rates because the number of days in production for any given month is not available. In Utica, the first three-month cumulative production per well increased from about 146 MMcf in 2011 to 824 MMcf in 2017. Moving forward, productivity gains are expected to continue as lateral lengths increase and optimization of spacing between wells improves well recovery.

Soil testing under way at site of possible Ohio cracker – It remains unclear whether an ethane cracker plant will be built in eastern Ohio, but small bits of news continue to emerge about the project proposed by PTT Global Chemical America, Kallanish Energy reports. A final investment decision on the $10 billion project is expected by the end of 2018.Crews were conducting soil tests recently at the site of FirstEnergy’s former R.E. Burger coal-fired power plant on the Ohio River at Dilles Bottom, in Ohio’s Belmont County. The power plant has been razed. In early May, the company paid $17.5 million to acquire a property southwest of the old power plant. The purchase gives PTT roughly 500 contiguous acres. Earlier this year, PTT approved an agreement with a subsidiary of Daelim Industrial Co. Ltd., a leading Korean construction and chemical company, to conduct a feasibility study and to secure funding for the petrochemical complex.The plant also grew a little in size and cost. The plant would be capable of producing ethylene and its derivative at a rate of 1.5 million metric tons per year.The cost of the project has jumped, from roughly $6 billion, to $10 billion, according to Ohio Gov. John Kasich, spoken at a press conference when the PTT-Daelim deal was announced. PTT Global Chemical America is a subsidiary of PTT Global Chemical, Thailand’s largest integrated petrochemical company.

US OKs start of more ETP Rover natgas pipeline segments in Ohio (Reuters) – U.S. federal energy regulators on Thursday approved Energy Transfer Partners LP’s (ETP) (ETP.N) request to commence service on a couple more segments of its Rover natural gas pipeline in Ohio. The U.S. Federal Energy Regulatory Commission (FERC) authorized ETP to start service on the Supply Connector in Ohio and parts of Mainline B, which is a 42-inch (107-cm) pipe that runs alongside the 42-inch Mainline A pipe from southeast Ohio to northwest Ohio. FERC, however, said it was still considering ETP’s request to start service on other pipeline segments, including the Burgettstown Lateral from Pennsylvania to Ohio and the Majorsville Lateral from West Virginia to Ohio. FERC said it granted the authorization to start service on the Supply Header and Mainline B on the expectation that “rehabilitation and restoration of the affected areas are generally proceeding satisfactorily.” At this time, final restoration of the Supply Header and Mainline B is over 90 percent complete, FERC said, noting that ETP has estimated it will complete full restoration by July 24. ETP said on Wednesday that placing all of the requested segments into service would have unlocked about 0.85 billion cubic feet per day (bcfd) of capacity that is not currently available to the market, which the company said could help offset the nation’s current storage deficit before next winter. The $4.2 billion Rover project is the biggest gas pipeline project under construction in the United States. It is designed to carry up to 3.25 bcfd of gas from the Marcellus and Utica shale fields in Pennsylvania, Ohio and West Virginia to the U.S. Midwest and Gulf Coast and Ontario in Canada. ETP has said it wanted to put the entire Rover project into service by June 1.

FERC approve Rover Pipeline’s full Mainline B pipeline — Energy Transfer Partners, L.P. announced yesterday that Rover Pipeline, LLC received approval from the Federal Energy Regulatory Commission (FERC) to commence service of the Supply Connector B and full Mainline B pipeline segments. This latest approval allows for 100% of Rover’s mainline capacity, 3.25 billion ft3/d of natural gas, to be placed into service. Starting 1 June, service to the Market Zone North Segment of the pipeline, with deliveries into the Union Gas Dawn Storage Hub in Ontario, Canada, will begin by way of the Vector Pipeline Connection in Michigan. Rover transports natural gas from the Marcellus and Utica Shale production areas to markets across the US, as well as into the Union Gas Dawn Storage Hub for redistribution back into the US or into the Canadian market.

Study: Using Oil and Gas Wastewater on Dirt Roads is Radium Health Hazard – — In more than a dozen states, it is legal to use the wastewater from the oil and gas industry to tamp down dust on the millions of miles of America’s dirt roads. The option is attractive to local governments, since it is cheap and effective.A new study by scientists at Penn State contends that it is also harmful to the environment, and hazardous to Americans, because it is putting radium in the water and air.The paper, published in the American Chemical Society journal Environmental Science and Technology, finds that many metals from the process leach into local water sources over time. Radium, in particular, leaches off the road and what remains could get kicked up in dust, and inhaled, the scientists report.The amount of radioactivity released through the road treatment process exceeds that from spills and wastewater treatment plants combined, the scientists find.“Spreading O&G wastewater on roads can harm aquatic life and pose health risks to humans,” according to the researchers.The survey of wastewater involved local conditions in 14 townships in northwestern Pennsylvania.The scientists assessed the actual wastewaters in the towns’ tanks and employed a Thermo Scientific mass spectrophotometer to look for barium, copper, iron and an assortment of other inorganic substances. Then, they separated out the organic compounds by concentrating aliquots, and conducting observations using comprehensive two-dimensional gas chromatography coupled to a time-of-flight mass spectrometer, according to the paper. The leaching process was assessed by looking at what ran off the road, and what was left behind. The radium was found using gamma spectroscopy, and experiments in the lab simulated spreading and runoff events. The determination was that radium from the unpaved roads is a danger to the people and animals in Pennsylvania.

Study finds health threats from oil and gas wastewater spread on roads – Spreading oil and gas wastewater has been a common and cheap way for municipalities to suppress dust on unpaved roads in parts of Pennsylvania for years. But a new study found the practice – which the state recently ended – could threaten environmental and public health by leaching metals, salts, and radioactive materials into surface or groundwater, nearby soil, and even the air. The study, from researchers at Penn State, found this water can contain contaminants like radium, a radioactive element and known carcinogen, “often many times above drinking water standards.” State law prohibits using brine from Marcellus shale gas wells. But for years, waste from shallow, conventional wells was allowed, even though it contains many of the same contaminants as that from deeper shale wells. The study found there were “no universal standards” for radioactivity or other components in wastewater used on roads, and that while Pennsylvania did test the brine for some contaminants, “radium concentrations were never reported” by the state. The Department of Environmental Protection, which for years allowed municipalities to treat their roads with brine, said last week it was ending the practice, after it was sued by a Warren County resident. Before the decision, over a dozen counties in Western Pennsylvania used oil and gas wastewater on roads, and at least 13 other states – including Ohio, Michigan, West Virginia and New York – allowed the practice, according to the Penn State study. But it was especially common in northwestern Pennsylvania. In 2016, municipalities spread more than 11 million gallons of brine on roads in Pennsylvania, 96 percent of it in northwest part of the state. That represented 6 percent of the Pennsylvania conventional oil and gas industry’s wastewater.

More attention being paid to Utica play in Pa., West Virginia – There is a “new” play that’s beginning to garner some serious interest in the Appalachian Basin, with one major basin player admitting it’s moving to a drilling program centered on this particular play.This play is stacked with the Mighty Marcellus in Pennsylvania and West Virginia, and thus, until now, has pretty much been an after thought in those two states.But the Utica Shale is going to break out in a big way as exploration takes place. Yes, that Utica Shale. Thought by many as an eastern Ohio play, geologic maps indicate the Utica is much bigger than the Marcellus, covering more area, more states, extending under Lakes Erie and Ontario, and into Canada.In fact, the thickest portion of the Utica in terms of pay is in Westmoreland County, in southwest Pennsylvania.“Since the Utica gets relatively deeper and drier moving east, it’s often referred to as ‘dry Utica’ in Pennsylvania and West Virginia,” according to Marissa Anderson, a senior energy analyst with BTU Analytics, in a recent blog. According to BTU data, from 2013 through 2017, 156 horizontal Utica wells were drilled and producing in Pennsylvania, led by Houston-based Hilcorp, one of the largest, privately-held independents in the U.S., which totaled 57. More than 8,200 unconventional wells are producing in Pennsylvania, according to Marcellus Shale Coalition president Dave Spigelmyer. One problem with the Utica in Pennsylvania and West Virginia, at least until now, has been the fact the play is deeper in the ground, which means greater expense. EQT, which tapped the monstrous Scotts Run Utica well in Greene County in southwest Pennsylvania, suspended its deep Utica testing program in middle of 2017 to focus on the Marcellus. Scotts Run’s 24-hour deliverability test of 72.9 million cubic feet per day (MMcf/d), with an average flowing wellhead pressure of 8,641 pounds per square inch, according to Anderson. “Lately though, discussion of the dry Utica is making an appearance in producer earnings, particularly with the ‘stacked pay’ potential it provides,”

Fracking is Destructive but Defenders Continue the Hype – Hoppy Kercheval’s May 16 opinion piece, “Evidence against fracking lacking,” is remarkable for several reasons.First, he writes about a subject, hydraulic fracturing, citing a single piece of research, coming to the conclusion it “demonstrates that the hysteria over fracking is unwarranted.”Not so fast Mr. Kercheval! There is now a literature of more than 600 articles published in scientific journals. Such peer-reviewed research is difficult, expensive, and time consuming to complete.Six years ago, before the body of literature developed, a single article with such conclusions might have been acceptable as a first try, but that is hardly the case now.The articles now published are divided, by my estimation 80 percent saying investigators found harms or substances that could cause harm as a result of fracking. That doesn’t provide a tight cinch, but it certainly doesn’t justify Mr. Kercheval’s facile conclusion.Second, referring to the concerns of rural people who have observed adverse effect in their children, their seniors and themselves as “hysteria” is roundly and soundly depreciating. It is much like racism or depreciation of foreign people or minority religion.The countryside is not inhabited by mindless souls who function with the sensibilities of ghouls. These are real people who take their children to physicians who treat various medical issues that may include respiratory problems, birth defects, blood disorders, cancer and nervous system impacts from questionable causes. When the disease occurs concurrently with drilling and production and nothing else new has happened, it doesn’t seem unreasonable to suspect fracking. Not much else does happen in the country side involving a thousand or more truckloads of chemicals and water per well, injected underground at as much as 15,000 pounds per square inch, along with surface disturbance of several acres for well sites, access roads and pipelines.

One of four injured in Doddridge County explosion dies -One of the four people flown to the hospital after an oil tank exploded in Doddridge County has died, according to the Occupational Safety and Health Administration. Barry Lattea, 51, was removing oil tanks on White Hair Lane in West Union Friday morning about 10 a.m. when one of the tanks caught fire and exploded, said Blake McEnany, assistant area director for the OSHA’s Charleston office. Four people were flown to the hospital for their injuries, and Lattea later died at Mercy Hospital in Pittsburgh. Lattea died of thermal and inhalation injuries, McEnany said. He didn’t comment on the status of the other three people who were injured. Lattea worked for Hydrocarbon Well Service, a Buckhannon-based oil and gas company, McEnany said. The other three people were employed by Waste Management, he said.

Public comments on pipeline plans may be slipping through cracks at FERC, audit says – The federal process for approving new natural gas pipelines is veiled from the public, does a poor job of tracking their views, and may not be considering their concerns when weighing new projects, according to a new auditor’s report.Environmental and pipeline safety advocates say the U.S. Department of Energy’s Office of Inspector General’s findings about the Federal Energy Regulatory Commission (FERC) are alarming, if not surprising.”It’s frankly quite troubling, but at the same time, this is not news to those folks who have been impacted by proposed pipelines and those folks who try to be involved and navigate FERC’s system,” Montina Cole, a senior energy advocate with the Natural Resources Defense Council (NRDC).The report found that FERC lacked a consistent process for tracking public comments on proposed pipeline projects, suggesting that all comments might not be reviewed.”In the absence of a consistent methodology, we did not verify to what degree comments received by FERC were considered, aggregated, and reflected in the environmental documents or final orders for the certificate applications during our review,” the report concluded. “The lack of a consistent methodology could increase the risk that FERC may not address significant and impactful public comments in the environmental document or final order.””If people’s comments are not being reviewed at all, that is highly problematic and completely unacceptable,” Cole said. “There are high stakes here; people’s lives, their livelihoods, property and certainly the environmental on which we all depend.” The findings of the inspector general’s May 24 report mirror those of a 2017 report commissioned by NRDC. That report concluded that the Commission needed to better take into account public comments, especially from stakeholders with limited resources.

FERC’s approval of Mountain Valley Pipeline invalid, groups argue – The environmental project manager who has been signing off on Mountain Valley Pipeline construction doesn’t have the authority to do so, lawyers for a citizen group are arguing in the Fourth Circuit Court of Appeals.The project manager for the Federal Energy Regulatory Commission, Paul Friedman, has been granting approval to continue with construction on the MVP, a 300-mile-long natural gas pipeline that will span from West Virginia to Virginia. But he doesn’t have authority to approve construction because he isn’t a division head or comparable FERC official, says Bold Alliance, a citizen group.Bold Alliance asked FERC to rehear the notices to proceed that Friedman signed between January and February, but FERC denied the rehearing on May 4. Now, the group is asking the circuit court for a rehearing of the case, plus a stay of construction. Friedman’s approvals are “unlawful because as a low ranking project manager, Friedman has not been delegated authority under the Commission’s regulations to act on requests to proceed with construction,” Carolyn Elefant, a lawyer for Bold Alliance, wrote in the motion for stay pending review of commission staff notices to proceed. FERC is listed as a respondent in the filings filed earlier this month. A spokeswoman for FERC would not comment on the pending litigation. Just because FERC ratified the first few notices doesn’t mean Friedman can continue approving construction, Bold Alliance argues. “The problem is that these grants of notices to proceed are a moving target because Mountain Valley Pipeline has filed about 23 requests for notices to proceed and Friedman grants them every week or so,” Elefant said. “Because Friedman is not a ‘designee’ to whom the Director could delegate authority, the letter orders granting MVP’s request to commence construction are null and void and MVP should not be allowed to proceed,” she wrote in the motion for stay.

Nationwide Permits to Mountain Valley Pipeline Out-of-Place – Today, lawyers for a coalition of environmental advocates including Appalachian Voices filed a motion for stay, asking the United States Court of Appeals for the Fourth Circuit to put an immediate stop to the construction across waterways of the fracked-gas Mountain Valley Pipeline (MVP). Because MVP’s own documents show it cannot meet the conditions required under its “nationwide 404 permit,” the streamlined permit issued by the Army Corps of Engineers is illegal.Today’s filing comes less than a month after West Virginia regulators cited MVP for failing to control erosion and just days after several inches of mud ran off MVP construction sites and blocked a road in Franklin County, Virginia.Under section 404 of the Clean Water Act, the Corps is charged with issuing a permit for the pipeline’s stream crossings that allows the project’s builders to trench through the bottom of those streams, including the Greenbrier, Elk, and Gauley rivers, and fill the crossings with dirt during construction of the pipeline. The permit issued to MVP by the Corps is commonly known as a “nationwide permit 12,” which takes a one-size-fits-all approach and is generally viewed as fairly limited in scope to be used for projects much smaller than ones the magnitude of the MVP, a 300-mile-long, 42-inch pipeline requiring a 125-foot right-of-way construction zone that would cross streams, rivers and other waters in West Virginia and Virginia more than 1,000 times.One condition of the nationwide permit is that if even one water crossing in a project is ineligible for the permit, it cannot be used for any of them. Another condition is that MVP cannot take more than 72 hours to complete construction across a stream or river. Since MVP has said the 72-hour limit would not give them enough time to complete construction across four important rivers, they cannot use the permit for any of the other water crossings along the pipeline’s route.

U.S. Army pulls Mountain Valley natgas pipeline permit in West Virginia – The U.S. Army Corp of Engineers pulled a permit last week for EQT Midstream Partners LP’s Mountain Valley natural gas pipeline from West Virginia to Virginia that could delay the $3.5 billion project’s expected late 2018 in-service date. * “This is a big one,” Katie Bays, energy analyst at Height Capital Markets in Washington, DC, said in a report on Monday, noting “The loss of the (Nationwide Permit) is not easy to reconcile and could delay the project.” * The permit, known as Nationwide Permit (NWP) 12, authorizes Mountain Valley to discharge dredged and fill materials into several rivers, including the Gauley, Greenbrier and Elk, at 591 locations. * Officials at EQT Midstream were not immediately available for comment. * The Army Corps said in a filing made available on Thursday that it pulled the permit on May 22 to determine if it is at odds with West Virginia environmental rules. * The Sierra Club and others alleged violations of the West Virginia rules in an appeal to the Army Corps and a lawsuit that is currently before the U.S. Fourth Circuit Court of Appeals. * Even if the Army Corps reissues the permit, Bays at Height Capital Markets warned if Mountain Valley loses the Sierra Club lawsuit, it could delay the pipeline’s in-service date by a year and require re-routing around three rivers in West Virginia. The 303-mile (488-kilometer) pipeline is designed to deliver up to 2 billion cubic feet per day of gas from the Marcellus and Utica shale formations in Pennsylvania, West Virginia and Ohio to meet growing demand for the fuel for power generation and other uses in the U.S. Southeast and Mid-Atlantic. * The project is owned by units of EQT Midstream, NextEra Energy Inc, Consolidated Edison Inc, WGL Holdings Inc and RGC Resources Inc. EQT Midstream will operate the pipeline and owns a significant interest in the joint venture. The companies have said they expect to complete the project in the fourth quarter of 2018. * In April, the companies said they planned to spend about $350 million to $500 million to extend the pipe about 70 miles from Virginia into North Carolina by the fourth quarter of 2020.

Pipeline Bombshell: Even Dominion Energy Says Mountain Valley Pipeline Contractor Is Incompetent — In recent weeks, Mountain Valley Pipeline (MVP) started tree clearing and ground preparation for its proposed 42-inch, 303-mile fracked natural gas pipeline running from West Virginia through Virginia. Almost immediately, reports emerged that MVP and its contractor, Precision Pipeline, LLC were wreaking havoc on Virginia’s water and land resources. Photos and video evidence clearly showed that Precision Pipeline, a Wisconsin company, had no idea how to deal with the springtime mountain rains that typify southwest Virginia, leading to landslides, mud on roads and sediment pollution in creeks and streams. And this massive construction project has only just begun. Activists are screaming “we told you so” because they have been saying for four years that the Mountain Valley Pipeline cannot be safely built in the mountainous regions of southwest Virginia. Local residents, with growing support from around the Commonwealth, have been arguing that construction of this pipeline alone would create permanent damage to the forests, creeks, streams, springs, and rivers on which hundreds of thousands of people depend for their drinking water. The evidence of Precision Pipeline’s incompetence in the initial stages of this project is mounting, as shown here, here, here, here, here, here, here, here, here and here. It turns out that someone else is saying we told you so: Dominion Resources. It turns out that Dominion’s wholly owned subsidiary, Dominion Transmission, Inc. (“DTI”) has been fighting Precision Pipeline in federal court for almost three years in a battle royale over a pipeline that Precision built for Dominion several years ago in western Pennsylvania and West Virginia. That fracked gas pipeline, which was part of Dominion’s larger Appalachian Gateway Project, was a relatively small 30 inches in diameter and “only” 55-miles long. Dominion points, in part, to a series of expert reports that it says document Precision’s incompetence in building the pipeline. In one of those reports, never before released but published here for the first time (see below), an engineering firm hired by Dominion details a long and terrifying account of Precision Pipeline’s incompetence when it comes to causing landslides during pipeline construction.Yes, landslides. Thirteen of them. In a 55-mile pipeline project.

Mudslide Pushes Landowners to Sue Mountain Valley Pipeline – The fight against the Mountain Valley Pipeline has gone from the trees to the courts, as six landowners filed suit against the pipeline in federal court Tuesday, claiming a mudslide near one of its construction sites damaged their property, WSLS 10 reported .The suit comes a week after the U.S. Army Corps of Engineers pulled the project’s permit to empty dredged material into West Virginia rivers while it evaluates if the project violates West Virginia’s environmental rules, potentially delaying the pipeline, Reuters reported .The controversial pipeline would carry fracked natural gas through 300 miles of West Virginia and Virginia. It has faced vocal opposition, motivating nine tree sitters to block its path since February.The landowners in Tuesday’s suit, Wendell and Mary Flora, Glenn and Linda Firth, and Michael and France Hurt, live near a pipeline construction site in Franklin County, Virginia. Heavy rains May 15 caused a mudslide to override construction barriers at the pipeline work site on May 18 and block Cahas Mountain Road with 8 inches of mud.The landowners claim the runoff from the mudslide entered their properties and damaged streams. The suit says the company showed a “startling disregard” for the impacts of construction and asked the judge to stop work on the pipeline.

Why New Jersey is leading the resistance to Trump’s offshore drilling plan – The Trump administration’s bid to expand offshore drilling sounds like a sweet deal when the oil and gas industry sells it: more jobs, increased local revenue and possibly an energy surplus that could lower home heating costs.But Mayor John Moor’s opinion of the proposal to drill off the Atlantic Coast for the first time in decades is set: “I don’t think the risk is worth all the money in the world,” he said at City Hall, a few blocks from the popular beach boardwalk that is fueling his city’s economic turnaround.“You could stack billions atop of billions atop of billions and it’s just not worth the risk.”Moor’s unwavering view stretches the length of the 142-mile Jersey Shore, from northern municipalities such as Asbury Park to Cape May in the south. As Memorial Day and beach season approached, several mayors whose economies rely heavily on tourism said they are united in opposition to President Trump’s plan.New Jersey beaches were an embarrassment 30 years ago, but state officials have poured millions of dollars into efforts to recover from a pollution catastrophe. The shore is revitalized, a state treasure that residents, conservationists and politicians fiercely protect.Across the Atlantic Coast strip, mayors in nearly every city teamed with council members, conservationists, business leaders and residents to craft resolutions that denounced the proposal to widen federal offshore leasing to 90 percent of the outer continental shelf, an effort that began just days after Interior Secretary Ryan Zinke announced the plan in January.They helped put New Jersey at the forefront of resistance to Trump’s “energy dominance” agenda, crafting obstacles to the five-year lease proposal that at least one other state copied and another is considering.Last month, New Jersey became the first Atlantic state to adopt a legal barrier to offshore drilling. Lawmakers passed a bill, signed by Gov. Phil Murphy (D), that prohibits oil exploration in state waters, which extend three miles from shore.An amendment to the law went further, barring the construction of infrastructure such as a pipeline to deliver oil and natural gas from drilling platforms in federal waters that start where state waters end, a move that would head off the industry’s favored method of bringing energy resources to shore. New York quickly passed a similar law. And a Republican state senator in Delaware submitted a bill in mid-May that mirrors those of the state’s northern neighbors.

Spill exposes poor regulation consequences – “A really unfortunate series of circumstances,” was how Kevin Lien described a recent spill of ten million gallons of orange sludge from a sand mine processing facility. A bulldozer and its operator slid into a deep settling basin at the Hi-Crush mine and sand processing plant in Whitehall, Wisconsin. Mine workers, working with emergency responders, dug through an earthen berm and intentionally released the thick, orange sludge. The sludge ran into Poker Coulee, making its way downstream into the Trempealeau River. Eventually the material made its way to the Mississippi River. Mr. Lien is the Director of Land Management for Trempealeau County. He spent nearly the past decade at the epicenter of sand mining in Wisconsin. Using the regulatory powers of the county, he worked with county board members to develop protections for the environment, communities and public health. The county continues to monitor many mines. But the mine that discharged the orange sludge is out of his jurisdiction. “The county has no jurisdiction,” Mr. Lien told me. “And, the city is unregulated.” The county has no jurisdiction because the mine is in both the cities of Independence and Whitehall. Several years ago, the mine sought and received approval to annex into the two cities – some five miles apart – to avoid county regulation. Annexation was approved in late 2013 by the Whitehall and Independence City Councils. A lack of regulation allowed the mine to avoid expensive but necessary protections.

China is preparing to buy a lot more natural gas from the US — It looks like China will make another bet on US natural gas, building new gas terminals at ports in four provinces. The facilities will accommodate the country’s increasing reliance on foreign gas.The CEO of Kunlun Energy said in its annual shareholders meeting that the company is conducting feasibility studies to build import terminals in four provinces. Kunlun is a subsidiary of China’s state-owned oil and gas company China National Petroleum Corporation (CNPC). Earlier this year, CNPC signed a 25-year contract with Cheniere Energy, a US-based liquified natural-gas producer. It was the first ever long-term contract to export liquefied natural gas from the US to China. China’s domestic production of natural gas can’t keep pace with the country’s needs. The nation’s effort to reduce air pollution and replace coal has led to a spike in natural gas use. Building new import terminals is an important step towards facilitating long-term energy-based trade partnerships. CNPC estimated that US exports of liquefied natural gas to China this year could be worth up to $6.7 billion dollars.

The Biggest Challenge For U.S. Oil Exports – As Saudi Arabia and Russia grapple with both the geopolitics and economics of continuing or stopping their one and a half year long oil production cut reached between OPEC and non-OPEC members in early 2017, U.S. oil exports are slowly making their way into Asia. American companies will export some 2.3 million barrels per day (bpd) of oil next month and over half of that (1.3 million bpd) will find their way to Asian markets, Reuters said, citing a key executive with an U.S. oil exporter. This follows a record 2.6 million bpd of oil that the U.S. exported just two weeks ago. Increased oil exports into Asia come as the price differential between global oil benchmark Brent crude and U.S. benchmark NYMEX-traded West Texas Intermediate widens. That price differential is currently around $9 per barrel, offering arbitrage opportunities for producers and huge savings for Asian refiners who buy U.S. crude oil. Moreover, the discount between the price of Brent crude and WTI produced in the Permian Basin widened to nearly $11 per barrel in April, marking the the largest monthly spread in almost four years. In April, Brent futures sold for an average $72 per barrel, while Permian crude sold for just $61 a barrel. As long as price differentials remain, U.S. oil exports will continue to chip away at both Saudi and Russian market share in Asia, the world’s largest oil consuming region, led by China, Japan, India, and South Korea. One problem for U.S. oil exporters, however, is that many Asian refineries are configured to process heavier crude blends and have to use lighter, sweeter U.S. oil to blend with other crude grades. For refiners that can process lighter U.S. crude the price differential is a boon and ensures that U.S. oil exports will continue to grab Asian market share. Yet, the U.S. also exports other grades like Mars and Southern Green Canyon which are medium sour grades as well as Bryan Mound Sour.

Amid Permian ramp up, U.N. cautions against fracking getting too big, too fast — A new United Nations report cautioned nations and companies about embracing the fast-growing energy trend of hydraulic fracturing, better known as fracking, without considering the environmental risks involved.The U.N. Conference on Trade and Development report found that the meteoric rise of natural gas production has led to “major concerns” about contamination of both ground and surface water and an increase in seismic activity. The report conceded that the risks of significant fracking-related issues are slim, but warned that consequences could be dire. The report comes at a time when the U.S. has embraced natural gas as the single largest source of energy. About a quarter of the country’s natural gas is produced in Texas, where the oil and gas sector is one of the state’s largest employers. Fracking, used in concert with horizontal drilling, has revitalized the U.S. natural gas industry, and firms have taken to shale fields across the country to get in on the action. Now, natural gas accounts for the largest share of domestic energy generation, at above 30 percent, replacing coal.And it’s cheap, making gas appealing to large-scale industrial operations and thus competitive in the energy marketplace. The average price for 2009-2017 is around half what it was from 2000-2008. In West Texas’ Permian Basin, natural gas production is so significant that it’s almost exceeding pipeline capacity. The U.S. Energy Information Administration estimated in a May 2018 report that on average, 10.3 billion cubic feet of natural gas is produced in the basin every day.

Fracking Industry Fights Allegations It Caused Earthquakes In Oklahoma –The fracking industry is defending itself against a class action lawsuit blaming it for earthquakes in Oklahoma. Class action attorneys are targeting a group of natural gas companies in an Oklahoma state court, having successfully argued that the case doesn’t belong in federal court. Chesapeake Operating and Special Energy are two of the companies that recently filed their motions to dismiss in Logan County District Court. The plaintiffs are claiming the chemicals disposed of by the defendants during the fracking process have increased the risk of earthquakes in certain parts of the state. The chemicals allegedly included saltwater that was produced during oil and gas operations. They alleged there were nine earthquake clusters between 2014 and 2017. Chesapeake had previously filed a motion to dismiss when the lawsuit was in federal court Dec. 18, but the case was remanded to state court Dec. 28, so the company refiled. In its motion to dismiss, Chesapeake wrote that Oklahoma law requires the plaintiffs to demonstrate causation, which it believes they have failed to do. Chesapeake argues that the plaintiffs made vague and conclusory allegations but that there was no causal link between the alleged damages and the disposal wells.The plaintiffs failed to identify any particular earthquake clusters that purportedly caused damage to their or any other putative class member’s home, according to the motion. Griggs isn’t the only plaintiff to take on the fracking industry. A lawsuit by the Sierra Club and Public Justice attempted to use the Resource Conservation and Recovering Act in a way it had never been used before, but U.S. District Judge Stephen Friot dismissed the case in last year. The two groups had alleged fracking caused the amount of earthquakes in the state to skyrocket – from 167 in 2009 to 5,838 in 2015. But Friot dismissed the case under a doctrine that allows the court to pass on deciding an issue when a state court has greater expertise in the area.

24 Oil Wells in a School’s Backyard. How Close Is Too Close? – – A new oil rig will rise behind a middle school in this sprawling county in the coming months, its slender tower bearing an announcement: fracking is back.After a downturn that began in 2015, oil and gas production is booming again, and new projects are sprouting along American freeways and padding government budgets, cheered by state legislatures, the fossil fuel industry and the Trump administration. But this growth is also spurring a return of the turmoil that accompanied the last boom, pitting neighbor against neighbor and communities against companies in a fight over which projects should be allowed to pierce the land. In few places is that tension more evident than along Colorado’s Front Range, where a fracking boom is colliding with a population explosion. Drilling applications in the state have risen 70 percent in just a year, while the area north of Denver is expected to double in population by 2050.In Weld County – the center of the state’s oil and gas activity and home to more than 23,000 active wells – that tension has converged at a school called Bella Romero Academy. Just behind the school, workers are laying the foundation for a 24-well project that will pull oil and gas from the earth as students race across the playground.The project has the support of state regulators and the county commission. But it is opposed by the school board, the superintendent and many parents, some of whom say they support fossil fuel development but are alarmed by such a large operation so close to their school.Well heads will sit 828 feet from the edge of Bella Romero property.Exacerbating the conflict is a spate of deadly fires at industry sites in the county, as well as the company’s decision to place the wells near a school that is overwhelmingly black and Latino, after nixing a proposal near a mostly white school that drew protests from parents. “It’s like they said, ‘Put it where the Mexicans live, over there it’s O.K.’” said Yveth Haro, 42, whose son Elian, 10, is a student at Bella Romero. “Well I don’t think it’s O.K.”

Troubled Gas Firm Drops Request to Dodge Drilling Limits Near New Mexico’s Methane Hot Spot – DeSmog (blog) – Today, one of New Mexico’s largest oil and gas producers, Hilcorp Energy, dropped its recently filed request to increase the number of wells it can drill or frack in the San Juan Basin, already home to tens of thousands of gas wells. Hilcorp’s proposal also would have shut the public out of the decision-making process by establishing an “administrative approval” process. Back in 2014, this corner of northern New Mexico made international headlines when NASA researchers discovered a persistent methane plume the size of Delaware. Two years later, they pinned one of the main sources of this methane “hot spot” to natural gas wells, pipelines, storage tanks, and processing plants in the San Juan Basin. A second peer-reviewed study last year confirmed those findings. On Friday, state regulators were scheduled to hear Hilcorp’s request to amend the state’s well spacing regulations, which would have allowed the company to drill more wells or target different formations than the rules currently allow. “The effect of that would be that rather than having a public hearing process where each of those items is heard, that entire process would be done away with and it would only require the local Oil Conservation Division official,” “His name is Charlie Perrin and the oil company could just walk in and say ‘Charlie, we want to drill some wells or recomplete some wells and just sign right here.'” The state now produces more oil than California or Oklahoma and ranks as the nation’s third largest oil-producing state after Texas and North Dakota, according to the New Mexico Oil and Gas Association. And, as NASA found, leaks here of methane, a powerful greenhouse gas, are unusually pronounced. In addition, in the rural Four Corners region where Utah, Colorado, New Mexico, and Arizona meet, smog levels reached so high last year that scientists warned the region is at risk of breaching national health standards. The central issue of Hilcorp’s seemingly mundane request is enormously consequential, because it relates to one of the most clear-cut limits that drillers face: how densely they are allowed to drill their wells. Currently in New Mexico, as in many states, drillers have to follow well spacing rules, which cap the number of wells targeting a given rock formation per “unit,” typically 640 acres. That’s a vital control because it’s relatively simple for state officials to enforce, unlike many pollution controls which require periodic inspections or constant monitoring. Either the company is allowed to drill a new well or it isn’t.

Bakken crude differentials soar on widening Brent-WTI spread – Bakken crude differentials for delivery in July rose sharply Wednesday to multi-month highs, flipping to a premium to the NYMEX WTI calendar-month average amid further widening Brent-WTI crude spreads, with Williston barrels rising to parity with Clearbrook for the first time. Bakken had a very active spot market, with differentials heard going up continually throughout the day. Sources cited the further widening Brent-WTI spread, which rose above $9/b during the day, as the primary driver of the rally, giving the incentive to ship Bakken barrels south to the US Gulf Coast. S&P Global Platts assessed the July-delivered crude spread at $9.52/b — the highest in more than three years. Close to the oil wells in North Dakota, Williston-origin barrels for rail transport were heard traded as high as NYMEX WTI CMA plus 25 cents/b, a steep rise of $2.20/b from Tuesday’s assessment. This was the highest differential since November 11, when it was assessed at NYMEX front-month WTI CMA plus 35 cents/b.Williston barrels for delivery on the Dakota Access Pipeline were heard traded as high as NYMEX WTI CMA plus 20 cents/b.Bakken crude in the Clearbrook, Minnesota, hub that supplies the Midwest market, meanwhile, was talked valued at a rare parity with Williston barrels, equivalent to a rise of $1.45/b day on day. This was the first time Williston barrels rose to parity with Clearbrook since S&P Global Platts started assessing the former in April 2014. Clearbrook barrels typically trade at a premium to Williston barrels to account for transportation costs westward, with the spread averaging at $1.14/b so far in June. But the recent slump in the Western Canadian crude market, which also supplies the Midwest hub, has limited the rise of Clearbrook crude.

Feds Receive First Application to Explore ANWR for Oil – The Interior Department’s Bureau of Land Management office in Alaska received a plan to conduct extensive, 3-D seismic testing in search of oil on the coastal plain of the Arctic National Wildlife Refuge ( ANWR ) this winter. The plan – submitted by surveying services SAExploration, Inc. and its partners Arctic Slope Regional Corporation and the Kaktovik Inupiat Corporation – is the first step in opening up Alaska’s pristine refuge for oil exploration and drilling, the Washington Post reported. Last year, Congress controversially lifted a four-decade ban on energy development in ANWR after pro-drilling Alaska Sen. Lisa Murkowski buried the provision into the GOP tax bill that passed in December.President Trump also claims he was the driving force behind the provision’s inclusion. The companies have requested a permit to survey an area encompassing 2,602 square miles, or the entire “1002 area” of the 1.5-million-acre coastal plain, which has an estimated 12 billion barrels of recoverable crude. SAExploration said that “this partnership is dedicated to minimizing the effect of our operations on the environment.” However, the Interior Department’s Fish and Wildlife Service (FWS) said the plan is “not adequate,” the Post revealed. FWS said the application showed “a lack of applicable details for proper agency review.” The department complained that the companies’ permit application did not include any studies about the impacts of the seismic work and equipment on wildlife, the tundra or the aquatic conditions in the area. “There is no documentation of environmental effects, whether positive or adverse,” FWS said. According to the Post, the department’s response shows no sign it will approve the request. The 1002 area is described by the Sierra Club as “the biological heart” of ANWR – home to polar bears, caribou, migratory birds and other species – as well as vital lands and wildlife for the subsistence way of life of the Gwich’in Nation .

US Interior sees Arctic National Wildlife Refuge lease sale as soon at July 2019: assistant secretary Balash — A lease sale in the US Arctic National Wildlife Refuge could come as early as July 2019, according to a top Interior Department official. The “scoping” process for an environmental impact statement for ANWR is now underway and will be completed in June, Joe Balash, assistant interior secretary for lands and minerals, told reporters in a briefing. The draft EIS is expected in early 2019 followed by the final document in late April, Balash said. “We will hold the lease sale when the EIS is completed.” Balash was in Alaska to attend scoping meetings held in several communities including in Anchorage on Wednesday. “We will definitely have a lease sale ” because it is required by Congress in the Tax and Jobs Act of 2017, he said. “The law said ‘we shall’ have the sales. “The purpose of the EIS is to inform the public and federal agencies on the impacts,” Balash said. “In the scoping, we are asking people for advice on what kinds of impacts we should look for.” Interior is required to hold two lease sales of not less than 400,000 acres each in a 1.6 million-acre section of coastal plain in the refuge. One of the problems Interior is wrestling with is how to deal with a limit of 2,000 acres of surface disturbance for development of any discoveries, Balash said. The limit is also in the federal tax act that authorized the leasing. “We have to craft a way to deal with this in the lease sale ” in how the limits on surface use will be allocated across tracts that will be offered, Balash said. “We have not yet determined a way to do it.”

Is A Natural Gas Pipeline Between Alaska And China Realistic? – When Alaska’s governor Bill Walker headed with a trade delegation to China earlier this week, he must have hoped to bring back good news about an 800-mile gas pipeline project that would see the state’s gas reserves flow into an increasingly gas-hungry Chinese economy. However, the only news the delegation brought home was that Sinopec and Bank of China were still interested in the project. This declaration of interest is hardly worth a headline, but one outtake from the meeting with Sinopec’s president, as reported by Alaska’s Energy Desk Rashah McChesney, is worth mentioning. The president of China’s largest refiner said, “After some of the work we did, in terms of assessment and evaluation in technology, economics and in terms of the resources of Sinopec – I think there’s a lot more work for us to be done than originally imagined.” The latter part of this remark should be a cause for concern for the project’s proponents as it is a clear sign that Sinopec will be taking a cautious approach to what could be a multibillion-dollar investment. To be more precise, the pipeline will cost an estimated US$45 billion. It would ship natural gas from Prudhoe Bay to the southern Alaska coast, in Nikiski, from where the now liquefied gas will be shipped to a booming Chinese gas market. Without it, the gas is as good as non-existent, because it cannot be brought to market without a pipeline. Given the size of the investment that would be needed to build the infrastructure, it’s no wonder that Governor Walker reached out to potential investors in the country that would benefit from the project. He inked a preliminary deal with Sinopec, China Investment Corp., and Bank of China last November. This, by the way, happened after the original companies behind the deal, including Exxon, BP, and ConocoPhillips, quit, worried about a surge in global LNG supplies that made the project “one of the least competitive” globally, according to Wood Mackenzie. But Alaska is not giving up. With falling oil production and revenues, tapping the U.S.’s huge Arctic gas reserves, which estimates peg at as much as 200 trillion cubic feet, makes perfect economic sense, provided that Chinese demand lives up to the promise and there isn’t too much competition, which is doubtful, what with all the megaprojects in Australia, and Russia joining the LNG game with its eyes set mainly on Asia.

Refi wave lurks for energy borrowers on back of higher oil prices – The rise in oil prices has come at an opportune time for oil and gas borrowers, which are facing US$400bn of maturing debt over the next 18 months and are preparing to engage in refinancing talks with lenders. There is approximately US$833.3bn of loans outstanding in the oil and gas sector, with about US$399.5bn scheduled to mature by the end of 2019 and US$138.4bn by the end of 2018, according to Thomson Reuters LPC data. As higher oil prices boost the credit quality of oil companies, issuers are likely to get more favorable terms when they negotiate refinancing terms. “There’s an awful lot of debt maturing by 2019 and 2020,” said Thomas Watters, managing director in the oil and gas ratings group at S&P Global. “Back between the years of 2012 and 2014, there was an irrational exuberance going on where oil prices were high and interest rates were low and there were a lot of deals getting done. A lot of high-yield credits came out first-time financing and they issued five- to seven-year papers. Higher oil prices will no doubt help them refinance.” The thriving oil market is supporting a steady recovery in the US oil and gas loans as the secondary prices have slowly climbed to a three-year high. The average bid of oil and gas loans has climbed 135bp so far this year to 97.33 in tandem with higher oil prices. About 80% of oil and gas loans are bid above 90 cents of the dollar, compared to 72% at the end of 2017 and only 32% in June 2016. There are signs that borrowers from the energy sector are already enjoying strong investor demand.

Flip This Well: How Fracking Company CEOs Get Rich While Losing Billions – DeSmog (blog) Last year the fracking company Halcón Resources announced a new strategy that was sold as the path to profits for the previously troubled shale oil and gas firm. The company had sold its stake in the Bakken oil fields in order to double down on the Permian shale in Texas. At the time, Reuters touted the deal as a “stunning turnaround” for CEO Floyd Wilson, and the good news immediately drove up the Halcón stock price by 35 percent.“The sale of our Williston Basin operated assets transforms Halcón into a single-basin company focused on the Delaware Basin where we have more than 41,000 net acres,” Wilson said in a statement. He was making his pitch and investors responded.However, the move was part of a familiar formula for those in the shale industry, which uses horizontal drilling and hydraulic fracturing (fracking) to release oil and gas from shale formations: Borrow lots of money, drill lots of fossil fuels at a loss, flip the company for a profit.As the Reuters article points out, Wilson’s ultimate goal is to create excitement about the potential of its Permian basin wells and then flip Halcón, just as he’s flipped other shale firms: “Focusing on the Permian could help Wilson achieve his long-held dream of selling Halcón to the highest bidder.”Wilson made his name in the industry by doing just that three times before. He sold Hugoton Energy to fracking giant Chesapeake Energy for big profits, flipped the company 3TEC to Plains Exploration & Production and then sold his company Petrohawk to energy giant BHP. The latter sale was a big, and necessary, win for Wilson. As one analyst told Dealbook at the time, “Petrohawk tapped practically every source of capital that it could.” When you run out of people willing to lend you money, it is time to flip. Those deals made Wilson a respected oil man and instilled confidence that he would do the same with Halcón.

Trudeau “summons” rare cabinet meeting first thing tomorrow morning – The federal Liberal government is reportedly nearing an agreement that could see Ottawa buy the troubled Trans Mountain pipeline expansion from Kinder Morgan to ensure the controversial Alberta-B.C. project gets built.The deal, designed to kick-start construction that was suspended last month by Kinder Morgan’s jittery investors, could be announced as early as Tuesday morning, when Prime Minister Justin Trudeau has scheduled an urgent cabinet meeting. Prime Minister Justin Trudeau said again Monday that the Trans Mountain pipeline extension is “in the national interest.” New Democrat MP Guy Caron challenged the Liberal government’s plan to cover Kinder Morgan’s losses from delays caused by the B.C. government. Ottawa first offered to indemnify the expansion project but is now likely instead to buy it in full, Bloomberg reported Monday night, citing sources familiar with the talks who spoke on condition of anonymity. The federal government plans to sell the project – the existing line and its expansion – as soon as is reasonable once it’s guaranteed that it will be built, Bloomberg reported. A spokesperson for Finance Minister Bill Morneau told Bloomberg he wouldn’t comment on “speculation.”

Canada likely to “buy” full Trans Mountain Pipeline Project –Canada is likely to buy Kinder Morgan Canada Ltd.’s Trans Mountain oil pipeline and its controversial expansion project in a bid to ensure it gets built amid fierce opposition, according to a person familiar with the talks. Buying the pipeline outright has become increasingly likely and is now the most probable option for the Canadian government, the person said, speaking on condition of anonymity because the discussions are private. The deal, a value for which hasn’t been publicly reported, will be announced as soon as Tuesday when Prime Minister Justin Trudeau’s cabinet meets in Ottawa. A purchase would mark a stunning development for Trudeau’s government — effectively nationalizing the country’s highest-profile infrastructure project until an operator can be found. The project has been beset by legal uncertainty and rising protests from environmental groups and the province of British Columbia. It will be a key test of Trudeau’s bid to balance the environment and the economy by backing the C$7.4 billion ($5.7 billion) pipeline expansion while pushing a national carbon price to reduce greenhouse gas emissions. Canada first offered earlier this month to indemnify the expansion project but is now likely to buy it, along with the existing pipeline that’s been in operation since 1953. The Canadian government plans to sell the project — the existing line and its expansion — as soon as is reasonable once it’s guaranteed that it will be built, the person said. It’s unclear if other Kinder Morgan assets will be included in any sale. In an emailed statement late Monday, the Calgary-based company said it didn’t intend to issue updates “unless and until these discussions have concluded or we’ve reached an agreement that satisfies our two objectives: clarity on the path forward, particularly with respect to the ability to construct through British Columbia, and ensuring adequate protection of our KML shareholders.” The Trans Mountain expansion would almost triple capacity to 890,000 barrels of oil on a line running from Alberta to a terminal near Vancouver. The 980-kilometer (600-mile) expansion is seen by the oil industry as a crucial link to Asian markets, allowing producers to diversify away from the U.S., which takes the vast majority of Canadian oil exports.

Canada set to purchase Kinder Morgan pipeline for $4.5 billion – The Canadian government is planning to buy the Trans Mountain oil pipeline from major energy corporation Kinder Morgan for $4.5 billion in an effort to secure its construction. The controversial project, which would triple the current capacity of the Trans Mountain pipeline and run from the tar sands of Alberta to the Pacific Coast, is a major priority for Ottawa. The pipeline has suffered delays due to opposition from indigenous communities and environmental groups. Alberta and British Columbia have also been at odds over the potential environmental risks of the project. With the Canadian government’s financial and political support, the project is more likely to move forward. The Trans Mountain pipeline expansion project would vastly increase Canada’s ability to export oil to Asia. Canada possesses the world’s third largest oil reserves, but 99 percent of its oil exports are sold in the U.S. While the government’s takeover of the project has reassured its backers that it will be built, with construction starting in August, it also raises the stakes for Ottawa. “It’s a chess move that allows the project to proceed and positions it as a national interest,” infrastructure expert Matti Siemiatycki told the Guardian. “[But] it’s also highly risky because now the government bears the risk.” The government intervention to save the project is based on the idea that investing in oil today will pay off in the future, something that is far from certain. “The pipeline expansion presumes there’s going to be a high demand for oil going forward for decades – but there’s significant risk that that may not prevail because of changing technologies and changing demand,” explained Siemiatycki.

Liberals to buy Trans Mountain pipeline for $4.5B to ensure expansion is built – CBC – The Liberal government will buy the Trans Mountain pipeline and related infrastructure for $4.5 billion, and could spend billions more to build the controversial expansion. Finance Minister Bill Morneau announced details of the agreement reached with Kinder Morgan at a news conference with Natural Resources Minister Jim Carr this morning, framing the short-term purchase agreement as financially sound and necessary to ensure a vital piece of energy infrastructure gets built. ‘When it’s in Canadians’ advantage to know them…then of course that’s going to be fully transparent,’ says Bill Morneau. 8:23 “Make no mistake, this is an investment in Canada’s future,” Morneau said. Morneau said the project is in the national interest, and proceeding with it will preserve jobs, reassure investors and get resources to world markets. He said he couldn’t state exactly what additional costs will be incurred by the Canadian public to build the expansion, but suggested a toll paid by oil companies could offset some costs and that there would be a financial return on the investment. Kinder Morgan had estimated the cost of building the expansion would be $7.4 billion, but Morneau insisted that the project will not have a fiscal impact, or “hit.” The Conservatives’ Shannon Stubbs and the NDP’s Jenny Kwan discuss the government’s pipeline purchase. 8:37 He said the government does not intend to be a long-term owner, and at the appropriate time, the government will work with investors to transfer the project and related assets to a new owner or owners. Investors such as Indigenous groups and pension funds have already expressed interest, he said.

Canada to Buy Controversial Tar Sands Pipeline — The Canadian government plans to spend $4.5 billion Canadian dollars ($3.5 billion) to buy Kinder Morgan’s existing Trans Mountain pipeline and its controversial expansion project that will triple the amount of tar sands transported from Alberta to the coast of British Columbia.The pipeline has been at the center of widespread protests by environmentalists and some Indigenous groups. The announcement was met with condemnation from 350.org organizers, who slammed Prime Minister Justin Trudeau and his government for “turning Canada into a fossil fuel company.”Kinder Morgan halted all non-essential spending the pipeline project last month, citing continuing opposition in British Columbia. The company set a May 31 deadline to get assurances it can proceed with the project without delays.Bill Morneau, the federal finance minister, said in Ottawa Tuesday that the government’s purchase will guarantee the summer construction season for workers and will ensure the project is built to completion.”Our message today is simple – when we’re faced with an exceptional situation that puts jobs at risk, that puts our international reputation on the line, our government’s prepared to take action,” he said.The agreement was approved by the Cabinet this morning and is subject to approval by Kinder Morgan shareholders. The purchase is expected to close this August, he said. Morneau said the government will eventually sell the expanded pipeline back to the private sector.

How Kinder Morgan won a billion-dollar bailout on Canada pipeline (Reuters) – U.S. energy firm Kinder Morgan’s C$4.5 billion sale of an oil pipeline to Canada’s government marked an extraordinary escape from months of fraught negotiations among warring camps of Canadian officials. But even before the bailout, the company had little to lose – despite the C$1.1 billion it has spent so far on a plan to add a second pipeline from Alberta’s oil sands to British Columbia’s coast, according to a Reuters review of the project’s bank financing and oil-shipping contracts with producers reserving space on the proposed line. The documents show Kinder Morgan cut creative deals with lenders and oil producers to shield itself from massive write-downs like the ones taken recently by rivals TransCanada Corp and Enbridge Inc in canceling controversial pipeline projects. The arrangements, which have not been previously reported, gave Kinder Morgan unique leverage in threatening last month to walk away from the project by May 31 unless Prime Minister Justin Trudeau’s government guaranteed a path to construction over the objections of British Columbia officials, environmentalists and some aboriginal bands. The company’s cautious financial planning and hard-ball politicking combined to create a no-lose bet on what might have been one of the oil industry’s riskiest plays, given the volatility of Canadian pipeline politics. The firm’s ultimatum made rescuing its Trans Mountain pipeline expansion a national emergency for Trudeau, thrusting the prime minister into a constitutional crisis over the limits of federal power and a political crisis in refereeing a feud between Alberta and British Columbia. Trudeau argued the project must go forward to alleviate a crude transportation bottleneck that costs Canadian oil producers C$15 billion annually in forgone export revenue. The expansion would nearly triple the flow of crude through Trans Mountain pipelines, to 890,000 barrels per day. Now, in a deal announced Tuesday, Canada will pay Kinder Morgan the C$1.1 billion it has spent and another C$3.4 billion for the existing pipeline and to compensate the firm for giving up the expansion’s potential profits.

The Oil Giant That Outsmarted Trudeau – In a desperate bid to keep its last remaining proposed oil pipeline alive, Canada has decided to buy Kinder Morgan’s Trans Mountain Pipeline system for an estimated C$4.5 billion.Canada will pay Kinder Morgan for the money that the company has already spent on the expansion project as well as for the existing Trans Mountain pipeline, which has a capacity of about 300,000 bpd.Trans Mountain runs from Alberta to British Columbia and the proposed expansion would be a twin line that would triple the system’s carrying capacity to 890,000 bpd. British Columbia has vowed to block the pipeline even though the federal government supports the project. BC’s opposition had nearly killed the project…and still might finish it off despite the gamble by the federal government to nationalize the pipeline system.As Reuters discovered, it appears that Canada has been taken for a ride by Kinder Morgan. The Texas-based pipeline company structured deals in such a way that it couldn’t lose, even if the project stalled. “Kinder Morgan cut creative deals with lenders and oil producers to shield itself from massive write-downs like the ones taken recently by rivals TransCanada Corp and Enbridge Inc in canceling controversial pipeline projects,” Reuters wrote.These deals included requiring oil producers to pay even if the project was blocked by regulatory holdups. Also, the 26 lenders that Kinder Morgan negotiated with agreed to exempt the pipeline company from penalties on loans if the project was delayed or obstructed because of political problems. All of that made Kinder Morgan more than willing to walk away, putting intense pressure on the Canadian government to resolve the dispute. Prime Minister Justin Trudeau first proposed to indemnify the project from risk, but ultimately decided to purchase it outright as the May 31 deadline neared.

Royal Bank of Scotland to stop financing new coal power and oil sands projects – The Royal Bank of Scotland (RBS) has announced new policies to support the transition to a low-carbon economy. As a result, it will now cease financing for all new coal-fired power plants and oil sands projects, along with any oil activities in the Arctic and new thermal coal mines.The move comes as the bank focusses more on funding renewable energy projects in Europe; it has previously announced a commitment to invest £10 billion in the sector over the next two years. It also follows a similar announcements from British banks, including HSBC, which ruled out funding coal and tar sands in April.

Damaging audit of fossil fuel fracking in northern BC surfaces after 4 years – CBC – An audit looking into the practices of gas drillers in northern British Columbia has only just come to light since it was conducted more than four years ago.The report, put together by biologist Dan Webster in April 2014, found that oil and gas companies near Fort Nelson were not consistently following provincial rules to protect declining boreal caribou herds in the area. The Oil and Gas Commission suppressed those findings, alleges the Canadian Centre for Policy Alternatives who recently received a copy of the report.”This audit was submitted to the Oil and Gas Commission,” said Ben Parfitt, a resource policy analyst with the CCPA.”That was the last that anybody heard of it until we received a copy anonymously and started to look into the audit’s findings.” The report was not released to the public or to the Fort Nelson First Nation who had requested a copy. Parfitt said the audit found companies were “systematically” failing to abide by rules set in place by the provincial government in 2011, part of a recovery plan in response to the federal government officially listing boreal caribou as a threatened species in Canada. “They were building gas well pads that were far larger than the rules said they should be,” Parfitt told Carolina de Ryk, the host of CBC’s Daybreak North. “They were building long road corridors and pipeline corridors in straight lines that allowed wolves to very easily spot caribou – they did a number of things that violated the rules.” The commission, a Crown corporation, said in an emailed statement there were concerns with the audit that prevented it being finalized in 2014.

Gas commission sits on results critical of caribou practices: Think-tank — The B.C. Oil and Gas Commission knew in 2014 that gas drillers weren’t consistently following rules to protect threatened boreal caribou herds, but has held the audit report showing those results under wraps, the Canadian Centre for Policy Alternatives alleges.The audit, conducted by a wildlife biologist in April 2014, was a follow-up work in the province’s 2011 recovery plan for seven threatened caribou herds in B.C.’s far northeast. While biologist Dan Webster submitted his results to the commission, it was never released publicly, according to the CCPA. The advocacy group, however, received a copy of the audit report “in an unmarked brown envelope,” said researcher and policy analyst Ben Parfitt. Parfitt said the CCPA forwarded a copy of the report to the Fort Nelson First Nation, which had requested one but never received it. The CCPA released Parfitt’s briefing document May 28. “It’s no surprise, given the circumstances of the audit’s ‘release,’ that the suppressed document shows that, over and over again, companies broke the very modest rules to protect the caribou,” Parfitt wrote in a briefing document. What Webster found included well pads that were built larger than necessary, repeated failures to restore well sites and repeated failures to place visual blocks across roadways and pipeline corridors to protect caribou from their chief predator, the gray wolf. And Parfitt said the leaked report marks the third time in less than a year that the CCPA has gleaned information about concerns with industry operations through Freedom of Information requests or other means that the commission has withheld or delayed releasing.

Fracking report warns over tremors –Fracking on up to half of the land licensed by the Government for shale gas operations could trigger earthquakes, a seismologist has claimed. Former advisor to No 10, Professor Peter Styles, said hydraulic fracturing in former coal mining areas increases the probability of earthquakes on faults that have already been subject to movement through mining. As the Government announced plans to speed up fracking developments by fast-tracking private companies’ planning applications, Professor Styles has called for more rigorous checks to identify the dangers. In his new report, ‘Fracking and Historic Coal Mining: their relationship and should they coincide?’, he said there was a “serious earthquake risk” posed by fracking in former coalfields, because induced tremors would be “dramatically enhanced”. Although the Fylde has no mine workings, the Blackpool area was hit by two induced tremors in 2011 linked to Cuadrilla’s fracking operation at the now abandoned Preese Hall drill site. Prof Styles recommends a 850-metre buffer zone between fracking and any significant natural fractures or faults. There are faults beneath the Fylde.

Total liquid fuels inventories return to five-year averages in the United States and OECD – Global petroleum inventories declined through 2017 and the first quarter of 2018, marking the end of an extended period of oversupply in global petroleum markets that began before the Organization of the Petroleum Exporting Countries (OPEC) November 2016 agreement to cut production. OPEC plans to reconvene on June 22, and markets now appear more in balance, but uncertainty remains going forward. As a result of the November 2016 OPEC supply agreement, which took effect in January 2017, OPEC member countries agreed to reduce crude oil production by 1.2 million barrels per day (b/d) compared with October 2016 levels and to limit total OPEC production to 32.5 million b/d. In addition, Russia agreed to reduce its crude oil production. OPEC extended the agreement in November 2017, with the production cuts remaining in place until the end of 2018. Since the agreement took effect, global oil markets have tightened, which can be seen in the decline in crude oil and other liquids inventories following sustained increases in quarterly global liquid inventories from mid-2014 through most of 2016.Data on global petroleum inventory levels are not collected directly, but changes in global inventories are implied based on the difference between estimates of world production and world consumption. For the United States and for countries in the Organization for Economic Cooperation and Development (OECD), however, inventory estimates are available and can indicate what is happening globally. From January 2017 to April 2018, OECD inventories decreased by 234 million barrels. The United States accounted for more than half of that decline, as U.S. crude oil and other liquids inventories decreased by 162 million barrels over that period. By the end of April 2018, both OECD and U.S. inventory levels were lower than the averages for April 2013 – April 2017.

U.S. record oil exports bite into Russia, OPEC market share in Asia (Reuters) – Record crude oil volumes exported from the United States will be heading to Asia in the next couple of months to take another piece of the market away from Russia and producers in the Organization of the Petroleum Exporting Countries (OPEC). The United States is set to export 2.3 million barrels per day (bpd) in June, of which 1.3 million bpd will head to Asia, estimated a senior executive with a key U.S. oil exporters. Data from the Energy Information Administration shows U.S. oil exports peaked at 2.6 million bpd two weeks ago. [EIA/S] The record outbound volumes come as U.S. crude production hit all-time highs, depressing U.S. prices to discounts of more than $9 a barrel below Brent crude futures on Monday, the widest in more than three years and opening an arbitrage for excess supplies to other markets. WTCLc1-LCOc1 The difference in the key benchmarks was a chance for Asian refiners to reduce light crude imports from the Middle East and Russia after Brent and Gulf prices touched multi-year highs, traders in Asia said. “We’re diversifying a lot to other regions. If Saudi Aramco still doesn’t reduce prices next month and ADNOC (Abu Dhabi National Oil Company) follows, we will increase our U.S. crude purchases,” a Southeast Asian oil buyer said. In Asia, China – led by Sinopec (600028.SS), the region’s largest refiner – is the biggest lifter of U.S. crude. The company, after cutting Saudi imports, has bought a record 16 million barrels (533,000 bpd) of U.S. crude, to load in June, two sources with knowledge of the matter said. India and South Korea are the next biggest buyers in Asia, each lifting 6 million to 7 million barrels in June, sources tracking U.S. crude sales to Asia said. Indian Oil Corp (IOC.NS) bought 3 million barrels earlier this month via a tender, while Reliance Industries (RELI.NS) purchased up to 8 million barrels, the sources said,

Opec and Russia Best Not Poke the Shale Oil Bear – Here’s one under-reported factor that may explain Russian and Saudi Arabian willingness to turn their backs on almost 18 months of Opec oil supply cuts – the spread between Brent crude and West Texas Intermediate has reached its widest level in three years: The simple reason for this is that the shale oil boom has left crude sloshing around the U.S., resulting in a local oversupply. While Brent prices have risen some 14 percent over the past three months, WTI is up just 7.5 percent and Midland crude – the version of WTI priced in the booming Permian basin rather than the benchmark delivery point in Cushing, Oklahoma — is down 4.8 percent. A shortage of pipeline capacity between Midland and Cushing, and then a further shortage of pipeline and port capacity to get U.S. crude onto a hungry global market.T The 713,000 barrel-a-day decline in Opec’s total supply between 2016 and last month can be accounted for almost entirely by the decline in Venezuelan output, which has fallen by about one-third – 718,000 barrels a day – over the period. A further shoe may be about to drop, though: Iran, which added 308,000 barrels over the same period, is facing the prospect of U.S. and global sanctions that could sharply trim its output. A reversal of the 487,000 barrel-a-day cut by Saudi Arabia and Russia would help plug that looming hole in production. There’s a further factor to consider, though, and it relates to what’s happening on the plains of Texas and Oklahoma. The latest period of supply restraint from Opec and Russia has in essence seen them give up market share to onshore North America. The 1.8 million barrels a day that they’ve taken off the market is almost entirely compensated for by the 1.53 million barrels a day of additional unconventional crude production from the U.S., not to mention 640,000 of additional daily barrels that have come out of Canada.

Russia And Turkey Reach Deal On “Southern Stream” Gas Pipeline, Infuriate Washington — One and a half years after Russia and Turkey signed a deal to build the strategic “Turkish Stream” gas pipeline in October 2016, putting an end to a highly contentious period in Russia-Turkish relation which in late 2015 hit rock bottom after the NATO-member state shot down a Russian jet over Syria, on Saturday Russian state energy giant Gazprom and the Turkish government reached a deal on the construction of the land-based part of the Turkish Stream branch that will bring Russian gas to European consumers. According to Reuters, the two counterparts signed a protocol that would allow the construction, which was stalled by a legal rift over gas prices, to go forward. Gazprom and Turkey’s state-owned BOTAS agreed on the terms and conditions of the project, Gazprom said in a statement, adding that the deal “allows to move to practical steps for the implementation of the project.” The actual construction would be carried out by a joint venture called TurkAkim Gaz Tasima which will be owned by Gazprom and BOTAS in equal shares, Gazprom said.Earlier on Saturday, Turkish president Erdogan said that Gazprom and BOTAS resolved a long-running legal dispute over import prices in 2015-2016, and as a result Turkey would gain $1 billion as part of the gas-price settlement reached with Gazprom, in which Turkey and the Russian natgas giant agreed on a 10.25% price discount for gas supplied by Russia in 2015 and 2016.”We agreed on a 10.25% reduction in the price of natural gas in 2015-2016,” Erdogan announced while speaking at a rally on Saturday. “We got our discount. We get about $ 1 billion worth of our rights before the election,” the Turkish President said, as cited by Anadolu Agency. Russia and Turkey officially agreed on the project, which consists of two branches, in October 2016. The first branch will deliver gas to Turkish consumers, while the second one will bring it to the countries in southern and south-western Europe. The European leg is expected to decrease Russia’s dependence on transit through Ukraine. Each of the lines has a maximum capacity of 15.75 billion cubic meters a year. The greenlighting of the Turkish Stream project is sure to infuriate the US which previously announced it was considering sanctions of European firms that would participate in the Nothern Stream Russian gas pipeline.

Russia Just Won Big In The European Gas War — There’s been a lot of talk on both sides of the Atlantic about the U.S. pivot and efforts at locking in natural as market share in Europe. Much of this comes amid President Donald Trump’s so-called American energy independence push as well as both U.S. and several EU members thrust to wean Europe off of geopolitically charged Russian gas.In fact, Trump has pushed for U.S.-sourced LNG to become so much of the EU’s energy security that several European states, particularly Germany, have accused the president of playing energy geopolitics, cloaking American concern for European energy security under the guise and to the benefit of U.S. LNG producers.Now, however, Trump and U.S. LNG exporters will have an even harder time convincing key EU members to offset overreliance on Russian piped gas with U.S. LNG.Last week, Gazprom, the world’s largest gas producer, and the European Commission resolved a seven-year anti-trust dispute after the Russian state-controlled energy giant agreed to change its operations in central and Eastern Europe. Per terms of the deal that was reached on Thursday, Gazprom will be banned from imposing restrictions on how its customers in central and Eastern Europe use gas. Meanwhile, Bulgaria, the Czech Republic, Estonia, Hungary, Latvia, Lithuania, Poland and Slovakia will no longer be banned from exporting gas to another country. These countries originally sought to remedy over pricing problems for Russian gas. Going forward, customers in Bulgaria, Estonia, Latvia, Lithuania and Poland have the right to demand a price in line with those in Germany and the Netherlands. The deal has teeth since these customers can take their complaints to an EU arbitration body if Gazprom fails to live up to terms of the new settlement.

The Battle For Energy Dominance In The Mediterranean — The Eastern Mediterranean is easily one of the most important and hotly contested regions in the world due to several key factors: the Suez Canal is vital to international commerce, militaries of major powers are participating in the Syrian Civil War, and the region hosts two more unresolved conflicts in divided Cyprus and Israel/Palestine. However, recent major gas discoveries may have permanently altered the energy map of the region. If they play their cards right, Egypt, Israel, Lebanon, and Cyprus may soon go from energy importers to major exporters within a fortnight. Four of the six Eastern Mediterranean countries have seen their fortunes change overnight due to these two discoveries. Two countries, however, have been left out: Turkey and Syria. While Damascus remains distracted by its raging civil war, Ankara is desperate for a potential discovery. Turkey’s economy has grown steadily in recent time and its consumption has followed suit, doubling in the last decade to 55.2 bcm in 2017. Lacking any major energy deposits of its own, Ankara has been importing most of its gas from neighbouring countries – notably Russia, Azerbaijan, and Iran. While Turkey has missed out, Egypt has benefitted significantly from these most recent finds. Due to several significant discoveries in the past decades, Cairo had two liquefication terminals, with a capacity of 7.5 bcm, and export pipelines that could transport fuel to Israel and Jordan. However, the enormous growth in domestic consumption and the unexpected early depletion of several fields forced Egypt to stop exports altogether and start importing. The discovery of the mammoth Zohr gas field on the coast has been a gamechanger for Cairo. Egypt will, for the first time in years, not be importing expensive LNG in 2018 as production from the massive offshore field will be ramped up to meet domestic demand.

Africa’s Hidden Oil Hub Grows After Traders Make Millions — For oil traders, there’s no place quite like Saldanha Bay. When prices slumped in 2014, trading houses generated outsize profits by storing millions of barrels of crude in the deep-water harbor north of Cape Town.Now storage facilities at the port — where South Africa built vast concrete bunkers in the 1970s that helped insulate the apartheid regime from United Nations oil sanctions — are expanding.Saldanha could have turned into a white elephant, but it held an unforeseen commercial potential. When a price structure known as contango emerged in the oil market, traders were able to lock in profits by storing crude for future delivery to buyers elsewhere. This happened in 2009 and again four years ago, when companies from Mercuria Energy Group Ltd. to Vitol Group used the site. While those opportunities have evaporated as oil rebounded, the strategic importance of the shipping route around the Cape of Good Hope has grown. “There’s nothing that really compares with Saldanha Bay,” said Joe Willis, a senior research analyst at Wood Mackenzie Ltd., who highlights its accessibility to supertankers plying an ocean highway that connects key markets in Asia, Europe and the Americas. “It’s quite unique in its own right.”After the release of Nelson Mandela and the end of sanctions, South Africa’s Strategic Fuel Fund gradually sold off its reserves and began to lease out Saldanha’s six concrete tanks — which from satellite photos resemble a line of computer chips on a circuit board — to trading companies. About 5.8 million barrels a day of crude moved around the Cape of Good Hope in 2016, and accounted for about 9 percent of all seaborne-traded oil the previous year, according to the U.S. Energy Information Administration.

Maduro Vows To Double Oil Production With Help From OPEC – Venezuelan President Nicolas Maduro has promised to start increasing the crisis-stricken country’s oil production during his second six-year term in office.AFP reports that during his inauguration speech, Maduro said he will seek the help of OPEC to double Venezuela’s oil production, which is currently at 70-year lows and much below its production quota under the OPEC cut agreement. Maduro said the current production rate – about 1.5 million bpd – would need to increase by 1 million barrels daily by the end of this year.Further in his speech, Maduro said that Venezuela will defeat the U.S. sanctions and its economy will reverse its course to a more positive one, admitting, however, that it will be a tough job because of the sanctions and the ruinous state of its oil industry. “I cannot deceive anyone, they are going to create serious difficulties for us, painful difficulties, that we will face gradually — we will defeat them. Trump’s sanctions will be nullified and defeated,” Maduro said. Venezuela has been teetering on the brink of collapse for months now, and the thing that could push it over the edge would be further sanctions from the U.S, whether banning Venezuelan oil exports to Gulf Coast refineries or U.S. light crude exports to Venezuela, which it needs to mix its heavy crude with lighter grades to make it marketable.

Aramco awards Halliburton contract for unconventional gas services (Reuters) – Saudi Aramco said on Sunday it has awarded Halliburton a contract for unconventional gas stimulation services. The contract will “further improve the economics of Saudi Aramco’s unconventional resources programme”, Aramco said in a statement. “The new agreement will provide lump sum turnkey stimulation services which include major hydraulic fracturing and well intervention operations,” Aramco said. Saudi Aramco’s unconventional resources programme covers three areas of Saudi Arabia: North Arabia, South Ghawar and Jafurah/Rub’ al-Khali.

India says it will not follow US sanctions on Iran – India will keep trading with Iran and Venezuela despite the threat of fallout from US sanctions against the two countries, foreign minister Sushma Swaraj said on Monday. Asked at a news conference whether US action against Iran and Venezuela would damage India, Swaraj said the country would not make foreign policy “under pressure”. Earlier this month, US President Donald Trump withdrew the United States from the Iran nuclear deal and ordered the reimposition of US sanctions suspended under the 2015 accord. Swaraj said New Delhi’s position was independent of any other country. “India follows only UN sanctions, and not unilateral sanctions by any country,” she said. India and Iran have long-standing political and economic ties, with Iran one of India’s top oil suppliers. Bilateral trade between India and Iran amounted to $12.9bn in 2016-17. India imported $10.5bn worth of goods, mainly crude oil, and exported commodities worth $2.4bn during that same time period. India has other interests in Iran, in particular a commitment to build the port of Chabahar on the Gulf of Oman. Swaraj met Iranian foreign minister Mohammad Javad Zarif in New Delhi on Monday just weeks after the US’s rejection of the nuclear accord. “Zarif briefed about the discussions that Iran has undertaken with parties to the Joint Comprehensive Plan of Action following the US decision to withdraw from the agreement,” said an Indian government spokesperson in a statement, without elaborating further. India continued to trade with Iran throughout previous sanction periods, but was forced to cut oil imports as sanctions choked off banking channels and insurance cover for tankers.

Japan to consult US, seek easing of Iran oil import curbs: official – Japan will try to avoid any sudden reduction in its Iranian crude oil imports and may seek some form of exemption from the renewed US sanctions regime, an official at the country’s ministry of economy, trade and industry, Daisuke Hirota, said Wednesday. On the sidelines of a conference in Azerbaijan, Hirota, who is principal deputy director at METI’s oil and gas division, played down the prospect for Japan to reduce its imports of Iranian crude, something the Petroleum Association of Japan has said could happen from October. He noted Japan had an exemption from the US and EU-led sanctions regime earlier in the decade. “We continued to import about 170,000 b/d from Iran and now we continue to import from Iran at this level,” he told S&P Global Platts. “We think to continue to get the exemption from the US to keep this amount of imports from Iran.” “Japanese companies don’t want to stop imports suddenly,” he said, adding the US position needed clarifying. “The situation in the US government is drastically changing every day,” he said. “Now we are collecting information and keep in touch with the US government.” “We need to continue to keep imports, and to keep imports from Iran we need to get information and communication with the US government,” he said. Iran’s relatively low-cost crude accounts for around 5% of Japan’s crude oil imports, and is valued by Japanese refiners partly because of its heavier quality, Hirota noted.

There’s No Getting Around Iranian Sanctions – “I personally think none of us will be able to get around it,” Vitol’s chief executive Ian Taylor said last week, commenting on the effects that renewed U.S. sanctions against Iran will have on the oil industry. The sanctions, to go into effect later in the year, have already started to bite. French Total, for one,announced earlier this month it will suspend all work on the South Pars gas field unless it receives a waiver from the U.S. Treasury Department – something rather unlikely to happen. The French company has a lot of business in the United States and cannot afford to lose its access to the U.S. financial system. So, unless the EU strikes back at Washington and somehow manages to snag a waiver for its largest oil company, Total will be pulling out of Iran.Other supermajors have not dared enter the country, so there will be no other pullouts of producers, but related industries will be affected, too, in the absence of a strong EU reaction to the sanctions. For example, Boeing and Airbus will both have their licenses for doing business in Iran revoked, Treasury Secretary Steven Mnuchin said, which will cost them some US$40 billion – the combined value of contracts that the two aircraft makers had won in Iran. Tanker owners are also taking the cautious approach. They are watching the situation closely, anticipating Europe’s move, but acknowledging that the reinstatement could have “significant ramifications” for the maritime transport industry, as per the International Group of PI & Clubs, which insures 90 percent of the global tanker fleet.Everyone is waiting for Europe to make its move even as European companies in Iran are beginning to prepare their exit from the country. Everyone remembers the previous sanctions, apparently, and they don’t want to be caught off guard. But the signals from Europe are for now positive for these companies, of which there are more than a hundred.Earlier this month, an adviser to French President Emmanuel Macron said that Europe’s response to the thread of U.S. sanctions on Iran will be “an important test of sovereignty.” Indeed, unlike the last time there were sanctions against Iran, the European Union did all it could to save the nuclear deal and has signaled it will continue to uphold it.

Iran, global maritime security and the US role in policing international waters — Capitol Crude podcast – Iran threatened to shut down the Strait of Hormuz back in 2012. Now that the US is exiting the Iran nuclear deal, will the threat to shut downthe world’s busiest oil chokepoint return? On the latest episode of Capitol Crude, US Navy Admiral Jonathan Greenert, the Chief of Naval Operationsfrom 2011 to 2015, talks with Meghan Gordon and Brian Scheid about Iran, global maritime security and the US role in policing international waters. (Part 1 of 2.) Part 2: US Navy’s fuel-innovation efforts may never get serious without $100/b oil

China and Russia Push Into Iran, Exploiting Europe’s Caution – – Chinese and Russian state-backed companies are maneuvering to profit from European firms leaving Iran, threatening the Trump administration’s bid to raise economic pressure on Tehran. Their efforts show how Iran’s business landscape has shifted since the Trump administration withdrew from the nuclear pact, which lifted crippling sanctions on Iran in exchange for curbs on its nuclear program, following 17 months of rising pressure. Secretary of State Mike Pompeo has threatened the “strongest set of sanctions in history” if Iran doesn’t rein in its military activities across the Middle East and stop testing long-range missiles. European executives who tried to make inroads in Iran since the Obama administration struck the nuclear deal in 2015 are now concerned Beijing and Moscow will seize an insurmountable advantage in a large, growing market. “What would be not good neither for the U.S., nor for Europe, is if that at the end only Russia and China can do business in Iran,” said Patrick Pouyanné, chief executive of French energy company Total SA, in a speech in Washington after the policy shift this month. China Petroleum & Chemical Corp., or Sinopec, a giant Chinese-state oil company, sent a delegation to Tehran this month to complete a $3 billion deal to further develop a giant Iranian oil field that Royal Dutch Shell PLC was negotiating for until it decided in March the sanctions risk was too great, say Iranian and Western oil executives. That deal, to develop the Yadavaran oil field, would be potentially the biggest foreign investment in a decade. China National Petroleum Corp., another state-owned giant, has an option for the $1 billion investment pledged by Total for a natural-gas development in Iran that the French company is considering leaving because of U.S. sanctions, CNPC and Iran officials say. CNPC is Total’s partner in the project. Chinese companies have also joined with Iranian peers to renovate railways, build metro lines and manufacture cars. Cheap clothing, cookware, consumer electronics and sunflower seeds imported from China have become popular in Tehran’s street markets.Russia has viewed Iran more cautiously as a business partner, but its companies have worked to build ties there. Russia is selling oil-drilling equipment to Iranian energy companies that don’t have access to Western technology.

China May Get World’s Largest Gas Field Because of U.S. Sanctions Against Iran – Iran has threatened to give petroleum giant Total’s stake in the South Pars gas fields to China if the French company could not secure protection from U.S. nuclear-related sanctions. Total signed a $4.8 billion contract to develop phase 11 of the South Pars – by far the world’s largest natural gas field – last July, after the 2015 nuclear deal struck between the U.S., Iran and five other world powers saw a rolling back of sanctions against Iran in exchange for it cutting nuclear production. Trump’s May 8 withdrawal from the nuclear accord, however, has put this investment at risk and Iranian Petroleum Minister Bijan Zanganeh said the state-owned China National Petroleum Corporation (CNPC), which already claims 30 percent of the project, could take the French supercompany’s 50.1 percent stake. “Total has 60 days to negotiate with the U.S. administration while the French government can also use these 60 days to negotiate with the U.S. administration so that Total can stay in Iran,” Zanganeh said in a statement, according to The Financial Times. “If the U.S. administration does not agree with Total staying in Iran, China will replace this company,” he added.

Iran seeks OPEC support against U.S. sanctions (Reuters) – Iran has asked OPEC to support it against new U.S. sanctions and signalled it is not yet in agreement with Saudi Arabia’s views on the possible need to increase global oil supplies, creating potential problems for OPEC at its meeting next month. Iran, the arch-rival of Saudi Arabia, has a history of being difficult at OPEC meetings including in 2015 when the country refused to sign up to OPEC policies, saying it needed to raise output due to the easing of sanctions following Tehran’s accord with major world powers. U.S. President Donald Trump earlier this month pulled out of that nuclear deal with Iran and announced the “highest level” of sanctions against the OPEC member. Iran is the third-largest oil producer in the Organization of the Petroleum Exporting Countries after Saudi Arabia and Iraq. “I would like to … seek OPEC’s support in accordance with Article 2 of the OPEC Statute, which emphasises safeguarding the interests of member countries individually and collectively,” Iranian Oil Minister Bijan Zanganeh said in a letter seen by Reuters. Zanganeh also suggested in the letter that Iran was not in agreement with some OPEC ministers’ recent comments on the oil market. He said some OPEC ministers “have implicitly or unwittingly spoken for the organization, expressing views that might be perceived as the official position of the OPEC.” The energy ministers of Saudi Arabia and Russia said last week they were prepared to ease output cuts to calm consumer worries about supply. Raising output would bring an end to about 18 months of strict supply curbs amid concerns that oil price have risen too far. Oil price have hit their highest since late 2014, rising above $80.50 a barrel this month, but have since eased.