oil prices fell from last week's highs this week, but not before testing another 37 month intraday high on Monday...after rising last week to a 37 month high of $66.14 a barrel, oil prices opened higher and rose to $66.46 a barrel on Monday morning, before pressure from a strengthening dollar and traders expectations of increasing U.S. crude supplies drove prices lower, with contracts of light US oil for March delivery ending the session down 58 cents, or nearly 1 percent, at $65.43 a barrel... oil prices then fell for a second day on Tuesday, driven by a stronger dollar and ongoing evidence of rising U.S. crude output, with US crude falling $1.06, or 1.6 percent, to close at $64.50 a barrel, in a broad-based selloff of stocks, bonds and commodities...oil prices then rose 23 cents to $64.73 a barrel on Wednesday, despite a big jump in US crude stockpiles, as gasoline demand rose while a Reuters survey showed the OPEC members had achieved a 138 percent supply cut (sic)...US oil prices then jumped $1.07 on Thursday to $65.80 a barrel, after Goldman Sachs said oil supply and demand had reached a balance and raised their 6-month Brent oil-price forecast to $82.50 a barrel...oil prices then fell on Friday in the midst of the worst broad market selloff in two years, as the U.S. dollar rose following a strong jobs report, suggesting that the economy was strong enough for the Fed to again raise interest rates, amplifying the ongoing selloff of stocks, bonds and oil, with crude ending down 35 cents at $65.45 a barrel, a loss of roughly 1% for the week...
meanwhile, natural gas prices were much lower this week, partially because prices fell on their own accord, and partially because trading in the February natural gas contract expired, leaving the widely followed front month price quotes referencing the already lower priced March contract...let's walk through how that happened...you might recall that last week we reported that natural gas prices rose more than 30 cents to a 12 month high of $3.505 per mmBTU...that price was for natural gas to be delivered in February, the closest month to which natural gas contracts were then still trading, typically called the "front month", which would be the price you'd get for natural gas by asking google or by going to any website that shows commodity prices...the price for that February contract then rose 12.6 more cents to close at $3.631 per mmBTU before trading in that contract expired on Monday of this week...then, starting Tuesday, the natural gas price you'd get by checking websites that show commodity prices would be for natural gas to be delivered in March, the closest month which was trading at the time...the price for that March contract rose 2.8 cents on Tuesday to close at $3.195 per mmBTU...however, despite the fact that the price of natural gas rose that day, the price quoted on the commodity price sites appeared to fall 43.6 cents, from $3.631 per mmBTU on Monday to $3.195 per mmBTU on Tuesday....that's because, by convention, the actively traded front month price is always quoted as the price of the commodity...now quoting exclusively March contracts, "natural gas prices" then went on to fall 20 cents on Wednesday, 13.9 cents on Thursday, and another penny on Friday to end the week at $2.846 per mmBTU, quite a substantial drop from the 12 month high price quoted last Friday and the even higher price it reached on Monday...to help you visualize how that happened, we'll include a graph that shows the widely quoted daily prices, irregardless of what contract month it references each day:
the above graph is a Saturday screenshot of the live interactive natural gas price graph at Daily FX, an online platform that provides trading news, charts, indicators and analysis of the markets...each bar on the graph represents natural gas prices for one day of trading between August 24th and February 2nd, with green bars representing days when the price of natural gas went up, and red bars representing the days when the price of natural gas went down...for green bars, the starting natural gas price at the beginning of the day is at the bottom of the bar and the price at the end of the day is at the top of the bar, while for red or down weeks, the starting price is at the top of the bar and the price at the close is at the bottom of the bar...also visible on this "candlestick" style graph are the feint grey "wicks" above and below each bar, to indicate trading prices during each day that were above or below the opening to closing price range for that day...
thus for Monday, January 29th, you can see that natural gas prices opened below $3.30 per mmBTU and rose to above $3.66 per mmBTU before closing at $3.631 per mmBTU...then Tuesday, natural gas prices opened much lower but were still green, or up for the day, as the quoted month rolled from February to March...from there, however, it was all downhill, with quoted prices for natural gas falling all the way to $2.846 per mmBTU by the close of Friday, actually down more than 80 cents from their high on Monday...
now, even though more than half of this week's price drop in natural gas was due to the change in the month referenced, there was still a drop of over 32 cents in the March contract itself...that was mostly because the weekly natural gas storage report showed a relatively modest 99 billion cubic feet withdrawal of gas supplies from storage for the week ending Friday, January 26th, leaving 2,197 billion cubic feet of gas still in storage, which the EIA reports is "within the five-year historical range" of gas in storage at this time of year....that simply means that although it's worse than the past 3 years, it's not as bad as the polar vortex year of 2014...still, the 2,197 billion cubic feet we had in storage on January 26th was 526 billion cubic feet, or 19.3% less than was in storage on January 27th of last year, and 425 billion cubic feet, or 16.2% below the five-year average of 2,622 billion cubic feet for the fourth week of the year...but since the price of natural gas had spiked due to last week's withdrawal of 288 billion cubic feet, the 99 billion cubic feet withdrawal was mild by comparison, and hence the market panic subsided and natural gas sold off..
now, to help visualize why the withdrawal of natural gas from storage was below normal this week, we have a graph of daily population-weighted heating degree days nationally up to the date of the natural gas storage report...
the above graph came from a package of natural gas graphs that John Kemp, senior energy analyst and columnist with Reuters, emailed out on Friday; it incorporates heating degree day data from all locations across the US and weighs it by the number of people living in each reporting location to give a population weighted degree day average for the US...degree days are computed by taking the average daily temperature in each location and subtracting that temperature from 65F, the temperature when most buildings are expected to start needing heating...thus, the colder it gets, the greater the number of heating degree days will accumulate, giving utilities and suppliers of heating fuels a heads up as to what the daily demand for heating will be...
on the above graph, the yellow line shows the average degree days needed per capita over the typical US heating season (starting with zero in July) and the red dots show the actual population degree days for each day this heating season of 2017-2018....while those dots are difficult to read and line up, you can orient what the graph shows by noting that the highest number of degree days was on January 1st, when the all time record for natural gas consumption was set...that date looks to be close to 43 degree days, about 17 degree days above normal for that date...but we can also see that for the cluster of the 10 most recent days on this graph - the ten days prior to the release of this week's natural gas storage report, heating needs were below normal nationally over the period...considering that heating needs for at least 5 of those days was 7 or 8 degrees days below normal, it's almost a surprise that we still needed to take 99 billion cubic feet of gas out of storage, in addition to the roughly 525 billion cubic feet of natural gas that was being produced by US wells over the same period...
The Latest US Oil Data from the EIA
this week's US oil data from the US Energy Information Administration, which covers the details for the week ending January 26th, showed that another big reduction in operations at US refineries, combined with another new record in production from US wells and an ongoing increase in oil imports meant that we had surplus crude oil left over for the first time in 11 weeks...our imports of crude oil rose by an average of 389,000 barrels per day to an average of 8,430,000 barrels per day during the week, while our exports of crude oil rose by an average of 354,000 barrels per day to an average of 1,765,000 barrels per day, which meant that our effective trade in oil worked out to a net import average of 6,665,000 barrels of per day during the week, 35,000 barrels per day more than the net imports of the prior week...at the same time, field production of crude oil from US wells rose by 41,000 barrels per day to a weekly record high of 9,919,000 barrels per day, which means that our daily supply of oil from our net imports and from wells totaled an average of 16,584,000 barrels per day during the reporting week..
during the same week, US oil refineries were using 16,013,000 barrels of crude per day, 470,000 barrels per day fewer than they used during the prior week, while 1,001,000 barrels of oil per day were being added to oil storage facilities in the US....hence, this week's crude oil figures from the EIA seem to indicate that our total supply of oil from net imports and from oilfield production was 430,000 more barrels per day less than what refineries reported they used during the week plus what was added to storage...to account for that disparity, the EIA needed to insert a (+430,000) 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"...(how this weekly data is gathered, and the reason for that "unaccounted" oil, is explained here)
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 8,020,000 barrels per day, still 4.3% less than the 8,383,000 barrels per day average we imported over the same four-week period last year....the 1,001,000 barrel per day increase in our total crude inventories came about on a 968,000 barrel per day addition to our commercial stocks of crude oil and a 33,000 barrel per day addition of oil to our Strategic Petroleum Reserve, likely a return of oil that was borrowed from the Reserve during the post Hurricane Harvey emergency, since the Reserve is not authorized to buy oil at this time....this week's 41,000 barrel per day increase in our crude oil production included a 40,000 barrel per day increase in output from wells in the lower 48 states, and a 1,000 barrels per day increase in output from Alaska.....the 9,919,000 barrels of crude per day that were produced by US wells during the week ending January 26th was the highest week on records going back to 1983, 13.1% more than the 8,770,000 barrels per day we were producing at the end of 2016, and 17.7% above the interim low of 8,428,000 barrels per day that our oil production fell to during the last week of June, 2016...
US oil refineries were operating at 88.1% of their capacity in using those 16,013,000 barrels of crude per day, down from 90.9% of capacity the prior week, and down from the wintertime record 96.7% of capacity just four weeks earlier...the 16,013,000 barrels of oil that were refined this week were 9.1% less than the off-season record 17,608,000 barrels per day that were being refined during the last week of December 2017, but were still a bit more than the 15,947,000 barrels of crude per day that were being processed during the week ending January 27th, 2017, when refineries were operating at 88.2% of capacity....
even with the seasonal slowdown in the amount of oil being refined, gasoline production by our refineries was still higher, increasing by 209,000 barrels per day to 9,567,000 barrels per day during the week ending January 26th, after decreasing by 352,000 barrels per day the prior week....for the week, our gasoline production was 5.1% higher than the 9,101,000 barrels of gasoline that were being produced daily during the week ending January 27th of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) fell by 214,000 barrels per day to 4,613,000 barrels per day, after falling by 765,000 barrels per day over the prior three weeks...but even after those four big decreases, the week's distillates production was just 1.4% lower than the 4,677,000 barrels of distillates per day than were being produced during the the fourth week of 2017....
even with the increase in our gasoline production, our gasoline inventories at the end of the week fell by 1,980,000 barrels to 242,060,000 barrels by January 26th, their first decrease in 12 weeks...that was as our domestic consumption of gasoline rose by 347,000 barrels per day to 9,044,000 barrels per day, and as our imports of gasoline fell by 66,000 barrels per day to 509,000 barrels per day, while our exports of gasoline fell by 212,000 barrels per day to 615,000 barrels per day....but even after eleven increases in twelve weeks, our gasoline inventories are still 5.8% lower than last January 27th's level of 257,086,000 barrels, even as they are roughly 4.1% above the 10 year average of gasoline supplies for this time of the year...
with the week's drop in distillates production, our supplies of distillate fuels fell by 1,940,000 barrels to 137,900,000 barrels over the week ending January 26th, the second decrease in distillates supplies in the past seven weeks...that was as the amount of distillates supplied to US markets, a proxy for our domestic consumption, jumped by 623,000 barrels per day to 4,470,000 barrels per day, even as our imports of distillates rose by 333,000 barrels per day to a eight year high of 584,000 barrels per day, and as our exports of distillates fell by 136,000 barrels per day to 1,004,000 barrels per day... after this week’s inventory decrease, our distillate supplies ended up 19.2% lower at the end of the week than the 170,717,000 barrels that we had stored on January 27th, 2017, and roughly 4.2% lower than the 10 year average of distillates stocks at this time of the year…
finally, with the slowdown of our refining, the increase in our oil imports, and with our weekly crude oil production at a record level, our commercial crude oil supplies rose for the first time in 11 weeks and for just the 11th time in the past 46 weeks, increasing by 6,776,000 barrels, from their 34 month low of 411,583,000 barrels on January 19th to 418,359,000 barrels on January 26th....but our oil inventories as of that date were still 15.4% below the 494,762 ,000 barrels of oil we had stored on January 27th of 2017, and 11.2% lower than the 471,344,000 barrels of oil that we had in storage on January 29th of 2016, even they were still 10.2% greater than the 379,473,000 barrels of oil we had in storage on January 30th of 2015, at a time when US supplies of oil had just begun to increase...
This Week's Rig Count
US drilling activity decreased for the fifth time in the past 13 weeks during the week ending February 2nd, as rigs drilling for oil increased while those drilling for natural gas decreased....Baker Hughes reported that the total count of active rotary rigs running in the US was down by 1 rig to 946 rigs in the week ending on Friday, which was still 217 more rigs than the 729 rigs that were deployed as of the February 3rd report of 2017, while it was less than half of the recent high of 1929 drilling rigs that were in use on November 21st of 2014...
the number of rigs drilling for oil rose by 6 rigs to 765 rigs this week, which was also 182 more oil rigs than were running a year ago, while the week's oil rig count remained far 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 7 rigs to 181 rigs this week, which was only 36 more gas rigs than the 145 natural gas rigs that were drilling a year ago, and way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...
drilling activity from platforms in the Gulf of Mexico decreased by 1 rig to 16 rigs this week, which was down from the 21 rigs deployed in the Gulf of Mexico a year ago and the total of 22 rigs offshore nationally a year ago....the week's count of active horizontal drilling rigs was unchanged at 808 horizontal rigs this week, which was still up by 212 rigs from the 596 horizontal rigs that were in use in the US on February 3rd of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...the vertical rig was also unchanged at 66 vertical rigs this week, which was 1 less than the 67 vertical rigs that were in use during the same week of last year....meanwhile, the directional rig count was down by 1 rig to 72 directional rigs this week, which was still up from the 66 directional rigs that were deployed on February 3rd 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 February 2nd, the second column shows the change in the number of working rigs between last week's count (January 26th) and this week's (February 2nd) count, the third column shows last week's January 26th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday 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 for the 3rd of February, 2017...
note that the 3 rig decrease in Wyoming drilling was not in a major basin (although it could have been in the Powder River) so it doesn't show up in the lower table, while the two rig increase in the Haynesville is not noticeable in the count of either Texas or Louisiana, which were both down a rig... the Haynesville increase included one oil directed rig and one natural gas rig, while the Utica shale saw the addition of two new rigs drilling for oil, while a natural gas rig was shut down....with that in mind, scroll down a few paragraphs into the news links below and you'll see that Cabot Oil and Gas is leasing tracts in Richland, Ashland and Knox counties, southwest of Cleveland, with an eye to exploitative drilling....checking our maps of the Utica shale, we note that the Utica is relatively immature in that region of Ohio, meaning that Cabot is likely looking to frack for oil....the combined Utica-Pt Pleasant shale averages 225 feet thick down there, and roughly 2 to 3% of the shale underlying those counties is organic carbon...that contrasts with a combined shale thickness running between 245 and 345 feet in our corner of the state, with an organic content averaging 1 to 2%...
Fairmount Santrol eyes Independence for new corporate HQ, with merger under way - -- Fairmount Santrol, a publicly traded company that mines sand used for fracking in the oil-and-gas industry, could move its corporate offices to Independence on the heels of a merger with another mining business.On Monday, the Ohio Tax Credit Authority approved an eight-year job-creation tax credit valued at $1.46 million to support what's described as a headquarters move and consolidation. As part of the relocation, Fairmount Santrol expects to create 27 jobs - high-paying ones, based on projected new payroll of $6.8 million a year - by the end of 2020. The credit amount will go up or down based on actual hiring. Based in Chesterland, Fairmount Santrol employs 52 people in Geauga County, between its headquarters and another site, with $7.7 million in existing payroll. In December, the company's board of directors signed off on a merger with Unimin Corp., a Connecticut-based minerals company. The merger is scheduled to occur in mid-2018 and is subject to shareholder approvals.In a news release issued late last year, the companies said they planned to pick a headquarters site before the deal closes. The combined company, whose shares will be listed on the New York Stock Exchange, also will maintain regional offices. Independence Mayor Anthony Togliatti said that Fairmount Santrol has been seeking approximately 30,000 square feet of top-shelf office space along the Rockside Road corridor. He wouldn't provide a precise address, saying he hasn't heard that the company's deal is final.
Community questions possible fracking in Richland, Ashland counties - Mansfield News Journal — Community members have formed a tri-county landowners coalition to discuss concerns with a Houston-based company's plans for possible fracking in Richland, Ashland and Knox counties. Frack Free Ohio organizer Bill Baker said the coalition, made up of landowners, formed in response to Cabot Oil and Gas Corporation's initial work in recent months to develop exploratory wells in the area. "This controversial drilling practice has the potential of changing the rural landscape of north central Ohio permanently, and not in a manner that would enhance the inherent beauty of the land nor protect the economic boon provided by farming and tourism that brings tens of thousands of visitors to the area each year," Baker said during a press conference at the Mansfield/Richland County Public Library on Thursday evening. Several of the coalition members raised environmental and safety concerns with the hydraulic fracturing process, including potential leaks from the fracking site into their own water wells or water supply."In the end, where will we have to turn if we have destroyed our basic needs for greed? Will we be better off than before if we allow them in here and we take the money, are we gonna be better off?" said Theresa Clark with Advocates for Local Land. She lives outside Loudonville in Holmes County. "We cannot drink money." Dave Graham with Monroe Township Landowners Coalition said visiting examples of fracking sites in other parts of Ohio, including in Carroll County, was enough to convince him it's not something he wants in his backyard. Rumors have flown in the area in recent months about who has signed leases. A two-page letter dated Dec. 22 was sent to about 4,000 landowners, said Cabot director of external affairs George Stark. The letters were sent to landowners atop Columbia Gas storage facilities in Richland, Ashland and Knox counties to start a conservation with those landowners about Cabot's plans, Stark said. About 80 percent of the letters were sent out in Ashland County.
What the frack? Tri-county coalition takes drilling concerns to the public - - Four groups tasked with protecting land that gas corporations are investigating for exploratory drilling held a press conference Thursday in the community room at the Mansfield/Richland County Public Library. The groups -- Advocates of Local Land (ALL), Hayesville Community on Fracked Gas (HCFG), Clear Fork Landowners Group (CFLG) and Frack Free Ohio -- took turns at the podium addressing a crowd of about 25 people. Property in Richland, Ashland and Holmes County encompassed the focus of the discussion. "This controversial drilling practice has the potential of changing the real landscape of north central Ohio permanently and not in a manner that would enhance the land nor protect the economic boon provided by farming and touring that brings tens of thousands of visitors to the area each year," said Bill Baker, an organizer for Frack Free Ohio. Jayne Moser of the CFLG said she and her husband received a letter from Cabot Oil and Gas along with copies of her original lease with Columbia Gas and an amended lease from Cabot. "We were disturbed by numerous provisions in the amended lease," she said. "The permanence of the lease, the totally inadequate protections in case of environmental accidents, the insulting levels of reimbursement and the loss of control for one's land were just a few of the provisions which led us to determine that this agreement should be opposed." Kevin and Theresa Clark of ALL shared similar frustrations with the idea of fracking in their backyard. "We can't close our eyes," said Theresa. "In the end where will we have to turn if we have destroyed our basic needs for greed? We cannot drink money. They come in here and offer us money to exchange our land, exchange our water, exchange our health and well being in the area. You can't even put a price on that. If there's any risk involved, there's no price for us."
Call on Rep. Edwards to oppose dangerous brine bill - Athens NEWS - A very dangerous piece of legislation is currently being considered by the Ohio House. Rep. Jay Edwards supports Sub. House Bill 393, which would allow oil and gas waste to be “processed” for sale in stores for deicing Ohio roads, sidewalks, and even your own front steps. Athens City Council has already passed a resolution opposing the Senate version (S.B. 165). I urge all Rep. Edwards’ constituents to educate him on the disastrous implications for this dangerous bill.Oil and gas waste can hundreds of toxic ingredients, many undisclosed (thanks to trade secrets and weak Ohio and federal regulation). Most are not subject to government regulation or health standards, although most have known health impacts. In one study by Endocrine Disruption Exchange of 980 products used in oil and gas extraction, 90 percent had at least one known health effect. Nearly half the products contained at least one chemical considered an endocrine disruptor (chemicals that interfere with the endocrine system, including development and reproduction, and which can have severe lifelong effects on sensitive populations, like babies and children, even at extremely low doses). Oil and gas waste is more toxic even than the chemicals used to drill and stimulate wells, as authors of the report cited above documented: Health effects of 40 chemicals and heavy metals studied from New Mexico oil and gas waste evaporation pits “produced a health profile even more hazardous than the pattern produced by the drilling and fracking chemicals.” In fact, “98 percent of the 40 chemicals found in the pits are listed on U.S. EPA’s 2005 CERCLA (Superfund) list and 73 percent are on the 2006 EPCRA List of Lists of reportable toxic chemicals. Of the nine chemicals found to exceed the New Mexico state limits, all are on the CERCLA list and all but one are on the EPCRA List of Lists.”
Commissioners don't want frack waste to be used to treat roads - The Athens County Commissioners planned to send a letter to Athens County’s state legislators on Wednesday opposing Substitute House Bill 393, a bill that its promoters say will encourage the use of brine from oil and gas wells as a road deicer treatment.The Commissioners voted Tuesday to oppose Sub. HB 393, which is a substitute version of an earlier bill. That newer version was approved by the Ohio House of Representatives’ Energy and Natural Resources Committee.Sub. H.B. 393 establishes “conditions and requirements” for the sale of brine from “certain oil or gas operations” as a commodity. The bill also specifies that that brine can only come from a vertically drilled well, and must be processed or recycled to remove “free oil, dissolved volatile organic compounds, and other contaminants” in accordance with an approval order or permit issued by the chief of the Ohio Division of Oil and Gas Resources Management, a division of the Ohio Department of Natural Resources. Under current Ohio law, people are prohibited from disposing of or processing brine without a permit from the aforementioned state agency. Under Sub. H.B. 393, that permit from the chief of that agency is still required, and the person then must demonstrate that use of the brine won’t damage or injure public health, safety or the environment, before being granted approval to sell it.
Wayne National Forest oil, gas leases are being auctioned - Parkersburg News — Two extraction leases for parcels in the Wayne National Forest in Monroe County and in Noble County, both near the boundary of Washington County, are being auctioned with proposals to be opened March 22. The auction is part of the joint effort between the national forest and the Bureau of Land Management to allow access to energy production companies to public lands and generate revenue for the federal agencies and state government. The leases are offered quarterly and the most recent in December, when leases were sold on five parcels in Monroe County totaling just more than 350 acres, generated nearly $1 million, according to the bureau’s Eastern States sale summary records. The successful bidder on all the parcels was Triad Hunter LLC, with an office in Marietta, according to the records. Proceeds from the leases are split with the federal government receiving a 12.5 percent royalty on proceeds from extraction and the state government receiving a minimum of 25 percent of the bonus bid and royalty revenue. The March auction will include about 306 acres in Monroe County, just east of the Washington County line past New Matamoras, and about 40 acres in Noble County. The Noble County leases include stipulations to plug 14 abandoned gas wells and remove two tanks and associated oil field equipment. The sales are opposed by several environmental groups, including the Sierra Club and the Ohio Environmental Council, a coalition of which filed a complaint in federal court in May. The lawsuit alleges that the Forest Service and the BLM failed to adequately assess the environmental impact of oil and gas extraction on public lands in lease offerings. The Wayne National Forest covers about 240,000 acres of land in southeast Ohio, and about 40,000 acres is available for oil and gas leasing.
Quake attributed to natural causes - Marietta Times -- Though the small earthquake Friday was barely noticed by local residents, it was enough to catch the attention of those with political aspirations. The 2.6-magnitude quake was noted by the U.S. Geological Study at 8:20 a.m. just south of Ohio 676 between Hickman and Smith roads in Palmer Township. Werner Lange, a Democratic congressional candidate who plans to run against U.S. Rep. Bill Johnson in the Sixth congressional District, blames the oil and gas industry. “Dangerously close (to) that area is one of the most intense fracking (hydraulic fracturing) operations in the entire nation, and man-made earthquakes directly connected to fracking are on the rise,” said Lange. “The time to impose a moratorium on fracking is now. The time for a full-scale independent investigation into this earthquake is now.” Meanwhile, retired Marietta College petroleum engineering professor Bob Chase noted that no hydraulic fracturing is occurring within the vicinity of the shaker. “Bah, humbug,” said Chase. “There’s no horizontal drilling going on in that area and therefore no hydraulic fracturing there… But there are active faults in Washington County, especially along the rivers and the Burning Spring Anticline.” The Ohio Department of Natural Resources confirmed Tuesday that the earthquake was “natural seismicity.”
Quake attributed to natural causes - Marietta Times -- Though the small earthquake Friday was barely noticed by local residents, it was enough to catch the attention of those with political aspirations. The 2.6-magnitude quake was noted by the U.S. Geological Study at 8:20 a.m. just south of Ohio 676 between Hickman and Smith roads in Palmer Township. Werner Lange, a Democratic congressional candidate who plans to run against U.S. Rep. Bill Johnson in the Sixth congressional District, blames the oil and gas industry. “Dangerously close (to) that area is one of the most intense fracking (hydraulic fracturing) operations in the entire nation, and man-made earthquakes directly connected to fracking are on the rise,” said Lange. “The time to impose a moratorium on fracking is now. The time for a full-scale independent investigation into this earthquake is now.” Meanwhile, retired Marietta College petroleum engineering professor Bob Chase noted that no hydraulic fracturing is occurring within the vicinity of the shaker. “Bah, humbug,” said Chase. “There’s no horizontal drilling going on in that area and therefore no hydraulic fracturing there… But there are active faults in Washington County, especially along the rivers and the Burning Spring Anticline.” The Ohio Department of Natural Resources confirmed Tuesday that the earthquake was “natural seismicity.”
Land sales in the Wayne National Forest worry environmental groups - The Bureau of Land Management Eastern States announced in January that it will be leasing 345 acres of land in the Marietta Unit of the Wayne National Forest for oil and gas manufacturing. Those oil and gas leases could lead to fracking in Ohio’s only national forest. Hydraulic fracturing — or fracking — is a process in which pressurized liquid fractures rock to release gas. Developers who lease the land have up to 10 years to submit an Application for Permit to Drill, which includes a map, drilling plan and other means of obtaining oil and gas, which could include fracking. Although it may provide jobs in the area, fracking can have severe environmental consequences, Ohio University Environmental Studies Outreach Coordinator Loraine McCosker said. The process impacts the local water system because it uses 5 million to 10 million gallons of water per frack, McCosker, said.“There are concerns about the enormous amount of water used for fracking,” Wendy Park, a senior attorney with the Center for Biological Diversity, said. “(Fracking) could dry out animals’ habitats.”Fracking can also pollute water systems in the Wayne National Forest. There are concerns about the large amounts of hazardous chemicals that are used in the fracking process, Park said. “People that depend on water resources and the health of the forest will be affected by fracking operations,” Mathew Roberts, info and outreach director at environmental group UpGrade Ohio, said in a previous Post report. “People are afraid their water could get contaminated.”Transporting the chemicals used in fracking is also a concern for environmental groups. “There’s a massive amount of chemicals being used to produce gas and oil,” Park said. “Transporting chemicals can subject streams to spills, and many of the chemicals being used are toxic.”
Letters to the editor | Sunday, Jan. 28 - Mansfield News Journal – In recent weeks, many residents of the Clear Fork Valley have received a letter from Cabot Oil & Gas. This letter tells those who have an existing lease with Columbia Gas Transmission for the mineral rights on their land, that Cabot has entered into a sublease agreement with Columbia Gas Transmission, LLC. to “explore, and hopefully develop, the potential resources below Columbia’s natural gas storage fields.” Cabot is working together with the same Columbia Gas that acquired some local mineral rights a few years ago through eminent domain in the Clear Fork Valley. Cabot states that leases need to be amended “to allow for pooling and unitization and support oil and gas development … by allowing for horizontal drilling.” Injecting fluids into the horizontal drilling is often referred to as “fracking.” Please know that you are not required to sign the amended lease agreement. If contacted by a Western Land Management agent, feel free to ask for a copy of your original lease and the amended lease agreement from Cabot. As with the original leases, this amended lease is forever, so it is vital to examine closely how these provisions will affect what happens on your land. Area landowners are getting together for an informational meeting in the near future, but in the meantime, don’t be pressured to sign by hearing that your neighbors have signed, or that you will miss out on an opportunity for big money. For questions or more information, please contact CFlandowners@gmail.com. The agreement was written to protect the interests of Cabot Oil and Columbia Gas. The control of your land now and forever into the future is too important to make this decision without more information.
Utopia Pipeline Sending Ohio Valley Ethane to Canada - Wheeling Intelligencer - — After hundreds of eminent domain lawsuits, several route adjustments and at least $500 million worth of investments, Kinder Morgan is pumping Marcellus and Utica shale ethane from the Cadiz area to Michigan for export to Canada via the Utopia Pipeline. Despite continuing efforts to bring a $6 billion ethane cracker to Belmont County, proposals by China Energy to build $83.7 billion worth of petrochemical projects in West Virginia and ongoing construction on the Royal Dutch Shell plant north of Pittsburgh, there is still no end-user for ethane in the Marcellus and Utica region. The Utopia is the latest pipeline to send ethane — drawn from fracked shale wells across Ohio, West Virginia and Pennsylvania — to other regions for processing. The Utopia joins these pipelines in shipping ethane out the Marcellus and Utica area:
- ∫ the Enterprise Products Partners ATEX Express pipeline, which sends ethane to the Gulf Coast;
- ∫ the Sunoco Logistics Mariner East pipeline, which sends ethane to the East Coast for export to Europe; and
- ∫ the Sunoco Mariner West pipeline, which sends ethane northwest to Canada.
The 12-inch diameter Utopia conduit has a current capacity of 50,000 barrels per day, but this volume could eventually be expanded to 75,000 daily barrels. For perspective, West Virginia University Energy Institute Director Brian Anderson recently said Shell ethane cracker set for Beaver County, Pa. will likely consume about 100,000 barrels of ethane each day. He also said the potential PTT Global Chemical project at Dilles Bottom, as initially proposed, would use about 70,000 barrels each day. However, according to the U.S. Energy Information Administration, the nation’s ethane production should reach 1.7 million barrels per day this year. This is an increase of 450,000 barrels per day compared to 2016 yields, so the production increase could leave plenty of ethane in place to run the proposed local petrochemcial projects.The Utopia stretches northwest from the MarkWest Energy Harrison County facilities into Michigan. Plans call for the ethane to then be shipped across the border into Ontario, Canada for cracking by NOVA Chemicals Corp., which already receives ethane from the Mariner West line.
Study Fills in Missing Data on Homes, Schools, Habitats at Risk from Shell's Falcon Pipeline - DeSmog (blog) - At the end of 2017, Shell ran slightly afoul of Pennsylvania state regulators after filing a pipeline permit application to the state and the U.S. Army Corps of Engineers that failed to show sensitive environmental areas in the path of its proposed Falcon ethane pipeline. Now, a concerned nonprofit has pieced together the details Shell should have included (and more), revealing hundreds of homes, schools, streams, and wetlands in the path of the fracking products pipeline. The 97-mile Falcon Ethane project will carry more than 107,000 barrels a day of a flammable plastics precursor to a small town in Pennsylvania where Shell is building an ethane “cracker” facility. In a region poised to be transformed by petrochemical development, this huge plastics plant will superheat the ethane and “crack” it as it manufactures over a million tons per year of tiny plastic beads of ethylene or polyethylene. Shell's pipeline plan lacked maps that would show area creeks, rivers, waterways, and other sensitive areas like wildlife sanctuaries and preserved lands, the state Department of Environmental Protection said after it issued “incompleteness letters” to the plant in October, a local newspaper, The Times Online, reported. Now, in a rare detailed look at this early stage of pipeline planning, the FracTracker Alliance, a nonprofit focused on “the risks of oil and gas development,” has published a Falcon Public Environmental Impact Assessment Project, detailing the impacts and risks the Falcon pipeline will bring to Pennsylvania, West Virginia, and Ohio. FracTracker's analysis found that, assuming the project is built as planned, the Falcon pipeline will cross 319 streams and 174 wetlands and that “550 family residences, 20 businesses, 240 groundwater wells, 12 public parks, 5 schools, 6 daycare centers, and 16 emergency response centers are within potential risk areas.” Those risks include both explosions and vapor leaks. “Should a leak occur, ethane is not easily detected because it is a colorless and odorless gas,” FracTracker Alliance's new site reports. “Slightly heavier than air and extremely flammable, triggers such as ignition of a car engine, cell phones, doorbells, or light switches can provide an effective ignition source if concentrations are high enough.”
Enbridge prepares to replace pipeline in Michigan (AP) — A natural gas distribution company is preparing to replace a pipeline that runs underneath a river in eastern Michigan. Enbridge Energy's Line 5 pipeline cuts through Marysville and the St. Clair River, The Times Herald reported . The company is working to secure the proper state and federal permits for the project, said Paul Meneghini, a senior manager at Enbridge. The line crosses the U.S.-Canadian border so the company must also acquire Canadian permits. Construction likely won't start until the end of next year, Meneghini said. "All dependent on permitting," he said. "But the intent is to move forward as soon as we can, as practical as we can once all the permits are in hand." The work is expected to take about two months to complete. Activists and officials across the state have been calling for the line's decommissioning amid concerns of its condition. The company has seen nothing to spark concern about the line's integrity, Meneghini said. Kellie Randolph lives near the pipeline. She said her family is concerned about the project's timeline. "We were concerned about safety and are still concerned about safety," she said. "Just the concern that it's a pipeline and I don't know what's going to happen with that." Workers will use a drill to tunnel underneath the river for the new pipe. The new pipe will be connected to the existing system on the Canadian side. The current pipeline was laid in 1953 and is 4 to 15 feet (1.22 to 4.57 meters) below the river, Meneghini said. The replacement line will be 30 feet (9.14 meters) or more below the bottom of the river.
Snyder rejects advice to shut down Line 5, extends deal with Enbridge - Gov. Rick Snyder has rejected three recommendations from a state advisory board tied to operation of Enbridge's Line 5 oil pipeline, including one that proposed a temporary shutdown where it crosses the Straits of Mackinac.In a Jan. 26 letter to members of the Pipeline Safety Advisory Board, Snyder thanks them for the resolutions put forward at the board's Dec. 11 meeting before explaining why he is not acting on any of them.Mike Shriberg, executive director of the National Wildlife Federation's Great Lakes Regional Office and member of the Pipeline Advisory Board, criticized the governor's response."Governor Snyder's response to the resolutions which passed his Pipeline Safety Advisory Board appears to be kicking the can down the road while the Great Lakes remain at risk," Shriberg said in a statement. "The state's failure to produce a timely and effective risk and alternatives analysis should not be an excuse for defensiveness and inaction."The December advisory board meeting came in the wake of a new agreement between Enbridge Inc. and the state government, intended to improve safety and transparency issues tied to the 64-year-old twin underwater pipelines crossing the Straits of Mackinac.In an apparent rebuke of that deal, three advisory board resolutions asked for revisions of the agreement, a new analysis of the public need for Line 5 and a temporary shutdown until damage to the pipeline's protective coating can be inspected and repaired. The 645-mile Line 5 pipeline, built in 1953, runs from Superior, Wisc., to Sarnia, Canada, and transports up to 540,000 barrels of light crude oil and natural gas liquids per day. Enbridge has faced harsh scrutiny in recent years from environmental advocates and government officials alike over the viability of the aging pipeline.
Gov. rejects shutdown of great lakes oil pipeline that's losing its coating - Michigan Gov. Rick Snyder has rejected the recommendation of an independent pipeline safety advisory board to shut down an aging crude oil pipeline that has been losing sections of its protective coating where it crosses beneath the Great Lakes.The board called for an immediate, temporary shutdown of the 65-year-old pipeline in December after Enbridge, the Canadian company that owns and operates the line, notified the board that sections of anti-corrosion coating had come off the dual pipelines that run along the bottom of the Straits of Mackinac. Line 5 has had more than two dozen leaks over its lifetime, and there have been concerns about the pipeline's outer coatings, but as recently as March, company officials said the pipelines were in as good of condition as the day they were installed."Line 5 is violating its easement right now because the coating for the pipeline is not intact," said Mike Shriberg, a member of the board and the executive director of the National Wildlife Federation's Great Lakes Regional Office. "They have bare metal exposed to water, and they can't tell us anything significant about the extent of the problem."Snyder downplayed any imminent threat in his January 26 letter to the board."While the coating gaps remain of key concern and must be addressed, review of the recent hydrotest results of Line 5 through the Straits indicate there is not a risk of imminent failure, and that test was done when these coating gaps existed," Snyder wrote. The governor stated that further inspections and repairs could not be completed until summer because of ice on the Straits, which connect Lake Michigan and Lake Huron. He also said: "It is highly unlikely that Enbridge would agree to voluntarily suspend pipeline operation for months pending further external coating inspections and repairs."
As Siberian Gas Awaits US Landing, a Second Ship May Be Coming -- A second tanker carrying Russian natural gas may be on the way to the U.S., following in the footsteps of a ship now sitting near Boston Harbor with a similar cargo. The Gaselys tanker, which has been sitting for two days in the waters outside of Boston, carries liquefied natural gas originally produced in Siberia, according to vessel tracking data. The ship, poised to dock at Engie SA's Everett import terminal, would be the first LNG shipment from anywhere other than Trinidad and Tobago in about three years. Now Engie is poised to pick up a second Russian cargo from northern France that may land in Massachusetts on Feb. 15, according to Kpler SAS, a cargo-tracking company. The tankers would arrive at a time when New England is paying a hefty premium for supplies as pipeline capacity limits flows of cheap shale gas from other parts of the country in the peak demand season. The tanker named Provalys was sailing to France's Dunkirk terminal to pick up LNG on Friday and unload a small amount of it nearby in Belgium before heading across the Atlantic, the cargo tracker said. Engie couldn't be immediately reached for comment about this shipment. Gaselys loaded its cargo at the Isle of Grain terminal near London, where another tanker had unloaded the Russian LNG. French energy giant Engie bought the cargo on the spot market "due to the high natural gas demand during the recent record cold snap," Carol Churchill, a spokeswoman at Engie's Everett terminal said in an email Wednesday. LNG produced from Trinidad was already committed, so Engie looked for uncommitted cargoes with the proper fuel quality that could be delivered by tankers compatible with the Massachusetts terminal, she said. "Boston needs it because there are constraints on pipeline capacity from the Gulf Coast to the Northeast and no one has been able to build pipelines from the shale plays in the Northeast to demand centers,"
Murphy Announces Support for Fracking Ban in the Delaware River Basin | Observer - On Thursday, Gov. Phil Murphy announced that New Jersey would be joining the governors of Pennsylvania, New York and Delaware in support of a ban on hydraulic fracturing—AKA fracking—in the Delaware River Basin. In September of 2017, the Delaware River Basin Commission (DRBC) proposed changes to its regulations that would ban fracking in the watershed and discourage both the export of water for fracking outside the basin and the import of fracking wastewater. New Jersey—under former Gov. Chris Christie—was the only Delaware River Basin state to withhold support by abstaining from the vote. “New Jersey is reversing course,” Murphy said at a news conference on the banks of the Delaware in Phillipsburg, according to NorthJersey.com. “Fracking puts our health and safety and the health and safety of our environment in our communities at risk. It is a direct threat to our water and runs counter to our values.” Fracking—a method of extracting oil and natural gas by injecting highly pressurized liquid into the earth—has been linked to contaminated ground and surface water, air pollution and induced seismic activity. A 2016 Environmental Protection Agency (EPA) report found “scientific evidence of impacts to drinking water resources at each stage of the hydraulic fracturing water cycle.” Murphy’s Thursday announcement was accompanied by a letter to Pennsylvania Gov. Tom Wolf, the chair of the DRBC, pledging to uphold the ban as the DRBC moves toward a permanent decision on fracking. “My administration is resolute in our commitment to protecting the environment and natural resources of the Delaware Rive Basin, and we will not allow dangerous exploratory activities to put them at risk,” the letter reads. “We stand with you and our sister states New York and Delaware in our responsibility to protect the Delaware River Basin.”
Mountain Valley seeks federal permission to start pipeline work in Giles County - In a letter Friday to the Federal Energy Regulatory Commission, an attorney for the Mountain Valley Pipeline asked for what’s called a notice to proceed — the final go-ahead needed before work can start. The request, for parts of the 303-mile pipeline that are in Giles County, is the first of its kind to be made in Virginia. FERC granted a similar request last week for five counties in West Virginia. Mountain Valley wants approval from the agency by Thursday, a date that it has said in court papers must be met in order to satisfy deadlines imposed by federal wildlife protections. However, it’s unclear whether a few remaining regulatory and legal pieces to the puzzle will fall into place for preliminary work to begin by then. A federal judge in Roanoke has yet to rule on Mountain Valley’s attempt to use the controversial process of eminent domain to run the pipeline through private property. More than 200 landowners are fighting the company’s efforts to obtain forced easements through their property. The Virginia Department of Environmental Quality has yet to sign off on erosion and sediment control plans that must be in place before work can begin, a spokeswoman for the agency said late last week. And there’s no guarantee that a final FERC order will come by Thursday; the agency took nearly three weeks to issue the first notice to proceed that Mountain Valley asked for in West Virginia, which was limited to work on access roads and construction yards.
Federal judge puts a pause on Mountain Valley Pipeline construction plans - With just a few hours remaining until Thursday, the day that Mountain Valley Pipeline had hoped to start work on a natural gas pipeline through Southwest Virginia, a judge put a pause to those plans. The decision by U.S. District Court Judge Elizabeth Dillon came during a proceeding in which Mountain Valley had sued nearly 300 property owners who refused to surrender their land for the controversial project. Although the laws of eminent domain give Mountain Valley the power to obtain forced easements for its buried pipeline, Dillon ruled, she rejected the company’s request for immediate access to the parcels. “This is a victory for the landowners along the pipeline, absolutely,” said Stephen Clarke, one of their attorneys. “There’s no way that they [Mountain Valley] can start construction on a vast majority of the properties,” he said — at least not now. Facing a tight deadline to have trees felled along the pipeline’s route by March 31 to meet federal wildlife protections, Mountain Valley executed what’s called a quick-take condemnation. That process might have allowed the company to start work by Thursday on the disputed properties. But first, Mountain Valley was required to demonstrate it could pay the property owners just compensation for the easements — at prices to be determined at trials later, likely well after construction had begun. Such a demonstration would have included paying a bond or deposit with the court. At a hearing earlier this month, Mountain Valley presented appraisals for just nine of the nearly 300 properties, which Dillon said was insufficient information on which to base an appropriate bond amount. “Until MVP can provide a more fulsome basis on which the court can assure that just compensation will be paid, the court cannot allow immediate possession at this time to nearly all of the properties,” Dillon wrote in a 52-page decision released shortly before 6 p.m. Wednesday. The judge gave the company seven days to report back to her with a timeline of how long it might take to conduct more appraisals and gather additional information needed to determine a bond. Only after that happens would Mountain Valley be allowed access to the land it needs in the counties of Giles, Craig, Montgomery, Roanoke, Franklin and Pittsylvania for its 303-mile pipeline. In the meantime, Dillon allowed immediate entry on the nine properties that were appraised, but only after a bond of three times their established value is posted.
First natural gas export terminal opens on East Coast -- Dominion Energy opened the first natural gas export terminal on the East Coast the day after President Trump touted energy exports as a national priority in his State of the Union speech Tuesday night. Dominion announced Wednesday that its Cove Point liquefied natural gas export terminal in Lusby, Md., was beginning production, with Shell providing the natural gas for export into the global market. “Today marks an important day, not just for Cove Point, but for the U.S. LNG industry," said Charlie Riedl, executive director of the trade group Center for LNG. "Cove Point’s production of LNG represents a fast-emerging industry providing thousands of jobs at home and environmental and geopolitical benefits abroad." Trump played up the fact that the U.S. has become a net exporter of natural gas in his Tuesday night address to Congress. The administration also held a meeting with the Mideast nation of Qatar Tuesday about the energy giant's plans to invest in an LNG facility in Texas. The U.S.'s recent status as both a leading oil and natural gas producer as a result of the shale energy boom is attracting investment and making the country a global player across energy markets. The $4 billion Cove Point facility is one of the largest construction projects in Maryland, providing more than 10,000 jobs, with $565 million in payroll, the trade group said. Dominion, which is a large utility based in Virginia that serves the Washington area, confirmed that "construction is complete," and natural gas for processing into liquefied form for export has been brought to the facility. The LNG the facility will produce is destined for Japanese and Indian customers who have signed 20-year contracts to take the fuel.
Obama Alums Are Pushing Fracked Gas Exports. That’s Exactly What Trump Wants -- During his State of the Union address, President Donald Trump exclaimed that the “war on American Energy” had ended and that “we are now an exporter of energy to the world.” What Trump did not say, though, is that several former senior energy officials from the Obama administration — the one Trump said had declared a “war on American Energy” — now either lobby or work as executives for companies making his “energy dominance” agenda possible. At least five of these Obama officials now work for natural gas export companies, four of them for Cheniere and another for Tellurian. One of those Obama alums, former top White House climate and energy staffer Heather Zichal, now sits on the Board of Directors for Cheniere. She also recently was named managing director of corporate engagement for the environmental group The Nature Conservancy. In her book This Changes Everything: Capitalism vs. The Climate, Naomi Klein reveals that The Nature Conservancy actually owns an oil well in Texas and uses the financial earnings which come from it as part of its funding stream. Further, both BP and Chevron sit on The Nature Conservancy's Business Council. As DeSmog previously reported, White House meeting logs show that Zichal met twice with Cheniere officials in 2013 while she was working under Obama. Not only was Cheniere the first company to receive an LNG export permit from the Obama administration in 2012, it was the first to receive such a permit in over 50 years. While E&E News reported that Zichal “served” on the board of directors for Cheniere, company spokesperson Eben Burnham-Snyder confirmed with DeSmog that Zichal still serves on the board. According to forms filed with the U.S.Securities and Exchange Commission (SEC), Zichal earned $90,000 for her service on the board in fiscal year 2016 and another $90,014 worth of stock options, for a total of about $180,000 in compensation. Cheniere CEO Jack Fusco was part of the CEO delegation which accompanied President Trump and U.S. Commerce Secretary Wilbur Ross on their recent trade mission to China. Cheniere also recently signed a Memorandum of Understanding (MOU) with China National Petroleum “on Long-term LNGSale and Purchase Cooperation.”
NC approves Atlantic Coast Pipeline permit through 8 counties -- A key state permit for the Atlantic Coast Pipeline was approved by state regulators Friday, clearing a major hurdle for the interstate natural gas project to move ahead in North Carolina. The state Department of Environmental Quality announced its long-awaited decision more than a year and a half after Duke Energy and other partners filed their application. Opponents immediately vowed legal challenges to try to block the project. The approval for the underground pipeline comes with a number of conditions for testing, monitoring and inspections. “DEQ left no stone unturned in our exhaustive eight-month review,” DEQ Secretary Michael Regan said in the agency’s announcement. “Our efforts have resulted in a carefully crafted permit that includes increased environmental protections, while giving us the tools we need to continue close oversight of this project as it moves forward.” The Atlantic Coast Pipeline has already received several federal permits, as well as approvals from Virginia and West Virginia regulators, leaving North Carolina as the last major hurdle. The project still requires several minor state approvals in North Carolina: an air-quality permit to operate a compressor station in Northampton County, as well as stormwater permits for Nash and Cumberland counties.
Atlantic Coast Pipeline moves forward despite controversy and criticism | McClatchy - U.S. Senator Tim Kaine wants a do-over. The Virginia Democrat has asked the Federal Energy Regulatory Commission to reconsider its approval of the $5 billion Atlantic Coast Pipeline that will ferry fracked natural gas from West Virginia to Virginia and North Carolina. Two of five commission seats were vacant when the panel approved the project by a 2-1 vote in October 2017. Noting the commission is back at full staff, Kaine wants a re-vote saying “there is a real concern about whether the divided rulings by a partial Commission fairly reflect the FERC position.” A handful of environmental groups, property owners and even a North Carolina state agency also want FERC — for various reasons — to reconsider their approval of the project. Along with issues related to greenhouse gasses, eminent domain and damage to wetlands and rivers, opponents also question whether a legitimate economic need exists for the ACP, and numerous other pipelines, that FERC has greenlighted to move natural gas from the Marcellus-Utica shale basin in Ohio, Pennsylvania, and West Virginia. The project also reflects another growing dispute in America: Whether economic development projects have a disparate impact on communities of color.
DC Circuit ruling could shut down pipeline - A federal court may shut down a Southeast natural gas pipeline in a stunning rebuke of government regulators who approved the project. The U.S. Court of Appeals for the District of Columbia Circuit yesterday refused to revisit its 2017 ruling that the Federal Energy Regulatory Commission should have taken a closer look at climate impacts from the Sabal Trail pipeline. As soon as the court issues a formal mandate finalizing the decision, Sabal Trail's federal certificates will be void, and operations will come to a halt. The D.C. Circuit is expected to issue the mandate next week. It's unclear, however, what FERC and pipeline backers could do to attempt to stall the process, and it's possible any interruption in pipeline operations would be short-lived. Still, the court's decision is the strongest legal rebuke of FERC's oversight since the rush to build out natural gas pipelines began several years ago. The case centers on a Sierra Club lawsuit that alleged, among other things, that regulators failed to study greenhouse gas emissions from the burning of natural gas delivered by Sabal Trail and the broader Southeast Market Pipelines Project, which cuts across Alabama, Georgia and Florida. The D.C. Circuit sided with the environmental group in an August 2017 decision that ordered FERC to analyze the issue. In the meantime, the ruling said, underlying project permits would be vacated.
Bayou Bridge Pipeline's controversial construction begins - Construction of the controversial Bayou Bridge oil pipeline has begun at multiple sites on its 163-mile route from St. James Parish to Lake Charles. Energy Transfer, the parent company of the pipeline announced last week that it recently finished a two-year permitting process and immediately set to work. The company declined to provide specifics about construction sites or the timing of construction. The pipeline would eventually connect with the controversial Dakota Access pipeline carrying Bakken oil from North Dakota. Environmental groups opposed to the project say the route imperils the Atchafalaya Basin, considered one of the largest swamps in America, and poses human health risks in dozens of communities. In an email, Energy Transfer called the pipeline an "investment into safe and reliable transportation for energy in our country." Atchafalaya Basinkeeper and other groups filed a lawsuit in federal court to block the pipeline construction permits awarded by the Army Corps of Engineers. The suit contends the corps did not adequately address the project's environmental risks. A state district court judge on Friday (Jan. 26) rejected a separate claim that Energy Transfer should make many of the project's documents publicly available. The judge ruled that Louisiana's public records rules do not apply to private companies.
Judge Rejects Bid to Suspend Louisiana Pipeline Construction (AP) — A federal judge refused Tuesday to order a temporary halt to construction of a crude oil pipeline through a river swamp in south Louisiana, a setback for environmental groups challenging the project. U.S. District Judge Shelly Dick denied the groups' request for a temporary restraining order that would have suspended pipeline construction in the environmentally fragile Atchafalaya Basin pending a hearing next week. Environmental groups sued the U.S. Army Corps of Engineers on Jan. 11. The lawsuit accuses the Corps of violating the Clean Water Act and other environmental laws when it approved a permit for the Bayou Bridge pipeline project in December. The Corps completed an environmental assessment for the project before issuing the permit. The groups' lawsuit claims that review was "plainly inadequate" and ultimately wants the court to vacate the permit. Judge Dick, however, said she reviewed the Corps' 92-page environmental assessment and "cannot find that the Corps was arbitrary and capricious" in its review. "Simply having an opposing opinion, or disagreeing with the mitigation plans imposed, is insufficient to establish a substantial likelihood of success on the merits, especially in light of the high deference that the law requires the Court to afford the Corps," she wrote. Dallas-based Energy Transfer Partners plans to build the 162-mile-long (261-kilometer), 24-inch-wide (60-centimeter-wide) pipeline from Lake Charles to St. James Parish, a path that crosses the basin. Dick scheduled a Feb. 8 hearing for environmental groups' request for a preliminary injunction that would block construction of the pipeline through the basin until their lawsuit can be resolved. In the meantime, the groups had asked for a "short-term delay in construction." The groups didn't ask the court to suspend pipeline work outside the basin.
US refiners talk expansion after reaping billions in tax gains --The biggest independent refiners in the U.S. are lining their pockets with billions of dollars in tax reform windfalls just in time to invest in equipment that meets ever-tightening domestic and global environmental rules, making the “liquid freedom” they export cleaner than ever.“The reduction in the corporate tax rate is a catalyst for incremental investment in the business,” said Gary Heminger, CEO of Marathon Petroleum Corp during the company’s fourth quarter earnings call. Marathon’s 2018 capital investment plan includes $950 million in refining upgrades to make cleaner fuels and export enhancements. Its projects aim to satisfy International Maritime Organization rules that require lower sulfur in distillate by 2020, and U.S. based Tier-3 gasoline standards intended to clean up the air.Valero Energy Corp will pour $1 billion into growth projects this year, including a $400 million refinery unit that churns out octane to make premium gasoline. It now has $1.9 billion in extra spending cash from the Republicans’ tax overhaul.U.S. refiners exported staggering amounts of diesel and gasoline last year, hitting records in both categories while continuing to eye more opportunities to expand. But meeting the stringent rules of IMO 2020 promise double-digit returns on investment, according to Marathon’s Heminger. “And that’s being very conservative on IMO,” he said early Thursday. “We do believe that there is significant upside opportunity with IMO.”
Billions from Trump tax cuts supercharge fossil fuel industries - Oilmen, wildcatters and particularly refiners are reaping billions in gains from President Donald Trump’s tax overhaul, helping boost the staying power of old-style energy even as the world searches for cleaner fuels. The tax adjustments come as crude prices have rallied 54 percent since June. Together, the price rise and the new tax code have supercharged the oil industry in ways that could test the resolve of money managers who’ve vowed to divest from companies that have powered the world’s economic engines for two centuries. The top four refiners this week reaped $7 billion in gains, led by a $2.7 billion jump announced Friday by the biggest, Phillips 66. Meanwhile, the tax overhaul appears to be a mixed bag for solar purveyors and wind farms. They could face higher borrowing costs because the federal tax credits they retain probably won’t be as attractive to large banks that now have lower tax liabilities. “Oil is a resilient industry and it isn’t going away any time soon,” . “Tax reform, in the long run, only increases their profitability.”
'Major' Deep Offshore Oil Discovery Made in US Gulf of Mexico -- Chevron Corporation announced Wednesday that a ‘major’ oil discovery has been made at the Ballymore prospect, located deep offshore in the U.S. Gulf of Mexico. The Ballymore well reached a total measured depth of 29,194 feet and encountered more than 670 feet of net oil pay with ‘excellent’ reservoir and fluid characteristics, Chevron said in a statement on its website. A sidetrack well is currently being drilled to further assess the discovery, which is already deemed commercially viable. “The Gulf of Mexico deepwater is an integral part of our company’s long-term strategy,” Jeff Shellebarger, president of Chevron North America Exploration and Production, said in a company statement. “This discovery is an important addition to our portfolio, especially with its combination of size, quality and proximity to existing infrastructure,” he added. Located approximately three miles from Chevron’s Blind Faith platform, the Ballymore prospect is situated in water depth of about 6,540 feet, 75 miles from the Louisiana coast, and covers four blocks in the Norphlet play. Total, which acquired a 40 percent working interest in Ballymore as part of an exploration agreement with Chevron signed in September 2017, said it was thrilled to reveal its latest find.
Under Rauner, penalties sought against Illinois polluters have plummeted - Well before the Trump administration began shifting responsibility for enforcing environmental laws to the states, Illinois already had slowed down the policing of air and water pollution under Gov. Bruce Rauner. A Tribune analysis of enforcement data shows that since the Republican businessman took office in 2015, penalties sought from Illinois polluters have dropped to $6.1 million — about two-thirds less than the inflation-adjusted amount demanded during the first three years under Rauner’s two predecessors, Democrats Pat Quinn and Rod Blagojevich. Rauner’s enforcement record during the past three years also pales in comparison to the final year in office of the state’s last Republican governor, George Ryan. Adjusted for inflation, the penalties sought since Rauner took office are less than half the amount demanded as Ryan wrapped up his four-year term in 2002. One of the main reasons enforcement is on the decline statewide is the Illinois Environmental Protection Agency has cut back sharply on using its most powerful tool: referring cases to the state attorney general’s office for civil or criminal prosecution. One case that highlights the state’s sluggish enforcement system is unfolding in downstate Champaign County, where natural gas from a Peoples Gas storage facility has seeped into an aquifer that provides drinking water to 850,000 people across a wide swath of central Illinois.In December 2016, shortly after the company alerted the EPA and other regulatory agencies about a leak from one of its gas wells, people living nearby began reporting milky bubbles in well water sputtering from their faucets — a sign of natural gas contamination.Several homeowners in a rural area north of Mahomet said they were able to light their tap water on fire. Despite the obvious threat to the facility’s neighbors and evidence suggesting natural gas might have spread farther into the Mahomet Aquifer, state officials did not refer the case to the attorney general’s office until October 2017.
The potential impact of hydraulic fracturing on streams -- Concerns over hydraulic fracturing, an oil and gas extraction method that injects millions of gallons of freshwater and chemicals into shale, have largely focused on potential impacts on water quality. But, as scientists report in ACS' journal Environmental Science & Technology, "fracking" operations could have impacts on water quantity because they are withdrawing these large amounts of water from nearby streams, which house aquatic ecosystems and are used by people for drinking and recreation. On average, more than 5 million gallons of freshwater is used to fracture one gas well in the U.S. That's more than enough to fill seven Olympic-size swimming pools. Small streams are a major source of water for these operations. Some of these streams also provide drinking water for communities and homes for species with already declining populations. However, little is known about the amount of water that can be sustainably withdrawn from these sources. Sally Entrekin and colleagues wanted to flesh out this picture for the Fayetteville Shale play, an active gas field in Arkansas where more than 5,000 gas wells were drilled using fracking techniques between 2004 and 2014. The researchers estimated the water stress that hydraulic fracturingmight place on streams in the gas field based on water usage and timing for fracturing wells and data on nearby stream flow rates. The streams in the area studied help supply drinking water to thousands of people in the region and are home to 10 aquatic species that are declining at a concerning rate. The team's calculations revealed that freshwater usage for fracking could potentially affect aquatic organisms in 7 to 51 percent of the catchments, depending on the month. If 100 percent of the wastewater were recycled, the potential impact drops, but 3 to 45 percent of catchments could still be affected. The researchers conclude that improved monitoring and access to water withdrawal and streamflow data are needed to ensure protection of streams as drinking water sources and valuable habitat in the future.
5 Million Gallons of Freshwater Used to Frack Just One Well - A lot has been said about the toxic slurry of fracking fluids and its impact on water quality, but what about the millions of gallons of water that's sucked up by the drilling process and its impact on water quantity ? A new study highlights how the five million gallons of freshwater used to fracture just one gas well in the U.S.—or more than enough to fill seven Olympic-size swimming pools—has depleted water levels in up to 51 percent of streams in Arkansas, as Motherboard reported from the research.The paper, published in the American Chemical Society 's journal Environmental Science & Technology, also finds that high-volume, short duration water withdrawals used for fracking fluids creates water stress to aquatic organisms in Fayetteville Shale streams. These streams—which also supply drinking water to thousands of people in the region—are home to 10 aquatic species that are declining at a concerning rate, according to a releaseon the study. Depending on the time of year, freshwater usage for fracking could potentially affect aquatic organisms in 7 to 51 percent of the catchments, the research team found. Even if 100 percent of the fracking wastewater were recycled, between 3 to 45 percent of catchments could still be affected. In the summer especially, drawing out millions of gallons of water from a stream for fracking fluids likely has a significant impact on stream temperatures and stream flow, which affects aquatic insects, fish and bottom-dwelling mussels, the study said. . "Little is known about how much water can be withdrawn from these streams without impacts on fish and other aquatic species," lead author Sally Entrekin, a biologist at University of Central Arkansas, told the publication. "We don't know if there has been an impact on the streams because there isn't any site-specific monitoring," she added.
U.S. crude oil exports increased following hurricane-related refinery disruptions - From late August through September 2017, Hurricane Harvey caused disruptions to the U.S. Gulf Coast refining sector, resulting in record-high U.S. crude oil exports when export facilities reopened after the storm and before many refineries returned to pre-storm levels of utilization. In October 2017, crude oil exports from the United States reached a monthly record of more than 1.7 million barrels per day (b/d). EIA’s Petroleum Supply Monthly data for October 2017 show that the largest increases in U.S. crude oil exports were to Asia, followed by Europe. Exports to Asian countries accounted for 35% of total U.S. exports of crude oil in the first eight months of 2017, averaging 312,000 b/d. In September and October, exports to Asia accounted for 40% of total U.S. exports of crude oil, averaging 636,000 b/d, or more than double their pre-Harvey levels. Similarly, exports to European countries accounted for 22% of total U.S. exports of crude oil in the first eight months of 2017, averaging 193,000 b/d. In September and October, exports to Europe averaged 510,000 b/d, which accounted for 31% of U.S. exports of crude oil. In previous years, Canada received most of the U.S. crude oil exports because it was exempt from restrictions on exporting U.S. crude oil. When certain restrictions on U.S. crude oil exports were lifted in December 2015, U.S. exports of crude oil increased and began reaching more destinations. Aside from Canada, countries in Asia and Europe have been some of the largest recipients of U.S. crude oil since the restrictions were lifted. However, because of the way U.S. Customs and Border Protection export data are reported, some nations listed as receiving crude oil exports from the United States in EIA statistics, such as Singapore and Netherlands, may not be final destinations. Most crude oil exports in October also went to Asia, providing evidence that the marginal competitive market for U.S. crude oil is Asia. According to data in EIA’s Weekly Petroleum Status Report, from late October through the end of 2017, exports of crude oil and inputs to Gulf Coast refineries remained relatively high, resulting in a continued decrease in Gulf Coast crude oil inventories.
Texas oil and gas workforce at 7-year low - Houston Chronicle: The Texas oil industry's attempt to do more with less may have left the state's oil and gas workforce permanently smaller. Since crude prices collapsed more than three years ago, U.S. shale drillers have cut costs, gotten discounts on oil field services and drilled in more prolific sweet spots in an effort to pump more crude at lower costs. Drillers in Texas are on the cusp of beating the state's 45-year-old oil-production record, even though the workforce supporting the oil industry in Texas is about the size it was in 2011. In fact, several measures of economic activity in the Texas oil industry – the number of working rigs, drilling permits, bringing wells into production – have come in pretty low recently, Amarillo economist Karr Ingham said. Seven years ago, as the U.S. economy recovered from a downturn, oil companies had just managed to transfer the technology and techniques that opened up once-inaccessible U.S. shale gas reserves into the nation's oil patches. The workforce was around the same size it is today. By December 2014, the Texas oil and gas workforce grew to its largest size in decades, at about 300,000 employees. But after the oil-market crash, that workforce shrank by more than a third, to 192,000 workers by September 2016. Since then, with higher oil prices supporting Texas drilling activity, the state's oil and gas headcount has grown to only 223,000. But the Texas Petro Index, which tracks the various leading indicators of oil activity, is still well below its peak in 2014, thanks to more efficient oil and gas output. But Texas oil producers are expected to harvest 1.42 billion barrels in 2018, beating the 1972 record of 1.26 barrels. The index "is nowhere close to where it was in late 2014," Ingham said. "What are the chances it's going to get back to that level anytime soon? Pretty slim, frankly."
Exxon plans fivefold rise in Permian Basin shale oil production - ExxonMobil, the largest US energy group, plans to increase its shale oil production in the Permian Basin of Texas and New Mexico fivefold to 500,000 barrels a day in 2025, the company said on Tuesday. It is the latest sign of how large international companies are increasingly pinning their hopes for future growth on “unconventional” resources in North America. Rivals including Chevron and Royal Dutch Shell are also planning for expansion. Exxon has been building up its position in the Permian Basin with a series of acquisitions, including a deal a year ago to buy drilling rights on 250,000 acres from the Bass family for up to $6.6bn. It has also been working to cut production costs, and says it can develop the resources profitably “at a range of prices”. Its development and production costs in the region are less than $15 a barrel of oil and gas, Exxon said. Total oil production in the Permian basin has roughly tripled in the past seven years as a result of the shale boom, from under 1m b/d a day at the start of 2011 to about 2.8m b/d today, and Exxon’s plans suggest there is still potential for many more years of growth. Most US shale companies have struggled for profitability, and the industry as a whole has consistently lost money since the first successful shale oil wells were drilled in 2008-09. Exxon itself lost $439m on oil and gas production in the US in the first nine months of 2017.
Oklahoma is seeing hundreds of earthquakes every year — and a new study found a scarily direct link to fracking - Over the course of a few days in August, Oklahoma was pummeled by seven earthquakes. The wave started on a Tuesday night, when five quakes struck the central part of the state in less than 28 hours. The shaking continued extended into the early hours of Thursday as two more hit. Although none of those quakes was severe enough to cause significant damage, scientists are increasingly concerned about their cause. Rather than emanating from natural tectonic shifts deep inside the Earth, these temblors appear to be the result of human activity. Hydraulic fracturing, more commonly known as fracking, involves jamming water deep into the Earth's layers of rocks to force open crevices and extract the oil or gas buried inside. For several years, researchers have shown a link between wastewater injection, a process that's used to dispose of waste fluids from a number of industrial activities and is similar to fracking, and the incidence of earthquakes in a region, but a new study highlights just how strong that connection is. The authors of the latest paper, published this week in the journal Science, found that they could use the depth of the wastewater injection sites to roughly predict how big the earthquake they caused would be. In other words, the deeper the injection site, the stronger the quake. The researchers were confident enough in their assertions to make a recommendation:"Reducing the depth of injections could significantly reduce the likelihood of larger, damaging earthquakes," Thomas Gernon, an associate professor of earth science at the University of Southampton, wrote in an article for The Conversation.
Oklahoma Quakes Linked to Wastewater Injection Depth - The alarming string of earthquakes that have shaken Oklahoma for years has long been tied to the large volume of fracking wastewater dumped into the state's injection wells. And while state regulators have taken numerous measures to reduce wastewater disposal volumes to prevent such "induced" earthquakes, they might want to consider another measure—restricting how deep wastewater gets sent underground. A new study , published Thursday in the journal Science, finds that Oklahoma's earthquakes can also be triggered by wastewater injection depth. The research was conduced by researchers at the University of Bristol and involved the University of Southampton, Delft University of Technology and Resources for the Future. After analyzing the state's 10,000-plus wastewater injection wells, the researchers concluded that the amount of wastewater injected and the depth are key to understanding the state's unusual seismic activity, the Associated Press reported from the study. Oklahoma regulators could reduce the number of quakes by half by restricting deep injections in the ground, lead author Thea Hincks, an earth scientist at the University of Bristol, told the AP. Wastewater should not be injected within 600 to 1,500 feet of the geologic basement, where earthquake faults can generally be found. The AP reported: "Previous studies had pinpointed the amount of fluids injected into wells as an issue. Gernon said volume does trigger earthquakes, but when volume levels were reduced the number of quakes didn't drop as much as had been expected. That's because where the stuff is put matters slightly more, he said." Oklahoma's wastewater reduction regulations have worked to a certain degree . While the Sooner State has dropped from two quakes a day to less than one a day, the post-regulatory quakes have been large and damaging. Two big ones happened in 2016: the 5.0-magnitude temblor that struck Cushing, one of the largest oil hubs in the world, and a 5.8 that hit near Pawnee, the largest ever recorded in the state.
Chesapeake Energy reportedly lays off about 400 employees - Local news outlets in Oklahoma are reporting that Chesapeake Energy has announced it will lay off hundreds of employees as the debt-burdened natural gas driller continues to overhaul its business.In a letter to employees, Chesapeake said it will let go about 13 percent of its workforce. The Oklahoma City-based company employed 3,247 people as of September, which suggests it will trim back about 400 positions.The layoffs will occur primarily at Chesapeake's Oklahoma City campus.Chesapeake did not immediately respond to requests for confirmation by phone and email.Chesapeake CEO Doug Lawler said the job cuts were the result of asset sales that the company has made in recent years. He explained that Chesapeake did not initially cut staff after selling the assets because it had entered into transition arrangements with buyers, which required workers to remain in their positions.However, with those arrangements coming to an end, Chesapeake needed to "respond accordingly," Lawler said. Chesapeake rose to prominence under founders and shale drilling pioneers Aubrey McClendon and Tom Ward, who borrowed heavily to buy vast swaths of land to produce natural gas. The company has sold off about 25 percent of its wells in recent years in order to shrink its debt load, improve profit margins and operate its business within the confines of its cash flow, Lawler noted in his letter.
Why Is The Shale Industry Still Not Profitable? -- Echoing the criticism of too much hype surrounding U.S. shale from the Saudi oil minister last week, a new report finds that shale drilling is still largely not profitable. Not only that, but costs are on the rise and drillers are pursuing “irrational production.” Riyadh-based Al Rajhi Capital dug into the financials of a long list of U.S. shale companies, and found that “despite rising prices most firms under our study are still in losses with no signs of improvement.” The average return on asset for U.S. shale companies “is still a measly 0.8 percent,” the financial services company wrote in its report. Moreover, the widely-publicized efficiency gains could be overstated, at least according to Al Rajhi Capital. The firm said that in the third quarter of 2017, the “average operating cost per barrel has broadly remained the same without any efficiency gains.” Not only that, but the cost of producing a barrel of oil, after factoring in the cost of spending and higher debt levels, has actually been rising quite a bit. Shale companies often tout their rock-bottom breakeven prices, and they often use a narrowly defined metric that only includes the cost of drilling and production, leaving out all other costs. But because there are a lot of other expenses, only focusing on operating costs can be a bit misleading. The Al Rajhi Capital report concludes that operating costs have indeed edged down over the past several years. However, a broader measure of the “cash required per barrel,” which includes other costs such as depreciation, interest expense, tax expense, and spending on drilling and exploration, reveals a more damning picture. Al Rajhi finds that this “cash required per barrel” metric has been rising for several consecutive quarters, hitting an average $64 per barrel in the third quarter of 2017. That was a period of time in which WTI traded much lower, which essentially means that the average shale player was not profitable. Not everyone is posting poor figures. Diamondback Energy and Continental Resources had breakeven prices at about $52 and $37 per barrel in the third quarter, respectively, according to the Al Rajhi report. Parsley Energy, on the other hand, saw its “cash required per barrel” price rise to nearly $100 per barrel in the third quarter. A long list of shale companies have promised a more cautious approach this year, with an emphasis on profits. It remains to be seen if that will happen, especially given the recent run up in prices.
Interior rolls back oil drilling policies for federal land | TheHill: The Interior Department implemented a new policy Thursday aimed at streamlining the oil and natural gas drilling process on federal land by cutting back on the opportunities for drilling opponents to slow down the process.A memo signed Wednesday and released Thursday by the Bureau of Land Management (BLM) states that it is the agency’s policy to “simplify and streamline the leasing process to alleviate unnecessary impediments and burdens, to expedite the offering of lands for lease,” and to ensure drilling rights sales happen regularly. The changes include setting a 60-day deadline for processing proposed lease sales, leaving public participation in certain reviews up to low-level officials, limiting protest periods for sales to 10 days and repealing an Obama administration policy that let other land users, like hunters and anglers, object. The memo is part of a wide-ranging plan at Interior and elsewhere to tear down barriers to domestic production of oil, natural gas and other fossil fuels. Conservationists slammed the policy change, calling it a threat to the environment and to other users of federal land. “Not only is the administration rolling back safeguards for fish and wildlife and other natural resources, it’s also making it harder for Americans to weigh in on decisions about their own public lands by decreasing opportunities for input,” Tracy Stone-Manning, the National Wildlife Federation’s associate vice president for federal lands, said in a statement. “The headlong rush to prioritize energy development above all other uses is nothing but a giveaway to the oil and gas industry. It’s bad for wildlife, bad for public lands and bad for future generations,” she said.
Trump administration tears down regulations to speed drilling on public land -- The Trump administration is aggressively sweeping aside regulations protecting public land to clear a path for expanded oil and gas drilling. A memorandum from the Interior Department, made public Thursday, directs its field offices “to simplify and streamline the leasing process” so that federal leases to the oil and gas industry can be expedited “to ensure quarterly oil and gas lease sales are consistently held.”According to the memo, which was dated Wednesday, doing so will ease such “impediments and burdens” as months-long environmental reviews that assess the impacts of drilling and potential spills on land and wildlife.The new approach requires the Bureau of Land Management to process a proposed lease within 60 days. Once-mandatory public participation in safety reviews is now left to the discretion of the agency’s field representatives. Public protests of finalized leases will be shortened to 10 days, and a sale can move forward even if disputes are unresolved, according to the memo.Interior also ended “Master Lease Plans” implemented under the Obama administration to give hunters, anglers and groups hoping to protect cultural artifacts a voice in how public land should be managed when parcels are proposed for leasing. The moves are consistent with an executive order President Trump issued in his first days in office to fulfill his campaign goal of “expediting environmental reviews and approvals” to fast-track efforts to fix the country’s roadways and bridges. Trump’s order was later followed by a similar order from Interior Secretary Ryan Zinke.
Utah spent $33 million on a pipeline application it never finished--the feds approved it anyway. -- If you’re hoping to understand Utah’s drive to build the massive Lake Powell pipeline and what it might cost you, don’t start with the state’s explanation of it all to the U.S. government. The thousands of pages Utah produced to justify the 140-mile, multibillion-dollar pipeline from Lake Powell to water districts in two southwestern Utah counties are inscrutable to most involved — the project’s opponents, government regulators, and even some of the people who wrote the documents. “It has been confusing for everyone,” said Jane Whalen, a Hurricane-based environmentalist who has followed the project closely. “Even the lead attorney for the water district seems confused.” Indeed, records obtained by The Salt Lake Tribune indicate those state documents — prepared at a cost of more than $33 million — were part of a decadelong ordeal for the engineers who produced them, particularly in the final months as they feverishly sought to correct years of procrastination and disarray. Now that Utah’s bid for a license to build and operate the Lake Powell pipeline has been cleared for further study, Utah water managers are hoping that they can put the documents’ troubled past behind them. But a new snag has emerged over precisely which federal authorities will approve Utah’s bid, raising prospects of further delays and added costs. If state officials are feeling spooked, it could be because their application is arguably still incomplete — and because one of its major omissions is Utah’s vanished analysis of whether it can actually afford the project. Utah’s leaders have been on a 10-year quest to build the interstate pipeline, meant to draw millions of gallons of Colorado River water out of Lake Powell and pump it through a series of reservoirs and hydroelectric generators for delivery to up to 13 southwestern Utah communities, including St. George.
North Dakota Oil Output on Track to Hit New Record in 2018 -- As per North Dakota’s oil regulator, the state’s daily crude output rose 0.9% in November after climbing 6.9% in the previous month. The North Dakota Department of Mineral Resources’ ("DMR") latest data said that oil production in November averaged 1,194,920 barrels a day, up 11,110 barrels a day from October.Reflecting a healthy increase, the newest numbers confirm the resurgence in volumes extracted from North Dakota, centered on the Bakken Shale formation. As daily output consolidated above 1 million barrels for the tenth month in a row, the state’s total number of producing wells numbered 14,324 at the end of November, a new all-time high. Interestingly, natural gas output was up 1.4% in November to 2,095,342 thousand cubic feet per day – another record – as operators scrambled to the core areas of the Bakken where wells tend to produce more gas along with crude. Some 54 drilling rigs were active in the state in November. The all-time low of 27 was set in May 2016, while a year ago, North Dakota had just 37 rigs operating. A closely watched yardstick of North Dakota oil industry's strength, the year-over-year improvement in the number of units searching for oil and gas in the region indicates essentially steady drilling activities and production. However, the rig count is still down considerably from the peak of May 2012 when North Dakota had 218 units drilling. More rigs in operation and stable production not only confirms the positive developments for the state of North Dakota, but also points to the rising flood of U.S. shale-driven production.Now at a financial equilibrium, the shale firms are putting more rigs and employees back to work. Throughout the downturn, producers (in North Dakota and particularly the Permian Basin in Texas) worked tirelessly to cut costs down to a bare minimum and look for innovative ways to churn out more oil from rock. And they managed to do just that by improving drilling techniques. With these efforts, many upstream companies have repositioned themselves to adapt to the new $50-$60 oil reality and even thrive at those prices. In other words, while OPEC's moves to trim output and rebalance the demand-supply situation has stabilized the market to a large extent, in the process it has incentivized shale drillers to churn out more.
Washington Governor Inslee Rejects Major Oil-by-Rail Project - On Jan. 29, Washington Gov. Jay Inslee rejected a permit required for Tesoro-Savage to build the Vancouver Energy oil-by-rail facility, the largest such project in the nation, at the Port of Vancouver, along the Washington-Oregon border. The governor explained the basis of his decision, which followed a several year long process, in a letter to the state Energy Facility Site Evaluation Council: "When weighing all of the factors considered against the need for and potential benefits of the facility at this location, I believe the record reflects substantial evidence that the project does not meet the broad public interest standard necessary for the Council to recommend site certification."Vancouver Energy, a joint venture of Tesoro and Savage, has not yet commented on the decision but has 30 days to file an appeal. Local environmental groups, however, were quick to applaud the news. "This project was absurdly dangerous and destructive, and Governor Inslee saw these risks clearly," said Dan Serres, conservation director of Columbia Riverkeeper . "The threat of an earthquake or accident creating an oil spill in the Columbia River poses far too great a risk to the Columbia, its salmon and its people." Serres and the governor both outlined why many oil-by-rail projects have been fiercely opposed by local communities: The projects offer huge risks and very little reward for the communities where they are located. The Vancouver Energy terminal would have resulted in oil train traffic hauling more than 131 million barrels of oil along the Columbia Gorge and transferred to ships bound for West Coast refineries. The governor's decision came a week after three rail employees involved in the deadly Lac-Mégantic, Quebec, oil-by-rail disaster were acquitted, a situation which makes the potential risks of moving explosive oil through communities readily apparent.
What Northwestern tribes say about the Jordan Cove pipeline - In 2007, the Canadian company Veresen Inc. applied for a U.S. permit to build a natural gas terminal in Coos Bay, Oregon, and a 229-mile pipeline connecting gas-rich basins in the Interior West to the coast. The proposed pipeline, branching off the existing Ruby Pipeline, raised both job prospects and alarm bells for tribal communities and towns in Oregon, while encouraging export hopes for Colorado, Wyoming and Utah. The Obama administration denied the permit several times, but President Donald Trump’s vision of U.S. energy dominance has given the Jordan Cove LNG project another chance. Veresen reapplied last year and is now undergoing the permitting process under a new Federal Energy Regulatory Commission board. This has renewed concerns over the use of eminent domain, as well as construction impacts on ancestral tribal territory, fragile salmon habitat and forestland. While it’s unclear whether FERC will approve the application (it denied a proposed Energy Department coal policy earlier this year, partly because of climate change concerns), Pacific Northwest tribes have been vocal and actively involved, setting the stage for future battles if the pipeline is approved. With the exception of coastal Oregon tribes, who have remained neutral, most tribes near the proposed route are opposed to it. (infographic map)
5 Ways This Company Misinforms Consumers About Oil Wastewater Use - The Wonderful Company, maker of Halos mandarins and POM products, continues to give consumers misleading information about their use of oil wastewater to irrigate crops. Last October we reported on the response the company gave to consumer concerns. Fast forward over a year since we launched the campaign to tell the company to stop using oil wastewater and the company is still trying to be slick (pun intended). While the company spouts claims of "filtered" we know the waters are murky, so to speak. While The Wonderful Company claims to use " filtered " water, exactly how it is filtered we do not know, and we do not know what chemicals make it through their filters. Part of their process involves blending the water with freshwater, which is designed to reduce the concentration of chemicals, not eliminate them, so it is more than likely that their filtration process is not removing all of the chemicals. The water is tested but not for all the chemicals that we believe are possible in the wastewater. There is also no adequate state oversight of this type of irrigation to ensure the process is safe. Oil wastewater is not gray water, at least not in the way we regard gray water as being recycled water. Gray water is wastewater generated from residential, commercial, and industrial bathroom sinks, bath tub shower drains, and clothes washing equipment drains (excluding water streams from toilets). Instead, oil wastewater is a byproduct of the oil extraction process. As such, it has a very particular exposure to toxic chemicals that would not be expected in normal gray water. There has been extremely limited testing of crops to determine whether it contains toxic chemicals from the oil wastewater; we're working on getting more testing done, along with our campaign to have more (all) of the possible chemicals disclosed. It is hard to test for something without knowing what you are looking for. A recent report examined the chemical additives used in the oil operations that supply wastewater for crop irrigation. The result is alarming. They found that a total of 173 different chemical additives were used in oil and gas fields, of which 38 percent were not sufficiently identified for preliminary hazard evaluation.
Trump: 'I Never Appreciated ANWR' Until Oil Industry Friend Called - The political battle over whether to open the Arctic National Wildlife Refuge ( ANWR ) for oil and gas exploration has raged for decades. Despite the majority of Americans opposing drilling in ANWR, pro-drilling Republicans have tried more than 50 times open up the pristine wilderness to energy development.But President Trump was apparently indifferent to the matter until an oil industry friend told him that past presidents, including conservative icon Ronald Reagan, couldn't get drilling done."I never appreciated ANWR so much," Trump said Thursday during a speech at a Republican retreat in West Virginia. "A friend of mine called up who is in that world and in that business. He said, 'Is it true that you're thinking about ANWR?' I said 'Yeah, I think we're going to get it but you know …' He said, 'Are you kidding? That's the biggest thing by itself. Ronald Reagan and every president has wanted to get ANWR approved.' And after that I said 'Oh, make sure that is in the bill. It was amazing how that had an impact."Congress lifted a 40-year drilling ban on the refuge after the Republican tax reform bill was approved in December. This " backdoor drilling provision ," as environmentalists have dubbed it, was added to the tax reform package to secure the key vote of Alaska Sen. Lisa Murkowski, who introduced the measure and haslong championed the cause.Trump's remarks, however, implied that he was the driving force behind the provision's inclusion. "I really didn't care about it," he said. "Then when I heard that everybody wanted it, for 40 years, everybody tried to get it approved, 'Make sure you don't lose ANWR.'"
U.S. monthly crude oil production exceeds 10 million barrels per day, highest since 1970 - EIA - U.S. crude oil production reached 10.038 million barrels per day (b/d) in November 2017, according to EIA’s latest Petroleum Supply Monthly. November’s production is the first time since 1970 that monthly U.S. production levels surpassed 10 million b/d and the second-highest U.S. monthly oil production value ever, just below the November 1970 production value of 10.044 million b/d. Within the Lower 48 states, November 2017 production reached a record high in Texas at 3.89 million b/d, followed by North Dakota at 1.18 million b/d. Production in the Federal Gulf of Mexico reached 1.67 million b/d, up 14% from the October 2017 level as the region recovered from Hurricane Nate. The production values presented here are based on EIA’s monthly survey of crude oil production, which, for reasons explained in a webinar presented earlier this week, are considered more comprehensive and reliable values of U.S. crude oil production than the preliminary estimates presented in EIA’s Weekly Petroleum Status Report.U.S. crude oil production has increased significantly over the past 10 years, driven mainly by production from tight rock formations including shale and other fine-grained rock using horizontal drilling and hydraulic fracturing to improve efficiency. EIA estimates of crude oil production from tight formations in November 2017 reached 5.09 million b/d, surpassing a previous high of 4.70 million b/d in March 2015. These formations also produce considerable volumes of natural gas associated with the crude oil. Liquid production—both crude oil and condensate—from tight rock currently accounts for about 51% of total production. A decade ago, in November 2008, production from tight formations accounted for only 7% of total U.S. production. Non-tight oil production has been mostly constant over the previous decade. Tight oil production can be sensitive to changing oil prices. After increasing relatively steadily since 2011, tight oil production began to decline after the West Texas Intermediate (WTI) crude oil price decreased from $105 per barrel (b) in June 2014 to a low of $30/b in February 2016. WTI prices were about $60 a barrel in January 2018. Production continued to increase through these price fluctuations in three formations in the Permian Basin—the Spraberry, Bone Spring, and Wolfcamp plays that span parts of western Texas and eastern New Mexico—and in the Bakken formation in the Williston Basin in North Dakota and Montana.
US oil production tops 10 million barrels a day for first time since 1970 - U.S. oil production broke 10 million barrels a day for the first time in 48 years in November, according to new monthly data released by the government on Wednesday.While U.S. production has been rising as prices rose, the 10 million barrel mark is an important milestone that reinforces America's place in the energy big leagues and also its aspiration to use its new oil dominance in diplomacy.The U.S. last produced 10 million barrels a day in November, 1970, just when production peaked before a very long decline, according to U.S. Energy Department monthly data. Unlike 1970, U.S. oil production in 2018 is on an upswing, and U.S. shale and other producers are expected to add more than 1 million barrels a day this year alone for an average production rate government forecasts put at 10.3 million barrels a day."This is significant in market terms, and it's very significant psychologically. The U.S. is back big time as an oil producer and could be by next year the largest in the world. We're one of the big three now, and we could be number one," said Daniel Yergin, vice chairman IHS Markit. Saudi Arabia was producing 10.6 million barrels a day before it cut back production to steady the oil price by reducing new supply, and Russia has been drilling about 11 million barrels a day. The U.S. produced 10.038 million barrels a day in November, and produced 10.044 million in November, 1970. In weekly EIA data that will be revised, the U.S. produced 9.92 million barrels a day last week, up sharply from 8.9 million barrels a day a year ago.
Hydraulically fractured horizontal wells account for most new oil and natural gas wells --In 2016, hydraulically fractured horizontal wells accounted for 69% of all oil and natural gas wells drilled in the United States and 83% of the total linear footage drilled. The combination of horizontal drilling and hydraulic fracturing has increased the rate of recent U.S. crude oil, lease condensate, and natural gas production. Hydraulically fractured horizontal wells became the predominant method of new U.S. crude oil and natural gas development in October 2011, when total footage (in linear feet) surpassed all other drilling and completion techniques. The combination of horizontal drilling and hydraulically fracturing has contributed to increases in crude oil and natural gas production in the United States, which are both expected to reach record levels in 2018. The process involves drilling a well vertically to a certain depth and then bending the path of the drilling until it extends horizontally. Because they are longer, and the drilling process is more complex, a horizontal well is generally more expensive to drill than a vertical well, but it is expected to produce more crude oil and natural gas. Horizontal drilling allows more of the wellbore to remain in contact with the producing formation, increasing the amount of oil or natural gas that can be recovered. This method also results in horizontal wells having more drilled footage than vertical wells—hence total footage drilled using horizontal drilling techniques surpassed vertical footage before the actual number of horizontal wells surpassed the number of vertical wells. In 2016, total drilled footage reached nearly 13 million feet, about 10.7 million of which were hydraulically fractured and horizontally drilled. The length of the horizontal section, or lateral, can range from a few hundred feet to several miles. Hydraulically fractured horizontal wells have accounted for most of all new wells drilled and completed since late 2014. As of 2016, about 670,000 of the 977,000 producing wells were hydraulically fractured and horizontally drilled.
Texas shale tests North Sea crude as oil benchmark (Reuters) - Surging shale oil production in Texas and North Dakota is being felt on trading desks in Chicago, Houston and New York, where a brisk business in West Texas Intermediate crude futures is far outpacing contracts for London-based Brent crude. As the United States approaches a record 10.04 million barrels of daily production, trading volumes of so-called “WTI” futures exceeded volumes of Brent crude in 2017 by the largest margin in at least seven years. A decade ago, falling domestic production and a U.S. ban on exports meant that WTI served mostly as a proxy for U.S. inventory levels. Two changes drove the resurgence of the U.S. benchmark. One was the boom in shale production, which spawned a multitude of small producers that sought to hedge profits by trading futures contracts. Then two years ago, the United States ended its 40-year ban on crude exports, making WTI more useful to global traders and shippers. As U.S. production and exports grow, global firms that increasingly buy U.S. oil are offsetting their exposure by trading in U.S. financial markets. That also gives U.S. shale producers more opportunity to lock in profits on their own production. The U.S. boom has reignited a competition over oil trading that began in the 1980s between two of the world’s biggest exchange operators - Intercontinental Exchange, and the New York Mercantile Exchange, or NYMEX, which was acquired by Chicago-based CME Group in 2008. For ICE and CME, energy represents the second-biggest source of revenue, trailing only stocks and interest rate trading, respectively. ICE is based in Atlanta, but is known for its European contracts after it bought London’s International Petroleum Exchange and its Brent futures contract in 2001. Energy products including WTI brought in $790 million in revenue for CME in 2016, the latest annual data available. Brent crude futures and options alone contributed nearly $300 million to ICE’s revenues in 2016.
Trump hints at energy dominance as US producers cross historic threshold - President Donald Trump said Tuesday that the "war" on American energy is over in a State of the Union speech given as US crude oil output is set to reach levels not seen in more than 47 years.The speech barely touched on energy. Trump did not even mention oil and much of the growth in US output took place while President Obama was still in the White House. But this month, US production is expected to average more than 10 million b/d for the first time since November 1970. The output jump is already altering US foreign relations and bolstering the Trump administration's calls for energy "dominance."But those watching the path of US crude production closely remain uncertain over just how much America's relatively newfound supply wealth benefits future diplomatic efforts and how much influence US producers can possibly have over the ever-growing global oil market. In addition, domestic infrastructure constraints, shifting trade policy, and mounting demand could all blunt the impact of the increase in US output.So, just what does America's breach of the 10 million b/d mean? "It's obviously a symbolic milestone, but it symbolizes the re-emergence of the US as one of the world's energy superpowers," At last week's World Economic Forum in Davos, Switzerland, Russian oil minister Alexander Novak, Saudi oil minister Khalid al-Falih and US energy Secretary Rick Perry shared a stage. Rather than a discussion on efforts to keep foreign crude flowing into the US to dampen potential increases in gasoline prices, the panel focused on the role of US shale in "spoiling" efforts by OPEC, Russia and other producers to cut oil output and the likelihood of more US sanctions aimed at Russia's oil sector. "It's a different conversation now," said Bordoff. This new status as a global energy superpower has augmented the Trump administration's push to for US energy "dominance," a vague move away from the rhetoric of previous administrations to be energy independent.
Exxon to invest over $50 billion after Trump tax cuts -- Exxon's CEO says the oil company will invest more than $50 billion over the next five years to expand its business in the U.S. Chairman and CEO Darren Woods said Monday that the investments are possible because of the company's strength, helped by the recent law that cut taxes on corporations. In a blog on the Exxon website, Woods said that Exxon plans to increase oil production in the Permian basin in Texas and New Mexico, build new manufacturing plants and expand current operations. He said the initiatives will create "thousands" of jobs and increase energy security. "These investments are underpinned by the unique strengths of our company and enhanced by the historic tax reform recently signed into law," Woods said. Exxon reported $11.3 billion in profit in the first nine months of 2017, already far surpassing its earnings for all of 2016 as oil prices recovered from a two-year slump. Still, Exxon profits are down sharply from the $44.9 billion it posted in 2012. Woods said the new investments are in addition to Exxon's $20 billion plan to build refining, chemical and export facilities along the Texas Gulf Coast over 10 years. Last March, the company and President Donald Trump praised each other for making those investments possible, although some of them began more than three years before Trump became president.
Shell profits more than double thanks to soaring oil prices - Oil giant Royal Dutch Shell has hailed a “strong” annual performance after profits more than doubled thanks to the surging cost of crude. The group posted underlying earnings of $15.8bn (£11.2bn) for 2017, up from $7.2bn the previous year. Shell said bottom line profits jumped to $12.1bn, up from $3.5bn in 2016, while fourth quarter underlying earnings rose 140 per cent to $4.3bn. The group’s results have benefited as oil prices have risen past $70 a barrel for the first time in more than three years, boosted by supply curbs from oil cartel Opec, a record run of declines in US crude inventories and a weaker US dollar. The group said its annual earnings, which came in just higher than City expectations, were bolstered by the oil price rally and higher production levels from new oil fields, which offset declines from existing fields as well as its mammoth asset-selling programme.
The end of natural gas is near – Amidst the madness of 2017, a bigger shift was missed than probably any other — right at the commanding heights of the economy: Natural gas fizzled out of the plan for the future.That’s major.Natural gas is no longer a contender or pretender, just a relic of the past, likely to fall as far and as fast as Old King Coal, and maybe faster. This has repercussions for the economy of many states and nations, and the politics of the transition in terms of what we ask for and what we will get.The big signal that got some coverage in the pink pages (FT) and energy-wonk trade press in November was the closure of Siemens and GE’s gas turbine-making capacities. Just to recap for those that missed it, first Siemens, the giant European champion of the electric power revolution, laid off 7,000 workers. It reported that it had a capacity to make 400 100MW gas turbines annually but only had received orders for 110 in 2017. Ouch. Retrain!And then GE: Two weeks later, it laid off 20,000 workers in its gas-related business, including turbine-making teams around the world. Remember, just about five years ago Siemens and GE battled for the gas business of Alstom, the French descendent of the same companies GE came out of in the early 20th century. GE paid $10 billion for it and declared a coup.But now, they’re writing it off. Their strategic choices under Jeff Immelt are being questioned by the market: while the Dow is up about 30 percent over the past 12 months, GE’s stock is down about 45 percent. (Indeed, GE won the "honor" of being the Dow Jones Industrials worst-performing stock of 2017.) If we can build large-scale storage that can do all the functions of a fast-ramping gas turbine in less than six months for less money, there will be no market for gas turbines peaking services.
NYMEX Feb natural gas futures fall 10.9 cents to $3.396/MMBtu ahead of contract expiry - NYMEX February natural gas futures tumbled in profit taking overnight leading up to Monday's open and the contract's roll off the board at the close of business. At 6:52 a.m. ET (1152 GMT) the contract was 10.9 cents lower at $3.396/MMBtu. March futures, set to take the lead position, were 8.0 cents lower at $3.095/MMBtu. February gas picked up 32 cents in total last week after ending higher in four out of the five business days, but sentiment of overbought conditions pervade the market and have since begun to prompt a round of selling despite predominantly bullish fundamentals. Strong withdrawals from stocks of late prompt worries over end-of-season inventories, with the US Energy Information Administration noting that net stock drawdowns over the last four storage report weeks totaled 1,036 Bcf, besting the previous four-week draw record of 980 Bcf that occurred in the period between January 17, 2014, and February 14, 2014, during a polar vortex. Total working gas stocks currently sit at 2,296 Bcf, or 519 Bcf below the year-ago level and 486 Bcf below the five-year average of 2,782 Bcf, after the EIA outlined a 288 Bcf withdrawal for the week ended January 19 that tied as the second-largest stock drawdown since the data collection began. It was above the full range of estimates coming into the day, as well as both the 164 Bcf five-year average pull and a 137 Bcf year-ago draw. The EIA said that if storage draws were to match the five-year average for the remainder of the heating season, working gas stocks would total 1,216 Bcf on March 31, or 29% lower than the five-year average.
NYMEX March natural gas futures up 3.4 cents at $3.201/MMBtu - NYMEX March natural gas futures were on the offensive overnight ahead of the Tuesday, Jan. 30, open, as colder weather in store spelled elevated heating demand and additional large storage draws.At 6:49 a.m. ET (1149 GMT) the contract was 3.4 cents higher at $3.201/MMBtu. Updated National Weather Service outlooks show a wide swath of below-average temperatures encompassing the bulk of the central and eastern US through both the upcoming six- to 10-day and eight- to 14-day periods, hemmed in by bands of average temperatures stretching over a few areas of the South into portions of the Midwest and a small section of the Northwest. Above-average temperatures are called only for much of the West, parts of the west-central US and fringes of the Southeast. Weather as projected suggests stronger demand for heating that would ramp up anew the amount of natural gas drawn from underground storage facilities, following an anticipated slowdown in the pace of stock erosion in the forthcoming inventory data fueled by evidence of diminished demand amid milder weather. The US Energy Information Administration's latest "Natural Gas Weekly Update" for the week ended January 24, much of which will be reflected in the next weekly storage data that will cover the week to January 26, detailed a 19% week on week decline in total US natural gas consumption, as temperatures rose across the contiguous US Total working gas stocks currently sit at 2,296 Bcf, or 519 Bcf below the year-ago level and 486 Bcf below the five-year average of 2,782 Bcf, after the EIA outlined a 288 Bcf withdrawal for the week ended January 19. The reported withdrawal tied as the second-highest stock drawdown on record, putting the two largest weekly withdrawals ever since data collection began in the last three weeks.
NYMEX Mar natural gas ticks higher to $2.900/MMBtu after further steep decline - NYMEX March natural gas futures ticked higher in buying at lows overnight in the US ahead of Friday's open. At 7:10 am ET (1210 GMT) the contract was 4.4 cents higher at $2.900/MMBtu, having shed 13.9 cents the previous day. March gas crumbled for the second consecutive session Thursday after the US Energy Information Administration outlined a net 99 Bcf withdrawal during the week ended January 26 that was below both the average anticipated 102 Bcf draw and the 160 Bcf five-year average pull. Lackluster demand in the subsequent days suggests another modest withdrawal from stocks in the current week as the EIA's latest Natural Gas Weekly Update for the week ended January 31 shows a 2% week-on-week slump in total US gas consumption. Seasonable to colder-than-normal weather in midrange outlooks suggests elevated heating demand and a ramped up rate of weekly storage draws but only briefly, as moderating conditions in longer-range projections suggests renewed demand weakness and a reprise of a slower rate of inventory erosion as winter transitions to spring.
South Africa could turn into major market for US natural gas -- South Africa, the largest producer of greenhouse gas emissions on the African continent, is undergoing an energy transition that will mean demand for natural gas will rise, according to a new report from the Energy Information Administration. “In an effort to reduce [carbon dioxide] emissions, South Africa is planning to diversify its energy portfolio, replacing coal with lower CO2-emitting fuels such as natural gas and renewable sources,” the EIA analysis says.Energy Secretary Rick Perry visited South Africa in October to meet with African leaders about importing more natural gas in 2018, several months before President Trump emphasized energy exports in his first State of the Union speech Tuesday night. Much of the transition to natural gas is being driven by South Africa’s commitment to the Paris Agreement. The country plans for carbon emissions to peak by 2025, remain flat for the next decade, and then begin to drop around 2035, the EIA said. Energy Secretary Rick Perry visited South Africa in October to meet with African leaders about importing more natural gas in 2018.
Why Canada Is The Next Frontier For Shale Oil (Reuters) - The revolution in U.S. shale oil has battered Canada's energy industry in recent years, ending two decades of rapid expansion and job creation in the nation's vast oil sands. Now Canada is looking to its own shale fields to repair the economic damage. Canadian producers and global oil majors are increasingly exploring the Duvernay and Montney formations, which they say could rival the most prolific U.S. shale fields. Canada is the first country outside the United States to see large-scale development of shale resources, which already account for 8 percent of total Canadian oil output. China, Russia and Argentina also have ample shale reserves but have yet to overcome the obstacles to full commercial development. Together, the Duvernay and Montney formations in Canada hold marketable resources estimated at 500 trillion cubic feet of natural gas, 20 billion barrels of natural gas liquids and 4.5 billion barrels of oil, according to the National Energy Board, a Canadian regulator. Canada's shale output stands at about 335,000 bpd, according to energy consultants Wood Mackenzie, which forecasts output should grow to 420,000 bpd in a decade. The pace of output growth could quicken and the estimated size of the resources could rise as activity picks up and knowledge of the fields improves, according to the Canadian Association of Petroleum Producers. Seven Generations and Encana Corp, also based in Calgary, are among leading producers developing the two regions. Global majors including Royal Dutch Shell and ConocoPhillips - who pulled back from the oil sands last year - are also developing Canadian shale assets. Chevron Corp announced its first ever Canadian shale development in the Duvernay in November. Spokesman Leif Sollid called it one of the most promising shale opportunities in North America. ConocoPhillips sees potential for the Montney to deliver significant production and cash flow to the company, executive vice president of production drilling and projects Al Hirshberg said in November. Shell will invest more money this year in the Duvernay than any other shale field except the Permian Basin in West Texas, the most productive U.S. shale play, spokesman Cameron Yost said.
Canada's Trudeau says Kinder Morgan pipeline expansion to proceed: radio (Reuters) - Prime Minister Justin Trudeau said on Thursday his government would ensure Kinder Morgan Canada’s Trans Mountain oil pipeline expansion is built and added the C$7.4 billion ($6 billion) project is not a threat to Canada’s West Coast. Trudeau reiterated the government’s position in two separate radio interviews. His comments came two days after British Columbia proposed new laws that would temporarily ban increased shipments of crude oil through the West Coast province, adding another hurdle to the delayed Trans Mountain expansion project. “That pipeline is going to get built. We will stand by our decision,” Trudeau said in an interview on 630 CHED radio in Edmonton, Alberta. “We will ensure that the Kinder Morgan pipeline gets built.” The Alberta province pledged on Wednesday to sue its western neighbor over the planned legislation, calling on the federal government to step in as it has jurisdiction over inter-provincial infrastructure projects. The federal government approved the expansion in 2016. Kinder Morgan Canada is pushing to start construction on the Trans Mountain expansion, which will nearly triple capacity on the existing 1,147-kilometer (712 mile) line to 890,000 barrels per day. “We know that getting our oil resources to new markets across the Pacific is absolutely essential,” Trudeau said in a separate interview with CBC Radio, also in Edmonton. “We can’t continue to be trapped with the price differential we have in the American market. We need this pipeline and we’re going to move forward with it responsibly like I committed to.” Earlier this month Kinder Morgan delayed the start up of the project, which extends from Alberta’s energy heartland to a port in suburban Vancouver, to December 2020, due to continued difficulty obtaining permits. The project is considered crucial for Canada’s oil industry, but is fiercely opposed by British Columbia, many municipalities, some Aboriginal groups, and environmental activists concerned about possible oil spills.
Refined-Product Delivery And Storage Infrastructure In Mexico, Part 3 -- The opening of Mexico’s refined-products sector to competition after 80 years of Pemex monopoly is spurring the development of new motor fuel-related distribution infrastructure on both sides of the U.S.-Mexico border. A number of these pipelines, rail loading/unloading facilities, storage and other projects aren’t advancing as quickly as their developers may have hoped — replacing the old order with the new is taking time. But the need for new infrastructure is evident. Today, we continue our series on efforts to facilitate the transportation of motor fuels from U.S. refineries to — and within — Mexico, this time focusing on rail-related projects. This is the third episode of our series. In Part 1, we discussed the points that until April 2016, state-owned Petróleos Mexicanos (Pemex) was the only entity that could import gasoline and diesel to Mexico, and that until early 2017, independent/third-party importers could not use Pemex’s refined-product distribution and storage network. We also noted that competition is being introduced to Mexico’s energy markets during a trouble-filled period for Pemex’s six refineries. Due to operational and other problems, the refineries’ production of gasoline and diesel is off sharply, and Mexico has been importing more motor fuels from the U.S. and other sources to keep pace with rising demand. In the first 10 months of 2017, U.S. exports of gasoline to Mexico averaged 377 Mb/d, up 58% from 2015, while U.S. exports of diesel south of the border averaged 232 Mb/d, up 65% over the same two-year period.
Pemex woes, presidential race stall Mexican oil joint ventures (Reuters) - Mexico will likely have trouble finding international oil firms willing to partner with state-owned Pemex due to hefty fees, low oil prices and uncertainty ahead of a presidential election in July, a blow to efforts to reform the energy sector and boost government revenue. The government of President Enrique Pena Nieto enacted a wide-ranging reform in 2013-2014 to encourage foreign investment and end the slide in oil output to multi-year lows. The reform ended Pemex’s 75-year monopoly over the energy sector, which is one of the key generators of revenue for the government. Mexico has opened oil and gas exploration and production to foreign investors, as well as fuel retail in Latin America’s second-largest economy. On Wednesday, Mexico will auction 29 areas in the Gulf of Mexico, the biggest chunk of oil and gas wealth on offer since the reform. The rights were offered to companies including Royal Dutch Shell Plc, Exxon Mobil Corp and China National Offshore Oil Corp, without obliging them to tie up with Pemex. However, Pemex is struggling to achieve another of the reform’s goals - luring foreign oil firms to develop what were considered potentially lucrative oil fields at two offshore sites. Foreign oil firms saw the cost for buying into the joint ventures as high, officials and oil executives said, because the fees include a share of what Pemex has already spent in exploring oil and gas at those fields. Fully transferring exploration costs incurred by the inefficient state-run oil company put the profitability of such partnerships at risk and has been the main obstacle to finding partners, along with the opacity of Pemex’s accounts, the sources said. “Pemex is well known for inefficiency,”
Shell sweeps nine of 19 blocks awarded in Mexico oil auction (Reuters) - Royal Dutch Shell (RDSa.L) snapped up nine of 19 Gulf of Mexico oil and gas blocks awarded in a Mexican auction on Wednesday, as the global oil major raised its big bet on Latin America’s deep waters. Mexican officials estimated the auction, the most important since the country’s energy sector opened to foreign firms in 2014, could bring $93 billion in investment to the country as oil firms develop the areas they won. The stakes were high for Mexican President Enrique Pena Nieto and his struggling party, which wants to showcase the results of its energy liberalization ahead of a presidential election in July. (Graphic: Mexico readies deepwater auction - tmsnrt.rs/2DGpgnB) With oil prices at a three-year high, conditions were better for this auction than any of the previous eight sales in Mexico since 2015, lending weight to Pena Nieto’s argument that opening up the sector would bring the investment needed to turn around a dilapidated state-run oil and gas industry. Shell bid aggressively despite fears that Pena Nieto, who will not run in July, could be succeeded by a leftist leader who may revise the terms of energy contracts. The company also won blocks in Brazil’s Atlantic waters just three months ago, which require heavy investment. Both Mexico and Brazil have benefited from a revival in interest from the world’s top energy firms in big-ticket deepwater projects, as the industry emerges from a three-year recession. “We wanted a presence in both countries,” said Alberto de la Fuente, president of Shell Mexico. “We are a big player in deep water worldwide. This is excellent news for Mexico and is a strong commitment for Shell in Mexico.” The higher oil price helped Shell put together solid bids, de la Fuente said to reporters at the auction. Mexican officials called the auction a success. Ahead of the bid round, the government had said it expected only seven of the 29 blocks on offer to be awarded. In the end, nineteen were awarded. Aside from Shell, the biggest winners were Malaysia’s state oil firm Petronas, which participated in six winning bids, and Qatar Petroleum, which participated in five. Some firms bid alone, and others in consortia.
Touted Energy “Reform” Goes Awry in Mexico - Four years ago, Mexico’s government passed a sweeping energy reform aimed at opening up Mexico’s long-protected oil and gas sectors to global competition and expertise for the first time in over 70 years. The reforms would lead to lower energy prices for domestic consumers as well as thrust Mexico into a more prominent position in the global hydrocarbons market, the government confidently predicted.Instead, the opposite has happened: prices of gas, diesel and natural gas have soared while Mexico’s heavily indebted state-owned energy giant, Petróleos Mexicanos, or Pemex, got tangled up in the oil bust, lost $9 billion in 2016, received a bail-out, and after making money in Q1 and Q2 of 2017, lost another $5.5 billion in Q3 2017. In other words, it has been tough on Pemex.Production at Pemex dropped 9.5% in 2017 to 1.94 million barrels per day, its lowest level since 1980. At the same time 71.6% of the gasoline used by Mexicans last year was imported. It’s a humbling statistic for a country that not so long ago boasted the world’s second biggest oil field by production, the Canterfell. On average, 570,600 barrels per day were bought from abroad in 2017, 60% more than in 2013. Much of it came from the US. As for Diesel, 237,500 of the 317,600 barrels sold each day came from another country — an import rate of 75% — while an average of 67% of the 2,623 million cubic feet of natural gas sold per day was imported from abroad.
Venezuela Skirts U.S. Sanctions With Chinese Oil-For-Cash Loans - Oil-for-loan deals between Beijing and Caracas are preventing American sanctions from having their full effect on Venezuela’s economy, according to David Malpass, U.S. treasury under-secretary for international affairs.“Most of the blame for Venezuela’s economic collapse and humanitarian disaster falls squarely on Venezuela’s rulers, but China has been by far Venezuela’s largest lender, supporting poor governance,” Malpass said at the Center for Strategic and International Studies, Bloomberg reported. “The result will raise the ultimate cost to the international community once Venezuela returns to democracy and economic reforms.”Because China expects payment in barrels of oil, the dollar amount of the loans are difficult to ascertain. “This has the effect of masking the exact amount of payments that China made to Venezuelan officials and that Venezuelans are expected to make to China in the future,” Malpass added. “China offers the appearance to an attractive path to development, but in reality this often involves trading short-term gains for long-term dependency.”China also has an open invitation to join the Community of Latin American and Caribbean States, which the Asian giant could exploit for its One Belt, One Road initiative aiming to bring large developing countries together, economically. Despite assistance from Beijing, Venezuela is still suffering economically. The ongoing crisis in Venezuela has causedoutput to fall and reliable customers to find new supplies. Cuba recently signed a deal with Algeria to increase the amount of oil products it imports from the North African country because its main supplier, Venezuela, is struggling to stay afloat. The country sitting on the world’s largest oil reserves saw its crude oil production drop by 649,000 bpd in 2017—a 29-percent annual plunge—and probably the worst loss of oil production in a single year in recent history.
BP finds North Sea oil and gas at two separate wells — On Wednesday, British energy major BP announced oil and gas discoveries in the North Sea, in a boost for the company and local industry. The discoveries were made in Capercaillie in the central North Sea, and in Achmelvich, west of Shetland, the company said in a statement. BP fully owns the Capercaillie well, while the Achmelvich well is a partnership between operator BP (52.6%), Royal Dutch Shell (28%) and US peer Chevron (19.4%). The Capercaillie well was drilled to 3,750m and found oil and gas. The Achmelvich well was drilled to 2,395m and located oil. "These are exciting times for BP in the North Sea as we lay the foundations of a refreshed and revitalised business that we expect to double production to 200,000 barrels per day by 2020, and keep producing beyond 2050," said Mark Thomas, BP North Sea regional president. "We are hopeful that Capercaillie and Achmelvich lead to further additions to our North Sea business."
BP expects gas to overtake oil as main energy source in 2040 (Reuters) - BP expects gas to overtake oil as the world’s primary energy source in around 2040 as demand for the least polluting fossil fuel grows, its vice president for strategic planning said on Wednesday. “We see it (gas) take over from coal in the early 2030s... We think there is a very good case for gas actually overtaking oil post 2040 or just before 2040,” Dominic Emery told a gas conference in Vienna. Emery highlighted estimates for demand growth for gas in China of around 15 percent year-on-year last year and said BP expects overall gas demand to grow around 1.6 percent a year for years to come, compared with 0.8 percent for oil. “We do see a very strong chance that (gas) is going to be the largest source of primary energy into the future... By gas we mean natural gas, but also ... we mean biogas, we mean biomethane, we mean power-to-gas...” In terms of demand for gas from different sectors, Emery singled out industry as especially resilient and transport as fast-growing, albeit from a low base, at annual rates of three to four percent. BP is due to reveal more details in its next energy outlook on Feb. 20. In its last outlook it said it saw gas overtaking coal’s share in the primary energy market to become the second-largest fuel source by 2035. BP’s previous forecast to 2035 forecast oil’s share shrinking from around 33 percent to around 30 percent and gas’ share grow from the low 20s to the mid 20-percentage range. Emery said one of the biggest challenges for the gas industry was reducing methane leakages from pipelines, which he said was estimated at around 1.3 to 1.4 percent. “Once (methane leakage) exceeds 3 percent it means that gas, certainly in the nearer term, over a few decades, is actually worse than coal from a (greenhouse gas) perspective,” he said.
BP reshapes portfolio to ensure oil assets aren't left undrilled - BP Plc is looking to a future beyond oil as it concedes some crude will be left in the ground. “Not every barrel of oil in the world will get produced,” Bernard Looney, head of the company’s upstream division, said Tuesday. “We’re facing competition from alternative sources of energy like we’ve never had before.” The world’s energy giants face mounting pressure from investors and environmental activists who deem fossil-fuel growth risky as governments tighten climate regulations and renewable sources proliferate. For BP and many of its peers, the prospect of waning demand for crude has prompted an increased focus on natural gas as a bridge toward a cleaner energy future. Gas will be “the fastest-growing hydrocarbon in the world over the next 20 to 30 years,” Looney said at a conference in Florence, Italy. “So you’ll see us shifting and growing our gas position,” among other businesses. BP on Tuesday also announced an investment in electric-car charging company FreeWire. The comments from the upstream chief expand on a warning from BP a year ago, when it said oil supplies will remain abundant in the coming decades and demand may peak in the mid-2040s. Nevertheless, its Chief Economist Spencer Dale in May rejected the notion that the company itself will be left holding assets it can’t drill. Looney’s remarks on Tuesday didn’t repeat that certainty. “We have more oil than the world needs,” he said. “The change is structural. The change is here to stay and competitiveness is, in our view at least, the way forward."
INTERVIEW-BP vows to be tight-fisted despite oil price rally (Reuters) - BP will not change its spending plans because of rising global oil prices and is preparing to approve projects this year that can make money with prices below $40 a barrel, the head of its oil and gas division Bernard Looney told Reuters. Irishman Looney, 46, is seen across the industry as one of the strongest candidates inside BP to succeed Chief Executive Bob Dudley, 62, who is expected to serve at least a few more years in the job. Like its rivals, BP is set to enjoy a strong increase in revenue from the 50 percent rise in oil prices since the middle of last year to around $70 a barrel. But Looney, in a rare interview, said the British company would retain the spending discipline it achieved through deep cost cuts and more efficient work patterns during the three-year downturn from 2014. BP said last year it would have annual capital expenditure of $15-17 billion until 2021. “Discipline has to remain the word and we shouldn’t be seduced by the oil price,” Looney told Reuters on the sidelines of the Baker Hughes conference in Florence. “We’re not going to say that now that the oil prices are back up, let’s do more, let’s spend more,” Looney said. The company, which still faces billions in penalties over the deadly 2010 Deepwater Horizon spill, is now able to generate profit with oil prices in the $50s per barrel, halving the break-even from earlier in the decade. BP will approve more new projects this year, which will all generate profits at oil prices far lower than current levels, Looney said. “You’ll see us continue to invest, but we will always do that when the project meets our threshold and we believe it is the best it can be,” he added. “It has to be resilient in what is a different world and it has got to be built to make money at less than $40 a barrel for sure.”
Hackers Create "Perfect Virus" - Put Oil Companies On Edge -- Russian security services have arrested a local hacker who planted malware at gas stations across Russia’s southern regions that had been cheating drivers out of the gasoline that they pumped in their cars in a major fraud scheme that later resold the stolen fuel. Russia’s Federal Security Service (FSB) have arrested the creator of the malware, Denis Zayev, who had gas stations employees working with him to trick the software systems to selling less fuel to the customers, while reselling the fuel that was stolen. This fraud was one of the largest such scams uncovered by the Russian services, a source in law enforcement told news outlet Rosbalt. The scheme extended to almost all regions in the south of Russia, with dozens of gas stations infected with the malware. Zayev has created a “perfect virus” that couldn’t be detected by either security controls that oil companies have used to remotely monitor gas stations, or by specialists at the Ministry of Internal Affairs, according to the police source who spoke to Rosbalt.The virus planted in the systems allowed the hacker and his accomplices to steal up to 7 percent of the fuel. Zayev acted not only as the “seller” of the malware at some stations, but also as co-owner of the channel to steal fuel, and received a cut from the proceeds from the re-sale of the stolen fuel.
Dutch Gas Rocked By Earthquakes - Dutch gas dreams have ended with a bang after Dutch independent regulator SodM presented its recommendation to the Dutch government to cut existing natural gas production at the Groningen field from 21.6 bcm to a historical low level of 12 bcm. The Netherlands (until the mid-1990s, one of the world’s top natural gas producers and exporters), holding an ambition of becoming the main European gas roundabout, can now start to lick its wounds, as not only gas production at Europe’s largest continental gas field is set to end soon, but the government budget is also hit. Global markets and energy transition can’t be blamed, but only a simple physical phenomenon: earthquakes. The latter hasn’t only shaken houses, but has also broken down the defensive walls of international oil giants Shell (NYSE:RDS.A) and ExxonMobil (NYSE:XOM) and the Dutch government. A popular uprising in the Groningen Province (Northeast Netherlands), combined with an offensive of green movements, has built up a momentum strong enough to end the Netherlands’ pivotal role in global gas. Still, the real discussion is far from over. Not only does the Dutch government need to assess the SodM recommendations, but it also must set up a rational and feasible strategy to wean the Dutch economy and its citizens from natural gas in the coming years. This will be an enormous task. Removing natural gas from Dutch society is shaking its societal structure, as more than 7 million households are on the gas network, and almost all industries in the Netherlands rely on gas supplies. At the same time, due to the fact that Groningen gas opened up the European continent to a gas-based future in 1953, existing long-term contracts with customers in Germany, Belgium and the north of France have still to be fulfilled. The government and its main stakeholders, Gasunie en GasTerra, will have to discuss a reduction in export volumes and contracts the coming years. Some even have called to put a point on the horizon to end exports totally. The cost of this all will be enormous. After decades of a Dutch disease, an earthquake migraine is the only thing that is left.
US says planned Russian pipeline would threaten European energy security (Reuters) - The United States sees the planned Nord Stream 2 gas pipeline between Russia and Germany as a threat to Europe’s energy security, U.S. Secretary of State Rex Tillerson said on Saturday. Poland, Ukraine and Baltic states fear the pipeline would increase Europe’s dependence on Russian gas and provide the Kremlin with billions of dollars of additional revenue to finance a further military build-up on European Union’s borders. “Like Poland, the United States opposes the Nord Stream 2 pipeline. We see it as undermining Europe’s overall energy security and stability,” Tillerson said at a joint news conference with the Polish foreign minister in Warsaw. “Our opposition is driven by our mutual strategic interests,” he said. The United States has already sanctioned Russian companies over Moscow’s involvement in the Ukraine crisis, and foreign companies investing in or helping Russian energy exploration. Poland, an EU member since 2004, sees Russia as its biggest potential threat, especially since Moscow annexed the Crimean peninsula from neighboring Ukraine in 2014. Russia is also engaged in the long civil war in Syria, which has killed hundreds of thousands of people, driven millions from their homes, and fueled a refugee crisis in the European Union. Nordic nations have already voiced security concerns over the pipeline being laid near their shores under the Baltic. But Germany and Austria have focused more on the commercial benefits of having more cheap gas, arguing there could be little harm from an additional pipe. “Any additional gas infrastructure can contribute to increased supply security in Europe,” Germany’s economy ministry spokesman said, adding Berlin’s stance was that Nord Stream 2 was a commercial venture that must comply with relevant laws.
European Pipeline Wars: Realpolitik Meets Geography - The headlines are ablaze this month with news from all over about new pipeline projects coming into Europe. Never one to miss an opportunity to do the U.S. State Department’s bidding in how it presents pipeline politics, Oilprice.com published a howler of a piece about the Southern Gas Corridor.Titled, “Is This the World’s Most Critical Pipeline?” the piece is pure marketing fluff designed to make you think that Azerbaijani gas will change the face of European gas politics.The beginning is the most telling, “Europe wants to become less dependent on Russian gas and use more clean energy…” This is a lie.Europe doesn’t want this as a continent, the leaders of the European Union who are aligned with the United States who view Russia as the enemy want to become less dependent on Russian gas. Most of Europe wants Russia to supply them with natural gas because it is 1) cheap and 2) plentiful. For geopolitical reasons the U.S. doesn’t want an ascendant Russia. The EU technocracy agrees because a strong Russia owning more than 40% of European gas sales is a Russia that can’t be destabilized through currency and proxy wars. The Southern Gas Corridor is a nearly 4000km (2500 mile) gas pipeline project to bring Caspian Sea natural gas into southern Europe. It is slated, when completed with all the side projects tying into it, between 60 and 120 billion cubic meters of gas annually (bcma) starting with an unknown amount from Azerbaijan in 2019. That number comes from an announcement in the Financial Times circa 2008. A better number for it is closer to just 16 bcma.It’s estimated cost at the time of negotiation was over $41 billion. Today, it’s $45 billion with corruption and graft likely to take that number higher. This is the very definition of a solution in search of a problem. It is nothing more than a $45 billion bribe to both the U.S.-favorable regime in Azerbaijan and BP who is sitting on the major Shah Deniz gas deposit with out a market to sell it to. The U.S has been using EU countries hostile to Russia, namely the Baltics and Poland, to delay or scuttle new Russian gas projects into Europe; projects that countries like Italy, Greece and Bulgaria are screaming for.
Bangladesh Signs Deal With Indonesia For LNG Imports - (Reuters) - Bangladesh signed an agreement with Indonesia on Sunday to open talks on imports of liquefied natural gas (LNG), as the South Asian country turns to the supercooled fuel to fill a shortfall of domestic natural gas. A letter of intent was signed between two state energy companies, Petrobangla and Pertamina, after a meeting between Prime Minister Sheikh Hasina and Indonesian President Joko Widodo, who arrived in Dhaka on Saturday. Bangladesh, a country of more than 160 million people, may import as much as 17.5 million tonnes of LNG a year by 2025, as its domestic gas reserves dwindle and demand grows. Petrobangla is finalising several floating storage and regasification units, the first of which is expected to commence operations in April 2018. In September, Bangladesh signed its first ever LNG import deal with Qatar, underscoring the rise of South Asia as a new market for the fuel. Widodo's visit comes as Bangladesh is struggling to cope with an influx of around 688,000 Rohingya refugees who have fled an army crackdown in Myanmar's Rakhine state since last August. "He reiterated his country's support to the safe, dignified return of the displaced persons to the Rakhine State," a joint statement said after Widodo visited a refugee camp in the Cox's Bazar region of southern Bangladesh. Hasina "appreciated Indonesia's supportive role, including the humanitarian assistance for the displaced persons from Rakhine State sheltered in Bangladesh," the statement said. Myanmar and Bangladesh agreed earlier this month to complete a voluntary repatriation of the refugees in two years.
Asian oil products demand to outweigh refinery capacity by 2025: McKinsey - Asian demand for oil products will outweigh current and upcoming refinery capacity by 2025, Tushar Tarun Bansal, Director at McKinsey, told attendees at S&P Global Platts annual Middle Distillates Conference in Antwerp Thursday. In particular, China and India were singled out as two of the largest consumers that will move from a current oil product balances to an oil product deficit by 2025. In China, demand continues to rise, and refining capacity will be incapable of keeping pace resulting in China being reduced to a net importer, Bansal said. Beyond 2020, international players might see a revival in refining investment opportunities in China. Bansal expects demand in China to grow by 5% per year between 2010 and 2018, changing to 2% per year by 2025 as the country moves from an industrial economy to a more service-oriented economy. Current capacity will see 1% per year added over 2018-2025 creating a deficit between demand and capacity of around 180,000 b/d. In India, demand will grow by 6% per year from 2010-2018 with a forecast of 4% per year growth until 2025. Diesel will drive a significant proportion of this demand growth, Bansal said. Addressing questions as to whether recent growth in India is purely attributed to a low flat price environment, Bansal said demand in India is both structural and strong, and not merely a product of recent low crude prices. With strong growth until 2025, the current surplus will continue to reduce up to 2020, resulting in India becoming a net importer -- mostly of LPG and naphtha -- after 2020. The wider Southeast Asian market will mirror the growth expected in China and India. Demand in Southeast Asia will grow by 3% per year from 2010-2018 with forecasts predicting 2% per year growth until 2025.
Asia Is About To Be Hit By The “Worst Oil Tanker Spill In Decades” - The Sanchi disaster is even worse than many initially expected, according to a chilling new report published by Britain's National Oceanography Centre that shows the ship's cargo - the equivalent of nearly 1 million barrels of ultra-light crude, plus its own fuel - snaking across the East China Sea into the northern Pacific, according to a series of visualizations created by Reuters. The Panama-registered vessel burst into flames after colliding with a cargo ship off the east coast of China while on its way to South Korea. The disaster, which took place in the East China Sea, is the worst oil spill since Exxon Valdez.The Sanchi tanker and a cargo ship collided 260km (160 miles) off Shanghai on Jan. 6. Afterward, the tanker - which burned for a week before exploding and sinking - then drifted south-east towards Japan.At the time, the Iranian press reported that all 32 crew members - 30 Iranians and two Bangladeshis - died in the accident. The tanker was carrying 136,000 tonnes of ultra-light crude. The always-credible Chinese media claimed that no oil slick had formed.Authorities have had trouble pinning down how big the spill is, as it changes by the day amid strong ocean currents. But concerns are growing about the potential impact to key fishing grounds and sensitive marine ecosystems off Japan and South Korea, which lie in the projected path of the oil, according to Britain’s National Oceanography Centre."An updated emergency ocean model simulation shows that waters polluted by the sinking Sanchi oil tanker could reach Japan within a month," the center said a report posted on Jan. 16. "The revised simulations suggest that pollution from the spill may be distributed much further and faster than previously thought, and that larger areas of the coast may be impacted."According to Reuters, which examined the data, first, the toxic ultra-light crude would probably dissolve, forming a poisonous plume under the sea surface. However, it remains unclear how long condensate would stay in the water, with South Korean officials believing it would most likely evaporate. However, the heavy fuel used to power the ship could wind up washing ashore, as depicted in the map below...
Sanchi Oil Spill Has Already Caused 'Serious Ecological Injury' -- The Sanchi oil spill in the East China Sea could potentially be one of the worst tanker spills in decades, experts are warning, even though the spill has now largely disappeared from news reports. Work by scientists from the National Oceanography Centre (NOC) and the University of Southampton, who have plotted where the condensate ends up, believe that the spill could even reach Japan within a month. In doing so , it could severely impact locally important reefs , fishing grounds and protected marine areas.An Iranian tanker, the Sanchi sank on Jan. 14 after colliding with a cargo ship and setting fire. The ship was carrying 136,000 tons of ultra-light condensate when it sank. What is puzzling scientists is where this will end up and how much damage will be caused.The scientists from Southampton predict that the condensate could enter the regionally important Kuroshio current and then be "transported quickly along the southern coasts of Kyushu, Shikoku and Honshu islands, potentially reaching the Greater Tokyo Area within 2 months. Pollution within the Kuroshio may then be swept into deeper oceanic waters of the North Pacific." According to the scientists, "The revised simulations suggest that pollution from the spill may be distributed much further and faster than previously thought, and that larger areas of the coast may be impacted." Their recent simulations "also shift the focus of possible impacts from South Korea to the Japanese mainland, where many more people and activities, including fisheries, may be affected.""It's not like crude, which does break down under natural microbial action. This stuff actually kills the microbes that break the oil down."
Oil Spill From Sanchi May Have Reached Japan - Oil from the stricken oil tanker Sanchi, which exploded and sank in the East China Sea, may have now reached the shores of Japan, according to the country's Coast Guard.Reuters reported Friday that residents on the Japanese Amami-Oshima islands, famed for pristine beaches and reefs , have reported black oil clumps being washed up.Officials are now checking to find out whether the oil is from the Iranian registered tanker, which was carrying an estimated 136,000 tonnes of condensate when it sank in mid-January, with the loss of all 32 members of the crew. It also had nearly 1,900 tonnes of bunker fuel oil on board.It is unknown if the ultra light condensate could form black oily clumps or if indeed this is even the heavier bunker oil. But if the oil has come from the Sanchi, then this would be a serious setback for Japanese authorities, who said last month that there was little chance the spill would reach the county's shores.This optimism, however, was contradicted by scientists from the National Oceanography Centre (NOC) and the University of Southampton in the UK. As I reported earlier in the week, they plotted the path of the spill and believed it could reach Japanese shores "within a month."
Minister: Iraq To Comply With OPEC Deal Despite Oil Export Capacity Rise -- Reuters) - Iraq will comply with the OPEC-led deal on reducing output even though Baghdad is working hard to increase its oil export capacity from the north and south of the country, its oil minister said on Monday. Jabar al-Luaibi told a Chatham House conference in London that Iraq's export capacity was nearing 5 million barrels per day (bpd), including 4.6 million bpd from the south. Iraq, the second largest producer in the Organization of the Petroleum Exporting Countries, has had to limit output in line with OPEC's commitment to cut output by about 1.2 million barrels per day (bpd) as part of a deal with Russia and others. "Iraq has made it clear at every time and every event that Iraq will comply with OPEC declarations in good spirit, genuine spirit," the minister said. "We are determined that we will reach 5 million bpd export capacity by the end of this year." The OPEC cut has boosted oil prices, which last week topped $71 a barrel for the first time since 2014. OPEC members are enjoying the rally and extra revenue, and say prices are not too high. Luaibi described prices as "reasonable" so far. He said Iraq hoped to more than double production from the northern Kirkuk oilfields with the help of BP. Iraq said this month it had signed a memorandum of understanding with BP to boost capacity at the fields. While exports from the south are at record levels, output in northern Iraq is down after falling in mid-October when Iraqi forces retook control of oilfields from Kurdish fighters who had been there since 2014. This has had the side-effect of boosting Iraqi compliance with the OPEC cuts in recent months. Last year, Iraq's compliance lagged Saudi Arabia and other large OPEC producers. The minister said the market was nearing "good stability" and Iraq was pumping 4.35 million to 4.36 million bpd of oil. Assuming Iraqi output of that level in January, the country has cut supply by 206,000 bpd and delivered 98 percent of its pledged reduction of 210,000 bpd under the OPEC deal, according to a Reuters calculation.
The case for Russian membership of Opec - Russia may be willing to work with Opec beyond 2018 to manage oil markets. Unprecedented co-operation has reversed a slump in prices and drained overflowing global inventories. Making their temporary alliance permanent would now bring wider benefits for both sides.Opec with Russia as a permanent member could regain its swing-producer status, which has been eroded by the rapid growth of US shale. Moscow would also potentially gain from taking a prominent role at the centre of an internationally recognized intergovernmental organization, and by gaining even more strategic influence among the group’s Middle East members, which control at least half the world’s proven reserves.However, the foremost benefit of permanent Opec membership would be the added pricing clout Russia brings to the table. The slump in prices triggered in 2014 has forced producers within the 14-member group to tighten their economic belts and radically cut spending. Real GDP growth in the core Arabian Gulf states – which combined account for about two-thirds of Opec capacity – may have fallen to 0.5 per cent last year, from 2.2 per cent in 2016, according to the International Monetary Fund. Russia’s flexible exchange rate and larger industrial economic base has helped to soften the blow somewhat, but the country has still suffered. Although no longer in recession, economic growth is expected by the IMF to remain tepid at around 1.5 per cent over the next five years. Boosting oil prices and ensuring market stability remains financially imperative for all sides. Their cooperation, which started at the end of 2016, has reversed the price slump. Brent crude has gained 32 per cent to trade at around US$70 per barrel since Opec with the help of Russia and a clutch of smaller producers outside the grouping. Combined cuts of 1.8 million barrels per day – of which Russia contributes about a sixth – have also drained inventories. Global crude stockpiles have dropped by 220 million barrels since the beginning of last year.
Oil Is Looking Unstoppable as Hedge Funds Take Bets to New High (Bloomberg) -- The enthusiasm in the oil markets is breaking records. Hedge funds reported record wagers on continued price increases for both U.S. and global oil benchmarks, along with gasoline and diesel. Meanwhile, producers are hedging production at record rates as oil experiences its best January since 2006. “There is a lot of interest in the direction of crude oil,” Rob Thummel, managing director at Tortoise Capital Advisors LLC, which handles $16 billion in energy-related assets, said by telephone. “The long oil trade continues to be the place to be.” The tailwinds propelling futures to three-year highs increasingly converge: OPEC has shown unprecedented discipline in sticking to output cuts, Russia and Saudi Arabia are doubling down on their commitment to wipe out the global supply glut, U.S. stockpiles are on their longest downhill slide ever, and last week a boost from a weaker dollar was added to the mix. Another significant sign the oil crash is behind us, is the clear shift in the futures curve. Both in New York and London, the closer the delivery, the higher the price all the way through 2022. That pattern, known as backwardation, is typical of times when demand is rising and supplies are tightening, and it hadn’t been so marked since 2014. At the World Economic Forum in Davos last week, Marco Dunand, the head of trading house Mercuria Energy Group Holding SA, said the crude market will remain in backwardation throughout this year with prices trading between $60 and $75 a barrel. BBL Commodities LP, one of the world’s largest oil-focused hedge funds, believes Brent crude will climb to $80 in 2018. Also in Davos, chatter emerged from Organization of Petroleum Exporting Countries oil ministers on the favorable state of supply and demand. OPEC Secretary-General Mohammad Barkindo said he sees the much-anticipated rebalancing of the market occurring this year, Russia’s Energy Minister Alexander Novak said that goal is almost in hand and Saudi Minister of Energy and Industry Khalid al-Falih said there are no signs of a significant slowdown in oil demand growth.
Hedge funds pile into oil despite rising risk of a correction: (Reuters) - Hedge funds continue to increase their bullish positions in oil, even as prices hit the highest level since the slump began in 2014, brushing aside concerns about overheated markets and the risk of a correction. Hedge funds and other money managers raised their net long position in the six most important futures and options contracts linked to oil by 44 million barrels to a record of 1,484 million in the week to Jan. 23.Portfolio managers have raised their net long position in Brent, NYMEX and ICE WTI, U.S. gasoline, U.S. heating oil and European gasoil by the equivalent of 1,174 million barrels since the end of June.Hedge funds are more bullish on the outlook for petroleum than at any time on record, even though benchmark Brent prices have already nearly tripled over the last two years (http://tmsnrt.rs/2EifLfr).The ratio of hedge fund long positions to short positions has climbed to a record 11.51:1, up from a low of just 1.55 at the end of June. Since the start of 2015, such lopsided hedge fund positioning has usually preceded a sharp reversal in the recent price trend.But most fund managers seem unconcerned about the threat of a short-term reversal because the medium-term fundamentals appear solid.Oil consumption is growing rapidly as a result of synchronised growth in the major economies. OPEC and its allies have reiterated their commitment to output restraint. And global inventories are falling.Portfolio managers increased their bullish positions in every element of the petroleum complex in the week to Jan. 23.Net long positions rose in Brent (+14 million barrels), WTI (+8 million barrels), U.S. gasoline (+12 million), U.S. heating oil (+4 million) and European gasoil (+6 million).Net long positions are at record levels in every contract and in most contracts the ratio of long to short positions is at a multi-year highs.Brent prices are close to their 10-year average ($82 per barrel) and already above their average over the last complete cycle from 1998 to 2016 ($64).The implication is that petroleum prices are no longer cheap but still have room to rise further as the price cycle matures in 2018 and 2019 (http://tmsnrt.rs/2DIoGG6 and http://tmsnrt.rs/2EkJBQA).Oil consumption is expected to continue rising strongly thanks to fast growth in the global economy and world trade.The principal risks come from an acceleration in U.S. shale drilling, declining compliance in OPEC and its allies, increased production from non-OPEC non-shale sources, or a deceleration in demand owing to rising prices.None of these risks appears likely to materialise imminently but they will all increase the higher that oil prices rise.
Crude oil futures soften on US rig count, stronger dollar - Crude futures were softer Monday during mid-morning trade in Europe, with a bearish rig count in the US and to a lesser extent a stronger dollar weighing on prices. At 1220 GMT, ICE March Brent crude was down 66 cents from Friday's settle to $69.86/b, while the NYMEX March light sweet crude contract was 42 cents lower at $65.72/b. The US rig count rose by 12 over the last week to a total of 759, the latest data from Baker Hughes showed, making it the biggest weekly increase since March 2017. There are expectations that profit-taking could be around the corner, with further falls in prices. "If [Brent futures] fall by $2-3/b, greed will turn to fear," said Torbjorn Kjus, chief oil economist at DnB Markets, adding that a selloff by money managers could see prices drop up to $10/b. "Normally you see a big selloff between 2-4 times a year," he added. Kjus warned that the total value of money managed is now greater than in 2014 when oil prices exceeded $110/b before plunging to multi-year lows. Nonetheless, at the moment "speculative financial investors in the energy sector are betting on further price rises," Commerzbank analysts noted Monday, commenting on a rise in net long positions in Brent of 13,892 to a record 579,260 contracts in the week to January 23. Meanwhile, a recovering US dollar against the euro Monday, reacting to supportive comments by President Trump at the World Economic Forum in Davos last week, also played a role in pressuring crude futures lower. The US Dollar Index was up 0.25 at 89.28.
Oil settles lower after dollar strengthens, rising U.S. output - (Reuters) - Oil prices settled lower on Monday, pressured by a strengthening dollar and rising U.S. crude output, but prices remained on track for the biggest January increase in five years. Brent crude futures LCOc1 for March delivery settled down $1.06, or 1.5 percent, at $69.46 a barrel, after rallying to a session high of $70.64. U.S. West Texas Intermediate (WTI) crude futures CLc1 fell 58 cents, or 0.9 percent, to close at $65.56 a barrel. The rally in oil prices has been buoyed by the U.S. dollar's six straight weekly slides. The greenback is set to fall 3 percent this month. .DXY Oil is priced in the U.S. currency, so a falling dollar can boost demand for crude from buyers using other currencies. The dollar index had been below $90 since Jan. 24. But the currency has rebounded 0.3 percent since Friday to $89.31, which has weighed on crude prices. "The strength in the dollar pushed some sellers in the market. There are some warning signs that maybe the rally is getting a bit overextended," said Gene McGillian, manager of market research at Tradition Energy in Stamford, Connecticut. Analysts expected U.S. crude supplies would post a weekly rise for the first time in 10 weeks, a preliminary Reuters poll showed on Monday. Industry group American Petroleum Institute posts its data on Tuesday and the U.S. Energy Information Administration reports on Wednesday. Crude prices also had drawn support from a large premium in the front-month Brent oil contract over those for future delivery, as investment in crude futures and options reached a record high last week. O/ICE Oil consumption is surging as a result of growth in major economies, while OPEC and its allies have made repeated commitments to limiting their crude output.
US oil and gas drilling costs rise as rig count climbs: Kemp (Reuters) - U.S. shale producers are facing rising costs for everything from drilling rigs to pressure pumping equipment and labour as the cyclical expansion in oil prices and drilling matures.The cost of drilling oil and gas wells has increased significantly over the last year, according to the latest provisional estimates from the U.S. Bureau of Labor Statistics.Drilling costs have increased by more than 10 percent since hitting a cyclical low in November 2016, though they are still 27 percent below the cyclical peak set in March 2014.Changes in drilling costs tend to follow changes in the number of rigs employed with a lag of around 1-2 months.The oil rig count itself tends to follow changes in the price of benchmark U.S. crude futures (WTI) with a lag of 4 months (http://tmsnrt.rs/2DLHaFC).In the current slump, however, drilling costs have recovered more slowly than normal as the market has absorbed a huge number of idled rigs.U.S. crude prices hit a cyclical low in February 2016, the rig count reached its nadir in May 2016, and drilling costs fell to their lowest point in November 2016.Since then, drilling costs have been on a gradual upswing as the number of rigs drilling for oil and gas has more than doubled from 404 in May 2016 to 947 in January 2018.The number of active rigs is still less than half its peak before the oil prices started slumping in the second half of 2014.But the rig market is tighter than it appears because many older rigs have been scrapped, cannibalised for spare parts, or are simply unsuitable for drilling the very long wells now favoured by shale producers.Producers increasingly favour new high-powered horizontal rigs that can drill ultra-long laterals as quickly as possible, so many of the older, lower-powered vertical or directional rigs are of marginal value.In other parts of the service sector, especially pressure pumping, shortages of equipment and trained crews are even more acute, and prices have been rising even faster. .Costs in the oil and gas industry have always been strongly pro-cyclical, which is why it makes no sense to talk about a long-run static breakeven price.During the slump, supposed breakeven prices tumbled as the costs for everything from labour, raw materials, royalties and service contracts were slashed. In the recovery, however, breakevens are rising as all these cost trends go into reverse, which is in turn offering some underpinning to oil prices at a higher level.
Crude oil futures: Crude dips on expectations for higher US inventories - Crude oil futures were lower in mid-morning trade in Europe amid expectations that imminent US data would show a build in crude and product stocks after 10 straight weeks of declines. At 1218 GMT, the ICE March Brent crude futures contract was 40 cents/b lower at $69.06/b, while NYMEX March light sweet crude was down 64 cents/b at $64.93/b. Analysts surveyed Monday by S&P Global Platts were expecting US crude stocks to have increased by 325,000 barrels in the week ended January 26. If confirmed by American Petroleum Institute and US Energy Information Administration data released later Tuesday and Wednesday respectively, this would end the long-running decline in US crude stocks which has seen them drop by 47.4 million barrels over a 10-week period to 411.58 million, the lowest level since February 2015. "Prices typically react to analyst expectations at the start of the week and recalibrate based on what the actual data shows, with the EIA figures carrying more weight," said Vandana Hari, founder of Vanda Insights. Distillates stocks were expected to decline 1.5 million barrels for the latest reporting week, while gasoline inventories were expected to rise by 1.05 million barrels. The rise in both crude and product inventories is to be expected ahead of scheduled refinery maintenance planned for February and March, said Michael Poulsen, a senior oil risk manager at Global Risk Management. "This will be part of a larger trend that we will come to see in the next weeks," said Poulsen, adding that ahead of the turnaround refineries would be looking to crack as much product as possible to replenish their inventories.
WTI/RBOB Drop After Surprise Crude Build - WTI/RBOB prices sank for the second day ahead of tonight's API as anxiety over a "slack demand period" builds and US production surges. While expectations were for a modest crude build, inventories jump over 3mm bbl - ending the 10-week draw-streak and sending WTI lower.. “The crude market is looking at the weakness in stock market. That’s making the oil traders a little nervous,” Phil Flynn, senior market analyst at Price Futures Group Inc. in Chicago, said by telephone. At the same time, “there is an expectation that we will see the first increase in supply in a long time.” API:
- Crude +3.229mm (+900k exp) - biggest build since Sept.
- Cushing -2.383mm
- Gasoline +2.692mm (+2mm exp)
- Distillates -4.096mm
Party's Over - after 10 weeks of crude draws, API reported a big build and a 12th week of gasoline builds...
Oil prices take biggest hit of the year - Oil took its biggest tumble since early December as investors worry U.S. stockpiles started expanding again. Crude futures in New York slid 1.6 percent, while gasoline also traded lower in the wake of a Bloomberg survey suggesting stockpiles of both may have risen last week. As the spread tightens between West Texas Intermediate and Brent, crude exports from the U.S. may become less attractive, leading to storage buildups. Energy stocks fell amid a broader rout in U.S. markets. Nationwide crude inventories probably rose by 900,000 barrels last week, according to the median estimate of analysts. At the same time, U.S. crude output could top 10 million barrels a day at any time. "Exports are being hurt a bit by the reduction in the Brent-WTI spread, which should also help inventories replenish. This is the slack demand period," While the Organization of Petroleum Exporting Countries works to reduce output, concern that U.S. crude production will hit new records remains on investors' minds. Yet, OPEC and Russia will let oil prices climb as high as the market can bear, according to Gary Ross, global head of oil analytics at S&P Global Platts. American crude production reached 9.88 million barrels a day last week, the highest in weekly government data going back to 1983. While crude stockpiles have dropped for 10 straight weeks, gasoline supplies have been on the rise since early November, and analysts estimate they rose by another 2 million barrels last week. Inventory figures will be released by the Energy Information Administration on Wednesday.
Have Oil Prices Hit A Ceiling? - Oil prices posted some losses at the start of the week. The sharp jump in the rig count on Friday raised concerns about an acceleration in shale drilling. At the same time, the dollar stopped shedding value, removing one of the main positive drivers for oil prices over the past two months. Perhaps most importantly, there is growing speculation that inventories will start rising again in the near future. Poland’s Prime Minister said that he wants the U.S. to put sanctions on the Nord Stream 2 pipeline, which would carry Russian gas to Germany, doubling the existing line’s capacity to 110 billion cubic meters per year. “Yes, we talked about Nord Stream 2. We want the construction of the Nord Stream 2 pipeline to fall under the U.S. sanctions bill ...which includes, among others, sanctions against Russia,”. Meanwhile, on Monday, the Trump administration said it has decided not to put additional sanctions on Russia for now.. Last spring, two sites run by Anadarko Petroleum exploded, killing three people. That has raised the specter of tighter regulations to improve safety. As such, Bloomberg points out that while energy stocks of all types have posted strong gains in recent weeks, Colorado-focused drillers are not experiencing an upswing in their share prices. Extraction Oil & Gas and SRC Energy Inc. have undervalued share prices relative to their peers, which analysts argue is the result of fears over forthcoming regulatory pressure from the state. ExxonMobil said it plans to invest more than $50 billion in spending in the U.S. over the next five years, a level of spending that will be “enhanced by the historic tax reform recently signed into law.” Exxon said much of the spending will go to the Permian Basin, along with petrochemical projects along the Gulf of Mexico. The statement appears to be proof that the tax reform will entice new investment, but there is a hefty dose of corporate spin in the announcement. Exxon was already spending $10.5 billion in the U.S. per year from 2012 to 2016. The announcement means spending levels will simply rebound to about those levels after dipping in 2016 and 2017. It is unclear if the spending increase would have happened anyway as Exxon steps up its focus on shale drilling.
Oil Prices Fall After Strong Crude Inventory Build - As investment banks become increasingly bullish on crude oil, the Energy Information Administration reported a 6.8-million-barrel build in U.S. crude oil inventories for the week ending January 26. The report comes a day after the American Petroleum Institute surprised markets once again with an estimated build of 3.23 million barrels. Analysts had expected the EIA to report a draw of 1.6 million barrels, in keeping with a string of tenth consecutive weekly draws. Gasoline stockpiles, according to the EIA, fell by 2 million barrels, from a build of 3.1 million barrels for the previous week. Gasoline production last week averaged 9.6 million barrels, versus 9.7 million bpd in the week before. Refineries processed an average 16 million bpd of crude last week, compared with 16.5 million bpd a week earlier. With refinery maintenance season approaching, some analysts are starting to warn we will begin to see inventory builds and this could hurt prices for a while. Meanwhile, earlier this week the EIA took the trouble to defend its weekly numbers, which some industry watchers have shunned as lacking credibility. The weekly inventory and, more importantly, production numbers—which have strong market-moving potential—are taken by extrapolation from the EIA’s Short-Term Energy Outlook, the authority explained. This is necessitated by the fact that although oil producers report weekly data, it is impossible to gather enough of this data to make a calculation based purely on it within the very short reporting window: producers report on Monday and the Weekly Petroleum Status Report is published Wednesday. So the EIA uses its STEO figures, which are again forecast and not actual. While it would seem that estimating production numbers based on forecast data wouldn’t be too accurate, the EIA said that in hindsight the accuracy is very high, with the average difference between estimated and actual figures standing at 1.3 percent in absolute terms. In other words, all those doubting how accurate the numbers that the EIA releases every Wednesday can rest assured that they are, in fact, very accurate.
Crude Oil Prices Settle Higher Despite Massive Build in Supplies - Crude oil prices settled higher shrugging off data showing US domestic oil supplies rose for the first time in 11 weeks and production rose above 10 million barrels per day in nearly half a century. On the New York Mercantile Exchange crude futures for March delivery rose 23 cents settle at $64.73 a barrel, while on London's Intercontinental Exchange, Brent gained 0.44% to trade at $68.82 a barrel. Inventories of U.S. crude fell by rose 6.776 million barrels for the week ended Jan. 26, well above expectations for of a draw of 308,000 barrels. That was the biggest increase in US stockpiles in ten months. Gasoline inventories – one of the products that crude is refined into – fell by 1.980 million barrels, confounding expectations for a build of 1.877 million barrels, while supplies of distillate – the class of fuels that includes diesel and heating oil – unexpectedly fell by 1.940 million barrels, a steeper fall than the 1.454 million barrels expected. The sharp build in US oil supplies come as the spread between WTI crude and Brent continues to tighten, lessening demand for domestic crude exports, leading to a build in crude stockpiles. U.S. crude production rose to 10.04 million barrels a day set in November 1970, according to data released by EIA on Wednesday. That level brings the US closer to world's top producers Saudi Arabia and Russia.
March NYMEX natural gas keeps tumbling to $2.941/MMBtu on bearish storage outlooks - NYMEX March natural gas futures continued to decline overnight in the US ahead of Thursday's open and the midmorning release of the weekly storage data that is poised to show a slower pace of stock erosion. After tumbling by 20.0 cents Wednesday, the contract was a further 5.4 cents lower at $2.941/MMBtu at 7:15 am ET (1215 GMT) today. Weather that trimmed heating demand is expected to have driven a modest withdrawal from inventories when the US Energy Information Administration releases its next storage report for the week ended January 26. Traders and analysts anticipate a pull from stocks from 90 Bcf to 116 Bcf, with consensus formed at a 102 Bcf drawdown. That would signal a significant step down in the rate of weekly withdrawals, as it would come on the heels of the 288 Bcf draw the previous week that tied as the second-highest draw ever recorded. Weather in store suggests diverging demand that will likely encourage a fluctuation in the rate of weekly storage draws going forward, while longer-range weather projections reflect moderating weather likely to dampen demand anew and allow for a slower rate of storage withdrawals as winter transitions to spring.
Crude oil futures: Crude up on US product draws and Venezuelan production - Brent and WTI crude futures gained momentum in the European morning session Thursday, after trading sluggishly in Asia at levels slightly above Wednesday's close. At 1033 GMT, April ICE Brent crude futures were up 54 cents/b at $69.43/b, while the NYMEX March light sweet crude contract was 45 cents/b higher at $65.18/b. The increase was led primarily by a draw in US products in weekly data, eclipsing the bearish pull coming from a build in oil inventories. According to data from the US Energy Information Administration Wednesday, US crude stocks rose 6.776 million barrels in the week ended Friday, January 26, ending a streak of 10 consecutive weeks of declines. Analysts surveyed Monday by S&P Global Platts had expected US crude stocks to have increased by 325,000 barrels. Gasoline inventories fell 1.98 million barrels. Distillate stocks also fell, by 1.94 million barrels, according to the EIA data, compared with analysts expectations of a draw of 1.5 million barrels. "The draws in gasoline were supportive, WTI managed to hold onto its 20-day moving average and Brent has not broken the lows of January, so I think the complex is holding," said Jakob Olivier, founder of PetroMatrix. Furthermore, "high involuntary production outages in Venezuela pull OPEC production significantly below target in January," Commerzbank analysts said in a note, something which was also said to be supporting prices. "The resulting cut by 467,000 b/d was almost five times as high as necessary, and is nearly enough on its own to explain OPEC's substantial overcompliance. OPEC is, therefore, profiting considerably from the involuntary production outages in Venezuela at present, without which the oil market would be oversupplied," Commerzbank said.
U.S. oil production nears 47-year record as shale booms (Reuters) - U.S. crude oil production topped 10 million barrels per day (bpd) in November, according to monthly estimates published by the Energy Information Administration on Wednesday. Crude output was the highest in 47 years and just 6,000 bpd below the record set in November 1970 (“Petroleum Supply Monthly”, EIA, Jan. 31).Production has doubled over the last 10 years, from a low of around 5 million bpd in 2007, reversing decades of decline since the 1970s.The most recent surge in output confounded some observers, who had forecast production was about to level off, though the EIA had predicted it for some time.Crude production increased by almost 850,000 bpd in just the three months to November, according to the EIA. Nearly all the recent surge has come from the lower 48 states excluding federal waters in the Gulf of Mexico (http://tmsnrt.rs/2DSvXTy). Most of that increase has come from onshore shale plays in Texas (where output has risen by 500,000 bpd since August) and North Dakota (where output is up by more than 100,000 bpd). Production from the lower 48 excluding the Gulf of Mexico hit almost 7.9 million bpd in November, easily beating the previous peak of nearly 7.8 million bpd in March 2015. From an output perspective, the U.S. shale sector has fully recovered from the price and output slump that started in 2014 and 2015. Production has beaten its previous peak even though there are fewer than half the number of rigs drilling for oil compared with before the slump. Producers have pulled back from marginal areas to the most productive “core” parts of shale plays such as the Permian in western Texas and eastern New Mexico. Smaller, older rigs have been idled or replaced by newer, larger and more powerful equipment that can bore through rock faster and further. Rigs are increasingly drilling multiple wells from a single pad (avoiding downtime for moving in and rigging up) and individual wells have much longer horizontal sections (exposing more rock to each well). The result is that more oil is being produced with far fewer rigs and drilling teams.
Oil prices leap after Goldman Sachs hikes forecast to over $80 a barrel -- Crude climbed by the most in a week amid a wave of bullish sentiment pinned on expectations that tightening supplies and a rosy economic outlook will keep prices elevated. Goldman Sachs Group Inc. boosted a price forecast by a third and said global crude markets have probably rebalanced. The bank now estimates Brent will reach US$75 a barrel over the next three months and will climb to US$82.50 within six months, analysts including Damien Courvalin wrote in an emailed report. Their previous estimate for both time periods was US$62 a barrel. “The rebalancing of the oil market has likely been achieved, six months sooner than we had expected,” Goldman’s analysts wrote. “The decline in excess inventories was fast-forwarded in late 2017 by stellar demand growth, high OPEC compliance, heavy maintenance as well as collapsing Venezuela production.” Futures rose for a second day in New York, adding as much as 1.4 per cent. The dollar declined, further adding support to crude prices. As the Organization of Petroleum Exporting Countries trims production, U.S. oil output is surging. Production rose above 10 million barrels a day for the first time in more than four decades in November, while U.S. crude stockpiles broke a 10-week run of draw-downs last week, Energy Information Administration data showed Wednesday. The U.S. benchmark has remained above US$60 a barrel since late December, lending support for American drillers to pump more. West Texas Intermediate crude for March delivery advanced 72 cents to US$65.45 a barrel at 9:54 a.m. on the New York Mercantile Exchange. Total volume traded was about 27 per cent above the 100-day average. Brent for April settlement jumped 72 cents to US$69.61 a barrel on the London-based ICE Futures Europe exchange. The global benchmark crude traded at a premium of US$4.37 to April WTI. The March contract expired Wednesday
Oil rises as OPEC compliance eclipses boom in US output (Reuters) - Oil rose on Thursday after a survey showed OPEC’s commitment to its supply cuts remains in place, even as U.S. production topped 10 million barrels per day (bpd) for the first time since 1970. On its first day as the front-month, Brent futures for April delivery gained 76 cents, or 1.1 percent, to settle at $69.65 a barrel, while U.S. West Texas Intermediate (WTI) crude for March delivery jumped $1.07, or 1.7 percent, to settle at $65.80. That put both crude futures contracts close to their highest levels since December 2014. In January, both benchmarks rose for a fifth month in a row with Brent up 3.3 percent and WTI up 7.1 percent, marking the strongest start to a year for Brent in five years and WTI in 12 years. “Oil is up today because of OPEC’s reinforced commitment for 2018,” said Brian Kessens, a portfolio manager and managing director at Tortoise in Leawood, Kansas. Oil output in the Organization of the Petroleum Exporting Countries (OPEC) rose in January from eight-month lows as higher output from Nigeria and Saudi Arabia offset declines in Venezuela and strong compliance with the OPEC-led supply pact, according to a Reuters survey. [OPEC/O] “The OPEC compliance for January was elevated but there are real questions going forward given the outsized participation of Venezuela,” John Kilduff, partner at energy hedge fund Again Capital LLC in New York, said. Oil output in Venezuela has been declining amid an economic crisis. The country produced about 1.6 million bpd in January, according to the Reuters survey, putting its output well below what it pledged to cut. Also supporting Thursday’s crude market was a note from Goldman Sachs boosting their oil price target. Goldman Sachs raised its three-month forecast for Brent to $75 from $62 and its six-month forecast to $82.50 from $75. Oil prices, however, are unlikely to advance much above $70 a barrel in 2018, given the tug of war between OPEC and the U.S. shale industry, a Reuters poll showed on Wednesday.
Oil Markets Are At A Stalemate -- Oil prices seesawed over the past few days, but look poised to close out the week flat compared to last week. High OPEC compliance and falling Venezuelan production more or less offset surging output from U.S. shale and an uptick in inventories. U.S. oil production tops 10 mb/d. The EIA said this week that U.S. oil production surpassed 10 mb/d in November, just shy of the all-time high set decades ago. There was a huge increase from October, a monthly increase of over 380,000 bpd. The surging output is clear evidence that the shale industry is ramping up production at an amazing pace, and could spoil OPEC’s plans to balance the market. Meanwhile, U.S. crude inventories also jumped last week, the first time that has occurred in several months. Goldman: Brent to $82 in 6 months. Goldman Sachs dramatically overhauled its forecast for oil prices this year, stating in a research note that the market is tightening much faster than expected. Moreover, the investment bank said that OPEC’s objective of bringing down inventories to the five-year average has probably already occurred. “The rebalancing of the oil market has likely been achieved, six months sooner than we had expected.” The bank predicts that OPEC will stick with the cuts for the first half of the year, which could tighten the market more than the group intends, and push prices up above $80 per barrel by the summer. From there, OPEC might gradually ratchet up output. OPEC maintained high levels of compliance with the production cuts in January, with its compliance rate at 138 percent according to Reuters. However, that is largely the result of the meltdown from Venezuela, which offset the gains from Saudi Arabia and Nigeria. Barclays estimates that Venezuela’s production could fall by 700,000 bpd this year, averaging 1.43 mb/d. The crisis continues to erode the country’s production base, a drop off that accelerated at the end of 2017. Meanwhile, U.S. Secretary of State Rex Tillerson seemed to offer some measure of support for a military coup in the country. "There will be a change in Venezuela. We want it to be a peaceful change," Tillerson said on Thursday at the University of Texas-Austin, according to Argus Media. "We have not advocated for the regime change or removal of President Maduro," he tried to clarify. "Maduro could choose to just leave, that would be the easiest. He has friends in Cuba and they can give him a nice hacienda on the beach and he can have a nice life there."
The Oil Rig Count Rises Once Again - The number of active oil and gas rigs decreased this week, according to Baker Hughes data, by a single rig. This brings the total number of oil and gas rigs to 946, which is an addition of 217 rigs year over year.Still the number of oil rigs in the United States rose this week, by 6, with the number of gas rigs decreasing by 7. The number of oil rigs stands at 765 versus 586 a year ago. The number of gas rigs in the U.S. now stands at 181, up from 145 a year ago. At 12:14pm EST, the price of a WTI barrel was trading down $1.02 (-1.55 percent) to $64.78—almost $1.00 under this same time last week. The Brent barrel trading down $1.51 (-2.17 percent) to $68.14, almost $2 per barrel under last week. While inventory figures and OPEC data are the usual catalyst for oil price swings, this week the stronger dollar has pushed oil prices downward in what is one of the biggest weekly drops in months.U.S. crude oil production rose again, to 9.919 million bpd, from 9.878 million bpd the week before, setting another new high and getting dangerously close to that psychologically important 10.0 million bpd mark. Canada has added hundred of rigs in the last three weeks. This week, Canada added another 14 oil rigs, but the number of gas rigs in Canada declined by 10. The total number of oil and gas rigs is now 342, with the number of gas rigs still down year over year. The Permian basin rig count was flat this week, with the Haynesville basin seeing the biggest increase to the number of rigs, which was up by 2. At 1:08pm EST, WTI was trading at $65.23 (-$0.57) with Brent trading at $68.56 (-$1.09).
US drillers add oil rigs for second consecutive week - (Reuters) - U.S. energy companies added oil rigs for a second week in a row as crude prices hovered near their highest levels since 2014, prompting drillers to return to the well pad. Drillers added 6 oil rigs in the week to Feb. 2, bringing the total count up to 765, the highest level since August 2017, General Electric Co’s Baker Hughes energy services firm said in its closely followed report on Friday. The U.S. rig count, an early indicator of future output, is much higher than a year ago when 583 rigs were active after energy companies started to boost spending in mid-2016 as crude were recovering from a two-year price crash. U.S. crude futures traded around $65 a barrel this week, near their highest since December 2014. That compares with averages of $50.85 in 2017 and $43.47 in 2016. Looking ahead, futures were trading around $63 for the balance of 2018 and $58 for calendar 2019. In anticipation of higher prices in 2018 than 2017, U.S. financial services firm Cowen & Co said 30 of the roughly 65 E&Ps they track, including Hess Corp, have already provided capital expenditure guidance indicating a 5 percent increase in planned spending over 2017. Cowen said the E&Ps it tracks planned to spend about $66.1 billion on drilling and completions in the lower 48 U.S. states in 2017, about 53 percent over what they planned to spend in 2016. Analysts at Simmons & Co, energy specialists at U.S. investment bank Piper Jaffray, this week slightly increased their forecast the total oil and natural gas rig count to an average of 1,006 in 2018 and 1,131 in 2019. Two weeks ago, they forecast 1,004 in 2018 and 1,128 in 2019. There were 946 oil and natural gas rigs active on Feb 2. On average, there were 876 rigs available for service in 2017, 509 in 2016 and 978 in 2015. Most rigs produce both oil and gas. The U.S. Energy Information Administration in January projected U.S. production would rise to a record high annual average of 10.3 million barrels per day in 2018 and 10.9 million bpd in 2019, up from 9.3 million bpd in 2017.
Oil prices tally a loss for the week - Oil prices finished lower Friday to tally a weekly loss, as recent U.S. monthly data show domestic crude production in record territory.March West Texas Intermediate crude fell 35 cents, or 0.5%, to settle at $65.45 a barrel on the New York Mercantile Exchange. The contract rose 1.7% Thursday, the biggest single-session gain since Jan. 24, according to FactSet data. For the week, prices were about 1% lower. April Brent, the global benchmark, dropped $1.07, or 1.5%, to end at $68.58 a barrel on the ICE Futures Europe Exchange. The contract marked a weekly loss of roughly 2.2%.U.S. oil production, driven by shale extraction, surpassed 10 million barrels a day in November for the first time in nearly 50 years, according to data released this week by the U.S. Energy Information Administration, reigniting concerns the market is oversaturated with crude. On Friday, Baker Hughes reported that the number of active U.S. rigs drilling for oil climbed for a second week in a row, highlighting a rise in drilling activity. It rose by 6 to 765 this week.Oil prices were additionally pressured by a selloff in the stock market, . “The equity sell off, really fueled by the rise in the 10-year bond yield] has turned the most markets into a risk off posture,” he said. “With the heavily long crude market not surprising to see it spill over to the energy market.” But oil prices have still found support from adherence to OPEC’s deal to limit supply. Compliance by the Organization of the Petroleum Exporting Countries with the oil cartel’s agreement with other major producers to hold back production by 1.8 million barrels a day rose to 138% last month, according to a Reuters survey. That is a “sign of their steadfast commitment to eliminating the global supply surplus, according to Stephen Brennock, an analyst at brokerage PVM Oil Associates Ltd. OPEC and 10 members outside the cartel, including Russia, first agreed in late 2016 to curb global crude output by nearly 2% in an effort to rein in a supply glut that has weighed on prices for over three years. The participants decided late last year to extend the deal through the end of this year. The current all-time U.S. output annual peak was in 1970 at 9.6 million bpd, according to federal energy data.
Saudi’s Aramco IPO dream could create shale oil nightmare -- Saudi Arabia’s dream of securing a $100bn windfall from the IPO of Aramco may be clouding its judgement. The kingdom needs higher oil prices to entice international investors to buy a stake in the state-owned company, which supplies almost all its crude. Using its OPEC clout to restrict global supplies and pump up the cost of its barrels makes the mega offering look more appealing but the move has also revived the kingdom’s biggest enemy in the form of US shale oil. Oil prices have climbed 33pc to trade around $70 per barrel since the Organisation of the Petroleum Exporting Countries (OPEC), with the help of Russia, agreed in late 2016 to shave 1.8m barrels per day (bpd) of crude from world supplies. That deal — brokered primarily by Riyadh — has now been extended for another year. The new timeline is conveniently synced with the scheme to offload up to 5pc in Aramco by the end of 2018. The danger with this strategy is that in emboldens US shale. The US Department of Energy predicts that America’s drillers will increase output by 1m bpd this year to average 10.3m bpd, rivalling Saudi Arabia and Russia in output terms. Despite these increases and the promise that US drillers could open their taps further, Riyadh remains unfazed. Rather than peaking anytime soon, it argues that global oil demand could grow a further 20% in the next 25 years, hitting 120 million b/d, with declines in smaller producing countries creating enough room for booming shale.
Saudi billionaire Twitter investor freed after settlement - BBC News: One of the world's richest men, Prince Alwaleed bin Talal, has been released two months after being detained in Saudi Arabia's anti-corruption purge. He was freed after a financial settlement was approved by the state prosecutor, an official said. Prince Alwaleed was held in November by a new anti-corruption body headed by the Saudi crown prince. More than 200 princes, politicians, and wealthy businessmen were detained in the crackdown. Since then, they have been held in the Ritz Carlton hotel in Riyadh, which is due to reopen on 14 February. Prince Alwaleed is the most high-profile detainee to have been released so far. Speaking to Reuters news agency before his release he said that no charges had been laid against him and expressed support for Crown Prince Mohammed bin Salman. The multi-billionaire has a vast array of business interests across the world, including holdings in Twitter and Apple. In November, Forbes estimated his net worth at about $17bn (£13bn), making him the 45th richest man in the world. Officials say he will remain as head of his company, Kingdom Holding. Other high-profile figures that have been set free include Waleed al-Ibrahim, the head of MBC television network, and Khalid al-Tuwaijiri, a former chief of the royal court. They have paid substantial financial settlements, reports say - though the amounts have not been made public.
Prince Alwaleed Finally Released From "Hotel Arrest" --Two weeks after we reported that Saudi Arabia's billionaire prince Alwaleed Bin Talal was reportedly carted off from the Riyadh Ritz Carlton to Saudi Arabia's highest security prison after refusing to pay a $6 billion "freedom fee" to Crown Prince Mohammed Bin Salman to secure his freedom, the flamboyant billionaire and Twitter investor appears to have finally cracked, and according to the WSJ, Saudi authorities on Saturday finally released Alwaleed, more than two months after he was detained in what was described to be a "widespread crackdown on corruption" in the kingdom but was really just a shakedown of some of the country's richest royals as well as arrests of MbS' political opponents. The FT quoted a colleague of bin Talal who said that He sounded very happy, well and the same"... if maybe a little bit poorer."Prince al-Waleed is already at his house in Riyadh and is expected to resume his business activities as normal", the WSJ reported citing sources. While it was previously disclosed that Saudi authorities demanded at least $6 billion from al-Waleed to free him, it wasn’t clear what if any "settlement" the prince agreed to pay; he has previously denied wrongdoing and fought allegations of bribery, extortion and money laundering.Alwaleed will remain in control of Kingdom Holding Co. after reaching the settlement a senior government official cited by Bloomberg, which would suggest that the amount of money exchanging hands was substantial. The official also declined to provide details of settlement, and "cannot confirm or deny" whether attorney general is convinced of Alwaleed’s innocence. "Settlements don’t happen unless the accused acknowledges violations and documents that in writing and pledges that he won’t repeat them. This is the general principle of all who were detained in corruption cases recently and not only Alwaleed bin Talal."
TEXT-Transcript of Reuters interview with Saudi Arabia's Prince Alwaleed bin Talal (Reuters) - Following are excerpts of a Reuters interview with Saudi Arabia’s billionaire Prince Alwaleed bin Talal, detained in the kingdom’s sweeping corruption probe. He spoke with Reuters for 30 minutes in a suite at Riyadh’s opulent Ritz-Carlton hotel, where he has been held since November. It was the first time the prince, one of the nation’s most prominent businessmen, has spoken publicly since his detention.
Saudi government says it's seizing over $100 billion in corruption purge -- Saudi Arabia's government has arranged to seize over $100 billion in financial settlements with businessmen and officials detained in its crackdown on corruption, the attorney general said on Tuesday. "The estimated value of settlements currently stands at more than 400 billion riyals ($106 billion) represented in various types of assets, including real estate, commercial entities, securities, cash and other assets," Sheikh Saud Al Mojeb said in a statement. The huge sum, if it is successfully recovered, would be a major financial boost for the government, which has seen its finances strained by low oil prices. The state budget deficit this year is projected at 195 billion riyals. The announcement also appeared to represent a political victory for Crown Prince Mohammed bin Salman, who launched the purge last November and predicted at the time that it would net about $100 billion in settlements. Dozens of top officials and businessmen were detained in the purge, many of them confined and interrogated at Riyadh's opulent Ritz-Carlton Hotel. In total, the investigation subpoenaed 381 people, some of whom testified or provided evidence, Mojeb said, adding that 56 people had not reached settlements and were still in custody, down from 95 early last week. Some cases are expected to go for trial, authorities have said previously. Over 100 detainees are believed to have been released. Billionaire Prince Alwaleed bin Talal, owner of global investor Kingdom Holding, and Waleed al-Ibrahim, who controls influential regional broadcaster MBC, were freed last weekend.
Saudi corruption purge winds down but scars will linger (Reuters) - Saudi Arabia’s stock market celebrated the release of some of the kingdom’s top businessmen from detention on Sunday but the after-effects of a purge of the business elite may last for years, deterring private investment. Billionaire Prince Alwaleed bin Talal, head of global investment firm Kingdom Holding 4280.SE, was among at least half a dozen tycoons freed at the weekend after over two months of confinement in Riyadh’s Ritz-Carlton Hotel. Their release signaled a massive anti-corruption drive, in which authorities detained over 200 people and said they aimed to seize $100 billion of illicit assets, was drawing to a close. The Ritz-Carlton is to reopen to the public in mid-February. But troubling questions about the purge have not been answered. Although few people doubt Saudi Arabia would benefit from less corruption, the scale and ferocity of the crackdown alarmed businessmen inside and outside the kingdom. Details of financial settlements between authorities and detainees have not been disclosed, leaving the public to wonder what the penalties are for large-scale corruption - and what allegations the detainees actually faced. The first major settlement was that of senior prince Miteb bin Abdullah, once seen as a leading contender to the throne, who was freed after agreeing to pay over $1 billion, according to Saudi officials. That fueled suspicion among foreign diplomats there might be political motives behind the purge. While the government says eliminating corruption will level the playing field for all investors, some local and foreign businessmen feel risks have risen, as they are not sure if local partners may become targets of another crackdown. “This was completely unprecedented – not only in Saudi Arabia, but among all Arab monarchies,” said Steffen Hertog, a leading Saudi Arabia scholar at the London School of Economics. “The appetite for big-ticket corruption among Saudi elites will certainly be a lot lower now. But many also believe, at least for the time being, that life has become less predictable for the private sector, which could make it harder to commit to long-term investment.”
Yemen separatists capture most of Aden, residents say - BBC News: Yemeni separatists have taken almost full control of the southern port city of Aden after days of fighting with government forces, residents say. PM Ahmed bin Daghar and members of his cabinet are believed to be holed up inside the presidential palace in Aden. There are reports of talks between the southern separatists and government forces, who were previously allies. The fighting opens up a new front in Yemen, splitting the alliance against Houthi rebels in the north. It has already led to the deaths of 40 people since Sunday, the Red Cross says. The separatists are also reported to have also seized Aden's military bases. Yemen's internationally-recognised government relocated to Aden in 2015, when President Abdrabbuh Mansour Hadi and his cabinet were forced to flee the capital, Sanaa, following an offensive by the Houthis. A assault on Sanaa prompted a Saudi-led multinational coalition to launch a military campaign to defeat the rebels. Since then, more than 9,245 people have been killed and 3 million displaced, according to the UN.
Saudi, U.A.E. Move to Quell Clashes Threatening Yemen Alliance - Saudi Arabia and the United Arab Emirates moved to contain deadly infighting between their Yemeni allies that threatens to jeopardize their common fight against Iran-backed Houthi rebels.The two Gulf states sent a “top military and security delegation” to the site of the clashes, the southern port city of Aden, to monitor implementation of a cease-fire between Yemen’s elected government and the secessionist Southern Transitional Council, the U.A.E.’s official news agency reported on Thursday. Thirty-eight people have been killed and 222 wounded since the fighting began Sunday, according to the International Committee of the Red Cross.The violence in Aden, where the government of ousted President Abd Rabbuh Mansur Hadi is based, threatened his control of the city and risked weakening the military coalition Riyadh and Abu Dhabi built three years ago to reassert his authority over the whole of Yemen. The clashes between the Saudi-backed Hadi and separatists supported by the U.A.E. had raised concerns the two Gulf nations’ alliance is fraying, and spurred criticism they had failed to agree on a unified vision for Yemen. In statements carried by Saudi and U.A.E. media outlets, the two nations emphasized a shared goal in Yemen: to preserve the integrity of the state. The conflict -- widely seen as a proxy war between Saudi Arabia and Iran -- has killed thousands, and created widespread illness, hunger and displacement in a country that was already among the world’s poorest.
Defence minister: Saudi, UAE intended to invade Qatar - Saudi Arabia and the United Arab Emirates had intentions to invade Qatar at the beginning of a diplomatic crisis that erupted in June, according to Qatar's defence minister.In an interview with the Washington Post on Friday, Khalid bin Mohammad Al Attiyah said his Gulf neighbours have "tried everything" to destabilise the country, but their intentions to invade were "diffused" by Qatar."They have intentions to intervene militarily," said Attiyah. When asked to confirm whether he thought such a threat still existed today, he responded: "We have diffused this intention. But at the beginning of the crisis, they had this intention. "They tried to provoke the tribes. They used mosques against us. Then they tried to get some puppets to bring in and replace our leaders." Attiyah, who met US Defense Secretary Jim Mattis last week during a visit to Washington, DC, described the beginning of the crisis by the Saudi-led bloc as an "ambush" that was "miscalculated".In June 2017, Saudi Arabia, the UAE, and Egypt and Bahrain cut off diplomatic relations with Qatar and imposed a land, sea and air blockade after accusing it of supporting "terrorism" and "extremism". Qatar has strongly denied the allegations.Attiyah said Qatar is the only country that has signed a memorandum of understanding with the US to counter terrorism in the region - namely in Iraq, Afghanistan, and Syria. Asked about Doha's relations with Saudi's rival, Iran, Attiyah noted that Qatar maintains "friendly relations with everyone".
Why Europe Must Reject U.S. Blackmail Over Iran’s Nuclear Agreement – The Trump administration has threatened to end the nuclear deal with Iran. In our last post we argued in detail that the attempt of the European 3, the United Kingdom, France and Germany, to soothe Trump by condemning Iran's ballistic missiles is itself a breach of the Joint Comprehensive Plan of Action and the UN Security Council Resolution 2231. The University of Alabama endorsed Moon of Alabama's legal reasoning. Professor Daniel Joyner, author of several books on international law, non-proliferation and the nuclear deal with Iran, responded to the piece: I examined 2231 in a chapter you can download here: Iran's Nuclear Program and International Law: From Confrontation to Accord, Chapter 7 I addressed the missile issue at pg. 240, and reached the same conclusion you do. Ellie Geranmayeh, a member of the European Council of Foreign Relations (a U.S. aligned institution), is also defending the nuclear deal and warns against endorsing its breach. She argues in Foreign Policy that the Europeans should not soothe Trump but take a strong stand against any U.S. attempt to put Iran back into the bad corner:Some European officials state in private that the best option is for Europe to muddle through in the hope that Trump will eventually shift his position. But muddling through just won’t do. Trump is likely to continue increasing his maximalist demands unless Europe flexes its political muscle.In order to protect its economic and security interests, Europe must not only reject Trump’s ultimatum — which would be a kiss of death for the nuclear deal — but also push back. Europe should put in place a viable contingency plan if the United States continues backtracking on the deal and let Washington know it’s ready to use it.The author puts forward a four point plan which would indemnify European companies which are dealing with Iran but threatened by secondary U.S. sanctions: Put simply, EU officials must tell Trump: If you fine our companies’ assets in the United States, we will reclaim those costs by penalizing U.S. assets in Europe. This would cause a major trade conflict that the Europeans want to avoid by all means.
Middle East’s Next Oil War? Israel Threatens Lebanon Over Hezbollah and Natural Gas - Israel has threatened to invade Lebanon amid a recent spat over natural resources and militant groups that, once again, raised tensions between the longtime foes.Addressing the Institute for National Security Studies at Tel Aviv University on Wednesday, Israeli Defense Minister Avigdor Lieberman said that Lebanon’s latest plans to drill in a disputed offshore oil and gas field known as Block 9 were “very, very challenging and provocative,” according to Reuters. In the same speech, the far-right minister threatened to wage a full-scale war against Lebanon if Hezbollah launched any attacks against Israel. The Iran-backed Shiite Muslim movement warned it would defend Lebanon’s natural resources at any cost. “We reiterate our firm and unequivocal position in decisively confronting any aggression against our oil and gas rights, defending Lebanon’s assets and protecting its wealth,” Hezbollah told Newsweek in an email statement. Israel has invaded Lebanon twice, the first time during the 15-year Lebanese civil war and a second time in 2006 in response to Hezbollah’s cross-border raids. In both instances, Hezbollah led the local resistance against Israel, which ultimately withdrew. In the latest crisis, Israel has warned foreign companies not to invest in Lebanese plans to explore the Block 9 offshore oil reserve located on the maritime border between Israel and Lebanon. Lebanon awarded bids last month to France’s Total Sa, Italy’s Eni SpA and Russia’s Novatek PJSC to drill for oil and gas in blocks 4 and 9 within Lebanon’s exclusive economic zone, but Lieberman warned this was a “grave mistake” and “contrary to all the rules” because Block 9 belonged totally to Israel, Bloomberg News reported, citing an Israeli Defense Ministry statement.
Miscalculations in Israel Could Pave Way to Wider War - Last week, Israeli political leaders were rolling with guffaws and ribbing each other in delight as Vice-President Mike Pence proved that, as a Christian Zionist, he was more Zionist than the Zionists in the Knesset (minus, of course, its evicted Arab members – see here). But one might wonder what the more sober Israeli security echelon figures were thinking as they listened to Pence’s Knesset speech, which was rife with Biblical references and declarations of his “admiration for the People of the Book.”Perhaps they were speculating how far they might be able to go in influencing Pence and his boss, Donald Trump, to wield U.S. military power to advance Israeli interests.Prime Minister Benjamin Netanyahu, via the Trump family go-betweens – Jared Kushner, and the Trump family lawyers – has certainly had an impact in Washington. The Middle East landscape has changed considerably over the last year as a consequence, but the nature of that change is what is at issue. How many of these changes have actually benefited Israel’s – or the U.S.’s – security interests?When Saudi Crown Prince Mohammad bin Salman (MbS) began his coup last June, ultimately resulting in this 31-year-old assuming absolute power, President Trump characteristically took full credit. “We’ve put our man on top!” he bragged to his friends, according to Michael Wolff in his book, Fire and Fury. Yes, Trump was right – partly. “Our man” came out on top, but it was Netanyahu, working the levers behind the scenes, and Mohammad bin Zayed (MbZ)’s “man” in Washington, United Arab Emeriates Ambassador Yousef al-Otaiba, who did the heavy lifting in order to change the U.S.’s settled preference for Prince bin Naif, as Successor to the Throne. And it was MbZ, in the first place, who had advised MbS that it was Israeli support that was both the necessary, and the sufficient condition, for him to become Crown Prince. Netanyahu (and Israel) cannot escape some responsibility for the condition in which the kingdom now finds itself.
Turkey Demands US Forces Leave Syria's Manbij Immediately - As Turkish and allied militant forces from the so-called Free Syrian Army (FSA) advance further upon Kurdish positions in northern Syria, Turkey has called upon the United States to vacate its military bases in the Syrian district of Manbij. Speaking to reporters on Saturday, Turkish foreign minister Melet Cavusoglu said that Ankara is calling upon the US, its official ally in NATO, to cease any and all support to Syrian Kurdish forces and militias. Cavusoglu’s statement came mere hours after an official telephone talk between Turkey’s Presidential Spokesman Ibrahim Kalin and US National Security Adviser Herbert Raymond McMaster about the ongoing Turkish invasion of Syrian soil. ] Though unconfirmed by officials in Washington, the US-funded Voice of America reports that McMaster "pledged to stop giving arms to YPG Kurdish forces in Syria" during the phone call. However, it is unclear what this would mean on the ground as the Pentagon has in the past attempted to make a linguistic distinction between the YPG per se (Kurdish "People's Protection Units") and the Syrian Democratic Forces (the former comprises the bulk of the latter), as well as a distinction between YPG operating in Afrin Canton and the rest of Kurdish forces in Rojava. While both Turkey and the United States are in violation of international law by entering Syria with military forces without permission by Damascus or a UN mandate, both countries have vastly different interests in the country.
US, Turkish Troops Headed For Military Showdown In Syria - Two days after we reported that Turkey valiantly demanded that US forces vacate military bases in the Syrian district of Manbij, when Turkey's foreign minister Melet Cavusoglu also said that Ankara is calling upon the US to cease any and all support to Syrian Kurdish forces and militias, not surprisingly the US refused, and on Monday a top American general said that US troops will not pull out from the northern Syrian city of Manbij, rebuffing Ankara demands to withdraw from the city and risking a potential confrontation between the two NATO allies. Speaking on CNN, General Joseph Votel, head of the United States Central Command, said that withdrawing US forces from the strategically important city is "not something we are looking into." Last week Turkish troops crossed into Syria in an push to drive US-backed Kurds out of Afrin. As part of the Turkish offensive, which is grotesquely code-named ‘Operation Olive Branch’, president Erdogan warned that the offensive could soon target “terrorists” in Manbij, some 100km east of Afrin. “With the Olive Branch operation, we have once again thwarted the game of those sneaky forces whose interests in the region are different,” Erdogan said in a speech to provincial leaders in Ankara last week. “Starting in Manbij, we will continue to thwart their game.”But not if the US is still there, unless for the first time in history we are about to witness war between two NATO members. And the US has no intention of moving.Colonel Ryan Dillon, spokesperson for the US-led coalition, told Kurdish media on Sunday that American forces would continue to support their Kurdish allies – despite Erdogan’s threats.
Why Turkey's battle for northern Syria matters - BBC News: Anyone who thought that the defeat of the Islamic State group would lead to an end or a simplification of the conflict in Syria was wrong. Just look at Turkey's controversial offensive in Syria's northern region of Afrin, intended to extend Turkey's existing buffer zone inside the country and to evict Kurdish fighters from a broad swathe of territory. The Ankara government sees the fighters as allies of Kurdish separatists inside Turkey. Indeed, despite various shifts in Turkish policy towards the conflict in Syria, opposition to Kurdish autonomy has been constant and absolute. The Turks will simply not tolerate what they see as the threat posed by an autonomous Kurdish zone on their southern frontier. And they are clearly willing to use significant force to remove it. But just how much force, and how far could this conflict in northern Syria go? The Kurdish fighters have long been trained and backed by the Americans, indeed, they have proved to be the most capable of Washington's allies in the struggle against Islamic State. And with IS defeated, at least as a territorial entity, the Kurds were able to consolidate control over a considerable region in the north. For Washington, the Turkish offensive raises difficult problems. It was poor messaging by a US military spokesman speaking about the creation of a Kurdish border force to maintain security in northern Syria that gave Ankara its immediate cause to launch its attack.This is an uncomfortable position for Washington: its Nato ally Turkey engaged in fierce combat with its main ally in Syria, the Kurds. And it could get worse.
The "Dirty Game" To Fuel Ethnic Proxy War Across The Greater Middle East -- Turkish allegations of Saudi, Emirati and Egyptian support for the outlawed Kurdish Workers Party (PKK) threatens to turn Turkey’s military offensive against Syrian Kurds aligned with the PKK into a regional imbroglio. The threat is magnified by Iranian assertions that low-intensity warfare is heating up in areas of the Islamic republic populated by ethnic minorities, including the Kurds in the northwest and the Baloch on the border with Pakistan. Taken together, the two developments raise the specter of a potentially debilitating escalation of the rivalry between Saudi Arabia and Iran as well as an aggravation of the eight-month-old Gulf crisis that has pitted Saudi Arabia and its allies against Qatar, the latter which has forged close ties to Turkey. The United Arab Emirates and Egypt rather than Saudi Arabia have taken the lead in criticizing Turkey’s incursion into Syria designed to remove US-backed Kurds from the border region and create a 30-kilometer deep buffer zone. UAE Minister of State for Foreign Affairs Anwar Gargash said the incursion by a non-Arab state signaled that Arab states would be marginalized if they failed to develop a national security strategy.Notably Egypt, for its part, condemned the incursion as a "fresh violation of Syrian sovereignty" that was intended to "undermine the existing efforts for political solutions and counter-terrorism efforts in Syria."Despite Saudi silence, Yeni Safak, a newspaper closely aligned with President Recep Tayyip Erdogan’s ruling Justice and Development Party (AKP), charged that a $1 billion Saudi contribution to the reconstruction of Raqqa, the now Syrian Kurdish-controlled former capital of the Islamic State, was evidence of the kingdom’s involvement in what it termed a "dirty game." Analysts suggest that Saudi Arabia may have opted to refrain from comment in the hope that it could exploit the fact that Iran, a main backer of Syrian president Bashar al-Assad, has refused to support the incursion. Nevertheless, Saudi, UAE and Egyptian support for the Syrian Kurds would jive with suggestions that the Gulf states are looking at ways of undermining regimes in Tehran and Damascus by stirring unrest among their ethnic minorities.
A Modest Proposal to dismember Syria … " ... the five countries called for a UN-supervised election for the -Syrians inside and outside the country and for radical changes in the Syrian constitution including stripping the Syrian presidency from most, if not all, of its powers.The five countries also suggested stripping the Syrian government from many of its powers and creating two parliaments that will have limited powers. This will leave most of the state’s establishments under the control of the local authorities in a decentralized political system.Syrian pro-government activists described the proposed constitution as an attempt to legalize the stateless situation in some parts of Syria in order to end the Syrian state once and for all. Bashar Jaafari, the Permanent Representative of Syria to the United Nations, rejected the Arab-Western plan and stressed that its content contradicts with the international resolutions, according to the Syrian Arab News Agency (SANA)." via SF. The French and British created the state of Syria in pursuit of their imperial interests and now, in association with the US and Saudi Arabia, they seek to destroy it. Jordan? This is laughable. Jordan is yet another artifact of the post WW1 re-structuring of the ecumenical empire that the Sublime Porte had more or less governed for hundreds of years in the name of Islam. For the Jordanians to sign on to the destruction of Syria is worse than a crime. It is stupid. Have the Jordanians no sense at all of what may be their fate when greater powers find them inconvenient.Saudi Arabia? Their obvious desire to subjugate the interests of the many religious and ethnic groups of Syria is clear. They have sought Wahhabi Sunni triumphalism and rule in the Levant for many years. Their participation in this foolish proposal is yet more of the same. Unless the Turks conquer a great deal of northern Syria and thereby make moot any such agreement, it is likely that in the end there will be some measure of autonomy granted to the Syrian Kurds by the SAG, but not more than that. Loosely confederated states are not favored in the Islamic World. They are thought to be inherently weak instruments of foreign meddling.