oil prices finished lower this week, but still remained in the same $2 trading range that they've been in for most of this year... prices barely budged on Monday, as US crude for April rose 6 cents, or 0.1%, to settle at $54.05 a barrel while the expiring April contract for Brent crude, the international benchmark price, fell 6 cents, or 0.1%, to $55.93 a barrel...US crude futures then gave up 4 cents of their Monday gains in trading on Tuesday, as traders anticipated that the after market release of oil industry inventory data from the American Petroleum Institute would show an eighth consecutive increase in US crude supplies...oil prices then slipped 18 cents to $53.83 as the expected inventory build materialized, but its impact was muted by news that OPEC compliance with the pledged output cuts had risen to 94% in February...prices then fell more than 2 percent on Thursday to close at $52.61 a barrel after news that Russian crude production remained unchanged in February, therefore meaning they were still producing 200,000 barrels per day more than they had promised...oil prices then found support on Friday after reports emerged that extra production cuts by the Saudis put OPEC compliance near 100%, and went on to close the week at $53.33 a barrel, up 72 cents for the day but still down 66 cents for the week...
natural gas prices, meanwhile, were up every day this week after Monday, but still ended lower than their February 17th print and more than 28% below their post Christmas high....while there is typically little daily news to indicate the underlying reasons for natural gas price changes, Monday saw April natural gas prices fall to $2.693 per mmBTU, after last week's March contract expired at $2.787 per mmBTU...from there it climbed to $2.774 per mmBTU on Tuesday, to $2.799 per mmBTU on Wednesday, to $2.804 per mmBTU on Thursday, and finally to $2.827 per mmBTU on Friday, up 5 cents from last week, despite the fact that the weekly natural gas storage report showed a net increase of 7 billion cubic feet for the week ending February 24th, the first time surplus gas was ever added to storage in February...
of course, these daily quotes are for April natural gas at the Henry Hub in Louisiana, and actual natural gas selling prices vary widely across the country....at the time Henry Hub gas for March was selling for at $2.62/MMBtu on Wednesday, down 77 cents month over month, gas at the Algonquin city gates in Ontario was trading at $3.26/MMBtu, down $4.13 month on month, gas at the New England border was selling for $2.98/MMBtu, while three large terminals in the Appalachians saw gas below $2...that depressed price for Appalachian natural gas is a function of still inadequate pipeline capacity, which keeps natural gas prices for heating and electricity in our region lower than the rest of the country, while simultaneously slowing further increases in drilling and associated fracking...we can expect that advantage to end soon, given the pipelines that are now under construction, or soon to start....
the EIA's Natural Gas Weekly Update for the week ending March 1, 2017 featured a 'news for the week' headline of "U.S. liquefaction capacity continues to expand", and since our own focus of last week's newsletter was on the expansion of LNG exports, we'll start today with a graph from that EIA weekly report, which will provide us with a timeline for the expansion of that export capacity..
the above graphic, taken from this week's Natural Gas Weekly Update, shows the expected completion time and the natural gas capacity for each of the liquefied natural gas (LNG) trains now under construction in the US...each of these trains are color coded as to which LNG plant they are part of, and the size of the bar represents the capacity in billions of cubic feet of gas per day that the train is expected to process when it's completed...briefly, each of these "trains" takes raw natural gas as it comes out of the delivery pipeline and removes all the impurities that are normally in the raw gas that can't be included in LNG because they freeze at different temperatures than methane, then lowers the temperature of the pure methane to approximately −260 °F, at which point the gas becomes liquid and thus takes up about 1/600th the volume of natural gas in the gaseous state...it is then stored in supercooled tank farms at the terminal until it is ready to be loaded onto ocean going tankers...(btw, if LNG should ever come in contact with even cold water, it will explode to 600 times its volume)
the sky blue bars above represent trains 4 and 5 of the Sabine Pass LNG facility at Sabine Pass, Louisiana, on the Gulf of Mexico at the Texas border, which now has three LNG trains already in operation...the "nameplate capacity" of each of the Sabine Pass trains is 0.7 billion cubic feet of gas per day, but the three existing trains are now processing 2.3 billion cubic feet of gas per day, so i assume these capacities aren't cast in stone...the 4th train of Sabine Pass is expected to be operational in the 3rd quarter of this year, and thus will shortly boost our national natural gas exports up to 3.0 cubic feet of gas per day...following that, train 1 of the export facility at Cove Point Maryland, indicated by the brown bar, is expected to add another 0.7 billion cubic feet of gas per day of liquefaction and export capacity in the 4th quarter of this year....Cove Point was originally an LNG import and storage terminal, so what were once distribution pipelines from that facility will now be the pipelines that will be delivering fracked gas from the Marcellus and Utica shales to that terminal for export..
the rest of the liquefaction and export capacity now under construction will not be complete until the second half of 2018 or later...Elba Island LNG, located in Georgia, is shown in grey and featured in this week's Natural Gas Weekly Update...Elba Island will be using a new technology that will consist of ten small-scale liquefaction trains, each with a capacity to liquefy approximately 33 million cubic feet per day (MMcf/d), with 6 to be completed in the 3rd quarter of next year, and 4 to be added at the beginning of 2018, for a total project export capacity of 0.35 billion cubic feet per day...at the same time, the first train of Cameron LNG Liquefaction Project in Hackberry, Louisiana, indicated in green, will add another 0.7 billion cubic feet of gas per day of liquefaction and export capacity in the 3rd quarter of next year, with additional 0.5 billion cubic feet of gas per day trains to be added at that facility in the 4th quarter of 2018 and the 3rd quarter of 2019...Cameron trains 4 and 5, currently on the drawing board, are not included in the above graphic of under construction facilities...
in the 4th quarter of 2018, the first train of the Freeport Liquefaction and Export Project, indicated by orange bars, will be completed, adding another 0.7 billion cubic feet of gas per day of liquefaction and export capacity, and they'll add similar sized trains in the 2nd quarter and 4th quarter of 2019...they already have 20 year contracts to sell the output of that LNG terminal to Toshiba, BP, Osaka Gas and Chubu Electric, which means they'll have a claim to US natural gas production before Americans will...lastly, the first two trains of the Corpus Christi Liquefaction facility, shown in a wine color, will be added in the 1st and second quarters of 2019...this was originally an LNG import and regasification terminal run by Cheniere Energy, the parent of the Sabine Pass facility, and is being refitted to liquefy and export LNG...when the plants represented by the graphic above are completed, the US is projected to have a 9.4 billion cubic feet per day liquefaction and export capacity, the third largest in the world, just behind that of Australia and Qatar...that would represent about 10% of our total natural gas production, assuming there no major changes in our own consumption over the next three years..
The Latest Oil Stats from the EIA
this week's oil data for the week ending February 24th from the US Energy Information Administration indicated that our imports of crude oil increased from the prior week's depressed levels, that our refinery activity also increased from last week's two year low but remained below normal, and that we again had a surplus of crude added to our stockpiles for the 8th week in a row, which were thus at another an all time high...our imports of crude oil rose by an average of 303,000 barrels per day to an average of 7,589,000 barrels per day during the week, while at the same time our exports of crude oil fell by 490,000 barrels per day to an average of 721,000 barrels per day, which meant that our effective imports netted out to 6,868,000 barrels per day for the week, 793,000 barrels per day more than last week...at the same time, our crude oil production rose by 31,000 barrels per day to an average of 9,032,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 15,900,000 barrels per day during the week...
meanwhile, refineries reportedly used 15,664,000 barrels of crude per day during the week, 393,000 barrels per day more than during the prior week, while at the same time, 214,000 barrels of oil per day were being added to oil storage facilities in the US...thus, this week's EIA oil figures seem to indicate that we used or stored 22,000 less barrels of oil per day than were accounted for by our net oil imports and oil well production…therefore, in order to make the weekly U.S. Petroleum Balance Sheet balance out, the EIA inserted a phantom -22,000 barrel per day number onto line 13 of the petroleum balance sheet, which the footnote tells us represents "unaccounted for crude oil"...that "unaccounted for crude oil" is further described in the glossary of the EIA's weekly Petroleum Status Report as "the arithmetic difference between the calculated supply and the calculated disposition of crude oil.", which means they got that balance sheet number by backing into it, using the same arithmetic we just illustrated.....
the weekly Petroleum Status Report also tells us that the 4 week average of our oil imports fell to an average of 8.185 million barrels per day, now just 5.1% higher than the same four-week period last year...meanwhile, the 4 week average of our oil exports was at 881,000 barrels per day, which is noted as 122.5% higher that a year earlier...that apparent big jump in our oil exports has led some in the media to suggest our oil exports are replacing those oil exports held off the global markets by OPEC...however, that's a percentage increase off a very small base, and our year to date oil exports which averaged have 763,000 barrels per day only represent 341,000 more barrels per day than last year's average of 421,000 barrels per day....at the same time, our oil imports have increased by 413,000 barrels per day from a year ago, from an average of 7,871,000 barrels per day during the first 8 weeks of 2016 to an average of 8,284,000 barrels per day this year....what appears to be happening is that we are exporting light sweet crude which we have an abundance of, and importing heavier sour crudes which our refineries are optimized to use...so while our oil exports may rise as we unload our surplus light oil, because we're importing even more oil to replace what we're exporting, our exports are not a threat to the OPEC cuts..
meanwhile, this week's 31,000 barrel per day oil production increase was facilitated by a 32,000 barrel per day increase in oil production in the lower 48 states, while at the same time oil output from Alaska fell by 1,000 barrels per day...our crude oil production of 9,032,000 barrels during the week ending February 24th was the most we've produced since mid-March of last year and was only a half percent lower than the 9,077,000 barrels of crude per day that we produced during the week ending February 26th of last year, while it remained 6.0% below our record for oil production of 9,610,000 barrels per day that we set during the week ending June 5th 2015 ..
US refineries were operating at 86.0% of their capacity in using those 15,664,000 barrels of crude per day, up from 84.3% of capacity the prior week, but down from the year high of 93.6% of capacity seven weeks earlier, when they were processing 17,107,000 barrels of crude per day....their processing of oil is also still down by 1.2% from the 15,852,000 barrels of crude that were being refined during the week ending February 26th, 2016, when refineries were operating at 88.3% of capacity....but even with the refinery pickup, gasoline production from our refineries was little changed, rising by just 27,000 barrels per day to 9,456,000 barrels per day during the week ending February 24th, which as it turns out was 1.3% more than the 9,335,000 barrels per day of gasoline that were being produced during the week ending February 26th a year ago, when gasoline output inexplicably slumped for a week...at the same time, refineries' production of distillate fuels (diesel fuel and heat oil) rose by 288,000 barrels per day to 4,755,000 barrels per day, which was still a bit less than the 4,801,000 barrels per day of distillates that were being produced during the week ending February 26th last year...
with the nominal increase in our gasoline production, the EIA reported that our gasoline inventories fell by 546,000 barrels to 255,889,000 barrels as of February 24th, as our domestic consumption of gasoline inched up by 23,000 barrels per day to a still below normal 8,686,000 barrels per day, while our gasoline exports rose by 43,000 barrels per day to 891,000 barrels per day and our gasoline imports rose by 90,000 barrels per day to 457,000 barrels per day...however, even with this week's inventory draw down, our gasoline supplies were at an all time high for the 3rd week in February, as they were up slightly from the 254,989,000 barrels of gasoline that we had stored on February 26th of last year, while they were 6.6% above the 240,060,000 barrels of gasoline we had stored on February 20th of 2015...
even with the large increase in our distillates production, our supplies of distillate fuels also fell, decreasing by 925,000 barrels to 165,133,000 barrels by February 24th, which was still much less of a drop than the 4,924,000 barrel drawdown of distillates last week...that was as the amount of distillates supplied to US markets, a proxy for our consumption, fell by 479,000 barrels per day to 3,813,000 barrels per day, and as our imports of distillates rose by 81,000 barrels per day to 210,000 barrels per day, while our exports of distillates rose by 277,000 barrels per day to 1,284,000 barrels per day....even so, our distillate inventories are still 0.4% higher than the distillate inventories of 160,715,000 barrels of February 26th during the warm winter of last year, and 33.5% above the distillate inventories of 122,976,000 barrels of February 27th, 2015…
finally, with the increase in our net oil imports significantly larger than the increase in refinery demand, we again had surplus crude remaining, and hence our inventories of crude oil rose for the 8th week in a row to yet another record, as they increased by 1,501,000 barrels to 520,184,000 barrels by February 24th...thus we ended the week with 8.6% more crude oil in storage than the 479,012,000 barrels we ended 2016 with, 6.9% more crude oil in storage than the then record 486,699,000 barrels we had stored on February 26th of 2016, 26.8% more crude than the 410,246,000 barrels of oil we had in storage on February 27th of 2015 and 56.5% more crude than the 332,453,000 barrels of oil we had in storage on February 28th of 2014...so you can all see what those record supplies look like, we'll include a picture of the interactive graph that accompanies the ending stocks of crude oil page at the EIA, which is much easier to understand than the complicated graphs on this that we've featured recently...
This Week's Rig Count
US drilling activity increased for the 17th time in 18 weeks during the week ending March 3rd, but just barely....Baker Hughes reported that the total count of active rotary rigs running in the US increased by just 2 rigs to 752 rigs in the week ending on this Friday, which was still 267 more rigs than the 489 rigs that were deployed as of the March 4th report in 2016, but far from the recent high of 1929 drilling rigs that were in use on November 21st of 2014...
the count of rigs drilling for oil rose by 7 rigs to 609 rigs this week, which was up from the 392 oil directed rigs that were in use a year ago, but down from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...meanwhile, the count of drilling rigs targeting natural gas formations fell by 5 rigs to 146 rigs this week, which was still up from the 97 natural gas rigs that were drilling a year ago, but down from the recent natural gas rig high of 1,606 rigs that were deployed on August 29th, 2008...there also remained a single rig that was classified as miscellaneous, which is marked as a 1 rig increase from a year ago, when there were no such miscellaneous rigs at work...
one more drilling platform was added to those working in the Gulf of Mexico this week, this time offshore from Texas, which brought the Gulf of Mexico count up to 18, still down from 24 during the same week of 2016...that also brought the total US offshore count for the week up to 18 rigs, all in the Gulf of Mexico, down from 24 offshore rigs a year ago, when they also were all in the Gulf of Mexico...
the number of horizontal drilling rigs working in the US increased by 9 rigs to 633 rigs this week, which is now up by 244 horizontal rigs from the 389 horizontal rigs that were in use in the US on March 4th of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, a net of 1 vertical rig was added this week, bringing the vertical rig count up to 62, which was also up from the 58 vertical rigs that were deployed during the same week a year ago...on the other hand, 8 directional rigs were taken out of service during the week, cutting the directional rig count back to 61, which was still up from the 42 directional rigs that were deployed during the same week last year....
as usual, 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 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 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 March 3rd, the second column shows the change in the number of working rigs between last week's count (February 24th) and this week's (March 3rd) count, the third column shows last week's February 24th active rig count, the 4th column shows the change between the number of rigs running this 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 4th of March, 2016...
as you can see above, the rig count increases this week were in the oil basins that saw their largest expansion earlier in the decade and have been more or less ignored recently, as the Permian and the SCOOP / STACK in Oklahoma's Cana Woodford have been in ascendancy....the Eagle Ford of south Texas, which once hosted 259 rigs, added 5 this week to bring their total back up to 69 rigs, while the Williston basin of North Dakota, home of Bakken crude, which had 224 rigs at that time, added 3 rigs this week to get their count back up to 38 rigs...meanwhile, the three major gas basins, the Marcellus, the Utica, and the Haynesville, each saw one rig pulled out, while 2 gas rigs were also removed from unnamed "other basins"...since Pennsylvania saw a 2 rig decrease and the Ohio rig count remained unchanged at 19 rigs, it's apparent that the Utica shale rig which was shut down this week had been drilling in Pennsylvania..
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Homeowners being sued over plan to build 800-mile pipeline: The stakes along a neighbor’s horse farm, about 100 feet from Jerry and Karen Jones’ Putnam Township home, mark where the ET Rover natural gas pipeline will run. Karen Jones said the family will likely move away because of the pipeline. She worries their home is too close if an explosion occurred. “It’s devastating,” she said. “We built our house 11 years ago, and it’s all our blood, sweat and tears. It’s our retirement.” The Federal Energy and Regulatory Commission on Feb. 2 gave Energy Transfer Rover approval to build an 800-mile interstate natural gas pipeline. The Rover Pipeline will pass through about 15 miles of Livingston County, coming from the south through Washtenaw and Lenawee counties. Now the company is suing property owners in the three Michigan counties, to gain easements to build the pipeline. In Livingston County, that includes eight private property owners and the county's drain commission. The company also wants to expedite the process, which usually takes months, in order to seize the lands and start clearing trees. It is required to clear trees before March 31, in order to protect the Indiana Bat, an endangered species. U.S. District Court Judge Mark A. Goldsmith is considering Energy Transfer’s motion for a preliminary injunction that would allow the company to take possession of the land immediately, in order to stick to a tight schedule, according to court records. A court hearing last Thursday lasted all day and will resume March 9. The pipeline will transport an estimated 3.25 billion cubic feet of natural-gas produced in the Marcellus and Utica shale formations, passing through West Virginia, Pennsylvania, Ohio and Michigan, and then on into Canada.
Is Pa. pipeline fight on Amish farm the next Standing Rock? “We’re prepared to be here for months” - With an evacuation deadline looming, the protest camp at Standing Rock went up in flames. Crowds that once numbered 10,000 dwindled to dozens Wednesday after an evacuation order from North Dakota's governor. Stragglers faced arrest. Some set fire to the tents and teepees that housed them there in an act of defiance, native ritual or both. Mark Clatterbuck watched footage of this from his home in Lancaster County. He'd gone to Standing Rock last year and been there during a violent clash between protesters and security personnel that helped thrust the protest into the international spotlight. He's also spent years fighting a natural gas pipeline project in his own backyard, one set to cross through 10 Pennsylvania counties and 200 miles of terrain. For Clatterbuck and activists like him, Standing Rock was a watershed moment, he explained, and its lessons and catalytic properties capable of being taken home and re-harnessed. Just last week, Clatterbuck helped oversee the beginnings of a DAPL-inspired encampment on an Amish farm in Lancaster County atop the route of the proposed pipeline he's spent years working to stop. He says hundreds of people, mostly locals, have also signed pledges "committing to civil disobedience to protect our homes, farms and properties" once pipeline construction begins. Hundreds have also taken "non-violent mass-action" trainings, he added.
Hare Krishna Community Sues DAPL Company to Protect Sacred Lands From Rover Pipeline -- Energy Transfer Partners, the company behind the Dakota Access Pipeline , is facing a familiar legal battle over its proposed Rover Pipeline . A Hare Krishna community in West Virginia is challenging the project on religious grounds, saying that the pipeline's planned route could cut through sacred lands. The New Vrindaban community in Marshall County was once America's largest Hare Krishna settlement, and is home to the Palace of Gold , an ornate temple that has been described as America's Taj Mahal. The religious organization, which has been trying to rebuild itself since the 1980s after being rocked by numerous scandals, happens to sit on the gas-rich Marcellus Shale. The commune has more or less welcomed gas leases as a means to repair its crumbling infrastructure and start new projects, and has reportedly netted more than $4.3 million in royalties. While the religious organization signed leases in 2010 and 2014 to sell the natural gas under its properties, according to its federal lawsuit filed at U.S. District Court in Wheeling on Tuesday, those leases do not allow for any surface disturbances and blocks off sacred areas from outside intrusion. The Pittsburgh Post-Gazette reports that the lawsuit seeks to block Rover's legal request for immediate access and possession of the pipeline pathway through two of the community's seven sacred temples. Energy Transfer Partners wants to build the pipeline on a permanent 50-foot-wide right of way about 3,000 feet long on the two properties, offering property owners $7,000. But the complaint states that the project infringes on religious freedom as it "seeks to take a non-metaphorical bulldozer through the Vrindaban Parties' property, and in turn, through their most sincerely held holy sites."
Shaking off fracking's unexpected aftermath - - Pennsylvanians need not shake in their boots over a finding by state environmental regulators that there is a likely correlation between a gas fracking operation in western Pennsylvania and a series of small earthquakes in that region.The earthquakes last April in Lawrence County were too weak to be felt by residents of the area and they did not cause any damage.Seth Pelepko of the state Department of Environmental Protection told the Associated Press that the state’s geology across the areas being drilled for natural gas generally does not lend itself to the more intense earthquakes that have affected other drilling regions, including Ohio and Oklahoma.The correlation between a particular fracking site and minor earthquakes is illustrative, though, in that earthquakes were not among the advertised potential environmental issues when the debate about drilling and levels of state regulation began more than a decade ago.Most of that discussion has been relative to water and air quality, which are more immediate concerns.Earthquakes are an unanticipated consequence of drilling and fracking that has emerged over time.The discovery raises questions about other unforeseen consequences that might arise later on, and the degree to which the industry and the state government are prepared to deal with them.In the earthquake case, driller Hillcorp Energy Co., based in Houston, stopped fracking the well in question and decided not to use a particular technique at other wells that it had employed at the suspect well.The DEP also required the driller to place seismic monitors in the host township.
Southwestern Energy Reaches Utica Shale in West Virginia –– Company officials believe Southwestern — which in 2014 paid Chesapeake Energy $5 billion to acquire its West Virginia assets — remains in a strong position as natural gas prices slowly recover, while the firm now has a successful Utica Shale operation in Marshall County. Southwestern now controls virtually all Marcellus and Utica shale drilling and fracking in Ohio and Brooke counties, along with substantial acreage in both Marshall and Wetzel counties. The Houston, Texas-based firm reported a $2.4 billion loss on drilling and fracking for 2016, but this is actually a significant improvement because its 2015 loss was $7.1 billion. In 2015, Southwestern President and CEO Bill Way said the company planned to invest $24 billion to produce oil and natural gas in West Virginia over the next two decades. Southwestern is one of the many oil and natural gas drillers increasing activity again as global prices slowly recover. According to oilfield services giant Baker Hughes, the number of active rigs in West Virginia is now 10, which is up from just seven in August. Among the rigs in use is the one Southwestern recently moved along Doolin Run Road in Wetzel County. “We hired off-duty state troopers to assist with traffic matters, which significantly reduced the travel time and interruption to the normal flow of traffic. Southwestern Energy is committed to reducing the time and amount of equipment on the roads when we can to minimize the impact to residents,” company spokeswoman Maribeth Anderson said. Southwestern is now producing from the Utica Shale in Marshall County, which is deeper in the earth than the Marcellus formation, so it requires more time, pipe, sand, water and chemicals. However, the company did cut overall production, due to low prices, in 2016 to 875 billion cubic feet, down from 976 Bcf in 2015. The company that sold these assets to Southwestern, Chesapeake, continues its operations in Ohio. The Oklahoma City-based fracker posted an overall loss of $3.14 billion in 2016.
Enbridge completes acquisition of Spectra Energy - Canada's Enbridge on Monday completed its acquisition of Houston-based Spectra Energy in a stock-for-stock merger transaction, which is expected to create one of the largest energy infrastructure companies in North America. "With the completion of the transaction, Enbridge has become a global energy infrastructure leader with roughly $126 billion in enterprise value," Enbridge spokesman Todd Nogier said in a statement Monday. "This combination brings together the best liquids and natural gas franchises in North America and is complemented by our rapidly growing renewable power generation business," he said. The merger, valued at $28 billion (C$37 billion) when it was announced in September, will combine Enbridge's liquid-weighted midstream assets located primarily in western Canada and the US Midwest with Spectra's network of primarily gas-related midstream assets, which include holdings in the US North, Gulf Coast and Midwest and the Canadian province of British Columbia.Unlike last year's abortive attempt to combine two giant midstream companies -- the proposed acquisition of The Williams Companies by Energy Transfer Equity, which fell apart in June -- the merger of Enbridge and Spectra moved through the regulatory process with relative ease. Given that the asset sets of the two companies were geographically diverse, Canadian or US regulators found little reason to challenge the proposed deal on grounds that it would harm competition.
Emerging supply constraints and premium pricing in south Texas. - There is a premium natural gas market developing in South Texas, where exports to Mexico could rise by more than 2.0 Bcf/d over the next four years and gas liquefaction and LNG export facilities are expected to add another 1.8 Bcf/d of demand to the market in that time. While gas production from the nearby Eagle Ford Shale is showing signs of at least a partial comeback and will help meet some of this new demand, the South Texas market may be heading toward being short supply in the next few years, resulting in higher prices there relative to surrounding markets. That would make the South Texas market an attractive destination for supply as far north as the Marcellus and Utica shales. In fact, there is a slew of proposed southbound pipeline projects extending deep into Texas along the Texas Gulf Coast for shippers to get their gas there. But how much incremental supply will be needed to balance the market? Today we begin a series analyzing the gas supply and demand balance in South Texas, starting with prospects for production growth out of the Eagle Ford Shale. One of the biggest enablers of U.S. natural gas production growth over the next several years will be the emerging export demand along the Texas Gulf Coast and across the border in Mexico—a subject we’ve written about extensively in our “I Saw Miles and Miles of Texas” Drill Down series. The low gas-price environment has spurred massive investment in new petrochemical plants, LNG export facilities and cross-border pipeline systems to serve growing electric generation demand in Mexico. A good portion of this emerging export demand in the next few years will be sourcing its gas from South Texas via a little-known trading hub in Nueces County, TX called Agua Dulce (30 miles west of Corpus Christi, TX).
Exxon Mobil Turns to U.S. Shale Basins for Growth: Exxon Mobil Corp. on Wednesday outlined an ambitious plan to turn to prolific U.S. shale basins for growth, showcasing how the oil giant now sees American production as a key to its future. The company plans to spend about a fourth of its 2017 budget -- about $5.5 billion -- drilling in Texas, New Mexico and North Dakota, tapping a vast inventory of wells that can turn a profit at a price of $40 a barrel. The U.S. increasingly appears at the center of a burgeoning global revival after prices rebounded modestly and companies such as Exxon have improved in their ability to profit due to lower costs and feats of engineering. Yet unlike some peers that plan to keep investment roughly flat in future years, Exxon plans to increase spending to an average of $26 billion a year from 2018 to 2020. The company plans $22 billion in investments this year. "Our job is to compete and succeed in any market, irrespective of conditions or price," new Chief Executive Darren Woods said at Exxon's analyst meeting in New York. It is his first major appearance since taking over for Rex Tillerson, who stepped down to become President Donald Trump's secretary of state. "The ultimate prize in the Permian is significant," he said, noting that the land the company controls in the West Texas and New Mexico oil region may hold the equivalent of as much as 6 billion barrels of oil and natural gas. The company also plans to invest in Guyana, where it made a major discovery in 2015.
Exxon Mobil shifts investments to quick-earning shale: (Bloomberg) -- Exxon Mobil Corp. is trading in long-term projects that pump oil over decades for U.S. shale drilling that can be switched on or off as crude prices change. Long a world leader in multi-billion dollar oil and natural gas developments that take years to build and even longer to profit, Exxon is diverting about one-third of its drilling budget this year to shale fields that will deliver cash flow in as little as three years, said Chairman and CEO Darren Woods. Next year, U.S. shale will absorb 50% of Exxon’s worldwide drilling budget, Woods said Wednesday during his first public appearance since succeeding Rex Tillerson in January. Output from shale wells will grow an average of 20% annually through 2025 as Woods intensifies the company’s focus on the Americas. “The shift from long to short is really a reflection of the opportunity that has grown in the short-cycle business,” Woods said. “That part of the business isn’t in discovery mode; it’s in extraction mode.” Exxon was a late-comer to shale, shunning it for the first decade of this century as a niche that couldn’t generate enough output to make a mark on the balance sheet of a major international explorer. When Tillerson steered Exxon into shale drilling with its $34.9 billion acquisition of gas explorer XTO Energy in 2010, he conceded Exxon had missed out on the first wave of the fracking revolution.
Epic pipeline from Permian to Corpus Christi announced -- Yet another pipeline is in the works. A 730-mile cross-Texas pipeline would take crude oil and condensates from the Permian Basin to the Port of Corpus Christi and other area drop-offs. The so-called Epic Pipeline would have a maximum capacity of 440,000 barrels per day with crude pickup points include Orla, Pecos, Crane and Midland, according to a news release. Three companies are working together to build the pipeline. San Antonio-based TexStar Midstream Logistics, Connecticut-based Castelton Commodities International, and Texas-based Ironwood Midstream Energy Partners are currently bidding out the first 200,000 barrels of pipeline capacity. They have not revealed cost nor start date of construction, but say it will be in operation by the first quarter of 2019. TexStar Logicstics is also currently developing a project in the Houston Ship channel and is actively pursuing other opportunities in the Permian Basin, South Texas and East Texas.
Will natural gas production in SCOOP/STACK be "OK"? A New Drill Down Report - The production economics of the crude oil-focused SCOOP and STACK plays in central Oklahoma are among the best anywhere—in fact, only the Permian Basin’s numbers outshine them. But, as in the Permian, crude production in SCOOP and STACK can only grow if sufficient midstream infrastructure is in place to process and take away all of the associated natural gas the wells there produce. Processing and takeaway constraints aren’t big issues in SCOOP/STACK yet, but they will be soon. Today we discuss highlights from RBN’s new Drill Down Report on production growth and looming infrastructure constraints in two of the U.S.’s most promising shale plays. The South Central Oklahoma Oil Province (SCOOP) and Sooner Trend Anadarko Canadian Kingfisher (STACK) plays in central Oklahoma have emerged as two of the most prolific and attractive shale producing regions in the U.S. The SCOOP/STACK region is much smaller than the Permian in West Texas and southeastern New Mexico, but the plays have similar characteristics. For one, SCOOP and STACK, like the Permian, are primarily oil plays but with significant volumes of associated gas and natural gas liquids (NGLs); further, they have very attractive producer economics in core areas, as well as resilient and increasing rig counts in those areas. And they share a robust outlook for future production. All that means 1) that more midstream infrastructure will be needed to support the production growth, and 2) that if new capacity isn’t added fast enough, takeaway capacity constraints could result in dire consequences for commodity prices within the region.
Is there enough natural gas takeaway capacity from the SCOOP / STACK -- part 5 -- Natural gas production out of Oklahoma’s SCOOP and STACK plays has been resilient in the face of lower oil and gas prices and is expected to grow by about 1.5 Bcf/d over the next five years. But with the Marcellus/Utica increasingly competing for both pipeline capacity and demand markets outside the Northeast region, the question is where can and will the new SCOOP/STACK supply go? That will be dictated in large part by where demand is growing—primarily along the Gulf Coast—and where the price differentials are attractive. But flows also can be hindered or facilitated by another, preeminent factor: pipeline takeaway capacity. Today we explore the potential for takeaway constraints out of the SCOOP and STACK. Earlier this week, we published our latest analysis and projections on production and infrastructure out of the SCOOP/STACK in the Drill Down Report, “Will Natural Gas Production in the SCOOP/STACK Be OK?” We’ve also posted some of that analysis on the RBN blogosphere in the “Stardust, And Much More” blog series. The SCOOP and STACK plays (acronyms for South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher, respectively) are located within an 11-county area of central Oklahoma where drilling for crude oil, natural gas liquids (NGLs) and condensates in the Woodford and Meramec formations of the Anadarko Basin is driving a revival of associated natural gas production volumes (see Scoop-y Doo and All Come to Look for a Meramec). As we noted in Part 1 of this series, gas production from the Midcontinent (Midcon) region has been in decline since mid-2014 when oil prices crashed, but gas production from Oklahoma has remained fairly flat in that time, propped up by rising gas volumes from the SCOOP and STACK plays. The two plays have some of the highest internal rates of return (IRRs) among oil-focused plays, second in profitability only to the Permian Basin.
Are fracking and earthquakes really connected? - - Oklahoma recorded 623 earthquakes of magnitude 3.0 or higher in 2016; throughout the 1990s, it felt only 16. The state’s largest-ever — a 5.8 magnitude quake felt from Chicago to Denver — hit in September 2016. By comparison, California experienced about 137 in 2016. Activists have blamed this spike in seismic activity on the controversial recent boom in hydraulic fracturing — or “fracking,” when fluids are injected at high pressure to fracture underground shale rock and create pathways for oil and gas to escape. But while scientists say fracking may be causing occasional quakes (and associate it with other malaises, often pollution-related), they largely agree that the technique itself is not responsible for a majority of these induced, or human-caused, earthquakes. Instead, a number of recent research papers suggest two other industry procedures are largely responsible. The first is pumping waste liquids into the ground. Oil and gas drillers have long re-injected the salty water that naturally appears in oil deposits, explains a 2015 paper in Science Advances. Tens of thousands of wastewater wells are active in the United States, according to an exhaustive 2013 paper for the National Academy of Sciences, and oversight is limited. Wastewater disposal wells, for example, “normally do not have a detailed geologic review performed prior to injection, and the data are often not available to make such a detailed review. Thus, the location of possible nearby faults is often not a standard part” of setting up these disposal wells. The water is often injected deeper into the earth, so as not to contaminate oil deposits, where it can add pressure to these unseen fault lines. The second, carbon capture and storage (CCS), is a newer process that the Environmental Protection Agency champions as a green alternative to carbon emissions. Yet, as a 2016 paper for the Royal Society of Chemistry explains, CCS often uses a liquid to pump the captured carbon deep into the earth. The National Academy of Sciences paper adds that CCS has an even larger potential to induce seismic events than wastewater disposal because the volumes of injected fluids are theoretically larger, occurring over longer periods of time and under higher pressure.
USGS sees lower earthquake risks in 2017, but Oklahoma hazards remain -- The US Geological Survey lowered its forecast for damage from natural and human-induced earthquakes in 2017, compared with 2016, but parts of Oklahoma and southern Kansas remain at risk of seismicity linked to wastewater injection wells, the agency said Wednesday. "Millions still face a significant chance of experiencing damaging earthquakes, and this could increase or decrease with industry practices, which are difficult to anticipate," Mark Petersen, chief of the USGS National Seismic Hazard Mapping Project, said in a statement. The 2017 map shows most of Oklahoma facing more than a 1% chance of earthquake damage, with the north-central part of the state facing a 5%-10% chance and a smaller area within that facing a 10%-12% chance. USGS said the 2017 forecast decreased from last year because fewer "felt earthquakes" occurred in 2016 than in 2015."This may be due to a decrease in wastewater injection resulting from regulatory actions and/or from a decrease in oil and gas production due to lower prices," USGS said. About 3.5 million people live and work in the areas of Oklahoma and southern Kansas identified as at risk of induced seismicity. In 2016, Oklahoma experienced its largest earthquake on record as well as the greatest number of large earthquakes, USGS said. USGS has connected past Oklahoma earthquakes to injection wells, concluding that the massive volumes of wastewater are changing the underground pressure, lubricating the faults and triggering earthquakes.
Oklahoma Remains Nation's Human-Induced Earthquake Hotspot - Despite a crackdown on wastewater injection volumes, Oklahoma has once again been named the state with the highest risk of human-induced earthquakes , according to new seismicity maps released Wednesday by the U.S. Geological Survey (USGS). Geologists believe that these man-made quakes are triggered by wastewater from oil and gas operations being injected into deep underground wells. These fluids can cause pressure changes to faults and makes them more likely to move. This process has been blamed for the Sooner State's alarming rise in seismic activity. Between 1980 and 2000, Oklahoma averaged only two earthquakes greater than or equal to magnitude 2.7—the level at which ground shaking can be felt—per year. But in 2014, the numbers jumped to about 2,500 in 2014, 4,000 in 2015 and 2,500 in 2016. The USGS said that the decline in 2016 quakes could be due to injection restrictions implemented by the state officials. According to Bloomberg , "State regulators aiming to curb the tremors have imposed new production rules cutting disposal volumes by about 800,000 barrels a day and limiting potential for future disposal by 2 million barrels a day." However, even if there were fewer tremors last year, Oklahoma felt more 4.0+ quakes in 2016 than in any other year. Of the earthquakes last year, 21 were greater than magnitude 4.0 and three were greater than magnitude 5.0. Some of the biggest quakes include a 5.0-magnitude temblor that struck Cushing, one of the largest oil hubs in the world, on Nov. 6. And the largest quake ever recorded in the state was a 5.8 that hit near Pawnee on Sept. 3.
Oklahoma’s earthquake rate slows, but Cushing oil hub remains in danger zone - The good news for Oklahoma is that the number of earthquakes stronger than magnitude 2.7 that hit the state last year fell by more than a third to 2,500, compared with 4,000 in 2015. The bad news is the 2016 total is still astronomical compared to the two earthquakes the state experienced annually between 1980 and 2000. A key question for Oklahoma regulators and for oil and gas drillers there is what caused last year’s decline: Was it mainly the result of state efforts to restrict drillers’ wastewater injections, which the US Geological Survey has linked to the increase in seismicity? Was it the slowdown in drilling activity from low oil prices? Or was it a combination of the two? That answer could become clearer as drilling picks back up as expected this year.One positive sign for oil and gas drillers in Oklahoma is that the promising SCOOP and STACK plays generate much less produced water than the Mississippi Lime, leaving producers with less wastewater to dispose underground. But even if the Oklahoma Corporation Commission’s action to restrict wastewater injections by as much as 40% is the main factor behind the lower earthquake rate, USGS geophysicist Rob Williams still sees a reason for caution ahead. He said the vast amounts of wastewater already pumped into the deep Arbuckle formation could still affect underground pressure and trigger damaging earthquakes. “They’ve injected billions of barrels of water in that region in Oklahoma and southern Kansas over the past few years, and the lingering effects of those changes in the stress conditions may last several years,” Williams said in an interview this week. “The chances of having earthquakes is going to be high for a while. We can’t rule out a damaging earthquake in that region, even if there are severe restrictions on injection. USGS said in a study this week that Oklahoma’s efforts to restrict wastewater injections appear to be curbing earthquake activity linked to oil and gas drilling, but large areas of the state — including key oil storage hub Cushing — remain at risk of damaging seismicity in 2017. The agency’s 2017 earthquake hazard map shifted the highest-risk zone in Oklahoma to the Cushing-Pawnee area based on two strong earthquakes that shook that area last year: a magnitude 5.8 tremor near Pawnee on September 3, the strongest in state history, and a magnitude 5.0 near Cushing on November 7.
Officials from Colorado, other states oppose moves to roll back federal methane rule - Denver Business Journal: More than 60 local elected officials from Colorado, three other western states and the Ute Mountain Tribe have sent a letter to the U.S. Senate voicing opposition to moves in Congress to roll back the Bureau of Land Management’s new regulations cracking down on leaks of methane, a greenhouse gas, from oil and gas equipment in the field. The BLM’s regulation, announced in November 2016 in the final months of former President Barack Obama's administration, are modeled on Colorado’s regulations approved in 2014. The regulations require energy companies to regularly look for leaks in field equipment and plug any that are found. “As elected officials from local governments across the interior West, we strongly support this recently adopted rule on venting and flaring methane because it will cut natural gas waste on federal and tribal lands, will help ensure a fair return to local governments and the taxpaying public, will put our energy resources to good use, and will clean up our air,” said the letter, available here. Officials from New Mexico, Nevada and Utah also signed the letter. The Republican-controlled U.S. House of Representatives voted Feb. 3 in favor of a "Congressional Review Act" resolution against the fledgling rule. If approved by the Senate and signed by President Donald Trump, the rule would come off the books for good.
EPA pulls back methane request for drillers | TheHill: The Environmental Protection Agency (EPA) is withdrawing its request that oil and gas drillers provide regulators with information about methane emissions. Under former President Obama, officials had asked drillers to give the EPA data about methane emissions and equipment at existing oil and gas wells. The request was the first step in an agency push to issue a rule cracking down on methane emissions, which have a potent impact on climate change. The oil industry and its supporters had opposed the request, as well as any EPA effort to crack down on methane, arguing drillers are reducing emissions through state rules and self-regulation. Officials from 11 states on Wednesday asked the EPA to suspend its information collection request, saying a methane rule would be costly and “unlawful.”The Trump administration, which opposes much of Obama’s climate change work, is highly unlikely to issue a methane regulation. In a Thursday statement, the EPA said the agency would “like to assess the need for the information that the agency was collecting through these requests.” “By taking this step, EPA is signaling that we take these concerns seriously and are committed to strengthening our partnership with the states,” EPA Administrator Scott Pruitt said in a statement. “Today’s action will reduce burdens on businesses while we take a closer look at the need for additional information from this industry.” Methane — the majority component of natural gas — has global warming potential 25 times greater than carbon dioxide, meaning its impact on climate change is significant. In the closing years of his presidency, Obama began to take aim at methane emissions, issuing rules against leaks and flaring of methane on public and private land. In May, the EPA finalized a rule cutting methane emissions at new drilling wells, and its information collection request was the first step in writing a rule for emissions at existing wells. But Trump and congressional Republicans have signaled they will undo much of those efforts. Besides pre-empting this information request, the House has passed a resolution undoing an Interior Department rule on methane leaks on public land.
Coal, oil and gas companies to pay less in royalties after Interior Rule - The Interior Department informed coal, oil and gas companies this week they do not need to comply with a new federal accounting system that would have compelled them to pay millions of dollars in additional royalties. The Office of Natural Resources Revenue’s new method of calculating royalties for minerals extracted on federal land — which was finalized last July and took effect Jan. 1 — was aimed at preventing firms from underpaying what they owe by selling coal to subsidiaries at an artificially low price. But energy firms, some of whom challenged the new rule in court, called the requirements confusing, complicated and onerous and pressed for a delay. “This rule would have had immediate detrimental effects to American energy producers and the hard-working Montanans and workers across the country they support,” said Sen. Steve Daines (R-Mont.), who asked the administration last month to stay the rule. Colin Marshal, president and chief executive of Cloud Peak Energy, called the change in accounting rules “among the most egregious” of the “punitive regulations” on coal the Obama administration had adopted, and welcomed its suspension. Companies were set to file their first reports under the new rule Tuesday. Lawmakers in both parties have questioned whether the current method of royalty collection for coal mined in the Powder River Basin, which encompasses parts of Wyoming and Montana, accurately compensates taxpayers. Firms are required to pay a royalty of 12.5 percent on the minerals they extract from federal land when they are first sold, but many coal companies initially sell to affiliates at the same price per ton that they pay the federal government for extracting it. By doing that, they avoid paying royalties on the higher price the affiliated companies receive on the open market. According to the U.S. Energy Information Agency, 42 percent of coal transactions in Wyoming took place between affiliated companies.
The Beginning Of The End For The Bakken Shale Play – Berman - It's the beginning of the end for the Bakken Shale play. The decline in Bakken oil production that started in January 2015 is probably not reversible. New well performance has deteriorated, gas-oil ratios have increased and water cuts are rising. Much of the reservoir energy from gas expansion is depleted and decline rates should accelerate. More drilling may increase daily output for awhile but won't resolve the underlying problem of poorer well performance and declining per-well reserves. December 2016 production fell 92,000 barrels per day (b/d)--a whopping 9% single-month drop (Figure 1). Over the past two years, output has fallen 285,000 b/d (23%). This was despite an increase in the number of producing wells that reached an all-time high of 13,520 in November. That number fell by 183 wells in December. Well performance was evaluated for eight operators using standard rate vs. time decline-curve analysis methods. These operators account for 65% of the production and also 65% of producing wells in the Bakken play (Table 1). Estimated ultimate recovery (EUR) decreased over time for most operators and 2015 EUR was lower for all operators than in any previous year (Figure 2). This suggests that well performance has deteriorated despite improvements in technology and efficiency. Figure 3 shows Bakken EUR and the commercial core area in green. The map on the left shows all wells with 12-months of production history and the map on the right, all wells with first production in 2015 and 2016. Most 2015-2016 drilling was focused around the commercial core area. The fact that EURs from these core-centered locations were lower than earlier, less favorably located wells indicates that the commercial core is showing signs of depletion and well interference. Well-level analysis indicates a fairly systematic steepening of decline rates over time. Figure 4 shows Continental Resources wells with first production in 2012 and 2015. 2012 wells have a shallow, super-harmonic (b-exponent = 1.3) decline rate but 2015 wells have a steeper, weakly hyperbolic (b-exponent=0.2) decline rate. Oil reserves for 2012 wells averaged 343,000 barrels but only 229,000 barrels for 2015 wells--a 33% decrease in well performance. Steeper decline rates result in lower EURs.
US: U.S. judge to rule on Dakota Access Pipeline easement in early March - Press From - US: A U.S. judge said on Tuesday he hopes to decide by about March 7 on a request by Native American tribes for the Army Corps of Engineers to withdraw an easement on religious grounds for the final link of the Dakota Access Pipeline. At a hearing Judge James Boasberg of the U.S. Court in Washington, D.C., said he hoped to provide a written ruling by that time on the injunction requested by the Standing Rock Sioux and Cheyenne River Sioux tribes regarding the final section of the line to go under a lake in North Dakota.Boasberg said if Energy Transfer Partners, the company building the $3.8 billion line, expects the project will be completed and oil will flow before March 7, that the company must give him 48 hours notice so he can release his ruling. The tribes, who have rights to water access in the area, say that the oil pipeline would spiritually degrade river and lake water and harm religious practices even if it does not spill. Their legal options to stop the pipeline are dwindling. Earlier this month, Boasberg denied a request by the tribes for a temporary restraining order to halt construction of the project. Boasberg on Tuesday questioned how the water could be harmed since the pipeline is being built under the Lake Oahe and oil would not likely touch the water in the event of a spill. Nicole Ducheneaux, a lawyer for the tribes, said at the hearing that the pipeline would spiritually degrade the water on the Missouri River because of its presence and that would prevent tribes from carrying out ceremonies because other nearby water sources had been contaminated from decades of mining.
Would pipeline threaten terminal at Port of Vancouver? | The Columbian: Almost as soon as the Trump administration took office, the future of the Dakota Access pipeline looked certain. Any hopes held by protesters that the 470,000-barrels-per-day project could be stopped were further diminished on Thursday when North Dakota law enforcement closed their main camp and arrested more than 40 people. So what does the North Dakota oil pipeline mean for Vancouver Energy, the 360,000-barrels-per-day crude-by-rail terminal that would receive Bakken crude at the Port of Vancouver before loading it onto vessels destined for West Coast refineries? It depends on whom you ask. In a blog post earlier this month, the Sightline Institute, a Seattle-based think tank focused on sustainability in public policy, argues that many changes in the energy market have shifted the landscape against the terminal since it was proposed in 2013. Clark Williams-Derry, Sightline’s director of energy finance, wrote a post titled “Did Trump Just Kill a Northwest Oil-By-Rail Project?’ In it, he argues that Bakken oil producers are struggling against low international oil prices. And while the Bakken’s production has declined — down to less than 1 million barrels of oil per day this month versus the roughly 1.24 million barrels per day at its peak in 2014 — more refineries and pipelines have come online to move the product out of the Dakotas. To bolster his point, Williams-Derry refers to a report from the U.S. Energy Information Administration showing crude-by-rail shipments out of the Upper Midwest in November were down by nearly two-thirds from their 2014 peak.“There’s no sign of long-term growth in Bakken oil, and (the Dakota Access pipeline) is just going to make oil-by-rail less attractive,” Williams-Derry told The Columbian in an email. “So unless Vancouver Energy thinks it’s going to source its oil from some other yet-to-be-determined region, it’s likely to be a stranded, underutilized asset from day (one).”
‘Buy American’ Rule for Keystone Pipeline Dropped After Ex-Foreign Steel Exec Became Commerce Secretary - The Trump administration’s decision to exempt the Keystone XL pipeline from “Buy American” rules could benefit one company in particular: the steel giant that newly minted Commerce Secretary Wilbur Ross invested in and helped run for a decade. Two days after Ross was confirmed, the White House announced that Commerce will not apply those rules to the project. “The Keystone XL Pipeline is currently in the process of being constructed, so it does not count as a new, retrofitted, repaired or expanded pipeline,” a White House spokesperson told Politico. The pipeline’s exemption from Buy American rules could benefit Luxembourg-based company ArcelorMittal, the world’s largest steel manufacturer. Ross, a billionaire investor and leveraged buyout specialist, sat on the company’s board until Wednesday, and in January disclosed equity holdings of between $750,000 and $1.5 million. ArcelorMittal has provided large amounts of material for the Keystone pipeline. According to company documentation, its plant in Bremen, Germany, sold dozens of kilotons of steel to Arkansas-based Welspun Tubular, which used the material to manufacture spiral welded pipe for the project. The resulting products would not qualify as “American-made” under the definition employed by President Trump’s executive order implementing the rules.
Trump Lied: Keystone XL Now Allowed to Be Built Using Imported Steel - Late Thursday evening, news broke that TransCanada, the company behind the formerly rejected Keystone XL pipeline, will not be required to use U.S. steel to construct the dirty tar sands pipeline from Alberta, Canada through the U.S. to refineries in the Houston area. This is in spite of the repeated pledges by President Trump —including at Tuesday's speech before a joint session of Congress —that it will be built with "American steel." Earlier this week, TransCanada delayed its $15 billion Investor State Dispute Settlement suit under NAFTA over President Barack Obama's rejection of the pipeline until March 27, the same day that the final permitting decision for Keystone XL is due. It has been speculated that the lawsuit was suspended rather that dropped to ensure that TransCanada was not required to use U.S. steel despite Trump's public statements that it would be. President Trump has sought to portray himself as some sort of master negotiator, but he clearly needs to spend more time in an apprenticeship. Just days ago, Trump pledged before the country and Congress that the Keystone XL pipeline that he was forcing on this country would be made with American steel, but instead, he was outmaneuvered by a foreign company that wants to use imported steel. TransCanada's success over Trump is what happens when you have an administration stacked with fossil fuel billionaires and a trade deal that enables corporate polluters to push their agenda at will. Keystone XL is a disaster waiting to happen for our economy, our health and our climate, which is why it was rejected and must remain so.
Unplugged Natural Gas Leak Threatens Alaska's Endangered Cook Inlet Belugas - Natural gas from a 52-year-old underwater pipeline has been leaking for at least two weeks into Cook Inlet in Alaska, home to a number of endangered species, including beluga whales. The company that owns the pipeline, Hilcorp, has said that the pipeline cannot be shut down without posing additional risk to the environment or employee safety because stopping the flow could trigger a crude oil leak. The 8-inch pipeline, which carries natural gas from shore to four offshore oil platforms, is leaking an estimated 210,000 to 310,000 cubic feet of natural gas each day, according to the company. Attempts at a response by the company and by federal and state agencies have been hindered by weather conditions and ice, which has kept divers from reaching the source. The leak was first spotted around 3 p.m. on Feb. 7, when a Hilcorp helicopter pilot flying between the town of Nikiski and its offshore oil Platform A spotted bubbles on the water's surface. An hour later, Hilcorp reported the leak to the National Response Center and to the Alaska Department of Environmental Conservation. The federal Pipeline and Hazardous Materials Safety Administration is investigating and monitoring the leak, but has been unable to reach it. Other federal, state and local agencies are investigating and will be involved in the response, which includes daily flights over the source (weather permitting) and observations of wildlife to determine any impacts from the leak. Hilcorp said in a statement that some amount of gas needs to flow through the pipeline. "If a minimum pressure is not maintained in the pipeline it could fill with water which would allow for the escape of residual crude oil, as this line was previously used as a crude oil pipeline," the statement said. Hilcorp did not respond to a request for comment.
Alaska underwater gas leak continues, 2nd group to sue — A second environmental group has given formal notice that it will sue the owner of an underwater pipeline spewing natural gas into Alaska’s Cook Inlet. The inlet is home to endangered beluga whales, salmon and other fish. Gas since at least Feb. 7 has bubbled from an 8-inch pipeline owned by Hilcorp Alaska LLC. The pipeline moves processed natural gas from onshore to four drilling platforms. The company in a statement said its modeling consultants conclude that only tiny amounts of natural gas likely are dissolving into the water and that there likely is minimal effect on marine life. Hilcorp says the leak will be repaired when it’s safe to dive. However, the Center for Biological Diversity in a letter to the company and the Environmental Protection Agency said the leaking gas is a threat to belugas. The Tucson, Arizona-based group said Hilcorp is violating four federal laws: the Clean Air and Clean Water acts, the Endangered Species Act and the Pipeline Safety Act. A lawsuit requires a 60-day notice. “Belugas and their prey are being harmed every day this leak continues,” said Miyoko Sakashita, the group’s oceans program director, in a statement. “We can’t wait another month or more for the sea ice to clear before plugging the leak.”The leak is about four miles off shore in 80 feet of water. A Hilcorp helicopter crew Feb. 7 spotted gas bubbling to the surface. The company estimates the pipeline is emitting 210,000 to 310,000 cubic feet of gas per day. The Alaska Department of Environmental Conservation and the federal Pipeline and Hazardous Materials Safety Administration are investigating.
Cook Inlet natural gas leak can't be fixed until ice melts, company says - The company responsible for an ongoing natural gas pipeline leak in Cook Inlet, Alaska, said it won't be able to attempt to repair it until the ice melts, which will be later this month at the earliest. The aging pipeline has been releasing natural gas into a critical habitat for the endangered Cook Inlet beluga whales since at least Feb. 7. Hilcorp Alaska, a subsidiary of Houston-based Hilcorp, owns the 8-inch underwater pipeline that transports natural gas from shore to four offshore oil platforms, also owned by Hilcorp. In a letter to the Alaska Department of Environmental Conservation on Feb. 20, the company said it would not be able to safely shut down or repair the pipeline until ice in the inlet recedes. "Given the typical weather patterns affecting ice formation and dissipation in Cook Inlet, we currently anticipate that the earliest that conditions will allow diving will be in mid-to-late March," wrote David Wilkins, senior vice president of Hilcorp Alaska. An estimated 210,000-310,000 cubic feet of natural gas is leaking into the inlet each day. The Alaska Department of Environment Conservation responded on Monday, noting that Hilcorp did not respond to its request for a plan monitoring the leak and any environmental impacts. Without that data, the state says it can't assess the extent of the threat to Cook Inlet. "The State cannot determine acceptable environmental conditions without first having characterized the release," wrote state on-scene coordinator Geoff Merrell. "Therefore, it's imperative that Hilcorp begin a sampling and monitoring program."
U.S. shale producers renew their challenge to OPEC: Kemp (Reuters) - U.S. crude oil production appears to be rising strongly thanks to increased shale drilling as well as rising offshore output from the Gulf of Mexico.Production averaged almost 9 million barrels per day (bpd) in the four weeks to Feb. 24, according to the latest weekly estimates published by the Energy Information Administration.Production has been on an upward trend since hitting a cyclical low of 8.5 million bpd in September ("Weekly Petroleum Status Report", EIA, March 1).Weekly production numbers are estimates based on a combination of hard data and modelling so there is some uncertainty around them ("Weekly Petroleum Status Report: Explanatory Notes and Details Methods", EIA).But the weekly estimates normally provide an accurate indicator for trends in the more comprehensive monthly data (http://tmsnrt.rs/2mcZphb).The most recent monthly statistics show output declining by 91,000 bpd in December, mostly due to exceptionally cold weather in North Dakota. Even with this weather-driven decline, which is expected to be temporary, production was still 216,000 bpd above the cyclical low reported in September. And the most recently weekly estimates suggest production increased significantly again during January and February.The rise in production is consistent with the substantial increase in the number of rigs drilling for oil since May 2016. Rising output also helps explain the big increase in U.S. crude exports and the continued high level of domestic crude stocks. U.S. crude exports have averaged almost 900,000 bpd during the last four weeks, up from about 500,000 bpd in September. U.S. crude prices have roughly doubled over the last year which has supported a sharp expansion in domestic drilling activity. The resurgence of shale production poses a direct challenge to OPEC's attempt to rebalance the global oil market while protecting its market share.In the short term, OPEC will downplay the renewed growth in shale output and emphasise its own compliance with announced production cuts. In the end, however, OPEC will be faced with a familiar dilemma: sacrifice market share to protect prices or defend market share and allow prices to find their own level.
The second coming of American oil shale is preparing to challenge OPEC again - After a two-year downturn spurred by oil’s plunge to $26 from $100, U.S. production is on the rise once again, opening the door for another showdown with the Organization of Petroleum Exporting Countries. The number of U.S. drilling rigs has grown 91 percent to 602 in just over nine months. Meanwhile, production has gained more than 550,000 barrels a day since the summer, rising above 9 million barrels a day for the first time since April. And as shale returns with a vengeance, it’s not just the pioneer cowboys that dominated the first phase of the revolution in the Bakken of North Dakota. This time, ExxonMobil and other major oil groups are joining the rush. It’s a new reality that OPEC and Russia — the main forces behind the production cuts approved last year as a solution to re-balance the global market — are starting to acknowledge. “With $55 a barrel, we see everyone very happy in the U.S.,” Long a world leader in multi-billion dollar oil developments that take years to build and even longer to profit, Exxon is diverting about one-third of its drilling budget this year to shale fields that will deliver cash flow in as little as three years, Chief Executive Officer Darren Woods said this week. In January, Exxon agreed to pay as much as $6.6 billion in an acquisition designed to more than double the company’s footprint in the Permian basin of west Texas and New Mexico, the most fertile U.S. shale field.
'U.S. oil exports are blowing past expectations - -- Outbound shipments of U.S. crude oil have exceeded 1.2 million barrels a day, surpassing last month's daily production of oil in 3 OPEC countries: Algeria, Ecuador and Qatar, per the Financial Times. Following the lifting of Washington's 40-year-old ban on crude oil exports in 2015, U.S. oil shipments to foreign countries — such as Canada, Spain, Singapore and China — have risen dramatically, far exceeding the baseline projections made by the U.S. Energy Information Administration. As the FT points out, the strong exports are a result of:
- The oil glut in the world market has made U.S. oil a relative bargain compared with other grades.
- A rebound in oil prices last year has encouraged U.S. companies to increase drilling. The EIA estimates domestic produciton is above 9 million barrels a day for the first time in 10 months.
- U.S. refineries, unlike OPEC, haven't done much to "mop up" the glut.
- Rates for leasing supertankers have declined, making its cheaper to transfer oil to foreign countries.
The situation poses a threat to Saudi Arabia and other key OPEC members, who have historically had control over the oil industry and the power to gauge pricing. But following the group's November agreement to curtail oil output starting Jan. 1, concerns about tighter oil supplies have led foreign countries to look elsewhere — such as to the U.S. — for their supply.
Record US oil exports ‘eating’ OPEC market share - The U.S. exported a record amount of crude oil, topping a million barrels a day for a second week and filling the gap in world markets created by OPEC cutbacks. Shale and other U.S. producers sent 1.2 million barrels of crude oil onto world markets last week, up nearly 200,000 barrels a day from the week earlier and about 350,000 barrels above the four-week average, according to Energy Information Administration data. Until recently, the U.S. was exporting about 500,000 barrels a day. “OPEC’s got a competitor. No doubt about it,” said Kyle Cooper, a consultant with Ion Energy Group. “They certainly have to be concerned with U.S. oil producers eating into their market share.” U.S. producers have also ramped up production to 9 million barrels a day last week, a level last seen in April 2016. The new production is increasing even as the U.S stockpiles continue to grow. According to EIA, oil supplies grew for a seventh week, adding a smaller than expected 564,000 barrels. “OPEC is definitely looking over its shoulder at these rising numbers of exports, and it’s undermining their efforts on a daily basis,” said John Kilduff of Again Capital. “Some of it’s going to Asia. China is one of the more unusual buyers in there. The shale guys are filling the gap of the very cuts that were put in place by the market.”
Four things driving 2017's "different kind of recovery." -- A number of indicators suggest that the energy slump that started in the latter half of 2014 has bottomed out, and that happy days are here again (at least for now). Who would have thought back in the good ol’ days three years ago this month—when the spot price for crude oil was north of $100/bbl and the Henry Hub natural gas price averaged $5.15/MMbtu—that Friday’s $54 crude and $2.63 gas would be seen as anything but a catastrophic meltdown. But not so. The fact is that in 2017, producers in a number of basins can make good money at these price levels. Consequently, drilling activity is coming on strong. Crude oil production is up more than 500 Mb/d since October 2016 to 9 MMb/d, a level not seen in almost a year. And gas output has also been poised to rise, if only real winter demand had kicked in this year. What’s going on? Today we discuss the fact that what we have here, folks, is a rebound unlike any we’ve seen before.
US' Saudi Arabia Crude Oil Imports -- Not Down All That Much -- March 2, 2017 -The numbers have just been posted for December, 2016. For all that talk about less Saudi Arabia oil coming into the US, the numbers don't back up the talk. I believe Saudi has refinery operations along the US gulf coast that would "absorb" most of the oil Saudi Arabia ships to the US. The link to the spreadsheet below is here.For the month of December, 2016, US imports from following countries, month-over-month,
- Iraq was the big winner, going from 13 million bbls to 18 million bbls (month)
- imports from Saudi Arabia, flat
- imports from Venezuela, flat
- imports from Canada went from 122 million bbls to 127 million bbls
- imports from Mexico went from 21 million bbls to 18 million bbls
- imports from Russia went from 13 million bbls to 10 million bbls
U.S. gasoline demand hits record number last year: EIA | Reuters: U.S. demand for gasoline hit record levels last year, averaging 9.326 million barrels per day, surpassing 2007 levels, according to new monthly figures released Tuesday by the U.S. Energy Information Administration. The surge in gasoline demand in 2016 came amid low pump prices and lower unemployment, but there have been early signs this year that consumer thirst for gasoline is weakening. Motorists drove a record 3.22 trillion miles (5.2 trillion km) on U.S. roads last year, a 2.8 percent rise from 2015 and the fifth consecutive year of year-over-year increases, federal figures show. U.S. gasoline demand was up 1.8 percent to 9.3 million bpd in December versus last year. The U.S. accounts for roughly 10 percent of the global demand for gasoline. Total oil demand in December was up 1.9 percent to 19.98 million bpd, EIA data showed. Total oil demand was at its highest level last year since 2007, EIA data showed. U.S. distillate demand was up 6 percent to 4.06 million bpd in December versus last year, EIA data showed. Warm weather in 2015 sapped demand for distillates. Overall, 2016 demand for distillates was 3.9 million bpd, down 2.7 percent from the year prior, EIA data showed.
US border policy could curb travel amid already weak jet fuel demand - The Barrel Blog: Uncertainty surrounding the Trump administration’s efforts to harden the US border could cut into business travel demand this year at a time when jet fuel demand is already quite weak, at least according to travel agents surveyed in the US and Europe this month. Winter is typically a slow time for air travel anyway, but recent Energy Information Administration data for product supplied shows demand for jet fuel has been trailing off more dramatically than usual. The latest EIA data showed jet fuel supplied in the US rose 242,000 b/d to 1.42 million b/d for the week ended February 17. However, that was down from 1.49 million b/d during the same week in 2016. The prior week’s data showed an even more precipitous fall. EIA reported 1.17 million b/d of jet supplied for the week ending February 10, a 24% year-on-year drop in demand to its lowest level in 22 years, when it plunged to 1.15 million b/d in April 1995. The result of this stifled demand has been higher differentials for Gulf Coast jet fuel. Platts assessed the benchmark 54 grade at NYMEX ULSD futures minus 8.70 cents/gal on February 23, 2017, a significant jump from the NYMEX minus 12 assessment on February 23, 2016. US traders were mostly dubious on whether the drop in jet fuel demand could be attributed to President Trump’s policy, but at least one agreed with the theory. “It doesn’t take much to change the balance of the market, so I suspect there was an effect,” said the trader. Courts have halted President Donald Trump’s January 27 executive order banning travel from seven Muslim-majority countries, but the White House is expected to issue a revised order. Travel agents surveyed by the Global Business Travel Association in Washington said they see potential impacts three to 12 months out.
The far-reaching impacts of low-sulfur bunker fuels on demand, prices, and refining. - A new international rule slashing allowable sulfur content in the marine fuel or “bunker” market will have profound effects on global demand for high sulfur fuel oil and low-sulfur middle distillates—and with that, major impacts on the price of those products, the demand for various types of crude, and the need for refinery upgrades. What we have in the making here is a refining-sector shake-up that will extend well into the 2020s. Today we begin a series on the rippling effects of the International Maritime Organization’s (IMO) mandate that, starting in January 2020, all vessels involved in international trade use marine fuel with sulfur content of 0.5% or less. The worldwide shipping industry is a leading consumer of petroleum products—tankers, dry bulkers and container ships now consume just over half of the world’s residual-based heavy fuel oil—so it’s not surprising that rules governing marine fuel standards have been a frequent topic in the RBN blogosphere. Most recently, in How Am I Supposed to Live Without You, we discussed the IMO’s October 2016 decision to reduce from 3.5% to 0.5% the allowable sulfur content in bunker used by most of the ships that ply international waters. (The new rule is planned to kick in January 1, 2020.) As we said then, an even tougher sulfur-content standard (a 0.1% cap on sulfur) already is in place for vessels that operate within the IMO’s “Sulphur Emission Control Areas” (SECAs, or sometimes ECAs), which include Europe’s Baltic and North seas and areas within 200 nautical miles of the U.S. and Canadian coasts.
Production and corruption: US oil and regulations about transparency – podcast - Senior oil editors Brian Scheid and Meghan Gordon talk with Jana Morgan, director of Publish What You Pay - US, on the likely fate of an anti-corruption rule with impacts on multinational oil, gas and mining companies. The rule, requiring companies to report bribes to foreign governments, was included in the Dodd-Frank Act but overturned in federal court. Within days of moving into the White House, President Donald Trump signed a bill to repeal it. What’s next? According to Morgan, the rule is still law and needs to be implemented, but how?
Shell Shuns New Oil Sands as Low Crude Prices Force Cost Control | Rigzone - Royal Dutch Shell Plc is unlikely to take on new oil-sands projects as it maintains a grip on costs after crude’s crash forced competitors to write down Canadian reserves. While Shell’s existing oil-sands operations generate strong cash flows, the expense of developing new projects discourages additional investments, Chief Executive Officer Ben Van Beurden said in an interview. Oil sands, the reserves of heavy crude found primarily in northern Alberta, lured investors in the past decade as oil’s surge above $100 a barrel made the difficult extraction process economic. But they’ve fallen out of favor following the subsequent market collapse as companies dump expensive projects amid fears that competition from low-cost crude could strand costlier assets. “All of those are reasons we are unlikely to develop new oil-sands projects,” Van Beurden said in London. “There are no plans for growth capital to be invested in oil sands.” Exxon Mobil Corp. slashed reserves after removing the $16 billion Kearl oil-sands project in Athabasca from its books last week. A day earlier, ConocoPhillips said that erasing oil-sands barrels had reduced its reserves to a 15-year low. In 2015, Shell itself took a $2 billion charge as it shelved an oil-sands project in Alberta, and last year sold other assets in the area for about $1 billion. The oil-sand mines in the region are among the costliest petroleum projects because the raw bitumen extracted must be processed and converted to a synthetic crude before being transported to refineries, mainly in the U.S. In addition, Canadian oil sells for less than benchmark U.S. crude because of the cost to ship it and an abundance of competing supplies from shale fields. BP Plc said last month that there’s enough oil in the world to meet demand to 2050 twice over and this may prompt producers of low-cost crude, like those in the Middle East, to bring production forward.
Have The Majors Given Up On Canada's Oil Sands? - Canada’s oil sands are incredibly expensive, some of the costliest sources of oil in the world. Unlike conventional oil drilling, or even drilling in shale, producing from oil sands is more like open-pit mining in many cases. The oil, often found as a sticky, viscous semi-solid known as bitumen, requires extra steps to extract and process before it can be shipped. That stands in stark contrast to conventional oil, which merely requires drilling into an oil field and pumping out the crude.As a result, the breakeven cost for Canada’s oil sands is dramatically higher than most other places in the world. Obviously, costs vary from company to company and project to project, but a 2016 estimate from IHS put the average breakeven price at a new greenfield oil sands mine at between $85 and $95 per barrel. A steam-assisted gravity drainage (SAGD) project could cost between $55 and $65 per barrel just to break even. With those figures, it is easy to see why very few, if any, greenfield projects could move forward in the near- to medium-term, particularly when companies could look elsewhere for oil.To make matters worse, Canadian oil typically trades at a discount to WTI, due to its lower quality and because it needs to be transported longer distances. A dearth of pipeline capacity induces discounts from producers, as they fight for pipeline space. Inadequate pipeline capacity keeps some oil sands supply on the sidelines, which is exactly why environmental groups have targeted the likes of Keystone XL and the Trans Mountain Expansion. Finally, developing oil sands requires billions of dollars and the payback period is stretched out over decades. The great thing about that for producers is that it provides consistent output for years. But that is no longer the top priority for oil companies hoping to avoid having cash tied up over long time horizons. The oil market is extremely volatile, so short-cycle shale is much more attractive these days even if shale wells fizzle out over a few years. In short, Canadian oil sands is struggling to remain competitive in a marketplace that has changed dramatically from three years ago.
BP Targets $40 Break-Even Oil Price to Reassure Investors - BP Plc said it will need a crude price of about $40 a barrel in 2021 to cover spending and dividends, down from $60 this year, as Chief Executive Officer Bob Dudley seeks to reassure investors on the oil major’s growth outlook and finances. The break-even level will fall as BP keeps capital spending at no more than $17 billion a year, the London-based company said Tuesday in a statement. It aims to raise output by 5 percent a year to 2021 and is targeting returns of more than 10 percent. Dudley, 61, is seeking to return BP to growth after the 2010 Gulf of Mexico oil spill and the market downturn of the past three years shrank the scale of its operations. The CEO must also show investors he’ll keep spending in check as crude prices remain at half the levels of 2012 and 2013. “We can see growth ahead right across the group,” Dudley said in the statement. “While always maintaining our discipline on costs and capital, BP is now getting back to growth -- today, over the medium term and over the very long term.”The company said Feb. 7 that its break-even oil price would rise to $60 a barrel this year from an earlier assumption of as much as $55 because of the cost of buying oil and natural-gas fields in Egypt, Mauritania and Senegal. That meant BP was moving in the opposite direction to Exxon Mobil Corp. and Royal Dutch Shell Plc, which said cash flow already covers spending. Dudley told investors and analysts on Tuesday the break-even price would steadily drop from this year to $35 to $40 a barrel by 2021.
Europe Pushes Ahead with Controversial Canadian Trade Deal, Opens Door for Tar Sands -- European lawmakers voted to approve a controversial Canada-EU trade deal called CETA in a move that could increase tar sands imports into the EU. The trade deal could also facilitate energy companies suing Member State governments when environmental policies threaten their profits. The European Parliament vote was passed 408 to 254 following a heated debate in Strasbourg, as protests went on outside. Some MEPs highlighted the economic benefits the major trade deal would bring to Member States, while those critical of the deal said it would compromise democracy for corporate interests and lower environmental standards. European trade and commerce think tank Euro Commerce’s director of policy praised the move forwards for the CETA deal.The EU Parliament ushered through the deal after a vote by European Commissioners to accept it on 12 January. The vote was one of the final hurdles to agreeing the trade deal, but it still needs to be ratified by Member States.The deal isn't yet secure, according to Mark Dearn, senior trade campaigner at War on Want, which campaigns on global inequality: “CETA has been passed by the European Parliament today, but its future remains far from certain due to legal hurdles it still faces and entrenched opposition in countries which are yet to vote on the deal.
US could challenge Northwest Europe, Asia for swing jet barrels: trade - Jet fuel market sources in the US and Europe say the US market could strengthen if the Trump administration follows through with potential changes to the Renewable Fuel Standard, attracting more barrels into the US West Coast from Asia. "US jet seems reasonably strong, especially with the RINs announcements," a European middle distillates trader said. "So I will be keeping a close eye on that." The Trump administration is discussing moving the point of obligation for RINs, or Renewable Identification Numbers, from refiners and importers to blenders at the wholesale rack. That could bring down RINs values, which in turn could lead to higher jet fuel prices, as refiners lose incentive to make jet and turn toward ULSD and other distillates. Related story:US EPA not involved in White House talks on RFS point of obligation: official If that is the case, sources said the US market may see an increase in the already heavy volume of jet fuel cargoes coming into the US West Coast from northern Asia, and even compete for cargoes that might head for Northwest Europe. "I see more coming [into Northwest Europe] for sure, and indeed a few cargoes going trans-Atlantic,"
Inside FERC Henry Hub March index down 77 cents to $2.62/MMBtu -- March bidweek average natural gas prices in the US weakened notably month on month, both on regional and national levels, with the national average decreasing $1 to trade at $2.45/MMBtu, as assessed by S&P Global Platts Wednesday. This downward movement was mimicked across the country, with the steepest fall in the Northeast, where the regional average dropped $2.53, or 49%, to trade at $2.64/MMBtu during March bidweek. The largest downward price movement in the Northeast was seen at Algonquin city-gates, which fell $4.13, or a whopping 56%, month on month to trade at $3.26/MMBtu. Along the Canadian border, Iroquois receipts also saw significant weakening, shedding $2.28 to settle at $2.91/MMBtu, while across the border in New England, Iroquois Zone 2 fell by slightly more, sliding $2.80/MMBtu to trade at $2.98/MMBtu.In Appalachia's production region, March index prices fell by an average of 87 cents, with the regional average coming in at $2.14/MMBtu, a 29% month-on-month decrease. The largest drop in Appalachia was seen at Transco Leidy Line receipts, which weakened 97 cents to $1.93/MMBtu. Two other Appalachian points, Millennium, East receipts and Tennessee, Zone 4-300 leg receipts, saw sub-$2/MMBtu March index prices. The March bidweek price at the benchmark Henry Hub decreased by 77 cents a 23% decrease month on month, to settle at $2.62/MMBtu, its lowest monthly index price since June 2016.
Chile's LNG imports soar in December, exports to Argentina resume - Chilean imports of LNG jumped to 263,000 mt in December, a threefold increase from the same month of 2015, government figures showed Friday. The figure also marked an increase from 171,000 mt imported in November. As a result, fourth-quarter imports rose 80.6% to 716,000 mt while annual imports rose 31.8% to 4.165 million mt. Imports have risen as generation from natural gas expanded to offset limited supplies of hydroelectricity.Trinidad and Tobago remained Chile's principle gas supplier, shipping 206,000 mt in December. But Chile also received 57,000 mt from the US during December, its first US imports since September. Chile has become an important market for Cheniere Energy's Sabine Pass liquefaction facility since it began exporting LNG last year. Thanks to the free trade agreement between the two countries, it enters Chile without a 6% import tariff. Figures also showed that Chile resumed exports of natural gas to neighboring Argentina, pumping 70,000 mt during December, for the first time since August. Chile began pumping gas over the Andes in May under an agreement between state energy firm ENAP and its Argentinian counterpart ENARSA. The gas, which Chile imports as LNG, reduces Argentina's reliance on other more expensive fossil fuels. The country has two regasification terminals -- Quintero in central Chile, which is controlled by Spain's Enagas, and Mejillones in the north, operated by Engie.
Gazprom natural gas sales in Europe, Turkey slide by 34 million cu m/d in Feb -- Russian natural gas flows to Europe and Turkey in February averaged 582 million cu m/d, down 34 million cu m/d from the January average, Gazprom data released late Wednesday showed. Flows of Russian gas to Europe dipped in February, given lower demand and a less attractive oil-indexed price versus the European hubs. Gazprom was also unable to use the higher capacity in the OPAL line last month due to ongoing legal action, having boosted supplies via Nord Stream/OPAL in January.Its gas deliveries via the Ukraine route also slid in the last week of February, triggering a warning from Ukraine's Naftogaz about record low pressure in the system. According to Gazprom data, total sales in Europe and Turkey (but not the countries of the former Soviet Union) were 16.3 Bcm, or an average of 582 million cu m/d. That is down from the January total of 19.1 Bcm, or an average of 616 million cu m/d. The total for the first two months of 2017 was 35.4 Bcm, still up 21% from the same period last year.
Platts JKM declines to $5.95/MMBtu on emerging US and Australian LNG supply - - : S&P Global Platts JKM for LNG cargoes to be delivered in April ended the week at $5.95/MMBtu, a $0.225/MMBtu fall from last Friday, on greater supply visibility from two large-scale liquefaction projects in US and Australia. Train two of the Gorgon project in Western Australia resumed production last week, following a shutdown for "minor" maintenance. In addition, Gorgon train three should start-up very soon, according to market sources. One source said he was confident it will start producing in "very, very likely to be early Q2."A Chevron spokesman declined to comment. Higher train two output, as well as an earlier-than-expected train three startup, would pressure prices in Asia, sources said. The Cheniere-operated Sabine Pass in the US project is also currently commissioning its train 3 which is expected to start up this month. Also, Angola LNG launched a single-cargo DES sell tender on Monday, for early-March delivery, which closed on Thursday. But some end-user demand stopped further price losses late in the week with at least two tenders floated by Asian end-users reported awarded this week.
Trump’s pro-oil and gas bias risks hurting Australia - President Donald Trump has sworn in a who’s who of oil leaders, which analysts have warned give his administration a pro-petroleum bias that may hurt Australia. Australia is just a small player in the oil market, but is the world’s third biggest LNG exporter. “We have seen some US-based companies not proceed with companies here in Australia and invest instead in the United States,” said Malcolm Roberts, chief executive of the Australian Petroleum Production and Exploration Association. LNG exports are worth $24 billion to the Australian economy and increased supply will hurt, with the US already muscling in on Australia’s traditional markets of Japan, Korea and China. Australia is already a high-cost producer. “It’s going to mean in the medium term considerably more competition in what’s already an oversupplied global market for LNG. LNG demand is growing steadily but we are in a period of oversupply which is resulting in very low prices.”
Kazakhstan adds Kashagan crude oil to surging Siberian Light exports - Kazakhstan has for the first time shipped Kashagan crude in the form of Siberian Light blend from the Russian port of Novorossiisk, the Kazakh state pipeline company has said, amid a surge in Siberian Light exports. In a statement on its website, KazTransOil said Kashagan crude was loaded on to the New Amorgos tanker at Novorossiisk on February 28, "mixed" with Siberian Light. Poor weather at the Black Sea port had prevented earlier shipment. The crude was transported from the Kashagan field through KazTransOil's pipeline to southern Russia and on to Novorossiisk using the Russian state's Transneft system "in the common flow of" low-sulfur Siberian Light, the statement said. Siberian Light loadings in March are scheduled to reach a multi-year high of over 150,000 b/d.The start of production from the vast Kashagan field in October has already contributed to a surge in shipments of Kazakhstan's main export blend, CPC, which also comprises crudes such as Tengiz and Karachaganak and is lighter and less sulfurous than Siberian Light. CPC has its own pipeline system across southern Russian from Kazakhstan and a different ownership from the Transneft system. However the partners at Kashagan, which include the Kazakh state and China's CNPC, are able to choose their own export methods. KazTransOil's statement noted that Kashagan crude had been shipped through the Transneft system before, but mixed in to less profitable Urals crude. The statement said output from other Kazakh light oil fields could also be exported as Siberian Light, although it did not specify which fields.
Middle East Oil & Gas Investment Surges To $294 Billion - Although global oversupply concerns continue to depress crude prices, producers in the Middle East and North Africa (MENA) region have invested around US$294 billion in oil, gas and petrochemicals projects that are at the pre-execution phase. According to Middle East business intelligence service MEED, the MENA region continues to pour in investments in expanding oil capacity, Saudi Gazette reports. In addition, Saudi Arabia and the UAE are studying investments in higher-cost sour gas and shale gas in order to meet growing domestic demand. In the MENA region, however, investment will continue to rise. MEED Editorial Director Richard Thompson said, as quoted by Saudi Gazette: “With an estimated $294bn-worth of projects in the pre-execution phase, the sector provides a wealth of opportunity for business from Saudi Arabia’s ambitious oil-to-chemicals complex to the re-emergence of the Iran oil industry following years of sanctions.”According to the MENA Oil and Gas 2017 report, Saudi Aramco plans to invest by 2025 a total of US$334 billion in the oil and gas value chain. Kuwait, for its part, is seen spending US$115 billion on energy projects over the next five years to ramp up its crude oil production capacity to 4 million bpd by 2020.
How Russia Is Using Oil Deals To Secure Its Influence In The Middle East --A string of oil deals between Russian oil companies and Arab petrostates have shifted the center of political gravity in the Middle East and North Africa towards Moscow – counteracting the effect of decades of American military and political involvement as U.S. President Donald Trump’s plan for the region remains unclear. The Arab World has been Putin’s favorite arena to grow the Russian sphere of influence. Syria took the first dose. The continuation of President Bashar Al Assad’s regime is all but guaranteed thanks to Russian political maneuvering in the months leading up to Trump’s inauguration and the Russian military’s contribution in the fall of several rebel strongholds in major Syrian cities.Russian oil and gas companies – all intimately related to Putin’s personal wealth – have reaped the greatest rewards from Moscow’s intrigues.According to Sputnik, which quoted Dmitry Sablin, Assad told a visiting Russian delegation of lawmakers this week that neither Iran nor China has companies with a worldwide reputation in the oil and gas sector like Russia has. Therefore, Assad “sees only the work of Russian companies”, Sablin said.State-owned oil and gas company Rosneft has shaken up the MENA region the most so far.Late last year, American authorities rechecked the terms of a deal for the purchase of a minority stake in Rosneft by the Qatari sovereign wealth fund commodities trader Glencore. At the time, the White House said the arrangement could be in violation of international sanctions levied against Russia after the country forcibly annexed Ukrainian Crimea. Since the $11.3 billion deal profits the Russian government and not Rosneft itself, Moscow argued that it did not violate the terms of the sanctions, which specifically named no-go entities. Two years ago, in Egypt, Rosneft signed two deals to supply liquefied natural gas and other petroleum products to Cairo. In the months following, Russia doubled down on its energy investments in the country, offering $25 billion to build a 1,200 MW nuclear power plant over 12 years. Most recently, Rosneft moved into Iraq and Libya, expanding its footprint in two Middle Eastern countries with weak domestic stability just recovering from years of civil strife.
Russian cuts to oil production stall in February | Reuters: Russia's oil output stayed unchanged in February from the previous month, with cuts at just a third of the levels pledged by Moscow under a global deal to reduce production, Energy Ministry data showed on Thursday. The country's oil and gas condensate output remained at 11.11 million barrels per day (bpd) last month, down 100,000 bpd from levels agreed as the starting point for the accord. OPEC and other large producers led by Russia agreed late last year to reduce their total oil output by almost 1.8 million bpd in the first half of 2017 to boost the price of crude, a key source of revenue. Of that, Russia pledged to cut 300,000 bpd, with 200,000 bpd of reductions in the first quarter. This compares to output of more than 11.2 million bpd in October last year, taken as the baseline for the global deal. In January, Russia cut output by around 100,000 bpd month-on-month, its first reduction since August. It kept that magnitude of output curbs in February. REAL CUTS Analysts at Moscow-based Sberbank CIB said that due to the gradual nature of reductions, "the average cut over the first half of 2017 from the October 2016 reference month would therefore be just under 200,000 bpd, or 99,000 bpd in annual terms". Reuters uses a barrels/tonnes ratio of 7.33. In tonnes, oil output reached 42.434 million in February versus 46.992 million in January. According to Reuters calculations, Russia's cut from the October level reached 100,000 bpd in February, resulting in compliance of just 33 percent. By contrast, compliance within the Organization of the Petroleum Exporting Countries is 94 percent, due mainly to a steep reduction by Saudi Arabia.
Analysis: Asia seen spoilt for choice as more US light oil becomes available - The recent approval of the Dakota Access Pipeline and rising Permian production is expected to leave Asian refiners spoilt for choice as more US light crude oil from the Gulf of Mexico becomes available to them. Once Dakota Access comes online, roughly "couple of hundred thousand barrels per day of US light oil could be available by capacity for exports," said Takayuki Nogami, chief economist at Japan Oil, Gas and Metals National Corp. Nogami said more US light oil could be available for exports as US refiners in the Gulf generally process medium to heavy grades. The delayed 470,000 b/d Dakota Access Pipeline received final federal approval in early February to complete construction, and start up is targeted between March 6-April 1.The four-state $3.8 billion pipeline is designed to deliver Bakken and Three Forks crude to Patoka, Illinois, where it will connect with the Energy Transfer Crude Oil Pipeline to Texas, leaving more crude available for export from the Houston terminals. The Permian is the US' most active crude play by far and the site of most of rig count increases. Production at the Permian Basin has been climbing steadily since September and is projected to reach 2.25 million b/d in March, according to the US Energy Information Administration. A number of refiners in China, Japan and South Korea said that they are closely watching the developments and will consider importing more light oil and possibly sour grades from the US whenever they became competitive against their main sour crude imports from the Middle East. "We will definitely watch this [development over the Dakota Access Pipeline and increasing US oil production] and seek more opportunity," said a refiner in South Korea.
China loads up on West African oil in March, hitting fresh record | Reuters - China's loadings of West African crude oil are set to rise to a new record in March as the nation stocks up on medium and heavy oil in the midst of OPEC production cuts, according to a Reuters survey of shipping fixtures and oil traders on Wednesday, Some 1.41 million barrels per day (bpd) of West African oil are expected to load for China over the coming month, surpassing February and hitting a fresh high since Reuters began tracking the shipments in 2004. China's state-run Unipec led the pack, along with Sinochem, while the nation's independent refineries, known as "teapots", joined in by taking cargoes from trading houses such as Trafigura and Total. The companies favoured Angola's medium and heavy oil including Cabinda, Dalia, Nemba, Plutonio and Saturno, and will also take the first cargo of Angola's newest oil grade, Olombendo. Chinese buyers also booked Congolese Djeno, Ghanaian Jubilee and some cargoes of Nigerian oil, including Escravos and Qua Iboe. Their buying has pressed the differentials versus dated Brent for Angola's crude to unusually high levels, but some analysts warned that some cargoes could be headed for storage rather than immediate consumption. "With seasonal turnarounds, they probably won't be processing it now - they cannot digest it," said Ehsan Ul-Haq, principal consultant with KBC. He added that the buyers were tempted in part because of a still-narrow spread between Brent and Dubai crudes DUB-EFS-1M, which makes West African grades more competitive in Asia, but production cuts from the Organization of the Petroleum Exporting Countries also led some to stock up.
China's largest 'teapot' refiner, CEFC team up in Shandong oil terminal venture | Reuters: Dongming Petrochemical, China's largest independent or 'teapot' refiner, has signed a deal with privately run CEFC China Energy and a local port authority to build a crude oil terminal in Shandong province, seeking to ease a logistics bottleneck gripping the country's teapot oil sector. The 3.9 billion yuan ($566 million) project with conglomerate CEFC China Energy and Rizhao port authorities comes as China's teapots refiners emerge as a catalyst in the global oil market, ramping up Russian and U.S. imports in frenzied buying that has led to tanker queues and scarce storage space. Executives at Dongming, formally known as Shandong Dongming Petrochemical Group, and private firm CEFC said on Friday that publicly owned Rizhao Port Authorities will take 51 percent of the project, CEFC 25 percent and Dongming 24 percent. Plans include a 300,000 deadweight tonnage (DWY) crude terminal, two 150,000-DWT crude berths and a 9.8 million barrel storage farm. "With Qingdao port nearly saturated, Rizhao stands out with its ideal location, with easy access to teapots to the north and close also to Lianyungang, one of China's planned future petrochemical hubs to the south," a CEFC executive told Reuters, declining to be named as he was not authorized to speak to media. CEFC has interests spanning finance and travel as well as oil. A CEFC press official confirmed the details of the deal. Qingdao port is the country's largest oil port by volume, accounting for 27 percent of China's total crude oil imports last year, with crude shipments into the port up nearly 50 percent over 2015, according to Chinese customs data.
Oil Production Vital Statistics February 2017 - January was the month that OPEC was supposed to reduce production by 1.2 Mbpd and Russia + others were supposed to cut a further 0.6 Mbpd. Now that the January production data are in we can see that OPEC cut by 1.04 Mbpd and that Russia + FSU cut by 0.1 Mbpd (well within the noise of revisions) and well short of the 0.3+ Mbpd expected. But global C+C+NGLs were down 1.46 Mbpd suggesting that other countries may have intentionally or unintentionally chipped in. Brent began January on $55.05 and ended the month on $54.77. Today it is $55.56. As explained in the feeble OPEC deal the depth of proposed cuts were to shallow when compared to the scale of over-supply and stocks to make a decisive impact on the direction of the oil price. In January, Libya produced 690,000 bpd, up 70,000 bpd on the month but well short of their target of soon reaching 1 Mbpd. But if Libya (inset map up top) does manage to keep growing production throughout this year this will continue to undermine OPEC efforts to support price.On 24 February there were 602 oil rigs operating in the USA up from 529 on 6th January as reported last month (Figures 4, 5, 6 and 7). Rising oil drilling activity in the USA will inevitably lead to more oil production at some point. US production was 12.48 Mbpd in January down from 12.51 Mbpd in December (Figure 12). Middle East drilling remains on a cyclical high (Figure 9) while drilling remains in the doldrums everywhere else (Figures 8 and 10).The following totals compare January 2016 with January 2017:
- World Total Liquids 96.62/96.39/ -230,000 bpd
- OPEC 32.00/31.86/-140,000 bpd
- Russia + FSU 14.19/14.43/ +240,000 bpd
- Europe OECD 3.55/3.55/ no change
- Asia 7.67/7.42/ -250,000
- North America 19.81/19.48/ -330,000 bpd
Note that Vital Statistics is now produced using the Global Energy Graphed database employing Google Sheets. Since these graphs are live, they will update automatically in future as more data are added meaning that the narrative will no longer match the data in the months ahead.
U.S. oil logs slight gain as signs of rising production cast a shadow - Oil futures barely budged Monday, with a rise in last week’s number of active oil rigs in the U.S. offering another sign that U.S. production is set to contribute to a global glut of supplies despite efforts by other major oil producers to cut output. West Texas Intermediate crude tacked on a few cents per barrel, while Brent crude ended a few pennies lower but overall, both have stuck to a tight trading range for weeks. WTI oil prices have been trading between $50 and $55 this entire year, “which is a relatively narrow range for prices to maintain for months…and a breakout will eventually happen,” said Daniel Waters, commodity analyst at Schneider Electric. “The question is: in what direction?” On the New York Mercantile Exchange, April WTI crude added 6 cents, or 0.1%, to settle at $54.05 a barrel. The April contract for Brent crude on London’s ICE Futures exchange, which expires Tuesday, fell 6 cents, or 0.1%, to $55.93 a barrel. Over the past week, “hedge funds have increased net-long positions in the WTI contract by 6%, which is a signal that managed money believes the breakout will be to the upside,” said Waters, in a note Monday. But “interestingly enough, this convergence of bets to the upside also creates a downside risk, in the event these positions exit relatively quickly on changing sentiment. This could happen if the OPEC deal shows any signs of weakness, specifically if members currently complying being to cheat—even slightly.”
Hedge funds find plenty of willing sellers in oil: Kemp - (Reuters) - For every buyer of futures and options there must be a seller. For every long position there must be a corresponding short position.Hedge funds and other money managers have purchased a record number of futures and options contracts linked to Brent and WTI, betting that prices will rise.As a group, hedge funds now hold a record net long position equivalent to 951 million barrels across the three main Brent and WTI contracts (http://tmsnrt.rs/2mm1HeI).Hedge fund long positions outnumber short positions by a record ratio of 10.3:1 (http://tmsnrt.rs/2mvnvBA). With hedge funds almost all long, some other group of traders must have sold a correspondingly large number of futures and options contracts, either as a hedge or betting prices will fall.Since September 2009, the U.S. Commodity Futures Trading Commission (CFTC) has employed a four-way classification for all traders with reportable positions in crude oil. Traders are classed as a producer/merchant/processor/user, a swap dealer, a money manager, or into a miscellaneous "other reporting" category. Unfortunately, the commission does not disclose how individual traders are classified, which creates considerable uncertainty about the composition of the categories.For example, if a major oil company hedges its inventory as well as providing price risk management services to customers, we don't know whether its trades are classified as producer/merchant/processor/user or as a swap dealer. On Feb. 21, hedge funds and other money managers held a net long position in WTI on the New York Mercantile Exchange (NYMEX) equivalent to 414 million barrels, according to CFTC data. "Other reporting" traders also held a net long position of 173 million barrels while non-reporting traders were net long by 15 million barrels. The corresponding short positions were held by producer/merchant/processor/users, with a net short position of 291 million barrels, and swap dealers, with a net short of 310 million barrels.As hedge funds have increased their net long positions in WTI, the majority of the contracts have been sold to them by swap dealers (http://tmsnrt.rs/2mlWLGN).Hedge funds and other money managers have increased their net long position in WTI by 254 million barrels since early November. Swap dealers increased their net short position by 202 million barrels over the same period (with the balance of extra short positions coming from producer/merchant/processor/users).
Oil prices slip as rising U.S. supplies offset OPEC cuts | Reuters: Oil prices slipped on Tuesday but continued to trade in a tight range, as concerns about rising U.S. crude inventories ahead of data overshadowed OPEC production cuts. U.S. crude stockpiles have been rising for seven consecutive weeks, and forecasts of an eighth build of 2.9 million barrels last week fueled worries that demand growth may not be sufficient to soak up the global crude oil glut.[EIA/S] Inventory data is due from industry group the American Petroleum Institute at 4:30 p.m. EST (2130 GMT) and the government's report at 10:30 a.m. EST on Wednesday. U.S. West Texas Intermediate crude futures settled down 4 cents, or 0.1 percent, at $54.01 a barrel and Brent crude fell 34 cents, or 0.6 percent, to $55.59 a barrel. For the month, Brent was little changed, and WTI set for a gain just above 2 percent. U.S. gasoline futures settled down 1.35 percent to $1.5120 a gallon, also weighing down the petroleum complex. Gasoline was under pressure on the final trading day for the March contract, the final month in which gasoline that complies with environmental standards for winter-grade fuel is offered. Abundant supplies of the fuel, which has different additives from those required in the summer, have weighed on prices. The Organization of the Petroleum Exporting Countries has so far surprised the market by showing record compliance with oil-output curbs, and could improve in coming months as the biggest laggards - the United Arab Emirates and Iraq - pledge to catch up quickly with their targets. While the Nov. 30 agreement to reduce production prompted oil prices to rise $10 a barrel, they have been trading in a narrow $3 range in recent weeks.
Oil traders back off bets on accelerated rebalancing: Kemp - Brent spreads have weakened sharply in recent days as traders become less convinced the oil market will rebalance early in the second quarter.The calendar spread from May to June has eased from 6 cents contango per barrel on Feb. 21 to 30 cents contango on Feb. 27 (http://tmsnrt.rs/2lP8pbF).Calendar spreads track the balance between crude supply, consumption and stockpiles, with contango indicating a market in balance or oversupply, while backwardation is associated with a fall in stocks.Most traders and forecasters expect the oil market to shift from a supply surplus in 2014/15 to a deficit in 2017/18 with a corresponding shift from contango to backwardation.But the timing and profile of the transition is subject to considerable uncertainty and has become one of the most popular plays for hedge funds and other traders.Spreads for the first few months of 2017 rallied consistently and sharply since the middle of January before backing off in recent days.The rally and subsequent reversal has been concentrated in the second quarter while spreads for the third and fourth quarter have been much more stable (http://tmsnrt.rs/2lP0w5W). The rally and reversal were most pronounced in Brent though a similar pattern has been visible in spreads for WTI (http://tmsnrt.rs/2mzz22Q).Hedge funds accumulated a large net long position in WTI spreads following the announcement of production cuts by OPEC and non-OPEC countries in November and December 2016.But the net long position has fallen from a recent peak of 160 million barrels in mid-January to 127 million barrels on Feb. 21. The net position declined by 18 million barrels in the most recent week alone and is back to levels last recorded in December (http://tmsnrt.rs/2m2bbe9).
Exclusive: Saudi Arabia wants oil prices to rise to around $60 in 2017 - sources | Reuters: Saudi Arabia wants crude oil prices to rise to around $60 a barrel this year, five sources from OPEC countries and the oil industry said. This is the level the OPEC heavyweight and its Gulf allies - the United Arab Emirates, Kuwait and Qatar - believe would encourage investment in new fields but not lead to a jump in U.S. shale output, the sources said. The Organization of the Petroleum Exporting Countries, Russia and other producers pledged last year to cut production by about 1.8 million barrels per day (bpd) from Jan. 1. The first cut in eight years is intended to boost prices and get rid of a supply glut. Crude prices have risen by more than 14 percent since the November pact but are still only trading around $56 a barrel despite record compliance by OPEC and non-OPEC members. OPEC officials have repeatedly said the group does not target a specific oil price and their focus is on drawing global oil inventories and helping the market to re-balance. But behind closed doors, Riyadh and its Gulf OPEC allies hope to see a higher level because the low price has pressured their finances and stoked fears of a future supply shortage. However, they do not want the price to be so high that it encourages rival U.S. shale producers, which were hard hit by the slump in oil prices, to ramp up production again. Advances in technology have made it easier for them to adapt quickly to oil price fluctuations.
The $60 Ceiling For Oil - Oil prices faltered on Tuesday on slow but steady gains in U.S. output. The failure to break out of a narrow trading range on the upside has exposed crude to some losses. "Having failed on a couple of occasions to break higher it is only natural to see it correct lower. I'm looking for a retracement to $55 on Brent and $52.70 on WTI,” Saxo Bank head of commodity strategy Ole Hansen told CNBC. A Reuters survey of 31 analysts and economists resulted in an average prediction for Brent crude prices in 2017 of $57.52 per barrel, a drop off from its previous survey. The analysts see oil staying below $60 per barrel even if OPEC extended its cuts through the end of the year. "OPEC will extend its deal to limit cumulative supply, probably adjusting the numbers in order to take into account developments about global stock levels and production from non-participating countries," Intesa SanPaolo analyst Daniela Corsini told Reuters. "We expect crude markets will be in deficit in the first three quarters of 2017 and then they could swing into a small surplus in the fourth quarter amid rising non-OPEC supply," Corsini added. Five OPEC sources told Reuters that Saudi Arabia wants oil prices to rise to $60 per barrel this year. That price level is optimal for OPEC, top officials in Saudi Arabia believe, because it will not lead to extraordinary increases in U.S. shale production but would still provide enough revenue for oil producers. Hedge funds and other money managers continue to ratchet up their bullish bets on crude oil, taking net-long positions to another record high. Meanwhile, oil producers have been increasing their hedges, fearing another downturn. "I’m looking for prices to rise this year, but not above $60, and the reason for the ceiling is the tremendous resilience of U.S. shale," Tamar Essner, an energy analyst at Nasdaq Inc., told Bloomberg. "The market is very one-sided right now, which makes me nervous because that often precedes a reversal." OPEC already achieved close to a 90 percent compliance rate with its oil production cut, and compliance could increase as Iraq and UAE promise to accelerate their reductions. The two OPEC members were the main laggards in what was an otherwise impressive rate of compliance. But top officials from the two countries recently made statements pledging more cuts in the coming months.
OPEC giving up the gains - So far, OPEC compliance with its production cut goals appears to have been good, with cold weather and natural declines adding to reductions from non-OPEC producers, resulting in Russia being ahead of schedule. Some OPEC members have exceeded their compliance targets, notably Saudi Arabia and Kuwait. The only real laggards are Iraq, the UAE and Venezuela.Overall, OPEC production in January, according to an S&P Global Platts survey, was down 690,000 b/d to 32.16 million b/d from December. The impact of the cuts was offset by gains of a combined 260,000 b/d from Nigeria and Libya, both of which are exempt from the deal, while Iranian production edged up by 30,000 b/d, which again is within the scope of the deal’s terms. Compliance has been high enough to sustain the gains made in the oil price since the agreement was announced.Given that the 10 OPEC members participating achieved 91% compliance with their October baseline and that Russia reduced output by 118,000 b/d in January from an overall target of 300,000 b/d in first-half 2016, it could be argued that there is not much more to come from the countries keenest to comply and make the deal a success.Meanwhile, the International Energy Agency reported that end-December OECD total oil stocks fell below 3 billion barrels for the first time since December 2015, and that they fell 800,000 b/d in fourth-quarter 2016, the largest drop in three years. This was before the cuts came into effect and must therefore be seen as a result of reduced non-OPEC production, in other words, OPEC’s earlier market share strategy. However, a surge in US crude imports since the start of this year has pushed US stocks to near record highs, highlighting the challenge OPEC faces in accelerating the reduction in global inventories.
RBOB Slides After Surprise Gasoline Inventory Build; New Record Glut In Crude -After a volatile day of White House rumors and denials, and OPEC headlines, WTI and RBOB ended the day lower ahead of tonight's API data which showed a slightly smaller than expected crude build (+2.5mm against expectations of +3mm). However RBOB prices tumbled after an unexpected build. API:
- Crude +2.502mm (+3mm exp)
- Cushing +544k
- Gasoline +1.84mm (-1.5mm exp)
- Distillates -3.73mm
While crude built again (the 8th week in a row), it was the swing back to a build in gasoline that is most notable...
OPEC compliance with oil curbs rises to 94 percent in February: Reuters survey | Reuters: OPEC has cut its oil output for a second month in February, a Reuters survey found on Tuesday, allowing the exporter group to boost already strong compliance with agreed supply curbs on the back of a steep reduction by Saudi Arabia. The Organization of the Petroleum Exporting Countries is cutting its output by about 1.2 million barrels per day (bpd) from Jan. 1 - the first such deal since 2008 to get rid of a glut. Non-OPEC countries pledged to cut about half as much. Previous OPEC cuts have been mired in mass cheating by its members, making strong compliance by OPEC this time a positive surprise for the market, with prices trading above $55 per barrel -- up from $35 a year ago. Top exporter Saudi Arabia and its Gulf allies are hoping the cuts will help oil rise a bit further to around $60, five sources from OPEC countries and the oil industry said, to boost exporters' income and industry investment. "If compliance is high by OPEC and non-OPEC, then I think prices will reach $60," said an OPEC delegate. "If it was higher it would be better, but $60 is fine." In January, OPEC delivered 82 percent of the promised cuts, according to a Reuters survey and over 90 percent according to OPEC's own report. The International Energy Agency has said it was impressed with OPEC's compliance, calling it a record level. In February, supply from the 11 OPEC members with production targets under the deal has averaged 29.87 million bpd, down from a revised figure of 29.96 million bpd in January and 31.17 million bpd in December, according to the Reuters survey.Compared with the levels the countries agreed to make the reductions from, in most cases their October output, this means the OPEC members have cut output by 1.098 million bpd of the pledged 1.164 million bpd, equating to 94 percent compliance.
WTI/RBOB Tumble As US Crude Inventories Hit New Record High, Production Surges After API's surprise gasoline build (sending RBOB prices lower), DOE reported a draw (though smaller than expected) but crude saw the 8th weekly build in a row - pushing US crude inventories to a new record high. Production continued to surge (above 9mm) to new cycle highs. DOE:
- Crude +1.501mm (+2.2mm whisper)
- Cushing +495k (-400k whisper)
- Gasoline -546k (-1mm whisper)
- Distillates -925k (-2.1mm whisper)
The 8th weekly build in a row for crude but Gasoline's draw is the most notable (relative to API)...
Oil slips after U.S. crude stocks build to record high | Reuters: Oil prices ended slightly lower on Wednesday as record high U.S. crude supplies tempered expectations that the market will rebalance as evidence emerges that OPEC producers are complying with an agreement to cut production. Crude stockpiles in the United States, the world's top oil consumer, rose 1.5 million barrels last week, less than forecast, but touching a record at 520.2 million barrels after eight straight weekly builds.[EIA/S] The consecutive increases have fueled worries that demand growth may not be sufficient to soak up the global oil glut despite a deal by major oil producers to cut output during the first half of the year. U.S. West Texas Intermediate (WTI) futures for April delivery CLc1 settled at $53.83 a barrel, down 18 cents or 0.3 percent. May Brent crude futures LCOc1 dropped 15 cents, or 0.3 percent, to $56.36 a barrel. "The EIA stats don't offer much in the way of surprises this week," said David Thompson, executive vice-president at Powerhouse, an energy-specialized commodities broker in Washington. "Lack of weather-generated demand for heating oil will be offset in coming weeks by agricultural demand, but with refineries coming back into service, the market looks capable of meeting any increased demand." Despite the reaction to the data, oil remained locked within a tight trading range as some investors took heart from strict OPEC compliance with its pledge to cut output.
Oil down more than 2 percent as Russian output cuts stall | Reuters: Oil prices fell more than 2 percent on Thursday after Russian crude production remained unchanged in February, showing weak compliance with a global deal to curb supply to tighten the oversupplied market. Russia's February oil output was unchanged from January at 11.11 million barrels per day (bpd), energy ministry data showed, with cuts remaining at 100,000 bpd or just a third of the levels pledged by Moscow under the agreement with the Organization of the Petroleum Exporting Countries. Brent futures ended the session $1.28, or 2.3 percent, lower at $55.08 per barrel and U.S. crude settled down $1.22, or 2.3 percent, at $52.61. A stronger dollar also weighed on green-back denominated oil, making it more expensive for buyers in other currencies. The dollar rose to seven week highs against a basket of currencies after hawkish comments by a Federal Reserve official encouraged investors to expect a near-term interest rate hike. [USD/] The oil markets extended losses from Wednesday when government data showed crude inventories in the United States, the world's biggest oil consumer, rose for an eighth straight week to a record 520.2 million barrels last week. Oil prices, however, have been unusually stable since producers agreed in November to reduce the oversupply that has weighed on prices for more than two years, with both Brent and U.S. crude locked in $5 ranges.
Russia's Novak says talk of global oil output cuts extension premature | Reuters: It is too soon to say if a global deal on oil output cuts will be extended later this year, but the current agreement envisages such a possibility, Russian Energy Minister Alexander Novak told Reuters in an interview. The Organization of the Petroleum Exporting Countries and non-OPEC producers, led by Russia, in December reached their first deal since 2001 to jointly curtail oil output, by around 1.8 million barrels per day (bpd). The deal is effective until the end of June. OPEC sources told Reuters last month that the group could extend the pact with non-members or even apply deeper cuts from July if global crude inventories fail to drop to a targeted level. OPEC's next meeting is planned for May 25. "It is premature to talk of what we will discuss in April-May. The technical possibility of the deal extension is envisaged by the agreements," Novak said in an interview cleared for publication on Thursday. Officials in the 13-member OPEC, including Saudi Energy Minister Khalid al-Falih, have said global oil stocks need to fall near to their five-year average for the group to say markets are becoming balanced. Novak said further action would depend on the size of stocks and how output in other producers, notably in the United States, China and Norway, which did not join the pact, would affect the global balance of supply and demand.End-December stocks of crude, natural gas liquids and oil products in OPEC member countries had fallen below 3 billion barrels, but were still 286 million barrels above the five-year average, the International Energy Agency said last month. Stocks also continued to build in China and volumes of oil stored at sea increased. Novak said Moscow was unlikely to cut more than it had already pledged if other non-OPEC producers failed to comply with their own promises.
Vitol Said to Offer 4 Million Barrels of Stored Oil as Crude Glut Ebbs -- Vitol Group BV is offering to sell Nigerian crude oil from a storage terminal in South Africa, five traders familiar with the matter said, in what may be a signal that the global supply glut is beginning to ease. The world’s biggest oil merchant has been offering 4 million barrels of Nigeria’s Qua Iboe for delivery to Europe that it’s been keeping at storage facilities in Saldanha Bay on South Africa’s west coast, according to the people, who asked not to be identified because the information is private. Normal trades are about 1 or 2 million barrels each. The proposed sales offer investors a signal that a glut that crashed prices could be clearing because it shows traders may be emptying out stockpiled supplies. They were able to profit from storing thanks to a pricing structure called contango, in which the glutted market made immediate prices cheapest of all. Saudi Arabia is now leading OPEC and its allies in trimming global supplies. “With the contango structure narrowing, it is no longer economical to stockpile,”. “Some refiners might be willing to take large volumes of West African crude if they can get it before they end their seasonal refinery turnarounds.” Brent crude oil futures for May traded 61 cents a barrel lower than November prices, according to data from ICE Futures Europe at about 4:34 p.m. in London on Thursday. As recently as November, the gap for equivalent contracts stood at $4.25. Provided traders could find storage and finance for cheaper than that, then they could profit from holding onto barrels. Andrea Schlaepfer, a Vitol spokeswoman, declined to comment. “Spreads will come under pressure” as stored barrels are sold, said Amrita Sen, chief oil analyst at Energy Aspects in London. “Everytime the curve flattens, stocks will be unwound and then spreads will weaken. This process will occur till the point there is no storage left to draw down.”
Are Oil Prices Really Driven By Supply And Demand? -- For most people the reflexive answer to the title question is yes. Consider, however, that over various time spans since 1980, the price of oil has dropped 75, 76, 78, and 75 percent, and risen 320, 265, 370, 196, and 254 percent (The Socionomic Theory of Finance, Robert Prechter, page 458). Prices for most goods sold in retail establishments, presumably determined by supply and demand, haven’t swing up and down like that over the years in either nominal or inflation-adjusted terms.Perhaps oil supply and demand have special characteristics that drive the price in ways such that percentage changes in price are far greater than the underlying percentage changes in production or consumption. If so, does anyone have a model that predicts supply and demand and delineates a relationship between them and the price of oil? Does this model yield testable hypothesis, and what is its predictive record? Has it consistently caught oil’s dramatic price swings?There is a model that has repeatedly predicted oil’s price swings and the amplitude of the ensuing trend, but explicitly rejects supply and demand as independent variables. At the very least, this model should prompt a critical examination of the supply and demand hypothesis and its applicability to the oil market. In Robert Prechter’s recently released The Socionomic Theory of Finance (STF), Chapter 22, “Elliott Waves vs. Supply and Demand: The Oil Market,” the author surveys the predictive track record of oil market analysts at his company, Stripped to its essentials, here are the basics of the socionomic theory.The main theoretical principles are that in human, complex systems:
- • Shared unconscious impulses to herd in contexts of uncertainty lead to mass psychological dynamics manifested as social mood trends.
- • These social mood trends conform to a hierarchal fractal called the Wave Principle (WP) and therefore are probabilistically predictable.
- • These patterns of human aggregate behavior are form-determined due to endogenous processes, rather than mechanistically determined by exogenous causes.
OilPrice Intelligence Report: U.S. Shale Is Killing The Oil Price Rally: Oil prices dropped to a three-week low on Thursday following a bearish data release from the EIA. Crude inventories broke a new record at 520.2 million barrels, and U.S. oil production figures jumped to 9.032 million barrels per day, a gain of 31,000 bpd from the previous week. Rising production and inventories weighed on prices. However, a weaker dollar buoyed WTI and Brent towards the end of the week. Data for February is in and it shows that OPEC increased its compliance rate. Saudi Arabia took on the additional burden, cutting deeper than it promised as part of the November deal. The oil kingdom cut output by 90,000 bpd in February from January levels, taking output down to 9.78 million barrels per day. Reuters puts the compliance rate at 94 percent, while Bloomberg has it at 104 percent. Saudi Arabia is making up for a handful of countries that are falling short on their commitments, including Iraq, the UAE, Angola and Venezuela. Plus, this does not take into account rising output from Libya, Nigeria and Iran. When included, OPEC is producing 415,000 bpd above its target. Moreover, Russia has not slashed its production beyond the 100,000 bpd reduction in January. Saudi Aramco discounted its oil by 50 to 75 cents for its light oil to be delivered to Asia in April, and cut prices for its light and medium grades by 30 cents per barrel, according to the WSJ. They also offered discounts to oil heading to North America and Northwest Europe. The price changes do not necessarily mean much, but changes in prices have been closely watched over the past few years by analysts hoping to glean clues from Saudi officials on their strategy. . Daryl Liew of REYL Singapore sees oil trading within a range of $50 and $60 for much of this year. OPEC compliance will keep prices from falling but rising U.S. shale production will cap any price gains. Normally, U.S. natural gas stocks are drawn down in the winter as heating demand spikes, only to be replenished between April and November. But the EIA just reported a shocking increase in natural gas inventories, a major development given that winter is not over yet. The increase of 7 Bcf puts gas stocks at 295 Bcf above the five-year average for this time of year. With only a few weeks left of winter, the disappointing drawdowns suggest that the market will be well supplied for the rest of the year, potentially heading off any chance of meaningful price gains. Natural gas spot prices are already down 30 percent from their December peak, sitting at $2.80/MMBtu.
Baker Hughes: oil rig count up 7, gas rigs down 5 -- The Baker Hughes rig count rose to 756 this week, with a gain of 7 rigs exploring for oil and gas. The U.S. gas rig count dropped by 5, according to data from Baker Hughes March 3. According to Business Insider, WTI crude oil futures are headed for a weekly loss of 1.5%, following data from the Energy Information Administration on Wednesday that showed inventories rose for the eighth straight week in a row by 1. 5 million barrels. U.S. oil inventories are “at the higher end of the average range for this time of year,” said the EIA. Crude prices are up due to OPEC’s continued production cuts but still risk a drop due to new shale drilling. Principal players in the oil market from Saudi Arabia, Russia, Brazil, Mexico and the US will meet next week for the annual CERAWeek energy conference. Shale drillers, especially those in the Permian Basin, can profit at $40 oil because of advances in drilling. Helena Croft, head of global commoditites strategy at RBS, told CNBC: I think OPEC is hoping that this remains largely a Permian story. … That a lot of the cost deflation we saw will rise as prices rise. Service companies will again charge more. There’s a sort of uncertain equilibrium they have to deal with in U.S. production. They hope it will remain largely Permian, but it could get away from them and require deeper cuts. I don’t think the problem is compliance within OPEC, because the Saudis will do what it takes. Oil closed today at $53.24, up 1.2 percent. Brent crude closed at $55.81, up 1.33 percent. Natural gas was also up 0.75 percent to close at $2.825.
Production, Rig Count Surge As Exxon Bets Big On U.S. Shale - US oil rig counts rose for the7th straight week (up 7 to 609) to the highest level since October 2015. With production surging back above 9mm b/d - the highest in a year - the trend in the rig count implies considerably more production to come... And with rig counts rising (in the Permian), production shows no signs of slowing, as OilPrice.com's Nick Cunningham notes, ExxonMobil’s new CEO Darren Woods announced a dramatic shift towards shale drilling this week, a new strategy that will prioritize drilling thousands of smaller wells while reducing spending on the massive projects that the oil major has long been accustomed to pursuing.Mr. Woods gave a presentation to investors on March 1, selling his vision after recently taking over from Rex Tillerson, who left to become U.S. Secretary of State. Exxon will now ramp up spending on shale drilling, after watching dozens of smaller companies profit from the surge in production in Texas, North Dakota and elsewhere over the past decade. Exxon will dedicate a quarter of its 2017 spending budget on shale, putting $5.5 billion into the effort. “More than one quarter of the planned spending this year will be made in high-value, short-cycle opportunities, including in the Permian and Bakken basins,” Exxon wrote in a March 1 statement. The oil major says that it has 5,500 wells in its queue for drilling in the Permian and the Bakken shales, each with a return of 10 percent or more at $40 per barrel.Exxon was able to build up this inventory of shale wells with the $6.6 billion it spent in January to double its Permian acreage. The shift towards shale should pay off over time, with a portfolio of thousands of tiny shale wells making up a growing share of the oil major’s production portfolio. By 2025, Exxon says that its production from the Permian and the Bakken could amount to 750,000 barrels per day, or about a fifth of its total output.
Oil Rig Count Hits A 17-Month High - The number of active oil and gas rigs in the United States increased on Friday by 2. Both benchmarks were trading up earlier on Friday on reports of an evacuation of Libya’s oil port earlier in the day, assuaging, albeit temporary, market fears that OPEC’s surprising compliance of 90 percent may offset by nonparticipants’ production increases—including Libya. Further pushing up oil prices earlier in the day was the falling dollar.The total number of active oil and gas rigs in the United States is now 756, according to oilfield services provider Baker Hughes, which is 267 rigs above the rig count a year ago.The number of oil rigs increased this week by 7, up from 602 last week to 609 this week. This week marks the seventh week in a row of increases to the number of active oil rigs in the United States—the most active oil rigs since October 02, 2015.Oil rigs have increased by 132 since the OPEC agreement was announced on November 30, as US drillers continue to ramp up while OPEC continues to hold its members largely to specified production caps.The number of gas rigs declined by 5 this week, and now stand at 146, sliding for the second week, after a long running fourteen-week streak of no losses.In Canada, the rig count declined by 6 to 335—206 rigs more than this time last year. At noon EST WTI was trading up 1.1% at $53.19 per barrel—around $1.00 lower than last Friday’s pre-rig count price. The Brent crude benchmark was trading up 1.02% at $55.64—almost $.50 below the price point last Friday. Both benchmarks began to slide slightly after the count was released, with WTI trading at $53.16 and Brent trading at $55.62.
Saudi fuel prices set for new hike in July; sources - Saudi Arabia, the world's largest crude exporter, is set for a new round of domestic fuel and energy price increases from the middle of this year, as the government seeks to drastically cut spending on subsidies, sources in the country said Tuesday. Price increases of around 25-30% for gasoline and diesel have been discussed, the sources said, but the government is still waiting for approval and to establish a mechanism which will protect lower income households from any sharp jump in costs. The ministry of finance was not available for comment. "Along with electricity price hikes, we see an increase of 30% for gasoline coming in July too. We have had to reshape our forecasts for 2017 based on this," one source at a major international bank in Saudi Arabia said.Increases of up to 40% had been widely expected to be included in the kingdom's 2017 budget late last year, but didn't materialize. Instead the government announced a few details of its planned economic reforms up to 2020, known as the Fiscal Balance Program, which it hopes will save around Riyals 362 billion ($97 billion). If the increased fuel and power prices are confirmed, it would be the second major hike after the kingdom's dramatic change in policy last year. In its 2016 budget, it increased long-standing prices for gasoline and domestic gas for power generation as well as ethane feedstock as part of a broader program to cut subsidies and reduce the budget deficit. The 2016 price rise saved the government as much as Riyals 29 billion, Riyadh-based Jadwa Investments said in a research note Monday. With additional increases in prices by 2020, it could save Riyals 209 billion.
The Saudi king is taking 459 tons of luggage on his trip to Indonesia — including 2 elevators -- Saudi Arabia’s King Salman bin Abdul Aziz doesn’t believe in travelling light. The Washington Post has an extraordinary story about Salman’s upcoming visit to Indonesia, the first visit by a Saudi king to the nation in 46 years. Salman’s international tours never fail to make headlines. In 2015, he and his 1,000-person entourage caused the closure of a French Riviera beach for three days. During that trip, a bizarre story emerged that a local mayor had complained because Salman’s group had poured concrete on the beach to install an elevator directly on the sand here, below the king’s private villa: Indonesian officials might take note of that story, because a large chunk of Salman’s 459 tonnes of luggage comes in the form of two elevators. Yes, you read that right – the Saudi king will be toting two electric elevators all the way to Indonesia. And two Mercedes-Benz S600 limousines. Adji Gunawan of the airfreight company PT Jasa Angkasa Semesta told the Antara News Agency his company had 572 workers ready to control Salman’s luggage. But if that sounds excessive, check out the full story at The Washington Post and details of what then US president Barack Obama lugged with him to sub-Sharan Africa in 2013.
As Saudis prepare to sell shares in oil giant, some have misgivings | Reuters: Jamil Farsi, a prominent Saudi Arabian jewelry tycoon, made an impassioned plea to the investment minister at a meeting of the Jeddah Chamber of Commerce this month. "I don't know anything about economics but I beg you, and I beg the officials in the country, not to sell Aramco - not 5 percent, not 1 percent," he said. Investment minister Majed al-Qasabi replied the economy would benefit from the sale of shares in national oil giant Saudi Aramco. It is expected to be the world's largest initial public offer, raising tens of billions of dollars. But Farsi's plea underlined misgivings among substantial parts of the public and the business community about the sale. Some fear Riyadh is relinquishing its crown jewels to foreigners cheaply at a time of low oil prices. Those misgivings are not likely to block the IPO, which is a central part of a drive to make the economy more efficient and diversify it beyond oil exports. Since 2015, the government has shown it is willing and able to carry out contentious reforms, such as cuts to civil servants' financial allowances. But the public criticism, rare in a country where there is usually little open debate about government policies, could influence the way the IPO is structured. Up to 5 percent of the company is due to be sold next year, with listings in Riyadh and at least one foreign market.
Cooking The Books? Saudi Aramco Could Be Overvalued By 500% - The world’s most valuable oil company, Saudi Aramco, is approaching its first IPO in 2018, as the government of Saudi Arabia prepares to sell off portions of the company in order fill a sovereign wealth fund crucial to the country’s transition away from an oil-based economy.Saudi Aramco is worth $2 trillion, according to Riyadh, and its five percent initial offering could yield $200 billion. This would be the largest IPO in history, blowing away the offering of China’s Alibaba in 2014.The problem, however, is that the company itself may not be worth as much as the Saudi government claims. Recent reports and growing skepticism regarding Aramco’s actual worth have cast some doubts on whether the world’s largest IPO will be as earth-shattering as originally thought.The original estimate offered by Saudi Arabia, which placed Saudi Aramco’s worth at around $2 trillion, was based on a valuation of Saudi Arabia’s oil proven reserves, 261 billion barrels. Multiplying at $8 per barrel, those reserves alone are worth $2.088 trillion. When Saudi Crown Prince Mohammed bin Salman made that original estimate, it garnered some skepticism: how could any company be worth such an astronomic sum?Now, analysts at Wood Mackenzie have conducted their own study of Saudi Aramco, and came up with a completely different (and much lower) figure. WoodMac puts Aramco’s true value closer to $400 billion, eighty percent less than the Saudi estimate, and it arrived at the figure by considering future demand and the anticipated average price of oil (on which profits will depend), as well as Saudi Aramco’s status as a state-run company.WoodMac doesn’t dispute the figure of 261 billion barrels lying under Saudi Arabia and just offshore; that figure has been confirmed by independent sources. Where things get complicated, though, is in the management and taxation of Saudi Aramco, which does not release financial statements. It is known that the company, which is the bedrock of the Saudi economy and the major foundation for state finances, pays a twenty percent royalty on revenues and an 85 percent income tax, supporting the Saudi government and providing a living for the 15,000 members of the Saudi royal family. Tax commitments of that size could have a major impact on the company’s profitability, leaving little in dividends, a factor WoodMac considered in its valuation.
Saudi Arabia Offers To Deploy Special Forces In Syria To Fight ISIS --Saudi Arabia's foreign minister, Adel al-Jubeir, better known to the US public for his threat last April 2016 to sell US Treasuries should the US press with a probe of Saudi involvement in the Sept 11 attacks, made a rare visit to Baghdad over the weekend in an attempt to mend the kingdom's tense relations with Iraq. al-Jubeir's surprise trip on Saturday marked the first official visit by a Saudi foreign minister since 1990, and the first high-level visit since the 2003 US-led invasion. "It's the hope of the Kingdom of Saudi Arabia to build excellent relations between the two brotherly countries," said Jubeir. "There are also many shared interests, from fighting extremism and terrorism [to] opportunities for investment and trade between the two countries."Jubeir, who met his Iraqi counterpart Ibrahim al-Jaafari and Prime Minister Haider al-Abadi, also announced Saudi plans to appoint a new ambassador to Iraq. But the biggest highlight of the meeting was the proposal by Saudi Arabia to "discuss cooperation" in the fight against ISIL.Jubeir expressed his country's support for an ongoing US-backed Iraqi campaign aimed at dislodging the group from Iraq, according to Abadi's official statement. A day earlier, Iraqi forces punched through the defences of the last ISIL stronghold in Mosul. Defeating ISIL in Mosul would roll back the self-styled caliphate it declared in Iraq and Syria in 2014 after seizing large parts of both countries. About 100,000 Iraqi soldiers, security forces, Kurdish Peshmerga fighters, and mainly Shia paramilitary forces are participating in the Mosul campaign that began on October 17.It wasn't just cooperating with Iraq to "eradicated" ISIS, but also the US. As quoted by the Saudi Embassy in the US, al-Jubeir said the following: "The Kingdom and other Gulf nations have expressed that they are ready, in cooperation with the United States, to send special forces. Even other nations that are part of the Islamic Coalition against Terrorism and Extremism are ready to send troops. We are cooperating with the United States to see what the plan is and what is necessary to take action."
Four Bombs Blast Oil Pipeline In Iraq --Four bombs detonated at an oil pipeline in Kirkuk, northern Iraq, killing one and injuring three members of the Kurdish security forces. At the time of the blasts, the pipeline was shut down for maintenance.The blown-up pipe is used to pump crude from the Bai Hassan field to a degassing facility in Kirkuk. The blasts come soon after Baghdad signed a memorandum of understanding with Tehran for the construction of a pipeline that would see crude from the Kirkuk area exported via Iran.The pipeline, local media note, would help the central government in Iraq diversify away from the autonomous region of Kurdistan, with which relations have been strained for years because of disputes regarding oil.The Bai Hassan field, along with others in the area, was operated by the North Oil Company until 2014, when the Kurdistan Regional Government took over. Based on recent media reports, however, it seems the NOC is back in control of the field. Its reserves are estimated at 2.08 billion barrels. Tensions between Baghdad and the KRG flared again last week, after the signing of the MoU with Iran. The Kurdish government said it had not been consulted on the pipeline construction project, suggesting it won’t go ahead without Erbil’s blessing. “It is being discussed again. But we don’t believe the talks will materialize to action, as no one has consulted the KRG,” a Kurdish government official was quoted as saying.
Iraqis are giving their kids Valium in order to escape from ISIS in Mosul : (AP) — Thousands of civilians fled Mosul overnight as Iraqi forces advanced north of a sprawling military base near the city's airport on Friday. Iraq's special forces pushed into the Wadi Hajar district in western Mosul and retook the area from the Islamic State group Friday, according to Brig. Gen. Yahya Rasool, spokesman of the Joint Military Operations. Special forces Brig. Gen. Haider al-Obeidi said clearing operations were ongoing in the area and his forces were close to linking up with the militarized federal police forces who were pushing up along the western bank of the Tigris river. Iraqi forces, including special operations forces and federal police units, launched an attack on the western part of Mosul nearly two weeks ago to dislodge IS. Since the offensive began, more than 28,000 people have been displaced by the fighting, according to the United Nations. Nahla Ahmed, 50 fled Mosul late Thursday night, walking more than five kilometers (three miles) from her home in the Shuhada neighborhood. "All the families were hiding behind a wall," she said, explaining how they escaped an IS-held part of the city. "We gave the children valium so they wouldn't cry and (the IS fighters) wouldn't catch us." Ahmed, like most of the civilians who have escaped Mosul in the past week, fled through Mamun neighborhood. The district is partially controlled by Iraq's special forces.
Syrian Rebels Are Using Snapchat to Sell and Show-Off Their Weapons - Young rebel fighters in civil war-stricken Syria are using Snapchat as their social media platform of choice for selling, buying, and boasting about weapons and equipment for the battlefield. Snapchat messages received by Motherboard itself, as well as screenshots provided to Motherboard of accounts posting items such as consumer drones and thermal scopes for sale, show that the ephemeral messaging app provides the perfect mix of instantaneous and direct storytelling for a mobile-only, millennial generation of fighters. Snapchat, which this week expanded sales of its Spectacles eyewear device to the general public, is most popular amongst 18 to 24-year-olds in the US. The story, Motherboard is told, is no different in Syria. "For the most part, rebel fighters use Snapchat like kids in the West," John Arterbury, a Washington DC-based security analyst, told Motherboard in an email. "They show off what they're doing, they document light-hearted moments, and they cultivate and project a stylized image of themselves. When they do use it as a weapons market, it's to showcase items that maybe aren't normally found in the real-world arms markets of Idlib and its surroundings." Arterbury showed Motherboard two documented cases of items put up for sale over Snapchat in the past couple of months. The first item was a Phantom 4 consumer drone, with the seller noting it had been used to film a Jabhat al-Nusra battle scene. Another instance, this one of an actual arms sales listing, pertained a thermal riflescope, which was being sold to raise funds for Haya-at Tahrir al-Sham, a Jihadist and Salafist group involved in the Syrian Civil War.
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