oil prices managed to see their first small increase in eight weeks this week, as traders waited for direction from this weekend's G-20 meeting in Buenos Aires and the December 6th OPEC meeting in Vienna, but still finished November with a 22% decline, the largest one month drop in oil prices in more than a decade...after falling more than 11% to $50.42 a barrel on fears of a supply glut last week, contract prices of US crude for January delivery rallied from their oversold condition by $1.21, or 2.4%, to $51.63 a barrel on Monday, clawing back some of last Friday's near 8% drop, supported by a broad rally in U.S. stock markets...but prices floundered again in early trading on Tuesday, sliding 2% to $50.30 a barrel, weighed down by uncertainty over the U.S.-China trade war and signs of increased global crude production, before recovering to end with a loss of just 7 cents at $51.56 a barrel, on expectations that oil exporters would agree to cut their output at the coming OPEC meeting...prices resumed their slide towards $50 on Wednesday, falling $1.27 to $50.29 a barrel, the lowest closing price in more than a year, after the EIA reported the 10th consecutive increase in U.S. crude inventories, feeding oversupply fears...oil prices then slipped under $50 a barrel for the first time in 14 months on Thursday morning as Russia initially signaled little urgency to commit to supply cuts, but then recovered to close with an increase of $1.16 at $51.45 a barrel, after Reuters, citing industry sources, reported that Russia was becoming increasingly convinced it will need to cut oil output in support of OPEC...oil prices then tumbled back below $50 a barrel on Friday morning before spiking to as high as $51.79 during a volatile end-of-week session ahead of the G20 and OPEC meetings, but slipped back again near the close to end 52 cents lower at $50.93 a barrel, with losses limited by expectations that OPEC and Russia would agree some form of production cut in the coming week...so while they avoided another massive selloff and eked out an increase of 1% on the week, the January oil contract still ended November 22.2% lower for the month, and 39% off the 4 year high of $76.41 a barrel seen in trading of November oil on October 3rd...
natural gas prices also ended higher for the week, with those gains complicated by the expiration of trading in the December oil contract on Wednesday...the natural gas contract for December delivery, which ended last week at $4.308 per mmBTU, fell 6 cents on Monday and 1.4 cents on Tuesday before jumping over 50 cents on a contract expiration rally on Wednesday, before ending the day with a gain of 45.3 cents at $4.715 per mmBTU, as yet another cold weather forecast fed the increase...meanwhile, the natural gas contract for January delivery, which ended the prior week at $4.355 per mmBTU, fell 4 out of 5 days but also jumped more than 40 cents on Wednesday and ended the week 5.9% higher at $4.612 per mmBTU, shaking off a Thursday drop to as low at $4.452 per mmBTU on a natural gas storage report from the EIA that showed a smaller than expected withdrawal from inventories...
the natural gas storage report for the week ending November 23rd from the EIA showed that the quantity of natural gas in storage in the US fell by 59 billion cubic feet to 3,054 billion cubic feet over the week, which left our gas supplies 644 billion cubic feet, or 17.4% below the 3,698 billion cubic feet that were in storage on November 24th of last year, and 720 billion cubic feet, or 19.1% below the five-year average of 3,774 billion cubic feet of natural gas that are typically in storage on the fourth weekend of November....this week's 59 billion cubic feet withdrawal from US natural gas supplies was somewhat less than the 76 billion cubic foot withdrawal that analysts had been expecting, but it was more than the average of 49 billion cubic feet of natural gas that have been withdrawn from storage during the third full week of November in recent years...natural gas storage facilities in the Midwest saw a 21 billion cubic feet drop in supplies over the week, which increased the region's gas supply deficit to 12.3% below normal for this time of year, while natural gas supplies in the East fell by 25 billion cubic feet and their supply deficit rose to 12.9% below normal for the 4th weekend in November...on the other hand, the South Central region saw a 5 billion cubic feet drop in their supplies, and their natural gas storage deficit remained unchanged at 26.8% below their five-year average for this time in November...at the same time, 4 billion cubic feet were pulled out of natural gas supplies in the Pacific region as their deficit from normal fell to 26.8%, while 3 billion cubic feet were withdrawn from storage in the sparsely populated Mountain region, where their natural gas supply deficit rose to 20.8% below normal for this time of year....
for a visualization of where our natural gas supplies stand vis-vis what is normal, we'll include this week's graph from the natural gas storage report showing natural gas in storage over the past two years, as compared to the 5 year range...
the above graph comes from this week's Natural Gas Storage Report, and it shows the quantity of natural gas in storage in the lower 48 states over the period from October 2016 up to the week ending November 23rd 2018 as a blue line, the average of natural gas in storage over the 5 years preceding the same dates shown as a heavy grey line, while the grey shaded background represents the previous upper and lower range of natural gas in storage for any given time of year for the 5 years prior to the two years that are shown by today's graph…thus the grey area also shows us the normal variation of natural gas storage levels as they fluctuate from season to season, with natural gas in storage underground normally building to a maximum by the first weekend in November, falling through the winter, and usually bottoming out at the end of March, depending of course on the spring heating requirements in any given year...notice that the blue line shows that the quantity gas we had stored in the fall of 2016 was at a record high up through October, and then dropped to near normal going into 2017, despite a much milder than normal winter...also notice how our supplies of natural gas in blue started last winter fairly close to the 5 year average of natural gas in storage shown in dark grey, then diverged over the year, beginning with the colder than normal January, with the gap separating the grey "normal" line and the blue current supply line slowly getting increasingly wider, until it finally fell below the 5 year low, represented by the grey shaded area, in August...since then, the gap between our current supplies and the previous 5 year minimum has only gotten progressively wider, and that deficit from normal has continued to widen up through this week...
this November 23rd's 3,054 billion cubic feet of natural gas in storage was thus 11.0% lower than the previous 5 year low of 3,432 billion cubic feet that was set on November 21st of 2014 which is represented on the graph above; moreover, it was also 19.1% below the 3,776 billion cubic feet that were in storage on November 22nd of 2013, before the 2014 winter that set the previous low supply records seen on that chart...compared to other late November low gas storage readings in this century, November 23rd's storage level was 10.8% below the previous 10 year low of 3,288 billion cubic feet that was set on November 21st of 2008, 5.3% below the 3,225 billion cubic feet of natural gas we had in storage on November 25th of 2005, and 3.2% below the 3,154 billion cubic feet that were in storage on November 21st of 2003...we have to follow the archived records (xls) back 16 years, to November 22nd of 2002, when 3047 billion cubic feet of natural gas were in storage, to find a lower quantity of natural gas in storage after three weeks of November than we have now.....
The Latest US Oil Data from the EIA
this week's US oil data from the US Energy Information Administration, reporting on the week ending November 23rd, indicated another large increase in the amount of of oil used by refineries and a corresponding jump in our oil imports, while simultaneous higher oil exports meant there was an even smaller addition to our commercial crude supplies than the prior week, but the still 10th increase in a row and hence the longest string of oil inventory increases since autumn 2015...our imports of crude oil rose by an average of 608,000 barrels per day to an average of 8,162,000 barrels per day, after rising by an average of 102,000 barrels per day the prior week, while our exports of crude oil rose by an average of 473,000 barrels per day to an average of 2,442,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 5,720,000 barrels of per day during the week ending November 23rd, 135,000 more barrels per day than the net of our imports minus exports during the prior week...over the same period, field production of crude oil from US wells was reportedly unchanged at 11,700,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from wells totaled an average of 17,420,000 barrels per day during this reporting week...
meanwhile, US oil refineries were using 17,553,000 barrels of crude per day during the week ending November 23rd, 698,000 barrels per day more than the amount of oil they used during the prior week, while over the same period a net of 225,000 barrels of oil per day were reportedly being added to the total amount of oil that's in storage in the US....hence, this week's crude oil figures from the EIA would seem to indicate that our total working supply of oil from net imports and from oilfield production was 358,000 barrels per day short of what refineries reported they used during the week plus what oil was added to storage....to account for that disparity between the supply of oil and the consumption or new storage of it, the EIA inserted a (+358,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as "unaccounted for crude oil"...(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 7,677,000 barrels per day, now 0.8% more than the 7,619,000 barrel per day average that we were importing over the same four-week period last year....the net 225,000 barrel per day increase in our total crude inventories included a 511,000 barrel per day increase in our commercially available stocks of crude oil, which was partly offset by a 286,000 barrel per day decrease in the amount of oil in our Strategic Petroleum Reserve, likely part of a sale of 11 million barrels from those reserves to Exxon et al that closed two and a half months earlier....this week's crude oil production was reported as unchanged at 11,700,000 barrels because the rounded figure for output from wells in the lower 48 states was unchanged at 11,200,000 barrels per day, while a 5,000 barrel per day decrease to 498,000 barrels per day in oil output from Alaska was not enough to change the rounded national total...last year's US crude oil production for the week ending November 24th was at 9,682,000 barrels per day, so this week's rounded oil production figure was 20.8% above that of a year ago, and 38.8% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
US oil refineries were operating at 95.6% of their capacity in using 17,553,000 barrels of crude per day during the week ending November 23rd, up from 92.7% of capacity the prior week, and the highest refinery utilization rate for anytime in November since 1998....the 17,553,000 barrels per day of oil that were refined this week were at a seasonal high for the time of year for the 23rd time out of the past 26 weeks, and 3.2 higher than the 17,003,000 barrels of crude per day that were being processed during the week ending November 24th, 2017, when US refineries were operating at 92.6% of capacity...
with the big jump in the amount of oil being refined, the gasoline output from our refineries was a somewhat higher, increasing by 132,000 barrels per day to 10,168,000 barrels per day during the week ending November 23rd, after our refineries' gasoline output had decreased by 20,000 barrels per day during the week ending November 16th...but even with that increase in this week's gasoline output, our gasoline production during the week was still 3.8% lower than the 10,222,000 barrels of gasoline that were being produced daily during the same week last year....meanwhile, our refineries' production of distillate fuels (diesel fuel and heat oil) increased by 270,000 barrels per day to a seasonal record 5,471,000 barrels per day, after that output had increased by 208,000 barrels per day the prior week....with that increase, this week's distillates production was 3.5% higher than the 5,284,000 barrels of distillates per day that were being produced during the week ending November 24th 2017....
with our gasoline production little changed, our supply of gasoline in storage at the end of the week fell by 764,000 barrels to 224,551,000 barrels by November 23rd, the 6th decrease in the past 7 weeks, and shrinking our gasoline supplies by 11,621,000 barrels over that span....our gasoline supplies fell again as our exports of gasoline rose by 176,000 barrels per day to 1,061,000 barrels per day, while our imports of gasoline rose by 137,000 barrels per day to 384,000 barrels per day, and as the amount of gasoline supplied to US markets rose by 3,000 barrels per day to 9,188,000 barrels per day...while our gasoline inventories are no longer at a seasonal high, they are still 4.9% higher than last November 24th's level of 214,102,000 barrels, and roughly 6.6% above the 10 year average of our gasoline supplies for this time of the year...
with the big jump in our distillates production, our supplies of distillate fuels increased for the first time in ten weeks, rising by 2,610,000 barrels to 121,801,000 barrels during the week ending November 23rd, after our distillates supplies had fallen by 11,185,000 barrels over the prior four weeks...our distillates supplies increased even though our exports of distillates rose by 669,000 barrels per day to 1,715,000 barrels per day because the amount of distillates supplied to US markets, a proxy for our domestic demand, fell by 701,000 barrels per day to 3,569,000 barrels per day, while our imports of distillates rose by 82,000 barrels per day to 186,000 barrels per day...but even after this week's decrease, our distillate supplies still ended the week 4.7% below the 127,779,000 barrels that we had stored on November 24th, 2017, and roughly 7.6% below the 10 year average of distillates stocks for this time of the year...
finally, even with this week's big increase in oil refining, our commercial supplies of crude oil increased for the 10th week in a row and now for the 26th time in 2018, rising by 3,577,000 barrels during the week, from 446,908,000 barrels on November 16th to 450,485,000 barrels on November 23rd...that increase means that our crude oil inventories are now roughly 7% above the five-year average of crude oil supplies for this time of year, and roughly 29.3% above the 10 year average of crude oil stocks for the fourth weekend in November, with the disparity between those figures arising because it wasn't until early 2015 that our oil inventories first rose above 400 million barrels...however, since our crude oil inventories had been falling through most of the past year and a half until just recently, our oil supplies as of November 16th were still 0.7% below the 453,713,000 barrels of oil we had stored on November 24th of 2017, 7.7% below the 488,145,000 barrels of oil that we had in storage on November 25th of 2016, and 1.5% below the 457,212,000 barrels of oil we had in storage on November 27th of 2015..
This Week's Rig Count
Note: this week's rig count summary covers 9 days, from last week's report on November 21st (ie, the day before Thanksgiving) to Friday, November 30th....with that qualification, Baker Hughes reported that the total count of rotary rigs running in the US decreased by 3 rigs to 1076 rigs over the 9 days ending November 30th, which was still 147 more rigs than the 929 rigs that were in use as of the December 1st report of 2017, but down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC announced their attempt to flood the global oil market...
the count of rigs drilling for oil increased by 2 rigs to 887 rigs this week, which was also 138 more oil rigs than were running a year ago, while it remained well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the number of drilling rigs targeting natural gas formations fell by 5 rigs to 189 natural gas rigs, which was still 9 more than the 180 natural gas rigs that were drilling a year ago, but way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008...
offshore drilling in the Gulf of Mexico decreased by 2 rigs to 23 rigs this week, which was still 3 more rigs than the 20 rigs active in the Gulf of Mexico a year ago...with no other offshore US drilling activity elsewhere either this week or a year ago, those Gulf of Mexico totals are again equal to the national offshore rig count totals....
the count of active horizontal drilling rigs increased by 5 rigs to 929 horizontal rigs this week, which was also 142 more horizontal rigs than the 792 horizontal rigs that were in use in the US on December 1st of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the directional rig count decreased by 5 rigs to 68 directional rigs this week, which was also down from the 71 directional rigs that were in use during the same week of last year....in addition, the vertical rig count decreased by 3 rigs to 74 vertical rigs this week, which was still up from the 66 vertical rigs that were operating on December 1st of 2017...
the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of November 30th, the second column shows the change in the number of working rigs between last week's count (November 21st) and this week's (November 30th) count, the third column shows last week's November 21st active rig count, the 4th column shows the change between the number of rigs running on Friday and those running on the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 1st of December, 2017...
obviously, the basin table above doesn't show us either how we had an increase of 5 horizontal rigs, nor how we had the net decrease of three rigs...Louisiana totals, however, offer a clue, as the state saw 3 rigs idled in the southern part of the state, and one rig shut down offshore, none of which were likely to have been horizontal...in addition, at least one of the rigs added in Wyoming was not in a major basin, since rigs in the DJ Niobrara chalk of the Rockies front range were unchanged...on the other hand, none of the Permian Texas oil districts showed any change, so for once the goose-egg in the Permian rig count accurately reflects that there was no change there...meanwhile, the natural gas rig count fell by 5 despite the addition of one natural gas rig in the Haynesville because 2 natural gas rigs were shut down in West Virginia's Marcellus, and 4 natural gas rigs were shut down in "other basins" not named separately by Baker Hughes; it would be a good bet that some or all of those were in Louisiana....we should also note that other than in the major producing states listed above, Alabama also has their only operational rotary rig shut down this week, the first time since April that there was no activity in Alabama...on the other hand, a land based rig began drilling in Florida this week, beginning the third period of drilling Florida has seen this year; in 2017, there was no drilling in Florida save for two weeks in May..
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Ohio May Expand Emissions Rules for Unconventional Oil, Natural Gas Ops - The Ohio Environmental Protection Agency (OEPA) is seeking input on potential rules that would expand air emissions rules for both existing and new unconventional oil and gas facilities that aren’t already covered by general permits for midstream and upstream equipment.The early outreach efforts kick-off a rulemaking process that could potentially lead to new regulations that are similar to those in effect for the industry under the U.S. Environmental Protection Agency’s New Source Performance Standards (NSPS). But unlike the NSPS, which cover only new or modified facilities, Ohio’s latest potential rules would extend to all unconventional oil and gas facilities.OEPA said it envisions new regulations covering equipment installed at well sites, including dehydrators, heaters and storage tanks. Equipment installed at midstream compressor stations and other equipment involved in processing natural gas once it leaves a well could also be covered.Early outreach, OEPA said, gives stakeholders an opportunity to provide comments and suggestions before the agency drafts the language of the rules. After it receives the input, the agency said it would begin drafting the proposed rule language and launch a formal comment period.OEPA said it would accept early input until Dec. 19. More information about the process can be found on OEPA’s website.If the agency proceeds with the rulemaking, it would be the latest in a series of regulatory overhauls since the first commercial production was reported from unconventional Utica Shale wells in 2011. Since then, OEPA has drafted and rolled-out general permits for the upstream andmidstream sectors to streamline the permitting process and reinforce the industry’s compliance with state pollution regulations. It’s also implemented requirements in recent years targeting fugitive emissions at well sites.
Weakening methane standards will hurt SE Ohioans - Our region is at the epicenter of the Utica Shale deposit and the booming oil-and-gas development that has accompanied the extraction of those resources. Compared to the rules already in place, these new rules proposed by the Trump administration do not go far enough in curbing harmful methane pollution, or in reducing how much of this harmful greenhouse gas is released into the atmosphere. These limits on methane emissions are not just theoretical numbers on paper – they offer real-life protections for my family and yours.Methane poses a great danger to our planet. With over 80 times the warming power of carbon pollution, methane is a dangerous driver of climate change. Right now, oil-and-gas industrial facilities release at least 8.1 million metric tons of methane pollution a year – the same climate impact as operating over 150 coal-fired power plants for a year or driving more than 145 million cars for a year.Throughout history, my home region has seen resources extracted, again and again, yet we never see the benefits. While corporations get richer, our communities have been left with the legacy costs of that extraction. Desolate landscapes, stagnant economies, generations of sick children – we have paid more than our fair share to power this country.First they came for timber, then coal, and now natural gas. Through all of this, we have had little protection from state and national agencies against these companies that can come in and buy towns outright. While we may be rural, we are worthy of protections, which are paramount for our future. My hometown of Cheshire is located within a stone’s throw of West Virginia, and Ohio’s Appalachian region flows directly into Pennsylvania and Kentucky. This is a region rich in natural resources, and because of its wealth in minerals, for decades it has borne the brunt of mining, drilling and extraction. Because pollution does not stop at state lines, the health of people of the central Appalachian region has suffered as a result, and we’re also beginning to see the impacts of a changing climate. For southeast Ohio, our climate impacts are not seen in wildfires or rising sea levels. Rather, we experience climate change in the form of more voracious tick populations and therefore higher tick-borne illnesses, more extreme and more frequent rain events, and therefore more flooding and infrastructure damage.
Marksmen Energy drilling in Ohio's Clinton Sandstone -- Calgary-based Marksmen Energy reports it's making progress in drilling a Clinton Sandstone well in southeast Ohio, Kallanish Energy reports. The company has a 60% interest in the Leaman #1 horizontal well in Hocking County. The well is operated by Hocking Hills Energy and Well Services LLC of Ohio. Completion of milling and drilling the 1,500-foot lateral is expected to begin this week. The lateral drilling is expected to take 10 to 15 days. The sandstone was previously stimulated with a 12-stage hydraulic fracturing or fracking process. Marksmen said it has interests in 5,500 acres of additional land with several potential Clinton Sandstone wells locations that could be developed under its agreement with its operator. The company has said it's planning “an aggressive drilling program in 2019 to fully develop the acreage,” subject to financing. Marksmen has targeted the Clinton Sandstone previously drilled in many parts of Ohio. The company points out that Texas-based EnerVest Ltd. had drilled eight Clinton Sandstone wells about 100 miles north of its Hocking County well. EnerVest, it said, is evaluating plans to drill multiple horizontal wells on its 115,000 gross acres of leases in Ohio’s East Canton oilfield in Stark County. It spills into surrounding counties. EnerVest operates roughly 1,600 vertical-only Clinton Sandstone wells in that area, some dating back to the late 1940s. The oil recovery from those wells has been estimated at 7% by EnerVest, Marksmen said. EnerVest reports a nearly 10-fold increase in Clinton Sandstone production by using horizontal wells, and it reported its horizontal wells encountered near virgin reservoir pressures within the field, the Canadian company reported. It also said U.S. Energy OH LLC is also drilling Clinton Sandstone wells in the East Canton field and has drilled and completed nine of 21 permitted locations.
Fears and Hopes on Cracker Expressed During OEPA Hearing in Shadyside — Dozens of local residents and environmental advocates turned out Tuesday to express their fear of the “plastic monster” Michelle Fetting believes PTT Global Chemical and Daelim will create if the companies construct an ethane cracker plant at Dilles Bottom. Many others, though, are eager to welcome another industry to the Ohio Valley, saying they believe good-paying jobs and a higher quality of life will come with it. Fetting, a representative of the Pittsburgh-based BreatheProject.org, described the monstrous impact she believes such a facility would have on the region. Her organization was formed in response to construction of a similar facility by Royal Dutch Shell at Monaca, Pennsylvania. She was one of 30 people who testified on the official record when the Ohio Environmental Protection Agency held a public hearing Tuesday evening at Shadyside High School.The hearing was regarding a draft air pollution permit-to-install for the proposed petrochemical complex in Belmont County. A cracker plant processes ethane to create ethylene, a key component of plastic. While describing the project and answering questions from the audience, OEPA’s Mike Hopkins, assistant chief of permitting for OEPA, talked extensively about the plant’s anticipated emissions. He said his agency has been monitoring air quality in Shadyside for two years and will continue to do so for many years after the cracker plant begins to operate, if the project becomes a reality.“The whole idea is to make sure we are protecting public health,” Hopkins said. He compared expected emission levels at the cracker plant to those of several other types of polluters. While the cracker might emit about 396 tons of volatile organic compounds per year, for example, a typical gas station or dry cleaner emits 10 tons annually, he said. Larger facilities, such as small factories, emit 50-100 tons per year, while an auto assembly plant or steel mill might emit 1,000 tons each year. He said the largest polluters in Ohio are usually coal-fired power plants, which can emit more than 50,000 tons of VOCs annually. But the fact that he classified the potential PTT plant as a “medium to slightly larger than medium-sized plant in terms of emissions” did not alleviate the concerns of many members of the audience.
Two US pipelines rack up violations, threaten industry growth (Reuters) - Energy Transfer LP and its Sunoco pipeline subsidiary have racked up more than 800 state and federal permit violations while racing to build two of the nation’s largest natural gas pipelines, according to a Reuters analysis of government data and regulatory records. The pipelines, known as Energy Transfer Rover and Sunoco Mariner East 2, will carry natural gas and gas liquids from Pennsylvania, Ohio and West Virginia, an area that now accounts for more than a third of U.S. gas production. Reuters analyzed four comparable pipeline projects and found they averaged 19 violations each during construction. The Rover and Mariner violations included spills of drilling fluid, a clay-and-water mixture that lubricates equipment for drilling under rivers and highways; sinkholes in backyards; and improper disposal of hazardous waste and other trash. Fines topped $15 million. Energy Transfer also raised the ire of federal regulators by tearing down a historic house along Rover’s route. The Appalachia region has become a hub for natural gas as it increasingly replaces coal for U.S. power generation, creating an urgent need for new pipelines. But the recent experience of residents and regulators with the two Energy Transfer pipelines has state officials vowing to tighten laws and scrutinize future projects. “Ohio’s negative experience with Rover has fundamentally changed how we will permit pipeline projects,” said James Lee, a spokesman for the Ohio Environmental Protection Agency.
Energy Transfer's Troubled Pipeline Projects Amass 800+ Violations --A damning new report has highlighted the spotty incident record of Energy Transfer, which owns tens of thousands of miles of pipelines across America, including the controversial Dakota Access Pipeline.The Texas-based energy company and its subsidiary Sunoco have amassed more than 800 federal and state permit violations and millions of dollars in fines while building its two newest natural gas pipelines, the Roverand Mariner East 2, respectively, Reuters reporters Scott DiSavino and Stephanie Kelly revealed Wednesday. To compare, Reuters analyzed four similar pipeline projects and found they averaged 19 violations each during construction.Rover and Mariner violations include spills of drilling fluid; sinkholes in backyards; and improper disposal of hazardous waste and other trash, with fines topping at $15 million, according to Reuters.Rover started construction in March 2017, while Mariner started in February 2017. The two troubled pipelines were slated for completion last year, but construction has slowed due to state and federal regulators halting the work after permit violations.The $4.2 billion Rover pipeline is a 713-mile interstate project designed to transport up to 3.25 billion cubic feet per day of fracked gas. Its proposed route includes Pennsylvania, West Virginia, Ohio, Michigan and Canada. In one of its most high-profile spills, the pipeline project released 2 million gallons of drilling fluids into Ohio wetlands last April. It followed with another 150,000 gallons of drilling fluid at the same site in January."Ohio's negative experience with Rover has fundamentally changed how we will permit pipeline projects," James Lee, a spokesman for the Ohio Environmental Protection Agency, told Reuters.The $2.5 billion Mariner East 2 is a 350-mile pipeline project designed to carry 275,000 barrels a day of butane, propane and other liquid fossil fuels from Ohio and West Virginia, across Pennsylvania to the Atlantic coast. Last year, horizontal directional drilling triggered three releases of drilling fluid around the same site in East Goshen, Pennsylvania in the span of three days. In September, a 24-inch natural gas line owned by Energy Transfer and Sunoco exploded in Beaver County, Pennsylvania a week after it was activated. The explosion prompted calls from environmentalists and lawmakers to halt the Mariner pipeline, which is currently under construction in the state.
Utica Shale provides stacked drilling options in Pennsylvania - Everyone thinks of Ohio when it comes to the Utica shale in the Appalachian Basin, but the gas-rich formation spills over into western Pennsylvania and West Virginia. Operators in Pennsylvania are starting to drill the Utica, as it creates new stacked options in northern Pennsylvania, as well as in southwest Pennsylvania, Penn State University’s Thomas Murphy told attendees at Kallanish New Horizons: Appalachian Basin. Pennsylvania has about 250 Utica wells and West Virginia has about 50 Utica wells, compared to roughly 2,080 producing Utica wells in Ohio. In southwest Pennsylvania, drillers have been reluctant to pursue the Utica because it is deeper than the lucrative Marcellus Shale. That makes it more costly and riskier for drillers to go after, Murphy said. It appears the Utica Shale play in northcentral Pennsylvania is thicker and shallower and those particulars have some operators like Eclipse Resources and JKLM Energy interested in it, he said. Shell drilled the first Utica wells in that region in Tioga County, Murphy noted. “It’s more of a stacked resource than people thought … and that makes it increasingly attractive and gives companies long-term options,” said Murphy, director of the Penn State Marcellus Center for Outreach and Research. Pennsylvania drillers can opt to go after the Utica, Marcellus and perhaps the Upper Devonian shales from the same pads, he said. The Marcellus remains “the king pin,” and Pennsylvania is No. 2 in the U.S. for natural gas production (behind Texas) with 15 billion cubic feet per day (Bcf/d) of Marcellus production, he said. Ohio is fifth with 5 billion cubic feet per day of Utica gas production that is still growing. It ranks behind Oklahoma and Louisiana. He estimated just 15% to 20% of the total number of wells that could be drilled have been drilled in the Appalachian Basin.
Allegheny Township property owners taking fracking fight to Pa. Supreme Court --Allegheny Township property owners are asking the Pennsylvania Supreme Court to appeal a ruling that allows unconventional gas drilling in all of the township’s zoning districts. The plaintiffs are asking the Supreme Court to review a Commonwealth Court ruling that they believe infringed on their “fundamental and constitutionally-protected property and environmental rights.” The appeal was filed Nov. 26 by the plaintiffs and Willowbrook Road residents Dolores Frederick, Patricia Hagaman and Beverly Taylor. The defendants include Allegheny Township, its zoning hearing board, CNX Gas Co. and other township residents. They have been challenging a series of court rulings stemming from CNX Gas Co. in October 2014 winning approval to install an unconventional natural gas well pad, which is used in fracking, within 1,200 feet of township homes. The gas well pad site is on the property of a neighboring farm owned by John and Anne Slike and Northmoreland Farms LP, who are among the defendants in the case. Specifically, the plaintiffs take issue with Allegheny Township’s enactment in 2010 of a zoning ordinance amendment providing for oil and gas drilling operations in all of the township’s zoning districts. They have argued that the intensive hydraulic fracturing process — fracking — and horizontal drilling used to tap deep gas reserves constitute an industrial use. Last month, the Commonwealth Court ruled 5-2 to deny an appeal by Allegheny Township property owners who tried to overturn multiple rulings that allow unconventional gas drilling in all of the township’s zoning districts. Although the state Supreme Court is asked to consider a number of cases, the plaintiffs’ attorney Christopher Papa, of New Castle, felt that the court would take the case. Papa said that the implications from the Allegheny Township case could be far-reaching because it covers residential property rights and zoning. “When you buy residential, you are not buying industrial and that is what this is about,” he said. If the Commonwealth Court ruling is allowed to stand, Papa said it would completely undercut traditional zoning. “The whole purpose of which is to segregate industry from residents,” he said.
Plaintiffs alleging EQT shortchanged on gas royalties reach tentative settlement - The trial of a major lawsuit alleging that energy giant EQT Corp. has been shortchanging thousands of West Virginians on their royalty payments won’t start Tuesday as planned, following the tentative settlement of the case late last week. Details of the deal have not yet been made public. Marvin Masters, lead lawyer for the plaintiffs, said “the parties have tentatively resolved the case,” pending settlement details being worked out. A spokeswoman for the court confirmed the settlement, and said the trial was canceled. Linda Robertson, spokeswoman for EQT, declined to comment on the settlement, citing “pending litigation.” More than 10,000 individuals and businesses in West Virginia are estimated to be members of the class of plaintiffs. They allege that EQT, the state’s second-largest gas producer, was illegally deducting various costs — such as for transporting and processing gas — from their royalty payments. Under federal court rules, details of class-action settlements are subject to review by members of the plaintiff class. Such settlements must also be reviewed by U.S. District Judge John Preston Bailey and determined to be “fair, reasonable and adequate.” The lawsuit against EQT was among the royalty cases highlighted earlier this month in a joint examination by the Charleston Gazette-Mail and ProPublica of the ways West Virginia natural gas producers whittle away at royalties promised to thousands of state residents and businesses. Companies have both deducted various costs from royalty payments, despite lease language that doesn’t allow them to do so, and formed shell companies that buy the gas at reduced rates, lowering percentage-based royalties. These practices have gone on for decades, despite efforts by state lawmakers and courts to ensure that residents get their fair share. Several lawsuits in the mid-2000s led to a series of settlements and a $400 million jury verdict in 2007. Those earlier settlements included a roughly $30 million deal by Equitable, as EQT was then known, with about 10,000 class members who had leases with the company.
Pipeline Company to Pay $122K for Environmental Violations - A company building a natural gas pipeline in West Virginia has agreed to pay $122,350 for environmental violations.The Charleston Gazette-Mail cited a consent order made public Monday in reporting that Columbia Gas Transmission agreed to pay the amount to the West Virginia Department of Environmental Protection for 16 violations while building the Mountaineer Xpress Pipeline.Columbia Gas Transmission is a subsidiary of TransCanada and will operate the Mountaineer Xpress Pipeline when it's completed.TransCanada spokesman Scott Castleman said the company implemented measures to address each environmental issue as it arose and has accepted the draft consent order.The pipeline is one of many being built in the region and would run 170 miles (274 kilometers) from Marshall County to Wayne County.
4th circuit opinion explains reasoning behind vacating pipeline permit in Oct. -- When the West Virginia Department of Environmental Protection waived its authority required for the Mountain Valley Pipeline, it made the project ineligible for a water-crossing permit from the Army Corps of Engineers, a panel of judges wrote in an opinion Tuesday.The opinion from the judges on the 4th Circuit Court of Appeals comes after the panel vacated the key Clean Water Act permit for the pipeline in October, saying regulators lacked legal authority to “substitute” one kind of construction standard for another.That order came four days after the panel heard oral arguments in the case brought by a coalition of environmental and citizen groups that challenged the federal government’s approval of the 300-mile long pipeline.The pipeline would run from Wetzel County, West Virginia, into Virginia.Questions about the permit began in early 2017, when West Virginia issued a 401 certification, needed for the streamlined permit, but then opted to waive the certification in November when the permit was challenged by environmental and citizen groups.“We further conclude that, absent completion of the notice-and-comment procedures required by the Clean Water Act, a state cannot waive a special condition previously imposed as part of its certification of a nationwide permit,” Judge James Wynn wrote in the 35-page opinion. Chief Judge Roger Gregory and Judge Stephanie Thacker joined. “Because West Virginia did not follow its federally mandated notice-and-comment procedures in waiving another special condition the state imposed as part of its certification of NWP 12, that condition remains a required — but, in this case, unsatisfied — condition of the nationwide permit,” he wrote.
Member of Appalachians Against Pipeline Group uses body to physically stop pipeline construction (WVNSTV video) For more than eight hours, a member of the Appalachians Against Pipelines group locked his body to a boom tractor, suspended in the air, to block construction at a Mountain Valley Pipeline site off Ellison Ridge Rd. on Tuesday, November 27.
Eminent Domain for Natural Gas Pipelines at Issue in NY State - A state appellate court ruled Friday that National Fuel Gas Corp. could not use eminent domain proceedings to cross a Clarksville couple’s property for the Northern Access Pipeline from McKean County, Pa. to Western New York. The Appellate Division, Fourth Judicial Department overturned an earlier State Supreme Court ruling granting eminent domain powers to National Fuel Gas in order to cross the 200-acre parcel owned by Joseph and Theresa Schueckler. The property lay in the path of the proposed 97-mile $455 million Northern Access pipeline. While National Fuel officials are still hopeful about the project’s future, the Schueckler’s attorney Gary Abraham thinks differently. “The pipeline is dead,” he said. Dozens of streams and creeks are also in the pipeline’s path, which require DEC permission to cross. The DEC asked National Fuel Gas to use horizontal drilling to minimize stream disruptions. The company said it was unnecessary in most streams. The 12-page ruling acknowledges the state Department of Environmental Conservation (DEC) denied a Water Quality Certificate under the federal Clean Water Act, which National Fuel Gas has challenged in the Second Circuit U.S. Federal Court in New York City. National Fuel Gas claimed DEC took longer than the one year allowed to review the company’s application for a Water Quality Certificate. The DEC said both parties had agreed to extend the deadline. Last year, the Federal Energy Regulatory Commission (FERC), which controls interstate transmission of natural gas, agreed with a National Fuel Gas request to approve the project with conditions. One of the conditions is that National Fuel Gas obtain a Water Quality Certificate from DEC. National Fuel Gas sued FERC in Federal Court in the District of Columbia to remove the conditions. The ruling states that “It is indisputable, however, that if the Water Quality Certificate denial is ultimately upheld, the pipeline cannot be built.”
Thousands remain homeless after Columbia Gas disaster in Massachusetts --Some 5,000 people are still unable to return to their homes and are having to survive in hotel rooms and trailers set up in city parks more than two months after the September 13 Columbia Gas explosions in Massachusetts’ Merrimack Valley. An early-season snow storm on November 15 caused pipes in the trailers to freeze, revealing that the drainage pipes carrying dirty “grey water” from sinks and showers mix with the pipes supposedly bringing clean water into the trailers. On Thanksgiving, thousands of people received nothing but boxed dinners, while outdoor temperatures dropped below 15 Fahrenheit (-9 Celsius).On Monday morning, Democratic US Senator Edward Markey hosted a hearing at a middle school in South Lawrence. Senator Elizabeth Warren, whom Markey called his “partner,” New Hampshire Senator Maggie Hassan, US Representatives Nikki Tsongas and Seth Moulton, and Representative-elect Lori Trahan, joined Markey in questioning a panel of state and federal regulators as well as Columbia Gas executives. The word “tragedy” was thrown around the auditorium by politicians and panel members in an attempt to deny what the September 13 events obviously were: a social crime. Markey and Warren’s pretense of holding the executives, Columbia Gas of Massachusetts president Steve Bryant and Joe Hamrock, the president of parent company NiSource, accountable was limited to calling for their resignations and to extracting a vague promise that victims will be “made whole” financially. Bryant refused to resign, knowing full well the toothless nature of the hearing, while both he and Hamrock said that they might forego their bonuses this year.
Michigan Senate to consider straits oil pipeline legislation (AP)— Legislation moving in Michigan's Senate would authorize the Mackinac Bridge Authority to help implement a deal to replace twin oil pipelines in a crucial Great Lakes channel.The Republican-led Senate Government Operations Committee passed the bill 3-2 on party lines Wednesday, but the full Senate delayed voting so changes can be made.Gov. Rick Snyder's administration says the bridge authority is the logical choice to oversee a proposed pipeline tunnel in the Straits of Mackinac. Opponents of the agreement say the authority's mission should not be altered so significantly. In October, the Snyder administration and Canadian pipeline giant Enbridge announced a deal to replace the 65-year-old oil pipes that critics describe as an environmental disaster waiting to happen. Snyder hopes to lock in the hotly contested deal before leaving office.
Eminent domain trial on Bayou Bridge pipeline begins with assertion that land worth only $1.11 — A testy trial over the Bayou Bridge pipeline began Tuesday with an assertion that the plaintiff's share of the land at the center of the dispute is worth only $1.11. The 162-mile Bayou Bridge will carry crude oil between Lake Charles and St. James, but to do so, it is designed to go through a contentious plot of property. The undeveloped Buffalo Cove swampland has been subdivided and passed down so many times it now has perhaps 700 heirs, attorneys have said. Most, but not all, appear to have agreed to let the company have its right-of-way. However, Theda Larson-Wright and siblings Peter and Katherine Aaslestad don’t want the pipeline and told the company if they want it, they’d have to seize it under eminent domain. Under Louisiana law, utility providers have the authority to legally expropriate property if they can prove it is for the public benefit. Industrialists and environmentalists sparred over the pipeline's merits and will continue to do so Wednesday in state district court in St. Martin Parish. On Tuesday, Bayou Bridge lawyers tried to show Judge Keith Comeaux that the plaintiffs are just three voices among hundreds. The company hired expert witness David Dominy to formally appraise the land. After a lengthy explanation, he revealed that while the 38-acre property is worth $871 an acre, Larson-Wright only owns 0.00994 percent, and the Aaslestads combine for 0.0003125 percent, meaning if the whole property were to sell at its appraised value, their share wouldn’t even buy a soda at a vending machine.
Trump poised to allow Atlantic Coast seismic testing for subsea oil and gas - The Trump administration is set to allow companies to conduct seismic tests for oil-and-gas resources in the Atlantic Ocean — a process that uses powerful air-gun blasts that could harm whales, dolphins and other marine life. The surveys will help gauge the size of hydrocarbon resources off coastal areas that are now off-limits to drilling, but would become available under draft federal offshore leasing plans. However, environmental groups say the tests could harm or even lead to the death of sensitive ocean mammals. The Obama administration had thwarted similar industry requests. The National Oceanic and Atmospheric Administration (NOAA) on Friday announced approvals for five companies to "incidentally harass" marine mammals in a region that spans from Delaware to Cape Canaveral, Florida. They still need separate Interior Department permits to undertake the testing. But Friday's move likely signals plans by the administration — which supports expanding regions made available for fossil fuel development — to let the tests proceed. Multiple environmental groups bashed the move Friday. "President Trump is essentially giving these companies permission to harass, harm and possibly even kill marine life, including the critically endangered North Atlantic right whale — all in the pursuit of dirty and dangerous offshore oil." NOAA officials, in their approval and comments to reporters, said the "incidental harassment authorizations" contain a suite of provisions aimed at protecting marine life. One example is a requirement that activities cease if a North Atlantic right whale is spotted within 1.5 kilometers of the testing. These whales are listed under the Endangered Species Act, and NOAA estimates there are only about 430 of them left in the wild. They transit areas off the East Coast, where the seismic blasting is set to take place. Studies have shown that military sonar and other loud underwater noises can disrupt marine mammals' feeding and other behavior, possibly leading to mass strandings. While the seismic testing is likely moving ahead, oil and gas drilling and production is not allowed off the Atlantic Coast. However, there's industry interest in sizing up the amount of hydrocarbons in the region. In January, the Interior Department issued a draft plan than envisions leasing offshore drilling blocs off the Atlantic Coast beginning in 2020.
New projects expected to reverse Gulf of Mexico natural gas production declines - Natural gas production in the U.S. Federal Gulf of Mexico (GOM) has been declining for nearly two decades. However, 10 new natural gas production fields are expected to start producing natural gas in 2018 and another 8 are expected to start producing in 2019, according to information reported to the U.S. Department of Interior’s Bureau of Safety and Environmental Enforcement. These new field starts may slow or reverse the long-term decline in GOM production. The 16 projects starting in 2018 and 2019 have a combined natural gas resource estimate of about 836 billion cubic feet.Marketed natural gas production in the Gulf of Mexico averaged 2.6 billion cubic feet per day (Bcf/d) through August 2018, accounting for 4% of total U.S. production. In 1997, when EIA began collecting GOM production data, production averaged 14.3 Bcf/d, accounting for 26% of the United States’ total annual marketed natural gas production. The decline in GOM natural gas production occurred as the number of producing natural gas wells in the GOM declined, falling from 3,271 in 2001 to 875 in 2017. The technology and expertise required to produce oil and natural gas from the seabed is expensive and specialized, and costs of production platforms can often exceed one billion dollars. With the growth in exploration and production activities in shale gas and tight oil formations, onshore drilling became more economic relative to offshore drilling. Most of the natural gas produced in the GOM is associated-dissolved natural gas produced from oil fields. Although older oil wells in the GOM tend to have higher natural gas content, newer wells are more oil-rich, resulting in less natural gas per well. According EIA’s Natural Gas Annual, 59% of gross withdrawals of natural gas in the GOM were from oil wells in 2017, up from 13% in 1997.
Cost Inflation Threatens Deepwater Recovery - Cost inflation could threaten the deepwater industry by raising break-even costs, according to a new report from Wood Mackenzie (WoodMac). The report notes that the cost to develop new deepwater barrels has fallen over 50 percent since 2013 and highlights steps operators have taken to lower their costs. But it also warns of the cyclical nature of inflation. “One of the key drivers in cost reduction in deepwater projects is lower rig costs, which is a cyclical factor,” research director Angus Rodger, said in a release. “But more importantly, there have also been big structural changes, such as the faster drilling of wells. For example, in the U.S. Gulf of Mexico it now takes half the time to drill a deepwater well compared to 2014.” WoodMac expects annual CAPEX for deepwater to reach nearly $60 billion by 2022, driven by large projects in Guyana, Brazil and Mozambique. However, that increase could be offset by offshore cost inflation, including rig day rates that could double by the early 2020s. “The return of cyclical inflation could see this epic period of deepwater cost reduction come to a close,” Rodger said. “The question now is how much of the ‘structural’ cost savings we have seen through the downturn will prove sustainable through the investment cycle, and which are just short-term company adaptions.” Rodger went on to say that many of the cost savings aren’t as “sticky” as the industry would have you believe. We’re “skeptical that many will stand the test of time during a sustained cyclical uptick,” he said.
High gasoline inventories help drive U.S. refining margins to five-year lows - Flattening year-over-year growth in gasoline demand in the United States, combined with high levels of refinery output, have contributed to low or negative motor gasoline refining margins for refiners along the East and Gulf Coasts. Gasoline refining margins—the difference between the spot price of gasoline and the Brent crude oil spot price—have been on a downward trend since August, and these margins have been at some of their lowest October and November levels in the past five years. At the same time, strong growth in distillate demand has driven increased distillate prices and refining margins. This combination of low gasoline and high distillate refining margins may signal a shift by refiners to maximize diesel fuel production instead of gasoline production. The crack spreads in the Amsterdam-Rotterdam-Antwerp (ARA) region of Europe and in Singapore, two global refining and distribution hubs, suggest markets in these regions are experiencing similar trends. Crude oil processed through a U.S. refinery typically yields about twice as much motor gasoline as distillate fuels. As a result, although gasoline margins have been low recently, refiners cannot completely stop making gasoline in favor of other petroleum products, such as distillate. High refinery runs (driven by increased distillate demand) combined with lower demand for gasoline contributes to the high gasoline inventory levels, which have been higher than their recent five-year range since mid-August. Higher gasoline prices in 2018 have contributed to flattening U.S. gasoline demand growth. Combined with increased levels of refinery output driven by strong demand for diesel fuel, gasoline production has outpaced demand, and inventories have increased beyond their normal seasonal levels, lowering gasoline prices and, as a result, gasoline margins. Motor gasoline margins based on wholesale gasoline prices at New York Harbor averaged 26 cents per gallon (gal) in the first half of 2018, but these margins fell to an average of 4 cents/gal in October 2018 and have been negative so far in November. Changes in margins in the Gulf Coast were similar, falling from 27 cents/gal in the first half of the year to 1 cent/gal in October and falling further to negative values during November. By comparison, New York Harbor ultra-low sulfur diesel margins averaged 38 cents/gal in the first half of 2018 and increased to 40 cents/gal in October and to more than 50 cents/gal in November.
Race to Export US Shale Gets Fierce, Gulf Coast Terminals Want In -- The race to export U.S. shale oil overseas is about to get fierce, with at least nine proposed terminals angling for a piece of a very limited pie. Within 18 months, new pipelines opening in the nation’s most prolific shale basin promise to carry an added 2 million barrels of oil a day to the Gulf Coast. But the extra crude will arrive at a time when existing terminals in the Corpus Christi area can already offer only about 300,000 barrels a day of unused capacity. Meanwhile, some of the terminals proposed are being designed to load a supertanker every other day, each capable of carrying 2 million barrels. The result: It’s likely only one or two new terminals are needed, with the edge going to companies such as Enbridge Inc., whose Freeport, Texas, effort could be fed by two pipelines it already owns interests in. . U.S. oil exports have soared to nearly 2 million barrels a day since a near four-decade moratorium was lifted in late 2015, just as shale production kicked into high gear. Trafigura Group Ltd. and other trading houses have jumped at the opportunity to send those supplies to Europe and Asia. But there’s been a problem: Pipeline shortages, particularly in the prolific Permian Basin, have limited how much oil makes it to the coast. Now, anticipating an end to those woes with three major new pipelines expected to open in 2019, several companies -- including Trafigura -- are lining up with plans to provide terminals that can take advantage of the change. Enbridge hasn’t released many details on its proposal for Freeport, which is about 175 miles northeast of Corpus Christi. But it would likely be fed by the company’s own Seaway pipeline system, which runs south from the U.S. storage hub in Cushing, Oklahoma, as well as the Gray Oak pipeline it owns a stake in. Once completed, that pipe will run southeast from Midland, Texas, in the heart of the Permian, into Freeport and Corpus Christi.
New report details oil and petrochemical opportunities as US becomes net exporter -Oil and chemical traders believe the U.S. will become a net exporter for the first time in generations, according to Petrochemical Update’s North American Downstream Market Outlook and Insights 2019. By the end of 2019, total U.S. oil production including natural gas liquids (NGLs) used in the petrochemical industry is expected to rise to 17.4 million barrels/day according to the U.S. Energy Information Administration (EIA).U.S. crude oil production and subsequently petrochemical production has increased significantly during the past ten years, driven mainly by production from tight oil formations using horizontal drilling and hydraulic fracturing. Total U.S. oil production is rising at the fastest pace in nearly 100 years and the pipeline bottleneck everyone warned about looks set to ease as early as the end of 2019. At this rate, many analysts are predicting that Texas will surpass Iraq and Iran and pave the way for the U.S. to become the world’s leader in oil production.Most recently, U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018, according to the U.S. EIA Petroleum Supply Monthly in November, up from 10.9 million b/d in July. This is the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil production exceeded the Russian Ministry of Energy’s estimated August production of 11.2 million b/d, making the U.S. the leading crude oil producer in the world.At that rate, oil and chemical traders believe the U.S. will become a net exporter, something that has not happened for 75 years. In the face of this almost unprecedented growth, the market is dealing with instability in oil prices, mega disruptions in technology, and a growing trade war. This confluence of market factors is driving new investments and a reconfiguration of the status quo.
Deep Water - A New Drill Down Report On Proposed Crude Export Terminals - This summer and fall, more than a half dozen companies and midstream joint ventures have announced plans for new deepwater export terminals along the Gulf Coast that — if all built — would have the capacity to load and send out more than 10 MMb/d, which is notable because the U.S. Lower 48 currently produces 11.2 MMb/d. Most of these projects won’t get built, of course — export volumes may well continue rising, and the economics of fully loading VLCCs at deepwater ports are compelling, but even the most optimistic forecasts suggest that only one or two of these new terminals will be needed through the early 2020s. So, there’s a fierce competition on among developers to advance their VLCC-ready export projects to Final Investment Decisions (FIDs) first. Today, we discuss highlights from our new Drill Down Report on deepwater crude export terminals as well as the export growth and tanker-loading economics that are driving the project-development frenzy.
Cheniere ramps up feedgas deliveries to LNG export terminal in Texas - — Cheniere Energy appears to be getting closer to having enough LNG produced at its export terminal near Corpus Christi, Texas, to ship a full cargo - the first from the site since startup November 14. The company has said the first export would occur soon, but has not been more specific, and a tanker that had been waiting at the terminal for about 10 days left over the Thanksgiving holiday - still unladen based on vessel tracking data. It diverted to Cheniere's Sabine Pass export terminal in Louisiana, where it loaded a cargo and departed again. Despite the uncertainty on timing, activity has clearly picked up at the Texas terminal. Feedgas deliveries to the 700 MMcf/d capacity Train 1 ramped up to an average of around 300 MMcf/d since Friday, peaking at over 400 MMcf/d on Sunday, S&P Global Platts Analytics data shows. Flows dipped to approximately 250 MMcf/d on Monday. In anticipation of the increased LNG production at Corpus Christi, Cheniere asked Williams' Transcontinental Gas Pipe Line to start up early an expansion project that will boost the amount of feedgas available to serve the export terminal. Transco said in a filing with the Federal Energy Regulatory Commission on November 19 that it was requesting permission for partial in-service of the Gulf Connector Expansion Project by Tuesday, so that it would be able to provide the LNG terminal up to 290 MMcf/d of service on an interim basis along the full path of the project beginning December 1. Speed to market was Cheniere's goal in getting its Texas terminal up and running ahead of schedule, amid a flurry of existing and proposed terminal projects that are poised to make the US a much bigger player in the global supply of LNG. Cheniere has five liquefaction trains in operation at Sabine Pass in Cameron Parish. A final investment decision is expected by early 2019 on whether to build a sixth train there. At the facility near Corpus Christi, three trains are under construction. CEO Jack Fusco told reporters November 15 during an event at the site to mark the facility's startup that workers planned to take the loading of the first cargo slowly to make sure it was done safely.
Sky falls for Permian gas prices on cyber Monday. - Permian natural gas markets felt a cold shiver this week, but not a meteorologically induced one of the types running through other regional markets. Gas marketers braced as prices for Permian natural gas skidded toward a new threshold: zero! That’s not basis, but absolute price, a long-anticipated possibility that became reality on Monday. The cause is very likely driven, in our view, by continued associated gas production growth poured into a region that won’t see new greenfield pipeline capacity for at least 10 months. What happens next isn’t clear, but expect Permian gas market participants to be a little excitable or jittery over the next few months. Permian gas markets were sent for a spin on Monday, with prices at the key Waha benchmark averaging just $0.625/MMBtu (see Figure 1). This is the second lowest price we have in our dataset from our friends at Natural Gas Intelligence (NGI), which dates to 2007. That’s not all though, as that average is based on trading throughout a period spanning roughly three hours between 7 and 10 a.m. Central Time. Prices near the end of this period traded one penny below zero at Waha, according to the daily range posted by NGI. Some trades at other points on pipelines in the Permian also traded in negative territory yesterday. That’s right, someone was paid to buy gas in the Permian on Monday. While we’d like to tell you this was some sort of transient, one-off event that led to a day of dramatically low gas prices, that isn’t likely the truth of the matter. The Permian gas market is flooded with associated gas and won’t see significant new takeaway capacity until the start-up of Kinder Morgan’s Gulf Coast Express (GCX) pipeline in late 2019. The problem is here to stay, at least for a few months. Take a deep breath if you trade the Permian gas markets.
Natural Gas Prices Fall Below Zero In Texas - Surging U.S. oil production in the Permian basin has helped crash oil prices. But the Permian is also home to skyrocketing natural gas production, and output is growing so fast that drillers are trying to give it away for free. When they can’t, they just burn it off into the atmosphere.Unlike in the Marcellus shale, where natural gas is the main target, drilling in the Permian is focused entirely on crude oil. Natural gas is a nice bonus that comes along with the oil. But the drilling frenzy in West Texas and New Mexico has resulted in a glut of this associated natural gas. There is a pipeline bottleneck for crude oil, but there is also a shortage of pipeline space for natural gas.The glut has become so bad that next-day prices for gas at the Waha hub in the Permian have plunged to a record low, falling to as low as 25 cents per MMBtu. In some instances, producers have actually sold some gas at negative prices. That means that a company is paying someone else to take the gas off of their hands. On Tuesday, the lowest price recorded was -25 cents/MMBtu (to be clear, that is negative 25 cents), according to Natural Gas Intelligence (NGI). It was the second consecutive day that prices were in negative territory. “That’s right, someone was paid to buy gas in the Permian on Monday,” RBN Energy LLC analyst Jason Ferguson said, referring to NGI’s pricing data. “While we’d like to tell you this was some sort of transient, one-off event that led to a day of dramatically low gas prices, that isn’t likely the truth of the matter.Ferguson went on to add that there is little prospect of a recovery until next year. “The Permian gas market is flooded with associated gas and won’t see significant new takeaway capacity until the start-up of Kinder Morgan’s Gulf Coast Express pipeline in late 2019,” Ferguson said, according to NGI. “The problem is here to stay, at least for a few months. Take a deep breath if you trade the Permian gas markets.” The negative prices are down sharply from the average price this year at $2.16/MMBtu at the Waha hub.
Tensions rise as oil and gas flow to the Texas coastline - Center for Public Integrity - —To the east, the Gulf of Mexico stretches out, blue-green and sparkling. To the west and north, flounder and trout meander in a chain of bays. People flock here to fish. Others come to this beach town near Corpus Christi to kayak, parasail or admire the hundreds of bird species on the barrier island, which is deep into rebuilding efforts after Hurricane Harvey damaged or destroyed 85 percent of the buildings here last year. A perfect location, from a certain point of view, to put not one but two crude-oil export terminals for ships so big they’re called supertankers. Those proposals are part of a historic buildout of oil and gas infrastructure in the United States as it becomes a top exporter of both fuels. More than 80 plants, terminals and other projects are in the works or planned up and down the state’s Gulf Coast, from Port Arthur to Brownsville, according to a Center for Public Integrity and Texas Tribune review of corporate plans. Companies have been laying enough pipeline in Texas in the last several years to stretch from the Atlantic to the Pacific three times over, more than 8,000 miles in all. Oil and gas production in the U.S. has skyrocketed, particularly in the Permian Basin, most of which underlies West Texas. When Congress lifted decades-old federal restrictions on crude exports at the end of 2015, a move that came on the heels of rule changes throwing open the doors for exports of natural gas, it set off a mad dash. Companies want to get oil and gas from West Texas to the Gulf Coast and, from there, abroad. Much of the infrastructure is headed for just two regions: Houston — America’s oil capital — and Corpus Christi, where a port previously focused on oil imports is battling it out with Houston to be the country’s No. 1 location for moving crude to other nations. Each shipped out more than $7 billion in crude during the first nine months of the year, up from less than $1 billion two years earlier, according to U.S. Census Bureau figures. Terminals once used to bring oil in are pushing it the other direction. Oil and gas export growth means jobs paying good wages. But it also intensifies a tragic quandary bedeviling the Gulf. Heavy industry there pumps out greenhouse gases warming the climate, upping the risks of powerful storms that, in turn, endanger those same facilities and everything around them. Harvey, which dumped more rain than any other U.S. storm on record, damaged hundreds of thousands of homes in Texas last year, killed at least 68 people and, particularly around Houston, sparked industrial spills, air pollution and explosions.
US rig count drops by 25 to 1183 in week ended November 28 — The US rig count dropped by 25 on the week to 1,183 for the period ended November 28, posting small reductions in most of the eight large domestic oil and natural gas basins, but with the Permian Basin by far the biggest loser, S&P Global Platts Analytics said Thursday. The Permian, located in West Texas and southeast New Mexico, fell by 12 rigs to 482, reversing most of the gains during the last month, according to Platts weekly rig count released each Thursday. Last week's numbers came out Monday to accommodate the US Thanksgiving holiday. The rig count has spent most of the second half of 2018 dangling just below 1,200 and only reached that figure in mid-November for the first time since early 2015. The week-on-week decline, during a post-holiday week, is relatively high, but could be traceable to potential sluggishness during the Thanksgiving break coupled with limited Permian pipeline capacity. The Permian is the largest producing oil and gas basin in the US with an estimated 3.6 million b/d of oil and 12.1 Bcf/d of gas output. But pipeline and other takeaway capacity is limited and virtually matches production. Experts say substantial new capacity will start coming online in the third quarter of 2019, although some new takeaway is already ramping up. Most of the rig reductions in the past week -- 19 -- came from oil-oriented basins, while five rigs chasing gas dropped out of active drilling. The numbers may not precisely add up because some rigs cannot be identified as either gas or oil, and so are assigned other categories according to Platts methodology. Meanwhile, the Marcellus Shale, a large gas-oriented play mostly in Pennsylvania and neighboring states, lost three rigs to 53, while the Eagle Ford Shale of South Texas lost two to 93. Another four basins lost a rig each, including the SCOOP/STACK of Oklahoma (down to 107), Williston of North Dakota and Montana (down to 63), Haynesville Shale in northwest Louisiana and east Texas (down to 59), and Utica Shale largely in Ohio and Pennsylvania (down to 16). The sole basin that gained during the week was the Denver-Julesburg Basin of Colorado, up one to 32 rigs. In addition, both oil and gas prices were down during the week, Platts average weekly assessments showed. WTI fell to $51.17/b, down $4.29, and WTI Midland fell $4.65 to $44.46/b. Also, the average Henry Hub gas price was $4.33/MMBtu, down 24 cents, while the Dominion South price fell to $4.07/MMBtu, down 16 cents. Drilling permits also fell substantially -- by 162 from the prior week to 1,040. The biggest change was in the DJ, which was down 96 permits week on week to 181. Permian was next, down by 24 to 121, while the SCOOP/STACK was down 10 to 28. The Haynesville and Marcellus each lost 13 permits, to 13 and nine, respectively, while the Eagle Ford was down by four to 41. The Williston, however, was up six to 24, and the Utica was up one to eight.
Trump Push For 'Energy Dominance' Boosts Drilling On Public Land - Peter Wold, CEO of Wold Energy Partners, has been investing heavily in the Powder River Basin, buying leases on both private and public land in recent years, and he's not alone. The number of applications to begin drilling in the state has increased over 400 percent in the past five years, a spike driven in part by the Trump administration's push for 'energy dominance.' "Our phone's been ringing off the hook as far as people that want a joint venture with us," Wold says. The wide-open land here is now filling up with trucks that kick up dirt on new roads. "I would call it a pre-boom, absolutely," says Wold. "We ought to call it recognition of economic exploration for Wyoming." Analysts say a perfect storm is making the country's largest coal state more favorable for oil and gas. Higher oil prices are certainly one factor, says Carl Larry, who advises oil and gas companies with the financial consulting firm Refinitiv in Houston. So is better technology for hydraulic fracturing, which allows wells to extract a lot more oil and gas than they used to from the same land. Another reason is the vast expanse of cheap land in this state, much of it federally owned, and some of which is now being auctioned off for as little as $2 an acre. That's a fraction of some prices in Texas, Larry says, where more competition has driven up the cost of land. In Wyoming, "we're looking at places that aren't so crowded," he says. "It's untouched fields and that's what people are most interested in." The Trump administration has made much more of that cheap, public land available to oil and gas companies. The amount of land for lease has increased six times over since 2016. Federal agencies like the Bureau of Land Management (BLM) have also streamlined and shortened the leasing process. "I think that makes a big difference here, and you're making it easy. It's not like there's lot of red tape and documents and paperwork to sign,"
Public land drilling contributes a quarter of all greenhouse gas emissions in US: report -- Drilling on public lands contributes nearly a quarter of all greenhouse gas emissions in the U.S., according to a new Trump administration report. The first-of-its-kind U.S. Geological Survey (USGS) report, released late Friday, found that emissions from fossil fuels produced on federal lands and offshore areas represent an average of 24 percent of all national emissions of carbon, a major contributor to air pollution and climate change. Wyoming was the top contributor of greenhouse gas emissions. Federal lands within the state contributed 57 percent of the climate change contributing emissions across all states and offshore areas combined. The report was released on the same day as another Trump administration report that raised an alarm over U.S. efforts to stave off the effects of climate change, arguing that they are insufficient. Democrats were quick to criticize the timing of that report's release — the day after Thanksgiving — and said it highlighted a need to address emissions as soon as possible. The USGS report, requested in 2016 under President Obama, measured total greenhouse gas emissions from oil, gas and coal drilling and mining on public land between 2005 and 2014. It found that emissions for all three greenhouse gases dropped in 2014 compared to 2005 values, including a 6 percent drop in carbon emissions. Fluctuations in greenhouse gas emissions and fossil fuel production are closely tied, according to the study. Environmental groups point out that emissions are likely to be higher today due to the Trump administration’s more active and supportive approach to drilling on federal lands and offshore. In March, the Interior Department under Secretary Ryan Zinke held the largest sale of oil and gas leases on federal land in U.S. history. Some 77.3 million acres of offshore waters were auctioned for drilling, covering coastal waters in Texas, Louisiana, Mississippi, Alabama and Florida. Thirty-three companies bidded on plots off the coasts of those five states for a total of $124.8 million. The USGS report found that the forests and other terrain on public lands does help to counter carbon emissions, but only offsets the greenhouse gases released on federal land by 15 percent.
Resource-Rich New Mexico Has a $322 Million Methane Problem - New Mexico has a methane problem. Despite being the No. 9 natural gas producer in the U.S., the Land of Enchantment ranks first when it comes to wasting federal gas. Producers operating on federal lands in New Mexico have reported losing more than 86.6 billion cubic feet of gas between 2008 and 2017 through venting, flaring and leaks. That amounts to about $322 million of wasted product, according to a report released Tuesday by the Wilderness Society and Taxpayers for Common Sense. The problem is poised to grow with the Trump administration’s relaxation of federal rules governing methane, a potent greenhouse gas that warms the atmosphere 84 times more than carbon dioxide.In a bid to cut industry costs, the Environmental Protection Agency in September proposed dialing back Obama-era rules to curb methane leaks on private land -- despite internal concerns that doing so would trigger greater methane missions. Weeks later, the Interior Department rolled backsimilar methane curbs on federal lands. That leaves regulation up to the states. Colorado has the strictest curbs, while New Mexico has some of the laxest. Unlike other top producers, New Mexico doesn’t ban the venting of natural gas at the wellhead, nor does it impose emissions standards for producers. New Mexico also happens to be deeply attractive to oil and gas explorers. A September auction of drilling rights on federal land saw leases going for a record $95,001 an acre.
Oil and Water: Finding New Uses for Fracking Waste Water - Fracking requires a huge amount of water, a major concern in dry Western states that otherwise welcome the practice. But New Mexico thinks it can mitigate that problem by pushing oil companies to treat and recycle fracking waste water for use in agriculture — or even as drinking water.State officials, with the help of the U.S. Environmental Protection Agency, are still working out the details. If they move forward with the strategy, other arid states may follow New Mexico’s lead.“Oil and gas in New Mexico provide over a third of our general fund,” said Ken McQueen, who heads the New Mexico Department of Energy, Minerals and Natural Resources. “We have to be concerned we’re doing what’s necessary into the future to make sure this industry continues to be alive and vibrant.”In addition to keeping a vital industry going, McQueen thinks the reclaimed waste water could be a boon to New Mexico farmers and ranchers who need water for their crops and herds. Factories could use it, and it might help revive parched wildlife habitat, he said. And even though the waste water is filled with salt and other minerals, it might even be treated and used for drinking.In a typical month, the amount of waste water generated by the fracking process in New Mexico, the country’s third-largest producer of oil, would be enough to fill Elephant Butte, the state’s largest lake.“Our hope is that it has a significant impact,” McQueen said, eyeing figures that might total a billion barrels of water a year. “As we see the produced water volumes increase, it just makes sense that we explore other methods of disposal, particularly if those methods may have an upside or beneficial use to New Mexico.” But even in the nation’s fifth-driest state, where water is as precious as crude, environmentalists are skeptical of a strategy many state leaders view as a greener approach to dealing with waste water. Even after it is treated, they argue, the water can be tainted by harmful metals or chemicals used in fracking, creating long-term risks for people and the environment.
U.S. crude oil and natural gas proved reserves set new records in 2017 --High prices and continued development of shale and tight resources drove proved reserves of both U.S. crude oil and natural gas to new records in 2017, according to EIA’s recently released U.S. Crude Oil and Natural Gas Proved Reserves report. Proved reserves of U.S. crude oil increased 19.5% from the end of 2016, reaching 39.2 billion barrels and surpassing the previous peak level of 39.0 billion barrels set in 1970. Proved reserves of natural gas increased 36.1% from the end of 2016 to reach 464.3 trillion cubic feet (Tcf) in 2017, surpassing the previous record of 388.8 Tcf set in 2014.Proved reserves are those volumes of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Changes in proved reserves from year to year reflect new discoveries (in new fields, new reservoirs in old fields, or extensions of existing reservoirs), net revisions and other adjustments to previous reserve estimates, and reductions from annual production of each fuel.Higher fuel prices typically increase estimates as operators consider a broader portion of the resource base economically producible. In 2017, the annual average spot price for the benchmark West Texas Intermediate (WTI) crude oil increased 20% from the 2016 average price, exceeding $60 per barrel for the first time since June 2015 and helping to drive increases in reserves. Texas and New Mexico had the largest net increases in proved reserves of crude oil in 2017, adding 3.1 billion and 1.0 billion barrels of proved crude oil reserves, respectively. Increases in these states were primarily the result of increased crude oil prices and development in the Permian Basin, particularly in the stacked oil-bearing formations of the Spraberry Trend and the Wolfcamp/Bone Spring shale play. The annual average spot price for natural gas also increased in 2017. Natural gas prices at Louisiana’s Henry Hub increased 21% in 2017, helping to drive increases in natural gas reserves. Pennsylvania added 28.1 Tcf of natural gas proved reserves, the largest net increase among states in 2017, as a result of increased prices and development of the Marcellus and Utica shales in the Appalachian Basin..
Oil Exploration Activity Will Pick Up in 2019 - There will be a pick up in oil exploration activity next year, compared to 2018, according to a new report from Fitch Solutions Macro Research. “On an annual average basis, revenues will be boosted by higher oil prices, while still compressed services costs will flatter margins and bolster cash flows. This will give companies greater flexibility to increase their CAPEX and assume more risk,” the report stated. “Exploration largely dried up following the oil price collapse in 2014, as companies focused on conserving their cash, gearing their spending towards lower risk, lower cost and shorter cycle projects. However, there are signs that exploration activity is starting to recover,” the report added. Exploration in frontier and deepwater plays “is showing signs of recovery,” according to the report, which also reveals that exploration appetite is returning in more prospective plays. Fitch Solutions Macro Research’s report highlights, however, that companies face continued constrains on their exploration spending. “Financial discipline continues to be a key concern for oil companies globally. Discipline will slacken as prices rise, but fears of peak demand and the longer-term health of the industry will likely keep margins more sharply in focus. This is not a bad thing and improved capital efficiency, and lower services cost, means companies can effectively do more with less,” the report said. “Arguably a bigger issue is not the level of spending, but how capital is allocated. As the market has recovered, much of the additional cash has been funneled towards shareholders (through dividends and buybacks) rather than towards productive investments. This competition for capital is likely to persist in 2019, continuing to drag on exploration next year,” the report added. Earlier this month, Rystad Energy announced that there was less appetite for exploration drilling.“Of the 100,000 wells drilled globally in 2013, four percent were exploration or appraisal wells. In 2018, this share is expected to drop to only two percent of the 70,000 wells drilled,” Rystad said in a company statement published on its website Nov. 9
Bakken crude back on infrastructure treadmill - Prices are not the only thing that’s been aligning to hold back future oil production growth in North Dakota.The industry’s record oil and gas production has filled up existing infrastructure much faster than industry has been able to build new pipelines and processing plants to take it away.That’s putting the Bakken back onto a familiar treadmill, one that’s similar to what’s happening in the Permian right now, and similar to what’s happened in the Bakken’s own not so distant past. The latest infrastructure crunch could result in significant dampening of future Bakken production and prices if it is not dealt with swiftly, according to analyst reports.Stratus Advisors, in its latest weekly analysis, notes that North Dakota’s August gas production alone added 260 million cubic feet per day of gas to daily production totals. By comparison, one world-class gas processing plant would handle 200 million cubic feet per day.Annualized on a 12-month basis, that kind of growth would require 16 new plants in a year’s time. So far, seven new gas plants have been proposed, adding a little more than one billion cubic feet per day in processing capacity, along with incremental increases of about 40 million cubic feet per day.The gas production doesn’t come alone, however. There are also NGLs associated with that, which require their own infrastructure. Using a conservative estimate of 6 gallons of NGLs per thousand cubic feet of gas, that would suggest about 40,000 new barrels of NGLs per plant that will also need takeaway and processing infrastructure. Bakken gas can be as low as 2 NGLs per thousand, but is more often up to 10, making 6 GPM a conservative estimate. Industry captured 83 percent of that, missing its 85 percent capture target for the sixth month in a row, and flaring 431 million cubic feet into the air. The situation has prompted some companies to voluntarily restrict production, according to Lynn Helms, Director of Mineral Resources and the Oil and Gas Division. He believes, based on his conversations with oil company officials, that oil production has been curtailed by as much as 50,000 barrels per day.The state has 1.37 million barrels per day in pipeline capacity for crude oil takeaway, but its oil production just tagged 1.36 million barrels per day in October. Right now the state is taking around 300,000 barrels per day by rail, which has helped leave some room on pipelines, but projections by the state’s pipeline authority, Justin Kringstad, have shown oil production exceeding current pipeline capacity by as much as 700,000 barrels per day in the next 10 to 15 years.Energy Transfer Partners recently proposed expanding the capacity of Dakota Access to 570,000 from 520,000, an additional 50,000 barrels per day of takeaway. And Phillips 66 and Bridger Pipeline have announced the Liberty Pipeline project, which could take up to 350,000 barrels per day to Texas. Keystone XL, meanwhile, was to have carried up to 100,000 barrels per day of Bakken crude at an on ramp in Baker, Montana. That is now on indefinite hold, however, after a judge ruled that certain studies for the line must be revisited to consider new information since the company’s initial application.
Bakken producers get a welcomed reprieve on natural gas flaring --Crude oil and natural gas production in the Bakken are at all-time highs, as are the volumes of gas being processed in and transported out of the play. The bad news is that for the past few months, the volumes of Bakken gas being flared are also at record levels, and producers as a whole have been exceeding the state of North Dakota’s goal on the percentage of gas that is flared at the lease rather than captured, processed and piped away. State regulators last week stood by their flaring goals, but in an effort to ease the squeeze they gave producers a lot more flexibility in what gas is counted — and not counted — when the flaring calculations are made. Today, we update gas production, processing and flaring in what’s been one of the nation’s hottest production regions. Given that Bakken gas production has been increasing more quickly than processing and takeaway capacity — and that North Dakota wants to stick to its flaring-reduction goals (if only to encourage more processing capacity to be built) — the NDIC on November 20 (2018) voted to change out the policy aims in its flaring-reduction rules and to provide additional flexibility to producers in their efforts to comply with the state’s flaring goals. First, the commission replaced its original policy aims of reducing the volumes of gas that is flared, the number of wells flaring and the duration of flaring with the aims of increasing the volumes of captured gas, reducing the percentage of gas flared and incentivizing investment in gas capture infrastructure (gathering pipelines, processing plants, onsite use of gas etc.) Second, the NDIC agreed to allow producers to remove from their monthly volume calculations:
- Any gas flaring tied to curtailments on gas gathering systems and processing plants,
- Any gas flaring resulting from newly completed wells being tied to the same gas infrastructure, and
- Any gas that is placed in geologic storage or used in enhanced oil recovery.
Keystone XL pipeline builder asks Montana judge to allow pre-construction work (AP) The company that wants to build the Keystone XL pipeline is asking a judge to change his order blocking the project to allow pre-construction work to continue, such as purchasing materials and finalizing contracts. Attorneys for the company will argue in a Wednesday telephone conference that U.S. District Judge Brian Morris should clarify or amend his ruling to say the injunction does not apply to activities such as finalizing contracts, purchasing materials, conducting land surveys and discussing federal permits. TransCanada wants to keep that preliminary work on track so that the Calgary-based company can be prepared to start pipeline construction as early as mid-February. Blocking the pre-construction work even for several weeks would likely cause the company to miss the entire 2019 construction season and delay its 2021 target for oil to start flowing through the pipeline. "A one-year delay in construction of the pipeline would result in substantial harm to TransCanada, as well was to United States workers, and to TransCanada's customers relying on the current in-service date of the project," TransCanada Pipelines Limited Senior Vice President Norrie Ramsay said in a written statement to the court. A year-long delay would cost TransCanada $949 million in earnings and put off the hiring of about 6,600 workers for construction, Ramsay said.
Toxic Oilfield Wastewater Used to Grow California Food, Including Organics -- Are families around the country—and around the globe—eating California produce grown with toxic water from oil drilling? If they consume Halos Mandarins, POM Wonderful pomegranate juice, Wonderful pistachios, Sunview Raisins, Bee Sweet citrus or Sutter Home wine, they may well be. Those companies grow some of their products in four water districts in California’s Central Valley that buy wastewater from Chevron and other oil companies’ drill sites. Now, Food & Water Watch is announcing a campaign to ban the practice, which threatens our food, farm workers and the environment, with a new documentary by noted filmmaker Jon Bowermaster and a campaign video capturing shocked reactions from people who previewed the video last week in front of Whole Foods’ headquarters in Austin, Texas. “It’s time to shine a light on the risky yet under-the-radar use of toxic oil wastewater to grow our crops,” said Wenonah Hauter, executive director of Food & Water Watch. “People are shocked when they hear that the food—even organic food—that they give to their kids is grown in districts where this is happening.” Nearly 40 percent of all organic produce grown in the U.S. comes from California. “So-called healthy brands grown in these districts are using toxic waste to grow crops and then labeling them as pure goodness.” According to the state, four water districts in California (Cawelo Water District, North Kern Water District, Jasmin Mutual Water District, and Kern-Tulare Water District) receive up to 16 billion gallons of wastewater each year—enough to fill 25,000 Olympic-sized pools—from oil companies that can be used in the systems that provide water for irrigating crops. The oilfield wastewater is minimally processed and mixed with fresh water and sold to farmers for crop irrigation. The crops are not routinely tested for toxic chemicals. A recent study found that nearly 40 percent of the chemicals used by the companies providing oil wastewater to the districts are classified as “trade secrets” or could not otherwise be identified, and known chemicals include several that cause cancer or reproductive harm, such as ethylbenzene and toluene.
Alberta officials are signaling they have no idea how to clean up toxic oilsands tailings ponds - The toxic waste of the Canadian oilpatch has been quietly spreading in the boreal forest since bitumen mining began near Fort McMurray in Northern Alberta in the 1960s. The mix of clay, water, toxic acids, metals and leftover bitumen has sprawled in artificial ponds to cover an area twice the size of the city of Vancouver. “It’s biologically and chemically an impossible fantasy,” said David Schindler, a renowned freshwater scientist and officer of the Order of Canada, when asked about Alberta's plan to clean up oilsands tailings. More than one trillion litres of the goop, called tailings, fill these man-made waste lakes that can be seen from space. An equivalent amount of water would take five days to tumble over Niagara Falls. The contaminated tailings ponds attract and kill migrating birds. They emit methane and other greenhouse gases. Despite years of public promises from officials that the tailings ponds would shrink and go away, they are growing. And in the meantime, troubling gaps are opening in the oversight system meant to ensure the oilpatch cleans up its mess. Alberta has collected only $1 billion from companies to help remediate tailings — a problem that is now estimated to cost about 100 times that. Decades and billions have been spent on research and still there is no sure solution to a problem that is getting attention beyond Alberta. In August, the Commission for Environmental Cooperation — a NAFTA organization composed of officials from the U.S., Mexico and Canada — announced it would investigate and produce a report on tailings ponds and the threat they pose to surrounding groundwater and rivers.
Oilsands waste is collected in sprawling toxic ponds. To clean them up, oil companies plan to pour water on them —The toxic waste of the Canadian oilpatch has been quietly spreading in the boreal forest since bitumen mining began here in the 1960s.The yogurt-like mix of clay, water, toxic acids, metals and leftover bitumen has sprawled in artificial ponds to cover an area twice the size of the city of Vancouver.More than one trillion litres of the goop, called tailings, fill these man-made waste lakes that can be seen from space. An equivalent amount of water would take five days to tumble over Niagara Falls.The contaminated tailings ponds attract and kill migrating birds. They emit methane and other greenhouse gases.Despite years of public promises from officials that the tailings ponds would shrink and go away, they are growing. And in the meantime, troubling gaps are opening in the oversight system meant to ensure the oilpatch cleans up its mess. Alberta has collected only $1 billion from companies to help remediate tailings — a problem that is now estimated to cost about 100 times that. While the world watches, the mining companies operating here have been allowed by regulators to pursue a clean-up technique called water capping.It’s supposed to work like this: put the tailings into a mined-out pit, then cover it with fresh water from a nearby river or reservoir. The idea, according to oil producer Syncrude, is that the tailings will settle to the bottom and over time the lake will turn into a healthy ecosystem supporting fish, animals and aquatic plants. “It’s biologically and chemically an impossible fantasy,” said David Schindler, renowned freshwater scientist and officer of the Order of Canada. Other scientists say the water-capped ponds may become effective in storing tailings even if they do not one day support aquatic life, though it will take years to be sure.
Trans Mountain: The billion-dollar oil pipeline Canadians own and can’t build - Canada recently spent billions on an oil pipeline in order to triple its capacity. But amid fierce opposition to Prime Minister Justin Trudeau's plans, will the Trans Mountain project ever get built? The Burnaby terminal of the Trans Mountain pipeline, at the pipeline's Pacific end, is now free of protesters, though over 200 people were arrested this year for blockading the construction site. Nestled in suburban Burnaby, British Columbia (BC), there is little sign the pipeline project has become a battlefield. The site is central to a fight over climate change and Canada's economy, the environment and the oil sector - between those who argue the pipeline project could devastate the Pacific coastline and those who say it will fuel the economy for years to come. The current peace is just a lull as sides regroup in the wake of a court rulling that dealt a blow to the project in August. That federal appellate court decision quashed Canada's 2016 approval of the project, saying regulators failed to adequately consult First Nations along the pipeline route and to fully account for the project's impact on the region's endangered killer whales. It was handed down the day Canada finalised its C$4.5bn ($3.4bn; £2.6bn) purchase of the 65-year-old pipeline from Kinder Morgan. The Texas-based energy infrastructure company agreed to sell the infrastructure amid myriad legal and regulatory challenges launched against their expansion plan. The C$7.4bn project would twin the existing 1,150km (715 mile) pipeline and increase capacity from 300,000 barrels per day to 890,000 per day from Alberta, the heart of Canada's oil industry, to Burnaby, BC. It would add roughly 980km of pipeline, new pump stations, and expand the dock facility and pipeline capacity at the Burnaby marine terminal. It would also increase oil tanker traffic on BC's coast from five to up to 34 tankers a month, tankers that would carry the oil along from Pacific coast refineries to Asian markets.
Canada's Output Grows Despite Pipeline Problems-- Canada’s lingering crude glut isn’t hindering the country’s growing oil output, according to the National Energy Board’s most recent forecast. The country’s oil production will average 4.59 million barrels a day, 22,000 more than previously forecast, data from the Canadian energy regulator show. The raised production outlook comes even as pipeline bottlenecks have driven Canadian crude prices to record lows and prompted some producers, including Canadian Natural Resources Ltd. and Athabasca Oil Corp., to reduce output by about 160,000 barrels a day, according to estimates by TD Securities Inc. The biggest driver of higher output is heavy oil-sands crude, which is forecast to have exceeded 2 million barrels a day in October to average 1.88 million daily barrels for the year. That’s 42,000 barrels a day more than the previously forecast. Output of conventional light and heavy oil also exceeded the earlier forecasts. The increase might reflect the faster-than-expected ramp-up of Suncor Energy Inc.’s Fort Hills oil sands mine, according to Stephen Kallir, upstream research analyst at Wood Mackenzie in Calgary. The 194,000 barrel-a-day Fort Hills mine started operation earlier this year and will run at 90 percent of capacity through the fourth quarter, Suncor Chief Executive Steve Williams said on a Nov. 1 conference call. “They are producing above 90 percent capacity as of end of the third quarter,” he said by phone. “We expected that early next year.” To be sure, the NEB recent data shows production trailing off in December with output lower than forecast earlier. Heavy Western Canadian Select crude fell below $14 a barrel on Nov. 15, the lowest in Bloomberg data extending back a decade. The crude’s discount to West Texas Intermediate futures widened to $50 a barrel in October, also a record in data extending back 10 years. The price fell $1.17 to $17.96 a barrel on Tuesday and the discount widened $1 to $33.50 a barrel.
Canada's Alberta province to buy rail cars to reduce oil glut (Reuters) - Canada’s Alberta province is in talks to buy rail cars to transport 120,000 barrels per day of crude oil and expects a deal to be concluded within weeks, Premier Rachel Notley said on Wednesday, as the oil-rich province tries to move oil stuck in the region because of a lack of pipeline capacity. Notley, who said the cars were needed to help deal with a glut that has slashed the price of Alberta oil, told a business audience she was disappointed the federal government was not helping fund the purchase. Reuters reported last week that Alberta had proposed a joint purchase of two unit trains worth of capacity and estimated the one-time capital cost at about C$350 million ($263.7 million). Federal officials are cool to the idea, saying that by the time the first cars come on line late next year, the supply problems will have eased. Alberta estimates it is producing about 250,000 bpd more than can be shipped using existing pipeline and rail capacity. “Alberta will buy the rail cars ourselves to move this oil,” Notley said in a speech. “We have already engaged a third party to negotiate and work is well under way. We anticipate conclusion of the deal within weeks.” She later told reporters a deal could be announced before year end. Based on the initial talks, Alberta expects the first 15,000 bpd of capacity to come online in December 2019, ramping up to the full 120,000 bpd by August 2020, with the agreement running for three years. “It’s a lot of trains and a lot of cars,” Notley told Maclean’s magazine in a webcast interview on Wednesday evening, noting it took multiple 60,000-barrel unit trains to move the equivalent of 120,000 bpd. The added transport capacity is expected to improve the Canadian crude discount by about $4 over the three-year term, the provincial government said. Under that time line, the first rail cars would roll out just as an expansion of Enbridge Inc’s Line 3 oil export pipeline is set to start operation, although Notley argued the rail capacity would still be needed. Notley said the cost of buying the cars would be fully recouped through royalties and the selling of shipping capacity. Her spokeswoman, Cheryl Oates, said the province did not anticipate keeping the unit trains beyond 2021.
Canada's Oil Industry Needs $40B to Flourish - At around 4.5 million barrels per day (MMbpd), Canada is the world’s 5th largest oil producer. Some 75 percent of Canada’s production occurs in the western province of Alberta, having a massive deposit of heavier, harder-to-produce “oil sands.” Canada has a nearly unlimited hydrocarbon resource, so importing oil nations around the world are increasingly seeking the country to supply resources. Canada’s biggest advantage may be its widening capacity to export. A slow growing population and mature energy demand market make incremental domestic needs rather low. Currently, most of Canada’s petroleum production is exported, and almost all of that gets shipped south to the U.S. This overreliance on the U.S. market has become a problem for Canada because a shale revolution has meant surging U.S. oil production amid its flat demand. As such, Canada needs to find new growing markets for its domestic oil industry to flourish. Canada’s natural goal is to reach Asia, responsible for about 70 percent of new oil demand in the world. Exporters are banking on cheaper transport. It takes a little over a week for a ship to reach Tokyo Bay from Vancouver, for instance, compared to nearly three weeks from the U.S. Gulf Coast. As seen by the ongoing legal fight of the Trans Mountain expansion running west from Edmonton to the Vancouver area, the anti-pipeline movement is very strong in Canada. This is especially true for those links that move oil sands crude because it has higher greenhouse gas emissions, making it a prime target for environmental groups. It is the very same lack of pipelines, however, that is also making Canadian oil cheaper and thus more desirable for importers abroad. For example, in recent weeks, Canada’s heavy oil has been trading at a whopping $50 per barrel discount to U.S. WTI. In turn, China purchased almost 1.60 million barrels of Canadian crude oil in September, up nearly 50 percent from April. China’s oil major Sinopec has joined a group planning to build an oil refinery in Alberta to better access the province’s heavily discounted crude.
Liberals renew efforts to save fracking ban- Shale gas politics dominated New Brunswick's fractured legislature on Wednesday, with the Liberal opposition launching a new effort to keep a moratorium on gas development in place. Liberal Leader Brian Gallant introduced legislation that would write the moratorium into law, making it harder for the Progressive Conservative minority government to undo it. Gallant said he introduced the bill because it's become clear the three People's Alliance MLAs plan to vote with the PCs on the issue in Friday's throne speech vote. Shortly after his comments, those Alliance MLAs confirmed that. They said they'll vote against Gallant's proposed amendment to the throne speech motion. The amendment would call for the provincewide moratorium to stay in place. They say voting to amend the PC throne speech motion would amount to a non-confidence vote that would bring down the Higgs government. "The last thing New Brunswickers want for Christmas is an election," said Fredericton-York Alliance MLA Rick DeSaulniers, who promised last week to vote against any lifting of the shale gas moratorium anywhere in the province.
TransCanada halts work on two pipeline projects in Central Mexico - Citing numerous delays, runaway costs and alleged acts of extortion, the Canadian pipeline company TransCanada has halted construction along the routes of two natural gas pipeline projects in Central Mexico that are worth more than $1 billion combined. TransCanada stopped construction in the state of Hidalgo on the Tuxpan-Tula Pipeline and the Tula-Villa de Reyes Pipeline, the company's Mexican subsidiary said in an open letter published in several Mexican newspapers. "The social and legal uncertainty that prevails in this state makes the continuity of our investments impossible," the company wrote in the statement. "On multiple occasions, social groups have made irrational requests that border on extortion and have performed acts outside the law." TransCanada won contracts with Mexico's state-owned power company to build the two pipelines as part of that nation's historic energy reforms. The company received a $500 million contract in Nov. 2015 to build the 163-mile Tuxpan-Tula Pipeline to move natural gas from the coastal state of Veracruz to power plants in Hidalgo. Several months later, the company received an April 2016 contract worth $550 million to build a pipeline to move natural gas from Tula to the State of San Luis Potosi. As part of larger network to move natural gas from South Texas into the Mexican interior, the two pipelines were originally planned to be in service this year, moving up to 886 million cubic feet of natural gas per day. But with routes going through rugged mountain terrain, the projects have encountered strong opposition and legal challenges from farmers and indigenous people citing landowner rights issues as well as environmental and safety concerns. TransCanada's situation in Hidalgo follows opposition to pipeline projects raised by indigenous groups in the United States, Canada and elsewhere in Mexico. Last year, members of the Yaqui tribe in Mexican border state of Sonora dug up a small section of a natural gas pipeline being built San Diego-based Sempra Energy on their land.
Pemex Triples Estimate for 'Most Important Onshore Field in 25 Years' -- Pemex has more than tripled its estimated reserves in its Ixachi field. The company now believes the onshore field in Veracruz contains 1.3 billion barrels of oil equivalent in proven, probable and possible, or "3P," reserves, Petroleos Mexicanos exploration chief Jose Antonio Escalera said Tuesday at a press conference in Mexico City. Pemex expects the field to reach 80,000 barrels a day of condensate production and 720 million cubic feet per day of gas production by 2022. “Without doubt this news will allow Pemex to contribute with more production in the future and stabilize the production platform,” Chief Executive Officer Carlos Trevino said. “I am confident the next administration will value this discovery a lot.” Trevino is due to step down from that role as President elect Andres Manuel Lopez Obrador takes office Saturday, having pledged to revive Mexico’s state-owned oil company. The field is currently producing about 2,000 barrels a day of condensate, Escalera said. The company is expecting 5,000 barrels a day of condensate and 30 million cubic feet a day of gas by the end of 2019. Ixachi is the most important onshore field in 25 years, Escalera said. Pemex has struggled to increase its crude production, which is heading for a 14th consecutive year of declines. It’s target for output in 2018 is about 1.8 million daily barrels, down from a previous target of 1.95 million barrels a day. In 2019, it expects to pump more than 1.8 million barrels a day, Trevino said. The estimated investment to develop Ixachi field is 30 billion pesos ($1.47 billion) for 40 wells, Trevino said. The Ixachi announcement comes a month after Pemex said it had found light crude in the shallow water Manik and Mulach oil wells in the Southeast Basin in the Gulf of Mexico, an area estimated to hold 3P reserves of more than 180 million barrels. Pemex’s Xikin-1 and Esah-1 fields are expected to begin production in 2019 and 2020, respectively.
This is what Cuadrilla has said about the 18 day halt to fracking at its Preston New Road site - Shale gas firm Cuadrilla has moved to deny rumours that there are problems with its fracking operation at Preston New Road. The move comes after Fylde MP Mark Menzies wrote to energy minister Claire Perry to ask for an independent probe into the site following questions from constituents and claims from anti-fracking campaigners. They say that no fracking has been carried out at the site off the A583 near Little Plumpton, since fracking operations triggered a series of 36 small tremors, six of which were above the 0.5ML (local magnitude) limit where a halt has to be called on fracking for 18 days. The protesters said Cuadrilla appears to have stopped fracking at the site, the only activity being staff entering and exiting the site and the odd cherry picker working near the silo tanks. They suggested that, as well as the earthquakes, Cuadrilla is facing problems ranging from further issues with their impermeable membrane to problems with their well bore. Mark Menzies letter to Claire Perry states: "Following recent seismic activity, constituents have expressed concern over the well integrity at this site and believe that the current checks being carried out are not satisfactory. I would appreciate if you could clarify what plans the department have for an independent inspection of the well integrity at this site, either directly by the OGA or an appointee of that body, to reassure nearby residents that recent seismicity has not jeopardised the safety of operations." But today, a spokesman for Cuadrilla said: “We are continuing to test the shale gas exploration well in Preston New Road, Lancashire, and the coiled tubing remains clearly and visibly attached to the coiled tubing tower on site above the well. "We have completed a series of smaller fracks along the length of the horizontal well to gather data to assess the micro-seismic response of the shale rock 2km below the surface. "We have said many times in recent days and weeks, to both local people and any media who have asked for an update, that we are now analysing that data as well as drawing on expert advice to determine how we can further optimise our hydraulic fracturing programme within the very rigorous operating boundaries of the micro-seismic traffic light system.
High Court to hear latest legal challenge to fracking in Lancashire - The latest legal challenge against fracking at Cuadrilla’s controversial Preston New Road site is set to be heard at the High Court. Friends Of The Earth claims the Environment Agency (EA) failed to ensure that the best available techniques are being used to reduce the environmental impact of fracking at the energy firm’s site in Little Plumpton, Lancashire. The environmental campaign group argues that the EA should have considered the use of other techniques which could produce less contaminated waste fluids when it considered Cuadrilla’s permit application in December 2017. At a hearing in London on Thursday, Mr Justice Supperstone will be asked to rule on Friends Of The Earth’s action. In a statement ahead of the hearing, Friends Of The Earth campaigner Tony Bosworth said: “All along, the Government stated that gold standard regulation would make fracking OK, but we believe our case, and the reality of what’s happening at Preston New Road, shows the opposite. “They should be putting in place the best possible regulation to ensure that people and the environment are protected. “How can the Government be considering rolling fracking out across the country when it can’t be properly regulated at even one site? “Isn’t it time the Government gives up on fracking and backs renewables instead?” Hydraulic fracturing, known as fracking, is a process to extract shale gas whereby rock is drilled into and “fractured” before water, sand and chemicals are pumped into it to release gas. Supporters say fracking could help provide greater energy security for the UK, but critics warn the process can trigger earthquakes and pollute water supplies.
Cuadrilla will seek to raise fracking tremor threshold in Lancashire - The company in charge of the UK's only active shale gas site said it would seek to raise the threshold of seismic activity at which fracking must stop.Cuadrilla has had to stop fracking four times for breaching the current limit of 0.5 magnitude at its site in Little Plumpton, Lancashire. Energy minister Claire Perry said in October it would be "foolish" to change the threshold at present.Cuadrilla confirmed the plan but did not provide a statement.Anti-fracking campaigners said they would strongly oppose any increase in the limit, which they said was in place for safety reasons.The plan would need to be submitted to the government and was outlined in a statement from one of Cuadrilla's main investors, the Australian mining company A J Lucas.Chairman Philip Arnall said the 0.5 ML threshold was regarded as "overly conservative". But he said Cuadrilla was "working on the assumption that this constraint will not be altered for the current hydraulic fracturing operations". Cuadrilla would also allow more fluid to come back to the surface after fracking, in an attempt to tackle the problem of earth tremors, the statement said.This process is predicted to reduce friction in the well, which is more than 2km (1.2 miles) underground.The statement to shareholders continued: "Cuadrilla will engage with the regulators and the industry to clearly demonstrate that a more appropriate upper limit on seismic monitoring should be set to enable optimal testing without compromising on world class environmental and safety measures."A series of 36 small tremors have been recorded since the company began fracking at the site near Preston New Road on 15 October, the largest measured 1.1 magnitude.Anti-fracking campaigners argue the process of fracking to extract shale gas poses risks to the environment. A 2.3 magnitude tremor on the Fylde coast seven years ago was probably caused by shale gas test drilling, a study found.Campaigners had tried to stop fracking at Little Plumpton with an injunction bid but failed. Judgment has been reserved in a new legal action over fracking at the site.
Scottish Government look to fortify fracking policy with fresh consultation - TThe Scottish Government confirmed last night it was looking to fortify its fracking policy with a fresh public consultation on the practice. The new consultation will hope to “finalise” the current ambiguity surrounding the development of unconventional oil and gas in Scotland, which has been described as an “effective ban” Last month, ministers confirmed they were consulting on their “preferred policy position” on fracking being prohibited in Scotland, more than a year after First Minister Nicola Sturgeon said the controversial practice was being banned “end of story”. Ms Sturgeon declared at the time: “Fracking is being banned in Scotland, end of story. There will be no fracking in Scotland. I don’t think that position could be any clearer.” But confusion reigned in July when ministers extended the licence of fracking firm Ineos across the Scottish central belt . Energy minister Paul Wheelhouse said responses were now being sought on the issue, with the consultation to last until December 18. A Scottish Government spokesperson said: “The Scottish Government’s preferred policy position is that it does not support unconventional oil and gas development in Scotland, based on consideration of scientific and economic evidence and a significant public consultation in 2017. “This position is now subject to key statutory assessments, including a Strategic Environmental Assessment and a Business Regulatory Impact Assessment. These assessments, which themselves involve current public consultations, are the latest steps in a cautious, evidence-led approach the Scottish Government has adopted in its policy-making process on this issue.
Fracking ban lifted by WA Government, but Perth, Peel and South West to remain 'frack free' - The WA Government has lifted its moratorium on hydraulic fracturing, or fracking, but has promised 98 per cent of the state will remain "frack free". Premier Mark McGowan said a ban on fracking in the Perth, Peel and South West regions would be maintained. Farmers, landowners and native title holders would also be allowed to refused fracking — a practice where drilling is used to fracture the ground and release trapped gas. The decision comes after the release of a 12-month inquiry, led by Environmental Protection Authority (EPA) chairman Tom Hatton and commissioned by the McGowan Government. The report found if the process was carried out safely, the risk of fracking to people and the environment was low. "However, the report identified the opportunity to further reduce risks with a set of recommendations for additional prescriptive regulation," the inquiry concluded.A total of 44 recommendations were made to tighten regulations, including:
- No fracking to be allowed within 2 kilometres of public drinking water sources;
- All projects to include EPA assessment;
- An enforceable code of practice; and
- No fracking to be allowed within 2 kilometres of towns and dwellings
"What we presented are the risks and how they might be minimised," Dr Hatton said. "The principal recommendation is for an enforceable code of practice, incorporating a number of very specific and technical and prescriptive recommendations aimed at further reducing the risk."
Protest movement swells as Premier green-lights fracking - The state government announced on Tuesday it would lift a moratorium on gas fracking in the Kimberley, Pilbara and Mid West of Western Australia on the grounds that the risks to people and environment were manageable and that it could not turn its back on industry. The Premier said the moratorium would only be lifted on existing petroleum titles, that landowners and traditional owners would get veto rights, and royalties would go into a fund for renewable energy. The McGowan government came to power promising to ban fracking in the South West, Perth and Peel regions and put a moratorium on fracking across the Kimberley, Pilbara and Mid West pending an independent inquiry headed by Environmental Protection Authority chairman Tom Hatton. Green groups, public figures, scientists, farmers and traditional owner groups have watched anxiously for the results of the inquiry into fracking and the government response, both announced on Tuesday. Dr Hatton said when the WA government announced its scientific inquiry last year, there was a widely held view that preceding national and international inquiries made one in WA unnecessary. But there was a unique and distinctive picture of WA's risks and concerns and how those risks might be further reduced. There was also new science that made other inquiries somewhat dated. The panel was asked to recommend a scientific approach to regulating fracking and limit its scope to the technical risks of shattering rock to get gas. Instead, the panel took a "wider view" of the risks and impacts a fracking industry would have on the environment and communities. "It was our view given the nature of the concerns ... that this broader interpretation would be of greater value and more respectful to the community and the West Australian government," Dr Hatton said.
Companies still face hurdles after WA fracking moratorium is lifted - Lifting a state-wide moratorium on fracking in Western Australia will lead to "very few" new jobs, despite hopes and promises of economic benefits, an independent mining analyst predicts. The WA Government has lifted its moratorium on fracking after a 12-month inquiry led by the Environmental Protection Authority found the risk to people and the environment was low if the process was carried out safely.The WA Premier Mark McGowan said the state could not turn its back "on the potential jobs, investment and new energy supply the onshore gas industry can supply". But independent mining analyst Tim Treadgold said the key to a successful fracking industry in the state would be oil extraction."The gas we've got we can't even develop and sell. The business case for fracking to produce oil and gas just does not add up at this point in time." He said the oil price would need to be double what it was now to make fracking a viable industry in WA. "You would need somewhere in the order of $US120 a barrel in order to justify the cost [of fracking]," he said."It is a devilishly expensive operation and you need a lot of oil to justify it."The nature of artificial stimulation of oil fields is that they don't actually produce a lot of oil per well. You would need to drill hundreds of these things in order to make the field commercially viable. "And the biggest problem of all is that in most places in Western Australia there is no pipeline to get the oil to a refinery.
Prices Edge Higher With Volatility To Remain Elevated And Weather Dependent - Highlights of the Natural Gas Summary and Outlook for the week ending November 23, 2018 follow. The full report is available at the link below.
- Price Action: The December contract rose 3.6 cents (0.8%) to $4.308 on a 64.2 cent range ($4.864/$4.222).
- Price Outlook: The market edged higher on continued bullish weather forecasts. Although inside weeks are considered rare, after last week’s huge $1.194 range, an inside week is not surprising. The market is extremely sensitive to change weather forecasts and will remain volatile. If temperatures remain below normal, last weeks’ $4.929 high will likely not be the high. CFTC data indicated a 52,996 contract increase in the managed money net long position as longs added and shorts covered. The is the smallest short position on record for comparable data. This is the largest net long position since February 20. The long position is 389,656 contracts smaller than the record long position of 809,566 from April 16, 2013.Total open interest rose 228,338 to 4.131 million as of November 13. Aggregated CME futures open interest fell to 1.321 million as of November 23. The is the smallest OI since September 28, 2017. The current weather forecast is now cooler than 8 of the last 10 years. Pipeline data indicates total flows to Cheniere’s Sabine Pass export facility were at 3.2 bcf. This flow volume suggests feed gas is entering Train 5. Cove Point is net exporting 0.8 bcf.
- Weekly Storage: US working gas storage for the week ending November 16 indicated a withdrawal of (134) bcf. Working gas inventories fell to 3,113 bcf. Current inventories fall (613) bcf (-16.5%) below last year and fall (718) bcf (- 18.7%) below the 5-year average.
- Storage Outlook: The EIA weekly implied flow was (14)bcf from our EIA storage estimate. This week’s storage miss is well above our tolerance. The forecasts use a 10-year rolling temperature profile past the 15-day forecast. Our joint publication with RBN updates storage projections daily.
- Supply Trends: Total supply rose 0.5 bcf/d to 81.6 bcf/d. US production fell. Canadian imports rose. LNG imports rose. LNG exports rose. Mexican exports fell. The US Baker Hughes rig count fell (3). Oil activity decreased (3). Natural gas activity was unchanged +0. The total US rig count now stands at 1,079 .The Canadian rig count rose +7 to 204. Thus, the total North American rig count rose +4 to 1,283 and now exceeds last year by +145. The higher efficiency US horizontal rig count fell (10) to 929 and rises +143 above last year.
- Demand Trends: Total demand rose +22.6 bcf/d to +98.1 bcf/d. Power demand rose. Industrial demand rose. Res/Comm demand rose. Electricity demand rose +5,622 gigawatt-hrs to 77,175 which exceeds last year by +4,497 (6.2%) and exceeds the 5-year average by 5,534 (7.7%%).
- Nuclear Generation: Nuclear generation rose 3,020 MW in the reference week to 82,664 MW. This is (6,255) MW lower than last year and (2,147) MW lower than the 5-year average. Recent output was at 88,183 MW.
The heating season has begun. With a forecast through December 7 the 2018/19 total cooling index is at (684) compared to (520) for 2017/18, (359) for 2016/17, (445) for 2015/16, (621) for 2014/15, (641) for 2013/14, (542) for 2012/13 and (519) for 2011/12.Natural Gas Summary and Outlook for the week ending November 23, 2018
November 23 Natural Gas Weekly: The Fears Of Under-Supply Are Exaggerated - We estimate that aggregate demand for American natural gas (consumption + exports) totaled around 675 bcf for the week ending November 23 (up as much as 14.0% y-o-y, but down 5% w-o-w). The deviation from the norm stayed positive, but declined from +44% to +31% (see the chart below). According to our calculations, aggregate demand for U.S. natural gas (on a weekly basis) has been above 9-year norm since February 24, 2017. This week, the weather conditions have warmed up across the country – but particularly in the Central and Midwest parts of the U.S. We estimate that the number of nation-wide heating degree-days (HDDs) dropped by 4.0% w-o-w in the week ending November 23. Non-degree-day factors were no longer supporting any extra consumption. The most important four non-degree-day factors that we are looking at are: the spread between natural gas and coal, wind speeds, hydro inflows and nuclear outages. Specifically, higher ng/coal spreads have already reduced some 3.0 bcf/d of potential coal-to-gas-switching, while the level of nuclear outages has normalized. According to U.S. Nuclear Regulatory Commission, nuclear outages averaged 11,300 MW this week, which was only 12% above 5-year average. Overall, however, total energy demand (measured in total degree-days) should be above last year’s level by no less than 26%. Total exports jumped by 13% w-o-w – mostly due to stronger LNG sales. According to Marine Traffic data, Sabine Pass and Cove Point together served no less than 10 LNG tankers last week (total natural gas carrying capacity of 34 bcf), which is a new all-time-record.mWe estimate that dry gas production has been expanding in annual terms for 77 consecutive weeks now. Currently, we project that dry gas production will average 90.0 bcf/d in November, 89.5 bcf/d in December and 89.3 bcf/d in January. The aggregate supply of natural gas (production + imports) averaged around 95.3 bcf per day for the week ending November 23 (up 12.0% y-o-y and up 1.0% w-o-w). Overall, total unadjusted supply/demand balance should be negative at around -8 bcf. The volume is as much as 48 bcf above last week’s results, but around 4 bcf below 5-year average for this time of the year (see the chart below). Last Thursday, the EIA reported a draw of 134 bcf. Total storage now stands at 3,113 bcf, which is 710 bcf (or 18.57%) below 5-year average for this time of the year. Currently, we expect EIA to report a draw of 67 bcf next week (final estimate will be released on Wednesday). Overall, at this point in time, we expect storage flows to average -73 bcf over the next three reports. Natural gas inventories deviation from 5-year average is currently projected to expand from -710 bcf (-18.57%) today to -742 bcf (-20.40%) for the week ending December 7.
Warmer Weekend Forecasts Hit Natural Gas --It was another volatile day for the December natural gas contract, as it gapped down significantly last evening and recovered through much of today's trading session but still settled down almost a percent and a half below Friday's settle. The February and March contracts were hit the hardest. This came following significant weekend GWDD losses, which we highlighted for clients in our Morning Update. Such weekend trends were not particularly surprising, as we had been tracking warm risks last week as well. Last Monday we highlighted in our Note of the Day that we were seeing weather model trends that may allow prices to set a top; they spiked on Wednesday off a bullish EIA print but that turned out to be the top (after initially seeming to set a top Monday). Then on Friday we warned that risk was skewed lower in prices despite low confidence in this high volatility environment, and that long-range warm risks should arrive on models by today. Those medium-range cold risks did intensify as expected, and current Week 2 forecasts have quite a few cold risks per the Climate Prediction Center. Models then show some easing cold risks late Week 2 into Week 3, as seen by less intense cold on the 12z GEFS this afternoon (model images courtesy of Tropical Tidbits). Prices did recover from their early morning lows today, thanks in part to lingering Week 2 cold risks and firm cash prices that we outlined in our Morning Update, which is why we said "...we would first look for bounces to $4.1 or even $4.25..." when prices were trading around $4.05. Yet into the settle the December and January contract both logged similar losses (though after hours the January contract has been hit a bit harder).
Another Couple Nat Gas Bounces Fail - It was a slow natural gas trading day by recent standards, yet the December contract still saw a range of 20 cents with large, quick moves in both directions as weather models bounced around and December futures options expired at the settle. Heavy selling into the settle cut into the December gain on the day, with the contract settling up slightly as later winter contracts were hit harder. In our Morning Update we outlined that there were some modest GWDD additions in Week 2 and that combined with "lingering cash strength or into options expiry $4.25-$4.3 resistance could get tested again..." In fact, resistance was tested first off AM cash strength and then again into options expiry, with a brief poke above before prices crashed back below into and after the settle. Some colder afternoon American weather model guidance in Week 2 helped prices recover a second time today, which the CPC picked up on. Yet clearly storage concerns overall eased with such relatively large March contract weakness. This was something we broke down for clients in our subscriber-only live chat today, where we fielded questions on our December weather forecast as well as natural gas pricing risk and the latest weather-adjusted demand balances. Of note were power burns really picking up again relative to past years on the cold shot peaking today. We also released our Seasonal Trader Report, which outlined out weather expectations through the next 5 months. In it we looked at the latest Sea Surface Temperature profile globally to look at where temperature risk was skewed and broke down the probabilistic El Nino forecasts by the Climate Prediction Center.
December Contract Expiry Sends Gas Soaring -- It was another wild day in the natural gas space, with the December contract shooting higher into its expiry as gas for the upcoming month was clearly in high demand. The December contract logged the largest gain on the day, clearly dragging the rest of the strip higher. The end result was the December/January Z/F spread ending in positive territory, which is far from common. Colder medium-range trends on afternoon weather model guidance likely helped add fuel to the fire in the expiration rally, as seen by colder 6-10 Day CPC forecasts. Our Morning Update also highlighted that "...we could see the December contract jolt higher as cash has been strong relative to futures recently..." which verified this morning and also likely played a role in this strong expiry, with the stage set by overnight HDD additions. Traders are now awaiting an EIA report tomorrow that should show a solidly smaller storage pull last week than was seen in the previous week thanks to less weather-driven demand, though it is unclear just how much smaller the draw will be.
US Midwest natural gas power burn remains strong despite higher prices — Midwest gas-fired power generation remains high despite Chicago November cash prices maintaining its highest average in four years. The balance of the Chicago winter 2018-19 strip has been on the rise this month, rising from a 10-cent premium in October to the current 35-cent premium the past few days. Daily Chicago cash prices have followed suit, rising from the $3.10 to $3.30/MMBtu range at the end of October to an average of $4.02 so far this November with daily cash reaching as high as $4.65. This is a drastic increase in the price of gas over past Novembers as Chicago November cash prices haven't averaged above $3.00/MMBtu since 2014. However, the power sector seems largely unaffected by the higher fuel costs as powerburn in the region has averaged more than usual when after prices get this elevated. For example, in November 2014, when Chicago cash prices averaged $4.35/MMBtu during November, the Midwest sample averaged 28 MMcf/d of gas burned at power plants per heating degree day, according to S&P Global Platts Analytics. This November, with Chicago cash prices averaging $4.02, Midwest power plants are burning an average of 61 MMcf/d per HDD. This is likely due to a large amount of coal retirements and new gas generation since 2012, shifting gas from the role of swing supplier to a baseload provider which is less sensitive to price swings. Since 2012, the Midwest has retired a total of 13.8 GW of coal capacity, although much of this occurred in 2015 and 2016, according to Platts Analytics. The Midwest power market has been more reliant on gas for several years. However, there have not been sustained prices of more than $4.00/MMBtu over that period. Still, as prices steadily rose in 2015 through 2017, powerburn per HDD remained strong and even set a new November high in 2017 despite prices that were higher than the two prior Novembers. The scenario will likely bring volatility to the Midwest this winter, as it does not appear as though the power sector will play a substantial role in balancing the gas market, according to Platts Analytics. The volatility could be especially pronounced if colder than average weather arrives prompting the region to conserve gas in order to not plow through already low storage stocks. Midwest inventories currently sit 70 Bcf lower than the five-year low for this time at 830 Bcf.
Weekly Gas Storage- Draw Falls Short of Expectations - The EIA released its weekly Natural Gas Storage Report today, outlining how national natural gas stocks have changed in the last week.In total, the EIA reports natural gas stocks fell by 59 Bcf last week, decreasing to 3,054 Bcf from 3,113 Bcf. This is 17.4% below the 3,698 Bcf that was in storage at this point last year and is 19.1% below the five-year average of 3,774 Bcf. This week’s storage draw fell slightly short of expectations, as analysts predicted a draw of 76 Bcf. Nearly every region saw a draw this week, with the largest in the East and Midwest region where stocks fell by 25 Bcf and 21 Bcf. The only build came in salt stocks in the South Central region, which added 8 Bcf.
Natural Gas Shakes Off A Looser EIA Print -- Though the January natural gas contract settled down slightly on its first day as the prompt contract, it settled higher than it was initially ahead of the morning's EIA storage number, closing solidly off the lows. It was the March contract that lagged the most on the day still, with the January contract settling down just over 5 cents from yesterday's expiry spike. Prices fell initially overnight on warmer GEFS American model guidance, then shot higher on a colder European model run. We outlined these differences in our Morning Update for subscribers. Yet prices still meandered down ahead of the morning EIA print as traders positioned for a potential bearish miss and reacted to what may have been an overdone short squeeze yesterday (which is why we held a Slightly Bearish sentiment in our Afternoon Update yesterday). This worked well as the EIA announced 59 bcf of gas was pulled from storage versus our estimate of 67 bcf and market expectations just north of 70 bcf. This was a much looser print when compared to the previous week's very large draw. Certainly the Thanksgiving holiday played a role, but even so it still was a far looser print. Yet very cold medium-range forecasts helped prices rebound through the session still. Now traders are attempting to figure out how long-range forecasts will adjust over the weekend, as the Climate Prediction Center is showing more warm risks there.
Brazil Eyes $30 Billion Offshore Oil Boom - Over the past few years, Brazil has held several very successful oil auctions under production-sharing contracts in its pre-salt layer, attracting major oil companies to its prized offshore oil area. Now President-elect Jair Bolsonaro wants to open more of the pre-salt assets - an area currently exclusively in the hands of state oil firm Petrobras - to private investors, hoping to earn US$31 billion (120 billion Brazilian reais) that could help narrow Brazil’s massive budget deficit.However, as Bolsonaro prepares to take office on January 1, 2019, his transition team may need to negotiate how different Brazilian states and municipalities could divide the revenues from the potential sale of stakes in more pre-salt fields to foreign oil firms. This uncertainty is not welcome news for Big Oil, which has expressed interest in the area that has been explored to some extent and proven to hold much more oil than initially thought.The area at stake is the so-called ‘transfer of rights’ area, where Petrobras holds 100 percent of the rights to produce 5 billion barrels of oil. The state oil firm has explored the area and found that a lot more oil lies in this low-risk offshore zone. There are estimates that the ‘transfer of rights’ area could hold up to 15 billion barrels of oil in excess of the 5 billion barrels to which Petrobras is entitled to produce when the government transferred the area to the state firm in 2010. Brazil has been looking to pass legislation to remove the obligation that only Petrobras can produce oil in the ‘transfer of rights’ area. Far-right President-elect Bolsonaro, who had supported state control over the oil assets in the past, now plans to sell oil and other energy assets and supports the bill to allow foreign participation in the currently Petrobras-only ‘transfer of rights’ area, Bolsonaro’s advisor Luciano de Castro told Bloomberg earlier this month.
Brazil's recent subsalt sales to add 2.1 mil b/d in output by 2028: PPSA— The 14 subsalt areas that Brazil sold at the country's five production-sharing auctions will yield about 2.1 million b/d and 24 million cu m/d in fresh output by 2028, according to a study published this week by government subsalt management company Pre-Sal Petroleo SA, or PPSA. Not registered? Receive daily email alerts, subscriber notes & personalize your experience. Register Now "The Brazilian subsalt is one of the world's biggest oil frontiers," PPSA's president Ibsen Flores said during a presentation at the company's first subsalt technical seminar. The record-setting profit oil guarantees submitted to win development rights to the subsalt blocks during the bid rounds also will result in the government receiving about 250,000 b/d and 3 million cu m/d for its share of output, according to the PPSA study. The forecasts show "the importance of these 14 contracts for Brazil," Flores said. Subsalt output, which already accounts for more than 50% of Brazil's 2.3 million b/d of production, will start to trend steadily higher starting in 2021, when the first floating production, storage and offloading vessel is installed at the Mero field in the Libra area. The FPSO will have installed capacity to produce 180,000 b/d and process 12 million cu m/d. Investments in the new areas will reach $144 billion to drill 316 injection and production wells that will feed 19 separate FPSOs, according to PPSA's forecast. But Brazil needs to continue with its current schedule of future bid rounds to ward off a sharp drop-off in investments in 2029, when the first phase of subsalt development will come to close, Flores said. President-elect Jair Bolsonaro, who will take office on January 1, has indicated that it will maintain the bid rounds, which the industry says it needs for planning purposes and to refresh portfolios. Brazil sold the first subsalt field under its production-sharing regime in 2013, when the Libra area was auctioned. That was followed by the three areas each in the second, third and fourth auctions and four areas in the fifth sale held in September. Additional subsalt acreage expected to come up for sale in 2019-2021, including the much-anticipated sale of oil discovered in the transfer-of-rights areas, is expected to further boost output over the next decade, officials said.
Oil Pipeline Spills 8,000 Barrels of Crude in Peruvian Amazon - Approximately 8,000 barrels (336,000 gallons) of crude oil spilled from a severed pipeline into the Peruvian Amazon on Tuesday night, according to state-owned oil company Petroperu.In a press release, Petroperu said its Norperuano pipeline was cut by members of the Mayuriaga indigenous community in the Loreto region in an act of "sabotage" and prevented technicians from repairing the pipe and containing the release.The four-decades-old pipeline transports crude from Amazonian oil fields to Petroperu's coastal refineries."We could face an environmental catastrophe," Beatriz Alva, a manager with Petroperu, told channel N television (via AFP).After the oil reached the Mayuriaga River, company chief James Atkins described the potential ecological damage as "tremendous and irreparable," teleSURreported.Environmental regulator (OEFA) is waiting on police and prosecutors to verify the damages and determine culpability, according to a statement published by teleSUR.The Norperuano pipeline has a history of spill incidents. More than 20,000 barrels of petroleum have spilled from the pipe in 15 protest attacks in just the last two years, Reuters reported, citing data OEFA. Another 5,600 barrels were released from corrosion or operative failures.Mayuriaga community leaders have not immediately issued any comments to the media about the latest leak. Pipeline Break Spills Oil Into Amazon Waterways – www.youtube.com
Peru catastrophe feared after 8,000-barrel Amazon oil spill - A Peruvian oil executive warned Wednesday of "catastrophe" after indigenous residents cut a major pipeline in a region of the Amazon, triggering the spill of 8,000 barrels of oil. "We could face an environmental catastrophe," Beatriz Alva, a manager with state oil firm Petroperu, told channel N television. Alva gave the volume of spilled crude as "more or less 8,000 barrels." Residents in a remote community of Morona district, in the northeastern Loreto region, "cut the pipeline" on Tuesday night and prevented workers from repairing it, Alva said. Residents of the district are overwhelmingly indigenous people. Villagers had threatened last week to cut the pipeline, which moves crude from Amazonian wells to coastal refineries, in a protest against alleged irregularities in local elections held in October. Peru's Amazon region has seen repeated oil spills in recent years, some the results of a lack of maintenance. Others were caused by protest attacks. The country produced 127,000 barrels of oil per day in 2017, according to the BP Statistical Review of World Energy.
Venezuela is leaking oil everywhere - From a distance, the scene is beautiful, a dark pool shimmering under the midday sun, reflecting billowing clouds. But when you close in on the dirt-packed trail leading toward a trio of storage tanks, a pungent odor makes it clear. It’s not pretty; it’s an oil spill. In this one spot in the Orinoco Belt, a region in Venezuela named for the river that flows above the world’s largest deposits of crude, so many barrels have escaped from underground pipes that a 2,150-square-foot pit around the tanks is filled to the brim. The country is pockmarked with these messes, as Petroleos de Venezuela’s infrastructure rots after years of neglect, scant investment and corruption scandals under the regimes of the late Hugo Chavez and his successor as president, Nicolas Maduro. Venezuela, an OPEC member dependent on oil sales for almost half the national budget, is pumping at the lowest levels since the 1940s. The spills are conspicuous signs of what has gone so horribly wrong at once-mighty PDVSA. The state-owned company doesn’t publish statistics, but environmentalists, analysts and workers keep seemingly endless lists of examples of wayward crude—unleashed by busted valves, ripped gaskets, cracked pipes and on and on—that they say has polluted waterways and farmland and probably has seeped into aquifers. PDVSA’s cleanup policy is, on paper, strict, because “if spills aren’t quickly attended to, they become environmental liabilities,” said Carmen Infante, a Caracas-based industry consultant. But resources are spread so thin that responses are rarely swift or comprehensive; trunks of nance trees near the three tanks in Anzoategui state are buried in crude more than 10 months after the leak was discovered. According to workers in the field, many of the services contractors that specialize in sponging up spills, with trucks equipped with giant vacuums, have gone out of business because they’ve had such trouble getting paid by PDVSA.
Forget Nordstream 2, Turkstream Is The Prize -- While the Trump Administration still thinks it can play enough games to derail the Nordstream 2 pipeline via sanctions and threats, the impotence of its position geopolitically was on display the other day as the final pipe of the first train of the Turkstream pipeline entered the waters of the Black Sea.The pipe was sanctioned by Russian President Vladimir Putin and Turkish President Recep Tayyip Erdogan who shared a public stage and held bilateral talks afterwards. I think it is important for everyone to watch the response to Putin’s speech in its entirety. Because it highlights just how far Russian/Turkish relations have come since the November 24th, 2015 incident where Turkey shot down a Russian SU-24 over Syria. When you contrast this event with the strained and uninspired interactions between Erdogan and President Trump you realize that the world is moving forward despite the seeming power of the United States to derail events.And Turkey is the key player in the region, geographically, culturally and politically. Erdogan and Putin know this. And they also know that Turkey being the transit corridor of energy for Eastern Europe opens those countries up to economic and political power they haven’t enjoyed in a long time.The first train of Turkstream will serve Turkey directly. Over the next couple of years the second train will be built which will serve as a jumping off point for bringing gas to Eastern and Southern Europe.Countries like Bulgaria, Hungary, Italy, Greece, Serbia and Slovakia are lining up for access to Turkstream’s energy. This, again, is in stark contrast to the insanely expensive Southern Transport Corridor (STC) pipeline set to bring one-third the amount of gas to Italy at five times the initial cost. Turkstream will bring 15.75 bcm annually to Turkey and the second train that same amount to Europe. The TAP – Trans Adriatic Pipeline — will bring just 10 bcm annually and won’t do so before 2020, a project more than six years in the making. The real story behind Turkstream, however, is, despite Putin’s protestations to the contrary, political. No project of this size is purely economic, even if it makes immense economic sense. If that were the case then the STC wouldn’t exist because it makes zero economic sense but some, if not much, political sense. No, this pipeline along with the other major energy projects between Russia and Turkey have massive long-term political implications for the Middle East. Erdogan wants to re-take control of the Islamic world from the Saudis.
A Gamechanger In European Gas Markets? - The Southern Gas Corridor on which the European Union is pinning most of its hopes for natural gas supply diversification away from Russia is coming along nicely and will not just be on schedule, but it will come with a price tag that is US$5-billion lower than the original budget, BP’s vice president in charge of the project told S&P Global Platts this week. "Often these kinds of mega-projects fall behind schedule. But the way the projects have maintained the schedule has meant that your traditional overspend, or utilization of contingency, has not occurred," Joseph Murphy said, adding that savings had been the top priority for the supermajor. The Southern Gas Corridor will carry natural gas from the Azeri Shah Deniz 2 field in the Caspian Sea to Europe via a network of three pipelines: the Georgia South Caucasus Pipeline, which was recently expanded and can carry 23 billion cubic meters of gas; the TANAP pipeline via Turkey, with a peak capacity of 31 billion cubic meters annually; and the Trans-Adriatic Pipeline, or TAP, which will link with TANAP at the Turkish-Greek border and carry 10 billion cubic meters of gas annually to Italy. TANAP was commissioned in July this year and the first phase of TAP is expected to be completed in two years, so Europe will hopefully have more non-Russian gas at the start of the new decade. But not that much, at least initially: TANAP will operate at an initial capacity of 16 billion cubic meters annually, of which 6 billion cubic meters will be supplied to Turkey and the remainder will go to Europe. In the context of total natural gas demand of 564 billion cubic meters in 2020, according to a forecast from the Oxford Institute for Energy Studies released earlier this year, this is not a lot. Yet at some point the TANAP will reach its full capacity and hopefully by that time, TAP will be completed. Surprisingly, it was the branch to Italy that proved the most challenging, and BP’s Murphy acknowledged that. While Turkey built TANAP on time to the surprise of the project operator, TAP has been struggling because of legal issues and uncertainty after the new Italian government entered office earlier this year. Meanwhile, however, Russia and Turkey are building another pipeline, Turkish Stream, that will supply gas to Turkey and Eastern Europe, as well as possibly Hungary. The two recently marked the completion of its subsea section. Turkish Stream will have two lines, each able to carry up to 15.75 billion cubic meters. One will supply the Turkish market and the other European countries. In this context, the Southern Gas Corridor seems to have more of a political rather than practical significance for the time being, giving Europe the confidence that it could at some future point import a lot more Caspian gas because the infrastructure is there.
Russian South Stream 2.0 Comes Out Of The Shadows - Russia and Turkey have announced that the two countries have reached significant progress in reviving the November 2014-shut down South Stream gas pipeline intended to land Russian gas across the Black Sea. The project is the part of the already secured open tender contracts for purchases of gas signed between Gazprom, Bulgaria, Serbia, Hungary, Slovakia and Austria. The new Black Sea gas pipeline Turkish Stream will run under sea from Krasnodar to a landing hub just west of Istanbul. On November 19, presidents Vladimir Putin and Recep Tayyip Erdogan met in Istanbul to announce the completion of pipeline's off-shore section.Pipeline capacity is for 30 bullion cubic meters, bcm, although initial phase capacity will be closer to 17bcm (the first pipe). Currently, Gazprom supplies the above volume (30bcm) to Turkey (ca 16bcm), Bulgaria, Serbia, Slovakia, Hungary and Austria. Turkish market has been supplied via Blue Stream pipeline, and the other countries are supplied via Ukraine. Based on reports from Russia's Kommersant (https://www.kommersant.ru/doc/3806415), Gazprom has managed to achieve two feats:
- Gazprom has completed laying two (not one) pipes for Turkish Stream, one intended to supply Turkey and another, to supply Southern Europe,
- Gazprom secured tenders for purchases of gas from all EU states to be connected to the South Stream project (Bulgaria's open tender closes in December 2018, but all other countries have already signed onto supply agreements).
Significantly, the tenders were secured in compliance with the EU Energy Directives. This means that Gazprom latest venture has addressed the main cause of the EU's original objections to the same pipeline prior to 2014. In the case of open tenders process, Gazprom used exactly the same scheme to secure capacity orders for its Nord Stream 2 pipeline to Germany, Czech Republic and Slovakia back in 2017. According to the experts cited by Kommersant, this makes in impossible for the EU to shut down the project. Of course, history reminder due, South Stream was primarily killed off not by the EU, but by the U.S. keen on protecting Ukraine's near monopoly on Russian gas transit. The Obama Administration exerted massive pressure on Bulgaria and other South Stream-receiving countries to prevent landing Russian gas in Southern Europe. So far, there has been little indication what Washington's position on the latest iteration of the South Stream might be, but I doubt it will be welcoming.
Stationary Cargoes Indicate LNG Market Might Be Following Oil’s Footsteps-- Some liquefied natural gas sellers aren’t in a rush to deliver their multimillion-dollar cargoes. With uncertain demand and no signs yet of bitter cold, some traders are preferring to keep their fuel inside vessels in the hope prices will rise. While the sight of stationary cargoes might not be unusual in the more-established oil market, technology has only recently made it feasible to keep LNG at minus 162 degrees Celsius (minus 260 degrees Fahrenheit) for longer periods. “There are cargoes parked close to Singapore, apparently waiting for the right market conditions to be delivered,” said Dumitru Dediu, an associate partner at McKinsey Energy Insights, which monitors LNG flows. “Some of the players are speculating.” There are about 30 vessels currently flagged as floating storage globally, two-thirds of which are in Asia, the biggest LNG consuming region, according to cargo-tracking company Kpler SAS. That’s still a fraction of a global fleet of more than 500 vessels. The practice of using tankers as floating storage is common in the more developed oil market. It happens during periods of contango -- when storage on land is used up, immediate demand is weak and the cost for later delivery is high enough to cover the expense of storing crude on a tanker. Trading houses and oil majors from Vitol Group and Glencore Plc to BP Plc and Royal Dutch Shell Plc collectively made billions of dollars from 2008 to 2009 stockpiling crude at sea. At the peak of the floating storage spree, sheltered anchorages in the North Sea, the Persian Gulf, the Singapore Strait and off South Africa each hosted dozens of supertankers. LNG, the fastest-growing fossil fuel, is starting to resemble the oil market in that sense. Holding it back is that some LNG is lost to keep it cool during its journey, known as boil off, and that most sales are through traditional long-term contracts without destination flexibility. But that’s rapidly changing. Modern tankers are capable of serving as floating storage, especially for markets such as China that lack that capacity. They have lower boil-off rates, bigger capacity and re-liquefaction units on board to keep the cargoes cool.
Aramco Plans To Significantly Boost Gas Output -Aramco has plans to increase its natural gas production by 64 percent from the current 14 Bcf daily to 23 Bcf, the company’s chief executive officer, Amin Nasser, said at an industry event in Dubai as quoted by S&P Global Platts.Natural gas is among Aramco’s top priorities for the future along with downstream crude oil operations with a particular focus on petrochemicals.The company will invest some US$160 billion in raising its natural gas production, Nasser said, as part of a larger US$500-billion investment program for the next decade. Natural gas production capacity will be boosted to 25 Bcf.The company will pursue both conventional gas developments and unconventional ones, the executive also said. Earlier this year, Aramco began production of unconventional gas at the North Arabia field. Production from the field was seen to ramp up from the initial 55 million cu ft per day to 190 million cu ft per day by the end of this year.As part of its gas plans, Aramco earlier this month signed a joint exploration and production agreement with Adnoc, covering both natural gas and LNG. Under the terms of the deal the two companies will look into LNG investment opportunities, the companies said at the time.Nasser yesterday said Aramco had allocated total investments of US$500 billion for its international expansion and diversification over the next ten years. Besides the US$160 billion earmarked for natural gas, the company would also set aside US$100 billion for growing its petrochemical business, on top of the US$70 billion Aramco is expected to pay for a majority stake in Saudi petrochemicals major Sabic.The company also plans to boost its refining capacity to 8-10 million barrels daily, the chief executive also said, t o “create a better balance between our upstream and downstream segments."
Oil demand for cars is already falling - The International Energy Agency published its World Energy Outlook last week, its annual effort at revising assessments of future demand for and supply of fuels and electricity. 1 There’s a familiar theme within it: The IEA expects more renewable-energy use in the future than it did in last year’s outlook, which was more than it forecast in the 2016 outlook. There’s also something noteworthy on transportation: The IEA is calling the top on oil demand from cars.According to the report:Oil use for cars peaks in the mid-2020s, but petrochemicals, trucks, planes and ships still keep overall oil demand on a rising trend. Improvements in fuel efficiency in the conventional car fleet avoid three-times more in potential demand than the 3 million barrels per day (mb/d) displaced by 300 million electric cars on the road in 2040.It’s noteworthy when a long-term projection calls the top on demand for something as fundamental as a component of global oil demand. But demand for oil consumed for transportation is already waning in certain markets and segments.One place is in buses. Electric buses will displace about 233,000 barrels of oil demand a day by the end of the year. Add in the much smaller displacement from electric cars, and there’s 279,000 barrels a day displaced — about as much oil as Greece consumes per day.Another is Europe. As Bloomberg Intelligence’s Rob Barnett notes, the latest figures from Germany show demand for diesel fell 9 percent in the first half of the year. The influence of Green Party lawmakers will dent demand further.Then there’s Italy, where demand for gasoline has fallen by nearly half since 2005. Even if electric vehicles make up a very small part of the current displacement of oil demand, that will certainly grow. Bloomberg NEF expects twice as many electric vehicles on the road as the IEA does, and those vehicles will displace more than twice as much oil demand as the IEA expects.
How IMO 2020 may impact markets and challenge refiners and shippers - The planned implementation date for IMO 2020 is still more than a year away, but this much already seems clear: even assuming some degree of non-compliance, a combination of fuel-oil blending, crude-slate shifts, refinery upgrades and ship-mounted “scrubbers” won’t be enough to achieve full, Day 1 compliance with the international mandate to slash the shipping sector’s sulfur emissions. Increased global refinery runs would help, but there are limits to what that could do. So, what’s ahead for global crude oil and bunker-fuel markets — and for refiners in the U.S. and elsewhere — in the coming months? Today, we discuss Baker & O’Brien’s analysis of how sharply rising demand for low-sulfur marine fuel might affect crude flows, crude slates and a whole lot more. The International Maritime Organization (IMO), a specialized agency of the United Nations, in recent years has been implementing ever-tightening rules to reduce allowable sulfur-oxide emissions from the engines that power the 50,000-plus tankers, dry bulkers, container ships and other commercial vessels plying international waters. In Against the Wind, we explained that in January 2012, the global cap on sulfur content in bunker (marine fuel) was reduced to 3.5% (from the old 4.5%) and that on January 1, 2020 — only 13 months away — it is set to be reduced to a much stiffer 0.5%. There are even tougher standards already in place in the IMO’s Emission Control Areas (ECAs) for sulfur, which include Europe’s Baltic and North seas and areas within 200 nautical miles of the U.S. and Canadian coasts. In July 2010, the ECA sulfur limit in marine fuel was reduced to 1% (from the old 1.5%), and in January 2015, the limit was ratcheted down again to a very stringent 0.1% — a standard that will remain in force within the ECAs when the 0.5% sulfur cap for the rest of the world becomes effective on New Year’s Day in 2020.
Nigeria will lose $6 billion in 'corrupt' oil deal with Shell and Eni, report claims - A deal Shell and Eni brokered with the Nigerian government in 2011 is set to cost the African nation $6 billion in lost revenue, a report claimed Monday.The report, published by campaign group Global Witness, said the allegedly corrupt deal's terms would stop Nigeria accessing its share of the profits from oil extracted from its offshore block. Shell and Eni were accused of bribery last year over a $1.3 billion payment that secured an exploration licence for the block, known as OPL 245, in 2011. It was alleged that although the funds were paid to the Nigerian government, the money actually went to Malabu Oil and Gas — a company linked to former oil minister Dan Etete. Global Witness claimed that a term granting Nigeria a share of the oil production profits was negotiated out of the 2011 deal by former Nigerian ministers, who it alleges took bribes from the oil giants. It said the clause was replaced with a back-in option that required Nigeria to pay more towards the exploration costs than it could afford. Shell and Eni — along with some of their former employees — are facing charges relating to the payment, with Italian prosecutors alleging there was awareness the funds would be pocketed by individuals. All of the defendants have denied any wrongdoing. In a statement emailed to CNBC, a Shell spokesperson said: "Since this matter is before the Tribunal of Milan it would not be appropriate for us to comment in detail. We maintain that the settlement was a fully legal transaction with the federal government of Nigeria and Eni and, based on our review of the prosecutor of Milan's file and all of the information and facts available to us, we do not believe that there is a basis to convict Shell or any of its former employees."
European Gas Stations Out Of Diesel- French Refinery Strike Deepens Crisis - Diesel is in short supply in Europe. The situation is about to worsen as the biggest French refinery is shutting down. Bloomberg reports Europe's Diesel Woes Deepen as Strike Halts French Oil Refinery. Total SA, France’s biggest refiner, is in the process of shutting its largest plant in the country, the 247,000-barrel-a-day Gonfreville facility in Normandy, due to a labor dispute, a spokeswoman for the company said on Tuesday. A few hundred miles away, in the Netherlands, retail fuel stations are running out of supplies because of shipping constraints on the Rhine, according to Royal Dutch Shell Plc.Shell said Nov. 20 that it cut production at its Rheinland refining site, the biggest complex of its kind in Germany, due to low water levels on the Rhine. In a tweet on Tuesday, the company said that it was temporarily unable to supply some unmanned fuel stations in the Netherlands.Gas stations in Germany had already been running dry due to the situation on the Rhine, a major petroleum product transportation corridor that runs northwest from the Swiss Alps all the way to the Netherlands. Switzerland released emergency fuel stockpiles because of the situation on the river.The premium per barrel of diesel over Brent crude - another indicator of market strength - was at $15.96 on Tuesday, the highest for the time of year in six years. This shutdown cannot possibly come at a worse time for French President Emmanuel Macron.Macron is already reeling over a protest of his diesel tax. People from across France went to Paris to let the president know how they feel about the taxes in general and the tax on diesel. The [Diesel Tax Protests](Diesel Protests in France Turn Violent) then turned violent.Expect more reactions when the price skyrockets.
Wave of refinery shutdowns may push India into importing fuel next year (Reuters) - A wave of shutdowns will hit Indian state-owned refineries next year as the country prepares for cleaner fuels from April 2020, company officials said, in moves that could temporarily dent oil demand and push up imports of refined fuels. India, the world’s third-biggest oil importer and consumer, has surplus refining capacity and rarely imports gasoil and gasoline. It also means that demand for fuel produced by India’s privately owned refiners will likely climb during the period, as state refiners seek to fill the gap. State refiners - Indian Oil Corp, Bharat Petroleum, Hindustan Petroleum and Mangalore Refinery and Petrochemicals - account for about 60 percent of the country’s nearly 5 million barrels per day (bpd) capacity. GRAPHIC: India gasoline & gasoil imports - tmsnrt.rs/2RmScrO The refiners will have to shut gasoil- and gasoline-making units at their plants for 15 to 45 days to churn out Euro VI-compliant fuels from January 2020 to be able to sell them from April of that year. “Next year will be challenging for us as I have to protect my crude throughput and finish the job at the refineries and get ready for Euro VI by April 2020,” said B.V. Rama Gopal, head of refineries at IOC, the country’s top refiner. IOC plans a roughly month-long shutdown of gasoline- and gasoil-producing units at all of its 11 refineries, he told Reuters. Key parts of the refineries requiring a revamp include naphtha hydrotreaters, catalytic reforming units, isomerisation units, diesel sulphurisers and diesel hydrotreaters. In addition, some refiners have to revamp or set up new gasoline treaters, hydrogen production and sulfur recovery units. India has been gradually reducing sulfur emissions from vehicles since 2000, when fuel sold in the country had 500 parts per million (ppm).
Tugboat spills oil at Vizhinjam - On Wednesday an abandoned tugboat at Seaward Wharf of Vizhinjam Port - MV Brahmekshara - sank spilling oil and fuel posing threat to marine life and environment. The port authorities were on the toes due to lack of pollution-fighting equipment and disaster management measures to contain the spill. The tugboat sank around 4.30 am. Initially, none of the authorities including the coastguards or fire department was ready to contain the spill claiming that the incident happened in Port's jurisdiction. The pollution control board, who tried to coordinate the damage control operations, were clueless on the steps to be taken as the Port had no equipment or facilities to skim spilt oil and contain the pollution. Skimmer, the device used to remove oil floating on liquid surface and barriers for avoiding spreading of oil, are the two necessary equipment required for the purpose. After hours of discussions, finally, the coastguard and fire department stepped in and used oil spill disbursement to control damages. A top official of the port department said that Vizhinjam Port is not a major port and commercial activities are very less. The tugboat has around 3,000 litres of diesel and 2,500 litres of used oil. "We have placed a proposal to buy pollution-fighting equipment. We cannot buy heavy duty and expensive equipment as there is no use for them most of the time. The incident occurred today is just a random one," said the official. "We took measures to auction the tugboat as the owner abandoned it. But the boat is in a legal tussle, and State Bank of India stopped the procedure to auction due to some default by the owner. The wreckage could be removed only with the permission of the bank or the court." He said that amount to the tune of Rs 46 lakh would be collected as dues before the wreckage is removed.
Russia crude supply to China surges to record, Iran shipments sink: customs (Reuters) - Russia shipped record volumes of crude oil to China in October as independent refiners continued to fill import quotas, while Iranian oil shipments fell on uncertainty over Washington’s imposition of sanctions on Tehran, data showed on Monday. China’s imports from top supplier Russia jumped 58 percent from a year earlier to 7.347 million tonnes, according to the General Administration of Customs data, marking the highest ever and equivalent to about 1.73 million barrels per day (bpd). For the first 10 months, Russian imports were at 57.91 million tonnes, or 1.39 million bpd, up 16.6 percent. Chinese customs last month began updating an online database with commodity imports by country of origin, replacing a service that had until March only been available to clients. Percentage changes with year-earlier figures were calculated by Reuters. China’s crude import demand hit an all-time high in October and is expected to stay strong to year-end as independent refiners snap up cargoes to use up their import quotas. The strong demand from China’s so-called “teapot” refiners has helped to push spot premiums for popular grades such as Russian ESPO Blend and Oman crude to their highest in more than four years. Iranian shipments, however, tumbled 64 percent in October from the year-ago month to 1.0496 million tonnes, about 247,160 bpd, ahead of U.S. sanctions that came into effect on Nov. 4. Month-on-month, imports from Iran in October marked their third fall in a row as China’s state oil firms came under growing pressure to scale back purchases ahead of the sanctions. For the January-October period, imports from Iran fell 3.4 percent from 2017 to 25.54 million tonnes, or 613,300 bpd. China is one of eight countries that have been granted a waiver to continue buying some crude oil from Iran. The world’s largest energy consumer is allowed to buy 360,000 bpd of oil from the Islamic Republic for at least 180 days from the imposition of sanctions, Reuters reported.
Contender: Saudi Arabia nabs new China oil demand, challenges Russia's top spot (Reuters) - Saudi Arabia is set to expand its market share in China this year for the first time since 2012, with demand stirred up by new Chinese refiners pushing the kingdom back into contention with Russia as top supplier to the world’s largest oil buyer. Saudi Arabia, the biggest global oil exporter, has been surpassed by Russia as top crude supplier to China the past two years as private “teapot” refiners and a new pipeline drove up demand for Russian oil. Now fresh demand from new refineries starting up in 2019 could increase China’s Saudi oil imports by between 300,000 barrels per day (bpd) and 700,000 bpd, nudging the OPEC kingpin back towards the top, analysts say. Saudi Aramco said last week it will sign five crude supply agreements that will take its 2019 contract totals with Chinese buyers to 1.67 million bpd. “With the recent crude oil supply agreements and potential increase of refinery capacity, the Saudis could overtake the Russians and reclaim (the) crown as the biggest crude exporter to China,” Rystad Energy analyst Paola Rodriguez-Masiu said. Saudi Arabia has already gained ground this year. China imported 1.04 million bpd of Saudi crude in the first 10 months of 2018, China customs data showed. This is equivalent to 11.5 percent of total Chinese imports, up from 11 percent in 2017, Reuters calculations showed. Saudi’s market share in China could jump to nearly 17 percent next year, if buyers requested full contractual volumes, analysts from Rystad Energy and Refinitiv said, while growth in Russian oil supply to China could slow. China imported 1.39 million bpd of Russian crude in January-October this year, about 15 percent of total Chinese imports, customs data showed. Russia had a 14 percent share at 1.2 million bpd in 2017. “We expect Chinese imports of Russian crude to remain at a similar rate in 2019 as a large share of these Russian barrels are imported via pipeline,” Refinitiv analyst Mark Tay said.
China is Said to Resume Iran Oil Imports -- Asia’s largest buyer of Iranian oil is said to have resumed purchases from the Persian Gulf state following a one-month hiatus, a move that will help allay fears that U.S. sanctions on the OPEC producer will constrain global supplies. China will start loading the crude again in November after it halted purchases in October, according to people with knowledge of the matter, who asked not to be identified because it’s confidential. The Asian nation was one of a handful that won exemptions from the U.S. to keep importing Iranian oil without falling foul of sanctions, with a waiver allowing 360,000 barrels a day for six months starting November. Global benchmark Brent crude surged more than 20 per cent after President Donald Trump’s decision to reimpose sanctions on Iran stoked fears of a supply deficit. Prices have since collapsed to their lowest level this year as those concerns eased after the issuance of waivers to eight nations including China, South Korea and India. The Chinese government had previously told at least two state-owned companies to avoid buying Iranian oil in the lead-up to the Nov. 4 sanctions review deadline. The nation’s decision to restart purchases precedes an upcoming meeting between Presidents Xi Jinping and Donald Trump at the Group of 20 summit next week and coincides with flaring trade tensions between the world’s two largest economies. Although Chinese purchases are set to resume shortly, payments to Iran will only be settled at a later date, say the people, as both parties strive to work out a smooth process. India, one of Iran’s top Asian customers, is set to purchase 1.25 million metric tons in November while Korean refiners are likely to be held back by payment and insurance complications until February or later. Nobody responded to faxes sent to China’s Ministry of Foreign Affairs and Ministry of Commerce seeking comment.
US State Department says Iranian oil exports will fall further 'very soon' — The US State Department is "doing everything we can to deter and discover" evasion of sanctions on Iran's oil buyers, a top official said Thursday, adding that Tehran's crude exports will fall further "very soon." Brian Hook, State Department special representative for Iran, said US sanctions on Iran's oil buyers have cut the country's exports by more than 1 million b/d."Many more barrels will be coming off very soon," Hook said at a briefing at Joint Base Anacostia-Bolling in Washington, DC."All of our diplomatic posts in the region, especially in the Middle East and in Europe, are putting in place strategies to detect and to prevent sanctions evasion," he added.Iranian crude export loadings are below 800,000 b/d so far for November, compared with a six-month average of 2.4 million b/d earlier this year, according to S&P Global Platts Analytics and data from Platts trade flow software cFlow.But Platts Analytics expects the actual November average to be higher than 800,000 b/d due to ships increasingly turning off transponders. Average loadings could be closer to 1.1 million b/d this month, given contractual lags in Japan and South Korea. Platts Analytics expects Iran's exports to stay around 1 million b/d by the next US sanctions deadline in May. Eight countries received waivers to continue importing Iranian crude through May 4: China, India, Japan, South Korea, Turkey, Taiwan, Greece and Italy. Many of the countries are expected to seek fresh waivers for the six months starting May 5, in exchange for cutting their Iranian imports further.Hook said the US government is concerned Iran could block two key chokepoints for oil shipments if its influence in the Yemen conflict grows. About 18.5 million b/d of oil flowed through the Strait of Hormuz and 4.8 million b/d through Bab el-Mandab in 2016, according to the Energy Information Administration.
Iran's nuclear chief warns EU patience is running thin (Reuters) - Iran’s nuclear chief said on Tuesday he was warning the European Union’s top diplomat that Iranian patience was running out on the bloc’s pledges to keep up oil trade despite U.S. sanctions. Ali Akbar Salehi, head of the Atomic Energy Organisation of Iran, said the Islamic Republic could resume enriching uranium to 20 percent purity - seen as well above the level suitable for fuelling civilian power plants - if it fails to see the economic benefit of the 2015 deal that curbed its nuclear program. “If we cannot sell our oil and we don’t enjoy financial transactions, then I don’t think keeping the deal will benefit us anymore,” Salehi told Reuters ahead of a meeting with EU foreign policy chief Federica Mogherini in Brussels. “I will pass certainly a word of caution to her (Mogherini): I think the period of patience for our people is getting more limited and limited. We are running out of the assumed timeline, which was in terms of months.” Following the meeting, Mogherini said she and Salehi remained committed to safeguarding the nuclear accord. Related Coverage • EU foreign policy chief determined to preserve Iran nuclear deal “They equally expressed their determination to preserve the nuclear agreement as a matter of respecting international agreements and a key pillar for European and regional security,” Mogherini’s office said in a statement. It said Mogherini also repeated the EU stance “on issues of concern such as Iran’s role in the region” - alluding to Iranian involvement in Middle East conflicts from Yemen to Syria. Under the 2015 deal with world powers, Iran restricted its enrichment program, widely seen in the West as a disguised effort to develop the means to make atomic bombs, in exchange for an end to international sanctions. U.S. President Donald Trump pulled out of the accord in May, arguing it was weak because it did not halt Iran’s development of ballistic missiles or support for armed proxies abroad, and reimposed sanctions on Iran’s vital oil export sector earlier this month. But Europe sees the nuclear deal as an important element of international security.
Iraq may be on the cusp of a major revenue windfall from oil - Iraq may be on the cusp of a revenue windfall after losing billions of dollars annually due to its insufficient oil production facilities, according to investors. International energy executives have been clinching new contracts to develop the hydrocarbon-rich country's energy sector that, despite being OPEC's second-largest producer, has failed to solve domestic poverty and infrastructure woes. But foreign investors admit that lofty development goals continue to be hindered by sluggish administration, corruption and a wall of bureaucracy. "The administrative decision-making process takes so long, it takes a lot of resources to be there and support during those fallow periods," Other executives noted it takes up to eight weeks for employees to get visas to enter the country. Development goals include capturing gas flares, or the gas burned off during oil production, to convert into usable energy and which Siemens estimates could save Iraq $5.2 billion over the next four years. Previous inability to capture this excess natural gas due to the war-weary country's underdeveloped infrastructure has amounted to billions of dollars in lost revenue per year. Working with Iraq's electricity ministry, multinational energy and industrial companies have major plans to turn the sector around — something that will be critical for post-war reconstruction, the funding of which the World Bank estimates will require up to $150 billion. Executives from Shell, BP, Chevron, Siemens and General Electric (GE), among others, gathered in Dubai on Sunday to present their plans for the country's energy and infrastructure sectors. The conference, organized by the Iraqi British Business Council (IBBC), focused on the private sector's role in rebuilding and investing in the country of 38 million, one year on from the defeat of the Islamic State group in Iraq. At the helm of major energy investments is GE, which in October beat out German manufacturer Siemens in a hotly contested competition for a massive 14 gigawatt (GW) power generation contract worth a reported $15 billion. Siemens inked its own agreement to provide a separate 11 GW to Iraq's power infrastructure.
Trump to Iraqi PM: How about that oil? President Trump twice raised to the Iraqi prime minister the idea of repaying America for its wars with Iraqi oil, a highly controversial ask that runs afoul of international norms and logic, according to sources with direct knowledge. Trump appears to have finally given up on this idea, but until now it hasn't been revealed that as president he's raised the concept twice with Iraq's prime minister and brought it up separately in the Situation Room with his national security team. In March last year, at the end of a White House meeting with Iraq's then-Prime Minister Haider al-Abadi, Trump brought up the subject of taking oil from Iraq to reimburse the United States for the costs of the war there. "It was a very run-of-the-mill, low-key, meeting in general," a source who was in the room told Axios. "And then right at the end, Trump says something to the effect of, he gets a little smirk on his face and he says, 'So what are we going to do about the oil?'" On the campaign trail, Trump complained that the U.S. had spent trillions in Iraq and lost thousands of lives but got "nothing" in return. He lamented that usually in war "to the victor belong the spoils" and he repeatedly said the U.S. should have seized Iraq's oilfields as reimbursement for the steep costs of the war. Top national security figures from both parties condemned Trump's idea, calling it outrageous and unworkable — a violation of international law that would fuel the propaganda of America's foes. In the March meeting, the Iraqi prime minister replied, "What do you mean?" according to the source in the room. "And Trump's like, 'Well, we did a lot, we did a lot over there, we spent trillions over there, and a lot of people have been talking about the oil.'"Al-Abadi "had clearly prepared," the source added, "and he said something like, 'Well, you know Mr. President, we work very closely with a lot of American companies and American energy companies have interests in our country,'" the source added. "He was smirking. And the president just kind of tapped his hand on the table as if to say 'I had to ask.'"
- "I remember thinking, 'Wow. He said it. He couldn't help himself,'" the source said.
- A second source who was in the room confirmed this account. "It was a look down and reach for your coffee moment," the second source said.
- A third source, who was briefed at the time on the conversation between Trump and al-Abadi, said the back and forth "made its rounds" around the National Security Council. "It was still early on in the administration, and we were all still trying to figure out how this was going to go, and so it was one of those horror stories … he's really going to do this."
Trump's desire to raid Iraq's oil is illegal and unworkable. But it reveals a great deal about his approach to the Middle East. Trump remains hellbent on extracting payments from Middle Eastern countries, in the form of natural resources, for the trillions of dollars America has spent since the early 2000s.Bob Woodward and others have reported on the formal steps Trump took to push his team to extract rare minerals from Afghanistan as repayment for the war. (Security concerns have stymied that effort; though Afghan's leadership was more open to Trump's pitch than Iraq's leaders have been.)
OPEC reportedly plans quiet oil output cut to avoid Trump's ire - OPEC and Saudi Arabia are reportedly planning to throttle back oil production but will attempt to message the output cut in a way that does not antagonize President Donald Trump. The strategy, explained by OPEC and Saudi sources to The Wall Street Journal, implies that top OPEC producer Saudi Arabia would slash production by up to 1 million barrels per day. OPEC is preparing to pull back output because the 15-nation cartel thinks the oil market will be oversupplied next year. Crude prices have plunged more than 30 percent since last month on the growing consensus that supply will soon outstrip demand. But ahead of OPEC's policy meeting on Dec. 6, Trump is urging the group against cutting production and imploring the Saudis to help him drive oil prices even lower. The president praised Saudi Arabia on Wednesday for helping to cut fuel prices by increasing output earlier this year. On Tuesday, Trump declared he'd stand by the Saudis even though the CIA has reportedly concluded that the nation's powerful crown prince ordered the killing of journalist and U.S. resident Jamal Khashoggi. Trump has repeatedly cast doubt on the CIA assessment this week. "Because of Khashoggi, the Saudis will do anything to make sure Trump doesn't do anything nasty," an OPEC official told The Wall Street Journal. In light of Trump's overtures, OPEC and the Saudis plan to reaffirm the output targets they first agreed to in November 2016, the Journal reported on Friday. That means Saudi Arabia would begin cutting output from its target of 11 million bpd this month to its 2016 quota, which is just over 10 million barrels a day.
Goldman Sachs contradicts Trump: $50 oil is bad for the US, commodity chief warns - The rapid plunge in oil prices to $50 a barrel is bad for the United States and threatens to create problems in the credit market, warns Jeff Currie, head of commodities research at Goldman Sachs.Currie's opinion is at odds with the view from the White House, where President Donald Trump has beencheering the recent oil market sell-off and urging Saudi Arabia to drive prices even lower. The president, eager to see gasoline prices fall, is publicly pressuring OPEC to reject price-boosting output cuts when the group meets with Russia and other producers next week. Saudi Arabia convinced about two dozen producers to increase output in June ahead of U.S. sanctions on Iran. However, Trump did not apply those sanctions as harshly as expected, and now OPEC and its allies are strongly signaling they will once again throttle back output following a collapse in oil prices.Currie thinks Saudi Arabia and Russia have an opportunity to convince Trump that the production cuts are necessary at this week's G-20 meeting in Argentina."We think a production cut is in the interest of all three parties," Currie told CNBC's "Squawk on the Street" on Monday. "Oil prices at $50 a barrel dig into the U.S. industry's cost structure. It's not good for the U.S. either at these prices." U.S. West Texas Intermediate crude prices plunged to a more than one-year low at $50.10 on Monday, down 35 percent since the start of October. The price that's best for all parties is the $65 to $70 range, according to Currie.
In Oil’s Huge Drop, All Signs Say Made in the U.S.A. - The downward spiral in oil prices is accelerating as a surge in crude production from a turbocharged U.S. petroleum industry runs into weaker global economic growth. Crude prices slid 7.7% Friday, their largest one-day drop since July 2015, and are now down by nearly a third since the start of October. The U.S. benchmark, West Texas Intermediate futures, closed at $50.42 a barrel—its lowest level in over a year. As economic growth outside the U.S. has flagged, producers and traders are beginning to worry that demand for crude will also decline. In export-dependent Germany, a purchasing managers index hit a four-year low, well below the level economists were expecting.The steepness of the drop has prompted Saudi Arabia and the Organization of the Petroleum Exporting Countries to consider a plan to quietly cut production to bolster prices, according to people familiar with the matter. The idea would see the cartel retain the official output targets it set in 2016. But, because Saudi Arabia is overshooting those targets by nearly 1 million barrels a day, it would effectively be a cut. Such a move may help support prices without raising the ire of President Trump, who has been calling on OPEC to keep prices lower. Investors remain skeptical that the OPEC meeting in Vienna on Dec. 6 will be able to turn the tide on oil supply enough to support prices. A big reason why: the emergence of the U.S. oil industry as one of the world’s most important players. Ballooning shale production—American output has nearly doubled since the start of 2012—has made the U.S. a key supplier and exacerbated worries about a global glut of crude. “I never thought I would hear these kinds of numbers coming out of the U.S.,” said Bob Yawger, director of the futures division at Mizuho Securities USA. “This is going to force OPEC’s hand.”
Could Oil Prices Fall To $40? - Crude market volatility has soared in the second half of 2018, with prices touching a four year high before entering their longest losing streak in three decades. Analysts were calling for $100 oil but now seem to think prices will head as low as $40. While inventory build-ups and oil traders continue to impact prices in short term, it is the KSA’s (Kingdom of Saudi Arabia) actions in December, a potential hike in U.S. interest rates and a rumbling trade war between China and the U.S. that will really move the market. Between them, these three factors have the potential to drive oil prices in the $40s. It appears that Saudi Arabia and its allies have gone too far in their attempt to avoid a supply shortage as sanctions on Iran loomed. As prices continue to fall, many in the oil market appear to be waiting on another OPEC agreement – but the outcome of OPEC’s meeting in December is far from certain. Trump appears to be against any production cut from OPEC, enjoying the low oil price environment. Russia, responsible for the largest production cut outside of OPEC, also appears to be against joining in with any production cut. While most in the market are expecting some sort of cut from the KSA and its allies, there remains a chance that the cut will either be less than expected or will simply not happen. There have been very few signs from either Beijing or Washington that the trade war will come to an end any time soon. There is, however, a flicker of hope. Trump and Xi are set to meet at the G20 summit at the end of November, with Trump having planned a dinner after the summit where both leaders will try to find a way to end the trade war. If these two superpowers were able to come to an agreement then oil prices would get a significant boost. The U.S economy has been showing robust growth of late and wages have also been increasing. All of this forms a strong case for another interest rate hike when the FOMC (Federal Open Market Committee) meets in December. This would result in a stronger U.S dollar which would make commodities more expensive for other countries to buy. This would lead to a fall in oil prices due to relatively low demand.
Falling oil prices could prompt world leaders to agree on production policy at G-20 summit - A crucial meeting between OPEC and its allies in early December could easily turn into a "formality," analysts have told CNBC, with the world's most influential oil market players likely to iron out production policy in Buenos Aires instead.The heads of the world's 20 largest economies are due to arrive in the Argentinian capital this weekend, where leaders will try to build a consensus on key issues. It comes a week before a much-anticipated meeting between OPEC and non-OPEC producers in Vienna, Austria, on December 6."All eyes are now on the upcoming OPEC meeting, but the get-together could easily turn out to be a formality," Tamas Varga, senior analyst at PVM Oil Associates, said in a research note published Tuesday."It might well be the case that when oil ministers from producing countries sit down a week later in Vienna they will merely make official what was agreed this weekend at the G-20 summit."Oil prices have crashed more than 25 percent since climbing to a four-year high in early October. The sharp decline has ratcheted up the pressure on the OPEC alliance to orchestrate another round of supply cuts.International benchmark Brent crude was trading at $59.71 a barrel Wednesday afternoon, down around 0.8 percent, while West Texas Intermediate (WTI) stood at $51.16, around 0.75 percent lower.OPEC kingpin Saudi Arabia has been leading calls for the oil cartel to trim output in a bid to alleviate concerns of oversupply. Earlier this month, the oil-rich kingdom even went so far as to promise it would be prepared to do "whatever it takes" in order to prevent the return of a supply glut.However, Russia has appeared reluctant to sign-off on a reversal in production strategy. The non-OPEC heavyweight has warned the Middle East-dominated group that it must be careful to ensure it does not end upchanging its course by 180 degrees whenever it meets. Meanwhile, President Donald Trump — who is publicly in favor of low fuel prices — has repeatedly urged OPEC not to cut production.
As Oil Plunges, the Real OPEC Meeting Will Be at Next Week's G20 - For the oil market, it looks like the real OPEC meeting will come a week ahead of schedule. The cartel is set to meet on Dec. 6 in Vienna, but days earlier the key decision makers are set to gather on the sidelines of the G20 summit in Buenos Aires in a meeting that may well decide the direction of oil prices in 2019. Saudi Crown Prince Mohammed bin Salman and Russian President Vladimir Putin, who lead the world’s two largest oil exporters and have been working together to manage the oil market for the past two years, both plan to be in the Argentinian capital at the end of next week. Just as important will be U.S. President Donald Trump, who’s made his opposition to OPEC a regular theme in his Twitter diplomacy. "I expect President Trump will be discussing the optimal price range with Crown Prince Mohamed bin Salman and President Putin at the G20," said Bob McNally, president of Washington consultant Rapidan Energy Advisors LLC and a former White House energy official. The oil market is abuzz with talk that MBS, as Prince Mohammed is known, may not be able to defy Trump’s desire for lower oil prices after the White House supported him following the killing of Washington Post columnist Jamal Khashoggi. "The market is assuming the Saudis won’t be able to cut," said Amrita Sen, chief oil analyst at Energy Aspects Ltd. in London.Khalid Al-Falih and Alexander Novak, the Saudi and Russian energy ministers, are also scheduled to travel to Buenos Aires together with their principals, according to people familiar with their plans, asking not to be named because their agendas haven’t been disclosed yet. Their presence reinforces the impression that Saudi Arabia and Russia will try to reach a deal ahead of the OPEC meeting a few days later.
Oil market power ebbs from OPEC to the troika – Kemp (Reuters) - The Organization of the Petroleum Exporting Countries has been marginalised as critical decisions about the oil market are taken by a troika of the United States, Russia and Saudi Arabia. The rise and subsequent fall in oil prices this year has been almost entirely driven by production decisions in these three countries and their policies towards managing the impact of renewed sanctions on Iran. The troika accounted for 36 million barrels per day of crude and condensates production in 2017 (39 percent of the global total) compared with just 27 million bpd from the rest of OPEC (30 percent of the global total). Troika production has surged even further this year as U.S. shale firms ramped up output in response to higher prices, while Russia and Saudi Arabia relaxed production curbs put in place at the end of 2016. Output from the troika is the fastest-growing element in global oil supplies, which will likely push its share above 40 percent in 2018 while the rest of OPEC falls below 30 percent(“Statistical review of world energy”, BP, 2018). Production decisions made in the troika tend to determine whether the oil market will be over- or under-supplied in the short to medium term, while other OPEC and non-OPEC countries watch from the sidelines. The rest of OPEC is struggling under sanctions, mismanagement and unrest; is too small to matter; is maximising production rather than participating in output controls; or simply aligns its output policies with those of Saudi Arabia. The only OPEC member that operates an independent production policy and has been able to increase its output significantly in 2017/18 has been Iraq. In this context, it is not surprising that the distinction between OPEC and non-OPEC members has become increasingly blurred and decision-making shifted outside the organisation. Discussion and analysis have moved away from OPEC’s twice-yearly ministerial conference to the Joint Ministerial Monitoring Committee (JMMC), which blends OPEC and non-OPEC members. The JMMC contains two leading non-OPEC producers (Russia and Oman) and just four OPEC countries (Saudi Arabia, Kuwait, Algeria and Venezuela) plus the OPEC president (currently the United Arab Emirates). The JMMC’s membership is a tacit admission that non-OPEC Russia and to a lesser extent Oman play a more important role in production policy than most OPEC members.
Oil price slump won't hit most Gulf states — but they're far from out of the woods - The near-panic in oil markets last week and expectations of continued low crude prices are likely to spare key Gulf states' balance sheets, regional analysts say. While many of the Gulf Cooperation Council (GCC) countries' currencies will avoid devaluations, however, the modest economic recovery of the last year is set to falter, with weaker growth expected in the next few quarters. The big question as to the market's direction, meanwhile, depends in large part on the decision of OPEC and non-OPEC members on production cuts in the weeks ahead.As prices hover around 2018 lows and struggle to stay above $60 a barrel, market watchers are reminded of the oil price collapse in 2014 that rocked the hydrocarbon-dependent economies of Saudi Arabia, Kuwait, Bahrain, Qatar, Oman, and the United Arab Emirates. Both global benchmark Brent crude and U.S. West Texas Intermediate (WTI) are down more than 20 percent this month, and if monthly losses continue at the current pace, could see their biggest fall in more than ten years. But according to Capital Economics, prices as low as $40 to $50 a barrel shouldn't put major strains on the larger economies' balance sheets as long as tight fiscal policy is maintained. The fiscal policy reforms of the last few years — subsidy and spending cuts and the introduction of new taxes — will continue but at a more subdued rate than when first implemented, preventing potential currency devaluations and protecting dollar pegs, the consultancy said in a research note published Monday. This means that current accounts in the major Gulf economies — the balance of imports and exports — are likely to stay in surplus.
What Oil at $50 a Barrel Means for the World Economy - Just a couple of months ago, major oil trading houses were predicting the return of $100 crude. Now, with oil prices at half that level, here’s a look at what the slump means for the world economy. Energy importers like India and South Africa will benefit; oil producers such as Russia and Saudi Arabia will hurt. Central banks under pressure to raise interest rates will get a reprieve; those looking to revive prices, such as the Bank of Japan, face another headwind. Ultimately, much depends on how world oil demand shapes up as it gets battered by a stronger dollar and global trade spats, and how the biggest producers react. Saudi Arabia sits between Russia on one side, its ally in managing production to support prices, and the U.S., where President Donald Trump is sending Twitter messages to the producer to get prices down. All eyes are on the Group of 20 meeting this week to see if a consensus on output emerges between the Saudis and Russians, and if that can carry through to the OPEC gathering next week. Here’s a Bloomberg Economics chart showing net oil imports (or exports) as a percentage of GDP -- cheaper oil helps those at the top of the chart and hurts those at the bottom. With the northern hemisphere winter approaching, the oil-price slump will cushion households and businesses during a period of slowing economic growth. Countries that import oil and have current-account deficits, such as South Africa, will also stand to benefit. China is the world’s biggest importer of oil and is already battling a broader moderation in its economy amid a trade war with the U.S. and domestic challenges. What does it mean for inflation? Lower oil prices mean less pressure on inflation and less pressure on central banks to raise interest rates. One example: Bloomberg Economics says the energy slump is a game changer for India and could mean the Reserve Bank of India shifts to a neutral outlook.
Oil prices steady as funds near end of liquidation – Kemp (Reuters) - Hedge fund managers continued to exit from their former bullish positions in crude oil and fuels last week but the worst of the selling may be over, which has helped steady futures prices. Hedge funds and other money managers cut their combined net long position in the six most important petroleum futures and options contracts by another 54 million barrels in the week to Nov. 20. Portfolio managers have slashed their combined net long position by a total of 607 million barrels over the last eight weeks, the largest reduction over a comparable period since at least 2013, when the current data series began, and very likely the largest ever. Long positions were reduced by 55 million barrels to just 752 million barrels, the lowest level since January 2016, at the trough of the bear market (https://tmsnrt.rs/2RhOtvg ). But short positions, betting on a further fall in prices, were trimmed, albeit by just 1 million barrels, the first such reduction in eight weeks. In particular, hedge fund managers reduced short positions in NYMEX and ICE WTI by 10 million barrels, the biggest reduction for 12 weeks. By Nov. 20, WTI prices had declined by 30 percent from their peak and Brent was down 28 percent, which likely convinced many fund managers the scope for further falls was much smaller than before. Long positions accumulated during the bull market in the second half of 2017 and early 2018 have now all been liquidated, and for the moment most managers appear reluctant to add new short positions. The wave of hedge fund selling which has hammered oil prices since the start of October may therefore have run its course for the time being.
Oil prices edge up after nearly 8-percent 'Black Friday' plunge --Oil prices rose on Monday, recovering some of the previous session's sharp declines, although uncertainty over global economic growth limited the gains. Brent crude futures were last up $1.76, or 3 percent, at $60.56 a barrel by 9:40 a.m. ET (1440 GMT). Brent sank 6 percent on Friday.U.S. West Texas Intermediate crude futures were up $1.46, or 2.9 percent, at $51.88 a barrel. The gains partly made up for Friday's 7.7 percent drop. "The recent weakness seems dramatic given the lack of actual catalysts - it seems to have been driven by a wider impending sense of doom amidst weak equities, geopolitics, subsequent softening demand and increasing supply," The International Energy Agency predicts global oil demand will top 100 million barrels a year in 2019, growing at a rate of 1.4 million barrels per day, but this is down from its initial assessment in June of 1.5 million bpd. A rising dollar that has undercut demand in key emerging market economies, higher borrowing costs and the threat to global growth from the escalating trade dispute between the United States and China have pushed investors out of assets that are more closely aligned with the global economy, such as equities or oil. In November alone, hedge funds have pulled more than $12 billion out of the oil market, based on a record drop in net long holdings of Brent and U.S. crude futures and options against the average oil price for the month. Analysts at Fitch Solutions said that even an expected supply cut led by OPEC following an official meeting on Dec. 6 "may not be enough to counteract the bearish forces." "2019 will be a choppy year for the oil market as questions surrounding the prospect of a slowing global economy and a supply surplus are expected to increase," The options market shows that investors in Brent crude, which is more closely linked to OPEC output, have increased their holdings of contracts that give the owner the right, but not the obligation, to sell oil futures below the current benchmark futures price, by 10 percent.This compares with an increase of just 4.5 percent in holdings of options that give the owner the right to buy oil futures above the current price by a certain date.
Saudis Confuse Traders By Pumping A Record Amount Of Oil As Goldman Top Trade Says Buy - After crashing by a dramatic 8% on Friday, and tumbling to one year lows, crude is attempting a feeble rebound this morning on hopes the OPEC meeting next week will result in new production curbs by OPEC+. However, trader optimism has been dented by overnight news that Saudi Arabia raised oil production to an all-time high in November, boosting its output well beyond the quota that had been agreed upon in the Vienna 2016 OPEC summit, and prompting fresh doubts if Riyadh is sincere about cutting output.Reuters cited an industry source, who said Saudi crude oil production hit 11.1-11.3 million barrels per day (bpd) in November, an all time high. That levels is up around 0.5 million bpd - equal to 0.5% of global demand - from October and more than 1 million bpd higher than in early 2018, when Riyadh was curtailing production together with other OPEC members.Saudi Arabia agreed to raise supply steeply in June, in response to calls from consumers, including the United States and India, to help cool oil prices and address a supply shortage after Washington imposed sanctions on Iran. However, the move backfired on Riyadh after Washington imposed softer than expected sanctions on Tehran. That promptly triggered worries of a supply glut and Brent collapsed to below $60 per barrel on Friday from as high as $85 per barrel in October. Russia, which teamed up with Saudi Arabia in the first OPEC joint production cuts since 2016, also raised production steeply in recent months to a post-Soviet high of 11.4 million bpd, as the world suddenly found itself awash in excess oil, and leading to a spike in oil inventories. Ironically, Saudi oil industry sources have signaled they wanted prices to stay above $70 per barrel and Saudi energy minister Khalid al Falih said this month global oil supply could exceed demand by over 1 million bpd next year, requiring OPEC to take action. Yet as so often happens, it was Saudi Arabia - OPEC's swing producer - that was instrumental for much of the excess production that has sent oil prices tumbling. And while Falih said earlier this month that state oil giant Saudi Aramco would ship 0.5 million bpd less crude in December than in November as demand from customers was lower, he now faces a formidable adversary to any stated production cut: US president Trump.
Factbox- Markets weigh risks of Kerch Strait escalation — Tensions in the Kerch Strait shipping route escalated over the weekend after Russia seized three Ukrainian naval vessels in the Sea of Azov off Crimea. Despite heightened political risk in the area, Russia's energy flows to international markets are unlikely to be disrupted by the dispute. Moscow and Kiev blame each other for the incident, which occurred Sunday. Ukraine is a major transit route for Russian gas to Europe, with 94 Bcm sent via the Ukrainian network to Europe and Turkey in 2017. These flows are equal to 20% of total European consumption. Russia produced 690 Bcm of gas in 2017 and exported 224 Bcm, making it the world's biggest gas exporter. Russia is currently the world's second-biggest oil producer after being overtaken by the US earlier this year. Russian crude output rose to 11.4 million b/d in October, according to the International Energy Agency. Ukraine's crude oil and gas condensate output increased 3.2% year-on-year to 1.618 million mt in January through September. Most of Ukraine's own crude imports are sourced from Azerbaijan, accounting for 95% of the country's imports. In 2017, Ukraine's imports of crude increased 96% on the year to 1.01 million mt. Russia is the largest exporter of wheat globally. In the last marketing year, it shipped over 41 million mt. The main markets include the Middle East, North Africa and Southeast Asia. Russia has a 27% share of the imported European wheat market. Ukraine is the fourth-largest exporter of corn globally. It shipped over 18.5 million mt of corn last year. It is the number one exporter to the EU and a big supplier to the Middle East and North Africa. Ukraine has almost 40% of the EU's import corn market share. European natural gas prices were unmoved in early trade Monday, with the UK NBP December contract down 4% at 65.10 p/th. There has been no obvious impact on crude oil prices.
Oil breaks above $60/bbl, but doubts about growth curb gains - (Reuters) - Oil prices rose nearly 3 percent on Monday, clawing back some of last week’s steep losses, but gains were capped by uncertainty over global economic growth and further signs of increasing supply, including record Saudi production. Brent crude futures rose $1.68 to settle at $60.48 a barrel, a 2.9 percent gain. U.S. West Texas Intermediate (WTI) crude gained $1.21, or 2.4 percent, to close at $51.63 a barrel. Prices on Friday hit their lowest since October 2017 amid intensifying fears of a supply glut. Brent sank to $58.41 a barrel, while WTI fell to $50.15 a barrel. “We are reluctant to read much into today’s oil price advance given a much oversold technical condition that needed only a moderate stock market rally to force some short covering,” Jim Ritterbusch, president of Ritterbusch and Associates, said in a note. Supporting oil prices, U.S. stock markets broadly rallied as Cyber Monday, the largest online shopping day of the year, began. Crude futures sometimes track with the equities market. Prices found some support as crude stockpiles at the delivery point for WTI at Cushing, Oklahoma, rose just 126 barrels from Tuesday to Friday, traders said, citing a report from market intelligence firm Genscape. However, demand concerns and record output from Saudi Arabia limited Monday’s rebound. Saudi crude oil production hit 11.1-11.3 million barrels per day (bpd) in November, an all-time high, an industry source said. A rising dollar that has undercut demand in key emerging market economies, higher borrowing costs and the threat to global growth from the trade dispute between the United States and China have pushed investors out of assets more closely aligned with the global economy, such as equities or oil. Hedge funds and other money managers raised their bullish position on U.S. crude for the first time in 8 weeks in the week that ended Nov. 20, the U.S. Commodity Futures Trading Commission (CFTC) said on Monday. The increase was the first since September and lifted net longs from their lowest point in more than a year.
Oil Dips After Biggest Gain in 2 Months -- Oil fell after rising the most in almost two months as major oil exporters prepare to discuss output policy amid rising price volatility. Futures in New York lost as much as 1 percent after a 2.4 percent gain Monday. All eyes are on this week’s G20 meeting in Argentina, which will include Saudi Crown Prince Mohammed Bin Salman and Russian President Vladimir Putin, before OPEC meets next week in Vienna. Meanwhile, U.S. crude inventories are seen falling for the first time in 10 weeks in a Bloomberg survey before government data Wednesday. Oil has collapsed into a bear market on fears of a supply glut amid a toxic mix of America’s unexpected sanctions waiver for Iranian oil, a record Saudi output and surging U.S. production. Also, rising trade tensions between the U.S. and China cloud the outlook for demand. Speculation is swirling over whether the Organization of Petroleum Exporting Countries and its allies will curb output when they meet on Dec. 6, despite President Donald Trump’s call for lower prices. “A tug-of-war between President Trump and oil producers will continue through the OPEC meeting,” said Satoru Yoshida, a commodity analyst at Rakuten Securities Inc. in Tokyo. “Oil could remain volatile until the meeting, which will determine the direction of prices.” West Texas Intermediate for January fell as much as 52 cents to $51.11 a barrel on the New York Mercantile Exchange and traded at $51.25 at 4:20 p.m. in Tokyo. The contract rose $1.21 to $51.63 on Monday after plunging about 11 percent last week, the most since January 2016. Total volume traded was 16 percent above the 100-day average. The Cboe/Nymex WTI Volatility Index fell on Monday from the highest level since early 2016 reached last Friday. Brent for January settlement slid 21 cents to $60.27 a barrel on London’s ICE Futures Europe exchange. The contract added $1.68 to at $60.48 on Monday. The global benchmark traded at a $8.97 premium to WTI.
Saudi Arabia Struggles As Oil Prices Crash - Oil prices are struggling to find a bottom, moving up on Monday but floundering in early trading on Tuesday. A few weeks ago, rumors floated of a potential aggressive production cut at the upcoming OPEC+ meeting, perhaps as large as 1.4 million barrels per day. However, that now looks unlikely, as President Trump has simultaneously protected Saudi Arabia from international outrage over the Khashoggi murder, at the same time that he has pressured them into keeping oil prices low. Russia is also not keen on a large production cut. That leaves Saudi Arabia looking for a “quiet cut,” which would mean taking production back down to previously agreed upon production limit – around 10 mb/d, down from the current 11 mb/d. The pressure campaign by the White House to deter OPEC+ from cutting production could succeed in keeping crude prices low, but prices are approaching a level that could damage U.S. shale companies. “We're at the point where we're nearing full cycle break-evens for Permian producers and depending on how long this lasts, we might see an impact on capex budgets over the next few months,” Muhammed Ghulam, senior research associate at Raymond James, told CNBC.. Saudi Aramco’s CEO told Bloomberg that the company will spend $500 billion over the next decade to transform itself into a major refiner and petrochemical maker, not just an oil producer. “Saudi Aramco will make the most of those prospects with global investments in the chemicals space of roughly $100 billion over the next 10 years -- in addition to prospective acquisitions,” Aramco CEO Amin Nasser said. In total, Nasser outlined $500 billion in spending plans. Long-term oil demand is looking increasingly fragile, but the petrochemical sector is where most demand growth will be concentrated, according to the IEA. Saudi Arabia is clearly itching for a production cut at the OPEC+ meeting next week, but Russia is much more hesitant. Russian oil firms are opposed to curtailing output, and the Russian economy does not benefit as much from higher prices than the Saudi economy does. Still, President Vladimir Putin has strategic reasons to keep up the partnership with Saudi Arabia. But after the production increases in June backfired, Moscow and Riyadh are not exactly on the same page anymore.
Oil prices- Saudi Arabia isn't hurting from the crash yet - Oil prices have crashed 30% in a matter of weeks but Saudi Arabia isn't hurting just yet. The OPEC kingpin and world's leading oil exporter would like a higher price, and has suggested it will back a production cut when the cartel meets next week. But in hard economic terms Saudi Arabia could bear even lower prices, and that would keep its key ally — President Donald Trump — happy at a time when the kingdom really needs its friends. US crude oil is now trading at $51 a barrel, off a peak of $76 a barrel in early October, while Brent crude has plunged to $60 from above $86. "Even if [Brent] prices fall further to $40-$50 a barrel, immediate balance of payments strains are unlikely to emerge," Capital Economics said in a report this week about the impact of the slump on Gulf countries. "That said, these economies are by no means out of the woods," it added. Prices could even drop to $30 a barrel and Saudi Arabia would still be able to finance the gap between its export and imports "from their foreign exchange savings for at least a decade," Capital Economics said. A fall of that magnitude would cause budget pressure, however. Analysts estimate the Saudi government's budget for 2018 is based on a conservative price of $50-$55 a barrel. The cost of pumping a barrel of oil in Saudi was less than $10 in 2015, and is unlikely to have changed much since. Saudi Arabia would like higher prices to fuel its economy, which contracted in 2017 and is projected to grow by just a little over 2% this year, according to the International Monetary Fund.
WTI Extends Rebound Despite 10th Weekly Crude Build In A Row -- WTI rebounded strongly intraday, after testing down to cycle lows near $50 during the morning, pushing $52 ahead of the API report that was expected to show a 10th weekly crude build in a row.“In this trading environment where all the moves that we see are exacerbated, the idea that the oil market has found a bottom doesn’t seem to be taking hold yet," said Gene McGillian, senior analyst and broker at Tradition Energy in Stamford, Connecticut.API:
- Crude +3.453mm (+700k exp)
- Cushing +1.302mm
- Gasoline -2.602mm
- Distillates +1.185mm
Last week's tiny 116k barrel draw at Cushing broke its build streak (no up 10 of 11 weeks) but Crude saw its 10th consecutive weekly build (and Distillates broke the 9 week draw streak with a 1.185m build)... WTI was drifting higher ahead of the API print and kneejerked above $52 after the print...
Oil prices steady near year lows ahead of G-20 and OPEC - Oil prices steadied on Tuesday, depressed by record Saudi production but supported by expectations that oil exporters would agree to cut output at an OPEC meeting next week.Brent crude oil was up 11 cents a barrel at $60.59, hovering above a 13-month low of $58.41 reached on Friday. U.S. light crude rose 6 cents to $51.69.Oil prices have lost almost a third of their value since early October, weighed down by an emerging supply overhang and widespread financial market weakness."The oil price correction has become a rout of historic proportions," U.S. investment bank Jefferies said in a note."The negative price reaction is as severe as the 2008 financial crisis and the aftermath of the November 2015 OPEC meeting, when the group decided not to act in the face of a very over-supplied market," the bank said. Saudi Arabia raised oil production to an all-time high in November, an industry source said on Monday, pumping 11.1 million to 11.3 million barrels per day (bpd).But the kingdom has been pushing for a collective production cut by members of the Organization of the Petroleum Exporting Countries, indicating it may reduce supply by 500,000 bpd. Norbert Ruecker, head of commodity research at Swiss bank Julius Baer, said oil had buckled after "a surprisingly swift and pronounced change in the market mood from shortage fears to glut concerns" while the world economy was also slowing down.
Oil prices fall more than 1 percent ahead of G20, OPEC meeting (Reuters) - Oil prices dipped on Tuesday, weighed down by uncertainty over the U.S.-China trade war and signs of increased global crude production, but losses were limited by expectations that crude exporters would agree to cut output at an upcoming OPEC meeting. Brent crude LCOc1 futures fell 27 cents to settle at $60.21 a barrel. U.S. West Texas Intermediate (WTI) crude CLc1 futures fell 7 cents to settle at $51.56 a barrel. Prices fell to their lowest since October 2017 last week - Brent at $58.41 and WTI at $50.15. Both crude benchmarks are down more than 30 percent since early October, depressed by an emerging supply overhang and widespread financial market weakness. Market participants looked ahead to a meeting of leaders of the Group of 20 nations (G20), the world’s biggest economies, on Nov. 30 and Dec. 1, with the trade war between Washington and Beijing top of the agenda. U.S. President Donald Trump is open to a trade deal with China but is prepared to hike tariffs on Chinese imports if there is no breakthrough on longstanding trade irritants during a Saturday night dinner with Chinese leader Xi Jinping, White House economic adviser Larry Kudlow said on Tuesday. The White House sees the dinner as an opportunity to “turn the page” on a trade war with China. But he said the White House has been disappointed so far in the Chinese response to trade issues. “The current tariffs have already hurt the global economy and the looming escalation only dampens the petroleum demand outlook further,” said John Kilduff, a partner at Again Capital Management in New York. (Graphic: Brent crude oil price slumps of 2008, 2014/2015 & 2018 in percent - tmsnrt.rs/2RiWkJ1) The top three crude producers, Russia, the United States and Saudi Arabia, will be at the G20 Summit, raising expectations that oil policy will be discussed. The Organization of the Petroleum Exporting Countries will meet on Dec. 6 in Vienna to discuss output policy with some non-OPEC producers, including Russia. Saudi Arabia raised oil production to a record high in November, an industry source said on Monday, pumping 11.1 million to 11.3 million barrels per day (bpd). But the kingdom has been pushing for a collective production cut and is discussing a proposal to curb output by OPEC and its allies by as much as 1.4 million bpd, sources close to the discussions told Reuters this month.
US Crude Oil Inventories Up A Whopping 3.6 Million Bbls; Now Over 7% Of The Five-Year Average -- Link here.
- US crude oil inventories: increased by another whopping 3.6 million bbls
- inventories now stand at 450.5 million bbls -- breaking through 450 million bbls -- wow
- inventories now 7% above the five-year average for this time of the year -- wow
- WTI, right now, holds steady, drops about 50 cents; barely holding above $51
- refinery operating capacity at: 95.6% -- fairly high, considering
- both gasoline and distillate fuel production slightly higher than their 10.0 and 5.0 - million benchmark
- imports slightly more than same time last year -- refineries need heavy oil to balance light oil; California needs imported oil
- jet fuel produced: up 4.1% compared with same time last year
- by the way, that "five-year average" continues to increase. One needs to look at the historical "norm" -- which for me is 350 million bbls -- 450 is 28.5% greater than the 350-million benchmark
WTI Tumbles After 10th Consecutive Weekly Crude Build - After an initially confusing bounce in WTI (after API reported a bigger than expected crude build), oil prices have resumed their drop overnight ahead of this morning's DOE data.Notably, Bloomberg Intelligence Senior Energy Analyst Vince Piazza points out that today's inventory data should have limited sway over sentiment, as the market looks ahead to talks between Saudi Arabia and Russia as well as broader discussions among OPEC members next month. We're less than convinced that cuts of about 1 million barrels a day will stabilize crude benchmarks, even though recent harsh price weakness is unsustainable and is approaching extremes. Russia is incentivized to maintain output close to current levels to manage gasoline prices. DOE:
- Crude +3.58mm (+2.53mm exp) - 10th weekly build in a row
- Cushing +1.177mm
- Gasoline -764k
- Distillates +2.61mm
DOE confirmed API's 10th consecutive weekly crude build (bigger than expected) but a big build in distillates broke the nine-week draw streak. US Crude production continues at a record pace - outstripping Russia and Saudi... “A significant production cut on the part of OPEC and its allied non-OPEC producers at their meeting next week in Vienna will thus be needed to re-balance the oil market next year and ensure that stocks do not rise any further,” said Carsten Fritsch, an analyst at Commerzbank AG in Frankfurt. WTI is tumbling after the crude and distillates build...
Crude Oil Slips but Gas Surges - At one point Wednesday, the January West Texas Intermediate (WTI) crude oil price was just seven cents above the $50 mark. After making a slight recovery, however, the WTI settled at $50.29 a barrel – a $1.27 day-on-day decline. The WTI peaked at $52.56 during the midweek session. Also losing ground Wednesday was the January Brent futures price, which fell by $1.45 to settle at $58.76 a barrel. “The weekly chart for WTI crude oil shows the market breaking our major support levels earlier this month,” said Jerry Rafferty, president and CEO of Rockville Center, N.Y.-based Rafferty Commodities Group, Inc. “The close below the 6400 area was significant and had caused us to turn bearish.” Shortly after the sub-6400 close, Rafferty on Nov. 7 told Rigzone “it would not surprise us to see the WTI market retest the 5450 level which was the original breakout area.” “There was a bounce from the 5450 area up to the 5800 area, and prices have since tumbled to the 5000 area where we have listed major support,” Rafferty said Wednesday. “We like buying against the 5000 area for January WTI and selling as the market approaches our resistance at 5461. If prices close below the 5000 level, there is plenty of room on the downside for prices to head lower.” Like crude oil, reformulated gasoline (RBOB) declined Wednesday. The December RBOB contract price lost two cents to settle just under $1.40 a gallon. December Henry Hub natural gas futures, meanwhile, posted an impressive double-digit gain. The benchmark surged 45 cents Wednesday to settle at $4.715. Rafferty told Rigzone that his firm’s daily continuation chart for natural gas shows the series of breakouts above major resistance levels that have propelled the market to levels not seen in four years.
Oil prices fall on rising US crude stockpiles, OPEC uncertainty -- Oil prices fell on Wednesday, pressured by a 10th consecutive rise in U.S. crude inventories and doubts over whether agreement on an OPEC-led output cut will be achieved next week. U.S. crude stockpiles rose by 3.6 million barrels in the week through Nov. 23, the U.S. Energy Information Administration said on Wednesday. That compared with analysts' expectations for an increase of 769,000 barrels in a Reuters poll. Brent crude, the global benchmark, was down 73 cents, or 1.2 percent, at $59.48 a barrel by 10:43 a.m. ET (1543 GMT), after trading as high as $61.27. U.S. West Texas Intermediate crude fell 42 cents to $51.14.Stockpiles at the Cushing, Oklahoma delivery hub for WTI crude rose by 1.2 million barrels, EIA said.Gasoline stocks fell by 764,000 barrels, compared with analysts' expectations for a 640,000-barrel gain. Distillate stockpiles, which include diesel and heating oil, rose by 2.6 million barrels, versus expectations for a 857,000-barrel drop, the EIA data showed.Saudi Arabia also dampened hopes of production cuts by OPEC and its allies by saying on Wednesday that it would not act alone and Nigeria stopped short of committing to a new push to curb supplies.The outcome of next week's OPEC meeting "remains clouded by uncertainty," "Elsewhere, a glut of stored oil in the U.S. shows no sign of waning."The price of Brent has slumped by more than 30 percent from a four-year high above $86 in early October, pressured by concerns that supply will exceed demand in 2019 as economic growth slows. OPEC plus Russia and other allies meet on Dec. 6-7. Producers are discussing a supply curb of 1 million to 1.4 million barrels per day (bpd) and possibly more, OPEC delegates have told Reuters.
Oil settles at lowest in over a year, with U.S. prices sliding toward $50 - Oil futures dropped Wednesday to settle at their lowest in more than a year, sending U.S. prices sliding toward $50 a barrel on the back of a 10th straight weekly rise in U.S. crude stockpiles. Trading was volatile Wednesday, with prices down ahead of the supply data, then moving higher as remarks from Federal Reserve Chairman Jerome Powell appeared to imply fewer future interest-rate hikes, putting pressure on the U.S. dollar. West Texas Intermediate crude for January delivery lost $1.27, or 2.5%, to settle at $50.29 a barrel on the New York Mercantile Exchange. January Brent crude the global benchmark, declined $1.45, or 2.4%, to $58.76 a barrel on ICE Futures Europe. Both benchmarks marked their lowest finish for a front-month contract since October 2017, according to Dow Jones Market Data. Oil had seen earlier gains, with the benchmark ICE U.S. Dollar Index trading 0.6% lower after Powell used a softer tone to describe where interest-rate policy presently stood. Commodities priced in dollars often trade inversely with the dollar. Early Wednesday, however, the Energy Information Administration reported that domestic crude supplies rose by 3.6 million barrels for the week ended Nov. 23. That followed weekly increases over each of the past nine weeks. The string of 10 increases is the longest run since autumn 2015. The data was expected to show a 500,000 barrel increase in crude stocks, according to a poll of analysts and traders conducted by The Wall Street Journal, though analysts surveyed by S&P Global Platts had forecast a decline of 430,000 barrels. The American Petroleum Institute on Tuesday reported a rise of roughly 3.5 million barrels. At 450.5 million barrels, U.S. oil inventories are at their highest since Thanksgiving week in 2017 and “have climbed by more than 56 million barrels since mid-September,” he said. Oil prices are also “nearly 30 percent lower since oil inventories started their ascent 10 weeks ago.” Gasoline stockpiles fell by 800,000 barrels last week, while distillate stockpiles rose by 2.6 million barrels, according to the EIA. S&P Global Platts survey had shown expectations for a supply rise of 141,000 barrels in gasoline, but forecast a fall of 315,000 barrels in distillate inventories. On Nymex, December gasoline fell 12.6% to $1.398 a gallon, while December heating oil lost 2.5% to $1.838 a gallon.
Oil strengthens ahead of G20 meeting, but supply rise caps gains -- Oil reversed course and rose on Thursday, after industry sources said Russia had accepted the need to cut production, together with OPEC. The price is still set for its biggest one-month fall in November since the depths of the financial crisis in 2008, having lost more than 22 percent so far. Brent crude futures were last up 71 cents, or 1.2 percent, at $59.47 a barrel, off an earlier session low of $57.50. U.S. crude futures rose 81 cents, or 1.6 percent, to $51.10, after earlier dropping below $50 for the first time in over a year. OPEC and non-OPEC producers meet in Vienna next week to discuss a new round of supply cuts of 1 million to 1.4 million barrels per day (bpd) and possibly more to prop up prices. The Russian Energy Ministry held a meeting with the heads of domestic oil producers on Tuesday. "The idea at the meeting was that Russia needs to reduce. The key question is how quickly and by how much," said one source familiar with the talks between Russian oil firms and the ministry. Russian President Vladimir Putin, whose country is the world's second biggest oil producer, said on Wednesday he was in touch with OPEC and ready to continue cooperation on supply if needed, but he was satisfied with an oil price of $60. U.S. crude inventories have hit their highest in a year, and are now only 80 million barrels below March 2017's record 535 million barrels, according to the Energy Information Administration. "WTI oil is now trading right around the $50 per barrel level, a price last seen well over a year ago, as the current oversupply situation has now manifested itself in 10 consecutive weekly increases in U.S. oil inventories," said William O'Loughlin, investment analyst at Australia's Rivkin Securities.
WTI oil price slides under $50 per barrel- One of the world's major oil contracts, New York's WTI, slumped under $50 per barrel on Thursday, reaching the lowest level in nearly 14 months. WTI and Brent North Sea crude, another benchmark contract, have been tumbling for weeks on fears of a supply glut -- despite oil kingpin Saudi Arabia planning an output cut and urging other producer nations to follow suit. WTI hit as low as $49.41 per barrel, the lowest point since October last year. Around 1025 GMT and after a slight recovery, WTI stood at $49.83, down 46 cents compared with Wednesday's close. Brent was down 63 cents at $58.13.
Oil Falls Below $50 for First Time in Over a Year - -- Oil crashed below $50 a barrel for the first time in more than a year as Russia signaled little urgency to commit to supply cuts, while U.S. crude stockpiles continue to grow. Futures tumbled as much as 1.8 percent in New York, after sliding 2.6 percent in the previous two sessions. Just days before talks on oil policy with Saudi Arabia, Russian President Vladimir Putin said current prices are “absolutely fine”, while Saudi energy minister said the kingdom is confident OPEC and its partners can reach a deal to stabilize the market. U.S. crude inventories rose for a 10th week, government data show. Crude has crashed into a bear market after America’s surprise sanctions waivers for Iranian oil fueled concern over a supply glut. As prices plunged, traders’ focus turned to G20 summit this week in Argentina where Russian leader and Saudi crown prince are expected to discuss production. The market is flirting with expectations that the Organization of Petroleum Exporting Countries and allied producers may agree on output curbs at their gathering next week in Vienna. “Putin’s comments raised speculation that Russia may not join its fellow producers in curbing production,” Sungchil Will Yun, Seoul-based commodity analyst at HI Investment & Futures, said by phone. “At the same time, we have expanding American crude stockpiles and they are unlikely to shrink in the near future.” West Texas Intermediate for January delivery fell as low as $49.41 a barrel on the New York Mercantile Exchange, the least since Oct. 9, 2017. The contract declined 2.5 percent to settle at $50.29 on Wednesday, the lowest close since October 2017. Total volume traded was 84 percent above the 100-day average. Brent for January settlement, which expires Friday, fell as much as 2.1 percent to $57.50 a barrel on London’s ICE Futures Europe exchange. The global benchmark traded at an $8.26 premium to WTI. The more-active February contract lost 1.3 percent. While Putin praised Saudi Crown Prince Mohammed Bin Salman and said Moscow is ready to cooperate further, he said crude around $60 a barrel is “balanced and fair” and well above the level needed to keep his government’s budget in surplus.
Oil falls as high inventories outweigh likely OPEC cuts -- Oil prices fell further on Friday as swelling inventories depressed sentiment, despite widespread expectations that OPEC and Russia would agree some form of production cut next week. The two global oil benchmarks, North Sea Brent and U.S. light crude, have had their weakest month for more than 10 years in November, losing more than 20 percent as global supply has outstripped demand. Brent was down 77 cents, or 1.3 percent, at $58.74 a barrel, having bounced from a session low of $58.25. U.S. West Texas Intermediate was down 23 cents, or half a percent, at $51.22, after earlier falling as low as $49.65. Surging oil production in the United States, Russia and by members of the Middle East-dominated Organization of the Petroleum Exporting Countries has helped fill global inventories and create a glut in some markets. A slowdown in oil demand growth is compounding the emerging oversupply. "Near-term oversupply has gutted Brent prices," said Jason Gammel, analyst at U.S. investment bank Jefferies, adding that there was "an increasing urgency to move crude into storage." This move is visible in the Brent forward price curve, which now has prices for future delivery above those for immediate dispatch, a structure known as "contango", which can make it attractive to put oil into storage for later sale. To rein in the glut, OPEC and its main partner Russia are discussing supply cuts and are due to meet in Vienna on Dec. 6 and 7 to agree production strategy. "The next OPEC meeting is going to prove a pivotal moment for the direction of oil prices in 2019," BNP Paribas strategist Harry Tchilinguirian told Reuters Global Oil Forum. "A decision will have to be made against a background of strong U.S. shale oil supply growth, and for now, weaker expectations on global oil demand growth."
Oil Prices Fall On Demand Worries - Oil prices resumed declines on Friday amid worries about falling demand after China reported its weakest factory growth in more than two years. Global benchmark Brent crude dropped 0.88 percent to $59.38 per barrel while U.S. West Texas Intermediate (WTI) crude futures were down 1.46 percent at $50.70 per barrel. China's manufacturing PMI stood at 50.0 in November, missing expectations for a score of 50.2, which would have been unchanged from the October reading. The non-manufacturing PMI came in with a score of 53.4 - also shy of expectations for 53.8 and down from 53.9 in the previous month, adding to signs of slowing growth in the world's second-largest economy. Amid deep divisions between the U.S. and China over international trade, analysts expect little progress on trade on the sidelines of the G20 summit in Argentina this weekend. U.S. President Donald Trump told reporters on Thursday that he was close to doing something on trade with China but is not sure if he wanted to do it. Traders also await the outcome of OPEC meeting in Vienna next week amid expectations that OPEC and Russia would agree some form of production cuts in view of an emerging supply glut.
Crude Oil Avoids Massive Sell-off for Week - Rigzone - The January West Texas Intermediate (WTI) contract price lost 52 cents Friday to settle at $50.93 a barrel. The benchmark bottomed out at $49.65 and peaked at $51.79 during the end-of-week session. The price of a barrel of Brent crude oil for January delivery remained flat Friday, settling at $59.51. “WTI and Brent continued trading lower for the eight straight week this week after last Friday’s plunge,” said Tom Seng, Assistant Professor of Energy Business with the University of Tulsa’s Collins College of Business. “Brent breached critical support of $60 then and failed to rise back above that level this week. Both oil markets were somewhat range-bound this week, but WTI fell below the critical $50 support level twice. A massive sell-off was avoided, however, as prices managed to rally back over $50 late.” The Brent last traded at similar levels in Oct. 2017 and the WTI in Sept. 2017, Seng added. He also noted that both benchmarks have lost more than 30 percent of their value since peaking in early October. Moreover, he said that the collapse in prices has contracted the WTI-Brent spread to approximately $7.50. “Fundamentally, the market view is still one of oversupply coupled with declining global demand,” Seng explained. “The ‘back-and-forth’ news coming out of the OPEC+ (OPEC and Russia) has only added to the market’s volatility.” Jason Feer, global head of business intelligence with Poten & Partners, noted that oil prices remain in a “holding pattern” pending the decision by OPEC members and Russia on whether to curb output. “Signals from Saudi Arabia and Russia indicate that some sort of reduction in output is likely but there are concerns that the cuts may be too small to provide significant support to prices,” Feer said. “An OPEC committee has recommended a reduction of 1.3 million barrels per day (MMbpd), but there are fears that rising U.S. production could offset much of that. Despite falling oil prices, U.S. production reached nearly 11.5 MMbpd in September and October is expected to be higher still when the final numbers are tallied.”
US crude plunges 22% in November, settling at $50.93, for weakest month in over 10 years -- Oil prices fell further on Friday as swelling inventories depressed sentiment despite widespread expectations that OPEC and Russia would agree some form of production cut next week. The two global oil benchmarks, North Sea Brent and U.S. light crude, have had their weakest month for more than 10 years in November, losing more than 20 percent as global supply has outstripped demand. U.S. West Texas Intermediate was down 52 cents, or 1 percent, at $50.93, after earlier falling as low as $49.65 Brent was down 76 cents, or 1.3 percent, at $58.75 a barrel by 2:28 p.m. ET, having bounced from a session low of $58.25. Prices pared losses from session lows after Bloomberg reported OPEC's advisory committee suggested decreasing production by 1.3 million barrels per day (bpd) from last month's levels, traders said. "Oil prices bounced back late in the day on Friday on reports that the OPEC committee had suggested a 1.3 million barrel per day cut from the October level," "The pressure has certainly been building as prices continued to fall amid ongoing concerns over excessive supply and lower demand growth ... If no action is taken, oil prices could certainly drop further, while a production cut should lead to a sizeable rebound for these severely oversold levels." OPEC and its main partner Russia are due to meet in Vienna on Dec. 6 and 7 to agree production strategy. Before the OPEC meeting, the world's top three producers — the United States, Russia and Saudi Arabia — will be part of a meeting this weekend of the Group of 20 industrialized nations in Buenos Aires, Argentina. Russia's energy minister Alexander Novak will meet his Saudi counterpart at the G20 summit in Argentina and discuss an oil output reduction in 2019, RIA news agency cited Novak as saying on Friday. He was also reported to have said that Russia's 2019 oil output is expected at the same level as this year but could be adjusted, depending on a deal between OPEC and non-OPEC members.
Saudi Arabia wants united front on oil output; Russia and Nigeria hold out (Reuters) - Saudi Arabia will not cut oil output on its own to stabilize the market, Energy Minister Khalid al-Falih said on Wednesday as Nigeria and Russia said it is too early to signal whether they would join any production curbs. Oil producer group OPEC and its allies, led by Russia, meet in Vienna next week against the backdrop of concerns over a slowing global economy and rising oil supplies from the United States, which is not involved in an existing agreement to restrain output. The negative economic outlook helped to push oil LCOc1 below $60 a barrel this week from as high as $85 in October, prompting Saudi Arabia, the de facto leader of the Organization of the Petroleum Exporting Countries (OPEC), to suggest significant production cuts. Riyadh, however, has come under renewed pressure from U.S. President Donald Trump, who asked the kingdom to refrain from output reductions and help to lower oil prices further. Possibly complicating any decision on oil output is the crisis around the killing of journalist Jamal Khashoggi at the Saudi consulate in Istanbul last month. Trump has backed Saudi Crown Prince Mohammed bin Salman despite calls from many U.S. politicians to impose stiff sanctions on Riyadh. Falih was in Abuja to meet his Nigerian counterpart Emmanuel Ibe Kachikwu. The Saudi minister said signals from fellow OPEC members Iraq, Nigeria and Libya were positive ahead of the group’s Dec. 6 talks because all ministers want to restore oil market stability. “We are going to ... do whatever is necessary, but only if we act together as a group of 25,” Falih told reporters, referring to OPEC and its allies. “As Saudi Arabia we cannot do it alone, we will not do it alone. “Everybody is longing (to) reach a decision that brings stability back to the market ... I think people know that leaving the market to its own devices with no clarity and no collective decision to balance the market is not helping.”
Saudi Arabia Squeezed As OPEC Meeting Nears - Oil prices dipped in early trading, but the next few days will be volatile. First, any news from the G20 summit on the Trump-Xi meeting regarding the trade war could have ramifications for the global economy and oil demand heading into 2019. But much of next week will be characterized by whatever jawboning or rumors come out of upcoming OPEC meeting. For now, oil is downbeat but awaiting direction. . Saudi Arabia is aiming to cut oil production in order to boost prices, but the recent vote by the U.S. Senate to end the war in Yemen, even if it doesn’t become law, heightens the pressure on Riyadh to assuage American concerns. That gives President Trump more leverage as he demands lower oil prices from Saudi officials. Riyadh faces a choice between accepting painfully low oil prices or defying Washington by cutting production. Reports suggest they are going to try to thread the needle, opting for modest cuts that at least put a floor beneath crude prices. “President Trump has effectively put a ceiling on oil prices -- arguably this ceiling is about $70 a barrel Brent, maximum $75,” Thibaut Remoundos, founder of Commodities Trading Corporation Ltd., told Bloomberg. “It will be interesting to see if Saudi-Russia can keep the floor in place.” . Many members of the OPEC+ coalition want Saudi Arabia to do all of the heavy lifting when it comes to production cuts. After all, they argue, Saudi Arabia was the one that added 1 million barrels per day of fresh supply since May. The Saudis “made this mess. They need to clean it up,” a Middle Eastern oil official told the Wall Street Journal. On Wednesday, Saudi oil minister Khalid al-Falih indicated that Saudi Arabia would not cut alone.. The Trump administration is taking an early but critical step that could pave the way to oil exploration in the Atlantic Ocean. According to Bloomberg, the National Marine Fisheries Service could allow seismic surveying by five companies in the Atlantic, a precursor to exploration. Seismic testing is essential to exploration, but is highly controversial because of its effect on marine animals such as whales and dolphins.
Why a critical OPEC meeting may end with confusion and lower oil prices - When OPEC reached a deal with Russia and other producers in 2016 to end a two-year oil price slump, it was a relatively straightforward affair. The alliance announced it was slashing output, each country agreed to a specific production quota and international oil prices rallied about $7 a barrel. Heading into next week's OPEC meeting, few analysts anticipate such decisive action or so clear-cut an outcome — even with the oil market near the bottom of the worst price plunge since the 2008 financial crisis. To be sure, top OPEC producer Saudi Arabia and its Gulf allies are widely expected to orchestrate another output cut when producers meet in Vienna on Thursday. The signals are clear: Forecasters think the oil market will be oversupplied next year, the cost of crude has tumbled more than 30 percent in just eight weeks, and most OPEC members don't stand a chance of balancing their budgets at current price levels. But the group is dealing with a very different set of challenges than it faced in 2016, including a U.S. president who is fiercely opposed to price-boosting production cuts. Analysts now expect the meeting to culminate with an official statement that leaves the market scratching its head over just how many barrels OPEC intends to take off the market. "I do think there will be OPEC math," said Tamar Essner, director of energy and utilities at Nasdaq Corporate Solutions. "You'll have to figure out the cuts from baseline levels. I don't think it will be necessarily all that clear based on the statements." That could result in a repeat of OPEC's June meeting. With oil prices rising rapidly, the group agreed to reverse course and hike output but offered little in the way of a blueprint. The OPEC alliance agreed two years ago to keep 1.8 million barrels per day off the market, but by this last April, the group's output had fallen by about 2.7 million bpd. Instead of clearly stating they would correct by restoring about 1 million bpd, producers vowed to return to 100 percent compliance. The group also failed to release revised quotas for each nation. Markets responded to OPEC's ambiguity by pushing oil prices higher, the opposite of what the cartel intended. In the following months, U.S. crude rallied to a nearly four-year high at $76.90 a barrel, driven by fears of oil shortages ahead of U.S. sanctions on Iran. The price has since tumbled 35 percent over the last eight weeks, hitting a 13-month low at $49.41 on Thursday. John Kilduff, founding partner at energy hedge fund Again Capital, says traders may punish oil prices if the OPEC statement once again disappoints the market. "If this OPEC meeting falls apart, you could see prices rapidly fall down to potential support down to $42,"
Saudi energy minister goes to OPEC with a weak hand- Kemp (Reuters) - Saudi Arabia’s energy minister, Khalid al-Falih, must play a bad hand of cards as well as he can at next week’s meeting of OPEC and non-OPEC oil producers in Vienna. Falih’s challenge is to get other countries on board with output cuts to avert another crash in oil prices next year while disguising the kingdom’s diminishing leverage in the oil market. Front-month Brent futures have fallen by a third since the start of October while the six-month calendar spread is in contango, indicating most traders expect the market to be oversupplied in 2019. The market outlook is strikingly similar to 2014, with production from U.S. shale surging while consumption growth slows as the global economy falters (https://tmsnrt.rs/2RjBrxq ). But in one respect the situation is even more uncomfortable because Saudi Arabia’s official foreign reserves are down to just over $500 billion, from almost $750 billion in June 2014. The kingdom probably needs to keep several hundred billion dollars’ worth of reserve assets on hand to maintain confidence in its fixed exchange-rate peg to the U.S. dollar and prevent a run on the currency. The kingdom can ill-afford another slump in oil revenues so soon after the last one, which suggests it will have to cut production, while trying to cajole other OPEC and non-OPEC countries to share the burden. At the same time, any cuts must avoid provoking a political reaction from the United States, where the president has continued to press for even lower oil prices.
Saudi Bond Yields Surge As Crude Crashes - In the current environment of rising interest rates, international bonds are likely to outperform U.S. bonds. At first glance, that might seem counterintuitive given that many international bonds offer lower yields than U.S. bonds with some even providing negative yields. Yet, rising yields usually lead to a fall in bond prices that’s usually more than enough to counteract higher yields thus leading to lower overall returns. Case in point: the Vanguard Total International Bond ETF (BNDX) sports higher total returns compared to the U.S.-focused Vanguard Total Bond Market ETF (BND). One such class of international bonds is Saudi bonds, which have been roiled by a sharp fall in oil prices as well as the ongoing outrage over the murder of international journalist and Washington Post columnist, Jamal Khashoggi. Saudi Arabia is extremely reliant on oil, with oil revenue accounting for 90 percent of the nation’s export earnings and 42 percent to GDP. Oil prices have declined sharply, with WTI falling from mid-70s per barrel to mid-50s in less than two months, partly due to the U.S. granting surprise waivers for sanctioned Iran crude. Meanwhile, international outrage on the role played by the Saudi government in the murder of Khashoggi in the Saudi consulate in Turkey seemed to increase the risk that the U.S. would impose stiff penalties on the country. The confluence of these factors has led to Saudi bonds falling quite dramatically with yields climbing. Saudi Arabia’s $5 billion bonds due 2028 have recorded a sharp rise in yield during the last week. The bonds now yield 4.6 percent - significantly higher than the U.S. 3 percent yield for 10-year notes.
The Khashoggi killing had roots in a cutthroat Saudi family feud - Behind the brutal murder of Jamal Khashoggi lies a power struggle within the Saudi royal family that helped feed the paranoia and recklessness of Crown Prince Mohammed bin Salman. Eventually, this rage in the royal court led to the death and dismemberment of a Washington Post journalist. According to a Saudi who was at the hospital as King Abdullah lay on his deathbed, Abdullah’s sons and courtiers briefly delayed informing his successor, King Salman, that the monarch had passed — perhaps hoping to control the court’s stash of money and sustain powerful positions for Abdullah’s wing of the family. The cutthroat scheming within the House of Saud over the following years matches anything in the fantasy series “Game of Thrones.” The fallout extended to the United States, China, Switzerland and other countries, as the two most powerful clans of the royal family jockeyed for power. As the tension increased, the royal court around Mohammed bin Salman, the new king’s favorite son, even dared to try to kidnap a member of the Abdullah faction in Beijing in a brazen operation in August 2016 that reads like a chapter in a spy thriller. MBS, as Salman’s son is known, became increasingly anxious and aggressive toward those he considered enemies. Starting in the spring of 2017, a team of Saudi intelligence operatives, under the control of the royal court, began organizing kidnappings of dissidents abroad and at home, according to U.S. and Saudi experts. Detainees were held at covert sites. The Saudis used harsh enhanced interrogation techniques, a euphemism for torture, to make the captives talk. They were forced to sign oaths that if they disclosed any of what happened, they would pay a severe price. This real-life drama was described to me in a series of interviews by prominent Saudis and U.S. and European experts, in the United States and abroad, in the weeks since Khashoggi’s death. These sources had firsthand knowledge of events but asked not to be identified because they involve sensitive international matters. The information was checked with knowledgeable U.S. sources to confirm its accuracy. It helps explain the vortex of rage and lawlessness that ultimately sucked in Khashoggi, a Post Global Opinions columnist, when he entered the Saudi Consulate in Istanbul on Oct. 2.
AP Interview: Saudi royal says crown prince is here to stay (AP) — A prominent Saudi royal said Saturday that whether or not heads of state gathered in Argentina next week for the Group of 20 summit warmly engage with Crown Prince Mohammed bin Salman, he is someone “that they have to deal with.” Prince Turki al-Faisal told The Associated Press the killing of Saudi writer Jamal Khashoggi in the kingdom’s consulate in Istanbul last month is “an unacceptable incident that tars and mars the long record of Saudi Arabia’s own standing in the world.” “We will have to bear that. It’s not something that should not be faced. And we do face it,” he said. Intelligence officials and analysts say the operation to kill Khashoggi, who wrote critically of the crown prince for The Washington Post, could not have happened without Prince Mohammed’s knowledge. The kingdom, which has offered several conflicting accounts of the killing, denies the crown prince had any involvement. The crown prince embarked late Thursday on his first foreign tour since the Oct. 2 killing with a visit to the United Arab Emirates. He’s expected to visit other Mideast countries before going to Buenos Aires Nov. 30 for the start of the two-day G-20 summit, where he’ll come face to face with world leaders. President Donald Trump and Turkish President Recep Tayyip Erdogan, who has kept international pressure mounting on the kingdom, are among those expected to attend. “Whether the leaders in that summit will warmly engage with the crown prince or not, I think all of them recognize that the kingdom as a country and King Salman and the crown prince are people that they have to deal with,” the prince said.
'I am worried' Macron's chat with Saudi prince captured - The Saudi crown prince, Mohammed bin Salman, suspected of ordering the murder of the dissident writer Jamal Khashoggi and accused of war crimes in the Yemen conflict, has told the French president, Emmanuel Macron, “Don’t worry” at the G20 summit in Buenos Aires. The two leaders were having an informal conversation on the sidelines of the summit, standing close together and apparently unaware their conversation was being recorded. The subject of the snatched conversation was not immediately clear but a French presidential aide said afterwards that the Khashoggi murder and the Yemen conflict were the two key topics of the short exchange. According to a Guardian analysis of their only partly audible conversation, Macron replies to the crown prince’s assurances: “I do worry. I am worried … I told you.” “Yes, you told me,” the prince says. “Thank you very much.” “You never listen to me,” Macron says. “No, I listen, of course,” replied Prince Mohammed, smiling broadly after apparently becoming aware of a television camera. “Because I told you. It was more important for you,” Macron says, and gives a tight smile, before turning away from the camera to speak further to the prince. Macron then says something inaudible, to which the Saudi leader says: “It’s OK. I can deal with it.” After another indecipherable segment of conversation, Macron says: “I am a man of my word.” The Élysée Palace said the two leaders had a five-minute exchange on the sidelines of the summit in which Macron conveyed a “very firm” message to the prince over the killing and the need to find a political solution for the situation in Yemen.
With Peace Talks on the Horizon, Saudis Defy Truce to Redouble Deadly Strikes on Yemen’s Civilians — In a remote area in Mustaba, Hajjah, southwestern Yemen, two volunteers push through the rubble of a partially collapsed home hit by an airstrike. Onlookers shield their mouths and noses from the dust and stench of corpses of those who perished beneath. A rescue worker pulls out the skeletons of children and women from under the rubble. A relentless payload of bombs was dropped on Mustaba in just a few hours on Saturday night, killing six civilians and injuring three. A woman and four children were among the victims of the Saudi airstrikes, which targeted homes in Ram district of the Mustaba region, dozens of kilometers away from the war’s closest frontlines. Upon the departure of United Nations envoy Martin Griffiths from Yemeni capital Sana’a on Friday, the Saudi-led coalition stepped up its campaign of airstrikes, as warplanes bombed residential areas in Hajjah, Hodeida, Sadaa and Sana’a — carrying out over 120 airstrikes, which resulted in a high number of civilian casualties. Griffiths was in Sana’a to meet Ansar Allah (Houthi) leader Abdul-Malik Badreddin al-Houthi and other high-level officials to discuss the group’s attendance in planned peace talks to be held in Sweden next month. The Houthis have agreed to negotiate a United Nations role in managing the vital port-city of Hodeida. Ahmed Suheil, an activist who lives in the Mustaba district, said he woke up to the sounds of bombing raids. “At 11 p.m., they attacked a home in our neighboring village four times. It’s far from my house, but it was so horrible to wake up to that sound,” Suheil recounted. “Everything was shaking.” “They do not respect their covenants” shouts Mohammed Jumaie, who led the village’s emergency response team. “We are in a truce. Why should civilians pay with their lives for this dirty aggression?” Recovery efforts were slowed by a lack of heavy machinery needed to access the bodies, as locals gathered around the site hoping their loved ones weren’t among the victims. One man could be heard crying: “Please, there are children under the rubble. My brother’s children. Maybe at least just one of them is still alive!”
Argentina Opens War Crimes Inquiry on Saudi Crown Prince for Role in Yemen War (MEE) — Argentina has opened up an inquiry on whether to press criminal charges against Saudi Arabia’s Crown Prince Mohammed bin Salman, known as MBS, for his role in leading the Saudi-led military campaign in Yemen, Human Rights Watch (HRW) said Monday.The inquiry was opened after HRW and an Argentine federal prosecutor lodged a complaint against the kingdom for violating international war crimes laws, according to a New York Times report.The investigation comes ahead of the crown prince’s visit to Argentina for the upcoming G-20 summit later this week, but officials in the South American country have said bin Salman’s arrest is “extremely unlikely,” the New York Times report said.“Mohammed bin Salman should know that he may face a criminal probe if he ventures to Argentina,” HRW executive director Kenneth Roth said in a statement.Argentina’s laws promote the idea of universal jurisdiction, where severe human rights violations are subject to persecution regardless of sovereign boundaries.The country changed its legal code towards universal jurisdiction in the first half of the 2000s to address the tens of thousands of Argentinians who disappeared in the 1970s and 1980s during the days of military rule, when the government rounded up families, including children, to prisons and camps. The investigation comes at a time when the crown prince is taking heat for the death of journalist Jamal Khashoggi in Saudi Arabia’s Istanbul consulate, but the Argentine inquiry is primarily focused on Riyadh’s role in Yemen.
UN Chief Ready to Meet Saudi Crown Prince to Discuss Yemen War — The head of the United Nations said he is willing to meet with Saudi Crown Prince Mohammed bin Salman to discuss the war in Yemen, as the UN continues to push for an end to the devastating conflict.UN Secretary General Antonio Guterres told reporters on Wednesday that the international body is “close to [creating] the conditions for the possibility for [Yemen] peace talks to start”.“And of course Saudi Arabia is absolutely crucial for that purpose, and I’m ready to discuss it with the crown prince or with any other Saudi officials because I believe it is a very important objective at the present moment,” Guterres said.The UN chief’s comments come amid growing criticism of Saudi Arabia over its role in the war in Yemen and a pending US Senate vote on ending Washington’s support for the Saudi-led coalition.That coalition, which includes the United Arab Emirates, launched a military offensive in Yemen in 2015 to root out Houthi rebels, who had deposed Yemeni President Abd Rabbuh Mansour Hadi and taken over the capital, Sanaa. The ongoing conflict has pushed millions of Yemeni civilians to the brink of famine.
Ambulances in Syria deliberately and repeatedly targeted as part of war tactics - Half of the ambulances targeted sustained serious damage and/or had to be withdrawn from service, the findings show. Now in its eighth year, the Syrian conflict has taken a heavy toll on medical facilities and health professionals from airstrikes, bombings, shootings, kidnappings and lootings. This is despite the fact that healthcare facilities and the ambulances servicing them are protected under International Humanitarian Law and the Geneva Conventions, and the UN resolution 2286, passed in 2016, condemning attacks on medical facilities and staff.To try and quantify the extent of the damage inflicted on the country's ambulance service, the researchers analyzed data from individual reports submitted to the Syrian Network for Human Rights (SNHR) throughout 2016 and 2017 and reviewed published research on attacks on ambulances since the start of the war in 2011. Analysis of the SNHR data showed that there were 204 individual attacks involving 243 ambulances in 2016 and 2017. Half (52%) of the vehicles were deliberately targeted. Most attacks occurred in areas with large factions of opposition forces: Aleppo, Idlib, and Damascus. Only 1-2 per cent of the attacks occurred in pro-government areas. Half of the vehicles (49%) were either heavily damaged or had to be withdrawn from service. Only 12 per cent of vehicles sustained mild damage.
Massive Al-Qaeda Gas Attack On Pro-Government Aleppo Leaves Over 100 Hospitalized - Over 100 civilians were hospitalized, including dozens of women and children, after anti-Assad militants unleashed a wave of mortars filled with poison gas on government controlled Aleppo Saturday evening. Syrian state-run SANA published multiple photos and video of victims in the city's hospitals being treated for what's reported to be chlorine gas exposure. Though it's not the first time that 'rebels' seeking to topple the Assad government have conducted a chemical attack on pro-government areas according to United Nations findings, it is the first time that mainstream American outlets like CNN and Reuters have featured coverage of such events. Crucially, pro-rebel media has now confirmed the poison gas attack, specially the Syrian Observatory for Human Rights (SOHR), which western media have long relied upon as a go-to source of anti-Assad opposition reporting. According to Reuters:In Aleppo city which the government controls, the shells had spread a strong stench and caused breathing problems, the Syrian Observatory for Human Rights also said.In total official Syrian government sources reported 107 people were injured, a sizable portion of them children, after al-Qaeda terrorists linked to the Hayat Tahrir al-Sham alliance (HTS, the main al-Qaeda group that controls Idlib) attacked three Aleppo districts with poison filled projectiles. Initially the death toll approached 12 according to early reports, however, it now appears there were no fatalities resulting from gas exposure, though many remain in the hospital in what international reports say is the highest casualty toll since the Syrian Army liberated Aleppo two years ago. “The explosive (shells) contain toxic gases that led to choking among civilians,” Aleppo police chief Issam al-Shilli told SANA.
In Syria’s Idlib, Islamists see classrooms as a new front - In Syria’s northwestern province of Idlib, temporarily shielded from assault by a Turkey and Russia-backed buffer zone, schools have become the latest target of Islamist militants. Parents and teachers interviewed by Asia Times say boys and girls who once attended class together are increasingly segregated into separate classrooms, with male teachers discouraged from teaching girls, and vice versa. “After the children have passed the third grade of primary school, the girls are isolated from the boys and are forced to wear sharia-compliant dress (abaya). There are patrols of women affiliated with the Guardians of Religion group at the school gates to inspect clothing on a daily basis. “Any girl who does not wear the abaya must return home immediately,” said one mother in the city of Jisr al-Shughour. “These rituals or beliefs seem very harsh for children of this age, but we are afraid to speak about this for fear of arrest or abduction,” she said. “Sometimes my children ask me, why do we play with our sisters at home but we are separated in school? As a mother, I cannot find an explanation or answer to these questions.” The so-called Guardians of Religion group was formed in February 2018, bringing together hardline militants who opposed a decision by Idlib’s most powerful armed group – Hayat Tahrir al-Sham – to leave Al-Qaeda. This splinter group, made up of mainly Asian foreign fighters numbering more than 1,500, also opposes any capitulation to agreements made by neighboring Turkey, Russia and Iran through the Astana process. The Guardians are not at odds with the hardline group they split from, sharing the same puritanical ideology and close coordination in controlling Idlib city and many of its surrounding areas. Despite an acute shortage of teachers, the Guardians of Religion have been pushing to forbid men from teaching girls, and vice versa, sometimes resulting in students being deprived of subjects.
Israeli Company Sold iPhone Spyware To Saudis Knowing Riyadh Would Purge Dissidents -- Weeks ago NSA whistleblower Edward Snowden was the first to reveal that Saudi Arabia used Israeli spyware to target murdered Saudi journalist Jamal Khashoggi, accusing a Tel Aviv-based compmany called NSO Group of “selling a digital burglary tool,” adding it “is not just being used for catching criminals and stopping terrorist attacks, not just for saving lives, but for making money… such a level of recklessness... actually starts costing lives.” This has now been confirmed in detail by a new bombshell investigative report in the Israeli newspaper Haaretz, which outlines how NSO Group representatives met with Saudi intelligence officials in Vienna in 2017 in order to demonstrate the powerful and easy hacking capability of its advanced Pagasus 3 system, which using a mere SIM card number can turn a person's phone into an all-purpose spying device sweeping up the user's voice conversations, camera, messages, and social media usage. Among the first requests the Saudi delegation made of NSO while negotiating a $55 million deal to procure the technology was that the company help Riyadh uncover the true identities behind dissident Saudi Twitter accounts. The June 2017 deal for the hacking tool came just months before crown prince Mohammed bin Salman's infamous purge which would see multiple dozens of princes and top officials rounded up and imprisoned in the Riyadh Ritz-Carlton hotel the following November, which also involved the days-long detention of Lebanese Prime Minister Saad al-Hariri.These latest revelations originated in a complaint to Israeli police now under investigation involving at least one company-linked whistleblower who thinks the Saudis used NSO's hacking tool to track down and ultimately murder dissidents. Haaretz confirmed the secret deal with Saudi intelligence "based on testimony and photos, as well as travel and legal documents". This comes at a sensitive moment when Israeli Prime Minister Benjamin Netanyahu has become increasingly vocal over his desire to deepen ties with Gulf states, especially by supplying advanced Israeli technology.
Israel demolishes 30 Palestinian buildings in Jerusalem this month alone - Israel has demolished 30 commercial and residential Palestinian-owned properties in occupied Jerusalem since the start of November, a report from the Palestine Liberation Organisation revealed on Saturday. The report was issued by the Negotiations Department of the PLO. The Israeli occupation authorities apparently demolished 17 commercial facilities on 21 November in Shuafat. According to Al Jazeera, the shops used to serve 23,000 Palestinian refugees in the refugee camp.The Palestinian owners, said the PLO, received evacuation and demolition orders just 12 hours prior to the buildings being destroyed. As a result, there was simply not enough time to remove all of the goods inside, most of which were lost. The occupation authorities have also imposed a travel ban on the Palestinian Authority governor of East Jerusalem, Adnan Gheith, and a member of the Fatah Executive Committee, Adnan Al-Husseini. Numerous other orders have been issued by Israel to restrict the movement of Palestinians in the occupied holy city. The PLO report included statistics about Israeli violations in Jerusalem since the start of this year. Five Palestinians have been killed by the Israeli occupation forces in the city, with 120 wounded and more than 1,100 others arrested. Many cases have been documented of illegal Jewish settlers inciting hatred and violence against Palestinians.
US Airstrike in Afghanistan Kills at Least 30 Civilians, Including 16 Children — Officials in Afghanistan’s Helmand province and international media are reporting at least 30 civilians, including 16 children, were killed in the latest US air strike targeting Taliban militants.Reuters reports the latest US mass casualty bombing in Afghanistan came amid a surge in aerial operations aimed at forcing the Taliban to the negotiating table after more than 17 years of US-led war there. Officials said Afghan government advisers and US troops were attacked late on Tuesday by Taliban fighters based in a compound in Garsmir district, south of Marjah, in southern Helmand. The militants attacked the Afghans and Americans with machine guns and rocket-propelled grenades, according to the NATO-led Resolute Support forces.Provincial governor Mohammad Yasin Khan said Afghan troops called in air strikes, with US warplanes responding with attacks that killed both Taliban fighters and local civilians. A local resident told Reuters that “foreign forces bombed the area and the bombs hit my brother’s house.” He said the victims included women and 16 children. Another local resident, Feda Mohammad, said more victims remained buried beneath the rubble of the compound.The NATO-led coalition said it was unaware of any civilians in the area of the air strikes.“At the time of the strike, the ground force was unaware of any civilians in or around the compound; they only knew that the Taliban was using the building as a fighting position,” a spokeswoman said in a statement.US air strikes in Afghanistan have sharply increased in recent months, part of a strategy meant to drive the Taliban into talks aimed at ending the longest war in US history. A spike in civilian casualties has accompanied this surge; last month a United Nations report revealed that the number of Afghan civilians — mostly women and children — killed or injured by NATO and Afghan air strikes has risen 39 percent in 2018. The UN report said 313 civilians had been killed and another 336 injured from January 1 through September 30, more casualties than in all of 2017. While the spike in innocent deaths is alarming, the 649 casualties represent just 8 percent of all Afghan civilian casualties for 2018. Ground engagements, improvised explosive devices (IEDs) and suicide attacks accounted for nearly three quarters of civilian casualties this year.
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