oil again traded in a narrow price range this week, ending about 1.0% higher at $53.99, although such a week over week comparison really shouldn't be made, because this week's prices were for April delivery, while last week's price quotes were for March oil...after closing last week at $53.40 a barrel, March oil traded 22 cents higher on the Presidents’ Day holiday for settlement on Tuesday as traders again played rising U.S. drilling activity against OPEC production cuts....prices then rose to near three-week highs on Tuesday after OPEC Secretary General Mohammad Barkindo told an oil conference that compliance with the output cuts was above 90 percent and that oil supplies would fall, with the expiring March contract closing out at $54.06 and the new front month April contract up 1% to $54.37...prices for April oil then fell about 1.5% on Wednesday on expectations of another surge in U.S. inventories, which were to be reported after the market closed at 4:30 PM, with that April contract closing at $53.59 a barrel...however, oil prices bounced back to close at $54.45 a barrel on Thursday after API estimates of supply indicated a small draw, with distillates seeing the largest draw since October 2014...oil prices then fell back on Friday, after EIA data showed an increase in both crude production and inventories, and yet another record high for the later, and ended the session 46 cents lower at $53.99 a barrel....
on the other hand, natural gas prices took another tumble this week, with the contract for March falling from a quote of $2.834 per mmBTU on Monday to $2.564 per mmBTU on Tuesday, as the post holiday markets opened to record warmth across a broad swath of the country...that price for March natural gas then recovered a bit in light trading, to $2.592 per mmBTU on Wednesday and to $2.617 per mmBTU on Thursday, when trading in the March natural gas contract expired...prices for the April natural gas contract then rose 3.8 cents to close at $2.787 on Friday, as increasing power loads and modestly higher peak power forecasts helped support prices...
as we pointed out last week, natural gas drilling activity has typically slowed at these price levels, only picking up when price quotes approach $4 per mmBTU, such that drillers can usual contract to sell their initial high output at prices above those levels...so while indications are that contract prices will stay below those break even levels in the near term, the specter that natural gas exports will eventually put pressure on supplies and raise prices to stimulate more drilling is still a threat we'll have to deal with...that was brought to the fore by two reports that were released this week, both of which forecast higher future demand for US LNG (liquefied natural gas) exports...
the first report, released Monday, was Royal Dutch Shell’s Outlook, an annual report which had previously been released by British Gas (BG), who Shell bought out early last year...they expect global natural gas demand to average an annual increase of 2% a year between 2015 and 2030, with LNG demand expected to rise at twice that rate, at 4 to 5% per year...in the year just ended, LNG import demand grew by 17 million tons to 265 million tons...the bar graph below from Shell shows where most of the growth in LNG imports came from last year:
the above graphic comes from page 9 of the the slide booklet of the 2017 Shell LNG Outlook and it shows the counties that increased their LNG imports last year, and by how much...in addition, those countries who were not LNG importers in 2015 are indicated in red, so all of their 2016 imports thus represent increased demand...note the US is the 3rd from the left, as even we increased LNG imports a bit last year...according to Shell, future demand for LNG will come from 2 groups of countries; those where LNG will be needed to replace declining domestic production, which includes countries such as India, Thailand, Malaysia, Indonesia, Kuwait, the Emirates, and Egypt, and those where LNG will supplement existing pipeline or domestic supplies, such as China, southern Europe and eastern Europe...
the second report that projected rising LNG demand was from the Wednesday release of the EIA's daily "today in energy" series, and was titled Liquefied natural gas exports expected to drive growth in U.S. natural gas trade...projecting from the Annual Energy Outlook 2017 base reference case, they expect us to become a net exporter of natural gas on an average annual basis by 2018...this will occur as our imports of natural gas from Canada fall and as our LNG exports increase, as they expect four more LNG export facilities that are currently under construction to be completed by 2021...the lead graphic from that report, which we'll include below, shows how this plays out over the next 20 years...
the above graphic, which we've copied from Wednesday's release Today in Energy, shows our imports of natural natural gas in trillions of cubic feet as a negative below the zero line, and our exports of natural gas in trillions of cubic feet as a positive above the zero line, with historical data represented for the years from 1980 to 2016, and projections shown for the years from 2017 to 2040...below the zero line, our natural gas pipeline imports from Canada are shown in pink, and our LNG imports are represented by light blue...above the line, our natural gas pipeline exports to Mexico are represented by the burnt orange shading, our pipeline exports to Canada are represented by the rose shaded section, and our projected LNG exports from existing and under construction port facilities are represented by the navy blue shaded part of the graph...while we've had weeks in 2017 where our exports may have exceeded our imports, and will likely have such weeks again in 2017, this projection is on an annual basis, and according the EIA, we were a small natural gas net importer in 2016 and will again be an importer in 2017....clearly, our current LNG exports are still so small they barely show up in 2016 on a graph of this scale...
right now, only one U.S. export facility is currently in operation, Sabine Pass, on the Gulf of Mexico border between Texas and Louisiana, where just 4.5 million tons per annum is operational, and 27 million tons per annum is still under construction... however, the Federal Energy Regulatory Commission has approved natural gas export terminals with a capacity of 17 billion cubic feet (bcf) per day, which would represent the offshoring of about 19% of current U.S. natural gas production...furthermore, if all terminals for which applications are pending or expected are included, the quantity of our LNG exports goes up to 42 billion cubic feet (bcf) per day, or about 47 percent of our current natural gas production...right now, roughly 40% of our natural gas production comes from the old legacy gas fields in the south, primarily in Texas and Louisiana, while the other 60% of our output comes from 7 shale basins, with the Marcellus and the Utica account for roughly half of that...should all these export terminals be pushed through, however, almost all of the new gas will have to come from the pure natural gas shale plays, the Marcellus, the Utica, and the Haynesville, which means there will be a massive expansion of drilling and fracking to meet these natural gas export requirements...
Australia is a bit ahead of us in exporting LNG, and their experience should give us a sense of what our coming LNG exports will do to U.S. natural gas prices...contracts for natural gas exports are written well in advance of delivery, and as a result Australians living in the country's eastern region ended up paying more than twice as much for natural gas last winter than did Japanese customers taking delivery of liquefied natural gas (LNG) from the same fields...the same could easily happen here...presently, US gas futures prices are generally below $3 per mmBTU, while current LNG prices in Japan are over $7 per mmBTU...even worse, just a couple weeks ago Spain was paying more than $10 per mmBTU for LNG...if an US gas exporter contracts to deliver LNG to Japan or Spain at those prices, they'll get the gas from US shale production before US customers who dont have a contract do...if that should occur during a cold snap in mid winter, a shortage of natural gas could develop domestically, sending our prices skyrocketing...and in such a case, some of us who cant afford the higher priced natural gas simply wont get it....we know this happens, because just three years ago an LP gas shortage developed in the US for exactly the same reason, and as US LP gas prices spiked while our LP gas exports soared, a North Dakota Standing Rock Sioux woman was found dead, froze to death in her mobile home, with an empty propane tank...we can expect the same to happen here once natural gas prices rise to levels beyond which those on fixed income can afford it...
The Latest Oil Stats from the EIA
this week's oil data for the week ending February 17th from the US Energy Information Administration showed that our imports of crude oil fell to the lowest level since October and our refining of that crude oil fell for the 6th week in a row to the lowest rate in two years, leaving us with a small surplus of crude to add to our stored oil supplies, which thus were at another an all time high...our imports of crude oil fell by an average of 1,205,000 barrels per day to an average of 7,286,000 barrels per day during the week, while at the same time our exports of crude oil rose by 185,000 barrels per day to an average of 1,211,000 barrels per day, which meant that our effective imports netted out to 6,075,000 barrels per day for the week, 1,390,000 barrels per day less than last week...at the same time, our crude oil production rose by 24,000 barrels per day to an average of 9.001,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 15,076,000 barrels per day during the week...
meanwhile, refineries reportedly used 15,271,000 barrels of crude per day during the week, 187,000 barrels per day less than during the prior week, while at the same time, 81,000 barrels of oil per day were being added to oil storage facilities in the US...thus, this week's EIA oil figures seem to indicate that we used or stored 276,000 more barrels of oil per day than were accounted for by our net oil imports and oil well production…therefore, in order to make the weekly U.S. Petroleum Balance Sheet balance out, the EIA inserted a phantom 276,000 barrel per day number onto line 13 of the petroleum balance sheet, which the footnote tells us represents "unaccounted for crude oil"...that "unaccounted for crude oil" is further described in the glossary of the EIA's weekly Petroleum Status Report as "the arithmetic difference between the calculated supply and the calculated disposition of crude oil.", which means they got that balance sheet number by backing into it, using the same arithmetic we just illustrated.....
the weekly Petroleum Status Report also tells us that the 4 week average of our oil imports fell to an average of 8.36 million barrels per day, still 7.5% higher than the same four-week period last year...at the same time our crude oil exports at 1,211,000 barrels per day was another new record for oil exports, beating the record set last week, and as a result our crude oil exports are now averaging 3 times what we were exporting last February...meanwhile, this week's 24,000 barrel per day oil production increase included a 17,000 barrel per day increase in oil production in the lower 48 states and a 7,000 barrel per day increase in output from Alaska...topping 9 million barrels per day for the first time since last April, our crude oil production for the week ending February 17th was just 1.1% lower than the 9,102,000 barrels of crude that we produced during the week ending February 19th of last year, while it remained 6.3% below our June 5th 2015 record oil production of 9,610,000 barrels per day...
the 15,271,000 barrels of crude per day that were refined this week was down by 10.7% from the 17,107,000 barrels per day being refined during the first week of this year, and 2.4% less than the 15,685,000 barrels being refined during the same week last year....US refineries were operating at 84.3% of their capacity in the week ending February 17th, their lowest operating rate in nearly 4 years, down from 85.4% of capacity the prior week and down from the 87.3% capacity utilization rate during the week ending February 19th year ago...since we're at an interim nadir for refinery throughput and capacity utilization this week, we'll include a graph of what that looks like compared to historical trends below...
the above graph comes from an emailed package of graphs from John Kemp, who is a senior energy analyst and columnist with Reuters (see my footnote below)...this graph shows US refinery throughput in thousands of barrels by "day of the year" for the past ten years, with the past ten year range of our refinery throughput on any given date shown in the light blue shaded area, and the median of our refinery throughput, or the middle of the daily range, traced by the blue dashes over each day of the year...the graph also shows the number of barrels of oil refined for each week in 2016 traced weekly by a yellow line, with our year to date oil refining for 2017 represented in red...there is an obvious seasonality to oil refining, with demand highest in the summer and again around the holidays, but we can still see that for most all of 2016 and the first five weeks of 2017, oil refining was either at seasonal record highs or near the top of the average range...however, with domestic inventories of gasoline, distillates and most other refined products also at record levels in recent weeks, storage space for refined products has been stretched to its limits, profit margins for refineries fell to the lowest in a year, and thus refiners have cut back on the amount of oil they processed...
however, even though they refined less oil this week, gasoline production from those refineries still rose by 479,000 barrels per day to 9,429,000 barrels per day during the week ending February 17th, which was still 5.4% less than the 10,009,000 barrels per day of gasoline that were produced during the week ending February 19th a year ago...meanwhile, refineries' production of distillate fuels (diesel fuel and heat oil) also rose, increasing by 136,000 barrels per day to 4,467,000 barrels per day, which was up fractionally from the 4,438,000 barrels per day of distillates that were being produced during the week ending February 19th last year, during a mild El Nino winter...
however, even with the increase in our gasoline production, the EIA reported that our gasoline inventories fell by 2,628,000 barrels to 256,435,000 barrels as of February 17th, in the second drop in our gasoline supplies in the past 8 weeks...that happened as our domestic consumption of gasoline rose by 230,000 barrels per day to a still below normal 8,663,000 barrels per day, while our gasoline exports rose by 293,000 barrels per day to 848,000 barrels per day and our gasoline imports fell by 238,000 barrels per day to 367,000 barrels per day...however, even with this week's inventory draw down, our gasoline supplies are up by nearly 29.3 million barrels since Christmas, remain statistically on a par with the 256,457,000 barrels of gasoline that we had stored on February 19th of last year, and are still 6.8% above the 240,014,000 barrels of gasoline we had stored on February 20th of 2015...
similarly, even with the increase in our distillates production, our supplies of distillate fuels fell by 4,924,000 barrels to 165,133,000 barrels by February 17th, as the amount of distillates supplied to US markets, a proxy for our consumption, rose by 439,000 barrels per day to 4,292,000 barrels per day, and as our imports of distillates fell by 87,000 barrels per day to 129,000 barrels per day and as our exports of distillates were up 15,000 barrels per day to 1,007,000 barrels per day....even so, our distillate inventories are still 2.7% higher than the distillate inventories of 160,715,000 barrels of February 19th last year, and 33.4% above the distillate inventories of 124,698,000 barrels of February 20th, 2015…
finally, with the major curtailment in our refining, we again had surplus crude remaining, and hence our inventories of crude oil rose for the 7th week in a row, increasing by 564,000 barrels to 518,683,000 barrels by February 17th, which was yet another record for our crude supplies...thus we ended the week with 8.2% more crude oil in storage than the 479,012,000 barrels we ended 2016 with, 8.9% more crude oil in storage than the then record 476,325,000 barrels we had stored on February 19th of 2016, 29.7% more crude than the 399,943,000 barrels of oil we had in storage on February 20th of 2015 and 56.7% more crude than the 331,024,000 barrels of oil we had in storage on February 21st of 2014...
This Week's Rig Count
US drilling activity increased for the 16th time in 17 weeks during the week ending February 24th, but the 5 week string of double digit rig count increases has finally ended....Baker Hughes reported that the total count of active rotary rigs running in the US increased by just 3 rigs to 754 rigs in the week ending on this Friday, which was 251 more rigs than the 502 rigs that were deployed as of the February 26th report in 2016, but still far from the recent high of 1929 drilling rigs that were in use on November 21st of 2014...
the number of rigs drilling for oil rose by 5 rigs to 602 rigs this week, which was up from the 400 oil directed rigs that were in use a year ago, but down from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...meanwhile, the count of drilling rigs targeting natural gas formations fell by 2 rigs to 151 rigs this week, which was still up from the 102 natural gas rigs that were drilling a year ago, but down from the recent natural gas rig high of 1,606 rigs that were deployed on August 29th, 2008...there also remained a single rig that was classified as miscellaneous, which is marked as a 1 rig increase from a year ago, when there were no such miscellaneous rigs at work...
the drilling platform that had been working offshore from Alaska was shut down this week, coincidentally the same week that we learned that an offshore gas pipeline under the Cook Inlet sprung a leak...that left the total US offshore count for the week at 17 rigs, all in the Gulf of Mexico, down from 27 offshore rigs a year ago, when again they were all in the Gulf of Mexico...at the same time, a rig was set up on an inland lake in southern Louisiana, where there are now 4 of them, up from two inland water rigs a year ago...
.the number of horizontal drilling rigs working in the US increased by 10 rigs to 624 rigs this week, which is now up by 227 rigs from the 397 horizontal rigs that were in use in the US on February 26th last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, 3 directional rigs were shut down during the week, cutting the directional rig count back to 69, which was still up from the 47 directional rigs that were deployed during the same week last year...in addition, a net of 4 vertical rigs were stacked this week, reducing the vertical rig count to 61, which was still up from the 58 vertical rigs that were deployed during the same week a year ago...
as usual, the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of February 24th, the second column shows the change in the number of working rigs between last week's count (February 17th) and this week's (February 24th) count, the third column shows last week's February 17th active rig count, the 4th column shows the change between the number of rigs running this Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was for the 26th of February, 2016...
again, this week's drilling changes were mostly about Texas, where they added 8 rigs, including 3 in the Permian in west Texas and another 3 in the Eagle Ford of south Texas...2 more rigs were also added in the Cana Woodford, site of the hot SCOOP and STACK plays...two rigs were shut down in Alaska, including the one offshore, and a net of two were pulled from Louisiana; otherwise, not much changed...note that outside of the major producing states shown above, Indiana also had their only active rig shut down this week; that left them unchanged from a year ago, though, when the state also had no drilling activity...
as i noted, one of the graphs that i included above was from an emailed package of graphs from John Kemp, a senior energy analyst and columnist with Reuters...i had used two of his graphs taken from his twitter account the prior week and in so doing, noted a twitter message from him which said: SIGN UP to receive a free daily digest of best in energy news + my research notes by emailing email@example.com
so i requested to be included on his daily digest mailing list and he responded: With pleasure. If you know anyone else who might like to receive the daily digest and my research notes, please encourage them to contact me and I will add their emails to the circulation as well. The mailing list is open to anyone interested in energy. Very best wishes. John.
i am now receiving a daily mailing of links & graphics, copies of his columns as published, and what appears a weekly pdf of graphs... so if anyone is interested in receiving the same, please write to John Kemp as noted above...alternatively you can also follow him on twitter, @ https://twitter.com/JKempEnergy where he seems to post much of what he otherwise mails...since i dont use twitter, his emails work best for me...
Ohio community fights proposed DPL coal plant closures - A group in Adams County wants the Public Utilities Commission of Ohio to rule against a Dayton Power and Light plan to close two power plants in that county located on the Ohio River. The group has filed a motion with the PUCO that targets what it calls the “self-serving” plan to retire the coal-fired plants “without even mentioning (much less attempting to explain away) the pervasive and disastrous closure effects that DP&L forthrightly admitted will be visited upon the citizens of Ohio — and particularly the residents of Adams County — by the shuttering of coal generation plants.” The motion says DP&L directly or indirectly employs nearly 700 people at the two coal-fired power plants, including 490 DP&L employees and 200 contractor employees. The two plants generate about $9 million in annual property taxes for the county and other political entities, the motion says. The Manchester School District alone gets $5.6 million in annual revenue from the plants, according to the motion. The motion, filed late last week, refers to a group calling itself “Citizens to Protect DP&L Jobs” whose members include business people, property owners and taxpayers. In November last year, DP&L told the PUCO that in talks with parties to its electric security plan, some “have raised the subject of the closure of Killen and Stuart Stations.” At that time, no decision had been reached. DEVELOPMENT: DP&L expands development role In late January, though, DP&L filed a proposed settlement with PUCO that, if approved, would increase customers monthly bills as well as close the two plants in question, both on the Ohio River. If approved by the PUCO, the company seeks to close its Stuart and Killen coal plants by mid-2018. A spokeswoman for DP&L said the company would not oppose the group’s motion to intervene.
Fracking produces unexpected benefits for Ohio counties - Oil and gas drilling, a long-time staple in Ohio, has become an important revenue source for not only gas companies themselves, but also for the counties that allow drilling on their land, a new industry study found. The study from two organizations, the industry trade group Ohio Oil and Gas Association and the industry-funded Energy in Depth, showed that six Ohio counties, Belmont, Carroll, Guernsey, Harrison, Monroe and Noble, saw sharp increases in their property tax revenue since 2010.These counties received $43 million from tax revenue from oil and gas drilling rigs between 2010 and 2015, and in 2015, 24 percent of all property tax collected from these counties came from taxes paid on drilling operations. This recent spike can largely be traced to hydraulic fracturing, a type of drilling that has been in Ohio since 2011. Fracking brought large-scale production to multiple states, including Ohio, and with this increase in production also came an increase in the taxes paid to the townships that give their land to drilling companies, according to Jackie Stewart, state director of Energy in Depth. Production has particularly spiked since 2013 in Ohio and gas drilling increasing by 852 percent since then, the study found. Although the study did not include the early results of 2016, Stewarts said the first three quarters of 2016 already greatly surpassed 2015 in overall production. In general, Ohio’s taxes on oil and gas are lower than the taxes on natural gas in other states, something Gov. John Kasich has attempted to adjust in the past, with little support form Republicans in the General Assembly. Carroll County is the leading county for natural gas production, with over $14 million made off revenue tax between 2010 and 2015. Their profits have largely gone back to schools in the county: overall real estate tax revenue given to the Carrollton Exempted Village School District jumped from $6.7 million in 2013 to $11.2 million in 2015.
New Protest Escalates Ohio Fracking Fight - Center for Biological Diversity (press release) — Conservation groups this week filed an administrative protest challenging a Bureau of Land Management oil and gas lease auction slated for Ohio’s Wayne National Forest. The protest takes aim at the Bureau’s refusal to adequately analyze the impacts of fracking on climate change, water quality and endangered species. “Our protest challenges the Bureau’s disturbing practice of favoring fracking industry interests over clean water, wildlife and human health,” said Taylor McKinnon of the Center for Biological Diversity. “With each new federal fossil fuel lease, the Trump administration pushes us closer to climate disaster.” The protest charges that the plan to allow hydraulic fracturing or “fracking” on 1,186 acres of Wayne would degrade streams and groundwater, fragment wildlife habitat and worsen climate change. The federal auction is scheduled for March 23. The groups also note that the federal environmental assessment for the lease auction failed to fully disclose fracking’s effects on the national forest. That’s because the government failed to study the increased surface disturbance, habitat fragmentation, and water-pollution impacts of opening up adjacent privately owned areas to oil industry development. “The Wayne National Forest is owned by all Americans, and it’s a special place that deserves protection,” said Nathan Johnson, an attorney with the Ohio Environmental Council. “Tens of thousands of citizens are demanding a halt to fracking in the Wayne. The public doesn’t want to see pipelines tearing up this forest, and we don’t want fracking chemicals staining its streams. This fight is about holding the federal government accountable to both the law and the will of the people.” The protest follows a November filing by the groups that raised similar concerns about a December oil and gas lease auction in Wayne National Forest. In January the groups filed a notice of intent to sue the Bureau and the U.S. Fish and Wildlife Service for failing to consider the impacts of fracking in conjunction with white-nose syndrome and climate change effects on the endangered Indiana bat and other protected species threatened with extinction in the area.
New natural gas processing and fractionation capacity in Marcellus/Utica -- Anticipating renewed growth in natural gas and natural gas liquids production in the Marcellus and Utica plays, midstream companies active in the region are planning new gas processing plants and fractionators, as well as new NGL takeaway capacity and in-region NGL storage. And Shell Chemicals has made a Final Investment Decision to build a $6 billion, ethane-consuming steam cracker in western Pennsylvania by the early 2020s. In today’s blog, “Unleashed in the (North)East—New Gas Processing and Fractionation Capacity in Marcellus/Utica,” Housley Carr continues our series on on-going efforts by midstreamers and others to keep pace with NGL growth in the epicenter of U.S. gas and NGL production. In Part 1 of this series, we noted that RBN’s Advance, Growth and Cutback forward price scenarios call for natural gas production in the Marcellus and Utica plays to increase by 30% to 47% over the next five years, which is especially impressive when you consider that the region already is producing more than 22 billion cubic feet a day (Bcf/d). NGL production in the liquids-rich “wet” Marcellus (western Pennsylvania and northern West Virginia) and Utica (eastern Ohio) is projected to increase even more sharply, driven not only by gas production gains but by rising NGL demand (from new steam crackers and export markets) and the expectation that NGL prices will increase with that rising demand. Under RBN’s Advance Scenario (2022 Henry Hub gas prices of $3.90/MMbtu), Northeast NGL production (including ethane “rejected” into the natural gas stream as well as NGLs separated out for fractionation) would soar 74% to 1,287 MMb/d in 2022 (from 740 Mb/d in 2016) and production would rise 63% (to 1.207 MMb/d) under the Growth Scenario ($3.60 Henry Hub gas in 2022).
Fracking Caused Pennsylvania Earthquakes, New Report Confirms - Earthquakes in Pennsylvania are usually rare but fracking operations triggered a series of small temblors in Lawrence County last year, officials at the state's Department of Environmental Protection (DEP) announced in a Feb. 17 report. Hilcorp Energy Co., a Texas-based oil and gas company, was fracking a pair of wells in the Utica Shale when seismic monitors detected five earthquakes measuring between 1.8 and 2.3 on the Richter scale between April 25-26, 2016. "Our analysis after doing the review... is that these events are correlated with the activity of the operator," DEP Acting Secretary Patrick McDonnell told Penn Live . While the tremors were too small to be felt by humans or cause any damage, they are the first quakes in the state to be blamed on fracking. Pennsylvania happens to be the second largest natural gas-producing state in the country. "At least within Pennsylvania, this is the first time that we have seen that sort of spatial and temporal correlation with [oil and gas] operator activity," Seth Pelepko, chief of well-plugging and subsurface activities for DEP's oil and gas management program, told Allegheny Front , a western Pennsylvania public radio program. "No faults identified along portions of the well bore where these seismic events were detected," Pelepko continued. Hilcorp spokesman Justin Furnace said operations were immediately suspended after learning about the tremors. Fracking and stimulation operations have since been discontinued at the well pad indefinitely. The DEP said that Hilcorp was using a technique known as "zipper fracturing" at the time, which involves the concurrent fracking of two horizontal wellbores that are parallel and adjacent to each other. Four wells were drilled to depth of about 7,900 feet in that location. Evidence indicates that induced earthquakes occur when the separation between Utica Shale and basement rocks is lessened during drilling operations. That means, when someone drills too close to basement rocks, there can be earthquakes.
Quake-Producing Fracking In Pennsylvania Stopped by Company Itself - The fracking operation of a natural gas company in Pennsylvania was found to cause earthquakes in the western part of the state. The owner of the operation, Hilcorp Energy Co., had the facility very near the earthquakes; however, no damage was reported. Regardless, fracking is known to be a method that can cause earthquakes.Seth Pelepko, an official in the Department of Environmental Protection, said: “This is the first time we have seen that sort of spatial and temporal correlation.” After the earthquakes were observed, Hilcorp Energy stopped extracting the natural gas. Justin Furnace, Hilcorp’s spokesman, stated that there will be no more fracking on the site and work with the state if concerns raise.In fact, there are many different ways of fracking: The one that the Hilcorp used was ‘zipper fracturing’. This method fracks two intersecting horizontal wells. Whatever the method, Hilcorp decided to stop fracking a quarter milenear the towns where the earthquakes occured to reduce the chance of a potential earthquake.The DEP asked Hilcorp to use its seismix monitors while working near the townships in case of any earthquake that can delay fracking procedures.This is not the first time that Hilcorp was accused of its fracking operations. There had been 77 earthquakes in Poland Township, Ohio, where the magnitude was as large as 3.0. This magnitude does not hold a vital threat; however, it was clearly felt by the residents and raised concerns for the potential of a larger earthquake.Pennsylvania is still one of the states under heavy dispute. Throughout the history, the earthquakes were generally seen in the southeastern part, whereas the gas fields are in the western and northeastern part.
Pipeline Standoff: Judge won’t halt Sunoco Logistics construction plans; community foes vow to fight on: Work may have started on the Sunoco Logistics Mariner East 2 pipeline, but that hasn’t stopped the Middletown Coalition for Community Safety (MCCS) from continuing its opposition to the project. The company began the 350-mile system within days of receiving the necessary permits from the Pennsylvania Department of Environmental Protection (DEP) and learning a state Environmental Hearing Board (EHB) judge had denied a request from three environmental groups to block them. MCCS, however, is not conceding. “Sunoco intends to wreak immediate and irreparable harm in Delaware County,” according to an email from the organization. “Legal action now becomes the primary defense against this proposed pipeline, which threatens public safety, property values and constitutional private property rights.” While it was not a party, the grassroots organization supported the appeal filed by the Clean Air Council, Delaware Riverkeeper Network and Mountain Watershed Association regarding issuance of the water obstruction and erosion and sediment control permits. The action, submitted within 24 hours of Monday’s DEP ruling, called the review process “inadequate” and stated the groups would suffer “immediate and irreparable injury” if Sunoco was permitted to break ground for the controversial plan. Judge Bernard Labuskes Jr. rejected the request to halt construction and the environmental organizations filed a motion with the EHB to reconsider the decision. He set a March 1 date to hear the appeal, according to published reports. Spanning Pennsylvania, West Virginia and Ohio, the Mariner 2 system would bring natural gas liquids such as propane, ethane and butane from the Marcellus shale areas to the Marcus Hook Industrial Complex. The first 20-inch pipeline would have an initial capacity of about 275,000 barrels a day with the ability to expand to 450,000; the second 16-inch line, if needed, would have an additional capacity of approximately 250,000 barrels a day. Both lines would be included as part of the project. The DEP decision waived the seven-day notice requirement, allowing Sunoco to begin construction.
Across tough terrain, Sunoco pipeline leaves some hard feelings: While a legal battle continues over Sunoco’s Mariner East 2 project, construction of the controversial Marcellus Shale pipeline has begun in far Western Pennsylvania, where crews are working feverishly to install the pipe in a deep trench cut across the landscape. More than two dozen workers in a slow-moving caravan of heavy equipment last week worked their way up a hillside in Hopewell Township, Washington County, welding sections of 20-inch-diameter coated-steel pipe before the conduit was lowered into place and buried. It's a messy business, involving lots of earth-moving machinery and mud, and it presages the disruption that could take place this year in Delaware and Chester Counties, when Sunoco Logistics Partners LP plans to build the other end of the 350-mile pipeline connecting the Marcellus and Utica Shale production areas with Sunoco’s terminal on the Delaware River in Marcus Hook. Sunoco and the state’s political and business leaders have endorsed this $2.5 billion project, which will provide a needed market outlet for producers to send propane and other liquid fuels extracted from the shale fields, potentially fueling new industries. “It’s really been welcomed here and in southeast Ohio,” said Jeff Shields, spokesman for Sunoco Logistics, whose headquarters are in Newtown Square. Most of the fuel that will be sent to Marcus Hook is set for export to European petrochemical producers, but Sunoco also hopes to develop new local industries to buy the materials.
4 Pipeline Fights Intensify as Dakota Access Nears Completion - Under orders from President Trump , the Army Corps of Engineers on Feb. 7 approved a final easement allowing Energy Transfer Partners to drill under the Missouri River near the Standing Rock Sioux Reservation in North Dakota. Construction has re-started, and lawyers for the company said it could take as little as 30 days for oil to flow through the Dakota Access Pipeline . While the Standing Rock Sioux and neighboring tribes attempt to halt the project in court, other opponents of the pipeline have launched what they're calling a "last stand," holding protests and disruptive actions across the U.S. In North Dakota, where it all began, a few hundred people continue to live at camps on the Standing Rock Sioux Reservation, using them as bases for prayer and for direct actions to block construction.Now, most of the thousands of people that visited Standing Rock last fall have returned home, and some have taken up long-shot local fights against the oil and gas industry. In Oklahoma, Arkansas and Tennessee it's the Diamond pipeline ; in Louisiana, the Bayou Bridge . In Wisconsin, the Bad River Band of Lake Superior Chippewa actually voted to decommission and remove the Enbridge Line 5 pipeline from their reservation. Many communities have turned to direct action as a last resort. The city of Lafayette, Colorado, which has long attempted to block fracking in the area, has even proposed a climate bill of rights, enforceable via nonviolent direct action if the legal system fails. In at least four states, encampments built as bases for pipeline resistance have emerged. They face corporations emboldened by Trump and the Republican-controlled Congress, which have used their first month in power to grant fossil fuel industry wishes, overturning environmental protections, appointing former ExxonMobil CEO Rex Tillerson as secretary of state, and reviving the halted Dakota Access and Keystone XL pipelines. "Forces arrayed against us are quite wide in my opinion," said Owl, a member of the Ramapough-Lunaape tribe who helped set up a camp in New Jersey to oppose the Pilgrim pipeline. "They are hell-bent on this infrastructure." Here's what you need to know about the Trans-Pecos, Atlantic Sunrise, Sabal Trail and Pilgrim pipelines:
Pipeline fights move from Dakota prairie to Louisiana bayous | Reuters: Rosinski is fighting the latest request for a right-of-way, this time from Energy Transfer Partners - the company behind the controversial Dakota Access Pipeline. She said ETP declined to make contract changes she wanted or to properly compensate her for lost property value. Opposition to the company's planned extension of the Bayou Bridge pipeline has made Louisiana bayous the latest battleground in a nationwide war against new pipeline construction. The pushback here is one example of the increasingly broad and diverse base of opposition nationally, which now extends beyond traditional environmental activists. In Louisiana, opponents include flood protection advocates, commercial fishermen and property owners such as Rosinski. Their fight follows high-profile protests in North Dakota that were led by Native Americans and joined by military veterans, who together succeeded in convincing the Obama administration to delay construction. Although the new administration of President Donald Trump has since cleared that project's completion, pipeline companies are nonetheless taking the rising political opposition seriously. Alan Armstrong, chief executive at pipeline firm Williams Companies, told a conference in Pittsburgh that Trump's action would not hamper the protest movement. “It may even enhance it,” he said the day after Trump cleared the Dakota pipeline in January.
Counties can reject solar power but not fracking - Currituck County commissioners this week approved a motion to prohibit new solar farms.The action followed a recommendation by the county's planning board, reported by the Daily Advance.The decision followed a lively discussion lasting nearly two hours (beginning at about the 1:05 mark of the video). Ordinary folks spoke both for and against the proposal. Farmers wanted the opportunity to lease some of their land for solar panels; others said the operations are disruptive.This was a democratic process. Local people expressed their views to their local representatives. The issues had to do with economic development, quality of life and everyone's vision of what's best for Currituck County.Even as they made their decision, commissioners noted that they could reverse themselves at some future time if circumstances change.I compliment all of them for the care they took to resolve an important local question.I also noticed that there was no interference from the state legislature in this matter.Certainly not! Why should there be?Well, if the subject were a natural gas drilling operation rather than a solar farm — arguably much more potentially disruptive — our legislature would have butted in, telling the Currituck County commissioners they have no right to decide for themselves what's best for Currituck County.Our legislature would have told the good people of Currituck County to save their breath. Their views don't matter.The "fracking" law passed by the General Assembly and signed into law by then-Gov. Pat McCrory in 2014, stated: "It is the intent of the General Assembly to maintain a uniform system for the management of oil and gas exploration, development, and production activities, and the use of horizontal drilling and hydraulic fracturing for that purpose, and to place limitations upon the exercise by all units of local government in North Carolina of the power to regulate the management of oil and gas exploration, development, and production activities by means of special, local, or private acts or resolutions, ordinances, property restrictions, zoning regulations, or otherwise ..."
"Recessionary" Demand Forces New York Harbor To Divert Gasoline Shipments -- Two weeks ago, Goldman analysts were stunned when they noted that in recent weeks gasoline demand in the US has collapsed to levels that suggest not all is well with the economy. In fact, as the bank's oil expert Damien Courvalin said "to achieve the 5.9% decline suggested by the weekly data, our model requires PCE to contract 6%, in other words, a recession. Perhaps, but so far those "transient" supply factors are only getting more chronic, and as supply continues to grow in anticipation of a demand bounce that refuses to materialize, leading to ever louder speculation that there is something very wrong with the US consumer.... gasoline inventories have hit record levels, and nowhere is this more obvious than on the East Coast, where as Bloomberg writes overnight, "the biggest gasoline market in the U.S. is bursting at the seams." As a result, just like during last year's unprecedented gasoline glut which, too, was supposed to be "transient", but has only gotten worse, traders are now lining up to export gasoline and diesel from New York Harbor, an area that normally relies on fuel imports from Europe and eastern Canada. While at least 6 cargoes that were headed to New York from Europe in January and early February were diverted to the Caribbean or the U.S. Gulf Coast, that wasn’t enough to stem the oversupply building up in terminals along the Eastern Seaboard. Record-high inventories in the region are now pushing prices low enough to turn the typical trade flow on its head.
U.S. refiners cut output as gasoline glut hurts profits | Reuters: U.S. refiners are cutting output to reverse slumping profit margins due to record high inventories ahead of the critical summer driving season. Profits for making gasoline have hit their lowest levels for a year as higher prices at the pump combine with the seasonal lull in demand from motorists to cut consumption and push up inventories. Refiners are hoping that cutting runs will prevent a repeat of last winter, when the industry amassed huge gasoline stockpiles that even a record summer driving season failed to draw down. At least three refineries have cut runs, according to executives and industry sources. More are expected to follow if routine maintenance shutdowns don't ease the supply glut, said Mark Broadbent, refinery analyst at Wood Mackenzie. Marathon Petroleum Corp has cut production by 11 percent to 195,000 barrels per day (bpd) at its Catlettsburg, Kentucky, refinery over the past month, a source familiar with the plant's operations told Reuters on Tuesday. PBF Energy has cut runs at two plants, Chief Executive Tom Nimbley told investors last week. The company ran its 180,000-bpd refinery in Toledo, Ohio, at reduced rates in the fourth quarter due to weak margins, he said. PBF also shut the sweet crude unit at the company's Chalmette, Louisiana, refinery for economic reasons. Refiners producing fuel that was going into storage should be concerned about being "on a fool's errand," Nimbley said
Shale Drilling Is on a Roll as OPEC Cuts Keep Oil Above $50 - Shale wildcatters pushed ahead on the biggest surge in U.S. oil drilling since 2012 as the explorers take advantage of prices above $50 for more than two months. Rigs targeting crude in the U.S. rose by 6 to 597 this week, the highest total since October 2015, according to Baker Hughes Inc. data reported Friday. Drillers have added 72 rigs since 2017 began, the best start in five years. “We’re seeing the rise that we anticipated to take place given the OPEC cuts,” Bloomberg Intelligence analyst Andrew Cosgrove said by phone. “These gains are spreading to other plays, and this is something we’re expecting will continue through the first half given the stability in the price of oil.” Oil producers have brought 281 rigs back to work since drilling bottomed out in May, the biggest gain since producers added 361 rigs over the nine months through June 2012. U.S. crude inventories rose to 518.1 million barrels last week, the highest in weekly data going back to 1982, according to the Energy Information Administration.
OPEC Production Cuts May Have Underestimated The Permian's Improving Breakevens - Play breakevens continue lower. Higher oil prices will spur oil production increases in the US. The Permian should realize the greatest increases. Some have said US unconventional oil is a Ponzi scheme. Those who surmise this rob Peter to pay Paul conspiracy may not understand the complex realities of oil exploration and production. It's a different type of investment. Oil production has high initial costs. Some operators pay high acreage prices to get into plays late. D&C costs can be high initially, but as with most businesses, costs decrease. LOEs are also key, as those costs are stripped from revenues from the well head. This complicated industry has become more so through unconventional designs. The Peak Oil theorists were wrong, as unconventional production was great enough to effect the world's supply and demand balance. It took time, and high oil prices, but US producers got the job done. It may have gotten the job done too well.Conventional wells contrast horizontals with respect to production. Production begins and declines at a relatively low pace month over month. Horizontals produce an immense volume of resource in the first month, followed by a higher decline rate. While conventional production declines are easily calculated, it takes an engineering degree to estimate unconventional curves. The decline is not constant. Decline rates are exponential over several years then change. Initial horizontal production is created through induced fracs and the interconnected natural fracturing within the interval. After three to seven years, induced fracs stop producing, and we enter matrix production. Although a simplistic explanation, it is what many bears get wrong. Matrix production declines are much like a conventional well. Estimates vary at 3% to 5%. So if a horizontal is modeled to decline exponentially, and matrix production is not accounted for, one could model that well to zero in a shorter time.
Permian production, US crude exports have midstream companies battling for barrels - Capitol Crude podcast - The Texas Gulf Coast is gearing up to handle more US oil production and a potential rise in crude exports, but pipeline capacity already outstrips the area's refining capacity. Sandy Fielden, director of oil and products research at Morningstar Commodities & Energy, talks with senior oil editors Meghan Gordon and Brian Scheid about why even more infrastructure is being built along the US coast. Midstream companies are battling for control of the final mile from the pipeline to refineries and marine docks, and Fielden looks to some of the challenges ahead for US crude exports and possible impacts of Congress' tax overhaul plans.
Texas Oil Fields Rebound From Price Lull, but Jobs Are Left Behind - Roughly 163,000 oil jobs were lost nationally from the 2014 peak, or about 30 percent of the total, while oil prices plummeted, at one point by as much as 70 percent. The job losses just in Texas, the most productive oil-producing state, totaled 98,000. Several thousand workers have come back to work in recent months as the price of oil has begun to rise again, but energy experts say that between a third and a half of the workers who lost their jobs are not returning. Many have migrated to construction or even jobs in renewable energy, like wind power. ... Indeed, computers now direct drill bits that were once directed manually. The wireless technology taking hold across the oil patch allows a handful of geoscientists and engineers to monitor the drilling and completion of multiple wells at a time — onshore or miles out to sea — and supervise immediate fixes when something goes wrong, all without leaving their desks. It is a world where rigs walk on their own legs and sensors on wells alert headquarters to a leak or loss of pressure, reducing the need for a technician to check. And despite all the lost workers, United States oil production is galloping upward, to nine million barrels a day from 8.6 million in September. Nationwide, with a bit more than one-third as many rigs operating as in 2014, production is not even down 10 percent from record levels. Some of the best wells here in the Permian Basin that three years ago required an oil price of over $60 a barrel for an operator to break even now need about $35, well below the current price of about $53. Much of the technology has been developed by the aviation and automotive industries, along with deepwater oil exploration, over more than a decade. But companies drilling on land were slow to adapt until oil prices crashed and companies needed to get efficient quickly or go out of business.
Is Automation Limiting The Number Of Jobs Created By The Texas Oil Boom? - The New York Times reports that renewed drilling for oil and natural gas in Texas isn’t creating as many jobs as in the past. The culprit? Automation. Automation in the oil industry is reducing the demand for unskilled labor and new jobs, despite U.S. oil production hitting record highs. “Computers now direct drill bits that were once directed manually,” reports NYT. “The wireless technology taking hold across the oil patch allows a handful of geoscientists and engineers to monitor the drilling and completion of multiple wells at a time — onshore or miles out to sea — and supervise immediate fixes when something goes wrong, all without leaving their desks.”Industry experts estimate roughly 163,000 oil jobs have been lost since the 2014 crude price collapse. The price of crude oil went from $108.09 in June 2014 to $29.18 by January 2016. Job losses just in Texas, the most productive oil-producing state, totaled 98,000. Automation has replaced one-third to half those jobs, NYT reports.On the other hand, automation significantly reduced operating costs for U.S. oil producers. Break-even oil prices at productive wells fell from $60 a barrel three years ago to around $35 today.Jobs are coming back, just not at the pace they were before, and oil companies are still investing in Texas oil.Oil companies poured more than $28 billion into the Permian Basin of west Texas and southeastern New Mexico last year, and $6.6 billion was invested to double the amount of land they control in the region. Land rights in the region can retail for more than $63,000 an acre.
Huge shortage of well inspectors leaves many unmonitored -- Houston Chronicle reported today that several thousand wells just haven’t been checked recently. Not because oil and gas operations are so efficient that there are never any mistakes. But because there just aren’t enough inspectors to go around. Commissioners report that approximately 65 percent of wells haven’t been inspected for at least five years.“The Railroad Commission, which regulates the state’s oil and gas industry, says it not only has a severe shortage of inspectors – just 158 for 435,000 wells – but also antiquated computer systems that make it nearly impossible to track whether wells and their owners have histories of violating state rules and regulations.” The Chronicle reported that the Railroad Commission is seeking a special appropriation of about $45 million from the Legislature to hire more inspectors, upgrade its technology and reduce the inspections backlog, among other things. The goal is to inspect every well at least once every five years and make data more accessible to the commission and the public.
Is there enough natural gas processing capacity in SCOOP / STACK? - The SCOOP and STACK plays in central Oklahoma have emerged as two of the most productive and cost-effective plays in the entire U.S. Rigs are returning, crude oil production is rising, and so is production of associated natural gas. Moreover, the RBN production economics model shows that SCOOP and STACK will continue to be attractive to drillers under all of our various price scenarios—even if crude were to slip back below $50 and natural gas goes back into the dog house, where it has been headed the past few days. Today we continue our look at the side-by-side Sooner State plays with a review of existing and planned gas processing capacity. SCOOP and STACK (acronyms for South Central Oklahoma Oil Province and Sooner Trend Anadarko Canadian Kingfisher, respectively) sit within an 11-county geographic area in central Oklahoma where drilling activity is targeting the oil-rich Woodford and Meramec shale formations of the Anadarko Basin (see Scoop-y Doo and All Come to Look for a Meramec). Producers have successfully exploited this area for decades, but for a time production growth faded. More recently though, the region has been enjoying a revival of sorts as one of the most attractive shale plays in the U.S. Drilling activity has ramped up in recent years, led by Continental Resources in the SCOOP, and by Newfield Exploration in the STACK.
Study Links Childhood Leukemia With Living Near Oil and Gas Development -- With the rise of new technologies like fracking and horizontal drilling, oil and gas development in the U.S. has exploded over the last 15 years. As development expands, it's also pushing ever closer into areas where people live. It's been estimated that today more than 15 million Americans live within one mile of oil and gas development. The drilling process, of course, has the potential to emit toxic substances, including the carcinogen benzene, polycyclic aromatic hydrocarbons and diesel exhaust, into the surrounding air and waterways. But researchers have long been trying to determine to what extent oil and gas drilling operations may threaten public health, particularly around cancer risk. However, new research suggests that children living in areas of high-density oil and gas development may face increased risk of health impacts, namely a certain type of leukemia, as a result of their exposure to pollutants associated with this activity. In some parts of Colorado where oil and gas development is especially concentrated, hundreds of oil and gas wells reportedly lie within one mile of residential areas. And according to a recent study , children and young adults who were diagnosed with acute lymphocytic leukemia were 4.3 times more likely to live within 10 miles of an active oil and gas well than kids with other types of cancer. This finding, published in the scientific journal PLOS One, applied to youth between 5 and 24 years old. "Over 378,000 Coloradans and millions of Americans currently live within a mile of at least one oil and gas well and petroleum development continues to expand into residential areas," Dr. Lisa McKenzie said in a statement .
Colorado Fracking Suit Pits State Vs. Community – -- In the latest salvo in an intensifying national battle over climate change policy and fossil fuel extraction, Colorado Attorney General Cynthia Coffman filed a lawsuit aimed at preventing local communities from restricting hydraulic fracturing. The Republican’s lawsuit on behalf of the powerful oil and gas industry comes only a few years after fossil fuel industry campaign cash boosted her campaign for public office. Republicans have traditionally portrayed themselves as supporters of local control; during a presidential campaign visit to Colorado, Donald Trump said he supported local officials’ right to restrict fracking. But Coffman’s lawsuit aims to overturn moratoriums on fracking passed by Boulder County officials who said they wanted to develop detailed plans for orderly fossil fuel development. “It is not the job of industry to enforce Colorado law; that is the role of the Attorney General on behalf of the People of Colorado,” Coffman said in a statement that asserted the lawsuit was designed to uphold state law. “Boulder County’s open defiance of state law has made legal action the final recourse available to the state.” Coffman's lawsuit to block local fracking regulations was filed just as a new Colorado School of Public Health study found that children in the state with "leukemia were 4.3 times more likely to live in the densest area of active oil and gas wells than those with other cancers." The legal fights over fossil fuel development in Colorado carry national significance, because the political swing state has one of the country’s largest reserves of natural gas.
Thousands of spills at US oil and gas fracking sites - BBC News: Up to 16% of hydraulically fractured oil and gas wells spill liquids every year, according to new research from US scientists. They found that there had been 6,600 releases from these fracked wells over a ten-year period in four states. The biggest problems were reported in oil-rich North Dakota where 67% of the spills were recorded. The largest spill recorded involved 100,000 litres of fluid with most related to storing and moving liquids. The rapid growth in the extraction of oil and gas from unconventional sources in the US has had a massive impact on the production and consumption of energy over the past ten years. The key to this expansion has been the use of hydraulic fracturing, the process of injecting fluids with chemical additives under pressure to crack underground rock and release the trapped resources. However, environmental campaigners have long been troubled by the potential for this process to contaminate water supplies and the environment through leaks and spills. A study carried out by the US Environment Protection Agency on fracking in eight states between 2006 and 2012 concluded that 457 spills had occurred. But this new study, while limited to just four states with adequate data, suggests the level of spills is much higher. The researchers found 6,648 spills between 2005 and 2014. "The EPA just looked at spills from the hydraulic fracturing process itself which is just a few days to a few weeks," lead author Dr Lauren Patterson from Duke University told BBC News. "We're looking at spills at unconventional wells from the time of the drilling through production which could be decades." The state reporting the highest level of spills was North Dakota, a hot bed of activity in both oil and gas recovery.
Fracking Caused 6,648 Spills in Four States Alone, Duke Study Finds - Hydraulic fracturing, or fracking , has long been tied to environmental risks such as spills. The frequency of spills, however, has long been murky since states do not release standardized data. Estimates from the U.S. Environment Protection Agency ( EPA ) vary wildly. "The number of spills nationally could range from approximately 100 to 3,700 spills annually, assuming 25,000 to 30,000 new wells are fractured per year," the agency said in a June 2015 report . Also, the EPA reported only 457 spills related to fracking in 11 states between 2006 and 2012. But now, a new study suggests that fracking-related spills occur at a much higher rate. The analysis, published Feb. 21 in the journal Environmental Science & Technology , revealed 6,648 spills in four states alone—Colorado, New Mexico, North Dakota and Pennsylvania—in 10 years. The researchers determined that up to 16 percent of fracked oil and gas wells spill hydrocarbons, chemically laden water, fracking fluids and other substances.
States' data on fracking well spills inadequate for comprehensive study, researchers say - The nation's regulation of oil and gas development is a mish-mash of disjointed state oversight that makes it difficult to quantify the environmental impacts of drilling. A new study highlights just how inconsistent spill reporting is, showing that the range in requirements makes it impossible to compare states or come up with a comprehensive national picture. The research, published Tuesday in the journal Environmental Science and Technology, pulled together some of the disparate data and found there have been about 5 spills each year for every 100 wells that have been hydraulically fractured. Of the states examined, North Dakota had the highest rate of spills while Colorado companies reported just 11 spills per 1,000 wells annually. But some or all of that difference may be due to the huge differences in what the states ask oil companies to report. North Dakota requires operators to report any spill of 42 gallons or more, while Colorado and New Mexico generally don't ask for anything smaller than 210 gallons. Texas, the nation's top oil and gas producing state, wasn't even included in the study because detailed data was not easily accessible. "It's quite scattershot the amount of information being collected, the form in which it's being collected and the way in which it's being shared with the public," said Kate Konschnik, a co-author of the study and director of the Harvard Environmental Policy Initiative. The paper comes just as Scott Pruitt takes over as administrator of the Environmental Protection Agency. While the agency enforces the nation's environmental laws, many elements of oil and gas development, including fracking, are overseen by states. Pruitt was previously attorney general of Oklahoma, a top oil and gas producer, and has vigorously advocated that states should have regulatory autonomy.
North Dakota Light, Sweet Oil -- About $3 Less/Bbl Than WTI -- A Reader -- A reader writes, with regard to pricing North Dakota light sweet oil (Bakken oil): I have been tracking the monthly average price of ND sweet and WTI since March 2010. These prices are compared each month with the price for the month’s sales we receive from XTO, our largest operator. The price we receive has averaged $6.00 per barrel more than the reported ND sweet price. The received price has averaged about $5.00 less than WTI. However, breaking the WTI differential down I find that it has averaged $3.00 or less for the last two years. Big spreads impacting the long-term average were experienced primarily in 2013 when there were some rather large spreads. As a result, when I’m estimating prices, I use the WTI and back off about $3.00. The NDS price just doesn’t give me much guidance. I have no explanation for why we are so far above the NDS average but I like it! The other three operators usually run a $1.00 of so higher than the XTO price so it is not a phenomena generated by XTO. Thank you, very much appreciated. I'm curious what the experience of others receiving royalties from wells in the Bakken are experiencing. But that makes it pretty easy: during periods of less volatility in pricing it appears that ND sweet, light oil is about $3 less / bbl than the WTI quote seen.
I Must Be Doing The Math Wrong -- Fracking Sand Volume -- February 24, 2017 -- I did this while multi-tasking other tasks so there may be huge mistakes on this page. Back-of-the-envelope:
- Bakken horizontals are about 10,000 feet long
- 1 million lbs of sand = 1,000,000 / 10,000 = 100 lbs / foot
- 10 million lbs of sand = 10,000,000 / 10,000 = 1,000 lbs / foot
- 30 million lbs of sand = 30,000,000 / 10,000 = 3,000 lbs / foot
Is that correct? Note this article at Investor's Business Daily: Continental Resources (CLR) plans to use less sand than other exploration and production companies do, as demand for materials used in fracking takes off and potentially adds to cost pressures for shale companies. Glen Brown, Continental's vice president of exploration, said during a conference call Thursday that the bellwether shale company is using 1,000-2,000 pounds of fracking sand per foot as it tests enhanced completion techniques in the Bakken formation. He noted that Continental's optimum range is closer to 1,000-1,500 pounds in the company's part of the shale play, while other operators in the area are using more than 3,000 pounds. Over at "high intensity fracks" -- these are the exceptions -- run through the list, see how many are using more than 10 million lbs/frack. I'm not seeing it (yet).
Whiting Petroleum nearly doubles its capital spending budget -- Whiting Petroleum Corp., North Dakota's largest oil producer, nearly doubled its 2017 budget for capital spending as crude prices stabilize following a two-year rout. However, shares of the company were down 3.5 percent after the bell as the oil producer's revenue fell below analysts' expectations due to a steep drop in production. Oil companies are betting big on a continued rise in crude prices by buying up acreage and raising capital spending. Whiting boosted its 2017 spending to $1.1 billion from $554 million in 2016. The company's production fell 23.4 percent to 118,890 barrels of oil equivalent per day in the fourth quarter ended Dec. 31. Whiting's net loss available to common shareholders widened to $173.3 million, or 59 cents per share, in the quarter from $98.7 million, or 48 cents per share, a year earlier.
Investors Urge Banks To Support Rerouting Dakota Access Pipeline -- A group of more than 120 investors on Friday told 17 banks financing construction of the Dakota Access Pipeline that the project should be rerouted away from a Native American tribe’s reservation. “We are concerned that if DAPL’s projected route moves forward, the result will almost certainly be an escalation of conflict and unrest as well as possible contamination of the water supply,” said the statement to banks, including Citibank and Wells Fargo, which have lent money to the companies behind the 1,172-mile oil pipeline. The group of investors includes California’s giant public employee pension fund, CalPERS; New York City teacher and firefighter pensions; dozens of religious organizations; and asset management firms. They have a combined $653 billion in managed assets, according to the statement. The investors expressed support for the Standing Rock Sioux, who say that the oil line threatens their drinking water and violates territorial rights in North Dakota established by an 1851 treaty with the federal government. “We call on the banks to address or support the Tribe’s request for a reroute and utilize their influence as a project lender to reach a peaceful solution that is acceptable to all parties, including the Tribe,” the letter said. The group worries that its investments in the banks could be hurt by a public backlash against the project through legal action or boycotts. “As investors we are very concerned by the reputational and potential financial risks due to these banks being associated with DAPL,” the statement said. Representatives of the banks were scheduled to meet with tribal leaders Friday, The Financial Times reported.
Like Keystone XL, Much of Dakota Access Pipeline Steel Made by Russian Company Tied to Putin – Steve Horn - At his February 16 press conference, President Donald Trump discussed his executive orders calling for U.S. federal agencies to grant TransCanada and Energy Transfer Partners the permits needed to build the Keystone XL and Dakota Access pipeline projects. Trump also cited a different executive order signed that same day, highlighting the “Buy American measures” which he said were “in place to require American steel for American pipelines.” But like Keystone XL, as DeSmog previously reported, much of the steel for the Dakota Access project appears to have been manufactured in Canada by Evraz North America, a subsidiary of the Russian steel giant Evraz. Evraz is owned in part by Roman Abramovich, a Russian multi-billionaire credited for bringing Russian President Vladimir Putin into office in the late 1990s. DeSmog's finding comes on the heels of Trump's former National Security Adviser Michael Flynn resigning for potentially having discussed U.S. sanctions against Russia with Russian diplomats before Trump took office, apparently without the knowledge of Trump or now-Vice President Mike Pence. Lisa Dillinger, who does media relations for Dakota Access, LLC, told DeSmog that 57 percent of the pipeline was manufactured in the U.S. by both Stupp Corporation in Baton Rouge, Louisiana and Welspun in Lake Charles, Louisiana. The remaining pipe, Dillinger said, was manufactured in Canada, though she did not comment on which Canadian company manufactured the steel. Welspun does not appear to have a plant in Lake Charles, though it does have one in Little Rock, Arkansas. The company is headquartered in Mumbai, India, while Stupp is headquartered in Baton Rouge. In March 2015, the Dakota Free Press published photos of a line pipe storage site located in Brown County, South Dakota. One of those photos shows pipelines labeled “Made in Canada.” Another photo published that same month by John Davis of the Aberdeen American News also shows the pipes were labeled “Made in Canada.” As Evraz North America points out on its website, it serves as the “only supplier of fully 'Made in Canada' [large diamater] pipe.”
Deadline Looms for Dakota Access Pipeline Protest Camp (AP) -- As dawn breaks over an encampment that was once home to thousands of people protesting the Dakota Access oil pipeline, a few hundred holdouts rise for another day of resistance. They aren't deterred by the threat of flooding, nor by declarations from state and federal authorities that they must leave by Wednesday or face possible arrest. They're determined to remain and fight a pipeline they maintain threatens the very sanctity of the land. Protesters have been at the campsite since August to fight the $3.8 billion pipeline that will carry oil from North Dakota through South Dakota and Iowa to a shipping point in Illinois. Dallas-based Energy Transfer Partners began work on the last big section of the pipeline this month after the Army gave it permission to lay pipe under a reservoir on the Missouri River. The protest camp is on Army Corp of Engineers land nearby. The protests have been led by Native American tribes, particularly the Standing Rock Sioux and Cheyenne River Sioux, whose reservation is downstream. They say the pipeline threatens drinking water and cultural sites. ETP disputes that. Faced with the prospect of spring flooding, some protesters are considering moving to higher ground, though not necessarily off the federal land. Some may move to the Standing Rock Reservation, where the Cheyenne River Sioux is leasing land to provide camping space even though Standing Rock Sioux Chairman Dave Archambault has urged protesters to leave. "We have the same goals," Cheyenne River Chairman Harold Frazier said of himself and Archambault. Those urging the protesters to leave say they're concerned about possible flooding in the area as snow melts. "The purpose of this is to close the land to ensure no one gets harmed," One concern is that floodwaters could wash tons of trash and debris at the encampment into the nearby rivers. "One of the biggest environmental threats to the Missouri is the camp itself," said North Dakota Gov. Doug Burgum.
Watch Live As The Last Remaining Standing Rock Protesters Are Evicted By Police - After nearly a year of conflict, today may mark the last stand at Standing Rock as authorities’ begin their final eviction of protesters, also known as water protectors, from their camps.The standoff in North Dakota revolves around Native American opposition to the Dakota Access Pipeline (DAPL), a controversial initiative the Standing Rock tribe says crosses over land that belongs to them pursuant to the Treaty of Fort Laramie from 1868.The #NoDAPL movement gained widespread attention in 2016 after videos and reportsemerged showing law enforcement’s brutal militaristic crackdown on protests. Hundreds of water protectors have been arrested and injured — some critically. The eviction, expected imminently today, stems from an executive order signed by Governor Burgum.Breaking: North Dakota Executive Order Forcing Unarmed Indigenous People Off Treaty Lands #defundDAPL #MniWiconi pic.twitter.com/PYsmo92xrt— IndigenousEnviroNet (@IENearth) February 22, 2017 Below is a collection of live video from the ground at Standing Rock that we will update throughout the day:
Deadline to clear protest camp prompts fiery farewell - The deadline for protesters to vacate the premises of the Oceti Sakowin camp near the construction of the controversial Dakota Access camp saw about 200 protesters “ceremoniously march” through the camp only 30 minutes before the eviction took place, reports the Huffington Post today. On their way out, some of the remaining activists set fire to a some of the remaining structures, including one at the camp’s main entrance, according to USA Today. At least two people were reported injured and taken to a Bismarck hospital. You can watch the clips of the fires from MSNBC here, posted on YouTube this morning.In preparation for the camp’s evacuation, some protesters set up razor wire to block the camp’s entrance while others beat drums and sang songs on their way out of the camp. One man was seen carrying an American flag upside-down. Others set off fireworks.The camp’s evacuation came after North Dakota Gov. Doug Burgum and the Army Corps of Engineers said it was necessary to clear the area to keep people safe from flooding and to keep debris from contaminating the river system. Activists left behind mounds of garbage and debris as the camp went from thousands of inhabitants to just a few hundred people remaining behind. A Facebook post by Gov. Burgum outlined travel assistance offering each protester water, snacks, a food voucher, a personal hygiene kit, a health and wellness assessment, hotel lodging for one night, and bus fare for the return home. The travel assistance was established to help clear out the camp ahead of spring flooding. Authorities warned that any remaining protesters risk arrest.
Stunning photos show Dakota pipeline protesters setting their tents on fire as deadline to leave passes - A group of activists protesting against the Dakota Access oil pipeline set their campground dwellings on fire in a symbolic final act as the deadline for them to leave passed on Wednesday. About 150 protesters remained out of the thousands that originally occupied the main encampment in Cannon Ball, North Dakota, by the time the 2 p.m. deadline rolled around. A small group stayed after the deadline, and are facing arrest, according to media reports. "It's an act of defiance," protester Nick Cowan told The New York Times. "It’s saying, 'If you are going to make us leave our home, you cannot take our space. We'll burn it to the ground and let the earth take it back before you take it from us.'" Wednesday's deadline, issued last week by North Dakota Gov. Doug Burgum, ended six months of resistance from the local Standing Rock Sioux tribe and activists who demanded an environmental review of the pipeline before its construction. The pipeline, they fear, could result in catastrophic oil spills that would damage sacred sites and pollute the water supply. Burning the remnants of the encampment is in line with Standing Rock tradition, according to one activist and journalist at the scene. "For some Indigenous peoples, when traditional dwellings are erected they are not dismantled in a conventional way," Jenni Monet told NBC News. "They are taken apart in a ceremonial way and that ceremonial way is by burning."
10 Arrested as Deadline to Evacuate Dakota Access Pipeline Protest Camp Passes --The deadline set by North Dakota Gov. Doug Burgum for evacuating the Cannon Ball Dakota Access Pipeline protest site passed Wednesday and most protesters peacefully vacated before the 2 p.m. cutoff time. Authorities arrested 10 remaining protesters refusing to leave the campground and an estimated few dozen people are still at the site. The Chicago Tribune reported this morning that the North Dakota's governor said the remaining people "will have another chance to leave peacefully Thursday." New polling released from the Pew Research Center Wednesday shows nearly half of Americans oppose building the pipeline. Despite continued public protest across the country—including divestment movements in several major cities —lawyers for the pipeline estimated in a court filing Wednesday that oil could be flowing as early as mid-March. "These water protectors inspired people around the world by standing up for the right to clean water and a future free from fossil fuels," Greenpeace USA Climate Campaigner Mary Sweeters said. "Allies around the world acting in solidarity with Standing Rock cannot stop now. We must expose every institution pushing the Dakota Access Pipeline project through and projects like it."
Dakota Access oil could flow by March 6 | The Dickinson Press: .—A status report from the contested Dakota Access Pipeline says it has completed the pilot hole for its horizontal drill under the Missouri River and the pipeline will be ready to flow oil as early as March 6. The company filed the information in U.S. District Court in Washington, D.C., to comply with a federal court order for weekly updates on the pipeline's status while litigation with the Standing Rock and Cheyenne River Sioux tribes continues. The first status report, filed Monday, says the pilot hole that stretches 7,500 feet from one side of the Missouri River/Lake Oahe just north of Standing Rock is being reamed to accept the 30-inch-diameter pipe. Even as the $3.8 billion pipeline from North Dakota's Bakken oil fields to Illinois nears completion, the pipeline's future is in question in federal court. The tribes' attorney, Jan Hasselman, said he was surprised by the early oil-flow date, since the company told the court its best-case scenario was further out, into May. Hasselman, on behalf of the tribes, wants Judge James E. Boasberg to issue a summary judgement in the case filed against the U.S. Army Corps of Engineers after it issued a general permit for the pipeline crossing in July. "We moved fast to get in front of operations. What's disappointing is that this (flow date) is a couple of weeks earlier than it told the court was its best-case scenario," Hasselman said. "Time is of the essence, but, as the judge said, the lawsuit doesn't become irrelevant if they turn on the tap, because he can always direct them to turn it off." The case had been put on hold with the Obama administration' s decision to withhold the corps' river-crossing easement for the pipeline pending a full environmental impact statement, including whether tribal rights had been considered.
Dakota Access developer ‘underestimated’ social media opposition | TheHill: The chief executive of the company developing the Dakota Access pipeline said he “underestimated the power of social media” in the wake of massive protests agains the project. On a call with investors on Thursday, Energy Transfer Partners CEO Kelcy Warren said he was surprised by the way Dakota Access opponents could share stories about the project online and “get away with it,” Bloomberg reports. “There was no way we can defend ourselves,” Warren said, according to the report. “That was a mistake on my part.” Environmentalists and indigenous rights groups broadly oppose the Dakota Access project and have rallied that opposition through protests in Washington, North Dakota, around the country and online. They say the project threatens water supplies in North Dakota and infringes on a local tribe's rights. Opponents of the project were able to stall it for several months, but President Trump fast-tracked it in January. The company now expects to be able to move oil through the $3.8 billion, 1,172-mile project within months. Dakota Access supporters, including Energy Transfer Partners, insist they followed the law and worked to consult with the Standing Rock Sioux Tribe, which opposes the project, before finalizing the pipeline’s route. A federal judge in September mostly approved the steps taken by both Dakota Access and regulators in finalizing the project. Regardless, protests against the pipeline persisted into this month; on Wednesday, law enforcement officials in North Dakota cleared a protest camp established by the pipeline’s opponents while construction work on the project continues nearby.
Dakota Access Owner Says Pipelines Safer Than Rail Yet Owns Rail Hub Connected to Pipeline – Steve Horn - In response to the ongoing battle over the Dakota Access and Keystone XL pipelines, the oil industry and the groups it funds have started a new refrain: transporting crude oil through pipelines is safer than by “dangerous” rail. It's a talking point wedded to the incidents over the past several years which have seen mile-long oil trains derail and even explode, beginning with the 2013 Lac-Megantic oil-by-rail disaster in Quebec, which killed 47 people. These trains were carrying oil obtained via hydraulic fracturing (“fracking”) from North Dakota's Bakken Shale basin. Bakken crude may be more flammable than other crude oils and is the same oil which would travel through the Dakota Access pipeline (DAPL), owned by Energy Transfer Partners. What goes unsaid, however, is that the Dakota Access pipeline actually connects to an oil-by-rail hub, also owned by Energy Transfer Partners, in Patoka, Illinois. Patoka is the end point of this pipeline, where it links to both the rail hub and the Energy Transfer Crude Oil Pipeline Project (ETCOP). “DAPL will provide shippers with access to Midwestern refineries, unit-train rail loading facilities to enable deliveries to East Coast refineries, and the Gulf Coast market through an interconnection in Patoka, Illinois, with ETCOP, which will provide crude oil transportation service from the Midwest to the Sunoco Logistics Partners and Phillips 66 storage terminals located in Nederland, Texas,” Energy Transfer stated in an August 2016 press release. While Energy Transfer Partners has not hidden the fact that it owns the Patoka oil-by-rail hub, entities the company funds are taking a different tact, presenting inland oil transport options as being either pipeline or oil-by-rail, but not both together. “The Dakota Access Pipeline has always been committed to providing low-cost energy as safety [sic] as possible,” Standing Rock Fact Checker, a project funded by Energy Transfer Partners in reaction to protests unfolding near the Standing Rock Sioux Reservation in North Dakota, wrote in a blog post. “Pipelines are already the safest means of transporting crude oil — 5 times safer than rail, 13 times safer than shipping, and 530 safer than trucking — and the Dakota Access Pipeline will be no exception.”
Natural gas leaking from pipeline in Alaska's Cook Inlet: Natural gas for at least 10 days has leaked from an underwater natural gas pipeline in Alaska's Cook Inlet and floating ice has prevented divers from reaching the site. The gas is bubbling from a 20-centimetre pipeline in 24 metres of water about six kilometres off shore. The pipeline belonging to Hilcorp Alaska, LLC, moves processed natural gas from shore to four drilling platforms in the inlet. The Alaska Department of Environmental Conservation is investigating the leak. In an email response to questions, spokeswoman Candice Bressler said the agency is assessing public health and environmental risks. "We believe the risk to public health and safety is small," the agency said. "Environmental risk is less easy to quantify since a monitoring and assessment program is not yet in place." The federal Pipeline and Hazardous Materials Safety Administration is also investigating. The U.S. Coast Guard warned mariners to stay at least 300 metres from the bubbling gas. Another federal agency expressed concern over possible adverse effects on marine mammals. "Our greatest concern is for endangered Cook Inlet beluga whales and impacts to their critical habitat," said Julie Speegle, spokeswoman for the fisheries section of the National Oceanic and Atmospheric Administration, by email. The natural gas discharge is within the winter foraging area for the white whales, she said. ;
Traders drain pricey U.S. oil storage as OPEC deal bites | Reuters: Traders are turning the spigots to drain the priciest storage tanks holding U.S. crude stockpiles as strengthening markets make it unprofitable to store for future sale and cuts in global production open export opportunities. That could signal the beginning of the end for a two-year trade play that came about during an international price war and global oil glut. It is also what the world's largest oil exporters wanted to see when they agreed last year to work together in a historic supply cut to end the glut. From Houston through Louisiana to floating storage in the Gulf of Mexico, traders are starting to ship crude out of inventories as the rising price of oil for near-term delivery erodes the profits to be had by holding onto oil for later sale. To be sure, shipments from storage have so far made only a small dent in record U.S. crude inventories. But if prompt oil prices continue to strengthen, more storage will empty out. "Right now, traders aren't incentivized (to store)," said Sandy Fielden, director of oil and products research at Morningstar. "It won't all stampede out of the gate, but inventory levels will come down. What will happen is that some of it will go to refineries, but a fair amount will be exported too." To make money by holding crude, the spread between oil prices for future months needs to be wide enough to cover the cost of leasing tank space and borrowing the money to buy the fuel to fill it. For the last two years, U.S. traders have rushed to that opportunity as those price spreads widened.Since November, when the Organization of the Petroleum Exporting Countries (OPEC) and some non-OPEC producers agreed to cut output, the spread, or discount of prompt barrels to later supplies known as a contango, between the front and second month U.S. benchmark CLc1-CLc2 crude price has narrowed to as little as 26 cents from 95 cents a barrel. That is no longer enough to cover the more expensive storage options, traders said.
Recession Concerns Grow After Gasoline Demand Slides Most In 16 Years --Two weeks ago, we reported that when Goldman observed the latest gasoline demand data, it said that either something must be wrong with the data, or the US is in a recession: as the firm's commodity analyst Damien Courvalin put it, such a steep drop in in US gasoline demand "would require a US recession." He added that "implied demand data points to US gasoline demand in January declining 460 kb/d or 5.2% year-on-year. In the absence of a base effect, such a decline has only occurred in four periods since 1960 during which time PCE contracted."Bloomberg's Liam Denning confirms that "big dips in U.S. gasoline demand, especially of 5 percent or more, are almost unheard of outside of a recession or oil crisis." Goldman then adds that "to achieve the 5.9% decline suggested by the weekly data, our model requires PCE to contract 6%, in other words, a recession."At this point Goldman - which naturally was aghast at the possibility that there is an under the radar consumer recession taking place at a time when the bank was predicting three rate hikes - quickly pivoted and explained that a far more likely explanation is that the latest weekly report was an aberration, and that there was simply something wrong with the data. Our analysis identifies weekly yield and exports as systematically deviating from their final values and such biases suggest that demand could be revised higher by 190 kb/d. The EIA's real-time export data still includes estimates and we see potential for the recent shifts in the Mexican gasoline market to exacerbate the overstatement of US exports by an additional 185 kb/d given (1) lower PEMEX refinery turnarounds, and seasonally lower demand exacerbated by the January 16% hike in prices. Adjusting for these lower exports points to US gasoline demand declining only 85 kb/d yoy in January, in line with our macro model.
U.S. crude oil production increases following higher drilling activity -- U.S. crude oil production increased for the second consecutive month in November 2016, the first time this has occurred since early 2015. Increased drilling activity in the Permian region, which spans Texas and New Mexico, as well as the start of a number of new projects in the Federal Offshore Gulf of Mexico (GOM), more than offset declining production from other regions in October and November 2016. Increased drilling in the Permian region responded relatively quickly to a rise in the West Texas Intermediate (WTI) crude oil price, which increased from an average of near $30 per barrel (b) in the first quarter of 2016 to $45/b or higher beginning in the second quarter of 2016. In the GOM, the new projects that came online in the last quarter of 2016 were planned and approved during the 2012–14 period. U.S. crude oil production averaged an estimated 8.9 million barrels per day (b/d) in 2016, and monthly U.S. crude oil production increased by 232,000 b/d in October and by 105,000 b/d in November. Production in the Lower 48 states increased by 104,000 b/d in October and decreased by 2,000 b/d to average 6.7 million b/d in November, while GOM production increased by 85,000 b/d in October and by 89,000 b/d in November. Changes in Alaskan oil production make up the remaining differences. The Permian region was the only area covered in EIA’s Drilling Productivity Report (DPR) that did not experience a month with a year-over-year production decline throughout 2014–16. This region benefits from a number of highly productive formations located within what is an established oil-producing region that allows producers to continue operations despite low prices. When the WTI spot price rose to more than $45/b in May 2016, the Permian experienced a rapid growth in drilling rigs, increasing by 85 rigs from May to November 2016, suggesting that some operators can generate positive returns in the region at those prices.
US Shale Production To Soar By 3.5 Million Barrels/Day Over Next Five Years: BofA Explains Why - Two years ago, when Saudi Arabia launched on an unprecedented campaign to crush high-cost oil producers, in the process effectively putting an end to the OPEC cartel (at least until last year's attempt to cut production), it made a bold bet that US shale producers would be swept under when the price of oil tumbled, leading to a tsunami of bankruptcies, as well as investment and production halts. To an extent it succeeded, but where it may have made a glaring error is the core assumption about shale breakeven costs, which as we reported throughout 2016, were substantially lower than consensus estimated. In his latest note, BofA's Francisco Blanch explains not only why a drop in shale breakevens costs is what is currently the biggest wildcard in the global race to reach production "equilibrium", but also why US shale oil production could surge in the coming years, prompting OPEC to boost production in hopes of recapturing market share. Specifically, Blanch predicts that US shale oil production could grow by a whopping 3.5 million barrels per day over the next five years. Here's why: as he explains "many oil companies around the world have survived the price meltdown by bringing down breakeven costs in the last two years. But what parts of the world can grow output in the years ahead? In BofA's view, US shale oil producers will come out ahead and deliver outsized market share gains by 2022. Shale oil output in the US may grow sequentially by 600 thousand b/d from 4Q16 to 4Q17 on increased activity in oil rigs and fast productivity gains. Importantly, breakeven costs for key major US plays now stand around the $55/bbl mark. As crude oil prices recover further, cost reflation may partly offset reduced costs linked to less regulation. So assuming a gradual recovery in oil prices into a long-term average of $60 to $70/bbl, BofA projects average annual US shale oil growth of 700 thousand b/d in 2017-22, or roughly 3.5 million bpd over the next 5 years. Shale production could rise even more if prevailing oil prices are higher than $55/barrel. Here is BofA's sensitivity analysis: We estimate that US shale production will decline annually by 270 thousand b/d, on average, until 2022 in a $40/bbl WTI environment. At $50/bbl, growth returns, though only at a small average of 240 thousand b/d. Should WTI trade at $60 for the next five years, growth reaches 700 thousand b/d, and at $70/bbl it reaches 950 thousand b/d (Chart 15). It goes without saying that the level of US shale output in 2022 will highly depend on the average price of WTI in the next five years (Chart 16).
U.S. crude oil imports from Saudi Arabia and Iraq combined recently approached five-year high, but are expected to decline - In November 2016, high production and seasonally low internal demand contributed to record crude oil exports from Iraq and near-record exports from Saudi Arabia (according to the Joint Organizations Data Initiative (JODI), with published data dating to January 2002). In that same month price spreads in the market supported high levels of U.S. crude imports from those countries. However, market developments, including the November 2016 agreement among certain members of the Organization of the Petroleum Exporting Countries (OPEC) to reduce production and the recent widening of the spread between Dubai/Oman crude and U.S.-produced Mars crude, suggest U.S. imports from Saudi Arabia and Iraq are now becoming less attractive to U.S. refiners. According to the latest JODI data, Saudi crude oil exports reached 8.3 million barrels per day (b/d) in November 2016, the highest level since May 2003, before declining to 8.0 million b/d in December. Saudi exports generally increase from August to November as seasonal declines in domestic consumption increase availability of oil for export. In Iraq, exports reached a record high of almost 4.1 million b/d in November and remained at that level in December (Figure 1). According to JODI data, Saudi and Iraqi production levels were relatively high prior to the pledged production cuts beginning January 2017, with December 2016 volumes up 321,000 b/d and 700,000 b/d, respectively, from their year-ago levels, creating an opportunity to increase exports.
U.S. Crude Exports Surge to a Record – Another week, another record for U.S. crude exports. Producers and traders shipped out 1.21 million barrels of crude a day from the U.S. in the week that ended February 17, the most in Energy Information Administration data going back to 1993. Domestic output increased to 9 million barrels per day last week, the fastest pace since April, while U.S. refiners used the least crude since October 2015. Shale output has surged and tankers loaded in the Middle East during the last days of all-out production by OPEC nations arrived this month in the U.S., swelling stockpiles to a record. Prices for West Texas Intermediate crude have averaged $2.24 a barrel below global marker Brent this year, making U.S. oil more attractive to refiners around the world. Local refiners are using as much domestic crude as they can and the remaining incremental production is being exported, Gary Morgan, director for Clarksons Platou Shipping Services USA LLC’s analyst group, said by phone from Houston. "Going forward, most of the increasing production will be for exports. As output moves from 9 million barrels a day to 9.3 million or 9.4 million, three-quarters of that increased output will be for export." For now, U.S. crude is looking especially attractive to buyers in Asia. WTI has averaged 22 cents below Dubai, a lower-quality grade that’s the benchmark for Asia, this year, based on front-month swaps data from broker PVM Oil Associates Ltd.. That compares to a $3.76 premium a year ago. Most of the incremental volumes from last week were destined for the Far East, Court Smith, director of research with shipbrokers MJLF & Associates, said by instant message from Stamford, Connecticut. "The Far East will remain the main destination for U.S. crude exports in the short-term, assuming there are no big swings in price spreads."
Shale production will be used for export, won’t hurt OPEC cuts -- OPEC’s agreement to cut production in order to boost the global oil market seems to be working, but new reports indicate the organization could extend the cuts. The group is likely to determine whether or not to continue with the cuts at its bi-annual meeting, scheduled for May 25. Seeking Alpha explains three reasons why this could happen:
- The “hangover” from overproduction in November and December was felt in January and February, so the positive effects from the cuts are just beginning to show. The six-month production cut now looks more like a four-month cut.
- Analysis of data from the cuts will take a while, and the short time until the May meeting may not be enough time to figure out whether or not the cuts did any good.
- Reports from Saudi Arabia show that the Saudi Aramco IPO will be delayed until 2018. This means that Saudi Arabia will have to support higher oil prices longer, since there’s not enough time to “fundamentally shift oil tactics” before the IPO, so staying on course is better for keeping oil prices higher.
Analysts around the world have speculated about compliance by OPEC since the agreement to cut production was signed. So far, reports show about a 90 percent compliance rate for OPEC and 40 percent for non-OPEC producers, according to Seeking Alpha. Even if some countries OPEC countries cheat, and compliance is not total, production cuts in any form are better than ending the agreement. Plus, the International Energy Agency (IEA) has said this is one of the “deepest cuts on record.” So despite some the fact the United Arab Emirates (UAE) has delivered smaller portions of their pledged reductions, Reuters reports that However, oilfield maintenance could help push the country’s compliance higher. The UAE’s OPEC governor, Ahmed Al Kaabi, told Reuters it is committed to OPEC cuts and is taking necessary measure to ensure it is fully compliant. Oil inventories are still high, and a glut still exists. Reuters reporters Catherine Ngai and Liz Hampton note that traders are reducing U.S. crude stockpiles, since it is unprofitable to store for future sales. This “could signal the beginning of the end for a two-year trade play that came about during an international price war and global oil glut.” In the last week, U.S. crude exports have hit a record high, and producers and traders have shipped 1.21 million barrels of crude a day.
U.S. shale revival likely to cap oil price gains: Kemp (Reuters) - U.S. shale producers are growing production again, renewing the challenge to OPEC’s market share and potentially limiting further increases in oil prices during 2017/18.U.S. crude and condensate production increased in both October and November, the first back to back increases since early 2015, according to the U.S. Energy Information Administration (http://tmsnrt.rs/2lOpdAs).Domestic oil production rose to 8.9 million barrels per day (bpd) in November, up from a cyclical low of 8.6 million bpd in September (“U.S. crude oil production increases following higher drilling activity”, EIA, Feb. 21).Offshore production from the Gulf of Mexico accounted for more than half the total gain, adding an extra 175,000 bpd, with output from Alaska’s North Slope also up 61,000 bpd.However, production increases were also reported from onshore predominantly shale plays in North Dakota (an extra 65,000 bpd), Oklahoma (11,000 bpd), New Mexico (15,000) and Texas (43,000 bpd).Production from the contiguous United States excluding the Gulf of Mexico was still down by almost 550,000 bpd (7.5 percent) in November 2016 compared with November 2015.But the annual decline was sharply lower than in May 2016 when output was down by almost 820,000 bpd (11 percent) compared with the same month a year earlier (http://tmsnrt.rs/2mfDDXA).U.S. oil production appears to have resumed an upward trend, after reaching a trough in September, and output was likely flat or higher in December, January and February. The number of rigs drilling for oil has risen by more than 280 (almost 90 percent) since the end of May 2016, according to oilfield services company Baker Hughes. Exploration and production firms are deploying an average of an extra 10 to 15 rigs each week to boost their oil output (http://tmsnrt.rs/2ltZmgn). And the increase in the rig count understates the extra new production because drilling and fracking operations have become much more efficient. Rig counts tend to affect recorded output with a significant lag because of delays in fracturing and other completion services as well as the gap before new production is reported.
ExxonMobil forced to make cuts to reported oil and gas reserves -- Reported oil and gas reserves at ExxonMobil dropped by 19 per cent last year as it revised away 3.5bn barrels of heavy bitumen at an oil sands project in Canada, the largest drop to be reported by one of the big international oil companies for at least a decade. In its 10-K annual report, filed to the Securities and Exchange Commission on Wednesday evening, Exxon said low oil and gas prices during 2016 meant that some of its assets no longer qualified as proved reserves. Its reported reserves were cut from 24.8bn barrels of oil equivalent at the end of 2015 to 20bn boe at the end of 2016. It is the second year in succession that Exxon’s reported reserves have fallen. It said that the cut, which was required by the SEC’s reporting rules, was “not expected to affect the operation of the underlying projects or to alter the company’s outlook for future production volumes”, and added that it could be reversed wholly or partially if crude prices recover. Exxon also defended its decision to take only relatively small charges for writing down the values of its assets because of weak oil and gas prices, saying “management does not believe that lower prices are sustainable if energy is to be delivered with supply security to meet global demand over the long term”. Although the drop in reported reserves does not have any direct impact on production or earnings, it underlines the strategic challenge the company faces in finding growth.
Exxon Cuts Reserves By A Record 3.3 Billion Barrels As Oil Crash Finally Takes Toll - Last September, when the price of oil was well below where it had been trading for the bulk of the past several years, we reported that NY Attorney General Eric Schneiderman was probing why Exxon Mobil hasn’t written down the value of its assets, two years into a pronounced crash in oil prices. The complaint was simple: out of the 40 biggest publicly traded oil companies in the world, Exxon - then still led by now Secretary of State Rex Tillerson - was the only one that hasn’t booked any impairments in the prior 10 years. And yet, Exxon had - until the later half of 2016 - declined to take any write-downs, the only major oil producer not to do so, which has led some analysts to question its accounting practices. All of that changed this afternoon, when Exxon, now ex-Tillerson, disclosed the deepest reserves cut in its history as the ongoing rout in oil prices erased the value of a $16 billion oil-sands investment and other North American assets. In a press release filed after the close, Exxon announced that "proved reserves were 20 billion oil-equivalent barrels at year-end 2016, inclusive of a net reduction of 3.3 billion oil-equivalent barrels from 2015. Reserves changes in 2016 reflect new developments as well as revisions and extensions to existing fields resulting from drilling, studies, analysis of reservoir performance and application of the methodology prescribed by the U.S. Securities and Exchange Commission." As a result of very low prices during 2016, certain quantities of liquids and natural gas no longer qualified as proved reserves under SEC guidelines.In other words, after years of denials, and claims that "we don't do write-down", Exxon just concluded the biggest reserve cut on record, as 3.3 billion barrels of crude was removed from the company's "proved reserves" category. Following the reserve cut, the company's total reserves dropped to 20 billion, the lowest in two decades.
Former Boehner Staffer Follows Revolving Door, Now Latest KXL Lobbyist -- TransCanada has wasted no time since President Donald Trump signed a January 24 executive order calling for U.S. federal agencies to permit construction of the Keystone XL pipeline. The Calgary-based company has already re-applied for a presidential permit through the U.S. Department of State to cross the U.S.-Canada border with the pipeline and has also applied in Nebraska to build the line across that state. It also has registered to lobby the federal government, deploying lobbyist and former GOP Congressional staffer Jay Cranford of theCGCN Group, for the job. As DeSmog has previously reported, fellow CGCN Group lobbyist Mike Catanzaro is the presumed choice for top energy adviser to President Trump. Catanzaro has a track record as a climate change denier and has lobbied for companies such as Devon Energy, America's Natural Gas Alliance (ANGA), and others.During 2016, Cranford lobbied alongside Catanzaro for an industry client list which included Encana Oil and Gas, Hess Corporation, Noble Energy, American Fuel and Petrochemical Manufacturers, Halliburton, and Koch Industries.Cranford's biography on the CGCN website reads like the prototype for the government-industry revolving door. “[Cranford] joined John Boehner’s leadership team in 2006 when the Ohio Republican was elected majority leader. During his time with Boehner, Cranford oversaw work on six committees, including Energy & Commerce, Natural Resources and Transportation and Infrastructure,” it says. “In that role, he helped coordinate legislative strategy with party leaders, rank-and-file lawmakers and the White House.” Cranford has worked as a pipeline lobbyist before, advocating on behalf of El Paso Corporation. Before joining the staff of Rep. Boehner (R-OH) — who himself is also now a lobbyist — Cranford served as staff director of the U.S. House Natural Resources Committee's Subcommittee on Energy and Minerals. While in this position, Cranford took several industry-funded trips, funded by the likes of BP, Shell, American Petroleum Institute, and Independent Petroleum Association of America.
Trump: Keystone, Dakota Access pipeline makers must buy US steel: President Donald Trump on Thursday said the companies behind two hotly contested oil pipelines must use U.S. steel in their projects. Trump ordered the Department of Commerce last month to develop a plan that would require any company that builds a pipeline within U.S. borders to use American-made materials and equipment. But he has previously stopped short of language suggesting a requirement in public statements, instead saying he would like the projects to be built with U.S. raw steel and pipes. The Commerce Department has not yet issued a report on the requirement, but Trump on Thursday said the companies behind the Keystone XL and Dakota Access pipelines would "have to buy" pipes made from U.S. steel. "And you're going to be doing pipelines now, you know that, right?" Trump told United States Steel CEO Mario Longhi during a meeting of business leaders at the White House. "We put you heavy into the pipeline business because we approved, as you know, the Keystone pipeline and Dakota, but they have to buy, meaning steel, so I'll say U.S. steel, but steel made in this country and pipelines made in this country." The requirement to use U.S. steel would create challenges for TransCanada because much of the pipe for its Keystone XL project has already been manufactured.It is unclear how the mandate would affect Energy Transfer Partners, since all but a small portion of its Dakota Access pipeline has been built. Energy Transfer expects the project to be ready to ship oil on April 1.
Canada's Trans Mountain crude oil pipeline oversubscribed by 25% in March - Kinder Morgan Canada will limit crude nominations on its Trans Mountain pipeline system by 25% in March, meaning the line will only carry 75% of nominated volumes, the company said Tuesday. March volumes on the Trans Mountain mainline system are expected to average 296,105 b/d, down from 326,280 b/d in February, Kinder Morgan said in an email. Exports from the Westridge Dock near Vancouver are expected to average 80,648 b/d in March, compared with 81,888 b/d in February. Vessel loadings are expected to consist of two barges and five tankers, the same amount as in February, Kinder Morgan said. Throughput on the Puget Sound pipeline is expected to average 136,546 b/d in March, down from 146,833 b/d in February. The Trans Mountain pipeline ships Canadian crude from Edmonton, Alberta, to the Westridge export terminal in Burnaby, British Columbia, and on to the connected 180,000 b/d Puget Sound pipeline to Seattle-area refineries.
Exxon to Leave Up to 3.6 Billion Barrels of Tar Sands/Oil Sands in the Ground -- ExxonMobil Corporation will admit this week that it can no longer profitably develop up to 3.6 billion barrels of its Alberta tar sands/oil sands reserves unless oil prices rise, the Wall Street Journal reports. The formal acknowledgement, forced on Exxon by the U.S. Securities and Exchange Commission, followed a quarterly report last fall in which Secretary of State Rex Tillerson’s former employer admitted that up to 4.6 billion barrels of its reserves might have to stay in the ground. The move comes after Exxon burned through $20 billion to “put the oil sands at the centre of its growth plans” through its Kearl project, about 70 kilometres north of Fort McMurray, and “highlights how dramatically the prospects of the region have dimmed,” the Journal reports [sub req’d]. “Once considered a safe bet, Canada’s vast deposits are emerging as a prominent case of reserves being stranded by a combination of high costs, low prices, and tough new environmental rules.” “For a lot of reasons the oil sands look like a prime candidate for eventual abandonment,” Baker Institute energy fellow Jim Krane told the WSJ. “One problem is that costs are persistently higher. The high carbon content only makes it worse.” The uniquely carbon-intensive process for extracting Alberta heavy oil and bitumen, the Journal acknowledges, has prompted the federal and provincial governments to introduce an (not necessarily foolproof) emissions cap and a carbon levy, on top of the already-high cost of tar sands/oil sands production. The Journal points to continuing low oil prices as the central factor that has “altered investment priorities” for fossil producers, drawing emphasis away from expensive (and acutely environmentally sensitive) Arctic, ultra-deep, and tar sands/oil sands deposits. “Such projects can require billions of dollars in up-front investment and seven to 10 years, or even more, to bring returns. Now companies are turning to new sources of crude oil, such as shale, that don’t require the same massive investment of time and money to bring to production,” the paper states. Citing ARC Financial, the WSJ says the price crash and ensuing shift in priorities have so far doomed at least a dozen and a half projects representing 2.5 million barrels of production per day. “Barring some geopolitical catastrophe that really changes the outlook,” said Amy Myers Jaffe, executive director for energy and sustainability at the University of California, Davis, “all these other projects are going to take the wind out of the oil sands.”
Canada's Fading Oil Promise Leaves US Majors Struggling - Oil-sands investments in Western Canada that gobbled tens of billions of dollars over the past decade are proving an Achilles heel for some of the world’s biggest energy producers. Exxon Mobil Corp. slashed proved reserves the most in its modern history after removing the entire $16 billion, 3.5-billion-barrel Kearl oil-sands project from its books on Wednesday. That followed ConocoPhillips’ announcement a day earlier that erased 1.15 billion oil-sands barrels, plunging its reserves to a 15-year low. While prolific shale plays in Texas and Oklahoma are going through an investment boom with oil above $50 a barrel, the oil sands have fallen out of favor. Current investments in the region amount mostly to long-planned expansions by large Canadian producers like Suncor Energy Inc., while majors like Statoil ASA have sold assets. Suncor, which took over Canadian Oil Sands Ltd. less than a year ago, is down more than 3 percent this year in Toronto. The oil-sands operations in northern Alberta are among the costliest types of petroleum projects to develop because the raw bitumen extracted from the region must be processed and converted to a thick, synthetic crude oil. In addition, Canadian crude sells for less than benchmark U.S. crude because of the added cost to ship it to American refineries and an abundance of competing supplies from shale fields. That’s why the oil sands have been particularly hard hit by the worst oil slump in a generation. The combined 4.65 billion barrels of oil-sands crude removed from Exxon’s and Conoco’s books are worth $183 billion, based on current prices for the Western Canada Select benchmark. The revisions hit as both U.S. companies, along with the rest of the oil industry, strove to recover from a 2 1/2-year market slump that collapsed cash flows, wiped out hundreds of thousands of jobs and prompted many explorers to cancel their most ambitious drilling programs.
Alberta’s Growing $30-Billion Liability: Inactive Wells - Alberta has among the continent’s most permissive policies on cleaning up inactive oil and gas wells, and that could saddle taxpayers with more than $30 billion worth of liabilities, according to a new report. While most North American jurisdictions require companies to clean up and restore non-producing oil and gas wells in a timely fashion, Alberta doesn’t, says the report by University of Alberta economist Lucija Muehlenbachs, also a visiting fellow at the U.S. think tank Resources for the Future.Most jurisdictions require companies to shut down and clean up wells that have been inactive for specified periods. Alberta allows companies to say wells are “suspended” indefinitely. “Alberta is one of the more lenient jurisdictions as it has no limit set on the length of time a well can remain suspended,” explains Muehlenbachs in a briefing paper released last week for the School of Public Policy at the University of Calgary.North Dakota, which has no backlog of inactive wells, requires that wells that been inactive for 12 months be properly plugged and decommissioned immediately or within a two-year time period. But Alberta’s lax policies have helped the number of inactive wells triple in the last 20 years from 25,000 in 1989 to 81,602 inactive wells as of Nov. 26, 2016. That means that one-third of the 255,000 oil and gas wells in Alberta are inactive. More than 10,000 of the inactive wells have been sitting idle for decades.Inactive wells pose a variety of environmental and financial risks to the public. Most inactive well sites leak methane and can contaminate soil and groundwater and support invasive weed growth. They also fragment ecosystems, devalue property and prevent farmers making full use of their land. The Alberta Property Rights Advocate Office warned in its annual report last year that conflicts between landowners and oil and gas companies were escalating as companies, struggling with low oil prices, walked away from lease agreements and reclamation responsibilities. Inactive wells also represent a staggering potential liability for taxpayers: they can cost anywhere from $50,000 to millions of dollars to plug, abandon and reclaim.
Rare cargo of US MTBE headed to Mexico: sources - A cargo of US-produced MTBE was bound for Mexico Wednesday, for just the second time this year, sources said. Fixtures for MTBE are not often seen on the spot market, a source with a shipbroker said. MTBE is primarily used as a blending agent in gasoline to increase the octane level. However, since the product is banned in the US due to environmental concerns, all MTBE produced in this country is either directly exported or blended at a load port to achieve a specific grade of gasoline. A shipping source agreed. "PMI often moves MTBE to the east coast of Mexico, but they normally blend it with unleaded gasoline at the load port to get a specific grade," he said. "But, once in a while, they take a full load of MTBE as well." On Wednesday, the Cape Bacton was heard to be fully fixed by PMI at a lump sum of $180,000 to move a 38,000 mt cargo of MTBE from the US Gulf Coast to the east coast of Mexico. The ship is due to begin loading February 24. That freight rate calculates out to $4.74/mt, or 57 cents/b.
Total US gas exports to Mexico set to rise 30% in 2017: Platts Analytics - Platt’s snapshot video - US natural gas exports to Mexico could reach as high as 5.4 Bcf/d by late summer 2017, according to data from Platts Analytics' Bentek Energy, but will be highly dependent on a roughly 4.1 Bcf/d year-on-year build in export capacity. Ross Wyeno, senior energy analyst, shares forecasts around Mexico's natural gas supply and details about four new pipelines that will increase Texas' exports to its southern neighbor.
Mexico turns to the Jurassic era for shale oil -- Mexico’s plans to develop its shale oil resources have finally taken a step forward following years of largely fruitless efforts by the state owned company Pemex. Canada’s Renaissance Oil and Russia’s Lukoil are joining forces to develop the Amatitlan block of the Chicontepec region. They aren’t interested in the shallower tight oil, but in the stack’s deeper Pimienta shale formation, which is what they consider Mexico’s Eagle Ford. Renaissance and Lukoil agreed to a $60 million accelerated development plan for the Amatitlan block for 2017, which will include workovers of existing wells, and the drilling of new wells. The Pimienta formation, located in the Upper Jurassic layer of the Chicontepec, is an important play for the future production of Mexico, as output has been trending lower. Renaissance estimates original oil in place in the Amatitlan block at 4.2 billion barrels of oil equivalent, and estimated the Pimienta section at 564 boe per acre-foot, compared with Eagle Ford at 598 boe. Also, both formations have similar pore pressure. Despite being discovered in 1962, the Amatitlan is largely underdeveloped. The field has produced about 175,000 barrels of light oil, ranging from 34 to 44 API. Pemex estimates that the entire Pimienta holds 20.8 billion boe, mostly liquid hydrocarbons. In 2014, Pemex explored for the first time the Pimienta formations by drilling three conventional exploratory wells. According to Nick Steinsberg, director of engineering with Renaissance Oil, one of these wells has produced close to 800 b/d. Renaissance is bringing shale experience to the project. Steinsberg pioneered horizontal drilling in the US Barnett Shale with Devon Energy. Dan Jarvie, Renaissance’s chief geochemist, was the former chief geochemist of EOG Resources, Eagle Ford’s largest shale producer.
Platts overhauls Brent crude benchmark, adds field - - The North Sea oil grades that underpin the global Brent crude price benchmark have been expanded to address the region's declining production, price reporting agency S&P Global Platts announced Monday. Oil from the Troll field in the Norwegian part of the North Sea will be added to the basket of crude used to calculate the benchmark from 2018, Platts said. The Brent crude price, based on four physical oil streams extracted from fields in the North Sea, is what the majority of the world's physical crude is priced off. The existing basket used to set the price includes Brent Ninian Blend, Forties, Oseberg and Ekofisk. The addition of Troll, a field operated by Norway's Statoil should increase deliverable supplies by around 20%. It will also mean Statoil overtakes Royal Dutch Shell PLC RDSA as the most dominant producer of the streams used to calculate the Brent price. North Sea oil production has been slowly declining since 2000 which is problematic because a robust volume of oil is needed to underpin a benchmark. Platts has addressed this by repeatedly adding to the grades used to calculate the price.
Platts revamps Brent oil benchmark for first time in a decade | Reuters: Oil pricing agency S&P Global Platts is making the first major overhaul of its Brent oil price assessment in a decade, to address falling supplies of the crude oil grades underpinning the benchmark that prices most of the world's oil. A decline in supply from North Sea fields has led to concerns that physical volumes could become too thin and hence at times could be accumulated in the hands of just a few players, making the benchmark vulnerable to manipulation. Platts said on Monday it would add Norway's Troll to the basket of four British and Norwegian crude grades which it already uses to assess dated Brent from Jan 1. 2018. This will join Brent, Forties, Oseberg and Ekofisk, or BFOE as they are known. "Overall we have had significant support for the addition of a new grade to the basket," Jonty Rushforth, global editorial director for S&P Platts Global's oil and shipping price group, said at an industry conference. "Far and away, Troll has received the most support." Troll will add about 200,000 barrels per day, or 20 percent, to the basket of crude supplies underpinning the benchmark, Platts said. The move was in line with expectations after Platts said in December it was being considered. Brent is used to set the price of billions of dollars of daily oil trade though a forward market for BFOE crude cargoes, swaps markets, physical benchmark dated Brent and Brent crude futures.
Brent market tightens sharply as traders eye stock draws, possible squeeze: Kemp - Brent futures prices for the second quarter have risen strongly in recent days suggesting traders expect the oil market to move into deficit earlier or that a squeeze is underway. Calendar spreads for nearby months have tightened sharply since the middle of February to a level that will make storing oil outside the United States unprofitable from the start of the second quarter onwards.The calendar spread from April to May has tightened from a contango of 35 cents per barrel on Feb. 15 to just 17 cents on Feb. 20 and is now trading around 12 cents (tmsnrt.rs/2mhTrZd).The spread is now too narrow to cover the cost of financing and storing barrels under any set of realistic assumptions about the cost of borrowing money and leasing tank space.Spreads are even narrower for later months, with a contango of just 10 cents for May-June and 7 cents for June-July.The spread tightening has been concentrated in the second quarter which implies traders now expect a supply deficit to occur from April rather than June (tmsnrt.rs/2mhEB4W).Calendar spreads have tightened much more in Brent than in WTI - where the spreads remain wide enough to finance crude stockpiles in the United States through until about June (tmsnrt.rs/2lirXoA).If the tightness in Brent persists, physical traders will have an incentive to unwind cash-and-carry storage trades where they hold a long position in physical oil and a short position in futures. Physical barrels will be sold from stockpiles to refiners and reported inventories should start to decline rapidly.
North Sea oil output jumps for second year - UK oil production rose for a second year in a row in 2016, increasing by 5% to 1.01 million b/d of oil equivalent, according to figures released Thursday, encouraging those who argue the North Sea industry still has life in it yet. For the full year, UK crude output increased by 3.2% to 914,000 b/d, while output of natural gas liquids rose 30% to 99,000 b/d, the government's department for business, energy and industrial strategy said. "Following strong production in 2015, crude oil production from the North Sea has been steady from fields that feed into the Flotta and Forties terminals," the department said. However, UK oil production levels remain barely a third of their 1999 peak, it added.Maintenance at the UK's largest producing field, Buzzard, meant liquids output dropped 5% in the fourth quarter from a year earlier, to 11.57 million mt, or 979,000 boe/d. In terms of trade, oil exports increased by 5% in the full year, to 33.31 million mt, while imports fell 5.8% to 42.53 million mt, as refineries sourced a higher share of their crude from the North Sea. The numbers confirm a revival in output caused partly by a surge in investment before oil prices slumped in 2014, as well as upstream tax cuts last year, the setting up of a new regulator, and efficiency measures. Separately on Thursday, US upstream company Apache confirmed plans to start production in the third quarter of this year from a UK discovery known as Callater, which lies near the Beryl field and holds 25 million-50 million barrels of oil equivalent, mainly in the form of liquids. Output should also be boosted by the imminent restart of the BP-operated Schiehallion field west of the Shetland Islands, following a four-year redevelopment.
Oil and gas discoveries at lowest level in 60 years - Discoveries of new oil and gas fields have dropped to a fresh 60-year low, as companies put a brake on exploration and large fields have become harder to find. There were only 174 oil and gas discoveries worldwide last year, compared with an average of 400-500 a year up until 2013, according to IHS Markit, the research group. The slowdown in exploration success shows that the world is likely to become increasingly reliant on “unconventional” resources such as US shale oil and gas to meet demand for energy in future decades. The typical time from discovery to production is five to seven years, so a shortfall in oil and gas discoveries now implies tighter supplies in the next decade. However, there are signs of a tentative upturn in conventional exploration this year, with some companies including Statoil of Norway planning to step up drilling activity.
Natural Gas - An Ugly Week - In recent weeks, I have been cautioning about the downside potential in the natural gas futures market as we are running out of winter weeks. I wrote that the energy commodity had been trending lower since the beginning of 2017. Although there are some pretty juicy price gaps on the daily and weekly charts on the upside, the magnetic force on the bullish side of the market has not been strong enough to entice the price higher. Natural gas had a great run at the end of 2016, the price on the nearby NYMEX futures contract traded to a high of $3.9940 per MMBtu at the end of December. Since then, it has been all downhill. Natural gas is one of the most volatile commodities that trade and while other commodities continue to trade at the upper ends of their trading ranges over the last year, action in the natural gas market turned ugly last week as a critical psychological level gave way. The risk in natural as right now is that speculators will try to create a repeat performance of last year's price action and given the activity in the March futures contract last week, they seem to be on their way. Last week, natural gas not only fell below the critical $3 per MMBtu level but it also took out the $2.90 level.As the weekly chart highlights, it has been a one-way street lower for natural gas prices in 2017. March natural gas closed on Friday, Feb. 10 at $3.035 per MMBtu. The energy commodity had not traded below $3 since the middle of November but last week that changed and the price did not manage to put up one print above that price. The weekly slow stochastic is trending lower and the prospects for even a relief rally at this point are slim given recent price action.
Natural Gas Bulls Crushed As Prices Tank - Natural gas prices plunged to their lowest level since November on mild weather in the U.S., which has caused storage levels to decline at a much slower pace than expected. Contracts for March delivery on the Nymex exchange dipped to $2.63 on February 21, down a third since December. The bearish swing has come after successive EIA reports showing a modest drawdown in gas inventory levels. Natural gas consumption is seasonal, with spikes in demand occurring in winter months. As such, storage levels build up over the course of the year, especially in the milder months of spring and fall. Then, gas is used up in the winter. The winter of 2016 was the warmest on record, leading to a paltry drawdown in inventories. The result was a cratering of natural gas prices last year as inventories swelled following the end of winter. This winter things were supposed to be much tighter. After all, upstream production fell last year after a decade of relentless growth. Meanwhile, the hollowing out of the coal industry has led to a corresponding uptick in natural gas consumption in the electric power sector, which is another way of saying that gas demand is rising on a structural basis. Also, LNG exports started to pick up last year, opening up another source of demand for U.S. natural gas. And the market has indeed tightened. Record high natural gas inventories have declined this winter, falling back closer to more average levels. But they have not declined as much as gas bulls may have liked. Front-month natural gas prices fell to $2.63/MMBtu in the third week of February, down from nearly $4/MMBtu at the end of last year.
Natural Gas Prices Plummet As Weather Forecasts Shift More Bearish - The latest weather update now pits February 2017 as the warmest February since 1970. For the month of February (2/3 to 3/3 week), HFI Research is forecasting -363 Bcf versus the -720 Bcf five-year average draw. Since the start of 2017, bearish weather has added 700 Bcf to the end of storage April estimates. Our EOS is updated daily, but the latest one pits April EOS at 2.1 Tcf or 300 Bcf higher than the five-year average. To give you an idea just how warm this Winter has been so far, Genscape Weather posted this: As a trader told us, "It was cold in all the places that shouldn't be cold and hot in all the wrong places." The structural deficit that continues to plague the physical side of the market has not gone away and will increase in the months to come as new power generation, higher Mexico gas exports, LNG, and industrial demand add 2.8 Bcf/d to total demand. The wide structural deficit did help accelerate storage draws this Winter, but it was not enough to fight off the bearish heating demand. As readers will see in the next several weeks, the weekly EIA storage reports will gradually get worse, and 2/24 week is now expected to be -140 Bcf less than we previously expected. The changes came mostly in the last 2 weeks. As traders combat the bearish short-term outlook with the long-term bullish outlook, we think the spreads for the shoulder months and Summer months could remain wide as the basket widened by $0.05/MMBtu today. We recently released a premium write-up to public, and you can read why we are still bullish natural gas here.
Will US natural gas avoid a collapse this year? -- After ending 2016 on a bullish note, the U.S. natural gas market has been hammered so far in 2017 by relentlessly mild weather—January 2017 ranked as the fifth warmest in 40 years. The prompt CME/NYMEX Henry Hub futures contract, which had climbed to nearly $4.00/MMBtu by late December 2016, has come off more than $1.00 since then to settle at $2.834/MMBtu as of last Friday (February 17, 2017). With every balmy winter day that passes, the chances of sustained $3-$4 natural gas prices seem to be fading away. Nevertheless, there are still some bulls out there hanging on in hopes of a rebound. Prices are still well above year-ago levels and the underlying supply/demand balance continues to carry the implied potential for tightening if given even normal weather. In today’s blog, we provide an update of the gas supply/demand balance, starting with a recap of how we got here. This is the latest of our periodic updates on the fundamental factors influencing the U.S. natural gas market—in particular the supply/demand balance, based on daily supply/demand data from our NATGAS Billboard report (RBN’s joint report with IAF Advisors). When we last wrote about the U.S. natural gas supply/demand balance in mid-December 2016 in The Long and Winding Road, the storage inventory had managed to decline from a record high a month earlier in mid-November to near the five-year average. Production was lagging. LNG and Mexico exports were ramping up. Demand on a per-degree basis was strong. And the overall supply/demand balance suggested the market was headed for a bullish start to 2017, assuming normal to cooler-than-normal weather. Instead, since the New Year, weather has been almost unceasingly bearish, with the potential to derail what the market expected would be a recovery in 2017.
Shell: Global LNG demand to rise 4-5%/year to 2030 - Global demand for natural gas is expected to increase 2%/year between 2015 and 2030, with LNG demand expected to rise at twice that rate at 4-5%/year, according to Royal Dutch Shell PLC’s first LNG Outlook. Shell inherited the outlook following its acquisition of BG Group PLC. The report, which draws on a broad range of independent industry data and internal analysis, projects the size of the global LNG market to rise 50% between 2014 and 2020, mainly attributable to LNG facilities already under construction or recently completed. In 2016, global LNG demand reached 265 million tonnes, including an increase in net LNG imports of 17 million tonnes from a year earlier. Shell notes many expected a strong increase in new LNG supplies would outpace demand growth during 2016. However, demand growth kept pace with supply as greater-than-expected demand in Asia and the Middle East absorbed the increase in supply from Australia. China and India, which are set to continue driving a rise in demand, were two of the fastest-growing buyers in 2016, increasing their imports by a combined 11.9 million tonnes of LNG. This boosted China’s LNG imports in 2016 to 27 million tonnes and India’s to 20 million tonnes. LNG demand has been bolstered by the addition of six new importing countries since 2015—Colombia, Egypt, Jamaica, Jordan, Pakistan, and Poland—bringing to 35 the number of LNG importers, up from about 10 at the start of the century. Egypt, Jordan, and Pakistan were among the fastest-growing LNG importers in the world in 2016. Due to local shortages in gas supplies, they imported a total of 13.9 million tonnes of LNG. The bulk of the increase in LNG exports in 2016 came from Australia, where exports rose 15 million tonnes from a year earlier to a total of 44.3 million tonnes. The US also contributed the growth, with 2.9 million tonnes of LNG delivered from the Sabine Pass terminal in Louisiana. Shell’s outlook forecasts LNG prices to continue to be determined by multiple factors, including oil prices, global LNG supply and demand dynamics, and the costs of new LNG facilities. In addition, the growth of LNG trade has evolved into helping meet demand when US gas markets face supply shortages.
Liquefied natural gas exports expected to drive growth in U.S. natural gas trade - EIA -The United States is expected to become a net exporter of natural gas on an average annual basis by 2018, according to the recently released Annual Energy Outlook 2017 (AEO2017) Reference case. The transition to net exporter is driven by declining pipeline imports, growing pipeline exports, and increasing exports of liquefied natural gas (LNG). In most AEO2017 cases, the United States is also projected to become a net exporter of total energy in the 2020s in large part because of increasing natural gas exports. In 2016, the United States was a net importer of natural gas, with net imports of 0.9 trillion cubic feet (Tcf), or 2.6 billion cubic feet per day (Bcf/d). As several LNG export projects currently under construction are completed, LNG exports are expected to make up a growing share of natural gas exports and to surpass pipeline exports of natural gas by 2020. The Sabine Pass facility in Louisiana became the first operating LNG export facility in the Lower 48 states in 2016. By 2021, four LNG export facilities currently under construction are expected to be completed. Combined, these five plants are expected to have an operational export capacity of 9.2 billion cubic feet per day. After 2021, projected U.S. exports of LNG grow at a more modest rate as U.S. natural gas faces growing competition from other global LNG suppliers.U.S. exports of natural gas by pipeline to Mexico are also expected to increase. U.S. exports to Mexico have doubled since 2009 and are projected to continue rising through at least 2020 as pipeline projects currently under construction are completed. U.S. imports of natural gas, most of which come by pipeline from western Canada, are projected to continue declining. In addition to importing less natural gas from Canada, primarily from Alberta, increasing amounts of natural gas from the Marcellus and Utica basins in the Northeast and Midwest regions of the United States are expected to flow to eastern Canadian provinces.
Pakistan seeks to end gas shortage with LNG imports - With domestic production faltering and pipeline import projects still uncertain, Pakistan's dependency on LNG imports is unlikely to fade away, especially since global oversupply and low LNG prices are set to continue helping the country resolve its decade-long energy crisis. Imports of the fuel are projected to jump over the next five years, with most bullish estimates pointing to a demand of 30 million mt/year, or 4 Bcf/d of gas equivalent, by 2022, which is half of the country's total gas demand projection of 8 Bcf/d for that year, according to industry and government estimates. In the longer term, LNG demand expansion will continue to slow from double-digit growth through 2019 to less than 7% after 2022, according to government estimates, as LNG affordability becomes less certain and pipeline imports add supply competition, but LNG imports will keep rising."LNG was initially seen as a short-term solution, but it looks like Pakistan would keep importing 3-4 Bcf/d or more in the long term, given rising domestic demand and difficulties to start exploration activities in the more unstable areas," said Zeeshan Afzal, head of research with Karachi-based Insight Securities. Pakistan's current gas consumption oscillates between 6.2 Bcf/d in the summer season and 6.8 Bcf/d in winter. Average minimum temperatures in Punjab province, where more than half of Pakistan's population lives, stay below 5 degrees Celsius for most of the winter period, causing heating demand to rise.
Japan plans second offshore methane hydrate output test from late April - Japan plans to conduct a second testing round for offshore production of methane hydrate from around late April, aiming to run the tests non-stop for up to a month, an official at the Ministry of Economy, Trade and Industry said Monday. This will be the world's second offshore methane hydrate production test after Japan produced 120,000 cubic meters, or 20,000 cu m/day, of gas from methane hydrate in a first, six-day offshore production test in the Pacific Ocean in March 2013. That trial followed more than a decade of field research as well as testing of various technologies. Like the last round, METI will conduct the trial using the decreasing pressure system at the Daini-Atsumi Knoll in the eastern Nankai Trough, 70-80 kilometers (43.4-49.6 miles) south of the Atsumi Peninsula in Aichi Prefecture, the official said. The key objectives for the upcoming production test are to evaluate whether Japan can produce gas from methane hydrate using the decreasing pressure system stably for a given period, with a view to commercializing output in the future, the official said.
Analysis: Singapore can't afford to let oil exports lose edge despite carbon tax - Singapore will need to strike the right balance in implementing a planned carbon tax from 2019 to ensure its refining industry remains competitive as the sector faces headwinds from volatile margins, growing exports from China and rising capacity in the region. Singapore Monday announced it will implement a carbon tax starting 2019. The tax, which will be Southeast Asia's first carbon tax, will likely cost between $10-$20 per mt of emissions. The tax is aimed at helping Singapore meet its commitment to cut emissions by 36% below 2005 levels by 2030 under the Paris Agreement. Analysts told S&P Global Platts Wednesday that the tax will raise the cost of operations and pose new challenges for the refining sector, but the way the tax is implemented will determine the final impact. Wood Mackenzie estimates that the increase in cost for the refining sector from this carbon tax regulation could be between 40 cents/b and 70 cents/b. "By 2019, we expect gross refinery margins to be $4-$5/b. So the profit margins could be impacted by 10-15%," said Sushant Gupta, research director for refining and chemicals at Wood Mackenzie.
Oil sold out of tanker storage in Asia as market slowly tightens | Reuters: Traders are selling oil held in tankers anchored off Malaysia, Singapore and Indonesia in a sign that the production cut led by OPEC is starting to have the desired effect of drawing down bloated inventories. Yet in the short-term, the crude released from tankers will weigh on markets and possibly undermine OPEC's goal of achieving a balanced market by mid-2017. The Organization of the Petroleum Exporting Countries (OPEC) and other producers outside the group, including Russia, announced late last year that they would cut output by almost 1.8 million barrels per day (bpd) during the first half of 2017, looking to drain a glut that pulled down prices from over $100 per barrel in 2014 to around $56.50 currently LCOc1. "OPEC's strategy is targeting inventories – given the scale of the overhang, the market won't rebalance in six months – we expect an extension into (the second half of 2017)," said Energy Aspects analyst Virendra Chauhan. As OPEC's cuts start to leave some demand unmet, a hefty 6.8 million barrels of crude has been taken out of tanker storage from Linggi, off Malaysia's west coast, in February, shipping data in Thomson Reuters Eikon shows. An additional 4.1 million barrels and another 1.2 million barrels have been taken out of storage on tankers in Singaporean and Indonesian waters, the data shows.In the short-term, the flood of crude from floating storage will add to supplies coming into Asia from as far away as the Americas and Europe. In the longer-term, however, clearing oil out of inventories like tankers is part of OPEC's goal to rebalance markets.
After OPEC cuts heavy oil, China teapot refiners pull U.S. supply to Asia | Reuters: Chinese independent, or teapot, refiners are bringing in rare cargoes of North American heavy crude in a new long-distance flow that traders say has only been made possible by OPEC's output cuts and ample supplies in Canada and the United States. In April, at least 1 million barrels of the heavy crude Mars, pumped from the U.S. Gulf of Mexico, are expected to land in China's Shandong province and 1 million barrels of a second unidentified heavy grade will arrive in China, trade and shipping sources said last week. This follows the arrival in January of 600,000 barrels of U.S. Gulf Blend, a heavy crude made up of a blend of various U.S. and Canadian grades loaded onto ships on the U.S. Gulf Coast, according to the sources and shipping data. Heavy crude is typically more dense and viscous than other oil grades. Refiners with facilities that can process these grades value heavy crude because its lower cost results in higher margins from producing fuels from these grades. The Organization of the Petroleum Exporting Countries' (OPEC) output cuts have targeted heavy crude, with linchpin producer Saudi Arabia and Venezuela reducing their exports of heavy crude. That has increased the price of Middle East heavy crudes for Asian delivery, making it economical for traders to ship crude from Russia, the Atlantic Basin and the United States to Asia. "The OPEC cuts started from medium and heavy grades and Venezuela (a key supplier to China) is exporting less,"
China’s use of methanol in liquid fuels has grown rapidly since 2000 - China is the global leader in methanol use and has recently expanded methanol production capacity. Since the early 2000s, China’s methanol consumption in fuel products has risen sharply and is estimated to have been more than 500,000 barrels per day (b/d) in 2016. EIA commissioned a study from Argus Media group to better understand China’s consumption of methanol and its derivatives. The estimates developed in the study have now been incorporated into EIA’s historical data and forecasts of petroleum and other liquids consumption in China. Methanol, like ethanol, is an alcohol with inherent issues such as its solubility in water and corrosiveness. Methanol or its derivative products can be added to fuels such as gasoline and liquefied petroleum gases (LPG). Similar to how ethanol is currently blended into motor gasoline in the United States, methanol is blended into gasoline in China. Most of China’s methanol supply is from domestic production. About two-thirds of China’s methanol feedstock is produced from coal and the remainder from coking gas (a by-product of steel production) and natural gas. China has abundant coal resources, and for more than a decade the country has increased its capacity to manufacture methanol using coal as a feedstock. Smaller amounts of China’s methanol supply are imported from the Middle East, Southeast Asia, South America, and the United States. Methanol is a clean-burning, high-octane fuel component, as the oxygen present in methanol aids in more complete fuel combustion. Blending methanol with gasoline allows refiners to extend China’s gasoline supply and increase the octane level of its gasoline. However, methanol has only one-half the energy per unit of volume as gasoline and requires more fuel consumption on a volumetric basis to provide the same amount of energy.
OPEC's Oil Curbs Grant Russia's Urals a Rare Ticket for Asia - The biggest oil producers in the Middle East are helping crude from Western Siberia boldly go where it’s rarely gone before. Top South Korean refiner SK Innovation Co. is set to receive about 1 million barrels of Urals crude in its first purchase of the Russian blend oil in a decade. The shipment was made viable because of rising costs for rival supply from the Middle East, as nations such as Saudi Arabia curb output to comply with a deal between global producers. The cargo is also another example that helps illustrate how the reductions by top OPEC members are rerouting the flow of oil across the globe. In recent weeks, Asia has become a destination for grades that typically don’t show up in the region -- from U.S. Mars Blend and Southern Green Canyon to West Canadian Select, Hibernia and White Rose. The premium of Oman crude, often pitted against Urals because they are of similar quality, jumped to its highest level this month against Middle East benchmark Dubai oil.“The flow of Urals into Asia is rare as it’s usually not economically viable versus other supplies such as Oman or Upper Zakum crude,” “The grade is typically transported on Suezmax or smaller vessels due to draft restrictions at the port and Suez Canal, and that makes it tough to compete with Mideast grades that are typically transported on Very Large Crude Carriers.” Urals, a medium-sour grade favored by processors in the European and Mediterranean regions, has been less popular among Asian buyers as Middle East crudes were cheaper, required less sailing time due to geographical proximity and were delivered in larger vessels. A VLCC can transport about 2 million barrels, while a Suezmax would hold about 1 million. SK bought about 1 million barrels of Urals for April arrival from Lukoil PJSC, three traders with knowledge of the deal said. Company spokeswoman Kim Wookyung confirmed the purchase. “As Dubai crude supply has become tighter in Asia, this made Russian cargoes more economical for us,” Kim said, adding that the cargo “will be our first purchase of Urals in a decade.”
Rosneft becomes first oil major to pre-finance Kurdish crude | Reuters: Russian state oil firm Rosneft has become the first major oil firm to pre-finance crude exports from Iraq's Kurdistan, joining trading houses in the race for crude from the semi-autonomous region. "We look forward to developing new markets for Kurdish crude oil," a statement by Rosneft quotes chief executive Igor Sechin as saying. The contract is due for 2017-2019, Rosneft said. Sechin said Rosneft would be taking Kurdish barrels to the company's growing refining system. In Europe, Rosneft owns alarge refinery system in Germany. Rosneft also said it was looking to cooperate with Kurdistan in upstream and logistics. Kurdistan's natural resources minister Ashti Hawrami said the deal was opening up new possibilities for cooperation between Rosneft and Kurdistan. Kurdistan has started independent crude exports from the central government in Baghdad in the past three years as it argued it was not getting its share of Iraq's budget revenue sand needed money to fund its war against Islamic State. But as oil prices crashed, the region had to borrow as much as $3 billion from trading houses such as Vitol, Petraco, Glencore and Trafigura as well as neighboring Turkey, repayable by future crude sales.Baghdad has first pledged to sue buyers of Kurdish oil as it insisted the central government was the only legal exporter of barrels both from southern and northern Iraq. But Baghdad has lately softened its stance on the companies and traders working in Kurdistan with the barrels being sold in both Europe and Asia.
Oil prices: the lonely role of the swing producer -- The new Opec quota has been in force for six weeks, which is sufficient time to judge what is happening on the basis of facts rather than speculation. The key questions are, first, whether the restraints on production agreed last November are working or not and, second, whether the regime that came into force at the beginning of January can be sustained until June, as planned. The oil price has been remarkably stable at around $54/$56 a barrel for Brent crude. That is about 15 per cent higher than before the November agreement but still barely half that seen three years ago. So will prices rise further or does the current level represent a ceiling? Let’s start with the facts. Three things are clear. Most of the target reduction is being achieved but the response on a state-by-state basis is far from uniform. Three countries — Algeria, Venezuela and Iraq — have not cut production or have cut by less than they promised. Outside Opec, the situation in Russia is confused. Some production has been cut but the most recent reports suggest an increase in output and exports, particularly from the Urals. Most of the rest have met their quotas and Saudi Arabia has gone further — cutting output to less than 9.8m barrels a day, almost 300,000 barrels below its agreed quota. Without this, the target would not have been met. That all explains the price movement — a tentative upward shift but nowhere near the $70 predicted by some. So what of the way forward? Fixed-point predictions are pretty valueless. The best way to approach the question is to consider the pressures in both directions and the signals to watch for. On the demand side, the prospect is for modest growth, with the strongest impetus coming from the surge in investment in infrastructure being prepared by the Trump administration in the US. Donald Trump’s plans to encourage new hydrocarbon development (which I wrote about last week) will take time to come to fruition. In the short term, the increase will be price-driven. The Energy Information Administration — the authoritative source in the US — predicts an increase of 100,000 b/d this year and 550,000 b/d in 2018. Some commentators are predicting faster growth in US output — of up to 500,000b/d by the end of 2017. Until that comes through, the US will rely on imports, as is evident in the January data. The conclusion from this on conventional wisdom is that prices can stay roughly where they are provided Saudi Arabia accepts that it is now the swing producer. That acceptance is the crucial uncertainty.
OPEC Ready To Cut Deeper - OPEC is finding itself backed into a corner: the group, it appears, is prepared to extend the oil production cut agreement that is set to expire at the end of June and also increase the cuts, if inventories fail to drop to a specified level, sources from the group told Reuters. The agreement, which also involves 11 non-OPEC producers, including Russia, Mexico, Kazakhstan, Azerbaijan, and several smaller producers, envisaged taking off around 1.8 million barrels from the global daily supply. This means, according to the sources, that global stockpiles should shrink with 300 million barrels in the six-month period, to reach the five-year average. This, however, requires a compliance rate of 100 percent from all participants. Despite this stated readiness to cut as much as necessary for as long as necessary, the odds are against any noticeable pickup in prices, at least until conclusive supply data becomes available. It’s true that OPEC is doing a surprisingly good job—at least initially—in complying with its promised output cuts, but pressured by budget deficits caused by the oil price crash, producers will be tempted to pump and export more at those higher prices. For many observers, there is only one question: when OPEC members – or non-OPEC producers for that matter – will start cheating and who will start first.
Hedge funds bet big on oil as OPEC gives them a free put option - Kemp (Reuters) - Hedge funds and other money managers have amassed a very large bullish position in crude oil futures and options without so far having much impact on oil prices. Hedge funds raised their combined net long position in the three main derivative contracts linked to Brent and WTI by another 51 million barrels in the week to Feb. 14. Funds now hold a net long position equivalent to a record 903 million barrels of oil, according to an analysis of records published by regulators and exchanges (http://tmsnrt.rs/2meDpzf). The combined net long position has a notional valuation of more than $49 billion, which is the highest since July 2014 (http://tmsnrt.rs/2lduZua). Hedge funds hold more than 9.5 long positions for every 1 short position in Brent and WTI combined, the highest ratio since May 2014 (http://tmsnrt.rs/2ldKiTX). Fund managers now have the most bullish view on oil since the first half of 2014, when Libya's exports were nearly halted by civil war and Islamic State fighters were racing across northern Iraq. The scale of the net long position is puzzling and raises important questions about how it will eventually unwind. Fund managers have been able to increase their bullish bets with almost no disturbance to the market price of crude. Volatility has been most remarkable by its absence. Funds have increased their net long position by 107 million barrels since Dec. 13 while prices have traded sideways in a narrow range of around $55.50 +/- $1.25 per barrel. Oil prices have been steady at around the $55 level most energy professionals expected would be the average for the year at the start of 2017. The accumulation of a large long or short position by fund managers has normally been the harbinger of a sharp reversal in oil prices when it unwinds.
Biggest Gasoline Glut In 27 Years Could Crash Oil Markets --Oil prices are stuck in a holding pattern, waiting for more definitive data on what comes next. OPEC compliance is helping keep prices afloat, but rising U.S. oil production is acting as a counterweight. A new problem that has suddenly emerged is the record levels of gasoline sitting in storage. The market has already had to digest the fact that U.S. crude oil stocks were rising, and investors have done their best to explain away the trend. But now gasoline inventories are climbing to unexpected heights. It would be one thing if crude stocks were rising, perhaps because refiners were going offline for maintenance. But if that were the case, then gasoline stocks would draw down on lower refining runs. But if both crude and refined product inventories are going up at the same time, then there should be some reasons for worry. In fact, the glut of gasoline is now the worst in 27 years. At 259 million barrels, U.S. gasoline storage levels are now at their highest level since the EIA began tracking the data back in 1990.Part of the reason for the glut, of course, are high levels of production. Although gasoline production ebbs and flows seasonally, U.S. production has been on an upward trend in recent years. Instead of bouncing around in a range of 8.5 to 9.5 million barrels per day before 2014, U.S. production since the collapse of oil prices has steadily climbed to a range of 9 to 10 mb/d.But that increase came in order to satisfy rising demand (which, of course, was stoked by lower prices). More demand should have soaked up that excess supply. However, that is where the problem gets worse. Lately, U.S. demand has faltered. U.S. gasoline demand plunged to just 8.2 million barrels per day in January, and sales were down 4 percent from a year earlier. It was also the lowest level in four years. Weak demand is raising some red flags for the market.Demand is seasonal, with softer demand in winter months, but this winter’s ‘valley’ is lower than any other since 2012. The problem becomes particularly acute when you take into account the fact that refiners have actually cut back on gasoline production in recent weeks. Even with lower refining runs, gasoline storage levels continued to rise.
Don’t Panic About the Gasoline Recession! Unless - According to the gasoline market, we're in a recession.You hadn't noticed? Hmm. Since late January, gasoline demand has been running about 5 or 6 percent lower, year over year, according to the Energy Information Administration's weekly estimates. Historically, that sort of drop has only happened when there's been a recession or a huge spike in prices: This Just Doesn't Happen Big dips in U.S. gasoline demand, especially of 5 percent or more, are almost unheard of outside of a recession or oil crisis Here we are, though, with oil stuck in the mid-$50s, unemployment below 5 percent and the IMF forecasting the economy to grow by 2.2 percent in 2017.This doesn't sound like a recession. Which means those weekly gasoline numbers are probably too pessimistic. The chart above uses the more reliable, revised monthly data (which is why it ends in November 2016). The EIA's weekly figure for gasoline demand is actually a residual rather than a firm estimate; revisions to export and import data, which are always lagging, have a tendency to lead to big revisions in gasoline demand (see this for a detailed take on how these data interact).EX Even if the rest of us can breathe easier, though, that doesn't mean refiners can.One figure that can't be disputed is this: 23.6 million barrels. That's how much excess gasoline had flowed into storage tanks this year as of February 10. The average for the same period in the previous five years is just under 10 million barrels, and that average is skewed higher by a similarly large build-up in early 2016.Even without a recession, gasoline demand is showing distinct signs of stalling out. The latest figures on how far Americans are driving, released this week by the Federal Highway Administration, show the boost delivered by the crash in pump prices is starting to wear off. You can see that boost here:
Oversupply Fears Grow As US Oil Exports Hit Record High - U.S. oil producers contributed a record 7 million barrels of crude oil to international markets during the Week of February 5th, 2017, approximately one million barrels per day. This is on the tail of OPEC strategically limiting their global contributions. These OPEC supply constraints are a continuation of policy agreed upon in January by OPEC nations and other suppliers to support higher prices. Some analysts speculate that this is a harbinger of continuously increasing American activity in the global oil market. However, it remains unclear if this level of output is sustainable in the long-run. The U.S. daily average in the preceding four weeks was a less advantageous 685,000 barrels per day. This increase from U.S. shale producers is a comeback from idle operations during last year’s market downturn. The bulk of the growth originates from Permian shale, a type found predominately in Texas. This increase has also given rise to short-term supply concerns, as too sharp an increase will lower prices. Brent crude oil, for example, dropped 0.4 percent in price on Wednesday, February 15th following a report from the American Petroleum Institute that North American oil production is steadily increasing. In addition to this data, the Energy Information Administration reported record numbers for U.S. oil stockpiles and gasoline inventories, at 518.2 million barrels and 259.1 million barrels, respectively. China seems to be one of the bigger destinations for this American oil, possibly due to the gaps in supply that the other large oil producers are creating. For example, PretoChina and Unipec both chartered 2 million barrels. Additional export destinations for U.S. oil include Europe, Latin America, and Canada. These spikes in shale production are in line with U.S. government estimates, the latest of which predict an increase of 80,000 barrels per day during the month of March – the third month in a row of increasing shale supply. Last week, total production of oil in the U.S. was just under 9 million barrels a day. This is perhaps a function of oil prices having stabilized above $50 a barrel, making production of shale in America more profitable. The forecast concludes that overall oil production will reach 9.5 million barrels per day by next year.
Oil rises in thin trade, but swelling U.S. output caps rally | Reuters: Oil prices inched higher on Monday, as investor optimism over the effectiveness of producer cuts encouraged record bets on a sustained rally, although growing U.S. output and stubbornly high stockpiles kept price gains in check. Top OPEC exporter Saudi Arabia's crude oil shipments fell in December to 8.014 million barrels per day (bpd) from 8.258 million bpd in November, official data showed on Monday. Brent futures LCOc1 ended the session up 0.7 percent at $56.18 a barrel. U.S. futures West Texas Intermediate crude CLc1 gained about 29 cents or 0.5 percent to $53.69 prior to the close of trade at 1 p.m. EST, an hour and a half early due to the Presidents Day holiday. Trading volume in Brent averaged about 181,000 lots of 1,000 barrels each, below the average of about 205,000. Volumes in U.S. crude also dipped, with just over a couple of thousand lots traded, a day ahead of the expiration of WTI futures for delivery in March. On average, more than 300,000 U.S. crude lots trade in a typical trading session. Prices received a lift from a weaker dollar .DXY as well. A strong greenback typically makes oil more expensive for holders of other currencies. The Organization of the Petroleum Exporting Countries and other producers, including Russia, agreed last year to cut output by almost 1.8 million bpd during the first half of 2017. Estimates indicate compliance with the cuts is around 90 percent. Reuters reported last week that OPEC could extend the pact or apply deeper cuts from July if global crude inventories fail to drop enough.
Oil Moves Higher On Expectations Of Tighter Market - Oil prices moved up on Tuesday on hopes that the market is tightening. OPEC says its cuts are working and hedge funds are still bullish on crude, but pitfalls remain. Hedge funds and money managers have been on a buying spree since OPEC announced its deal in late November. Bullish bets on crude oil futures have climbed at a rapid pace in the past few months, setting new records nearly every week. Now, hedge funds and other money managers have surpassed 1 billion barrels of bullish bets, a new record high. As we have noted many times, the record buildup leaves the market exposed to a backsliding in prices if the mood of traders turns sour. The OPEC deal called for cuts of 1.2 mb/d over the course of six months. If the deal is not extended until at least the end of the year, oil prices could fall back into the $30s, according to ABN Amro Bank NV. The “downside risk has become much bigger than previously,” Hans van Cleef, ABN Amro’s senior energy economist, told Bloomberg. The Wall Street Journal reported that Saudi Arabia is leaning towards a western stock exchange when it lists its state-owned oil company. The plan is a partial IPO of about 5 percent of the company, which could allow the kingdom to take in more than $100 billion. Saudi officials looked at exchanges around the world but decided against one in Asia. Now officials are looking at New York, London and Toronto, with New York as the leading candidate. The IPO could be the largest ever. However, because the company is state-owned, it will be difficult to disentangle its finances from the Saudi government. Roughly 90 percent of Aramco’s profits go into government coffers and the royal family certainly takes its share as well. Only about 10 percent of the profits are reinvested in the company. The complexity of this situation is likely to push the IPO off until late 2018 at the earliest, or more likely 2019, the WSJ says.
OPEC/non-OPEC oil cut compliance to rise in coming months: Barkindo - OPEC Secretary General Mohammed Barkindo Tuesday said any decision to extend a landmark oil production cut agreement past June will depend on global stock levels and an assessment of market fundamentals. Speaking at a news conference during the International Petroleum Week conference in London, Barkindo did not rule out further cuts, if necessary, but said "it's too early for us to begin to second guess" what market conditions would be like when OPEC ministers next met on May 25 in Vienna. The 11 non-OPEC countries that are party to the production cut deal will also be invited to confer with OPEC in Vienna to determine their next course of action, Barkindo said. "Confidence has returned to this market, but I think going forward, we have to watch how the stock levels continue to respond to the full and timely implementation of the declaration of cooperation between OPEC and non-OPEC countries," he said. The deal, which runs from January through June, calls for OPEC's 13 members to cut a combined 1.2 million b/d from October levels down to a range of 32.5 million-33 million b/d, while the 11 non-OPEC countries, led by Russia, have committed to a 558,000 b/d cut. OPEC has said the deal is aimed at reducing the global stock overhang down to its five-year average. Barkindo acknowledged that that goal is still a ways off.
U.S. oil on track for highest close in 20 months - Crude-oil futures on Tuesday were on pace to hit their highest settlement in about 20 months as investors bid prices up on the heels of growing bullishness about compliance to a global pact to curb crude output. The April contract for global crude benchmark Brent was up 89 cents, or 1.6%, to $57.07 a barrel while its U.S. counterpart West Texas Intermediate gained $1.01, or 1.9%, to $54.40 for March deliveries, which expires Tuesday. The April contract CLJ7, +1.77% which is the most active, was trading 94 cents, or 1.8%, higher at $54.72 a barrel. Both WTI contracts were on pace to finish at their highest levels since July 2, 2015, according to Dow Jones data. The crude rally comes as OPEC’s Secretary-General, Mohammad Sanusi Barkindo, offered encouragement about the effectiveness of the Organization of the Petroleum Exporting Countries’ and non-OPEC countries’ plans to shrink crude supply by about 2% globally, or 1.8 million barrels daily, during an International Petroleum Week conference in London on Tuesday. Moreover, Barkindo said U.S. shale production, which has been a nagging bugaboo in recent weeks for those contemplating risks to crude holding higher prices, isn’t likely to jeopardize efforts to limit oil. “We are not looking at the U.S. as a risk, we are looking at the U.S. as a partner, a strategic partner in the rebalancing process,” he said. Late last year, the 13 OPEC nations and 11 oil producers outside the group agreed to cut production in a bid to reduce alarmingly high global supplies and balance the market. But the U.S. isn’t a part of the global agreement and rigs drilling for oil have increased steadily since the OPEC agreement was put place in January, causing some to fret that resurgent U.S. production could destabilize prices and upend the pact.
Oil prices will surge to $70 per barrel by year-end – Citi - US investment bank Citi has posted a bullish prediction about oil prices. As supply and demand levels continue to rebalance, crude is likely to reach $70 per barrel by the end of 2017, the bank said in a note. However, the increase will come gradually, and a surge is to be expected a few months later, said Citi."Oil prices are not likely to stray far from their current $53-58 per barrel range in the near term as record investor net length and bearish inventory data will likely cap prices until more tangible evidence of a tighter market emerges," Citi’s analysts wrote. On Wednesday, crude prices were slightly down after the rally on Tuesday with Brent trading at $56.50 per barrel and WTI trading at $54.26.Citi expects to see a positive result from an OPEC production cut, which reported 93 percent compliance in January. The bank added that heavy refinery maintenance in Asia planned for the spring is also a decisive factor for oil prices. Another US bank - Goldman Sachs - expects oil inventories to keep falling globally. While stocks are likely to rise in the US, production cuts and strong growth in demand will be more significant, the bank said. "We do not view the recent US builds as derailing our forecast for a gradual draw in inventories, with in fact the rest of the world already showing signs of tightness. Given our unchanged 1.5 million barrels per day growth forecast for 2017, this higher base demand level should fully offset higher US output,” Goldman said in a note. "While the production cuts have so far reached a historically high level of compliance at 90 percent [93 percent, according to OPEC], the rebound in US drilling activity has exceeded even our above consensus expectations," the bank added.
Goldman says global crude stocks likely to keep falling | Reuters: Goldman Sachs expects global crude oil inventories to keep falling due to production cuts and strong growth in demand, although stocks are likely to rise in the United States. "We do not view the recent U.S. builds as derailing our forecast for a gradual draw in inventories, with in fact the rest of the world already showing signs of tightness," analysts at the bank said in a note dated Feb. 21. "Given our unchanged 1.5 million barrels per day growth forecast for 2017, this higher base demand level should fully offset higher U.S. output." The Wall Street bank reiterated its forecast for Brent and U.S. crude prices to rise to $59 and $57.50 per barrel respectively in the second quarter, before dropping to $57 and $55 for the rest of 2017. Oil prices held near multi-week highs on Wednesday, with the U.S. West Texas Intermediate April crude contract up 18 cents at $54.51 a barrel at 0228 GMT (5:28 a.m. ET), while Brent crude was up 24 cents at $56.90. Surging U.S. output has pushed crude and gasoline inventories to record highs, keeping a lid on prices after they climbed following an agreement by the Organization of the Petroleum Exporting Countries (OPEC) and other producers to cut output by about 1.8 million barrels per day (bpd). "While the production cuts have so far reached a historically high level of compliance at 90 percent, the rebound in U.S. drilling activity has exceeded even our above consensus expectations," Goldman said.
Oil prices slip on dollar strength, but OPEC hope cushions the fall: Global oil prices slipped on Wednesday as the U.S. dollar rose, but crude futures traded broadly at multi-week highs after OPEC signaled optimism over its deal to curb output with other producers. A stronger greenback makes dollar-denominated commodities like crude oil more expensive for holders of other currencies. The U.S. West Texas Intermediate April crude contract was down 70 cents, or 0.1.3 percent, at $53.63 a barrel at 9:22 a.m. ET (1422 GMT). The March contract expired on Tuesday. Brent crude was down 72 cents, or 1.3 percent, at $55.94. Nevertheless, an agreement by major oil producers under the OPEC umbrella, which came into place at the start of this year, lent a floor to oil prices.show chapters Citi analysts predict crude oil will hit $70 by the end of 2017 Tuesday, 21 Feb 2017 | 8:27 AM ET | 00:38 Mohammad Barkindo, secretary general of the Organization of the Petroleum Exporting Countries, told a conference on Tuesday that January data showed conformity from member countries in the output cut at above 90 percent. Hedge funds raised their combined net long position in the three main derivative contracts linked to Brent and WTI by 51 million barrels last week, holding a net long position equivalent to a record 903 million barrels of oil. The combined net long position has a notional valuation of more than $49 billion.
Oil prices drop on worries of swelling US stockpiles: Oil prices fell about 1.5 percent on Wednesday on expectations of another surge in U.S. inventories, but they traded close to multi-week highs after OPEC signaled optimism over its deal with other producers to curb output. Analysts polled ahead of weekly inventory reports from industry group the American Petroleum Institute (API) and the U.S. Department of Energy's Energy Information Administration (EIA) estimated, on average, that crude stocks increased by about 3.3 million barrels last week, its seventh weekly build. The API is scheduled to release its data at 4:30 p.m. EST (2130 GMT), while EIA data is due at 11 a.m. EST on Thursday, both delayed a day because of the federal holiday on Monday. The U.S. West Texas Intermediate April crude contract settled 74 cents, or 1.4 percent, lower at $53.59 a barrel. The March contract expired on Tuesday. Brent crude was down 90 cents, or 1.6 percent, at $55.76 at 2:33 p.m. ET (1933 GMT).Hedge funds raised their combined net long position in the three main derivative contracts linked to Brent and WTI by 51 million barrels last week, holding a net long position equivalent to a record 903 million barrels of oil. The combined net long position has a notional valuation of more than $49 billion. Goldman Sachs reiterated its outlook for a recovery in prices in the second quarter — WTI to rise to $57.50 and Brent to $59 — before declining to $55 for WTI and $57 for Brent for the rest of the year.
Oil settles lower to end 3 straight sessions of gains, as non-OPEC production weighs - Crude-oil prices on Wednesday finished lower, snapping a three-session string of gains as concerns about growing output by producers outside of a pact to curtail global production weighed on crude futures. West Texas Intermediate crude oil trading on the New York Mercantile Exchange for April delivery lost 74 cents, or 1.4%, to settle at $53.59 a barrel. Oil traded slightly higher in electronic trading following a release of data from the American Petroleum Institute showing a 884,000-barrel decline in U.S. crude supplies for the week ended Feb. 17, when a consensus of analysts polled by The Wall Street Journal were expecting a gain of 3.4 million barrels. At last check, crude traded up at $53.87 a barrel. The report precedes the more closely watched U.S. Energy Information Administration inventory report on Thursday. April Brent crude on London’s ICE Futures exchange traded down 82 cents, or 1.5%, to close at $55.84 a barrel. The crude market has been anxious about rising production, namely from U.S. shale-oil producers and Russia, which has a history of not complying with production limits.
Oil Bounces After Surprise Inventory Draw -- While OPEC compliance remains key, it appears fundamental over-supply fears are mounting once again. Against expectations of a crude build and gasoline draw, API reported a surprise crude draw but smaller than expected gasoline draw. Cushing also saw a major drawdown and Distillates saw the biggest draw since Oct 2014. WTI and RBOB prices were marginally higher on the print. API
- Crude -884k (+3.3m exp)
- Cushing -1.7mm
- Gasoline -893k (-1.5mm exp)
- Distillates -4.229mm
This surprise draw ends the 6 week streak of builds in crude but Distillates saw the biggest draw since Oct 2014...
Unsatisfied With Oil Prices, Iraq Calls For New OPEC Meeting - Iraq thinks that OPEC should hold a new meeting to discuss the cartel’s oil production cuts, given the fact that the current oil prices are still below expected levels, according to Iraqi Prime Minister Haider al-Abadi.The price of oil is still below the level that is needed to replenish the budget deficit of Iraq, Kazakh agency KazTag reported on Wednesday, quoting Iraqi media that carried al-Abadi’s statements. Iraq - OPEC’s second biggest producer behind Saudi Arabia - has “tried hard to cut down production volume in the cartel and keep the prices, now OPEC needs to conduct a new meeting to reach an agreement”, KazTag quoted al-Abadi as saying.Yesterday, al-Abadi said at a news conference in Baghdad that the country needed oil to reach US$60 per barrel in order to fill in the budget deficit gap. Iraq’s public finances have suffered from low oil prices, as Baghdad relies almost exclusively on oil revenues for budget proceeds. In addition, the country’s fight against Islamic State militants has been further stretching the dwindling financial resources.Iraq has contractual obligations to foreign oil companies, and must deal with the Kurdish Regional Government (KRG), which controls fields in the north, making any production cuts quite complex. In this way, Iraq faces more challenges than other OPEC members in trying to comply with the deal. Nevertheless, it’s a bit odd that Iraq – which in January missed its production cut target under the OPEC deal the most – is the one demanding a new meeting on cuts. In the November 30 supply-cut deal, Iraq pledged to reduce its crude oil production by 210,000 bpd to reach and keep for six months a production level of 4.351 million bpd. OPEC’s figures for January show that Iraq pumped – according to secondary sources – 4.476 million bpd last month. Iraq’s self-reported production was even higher – 4.630 million bpd. The secondary-source figure – which OPEC deems valid for cuts and compliance purposes – is still 125,000 bpd above the targeted level.
Oil To $70? Or Down To $30? - Will oil prices rise to $70 per barrel this year or fall to $30? Depends on who you ask.Oil price forecasts are always all over the map, but the exceptional disparity between some projections for 2017 is pretty stunning.On the one hand, you have Citibank, which sees oil shooting up to $70 this year as supply continues to tighten even as demand rises.Citi acknowledges the headwinds in the near-term. "Oil prices are not likely to stray far from their current $53-58 per barrel range in the near term as record investor net length and bearish inventory data will likely cap prices until more tangible evidence of a tighter market emerges," Citi analysts wrote in a recent research note. However, they see oil prices posting much stronger gains in the second half of the year. But the bearish threats to oil prices on the downside seem to be a lot more visible right now than the bullish ones. Aside from rising shale production, a dagger looms over oil prices in the very near-term. Hedge funds and money managers have pushed bullish bets to a new record high, equivalent to over 1 billion barrels of oil. The massive one-sided bet leaves the oil market dangerously exposed. When the herd suddenly realizes that they are all making the same bet, there could be a stampede back in the other direction. The buildup in bullish bets is all the more remarkable because it occurred at a time when oil prices were stagnant, stuck in the mid- to low-$50s per barrel. "The world is awash with oil at the moment and there continues to be endless supply so therefore I don't see a real reason for prices to rise above $60 or $70…so I'm really seeing probably the risks of the prices falling below $50 for a considerable period of time and probably even touching the levels of $40 to $45 this year," Eugen Weinberg, Head of Commodity Research at Commerzbank, told CNBC's Street Signs on February 21.Some oil watchers are even more pessimistic. Unless OPEC extends its production cut for another six months or so, crude prices could plummet to $30 per barrel, according to ABN Amro Bank NV. The OPEC deal has succeeded in already taking roughly 1 million barrels per day off of the market, but the supply/demand balance is not as tight as OPEC members had hoped it would be at this point.
WTI/RBOB Slide After Crude Inventory Hits Record High, Production Tops 9 Million Barrels -- After API's surprise draw across all major categories, DOE reported the 7th weekly crude build in a row (even as crude imports plunged). Gasoline, Distillates, and Cushing all saw draws even as crude production rose to new cycle highs - back above 9mm bbl/d. DOE:
- Crude +564k (+3.25m exp)
- Cushing -1.528mm (-50k exp)
- Gasoline -2.628mm (-1.5mm exp)
- Distillates -4.924mm (-1.0mm exp)
7th weekly crude build in a row but major draws across the other categories...
Oil volatility migrates from flat prices to spreads: Kemp - The benchmark price of Brent crude has been unusually stable since the middle of December, but there has been plenty of movement in the futures strip and crack spreads.Hedge funds have amassed an unusually large net long position in crude futures and options betting on a further increase in benchmark prices, but the position has not yet yielded much profit, with prices range bound.The more interesting and profitable trades for both hedge funds and physical traders so far in 2017 have been around the calendar, crack and quality spreads.Front-month futures prices have traded in a narrow range of just $3.46 per barrel since Dec. 13, never closing below $53.64 or higher than $57.10 (http://tmsnrt.rs/2mkxpWy).The standard deviation of front-month prices over the last month, which is one way to measure volatility, has fallen to the lowest level since July 2003 (http://tmsnrt.rs/2lREFfn).Some of the reduction in volatility is more apparent than real: as the dollar price has halved since 2014 so a smaller dollar move is equivalent to the same daily percentage change.Volatility is not exceptionally low when daily price changes measured in either dollars per barrel or percentage terms are considered rather than just the flat price (http://tmsnrt.rs/2lRtV0h).Nonetheless, there is no doubt flat-price volatility has declined over the last two months and is now at some of the lowest levels since the oil slump began in 2014 (http://tmsnrt.rs/2lRu6st). But while flat prices have been broadly stable, other elements of the constellation of oil prices have become increasingly volatile.
OilPrice Intelligence Report: What Will It Take For Oil To Breakout? - Oil prices gained some ground this week on the drawdown in gasoline stocks in the U.S., which the markets interpreted as a sign that the glut could be easing. However, on Friday, oil prices fell back a bit on concerns that there is still just too much supply out there. 2017 has brought remarkable increases in the inventory levels for crude oil and gasoline, both of which hit record highs this month. The buildups have threatened to erase the price gains achieved since OPEC announced its deal late last year. The latest data from EIA offered a bit of encouragement, revealing a 2.6-million-barrel drawdown for gasoline, although crude stocks rose by 0.6 million barrels. Investors chose to focus on the improving gasoline figures, and oil prices traded up more than 1 percent on Thursday. They apparently sobered up on Friday, and oil was down about 1 percent during early trading hours. ExxonMobil (NYSE: XOM) removed 3.3 billion barrels from its books this week, as low prices threaten to leave those reserves in the ground. The reserves are located in Canada’s oil sands, some of the most expensive sources of oil in the world. The move comes after ConocoPhillips (NYSE: COP) de-booked more than one billion reserves in Canada as well. The move is a sign of the struggle for Canada’s oil sands to compete in a world of much lower spending levels. Beyond the projects that are already under development, Canada’s oil sands could see fewer and fewer greenfield projects get off the ground. U.S. crude exports broke another record this past week, shipping 1.21 million barrels per day for the week ending on February 17. The oil export ban was only lifted at the end of 2015, and after some relatively small levels of exports throughout most of 2016, exports have accelerated dramatically this year. The sudden uptick in exports comes because crude oil inventories in the U.S. are overflowing and the WTI benchmark is trading at a discount to the more internationally-linked Brent marker, meaning U.S. crude is cheaper than other sources of oil, making it more attractive.
US Crude Production Tops 9 Million Barrels As Rig Count Hits 16-Month Highs -The US oil rig count rose once again this week (up 5) to 602 - the highest since October 2015.US crude production is surging - back above 9 million barrels/day in the last week - the largest since April 2016. The lagged response to rig count builds implies considerably more production to come.
U.S. Oil Rig Count Rises – Up 125 Since OPEC Deal - The number of active oil and gas rigs in the United States increased again, although modestly, on Friday by 3. Both benchmarks were trading down earlier on Friday despite reports of OPEC/non-OPEC compliance of 86 percent, along with Thursday’s EIA inventory data that showed another week of record-high crude oil inventories of 518.7 million barrels.The total number of active oil and gas rigs in the United States is now 754, according to oilfield services provider Baker Hughes, which is 252 rigs above the rig count a year ago.The number of oil rigs increased this week by 5, up from 597 last week to 602 this week. The number of active oil rigs in the United States is now the highest since October 09, 2015. Oil rigs have increased by 125 since the OPEC agreement was announced on November 30, as US drillers are continuing to gain as OPEC continues to hold its members largely to specified production caps. The number of gas rigs declined by 2 this week, and now stand at 151, ending a fourteen-week streak of no losses. Oil and gas rigs increased in the Permian, Eagle Ford, Cana Woodford, and Haynesville basins, and decreased in the Granite Wash and Williston basins. In Canada, the rig count climbed by 10 to 341—166 rigs more than this time last year—partially offsetting last week’s 21-rig decrease. At 11:17 am EST WTI was trading down 0.64% at $54.10—around $1.00 higher last Friday’s pre-rig count price. The Brent crude benchmark was trading down 0.83% at $56.11—more than $.60 above the price point last Friday. By 1:12pm EST, WTI was down further at $54.05, while Brent was up slightly over pre-rig count levels to $56.16.
Up, up and away! Rig count up another 3 -- The Baker Hughes U.S. rig count continues to steadily climb, gaining another 3 rigs this week. A total of 602 rigs are exploring for oil, up 5 from last week, while gas rigs declined by 2. By state, Texas still leads the pack with 386 rigs, up 8 from last week. Alaska and Louisiana each lost two, while North Dakota is down one rig this week. Wyoming gained one. By basin, the Permian still remains strong with 306 rigs, gaining 3 from last week, while the Eagle Ford gained three as well, with 64 rigs there total. The Cana Woodford was up 2 this week. The Haynesville also gained 1. The Williston Basin and the Granite Wash each lost a rig. Some concern about shale production still remains. Some believe the production cuts by OPEC could be compromised with the continued increase at home. According to EIA data, U.S. crude production at 9 million barrels a day last week was the highest level since early April 2016. Market watch’s Mark Decambre and Jenny W. Hsu stated Wednesday: The crude market has been anxious about rising production, namely from U.S. shale-oil producers and Russia, which has a history of not complying with production limits. However, OPEC has so far shown compliance, and the International Energy Agency (IEA) has said the OPEC cuts are the deepest on record. Oilprice.com reported OPEC Secretary-General Mohammed Barkindo dismissed speculation that the United States’ increase in shale oil production was counteracting the effects of the bloc’s less-than-two-month-old output reduction strategy. However, MarketWatch reported that Mohammed al-Sada, the oil minister of OPEC member Qatar, said not all the pieces were falling into place under the agreement, since compliance by non-OPEC members are only at about 50 percent of what was promised. Russia, one of those non-OPEC countries who committed to cuts did report it has reduced its oil production by 117,000 bpd in January, said Oilprice. But their exports, like the United States, were up. Exports through the Transneft pipeline were up 114,000 barrels per day in January compared to December.
Oil slips nearly 1 percent on concerns over rising U.S. output | Reuters: Oil prices fell about 1 percent on Friday as worries about rising U.S. supplies outweighed OPEC pledges to boost compliance with output curbs. But crude prices were on track for a weekly rise as traders have begun to pull out barrels from pricey storage, with physical markets showing signs of tightening. U.S. drillers added oil rigs for a sixth consecutive week, extending a nine-month recovery, energy services firm Baker Hughes Inc (BHI.N) said. [RIG/U] Prices were also pressured by book squaring ahead of the weekend and upcoming Feb. 28 expirations in Brent futures for April delivery, heating oil for March delivery HOc1, and March RBOB gasoline RBc1, analysts and traders said. Brent crude oil LCOc1 settled down 59 cents, or 1.04 percent, at $55.99 a barrel, while U.S. West Texas Intermediate CLc1 ended the session 46 cents lower at $53.99 a barrel. However, both benchmarks notched a weekly gain of about 1.1 percent. "The oil market remains focused on the global rebalancing act, with attention centered on OPEC compliance and U.S. production growth," Prices tumbled over the last two sessions after government data showed U.S. crude inventories rose for a seventh straight week. [EIA/S] But they have been supported within a tight $4 to $5 range since November, when the Organization of the Petroleum Exporting Countries (OPEC) and other producers agreed to cut production. OPEC's record compliance with the deal has surprised the market, and the biggest laggards, the United Arab Emirates and Iraq, have pledged to catch up with their targets.
OPEC still waiting for evidence oil cuts are doing their job - OPEC officials this week hailed the “ excellent” and “ unprecedented” implementation of their agreement to cut oil production, but were still waiting for solid evidence that the deal was fulfilling their key measure of success and shrinking the global glut.A reduction in the amount of oil held in storage around the world is the most important factor for the Organization of Petroleum Exporting Countries, Qatar’s Energy Minister Mohammed Al Sada said at the IP Week conference in London Wednesday. The pace of that decline will determine the group’s next move, including whether to extend the accord beyond its initial six-month term, said OPEC Secretary-General Mohammad Barkindo. The most reliable data available so far on inventories -- crude held in commercial storage in the U.S. -- is going in the opposite direction. Stockpiles in the world’s largest oil consumer have risen every week since OPEC began cutting on Jan. 1, while data on global storage levels has yet to be published. “The trend in inventories recently has been upwards and quite relentless. The market will be a bit careful to rally further if inventories are still building.” Brent crude has risen more than 20 percent since OPEC agreed last year to cut production, a deal that was joined later by Russia, Mexico and several other non-members. Even as the group’s initial compliance with the accord exceeded expectations, the price rally stalled in the mid-$50s as U.S. crude stockpiles surged to the highest level in more than three decades and oil drillers deployed the most rigs since October 2015.
Donald Trump, Saudi Arabia, And The Petrodollar --In late 2016, Obama vetoed the Justice Against Sponsors of Terrorism Act (JASTA). The bill would allow 9/11 victims to sue Saudi Arabia in US courts. With only months left in office, Obama wasn’t worried about the political price of opposing the bill. It was worth protecting Saudi Arabia and the petrodollar system, which underpins the US dollar’s role as the world’s premier currency. Congress didn’t see it that way though. Those up for reelection couldn’t afford to side with Saudi Arabia over US victims. So Congress voted to override Obama’s veto, and JASTA became the law of the land.The Saudis, quite correctly, see this as a huge threat. If they can be sued in US courts, their vast holdings of US assets are at risk of being frozen or seized. The Saudi foreign minister promptly threatened to sell all of the country’s US assets. Unlike every president since the petrodollar’s birth, Donald Trump is openly hostile to Saudi Arabia. Recently he put this out on Twitter:Dopey Prince @Alwaleed_Talal wants to control our U.S. politicians with daddy’s money. Can’t do it when I get elected.The dopey prince that Trump is referring to is Al-Waleed bin Talal, a prominent member of the Saudi royal family. He’s also one of the largest foreign investors in the US economy, particularly in media and financial companies. The Saudis openly backed Hillary during the election. In fact, they “donated” an estimated $10 million–$25 million to the Clinton Foundation, making them the most generous foreign donors. The Saudis did not want Donald Trump in the White House. And not because of some bad blood on Twitter. There are real geopolitical issues at stake.At the moment, Trump seems determined to walk back on US support for the so-called “moderate” rebels in Syria.The Saudis are furious with the US for not holding up its part of the petrodollar deal.They think the US should have already attacked Syria as part of its commitment to keep the region safe for the monarchy.
Trump's energy plan has him cozying up to Saudi Arabia -- Saudi Arabia is quickly becoming one of the biggest fans of President Trump's pro-fossil fuels energy plan, as Trump seeks to make the oil-rich kingdom a key strategic ally for energy security and combating terrorism. "President Trump has policies which are good for the oil industries," Saudi oil minister Khalid Al-Falih told the BBC this month. "He has steered away from excessively anti-fossil fuel, unrealistic fossil fuel policies," he said, referring to the strict policies of the Obama administration. Energy experts in Washington say the Saudis were not fans of former President Barack Obama's energy policies, which included ending sanctions on Iran's oil exports that has made the country a stronger power in the region. Iran is Saudi Arabia's chief nemesis in the Persian Gulf. "It's more geopolitically strategic with the Saudis than it is for the oil, per se," said Guy Caruso, the former head of the Energy Information Administration under former President George W. Bush, who also served as an economist for the Central Intelligence Agency. He is now the senior adviser for energy and national security at the nonpartisan Center for Strategic and International Studies think tank in Washington.Trump's policies are expected to boost cooperation with Saudi Arabia by making the country a key ally on energy and combating terrorism. The U.S.-Saudi joint energy strategy was outlined in Trump's "America First Energy Plan," which the White House posted on Inauguration Day. The plan calls for supporting increased domestic energy development, while simultaneously working "with our Gulf allies to develop a positive energy relationship as part of our anti-terrorism strategy." Those Gulf allies include Saudi Arabia, the United Arab Emirates and Kuwait as the largest crude oil producers, Caruso said.
Saudi Arabia debating shape of Aramco ahead of IPO: sources | Reuters: Saudi Arabia is considering two options for the shape of Saudi Aramco when it sells shares in the national oil giant next year: a global industrial conglomerate, and a specialized international oil company, industry and banking sources said. The listing of Aramco, expected to be the world's biggest initial public offer and raise tens of billions of dollars, is a centerpiece of the government's ambitious plan - known as Vision 2030 - to diversify the economy beyond oil. When the plan was publicly released in June last year, it pledged to "transform Aramco from an oil-producing company into a global industrial conglomerate". But now Saudi officials and their advisers are debating whether to make Aramco "a Korean chaebol", as one source said, referring to sprawling South Korean conglomerates, or a specialized company focused purely on oil and gas. A specialized company might be easier to value because of its simplicity and, since the risks in its business would be clearer, achieve a higher price for its shares. "There are two options being studied now. Either to make Aramco a pure oil and gas company, or a conglomerate and expand its role in petrochemicals and other sectors," said a Saudi industry source, declining to be identified because the debate is being conducted in private. An Aramco spokesperson said: "Saudi Aramco does not comment on rumor or speculation."
The Horrifying Starvation of Yemen Continues - The horrifying conditions in Yemen continue to get worse: Seven million Yemenis are closer than ever to starvation, the UN humanitarian coordinator in the country warned Tuesday, almost two years since a conflict escalated between the government and rebels.“Seven million Yemenis do not know where their next meal will come from and are ever closer to starvation” in a country of 27 million people, Jamie McGoldrick said. “Over 17 million people are currently unable to adequately feed themselves and are frequently forced to skip meals — women and girls eat the least and last,” he said in a statement. Yemen suffered from food insecurity before the U.S.-backed, Saudi-led intervention began in 2015, but that intervention, the ensuing damage to the country’s infrastructure and ports (most of it caused by coalition bombing), and the coalition’s cruel blockade have brought millions of people to the brink of famine. By enabling the coalition’s campaign, the U.S., Britain, and other supporting governments are partly responsible for creating the world’s worst humanitarian disaster, and they have had a hand in causing the famine that is now unfolding there. The disaster that engulfs Yemen was entirely predictable at the start of the intervention, and month after month many people kept warning that this is what would happen as a result of this reckless military intervention. The war has received intermittent coverage, but has been largely ignored. Millions of people are close to perishing from hunger and preventable diseases in a crisis that need not have happened and might still be ameliorated if there were a coordinated international response. Unfortunately, the international response has been anemic at best, and there is scant attention paid to the crisis in the Western countries whose governments have been working to exacerbate the civilian population’s misery.
Tulsi Gabbard Versus "Regime Change" Wars --Rep. Tulsi Gabbard is a rare member of Congress willing to take heat for challenging U.S. “regime change” projects, in part, because as an Iraq War vet she saw the damage these schemes do, as retired Col. Ann Wright explains to ConsortiumNews.com: I support Rep. Tulsi Gabbard, D-Hawaii, going to Syria and meeting with President Bashar al-Assad because the congresswoman is a brave person willing to take criticism for challenging U.S. policies that she believes are wrong. It is important that we have representatives in our government who will go to countries where the United States is either killing citizens directly by U.S. intervention or indirectly by support of militia groups or by sanctions. We need representatives to sift through what the U.S. government says and what the media reports to find out for themselves the truth, the shades of truth and the untruths.We need representatives willing to take the heat from both their fellow members of Congress and from the media pundits who will not go to those areas and talk with those directly affected by U.S. actions. We need representatives who will be our eyes and ears to go to places where most citizens cannot go.Tulsi Gabbard, an Iraq War veteran who has seen first-hand the chaos that can come from misguided “regime change” projects, is not the first international observer to come back with an assessment about the tragic effects of U.S. support for lethal “regime change” in Syria. Nobel Peace Laureate Mairead Maguire began traveling to Syria three years ago and now having made three trips to Syria. She has come back hearing many of the same comments from Syrians that Rep. Gabbard heard — that U.S. support for “regime change” against the secular government of Syria is contributing to the deaths of hundreds of thousands of Syrians and – if the “regime change” succeeded – might result in the takeover by armed religious-driven fanatics who would slaughter many more Syrians and cause a mass migration of millions fleeing the carnage.
The Cancer Of War: U.S. Admits To Using Radioactive Munitions In Syria -- Despite vowing not to use depleted uranium (DU) weapons in its military action in Syria, theUS government has now admitted that it has fired thousands of the deadly rounds into Syrian territory. As Foreign Policy Magazine reports:US Central Command (CENTCOM) spokesman Maj. Josh Jacques told Airwars and Foreign Policy that 5,265 armor-piercing 30 mm rounds containing depleted uranium (DU) were shot from Air Force A-10 fixed-wing aircraft on Nov. 16 and Nov. 22, 2015, destroying about 350 vehicles in the country’s eastern desert. Numerous studies have found that depleted uranium is particularly harmful when the dust is inhaled by the victim. A University of Southern Maine study discovered that:...DU damages DNA in human lung cells. The team, led by John Pierce Wise, exposed cultures of the cells to uranium compounds at different concentrations.The compounds caused breaks in the chromosomes within cells and stopped them from growing and dividing healthily. 'These data suggest that exposure to particulate DU may pose a significant [DNA damage] risk and could possibly result in lung cancer,' the team wrote in the journal Chemical Research in Toxicology. We should remember that the United States is engaged in military activities in Syria in violation of international and US law. There is no Congressional authorization for US military action against ISIS in Syria and the United Nations has not authorized military force in violation of Syria's sovereignty either. The innocent citizens of Syria will be forced to endure increased risks of cancer, birth defects, and other disease related to exposure to radioactive materials. Depleted uranium is the byproduct of the enrichment of uranium to fuel nuclear power plants and has a half-life in the hundreds of millions of years. Damage to Syrian territory will thus continue long after anyone involved in current hostilities is dead.
Russia asks world powers to pay for Syria rebuild -- Russia is pressing world powers to provide Syria with billions of dollars for reconstruction to bolster its faltering efforts to resolve the Arab state’s six-year conflict. But European and Gulf states, angered by Russia’s military intervention that tilted the war in favour of President Bashar al-Assad, will only contribute if Moscow secures a peace settlement that sets the terms for an eventual political transition, western diplomats say. “They [Russia] go in, they mess it all up, they break everything and want everyone to pay for it,” said a European diplomat. The issue is expected to be raised at UN-backed talks between the Syrian government and rebels that begin in Geneva on Thursday. Russia is the dominant foreign player involved in the war, but after helping broker a ceasefire between the warring parties in December, it has struggled to bring the adversaries closer to a political agreement. Mikhail Bogdanov, Russia’s deputy foreign minister in charge of Middle East issues, told a meeting of EU ambassadors in Moscow last week that the reconstruction of Syria would top the agenda very soon, according to European diplomats. He said “tens of billions of dollars” would be needed, while warning that “nothing” should be expected from Russia, the diplomats said.
Yemen president says $10 bn Saudi aid for reconstruction | Daily Mail Online: Yemen's President Abedrabbo Mansour Hadi said Wednesday that Saudi Arabia has earmarked $10 billion in aid for the reconstruction of provinces retaken from Shiite Huthi rebels.Riyadh, which since March 2015 has led a military coalition to support pro-Hadi fighters in Yemen, has made no official announcement on the aid.Hadi said the oil-rich neighbouring kingdom had allocated $10 billion "for the reconstruction of liberated provinces, including $2 billion as a deposit in the central bank to shore up the (Yemeni) riyal", the Saba news agency reported.The president, speaking in the government's temporary southern capital of Aden, called on his government to focus on power, water, roads, health and education in retaken areas.Pro-government forces backed by the Saudi-led coalition took back five southern provinces from the rebels in 2015, but Huthis still control the capital and much of northern Yemen.More than 7,400 people have been killed since the coalition intervened in impoverished Yemen two years ago, including around 1,400 children, according to the United Nations.
Mattis Tells Iraq We Are Not Here To "Seize" Your Oil - In the latest distancing by Trump administration advisors from recent statements by the President, Defense Secretary Jim Mattis arrived in Baghdad on an unannounced visit on Monday to discuss the war effort against ISIS, and said that the US military is not in Iraq "to seize anybody’s oil." Speaking to a small group of reporters traveling with him, Mattis was quoted by Reuters as saying “I think all of us here in this room, all of us in America, have generally paid for our gas and oil all along and I’m sure that we will continue to do so in the future."On his first trip to Iraq as Pentagon chief, Mattis is set to assess the war effort against the Islamic State as Iraqi forces launch a new push to evict ISIS militants from their remaining stronghold in the city of Mosul. In Iraq, he is likely to face questions about Trump's remarks and actions, including a temporary ban on travel to the United States and for saying America should have seized Iraq's oil after toppling Saddam Hussein in 2003. Trump told CIA staff in January: "We should have kept the oil. But okay. Maybe you'll have another chance." Trump later clarified his position in an ABC interview. The president said ISIS would not have become a global threat if it hadn’t taken over Iraq’s oil industry when the country was left weakened by the war.
Iraq: “Is It Oil?” Around the time that the United States invaded Iraq, 14 years ago, then-Senator John Kerry tried to justify the action. As he got into his speech, a loud, slow, calm voice came from the back of the room: “O – I – L.” Kerry tried to ignore the comment. But, again and again, “O – I – L.” Kerry simply went on with his prepared speech. The speaker from the back of the room did not continue long, but he had succeeded in determining the tenor of the day. Looking back on U.S. involvement in the Iraq, it appears to have been largely a failure. Iraq, it turned out, had no “weapons of mass destruction,” but this original rationalization for invasion offered by the U.S. government was soon replaced by the goal of “regime change” and the creation of a “democratic Iraq.” The regime was changed, and Iraqi dictator Saddam Hussain was captured and executed. But it would be very had to claim that a democratic Iraq either exists or is in the making—to say nothing of the rise of the so-called Islamic State (ISIS) and the general destabilization in the Middle East, both of which the U.S. invasion of Iraq helped propel. Yet, perhaps on another scale, the invasion would register as at least a partial success. This is the scale of O – I – L At the time of the U.S. invasion, I wrote an article for Dollars & Sense titled “Is It Oil?” (available online here). I argued that, while the invasion may have had multiple motives, oil—or more precisely, profit from oil—was an important factor. Iraq, then and now, has huge proven oil reserves, not in the same league as Saudi Arabia, but in group of oil producing countries just behind the Saudis. It might appear, then, that the United States wanted access to Iraqi oil in order to meet the needs of our highly oil-dependent lifestyles in this country. After all, the United States today, with just over 4% of the world’s population, accounts for 20% of the world’s annual oil use; China, with around 20% of the world’s population is a distant second in global oil use, at 13%. Even after opening new reserves in recent years, U.S. proven reserves amount to only 3% of the world total.
Iraqi forces storm Mosul airport, military base | Reuters: U.S.-backed Iraqi security forces captured Mosul airport from Islamic State on Thursday, advancing on multiple fronts towards the jihadists' last major stronghold in the western half of the city. The troops have gained ground rapidly in outlying areas south of the city, Iraq's second largest, since launching a new phase of a four-month offensive to terminate Islamic State's territorial holdings in the country. Elite counter terrorism forces joined the battle on Thursday in the southwest, entering the Ghozlani army base and pushing towards the districts of Tal al-Rayyan and al-Mamoun. Federal police and an elite interior ministry unit known as Rapid Response drove Humvees flying Iraqi flags into the perimeter of the airport, and state television later said they had taken full control of the heavily damaged facility. Islamic State fought back with suicide car bombs, drones carrying grenades and mortars, Reuters correspondents in the area said. The burnt corpses of two militants and the motorcycle from which they had fired at Iraqi forces were lying under a tree, apparently hit by an air strike. "Daesh (Islamic State) resistance is not inconsiderable but they are trying to save their strength for inside the city," First Lieutenant Ahmed al-Ghalabi of the Rapid Response force said outside the airport's main entrance. Iraqi forces hope to repair the airport and use it as a base from which to drive the militants from Mosul's western districts where around 750,000 people are believed to be trapped.
The Bitter Battle for Mosul -- Iraqi government forces have started their offensive aimed at capturing the western half of Mosul, Isis’s last big urban stronghold in the country. There are an estimated 4,000 jihadi fighters defending the close-packed houses and narrow alleyways in the half of the city west of the Tigris River, which is inhabited by some 650,000 civilians.Iraqi paramilitary federal police and interior ministry units are advancing from the south of Mosul with the initial aim of seizing the city airport. But the heaviest fighting is likely to come when the soldiers get into built up areas where the militant group has been digging tunnels and holes cut through the walls of houses so they can conduct a mobile defence away from artillery fire and airstrikes.The fighting could be as fierce as anything seen in the Iraq war, which has been ongoing since the US invasion of 2003 overthrew Saddam Hussein. The operation is being largely planned by the US, which has 6,000 soldiers in Iraq and which leads a coalition that has carried out more than 10,000 airstrikes and trained and equipped 70,000 Iraqi soldiers. “Mosul would be a tough fight for any army in the world,” said Lt Gen Stephen Townsend, the commander of the coalition, in a statement. The struggle for Mosul is the climactic battle in the bid by the Iraqi government and its foreign allies to destroy Isis, which established its self-declared caliphate in June 2014 when a few thousand fighters unexpectedly captured Mosul from a 60,000-strong government garrison. Abu Bakr al-Baghdadi, the Isis leader and self-appointed caliph, is in west Mosul according to Hoshyar Zebari, the former Iraqi finance and foreign minister, speaking to The Independent in an interview last week. This gives Isis an extra reason to hold the city to the last man.
Use of weaponized drones by ISIS spurs terrorism fears --Late last month, a pair of Islamic State fighters in desert camouflage climbed to the top of a river bluff in northern Iraq to demonstrate an important new weapon: a small drone, about six feet wide with swept wings and a small bomb tucked in its fuselage.The two men launched the slender machine and took videos from a second, smaller drone that shadowed its movements. The aircraft glided over the besieged city of Mosul, swooped close to an Iraqi army outpost and dropped its bomb, scattering Iraqi troops with a small blast that left one figure sprawled on the ground, apparently dead or wounded.The incident was among dozens in recent weeks in a rapidly accelerating campaign of armed drone strikes by the Islamic State in northern Iraq. The terrorist group last month formally announced the establishment of a new “Unmanned Aircraft of the Mujahideen” unit, a fleet of modified drones equipped with bombs, and claimed that its drones had killed or wounded 39 Iraqi soldiers in a single week.“A new source of horror for the apostates!” the group’s official al-Naba newsletter declared.While the casualty claim is almost certainly exaggerated, U.S. officials confirm that the terrorist group appears to have crossed a threshold with its use of unmanned aircraft. Two years after the Islamic State first used commercially purchased drones to conduct surveillance, the militants are showing a growing ambition to use the technology to kill enemies, U.S. officials and terrorism experts say.
Pope Francis: 'Muslim Terrorism Does Not Exist' - In an impassioned address Friday, Pope Francis denied the existence of Islamic terrorism, while simultaneously asserting that “the ecological crisis is real.” “Christian terrorism does not exist, Jewish terrorism does not exist, and Muslim terrorism does not exist. They do not exist,” Francis said in his speech to a world meeting of populist movements. What he apparently meant is that not all Christians are terrorists and not all Muslims are terrorists—a fact evident to all—yet his words also seemed to suggest that no specifically Islamic form of terrorism exists in the world, an assertion that stands in stark contradiction to established fact. “No people is criminal or drug-trafficking or violent,” Francis said, while also suggesting—as he has on other occasions—that terrorism is primarily a result of economic inequalities rather than religious beliefs. “The poor and the poorer peoples are accused of violence yet, without equal opportunities, the different forms of aggression and conflict will find a fertile terrain for growth and will eventually explode.” The Pope also reiterated his conviction that all religions promote peace and that the danger of violent radicalization exists equally in all religions. “There are fundamentalist and violent individuals in all peoples and religions—and with intolerant generalizations they become stronger because they feed on hate and xenophobia,” he said. While denying the existence of Islamic terrorism, Francis also seemed to condemn the denial of global warming, asserting that “the ecological crisis is real.” “A very solid scientific consensus indicates that we are presently witnessing a disturbing warming of the climatic system,” he said. We know “what happens when we deny science and disregard the voice of Nature,” the Pope said. “Let us not fall into denial. Time is running out. Let us act. I ask you again—all of you, people of all backgrounds including native people, pastors, political leaders—to defend Creation.”
Russia, Iran discuss oil cooperation, market conditions - Russian energy minister Alexander Novak discussed Russian companies' participation in Iranian oil projects and the situation on international oil markets with Iranian oil minister Bijan Zanganeh in Tehran on Tuesday, according to a ministry statement. Russia and Iran are key participants in an OPEC/non-OPEC deal to curb crude production and are planning to further strengthen links via deals for oil supplies and Russian participation in Iranian upstream projects in the near future. Earlier this week Russian companies also signed cooperation deals with Libya, Iraq and Iraqi Kurdistan, further cementing closer cooperation with partners in the region. Local media reported following the Tehran meeting that Russia and Iran are on the verge of signing a deal for the supply of 100,000 b/d of Iranian crude in return for cash and goods, in an indication that a long-discussed deal may be close to being signed. "It is expected that a contract for daily sales of 100,000 b/d of crude oil to Russia will be inked in early March," Zanganeh said, according to the Mehr news agency. Other agencies reported the deal would involve Russia paying 50% in cash and the remainder in goods. The Russian energy ministry did not immediately comment on the plans. Russia and Iran first signed a memorandum on an oil-for-goods deal in 2014. Covering a five year period, the deal envisaged supply of goods, oil equipment and services to Iran in exchange for Iranian oil. Since then officials have indicated that the deal has not been completely shelved, but little progress seems to have been made. Novak himself indicated in mid-2016 that the plan, designed to help sanctions-hit Iran market its crude, is less likely to be implemented since sanctions against Iran were eased.
Iran's foreign minister mocks Donald Trump 'putting him on notice' | The Independent: Iran’s foreign minister has mocked being “put on notice” in a tweet by Donald Trump and dismissed mounting pressure coming from Washington. Mohammad Javad Zarif drew laughter from an audience at an international security conference in Munich when, referring to the President's post, he said the “tweet is now very fashionable’’. Mr Trump had warned the Gulf nation it was “formally put on notice” on earlier in February after it tested a ballistic missile.The Trump administration then imposed sanctions on individuals and groups linked to the country's Revolutionary Guards. “We don’t respond well to threats, we don’t respond well to coercion and we don’t respond well to sanctions,” Mr Zarif told the meeting. “Crippling sanctions produced a net total of 19,800 centrifuges.” During his campaign, Mr Trump called a nuclear deal between several world powers and Iran was “one of the dumbest deals ever” and vowed to swiftly dismantle it. Iran has kept its part of the deal and significantly reduced its nuclear capacity, according to international monitors.
Iran Warns US: "The Enemy Will Receive A Strong Slap In The Face" --This past Saturday, two weeks after the White House unveiled new sanctions on two dozen Iranian entities in retaliation for a recent ballistic missile test, Iran's elite Revolutionary Guard announced it was set to conduct military drills this week despite warnings from the United States not to engage in such activity. General Mohammad Pakpour, commander of the force's ground units, told a news conference that "the manoeuvres called 'Grand Prophet 11' will start Monday and last three days." and warned that "rockets would be used" without specifying which kind. Several days later, as Tehran concluded the previously announced war games, Iran retaliated in the ongoing escalation of sabre rattling, when the abovementioned General Mohammad Pakpour again took to the airwave, and said quoted by Reuters that the United States should expect a "strong slap in the face" if it underestimates Iran's defensive capabilities, as Tehran concluded war games.On Wednesday, the Revolutionary Guards concluded three days of exercises with rockets, artillery, tanks and helicopters, weeks after Trump warned that he had put Tehran "on notice" over the missile launch. "The message of these exercises ... for world arrogance is not to do anything stupid," said Pakpour, quoted by the semi-official news agency Tasnim."The enemy should not be mistaken in its assessments, and it will receive a strong slap in the face if it does make such a mistake," said General Mohammad Pakpour, head of the Guards’ ground forces, quoted by the Guards' website Sepahnews.
Chinese Import Data Strongly Suggests OPEC Is Lying About A Production Cut -- To those cynics who accuse the self-monitoring OPEC, and its various adjunct agencies, of lying that it has implemented last year's agreed upon production cuts, China just released January crude import data, which validates this skepticism. As JPMorgan writes, while IEA estimated the OPEC crude oil production fell by 1mbd to 32.06mbd in January, suggesting an initial compliance of 90% with the output agreement reached end 2016, the latest oil supply details released by China customs today suggest a reduction of supplies was not yet seen by China, the world’s largest oil importer. In fact, quite the contrary: crude oil shipments from the 11 OPEC nations committed to a 1.2mbd output cut increased by 28% yoy, and more importantly, rose 4% from December 2016 - in a time when production was supposed to be declining - to 4.6mbd in January, accounting for 57% of China’s total oil imports. Ironically, if anyone was cutting it may have been the non-OPEC nations, mostly Russia, who foolishly assumed that Saudi Arabia et al would be true to its word: non-OPEC countries led by Russia that also agreed to a cut boosted their January supplies to China by 40% yoy, but saw a 10% drop sequentially, in line with what one would expect. Comparing January 2017 levels with the 2016 average, China’s crude oil imports from the committed OPEC and non-OPEC producers gained 6%/13% respectively, while the country’s total oil imports gained 5%.Some details:
- Saudi, Angola and Iran lead OPEC supply growth to China. According to the China Customs’ buy country oil supply data, Saudi Arabia boosted shipments to China by 19% yoy and 41% mom to 1.19mbd in January (16% growth versus the 2016 average). Imports from Angola increased by 63% yoy and 46% mom to 1.17 mbd last month (33% higher than 2016 average), while volumes from Iraq jumped by 43% yoy and 12% mom to 0.83mbd (14% higher than 2016 average).
- Russia and Oman drive non-OPEC supply growth. Among the non-OPEC countries that committed to 558kbd production cut from January, Russia’s oil supply to China increased by 36% yoy but fell 9% mom to 1.09mbd in January (3% higher than 2016 average), and Oman supplies expanded by 47% yoy and dropped 5% mom to 842kbd (20% higher than 2016 average).
It becomes even more blatant when charted: while total OPEC supply to China rose to a 4 month high, the combined oil supply from Saudi Arabia, Angola and Iraq in January soared to the highest a year, quite the opposite one would expect if the countries were cutting production instead of merely seeking to grab market share.