oil prices finally broke out of their narrow range this week, with US prices ending the week 9.1% lower than a week ago, as they fell every day this week, with the biggest drop precipitated by reports of a much larger than expected addition to our already record high supplies of crude oil...after closing the prior week down 66 cents at $53.33 a barrel, oil prices continued to weaken early this week, falling to $53.20 a barrel on Monday and to $53.14 a barrel on Tuesday, as traders remained concerned that Russia had failed to cut their production as promised in February...however, after the market closed on Tuesday, the American Petroleum Institute reported a massive 11.6 million barrel increase in US commercial oil inventories, against trader's expectations of a 1.4 million barrel increase, and oil prices began to slide in off market trading...the bottom then fell out of oil prices on Wednesday, when the EIA reported a still excessive 8.2 million barrel increase in US oil supplies, accompanied by a large surge in US oil production, and WTI contracts for April went on to drop $2.86, or 5.4%, to close at $50.28 a barrel...weakness from that crash persisted the rest of the week, as oil prices then fell another dollar to close at $49.28 a barrel on Thursday, steadied and rose back to near $50 a barrel on Friday morning, only to crash back to close at the day's low of $48.49 a barrel on Friday afternoon, after Baker Hughes reported anther double digit increase in active drilling rigs...since this was the largest price move since the OPEC cuts were initiated in November, we'll include a graph below of what it looked like...
this graph shows the daily closing prices per barrel of oil over the past 3 months for the April contract for the US benchmark oil, West Texas Intermediate (WTI), as stored or to be delivered to the Cushing Oklahoma storage depot...after oil prices jumped 14% on the OPEC production cut deal in the last week of November, oil prices then stayed in a narrow range above $52 a barrel for the next three months, with the range becoming even narrower over the last 8 weeks...over that span, with oil prices over $50 a barrel for the first time since early 2015, drilling for oil in the US has increased by nearly 30%, from the 477 rigs that were drilling on December 2nd to the 617 rigs that were working this week...over the year before that, drilling for oil generally held steady or increased slowly after peridos when oil prices were in the $45 to $50 a barrel range, while oil drilling generally slowed after periods when oil price quotes were in the low $40s or below...so we believe that this price break to below $50 a barrel will give drillers and frackers reason to pause, and even should drilling continue to expand from here, it will do so at a much slower and more irregular pace than we've seen over the past 3 months..
moreover, it seems certain that oil prices at these levels make it extremely unlikely that Transcanada can continue to pursue the Keystone XL pipeline, simply because oil sands expansion is out of the question at these price levels...because they have to burn one barrel of oil to extract three, the breakeven cost for extracting oil from Canada’s tar sands is much higher than most other places around the world; most figures i've seen indicate they need $50 US oil prices just to operate the extraction facilities now in existence, without any expansion...Keystone was originally proposed at a time when oil prices were twice what they are now., but 64 of the tar sands projects that were on the drawing board when oil prices first started falling have since been cancelled, with many of of the oil companies involved taking large losses, so the oil that was to fill the Keystone will no longer be there if the pipeline were to be completed...about a year ago, IHS estimated that a new greenfield oil sands mine (without an upgrader) required a WTI price between $85 to $95 per barrel on average to breakeven...a month ago, petrogeologist and oil analyst Art Berman at oilprice.com also showed that it would take at least $85 oil prices for 10 years to develop enough new oil sand projects to fill the Keystone XL…furthermore, there are already two massive Canadian tar sands pipeline projects already approved, which would ship any new dilbit production to the west coast and to the east...the major oil companies see the writing on the wall; just this week, Shell decided to divest nearly all of its Canadian oil sands interests in exchange for $7.25 billion, and Marathon announced an agreement to sell its Canadian subsidiary, including their interest in the Athabasca Oil Sands, and use the proceeds to buy Permian basin assets in Texas...all the deep pocketed major oil companies are getting out of the oil sands, and the small companies left with an interest there do not have the capital wherewithal to expand...
The Latest Oil Stats from the EIA
this week's oil data for the week ending March 3rd from the US Energy Information Administration indicated that our imports of crude oil rose back to near this years average, while our refinery activity fell further below the seasonal norm, resulting in a large surplus of crude for the 9th week in a row, pushing our supplies of oil to yet another an all time high...our imports of crude oil rose by an average of 561,000 barrels per day to an average of 8,150,000 barrels per day during the week, while at the same time our exports of crude oil rose by 179,000 barrels per day to an average of 897,000 barrels per day, which meant that our effective imports netted out to 7,253,000 barrels per day for the week, 385,000 barrels per day more than last week...at the same time, our crude oil production rose by 56,000 barrels per day to an average of 9,088,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 16,341,000 barrels per day during the week...
meanwhile, refineries reportedly used 15,492,000 barrels of crude per day during the week, 172,000 barrels per day less than during the prior week, while at the same time, 1,137,000 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 288,000 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 +288,000 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 used in explaining it.....
the weekly Petroleum Status Report also tells us that the 4 week average of our oil imports anomalously fell to an average of 7.879 million barrels per day, now 1.7% below that of the same four-week period last year...meanwhile, the 4 week average of our oil exports rose to 964,000 barrels per day, which was 145.2% higher than the same 4 weeks a year earlier, as the discount on American light sweet crude has made it attractive to foreign buyers...meanwhile, this week's 56,000 barrel per day oil production increase included a 46,000 barrel per day increase in oil production in the lower 48 states and a 10,000 barrel per day increase in output from Alaska...the 9,088,000 barrels of crude per day that we produced during the week ending March 3rd was the highest since the week ending February 19th last year, just barely topping last March 4th's total of 9,078,000 barrels per day, while it was still 5.4% below the June 5th 2015 record oil production of 9,610,000 barrels per day...
US refineries were operating at 85.9% of their capacity in using those 15,492,000 barrels of crude per day, down from 86.0% of capacity the prior week, and down from the year high of 93.6% of capacity eight weeks earlier, when they were processing 17,107,000 barrels of crude per day....their processing of crude oil is also down by 2.6% from the 15,911,000 barrels of crude that were being refined during the week ending March 4th, 2016, when refineries were operating at 89.1% of capacity....but even with the refinery slowdown, gasoline production from our refineries rose by 388,000 barrels per day to 9,844,000 barrels per day during the week ending March 4th, which turns out to be 2.8% more than the 9,580,000 barrels per day of gasoline that were being produced during the week ending March 4th a year ago...moreover, refineries' production of distillate fuels (diesel fuel and heat oil) was also higher, rising by 18,000 barrels per day to 4,773,000 barrels per day, which was also a bit more than the 4,744,000 barrels per day of distillates that were being produced during the week ending March 4th last year...
however, even with the increase in our gasoline production, the EIA reported that our gasoline inventories fell by 6,555,000 barrels to 249,334,000 barrels as of March 3rd, for the largest drop in our gasoline supplies since April 2011....factors contributing to that big drop in our gasoline supplies were a 582,000 barrel per day increase to a near normal 9,268,000 barrels per day of domestic consumption of gasoline, and a 215,000 barrel per day drop in our gasoline imports to 242,000 barrels per day, which was the least gasoline we imported in any week since the first week of January 1999...for a historical comparison of this week's drop in gasoline supplies, we have a small graph below taken from a stack of graphs at Zero Hedge...
the above graph comes from a set of graphs in an article at Zero Hedge about this week's EIA report...it shows the weekly change in gasoline supplies over the last six and a half years, with increases in gasoline supplies indicated by a green bar above the zero line, and decreases in our gasoline supplies indicated by a red bar below the zero line, with the size of each bar indicating the magnitude of the change...Zero Hedge also includes a dark red dashed line from this week's drop back to the last time there was a drop of this magnitude, which was for the week ending April 8th, 20011, when our gasoline supplies dropped by exactly 7 million barrels in just one week...
now, this week's drop in gasoline supplies is hardly a crisis, because as you might recall just 3 weeks ago our gasoline supplies were at an all time high, beating the record set in the same week of 2016...notice the above graph also shows a series of green bars in early 2017, when our gasoline supplies were on the rise...thus, despite this week's big drop, out gasoline supplies are still up by nearly 28.4 million barrels since the first week of November, only down slightly from the March record high of 250,463,000 barrels of gasoline that we had stored on March 4th of last year, and are still 3.9% above the 239,873,000 barrels of gasoline we had stored on March 6th of 2015...
our supplies of distillate fuels also fell this week, decreasing by 2,676,000 barrels to 161,532,000 barrels by March 3rd, as the amount of distillates supplied to US markets, a proxy for our consumption, increased by 278,000 barrels per day to 4,091,000 barrels per day, and as our exports of distillates rose by 46,000 barrels per day to a 24 week high of 1,330,000 barrels per day....while our distillate inventories have now slipped 0.6% below the distillate inventories of 162,478,000 barrels that we had on March 4th at the end of the warm winter of last year, they are still 28.7% higher than the distillate inventories of 125,503,000 barrels of March 6th, 2015…
finally, with our net oil imports higher and our refinery demand lower, we had an even larger surplus of crude oil remaining, and hence our inventories of crude oil rose for the 9th week in a row to yet another record, increasing by 8,209,000 barrels to 528,393,000 barrels by March 3rd...thus we ended the week with 10.3% more crude oil in storage than the 479,012,000 barrels we ended 2016 with, which we can see in the bar graph below..
the above graph comes from an emailed package of graphs from John Kemp, senior energy analyst and columnist with Reuters (see my footnote below) and it shows in bar graph fashion the amount of oil added to US crude inventories between December 31st and the first weekend in March for each of the past 11 years...while surplus crude is normally added to storage during the winter months, when refineries are runnng slower, it's quite obvious that the surpluses have been much larger than average (shown by the red dash) over the past three years...what that has resulted in in terms of increasing supply is then shown in the next graph we'll include below...
the above graph comes from a weekly pdf booklet of petroleum graphs produced by Yardeni Research, a provider of independent investment and economics research, run by Dr Ed Yardeni...it shows the end of the week supply of crude oil in millions of barrels for each week beginning with January 2013, up to and including this week's report for March 3rd, with graphs for each year color coded as indicated...here we can see how our oil inventories stayed in a narrow range during 2013 and 2014 (and during the years before then, for that matter), represented by the mustard and green bands, typically falling to below 330 million barrels by the end of each summer and then rising to nearly 370 million barrels by early spring....however, at the beginning of 2015, represented by the blue colored graph, our inventories of oil started rising each week till they topped 450 million barrels at the end of April 2015, and then stayed elevated in a range 80 to 100 million barrels above the previous norms over the rest of that year...that continued into 2016, represented by the grape colored graph, and although the rate of increase tailed off from the previous year, our 2016 oil supplies still generally averaged about 15% above 2015's elevated levels, and more than 40% above historical levels...now we see in the scarlet colored graph, representing the first nine weeks of 2017, that our oil supplies are now again rising at an faster rate from the records set in 2016...as a result, we now have 7.7% more crude oil in storage than the then record 490,843,000 barrels we had stored on March 4th of 2016, 27.2% more crude than the 415,425,000 barrels of oil we had in storage on March 6th of 2015 and 56.2% more crude than the 338,333,000 barrels of oil we had in storage on March 7th of 2014...
This Week's Rig Count
US drilling activity increased for the 18th time in 19 weeks during the week ending March 10th, as we saw the 6th double digit rig increase in the past 8 weeks....Baker Hughes reported that the total count of active rotary rigs running in the US increased by 12 rigs to 768 rigs in the week ending on this Friday, which was 288 more rigs than the 480 rigs that were deployed as of the March 11th report in 2016, but still far from the recent high of 1929 drilling rigs that were in use on November 21st of 2014...
the count of rigs drilling for oil rose by 8 rigs to 617 rigs this week, which was up from the 386 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...at the same time, the count of drilling rigs targeting natural gas formations rose by 5 rigs to 146 rigs this week, which was up from the 94 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...the rig that was classified as miscellaneous that has been running for several months was finally shut down this week, and thus there are now no such miscellaneous rigs at work...
two more drilling platforms were added to those working in the Gulf of Mexico this week, both offshore from Louisiana, which brought the Gulf of Mexico count up to 20 rigs, still down from the 26 rigs that were drilling in the Gulf during the same week of 2016...that also brought the total US offshore count for the week up to 20 rigs, all in the Gulf of Mexico, down from a total of 27 offshore rigs a year ago, when there was also a rig working offshore from California, in addition to the 26 rigs in the Gulf of Mexico...also this week, a rig was also set up to drill through an inland lake in Louisiana, where there are now 5 such inland lakes rigs active, up from the 3 that were drilling on inland waters a year ago...
the number of horizontal drilling rigs working in the US increased by 6 rigs to 639 rigs this week, which is now up by 264 horizontal rigs from the 375 horizontal rigs that were in use in the US on March 11th of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, a net total of 6 vertical rigs were added this week, bringing the vertical rig count up to 68, which was also up from the 55 vertical rigs that were deployed during the same week a year ago...meanwhile, the directional rig count was unchanged at 61 rigs, which was also up from the 50 directional rigs that were deployed during the same week last year....
as usual, the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of March 10th, the second column shows the change in the number of working rigs between last week's count (March 3rd) and this week's (March 10th) count, the third column shows last week's March 3rd 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 11th of March, 2016...
the first thing we have to note is that this week's increase came without an increase in drilling in Texas, who did not see an increase for the first time since September...the states with the largest increases this week included Louisiana, with the two new rigs in the Gulf, the one on an inland lake, and two in the Haynesville, and Colorado and Oklahoma, who each added three rigs...Oklahoma's increase does not appear to be of horizontal drilling outfits, since none of the shale basins in that state show a gain. whereas the 4 rig increase in the Denver-Julesburg Niobrara could account for the Colorado or the Wyoming increases....note that the Utica in Ohio added two rigs this week and now has 22 rigs active, double the 11 rigs that were active a year ago....also note that of the states not listed above, Mississippi also added a rig and now has 4 rigs active, up from 2 rigs a year ago, while Nevada saw its only rig, which had been working in the state since July, shut down...
International Rig Counts for February
Baker Hughes also released the international rig counts for February on Tuesday of this past week, which unlike the weekly North American count, is an average of the number of rigs that were running in each country during the month, rather than the total of those rig drilling at month end....Baker Hughes reported that an average of 2,027 rigs were drilling for oil and natural gas around the globe in February, which was up from the 1,918 rigs that were drilling around the globe in January, and up from the 1,761 rigs that were working globally in February of last year....increased North American drilling again accounted for most of the global increase, as the average US rig count rose from 683 rigs in January to 744 rigs in February, which was also up from the average of 532 rigs that were working in the US in February a year ago, while the average Canadian rig count rose from 302 rigs in January to 342 rigs in February, which was also up from the 211 Canadian rigs that were deployed in February a year earlier....outside of Northern America, the International rig count rose by 8 rigs to 941 rigs in February, which was still down from 1,018 rigs a year ago, as increases in drilling in Europe and Latin America more than offset small decreases in Asia and Africa..
the count of rigs deployed in the Middle East was unchanged at 382 rigs in February, after their drilling activity had increased by 6 rigs in January, which still left them down from 404 rigs a year earlier...OPEC member Kuwait, whose compliance with the cartel's agreed to cuts has been on par so far, activated 7 additional rigs in February, and thus had 59 rigs deployed, up from 43 rigs a year earlier...the Qataris, also an OPEC member, also added a rig in February and thus had 11 rigs working, up from the 6 that were drilling new wells a year ago...Bahrain, an island country in the Gulf who is not an OPEC member, also added a rig and now have 2 drilling, in contrast to a year ago, when they had no activity....on the other hand, the Saudis idled 4 of their rigs during the month, and now have 120 rigs active, which is down from the 128 rigs they had working a year ago..still, Saudi Arabia's rig count had averaged near 125 rigs weekly since early 2015, up from their average of around 105 rigs in 2014, so they've not yet pulled back to the level of drilling they were doing before OPEC started the price war...Egypt, who is not an OPEC member, shut down 2 of their rigs in February, leaving them 23 rigs still active, down from 35 rigs a year earlier...in addition, OPEC members Iraq and Abu Dhabi of the United Arab Emirates, and Israel each shut down 1 rig for the month...for Iraq, that left 40 rigs still active, down from 49 rigs a year earlier, for Abu Dhabi, that left 47 rigs down from 48 a year earlier, andthat left Israel with no drilling activity, down from 1 active rig a year ago..
meanwhile, the Latin American region saw their active drilling rig numbers increase by a net of 3 rigs to 179 rigs, down from 237 rigs in February of last year, and down from 321 rigs as recently as September of 2015, as the region idled 92 rigs over the first 6 months of 2016...OPEC member Venezuela added 3 rigs and thus had 54 rigs active for the month, which was down from the 69 rigs they had deployed a year earlier...in Argentina, where they had shut down 11 rigs in December and another 7 rigs in January, added two back in February and thus had 54 rigs working, down from 65 a year earlier and down from over the over 100 active rigs Argentina saw through most of 2015...Columbia, also not a cartel member, also added two rigs in February, bringing their active total up to 22 rigs, up from 7 rigs a year earlier....in addition, OPEC member Ecuador added 1 rig rig and thus had 7 rigs active, up from 4 rigs a year earlier...Latin American countries reducing their rig count included Brazil, who was down 2 rigs to 14 rigs, and down from 35 rigs a year ago, and Bolivia, Peru, Guyana, minor producers who each shut down 1 rig...
drilling activity in the Asia-Pacific region slipped by a net of 2 rigs to 196 rigs in February, which was still up from the 182 rigs working ove the region a year earlier...the Chinese shut down 2 more offshore rigs, after they had shut down 5 offshore rigs in January and 3 offshore rigs in December, leaving them with 18 rigs working offshore, down from the 25 offshore rigs they were running last February...India shut down 1 rig but still had 115 rigs active, up from 99 rigs a year earlier....and Vietnam also shut down 1 rig, leaving 3 rigs active, the same as they had a year ago...meanwhile, Thailand added one rig and thus had 13 rigs active, which was still down from 16 rigs a year earlier, and Bangladesh also started drilling with a single rig, in the first drilling in Bangladesh since the end of 2014...
on the other hand, drilling activity picked up in Europe, rising by 9 rigs to 107 rigs rigs, which was was the same number of rigs working in Europe a year ago at this time, as their offshore drilling activity rose from 31 rigs to 38 rigs, also up from the 36 rigs offshore of Europe a year ago...Noway added 4 platforms offshore to bring their total to 16 rigs, all offshore, down from 18 rigs offshore a year ago...the UK also added 3 offshore, increasing their offshore count to 11 rigs, up from 7 rigs offshore last February....Sakhalin Island, off the east coast of Russia but inexplicably included in the European totals, added 2 rigs offshore and 3 on land, bringing their total deployment to 12 rigs, up from 6 rigs a year ago...Romania added 2 land based rigs and shut down 1 offshore, and thus have 7 onshore rigs active, same as a year ago...in addition, Poland added 2 land based rigs and thus had 10 active, up from 7 rigs a year ago, and Greece started up a rig offshore, their first activity since last July...meanwhile, Turkey shut down 3 rigs, leaving them with 29 rigs still working, same as a year ago, Italy shut down one offshore platform, leaving 4 rigs on land still active, the Dutch shut down an offshore rig, leaving them with 2 offshore, and France, Hungary and Iceland each cut back from 2 rigs to one, as none of them ran more than 2 rigs over the recent year...
lastly, the African continent excluding Egypt saw a net decrease of 2 rigs to 77 rigs in February, which was also down from the 88 rigs working in Africa last year at this time...OPEC member Angola shut down 2 rigs, and now has 3 rigs active, also down from the 8 rigs they had active a year earlier..OPEC member Algeria shut down 1 rig, leaving 50 rigs still working in Algeria, down from the 52 rigs they had a year ago...Tunisia shut down 1 of the two rigs they had active, which is still more than a year ago when they had no rigs active...on the other hand, OPEC member Nigeria, who is exempt from the organization's production cuts for the time being, added 1 rig and now have 7 rigs working, which was still down from the 9 rigs they had deployed a year ago, and Senegal started up a single rig in their first drilling activity since May of last year...finally, note that Iranian, Russian, and Chinese rig counts are not included in this Baker Hughes international data, although we did note that China's offshore area, with an average of 18 rigs active in February, were included in the Asian totals here...
as noted above, 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...he advises that his mailing list is open to anyone, quoting him: "SIGN UP to receive a free daily digest of best in energy news + my research notes by emailing firstname.lastname@example.org " i've been receiving a daily mailing of links & graphics, copies of his columns as published, and a weekly pdf of graphs... so if anyone is interested in receiving the same, just 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....
GOP lawmaker confronts Kasich on Ohio's green-energy mandates - In the final days of 2016, Republican Gov. John Kasich vetoed legislation that would have delayed the state’s renewable energy mandates from going into effect for two years. Instead, they are set to resume this year.Now state Rep. Bill Seitz is pushing to get rid of these costly regulations altogether.Ohio’s renewable portfolio standards require utility companies to derive an increasing share of their electricity from renewable sources like wind and solar. By 2025, 12.5 percent of utility power must be generated from renewable energy. Financial penalties are imposed for failure to meet the mandate. Ohio utilities currently derive 2.5 percent of their electricity from renewables.The Ohio Legislature imposed a two-year pause on these mandates in 2014 while a newly established Energy Mandates Study Committee examined whether Ohio should revive them. After the committee recommended legislators indefinitely suspend Ohio’s portfolio standards, the Legislature sent to Kasich’s desk a measure that would have delayed implementation until 2019. Kasich vetoed the bill two days after Christmas. In a statement released with the veto, the governor said “Ohio cannot afford to take a step backward on the economic gains that we have made in recent years … and arbitrarily limiting Ohio’s energy generation options amounts to self-inflicted damage to both our state’s near and long-term economic competitiveness.” In response, Seitz plans to introduce legislation this session that would extend Ohio’s renewable energy target deadline to 2027 and turn it into a voluntary goal instead of a state mandate. These changes would effectively abolish Ohio’s renewable portfolio standards.
Republican Lawmakers Move, Again, Toward Repealing Ohio's Renewable Energy Standards | WKSU -- When Gov. John Kasich vetoed another two-year freeze on the state’s renewable energy benchmarks last year, his fellow Republicans in the Legislature promised they’d be back with a total repeal of those benchmarks. Statehouse correspondent Karen Kasler reports they appear to have taken the first step.Amid the rush in December, Gov. John Kasich vetoed a bill that would have frozen for another two years the state’s renewable energy standards for electric utilities. He says it would “do self-inflicted damage to Ohio’s economic competitiveness." He'd telegraphed that veto to lawmakers in Ohio while speaking at an appearance at the University of Texas last September. “If you try and kill the standards, whether it has to do with the renewables or whether it has to do with the issue of saving energy, I’ll veto the bill,” Kasich warned. That bill would have made the renewable energy benchmarks voluntary goals instead of required mandates for the utilities for two years. Kasich and others viewed last year’s proposal as a continuation of the two-year freeze lawmakers passed for the standards in 2014, and he had repeatedly had said he couldn’t support an indefinite freeze. After that veto, supporters of the freeze vowed they’d be back right away. And two months into the new two-year session, half the House is co-sponsoring a bill from Cincinnati Republican Rep. Lou Blessing that would make a major change in the renewable energy law by abandoning the state’s mandates and the penalties for not meeting them. “Now it is permanently goals. So there’s no compliance portion of the renewable portfolio standard,” Blessing said.Blessing’s bill also reduces the energy-efficiency goals for the next decade by a fifth. And it allows many businesses to opt-out of clean energy charges from electric utilities. Blessing maintains it’s not a total repeal. However, the chief opponent of the standards says the bill is where he thinks the state should go with repeal.
Ohio GOP lawmakers aim to kill wind, solar mandates, endorse competitive markets -- The Republican majority in the Ohio House is moving again to get rid of the state's renewable energy rules. In a bill sponsored by a Cincinnati Republican and released late Tuesday, the House would make voluntary the mandates that now require power companies to generate or buy and sell a percentage of power from wind, solar and other renewable technologies. The 73-page bill, as sponsored by State Rep. Louis B. Blessing would:
- Allow any customer who has signed a contract with an independent power company to avoid paying the delivery company any extra charges for green power. This provision appears to be aimed at American Electric Power's plans to build 900 megawatts of wind and solar (about as much power as the Davis-Besse nuclear plant generates) and have customers pay for the construction.
- Leave it up to each power company to decide what percentage of the power it sells has been generated by renewable technologies such as wind and solar. The law currently demands that by 2026, 12.5 percent of the power sold must be from renewables. The standards under this proposed legislation would be completely voluntary and there would be no penalties for companies that chose not to sell green power. The bill eliminates all fines since the standards would become voluntary benchmarks. And in 2026, even the voluntary benchmarks would disappear from the law.
The legislation continues rules on "Renewable Energy Credits, or RECs, but appears to effectively kill the value of RECs in future years. Starting in 2009, power companies could buy the RECs in a market rather than build their own wind and solar. The REC market was designed to be a source of money for independent companies building wind and solar.The bill would also: Allow large commercial or industrial customers to opt out of utility-sponsored energy efficiency programs. This is an expansion of the current law, which allowed only industrial customers to opt out. But residential customers are not permitted to opt out of the programs, as the bill is now written.
Liberty trustee raises concern about horizontal drilling in township -- Trustee Jodi Stoyak has raised welfare concerns about a company planning to drill horizontally within the township. The company also is seeking to hydraulically fracture, or “frack,” at the site, said Steve Irwin, a spokesman with the Ohio Department of Natural Resources. PAC Drilling LLC, an oil and gas company based in Bolivar, Ohio, has filed for a permit from ODNR to drill about 2 miles deep on 170 acres near Warner Road. Irwin said ODNR initially granted a permit to the company to drill horizontally in Liberty from the Clinton Sandstone formation. PAC Drilling has since submitted a new version of the permit, seeking to instead drill at an adjusted nearby location. The revised permit application is pending. “I have grave concerns about this,” Stoyak said of drilling. “I don’t think this type of activity should be happening in a residential area where people have no other choice but to rely on well water. ... ODNR will tell you that they have all these regulations in place, but there have been situations that occur. If there’s an accident, there’s no turning back.”
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.
Ohio EPA streamlines permitting process - — The Ohio Environmental Protection Agency announced last week it has created a program to consider permit applications for oil and natural gas midstream compressor stations on more of a generic basis.The move is being made in anticipation of more growth in horizontal fracturing of shale, or fracking, which has made vast reserves of oil and natural gas in the southern and eastern parts of the state more accessible.Previously, air emissions from future compressor stations — such as a controversial one planned between Waterville and Whitehouse for the upcoming NEXUS Gas Transmission pipeline being developed by Houston-based Spectra Energy and DTE Energy of Michigan — were subject to a longer case-by-case permit process.Applications for general permits follow a template, the Ohio EPA said, adding that it believes the new, streamlined process can become “an effective means to track and regulate air emissions and can be more efficient and timely for processing.” The new general permits and comments received from the public may reviewed online at: epa.ohio.gov/dapc/genpermit/ngcs.aspx.
Rex Energy reports better returns on Carroll wells - Canton Repository -Rex Energy is getting better returns on its Utica Shale wells in Carroll County. Assuming natural gas worth $3 per thousand cubic feet and oil at $55 a barrel, the rate of return on Carroll wells grew from 28 percent to 47 percent in 2016, according to a press release announcing Rex Energy’s earnings Tuesday.Rex drilled seven wells, fracked ten wells and began production from 13 wells in Carroll last year. No wells remained to be drilled or fracked at the end of the year.Among the new wells in production were the four wells of the Vaughn pad in Washington Township. The wells had a 5-day average sales rate per well equal to 1,500 barrels of oil per day, with liquids accounting for 65 percent of production.Rex is based in State College, Pa., and has drilled 31 Utica wells in Ohio.The company had a net loss of $67.4 million for the fourth quarter and $176.7 million for the year. The company spent $29.5 million on capital projects, about $6 million less than anticipated.Rex produced 71.5 billion cubic feet of natural gas equivalent in 2016, up 6.6 percent from the previous year.Average daily production is estimated at 194 million to 204 million cubic feet of natural gas equivalent per day in 2017.Rex agreed last year to sell 14 wells and the drilling rights to approximately 4,100 acres in Guernsey, Noble and Belmont counties to Antero Energy.Rex has said it plans to spend up to $80 million drilling and fracking wells this year, with one-fifth of that money invested in its Utica holdings in Carroll.The rest of the money will be spent in the company's Marcellus and Upper Devonian Burkett shales in Pennsylvania.
Pa. Supreme Court again considers how communities zone for drilling: — The Pennsylvania Supreme Court heard arguments Wednesday in a Marcellus Shale zoning case that could have broad implications for how municipal governments decide which of their land use districts are appropriate for oil and gas drilling. The case, Brian Gorsline v. Board of Supervisors of Fairfield Township v. Inflection Energy, has been closely watched because of its potential to influence shale gas development far outside of the Lycoming County community at its center. But during the session Wednesday the justices appeared inclined to keep a tailored focus. Four residents, represented by the environmental organization PennFuture, challenged Fairfield Township’s decision to allow Marcellus Shale wells as a conditional use in an area zoned for residential and agricultural uses. They argue that the township disregarded its own zoning commitments by introducing industrial drilling into a residential district designed to preserve its quiet character. A Lycoming County court judge sided with the residents, but the Commonwealth Court reversed that decision. The appeals court reasoned that a shale gas well is similar to types of facilities that provide a broad public service — such as a power substation or a water treatment plant — that can generally be located in any zone. The case offers the high court an opportunity to further define the scope of its 2013 landmark decision in Robinson Township v. Commonwealth that wiped out a provision of the state’s drilling law requiring shale gas development to be allowed in all zoning districts. The Gorsline case has drawn an array of friend of the court briefs from industry groups, chambers of commerce, environmental organizations and local governments hoping to guide the court’s direction.
DEP chief defends methane rules for well sites: The Pennsylvania Department of Environmental Protection is defending its controversial plans to reduce methane and other air pollution from natural gas production facilities even as it expands the timeline for public scrutiny of the proposals. Acting DEP Secretary Patrick McDonnell offered a detailed justification of the proposed permits for new shale gas well sites and associated equipment in a letter last Friday to three Republican Senate leaders. The proposed new and revised permits “balance the needs of industry for cost-effective operations and the needs of the public for enhanced environmental protection,” he wrote. Sens. Jake Corman, Joe Scarnati and Gene Yaw — the chamber’s majority leader, president pro tem and environmental resources and energy committee chairman — had raised 21 questions about the permits after meeting with Mr. McDonnell in early February to discuss their concerns that the complexity of the requirements will discourage companies from drilling in Pennsylvania. The senators were among those who asked DEP to expand the public comment period on the permits from March until June 5 — a move that environmental groups fear will make the permits vulnerable to being traded away during state budget negotiations that peak in the month leading up to the spending plan’s June 30 deadline.
Physician Diagnoses New Health Risk: Explosions at Drilling Sites - Marsha Haley, M.D., is a radiation oncologist at two of the University of Pittsburgh Medical Center hospitals. She’s also a concerned mother of a 10-year old.Together, they live in a newer, suburban neighborhood in the Borough of Seven Fields, Butler County, PA. Her daughter attends the local elementary school, part of a five building K-12 campus very close to natural gas well pads. Over the past few years, as fracking operations crept closer to school property, Dr. Haley became more and more concerned about the proximity of wells to school children. It’s not easy to evacuate a school and Dr. Haley particularly was worried about blast zones should an explosion at a well pad occur. At some point, she realized she could no longer stand by as her worries continued to grow. When a well was drilled 500 feet from another school in Southwestern PA, the absolute limit from a building allowed by Pennsylvania law, she knew she had to act. A serious, academic woman, tall, angular, and well-dressed, Dr. Haley chooses her words carefully. Growing concern lead her to begin researching the science behind setting setback distances, which are meant to protect those working and living around oil and gas operations from potential explosions. “I heard about a well pad fire in Ohio where firefighters were exposed to chemicals I was familiar with as a physician,” she says. Speaking from her sunroom, she goes on to explain that the Ohio firefighters were exposed to a therapy-grade radioactive isotope that was found onsite in a fracking truck. “As a radiation oncology physician, that caught my interest,” According to Dr. Haley, radiation oncologists are required to carefully track every microcurie of radioactive material for the Pennsylvania Department of Environmental Protection (PA DEP). However, for years, fracking operators were permitted to dispose of hydraulic fracturing waste water at public sewage plants, which were not equipped to handle the chemical-laden, radioactive material. “It’s such a double standard,”
FERC certificates several new natural gas pipelines in 2017 - Several large natural gas interstate pipeline projects have come online in recent years to support the shifting geography of domestic natural gas production. The Marcellus and Utica shale plays in the Northeast, where production has grown and resources are abundant, are major drivers for pipeline development. In 2016, the Federal Energy Regulatory Commission (FERC) certificated 17.6 billion cubic feet per day (Bcf/d) of new natural gas pipeline capacity. So far in 2017, FERC certificated more than 7 Bcf/d of new pipeline capacity before losing its quorum following the departure of one commissioner in February, which left just two sitting commissioners and three vacant seats. The seven projects certificated during the first few weeks of 2017 include more than 1,500 miles of natural gas pipeline construction and expansions, involving combined additions of more than 7 Bcf/d of capacity. The pipeline projects are concentrated in the eastern half of the United States to improve access to markets for growing eastern natural gas production, and they have projected 2017 and 2018 in-service dates. Two large-capacity projects, the Rover Pipeline Project (and related projects) and the Atlantic Sunrise Pipeline Project, were among those that received certificates in early 2017. The Rover Pipeline will move natural gas out of the Utica shale play that spans parts of New York, Pennsylvania, West Virginia, and Ohio. According to Rover Pipeline LLC, the $4.2 billion project will have direct deliveries in Ohio; West Virginia; Michigan; and Ontario, Canada and will reach a capacity of 3.3 Bcf/d. Construction will begin in the first quarter of 2017. The Atlantic Sunrise Pipeline will move natural gas out of the Marcellus shale play to markets in the mid-Atlantic and southeastern states. According to the Transcontinental Gas Pipe Line Company, LLC, the $2.6 billion expansion will add 1.7 Bcf/d of pipeline capacity, and construction will begin in mid-2017. Other recently certificated pipeline projects include the Orion Project, Transco to Charleston Project, Rayne and Leach Xpress, Northern Access, and Northern Lights 2017 Expansion. As of February 23, 33 projects had FERC applications in process, and 20 projects had submitted FERC pre-filings, according to data from PointLogic Energy. Consideration of these projects, among others, will be deferred until FERC has at least the three commissioners required to constitute a quorum.
"No Business As Usual": Over 130 Groups Nationwide Announce Their Opposition To FERC Appointments -- Over 130 organizations across the country announced today that they will oppose nominees made by the Trump Administration to the Federal Energy Regulatory Commission (FERC). The move reflects the growing resistance nationwide from residents, farmers, business owners, physicians, and environmentalists to FERC's practice of recklessly permitting pipelines that put hundreds of communities and the drinking water of millions of Americans at risk, in addition to the global climate. The 135 groups range from dozens of local community organizations and activists to national nonprofit organizations (Beyond Extreme Energy, Center for Biological Diversity, Food and Water Watch, and Green America). At a time when citizens are increasingly calling on Senators to oppose appointed officials that support the fossil fuel industry, the pledge signers, representing over a million people nationwide, pledge to work against each nominee to FERC made by the Trump Administration, and to call on U.S. Senators to use the nomination process to highlight FERC's rubber stamping of pipeline projects and refusal to listen the legitimate concerns of community groups. FERC is the agency primarily responsible for reviewing applications for pipelines and conducting environmental assessments, and the agency has been increasingly criticized by local communities impacted by pipelines for its failure to take into account community concerns and independent environmental impact analyses documenting the risks. "FERC serves the industry it supposedly regulates instead of the American public, and its rubber stamping of pipelines nationwide puts millions of people at risk," said Todd Larsen, executive co-director of Green America. "It is imperative that all Americans voice their opposition to business as usual at FERC and oppose any Trump nominees to the agency." "FERC is abusing its powers and the law in how it reviews, approves, and greases the wheels for pipelines cutting through communities across America," said Maya van Rossum, of the Delaware Riverkeeper and leader of the Delaware Riverkeeper Network. "Given the level of harm pipelines inflict on communities, Congress should be working hard to prevent new nominations to the FERC commission in order to prevent restoration of the quorum they need to approve new pipelines, rather than working with President Trump to advance them."
Warm US winter leaves natural gas market with excess supplies - Winter has lost its icy bite for the second straight year in the US, wrongfooting forecasters and slackening demand for natural gas, resulting in excess supplies. Unusual warmth across most of the country has led to the first-ever recorded rise in US natural gas inventories during the month of February. Normally utilities draw down stocks to fulfill heating demands. Demand for gas used in heating is averaging less than 38bn cubic feet per day this winter, off by more than 1.5bn cu ft/d from the five-year average, according to Platts Analytics. “Weather has been a big headwind for the gas distribution utilities in the last few months,” said Travis Miller, director of utilities research at Morningstar in Chicago. “A lot of gas utilities rely on heavy usage during the winter months to drive earnings for the entire year. That’s going to be a challenge this year.” When Public Service Enterprise Group released quarterly results on February 24, temperatures outside the utility’s New Jersey headquarters crested at a record 74 degrees Fahrenheit. The balmy conditions follow the warm winter of 2015-16, which had been intensified by El Niño, the Pacific weather pattern. When government forecasters looked ahead last autumn they eyed a winter about 12 per cent colder than last year, if still above normal. Instead, this heating season has been running 3 per cent warmer than last year, weighted for population, according to the US National Weather Service. Over the past 30 days, more than 700 monthly high temperature records were set across the country, while only one low record was made.
Fast Growth Coming for Northeast Shale Gas Pipelines - A surge in pipeline capacity for natural gas in the U.S. Northeast this year and next is expected to boost profits for producers and help hold down prices for Midwest and East Coast buyers. The $13.8 billion infrastructure build-out involves seven large pipeline proposals that will take gas in all directions. Producers in the Marcellus Shale region—primarily in Pennsylvania, West Virginia and eastern Ohio—are eager for the pipelines because they have been hurt by depressed prices in pockets of inadequate pipeline infrastructure, compounded by a nationwide two-year slump in gas prices. Gas producers in the region are likely to see substantial increases in profitability, said Andrew Weissman, the head of EBW Analytics Group and an attorney who specializes in energy practice at Pillsbury Winthrop Shaw Pittman LLP in Washington. Leading producers in the Marcellus include Cabot Oil & Gas Corp., Chesapeake Energy Corp., EQT Corp., Range Resources Corp., Southwestern Energy Co. and Chief Oil & Gas LLC. The Federal Energy Regulatory Commission, with regulatory authority over interstate gas transmission, has approved five of the seven large proposed pipelines for moving gas out of the Appalachian region, which includes the deeper Utica Shale underlying the Marcellus Shale. FERC decisions are not necessarily the last word, however. “There are all sorts of relatively minor approvals that have to be granted for the pipelines to be completed,” Weissman told Bloomberg BNA, referring to such things as approvals for clearing trees along the routes. Some landowners have tried to block pipelines to preserve their trees. Environmental activists also have strongly opposed the pipelines. Ample supplies of gas holding down prices can discourage competing wind and solar projects that don’t produce the carbon emissions causing climate change. The new pipelines also could spell more trouble for operators of electric power plants that rely on coal and nuclear energy in competitive wholesale power markets. “We are opposed to all fracking and fracked-gas infrastructure,” said Lee Stewart, an organizer for the group Beyond Extreme Energy. In fracking, or hydraulic fracturing, layers of rock are fractured to allow gas or oil to flow to a well. Opposition also can come from states, as the backers of the Constitution Pipeline project discovered.
Hindus glad as major gas pipeline re-routed, bypassing Lord Krishna complex in West Virginia - Hindus worldwide are delighted over reported route altering of major gas pipeline, thus skipping the sacred sites of New Vrindaban Holy Dham focused on Lord Krishna near Moundsville in rural West Virginia. This gas pipeline is being built by Rover Pipeline, a subsidiary of Energy Transfer Partners whose another pipeline project by the subsidiary Dakota Access was a site of highly publicized months long protests in North Dakota. The Rover and New Vrindaban officials reportedly reached a settlement over pipeline route around this multi-dimensional Hindu temple complex. Distinguished Hindu statesman Rajan Zed, in a statement in Nevada today, thanked Energy Transfer Partners for giving due regard to the feelings of the area and worldwide Hindu community and sacredness of Hindu sites. He also commended the community for making efforts and seeking a solution for saving the sacred sites. Rajan Zed, who is President of Universal Society of Hinduism, urged all businesses to work towards respecting and accommodating the religious sentiments of the believers. Rover Pipeline, involving an investment of about $4.2 billion, is a new interstate 713-mile natural gas pipeline that is designed to transport 3.25 billion cubic feet per day of domestically produced natural gas to markets in USA and Canada. Energy Transfer Partners is a Fortune 500 company, founded in 1995 and headquartered in Dallas, which reportedly owns-operates one of the largest most diversified portfolios of energy assets in USA. Kelcy L. Warren is CEO.
The True Cost of the Atlantic Sunrise Pipeline - A report prepared by Key-Log Economics for the Sierra Club and Appalachian Mountain Advocates was released Monday, detailing what it calls the true costs of the Atlantic Sunrise pipeline . The proposed fracked gas pipeline was approved by the Federal Energy Regulatory Commission (FERC) on its former chair's final day—just before the commission lost its quorum. The Atlantic Sunrise project would clear cut its way through 10 Pennsylvania counties, impacting 2,000 acres of forested land and crossings hundreds of wetlands and water bodies. The proposed route includes nearly 200 miles of new pipeline which would supply gas exports out of Maryland and gas plants in North Carolina and Florida. "FERC's failure to listen to the people and account for the true costs of this pipeline—not to mention recognize the lack of need for it—now puts tens of thousands of men, women and children at risk of not only polluted air, but spills and explosions." The report states that FERC overstated the pipeline's economic benefits while discounting or ignoring its costs, including the effects of the pipeline on property values; loss of environmental benefits like flood control, clean water and wildlife habitat; economic damages associated with increases in greenhouse gas emissions; and public health costs due to the release of toxins and smog-forming pollutants. "The report makes even more clear that, while the damage that this pipeline would cause to private property and the environment is very real, any benefits to the public are illusory," said Ben Luckett, an attorney with Appalachian Mountain Advocates. The report estimates the pipeline's total costs (the initial cost plus the discounted value of all future annual costs) at between $21.3 and $91.6 billion. The one-time costs (ecosystem services lost during construction) are estimated to be $6.2 to $22.7 million, while annual costs for this diminished ecosystem service productivity would total approximately $2.9 to $11.4 million per year. Using a 2.5 percent discount rate, the annual cost associated with the social cost of carbon from the project's greenhouse gas emissions would be $2.3 to $3.5 billion per year. The report cautions that the estimates are conservative and do not include the value of landscape preservation or damages to natural resources, property and human health in the event of a leak or explosion. The report does not quantify estimates in property value losses, but it does analyze what it calls FERC's failure to include realistic estimates in its analysis, citing the "well-established negative impact" of pipelines on property values.
Trump’s new Gulf of Mexico oil and gas drilling proposal looks a lot like Obama’s - The Trump administration on Monday announced an offshore oil and gas drilling proposal in the Gulf of Mexico that appears to mirror a plan offered by his predecessor a few months ago.In one of his first acts after last week’s Senate confirmation, Interior Secretary Ryan Zinke proposed leasing 73 million acres off Florida, Alabama, Texas, Louisiana and Mississippi over five years starting in August. The offer includes more than 13,700 lease blocks extending three miles to 230 miles offshore, according to an Interior Department statement.“Opening more federal lands and waters to oil and gas drilling is a pillar of President Trump’s plan to make the United States energy independent,” Zinke said in the statement. “The Gulf is a vital part of that strategy to spur economic opportunities for industry, states and local communities, to create jobs and homegrown energy and to reduce our dependence on foreign oil.” But the plan is similar to a five-year proposal by the Obama administration to lease 66 million acres in the same location, the gulf’s “Western, Central and Eastern planning areas” where water is as shallow as nine feet and as deep as 11,000 feet. As he prepared to leave office, President Obama banned drilling in the Arctic and Atlantic oceans for the next five years, but allowed it in the gulf with lease plans offered primarily off gulf states other than Florida. Obama’s interior secretary, Sally Jewell, said the proposal’s leases were focused “in the best places — those with the highest resource potential, lowest conflict and established infrastructure — and removes regions that are simply not right to lease.” The gulf, an area that has seen intense drilling, would see more compared with the Arctic and Atlantic, where little drilling occurs.
Exxon to invest $20 billion on U.S. Gulf Coast refining projects | Reuters: Exxon Mobil, the world's largest publicly traded oil producer, said on Monday it would invest $20 billion through 2022 to expand its chemical and oil refining plants on the U.S. Gulf Coast. The investments at 11 sites should create 35,000 temporary construction jobs and 12,000 permanent jobs, Chief Executive Darren Woods said in a speech at CERAWeek, the world's largest gathering of energy executives. Some of the expansions began in 2013, but the scope of the project is now growing and the timeline extended, Exxon said. Woods ran Exxon's refining division before becoming CEO two months ago, and the new spending benefits a sector with which he has significant experience and comfort. Investments in the high-margin projects should help ease concerns from Wall Street that Exxon's growth potential - especially in oil and gas exploration and production - is sliding. "Exxon Mobil is building a manufacturing powerhouse along the U.S. Gulf Coast," Woods said. "These businesses are leveraging the shale revolution to manufacture cleaner fuels and more energy-efficient plastics." The investments across Texas and Louisiana will take advantage of cheap shale gas to make plastics and other chemicals for export. The strategy builds on prior steps Exxon and peers, including Dow Chemical Co (DOW.N), have taken in the wake of the American shale expansion, which sharply cut production costs.
Saudi Aramco to Pay Shell $2.2 Billion in Refinery Breakup - Saudi Arabian Oil Co. will pay Royal Dutch Shell Plc $2.2 billion including debt to finalize the breakup of a 19-year refining partnership known as Motiva Enterprises LLC.Saudi Aramco’s Saudi Refining unit will take full ownership of the Motiva Enterprises name and legal entity, including the largest refinery in the U.S. at Port Arthur in Texas, and 24 distribution terminals, according to a joint statement. Shell will take sole ownership of the Norco and Convent refineries in Louisiana and 11 distribution terminals. Aramco will make a $2.2 billion balancing payment, split between debt and cash and subject to adjustments including working capital, Shell said in a separate statement. Aramco will assume almost all of Motiva’s $3.2 billion of net debt, including $1.5 billion of Shell’s share. A cash payment will cover the balance, Shell said. The arrangement will also take the Anglo-Dutch company closer to its target of selling $30 billion of assets in the three years to 2018. “Motiva is a strong competitor among U.S. refiners, and we value this important link with the dynamic U.S. energy sector,” said Abdulaziz Al-Judaimi, senior vice president of Aramco’s downstream business. “Our intent is to continue providing Motiva with strong financial support as it transitions into a stand-alone downstream affiliate.” The transaction is subject to regulatory approval and expected to close in the second quarter, the companies said. Shell and Aramco agreed last year to end the Motiva venture, which oversaw the three oil refineries as well as fuel terminals and fuel-branding rights in multiple U.S. states.
OPEC Said to Break Bread With Shale in Rare Show of Detente - For the last two years, they’ve been locked in a battle for supremacy of the oil market. But for a couple of hours in Houston over dinner on Sunday, the head of OPEC and leaders of some of America’s top shale producers shared a table for a rare off-the-record chat about the future of oil. Mohammed Barkindo, secretary-general of the Organization of Petroleum Exporting Countries, dined with 20 or so U.S. shale executives including Scott Sheffield of Pioneer Natural Resources Co., John Hess of Hess Corp., Robert Lawler of Chesapeake Energy Corp. and Tim Leach of Concho Resources Inc., according to people who attended the event and asked not to be named because it was private. Mark Papa, the oilman who helped create the U.S. shale industry more than a decade ago, also attended the dinner at a restaurant in downtown Houston on the eve of the annual CERAWeek conference. Halliburton Co. President Jeff Miller was among representatives of the oil-service sector. The sides agreed in principle that the market should be better balanced and lower inventories would be beneficial to everyone, according to the people. But while the shale producers signaled they weren’t ready to give up on the growth they see ahead, OPEC indicated it wants higher prices, even if it means enriching the shale companies, they said. “It was a very good exchange of information and views about oil," Hess Chief Executive Officer John Hess said in an interview Tuesday. “I really commend the OPEC secretary general for the outreach. It was a good talk." Spokespeople for Pioneer, Chesapeake and Concho Resources weren’t immediately available to comment on the dinner when reached outside of regular business hours. Mark Papa couldn’t be reached and Halliburton declined to comment.
OPEC invites U.S. shale firms, hedge funds into talks on glut: (Reuters) - The Organization of the Petroleum Exporting Countries is moving to bring U.S. shale producers and hedge funds into widening talks about how best to tame a global oil glut. The group held unprecedented talks with fund executives on Tuesday and earlier held meetings with shale producers, including Pioneer Natural Resources Co and ConocoPhillips. The introductory discussions were the first bilateral meetings with shale producers and investment funds, OPEC Secretary General Mohammed Barkindo said on Tuesday at the CERAWeek energy conference in Houston. The two have become important players in adding production to a world awash in crude oil. Cheap financing for newer producers has forced majors to turn their focus from big, long-term projects to those that can generate quick cash for their investors. Last November, OPEC took initial steps to widen its market reach as it sought to end a two-year price war, striking a historic agreement with 13 non-member countries, including such major oil producing nations as Russia, Kazakhstan and Mexico. Saudi Arabia Oil Minister Khalid al-Falih separately told a group of oil industry executives at the conference that the November pact set a new "cooperative framework" for OPEC to address short-term market turmoil. "All of us realize that such an expanded network of producers with a larger share of global production is the only way to achieve a constructive, stable market for all," he said.
Saudi says Opec deal invigorating US shale industry - Saudi Arabia’s energy minister told executives in Houston that its participation in an international agreement to cut crude output was reinvigorating rivals in the US shale patch, a development that could undermine efforts to stabilise a weak oil market. The comments of Khalid al-Falih at the CERAWeek by IHS Markit conference stood in stark contrast to those of his predecessor at the same venue a year ago. Then, minister Ali al-Naimi bluntly warned shale producers that they must trim their costs or risk bankruptcy. In November the Opec cartel, led by Saudi Arabia, joined 11 other producers to reduce output in the first six months of 2017. Oil prices have rebounded from less than $30 a barrel in early 2016 to more than $56. Mr Falih said that the cuts were taking effect more slowly than he expected and added that the agreement was helping sow “green shoots” in the industry, mainly in the US. As oil prices have increased, US producers have deployed more drilling rigs, threatening a rebound in supplies unbound by the output pact. He acknowledged that Saudi Arabia had a hand in “watering of the green shoots”, and welcomed the return of investment in US shale. He added: “I am optimistic about the global market outlook in the weeks and months ahead, though I caution that my optimism should not tip investors into irrational exuberance or wishful thinking that Opec or the kingdom will underwrite the investments of others at our own expense.” Saudi Arabia has reduced its own output to less than 10m barrels a day. Mr Falih said that any decision to extend the agreement would be predicated on how quickly oil inventories were falling back to average levels as well as the extent of other countries’ compliance with the deal.
OPEC and the shale industry seek a truce: Kemp (Reuters) - The Organization of the Petroleum Exporting Countries (OPEC) and shale producers have fought each other to a draw over the last two years, with neither able to achieve a decisive victory. Now both want a truce. There have been no winners from the oil producers’ civil war of 2014-2016, except for consumers, who have enjoyed two years of cheaper fuel prices. OPEC members are running out of money and need higher prices to reduce their budget deficits and halt the slide in their foreign reserves. And for all their bravado, shale producers and the entire U.S. oil supply chain have been badly wounded and rescued by a rise in prices largely engineered by OPEC. The bad-tempered exchanges between OPEC and shale chiefs that characterised 2014-2015 have given way in 2016-2017 to a recognition that their prosperity is tied together. OPEC and the shale industry are interdependent. Both lose if they raise output too much, flood the market with more oil than can be consumed, and cause prices to crash. Shale firms need OPEC to succeed in reducing global oil stockpiles and raising prices. And OPEC needs shale producers to be cautious in growing output to avoid undermining its policy of supply restraint. The warmer relationship between OPEC and shale firms on display at the CERAWEEK conference hosted by IHS Markit in Houston this week has been building for some time. OPEC's secretary-general said at the conference that the organisation had "broken the ice" with shale oil producers and hedge funds who have become major players in the market. Harold Hamm, head of one of the largest U.S. shale producers, said that industry would need to add output in a "measured way, or else we kill the market", suggesting no new dash for growth.
Shale Billionaire Hamm Says Industry Binge Can 'Kill' Oil Market - Harold Hamm, the billionaire shale oilman, said the U.S. industry could "kill" the oil market if it embarks into another spending binge, a rare warning in a business focused on fast growth to compete with OPEC. The statement, at an energy conference in Houston on Wednesday, comes as top shale companies announce large increases in spending for this year, and the U.S. government says domestic oil output next year will surpass the record high set in 1970. OPEC ministers have said they are keeping a close watch on shale production to decide in late May whether to extend their oil-supply cuts into the second half of the year. Oil prices plunged 5 percent on Wednesday to their lowest level this year, falling just above $50 a barrel, on investor concerns about unbridled growth in America’s shale basins swelling U.S. inventories. U.S. production "could go pretty high," Hamm said at the CERAWeek by IHS Markit conference in Houston, one of the largest gatherings of oil executives in the world. "But it’s going to have to be done in a measured way, or else we kill the market." After oil prices doubled over the past year, U.S. shale drillers have announced big increases in spending for 2017. Anadarko Petroleum Corp. this week said it planned to invest 70 percent more this year than in 2016. Last month, EOG Resources Inc., another big shale producer, said it will spend 44 percent more this year than last. Exxon Mobil Corp. plans to spend a third of its drilling budget this year on shale. Shale producers are staging the biggest surge in drilling since 2012, with the number of oil rigs rising to more than 600 this month, nearly double the level of June. They are rushing to spend again after the Organization of Petroleum Exporting Countries and Russia agreed last year to cut its supplies, boosting oil above $50 a barrel after a two-year price rout.
U.S. shale plots production growth despite OPEC's warning | Reuters: U.S. shale oil producers are plotting ambitious production growth outside the red-hot Permian Basin in Texas, widening a resurgence that could confound OPEC's strategy to tighten global supplies. As shale firms rebound from a two-year price war with OPEC, many are planning to expand production in North Dakota, Oklahoma and other shale regions. The Permian - America's largest oilfield - has already seen output jump in the past six months. Hess Corp, Chesapeake Energy Corp, Continental Resources Inc and other firms detailed their growth plans at an energy conference in Houston this week. The projects they outlined would result in a steady supply of American crude exports through the next decade. Rising U.S. energy clout has frustrated efforts by the Organization of the Petroleum Exporting Countries to control global oil prices through a production curb announced last fall - its first in eight years. The rise in U.S. output was enough to boost domestic crude stockpiles last week by 8.2 million barrels, more than quadruple estimates from analysts polled by Reuters. The unexpected supply surge pushed U.S. oil prices down more than 5 percent on Wednesday to close at $50.49. The price drop underscored the growing impact of U.S. shale production on global supplies and prices relative to OPEC member nations, which once exercised dominant influence on global markets. Representatives from both sectors acknowledged that power shift at the energy conference in Houston. "We are on something of an equal basis today with OPEC," said Harold Hamm, founder and chief executive of Continental Resources, which has invested heavily in Oklahoma shale projects in the past year.
U.S. oil production forecasts revised higher: Kemp - (Reuters) - U.S. oil production forecasts for 2017 and 2018 have been boosted significantly as a result of rising prices as well as improved modelling techniques for predicting output down to the well level. Crude production is expected to reach 9.53 million barrels per day (bpd) in December 2017, according to the latest forecasts from the U.S. Energy Information Administration (EIA). Forecast output for December 2017 has been revised up from 8.29 million bpd when the agency prepared its predictions in March last year (http://tmsnrt.rs/2moZoqc). The forecasts are contained in the "Short-Term Energy Outlook" EIA publishes every month. Forecast output has been revised higher every month since September 2016. Revisions are concentrated in output from the Lower 48 states, excluding federal waters in the Gulf of Mexico, so they are mostly about shale output, rather than offshore fields and Alaska (http://tmsnrt.rs/2moXWnN). EIA has revised expected output at the end of 2017 from the Lower 48 excluding the Gulf of Mexico up by 1.4 million bpd since March 2016 (http://tmsnrt.rs/2niqnRS). Upward revisions stem from a combination of higher oil prices, an increased number of rigs drilling, and improvements in methodology. Operators have added many more rigs and produced more oil than the agency was forecasting just six months ago. Oil prices ended up being $5 per barrel higher in the fourth quarter of 2016 than the agency forecast back in August. Prices in the first quarter of 2017 have so far averaged about $7 higher. Higher prices have contributed to more drilling, particularly in the Permian Basin of western Texas and eastern New Mexico, raising the current rig count and actual production the forecast uses as a baseline. Higher rig counts have also revealed new information about the price levels at which operators in certain areas can grow production, which have filtered through to the models that the agency uses. In addition to the price impact, the agency has made a number of improvements to its methodology. EIA has shifted from basin-level to well-level forecasts, and improved its understanding of the time lags between price changes and when operators add drilling rigs. The agency has also tweaked the model it uses to allow for more interplay between oil and gas prices, allowing the model to select whether drillers will focus on oil or gas depending on price differentials.
U.S. Oil Industry Becomes Refiner to World as Exports Boom --When PBF Energy Inc. scooped up a refinery from Exxon Mobil Corp. on the Mississippi River in 2015, it wasted no time sprucing up the plant with an eye toward quickly resuming lucrative fuel exports.Within three months, PBF was ready to load its first tanker for shipment abroad. By late last year, the New Jersey-based company was exporting 22,000 barrels a day of fuel, or 16 percent of that refinery’s output. Now, it wants to boost that to almost 25 percent.PBF isn’t alone in this push. From major producers such as Chevron Corp. to specialized refiners including Valero Energy Corp., the U.S. refining industry has shifted its game over the last five years, taking advantage of gaps left by struggling refiners in Latin America, Africa and Asia. Along the way, it’s transforming what had long been a largely domestic business into a new global venture."U.S. refiners are now the refiners for the world," said Ivan Sandrea, head of Sierra Oil & Gas, which is planning to build infrastructure to import U.S. fuels into Mexico.U.S. companies last year exported a record 3 million barrels a day of refined products, more than double the 1.3 million barrels a day shipped a decade ago, according to data from the Energy Information Administration. Gasoline led the surge, with exports hitting an all-time high of almost 1 million barrels a day in December, up ten-fold from a decade ago. On top of the export boom, U.S. refiners are enjoying fresh supplies of relatively cheap and high quality crude from the Permian, the Bakken and other shale basins. The combination is spurring oil companies to invest in new capacity, particularly along the Gulf of Mexico coast. Oil refiners are set to discuss their investment plans this week at the annual CERAWeek, an industry conference where every year thousands of executives, bankers and officials gather in Houston.
How new rules on bunker fuel sulfur content will impact refineries. Much tougher rules governing emissions from ships plying international waters soon will force wrenching change on the energy industry. Demand for high-sulfur fuel oil is expected to plummet; ditto for HSFO prices. Demand for low-sulfur distillates from the shipping industry will rise sharply, putting upward pressure on prices for marine gas oil, marine diesel oil and ultra-low-sulfur diesel. These demand and pricing shifts, in turn, will have a number of significant effects on refiners. Today we continue our series on the far-reaching effects of the International Maritime Organization’s (IMO) mandate to slash emissions from tens of thousands of ships starting in January 2020. This blog series is based on elements of a just-published report by our friends at Turner Mason & Co. that examines a number of crude oil- and refined products-related topics, including the impact of the IMO’s new sulfur rule (planned effective date: January 1, 2020) on high-sulfur fuel oil (HSFO) and low-sulfur marine distillate demand and prices, on future demand for various grades of crude (heavy vs. light, sour vs. sweet etc.), and on the refining sector more generally.
US crude exports hit record levels in January, February - US crude exports hit record highs in January and February, as domestic crude price discounts to Brent and Dubai widened significantly, an S&P Global Platts analysis of government data showed Tuesday. US Census Bureau data showed US crude exports rising by 304,000 b/d to 746,000 b/d in January, which was followed by a report by the US Energy Information Administration showing US crude exports averaging 900,000 b/d in the four weeks ending February 24. Congress' December 2015 decision to lift restrictions inaugurated a new era in US oil trade, with exports averaging an annual record of 521,000 b/d in 2016. Additionally, rising production from the Permian Basin in West Texas, in combination with a significant buildout in infrastructure to access export markets, has deepened price discounts for US light sweet crudes, allowing US crude exports to take off. "It's pure economics," said Tony Starkey, manager of energy analysis at Platts Analytics. "WTI/Brent finally widened enough to make some additional exports profitable since the export ban was lifted. There was also an uptick in exports back in August/September 2016 which aligns pretty well with when the WTI/Brent spread last flirted with the $3/b level." The WTI/Brent spread averaged $2.24/b in January, out from $2.03/b in December and 81 cents/b in November, making US crudes more competitive in Brent-linked markets across the Atlantic Basin. WTI flipped to a discount of 7 cents/b to Dubai in December, and that spread blew out to 95 cents/b in January as OPEC output cuts tightened the Middle Eastern sour crude market. Likewise, a widening discount of Mars crude to Dubai in recent months has boosted US crude exports to Asia.
- January 28, 2017: Exelon has applied for an LNG export facility permit for Brownsville, TX.
- Annova LNG: has proposed a six-train, 6-MTPA liquefaction/LNG export facility planned by Exelon Generation for Brownsville
- Third Point LLC (a NYC-based investment fund) and Samsung Engineering are developing Texas LNG, a proposed 4-MTPA liquefaction/LNG export terminal in Brownsville
- Rio Grande LNG, being developed by NextDecade LLC: up to six 4.5-MTPA liquefaciton trains and two LNG loading berths along the Brownsville Shipping Channel
Today, over at Rigzone, this appears to be the Third Point LLC (Texas LNG - Samsung / NYC-based investment fund consortium:Texas LNG Brownsville LLC announced Thursday that Samsung Engineering Co., Ltd. and KBR Inc. will provide pre-final investment decision (pre-FID) detailed engineering and post-FID engineering, procurement and construction (EPC) services for its proposed 4 million tonnes per annum (MTA) LNG export project in South Texas. Samsung Engineering, a minority equity owner and technical partner in the mid-scale liquefaction project, has already completed the conceptual study, pre-front end engineering design (pre-FEED) and FEED, Texas LNG stated in a press release. The project's design calls for constructing modular designed and prefabricated liquefaction trains using proven technology and standardized components in a controlled shipyard environment, the project developer continued. Such an approach reportedly would lower overall project costs, reduce complex onshore civil construction works and minimize local onsite environmental impacts as well as commissioning costs during permanent installation on the deepwater Brownsville Ship Channel near the Gulf of Mexico.
Why more liquefaction capacity may be needed in less than three years. -- Last year was the best for global LNG demand growth since 2011, and a combination of ample LNG supply, new buyers and relatively low prices suggest that demand will continue rising at a healthy clip in 2017. That’s good news not only for LNG suppliers, but for natural gas producers and for developers planning the “second wave” of U.S. liquefaction/LNG export projects. Before those projects can advance, the world’s current—and still-growing—glut of LNG needs to be whittled down, and nothing whittles a supply glut like booming demand. Today we discuss ongoing changes in the LNG market and how they may well work to the advantage of U.S. gas producers and developers. It’s easy to get caught up in the fact that way too much liquefaction/LNG export capacity is being added in the 2016-20 period, most of it in Australia and the U.S. Sure, it’s a bummer that liquefaction-plant developers, responding to fast-rising demand and high LNG prices early in this decade, started building an army of new facilities to supercool natural gas into LNG, only to see LNG demand growth stall and prices plummet in 2014-15, just as the first of their new plants were nearing completion and about to come online. As we said in Coming Up, though, markets do respond when supply and demand get out of whack. Spot prices for LNG for a time fell below $5/MMbtu, and the price of LNG purchased under long-term contracts (many of which index the LNG price to the price of crude oil) declined as well (though not nearly as far). In response––and with the knowledge that a slew of new Australian and U.S. liquefaction capacity would be coming online over the next few years––global demand for LNG started rebounding.
A take-it-to-Corpus option for the Permian and the Eagle Ford crude oil producers. --The expectation that crude oil production in the Permian Basin will continue growing has set off a competition among midstream companies, a number of which are known to be developing plans for additional pipeline takeaway capacity out of what is clearly America’s top-of-the-charts tight-oil play. One of the biggest topics of conversation the past few days has been the plan by EPIC Pipeline Co. to build a new crude pipeline from the Permian’s Delaware and Midland basins to planned storage/distribution and marine terminals in Corpus Christi. Today we detail EPIC’s plan and explain the rationale for the pipeline’s route and destination. The Permian Basin in West Texas and southeastern New Mexico has proven to be the Energizer Bunny of U.S. tight-oil and shale plays, not only surviving the oil patch’s nuclear winter of mid-2014 to mid-2016 but thriving during it. Sure, the rig count in the Permian fell by more than two-thirds post-crash—from 558 in July 2014 to 162 in July 2016, according to Baker Hughes. But unlike other major plays (the Bakken and the Eagle Ford, for instance), crude oil production in the Permian kept rising—from just under 1.6 million barrels per day (MMb/d) in June 2014 (when crude was selling for $108/bbl, on average) to just over 1.9 MMb/d in January 2016 (when it was selling for $29/bbl). And like that pink, drum-beating bunny, the Permian remains full of energy: Production there is up another 300 Mb/d in the past 14 months (now averaging about 2.2 MMb/d), and as of March 3 (2017) the Permian’s rig count stood at 308. As for the Bakken and the Eagle Ford, their production volumes are down 11% and 27%, respectively, since June 2014, even with crude prices now north of $50/bbl.
Emerging natural gas supply constraints and premium pricing in south Texas, part 2. -- U.S. natural gas exports drove a significant portion of overall gas demand growth in 2016 and are expected to continue being the primary demand driver over the next several years. Much of this export demand will be emerging along the Texas-Mexico border and at planned LNG export terminals along the southern Texas Gulf Coast. But production in the South Texas region is not expected to grow nearly as quickly or robustly as demand, setting the stage for supply constraints and premium pricing in the South Texas market and making the area a target destination for producers and pipeline companies. For example, on Wednesday, Enterprise announced the possibility of a new pipeline from Orla, TX, in the Permian Basin to Agua Dulce in South Texas. So how will all of this play out? Today, we continue our series analyzing the gas supply and demand balance in South Texas, this time with a look at the demand side and the resulting market balance.
Big Oil frets about Trump's border tax, Mexico policies -- — On the opening day of the biggest annual conference of energy executives, the chief executive of the biggest U.S. oil producer held forth on tax and trade policy. Exxon Mobil Corp. CEO Darren Woods didn't mention President Trump, but he came down clearly on the side of free international trade and against some of the administration's proposals on protective taxes. "Policies in the forms of subsidies, mandates and trade barriers only hinder progress," Woods told the 3,000 attendees at the annual CERAWeek conference by IHS Markit Ltd. "They are more expensive and lead to poor investment decisions focused on the limitations imposed, not true innovation," he said. The second and third days of the conference featured the heads of the No. 2 and No. 3 oil producers — Chevron Corp. and ConocoPhillips Co. — also talking about tax policy. Chevron CEO John Watson, who supports most of Trump's plan to overhaul the tax system, said a border tax could harm U.S. consumers by raising prices. Advertisement "I want to see the U.S. be more competitive, not burdening imports," he said yesterday. While the oil industry has generally supported Trump, the Big Oil executives gathered here — along with the utility and refining industries — are quietly staking out differences with the administration on a variety of issues, most notably taxes and trade policy.
Scientists Link Fracking to Explosion That Severely Injured Texas Family – Scientists have determined that methane from a fracked well contaminated a Texas family's water supply and triggered an explosion that nearly killed four members of the family. The family's ranch in Palo Pinto County is located only a few thousand feet away from a natural gas well. In August 2014, former oil field worker Cody Murray, his father, wife and young daughter were severely burned and hospitalized from a "fireball" that erupted from the family's pump house. A year later, the family filed a lawsuit against oil and gas operators EOG Resources and Fairway Resources, claiming the defendants' drilling and extraction activities caused the high-level methane contamination of the Murrays' water well."At the flip of the switch, Cody heard a 'whooshing' sound, which he instantly recognized from his work in the oil and gas industry, and instinctively picked his father up and physically threw him back and away from the entryway to the pump house," the complaint states. "In that instant, a giant fireball erupted from the pump house, burning Cody and [his father], who were at the entrance to the pump house, as well as Ashley and A.M., who were approximately twenty feet away."While the state's oil and gas regulator—the Texas Railroad Commission—has yet to definitely prove what caused the blast, new scientific studies commissioned by the Murrays' attorneys has directly linked the explosion to fracking operations.As the Texas Tribune detailed, the studies found that methane and drilling mud chemicals had escaped from a poorly sealed Fairway gas well and traveled through underground fractures and eventually into the Murrays' water supply.The hired experts include Thomas Darrah, a geochemist at Ohio State University; Franklin Schwartz, an Ohio State University hydrologist; Zacariah Hildenbrand, chief scientific officer at Inform Environmental; and Anthony Ingraffea, a civil engineering professor at a Cornell University with expertise in fracking."The timing is undeniable, the location is undeniable, the chemistry of the gas is undeniable," Chris Hamilton, the Murray's a ttorney, told news station WFAA. "This is not naturally occurring gas. This is gas that came from 4 to 6-thousand feet below the ground."
Back from the dead: US shale is booming again - Saudi Arabia’s attempt to kill off the US shale oil industry looks to have badly backfired. More than two years after Riyadh and its OPEC allies ramped up production to push down the price of oil and drive shale producers out of business, it’s actually the cartel that is licking its wounds – and not the US upstarts. The fight has destroyed OPEC members’ finances, forcing many to dip into reserves and sell bonds to finance spiralling fiscal deficits – Saudi’s alone is US$100bn a year. Other cartel members such as Nigeria have turned to the World Bank for emergency loans, while Venezuela has seen its economy paralysed by falling oil revenues. By contrast, the US shale industry is enjoying its second wave. After a painful couple of years when dozens of shale producers filed for bankruptcy and four out of every five rigs were mothballed, cost savings and big improvements in technology have reinvigorated the sector. Activity has rebounded, with 602 rigs now active, double the level last May. Rather than kill the sector off, the near-death experience has pushed US shale producers into becoming more efficient than ever. Five years ago, producers in the Permian basin were pumping 100 barrels per rig per day. Now it is over 600. Profits have leapt, cashflow is rising, and market share is growing – all at the expense of OPEC. “It’s worked out terribly for the Saudis and OPEC,” said Brian Gibbons, global head of oil and gas credit research at CreditSights “Their attempt at market share gains did of course result in a record number of shale producers defaulting, but what transpired at the same time was the remaining companies becoming that much more efficient.” “The US has got much stronger and more resilient … it’s the OPEC members that are haemorrhaging cash,”
$80,000 Jobs Find Few Takers in America's Red-Hot Shale Country - Five years ago, the thought of $55-a-barrel oil would have given Piotr Galitzine heartburn. Now it’s keeping one of his steel-pipe shops in Houston open 24/7 and fueling a flurry of orders. It’s stoking business for National Oilwell Varco Inc. too, with the oilfield-equipment giant for the first time in better than a decade selling more land-based than offshore gear. And it’s got Perry Taylor on the hunt for truckers to haul fracking sand. Even at $80,000 a year, jobs are hard to fill. “It’s tough,” said the chief executive officer of Agility Energy Inc. “We’ve got commitments that are very difficult to keep right now because we can’t get the drivers.” Crude is nowhere near its $100-plus highs of recent years, but drillers pounced after it steadily crept back up from the $26 bottom it sank to early last year. And as they tap more and more new wells, the rebound is spreading quickly, and powerfully, to the oilfield-services outfits that were so hard hit during the collapse. “Everyone is so hungry,” said Joseph Triepke, founder of the industry research company Infill Thinking in Dallas. “It’s like we’re hanging a steak in front of a bunch of starving people.” That services companies are hopping again with crude worth half what it was three years ago is thanks in large part to technological advances that help explorers to find more pockets of petroleum riches, and to drill faster and frack smarter. That last bit is key in the shale formations that hold the most promising on-land pockets of oil and gas; tapping them requires fracturing the surrounding rock with injections of water, sand and chemicals.The burst of activity has helped drive U.S. oil output up at a faster rate than during the last surge, with an average 125,000 barrels a day added since September. Now exploration and production spending in the U.S. and Canada is on track to climb four times more than the worldwide average this year.
Rising oilfield costs a 'test' for upstream companies: CEOs - - Oilfield costs that are set to rise in the energy industry are a test for upstream company managers as they seek to remain profitable at crude prices that persist at relatively low levels, chief executives of two top international oil companies said Monday. The start of recovery from a recent two-year industry downturn offers a "unique opportunity" for companies to transform and reset the cost base, Statoil CEO Eldar Saetre said during a panel discussion with the president of Petrobras on the first day of IHS CERAWeek. Statoil has brought down its breakeven price of what it calls its next-generation portfolio of emerging and current projects, which hold more than 3 billion barrels of oil equivalent, from around $70/b-plus to well below $30/b, Saetre told the annual gathering. "It turns out that we are capable of [shaving off] costs when we have to," he said. In addition, Pedro Parente, president of Brazil's state-controlled Petrobras, noted his company has undertaken a plan to reduce what was the oil industry's biggest debt load of $123 billion by selling about $15 billion of assets in 2015-16. The company also expects to accelerate its return to a better balance sheet by cutting net debt to 2.5 times EBITDA by 2018. In 2015, net debt was 5.3 times EBITDA.On top of the downturn where lower oil prices cut sharply into oil company profits, Petrobras was grappling with an internal corruption scandal involving kickbacks on building and other contracts. But Parente said the work that new management has done to revitalize the company and get it into better fiscal shape "has been recognized and acknowledged" by the market.
Could Artificial Earthquakes Trigger Disaster? Oklahoma's Risk "Now Equal To That Of San Francisco" - While Oklahoma has had a handful of notable earthquakes over the past century, it was essentially never an earthquake state. And rightfully so, given that the USGS and other officials, up until quite recently, ranked Oklahoma’s earthquake hazard level at the second lowest level, with a patch of slightly elevated, but still moderately low areas: According to the statistics that have been released, Oklahoma, in fact, had very few earthquakes (over a magnitude of 3.0) during the past half century – until the year 2009. That date marks the expansion of fracking in the oil industry, as the Obama Administration signaled an attack on coal and fossil fuels, and the petroleum industry sought to flood market supply to manipulate the political power of oil in certain key regimes around the world: Now, the low key heartland state of Oklahoma is suddenly rivaling San Francisco as the most earthquake-prone place in the United States.According to the Daily Mail:Oklahoma is the most at risk place in America for man made earthquakes caused by oil and gas drilling, a new USGS quake risk map has revealed. In its annual national earthquake outlook , the U.S. Geological Survey reported Wednesday that a large portion of Oklahoma and parts of central California have the highest risk for a damaging quakes this year: between 5 and 12 percent.Natural elevated quake risks exist through much of California, Seattle and the area where Missouri, Tennessee, Arkansas, Kentucky and Illinois come together, known as New Madrid.Seismologists say Oklahoma’s problem is triggered by underground injections of huge volumes of wastewater from oil and gas drilling.[…]From 1980 to 2000, Oklahoma averaged only two earthquakes a year of magnitude 2.7 or higher. That number jumped to about 2,500 in 2014 then to 4,000 in 2015 as the use of an oil and gas production technique that uses millions of gallons of water boomed.
New Mexico lawmakers fighting to keep limits on waste from oil, gas companies – New Mexico lawmakers are fighting a move in Washington to get rid of a rule that limits waste from oil and gas companies. They believe that waste is the cause of that giant methane cloud over the Four Corners area. NASA has documented that cloud over the years. It shows the largest plume of methane in the nation. While NASA is still investigating, they say the likely sources are venting from oil and gas activities, active coal mines and natural gas seeps. In November, a rule was passed under President Obama that would require oil and gas operators to limit the methane emissions. Now the Republican led House has passed a measure to get rid of that rule. It’s now in front of the Senate. New Mexico state lawmakers and Congressman Tom Udall argue that it would be very harmful to New Mexico in a number of ways. “When methane is released, so are harmful pollutants that have harmful consequences — benzene linked to cancer, small pollutants trigger asthma,” Rep. Georgene Louis, D-Bernalillo, said. “The natural gas is owned by the taxpayers, but instead of earning royalties, over $100 million worth of gas is going to waste each year just in New Mexico,” Sen. Udall said. State lawmakers argue that extra $100 million could help the state budget crisis. Many Republican argue the rules are hurting business. Other states like Colorado have enacted their own methane waste rules — something New Mexico lawmakers are also looking to do so that we don’t have to rely on the federal rules.
EPA scraps methane reporting for oil and gas industries - The Trump Administration has withdrawn an EPA request that oil and natural gas companies provide information on their methane emission from field operations.The Obama Administration had sent the data request to some 15,000 oil and gas companies late last year. It asked for basic information on the numbers and types of equipment used at onshore drilling and production facilities as well as more detailed information on methane emissions sources and control devices.Earlier in 2016, EPA issued methane control regulations for new oil and gas facilities, but did not address existing facilities. The data collection rule was an attempt by the Obama EPA to learn more about oil and gas operations in preparation for emissions regulations at operating facilities.Oil and gas operations are the largest industrial source of methane, a greenhouse gas 25 times more potent that carbon dioxide, according to EPA. The U.S. is experiencing an oil and gas bonanza with some million wells in operation. However, in the rush to exploit the resource much is unclear—even the exact number of wells is uncertain. Confusion also surrounds the quantity of methane emissions. The now-canceled reporting was intended to help resolve this uncertainty.
Random Update Fracking Sand Amounts; Note The Bakken Well That Was Fracked With More Than 27 Million Lbs Of Sand -- There have been a few articles recently on the amount of fracking sand used in the Bakken. It seems to me it varies widely from operator to operator. Many operators are still using 4 million lbs; others are trending a bit higher but staying below 10 million lbs; I am starting to see at least one operator using 20+ million lbs (I often forget to check the length of the horizontals -- I will try to remember to point out 3-section laterals -- super-long laterals -- which can obviously affect the amount of proppant used; fortunately, 3-section -- super-long laterals -- are fairly rare).
The best way to compare wells is by the amount of proppant used per foot but that takes a bit more time: for the Bakken, in general, one can assume the horizontals are two-sections long, about 9,000 feet. Look at the test date on an early well and the test dates of the three more recent wells and compare the amount of proppant EOG used in these sand fracks. Among the Bakken operators, EOG has talked often about the sand pits it owns. For these wells, I have included the depth of the wells:
- 31403, 1,447, EOG, West Clark 117-0136H, Clarks Creek, 36 stages, 27.65 million lbs t5/16; cum 201K 1/17; 18,217 feet;
- 31248, 1,272, EOG, West Clark 104-0136H, Clarks Creek, 36 stages, 21.029 million lbs; t5/16; cum 122K 1/17; 18,185 feet;
- 31247, 1,613, EOG, West Clark 103-0136H, Clarks Creek, 37 stages, 21.15 million lbs; t5/16; cum 148K 1/17; 17,965 feet;
- 20329, 1,203, West Clark 4-2425H, Clarks Creek, 34 stages, 9.12 million lbs, t5/13; cum 303K 1/17;(18 days in January, 2015); 19,594 feet;
It seems like the analysts are concerned about the cost of proppant. From my vantage point, the cost of sand is the least thing to be concerned about in the overall cost of the well (benefit vs cost analysis). The cost of resin-coated proppant may be a different story, but I still think the cost of sand is over-hyped.
Cost Of Fracking Sand Rising -- Seeking Alpha -- March 7, 2017 --- Recently I posted: It seems like the analysts are concerned about the cost of proppant. From my vantage point, the cost of sand is the least thing to be concerned about in the overall cost of the well (benefit vs cost analysis). Today, over at SeekingAlpha an article on the rising cost of sand.
- leading producers of sand used by oil and gas explorers such as U.S. Silica, Hi-Crush Partners, and Fairmount Santrol are soaring this year even after a recent selloff, but their gains are turning into oil producers’ pain and could affect the global energy market, WSJ's Spencer Jakab writes
- some analysts see demand for frack sand equaling or exceeding the 2014 peak even with drilling activity far lower; Raymond James analyst Praveen Narra estimates the amount used per foot of well depth last year was 40%-50% more than in 2014
- Tudor Pickering analysts say a typical Permian Basin well might have cost ~$6M to drill last year including $350K worth of sand, but that could reach $800K by late 2017 and conceivably top $1M if providers flex their pricing muscles
- the cost trend could hurt projected cash flows and means drillers would need higher breakeven prices to justify new investment, which Jakab concludes are "putting a smile on the faces of sand company shareholders but also should cheer people up in Riyadh and Moscow."
Minot legislators stand on principle against taxing frack water - The Minot Daily News reported yesterday that some Minot legislators have been taking some heat for voting against the Water Commission Budget (HB 1020), but they are standing their ground on principle to oppose the Water (Royalty) Tax on frack water for the oil industry.Reps. Larry Bellew and Dan and Matt Ruby, all R-Minot, explained their reasons for voting against the State Water Commission funding bill during a legislative forum in Minot Saturday.Bellew said he opposed the bill’s water tax on private water rights holders who draw from the Missouri River system for commercial, non-irrigation purposes. The bill imposes a royalty of 75 cents per 1,000 gallons on fresh water dispensed to an oil and gas industry user at a privately owned water depot or water-dispensing point in the state. Income from royalties would go to repay state-guaranteed loans to entities that sell fresh water to oil and gas industry users, particularly the publicly-owned Western Area Water Supply system.Dan Ruby said WAWS was to be self-sustaining as a water supply system for communities, rural residents and industry in northwestern North Dakota. He said he was skeptical of the project when it was proposed because he questioned the sustainability. Selling water to the oil industry was part of the project’s funding mechanism. He said:Every session they keep coming back and saying they can’t make it on what they are charging. I think they sold a bill of goods that was flawed from the beginning. Ruby said taxing private water sellers to pay for WAWS is not a good idea. He said he concedes the water is a public resource, but so is the water used for irrigation that is not subject to the royalty.
What a Difference a DAPL Makes - How the New Crude Pipeline May Spur Bakken Gains -- A number of the Bakken’s leading producers are talking up the shale play’s prospects for crude oil production gains in 2017—and especially in 2018—but we are still waiting on numbers that would prove that the play has truly turned a corner. What is crystal clear, though, is that the Bakken’s biggest takeaway project ever, the 470-Mb/d Dakota Access Pipeline to Illinois, is finally nearing completion and operation after a very public delay. When DAPL comes online this spring, it will further reduce crude-by-rail volumes out of the Bakken and should help to increase the odds that production in the play will begin to rebound in earnest. Today we update production and takeaway capacity in the nation’s third-largest crude-focused shale play. The Bakken formation, and especially the core of the play in western North Dakota (where well over 90% of total Bakken production occurs; most of the rest comes from eastern Montana), proved to be one of North America’s most prolific and fast-growing crude oil production regions in the early years of the Shale Revolution. As we said recently in I Can See Clearly Now, forecasters routinely underestimated how quickly Bakken crude production would grow. For one thing, many failed to appreciate the ability of producers to increase their drilling and completion efficiencies; for another, it was remarkable how rapidly the midstream sector responded to the Bakken’s serious (and growing) pipeline takeaway shortfalls earlier this decade by building more than 20 terminals where crude could be loaded into rail tank cars for delivery via existing rail networks. In Slow Train Coming, our 2016 Drill Down Report on crude-by-rail, or CBR, we discussed the fact that railroads moved more than half of the oil produced in North Dakota through all of 2013 and 2014, and that while new pipeline capacity continues to be developed (including the Dakota Access Pipeline, which we will get to in a moment), CBR still plays an important role in the Bakken.
Judge won't stop construction of Dakota Access pipeline - A federal judge declined Tuesday to temporarily stop construction of the final section of the disputed Dakota Access oil pipeline, clearing the way for oil to flow as soon as next week. The Standing Rock and Cheyenne River Sioux tribes pledged to continue their legal fight against the project, even after the pipeline begins operating. The tribes had asked U.S. District Judge James Boasberg in Washington to direct the Army Corps of Engineers to withdraw permission for Texas-based developer Energy Transfer Partners to lay pipe under Lake Oahe in North Dakota. The stretch under the Missouri River reservoir in southern North Dakota is the last piece of construction for the $3.8 billion pipeline to move North Dakota oil to Illinois. The tribes argued that a pipeline under the lake violates their right to practice their religion, which relies on clean water, and they wanted the work suspended until the claim could be resolved. When they filed their lawsuit last summer, the tribes argued that the pipeline threatens Native American cultural sites and their water supply. Their religion argument was new, however, and disputed by both the Corps and the company. Boasberg in his ruling Tuesday said the tribes didn't raise the religion argument in a timely fashion. He also questioned its merit.
Judge deals another setback to those trying to block the Dakota Access pipeline -- A federal judge in Washington refused to issue a preliminary injunction Tuesday to stop construction of the Dakota Access pipeline, making it increasingly likely that the nearly complete pipeline will be cleared to start carrying crude oil.The Standing Rock and Cheyenne River Sioux tribes had challenged the pipeline on the grounds that running it under Lake Oahe in North Dakota would violate their religious freedom because of beliefs linked to the lake’s waters.District Court Judge James Boasberg said that the challenge was unlikely to succeed and that a preliminary injunction on that basis would cause an unreasonable delay in the project.But Boasberg will continue to weigh the tribes’ other challenges, including the obligations of the Army Corps of Engineers to the Native American tribes under the Fort Laramie Treaties signed in the mid-19th century.“The ruling is disappointing but not surprising — it is very difficult to get an injunction under these circumstances,” Jan Hasselman, a lawyer for the tribes, said in an email. “However, the Court has yet to hear our primary legal case that the Trump-issued permits were illegal. We think we have a strong case and look forward to our day in Court.”The Fort Laramie Treaties ceded a larger area of land to the tribes than those included in the modern reservations created later by Congress. And the tribes have asserted that the Army Corps has obligations to protect the tribes’ rights to hunt, fish or gather on those lands and to guarantee protection from oil spills in the sacred waters of the Missouri River and Lake Oahe.“Once again, the federal government and the army are treating the original inhabitants of this land as though we are less than human, as though our lives and lands are something to be ignored and discarded in the never-ending quest for profit,” Chase Iron Eyes, the lead counsel of the Lakota People’s Law Project.
Contractor nearly finished $1 million clean-up of pipeline protest camps - The million dollar clean-up of three camps used by Dakota Access Pipeline protesters in south central North Dakota is nearly complete. A contractor hired by the U.S. Army Corps of Engineers has completed work at the largest of the camps and another just south of it. Both are on Corps of Engineers-owned land. A third protest camp not originally in the clean-up plan, located on property owned by the the Corps of Engineers and the Standing Rock Sioux Reservation, is more than a third complete. Corps spokesman Captain Ryan Hignight says one of the big concerns has been about hazardous waste on the properties which could get washed into the Missouri River, contaminating the Oahe reservoir and other downstream locations. Hignight says several locations have been where there was human waste but it was minor. He says, "those at the camp said they were doing a lot to compost or remove it. That's not to say it's not out there we just haven't found it." More than 7,000 cubic yards of debris and garbage, filling 1600 rollout dumpsters has been collected so far. Hignight says the Standing Rock Sioux tribe has also collected propane tanks and lumber for recycling or use left behind when the camps were evacuated about two weeks ago.
Police win warrant to search Dakota Access Pipeline protest Facebook page - Local Washington state police have obtained a court warrant to search the Facebook page of a group dedicated to protesting the Dakota Access Pipeline. The warrant from the Whatcom County Sheriff's Department seeks data surrounding the Bellingham #NoDAPL Coalition's Facebook page. The page, with more than 1,000 followers, provides information about pipeline environmental issues and is used to organize political protests and connect political activists.In addition to demanding account information about those who have interacted with the group's page, the warrant seeks "messages, photos, videos, wall posts, and location information" dating from February 4 to February 15. The search time period surrounds a February 11 protest in downtown Bellingham against the Trump administration's decision to follow through with the pipeline. Protesters had blocked Interstate 5 for more than an hour, snarling traffic for miles. Bellingham resident Neah Monteiro, the page's top admin, received an e-mail from Facebook after the protest. It said the social networking site had received a warrant for the data. The American Civil Liberties Union intervened and filed a motion (PDF) Thursday to quash the warrant. The ACLU said the data is constitutionally protected speech. The organization continued in its motion: In fact, the County’s warrant would reach the messages of even general members of the public who interacted with the group on the Facebook page by asking questions about the group’s activities or engaging with the group in political debate. Hosting and participating in an online forum for political organizing, debate, and advocacy is activity that lies at the core of the First Amendment—and the Founders would have recognized it as such. A hearing in Whatcom County Superior Court on the matter is set for next Tuesday.
US officials to hold meeting on Alberta Clipper pipeline -- State Department officials will come to Minnesota on Tuesday to hold the only public meeting on a draft environmental review for the final segment of Enbridge Energy's project to boost capacity in its Alberta Clipper pipeline, which carries Canadian tar sands oil across northern Minnesota to Superior, Wisconsin. The State Department's four-year review concluded that there would be no significant environmental impacts from completing the project, which requires a presidential permit because the last remaining segment crosses the U.S.-Canadian border in North Dakota. But environmentalists and some Native American tribes dispute that and are gearing up for the meeting in the northern Minnesota city of Bemidji. Enbridge built the Alberta Clipper, also known as Line 67, in 2009 for $1 billion. Its capacity was 450,000 barrels per day. Enbridge later decided to nearly double that to 800,000 barrels; the Calgary, Alberta-based company did most of that by adding pumping stations along the route. Enbridge needs a presidential permit for the 3-mile segment where the 1,000-mile pipeline crosses the border. Getting the permit is a lengthy process. The Keystone XL pipeline that would run from Canada's tar sands to Nebraska, for example, was derailed when President Barack Obama rejected its permit. President Donald Trump has invited Keystone XL developer TransCanada to reapply. Enbridge is operating the Alberta Clipper at full capacity with a temporary workaround. It built a detour to and from a parallel pipeline that crosses the border nearby and already has a permit. Opponents challenged the legality of that setup in court but lost. Other Enbridge projects in the works are a proposed replacement for its 1960s-era Line 3 that would follow part of the same corridor. In fact, the Alberta Clipper detour uses an upgraded section of Line 3 to cross the border. Line 3 is also drawing opposition from tribes and environmentalists.
A Father of Fracking Seeks to Emulate U.S. Shale Boom in Alaska - A pioneer of the U.S. shale revolution wants to take fracking to America’s final frontier. Success could help revive Alaska’s flagging oil fortunes. Paul Basinski, the geologist who helped discover the Eagle Ford basin in Texas, is part of a fledgling effort on Alaska’s North Slope to emulate the shale boom that reinvigorated production in the rest of the U.S. His venture, Project Icewine, has gained rights to 700,000 acres inside the Arctic Circle and says they could hold 3.6 billion barrels of oil, rivaling the legendary Eagle Ford. While the potential is huge, the difficulty of shipping millions of gallons of water, sand and chemicals -- the ingredients used in fracking -- to one of the most remote areas on earth is nothing short of monumental. At stake is an Alaskan industry that’s seen output tumble from 2.1 million barrels a day in 1988 to 520,000 in 2016 as reserves dwindled and explorers sought cheaper supplies in shale fields to the south. “The oil is there,” said Basinski, founder and chief executive officer at Houston-based Burgundy Xploration LLC, in an interview. “Now it’s a question of how quickly we can get it to flow and whether we can get the economics to work." One exploratory well has been drilled, he said, and a second is planned by mid year. The future of U.S. oil exploration has been among the hot topics as the industry’s biggest names gathered in Houston this week for the annual CERAWeek by IHS Markit conference. Alaska Senator Daniel Sullivan spoke during the meeting’s opening session and Senator Lisa Murkowski is set to help close it with comments on Friday.The dwindling volume of crude produced in the state has combined with a rout in oil prices over the last two years to undercut Alaska’s once-booming economy. When oil topped $100 a barrel in 2014, Alaska took in $5.7 billion in petroleum taxes and royalties for the fiscal year that ended that June, covering most of its budget. For fiscal 2017, the take is projected at $1.6 billion, a 72 percent drop. At the same time, the decline has fed worries that the 40-year-old Trans-Alaska Pipeline System, the North Slope’s 800-mile link to global oil markets, could become too expensive to operate by the next decade.
Alaska underwater pipeline leak may have started in December — A pipeline spewing natural gas into Alaska’s Cook Inlet may have started leaking in December, two months before the leak was spotted from the air, according to a federal pipeline safety office. The estimate of when gas started leaking into winter habitat for the endangered Cook Inlet beluga whales was issued in a proposed safety order last week by the U.S. Pipeline and Hazardous Materials Safety Administration that the agency confirmed on Tuesday. Processed natural gas continues to leak from a Hilcorp Alaska LLC pipeline that supplies four oil platforms in the inlet south of Anchorage — at a rate estimated by the company of 210,000 to 310,000 cubic feet of gas daily. A Hilcorp helicopter crew Feb. 7 spotted gas bubbling to the surface about four miles off shore. However, the company in late January reported that it had detected increased gas flow through the pipeline in January and started looking for a leak, according pipeline safety office’s report. A subsequent analysis of gas flow indicated the pipeline likely began leaking in December, the agency said. The agency late Friday issued the proposed safety order requiring the line to be repaired by May 1 or shut down.
Repsol, Armstrong Strike Big Oil Find In Alaska's North Slope - Repsol said March 9 it hit an oil find with big potential in Alaska's North Slope in the Nanushuk Play. With 1.2 billion barrels of recoverable light oil, Repsol and its partner, Denver-based Armstrong Energy LLC, claim the discovery is the "largest U.S. onshore conventional hydrocarbons discovery in 30 years." The Horseshoe No. 1 and 1A wells drilled during the 2016-2017 winter campaign confirm the Nanushuk Play as a significant "emerging play." The wells extend by 32 km (20 miles) in an area known as Pikka. Preliminary development concepts for Pikka anticipate first production there from 2021, with a potential rate approaching 120,000 barrels per day of oil. “Repsol and our partner Armstrong will continue evaluating these positive results in the coming months to determine next steps,” Repsol told Hart Energy in an emailed statement. Horseshoe-1 was drilled in January 2017, while Horseshoe-1A was drilled the following month from same well pad. The company said it has been actively exploring in Alaska since 2008, having made multiple discoveries on the North Slope since 2011 with Armstrong. Repsol holds a 25% working interest in the Horseshoe discovery and a 49% working interest in the Pikka Unit. Armstrong holds the remaining working interest and is currently the operator.
Respol announces largest U.S. oil discovery in 30 years - Spanish oil company Repsol announced what it is calling “the largest U.S. onshore discovery in 30 years,” according to a March 9 press release. Repsol, and its partner Armstrong Energy discovered what they believe is approximately 1.2 billion barrels of recoverable light oil from Alaska’s North Slope in the Nanushuk play. Repsol isn’t new to Alaska. The company has been exploring there since 2008, with several North Slope discoveries since 2011. The Trans-Alaskan Pipeline System may see a little more action due to Repsol and Armstrong Energy’s discovery on the North Slope. Photo: Pixabay. According to Alaska Public Media, Armstrong is hoping to start designing Nanushuk’s central processing facility. Development of this facility is crucial to Alaska’s oil industry, since it would prepare oil to send down the pipeline. The Trans-Alaska Pipeline System has seen a significant decline in the amount of oil running through it. Alaskan oil output has dropped from 2.1 million barrels a day in 1988 to about a fourth of that, 520,000 barrels a day, in 2016. So Repsol’s discovery is considered a “game changer” for the slumping Alaskan oil industry. Repsol and Armstrong aren’t the only companies interested in the revitalization of Alaska’s oil industry. Alaska Dispatch reported yesterday that Paul Basinski, the geologist who helped discover the Eagle Ford in Texas, is involved in a venture called Project Icewine, which has gained 700,000 acres inside the Arctic Circle. He believes this area could hold as much as 3.6 billion barrels of oil, similar to the reserves in the Eagle Ford. One of the reasons that Alaska’s oil industry declined was the difficulty to utilize hydraulic fracturing in frigid temperatures, says the Dispatch. Drilling in the Arctic can cost three times what it costs in the rest of the United States, especially in the Permian Basin where oil seems to flow like water these days. In addition, imaging technology that could accurately pinpoint shale oil reserves below the permafrost didn’t exist until recently, when 3-D seismic imaging technology allowed geologists to better evaluate what’s below the surface.
Canada says no big hurdles remain for Keystone XL Approval - TransCanada Corp.’s Keystone XL pipeline doesn’t face any major remaining hurdles to U.S. approval, Canada’s ambassador to Washington said. Discussions on TransCanada’s crude-oil route are going “extremely well” with U.S. federal authorities, Ambassador David MacNaughton said Friday in an interview at his office. “I don’t see any big hurdles in the way of Keystone from the administration’s point of view,” he said, referring to the government of President Donald Trump. While the state of Nebraska may still have some issues, the outlook for the pipeline’s approval looks “very positive,” MacNaughton said. Approval would end years of uncertainty over the project, which sparked protests from environmentalists and created tension between the U.S. and Canada. The route would carry crude from Canada’s oil sands to Gulf Coast refineries. In 2015, former President Barack Obama rejected the pipeline, saying the project would undercut the U.S. fight against climate change. Trump revived the prospect of approval shortly after taking office, inviting TransCanada to reapply. The company applied to the State Department for a presidential permit in January. Canada’s government has said its approvals for the Keystone project remain in place and that the fate of the pipeline is now in the hands of the company and U.S. lawmakers.
Canada's environment minister says 'No. 1 focus' is U.S. trade | Reuters: Canadian Environment Minister Catherine McKenna said on Thursday the "No. 1 focus" of her government, including her department, is trade relations with the United States, as Canada steels itself for possible NAFTA renegotiation with its southern neighbor. McKenna was speaking on the day Royal Dutch Shell (RDSa.L) announced it would sell most of its Canadian oil sand assets, the latest oil major to exit the region. Opposition critics and some in the oil sands sector say tougher environmental restrictions in Canada versus the United States will make Canada less competitive. "Canadians expect us to take climate action, but it's also a real opportunity for us to find the solutions that are going to create jobs and grow our economy," McKenna said at a business event in Calgary, where many Canadian oil and gas companies are headquartered. Canada sends 75 percent of exports, including almost all of its crude, to the United States, and U.S. President Donald Trump's vow to renegotiate the North American Free Trade Agreement (NAFTA) could negatively affect the country. "Our No. 1 focus right now - and that includes me as environment minister - is on our trading relationship with the United States," McKenna said. "I've had calls with my American counterparts .. and the first issue I raised was trade." While trade and the economy do not come under McKenna's portfolio, her work in implementing her Liberal government's national carbon tax could have consequences for Canada's emissions-heavy energy sector, especially as it contrasts with the Trump administration's looser approach on the issue.
Shell to divest nearly all of its Canadian oil sands interests for $7.25 billion - Oil & Gas Journal: Royal Dutch Shell PLC has agreed to sell all of its in-situ and undeveloped oil sands interests in Canada and reduce its share in the Athabasca Oil Sands Project (AOSP) to 10% from 60% in exchange for $7.25 billion. Under the first agreement, Shell will sell its entire 60% interest in AOSP, its 100% interest in the Peace River Complex in-situ assets including Carmon Creek, its 100% working interest in the Cliffdale heavy oil field, and several undeveloped oil sands leases in Alberta to a subsidiary of Canadian Natural Resources Ltd. (CNRL) for $8.5 billion. The purchase price comprises $5.4 billion in cash plus around 98 million CNRL shares currently valued at $3.1 billion. The current estimated production capability, before royalties, for the AOSP properties to be acquired by CNRL is 196,000 b/d with February production of 188,000 b/d of mine production and upgrader output of 195,000 boe/d from 70% working interest in AOSP; and 13,800 b/d of heavy oil from the Peace River properties. At yearend 2016, reserves associated with the assets were 2 billion bbl. In the second agreement, Shell and CNRL will jointly acquire and equally own Marathon Oil Canada Corp., which holds 20% interest in AOSP, from an affiliate of Marathon Oil Corp. for $1.25 billion each to be settled in cash. Marathon Oil also reported a separate agreement to acquire 70,000 net surface acres in the Permian basin from BC Operating Inc. and other entities for $1.1 billion in cash (OGJ Online, Mar. 9, 2017). That deal includes 51,500 acres in the northern Delaware basin of New Mexico, and current production of 5,000 net boe/d.
Shell sells Canadian oil sands, ties bonuses to emissions cuts | Reuters: Royal Dutch Shell has agreed to sell most of its Canadian oil sands assets for $8.5 billion, the latest international oil major to withdraw from the costly and carbon-heavy projects. Shell is trying to sell assets totaling $30 billion to cut debt following its $54 billion acquisition of BG Group and is under investor pressure to mitigate climate change risks. Shell also said on Thursday that 10 percent of directors' bonuses will now be tied to how well it manages greenhouse gas emissions in refining, chemical and upstream operations. Analysts welcomed the deal, under which Shell has agreed to sell its existing and undeveloped Canadian oil sands interests to Canadian Natural Resources and to cut its share in the Athabasca Oil Sands Project (AOSP) to 10 percent from 60 percent.Other oil firms including Exxon Mobil, Conoco Phillips and Statoil have written down or sold their Canadian oil sand assets. Shell said it would remain as operator of the AOSP Scotford upgrader and the Quest carbon capture and storage project.
Marathon Update; To Sell Canadian Sands; To Buy Permian -- From E & P Industry Research. From a press release dated today, March 9, 2017: Marathon Oil Corporation announced today it has signed an agreement to sell its Canadian subsidiary, which includes the Company's 20 percent non-operated interest in the Athabasca Oil Sands Project (AOSP), to Shell and Canadian Natural Resources Limited for $2.5 billion in cash, excluding closing adjustments. Marathon Oil also announced the signing of a definitive agreement to acquire approximately 70,000 net surface acres in the Permian basin from BC Operating, Inc. and other entities for $1.1 billion in cash, excluding closing adjustments. The acquisition includes 51,500 acres in the Northern Delaware basin of New Mexico, and current production of approximately 5,000 net barrels of oil equivalent per day (boed). This is interesting because I thought I just read that Shell was selling some of its western Canadian oil sands. Yes, I did -- earlier this morning: Shell sells sands -- $7.25 billion -- Reuters. Will use proceeds to acquire more Permian assets, data points:
- up to 10 targets within approximately 5,000 feet of stacked pay; base case assumes up to 6 target benches
- 70,000 net acres with 51,500 net acres in the Northern Delaware basin
- total implied acreage cost: $14,000
- at $55 WTI, 90% before-tax IRRs
- primary targets: Wolfcamp and Bone Spring
- 350 million boe of risked resource at $2.80/BOE with 630 gross company operated locations
- 900 million boe of total resource potential with 1,700 total upside locations
- one operated rig; will add second rig mid-year
Oil industry costs will rise as focus shifts to growth: Kemp - (Reuters) - Oil industry costs are notoriously pro-cyclical, which is one of the main reasons for the pattern of boom and bust that has afflicted in the industry from the beginning.The cost of everything from skilled and unskilled labour to engineering contracts, field services, raw materials, equipment, spare parts and rig hire tends to rise and fall with price of oil.During a boom, prices for labour and equipment escalate rapidly, pushing up the breakeven cost of finding and developing new deposits, and driving the market-clearing price of oil even higher.In a bust, labour and equipment prices fall sharply, pushing down breakeven costs and helping sustain production at an unexpectedly high level despite the plunge in oil prices.Pro-cyclical costs include everything from skilled petroleum engineers and unskilled labour, to fuel, rig hire and drill bits.Pro-cyclical costs apply to a host of other services in the supply chain including catering, accommodation and transportation.And in the broadest sense, pro-cyclical costs include taxes, royalties and other government charges on exploration and production.In a downturn, governments cut tax and royalty rates, and offer regulatory relief, to attract investment, only to increase them again during a boom to capture windfall gains.The pro-cyclical behaviour of costs is a classic example of positive feedback which amplifies the boom-bust cycle in oil prices and delays the process of adjustment following a supply or demand shock.Pro-cyclical costs ensure crude supply tends to respond sluggishly to even a big change in oil prices ("Oil prices: volatility and prediction", Reuters, 2016).Rising costs hampered efforts to boost oil production during the 2004-2014 boom; more recently falling costs have hampered efforts to cut output and rebalance the market during the slump.
EIA: Natural gas, crude production fell in 2016 -- According to the U.S. Energy Information Administration March 8, 2017 report, U.S. natural gas production and crude production both fell in 2016. Average crude oil production in the lower 48 states in 2016 fell to 8.39 million barrels per day (b/d). This is a decrease of 6.1 percent from the 2015 average, or approximately 0.55 million b/d. Natural gas withdrawals also decreased in 2015, averaging 1.03 billion cubic feet per day (Bcf/d), 1.3 percent lower than in 2015.The Gulf of Mexico saw the only significant increase in U.S. oil production in 2016. Since offshore projects take much longer to complete, new projects planned in 2012-14 finally came online over a year later. West Virginia and New Mexico were the only states that saw oil production increases in 2016. Ohio, Pennsylvania, North Dakota, and Louisiana saw net increases in natural gas production by state, despite an overall national decrease.While overall totals showed a net decline in crude production, recovery was evident in the increase in production during the second half of 2016. The price of West Texas Intermediate (WTI) crude oil went from a monthly low of $30 per barrel in January 2016 to an average of $53 per barrel in January 2017. Currently, oil is holding on just above $50 for March. However, current crude production increases across the shale plays have pushed market predictions lower. Some predict lower oil prices throughout the rest of the year. Eugene Graner with Heartland Investor Services says oil may have topped out in January. According to Oilprice, a stable market means a rebound to $55-60 in 2018 and 2019, but a stressed, oversupplied market will mean $40 a barrel through 2019. The Organization of Petroleum Exporting Countries (OPEC) have committed to cutting oil production to help improve the global oil oversupply, or glut. However, U.S. shale producers, in response to slightly increased prices, have continued to increase production in recent months. After Texas saw the largest volumetric decrease in 2016 of 239,000 b/d, production in Texas now continues to increase. The February 13, 2017 Drilling Productivity Report showed an increase in the Permian Basin of 70,000 b/d from the previous month from 2,180,000 b/d to 2,250,000 b/d. The Eagle Ford continues to produce just over a million b/d while the Bakken is just below. Production in the Bakken region, however, continues to drop, showing a decrease of 18,000 b/d over the last month.
Is The US Becoming Overdependent On Natural Gas? - The story sounds familiar. For decades, oil and natural gas drilling have been proceeding and creating prosperity for those involved. At some point, significant earthquakes occur in areas where they were formerly very rare or nonexistent. Those quakes are linked to oil and gas drilling and production. The industry denies the link. The quakes continue, get worse and finally get strong enough to do damage. To those living in Europe, it's the story coming out of The Netherlands, home to the Groningen Gas Field, one of the largest natural gas finds ever. What has caught the Dutch by surprise--and may someday soon catch America by surprise--is the speed with which its decades-long reliance on a large initial endowment of natural gas has turned into a liability. First, there were the earthquakes linked to drilling and production operations in Groningen which have forced the government (part owner of the field) to scale back production to reduce the frequency and severity of those quakes. This production decline of more than 50 percent has meant government gas revenues dropped by more than half from €13 billion to around €5 billion from 2013 to 2014. Second, as a result of the production cutbacks The Netherlands is now a net importer of natural gas, instantly losing its self-sufficiency status. Europe's gas now will likely have to come increasingly from Russia whose relations with Europe are replete with complications. Third, the Dutch have failed to prepare for this day. Some 98 percent of Dutch homes use natural gas for heating and cooking. Renewable energy makes up a paltry 5.5 percent of the country's energy mix as of 2014. Fourth, the Dutch are still obliged to honor long-term contracts which force them to deliver substantial quantities of natural gas to customers outside the country. The country is increasingly facing the strange predicament of having to import more and more natural gas to offset what it must ship abroad. This is in a country whose dominant field, Groningen, is now 80 percent depleted. And, here is where the Dutch situation ought to be a warning to the United States. America is entering into more and more long-term contracts to export liquefied natural gas (LNG) to customers in Europe and Asia even as the country remains a net importer. There is good reason to believe that most estimates of future natural gas production in the United States are far too optimistic. All shale plays have peaked and older plays, like the Barnett and Haynesville, are down 38 percent and 52 percent, respectively.
Dutch, German natural gas spot prices down on demand, weather - Dutch and German day-ahead gas prices were weaker Wednesday morning, with less demand expected and temperatures forecast above seasonal norms. Further dated contracts fell as crude prices dropped on weak data from China and the US. Around midday London time, TTF day-ahead last dealt at Eur16.25/MWh, down 32.5 euro cent from Tuesday's close. German NetConnect was also down 32.5 euro cent at Eur16.65/MWh, while GASPOOL moved lower by 20 euro cent to Eur16.825/MWh. Dutch and German prices followed UK NBP day-ahead, which was 0.50 p/th lower and last heard trading at 42.25 p/th at midday as a steep drop in demand caused both medium-range storage withdrawals and Dutch imports to cease. CustomWeather forecast temperatures in Amsterdam Thursday at 2 degree Celsius above seasonal norms, up from 1 C above norm Wednesday. Temperatures in Berlin, in the GASPOOL area, are expected to jump to 4 degrees C above norms Thursday, from normal Wednesday. In Munich, in the NCG area, temperatures are expected at 3 degrees C above seasonal norms Thursday, up from 1 C below Wednesday.
UK North Sea operators show signs of revival - Energy companies active in the UK North Sea will generate positive free cash flow in 2017 for the first time in four years, as groups show signs of recovery following the oil price crash of 2014, says the industry’s trade body.Exploration and production companies working in the basin are collectively forecast to generate £5bn of free cash flow this year if the rebound in oil prices persists around current levels, said Oil & Gas UK, which represents North Sea operators.That would mark an encouraging turnround from the past four years, when companies’ costs exceeded revenues as they battled against falling oil prices.Costs were exceeding revenues even before the oil price crash that began in mid-2014, with companies collectively having negative free cash flow in 2013, and this reflects how North Sea operators ran up some of the highest operating expenses in the world.The slump in crude prices pushed operators to cut costs, and average unit operating expenses in the basin have almost halved in the past two years, from $29.70 a barrel to $15.30, said Oil & Gas UK. This has led to optimism that the North Sea industry may finally be turning a corner and the basin has witnessed a flurry of deals since the turn of the year. These include Royal Dutch Shell’s agreement to sell assets in the basin to Chrysaor, a small UK company backed by private equity, for at least $3bn.
This Mysterious Oil Company Just Got A License To Drill In Crimea -- A mysterious company called Novye Proekty has been awarded an oil and gas exploration license for the Crimean Black Sea shelf, and the Kremlin’s spokesman is directing questions about it to the cabinet. The news about Novye Proekty was published by Kommersant earlier this week, sparking speculation, since according to some sources cited by the daily, the company was linked to fugitive Ukrainian energy and media businessman Serhiy Kurchenko, who is wanted by the Ukrainian authorities for the so-called “Kurchenko scheme”, which included fake oil deliveries and a number of other dubious enterprises. Kurchenko, according to Kommersant, currently lives in Moscow. What’s more interesting, however, is that Novye Proekty is a private company, and private companies are not allowed to explore for oil and gas in the Crimean shelf, TASS notes. Prime Minister Dmitry Medvedev opened the door for license-issuing for Crimea last year, but only state-owned companies were to be allowed through it. Yet, here this company is, awarded a 30-year license with the obligation to drill a well within the next eight years. The license is for the Glubokaya block, which holds reserves estimated in 2011 at 8.3 million tons of crude and 1.4 billion cu m of natural gas. Indeed, the Crimean shelf is believed to be quite rich in hydrocarbons, which is one logical reason for the annexation of the peninsula in the first place. Related: Saudi Arabia’s Secret Meetings With The World’s Largest Oil Traders An EU Observer article from 2014 discussed this in some depth, suggesting that Gazprom will be put in charge of the newly acquired oil and gas reserves. This does not seem to be the case in light of the Novye Proekty report. Coupled with Kremlin spokesman Dmitry Peskov’s reluctance to discuss the license, the plot thickens.
Argentina slashes drilling costs, sees more efficiencies | Reuters: Argentina's state-run oil company YPF has cut horizontal drilling costs by more than half and slashed the time required to complete new wells, the chairman said on Monday at the CERAWeek energy conference. The company cut the cost of horizontal drilling to around $8 million from $17 million a well, while the time required to complete a new well has been shaved to 15 days from 40 days, Miguel Gutierrez told the gathering in Houston. Those efficiencies have pushed break-even prices to below $40 per barrel, a significant gain for Argentina, which has struggled to attract capital since crude prices started to decline in 2014. Argentina recently has been pushing again to lure energy investment into the country, particularly into its massive Vaca Muerta formation. That reservoir is one of the largest shale deposits in the world. In January, Argentina announced changes to its subsidy program to offer producers $7.5 per million BTU of natural gas produced through 2020 - a figure well above U.S. gas prices. "It's competitive, especially compared to the United States," Gutierrez said on the sidelines of the conference. Despite the vast reserves, lack of production has left the country short on energy, and a bump in production is unlikely to curb imports in the near term. In 2016, Argentina was forced to significantly increase imports of LNG and purchase supplies from Chile, which resells a portion of the gas it receives to its neighbor.
Oil-for-loan debts cost Venezuela's PDVSA hard-won India market share | Reuters: Venezuela's state-run oil company, PDVSA, has spent at least a decade trying to build business ties and boost shipments to refineries in India, where crowds once welcomed the late socialist leader Hugo Chavez with cries of "Viva!" Now, the ailing firm is being forced to slash sales to its crucial trade partner. Venezuela has given up the fight for coveted market share in India because of a combination of declining crude production and heavy obligations under oil-for-loan deals with China and Russia, according to internal PDVSA data and two people familiar with the company's strategy and operations.Caracas needs the oil to pay debts to China and Russia, key political allies that have together lent Venezuela at least $50 billion in exchange for promised crude and fuel deliveries. PDVSA and the Venezuelan Oil Ministry did not respond to requests for comment. In 2013, when Venezuela exports and oil prices were high, PDVSA raked in nearly $14 billion from India, the world's fastest growing large economy. By last year, after an oil price crash, that figure had plummeted to $2.7 billion, according to a Reuters analysis of the PDVSA data. That means less cash income for the isolated South American economy, deepening a recession that has left many citizens skipping meals amid food shortages and soaring inflation. Oil accounts for almost all of Venezuela's export revenue, and many of Venezuela's customers pay for oil in kind - with food or medical supplies, for example. India is among the few trading partners that buy large volumes of PDVSA oil with cash.
Brazilian crude threatens Oceania, Middle East suppliers' Asian market share - China's strong appetite for Brazilian crude has set off alarm bells among various producers in Oceania and the Middle East, prompting Australian and key Persian Gulf crude suppliers to slash their selling prices in an effort to remain competitive and protect their market share in Asia, market participants said Wednesday. Since late 2016, China saw a dramatic increase in Brazilian crude imports and the trend remained firmly intact with two Chinese state-run oil companies purchasing 5 million barrels or more of heavy sweet crude from the South American state for loading in March, according to a source with direct knowledge of the deals. March shipping fixtures seen by S&P Global Platts also showed that PetroChina has fixed the San Jacinto to move 130,000 mt of crude oil for March loading from Brazil to China, while trading company Vitol also booked Suez Hans and Fraternity to move a combined 260,000 mt of crude for loading in the same month for the similar journey. In addition, Shell and Repsol fixed Maran Artemis and Aquarius Voyager respectively, to move a combined total of 560,000 mt of crude for March loading from Uruguay to China, according to the latest fixtures. Uruguay's Montevideo is a common loading destination for Brazilian offshore producers because of its proximity to several prolific oil fields like those in the nearby Santos Basin. The source indicated that the Brazilian crude grades that the state-run Chinese companies had purchased for loading in March consisted mainly of Roncador, Marlim and Lula.
Australia Gas Firms Locked in Legal Battles After $200 Billion Spree Sours - After splurging $200 billion building the world’s biggest gas export plants, producers in Australia are now locked in legal battles with contractors over who should shoulder billions of dollars in liabilities sparked by delays and cost blow-outs. Chevron Corp., owner of the $54 billion Gorgon facility, Australia’s largest resource development, along with Inpex Corp. and Santos Ltd. are among energy heavyweights trying to claw back funds. The number of disputes is growing weekly in a chain reaction of litigation, which extends to small businesses subcontracted to supply materials and services. “There are billions and billions of dollars of claims out there in the market, and claims of hundreds of millions of dollars are not uncommon,” said Matthew Croagh, who handles liquefied natural gas matters as a partner in Melbourne with London-based law firm Norton Rose Fulbright. Croagh wasn’t referring to any specific dispute. After an investment bonanza at the start of the decade -- poised to catapult Australia ahead of Qatar as the world’s biggest supplier of LNG -- many of the world’s top energy producers and service firms face the prospect of weaker returns. Costs of completing eight Australian projects exceeded initial forecasts by $55 billion amid competition from rival projects for equipment, labor and resources that pushed up prices and led to delays. Now, an oil market slump means companies may have to wait years to get a return on their investments. The scale of disputes is shown in a 138-page document filed by Santos in the Supreme Court of Queensland in December. Australia’s third-biggest oil and gas producer is suing U.S. contractor Fluor Corp. for A$1.5 billion ($1.1 billion) in damages for work on its $18.5 billion GLNG facility in the northeastern state.
Australia's Gorgon LNG Train 3 to start in Mar, beating Q2 2017 expectation - The third train at the US$53 billion Gorgon LNG facility in Western Australia is now expected to begin production this month, beating previous expectation of a second-quarter 2017 start, Chevron's executive vice president Jay Johnson said on Tuesday night in Australia. "Train 3 construction and commissioning has gone smoothly and we're expecting first LNG [production] before the end of this month, ahead of our previously announced schedule," he said at a security analyst meeting. "We applied the experience gained during the construction, commissioning and early operations of Train 1 to both Trains 2 and 3," he said. As a result, Train 2, which commenced production in October 2016, achieved over 90% of nameplate capacity within a week of beginning production, and has been performing "very well," Johnson said. Typically, LNG plants require six-months to ramp up to nameplate capacity, but each plant is different and some plants only take a few weeks, while others can take longer than six months, Platts Analytics says. That solid performance at Gorgon Train 2 followed various production issues at Train 1, which had its first LNG cargo depart in March last year. "At Gorgon, Trains 1 and 2 are producing about 230,000 oil equivalent barrels a day of LNG and domestic gas. We've shipped 22 cargoes of LNG so far this year," Johnson said on Tuesday night. At full capacity, the three-train Gorgon facility will have a shipment capacity of 15.6 million mt/year of LNG and a domestic gas plant with a capacity to supply 300 terajoules of gas per day to Western Australia, Chevron said. The increased production at Gorgon will help in making Australia the world's largest LNG exporter, surpassing Qatar, which Platts Analytics expects to happen in 2019.
Analysis: Global LNG outlooks test conventional wisdom of supply glut - When Shell last month presented its first global LNG Outlook since its 2016 acquisition of the UK's BG Group, it surprised some by effectively denying the existence of a global LNG supply glut, pointing instead to a well balanced market where all produced LNG cargoes were being consumed. Much of the commentary in recent months has been telling us the LNG market is already suffering a supply glut and is heading for a period of sustained oversupply until at least the start of the 2020s. LNG prices across the globe have fallen to multi-year lows -- other than a mostly weather-related spike in late 2016 -- and the expected slew of new project start-ups in 2017 from Australia and the US has been forecast to lead to a hugely oversupplied market with demand growth unable to keep pace.The report from Shell -- which is now more exposed than ever to LNG market dynamics since the BG purchase -- was in stark contrast to other views from the industry. Some players already talk of an oversupplied LNG market, with things only set to worsen in the coming years. Pablo Galente Escobar, head of LNG at global trader Vitol, said at a London conference last month his view of the LNG market was "very different" to Shell's. "We think the market will be significantly oversupplied over the next five years," he said, pointing to expected LNG supply growth to 400 million mt/year by 2020 from 240 million mt/year in 2015. This growth, he said, was unprecedented in the history of commodities, and represented the biggest "supply shock" he had ever known.
Bangladesh to build LPG-fueled power plant amid growing demand, gas shortage - Bangladesh plans to construct its first LPG-fired power plant to diversify energy supply sources and ease pressure on the country's diminishing natural gas resources, Nasrul Hamid, State Minister for the Ministry of Power, Energy and Mineral Resources, told S&P Global Platts Monday. The move is expected to add further momentum to the South Asian nation's LPG demand growth, largely driven by the use of the fuel in the automotive sector and the suspension of pipeline gas supply to households and commercial consumers. The project will be led by business conglomerate Beximco Group, in partnership with its US-based technical partner General Electric, according to another senior MPEMR official. The plant's capacity and location are yet to be confirmed. The project announcement follows the implementation January 29 of Bangladesh's first policy aimed at expanding supply and boosting consumption of LPG, to replace natural gas in the power, transport and industrial sectors.While Bangladesh's LPG consumption in 2016 was at around 300,000 mt, up from 200,000 mt a year earlier, MPEMR estimates that actual unconstrained demand could be around 500,000 mt as consumers are using kerosene and wood as alternatives to LPG due to lack of availability. Under the new policy, the private sector is now able to set up LPG terminals, autogas filling stations, autogas conversion plants and LPG bottling plants.
Japan LNG spot cargoes average price in Feb up 1.2% to $8.5/MMBtu - Natural Gas | Platts News Article & Story: The average price Japanese LNG buyers paid for spot cargoes contracted in February came in at $8.5/MMBtu, up 1.2% from January, data released by the Ministry of Economy, Trade and Industry showed Thursday. The ministry gathers data from LNG buyers in Japan to calculate a simple average, but it does not disclose delivery dates. Platts JKM spot price averaged $6.863/MMBtu in February, reflecting spot deals concluded for cargoes for March and April deliveries. The JKM gradually fell in February because of lack of demand and emerging supply. The ministry also said the February-delivered LNG spot price was $8.8/MMBtu in February, surging 20.5% from $7.3/MMBtu in January. The JKM for February-delivery cargoes averaged at $9.488/MMBtu. The February JKM started the assessment period at $9.2/MMBtu on December 16 and extended gains further before coming down to end the assessment period at $9.45/MMBtu on January 13.
LNG market at a ‘tipping point,’ CERAWeek speaker says -- If you are in LNG today, you want to be in Asia, the world’s biggest market for the power plant fuel. As much as there is opportunity, however, there also is uncertainty. The opportunity comes from the fact that the continent accounts for more than 70% of the world market for LNG. At the same time, concerns about oversupply due to significant new and expected output from the US and Australia have raised questions about how the renewal of long-term contracts will shake out as they expire by early next decade. The level of economic growth in China, the world’s most populous country, also is an uncertainty. That is forcing developers of proposed export projects in the US to be more cautious about moving forward with building their liquefaction terminals. If there is reason to be confident amid those dynamics, it is that virtually all of the new supply being produced now or planned for export facilities currently under construction is expected to be used up over the next five years, creating new demand around 2022. Also, new markets and buyers are emerging with different needs. “I’m confident we are at the tipping point,” said Hiroki Sato, chief fuel transactions officer at Jera, a Japanese firm established by Tokyo Electric and Chubu Electric that is the biggest individual buyer in the global LNG market. Speaking in Houston on Wednesday at the CERAWeek by IHS Markit energy conference, Sato said fragmentation of LNG buyers in Asia is helping to remove some uncertainties among producers, giving more weight to the opportunities that exist. Houston-based Cheniere became the first US exporter of LNG produced from shale gas when it launched its initial cargo in February 2016. It has ramped up output since then, operating two trains and commissioning a third. Two more trains are planned, and a sixth has been proposed and is awaiting commercial support before a final investment decision is made.
India sanctions ADNOC involvement in Mangalore strategic crude oil storage - India's cabinet has approved ties between Indian Strategic Petroleum Reserve Ltd and Abu Dhabi National Oil Company on crude storage, oil ministry officials said Tuesday. In January, state-owned ISPRL signed a major deal with ADNOC to establish a strategic crude oil storage in the southern city of Mangalore. The deal with ISPRL covers the storage of 5.86 million barrels of ADNOC crude oil at the underground facilities in Karnataka state, which can hold 11 million barrels of oil. "Out of the crude stored, some part will be used for commercial purpose of ADNOC, while a major part will be purely for strategic purpose," said a statement issued after a cabinet meeting on Monday.ISPRL has set up around 39 million barrels of strategic crude oil storage at three locations -- Padur and Mangalore on the west coast and Visakhapatnam on the east coast to meet India's exigency demand. The UAE is the fifth-largest supplier of crude oil to India, sending 15.7 million mt of crude to the country in the fiscal year 2015-16 (April-March), according to official data. India is 79% dependent on imports to meet its crude oil needs, 8% of which is supplied by the UAE. In 2016, Indian crude imports rose 9.6% year on year to 215.43 million mt, provisional data from the country's Petroleum Planning and Analysis Cell showed.
Analysis: India eyes Myanmar's oil, gas in pursuit of expanding beyond borders - Myanmar's dramatic growth in consumption of refined oil products and the inability of its aging refineries to meet that incremental demand have whetted the appetite of Indian oil companies to play a bigger role in the Southeast Asian nation's oil and gas sector -- from upstream to retail. Myanmar, one of the oldest oil and gas industries in the region and a country which exported its first crude oil centuries ago, is again emerging as a bright spot for overseas investors after sanctions, which were imposed on the country during a long period of military rule and political unrest, were lifted in 2012. To deepen ties, India's oil minister Dharmendra Pradhan led a delegation to Myanmar late February looking for opportunities to supply refined oil products to the country, as well as highlight the interest of Indian upstream companies to take part in the forthcoming bid round in Myanmar's oil and gas blocks. "They invited India to invest in all stream in oil and gas," Pradhan said in a message following the visit. Myanmar's demand for oil products has been steadily rising. But its production of oil and gas is expected to be more or less stagnant. While there have been some upgrades at the refineries in recent years through foreign assistance, including help from India, in the short term rising oil products demand is most likely to be met through higher imports.
Papua New Guinea Asks Energy Explorers: Can We Keep Some of Our Gas? --Less than three years after it began sending one of its most precious resources overseas, Papua New Guinea’s future may be determined by how much of it stays at home. The Pacific island nation wants some of the world’s top explorers to allow a portion of its natural gas to stay in the country, said Nixon Duban, the minister for the government’s petroleum and energy department. The fuel pumped from remote mountain ranges and forest-covered hills could spur industries, generate cheaper power for an electricity-starved population and even help catch tuna. But not at the cost of driving away drillers. “The challenge our government faces is finding the right balance,” Duban said. “We’re trying not to dictate against the energy industry.” Duban’s caution is understandable. The developing country of less than 8 million people is one of the poorest in Asia, with soaring crime rates, high unemployment, and almost half the population living in squatter settlements. It’s counting on energy resources to boost finances, and needs foreign investment. Its exports have led to some signs of prosperity, with Port Moresby turning home to a luxury hotel and a major mall as well as hosting international sporting events. Still, more sustained development will mean using some resources for itself. When the government signed deals almost nine years ago that led Exxon Mobil Corp. to build a liquefied natural gas terminal, it allowed the energy giant and its partners to export all of the gas it found. The project’s $19 billion price tag was more than the country’s annual gross domestic product. The LNG now lights the homes in metropolises including Tokyo, Beijing and Taipei.
Eni sells Exxon 25 pct stake in Mozambique gas field for $2.8 bln - Exxonmobil said on Thursday it had agreed to buy a 25 percent stake in the giant Mozambique gas field of Italian major Eni for about $2.8 billion. Eni, which is selling stakes in a number of fields to fund development of other projects, is currently the operator of Mozambique's Area 4 where it holds a 50 percent indirect stake held through Eni East Africa. The field holds about 85 trillion cubic feet of natural gas and is one of the world's largest gas discoveries in recent years. Under the deal Eni will continue to lead all upstream operations in the area, while ExxonMobil will be in charge of building the onshore liquefied natural (LNG) gas plants. The Italian major said it will remain in charge of building the floating LNG plant in the Coral field, which is part of Area 4. The area 4 project envisages the construction of onshore and offshore LNG plants to export the gas to areas such as India and Asia. In 2013 Eni sold 20 percent of its Area 4 stake to China's CNPC for $4.2 billion but since then oil and gas prices have come down sharply
Libya’s biggest oil port seized in blow to production surge: Libya’s biggest oil port was seized by an armed group, dealing a blow to the North African country as it seeks to revive production of its most important commodity. The Benghazi Defense Brigades, a militia that’s not allied to the United Nations-backed government in Tripoli, took control of the Es Sider terminal last week, according to people with knowledge of matter who asked not to be identified because they aren’t authorized to speak to the media. The facility had previously been under the control of eastern-based Gen. Khalifa Hifter. “That is a considerable blow to Hifter,” said Mattia Toalda, senior policy fellow at the European Council on Foreign Relations. “We have to see if there is an immediate impact on exports. But for confidence in Libya’s production it’s a blow.” The clashes show just how vulnerable Libya’s recent oil-production surge is to conflict that escalated in late 2014 but that had shown signs of calming in the past few months. The nation pumped about 700,000 barrels a day in February, almost doubling from a year ago, according to information compiled by Bloomberg. After sweeping through the oil crescent in September and taking control of the ports in the region, Gen. Hifter had allowed Libya’s National Oil Corp., part of the Tripoli-backed government that he opposes, to use Es Sider for oil exports. But production remains vulnerable without a lasting peace between the east and west of the country. International efforts to break the political stalemate have so far failed.
Analysis: Nigeria's recovery could end OPEC oil output cut exemption, Libya further away - When OPEC agreed to exempt Libya and Nigeria from its oil production cuts, market watchers said the two beleaguered countries' upside potential could complicate its attempt to accelerate the market's rebalancing. Both countries have ambitious aims to recover output following months of militant attacks on oil infrastructure that caused their production to plummet last year, as OPEC was negotiating the deal. But while Libya has seen a renewal of fighting that threatens to derail its recent fragile oil output recovery, Nigeria appears well on the way to full restoration of its output that could see it pressured by its fellow OPEC members to end its exemption from the production agreement. The six-month deal, which expires in June, will be up for review at OPEC's next meeting on May 25, with some ministers saying the production cuts should be extended to continue drawing down global inventories. "As things stand at present, potentially the new dynamic that will need to be resolved is if Nigeria's militant attacks die down, there will be a case to bring Nigeria into the quota system," said Richard Mallinson, geopolitical analyst with Energy Aspects. "That's unlikely to be something that Nigeria would welcome, but that would be a part of the negotiations." Nigeria oil officials could not be reached for comment, but oil minister Emmanuel Kachikwu, following the last OPEC meeting on November 30 when the production agreement was signed, acknowledged that a fully-recovered Nigeria likely would be asked to share in the cuts.
Peak Oil Exports - An oil export model has been developed based on BP Statistical Review 2016 oil production and oil consumption data. The model shows that global oil exports peaked in 2006 at 37.87 Mbpd. They have since fallen very slowly to stand at 37.07 Mbpd in 2015, the last year for which we have data. Exports have effectively been on a plateau since 2005. What this means is that much of the production growth seen in the exporting countries has been swallowed by consumption growth in these same countries. The impact of static oil exports on the global economy is for others to work out. Former readers of The Oil Drum will no doubt recall the Export Land Model (note that it even has its own Wiki page) that was introduced by Westexas (aka Jeffrey Brown) at a time when global oil production stubbornly refused to peak and decline as peak oilers expected it to do. Put simply, the export land model describes countries where rising domestic consumption, declining production or a combination of both results in a rapid decline in oil exports to the point where one time oil exporters evolve into oil importing nations. The poster child for the export land model was Indonesia, one time member of OPEC and major oil exporter, which watched exports evaporate as oil production went into decline while domestic oil consumption ballooned (Figure 1). Production peaked at 1.69 Mbpd in 1977 but only began to decline post-1991. But as population and prosperity rose, the production surplus turned to deficit in 2003 and by 2015, Indonesia imported 740,000 bpd. Should this be repeated in many of the oil exporting countries it must surely leave the oil importing countries gasping for breath.
The US Motorist Is Unwell: Miles Driven Suffer Biggest Slowdown In Over 2 Years - When trying to forecast the price of oil, it is becoming increasingly clear that the answer is not on the supply side at all but rather on the demand, where as we have been writing for the past month, things are getting quite troubling. While we urge readers to familiarize themselves with our recent coverage of collapsing gasoline demand to a level which according to a perplexed Goldman Sachs suggests the US economy should be in a recession... ... other troublesome indicators have emerged confirming that not all is well on the demand side. The latest evidence comes from a recent report by Deutsche Bank which shows that the number of miles driven in the US is not only slowing, but in December, it posted the smallest monthly increase since November 2013. As DB's Mike Baker writes, "we have hypothesized that the increase in gas prices could pressure miles driven, which as noted below slowed in 2016 versus 2015, and even more so towards the end of the year after the Thanksgiving inflection. The 0.5% increase in miles driven in December 2016 is the smallest monthly increase since November 2014. Gas prices inflected around Thanksgiving 2016 and are up year-on-year on a weekly basis over the last 15 weeks."While looking at the above chart of year-on-year change in monthly miles driven in 2016 versus the year-on-year change in average monthly gas prices, Baker notes an approximately (60%) correlation. He then notes that the concern is that gas prices were up only 14% year-on-year in December 2016. The reason why this is troubling is that while there is still no concurrent data, the national average price was approximately $2.23 per gallon as of February 27, 2017 and the price per gallon has increased more than 30% year-on-year over the last three weeks. In other words, if the deterioration in the trendline persists, it would imply that some time in January of February, we got the first negative print in miles driven in years, and would also explain the recent collapse in gasoline demand.
Hedge funds trim record bullish position in oil: Kemp (Reuters) - Hedge funds have trimmed their bullish position in crude oil by the largest amount since OPEC announced its decision to cut output in November.Hedge funds and other money managers cut their combined net long position in the three main Brent and WTI futures and options contracts by 61 million barrels in the week to Feb. 28.The reduction was the largest since the week ending Nov. 8, according to an analysis of positioning data published by regulators and exchanges (http://tmsnrt.rs/2msPIv4). But the decline comes after fund managers doubled their net long position from 425 million barrels on Nov. 8 to 951 million barrels on Feb. 21 (http://tmsnrt.rs/2meyam3). Even after the reduction in long positions and increase in shorts in the week ending on Feb. 28, the overall long position was still the third-highest ever. Hedge fund managers remain overwhelming bullish about the outlook for prices with long positions still outnumbering short positions by a ratio of nearly 8:1 (http://tmsnrt.rs/2megwP9). The accumulation of long positions may have helped accelerate the rise in Brent prices to $55 per barrel following the OPEC and non-OPEC accords in November and December.Oil prices have been closely correlated with the accumulation and liquidation of hedge fund positions since the start of 2015.Since Dec. 12, however, the rally has stalled, with no further rise in prices, despite an increase of 220 million barrels in the hedge funds' net long position since then.Commentators are divided over whether the large hedge fund long position in crude has become a crowded trade, and, if so, whether it signals a sharp reversal is imminent.Bullish hedge fund managers point to strong compliance by OPEC, renewed interest among investors in commodities as an asset class, a cyclical upswing, and the comparatively low level of oil prices. Fundamentals and positioning could both help push prices higher as oil stocks fall and institutional investors channel more money to specialised commodity hedge funds.
- U.S. crude oil production averaged an estimated 8.9 million barrels per day (b/d) in 2016. U.S crude oil production is forecast to average 9.2 million b/d in 2017 and 9.7 million b/d in 2018.
- Benchmark North Sea Brent crude oil spot prices averaged $55 per barrel (b) in February, largely unchanged from the average in January.
- EIA forecasts Brent crude oil prices to average $55/b in 2017 and $57/b in 2018. West Texas Intermediate (WTI) crude oil prices are expected to average about $1/b less than Brent prices in the forecast. NYMEX contract values for May 2017 delivery traded during the five-day period ending March 2 suggest that a range of $46/b to $63/b encompasses the market expectation for WTI prices in May 2017 at the 95% confidence level.
- Implied global petroleum and liquid fuels inventories increased by an estimated 0.5 million b/d in 2016. EIA expects a relatively balanced oil market in the next two years, with inventory builds averaging 0.1 million b/d in 2017 and 0.2 million b/d in 2018.
- U.S. monthly average regular gasoline retail prices are expected to increase from $2.30/gallon (gal) in February 2017 to $2.51/gal in July before falling to $2.24/gal by December. U.S. regular gasoline retail prices are forecast to average $2.40/gal in 2017 and $2.44/gal in 2018.
- U.S. dry natural gas production is forecast to average 73.7 billion cubic feet per day (Bcf/d) in 2017, a 1.4 Bcf/d increase from the 2016 level. This increase reverses a 2016 production decline, the first annual decline since 2005. Natural gas production in 2018 is forecast to rise by an average of 4.1 Bcf/d from the 2017 level.
- In February, the average Henry Hub natural gas spot price fell by 45 cents per million British thermal units (MMBtu) from the January levels to $2.85/MMBtu. Unseasonably warm temperatures in the Lower 48 states contributed to lower prices.
- New natural gas export capabilities and growing domestic natural gas consumption contribute to the forecast Henry Hub natural gas spot price rising from an average of $3.03/MMBtu in 2017 to $3.45/MMBtu in 2018. NYMEX contract values for May 2017 delivery traded during the five-day period ending March 2 suggest that a range of $2.15/MMBtu to $3.82/MMBtu encompasses the market expectation for Henry Hub natural gas prices in May 2017 at the 95% confidence level.
Oil majors reverse decade of stalled growth to beat supply crunch fears | Reuters: Oil majors have long been passive watchers of the pump war between OPEC and U.S. shale producers, but not any more. Majors were unable to grow output for the past decade even as oil prices soared above $100 per barrel due bad capital discipline and huge project delays. The oil price slump since 2014 has prompted the world's biggest oil firms to drastically cut costs but also to force contractors to make projects more efficient and extract the same amount of barrels for fewer dollars. As a result, most majors are now planning exceptionally strong production growth until at least 2021, a Reuters analysis of the latest investor presentation and corporate plans showed. Even as prices hold near $50 per barrel, the firms - Royal Dutch Shell, Exxon Mobil, Chevron Corp, BP Plc, Total, Statoil and Eni SpA - plan to grow output by a combined 15 percent in the next five years. "This environment requires discipline on costs and strong operating performance. It will reward businesses that can remain highly competitive at these prices," BP's chief Bob Dudley said at the London-based company's strategy day last week. The seven companies will add almost 3 million barrels per day to their combined output in the next five years effectively generating production the size of another major like Chevron.
U.S. oil output poses awkward forecasting problem for OPEC: Kemp - (Reuters) - U.S. oil drilling activity has surged but so far the impact on production has been limited because of the long delay in completing wells and reporting output. The number of rigs drilling for oil has almost doubled since hitting a cyclical low at the end of May and is up by more than 50 percent compared with a year ago, according to oilfield services company Baker Hughes.But output of crude and condensates has risen less than five percent since May and is still below the level at the corresponding point last year, according to data from the U.S. Energy Information Administration. But the increase in drilling should eventually show up in a significant rise in production, most likely with a delay of 9 months or more (http://tmsnrt.rs/2maNQ81). In most cases, decisions about drilling programmes are based on the level and change in oil prices over the previous 2-3 months.From the moment a decision is made to drill an additional well, there can be a delay of 1-2 months before rig arrives on location while contracts are placed and the rig is moved.Rigging up, actually drilling the well and then removing all the equipment from the site can easily take another month.The arrival of the fracturing crew and other well completion services usually results in a further delay of 2-3 months.So the well could start producing 4-6 months after the initial decision is taken provided there are no unusual problems.But production records are published for full calendar months and output for the first month is likely to be for a fraction of the full 30-31 days; full production will not be recorded until the second month.There will be a further delay before output is reported to regulators and a final delay before regulators publish aggregated numbers.Given all these delays, the full impact of a decision to increase production is unlikely to show up in the official production data for 9 months or more, and is based on prices that are up to a year old.Output reported now is the result of decisions taken in June 2016 or even earlier. More recent decisions taken in the autumn of 2016 and early 2017 will not show up in output until later.The big increase in drilling reported in the second half of 2016 and the first two months of 2017 will not show up in output until the second half of 2017.
OPEC Woos Old Nemesis—Wall Street -- The Organization of the Petroleum Exporting Countries is on an unusual listening tour, in which it exchanges views with hedge funds, investment banks and other big financial players while trying to figure out how the market reacts to its moves. The private meetings with oil traders and money managers in London and New York, along with a planned gathering this week at a conference in Houston, are a departure for OPEC. The cartel's leaders have long derided oil-futures-contract traders as "speculators" who cause unnecessary volatility in crude prices. Now, OPEC and its most powerful member, Saudi Arabia, are wooing traders, trying to convince the market they are serious about raising oil prices with a nearly 5% production cut agreed to in 2016. The oil producers are also trying to understand how traders and banks make decisions. The gatherings began in Vienna just before the Nov. 30 decision to cut production. A Saudi OPEC official sounded out the effects of a potential cut with French oil trader Pierre Andurand, Lukoil traders and Mark Couling of Vitol Group, according to people familiar with the meetings. Mr. Andurand and Vitol have declined to comment, while Lukoil didn't respond to requests for comment. Since the output-cut deal, OPEC Secretary General Mohammad Barkindo has met with a series of hedge funds and oil buyers. Among them: BBL Commodities Value Fund, a $540 million investment vehicle run by ex- Goldman Sachs trader Jonathan Goldberg; Ospraie Management, headed by veteran commodities investor Dwight Anderson; Taylor Woods Capital which is managed by former Credit Suisse trader Beau Taylor; and EasyJet, the U.K. budget airline that buys and sells oil-market derivatives to hedge against fuel-price rises.
Why OPEC Is Colluding With Hedge Funds --Something unprecedented happened last November when OPEC sat down in Vienna to hammer out the final terms of its oil production cut deal (which, incidentally, has yet to translate into a drop of all time high inventories): one day before the summit, the oil producing cartel - or rather Saudi Arabia - secretly invited hedge funds to sit in on the negotiations and provide OPEC, with input on what to do. However, news of the meeting leaked shortly thereafter, and was reported by the FT: "Saudi Arabia convened private talks with the world’s largest oil traders in Vienna before OPEC’s crunch meeting on whether to cut oil output, seeking views about the likely market reaction should they fail to clinch a deal, it has emerged. Mark Couling, head of crude oil at Vitol, the world’s biggest independent oil trading company, was invited to Vienna by the Saudi delegation, according to people with knowledge of the talks. Pierre Andurand, who runs the $1.5bn Andurand Capital fund, one of the world’s biggest oil hedge funds, was also invited, alongside at least one trader from Russian independent oil company, Lukoil. Why this overture by the Saudis to invite and give traders responsible for shipping millions of barrels of oil and trading billions in crude derivative a potential first look? As the FT explained at the time, "Saudi delegates have previously done so on occasion when they were looking to get a better feel for the market." It is now four months later, oil is modestly higher, but not too high, and conversation has recently shifted away from OPEC's favorite topic: production cuts, to something far less enjoyable: surging shale production which threatens to take away market share from the Saudis and OPEC, and whether or not OPEC will extend the production cut deal beyond the first half of the year. It also appears that the OPEC is once again nervous, because as the WSJ reports, the "Organization of the Petroleum Exporting Countries is on an unusual listening tour, in which it exchanges views with hedge funds, investment banks and other big financial players while trying to figure out how the market reacts to its moves."
Oil Bulls Concerned By Russia's Failure To Cut Production -- If record US crude and gasoline inventories (and soaring US production) were not big enough concerns, oil bulls are starting to lose faith (hedge fund shorts at 12-week highs) afterlower growth targets in China and concerns over Russia's compliance with a global deal to cut oil output sparked renewed worries over a crude oil supply glut. Reuters notes that China on Monday lowered its growth target for the year to 6.5 percent, compared with 6.7 percent last year, and also tightened regulatory controls in an effort to tackle pollution. Investors are watching the moves carefully for signs they could dampen demand for oil. Meanwhile, figures from Russia's energy ministry released last week showed February oil output was unchanged from January at 11.11 million barrels per day (bpd), casting doubt on its moves to rein in output as part of a pact with oil producers last year. Commerzank noted that Russia's production would need to fall by a further 100,000 bpd in March in order to comply with the agreement. And while prices are rebounding modestly today (as the machines buy the dip again), the recent trend is clear. The China demand, Russia supply concerns outweighed news of escalating violence in North Africa that sparked questions about oil exports from the region and prompted a small price rebound on Friday.
Russia to achieve 300,000 b/d in agreed cut by end April: minister - Russia will achieve by late April the 300,000 b/d cut it agreed to in the coordinated supply cut agreement reached with OPEC and 11 non-OPEC countries last year, Russian energy minister Alexander Novak told reporters Monday at IHS CERAWeek. Novak said Russia is currently meeting 50% of its supply cut commitment and will likely have cut 200,000 b/d by the end of March. Under the deal, OPEC in November agreed to cut 1.2 million b/d from its October levels while 11 non-OPEC countries led by Russia agreed to cut an additional 558,000 b/d. Novak said it remains unclear if the supply cut deal will be extended beyond June, a decision he said likely will not be made until shortly before the current deal is set to expire."It's a bit premature to talk about it right now," Novak said through a translator. "We just need to wait a little bit and see what will happen." He said Russia and other parties to the agreement will base their decision on extending the agreement based on a variety of factors, including supply and demand and price volatility. OPEC in February moved closer to full compliance with the landmark production cut agreement signed late last year, as output in the month fell from January levels to average 32.03 million b/d, according to an S&P Global Platts survey released Monday. In all, taking an average of January and February production, the 10 members obligated to reduce output under the deal have achieved 98.5% of their total combined cuts, according to the survey, up from 91% in January. Novak dodged a question Monday on whether the Trump administration was likely to lift sanctions against Russia and said that Russia was not interested in joining OPEC.
Oil Majors To Boost Production As IEA Warns Of Supply Deficit | OilPrice.com: The IEA issued a new report at the CERAWeek conference that looks at the oil market over the next five years, and the agency warned that although shale drilling is coming back and the market is currently oversupplied, relentless demand growth will soak up all the excess. By the early 2020s, the market could be short of supply, resulting in a price spike. The IEA says the draconian cuts to exploration spending over the past three years will result in too few barrels coming online in the five-year timeframe. OPEC will be stretched to its limits as demand soars. Russia’s energy minister Alexander Novak said that Russian oil production will drop by 300,000 bpd by late April, which will allow Russia to comply with the cuts it promised as part of the OPEC deal. Together with Russia, other non-OPEC countries pledged to reduce output by 558,000 bpd. Russia’s compliance will further boost confidence in the deal. A Reuters analysis finds that the largest oil companies in the world are planning on ramping up production over the next five years, after three years of contraction. Together, ExxonMobil (NYSE: XOM), Royal Dutch Shell (NYSE: RDS.A), Chevron (NYSE: CVX), BP (NYSE: BP), Total (NYSE: TOT), Statoil (NYSE: STO) and Eni (NYSE: E), will grow output by a combined 15 percent by 2021. Argentina’s state-run YPF (NYSE: YPF) said that drilling in Argentina’s shale is getting more cost effective. At the CERAWeek conference, YPF CEO Miguel Gutierrez said horizontal drilling costs have declined by half, falling from $17 million per well to just $8 million – still above U.S. shale drilling costs but rapidly converging towards parity. Also, the time it takes to drill a new well fell from 40 days to just 15 days. As a result, breakeven costs have dipped below $40 per barrel, making Argentina one of the most attractive places for shale drilling outside of North America.
Saudi cuts to lighter crude prices show shifting oil market: Russell | Reuters: A decision by Saudi Aramco to cut the price of its benchmark Arab Light crude to Asian refiners for April-delivery cargoes has prompted speculation that the world's top oil exporter is chasing market share. There is always a risk in over-interpreting moves in Aramco's official selling prices (OSPs), and trying to fit them into a narrative that supports a particular view of the state of the market. Perhaps a better approach is to look at whether the move in the OSP goes beyond what might be justified by changes in the market structure for crude oil in Asia, the region that buys about two-thirds of Saudi oil. First, the facts. Aramco cut the OSP for Arab Light for Asia to a discount of 15 cents a barrel over the Oman-Dubai benchmark for April cargoes from a premium of 15 cents the prior month. The effective 30 cents a barrel reduction came against a backdrop of a weakening premium for Dubai crude over global benchmark Brent and softer margins for key oil products in Asia, such as gasoline, naphtha and to a lesser extent, diesel. The Brent-Dubai exchange for swaps DUB-EFS-1M, a measure of the premium of Brent over the Middle East grade, dropped to $1.08 a barrel on Feb. 28, the lowest in 18 months. The profit of making a barrel of gasoline in Singapore GL92-SIN-CRK, known as the crack, has almost halved in just under a month, dropping to $7.30 a barrel on Monday, down from a recent peak of $13.16 on Feb. 2. The same measure for gasoil, the base product for diesel, was at $11.66 a barrel on Monday, down from $12.66 on Feb. 23.
Saudi Aramco expects OPEC crude oil output cut to be absorbed in spot LPG supplies - Saudi Aramco expects to see some impact on Saudi Arabia's LPG production from the OPEC crude output cut deal but it anticipates this will be absorbed in its spot supplies, a Saudi Aramco official said Tuesday. Speaking at the International LP Gas Seminar 2017 in Tokyo, Ali Alam, marketing coordinator of LPG sales and marketing, said Aramco expects Saudi Arabia's LPG production will probably fall as a result of the OPEC deal. But Alam said it is hard to determine the degree of LPG production cut because "Saudi LPG has so many variables" in its production associated with different crudes."We, Saudi Aramco, anticipate the [OPEC] cut to actually be on the spot side rather than the term side because this is part of our customer care," Alam said. Saudi Aramco had not offered any spot cargoes since January, a cutback from its previous spot offerings of about two cargoes per month in the fourth quarter, market sources said. Each cargo is 44,000 mt. OPEC on November 30 agreed to cut production by around 1.2 million b/d to 32.5 million b/d from January 1. This was followed by a commitment from 11 non-OPEC producers on December 10 to cut production by a combined 558,000 b/d also from January 1.
Extension of OPEC/non-OPEC crude output cut to be considered in May -- Saudi energy minister Khalid Al-Falih said Tuesday that an extension of the six-month OPEC/non-OPEC agreement to cut crude output will not be considered until May and will be based on levels of both conformity to the deal by participating countries and on global inventories. At a brief news conference at CERAWeek by IHS Markit in Houston, Falih and ministers from Russia, Iraq, Mexico and OPEC Secretary General Barkindo said that 1.5 million b/d have already been withdrawn from the global market as a result of the deal. Falih said he held the news conference to address concerns he heard in meetings at CERAWeek that the supply cut agreement could be undermined by the growth of US shale oil output. "This is a big market," Falih said, pointing to demand growth which could absorb the expected increase in US production. Russian energy minister Alexander Novak said that conformity with the deal has, thus far, been "satisfactory" and said the deal has had a "positive impact" on the market. Novak said his meetings with ministers and others at the conference had been focused on conformity levels, the possibility of an extension and the response from US shale to the deal. Barkindo said OPEC was intensifying its monitoring of commercial stocks, but declined to offer specifics on where that level would be in order for the deal to be extended. "We are closely monitoring this trend and it will be magnified in months to come," Barkindo said
Saudi energy minister says oil market fundamentals improving | Reuters: Saudi Energy Minister Khalid al-Falih said on Tuesday that oil market fundamentals were improving after an agreement struck with top oil producers to curb supply and end a two-year glut took effect. The kingdom led a pact between the Organization of the Petroleum Exporting Countries and other major producers, including Russia, Mexico and Kazakhstan, to cut global crude output by about 1.8 million barrels per day (bpd) from Jan. 1, and bring supply closer to demand. Saudi Arabia had cut beyond what it had pledged in the agreement and brought the kingdom's output below 10 million bpd, he said. Suppliers participating in the curbs have cut more than 1.5 million bpd, he said, exceeding what he called the market's low expectations. Global oil demand would grow by 1.5 million bpd in 2017, and increased output from the United States, Brazil and Canada would be more than offset by natural declines in aging fields, he said. "There is... cause for cautious optimism as we see the 'green shoots' of the recovery," Falih told energy executives and oil officials gathered at the CERAWeek industry conference in the U.S. energy capital of Houston. Benchmark Brent crude futures closed at $55.92 a barrel on Tuesday, and are up more than 10 percent since the output curb deal was struck in November. Still, he cautioned against any "irrational exuberance" among investors. "We should not get ahead of the market," he said.
Oil little changed as growing U.S. output offsets bullish Saudi comments | Reuters: Oil prices ended little changed on Tuesday, as growing U.S. production expectations offset earlier gains after Saudi Arabia's oil minister said market fundamentals were improving. The market, meanwhile, braced for U.S. crude inventory data later Tuesday that is forecast to show a 1.9 million-barrel build for last week, the ninth straight weekly increase in stocks that are already at record highs. [EIA/S] At the CERAWeek energy conference in Houston, Saudi Oil Minister Khalid Al-Falih said last year's agreement by OPEC and non-OPEC countries to curb supplies and boost prices has improved oil market supply and demand fundamentals. But Falih said that happened only because Saudi Arabia cut beyond what it pledged, bringing the kingdom's output below 10 million barrels per day (bpd). He also said the Organization for the Petroleum Exporting Countries (OPEC) would not let rival producers take advantage of the cuts to underwrite their own production investments. The group is expected to meet again in May, when it could consider extending the production cuts. Brent futures slipped nine cents, or 0.2 percent, to settle at $55.92 a barrel, while U.S. West Texas Intermediate (WTI) crude lost six cents, or 0.1 percent, to settle at $53.14. Oil prices have been stuck in a $3 band since February, failing to take off after OPEC implemented, to a surprisingly high degree, the first production cut in eight years.
WTI Dips (But RBOB Rips) As Crude Inventories Surge More Than Expected -- Despite the desperate jawboning of the Saudis and OPEC today - trying to tell everyone to ignore Russia - crude ended the day at its lows, testing towards $52 handle. When API reported a much bigger than expected crude build, WTI prices tumbled. RBOB prices surged though as Gasoline inventories drewdown by the most since April 2014. API
- Crude +11.6mm (+1.4mm exp)
- Cushing +788k
- Gasoline -5.00mm
- Distillates -2.9mm
With Crude and Gasoline inventories already at or near record highs, this week's massive Crude build is the 9th weekly build in a row. The Gasoline draw was the biggest since April 2014...
Fitch Predicts Drop In Oil Prices By 2017 As U.S. Shale Output Soars - Oil bigwigs should take a step back before becoming too comfortable with the new oil price range according to Fitch Ratings’ newest market analysis.“The recovery in US drilling activity will drive up shale oil production in the second half of 2017, offsetting a portion of recent oil price gains,” the credit rating agency’s report released on Monday says. “We therefore expect average oil prices for the year to be below those in January and February.”In a stable market scenario, Fitch estimates that by the end of this year, oil prices will fall to $52.50, but then rebound to $55 and then $60 in 2018 and 2019, respectively. Long-term prospects for Brent barrels sit at $65 in this model.A stressed, oversupplied market will mean a $40 barrel through 2019, however.Since January, a 1.8 million-barrel global production cut led by the Organization of Petroleum Exporting Countries (OPEC) and joined by several other nations has kept prices between the $55-$60 range.Compliance to the terms of the November deal by members of the bloc has been strong. Last week, new data showed that OPEC’s compliance stood at 94 percent.But non-OPEC enthusiasm for the deal has been much talk, with moderate action. A February 23rd report puts compliance by the 11 NOPEC nations at a modest 60-66 percent. Fitch cited the continuous increase of active oil rigs in the United States since May 2016 as key evidence for an impending price collapse. American production is set to top nine million barrels over the course of 2017, the analysts estimate, due to rejuvenated capital expenditure budgets and higher output capacity.
WTI/RBOB Surge After Massive Gasoline Draw (Despite Record Crude Glut) -- Following API's reported massive build in crude (and draw in gasoline), DOE confirmed the extreme moves with a major 8.2mm crude build and a massive 6.56mm draw in gasoline (the biggest since April 2011). US Crude production rose once again - to 13-month-highs. DOE
- Crude +8.21mm (+2mm exp)
- Cushing +867k (+406k exp)
- Gasoline -6.56mm (-1.99mm exp)
- Distillates -925k (-1mm exp)
This is the 9th weekly rise in crude inventories (some chatter on API data including SPR barrels but that was marginal at best compared to the headline print)...The gasoline draw is the biggest since April 2011
Market alert: US oil price plunges toward $50 as a perfect storm brews: Oil is on track to break through the key psychological level of $50 a barrel after a ninth straight rise in U.S. crude stockpiles came at exactly the wrong moment, analysts said Wednesday. The amount of crude oil in U.S. storage rose to another record high on Wednesday, jumping 8.2 million barrels from the previous week, the Energy Information Administration reported. The increase was more than four times what analysts expected. Weekly figures also showed U.S. oil production continuing to tick up toward 9.1 million barrels a day, the highest level in more than a year. That provided further evidence that rising American output is confounding efforts by the Organization of the Petroleum Exporting Countries, Russia and 10 other exporters to reduce global oil inventories by curbing their own output.The data sent U.S. benchmark West Texas Intermediate crude prices plunging more than 5 percent to a nearly three-month low. The plunge through a number of lows on Wednesday puts oil on a path to test the December low of $49.95 a barrel, said John Kilduff, founding partner at energy hedge fund Again Capital. "From there you could accelerate," he told CNBC, adding that $50 "was the fail-safe." Kilduff's downside target, once oil breaks below $50 a barrel, is $42. For the last three months, oil has traded in a range between $49.61 and $55.24.
Oil Tanks To $51 Handle - One-Month Lows -- It seems ever-exuberant energy traders are finally waking up to the reality that the global rebalance is not happening. A record glut of crude and surging production has sent WTI back to a $51 handle this morning (one-month lows) and has weighed on gasoline prices... WTI has broken below its 100-day moving average as the machines ran overnight stops and then plunged after the DOE data...“Inventory drawdown slower than I thought after cuts,” Saudi Arabia's Khalid Al-Falih admits. Bloomberg's Vince Piazza warns U.S. inventories across the product value chain remain elevated, with crude oil 39% above the five- year average and distillates, jet fuel and gasoline between 5.5% and 22% higher. This, along with the 51% rebound in rig count since last year, and the robust level of more than 5,300 DUCs (drilled yet uncompleted wells) implies the near-term return of U.S. hydrocarbon volume with an environment of lower range-bound prices.
Crude Is Crashing --WTI Crude is suffering its biggest down day since September 2015 - crashing over 5% to a $50 handle and the lowest levels since 2016...WTI and RBOB are plunging after an initial post-DOE bounce... April WTI just tested to $50.05...As Bloomberg notes, net long commitment of traders shows WTI and Brent positioning is “well over-extended” and could spark liquidation of long positions as prices have remained range-bound for a couple months now, Scotia’s energy commodity strategist Michael Loewen writes in note, citing CFTC data.Market could get worse before improving as traders reduce holdings by selling WTI and Brent contracts into front-end of the curve.WTI has ripped through the 50-, 100-, and 200-day moving averages... Additionally, this is the worst day for USO (Oil ETF) since October, with about 220k puts on the U.S. Oil Fund (USO) changed hands, compared with a 20-day average of 47k and 57k calls traded today.
Oil prices drop over 5% to end at 2016 low - Oil futures sank by more than 5% Wednesday to post the lowest finish of the year after U.S. government data revealed a weekly jump in crude supplies that lifted total inventories to another record. The plunge came even as representatives from the Organization of the Petroleum Exporting Countries this week touted high compliance among the output-cut agreement participants since the start of the year. OPEC Secretary-General Mohammed Barkindo said Tuesday, at a conference in Houston, that the commitment among output cut pact countries “remains high.” But in U.S., which isn’t part of the pact, the latest data revealed that crude production last week reached a more than one-year high.April West Texas Intermediate crude fell $2.86, or 5.4%, to settle at $50.28 a barrel on the New York Mercantile Exchange and May Brent crude on London’s ICE Futures exchange fell $2.81, or 5%, to $53.11 a barrel. Both marked their lowest settlement since Dec. 7, according to FactSet. The sharp drop in crude futures put pressure on the Dow Jones Industrial Average DJIA, -0.33% and the S&P 500 index SPX, -0.23% with the energy sector posting the steepest decline of the broad-market benchmark’s 11 sectors. The U.S. Energy Information Administration Wednesday reported an 8.2 million-barrel climb in domestic crude supplies for last week, lifting total commercial inventories to a record weekly level of 528.4 million. The weekly climb was the ninth in a row. Expectations for a large rise in the official data rose after data Tuesday from the American Petroleum Institute showed that domestic crude inventories rose by a whopping 11.6 million barrels in the latest week. Analysts polled by S&P Global Platts had forecast an inventory increase of 1.6 million barrels. “This report runs the gamut in terms of extremes, with a huge 8.2 million barrel build to crude stocks tilted bearish, large draws to the products distinctly bullish,”
OPEC Panics, Warns US Shale Not To "Assume" Production Cut Extension -- All it took for OPEC to panic, was the sharpest drop in oil prices since last summer, sending WTI not only back under $50, but also wiping out all gains since the November Vienna "supply cut" deal. With the cartel suddenly finding itself in unfamiliar territory, where neither the daily barrage of "flashing red headlines" sparks a headline-scanning algo buying frenzy, nor the alleged production cuts leading to a reduction in inventory (quite the contrary, US commercial stocks just hit a new all time high) OPEC had no choice but to make a threat to its biggest competitor: US shale companies.According to Reuters, Saudi energy officials told top independent U.S. oil firms in a closed-door meeting this week that they should not assume OPEC would extend output curbs to offset rising production from U.S. shale fields. The reason for Saudi ire is simple: it is producing less, having shouldered the bulk of OPEC cuts, and yet with prices once again declining, and US shale producers ramping up production, not only are Saudis pocketing less revenue, but they are also are permanently giving up market share to US producers whose production in recent months has soared, especially in the Permian, where breakeven costs are as low as $30 for some producers.
U.S. Shale Kills Off The Oil Price Rally - Oil prices plunged on Wednesday and Thursday, dropping to their lowest levels since December when the optimism surrounding the OPEC deal was just getting underway. WTI dipped below $50 for the first time in 2017 on March 9, a two-day loss of more than 8 percent. The catalyst for the sudden decline in prices was yet another remarkably bearish report from the EIA, which showed an uptick in crude oil inventories by 8.2 million barrels last week. That takes crude stocks to another record high, and it was the ninth consecutive week of inventory builds.Up until now, oil speculators have taken the unusual increase in crude inventories in stride. Instead of paring back their long positions, hedge funds and other money managers doubled down over the past two months, putting more money into bullish bets, hoping that the OPEC production cuts would outweigh the comeback in U.S. shale.The result was a shocking level of bullish bets on WTI and Brent, creating a lop-sided position in the futures market. That is not necessarily a problem if market conditions are tightening, as many investors believed, but it begins to look unbalanced if in fact the oil market is still oversupplied.The pace of adjustment in the physical market for crude oil is starting to drag on, and investors are getting anxious. With so many investors having staked out bullish bets, oil prices are exposed to sharp and sudden corrections if they unwind those positions. And that may be starting to occur. It was just a matter of time before sentiment shifted, and another week of enormous crude inventory builds might have been a too much to stomach. “When you look at a very visible marker like the weekly U.S. inventories and you see that crude stocks are still rising, then some of these market participants may begin losing a bit of faith in the effectiveness of producer restraint,”
Race to Bottom on Costs May Cause Oil to Choke on Supplies - When companies can lower the price at which they break-even, it means they can approve more projects and produce more oil, keeping dividends safe and investors happy. The risk: By drilling up their share price, they can also end up drilling down the price of oil. Welcome to 2017, the year after a two-year market rout made companies more efficient. At the CERAWeek by IHS Markit conference this week, fears of too much supply were palpable. "Everyone is driving break-even prices down," Deborah Byers, head of U.S. oil and gas at consultants Ernst & Young LLP in Houston, said in an interview at the meeting, the largest annual gathering of industry executives in the world. "It isn’t just shale companies; it’s everyone, from deep-water to conventional." As the conference was ongoing, those fears took physical form as West Texas Intermediate, the U.S. crude benchmark, plunged 9.1 percent this week, closing below the key $50-a-barrel level for the first time this year. It settled at $48.49 on Friday. The slump came as Scott Sheffield, chairman of Pioneer Natural Resources Co., said prices could fall to $40 if OPEC doesn’t extend its existing agreement to cut production. Shale billionaire Harold Hamm, the CEO of Continental Resources Inc., warned undisciplined growth could "kill" the oil market.The buzzword was efficiency. In panel discussions and keynote speeches, executive after executive tried to outdo rivals in announcing their low break-even prices. Eldar Saetre, head of the Norwegian oil giant Statoil ASA, told delegates that break even for his company’s next generation of projects had fallen from $70-plus to "well below" $30 a barrel."The downturn has been long and painful, but has presented the industry with a unique opportunity to strengthen ourselves," Saetre said. From Patrick Pouyanne of Total SA to Darren Woods of Exxon Mobil Corp., almost every executive commented on the lower break-evens. For some new projects tying back to existing facilities, executives said they could avoid losses even at $12 a barrel. According to Rystad Energy, a Norway-based industry consultant, the well-head break-even costs for U.S. shale plays declined 46 percent between 2014 and 2016.
Oil drops to lowest since OPEC deal, U.S. crude below $50/bbl | Reuters: Oil fell about 2 percent on Thursday in heavy trade, extending the previous session's slump to prices not seen since an OPEC-led pact to cut production was agreed, as record U.S. crude inventories fed doubts about the effectiveness of the deal to curb a global glut. U.S. crude prices fell through the $50 a barrel support level, with market participants unwinding some of the massive number of bullish wagers they had amassed after the deal. The losses followed Wednesday's slide of more than 5 percent, the steepest in a year, after data showed crude stocks in the United States, the world's top oil consumer, swelled by 8.2 million barrels last week to a record 528.4 million barrels. [EIA/S] But several analysts remained bullish on oil for the long term. "Headline risk can capture the imagination of the market over the near term, but we see dips as short-lived, key buying opportunities," RBC analysts said in a note. "Record high inventory levels are reason for pause, but we believe that the market is overly focused on U.S. stocks ... The U.S. will be the last of the major regions to rebalance stocks given that storage capacity remains abundant, cheap and U.S. shale is extremely elastic in a $50-per-barrel price environment." Brent crude settled 92 cents, or 1.7 percent, lower at $52.19 a barrel. On Wednesday, the benchmark slumped 5 percent, its biggest daily percentage move in a year. U.S. West Texas Intermediate crude (WTI) extended Wednesday's 5.4 percent losses by 2 percent, or $1, to end at $49.28 a barrel, the first time below the $50-mark since mid December.
Saudis tell U.S. oil: OPEC won't extend cuts to offset shale - sources | Reuters: Senior Saudi energy officials told top independent U.S. oil firms in a closed-door meeting this week that they should not assume OPEC would extend output curbs to offset rising production from U.S. shale fields, two industry sources told Reuters on Thursday. Oil producers led by Saudi Arabia and top non-OPEC exporter Russia are in an uneasy truce with U.S. shale firms after a two-year price war that sent many shale producers to the wall. The Saudis and Russia led a deal to curb output in late 2016 to end a global supply glut that pushed oil prices to a 12-year low. The resulting rise in oil prices has sparked a rush of new output by shale producers, who this week outlined ambitious production growth plans across the United States. Speaking at an industry conference in the U.S. energy capital of Houston on Tuesday, Saudi Arabia's Energy Minister Khalid al-Falih said that there would be no "free rides" for U.S. shale producers benefiting from the upturn. Falih's senior advisors went a step further at the meeting on Tuesday evening with executives from Anadarko, ConocoPhillips, Occidental Petroleum Corp, Pioneer Natural Resources, Newfield Exploration and EOG Resources. "One of the advisors said that OPEC would not take the hit for the rise in U.S. shale production," a U.S. executive who was at the meeting told Reuters. "He said we and other shale producers should not automatically assume OPEC will extend the cuts." The Saudis called the meeting to exchange views on the market and to gauge the outlook for shale output, both sources said. Both sources spoke about the meeting on condition of anonymity due to the sensitivity of the matter.
Saudi Oil Rations Signal Sweet U.S. Threat as Sour Crude Cut - Saudi Arabia is handing customers in the world’s biggest oil market sweet treats while limiting sour supplies. The producer cut volumes of its Arab Medium and Arab Heavy crude for April sales to at least two North Asian refiners, according to people with knowledge of the matter. It instead gave the buyers more of the Arab Light and Arab Extra Light varieties to compensate, said the people, who asked not to be identified because the information is confidential. One other buyer in the region received cuts in volumes for all grades it sought. Saudi Arabian Oil Co. also gave full volumes of contractual supplies to two other North Asian refiners, which mostly buy lighter “sweet” crudes that typically have less sulfur and are easier to process than heavier “sour” oils. Processors in South Asia and Southeast Asia got all the oil they asked for in April. The state-run producer known as Saudi Aramco didn’t respond to an email seeking comment sent to its press office in Dhahran outside regular business hours. The strategy to offer more of its light crudes to customers reflects its pricing for supplies. While sweet crudes are typically costlier than sour oils, Aramco’s April official selling prices show the premium of one of its lightest grades to its heaviest has shrunk to the smallest since July 2015. That’s as it seeks to defend the market share of its less sulfurous varieties at a time when similar-quality crudes are rushing to Asia from the Americas, Europe and Africa. The increased supply of light crude along with lower pricing for the oils is Saudi Arabia’s latest effort to ward off rivals in Asia while leading output cuts as part of a deal between OPEC and other nations to erode a global glut. In January, people with knowledge of the matter said it’s continuing to pump lighter oil while fulfilling its promise to cut output by focusing curbs on medium and heavy varieties.’
Is The Oil Price Plunge A Turning Point? – Berman -WTI futures fell $2.86 from $53.14 to $50.28 per barrel, and Brent futures dropped $3.81 from $55.92 to $52.11 per barrel. WTI is trading below $49 and Brent below $52 per barrel at the time of writing. The apparent cause was a larger-than-expected 8.2 million-barrel (mmb) addition to U.S. crude oil inventories. Based on history, we can see that this was an over-reaction. WTI has fallen below the $50 to $55 per barrel range in which oil futures have traded for the last 3 months (Figure 1). An 8.2 mmb addition to crude oil storage is actually fairly normal during the annual re-stocking season that we are in now (Figure 2). Inventories increased 10.4 mmb during this week in 2016 and the 5-year average for this date is 5.3 mmb. The fact that inventories have been in record territory since the beginning of 2015 has not kept oil futures from going through several rallies or from trading near $55 per barrel since November. The 13.8 mmb addition to storage a month ago was larger than yesterday’s amount yet prices barely responded. Comparative inventory–the crucial price indicator-only moved up 2.4 mmb (Figure 3). That is because we are in the re-stocking season and compared with previous years, this addition to storage is not that big. Other key measures of gasoline and diesel volumes fell by more than 1 mmb each. And there was some very good news this week that the markets ignored. EIA’s Short-Term Energy Outlook (STEO) showed that the global market balance (production minus consumption) moved to a deficit last month. The world consumed almost a million barrels more than it produced in February (Figure 4). This is a one-month data point and should not be seen as a trend. Still, it is a positive sign that seems to have been overwhelmed by an otherwise normal addition to U.S. storage.
Tumbling Oil Launches Record Options Trading As "800 Million Barrels" Change Hands --With oil's recent somnolent, low-vol levitation at their back, the number of hedge funds and other speculators who were soothed by the gradual move higher and betting on the success of OPEC reflationary strategy, had recently grown to an all time high, as seen in the chart below showing the number of long net-spec positions in the combined oil futures market. So when the price of oil unexpectedly tumbled on Wednesday, then continued to slide over the next two days, many were wondering if this sharp reversal in prices would unleash a margin-call driven liquidation scramble. For now, while the selling has persisted, it has been largely orderly and no major "flushes" lower have been observed following the sharp move on Wednesday. Furthermore, until we get the latest CFTC data later on Friday it will be impossible to determine if the record long overhang had dropped (or perhaps increased further), however what we do know is that according to ICE and CME data, a record number of options contracts traded on Thursday, as Bloomberg reports. The total includes contracts referencing Brent and WTI, and also shows a surge in bullish bets that the former will reach $70 a barrel by September.While it is possible that the spike in option trading is to hedge existing, predominantly long positions, thus preventing a wholesale sell-off, it is just as likely that the momentum chasers simply rushed to "buy the dip", thus becoming even more exposed, this time with leverage and theta, to continued downside risk. In total, options equivalent to to than 800 million barrels of crude oil exchange hands yesterday, an amount that is well more than half the total outstanding net long spec positions.
OilPrice Intelligence Report- How Much Further Can Oil Prices Fall? - Oil prices awoke from their slumber this week, breaking out of a narrow trading range and plunging by more than 8 percent. WTI dipped below $50 per barrel on Thursday, and Brent dropped below $53 per barrel, the lowest levels since early December when the OPEC deal was announced. The reason for the sudden decline was the bearish EIA report, which showed a whopping 8.2 million barrel increase to crude oil inventories, pushing total stocks to another record high. The inventory increases have been consistent throughout 2017, but the combination of rising U.S. oil production and relentless stock builds seems to have finally put a dent in market bullishness. At the CERAWeek Conference in Houston this week, OPEC officials made a concerted effort to court U.S. shale players, hoping to smooth over differences in order to cut down on market volatility. OPEC’s Secretary-General dined with shale executives, and met with investment banks to better understand OPEC actions on the market. By all accounts, the meetings have brought an aura of understanding between OPEC and market players. But, to be sure, they are still competitors. Saudi energy minister Khalid al-Falih warned shale companies not to move too quickly, arguing that OPEC would not bail out the shale industry if it makes unjustifiable investments. "He said we and other shale producers should not automatically assume OPEC will extend the cuts,” a shale executive told Reuters. The statement is all the more poignant given the slide in oil prices this week amid concerns of oversupply. CEO Harold Hamm also warned the shale industry not to “kill” oil prices by ramping up too quickly. Wednesday saw the worst one-day drop in oil prices in over a year. That has added a lot of weight and speculation to OPEC’s production cuts and whether the cartel will extend their deal through the end of the year. OPEC officials said they would wait until May and look at U.S. inventory levels before they decide. But with oil prices already falling, the failure to extend the cuts would mean more losses are to come. “If OPEC doesn’t extend the deal that would be price suicide, plain and simple,” Tamas Varga, analyst at London-based PVM brokerage, told the WSJ. Speculators have built up a record position in net-long bets on crude oil, a position that could unwind with the shift in market sentiment. "It's confirmatory to me that they've thrown in the towel and we're in the process of a pretty big long liquidation at the moment that should carry us all the way down, I think, to the November lows of $42. We'll retrace the entirety of the rally from November to just recently,"
- The total U.S. rig count climbed by 12 to 768, rising for the eighth consecutive week, Baker Hughes reports in its latest weekly survey.
- The oil rig count rose by 8 to 617, while the natural gas rig count rose by 5 to 151; a rig classified last week as miscellaneous was removed.
- The total rig count is up by 288 rigs from last year's count of 480, with oil rigs up 231 from 386 and gas rigs up 57 from 94.
U.S. oil and gas rig count climbs by 12 - Drillers sent another 12 rigs this week back into oil and gas fields across the nation, Baker Hughes said Friday. The number of active oil-drilling rigs climbed by eight, up to 768, in the eighth consecutive weekly increase. Meanwhile, gas rigs increased by five, up to 151. One rig classified as miscellaneous was removed from the oil field service company’s go-to list of active rigs. Four of the oil rigs were sent to the DJ and Niobrara basins in Colorado and nearby states. One went to the Permian Basin in West Texas, another went to the Utica Shale in Ohio, and several more headed for regions Baker Hughes does not track. The nation’s rig count has climbed from 404 in late May to 768 this week, as oil prices have risen and OPEC’s oil production cut spurred drilling activity in U.S. shale plays.
BHI: US rig count records sixth double-digit rise of past 8 weeks - The US drilling rig count climbed 12 units to 768 during the week ended Mar. 10, according to Baker Hughes Inc. data.The count has now risen in 8 straight weeks, 6 of which have been double-digit increases (OGJ Online, Mar. 3, 2017). Since May 27, 2016, the final week of an extended drilling downturn, the count has added 364 units.US oil-directed rigs, which represent more than 80% of the rigs to have come online since May 27, gained 8 units this week to 617, an increase of 301 units since May 27. Gas-directed rigs rose 5 units to 151, up 70 since Aug. 26 in their own rally. The country’s only unclassified rig stopped operations. Onshore rigs tallied 9 units to 743 as horizontal drilling rigs increased 6 units to 639, up 325 units since May 27. The offshore slump was somewhat eased by a 2-unit rise to 20. The count of rigs drilling in inland waters rose a unit to 5. Among the major US operators contributing to the overall drilling rebound, Anadarko Petroleum Corp. this week reported 2017 plans reflecting its sharpened focus on the Permian Delaware and DJ basins after divesting several natural gas-weighted assets last year.The firm plans to average 10-14 operated drilling rigs in the Delaware during the year and drill more than 150 operated midlateral-equivalent wells. In the DJ basin, Anadarko plans to average 5-6 operated rigs and drill 290 midlateral-equivalent wells. The continued ramp up in rig deployment by operators in the Permian and other major oil regions has contributed to further upward revisions in forecast US crude oil production. The US Energy Information Administration this week lifted its US crude output forecast for 2017 by 200,000 b/d to 9.2 million b/d (OGJ Online, Mar. 7, 2017). A rare quiet week in Texas compared with other weeks during the drilling rebound allowed Louisiana and Colorado’s and Wyoming’s DJ-Niobrara to lead the way in activity increases. In part reflecting the offshore gains, Louisiana rose 5 units to 56.Oklahoma and Colorado each increased 3 units to 101 and 28, respectively. Oklahoma is up 47 units since June 24, and Colorado is up 13 units since May 13. The Cana Woodford edged down a unit to 49. The DJ-Niobrara jumped 4 units to 24, double its count from June 24. Ohio and the Utica each gained 2 units to 21 and 22, respectively. Wyoming also rose 2 units to 22. California posted its first increased since last September, edging up a unit to 7.
OPEC aims in vain for the Goldilocks oil price: Kemp - (Reuters) - CERAWeek has exposed all the contradictions at the heart of OPEC’s attempt to rebalance the oil market without rekindling the shale boom or conceding too much market share to rivals.The oil industry conference in Houston started with a celebration of higher prices, progress towards drawing down global stockpiles, and optimism about the outlook for shale producers.But it ends with the biggest daily fall in prices for more than a year, fears that stocks are not declining as planned, and warnings that shale producers could cause a renewed slump if they increase output too fast. OPEC members led by Saudi Arabia have reported nearly full compliance with output cuts announced last November, though performance remains very uneven across the group. Once again, Saudi Arabia has made the deepest cuts to offset patchy compliance by other members, returning to its hated role of swing producer. But OPEC’s rush to increase output before the accord took effect in January has left the market bloated with crude that continues to show up in the statistics as tankers arrive in North America and unload. The attempt to beat the deadline has made rebalancing harder and effectively moved the market against the organisation’s own members. OPEC enlisted support from 11 other countries to spread the burden of rebalancing and protect its market share but compliance from non-OPEC countries has been much lower. The organisation’s members have been forced to discount their selling prices to protect their prized relationships with Asian refiners. And OPEC has encouraged hedge funds and other money managers to believe prices will rise to $60 per barrel or more. But OPEC and Saudi Arabia have spent CERAWeek warning shale producers against raising output too much and assuming the production cuts will be extended automatically. Saudi Arabia has pointedly warned shale producers that it will not cut its own output simply so they can grow theirs (“Saudis tell U.S. oil: OPEC won’t extend cuts to offset shale”, Reuters, Mar. 9). Without an extension, however, global oil production would rise by more than 1 million barrels per day at the start of June, and oil prices would likely swoon.
Why Kurdish Oil Is a Wild Card for Markets: If Iraq’s Kurdish territory were a country, it would probably qualify for OPEC membership. It wouldn’t even be the smallest member, given its production of about 600,000 barrels of oil per day. That’s an impressive achievement for a landlocked enclave that started exploring only a decade ago. The region’s potential is greater still, though it faces political, military and economic challenges to expanding its output.The semi-autonomous Kurdistan Regional Government says the area’s reserves could total 45 billion barrels, more than Nigeria’s, and Kurdish crude is generally cheap to extract. When foreign investors tramped into the region’s oil fields after the fall of Saddam Hussein’s regime, the crude was so abundant it seeped from the ground beneath their feet. Tony Hayward, former BP Plc boss turned wildcatter, called Iraqi Kurdistan “one of the last great frontiers” in the oil and gas industry as his new company Genel Energy Plc started prospecting there in 2011. Ashti Hawrami, natural resources minister for the KRG, has spoken of increasing exports to 1 million barrels a day or more. Iraq’s Kurds have long chafed against control by Arab-led governments in Baghdad, and they’ve been developing their hydrocarbon industry to enhance their self-sufficiency. Kurdish authorities began offering oil contracts to foreign investors in 2007, against Baghdad’s wishes. The central government then barred companies working with the Kurds from operating in other parts of the country. Baghdad also threatened to sue anyone buying Kurdish crude. When it did just that in Texas in 2014, a U.S. judge blocked a tanker from unloading its cargo of Kurdish oil. The stakes rose that same year when Kurdish forces, defending against the encroachment of Islamic State, occupied oil facilities in the disputed province of Kirkuk. That’s left Baghdad in control of less than half of Kirkuk’s oil.
Saudi pledges big projects to soften austerity hit to business | Reuters: Saudi Arabia has promised to launch major development projects towards the end of 2017 to re-energize an economy which has been hit by austerity measures, industry sources told Reuters. Deputy Crown Prince Mohammed bin Salman, the kingdom's top economic official, made the commitment at a recent meeting with a delegation representing the Saudi private sector, the sources, who spoke on condition of anonymity, said. While they pledged support for Prince Mohammed's economic reforms, which aim to rescue state finances and diversify the economy in an era of cheap oil, the representatives of the business associations complained that the private sector had been hit hard by cuts to state spending and subsidies. The complaints underline growing pressure on the government as austerity policies in response to low oil prices enter their third year. While Prince Mohammed has cut a $98 billion state budget deficit and put the kingdom on track towards eliminating its deficit within several years, austerity has stifled the companies needed to create jobs for a growing population. The private sector, which grew by just 0.1 percent last year, "is now suffering from increasing operating costs and declining purchasing power among the people," Ahmed bin Suleiman al-Rajhi, the head of the Riyadh Chamber of Commerce and Industry, said in a report on the meeting. "In addition, the industry is starting to lose its competitive edge because of the increasing cost of power and fuel as well as the rising cost of foreign workers." The report did not give details of the development projects planned by Prince Mohammed, whose media team did not respond to a request for comment, although the government said in December it would provide $53 billion of incentives to the private sector over the next four years and establish a fund to enable capital investments.
Pentagon plan to seize Raqqa calls for significant increase in U.S. participation - WaPo - A Pentagon plan for the coming assault on Raqqa, the Islamic State capital in Syria, calls for significant U.S. military participation, including increased Special Operations forces, attack helicopters and artillery, and arms supplies to the main Syrian Kurdish and Arab fighting force on the ground, according to U.S. officials.The military’s favored option among several variations currently under White House review, the proposal would ease a number of restrictions on U.S. activities imposed during the Obama administration.Officials involved in the planning have proposed lifting a cap on the size of the U.S. military contingent in Syria, currently numbering about 500 Special Operations trainers and advisers to the combined Syrian Democratic Forces, or SDF. While the Americans would not be directly involved in ground combat, the proposal would allow them to work closer to the front line and would delegate more decision-making authority down the military line from Washington.President Trump, who campaigned on a pledge to expand the fight against the militants in Syria, Iraq and beyond, received the plan Monday after giving the Pentagon 30 days to prepare it.But in a conflict where nothing has been as simple as anticipated, the Raqqa offensive has already sparked new alliances. In just the past two days, U.S. forces intended for the Raqqa battle have had to detour to a town in northern Syria to head off a confrontation between two American allied forces — Turkish and Syrian Kurdish fighters. There, they have found themselves effectively side by side with Russian and Syrian government forces with the same apparent objective.
IS conflict: US sends Marines to support Raqqa assault - BBC News: The US has sent 400 additional troops to Syria to support an allied local force aiming to capture the so-called Islamic State stronghold of Raqqa. They include Marines, who arrived in the past few days. US special forces are already in Syria. Meanwhile, US-led coalition air strikes killed 20 civilians - including children - near the city, reports say. US Secretary of State Rex Tillerson is to host talks with coalition members ahead of an expected assault on Raqqa. Foreign ministers and senior officials from 68 nations and international organisations had been invited to attend a two-day gathering in Washington beginning on 22 March, the state department said. "Secretary Tillerson has been crystal clear that defeating Isis (IS) is the state department's top priority in the Middle East," acting state department spokesman Mark Toner said. Defence officials told the Washington Post that a Marine artillery unit had been deployed with large field guns that can fire 155mm shells about 32km (20 miles). A coalition spokesman, Col John Dorrian, told Reuters news agency they would help "expedite the defeat" of IS in Raqqa. Over the weekend, a separate force of elite US Army Rangers was also deployed near a town north-west of Raqqa in heavily-armoured vehicles. The move was an attempt to end clashes between units from the Kurdish-Arab alliance, known as the Syrian Democratic Forces (SDF), and Turkish-backed rebels
Syria’s Civil War Is Almost Over … And Assad Has Won - Winners and losers are emerging in what may be the final phase of the Syrian civil war as anti-Isis forces prepare for an attack aimed at capturing Raqqa, the de facto Isis capital in Syria. Kurdish-led Syrian fighters say they have seized part of the road south of Raqqa, cutting Isis off from other its territory further east.Isis is confronting an array of enemies approaching Raqqa, but these are divided, with competing agendas and ambitions. The Syrian Democratic Forces (SDF), whose main fighting force is the Syrian Kurdish Popular Mobilisation Units (YPG), backed by the devastating firepower of the US-led air coalition, are now getting close to Raqqa and are likely to receive additional US support. The US currently has 500 Special Operations troops in north-east Syria and may move in American-operated heavy artillery to reinforce the attack on Raqqa.This is bad news for Turkey, whose military foray into northern Syria called Operation Euphrates Shield began last August, as it is being squeezed from all sides. In particular, an elaborate political and military chess game is being played around the town of Manbij, captured by the SDF last year, with the aim of excluding Turkey, which had declared it to be its next target. The Turkish priority in Syria is to contain and if possible reduce or eliminate the power of Syrian Kurds whom Ankara sees as supporting the Kurdish insurrection in Turkey.Turkey will find it very difficult to attack Manbij, which the SDF captured from Isis after ferocious fighting last year, because the SDF said on Sunday that it is now under the protection of the US-led coalition. Earlier last week, the Manbij Military Council appeared to have outmanoeuvred the Turks by handing over villages west of Manbij – beginning to come under attack from the Free Syrian Army (FSA) militia backed by Turkey – to the Syrian Army which is advancing from the south with Russian air support. Isis looks as if it is coming under more military pressure than it can withstand as it faces attacks on every side though its fighters continue to resist strongly. It finally lost al-Bab, a strategically placed town north east of Aleppo, to the Turks on 23 February, but only after it had killed some 60 Turkish soldiers along with 469 FSA dead and 1,700 wounded.
Iraqi forces retake Mosul museum, close in on IS-controlled old town | Reuters: Iraqi forces on Tuesday recaptured the main government building in Mosul, the central bank branch and the museum where three years ago the militants filmed themselves destroying priceless statues. A Rapid Response team stormed the Nineveh governorate complex in an overnight raid that lasted more than an hour, killing dozens of Islamic State fighters, spokesman Lieutenant Colonel Abdel Amir al-Mohammadawi said. The buildings, already in ruins, were not being used by Islamic State, but their capture is a landmark in the push to retake the militants' last major stronghold in Iraq, now restricted to the heavy populated western half of Mosul. Prime Minister Haider al-Abadi flew into to Mosul to visit the troops fighting to oust Islamic State from the city in which it declared its sprawling caliphate in 2014. Islamic State snipers continued to fire at the main government building after it was stormed, restricting the movements of the soldiers, and forces pushing further into western Mosul came under rifle and rocket fire. "The fighting is strong because most of them are foreigners and they have nowhere to go," said the head of a sniper unit for the Rapid Response, al-Moqdadi al-Saeedi. Some of Islamic State's foreign fighters are trying to flee Mosul, U.S. Air Force Brigadier General Matthew Isler said. "The game is up," Isler told Reuters at the Qayyara West Airfield, south of the city. "They have lost this fight and what you're seeing is a delaying action."
U.S. Military Deepens Yemen Role With Escalating Strikes Against Al-Qaeda Affiliate - Bloomberg - The U.S. military is deepening its involvement in Yemen, with escalating counterterrorism strikes targeting an al-Qaeda affiliate that’s gained ground in the chaos of the country’s civil war. U.S. forces carried out more than 30 strikes by airplanes and drones in the past week in southern and central provinces, said Navy Captain Jeff Davis, a Pentagon spokesman. The strikes followed the first commando operation Donald Trump approved as president, a Jan. 28 raid against the terrorist group by the Navy’s SEAL Team 6 in which a U.S. serviceman was killed. Al-Qaeda in the Arabian Peninsula, known as AQAP, has taken advantage of more than two years of fighting between Shiite Houthi rebels and President Abdurabuh Mansour Hadi’s government, which is backed by Saudi Arabia, Davis said. The U.S. provides the Saudi-led coalition with logistical and intelligence support, but not troops. It’s been estimated that at least 10,000 civilians have been killed in the fighting since the Saudi-led coalition began airstrikes in March 2015. All the while, AQAP has moved deeper into ungoverned provinces after being driven out of the port of Mukalla, which it had seized. Although attention in the fight against terrorism by the U.S. and allies has focused on Islamic State militants in Iraq and Syria, “AQAP is the organization that has more American blood on its hands,” Davis told reporters Friday at the Pentagon. “U.S. forces will continue to target AQAP militants and facilities in order to disrupt the terrorist organization’s plots and ultimately protect American lives.”
The U.S. Is Killing a Lot More Civilians in the Middle East This Year. Is It Because of Trump? - An airstrike in Syria on Thursday, believed to have been carried out by the U.S.-led coalition against ISIS, killed 23 civilians, including eight children, Reuters reports, citing the Syrian Observatory on Human Rights. The strike, in the countryside around the city of Raqqa, was part of the escalating campaign by the U.S. and allied local forces to recapture the city, ISIS’s de facto capital. An Air Force spokesman acknowledged that a strike had taken place in the area and said the event would be investigated. Also on Thursday, the Intercept published a dispatch by reporter Iona Craig from the Yemeni village of al Ghayil, the site of the now infamous Jan. 29 raid that left a number of civilians and a Navy SEAL dead in the first major counterterrorism operation of the Trump administration. Craig’s reporting disputes the administration’s description of the raid as a success and suggests that the event shows that “the Trump White House is breaking with Obama administration policies that were intended to limit civilian casualties.” Trump suggested during his campaign that he would take far more aggressive action against terrorist groups than his predecessor—“bomb the shit out of them,” to be precise. On Jan. 28, he issued a presidential memo recommending changes to rules of engagement for counterterrorism operations "that exceed the requirements of international law regarding the use of force against ISIS." This was generally interpreted to mean that measures preventing civilian casualties would be deprioritized. The White House reportedly also wants to speed up the process for approving raids by delegating more responsibility to the Pentagon, even after the January raid. It’s too soon to tell if Trump is the cause, but the U.S. appears to have been both accelerating the pace of counterterrorism operations this year and killing more civilians in the process. This has been most evident in Yemen, where the main target is al Qaida in the Arabian Peninsula, or AQAP, and Iraq/Syria, where the main target is ISIS. (America's oddly neglected war in Afghanistan already saw a dramatic increase in both strikes and casualties last year.) The U.S. has dramatically ramped up the campaign against AQAP in Yemen in 2017, with deadly results. New America estimates that approximately 16 civilians have been killed in U.S. strikes in Yemen so far this year. All but one of these strikes was launched after Trump took office. The last time a yearly figure was that high was in 2013.
U.S. Drone Strikes Have Gone Up 432% Since Trump Took Office - When he was in office, former President Barack Obama earned the ire of anti-war activists for his expansion of Bush’s drone wars. The Nobel Peace Prize-winning head of state ordered ten times more drone strikes than the previous president, and estimates late in Obama’s presidency showed 49 out of 50 victims were civilians. In 2015, it was reported that up to 90% of drone casualties were not the intended targets.Current President Donald Trump campaigned on a less interventionist foreign policy, claiming to be opposed to nation-building and misguided invasions. But less than two months into his presidency, Trump has expanded the drone strikes that plagued Obama’s “peaceful” presidency. According to an analysis from Micah Zenko, an analyst with the Council on Foreign Relations, Trump has markedly increased U.S. drone strikes since taking office. Zenko, who reported earlier this year on the over 26,000 bombs Obama dropped in 2016, summarized the increase:“During President Obama’s two terms in office, he approved 542 such targeted strikes in 2,920 days—one every 5.4 days. From his inauguration through today, President Trump had approved at least 36 drone strikes or raids in 45 days—one every 1.25 days.” That’s an increase of 432 percent. The Trump administration has provided little acknowledgment of the human toll these strikes are taking. As journalist Glenn Greenwald noted in the Intercept, the Trump administration hastily brushed off recent civilian casualties in favor of honoring the life of a single U.S. soldier who died during one of the Yemen raids just days after Trump took office:
U.S. program for Afghan translators in jeopardy as visa supply runs low | Reuters: The U.S. State Department said on Thursday it will soon run out of visas for interpreters and other Afghans who have worked for the U.S. government during the decade and a half that U.S. forces have been engaged in the country. At least one U.S. senator, Democrat Jeanne Shaheen, said any decision to let the program lapse sends a message to allies in Afghanistan that the United States is not supporting them. She pledged to immediately introduce legislation to provide more visas. "It's both a moral and practical imperative that Congress right this wrong immediately," Shaheen said in a statement. Her office said more than 10,000 applicants are still in the process of obtaining visas. Shaheen and Republican Senator John McCain led a failed effort last year to pass legislation extending to 4,000 more people an existing special immigrant visa program for Afghans who assisted U.S. forces, often risking their lives. In Afghanistan, where the Taliban has steadily expanded its insurgency and where government forces now control less than 60 percent of the country, there has been deep concern among local contractors working for international forces. "Most of those working with foreigners are in trouble with their relatives, villagers and even family members," said one translator, who is waiting for medical checks after completing his interview. He declined to give his name because his visa has not yet been granted. The Taliban has captured biometric equipment to let it identify staff working for the Western-backed government and international forces, heightening the risk for those on official payrolls. "I cannot go to my home and it has been two years now," the translator said. "If they don't give us a visa, we will be killed or in big trouble, especially once foreigners leave Afghanistan."
Malaysia’s Future Role in Saudi Arabia’s Islamic Military Alliance -- Saudi King Salman is currently on a three-week tour across six Asian countries. It comes at a time when the kingdom is promoting Vision 2030—an ambitious agenda aimed at ending the country’s reliance on oil and creating a prosperous and sustainable knowledge-based economy—and seeking to strengthen its geopolitical influence across the Asia-Pacific region. Significantly, the first leg of the king’s Asia tour was in Malaysia, which no Saudi monarch had visited since 2006. While in Kuala Lumpur, King Salman sought to identify new markets for Saudi Arabia’s non-oil exports and secure more Malaysian investment in Vision 2030. The two governments signed several agreements to enhance bilateral cooperation in sectors including construction, aerospace, halal products, and hajj services. Most importantly, Aramco agreed to invest $7 billion in a Petronas refining and petrochemical project, marking the kingdom’s largest downstream investment outside of Saudi Arabia. Symbolic, religious, and political dimensions contribute to Malaysia’s importance in Saudi Arabia’s grand vision for the Asia-Pacific region. Determined to extend influence among Muslim-majority countries in Southeast Asia, the kingdom sees Malaysia as having an important role to play in Saudi Arabia’s 41-member Islamic Military Alliance to Fight Terrorism (IMAFT). To showcase unity in the struggle against terrorism, Saudi Arabia and Malaysia announced the King Salman Center for Global Peace (KSCGP) to “intensify and concert the Islamic world’s effort to confront extremism, reject sectarianism and to move the Islamic world toward a better future.” The center, which is set to launch later this year, will focus on the threat of international terrorism without associating it with “any race, color or religion.” The Intellectual Warfare Center at the Saudi Ministry of Defense and the Center for Security and Defense at the Malaysian Ministry of Defense will jointly set up the institution. The Malaysian University of Islamic Societies and the Jeddah-based Muslim World League will be stakeholders in KSCGP.
Iran Wields Growing Influence in Unexpected Places - Nigerian carpenter Bashir Muhammad has never been to Iran, but he would fight to the death for the country. “If Iran wants our help, we are ready to go and help it, even with our blood,” he said. “Donald Trump needs to know that Iran has followers all over the world ready to help defend it against America.” Touring the narrow unpaved streets of Zaria in Nigeria’s predominantly Muslim north, Muhammad shows Iran’s success in building enclaves of fervent support way beyond the Middle East and the limits of any harsher foreign policy planned by the U.S. president to contain it. The 30-year-old is among an increasing number of converts to the Shiite brand of Islam that Iran has been exporting since its 1979 revolution. As the world adjusts to the Trump era, the message for Washington and its allies is that Iran wields growing influence in unexpected places. The Islamic power has been able to expand its reach regardless of the economic sanctions that excluded it from much of the global oil market until last year. In this case, it’s in Africa’s most populous nation, key oil producer and a country where the sectarian battle that has thrown the Middle East into chaos is festering. Nigeria’s Muslims are mainly Sunnis and Iran’s growing foothold in Africa has alarmed the Saudis. “Iran is on its own crusade, its own global war, believing that the U.S. is out to get it,” “They’re building networks, under religious slogans, that they can use in any fight. And wherever they are expanding, there’s a potential for a sectarian Shiite-Sunni conflict.”
Peace or War? Sanders on Israel, Palestinians and the Middle East - READ IN FULL: Bernie Sanders’ Speech on Israel, Trump and anti-Semitism at J Street Conference Bernie Sanders’ full speech to the J Street 2017 conference.
China launches world's largest oil exploration offshore platform, Bluewhale 1 weighs 42,000 tonnes and has a deck the size of a football field. Its height is 118m, or as tall as a 37-storey building. The platform has a maximum operating depth of 3,658m, and can drill a farther 15,240m into the earth's crust. It is suitable for deep-sea operation across the world, according to the official website of CIMC Raffles. Hong Kong's South China Morning Post said the Bluewhale 1 is designed "specifically for the South China Sea, where untapped oil reserves can lay buried 3,000m and more below sea level". China's deployment of large drilling rigs in disputed waters has raised concerns among its neighbours, particularly Japan and Vietnam. In 2014, Chinese and Vietnamese marine forces had a stand-off when the Haiyang Shiyou 981 platform drilled near the disputed Paracel Islands in the South China Sea. The Bluewhale 1 drilling platform uses state-of-the-art technology from leading domestic and overseas suppliers such as Germany's Siemens. Its operating speed is about a third faster than other Chinese drilling vessels, according to the manufacturer. The Bluewhale I was delivered to the client - China National Petroleum Corporation (CNPC) Offshore Engineering Company, a subsidiary of the oil giant CNPC - at Yantai, a port city in Shandong province on Feb 13.Chinese rig makers also made news last month when an oil platform weighing 31,000 tonnes was loaded onto its largest semi-submersible ship Xinguanghua for delivery to Britain's Western Isles Development Project in the North Sea. The first of its kind to be built by China, it will reach North Sea Oil Field in June.