the $50 a barrel level, as Texas Gulf Coast refineries returned to operation and began to soak up some of the oil glut that had built up during their shutdown...however, front month Brent oil prices, the international benchmark, did rise every day this week and ended at $56.62 a barrel, 13.5% higher than the US price for the same kind of oil...John Kemp at Reuters included a graph of that differential between the two oils for two contract months in one of his articles this week, which we'll include below:
the above graph accompanied John Kemp's article titled 'Mind the gap: Brent and WTI point in opposite directions', published on Tuesday of this week, and it tracks the difference between the price for North Sea Brent, the global oil benchmark, and West Texas Intermediate (WTI), the US benchmark, which is what we quote every time we speak of US oil prices...the mustard colored graph above shows the excess price of Brent over WTI in dollars per barrel for a contract to deliver each type of oil in November, while the white graph shows the excess price of Brent over WTI in dollars per barrel for a contract to deliver each type of oil in April of 2018...
there had long been a discount on US oil before the export ban on it was lifted as part of a budget deal signed by Obama at the end of 2015, which subsequently brought US oil up to parity with the global price...however, that parity did not last long, and for most of 2016, US WTI oil traded around a dollar below the international price...however, as the chart above indicates, the price differential started rising early in 2017, and had reached an average of around $2.50 a barrel before Harvey shut down Gulf Coast refineries, creating a glut of oil on the Gulf Coast, and shut down the ports, so that oil could not be exported...at that time, November US crude fell in price, while Brent did not, resulting in a premium for Brent of as much as $6, which continued through this week...a smaller gap opened up between the prices for Brent and WTI for April 2018 delivery in white, not particularly logical, as it's not likely that any impact from Harvey would persist that far into the future...of course, if oil overseas continues fetching $6 a barrel more than what oil in the US sells for, then US oil will be exported into those higher priced markets until such time as that price gap closes...
OPEC's September oil report
we're going start by reviewing OPEC's September Oil Market Report (covering August OPEC & global oil data), which was released on Tuesday of this past week....the first table from this report that we'll include here is from page 67 of that OPEC pdf, and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months as the column headings indicate...for all their official production measurements, OPEC uses an average of estimates from six "secondary sources", namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as an impartial adjudicator as to whether their output quotas and production cuts are being met, to resolve any potential disputes that could arise if each member reported their own figures...
from the above table of official oil production data, we can see that OPEC oil output decreased by 79,100 barrels per day in August, to 32,755,000 barrels per day, from a July oil production total of 32,834,000 barrels per day, a figure that was originally reported as 32,869,000 barrels per day (for your reference, here is the table of the official July OPEC output figures before this month's revisions)...as we can see in the far right column, the reason that OPEC's output fell 79,100 barrels per day was largely due to a 112,300 barrel per day decrease in output from Libya, as the 138,300 barrel per day increase from Nigeria was offset by modest decreases in production by Gabon, Iraq, the United Arab Emirates and Venezuela.....these totals bring most OPEC members other than Iraq close to their agreed to production quota, as can be seen in the table below:
the above table is from the "OPEC guide" page at S&P Global Platts: the first column of numbers shows average daily production in millions of barrels of oil per day for each of the OPEC members over the first eight months of this year, and the 2nd column shows the allocated daily production in millions of barrels of oil per day for each member, as was agreed to at their November meeting, and the 3rd column shows how much each has averaged over or under their quotas for the eight months of this year that OPEC has curtailed production...as you can see from the above, most OPEC members are pretty close to meeting their commitment to cutting their production back 4%, except for Iraq, who has consistently overproduced by roughly 2%...
the next graphic we'll include shows us both OPEC and world oil production monthly on the same graph, over the period from September 2015 to August 2017, and it comes from page 68 of the September OPEC Monthly Oil Market Report....the light blue bars represent OPEC oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale...
the preliminary OPEC data indicates that total global oil production fell to 96.75 million barrels per day in August, down by .41 million barrels per day from a July total of 97.16 million barrels per day, which was revised .14 million barrels per day lower than the 97.30 million barrels per day global oil output for July that was reported a month ago...global oil output for August was also 1.10 million barrels per day higher than the 95.65 million barrels of oil per day that was being produced globally in August a year ago (see last September's OPEC report for the year ago data)...OPEC's August production of 32,755,000 barrels per day thus represented 33.9% of what was produced globally, a small increase from the revised 33.8% OPEC share in June...OPEC's August 2016 production, excluding ex-member Indonesia, was at 32,512,000 barrels per day, so even after the alleged production cuts, the 13 OPEC members who were part of OPEC last year, excluding new member Equatorial Guinea, are still producing more oil than they were producing a year ago, when they were supposedly producing flat out...
after eight months of relatively lower production we can see on the above graph, there was finally a small deficit in the amount of oil being produced globally, as the next table from the OPEC report will show us..
the table above comes from page 37 of the September OPEC Monthly Oil Market Report, and it shows regional and total oil demand in millions of barrels per day for 2016 in the first column, and OPEC's forecast for oil demand by region and globally over 2017 over the rest of the table...on the "Total world" line of the fourth column, we've circled in blue the figure we're interested in, which is their estimate for global oil demand for the third quarter of 2017...
OPEC's estimate is that during the 3rd quarter of this year, all oil consuming areas of the globe will use be using 97.57 million barrels of oil per day, which is an upward revision from their prior estimate of 97.28 million barrels of oil per day...note that they have also revised global oil demand for the second quarter 400,000 barrels per day higher, to 96.05 barrels per day, and revised demand for the first quarter 150,000 barrels per day higher, to 95.54 barrels per day, at the same time...meanwhile, as OPEC showed us in the oil supply section of this report and the summary supply graph above, after the OPEC and non-OPEC production cuts, the world's oil producers were only producing 96.75 million barrels per day during August, which means that during this summer month of greatest demand, there was a shortfall of around 820,000 barrels per day of global oil production in August...also note that global production for July was concurrently revised lower, to 97.16 million barrels per day, so that means there was also a deficit of 410,000 barrels per day in July output, which we had previously figured to be a global oil surplus of around 20,000 barrels per day...in addition, the 400,000 barrels per day upward revision to second quarter demand reduces the June surplus to 1,080,000 barrels per day, and turns what we had previously figured to be a 270,000 barrels per day surplus in May into a 130,000 barrel per day deficit....April's revised figures now show a 440,000 barrel per day deficit, and prior to that the global oil surplus during March would be revised to 630,000 barrels per day, and average surpluses over January and February would be reduced to around 850,000 barrels per day....taken together, this data means that after eight months of OPEC production cuts, roughly 48 million barrels of oil have been added to the global oil glut since the 1st of the year, quite a bit less than the 135 million barrel addition last month's report indicated..
last, we'll include a graph of the total OPEC oil output for the 13 long term OPEC members included in this report, so we can see how this month's production stacks up compared to historical figures...
the above graph, taken from the "OPEC August Crude Oil Production" post at the Peak Oil Barrel blog, shows total oil production, in thousands of barrels per day, for the 13 members of OPEC, for the period from January 2005 to August 2017, using the same official data from multiple secondary sources as we saw in the first table above...here we can obviously see that OPEC's production for June, July and August is up quite a bit from their previous production this year and is even approaching the record of 33,374,000 million barrels per day the cartel produced in November, a level achieved because they all over produced so that their cuts would be off a higher base...so even as they've cut their oil production from that level, their output for each of the eight months of this year was actually higher than in each of the same months months a year ago, leaving OPEC well on track to exceed their 2016 production this year, even as they attempt to orchestrate the oil markets with reports of their "reduced" production...
The Latest US Oil Data from the EIA
this week's US oil data from the US Energy Information Administration, covering details for the week ending September 8th, continued to show the effect of Hurricane Harvey on oil supplies and consumption as it transversed Texas and the adjacent Gulf of Mexico the prior week; it indicates a further drop in oil imports, as ship channels in the affected ports remained silted, but a rebound in oil exports, as the primary US oil export facilities at Corpus Christi were reopened, a recovery in oil production, as output from the Eagle Ford shale and the Gulf came back online, and a small drop in per diem oil refining, as the major refinery shutdowns impacted both this week and the last half of the prior one...
our imports of crude oil fell by an average of 603,000 barrels per day to an average of 6,480,000 barrels per day during the week, while at the same time our exports of crude oil rose by 621,000 barrels per day to an average of 774,000 barrels per day, which meant that our effective imports netted out to an average of 5,706,000 barrels per day during the week, 1,224,000 barrels per day less than during the prior week...at the same time, our field production of crude oil rose by 572,000 barrels per day to an average of 9,353,000 barrels per day, which means that our daily supply of oil coming from net imports and from wells totaled an average of 15,059,000 barrels per day during the cited week...
during the same period, US oil refineries were using 14,078,000 barrels of crude per day, 394,000 barrels per day less than they used during the prior week, while at the same time 614,000 barrels of oil per day were being added to oil storage facilities in the US...hence, this week's crude oil figures from the EIA seem to indicate that our total supply of oil from net imports and from oilfield production was 367,000 more barrels per day than what refineries reported they used during the week plus what was added to storage...to account for that discrepancy, the EIA needed to insert a (-367,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, which they label in their footnotes as "unaccounted for crude oil"...
further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports fell to an average of 7,565,000 barrels per day, which was 7.6% below the imports of the same four-week period last year....this week's 572,000 barrel per day increase in our crude oil production was the result of a 582,000 barrels per day rebound in oil output from wells in the lower 48 states and a 10,000 barrel per day decrease in oil output from Alaska...the 9,353,000 barrels of crude per day that were produced by US wells during the week ending September 8th was still 1.9% less than the 9,530,000 barrels of crude per day being produced during the pre-hurricane week ending August 25th, but 6.6% more than the 8,770,000 barrels per day we were producing at the end of 2016, and 10.1% more than the 8,493,000 barrels per day of oil we produced during the during the week ending September 9th a year ago, while it was 2.7% below the record US oil production of 9,610,000 barrels per day set during the week ending June 5th 2015...
US oil refineries were operating at 77.7% of their capacity in using those 14,078,000 barrels of crude per day, down from the of 79.7% of capacity the prior week, and the lowest capacity utilization rate since the end of September 2008....the 14,078,000 barrels of oil refined this week was the least oil refined in the US since March 8th, 2013, 20.6% less that was being refined two weeks earlier, and 15.9% less than the 16,730,000 barrels of crude per day.that were being processed during week ending September 9th, 2016, when refineries were operating at 92.9% of capacity, and roughly 10% below the 10 year average of 15.7 million barrels of crude being refined per day at this time of year...
even with the drop in US oil refining, gasoline production from our refineries rose by 371,000 barrels per day to 9,888,000 barrels per day during the week ending September 8th...that brought this week's gasoline output almost up to the level of the 9,900,000 barrels of gasoline that were being produced daily during the comparable week a year ago....however, our refineries' production of distillate fuels (diesel fuel and heat oil) fell by 519,000 barrels per day to 3,973,000 barrels per day at the same time, which was 19.5% less than the 4,933,000 barrels per day of distillates that were being produced during the week ending September 9th last year....
even with this week's increase in gasoline production, our end of the week gasoline inventories fell by 8,428,000 barrels to 226,738,000 barrels by September 8th, the 10th decrease in gasoline inventories in 13 weeks and the largest drop on record...that was as our domestic consumption of gasoline rose by 456,000 barrels per day to 9,619,000 barrels per day, and as our exports of gasoline rose by 209,000 barrels per day to 528,000 barrels per day, while our imports of gasoline rose by 81,000 barrels per day to 556,000 barrels per day....with significant gasoline supply withdrawals in 10 out of the last 13 weeks, our gasoline inventories are now 4.4% below last September 9th's level of 228,360,000 barrels, even as they are still fractionally higher than the 217,387,000 barrels of gasoline we had stored on September 11th of 2015, and roughly 3.4% above the 10 year average of gasoline supplies for this time of the year...
meanwhile, with the big decrease in our distillates production, our supplies of distillate fuels fell by 3,215,000 barrels to 144,552,000 barrels over the week ending September 8th, as the amount of distillates supplied to US markets, a proxy for our domestic consumption, slipped 6,000 barrels per day to 4,057,000 barrels per day, while our exports of distillates fell by 227,000 barrels per day to 511,000 barrels per day and our imports of distillates rose by 26,000 barrels per day to 136,000 barrels per day...after this week’s decrease, our distillate inventories were 11.2% lower than the 162,754,000 barrels that we had stored on September 9th, 2016, and 6.1% lower than the distillate inventories of 153,963,000 barrels of distillates that we had stored on September 11th of 2015, even as they remain fractionally higher than the 10 year average for distillates stocks for this time of the year…
finally, with another big drop in use of crude by our refineries, our commercial crude oil inventories rose for the 2nd week in a row, increasing by 5,888,000 barrels to 468,241,000 barrels as of September 8th, just the 4th increase in the past 24 weeks...while our oil inventories as of September 8th were 2.5% below the 480,166,000 barrels of oil we had stored on September 9th of 2016, they were 10.4% higher than the 423,958,000 barrels in of oil that were in storage on September 11th of 2015, and much higher than the normal level for our oil supplies in the years before the oil glut started building up, ie., 41.4% higher than the 331,101,000 barrels of oil we had in storage on September 12th of 2014...
This Week's Rig Count
US drilling activity decreased for the 8th time in the past 12 weeks during the week ending September 15th, after a string of 23 consecutive weekly increases earlier this year, with both oil and gas drilling seeing pullbacks....Baker Hughes reported that the total count of active rotary rigs running in the US fell by 8 rigs to 936 rigs in the week ending Friday, which was 430 more rigs than the 506 rigs that were deployed as of the September 16th report in 2016, while it was still less than half of the recent high of 1929 drilling rigs that were in use on November 21st of 2014....
the number of rigs drilling for oil was down by 7 rigs to 749 rigs this week, their 6th week without an increase, which still left oil rigs up by 333 over the past year, while their count remained far 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 decreased by 1 rig to 186 rigs this week, which was still 97 more rigs than the 89 natural gas rigs that were drilling a year ago, but still way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...in addition, one rig that was classified as miscellaneous was still drilling this week, just as there was also a miscellaneous rig that was deployed a year ago...
with new drilling starting on a platform off the Louisiana coast, the Gulf of Mexico rig count increased by 1 rig to 17 rigs this week, which was also the total US offshore count...in both cases, that was down from 20 rigs offshore in the Gulf and for total US a year ago...however, a platform that had seen drilling on an inland lake in southern Louisiana was shut down this week, leaving an 'inland waters' count of 4 rigs, the same as a year ago...
the count of active horizontal drilling rigs rose by 2 rigs to 795 rigs this week, which was up by 401 rigs from the 394 horizontal rigs that were in use in the US on September 16th of last year, but was also down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014....on the other hand, the vertical rig count was down by 8 rigs to 67 vertical rigs this week, which was still up from the 64 vertical rigs that were deployed during the same week last year...at the same time, the directional rig count was down by 2 rigs to 74 rigs this week, which was still up from the 48 directional rigs that were deployed on September 16th of 2016....
the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows 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 September 15th, the second column shows the change in the number of working rigs between last week's count (September 8th) and this week's (September 15th) count, the third column shows last week's September 8th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was for the 16th of September, 2016...
this week's details are pretty simple; there were no other changes in states or basins that aren't shown on the table above...
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These 'friends of the court' are friends of the oil & gas industry - Athens News - As reported in the Athens Messenger (“Groups Weigh in on Athens County Charter Dispute” Sept. 7), several state-level organizations have submitted amicus curiae (“friends of the court”) briefs to the Ohio Supreme Court supporting the Athens County Board of Elections’ decision to refuse to certify the proposed county charter initiative to the ballot for the Nov. 7 election. The list of organizations contains notorious “friends of the oil and gas industry” whose legal arguments all boil down to the claim that state laws pre-empt local laws, and most importantly in this case, state laws can pre-empt even the attemptto charter a county when its provisions conflict with state law.This is an important issue for them because it is much easier and more efficient for them to wield their influence at the state level, rather than having to deal separately with multiple counties and municipalities. The state law in question here is H.B. 278 (2004) which gives sole discretion to the Ohio Division of Natural Resources to site injection wells for dumping toxic and often radioactive fracking wastes anywhere in the state, without the need to obtain permission from (or even inform) local elected officials, and without public hearings to discuss impacts on citizens’ health and safety. While it is patently clear why certain “friends of the court” wish to defeat the Athens County Charter initiative, it would be unfair to attribute such motives to the members of the local boards of elections. Their decisions were based on their reading of the relevant law, and there is no evidence that they are beholden to the oil and gas industry in any way. As citizens of the county, moreover, they certainly must be aware of arguments both for and against the charter initiative. But that is exactly why the issue needs to be placed before the voters to decide.
Ohio gas plant developers primed to seize King Coal's crown — Where most people traveling south from this small southeast Ohio village see grassy fields and rolling hills alongside Interstate 77, Michael King sees the future of Eastern power markets. King, managing partner of Apex Power Group LLC, is particularly fixed on 118 acres across the I-77 from a highway rest stop. The empty field happens to be adjacent to the Rockies Express natural gas pipeline transporting Appalachian shale gas to points east and a high-voltage line moving electricity across the Mid-Atlantic. He figures the spot is perfect for a new $1.45 billion power plant that will run on gas from the Marcellus and Utica shale formations that underlie the area. The 1,650-megawatt Guernsey Power Station is the largest of almost a dozen of this new breed of power plants being developed across Ohio these days, a number that includes the recently completed Oregon Clean Energy Center, an 870-MW plant outside of Toledo. Together, the plants represent about $10 billion of investment in new generating capacity that will power millions of Ohio homes and, not coincidentally, ratchet up the pressure on aging coal and nuclear plants in the region. The wave of development is occurring against the backdrop of relentless lobbying by utilities seeking millions of dollars in subsidies to prop up those same plants, which are struggling to compete in a new world of cheap shale gas and eroding electricity demand (Energywire, Nov. 7, 2016).
ETP's Rover pipeline sends more Marcellus / Utica shale gas west - In another key milestone for Northeast pipeline takeaway capacity expansions, Energy Transfer Partners’ beleaguered Rover Pipeline project began partial service on its Phase 1A portion on gas day September 1. The 3.25-Bcf/d project, which is due for completion in early 2018, is expected to provide relief for constrained Northeast producers while exacerbating oversupply conditions and gas-on-gas competition in the Dawn, Ontario, storage and demand market area and surrounding region. Within days of initial start-up, flows on Rover ramped up to 700 MMcf/d, and both Ohio and overall Northeast production already have posted record highs since then as a result. Today, we take a look at the project, including initial flows and the expected timing of full completion. It’s been a long, tumultuous road for ETP’s Rover Pipeline project so far. From its inception, the project was competing head-to-head for shipper commitments and investment dollars against the DTE Energy Co./Enbridge 1.5-Bcf/d NEXUS Gas Transmission project which would begin in the same general gas-supply area (eastern Ohio) and serve the same general markets (southeastern Michigan and Ontario). Then, in late 2016/early 2017, ETP found itself racing against the clock to secure its final certificate of approval and finish clearing trees along the project route before some endangered bats — yes, bats — came to roost (see Bat Out of Hell). The developer managed to beat the clock on that, with the Federal Energy Regulatory Commission (FERC) issuing the certificate in early February 2017, just one day before the departure of Commissioner Norman Bay broke the quorum needed to get that final approval. With the certificate in hand, Rover construction proceeded at break-neck speed, and for a while the project seemed unshakable — that is, until disaster struck in May 2017 in the form of a two-million gallon spill of fluid containing diesel in a protected wetland area near the Tuscarawas River in Stark County, OH, which prompted FERC to issue an order halting any new Rover-related drilling activity pending a third-party review.
West Virginia officials to re-examine controversial pipeline | TheHill: West Virginia environmental officials are planning to take a new look at a natural gas pipeline that they previously approved amid national controversy. The state’s Department of Environmental Protection last week withdrew approval for the Mountain Valley pipeline. The agency told a federal court Wednesday that the information it used to approve the project “needs to be further evaluated and possibly enhanced.”Specifically, the agency wants to take a new look at how the pipeline proposed by EQT Corp. complies with West Virginia’s “antidegradation” policy, which seeks to prevent or mitigate environmental degradation. Wednesday’s filing was in response to a federal lawsuit that the Sierra Club and other environmental groups filed against the pipeline. The state agency asked the court to kick the issue back to the agency for its new review. The Sierra Club cheered the development. “Our rivers and streams make West Virginia a beautiful place for residents and visitors alike and preserving them also preserves what we love about our state,” said Justin Raines, chairman of the Sierra Club’s natural gas committee in West Virginia. “The fracked gas Mountain Valley Pipeline is dirty, dangerous and needlessly endangers West Virginia’s waterways, wilderness, and communities, and it should be rejected.”
West Virginia files to revoke permits for a massive natural gas pipeline - The West Virginia Department of Environmental Protection filed a motion Wednesday to withdraw its certification of water protection for the Mountain Valley Pipeline (MVP), a 300-mile long natural gas pipeline running from West Virginia to southern Virginia. The move came just a day before the state was due to defend its approval in court against a lawsuit from Appalachian Mountain Advocates, representing a number of local and environmental groups. The groups challenged DEP’s process in granting a Clean Water Act permit, known as a 401 certification. (While the Clean Water Act is a federal statute, many states are authorized to enforce its regulations.) “We’re pleased that DEP recognized its 401 certification was defective,” said senior attorney Derek Teaney. “But it’s a shame that it took a lawsuit to get DEP to do its job.” Section 401 of the Clean Water Act requires the state to certify that a project will not violate water quality standards — including making sure that existing streams and rivers won’t be degraded. The Mountain Valley Pipeline route will cross over 600 local streams, Teaney told ThinkProgress. During construction, the streams would be dammed before the company digs a trench, buries the pipe, and allows the water to flow again. After the pipeline is complete, it will remain in a “maintained pipeline corridor,” which will increase runoff and sediment. “Amazingly, neither DEP nor MVP bothered to calculate how much sediment the affected streams could tolerate or how much the pipeline would add to them,” Teaney said. “DEP never did that analysis the first time around. It didn’t even have the data necessary — baseline water quality data and a quantification of the amount of new pollution from the pipeline — to do that review.” According to the motion, filed with the United States Court of Appeals for the Fourth Circuit, West Virginia agrees that its review was insufficient. “During its review of the [court] filings… DEP determined that the information used to issue the Section 401 Certification needs to be further evaluated and possibly enhanced,” it says in the motion. The DEP specifically noted that “it needs to reconsider its antidegradation analysis.” The stiff language belies the damage the Mountain Valley Pipeline could do. According to an environmental impact statement, the project “would be located in 13 major watersheds.” The route crosses more than 1,100 waterways, including five “major bodies.” Moreover, 152 miles (all but 44 miles) of the pipeline route in that state “were identified as having a high incidence of and high susceptibility for landslides.”
How a Recent Court Ruling Could Impede New Gas Pipelines - A federal appellate court decision has set back the approval of a newly completed set of natural gas pipelines in the U.S. Southeast, and raised the possibility that all gas pipeline projects will need to clear a new — and potentially challenging — hurdle before they can secure a final OK from the Federal Energy Regulatory Commission (FERC). In its late-August ruling in Sierra Club, et al vs. FERC, the U.S. Court of Appeals for the District of Columbia Circuit said FERC’s environmental impact statement for the Southeast Market Pipelines Project, which includes the 1.1-Bcf/d Sabal Trail pipeline from west-central Alabama to central Florida, should have considered greenhouse gas emissions from gas-fired power plants the new pipelines will serve. Today, we explore the potentially far-reaching effect of the decision on midstream companies and the utilities that depend on them. The abundant supplies of U.S. natural gas made possible by the Shale Revolution — and the relatively low and stable gas pricing that came with that abundance — have played a significant role in reducing the volume of carbon dioxide (CO2) and other greenhouse gases (GHGs) emitted by the electric power industry. As shale-gas production increased over the past 10 years, electric utilities and independent power companies have scrapped their plans for new coal plants, retired scores of existing coal units and built dozens of new gas-fired plants (most of them highly efficient and operationally flexible combined-cycle facilities). Additionally, as abundant, low-cost gas supplies flooded the market (causing prices to drop), gas began beating coal economically for day-to-day generation. The net effect of this shift from coal to natural gas as the U.S.’s leading power plant fuel — plus the addition of new wind farms and solar facilities — has been a more than 20% decline in GHG emissions by the power sector since 2007. (The coal-to-gas shift has also helped to slash emissions of sulfur dioxide, mercury and other pollutants.)
Inspections show Line 5 coating gaps larger than disclosed - - Patches of bare metal larger than dinner plates are visible in photos of protective coating gaps on Enbridge Line 5 submitted to the state of Michigan this weekend. The photos are part of an initial report demanded by state officials who have noticeably soured on the controversial oil pipeline under the Straits of Mackinac.Seven pipeline "holidays," or areas of external anti-corrosion coating loss, are detailed in inspection documents sent to the state on Friday, Sept. 8, and obtained by MLive. Several holidays are larger than the "Band-Aid"-sized areas Enbridge initially described when the gaps were revealed. The largest patch of exposed pipeline metal is 16 inches long and 10 inches wide. Others are narrower but also exceed a foot in length. Also detailed in the reports is a "disturbed" coating area that's more than 3 feet long, a "dislodged" coating area that's 13 feet long and a mysterious 8-inch "white deposit" of unknown origin that Enbridge says "remains under investigation." The coating damage is the latest tough news for Line 5 this year, and some pipeline opponents think the angry response from Michigan officials signals intent to finally force the line's closure, a move that fossil fuel industry groups would likely oppose. Michigan officials were quick to demand repairs when the coating gaps were disclosed -- another surprise for regulators conducting a high-profile Line 5 public review that has thus far culminated in a roundly criticized independent report on feasible alternatives to Enbridge's continued operation of an unpopular pipeline. The news follows revelations that Enbridge was previously violating its easement for years by failing to properly support long spans on the line with anchors, which the company is presently seeking a state permit to install 22 more of this fall. Some of those anchors are in an area where inspections show the pipeline is bent and deformed. Line 5 is bent and deformed where Enbridge wants to anchor it The extent of coating failures, according to the Michigan Department of Environmental Quality, is troubling to the state, which was assured by Enbridge this spring that no areas of bare metal exposed to lake water existed on the pipeline after a federal work plan to investigate holidays surfaced in Chicago. When the external coating gaps were confirmed in August, Enbridge said there were only "two, possibly three" spots that were about 3 inches or so.
DRBC Acts to Ban Fracking in Delaware River Basin - NJ Spotlight: The Delaware River Basin Commission is initiating a process that could ban drilling and hydraulic fracturing for natural gas within the basin, the source of drinking water for 15 million people in four states. In a notice issued yesterday afternoon, the regulatory agency announced it would consider directing its staff to develop new regulations to address natural-gas development within the Delaware River Basin, including rules governing wastewater generated from drilling activities from outside the region. Natural-gas development is one of the more contentious environmental issues within the four-state region. Fracking — injecting huge quantities of water and some chemicals into rock formations to extract gas — has led to lower fuel costs for both consumers and businesses, as vast new supplies have been tapped in Pennsylvania and other states. Opposed to fracking But environmentalists and many communities oppose the practice, fearing it will contaminate drinking water. New York, one of four states on the commission, enacted a statewide ban on fracking last year. In moving to adopt new regulations, the DRBC is expected to initiate a rule-making process at a meeting tomorrow at Bucks Community College that would be published by the end of November. No drilling has occurred within the basin since the commission adopted a moratorium back in 2010. The moratorium was enacted to give time to adopt regulations governing drilling, but the commission never did so after some members balked. Environmental groups are happy the commission is moving to ban fracking within the basin, but were taken aback by the concurrent decision to consider adopting regulations for storage, treatment, and disposal of fracking wastewater within the region. They also oppose any effort to allow water withdrawals from the basin for natural gas drilling elsewhere. “We want a total ban on fracking from start to go,’’ said Maya van Rossum, Delaware Riverkeeper. “If you want to protect the watershed, you have to ban the entire process.’’
Regulators take step to ban fracking near Delaware River (AP) -- A commission that oversees drinking water quality for 15 million people took an initial step Wednesday to permanently ban drilling and hydraulic fracturing near the Delaware River and its tributaries, drawing criticism from the natural gas industry as well as from environmental groups worried that regulators would still allow the disposal of toxic drilling wastewater inside the area. The Delaware River Basin Commission, which oversees the river's water quality in Delaware, New York and Pennsylvania, voted 3-1, with one abstention, to begin the lengthy process of enacting a formal ban on drilling and fracking, the technique that's spurred a U.S. production boom in shale gas and oil. The watershed supplies Philadelphia and half of New York City with drinking water. The resolution approved by the commission says that fracking "presents risks, vulnerabilities and impacts to surface and ground water resources across the country," and directs the staff to draft regulations to ban it. Representatives of the governors of New York, Pennsylvania and Delaware voted for the measure. New Jersey's representative abstained and the federal government representative voted "no," drawing lusty boos from a strongly anti-fracking crowd attending the meeting outside Philadelphia. New York banned horizontal drilling and hydraulic fracturing statewide in 2015. Commissioner Mark Klotz, representing Democratic New York Gov. Andrew Cuomo, said the state is "strongly supportive of the resolution." Delaware's representative, Kara Coats, likewise expressed support. None of the other commissioners commented.Environmentalists were infuriated by provisions they said would allow the industry to draw water from the river and its tributaries for hydraulic fracturing outside the region, and to dispose of fracking wastewater within the Delaware watershed. "The frackers get our clean water and we get a Superfund site back. It’s a wolf in sheep’s clothing. This is not a deal that we should be making," Jeff Tittel, director of the New Jersey Sierra Club, told commissioners.
Twist in proposed Delaware River Basin fracking ban angers environmentalists -- A new proposal may permanently ban hydraulic fracturing within the massive Delaware River Basin, but not the disposal of waste from the process used to drill for natural gas, officials and environmental groups said Monday. The Delaware River Basin Commission announced a procedural vote is set for Wednesday on the new natural gas development draft regulations. The vote happening in Bucks County would pave the way for opening public comment until Nov. 30 on the proposal. "If the proposed resolution is approved by the commission on Sept. 13, the revised draft rules to be published on a later date would include prohibitions related to the production of natural gas utilizing horizontal drilling and hydraulic fracturing within the Delaware River Basin," the commission said in a statement. "The revised draft regulations would also include provisions for ensuring the safe and protective storage, treatment, disposal or discharge of hydraulic fracturing-related wastewater where permitted and provide for the regulation of inter-basin transfers of water and wastewater for purposes of natural gas development where permitted," the statement continued. The commission is a federal-state governmental agency responsible for managing water resources within the 13,359-square-mile Delaware River Basin that spans parts of Pennsylvania, New Jersey, New York and Delaware. Hydraulic fracturing, or fracking, is a process in which sand, water and chemicals are injected at high pressure deep underground to release natural gas. It's been used for years to draw the commodity from the Marcellus Shale geological formation underlying parts of Pennsylvania. The wastewater that is also generated can contain contaminants from the process and even radioactive elements brought up from beneath the surface. The basin commission's proposal to permit its disposal within the basin isn't sitting well with groups like the New Jersey Sierra Club.
Delaware, New York, Pennsylvania ban fracking in Delaware River Basin - - The governors of Delaware, New York and Pennsylvania, comprising a majority of the Delaware River Basin Commission, announced Sept. 13 they had voted in favor of a resolution put forward by the commission to issue draft regulations to permanently ban hydraulic fracturing for oil and gas in the Delaware River Basin. The DRBC vote was 3-to-1 with one abstention in passing the resolution for promulgating regulations that would prohibit any water project in the Delaware River Basin proposed for developing oil and gas resources by high-volume hydraulic fracturing. Delaware Gov. John Carney said that the DRBC resolution is consistent with the Delaware River Basin Conservation Act, a bill introduced by Carney and passed by Congress in 2016, by helping to ensure that the water resources of the basin will be protected for present and future generations. The Delaware River Basin, which drains from portions of New York, New Jersey, Pennsylvania, and Delaware, supplies drinking water to more than 15 million people. Governors of the four basin states and a federal representative serve as DRBC, tasked with overseeing a unified approach to managing the river system without regard to political boundaries. The commission has oversight in the basin for water quality protection, water supply allocation, regulatory review, water conservation initiatives, watershed planning, drought management, flood loss reduction and recreation.
Brooklyn considers fracking waste rule - — The Board of Selectmen thinks it may be time to put forward an ordinance to deal with petroleum fracking waste.The Conservation Commission asked the board to deal with the issue in the winter, but the board held off at the time. The state Department of Energy and Environmental Protection was looking at the issue at the time.“We need to take a hard look at this now,” said First Selectman Rick Ives. “I’m not sure DEEP is going to take care of this.”Petroleum fracking is a controversial practice. It involves drilling down a mile or more and then drilling horizontally several thousand more feet to create multiple wells. The wells are then pumped with a high-pressure mix of water, sand and additive to create micro-fractures in the rock. It’s the additives that concerns opponents most and it is the water, sand and additives that constitute fracking waste.According to the Natural Resource Defense Council, fracking directly poses a hazard to water, air and soil quality and diminishes the health of the communities it is based in. Proponents of fracking, however, claim it is a safe and cost-effective way to collect natural gas. Conservation Commission member Jeannine Noel attended a fracking waste workshop and said the practice occurs in about 30 states. It’s not fracking, but the byproducts the commission is most concerned about.
North Carolina delays decision on Atlantic Coast Pipeline - Faced with a Monday deadline and a lopsided number of public comments opposing the Atlantic Coast Pipeline, North Carolina Gov. Roy Cooper’s administration has delayed until mid-December its decision on whether to permit the controversial project.Without fanfare or press release late yesterday, the state issued a four-page “request for additional information,” part of its duty under the federal Clean Water Act to ensure the natural gas pipeline won’t harm the over 320 rivers and streams and hundreds of acres of wetlands in its path.Pipeline foes hailed the action, which appeared to vindicate a critique they’ve been leveling for months against the project, slated to hug the state’s I-95 corridor and pass through eight eastern North Carolina counties.“The current application leaves out critical information,” said Geoff Gisler, an attorney with the Southern Environmental Law Center. “There are literally hundreds of streams and wetlands that the company has asked to dig through with hardly any analysis.”The delay followed a series of rowdy hearings and meetings last month that were packed with pipeline opponents, and the receipt of over 9,000 written public comments – 85 percent urging rejection. “That’s an incredible number,” said Gisler. “That’s something you’d expect to see in a federal rule making that covers the whole country.”
Natural Gas Factbox: Southeastern US gas demand remains below pre-storm levels -- The US natural gas industry on Thursday continued to recover from the impacts of hurricanes Harvey and Irma, which struck the country's western and eastern Gulf coasts in a span of a few short weeks.Demand for gas from the power generation sector continued to lag behind pre-storm levels, especially in Florida and the rest of the southeastern US, as crews worked to restore electricity service to regions hard hit by Irma, while most interstate gas pipelines and gas utility companies reported only minimal disruptions to service as a result of the two storms.* Gas demand from the southeastern US power generation sector increased 554 MMcf day on day to 8.1 Bcf Thursday, some 679 MMcf below the September pre-storm average, according to data from Platts Analytics' Bentek Energy unit. This has driven total demand in the region up to 18.1 Bcf. * Demand from Florida generators increased another 127 MMcf to 3.4 Bcf Thursday. Throughput on the Florida Gas Transmission segment that feeds such demand has reached pre-storm levels, and volumes on the other main pipeline feeding the area, Gulfstream Natural Gas System, reached 929 MMcf, some 190 MMcf shy of the pre-storm average.* Deliveries from Transcontinental Gas Pipeline onto Sabal Trail Transmission Pipe Line remained about 250 MMcf/d below where they were prior to Irma and may not return to normal levels until the Florida power sample completely recovers, according to Platts Analytics.
Gas Shortages in Florida Reveal a Fragile Supply Chain -- In Gainesville, some 45 percent of gas stations are running dry as of Wednesday. In West Palm Beach, it’s 50 percent. And the price of gas has jumped nearly 30 cents on average—and that’s without the widespread price gouging that plagued Florida this past weekend. These are the tough realities Floridians who evacuated in the face of Hurricane Irma last week even as they begin to return home. An unprecedented six million fled from the Category 5 storm, the largest evacuation in U.S. history. The exodus created widespread gas shortages in the days before landfall, with the majority of South Florida gas stations dry by Thursday. Disabled and abandoned vehicles dotted northbound routes. It was a situation that paralyzed many Floridians who wanted to evacuate, as I found when I called several residents weighing their options. “They knew the hurricane was coming, but where was the backup gas?” a West Palm Beach woman named Adrienne Beauchamp wondered to me the same day. “Why wasn’t Florida more prepared?” I took her question and others to fuel experts. A car-dependent state with a history of hurricanes, Florida had a week before Irma hit to lay in enough fuel for residents to drive out of harm’s way—the choice mode of evacuation. Unlike states with more shared borders and freight infrastructure, roughly 97 percent of the refined fuel sold in Florida gets shipped in, from the Gulf of Mexico. Much of it usually come from refineries on the shores of Texas—which were devastated just weeks ago by the second-costliest storm in U.S. history, Hurricane Harvey. With Texas refineries knocked out of commission because of Harvey, Florida’s fuel suppliers were already feeling the squeeze before Irma’s path became clear. In fact, as of the week before Labor Day, according to Jim Storey, the business development director of the Georgia-based fuel distributor Mansfield Oil, Florida was trucking some of its own supplies over there to help out Texas. But as Irma predictions shaped up, the flow of fuel out-of-state was swiftly reversed.
Fuel cargoes line up as Florida's Port Everglades, Tampa set to reopen - Port Everglades on Florida's southeast coast and Port Tampa Bay on the west side are set to reopen Tuesday, allowing fuel cargoes to replenish supply drained by last week's massive evacuation for Hurricane Irma. Florida depends on tanker and barge shipments rather than pipelines for 97% of its refined products. Tampa receives deliveries from Texas and Louisiana refineries, while Port Everglades receives deliveries from the East Coast. Port Tampa Bay expects to reopen at 2 pm Tuesday (1800 GMT), spokeswoman Samara Sodos said. Four oil vessels were waiting to unload Tuesday morning. Tampa fuel terminals reopened Monday, dispensing stored fuel on to tanker trucks. The US Coast Guard was completing surveys of Port Everglades' navigation channels early Tuesday before the reopening, the port authority said. At 8 am (1200 GMT), three petroleum tankers, two cargo ships and three cruise ships were waiting to enter. Five of the 12 oil terminals at Port Everglades were operating, loading fuel trucks to supply retail stations. The port authority expects five more terminals to reopen midday Tuesday. Two refined products vessels are scheduled to arrive in Tampa this week, according to cFlow, S&P Global Platts trade flow software. The tanker Florida and tanker Louisiana are both scheduled to arrive Wednesday and make regular runs between Louisiana and Florida. The West Virginia is due to arrive in Tampa on Thursday, having left the New York area eight days ago. Several other refined products vessels are scheduled to unload at Port Everglades this week, including the Mare Pacific on Tuesday, the Overseas Nikiski on Thursday and the Mt Sea Halcyone on Friday, according to cFlow.
Tankers: Jones Act waiver spurs flurry of vessel bookings on USGC/USAC-Florida run The seven-day Jones Act waiver announced Friday by the Department of Homeland Security in recognition of the severity of Hurricanes Harvey and Irma prompted a flurry of fixing activity for non-US flagged Medium Range tankers loading gasoline on the US Gulf Coast and Atlantic Coast to sail to Florida. The Jones Act requires vessels transporting goods between US ports to be US-flagged, US-built and majority US-owned. "There have not been any [Jones Act] ships to work with prior to Irma; ships have been snapped up [after Harvey]," a Jones Act tanker broker said. Port Everglades on Florida's southeast coast and Port Tampa Bay on the west side reopened Tuesday, allowing fuel cargoes to replenish supply drained by last week's massive evacuation for Hurricane Irma. The waiver permits non-US flagged vessels to deliver US products within points in the US from September 8-15 as a precautionary measure to ensure that there will be enough fuel to support life-saving efforts, respond to the storm, and restore critical services and critical infrastructure operations, according to DHS acting Secretary Elaine Duke. A total of 11-12 Jones Act-waivered vessels have been placed on subjects on the USGC/USAC-Florida run since Friday, but shipbrokers believed a minimum of six had already failed. "Because of the hurricane damage on the USGC, people can't get their hands on the product," a shipbroker said, alluding to reduced refining capacity and limited drafts at USGC ports.
Phillips 66 makes use of Jones Act waiver (Argus) — Independent refiner Phillips 66 says it has chartered a foreign-flagged tanker under a Jones Act waiver President Donald Trump's administration issued to relieve hurricane-related fuel shortages in the southeast US. The refiner said it used the waiver to charter the Nave Jupiter, which is flagged in the Marshall Islands. The tanker left Houston on 9 September and was docked near Phillips 66's 250,000 b/d Alliance refinery in Louisiana today, according to vessel tracking data. The company says it chartered the vessel this week but declined to provide further details. Phillips 66 was earlier heard fixing a New Orleans-Florida gasoline shipment on the Nave Jupiter, although the fixture counterparties were unconfirmed. The company previously requested a Jones Act waiver to supply crude to the Alliance refinery, but the company withdrew the request before the administration made a decision. Phillips 66 is the first company known to use the administration's Jones Act waiver, a law that requires shipments between domestic ports to occur on US-flagged, owned and crewed ships. US Homeland Security acting secretary Elaine Duke this week signed an order extending the waiver through 22 September, citing "severe disruptions" that Hurricane Harvey caused to the midstream and downstream sectors of the oil industry. The latest waiver creates an exemption for shipments of petroleum products to Florida, Georgia, South Carolina, North Carolina, Virginia, West Virginia and Puerto Rico, from ports in New York, New Jersey, Texas, Louisiana, Mississippi, Alabama and Arkansas.ExxonMobil subsidiary SeaRiver Maritime was the only other company to request a Jones Act waiver in the wake of Hurricane Harvey, which made landfall in Corpus Christi, Texas, last month. ExxonMobil declined to comment on whether it intended to use the waiver.
Hurricane Irma’s Wrath Weighs On Natural Gas - Hurricane Irma has left millions of people without power in Florida, a critical situation that could take a painfully long period of time to sort out. Estimates vary, but some 9 million people lost power during Hurricane Irma, according to the CEO of Florida Power & Light, the state’s largest utility. As of Monday, an additional 1 million people lost power in Georgia and South Carolina as the remains of Irma moved north. While most attention has been paid to how the hurricane would affect oil and gasoline markets, particularly after Hurricane Harvey devastated Gulf Coast refineries two weeks ago, the massive power outages could also result in some disruptions in other energy markets. For example, about two-thirds of Florida’s electricity is generated from natural gas, and the outages could cause a dip in natural gas consumption. Just like how millions of people not driving in their cars after the hurricane could lead to a temporary decline in gasoline consumption, the millions of people without power for a period of time could cause some natural gas supplies to build up. Florida’s natural gas demand “fell from 4.43 Bcf/d on 9/7 to 2.74 Bcf/d on Monday (Sept. 11), a drop of 1.69 Bcf/d,” according to Genscape Inc., reported on by Natural Gas Intelligence. Taken together, the gas demand in Florida, Georgia and South Carolina plunged by a third between Thursday and Sunday from 9.47 Bcf/d to 6.21 Bcf/d. Most of the reduction was because of the electricity outages. The U.S. natural gas market has been sleepy since the end of last winter, with prices stuck around the $3 per MMBtu mark. Gas inventories have tracked within the five-year range for the better part of a year, after the extraordinary buildup in 2015 and 2016. A dip in gas production last year helped erase a bit of the glut, and the market stabilized this year as output rebounded and kept pace with demand. Florida’s power outages probably won’t knock the markets off course, but they could lead to a sharper-than-average gain in inventories a few months ahead of the start of winter season.
LNG Glut May Flip to Deficit as Cheniere Sees China Growth (Bloomberg) -- The global glut plaguing liquefied natural gas markets may start to dwindle in five years, threatening to spur a deficit equivalent to twice the output of leading producer Qatar. New projects are needed to fill the shortfall, with demand for the super-chilled fuel forecast to double in the 20 years to 2035, Cedigaz, a Paris-based industry research group, said in its LNG Outlook. Buyers in Asia are boosting use of the fuel at a “staggering” pace, Jack Fusco, chief executive officer of U.S. exporter Cheniere Energy Inc., said in a Bloomberg Television interview. While plants currently in operation or being built will add to global oversupply, aging facilities and shrinking resources in some areas mean capacity will start declining after 2021. That’s a boon for companies from Royal Dutch Shell Plc to Tellurian Inc. and Novatek PJSC looking to invest in new production in the next decade to meet demand. “The continuous growth of the LNG market will leave a large margin for the implementation of new projects,” Cedigaz said in the report emailed Thursday. The U.S. shale boom will make the country the biggest LNG producer by the end of the period, according to the Cedigaz report. Output will end in some nations such as Trinidad and Tobago. “I foresee that the LNG market needs at least a hundred million tons of new liquefaction capacity above what’s under construction today in order to meet demand needs of the market by 2025,” . “Demand is growing more than people expected.” Global LNG capacity is expected to peak at 387 million tons a year by 2021-2022 from 288 million tons this year at existing or under-construction plants, Cedigaz said. Trinidad and Tobago, the world’s ninth-biggest producer, will stop production in 2029. The Atlantic LNG venture in the Caribbean nation has already curbed output and cut its workforce due to feed-gas shortages. Algeria, Indonesia, Malaysia and even Australia, which next year will add more capacity than any other nation, will see declines in output by the end of the next decade.
September crude imports at LOOP up 10% from average following Harvey - The Louisiana Offshore Oil Port continues to experience a surge in crude oil imports more than two weeks after Hurricane Harvey hit the Texas Gulf Coast and prevented ports in that state from receiving crude for days.The LOOP oil terminal has received 4.1 million barrels of crude in September through Sunday, or about 410,000 b/d, according to Platts Analytics and the latest US Customs data available. That is the highest volume of crude imported into LOOP over the first 10 days of a month since May. LOOP typically receives about 370,000 b/d of crude through the first decade of the month, Platts data shows. By comparison, the three Texas ports to have received crude in September so far — Houston, Corpus Christi and Texas City — have taken in 4.3 million barrels, or just 200,000 barrels more than LOOP alone. Valero and ExxonMobil each accounted for 1.6 million barrels of the LOOP total in September while Marathon imported 550,000 barrels and an as-yet-unknown consignee brought in a further 400,000 barrels.Harvey’s disruption appears to have led to an increase in sweet grades into LOOP as well. LOOP customers typically focus on sour crude imports. However, since Harvey made landfall, 544,000 barrels of Nigerian Bonga was imported August 28 on the tanker SKS Spey while 400,000 barrels of Bonga was imported on the same tanker September 6. Prior to late August, no West Africa crude had been imported into LOOP since January. The cost to store crude at LOOP also has increased. LOOP sells the right to store a blend called LOOP Sour on a monthly basis. On Friday, 245 capacity allocation contracts, or CACs, representing 245,000 barrels, were cleared on CME for October storage at 20 cents/b. That is 5 cents/b more than the price for September storage, based on data published by Matrix Markets, which hosts the auction on behalf of LOOP.
Six companies buy oil from SPR (Reuters) - Six companies bought 14 million barrels of oil from the U.S. Strategic Petroleum Reserve in a sale required by law to help fund medical research and the federal government, said the Department of Energy on Thursday. BP Oil Supply, Exxon Mobil Corp, Phillips 66, Shell Trading, Valero Marketing and Supply Company, and Macquarie Commodities Trading bought oil from the reserve, which is held in salt caverns on the Texas and Louisiana coasts. The companies bought the oil at a range from $46.98 to $47.91 a barrel, slightly below the current futures price of about $49.70 per barrel, depending on which location the crude came from and whether it was sent by pipeline or directly to vessels, which could export the petroleum.
Largest U.S. refinery restarts production after Harvey: sources (Reuters) - The largest U.S. refinery was restarting production on Monday for the first time since being shut nearly two weeks ago by Hurricane Harvey, said sources familiar with plant operations. Motiva Enterprises restored the 325,000 barrel per day (bpd) VPS-5 crude distillation unit at its 603,000 bpd Port Arthur, Texas, refinery to minimum production levels early in the day, the sources said. After bringing the VPS-5 online, Motiva began restarting the 105,000-bpd Hydrocracking Unit 2, the sources said. The HCU-2 is a lucrative source of motor fuel exports for Motiva. Motiva did not immediately reply to requests for comment about operations at the refinery, which has been shut since Aug. 30 due to flooding from Harvey. Last Thursday, the VPS-5, HCU-2 and the 110,000 bpd coking unit were ready to resume production after being placed on circulation in which the units were at operating temperatures and circulating feedstock, the sources said. However, Motiva had been waiting for adequate crude supply to be restored to the VPS-5 before restarting production, according to the sources. Motiva said last week the Port Arthur refinery would resume production at 40 percent capacity by Monday. Motiva did not give a timeline for fully restoring output.
Harvey’s flooding blamed in major gasoline spill in Texas (AP) Hurricane Harvey’s floodwaters triggered a spill of almost a half-million gallons of gasoline from two storage tanks along the Houston Ship Channel, marking the largest spill reported to date from a storm that slammed into the heart of Texas’ huge petrochemical industry.The spill measured 10,988 barrels, or more than 461,000 gallons, and occurred at a petroleum tank farm in Galena Park operated by Magellan Midstream Partners, according to the Oklahoma-based company and accident reports submitted to federal officials.Some of the spilled fuel flowed into a waterway adjacent to the ship channel, a heavily-industrialized area that’s lined with dozens of petrochemical facilities, the reports said.Gasoline is more volatile than oil, meaning it evaporates more quickly after it’s spilled. But it’s also more likely to catch fire and can more rapidly penetrate the soil and potentially contaminate groundwater supplies. Magellan spokesman Bruce Heine said the gasoline that reached the small, unnamed waterway had been contained. The spilled fuel was sprayed with foam to prevent it from releasing harmful vapors, he said.
Tankers: Texas ports open but draft restricted as lightering rates jump -- Lightering day rates have soared as draft restrictions along the Texas coastline keep fully-laden dirty products tankers from coming into ports seen still dredging silt in the wake of Hurricane Harvey."Delays are killing everyone ... there are no safe itineraries right now," a source said as ports and the US Army Corps of Engineers work to get storm-ravaged port facilities back to pre-storm activity levels. All Texas ports are open with restrictions in place. The Houston Ship Channel below the Sidney Sherman Bridge is open with draft restrictions.The entrance to the channel to Houston Cement West is open to vessels with 40 to 42 feet drafts, according to shipping operations sources. Platts Ocean Intelligence is the go-to source of credit and due diligence reports for companies in the shipping and bunker sectors, helping to make informed decision in the high-cost, high risk maritime world. What distinguishes us from the competition is that we leverage the deep resources of S&P Global which enables us to embed our intelligence on companies within a larger market context and provides our reports with more insight and perspective. The draft is restricted to 36 feet from Houston Cement West to the Sidney Sherman Bridge and movement is restricted to daylight only, one-way traffic for larger vessels with prior approval and coordination between Houston Pilots Association and the US Coast Guard Vessel Tracking Service. The Corps has finished surveys and is carrying out dredging in different areas, shipping operations sources said, as well as issuing a contract for removal of 10 obstructions along the channel. Authorities are focused on getting the channel back to its pre-storm level of a 46 foot draft, using the mean low water, sources said. Calculating draft for the ship channel is a tricky proposition as it is dependent on cargo density. "Mexican and Venezuelan crude might draft too much."
New Drill Down Report on Permian NGLs -- Natural gas liquids production in the Permian Basin has doubled in the past four years, and may well double again by 2022. That rapid growth — driven by the pursuit of Permian crude oil and the resulting production of large volumes of NGL-rich associated gas — threatens to overwhelm the region’s existing gas processing and NGL-pipeline infrastructure. This is a big deal, because if there’s not enough gas processing and NGL takeaway capacity out of the Permian, exploration and production companies (E&Ps) in the U.S.’s hottest shale play would be forced to slow the pace of their development. Today we discuss highlights from our new Drill Down Report on Permian NGL production growth and the need for more NGL-related infrastructure. One of the surer bets in an energy industry rife with uncertainty is that production of crude oil, natural gas and natural gas liquids (NGLs) in the Permian will continue rising. The hydrocarbon resources in the best parts of the Permian are extraordinary, and E&Ps active in the play have — after considerable effort — cracked the code to wringing vast volumes of crude and NGL-packed associated gas from new wells there at a remarkably low cost per barrel of oil equivalent (boe). But production growth can only occur if sufficient supporting infrastructure is in place to process and transport all the crude, gas and NGLs emerging from wellheads across the 70,000-square-mile Permian region.
Lawyers Return With Lawsuit Blaming Earthquakes In Oklahoma On Fracking - A lawsuit that blames the fracking industry for increased earthquake activity in Oklahoma is back.Class action attorneys who are targeting a group of natural gas companies will now ask a federal court to send the case back to the state court in which it was filed. It was because their previous case would have been heard in federal court that they dropped it more than a year ago. “By disposing of fracking wastewater deep into the earth, Defendants introduced contaminants into the natural environment that caused an adverse change to it in the form of unnatural seismic activity,” says the second complaint of Lisa Griggs and April Marler, filed in August in Logan County District Court. “In other words, due to Defendants’ pollution of the environment, they caused the earthquakes at issue in this case.”This lawsuit is one of a few making similar allegations against the fracking industry:
- Sandra Lagra’s lawsuit was the subject of a 2015 Oklahoma Supreme Court decision that allowed her personal injury claim to proceed in Lincoln County District Court rather than before the Corporation Commission;
- Jennifer Cooper’s lawsuit is similarly still pending in Lincoln County; and
- The Sierra Club and Public Justice attempted to use the Resource Conservation and Recovering Act in a way it had never been used before, but U.S. District Judge Stephen Friot dismissed the case in April.
The two groups had alleged fracking caused the amount of earthquakes in the state to skyrocket – from 167 in 2009 to 5,838 in 2015. But Friot dismissed the case under a doctrine that allows the court to pass on deciding an issue when a state court has greater expertise in the area. “(I)t is plain that the Oklahoma Corporation Commission has brought to bear a level of technical expertise that this court could not hope to match,” Friot wrote. “The challenge of determining what it will take to meaningfully reduce seismic activity in and near the producing areas of Oklahoma is not an exact science, but it is no longer one of the black arts.
How man-made earthquakes could cripple the US economy - Dubbed the “Pipeline Crossroads of the World,” Cushing, Oklahoma is the nexus of 14 major pipelines, including Keystone, which alone has the potential to transport as much as 600,000 barrels of oil a day. The small Oklahoma town is also home to the world’s largest store of oil, which sits in hundreds of enormous tanks there. Prior to this recent spate of natural disasters, Cushing oil levels were already high. They’ve increased nearly a million barrels, to nearly 60 million barrels, since Harvey hit. This concentration of oil, about 15 percent of U.S. demand, is one reason the Department of Homeland Security has designated Cushing “critical infrastructure,” which it defines as assets that, “whether physical or virtual, are considered so vital to the United States that their incapacitation or destruction would have a debilitating effect on security, national economic security, national public health or safety, or any combination thereof.” The biggest potential cause of that incapacitation? According to Homeland Security, it’s not terrorism or mechanical malfunction. It’s natural disaster. And here’s the problem: When most of the Cushing tanks were constructed, the most logical cause of any such disaster seemed like a catastrophic tornado. No one anticipated swarms of earthquakes. But that’s what began occurring about five years ago, when wastewater injection and other fracking-related activities changed the seismic face of Oklahoma in dramatic fashion. When most of these tanks were constructed, seismic activity in Oklahoma was negligible. In 2011, the state experienced a 5.6 quake. Last year, it had a 5.8—the same magnitude as the quake that rocked Washington, D.C., and much of the Eastern seaboard six years ago. That Oklahoma event toppled the exteriors of historic buildings and prompted the Pawnee nation to declare a state of emergency. Seismologists at the United States Geological Survey say the area around Cushing is capable of an even stronger quake—maybe even a 7.0. Earthquake magnitude is measured exponentially, which means that a 7.0 quake would be 15 times larger than the biggest one to hit Oklahoma so far. And it would release over 60 times as much energy.
Colorado outlines new pipeline rules after fatal explosion — Colorado regulators made public a rough outline Wednesday for new rules for oil and gas pipelines after a fatal house explosion blamed on a natural gas leak. The state Oil and Gas Conservation Commission's outline calls for new standards for designing, testing and permanently shutting down flow lines, which carry oil or gas from wells to tanks and other gathering equipment.The outline was dated Sept. 8 and posted online Wednesday. The commission's staff plans to complete draft rules by Oct. 15 after meetings with interested groups on Sept. 21 and 22.A formal public hearing is scheduled for Dec. 11 and 12, and the commission could vote on adopting the rules after that.The rules are in response to an April explosion in the town of Firestone that killed two people and injured a third. Investigators blamed the explosion on odorless, unrefined natural gas leaking from a flow line that was thought to be out of service but was still connected to a well with the valve turned to the open position.The house that exploded was within 200 feet (60 meters) of the gas well, and the flow line was severed about 10 feet (3 meters) from the house, officials said. Investigators said gas seeped into the home's basement.The well and pipeline were in place several years before the house was built.The new rules would require oil and gas o perators to provide information about flow lines to the existing Call 811 program, which marks the location of underground utilities at a property owner's request.
Neighbors are fed up with fracking smells, noises in Erie subdivision - Denver7 -- The fracking debate over how close is too close to homes is playing out in Erie's Vista Ridge subdivision. "We paid extra for the view, and now it's been marred," said resident Christiaan van Woudenberg. Van Woudenberg's house is less than a thousand feet from the Pratt fracking site, and he can see another drill site to the west. Both are operated by Crestone Peak Resources. "The smell was like someone had stuffed your noise into a gas tank of a diesel truck," explained van Woudenberg. "I haven't been able to spend a single evening outside." Neighbors are fed up with the smell, and constant noises coming from the site at all hours of the day. "The noise is what keeps us up at night," said van Woudenberg. He took a video of the noise with a sound monitor late Wednesday night, and again Thursday morning. "Not only do you see it, but today, in particular, you hear it," van Woudenberg says in the video. You can hear a loud rumbling noise coming from behind the sound barrier in the video he recorded on his cell phone. "Highest peak there at about 70 decibels on the C-scale," said van Woudenberg, which is the highest measurement he's taken with his equipment. "Wake people up at literally three and four in the morning," said Ani Hulse, who lives down the street. Hulse said they've tried to get the Colorado Oil and Gas Conservation Commission, which regulates the industry, to take action.
Wisconsin budget bill strips local government control of quarries - lacrossetribune.com: Last-minute changes to the state budget would strip local governments in Wisconsin of the right to regulate quarries, and some fear the proposals could be expanded to take away town and county control over the frac sand mines that dot the western part of the state. The Legislature’s budget-writing committee last week approved a package of changes to the spending plan. In addition to stipulations on transportation funding and policy issues, the 18-page memo includes five pages of language devoted to the regulation of quarries that supply sand and gravel for construction. Among other things, it prohibits counties and municipalities from regulating blasting, hours of operation, and noise, air and water quality. It would also limit the reach of local zoning laws. The amendment threatens “100 years of tradition of local control — letting local people make land use decisions,” said Timothy Zeglin, vice chairman of the Trempealeau County Board. Fellow supervisor Jeanne Nutter said without control local officials can’t be accountable to their constituents. “Who are they going to call?” she said. “If there’s a problem. Are they going to call Madison? The DNR? Madison isn’t always going to know what’s going on in Trempealeau County.”
Minn. regulators recommend against $6.5B pipeline project | TheHill: Officials in Minnesota will recommend the state utilities commission reject a permit for an $6.5 billion pipeline project due to cross the state. The state’s Department of Commerce said Monday that Enbridge’s proposal to replace its Line 3 pipeline would not benefit the state and instead pose environmental risks. It will ask the Minnesota Public Utilities Commission to deny a permit for the project, a decision due next year. “In light of the serious risks and effects on the natural and socio-economic environments of the existing Line 3 and the limited benefit that the existing Line 3 provides to Minnesota refineries, it is reasonable to conclude that Minnesota would be better off if Enbridge proposed to cease operations of the existing Line 3, without any new pipeline being built,” the Department of Commerce said.Enbridge is looking to replace its 1960s-era Line 3 pipeline, which transports oil from Alberta to terminals in Minnesota and Wisconsin. It secured Canadian approval for the 1,031-mile, 760,000-barrel-per-day project in November, and construction is underway on a small portion of the pipeline in Wisconsin. A Minnesota Commerce Department study issued last month said that the proposed route through the state would affect fewer drinking water and cultural sites than the current pipeline, but impact areas of importance to recreational and tourism industries, Minnesota Public Radio reports. Environmentalists and Indian tribes in Minnesota have opposed the project, though Enbridge has said it can operate the pipeline safely and that it would be an upgrade over its current infrastructure.
Desjardins suspends oil pipes lending -- Desjardins temporarily suspended lending for energy pipelines projects on 7 July due to concerns about the impact such projects might have on the environment. The largest association of credit unions in North America, Desjardins Group said it had no intention of pulling out of current financing or investment activities but it was taking time to define its position. The group is still committed to a CAD $145m loan for Kinder Morgan Canada Ltd’s pipeline. According to a spokesman, Desjardins wants to ensure that “its business practices, its co-operative values and its position in regard to social responsibility and sustainable development are all aligned”. The move comes after Desjardins’ president and chief executive, Guy Cormier, asked the teams involved to work on establishing a global position for all of Desjardins’ financing and investment activities, based on its principles of responsible investing. “We are still in the process of defining our final position on this issue and a decision is likely to be taken by this fall,” said the spokesman. Responding to Desjardins’ moratorium on pipeline financing, Greenpeace Canada Climate and Energy campaigner Patrick Bonin, said: “This decision shows that astute financial institutions are becoming increasingly wary of financing fossil fuel projects. Tar sands pipelines pose major risks, whether you are concerned about profits, human rights, the environment, or all three. Desjardins has made the right decision by announcing a moratorium on investments in and financing of oil pipelines, and we look forward to it becoming permanent.”
Canada, N.Dakota crudes surge on Harvey after-effects (Reuters) - Light, sweet crude out of Canada and North Dakota surged to their highest levels in over four years on Thursday, as Midwest and East Coast refiners bid heavily for those grades after Hurricane Harvey upended energy markets in the U.S. Gulf. Widespread flooding following the giant storm forced several U.S. Gulf Coast refiners to shut, idling a quarter of nationwide refining capacity. Many of those refiners are only now rumbling back into operation. The shutdowns had a twofold effect for Midwest refineries. It pushed U.S. oil to its lowest point against Brent crude in two years, cheapening Bakken and Canadian grades for Midwest buyers. It also boosted refining margins, creating a unique opportunity for the likes of Marathon Petroleum, HollyFrontier Corp and others. Those refiners delayed scheduled work to take advantage of the stronger returns, bid up physical barrels and ran their refineries at higher-than-usual rates for this time of year. Canadian prices are higher due to demand by Midwest and East Coast refiners “anxious to cash in on higher margins while Gulf Coast plants remain offline,” said Sandy Fielden, director of oil and products research at Morningstar. He said the wider Brent/WTI spread signals that excess crude will head into the export market as soon as ports return to normal service. Canadian light synthetic prices were already higher after Canadian Natural Resources Ltd’s Horizon project in northern Alberta, one of the largest sources of supply, started a 45-day turnaround and had a fire at the plant on Monday. “It’s going up a dollar a day. It’s wild,” said one Calgary-based broker. “Nobody saw this coming.” Synthetic crude for October delivery hit $6.25 a barrel over WTI in mid-morning trade on Thursday, according to Shorcan Energy brokers. On Tuesday it closed at a premium of $3.15 per barrel.
China’s CNOOC cancels Aurora LNG project in B.C. - China's CNOOC Ltd. has cancelled a liquefied natural gas project planned for northwest British Columbia. The goal had been to build an LNG terminal on provincial Crown land on Digby Island, located less than four kilometres away from Prince Rupert Airport. But CNOOC, through its Calgary-based Nexen unit, and its partners announced on Thursday that they have decided to scrap Aurora LNG. "Over the past four years, Aurora LNG has been conducting a thorough feasibility study on liquefying and shipping LNG from the northwest coast of British Columbia to Asian markets," the consortium said in a statement on Thursday. "Through this feasibility study, Aurora LNG has determined that the current macro-economic environment does not currently support the partners' vision of developing a large LNG business at the proposed Digby Island site." Through Nexen, CNOOC owns 60 per cent of Aurora LNG, while the remaining 40 per cent is held by Inpex Corp., JGC Corp. and JOGMEC, all based in Japan. "While disappointed in this outcome, Aurora LNG is proud of its work in northwest British Columbia over the past three years and the relationships it has built with local community members, Indigenous groups, stakeholders and government," the consortium said. "The partners are committed to a responsible and orderly conclusion of their activities in the Prince Rupert region."Aurora LNG is the latest group to halt plans to export fuel from the West Coast to Asia.Pacific NorthWest LNG, led by Malaysia's state-owned Petronas, cancelled its construction plans for northwest B.C. in July. There have been more than 20 British Columbia LNG ventures pitched in recent years. Woodfibre LNG is the lone B.C. LNG venture so far to decide that it is worthwhile to build despite sharply lower prices for the fuel in Asia.
Canada Gas Set to Strike Back Against US Shale as Glut Eases | Rigzone -- Canadian natural gas, locked in a fierce battle for market share with U.S. shale, may stage a modest recovery as output from some longtime producers wanes and pipeline maintenance ends. While Canadian gas will almost always trade for less than U.S. gas -- due mostly to the cost of moving the fuel to markets in Texas and the American Midwest -- the discount recently widened to the most since 2005. The culprits are prolific new wells that are hard to shut off, along with outages on a network of pipelines that move gas around Alberta. But with the pipeline repairs that caused those disruptions mostly completed and producers like Royal Dutch Shell Plc and Petroliam Nasional Bhd's Canadian unit dialing back on output in British Columbia, the glut of Canadian gas may ease. Higher prices would be a boon for Canadian producers that have been forced to cut costs and seek new outlets in the face of escalating competition from the U.S. shale gas boom. "The Canadian operators -- given the differential problems they've had over the past few years -- they've gotten pretty adept at trying to operate this kind of environment," said Jeremy McCrea, an analyst at Raymond James Ltd. in Calgary. "So if that differential did narrow, they're set up to take advantage." Canadian gas, which is tracked using benchmark Alberta Energy Company prices -- AECO for short -- traded at $2.70 per million British thermal units less than the U.S. benchmark Henry Hub gas price on Tuesday, the steepest discount since December 2005. It narrowed to $1.33 on Wednesday. The spread has been especially volatile for the past two and a half months because of outages on TransCanada Corp.'s NGTL system in Alberta. The pipeline company has been working on a C$1.3 billion ($1.1 billion) upgrade, including the addition of compressor stations to increase capacity. That project, which is nearing completion, will increase the capacity of the northwest portion by about 700 million cubic feet a day, the Calgary-based company said in an emailed statement. Many sections are completed and operating again, and others will be back in service this month.
U.S. shale sector at critical price threshold - (Reuters) - Forward U.S. oil prices for 2018 have climbed back above $50 per barrel, a level that should be high enough to stabilise drilling activity over the next two months.But if prices continue their current upward trend, shale firms will almost certainly interpret that as a sign to increase output and begin ramping up their drilling programmes again.Shale drilling has proved very sensitive to changes in the value of West Texas Intermediate (WTI) crude, especially the forward prices shale firms rely on to hedge production and reduce their risks.Between February 2016 and January 2017, the progressive increase in forward prices encouraged shale producers to boost output by hiring extra drilling rigs (http://tmsnrt.rs/2jsXK7g).The number of rigs drilling for oil, which had been falling during the industry slump, started to increase again from May 2016, and oil output began to rise from October 2016.Rig counts typically respond to a change in oil prices with a lag of 16-20 weeks, while output tends to respond after an additional delay of five to six months.By January 2017, however, the rapid escalation in the rig count implied a large increase in production that threatened to overwhelm the market.Forecasts by the U.S. Energy Information Administration showed crude and condensates output growing by more than 0.5 million barrels per day (bpd) in 2017 and almost 1.0 million bpd in 2018.To temper the drilling boom, forward prices began to slide, with the WTI calendar strip for 2018 declining from more than $57 in January to a little over $45 in June. The calendar strip is the benchmark against which shale producers hedge production so the sharp drop sent a strong signal to ease back on drilling programmes (http://tmsnrt.rs/2f8Mqfv).The rig count levelled off in July and has been falling since August, according to oilfield services company Baker Hughes, in a lagged response to the decline in prices earlier this year (http://tmsnrt.rs/2juapHt). During their second-quarter earnings calls with investors, held in August, many shale firms announced a reduction in capital expenditure and drilling programmes for the second half of 2017. It was widely seen as a tap on the brakes to assuage investors’ concerns about overproduction and falling prices. Harold Hamm, chief executive of Continental Resources, one of the largest shale oil producers in North Dakota and Oklahoma, has said prices need to be above $50 to be sustainable.
US crude oil output to average 9.25 mil b/d in 2017, 9.84 mil in 2018: EIA -- The US Energy Information Administration on Tuesday lowered its forecasts for US crude oil output both this year and next, but still expects domestic production records to be broken next year. In its Short-Term Energy Outlook, the agency said it expects US crude output to average 9.25 million b/d in 2017 and 9.84 million b/d in 2018. Those estimates are 100,000 b/d and 70,000 b/d, respectively, lower than last month's estimate, but the expected 2018 average would mark the highest annual average production in US history, according to the EIA. The previous record dates back to 1970, when the US averaged 9.6 million b/d. EIA expects much of the growth to take place onshore, in the Lower 48 states, where daily output will climb from 6.76 million b/d in 2016 to 7.08 million b/d in 2017 and to 7.58 million b/d in 2018. Production in the Gulf of Mexico is forecast to climb from 1.69 million b/d in 2017 to 1.78 million b/d in 2018, while oil production in Alaska is expected to drop slightly over that time, from 490,000 b/d to 480,000 b/d, according to EIA. Overall, US production is forecast to climb from 9.29 million b/d this month to 9.69 million b/d by the end of the year. Output is expected to, for the first time, cross the 10 million b/d threshold in November 2018, when it is forecast to average 10.02 million b/d. EIA also forecast WTI spot prices to average $48.83/b in 2017 and $49.58/b in 2018, essentially the same as it had forecast in last month's report. EIA also forecasts Brent to average $51.07/b in 2017, down 65 cents/b from last month's forecast, and $51.58/b in 2018, the same as it forecast last month.
In sign of oil rebalancing, North Sea floating storage shrinks (Reuters) - The volume of global price benchmark North Sea crude being held in floating storage has declined sharply since mid-August, according to shipping data and trade sources, a sign that a long-awaited market rebalancing is gaining momentum. Two supertankers being used to store North Sea crudes offshore the UK, Desimi and Gener8 Neptune, contain about 4 million barrels of oil, trade sources said. Three weeks ago, the total was closer to 10 million barrels. The clearing of the crude to destinations including China and South Korea has been encouraged by a rise in the price of Brent crude for delivery soon relative to later supplies, trade sources said, a feature known as backwardation. “The whole market is tightening up,” said a North Sea trade source. “Crude inventories have been drawn down, and there is no direct economic incentive for floating storage.” The North Sea is home to the dated Brent benchmark, which is underpinned by Forties crude and three other grades. A stronger North Sea price can affect the wider market, as Brent is used to price oil around the world and underpins the futures market. Brent futures have moved back into their pre-Hurricane Harvey backwardation after concern of a significant drop in crude demand failed to materialise. With the Brent market in backwardation, the economic gain from keeping the crude in floating storage is removed. South Korea and China are regular buyers of North Sea Forties crude when the arbitrage is open.The volume of floating storage in the North Sea built up earlier this year amid a global crude glut and the price of oil being higher for future supplies, a feature known as contango.
Offshore Drilling Giant Seadrill Files For Bankruptcy --Seadrill Ltd., the London-based offshore driller controlled by billionaire Norwegian shipping magnate John Fredriksen, filed bankruptcy protection in the Southern District of Texas after working out a deal with most of its senior lenders to inject $1 billion of new money into the company pursuant to a pre-arranged plan of reorganization. The filing was largely expected and came just a couple of days before the company's $843 million 5.625% Notes of 2017 came due. According to Bloomberg, Fredriksen spent more than 18 months trying to strike an agreement with creditors to restructure the industry’s biggest debt-load after crude’s collapse curbed demand for Seadrill’s services. Daily leases for the company’s rigs, which once commanded up to $800,000, have dropped to around $200,000 as cheap oil from U.S. shale drilling continues to flood the market.“The deal gives us a great liquidity cushion,” allowing Seadrill to survive the “mother of all downturns,” Chief Executive Officer Anton Dibowitz said by phone. The new capital is “underpinned” by top shareholder Hemen Holding Ltd. and more than 40 percent of bondholders support the plan along with 97 percent of Seadrill’s secured bank lenders, he said. Dibowitz expects more bondholders to sign up to the deal.Bondholders are currently predicting their ultimate recovery is worth about 25 cents on the dollar as of today. Of course, Seadrill is just the latest bankruptcy filing in an industry that has been devastated by persistently weak commodity prices. In late July, Ocean Rig UDW Inc. filed for bankruptcy protection in the U.S. Hercules Offshore Inc., GulfMark Offshore Inc., Toisa Ltd. and Vantage Drilling Co. have also spent time in bankruptcy court since oil and gas prices cratered. Paragon Offshore PLC emerged from Chapter 11 in August but was forced back into bankruptcy after it was unable to transfer two rigs to its reorganized entity. Its successor, Paragon Offshore Ltd., isn’t under bankruptcy protection and was unaffected by Paragon Offshore PLC’s new filing.
Oil-rich Norway struggles to beat its petroleum addiction - For climate reasons as much as economic prudence, Norway is trying to cut its dependence on oil, a godsend that has made the small Scandinavian country rich beyond its dreams -- which is exactly what makes it hard to pass up. ‘Black gold’ has enabled Norway to build up the world’s largest sovereign wealth fund, currently worth close to $1.0 trillion. Yet several small political parties have raised their voices ahead of the country’s legislative elections on Monday to make sure Norway puts its oil days behind it. “We want the end of all new oil exploration,” Rasmus Hansson, one of two co-leaders of the Greens Party, told AFP. “We will not support a government that doesn’t accept our ultimatum.” The party, which according to several opinion polls could end up in the position of kingmaker, also wants to phase out Norway’s entire oil industry within 15 years. A country of 5.3 million people, Norway has become very much aware of just how petroholic, or addicted to petrol, it is — especially since the recent drop in oil prices has erased 50,000 jobs from the industry.
Floating tar, dead fish: oil spill threatens Greek beaches - The Greek authorities scrambled on Thursday to clean up fuel leaked by an oil tanker that sank near Athens, putting popular beaches off limits to swimmers and raising fears of environmental damage.The Agia Zoni II, a 45-year-old oil tanker, sank early Sunday morning near the island of Salamis, about seven miles from the country’s main port, Piraeus. It was carrying more than 2,500 metric tons of fuel oil and marine gas oil.Though the leak was initially thought to be contained to the area of the shipwreck, it soon expanded to the coastline area known as the Athens Riviera.Evaggelia Simou, a resident of Salamina, on the island, denounced the authorities for not tackling the oil spill more quickly and fully. “We drove by the Selinia beach on Sunday night, and were alarmed because of the suffocating smell of oil,” Ms. Simou said in a Facebook chat. When she and her husband went to the beach, they were shocked to see that a thick coat of oil had blackened the water. “Huge pieces of floating tar were burdening the waves, dead fish floated on the surface,” Ms. Simou said. They were surprised to see no cleanup workers, she said.Ms. Simou returned to the beach on Monday morning, along with her son, and was stunned to see no sign of an active cleanup, more than 24 hours after the shipwreck. Thick, black masses of oil had reached the beaches around Glyfada, a high-end seaside community south of Athens, by Wednesday afternoon.George Papanikolaou, the mayor of Glyfada, said he got a phone call from the Piraeus harbor master warning of the spill only a few hours before the black ooze washed up. “The vessel sank on Sunday. How is it possible that the leak reached Glyfada from Salamina?” Mr. Papanikolaou asked in a phone interview. “And how is it possible that we only heard about it on Wednesday?”
Footage of Greek Oil Spill Shows Massive Scale of Damage - The sinking of a tanker carrying 2,200 tons of fuel oil and 370 tons of marine gas oil has coated some of Greece's most popular beaches in thick, black sludge, leading to health authorities to ban swimming along shorelines in Athens. The Agia Zoni II tanker sank Sunday off the coast of Salamina island and left behind "a huge environmental and financial disaster," Salamina mayor Isidora Papathanasiou told local news , adding that the "smell is intense and our eyes are stinging." The mayors of Salamina, Piraeus and Glyfada warned they might take legal action over the pollution "against whoever is responsible." Greece's government has been criticized for not doing enough to prevent the oil slick from spreading to the Saronic Gulf in Athens, a region home to a wide variety of marine life including dolphins, turtles, fish and sea birds. "If a small relative leak causes such a disaster next to the country's largest port and the operational center of the Ministry of Mercantile Marine, what exactly is the country's ability to cope with spills and accidents from large-scale oil activities in the Ionian Sea and the Cretan Sea?" said Takis Gregoriou, the head of the campaign for climate change and energy at Greenpeace Greece , in a statement. World Wildlife Federation Greece also called the spill an "environmental crime." After touring affected areas, shipping minister Panagiotis Kouroumblis insisted that the situation is improving. He said that cleanup is underway and also suggested Thursday he would resign if asked by Prime Minister Alexis Tsipras, according to Greek Reporter . The Associated Press reports that Greece has requested help from the European Union's Civil Protection Mechanism and deployed a specialized cleanup vessel.
BP and partners sign new 25-year Azerbaijan oil production sharing contract - BP and its partners in Azerbaijan's giant ACG oil production complex agreed Thursday to extend the production sharing contract by 25 years to 2049 and to increase the stake of state-owned SOCAR, reducing the size of their own shares. SOCAR stake raised at partners' expense Deal accesses 2 billion more barrels The Azeri-Chirag-Deepwater Gunashli (ACG) complex in the Caspian Sea produces most of Azerbaijan's sought-after crude oil. At the time of the signing of the original production sharing contract in 1994, it was seen as a major advance by the international oil industry into the former Soviet state, dubbed the "contract of the century." Output has been declining for a number of years, however, falling particularly steeply in the first half of this year -- by 11% compared with a year earlier -- to 585,000 b/d, despite the startup of a new platform in 2014 at a cost of $6 billion. Under Thursday's deal, the international companies will pay a $3.6 billion bonus to the state oil fund over a number of years. The international partners comprise BP, currently with a 35.8% stake; Chevron with 11.3%; Japan's INPEX with 11%; Norway's state-controlled Statoil with 8.6%; ExxonMobil with 8%; Turkey's TPAO with 6.8%; Japan's ITOCHU with 4.3%; and India's ONGC Videsh with 2.7%. The extension of the production sharing contract, which was to expire in 2024, was seen as necessary to ensure continued investment. The altered shareholder structure also gives SOCAR a greater share of production and greater spending obligations as its stake in the consortium rises from 11.6% to 25%. Total operating costs last year for ACG were $503 million, and capital expenditure was $1.45 billion. BP said the deal would enable the partners to access an additional 2 billion barrels of economically recoverable oil from the end of the current version of the production sharing contract. The partners will carry out preliminary engineering work to evaluate the possible addition of another platform, it added. The deal cuts BP's stake by 5.43% to 30.37%, with corresponding reductions for the other partners.
Did This Oil & Gas Deal Just Change The Global Energy Balance? - One of the biggest energy stories this year has been Russia’s Rosneft buying India’s Essar Oil - giving the Russian company a firm grip on one of the world’s biggest emerging oil and gas markets. And this past week, that story got more complex. With Rosneft striking another big deal — drawing in another heavyweight energy nation. China. Rosneft announced Friday it is selling a significant chunk of its equity to Chinese investors. In this case, little-known exploration and production firm CEFC China Energy. Although few investors know CEFC, the company is bringing significant capital to the deal. With the firm agreeing to pay $9 billion to acquire a 14.16 percent stake in Rosneft. The deal is historic in being the first major buy-in by China into the Russian oil and gas sector (although Chinese firms have been involved in financing LNG export projects in the Russian Arctic).Showing the strength of the ever-growing ties between Russia and China in the energy space. Rosneft and CEFC have been at the center of that burgeoning relationship. With the two companies having signed a deal this past September for long-term supply of Russian crude into China. This week’s equity purchase further cements those business ties. And shows that China sees Russia as a critical ally in the energy game going forward.But there are implications well beyond these two countries. With China now having backdoor access into markets like India — through Rosneft’s recently-acquired holdings in that country. That’s a critical development for the world energy picture. Given that Chinese companies haven’t directly gained much access into India — despite the nation being one of the most important emerging players on the energy stage. Ownership in Rosneft could help change that. And could open up opportunities in other parts of the world — with Rosneft currently having operations in places ranging from Egypt to Brazil to Venezuela.
India's Energy Crisis Just Went "Super Critical" -- Big disappointment in the global natural gas industry this week, with majors Total and Eni coming up largely dry in a much-anticipated well offshore Cyprus. But elsewhere things are turning extremely bullish for natgas. With one of the world’s fastest-emerging energy consumers scrambling to get all the supply it can. India. Local media reported this week that India’s power generators are seeing a sudden surge in natgas buying because of an “acute” shortage in the country’s go-to energy fuel: coal. After enjoying years of ample coal supply, India’s power sector has seen inventories slip drastically into the red in recent months. With ten major power plants classified as “critical”, with less than seven days of coal stocks — and five of those being “super critical” with less than four days of coal supply. And that drastic shortage has reportedly turned these generators to natural gas in a major way. Sources said India’s generators have purchased 10 million cubic meters (350 million cubic feet) during “the last couple days”. Indicating energy producers are getting desperate in keeping their operations in business amid the coal shortage. This potentially has long-term implications for global natural gas. Because of a peculiar feature of India’s energy landscape: a fleet of unused gas-fired plants. India in fact has over 25 GW of installed gas-driven generating capacity. But here’s the thing: 55 percent of that capacity usually never runs. Because it’s “technically stranded” — having no access to natgas feed at commercially-competitive prices. But the coal crisis is changing the economics here. Power operators are so desperate to keep the lights on, they’re willing to pay the higher prices required to deliver gas to the stranded power plants — causing this week’s major surge in natgas buying. If the coal shortage persists, that demand could become permanent. Watch for weekly data on coal stocks at India’s power plants, and stats on natural gas usage across India — which could have knock-on effects on imports.
ExxonMobil slashes LNG price to India in bad omen for producers (Reuters) - India has won a price cut on a 20-year liquefied natural gas (LNG) deal with global giant ExxonMobil in a rare contract renegotiation, a bad sign for producers in a heavily oversupplied global market. In a trade-off for ExxonMobil, India’s Petronet LNG will increase its volumes from the Gorgon LNG project in Australia by an extra 1 million tonnes a year to about 2.5 million tonnes a year, but at cheaper rates than initially agreed in 2009. Long-term contracts are rarely revised in the LNG market, and for a big producer to cave in shows how supply from new plants in Australia and the United States over the past two years has transformed the market, analysts said. “This trend is overall a negative for sellers, as they are forced to provide more flexibility to buyers’ needs to maintain their markets,” said Saul Kavonic, an analyst with energy consultants Wood Mackenzie. India has been aggressive in seeking cheaper deals, also renegotiating a contract with Qatar in 2015, but the real pain for producers would come if major Asian buyers in Japan, Korea and China followed suit. “Happy to share good news that India has, yet again been able to address the long term price issue of LNG from Gorgon to suit Indian market,” India’s oil minister, Dharmendra Pradhan, said on Saturday on social media. Indian consumers would soon receive LNG at an “amicable price”, Pradhan said. India started receiving Gorgon supplies from January this year. Petronet said in a stock exchange announcement on Monday it had reached a “broad understanding of terms” with ExxonMobil, without giving further details.
Exxon Mobil's deal to cut India LNG prices is actually quite good: Russell (Reuters) - Exxon Mobil’s deal to cut the price of liquefied natural gas (LNG) supplied under long-term contract to an Indian buyer has largely been viewed as a bad outcome for producers of the super-chilled fuel. Certainly the trade made by Exxon to supply more LNG to Petronet LNG, but at a lower price, does seem to favor the Indian utility. Exxon will increase the volume supplied from its share of the Chevron-led Gorgon project in Western Australia by 1 million tonnes a year to about 2.5 million tonnes, but at a lower cost than originally agreed in 2009. The revised deal has sparked market speculation that this is the first domino to fall, and that more re-negotiations of long-term LNG contracts are likely. Up until now it has been extremely rare for these agreements to be amended, and so far, it has only been in India, where a deal with top LNG supplier Qatar was re-worked in 2015. Producers are probably nervous that major buyers in Japan, South Korea and China, which account for more than half of the global LNG market, will be tempted to seek better terms. Already there are some moves towards this end, with utilities in Japan banding together to pool their buying power and seek more flexible and shorter-term deals. What the Exxon-Petronet deal is a further sign of is that the era of long-term LNG contracts with prices linked to moves in crude oil are going the way of the dinosaurs. The market is already moving towards both spot and short-term deals, ranging from several months to a few years.
Political headaches as China sucks up Australian coal, LNG - (Reuters) - When is rising Chinese demand for your natural resources not a good thing? When you are Australian and higher prices for coal and liquefied natural gas (LNG) are causing domestic shortages and soaring electricity prices. In theory it should be great days for Australia’s economy and resource companies, and even Australian politicians keen to take the credit for booming exports and the associated jobs. But the world’s largest exporter of coal, and second-biggest of LNG, is discovering that export success can quickly become a politically-charged hot potato when it is linked to rising costs for local consumers. First the three new LNG plants in the eastern state of Queensland were accused of sucking up natural gas supplies, driving up prices and potentially causing supply shortages. This was a bit of a stretch as only one of the three projects was capable of using natural gas that may have otherwise been made available to the domestic market. Still, the perception that LNG exports were driving domestic prices higher stuck, leading the Liberal Party-led federal government of Prime Minister Malcolm Turnbull to introduce a mechanism to divert natural gas to the domestic market if the demand is there. It’s not clear whether this solution will work in practice, as the main problem appears not to be the domestic availability of natural gas, rather that the local price is effectively linked to what supplies can be sold for as LNG exports. As one analyst put it, if natural gas is available in Queensland at the same price as LNG, and nobody wants it, is there still a shortage?The situation has been complicated by governments in the populous states of New South Wales and Victoria, home to the major cities of Sydney and Melbourne respectively, acting to restrict or ban the production of onshore natural gas.
Analysis: Iranian oil flows gain further ground in China, Europe - Iran's crude and condensate exports rose slightly in August as lower deliveries from key competitors like Saudi Arabia and Iraq meant there was more demand for crude from some of Iran's main buyers. Total estimated export volume on Aframaxes, Suezmaxes and VLCCs from Iranian ports in August rose almost 2.5% to 2.42 million b/d from 2.37 million b/d in July, according to data from Platts trade flow software cFlow. Exports to Asia fell to 1.46 million b/d in August from 1.55 million b/d in July, with demand from key customer India down sharply, although flows to China continued to rise. Europe's share of Iranian exports grew sharply, with demand from Italy, France, the Netherlands and Greece all up, while Turkey remained a key buyer too. Sources and analysts noted that Iranian oil exports last month rose as demand for its crude, especially in China and Europe, climbed, supported by favorable economics. Moves by Saudi Arabia and Iraq to further reduce their exports in August, both to meet domestic demand and also as part of OPEC's coordinated output cuts, bode well for Iran. The reductions have created a gap for Iran to fill, while state-owned NIOC has also reduced prices for some if its heavy crude grades, making them more economically viable for refiners and pushing up spot demand.
Saudi to supply full crude allocations to most Asian refiners: sources (Reuters) - Saudi Arabia will supply full contracted volumes of crude oil to at least five north Asian term buyers in October, while a sixth regional refiner was notified of cuts to its October Arab Extra Light supplies, sources familiar with the matter said on Monday. The October allocations are in contrast to the steep cuts in the September allotments and reaffirms Saudi Arabia’s desire to maintain its Asian market share. Saudi Arabia is the world’s biggest crude exporter. Saudi Arabia is likely taking advantage of the lower refinery run rates and ample crude inventories in the United States in the wake of Hurricane Harvey, to redirect the allocation cuts from Asia to the United States, a trader who specializes in Middle East crude supplies said. “Saudi allocations are all about the math. They can cut U.S. allocations and supply that to Asia,” the trader added. A source from the sixth Asian refiner said that its October supply of Arab Extra Light crude was cut by 10 percent, likely because of repair work in September at Saudi Arabia’s Abqaiq oilfield, which produces the grade. Saudi Arabia plans to cut crude oil allocations to its customers worldwide in October by 350,000 barrels per day (bpd), an industry source familiar with Saudi oil policy told Reuters on Thursday, in line with Saudi Arabia’s commitments to a supply reduction pact by the Organization of the Petroleum Exporting Countries and other producers. In comparison, Saudi Arabia pledged last month to cut its September crude oil worldwide allocations by 520,000 bpd.
OPEC Fails To Cut Oil Exports Below 2016 Levels -- OPEC exported 25.19 million bpd of crude oil last month, the lowest since April this year, Thomson Reuters Oil Research said, but the eight-month average for the year to date was 25.05 million barrels, exceeding the average for the corresponding period of 2016, which stood at 24.85 million bpd. What’s more disheartening for the cartel, which has been cutting production since last December, is that the August fall was mostly a result of supply disruptions in Africa rather than the outcome of the conscious effort.“Crude oil exports from OPEC’s African members tumbled by 540,000 bpd month-on-month to below 5 million bpd after posting their highest export volumes in July since at least Jan. 2015, thereby breaking a four-month streak of rising exports,” the research unit said in a report on Wednesday. While this fall in crude oil exports from Africa compensated for higher shipments from Middle Eastern OPEC members, it will likely be short-lived, Thomson Reuters Oil Research said. The crisis in Venezuela, however, which was the other main contributor to the 370,000-bpd decline in OPEC exports from July to August, will probably persist, providing further support for lower exports.Yet not everyone agrees with Reuters figures. Earlier this month, energy data provider Kpler reported that OPEC’s August exports averaged 25.897 million barrels daily, on the back of Saudi Arabia’s 494,000 bpd cut in shipments as per its pledge to export no more than 6.6 million barrels in that month. According to Kpler, three African members of the cartel actually increased their exports in August: Algeria, Angola, and Nigeria. The combined increase from these three countries exceeded 350,000 bpd. OPEC officials insist that the output cut deal is working and global supply is falling, despite export patterns. Even so, the deal might get another extension beyond March 2018, as per comments made yesterday by Russia’s Energy Minister Alexander Novak. The chance of this happening remains uncertain but the option is on the table.
OPEC Reports First Oil Production Drop In 4 Months As Deal Compliance Slides -- Confirming Monday leaks that OPEC production had dipped last month, the just released OPEC report for the month of September confirmed that in September, OPEC produced 32.755mmb/d (according to secondary source data), a drop of 79,100 bpd, and the first monthly decline in 4 months. According to the underlying data, in the last month output increased in Nigeria (+138.3Kb/d), while declining in Libyam Gabon, Venezuela and Iraq. Saudi Arabia. While secondary sources pegged Saudi production in August at 10.022mmb/d, a drop of 10.3kb/d in the past month, the Saudi self-reported number was 9.951mmb/d, not a nominal difference and a drop of nearly 60kb/d from the Saudi self-reported 10.01mmb/d July number, perhaps indicating that the Saudis are trying a little too hard to demonstrate compliance with the production cut agreement. In the same report, OPEC boosted global oil demand growth in 2017 to 1.42mmbpd, an upward revision of 50kb/d from last month's estimate, predicting that the impact of Hurricane Harvey on demand will be “negligible”, with disruption offset by rebuilding activity. Demand for OPEC crude in 2017 is estimated at 32.7mmb/d, roughly 0.5mmb/d higher than the 2016 level. 2018 demand is now seen at 98.1m b/d, with growth rate revised up by ~100k b/d to 1.35m b/d. At the same time, OPEC also raised estimates for the amount of crude it will need to supply next year by 400k b/d to 32.8m b/d. OPEC expects non-OPEC supply to grow by 0.78mmbpd in 2017, unchanged from the previous month due to offsets between Kazakhstan and the US. OPEC also cut its forecasts for growth in non-OPEC supply next year by 100k b/d amid lower expectations for Russia and Kazakhstan; total non-OPEC is projected to expand by 1m b/d to 58.8m b/d in 2018. From the report: Based on the current global oil supply/demand balance, OPEC crude in 2017 was revised up by 0.2 mb/d from the previous report driven mainly by the upward revision in demand. Within the quarters, the second quarter was revised up by 0.3 mb/d, while the first, third and fourth quarters were revised up each by 0.2 mb/d. As a result, OPEC crude is estimated at 32.7 mb/d, representing an increase of 0.5 mb/d from the 2016 level.
OPEC Unfazed By Falling US Oil Demand - Oil prices held steady in early trading on Tuesday after the release of OPEC’s latest report, which struck a confident tone about the pace of rebalancing underway in the oil market. . In its latest monthly report, OPEC revised up its forecast for global oil demand growth, predicting consumption will expand by 1.42 mb/d this year, an upward revision of 50,000 bpd from a month earlier. Meanwhile, OPEC’s collective oil production dipped in August for the first time in four months. Output fell by 79,000 bpd in August from a month earlier, mostly the result of sizable outages in Libya, but also because compliance with the group’s cuts improved among other OPEC members. OPEC’s estimate for oil inventories in OECD countries also declined for the third consecutive month, putting total storage at 195 million barrels above the five-year average. “It is clear the rebalancing process is under way,” OPEC’s Secretary-General Mohammad Barkindo said in a speech on Monday. OPEC also dismissed worries about demand falling short in the U.S. because of the two major hurricanes. The cartel said the storms will have a “negligible” impact on U.S. demand. Goldman Sachs says that Hurricane Harvey will reduce demand by 600,000 bpd in September while Irma could reduce demand by 300,000 bpd. After factoring in oil production outages in Texas from Harvey, which cut output by 300,000 bpd, Goldman says that on balance the two hurricanes will cut oil demand by 600,000 bpd in September. Other analysts agree. Thomas Pugh, a commodity economist at Capital Economics, estimates that the two hurricanes will lead to a steeper drop in demand than Hurricane Katrina in 2005, which saw a dip in U.S. oil demand by 2 percent in the three months following the storm. Ultimately, that could lead to an increase in crude oil inventories by about 40 million barrels in the next month, Goldman says. “That’s obviously not particularly useful for the global rebalancing effort,” he said, according to the WSJ. Meanwhile, the bank says that the refineries in Texas and Louisiana are still operating at reduced rates, keeping 2.24 mb/d of refining capacity offline.
Hedge funds watch U.S. refinery restarts: Kemp - Hedge funds are betting crude oil stocks will adjust quickly to the aftermath of Hurricanes Harvey and Irma but gasoline and distillate inventories may take more time to normalise. Hedge funds and other money managers increased their combined net long position in the five major petroleum contracts linked to crude, gasoline and heating oil by 46 million barrels in the week to Sept. 5, according to the latest regulatory and exchange data. Fund managers recovered some of their pre-hurricane bullishness after cutting net long positions in the petroleum complex by a total of 116 million barrels over the previous two weeks (http://tmsnrt.rs/2jhR0sX). But position changes varied significantly between Brent and WTI, and between crude and fuels, reflecting the fact the hurricanes have hit refineries, distribution systems and motorists rather than oil wells. Hedge fund managers have sharply increased bullish positions in U.S. gasoline, U.S. heating oil and European gasoil to multi-year highs. Speculators anticipate shortages of road fuels and heating oil since many U.S. refineries are still offline or operating at reduced rates after extensive flooding. Fund managers increased their net long position in U.S. gasoline by almost 17 million barrels to 66 million, the highest level since oil prices started slumping in the middle of 2014. Funds also increased their net long position in U.S. heating oil by 11 million barrels to 41 million barrels, the highest for 42 months. Portfolio managers also increased their net long position in European gasoil by 2.8 million tonnes to 15.7 million tonnes, the highest since at least 2014. U.S. refinery disruptions are expected to draw European gasoline to the United States to meet the supply shortfall while curbing the counter-flow of U.S. diesel to Europe. But while hedge funds see the impact on fuel supplies lingering for some time, they are more confident that crude producers will find a way around the refinery bottleneck.
Mind the gap: Brent and WTI point in opposite directions – Kemp (Reuters) - Commodity markets abhor a gap and will find a way to arbitrage it away. Such a large gap between forward Brent and WTI prices is unlikely to persist for every long.Either Brent prices and calendar spreads must weaken, WTI prices and spreads must strengthen, or some combination of both.In the short term, Hurricanes Harvey and Irma have extensively disrupted oil refineries, distribution systems and motorists along the U.S. Gulf Coast.The result has been to cut refinery consumption of domestic crude and depress the price of WTI compared with Brent.WTI futures for delivery in November 2017 are trading at a discount to Brent of around $5.30 per barrel compared with $2.75 on Aug 14 (http://tmsnrt.rs/2f28kkj).WTI is trading in a contango of about 44 cents per barrel between November 2017 and December 2017 compared with a backwardation of 22 cents in Brent (http://tmsnrt.rs/2jlQ9aR).Backwardation in Brent is consistent with a tightening global oil market while contango in WTI is consistent with local oversupply of crude as a result of refinery shutdowns and the closure of export terminals.Most of this can be put down to temporary disruptions caused by the hurricanes.Restarting refineries after flooding is a slow and complicated process plagued with safety risks ("After Harvey: precautions needed during oil and chemical facility start up", U.S. Chemical Safety Board, Aug 2017).And U.S. export terminals were badly affected by the storm which cut crude exports to just 153,000 barrels per day in the week ending on Sept.1 compared with 902,000 bpd the week before.So the hurricanes will almost certainly leave the United States with a short-term build up of crude stocks that could linger for some weeks or months until it can be exported or absorbed by domestic refineries.The problem is that the gap extends well into the first half of 2018 when U.S. refineries and export terminals should have been back up and running for several months.
Oil rises as U.S. refineries restart, Irma wanes | Reuters: (Reuters) - Oil prices rose on Monday as key U.S. refineries began restarts following Hurricane Harvey, which may help revive crude oil processing, while fuel prices fell as Hurricane Irma is likely to clip demand for gasoline and diesel. The possibility of an extension to the 15-month production pact between members of the Organization of the Petroleum Exporting Countries and non-OPEC producers also helped to support prices, traders said. Brent crude oil futures settled up 6 cents, or 0.1 percent, to $53.84 a barrel while U.S. West Texas Intermediate crude rose by 59 cents, or 1.2 percent, to $48.07. Hurricane Irma knocked out power to over 7.3 million in Florida, Georgia, South Carolina and Alabama, according to state officials and utilities on Monday. That has raised concerns about demand, as storms tend to cut down on driving, particularly as many cars have been destroyed. Both U.S. product futures ended lower - gasoline dropped 0.7 percent and heating oil fell 1.4 percent. Harvey is still likely to be a bigger driver for the crude market, analysts at Goldman Sachs said. A quarter of U.S. refining capacity to be taken off-line due to the hurricane, sapping demand. Refining runs on the U.S. Gulf Coast hit a record low in the week to Sept. 1, just after the storm, due to shutdowns. “While some are concerned about the demand side [from Irma] I don’t think it’s that big a situation,” said James Williams, president of energy consultant WTRG Economics, noting that Harvey had more of an impact on crude, “The demand for crude is going to be set by the refineries coming back online.”
Refined oil product futures falling on demand concerns following Irma - Refined product futures were leading the oil complex lower Monday as Hurricane Irma moves north through Florida's Gulf Coast, provoking concerns about depressed oil demand in the storm's wake. At 1444 GMT, NYMEX October ULSD was down 3.47 cents at $1.731/gal. NYMEX October RBOB was 4.29 cents lower at $1.6047/gal. NYMEX October crude was 9 cents lower at $47.39/b. NYMEX November Brent was 35 cents at $53.43/b. The arrival of Irma has helped unwind some of the recent strength seen in product cracks. The front-month NYMEX ULSD crack against WTI was near $27/b last week, its highest level since March 2015. The ULSD crack was down $1.38 at $25.30/b Monday morning. The NYMEX RBOB crack has cooled off after spiking above $27/b, hovering around $20/b-$22/b since last week. Another reversal Monday was the front-month ICE Brent/WTI spread coming in after reaching its widest level on Friday since August 2015. That spread was around $5.48/b Monday, compared with $5.72/b a day earlier. In addition, the US Dollar Index was rebounding Monday morning after having fallen Friday to 91.011, its lowest point since January 2015. The dollar index was up 0.377 at 91.729 Monday morning. That index has fallen sharply of late, partly driven by reduced expectations the Federal Reserve will raise interest rates before the end of the year, according to BBH analysts. Personnel news regarding central bankers Stanley Fischer and Janet Yellen, as well as White House economic advisor Gary Cohn may have also played a role, the analysts said. "The early retirement of the Federal Reserve's Vice Chairman Fischer and reports that suggest the chances of Cohn replacing Yellen have fallen may have contributed to the reduced expectations and the weaker dollar," they said. A weaker dollar is supportive for commodity prices, but crude oil has failed to catch a bid from this soft patch. Front-month NYMEX crude was trading Monday at roughly the midpoint of the $45/b-$50/b range where the contract has been since mid-July.
Oil Factbox: Refined product prices fall as Irma moves north - Refined product futures were lower Monday as Hurricane Irma moves north along Florida's Gulf Coast.The NYMEX front-month RBOB contract settled down 1.31 cents/gal at $1.6345/gal, while the front-month ULSD contract fell 2.30 cents/gal to settle at $1.7427/gal. Irma did not cause any damage to the limited oil infrastructure in Florida, which consists primarily of ports and storage terminals, but sparked concerns about depressed refined product demand.Goldman Sachs analysts said Monday in a note that the recovery in refinery runs and trade flows was taking longer than had been expected. After rising because of evacuations, gasoline demand will fall for two weeks and perhaps longer because of residual flooding, with the average loss attributed to Irma at 250,000 b/d for the next month, Goldman said. Fuel terminals in the ports of Tampa and Port Everglades have reopened and distributors were working Monday to restock thousands of stations drained of fuel during last week's massive evacuation. Platts cFlow trade flow software shows two refined products vessels scheduled to arrive in Tampa this week. The tanker Florida and tanker Louisiana are both scheduled to arrive Wednesday and make regular runs between Louisiana and Florida.The West Virginia is due to arrive in Tampa on Thursday, having left the New York area seven days ago.Several other refined products vessels are scheduled to unload at Port Everglades this week, including the Mare Pacific on September Tuesday, the Overseas Nikiski on September Thursday and the Mt Sea Halcyone on September Friday, according to cFlow.The Mexican Gulf Coast ports of Tuxpan, Veracruz, Tampico, Pajaritos, and Cayo Arca are all currently operating after being closed last week ahead of the arrival of Hurricane Katia, data from Pemex showed Monday. The port of Tuxpan was closed September 6 ahead of Katia, which made landfall over the weekend. Data from Platts cFlow showed several refined products vessels near Tuxpan Monday. The Largo Sun appeared to be offloading refined products. That vessel in late August had loaded at the IMTT terminal in Bayonne, New Jersey. Mexico at the time was sourcing refined products from outside of US Gulf Coast refineries, many of which were shut because of Hurricane Harvey.
Oil prices climb for 2nd day as OPEC report shows production drop - Oil prices headed higher Tuesday, stretching gains in to a second-consecutive session as the latest OPEC report that showed oil production from the cartel fell last month. Expectations for a hefty weekly rise in U.S. crude-oil supplies limited the price rise for oil, however. Inventories likely jumped on the back of lower demand from refineries that shutdown output of petroleum products in the wake of Hurricane Harvey. West Texas Intermediate crude oil for October delivery gained 16 cents, or 0.3%, to $48.23 a barrel on the New York Mercantile Exchange, while Brent oil for November added 48 cents, or 0.9%, to $54.32 on ICE Futures Europe. In a monthly report released Tuesday, the Organization of the Petroleum Exporting Countries said output in August fell by 79,000 barrels a day to 32.76 million, driven mainly by a decline in Libya, Gabon, Venezuela and Iraq. Production had been on the rise over the summer, raising concerns OPEC’s deal to cut output wasn’t working. Saudi Arabia—OPEC’s most influential member—has been debating whether to extend the cartel’s production accord after it expires in March 2018. The report from OPEC also highlighted that production outside the group fell in August, driven by disruptions in the U.S. after Hurricane Harvey rampaged through the oil producing regions in Texas and Louisiana. It made landfall on the Texas coast on Aug. 25. But many refineries along the Gulf Coast were knocked offline by the hurricane, prompting a notable rise in crude stockpiles for the week ended Sept. 1, according to the Energy Information Administration.
WTI/RBOB Extend Gains After Biggest Gasoline Draw On Record --WTI/RBOB gained on the day after OPEC headlines but with disruptions still looming over much of the refining capacity in the Gulf Coast, today's API data, showing the trend of Gasoline draw (the biggest ever) and Crude build continues, sparked further gains. API:
- Crude +6.181mm (+4.82mm exp)
- Cushing +1.32mm (+1.6mm exp)
- Gasoline -7.896mm (-1.5mm exp) - biggest ever
- Distillates-1.805mm
Last week saw the biggest gasoline inventory draw on record as Crude's build trend continued... WTI/RBOB gained today on the heals ofOPEC production cut extension chatter, but as Kyle Cooper, director of research at IAF Advisors, says, "OPEC potentially extending cuts is “bullish in the sense that they are willing to do it, but it’s effectively bearish that they have to...” While the initial move was algos slamming them lower, the trend was higher...
Goldman: Harvey, Irma Cause 900,000 Bpd Drop In Demand -- In the wake of the hurricanes Harvey and Irma, oil demand is expected to drop by some 900,000 bpd this month, Goldman Sachs said on Monday. “Irma will have a negative impact on oil demand but not on oil production or processing,” Goldman analysts said in a note, as carried by Reuters.“Harvey’s negative impact on demand will remain larger, however, given the large concentration of energy-intensive petrochemical activity in its path,” the bank said.According to Goldman’s estimates, the combined effects of production disruption and demand drop from hurricanes Harvey and Irma alone will lift global oil inventories by 600,000 bpd in September.For next month, estimates are that the hurricanes will lower oil demand by some 300,000 bpd, according to Goldman Sachs. Gasoline demand will suffer the most from the storms, adding to the expected 150,000-bpd drop this month due to seasonal factors, Goldman said. Harvey hit Texas and Louisiana two weeks ago, and led to more than one-fifth of the U.S. refining capacity to shut down. Refineries are restarting in Texas and as of 02:00 PM EDT on Sunday, five refineries in the Gulf Coast region were still shut down, with a combined refining capacity of 1,069,300 bpd, equal to 11 percent of total Gulf Coast refining capacity and 5.8 percent of total U.S. refining capacity, according to the DOE. Last week, Goldman Sachs said that reconstruction in Hurricane Harvey’s aftermath was expected to be ultimately positive for U.S. oil demand in a few months, as fuel consumption is expected to increase as people rebuild homes. However, Goldman said that its prediction for increased fuel demand could be upset if Hurricane Irma were to make landfall in Florida, where it would not be felt so much on the sparse oil infrastructure than on fuel demand.
IEA Forecasts Fastest Oil Demand Growth In Two Years -- The International Energy Agency, which advises most major economies on energy policy, forecast that global oil demand will climb this year by the most in two years amid stronger-than-expected consumption in Europe and the U.S. although it was unclear just how this will offset recently fading demand by the two biggest marginal consumers, China and India. The IEA reported that global oil demand grew very strongly in Y/Y in Q2 2017, by 2.3mmb/d, or 2.4%, and increased its estimate for demand growth in 2017 by 100,000 barrels a day to 1.6 million a day, or 1.7%. The IEA has now raised its 2017 oil-demand growth forecast for three months in a row. The agency observed that the re-balancing of oversupplied world markets continues with OPEC supplies falling for the first time in five months as reported yesterday, and inventories of refined fuels in developed nations subsiding toward average levels. In August, global oil supply fell by 720 kb/d due to unplanned outages and scheduled maintenance, mainly in non-OPEC countries. OECD commercial stocks were unchanged in July at 3 016 mb, when they normally increase. “Demand growth continues to be stronger than expected, particularly in Europe and the U.S.,” the Paris-based agency said in its monthly report. The IEA also said that the impact of Hurricane Harvey on global oil markets is “likely to be relatively short-lived,” according to Bloomberg. Although the oil market “coped relatively well” with the disruption caused by this year’s storms, the damage to U.S. facilities will still be felt, according to the report. The country’s production was curbed by about 200,000 barrels a day in August and 300,000 a day in September.
Oil Prices Rise After API Reports Largest Gasoline Draw On Record -- The American Petroleum Institute (API) reported a build of 6.181 million barrels in United States crude oil inventories, compared to analyst expectations that inventories would build by 10.1 million barrels for the week ending September 8 as many refineries in the Gulf Coast remain offline and demand in Florida wanes in the wake of the most recent hurricane. Gasoline inventories fell more than anticipated—by 7.896 million barrels for the week ending September 8, against an expected draw of 4.0 million barrels. Crude oil prices rose on Tuesday as OPEC reported lowered production in August—down to 32.755 million barrels daily per month in August, down from 32.834 million bpd in July, according to OPEC’s Monthly Oil Market Report published on Tuesday. The production decreases were more due to Libya’s unrest that saw a 112,300-barrel decline in August’s production, rather than a conscious effort to adhere to the cartel’s production cut deal. WTI climbed 0.4% by 2:15pm EST to $48.26, and Brent prices increasing by 0.72% to $54.23. Gasoline was also trading up—1.29%—but almost flat on the week at $1.6556 as much of the refining capacity in the Gulf Coast comes back online. This week’s crude oil inventory build takes away from the previous streak of draws that saw almost 50 million barrels removed from inventory, according to API data. The total draw for crude oil in 2017 now stands at 23 million barrels. Distillate inventories fell this week, by 1.805 million barrels, against a smaller expected draw of 300,000 bpd. Inventories at the Cushing, Oklahoma, site increased by 1.320 million barrels. By 4:40pm EST, WTI was trading at $48.18 with Brent Crude trading at $54.21.
WTI/RBOB Sink After Big Crude Build, Production Jump Offsets Greatest Gasoline Inventory Draw In History WTI and RBOB prices are higher this morning following API's reported the biggest gasoline draw in history (compared to EIA data). Of course, disruptions (Florida demand and Texas supply) remain dominant but DOE reports a massive 8.4mm draw in Gasoline inventories - the biggest draw ever. The reaction in prices is anti-climactic as production rebounded and crude built dramatically to offset the exuberance.Bloomberg's Javier Blas reminds readers that the report covers the period from 7:01 am on Friday, Sept. 1 to 7:00 am on Friday, Sept. 8. So a lot of disruption from Harvey (particularly from Sept. 1, 2, and 3) will still impact everything from refining intake to crude production and U.S. imports and exports. DOE:
- Crude +5.888mm (+4.82mm exp) - biggest build in 6 mos
- Cushing +1.023mm (+1.6mm exp- biggest build in 6 mos
- Gasoline -8.428mm (-1.5mm exp) - biggest draw ever
- Distillates -3.215mm - biggest draw in 6 mos
Bloomberg Intelligence energy analyst Vince Piazza notes that the impact from hurricane season will keep crude demand subdued, with roughly two million barrels of daily refining capacity off-line. Depressed gasoline consumption should persist temporarily on lower transportation use and suppressed refining utilization. Gasoline inventories confirmed API's data and saw the biggest draw in history as Crude and Cushing saw major builds... The bearish data point is that total U.S. petroleum inventories (that's crude, refined products, propane and the volatile "other oils" category) have built for the second consecutive week. Total stocks up 1.7 million barrels, driven by big builds in crude, propane and other oils.
EIA Reports Crude Oil Inventories Rose 5.9 Million Barrels, WTI Oil Price Edges Lower: The latest Energy Information Administration (EIA) data recorded an inventory build of 5.9 million barrels for the week ending September 8th following a build of 4.6 million barrels the previous week. Consensus forecasts were for a build of 4.0 million barrels, although there was again an important element of uncertainty given the impact of hurricane Harvey which continued to cause sharp fluctuations across all metrics. Crude inventories increased to 468.2 million barrels, although there was still a year-on-year decline of 2.5%. Cushing inventories recorded a build of 1.02mn barrels on the week which was close to consensus expectations. Domestic crude production recovered sharply by 6.5% on the week at 9.35mn bpd following the 7.9% decline the previous week as production restarted following hurricane Harvey. There was an annual increase in production of just over 10.0%. Gasoline inventories declined a record 8.4 million barrels on the week with a 4.4% annual decline while distillate stocks fell 3.2 million barrels with a year-on-year decline of 11.2%. Refinery use fell a further 2.0% on the week due to the continuing impact of outages as flooding caused substantial damage, although markets had been expecting a recovery in capacity use for the week. Potential price support from the decline in gasoline inventories was offset by the higher than expected headline build and sharp recovery in production.
Oil futures little changed after data shows product draws, crude build - Oil futures were little changed Wednesday after Energy Information Administration weekly data showed a build in US crude stocks and draws in gasoline and distillates directionally consistent with expectations. EIA data released Wednesday covered the week ended September 8, providing insight into the full impact Hurricane Harvey had on US oil inventories and refinery operations. The loss of Gulf Coast refining capacity has caused draws in product stocks and builds in crude inventory for the last two reporting periods. The size of those swings last week was even larger than the previous week as refinery activity slowed further. Total refinery utilization fell 2 percentage points last week to 77.7%. That is down from 96.6% in the week ending August 25. US crude inventories rose 5.888 million barrels to 468.241 million barrels in the week ended September 8, EIA data showed. Analysts surveyed Monday by S&P Global Platts expected crude stocks to build 10.1 million barrels. At 1442 GMT, NYMEX October crude was up 59 cents at $48.82/b. ICE November Brent was 34 cents higher at $54.61/b. Before the release of the EIA data, NYMEX October crude was 51 cents higher at $48.74/b. ICE November Brent was 33 cents higher at $54.60/b. US gasoline stocks declined 8.428 barrels to 218.310 million barrels last week, EIA data showed. Analysts expected a draw of 4 million barrels.
Oil Prices Rise On Huge Draw In Gasoline Stocks -Crude oil prices inched up after the EIA reported a smaller-than-expected build of 5.9 million barrels in crude oil inventories for the week to September 8, after a 4.6-million-barrel build in the prior week due to the Gulf Coast refinery shutdowns.A day earlier the American Petroleum Institute had estimated crude oil inventories had risen for the second week in a row, by a hefty 6.18 million barrels, which was only to be expected as the market is prepared for the Hurricane Harvey effects on Gulf Coast refining to linger for another few weeks.Yet refineries are coming back online and they are raising gasoline production, the latest figures suggest. EIA said that last week refineries processed 14.1 million barrels of crude daily, producing 9.9 million barrels of gasoline daily. This compares with daily runs of 14.5 million bpd and gasoline production of 9.5 million bpd a week earlier.Gasoline inventories, according to the EIA fell last week, by 8.4 million barrels, generally in tune with API’s estimate of a 7.896-million-barrel decline—and the largest gasoline draw on record. This could reinforce any effect EIA’s oil inventory figures would have on prices but to what extent, remains uncertain.In its latest Short-Term Energy Outlook, out on Tuesday, the EIA said that the effect of the supply disruptions on the Gulf Coast will last for a while, which would boost the uncertainty around oil and gas prices in the coming weeks. In refining, the EIA projected an average daily rate of 15.3 million bpd for September, down from 17.1 million bpd in August. This, however, would recover somewhat in October, to an average of 15.9 million bpd, the authority said. In production, the EIA forecasts an average daily of 9.3 million bpd for this year, and 9.8 million bpd for 2018. Oil prices, which have recently received some support from reports about discussions of another possible extension of the OPEC production cut deal, remained stable following the release of the EIA report, with WTI trading at US$48.75 a barrel and Brent crude at US$54.62 a barrel.
OilPrice Intelligence Report: U.S. Shale Struggles While Oil Markets Strengthen -- WTI rose to its highest level in more than a month this week, hovering just around $50 per barrel. Brent surpassed $55 per barrel on Thursday, the highest level since the beginning of the year. Strong demand combined with easing fears about hurricane disruptions in the U.S. has pushed oil up this past week. Plus, another missile launch from North Korea kept the markets on edge. The IEA published an encouraging Oil Market Report this week, noting that global oil supply contracted for the first time in months while demand remains very robust. The Paris-based energy agency said that oil demand growth could hit 1.6 mb/d this year, an upward revision from the 1.5 mb/d estimate last month. Refined product inventories are also nearing the five-year average level, a sign that the oil market is making a great deal of progress towards rebalancing. The report also dismissed fears that the hurricanes in the U.S. would dramatically reduce demand – the agency said any effects will be “short-lived.” U.S. oil production rebounded sharply after a major disruption from Hurricane Harvey. After declining by about 750,000 bpd in the week after the storm, U.S. oil production jumped back by about 570,000 bpd last week. Still, inventories climbed again in the most recent EIA data release, with about 10 million barrels added over the two-week period. . While OPEC members have cut some 1.2 million barrels of production over the past year (plus a little less than 0.6 mb/d from non-OPEC members), that has not actually translated to the same reduction in exports. In fact, oil exports from the participating countries remain elevated, undercutting the efficacy of the agreement. The Wall Street Journal says that although OPEC agreed to cut output by 1.2 mb/d, exports have only declined by 213,000 bpd, as countries sell product from storage or otherwise reduce consumption to leave more oil for export. Saudi Arabia now wants to change that and its officials are pushing for OPEC to monitor country-level exports at its upcoming meeting on September 22.
U.S. Oil Rig Count Continues To Collapse -- The number of active oil and gas rigs in the United States fell this week by 8 rigs. The total oil and gas rig count in the United States now stands at 936 rigs, up 430 rigs from the year prior, with the number of oil rigs in the United States decreasing by 7 this week and the number of gas rigs decreasing by 1. Canada, meanwhile, added 10 oil rigs for the week ending September 15. Oil rigs in the United States now number 749—333 rigs above this time last year. Although the number of oil rigs are still up significantly year on year, the increases slowed in the second quarter, and have reversed in the third. The first quarter 2017 saw 137 oil rigs added in the United States, while the second quarter 2017 saw 97 rigs added. In stark contrast, the third quarter, for which there are still two weeks to go, has seen the total number of rigs decrease by 7. The spot price for WTI fell earlier on Friday, down 0.16 percent to $49.81 at 11:53am. Brent crude, however, was trading up 0.27 percent on the day at $55.62. Prices have been volatile in August and so far in September, with WTI going as low as $45.58 on August 31, and as high as $50.50, which it reached yesterday—the highest level we’ve seen in six weeks—as global production declined 720,000 barrels per day in August compared to July, according to OPEC’s Monthly Oil Report. It was the first drop in four months.
WTI Crude Fails At $50 Again As Rig Count Tumbles Most In 8 Months --As Texas slowly normalizes from Hurricane Harvey's impact, production has rebounded but the rig count continues to tumble (down 7 to 749 this week). This is the biggest weekly drop in oil rigs since Jan 2017 and June 2016. WTI Crude futures have once again tested $50 (and failed) this morning. This is the 5th week in a row with no increases in oil rig counts. The massive collapse in US crude production last week - with most of Texas offline - has recovered somewhat with a 572k surge in production this week. However, it is clear that levels of production are well off pre-Harvey levels... WTI retested $50 this morning, and failed, but RBOB gasoline is on the rise...“The dollar is once again weakening and that is adding some support to oil too” However, some remain bulish - “The market is realizing that demand is a lot stronger than there was given credit for,” says Phil Flynn, senior market analyst at Price Futures Group. “The untold story hidden behind the glut has been the demand growth”
Aramco Valuation Comes Under Scrutiny - Saudi Crown Prince Mohammed bin Salman says Saudi Aramco should be valued at $2 trillion for its initial public offering, but its true value will only be known when the company releases its financials next year.Because Aramco’s reserves are a staggering 266 billion barrels, the valuation of each of those barrels is particularly important. If, for example, each of those barrels get a $7 or $8 valuation, the $2 trillion valuation seems possible. But that’s not all what IPO valuations are based on.Investors use many of other metrics—financial ones—to measure an oil company’s worth, and Aramco’s finances will not be known until next year, ahead of the planned IPO.According to one such globally accepted metric for oil industry giants—enterprise value vs. earnings before interest, tax, depreciation, and amortization (EBITDA)—in order for Aramco to reach a company valuation of $2 trillion, it needs to report an EBITDA of around $130 billion next year, according to Reuters estimates.And this could prove quite challenging for the Saudi firm. No company ever—not only in the oil industry but in any industry—has reported such a high EBITDA figure, or EBITDA of more than $100 billion, according to Reuters. To compare, Apple, for example, the most valuable listed company in the world, is now worth more than $830 billion and its 2015 EBITDA was just $82 billion. Reuters data shows that Exxon Mobil reported EBITDA of $23 billion last year, and the world’s biggest listed oil firm currently has a market capitalization of $335 billion. At peak oil prices, Exxon’s EBITDA was $65 billion in 2012, but a barrel of oil is half the cost today that it was then. Core earnings at $130 billion would be necessary for Aramco to match the ambitious EV/EBITDA ratio of Exxon, Reuters calculations show.
Breaking News of Saudi Crown Prince's "Secret" Visit To Israel Brings Embassy Scramble -- Clearly the war in Syria and the international push for regime change against Assad has created strange alliances in the Middle East over the past few years. Among the strangest bedfellows are the Israelis and Saudis. It's no secret that common cause in Syria of late has led the historic bitter enemies down a pragmatic path of unspoken cooperation as both seem to have placed the break up of the so-called "Shia crescent" as their primary policy goal in the region. But that's perhaps why few pundits seemed overly shocked when Israeli media late last week began reporting that a Saudi prince made a secret visit to Israel, in spite of the fact that the kingdom does not recognize the Jewish state, and the two sides do not have diplomatic relations. Last Wednesday (9/6) Israel's state funded Kol Yisrael radio service made cryptic reference to the "secret" yet historic visit while withholding names and specifics. "An emir of the Saudi royal court visited the country secretly in recent days and discussed with senior Israeli officials the idea of advancing regional peace," the station reported. It added further that, "Both the Prime Minister's Office and the Foreign Ministry refused to comment on the issue."
"Unprecedented" Saudi Crackdown Targets Regime Loyalists As King Prepares To Abdicate -Are we seeing early signs of an "Arab Spring" coming to Saudi Arabia, or will the next king emerge stronger than ever? The kingdom is now in the midst of an unprecedented crackdown of both dissidents and even loyalists perceived as less than enthusiastic about Crown Prince Mohammed bin Salman's consolidation of power as he prepares to ascend the throne of his aging and increasingly senile father. It was only last June that King Salman shocked the world by suddenly and unexpectedly removing next in line for the crown Muhammad bin Nayef, which made Mohammed bin Salman heir apparent to the throne.In a rare front page story airing sharp criticism of the kingdom, The Wall Street Journal assessed the scope of the crackdown today:In the past week, Saudi authorities have detained more than 30 people, roughly half of them clerics, according to activists and people close to those who have been detained. The campaign goes beyond many of the government’s past clampdowns, both in the scope of those targeted and the intense monitoring of social media posts by prominent figures. It is not known if any charges have been filed. WSJ further mentions that several senior princes have been essentially under house arrest as they are barred from traveling abroad, which even includes a brother of King Salman. The kingdom has been tight lipped amidst the crackdown, refusing to engage with the media since as the story began breaking early this week.
Iraqi Kurdish parliament backs independence referendum - The parliament of Iraq's autonomous Kurdistan region has approved holding a referendum on independence on September 25 despite growing opposition from Baghdad and neighbouring countries. Kurdish MPs in the regional capital of Erbil, in northern Iraq, convened for the first time in two years on Friday and overwhelmingly decided to go ahead with the vote as planned earlier in the year.The region's vice president, Jaafar Aimenky, who chaired the session, announced the decision after 65 out of 68 politicians present voted in favour of the poll. The central government in Baghdad opposes the referendum, with its parliament having rejected the Kurdish plans in a resolution on Tuesday. Iraq's neighbours, Iran and Turkey, have also expressed their opposition to the plan as they fear an independent Kurdish state could fuel separatism among their own Kurdish populations.Friday's vote also followed the removal on Thursday of Najm Eddine Karim as the governor of the Kurdish-controlled Kirkuk. Masoud Barzani, the president of the Kurdistan Regional Government (KRG), had earlier said on Friday that the vote won't be delayed, despite pressing requests from the United States and other western powers worried that the tension between Baghdad and Erbil would distract from the war on the ISIL group.
"Like Moths To The Flame": ISIS Fighters Cut Down While Approaching Stranded Convoy -- A convoy of buses containing hundreds of lightly armed ISIS terrorists and their family members remains stuck in the Syrian desert and pinned down as US and coalition planes continue to pick off militants who stray too far from the group. External ISIS vehicles have also tried to access and aid the group, but as US coalition spokesman Army Col. Ryan S. Dillon stated, coalition aircraft are picking them off as they come close "like moths to the flame."Dillon estimated that over 40 ISIS vehicles were destroyed, including nearly 100 terrorists killed, while heading toward the convoy as the coalition has been "able to continue to just observe and pick them off one at a time.” But on Friday afternoon the US alliance announced the sudden withdrawal of its surveillance aircraft over the site at Russia's request, publishing the following statement: At approximately 7am GMT Sept. 8, Syrian pro-regime forces advanced past the 11-bus convoy of ISIS terrorists and non-combatants in the eastern Syrian desert. To ensure safe de-confliction of efforts to defeat ISIS, coalition surveillance aircraft departed the adjacent airspace at the request of Russian officials during their assault on Dawyr Az Zawyr.
North Korea slapped with UN sanctions after nuclear test - BBC News: The United Nations has imposed a fresh round of sanctions on North Korea after its sixth and largest nuclear test. The measures restrict oil imports and ban textile exports - an attempt to starve the North of fuel and income for its weapons programmes. The US had originally proposed harsher sanctions including a total ban on oil imports. Pyongyang said it "categorically rejected" what it called an "illegal" resolution. North Korea's ambassador to the UN, Han Tae Song, told a conference in Geneva: "The forthcoming measures by DPRK [the Democratic Republic of Korea] will make the US suffer the greatest pain it has ever experienced in its history." Monday's vote was only passed unanimously after Pyongyang allies Russia and China agreed to the reduced measures. The US call last week for a total ban on oil imports was seen as by some analysts as potentially destabilising for the regime. The new sanctions agreed by the UN include:
- Limits on imports of crude oil and oil products. China, Pyongyang's main economic ally, supplies most of North Korea's crude oil
- A ban on exports of textiles, which is Pyongyang's second-biggest export worth more than $700m (£530m) a year
- A ban on new visas for North Korean overseas workers, which the US estimates would eventually cut off $500m of tax revenue per year
A proposed asset freeze and a travel ban on North Korean leader Kim Jong-un were dropped. The US ambassador to the UN Nikki Haley, told the Security Council after the vote: "We don't take pleasure in further strengthening sanctions today. We are not looking for war." "The North Korean regime has not yet passed the point of no return," she added. "If North Korea continues its dangerous path, we will continue with further pressure. The choice is theirs."
Reports Confirm North Korea Has Enough Oil To Survive An Embargo -- While a full scale oil embargo against North Korea is unlikely, the reality is that North Korea would be able to survive such a measure with comparative ease. The United States has recently suggested a global oil embargo against North Korea, something both China and Russia oppose. The DPRK’s neighbours to the north support UN sanctions against Pyongyang, but have firmly opposed unilateral US sanctions against North Korea. Russia and China have made a commitment never to support sanctions against Pyongyang which could negatively impact on the civilian population of their neighbour and this would almost certainly include a full-scale oil embargo. On the contrary, Russia’s plan to de-escalate tensions on the Korean peninsula is to develop trilateral economic initiatives linking South and North Korea to Russia. Given the realities on the peninsula, Russia’s ‘carrot’ is seen as preferable on both sides of the 38th parallel to Washington’s increasingly bellicose ‘stick’. But even if Donald Trump was somehow able to convince the world to engage in an oil embargo against North Korea, North Korea would appear to have enough domestic oil reserves to make up for the loss of imports. In addition to large reserves of domestic coal and the increased reliance on green energy in the form of hydroelectric power , North Korea’s domestic oil reserves are likely far greater than previous conservative estimates have indicated. In 2015, when relations between the DPRK and the rest of the world were somewhat better than they are at present, independent oil exploration expert Michael Rego investigated North Korea’s oil potential. The results of his report paint a broadly positive picture for North Korea, a state which has always striven towards economic self-sufficiency, a principle implicit in the Juche idea of the DPRK’s founder Kim Il-Sung, which remains Pyongyang’s guiding political programme.
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