US oil prices ended slightly lower for the third week in a row this past week, but the major movement in oil prices was in the international markets, where North Sea Brent crude, the international benchmark, spiked to a two and a half year high on Tuesday, after a crack was discovered in the Forties pipeline, which carries about 40% of the North Sea's output to the UK, forcing its shutdown and the shutdown of the 80 offshore platforms it had been servicing...the same day, an explosion and fire at the Baumgarten natural gas hub in Austria near the Slovak border shut down what is one of the main distribution hubs of Russian natural gas in Europe, temporarily shutting off gas to parts of Germany, France, Hungary, Italy, Slovenia and Croatia, sending European natural gas prices to a six year high, and prompting a state of emergency in Italy, where gas prices jumped 150%...while the operator of the Austrian hub managed to quickly reroute gas supplies to most destinations in central Europe, the British pipeline is expected to be shut down for weeks for repair work, forcing closure of a major UK refinery...meanwhile, while natural gas was priced at $9.86 per mmBTU in Europe and at $9.61 per mmBTU for December and January deliveries to Japan, the benchmark price for natural gas in the US was falling to a 16 month low at $2.61 per mmBTU…
we're going to start this week by reviewing OPEC's December Oil Market Report (covering November OPEC & global oil data), which was released on Wednesday of the past week, and which is available as a free download....the first table from this report that we'll look at is from page 64 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...
as we can see from this table of official oil production data, OPEC oil output decreased by 133,500 barrels per day in November, to a six month low of 32,448,000 barrels per day, from an October production total of 32,581,000 barrels per day, a figure that was originally reported as 32,589,000 barrels per day (for your reference, here is the table of the official October OPEC output figures as reported a month ago, before this month's revisions)...as you'll note in the far right column above, the reasons that OPEC's output fell by 133,500 barrels per day in November was that the decrease of 108,700 barrels per day in output from Angola more than offset the 95,800 barrel per day increase in output from Nigeria, and that the Saudis, the Emirates and Venezuela all also saw sizable reductions in their oil output...the cutback in Angolan production now lowers their output to below their agreed to quota, leaving Iraq as the only OPEC member whose production is well in excess what their pact calls for, 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 eleven 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 2016 meeting, and the 3rd column shows how much each has averaged over or under their quotas for the ten months of this year that the OPEC pact to curtail production has been in effect...one minor clarification would be that Nigeria and Libya are no longer exempt from the pact, in that they have agreed to a combined output cap of 2.8 million barrels per day at the November 30th OPEC meeting two weeks ago...with a combined output of 2,983,000 barrels per day in November, they were obviously in excess of that new quota for one month, possibly as they overpumped in anticipation of having to throttle back in December...but 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, whose production has averaged nearly 2% higher than what they committed to...however, cuts in excess of what was agreed to by the Saudis, Venezuela, and other OPEC countries have more than made up for the 83,000 barrels per day that Iraq has been overproducing, so the organization as a whole has kept their commitment to reduce supply....
for a visualization of how OPEC's cuts have progressed, we'll next include a longer term historical graph of their monthly oil output:
the above graph, taken from the "OPEC November Oil Production" post at the Peak Oil Barrel blog, shows total oil production, in thousands of barrels per day, for the current 14 members of OPEC, for the period from January 2005 to November 2017, using the history of the same official data from secondary sources that we saw in the first table above...here we can obviously see that OPEC's November production of 32,448,000 barrels per day is lower than their production of the past five months, but up from earlier this year...but we can also see how their production spiked to a record last November, just before they announced their output cuts, giving them quite a bit of leeway to "reduce" production from those elevated levels, without ever having to fully cut back to the level they were producing at in late 2015 and early 2016...
the next graphic we'll include shows us both OPEC and world oil production monthly on the same graph, over the period from December 2015 to November 2017, and it comes from page 65 of the December OPEC Monthly Oil Market Report....the cerulean 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...
OPEC's preliminary data indicates that total global oil production rose to a 12 month high of 97.44 million barrels per day in November, up by .84 million barrels per day from a October total of 96.60 million barrels per day, which was revised .11 million barrels per day lower from the 96.71 million barrels per day global oil output for October that was reported a month ago...global oil output for November was also 0.60 million barrels per day higher than the 96.84 million barrels of oil per day that was being produced globally in November a year ago (see last December's OPEC report online (pdf) for the year ago data)... OPEC's November production of 32,448,000 barrels per day thus represented 33.3% of what was produced globally, down from their 33.7% share of October global output, as oil output increases by the US, Canada, Norway, the UK and Brazil more than made up for OPEC's decrease...OPEC's November 2016 production, excluding ex-member Indonesia, was at 33,131,000 barrels per day, so even after their production cuts, the 13 OPEC members who were part of OPEC last year, excluding new member Equatorial Guinea, are only producing 2.5% less oil than they were producing a year ago, at a time when they were producing at a record level...
however, even after the increase in global oil output that we can see on the above graph, there was again a 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 38 of the Decmeber 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 estimate of oil demand by region and globally quarterly over 2017 over the rest of the table...on the "Total world" line of the fifth column, we've circled in blue the figure that's relevant for November, which is their estimate of global oil demand for the fourth quarter of 2017...
OPEC's estimate is that over the 4th quarter of this year, all oil consuming areas of the globe will be using 98.08 million barrels of oil per day.....at the same time, 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 97.44 million barrels per day during November, which means that there has been a shortfall of around 640,000 barrels per day in global oil production vis-a vis demand during the month...
global oil production estimates for October were also revised lower with this report, to 96.60 million barrels per day, so that now means there was also a deficit of 1,480,000 barrels per day in October global output, which we had previously figured to be a global oil deficit of around 1,370,000 barrels per day...meanwhile, since there were no revisions to oil production or demand estimates for the prior months, that means the figures we computed for the previous months of this year remain as they were...those include a shortfall of 1,540,000 barrels per day in September global output, and a global shortfall of 1,630,000 barrels per day in August, when global oil production was even lower...
prior to that, we estimated a global oil deficit of 560,000 barrels per day in July, a global oil surplus of 850,000 barrels per day in June, a global oil deficit of 360,000 barrels per day in May, a global oil deficit of 670,000 barrels per day in April, a global surplus of 390,000 barrels per day in March and average surpluses over January and February of around 610,000 barrels per day....taken together, the data from these monthly OPEC reports means that after eleven months of OPEC production cuts, the global oil glut has been reduced by roughly 95.27 million barrels of oil since the 1st of the year, with most of that reduction coming over the past four months...more than 30.9 million barrels of that drawdown from global oil supplies came out of US oil inventories; last week we reported that US crude inventories had fallen to 448,103,000 barrels as of December 1st; that was down from the 479,012,000 barrels we had in storage on December 30th 2016, in the last report for last year...as we'll see, that draw out of US supplies also continued into early December, according to the latest EIA report...
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 December 8th, showed that our oil imports edged up as dilbit flows from Canada were restored, while our refineries slowed to using oil at a near normal pace for this time of year, but still found it necessary to pull oil out of storage to meet their needs...our imports of crude oil rose by an average of 161,000 barrels per day to an average of 7,363,000 barrels per day during the week, while our exports of crude oil fell by an average of 272,000 barrels per day to average 1,086,000 barrels per day, which meant that our effective trade in oil worked out to a net import average of 6,277,000 barrels of per day during the week, 433,000 barrels per day more than the net imports of the prior week...at the same time, field production of crude oil from US wells rose by 73,000 barrels per day to another record high of 9,780,000 barrels per day, which means that our daily supply of oil from our net imports and from wells totaled an average of 16,057,000 barrels per day during the reporting week...
during the same week, US oil refineries were using 16,952,000 barrels of crude per day, 243,000 barrels per day less than they used during the prior week, while at the same time 696,000 barrels of oil per day were being withdrawn from 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, from oilfield production, and from storage was 199,000 fewer barrels per day than what refineries reported they used during the week...to account for that disparity, the EIA needed to insert a (+199,000) 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, a metric that is labeled 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 7,442,000 barrels per day, 3.3% less than the 7,697,000 barrels per day average imported over the same four-week period last year....the 696,000 barrel per day decrease in our total crude inventories came about on a 731,000 barrel per day withdrawal from our commercial stocks of crude oil, which was slightly offset by a 35,000 barrel per day addition of oil to our Strategic Petroleum Reserve, which was likely a return of oil that was borrowed from the Reserve during the post Hurricane Harvey emergency...this week's 73,000 barrel per day increase in our crude oil production included a 65,000 barrel per day increase in output from wells in the lower 48 states, and a 8,000 barrels per day increase in output from Alaska....the 9,780,000 barrels of crude per day that were produced by US wells during the week ending December 8th was yet another new record high for US output, 11.5% more than the 8,770,000 barrels per day we were producing at the end of 2016, and up 16.0% from the recent output nadir of 8,428,000 barrels per day produced during the last week of June 2016...
US oil refineries were operating at 93.4% of their capacity in using those 16,952,000 barrels of crude per day, down from 93.8% of capacity the prior week, still a bit above their normal pace for this time of year....the 16,952,000 barrels of oil that were refined this week was 4.4% less than the record 17,725,000 barrels per day that were being refined at the end of August, but still 2.9% more than the 16,474,000 barrels of crude per day that were being processed during week ending December 9th, 2016, when refineries were operating at 90.5% of capacity, and 10.4% above the 10-year seasonal average for this time of the year...
even with the decrease in the amount of oil refined, gasoline output from our refineries was 4.5% higher, increasing by 371,000 barrels per day to 10,129,000 barrels per day during the week ending December 8th, after two equally inexplicable gasoline output drops in a row...that increase meant our gasoline production was 3.1% higher than the 9,828,000 barrels of gasoline that were being produced daily during the week ending December 9th of last year...on the other hand, our refineries' production of distillate fuels (diesel fuel and heat oil) fell by 155,000 barrels per day to 5,247,000 barrels per day, down from last week's record high output...however, that was still 4.8% more than the 5,009,000 barrels per day of distillates that were being produced during the the same week a year ago....
with the increase in our gasoline production, our gasoline inventories at the end of the week rose by 5,664,000 barrels to 226,546,000 barrels by December 1st, following a year-high 6,780,000 barrel jump in gasoline supplies the prior week...that was as our domestic consumption of gasoline rose by 196,000 barrels per day to 9,091,000 barrels per day, while our exports of gasoline fell by 163,000 barrels per day to 731,000 barrels per day, and while our imports of gasoline fell by 5,000 barrels per day to 483,000 barrels per day...however, with significant gasoline supply withdrawals in 15 out of the last 26 weeks, our gasoline inventories are still down by 6.6% from their pre-summer high of 242,444,000 barrels, and down by 1.5% from last December 9th's level of 230,045,000 barrels, even as they are now roughly 4.1% above the 10 year average of gasoline supplies for this time of the year...
meanwhile, with the drop in our distillates production, our supplies of distillate fuels fell by 1,370,000 barrels to 128,076,000 barrels over the week ending December 8th, the eleventh decrease in distillates supply in fifteen weeks...this week's drop was because the amount of distillates supplied to US markets, a proxy for our domestic consumption, jumped by 643,000 barrels per day to 4,380,000 barrels per day, even as our exports of distillates fell by 360,000 barrels per day to 1,212,000 barrels per day, while our imports of distillates rose by 4,000 barrels per day to 149,000 barrels per day...after this week’s decrease, our distillate inventories were thus 17.9% lower at the end of the week than the 155,935,000 barrels that we had stored on December 9th, 2016, and roughly 5.9% lower than the 10 year average of distillates stocks at this time of the year…
finally, even with the week's increase in our oil imports and the decrease in our refining, our commercial crude oil inventories still fell for the 29th time in the past 36 weeks, decreasing by 5,117,000 barrels, from 448,103,000 barrels on December 1st to a 26 month low of 442,986,000 barrels on December 8th....while our oil inventories as of December 8th were thus 8.3% below the 483,193,000 barrels of oil we had stored on December 9th of 2016, and 3.4% lower than the 458,354,000 barrels of oil that we had in storage on December 11th of 2015, they were still 27.5% greater than the 347,466,000 barrels of oil we had in storage on December 12th of 2014, before the current oil glut in the US had really built up our crude supplies to above normal levels...
This Week's Rig Count
US drilling activity decreased for the first time in 6 weeks during the week ending December 15th, with a drop in oil directed rigs responsible for the decrease, despite elevated oil prices...Baker Hughes reported that the total count of active rotary rigs running in the US fell by 1 rig to 930 rigs in the week ending on Friday, which was still 293 more rigs than the 637 rigs that were deployed as of the December 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 fell by 4 rigs to 747 rigs this week, which was still 237 more oil rigs that were running a year ago, while the week's oil rig count was far below the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the number of drilling rigs targeting natural gas formations rose by 3 rigs to 183 rigs this week, which was still only 57 more gas rigs than the 126 natural gas rigs that were drilling a year ago, and way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...
offshore drilling activity in the Gulf of Mexico and nationally was down by 1 rig to 19 rigs this week, which was also down from the 22 rigs deployed in the Gulf of Mexico and nationally a year ago....the count of active horizontal drilling rigs increased by 5 rigs to 801 horizontal rigs this week, which was up by 289 rigs from the 512 horizontal rigs that were in use in the US on December 16th of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the directional rig count was down by 2 rigs to 69 rigs this week, which was still up from the 54 directional rigs that were working during the same week last year....likewise, the vertical rig count was down by 4 rigs to 60 vertical rigs this week, but that was also down from the 71 vertical rigs that were deployed on December 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 December 15th, the second column shows the change in the number of working rigs between last week's count (December 8th) and this week's (December 15th) count, the third column shows last week's December 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 9th of December, 2016...
as you can see from the above, the 3 rig increase of rigs targeting natural gas was all in the Marcellus and all in Pennsylvania, the second week in a row that the Marcellus has seen a three rig increase...it's possible the new drilling there was meant to coincide with the opening of several pipelines that would take natural gas away from this area; the original start date for the Rover was to be in December, but that was delayed when their drilling was shut down after several fluid spills...FERC just gave the Rover the go ahead this week, and in addition the Leach XPress pipeline, which originates near the PA border and will deliver gas to central Ohio and thence points south, is expected to commence service on January 1st...we should also note that outside of the major producing states listed in the first table above, a rig was also shut down in Montana this week, where one rig still remains active, which is nonetheless an increase from a year ago, when no rigs were working in Montana..
Shale Energy Alliance touts ways to build the oil and gas industry - Marietta Times — Area oil and gas company representatives gathered Wednesday at the Blennerhassett Hotel to learn how the Shale Energy Alliance can make a difference and make the industry grow. Dave Caliguiri, with the Shale Energy Alliance, said the alliance is dedicated to the development of the oil and gas industry in the region.“We are a group of committed stakeholders, this includes producers, landowners, lease holders and others,” he said. “The Shale Energy Alliance is dedicated to preserving the safe, responsible and rational development of our nation’s natural energy resources. We are committed to fostering and promoting the positive benefits of shale development and hopefully, one day, getting us closer to energy independence.”Caliguiri said the group wants to help the industry grow across the region.“You, our members, work tirelessly every single day to make sure your neighbors have the energy they need to turn on the lights, cook a meal and heat a house — and we’re doing it locally.”Caliguiri said the members of the alliance work together.“One of those folks is energy transportation,” he said. “They do business with many of you in this room, they haul water and other services to this industry and they also buy vehicles from local businesses. We are a family united together to help one another and our neighbors.” “The Shale Energy Alliance makes sure our community leaders, our decision makers, our regulators and the media have the most up-to-date information and understanding of the positive effects of the natural gas industry. That’s who we are and what we can do,” Caliguiri. Lynette Stevens, a director with the Shale Energy Alliance, said the group is looking forward to working with the 2018 Legislature. Stevens said the next session is their opportunity to put natural gas legislation on the books.
Residents voice concerns with possible Ashland County fracking - Mansfield News Journal — Residents voiced their concerns with a company's plans for possible fracking in Ashland County during a public meeting Monday evening.The meeting came after Houston-based Cabot Oil and Gas Corporation began initial work in recent months for potential exploratory wells in Ashland County. About 10 people gathered in the shelter building at Kendig Park in Hayesville for the panel discussion."This little town will never be the same if the trucks come in and out and put in that well," said Ashland County resident and panelist Elaine Tanner with Friends for Environmental Justice. "And it's gonna come right off of Route 30, you know. That's the easiest way to get here, and we just don't want to see that happen." The four-member panel included Tanner, local environmental activist Bill Baker from Mansfield, Ashland University English professor Deborah Fleming and a concerned resident who asked not to be named.The panelists raised several environmental and safety concerns with the hydraulic fracturing process.Hydraulic fracturing, often called fracking, is a drilling process in which a high-pressure liquid is directed at rocks below the earth's surface to extract oil or gases from inside. "My number one concern is the water, water quality," Tanner said. "Once it's gone, we have no choice but to find plan B, and there's no plan B for our water. There's no plan B for our air." Fleming said the underground shale, which in this part of Ohio is part of the Utica Shale, is permeable and can allow chemicals from fracking to pass through, potentially into water supplies. "I don't want to sit still and let somebody else poison my water," she said. Some residents said they've heard of one neighbor in the area who signed a lease for a well to be allowed on their property. Tanner said the resident who signed the lease lives on a site on U.S. 60 a little more than a mile south of the village. George Stark, spokesperson for Cabot Oil and Gas Corporation, said the company is considering several sites around Ashland County for an exploratory well. “We’re exploring many options," he said in a phone call Monday afternoon. Stark said no sites have been selected at this point, and no permits have been signed.
US OKs more ETP natgas pipe drilling, Ohio wants pause (Reuters) - U.S. energy regulators on Thursday approved Energy Transfer Partners LP’s request to resume horizontal drilling at eight sites in Ohio and West Virginia as it works to complete part of the Rover natural gas pipeline by the end of the year. The approvals came as the Ohio Environmental Protection Agency sought a pause in Rover’s horizontal drilling in the state due to repeated spills of the clay and water mix used to lubricate the drilling blades. The Ohio EPA asked the U.S. Federal Energy Regulatory Commission (FERC) for the pause on Nov. 24. “Ohio was only informed shortly before and not consulted about the FERC approval to Rover. We are still very concerned about the total and continuing number of environmental impacts Rover is causing in Ohio,” Ohio EPA director Craig Butler said in a statement. Pipeline companies use horizontal directional drilling to cross under large obstacles like highways and rivers. ETP said that with the FERC approval on Thursday it can proceed with all 49 horizontal drills for the entire Rover project. It has already completed 29 of those drills. Once finished, the $4.2 billion Rover will carry up to 3.25 billion cubic feet per day of gas from the Marcellus and Utica shale fields in Pennsylvania, Ohio and West Virginia to the U.S. Midwest and Ontario in Canada. One billion cubic feet per day of gas can supply about 5 million U.S. homes. In a letter filed with FERC late on Wednesday, ETP said the Ohio EPA “grossly mischaracterizes Rover’s activities.” ETP said the five spills identified by the Ohio EPA in its Nov. 24 request were at two locations, Captina Creek and Black Fork Mohican, and not “significant” in size, the biggest being an estimated 1,188 gallons (4,500 liters) at Captina Creek on Oct. 11. ETP said in its letter that Rover was in compliance with the FERC-approved plan that allowed the company to start horizontal drilling again in September.
Columbia Gas seeks January 1 startup for Leach XPress Pipeline - Columbia Gas has filed a request with the US Federal Energy Regulatory Commission for authorization to commence service on its 1.5 Bcf/d Leach XPress Pipeline effective January 1. During early trading Thursday, Markets responded to news of the late-Wednesday FERC filing with a 9-cent/MMBtu jump in forward basis prices for January gas delivered to the Dominion South hub, where the greenfield pipeline is expected to have measurable impacts on prices and production. The authorization request for Leach XPress follows a recent move by Columbia Gas to delay the startup of service on the pipeline, initially scheduled for November 1. At the time, Columbia Gas said that slow permitting processes, weather setbacks and unforeseen construction hurdles were to blame for the delay. The targeted in-service date was pushed back to early January, making Wednesday's January 1 startup request an ambitious target. In the FERC filing, Columbia Gas said that it anticipates the commissioning process for the pipeline to begin as early as December 25. The startup of service on Leach XPress is expected to help relieve production constraints for producers in Ohio, West Virginia and Pennsylvania with the addition of 1.5-Bcf/d of new upstream takeaway capacity in the tri-state region. The additional capacity will give upstream producers more optionality, lifting prices at constrained upstream hubs Dominion South and Texas Eastern M-2. But with Leach Xpress designed to deliver an incremental 0.4 Bcf/d to the Columbia Gas Appalachia hub, also known as TCO Pool, the expansion could put prices there under downward pressure next year.
Babies born near fracking sites face low birth weight,study finds. Researchers studied more than 1.1 million births in Pennsylvania … Babies born to mothers living within two-thirds of a mile from a fracking well site see a 25 percent increase in the probability of significantly low birth weight, a condition linked to other health problems later in life, according to a new study. The research adds to a growing body of scientific work that links the controversial extraction process with adverse effects on the environment and people. Based on an analysis of more than 1.1 million births in Pennsylvania between 2004 and 2013, the researchers found that babies born to mothers who lived within 1 kilometer, or 0.64 miles, of a fracking well weighed, on average, 1.38 ounces less than babies born to women whose pregnancies occurred 3 kilometers or more from a fracking site. Low birth weight is a risk factor for numerous negative outcomes, including infant mortality, attention deficit hyperactivity disorder, asthma, lower test scores, lower schooling attainment, lower earnings, and higher rates of social welfare program participation, the researchers noted. The Princeton University, University of Chicago, and University of California-Los Angeles researchers found little evidence of health effects at distances beyond 3 kilometers, suggesting that health impacts of fracking are highly local. The study, “Hydraulic Fracturing and Infant Health: New Evidence from Pennsylvania,” was published Wednesday in the journal Science Advances. “Given the growing evidence that pollution affects babies in utero, it should not be surprising that fracking, which is a heavy industrial activity, has negative effects on infants,” co-author Janet Currie, the Henry Putnam Professor of Economics and Public Affairs at Princeton University, said in a statement.
Babies born to moms who lived near fracking wells faced health risks, study suggests - - After combing through a decade's worth of Pennsylvania birth records, researchers have found that pregnant women living within two-thirds of a mile of a hydraulic fracturing well were 25 percent more likely to give birth to a worryingly small infant than were women who lived at least 10 miles outside that zone during pregnancy. Over these babies' lifetimes, their low birth weights raise the likelihood they will suffer poorer health and lower achievement, including reduced earnings and educational attainment. The authors of the new research estimated that 29,000 of the close to 4 million annual births in the United States — roughly 0.7 percent of babies born each year — were to women who lived within about two-thirds of a mile of a hydraulic fracturing operation during their pregnancies. The study was published Wednesday in the journal Science Advances. Nationally, the advent and expansion of hydraulic fracturing operations have reduced gasoline prices, decreased some air pollution emissions, and driven down U.S. dependence on foreign oil. But in areas surrounding the nation's roughly 1.2 million fracking wells, the extraction technique has increased pollution of air, soil, groundwater and surface water. Many of the toxic chemicals used in the hydraulic fracturing process are known carcinogens. Toxic gases, including benzene, are released from the rock by fracking. And the high-pressure pumping of a slurry of chemical into the ground is widely thought to release toxins and irritants into nearby air and water. The noise and pollution emitted by trucks and heavy machinery also may affect the health of people living nearby.
Living Near Fracking During Pregnancy Linked To Poorer Newborn Health – Forbes - The closer pregnant women live to fracking sites, the greater the potential health risks may be to their developing fetus, suggests a new study published in Science Advances December 13. But the study has enough limitations to tamp down anxiety among expecting moms who live near fracking sites. It’s not necessary to run away from home until giving birth if you’re around the corner from fracking. In the study, infants born to women living within a 1-km radius (just over a half mile) of a fracking site during pregnancy had a 25% greater risk of having a low birthweight, defined as under 5.5 lbs. Those born within 3 km (nearly 2 miles) of a fracking site also had a slightly increased risk of low birthweight, but it was about one third to one half the risk seen in women living within 1 km. “The results of our analysis suggest that the introduction of fracking reduces health among infants born to mothers living within 3 km of a well site during pregnancy,” the authors wrote. “There is little evidence of health effects at further distances, suggesting that health impacts are highly local.” The overall risk of low birthweight among all the infants in the study overall was on par with national rates. The findings are based on an analysis of more than 1.1 million single-child births in Pennsylvania between 2004 and 2013, and they line up with similar studies comparing infant health and air pollution. About a quarter of the infants included in the study were born to women living within 15 km of an active fracking site while pregnant. Across the U.S., an estimated 65,000 babies are born each year to mothers living within 1 km of a fracking site.
We Just Found The Strongest Evidence Yet That Fracking Affects Human Health - More than 100,000 babies born in the US every year start life in such close proximity to fracking sites that it could significantly damage their health, new research suggests. Fracking – aka hydraulic fracturing – has long been criticised for its negative effects on the environment, but a new study analysing more than 1 million births provides what scientists say is the most damning evidence yet that fracking is bad for human beings."This study provides the strongest large-scale evidence of a link between the pollution that stems from hydraulic fracturing activities and our health, specifically the health of babies," economist and energy policy researcher Michael Greenstone from the University of Chicago told the Los Angeles Times.Greenstone and fellow researchers analysed records of more than 1.1 million births across Pennsylvania from 2004 to 2013, looking to see what differences if any were evident between babies born close to fracking sites compared to babies born further away. What they found was that babies born within 3 kilometres (1.9 miles) of fracking sites start to show greater risk of being born at a low birth weight, which in turn increases their likelihood of things like infant mortality, ADHD, asthma, and lower educational and earning outcomes. Outside of that 3 kilometre radius, no localised health effects were evident from fracking, but for babies born inside the zone, the danger seems to heighten the closer you get to drilling sites, as exposure to industrial pollutants increases. Babies born within 1 kilometre (0.6 miles) of a fracking site were 25 percent more likely to be born underweight than babies outside the 3 kilometre radius. Infants who started life within 1 to 3 kilometres of the sites were also affected by their proximity, but less significantly. "Birth weight is a proxy: it gives us an insight into what's going on in gestation, and we worry a lot when we see changes like this," "We know that babies born at low birth weight have a much, much higher risk of diseases such as coronary artery disease, hypertension, diabetes, and obesity."
Pennsylvania gas output remains focused in northeastern, southwestern corners -- Pennsylvania natural gas production continues to be concentrated in counties in the northeastern and southwestern corners of the state, according to a report by the state's Independent Fiscal Office. Four counties -- Susquehanna and Bradford, in the dry gas northeastern region, and Washington and Greene in the liquids-rich southwestern region -- comprised two-thirds of statewide production in the first three quarters of 2017, the IFO report said. Susquehanna in the northeastern corner of the Commonwealth was the leading gas producer, with output of 966.1 Bcf through September, comprising almost one quarter of the total gas production in the state. Coming in at second place with production of 679.2 Bcf, about 17% of the state's total, was Washington County. Bradford County, one county to the east of Susquehanna, came in as the No. 3 producer, with production through September of 583.3 representing almost 14% of the state's production. Rounding out the top five producing counties were Greene, with production of 495 Bcf, and Lycoming in the Northeast, with output of 268.3 Bcf. All of the state's gas-producing counties except Greene, Lycoming and Fayette registered gains in terms of production for the first three quarters of the year compared with the same period of last year. "The order of top gas-producing counties generally has remained consistent over the last several years, with production shifting somewhat from northeast to southwest counties," IFO spokesman Mark Ryan said in an email statement Friday. The report found that most of the production gains recorded in the first three-quarters of 2017 came from wells spud in 2015 and 2016. Although the report did not attempt to identify the reason behind this trend, Ryan said it might have resulted in part from producers drilling but not completing wells, in order to complete them at a later time when price realizations were better.
Michigan panel urges temporary shutdown of Mackinac pipeline - A government safety panel on Monday urged the temporary shutdown of twin oil pipelines in the Straits of Mackinac until their operator can finish inspections and repair coating gaps, after some members expressed concerns over a recent deal between the state and Enbridge Inc. The Michigan Pipeline Safety Advisory Board approved the non-binding resolution as members of Gov. Rick Snyder's administration who sit on the panel abstained from voting. Other non-binding resolutions call for temporarily halting the flow of oil during storms that produce sustained waves at least 3 feet (0.9 meter) high for longer than an hour, instead of an 8-foot (2.4-meter) threshold included in the agreement, and recommend that a "more robust" study of alternatives to Line 5 be completed. The agreement, announced Nov. 27, sets an Aug. 15 deadline for determining the future of the nearly 5-mile-long (8-kilometer) segment beneath the channel where Lakes Huron and Michigan converge. Options include shutting down the pipeline or routing it through a tunnel beneath the lakebed where it now rests. Because five or six members of the 16-person board voted for the measures while many others abstained, there was confusion over whether they had passed. Co-chairwoman Valerie Brader, executive director of the Michigan Agency for Energy, said she expected the Republican governor's administration to consider the resolutions as advisory while also taking note of the number of abstentions. Although the federal government regulates oil pipelines, Michigan owns the lake bottom and in 1953 granted an easement to the Canadian company allowing the pipeline to go there. "We know we have coating gaps. It's a violation of the easement and it only makes sense to shut down the pipeline until Enbridge can adequately address and fix the coating issues to ensure we don't have any type of rupture or leak," The line transports about 23 million gallons (87 million liters) daily between Superior, Wisconsin, and Sarnia, Ontario. At least four board members expressed frustration that Snyder struck the agreement without their input, contending it short-circuited the public process and signals that tunneling the pipeline is ultimately the state's preference.
Federal judge again denies South Portland’s plea to dismiss pipeline company’s lawsuit - Judge John Woodcock Jr. opened his written order issued Tuesday with a weary-sounding reference to “another motion to dismiss” from the city of South Portland.The federal judge then firmly denied the city’s renewed motion to dismiss a nearly 3-year-old lawsuit by the Portland Pipe Line Corp. over a municipal ban on crude oil exports. Woodcock denied the city’s first consolidated motion to dismiss the lawsuit in August. The city filed the latest motion in October, after TransCanada Corp. announced that it had abandoned plans to build the controversial Energy East pipeline, which would have carried 1.1 million barrels of crude oil daily from western Canada to the Atlantic coast.Without the Energy East pipeline, the Portland Pipe Line could no longer claim to have a ready source of Canadian crude that would warrant reversing the flow of its 236-mile pipeline from South Portland to Montreal, the city’s lawyers argued in November in U.S. District Court in Portland.The company is fighting a 2014 city ordinance that banned shipments of crude oil from South Portland’s waterfront and effectively blocked the company from reversing the flow of its pipeline, which currently transports a dwindling amount of imported crude to refineries in Montreal.Woodcock flatly rejected the city’s latest challenge of the Portland Pipe Line’s right to fight the so-called Clear Skies ordinance based on the lack of demand for the pipeline’s use.Woodcock cited the company’s claims that the pipeline could have access to other sources of Canadian crude and that it “will continue to be the sole operator of a crude oil pipeline running to the Atlantic coast.”“The court still finds that if it is legally permitted to do so, Portland Pipe Line Corp. intends to and is sufficiently likely to be able to reverse the flow of oil in its South Portland-to -Montreal pipelines,” Woodcock said in his dismissal order.
Environmental groups file suit in federal court against gas pipeline -- A coalition of environmental groups filed suit Friday to try to block the Mountain Valley Pipeline, a natural gas pipeline planned for the southwestern portion of Virginia that cleared the last regulatory hurdle and won state water permits Thursday. Appalachian Mountain Advocates filed the suit in the U.S. Court of Appeals for the 4th Circuit, seeking a review of the permits issued by the State Water Control Board. The pipeline is planned to run about 300 miles from West Virginia through the southwest corner of Virginia, to a location in Pittsylvania County near the North Carolina border. It’s being built by a group of companies led by EQT Midstream Partners of Pittsburgh. Appalachian Mountain Advocates was joined in the lawsuit by the Sierra Club, Appalachian Voices, the Chesapeake Climate Action Network and Wild Virginia. The groups contend that the state board and the Department of Environmental Quality rushed the review process and cut corners. The state has said that the pipeline has faced “the most rigorous regulatory process” of any such project in state history. An even larger pipeline project — the more than 600-mile Atlantic Coast Pipeline, backed by the state’s largest utility, Dominion Energy — faces water permit hearings Monday and Tuesday. That pipeline would run from West Virginia through Virginia to North Carolina. Supporters of the pipelines, including Gov. Terry McAuliffe (D), say they will generate jobs and economic activity for the state and provide utilities with needed capacity. Opponents, including environmentalists and land-rights activists, say they threaten fragile ecosystems and impinge on property rights of landowners along the routes.
Panel grants conditional OK on key pipeline approval — A panel of Virginia environmental regulators granted a conditional permit Tuesday for the proposed Atlantic Coast Pipeline, making its approval contingent on getting more information about the project’s impact on water quality. The Virginia State Water Control Board voted 4-3 to approve a key Clean Water Act permit referred to as a 401 water-quality certification. The citizen board of gubernatorial appointees was charged with determining whether there is “reasonable assurance” water along the route won’t be contaminated during construction of the approximately $5 billion, 600-mile (965-kilometer) natural gas pipeline. The permit won’t take effect until several additional studies — including an erosion and sediment control plan, stormwater management plan and testing on sensitive karst topography — are reviewed and approved by the Department of Environmental Quality, spokesman Bill Hayden said. A full text of the amendments the board voted to include wasn’t immediately available late Tuesday. The department will not allow pipeline construction to begin until the erosion and sediment control plan is completed and approved, which might not be until March or April, Hayden said. Pipeline spokesman Aaron Ruby called the decision “a very significant milestone for the project and another major step toward final approval.” The company will work closely with state authorities “to complete all remaining approvals in a timely manner and ensure we meet all conditions of the certification,” he said in a statement. Richmond-based Dominion Energy is the lead developer of the project, which would start in West Virginia and cross into Virginia and North Carolina. A company executive has also suggested it might extend into South Carolina, but officially the company has said no decision has been made about a possible expansion. Many of the opponents who question the need for the project and say it will damage the environment, infringe on property rights and commit the region to fossil fuels, characterized Tuesday’s decision as a partial victory. “While this outcome buys us time, it’s still far from the end result for clean water we wanted - a flawed application that didn’t include required details outlining how Dominion planned to mitigate water pollution from its unnecessary pipeline shouldn’t have even gotten a hearing in the first place,”
Atlantic Coast Pipeline Opponents Down But Not Out After Conditional Approval - A Virginia panel of regulators granted a conditional approval for a controversial gas pipeline Tuesday, saying that more information on environmental impact is needed before the project can proceed. The Virginia State Water Board voted 4-3 to approve water permits for the pipeline in one of the project's last remaining hurdles, but delayed the start of construction until several additional environmental studies are reviewed and approved. The Atlantic Coast Pipeline , backed by state political power player Dominion Energy, has met with heavy local opposition. Advocates filed suit in federal court last week following the water board's decision to green light a similar project, the Mountain Valley Pipeline , last week. As reported by the Richmond Times-Dispatch : The board, which had been grappling with delaying a decision on the project, ultimately approved the certification with an amendment by board member Timothy G. Hayes that prevents it from becoming effective until the Virginia Department of Environmental Quality finishes reviewing and approving a series of plans and mitigation measures. Many pipeline opponents contend that those plans, which deal with stormwater and erosion and sediment control, among other areas, are key to deciding whether the project can be built without degrading state waterways. Developers' plans call for the 600-mile Atlantic Coast Pipeline to cut through 11 Virginia counties on its way to North Carolina, not including an extension to Chesapeake. "While this outcome buys us time, it's still far from the end result for clean water we wanted—a flawed application that didn't include required details outlining how Dominion planned to mitigate water pollution from its unnecessary pipeline shouldn't have even gotten a hearing in the first place," Lee Francis, communications manager for the Virginia League of Conservation Voters , said in a statement. "It's at least a promising sign that regulators sent Dominion back to the drawing board."
White House to Release Offshore Drilling Plan - The Trump administration is expected to unveil the new Five Year Offshore Oil Drilling Plan as early as this week, after signing an executive order earlier this year to expand offshore oil drilling in U.S. waters. Expanded offshore oil drilling threatens recreation, tourism, fishing and other coastal industries, which provide more than 1.4 million jobs and $95 billion GDP along the Atlantic coast alone. The executive order directed the Interior Department to develop a new five-year oil and gas leasing program to consider new areas for offshore drilling. The order also blocked the creation of new national marine sanctuaries and orders a review of all existing sanctuaries and marine monuments designated or expanded in the past ten years. "Our ocean, waves and beaches are vital recreational, economic and ecological treasures to our coastal communities that will be polluted by new offshore oil drilling, regardless of whether or not there is a spill," said Dr. Chad Nelsen, CEO of the Surfrider Foundation . "Without a massive mobilization by coastal communities around the country in opposition to new offshore drilling, our voice will be drowned out by the lobbying power of Big Oil in Washington, DC." New offshore drilling would threaten thousands of miles of coastline and billions in GDP, for a relatively small amount of oil. Ocean tourism and recreation, worth an estimated $100 billion annually nationwide, provides 12 times the amount of jobs to the U.S. economy, compared to offshore production. Even under the best-case scenario, America's offshore oil reserves would provide only about 920 days, or 18 months supply of oil at our current rate of consumption, according to federal agency estimates.
US considers weakening offshore safety rules to promote more drilling - The Trump administration is considering easing offshore oil and natural gas safety regulations, including eliminating certain requirements for Arctic drilling put in place by the Obama administration, and cutting testing requirements for rules developed in response to BP's Deepwater Horizon disaster, an Interior Department document showed Thursday. In addition, the administration is considering giving operators access to Arctic waters for longer periods than currently allowed, a rule change regulators claim could boost interest in exploration. Details of the administration's plans of offshore rules were outlined in the Interior Department's latest statement of regulatory priorities, which was released Thursday. That plan calls for Interior's Bureau of Safety and Environmental Enforcement to rollback or weaken offshore safety regulations put in place by the Obama administration in order to promote additional oil and natural gas drilling in federal waters. "BSEE is reviewing existing regulations to determine whether they may potentially burden the development or use of domestically produced energy resources, constrain economic growth, or prevent job creation," the plan states. "BSEE is well-positioned to help maintain the nation's position as a global energy leader and foster energy security and resilience for the benefit of the American people, while ensuring that any such activity is performed in a safe and environmentally sustainable manner." According to the plan, BSEE is considering significant changes to a well control and blowout prevention system rule which Obama's Interior Department finalized in April 2016. That rule, developed in response to BP's Deepwater Horizon disaster, took years to develop and was revised multiple times. Industry groups have criticized elements of the rule, including frequent testing of the blowout preventers and standardized safe drilling margins, arguing they will increase costs for offshore operators.
The Panama Canal Is Now a Major Problem for U.S. Shale - Just as the Panama Canal was unveiling a new, fatter set of locks, U.S. shale drillers were readying their very first exports of liquefied natural gas. While the wide-body tankers that transport LNG would’ve had no chance of squeaking through the original steel locks built a century ago, they could easily traverse the bigger channel and shave 11 days off the trip to primary markets in Asia. But 17 months in, it’s not quite working out as planned. Only a single LNG tanker has a guaranteed passage each day. The natural-gas industry blames the Panama Canal Authority for holdups, and the canal authority blames the industry for being lackadaisical about transit timetables.Whoever’s at fault, this much is clear: The pressure is on both sides to resolve their problems. For gas exporters, it’s critical to establish credibility as a reliable new source of fuel for clients in Asia. For the canal authority, the stakes are high too, with Mexico and other countries flirting with creating alternative routes as gas demand booms.“The canal surely has had some issues getting the new set of locks up and running smoothly,” said Peter Sand, an analyst with the shipping association BIMCO. “It has taken longer than the canal and the industry expected.”The story starts at the opening in June 2016 of the expansion project. It couldn’t have come at a better time for the LNG market, just as Cheniere Energy Inc. was ramping up operations at the first export terminal ever built in the lower 48 states, at Sabine Pass on the Louisiana-Texas border. The Panama Canal Authority promised a dozen daily slots for ships of all stripes to pass through the new lane -- ultimately. So far, the maximum it has been able to handle every 24-hour period is eight; preparations are underway to move that up to 10 or more in 2019. What rankles LNG companies is that they’ve been awarded just the single reserved slot, with the rest going to container ships that carry consumer goods from sneakers to refrigerators. One position isn’t sufficient now and will be wholly inadequate once all the new export terminals under construction go on line, said Octavio Simoes, president of Sempra LNG & Midstream, at a conference in October. He caused a ruckus when he warned that canal holdups could crimp sales and cost traders serious money.
Panama Canal Can’t Handle U.S. LNG Boom - The International Energy Agency recently predicted that the United States could become the world’s top LNG exporter within ten years. This prediction, however, is far from a certain one. The U.S. LNG boom is fraught with challenges, the latest among them, apparently, the Panama Canal. LNG producers and the Panama Canal Authority are locked in an argument about whose fault it is that not enough LNG tankers are using the freshly expanded channel that saves 11 days from the journey to Asia, which has become a key market for U.S. LNG. According to the producers, the canal has expanded the access of cargo vessels at the expense of LNG tankers. According to the authority, LNG producers can’t comply with timetables. The facts are as follows: the expansion of the Panama Canal has been going more slowly than initially planned. To date, only one LNG tanker a day can pass through the Panama Canal. That’s compared with a promised 12 slots for all kinds of vessels every day via the wider channel. Of this planned total, however, right now the Canal has a capacity to service just eight over 24 hours. But there’s more: recently the head of an LNG producer, Sempra, and the chief executive of the Panama Canal Authority locked horns over the discrepancy between the LNG industry’s plans and the Canal’s capacity. Sempra’s head, Octavio Simoes, fired the first shot, saying that in the future, insufficient channel capacity could cost gas traders a substantial sum and cripple U.S. LNG sales internationally. The Authority’s head, Jorge Quijano, responded with a hint that the LNG industry has yet to prove it deserves more slot reservations than one a day. If capacity-building were a sure indicator of the industry’s worth in the eyes of the Panama Canal Authority, then this worth would be quite high. Besides the Sabine Pass liquefaction plant—already the second-largest globally after Qatar’s Ras Laffan—there is now what the Houston Chronicle calls a second wave of LNG terminals coming on stream.
The Next U.S. Crude Export Surge May Start at a Lonely Gulf Buoy - The Louisiana Offshore Oil Port, which already handles imports from similar large ships known as Very Large Crude Carriers, or VLCCs, will likely be the first port to to load oil into a supertanker. LOOP has indicated that its pipelines require minor modifications and could operate in both directions in early 2018. "Expanding U.S. ports to accommodate direct loading of VLCCs will logistically help to streamline and expedite exports," Loading these mammoth ships without having to use other tankers to ferry the oil from shore could save shippers about a million dollars on each cargo. To a refiner in Europe or Asia, that may mean the difference between using U.S crude instead of oil from the Middle East, North Sea or West Africa. It may broaden the market for shale producers and further boost U.S. exports, which quadrupled in the past year to as high as 2.1 million barrels a day. A VLCC that gets its entire 2 million-barrel cargo directly from a single terminal spares the exporter the cost of hiring smaller ships to fill it up, Sandy Fielden, director of research and commodities for Morningstar Inc. in Austin, Texas, said in a phone interview. This process, known as reverse lightering, could cost at least 50 cents a barrel, he said. In addition to the freight cost, shipowners bill charterers if there are delays in lightering, which are not uncommon. These late fees, or demurrage, can run more than $35,000 a day for a VLCC, LOOP has a big advantage over Texas ports. Its buoy sits 20 miles (32 kilometers) offshore in 100 feet of water, deep enough to handle the biggest tankers. The ports of Corpus Christi and Houston, which currently handle the most exports, aren’t deep enough to fully load a VLCC with a draft of 70 feet to 74 feet.
Permian Basin Refinery Project Doubles in Capacity | Rigzone: The developer of a planned West Texas refinery has decided to increase crude oil processing capacity in the Permian Basin by one-third rather than one-sixth. MMEX Resources Corp, which in March of this year unveiled plans to build a 50,000-barrel per day (bpd) refinery in Pecos County, Texas, on Nov. 17 broke ground on the facility’s 10,000-bpd crude distillation unit (CDU). Moreover, the company has raised the capacity of its planned refinery – to be built on a 250-acre site northeast of Fort Stockton – to 100,000 bpd. The Permian Basin’s three existing refineries can process 300,000 bpd of crude oil, and MMEX plans to start the permitting process for its refinery early next year.MMEX’s project will be one additional outlet for growing Permian crude oil production. In just the past week, companies such as Enterprise Products Partners L.P. and Phillips 66 and Enbridge have announced projects to add crude pipeline takeaway capacity from the region.“By increasing the refinery’s capacity to 100,000 bpd, we are able to double the output of the refinery for only one-third of the increase in CAPEX,” Jack W. Hanks, MMEX’s president and CEO, told Rigzone late last week.When it initially announced the refinery project, MMEX had projected a $450 million cost for the then-50,000-bpd plan. Since then, the project – in addition to getting a larger price tag of roughly $600 million and beginning construction on the CDU – has cleared various milestones, Hanks noted. He explained that the initial CDU phase is a distinct project from the full-scale refinery and has been permitted separately from the larger, “Phase II” refinery component. He said that MMEX expects to kick off Phase II permitting during the first quarter of 2018. The CDU/Phase I construction should support approximately 100 jobs and create 25 to 30 full-time positions once the unit begins operations by the end of 2018, said Hanks.
Will A Wave Of Permian Pipeline Projects Avert Takeaway Constraints? -- A number of Permian pipeline projects that would help alleviate impending takeaway constraints in the fast-growing production region have advanced in recent weeks — a clear sign that producers, shippers and midstream companies alike are paying close attention. But will these projects be enough, particularly when you consider the flood of capital spending in the Permian by exploration and production companies and the accelerated production growth that it may spur? Today, we discuss the progress midstreamers have been making on the Permian takeaway front as production of crude oil, natural gas and natural gas liquids (NGLs) in the play ratchets up. Production of crude oil and NGL-packed associated gas in the Permian has been rising quickly, putting added pressure on midstream companies to build more pipeline takeaway capacity — and fast. Crude oil output in the 70,000-square-mile play in West Texas and southeastern New Mexico now tops 2.6 MMb/d, while natural gas production is up to 7 Bcf/d and NGL output exceeds 800 Mb/d. And with the price of West Texas Intermediate (WTI) higher than it’s been in more than two years and the breakeven cost for many Permian producers falling, production growth is poised to accelerate. As we discussed recently in Ready to Run, a number of the oil-focused and diversified E&Ps we track have been ramping up their planned 2018 capex in the Permian — examples we noted include ConocoPhillips, Parsley Energy and Occidental Petroleum. Just after we posted that blog, Chevron announced that in 2018 it will invest $3.3 billion in Permian projects, and that it plans to increase its Permian rig count by one-third (to 20 from the current 15) by the end of next year. Previously, ExxonMobil said that in 2018 it plans to add 10 Permian rigs to the 20 already active there.
Update On Fracking Sand -- Financial Times -- December 9, 2017 - From The Financial Times: Going local for supplies sparks new frac sand boom. Market is stretched to full capacity amid US shale oil’s drive to extend output cheaply. Windblown dunes in west Texas are the latest front in the shale oil industry’s campaign to extract more barrels at less cost. The industry is excavating dunes for frac sand, which is pumped into wells to crack open rocks and get oil and gas flowing. The deposits are in demand because they lie close by the hot Permian shale region, making them cheaper than sands carried in from older mines 1,000 miles away. Locally dug sand is influencing the economics of US oil production, helping shale supplies compete in world markets. It is also worrying investors who own shares in railroads that haul sand and in sand miners that may be on the cusp of a glut. Sand was a critical ingredient of the shale drilling revolution. Without it, US oil production would not have nearly doubled in the past decade to an estimated 9.7m barrels per day. Between 2012 and 2014, total US demand for “proppants” such as frac sand rose from 34m to 61.5m short tons, according to Rystad Energy, a consultancy. Then oil prices collapsed, bringing down sand consumption as well. Volumes are again on the upswing as drilling accelerates, oil wells get longer and more sand is used per foot of well. Demand is forecast to surpass 100m short tons next year, Rystad says. “Right now, the market is really stretched thin,” says Thomas Jacob, a senior analyst at IHS Markit, a research company. “Everyone is running at full capacity.” But this sand boom is different than the last. In the first phase of the shale fracking boom, oil producers were notorious for prioritising production growth over investor returns. They sought premium sand supplies far from the oil patch in states such as Wisconsin. Its “northern white sand” was prized for hardness and roundness that made a porous latticework inside underground wells. But given its bulk, it also cost a fortune to ship. Northern white sand has averaged $41 per short ton at the mine gate this year, according to IHS Markit, but can cost $120 at a Texas well head after transport. Cost-cutting among oil companies sparked a search for supplies lying around the Permian, known as brown sand. While finer in grain, it is also cheaper at $75-$80 per short ton at the well head, Mr Jacob says. Distances are short enough to make some deliveries economical by truck.
Small earthquakes at fracking sites may be early indicators of bigger tremors to come, say Stanford scientists -- Stanford geoscientists have devised a way of detecting thousands of faint, previously missed earthquakes triggered by hydraulic fracturing, or “fracking.” The technique can be used to monitor seismic activities at fracking operations to help reduce the likelihood of bigger, potentially damaging earthquakes from occurring, according to the new study. “These small earthquakes may act like canaries in a coalmine,” “When they happen, they should be viewed as cautionary indicators of underground conditions that could lead to larger earthquakes.” . “In our study, you can actually see individual earthquakes occurring next to the section of a well that’s being fracked,” said Stanford PhD student Clara Yoon, lead author of the study published in the Journal of Geophysical Research. In October 2010, residents near an Arkansas natural gas field were shaken by a magnitude 4 earthquake that was followed by two larger aftershocks in February 2011.Scientists say these large earthquakes were caused by injections of wastewater from fracking sites into deep underground wells, and not by fracking operations closer to the surface. Using an advanced data-mining algorithm developed by Yoon and her colleagues, the Stanford team conducted a retrospective analysis of seismic activity in Arkansas prior to the magnitude 4 event. The algorithm uses earthquake-pattern recognition to generate detailed records of seismicity. The analysis tracked seismic events generated at production wells that utilized fracking and at deeper wastewater-disposal wells nearby. “We were interested in how the sequence that led to the magnitude 4 earthquake got started,” When Yoon ran the algorithm on this dataset, she discovered more than 14,000 small, previously unreported earthquakes. By comparing the timing and location of the tremors with fluid-injection data provided by the state of Arkansas, Yoon was able to demonstrate that most of the earthquakes were the direct result of fracking operations at 17 of the 53 production wells. “It had been thought, and we thought, that early earthquakes in this area were related to wastewater injection. But we found that the majority were caused by fracking.”
Nebraska PSC hears arguments over TransCanada's motion to amend its application on Keystone XL pipeline — The corporation behind the Keystone XL oil pipeline urged a Nebraska regulator Tuesday to amend a recent order approving a route for the controversial project. The five members of the Nebraska Public Service Commission heard oral arguments from attorneys for and against the commission’s Nov. 20 approval of a pipeline route. A lawyer for TransCanada Corp. said Tuesday that the company wants to amend its application, which gained approval on a 3-2 vote. Allowing changes to the application and the PSC’s final order would address questions that could prompt more legal challenges and further delays, the lawyer added. “We think the commission has the perfect opportunity right now to erase any such concern and prevent the risk of relitigating these issues,” said James Powers, an Omaha attorney who represents TransCanada. Pipeline opponents said the routing law allows only rejected applications to be amended. The PSC approved a route, however flawed that approval might have been, said David Domina, an Omaha lawyer who represents affected landowners. In addition, the law gives the PSC seven months to render a decision on the pipeline application, and that deadline elapsed on Nov. 23, Domina argued. “The gun has sounded; the game is over. You have no jurisdictional authority now to back up ... so they can amend,” he said. TransCanada had asked the PSC to endorse what it called the preferred route for the underground 36-inch pipeline, which would carry 830,000 barrels daily from Canada’s tar sands region to refineries on the Texas Gulf Coast. But in an unexpected decision, the PSC approved the “mainline alternative route,” which the company also had included in its application. The slightly longer alternative route parallels a portion of the company’s original Keystone pipeline, which went into service in 2010. Powers said Tuesday that the company agrees that the alternative route meets the public interest, which was the fundamental determination the PSC had to make before approving the application. Domina and other opponents disagreed. They said that the law compels the PSC to consider a single route and that TransCanada must file a new application if it wants to use the alternative route.
Trump, Zinke to Auction Away 700,000 Acres of Western Public Lands for Fracking -- President Trump and Interior Sec. Ryan Zinke are continuing their onslaught against American public lands this holiday month and moving forward with plans to auction off 700,000 acres for fracking , endangering clean air and water, the climate and sacred lands. "First it's our cherished national monuments , now Trump and Zinke are set to give away even more public lands to the fossil fuel industry," said Becca Fischer, climate guardian for WildEarth Guardians . "Rather than giving back this holiday season, this administration is proving that it will stop at nothing to put our public lands in the hands of dirty energy executives and sell off our rights to clean energy and a healthy environment." In total in 2017, the U.S. Department of the Interior's Bureau of Land Management (BLM) has auctioned and is proposing to auction off more than a million acres of public lands for fracking in Colorado, Montana, Nevada, New Mexico, Utah and Wyoming . Of that 1 million, the BLM will sell 700,000 acres in the December sales.
- ● On Dec. 7, the BLM sold 22,000 acres in northwestern Colorado and 2,100 acres in southeastern New Mexico.
- ● On Dec. 12, 99,000 acres in Montana, 388,000 acres in Nevada and 94,000 acres in Utah are slated to be auctioned off for fracking.
- ● On Dec. 14, 72,000 acres in Wyoming are slated to be auctioned off.
The pace of public lands giveaways is set to increase in 2018. The BLM's lease sales for the first half of the year already total almost 1 million acres . "While oil and gas companies get rich, Americans are shouldering the cost of climate change , air pollution , water contamination, lost wildlife habitat and degraded sacred lands," said Fischer. "This administration has made abundantly clear that the American public and their lands are nothing more than a 'burden' to industry." The December lease sales come amid growing protests over the BLM's management of public lands for fracking. WildEarth Guardians filed administrative appeals (also called "protests") challenging the proposed leasing in Colorado , Montana , Nevada , New Mexico , Utah and Wyoming as illegal under federal law. "In every western state, the Bureau of Land Management is sidestepping the law, shortcutting its reviews and doing everything it can to lock out the American public," said Fischer. "Sadly, on our public lands, the BLM is putting fracking above everything."
ALEC, Corporate-Funded Bill Mill, Considers Model State Bill Cracking Down on Pipeline Protesters – Steve Horn - At its recent States & Nation Policy Summit, the American Legislative Exchange Council (ALEC), a group that connects state legislators with corporations and creates templates for state legislation, voted on a model bill calling for the crack down and potential criminalization of those protesting U.S. oil and gas pipeline infrastructure.Dubbed the Critical Infrastructure Protection Act, the model legislation states in its preamble that it draws inspiration from two bills passed in the Oklahoma Legislature in 2017. Those bills, House Bill 1123 and House Bill 2128, offered both criminal and civil penalties which would apply to protests happening at pipeline sites. Critics viewed these bills as an outgrowth of the heavy-handed law enforcement reaction to protests of the Dakota Access pipeline.At the time the bills were still under proposal, the Oklahoma American Civil Liberties Union (ACLU) criticized them, saying they had the potential to quash free speech and the right to assemble as protected by the First Amendment. “The First Amendment protects our right to stand in the Capitol rotunda,” Ryan Kiesel, executive director of the Oklahoma ACLU, told the Oklahoma Gazette in March. “It also protects the rights of Oklahomans and Americans to engage in speech and activity, knowing that if they engage in civil disobedience, that the penalties they face should not be disproportionate. If we chill and keep people home, away from the cameras and away from the public they are trying to wake up on any number of issues, we are doing a real disservice to our democracy.” Alyssa Hackbarth, a spokesperson for ALEC, did not respond to multiple requests for comment clarifying whether the model bill actually passed through the Energy, Environment and Agriculture Task Force. Officials working for the Task Force also did not respond to a request for comment. ALEC's website still lists the bill as a draft proposal introduced on December 7.
Final GOP tax bill would allow Arctic refuge drilling | TheHill: A tax cut compromise reached Wednesday by GOP negotiators contains a plan to drill for oil in the Arctic National Wildlife Refuge (ANWR), Sen. Lisa Murkowski (R-Alaska) said. At a tax bill conference committee meeting, Murkowski said the bill “contains the single most important step I believe we can take to strengthen our energy security and create new wealth.” “We fought long to authorize a program for energy development in Alaska’s nonwilderness 1002 area,” she said, using the formal term for the area within the refuge that would see drilling under the GOP plan.Murkowski said the terms of the bill would raise “more than $1 billion within 10 years and it will likely raise over $100 billion for the federal Treasury” over the long term. “This is new wealth from responsible development and the investment it brings,” she said. "It’s time to open up the 1002 area and it’s time to reform our broken tax code.” The Senate-passed version of the tax bill included a Murkowski provision calling for drilling lease sales in a corner of the 19 million-acre ANWR within the next decade, with the federal and Alaskan governments splitting the revenues. The oil industry and supporters of the plan insist it will raise significant revenue, though analysts and critics of ANWR drilling question whether there is enough demand to match those estimates. Rep. Raúl Grijalva (D-Ariz.), another tax bill negotiator, called the ANWR provision “a completely unrelated, unpopular provision that should not be forced through this Congress under these procedures.” “We don’t need the oil. We’re exporting millions of barrels per day in this country and I hope there is consideration given to that.”
GOP Tax Bill Sneaks Plan to Drill Arctic Refuge -- The pristine Arctic National Wildlife Refuge ( ANWR ) faces a looming threat from oil and gas drilling. The little known provision , proposed by Sen. Lisa Murkowski of Alaska, was quietly included in the House and Senate Republicans' compromise tax bill. The bill “contains the single most important step I believe we can take to strengthen our energy security and create new wealth," Murkowski, who chairs the Energy and Natural Resources Committee, said Wednesday at the tax bill conference committee meeting. “We fought long to authorize a program for energy development in Alaska's nonwilderness 1002 area," she said. The “1002 area" is a 1.5-million-acre coastal plain that holds potentially large deposits of oil and gas but also contains crucial wildlife habitats. A new analysisby the Center for American Progress and Conservation Science Partners describes the coastal plain that Sen. Murkowski's rider would auction off for drilling as the “biological heart" of the Arctic Refuge that hosts one-third of all polar bear denning habitat in the U.S. and one-third of the migratory birds that come to the Arctic Refuge. It is also considered sacred to the indigenous Gwich'in people, who sustain themselves from the caribou that migrate there. Opening up the area to petroleum exploration has been deferred since ANWR's establishment in 1980. Drilling ANWR would help pay for the Republicans' sweeping corporate tax cut plan. Murkowski insisted that her rider would raise “more than $1 billion within 10 years and it will likely raise over $100 billion for the federal Treasury" over time. Opponents of ANWR drilling are now racing against time since Republican leaders are hoping to get their tax bill signed by President Donald Trump by Christmas.
Here’s what oil drilling looks like in the Arctic refuge, 30 years later - These satellite images of a small part of the Arctic National Wildlife Refuge show the site of what, so far, is the only oil well ever drilled in the refuge, an exploratory well known as KIC-1 that was completed in the mid-1980s. The well was plugged and abandoned, and the drilling equipment and a special timber pad it sat on have long since been removed. But as these infrared images show, even after three decades, the well’s footprint — about 600 feet long on its longest side — is easily distinguishable from the undisturbed tundra around it. The arctic refuge is a vast region of tundra: mosses, sedges and shrubs underlain by permafrost. But the area is also believed to contain large petroleum reserves. Since the current boundaries of the refuge were established by an act of Congress in 1980, there has been a debate over whether oil and gas exploration should be allowed in a portion of the area, 1.5 million acres on the coastal plain. The issue has been revived in recent months, and through the budget-making process Republicans in Congress are perhaps closer than ever to opening the area to drilling. Here’s the site in 1988, a couple of years after operations at the well ceased, when most of the vegetation was dead: “It’s easy to do something on the tundra but it’s very difficult to restore,” The drillers took care to protect the tundra, creating an ice runway to fly in huge timbers to serve as the pad, instead of a potentially more destructive gravel base. The pad was insulated from the ground as well, and the operators also dug two pits next to it to hold the mud and rock that was drilling waste. While the timber pad offered some advantages, it effectively killed the vegetation beneath it, Without the vegetative cover to keep the permafrost cold, it began to thaw. Vertical wedges of solid ice melted, creating pools of water. The two pits, which were initially covered with soil, subsided over the years, leading to more pooling. They were topped with gravel a decade ago and now have very little vegetation. Given all the thawing and melting, Ms. Jorgenson said, about 17 percent of the site is covered in water now, compared with about 2 percent of the surrounding tundra.
Scott Pruitt and a crew of EPA aides just spent four days in Morocco promoting natural gas - Environmental Protection Agency Administrator Scott Pruitt returned Wednesday from a trip to Morocco, where he talked with officials about their interest in importing natural gas as well as other areas of “continued cooperation” between the two countries. The EPA disclosed the trip late Tuesday, issuing a media release that included photos and a statement from Pruitt saying that the visit “allowed us to directly convey our priorities and best practices with Moroccan leaders.” “We are committed to working closely with countries like Morocco to enhance environmental stewardship around the world,” Pruitt said. The purpose of the trip sparked questions from environmental groups, Democratic lawmakers and some industry experts, who noted that EPA plays no formal role in overseeing natural gas exports. Such activities are overseen primarily by the Energy Department and Federal Energy Regulatory Commission. Pruitt took along seven aides and an undisclosed number of staff from his protective detail. The group included four political aides, including Samantha Dravis, associate administrator of the Office of Policy, and senior advisers Sarah Greenwalt and Lincoln Ferguson, as well as one career official, Jane Nishida, principal deputy assistant administrator of the Office of International and Tribal Affairs. Pruitt’s head of security determines how many advance staffers travel on any given trip, EPA officials said, and in this instance it was two. At the request of Senate Democrats, the EPA inspector general is looking into Pruitt’s use of military and private flights, as well as his frequent visits to his home state of Oklahoma during his first few months on the job. “It seems strange that Administrator Pruitt would prioritize a trip to Morocco to discuss natural gas exports while there is no shortage of more pressing issues here in the U.S. that actually fall within the jurisdiction of the agency he leads,” said Sen. Thomas R. Carper (Del.), the top Democrat on the Senate Environment and Public Works Committee. “I presume Mr. Pruitt is aware his agency’s inspector general is conducting an investigation into his questionable travel, which makes his decision to take this trip an odd choice at best.” Sierra Club Executive Director Michael Brune said in a statement that Pruitt “acts like he is a globe-trotting salesman for the fossil fuel industry who can make taxpayers foot the bill.”
Rise of electric vehicles threatens oil industry -- Refiners and oil executives are beginning to look at the threat that electric cars pose to the future of diesel and gasoline as the vehicles gain staying power. The issue is being raised more as China and Europe announce they will phase out liquid fuels and shift vehicle fleets to all-electric cars, trucks, and buses. In addition, companies are pledging to begin producing more electric cars. Volkswagen, the largest global automaker by sales, announced that it will sell an electric version of all 300 of its car models by 2030. Some oil CEOs say the issue is not getting enough attention, but it should. “Seventy percent of oil consumption is as a transportation fuel. So, if you move those numbers in the long-term it can cause titanic shifts,” said Dan Eberhart, an oil executive who owns Canary, one of the largest oil drilling wellhead manufacturers in the country. Eberhart believes that most news outlets miss the significance of the electric car on refiners and oil producers. They “bifurcate the electric car story and they relate it to the automobile companies, and 10 minutes later they talk about oil prices,” he explained. “But they never connect the two.” The issue is gaining the attention of the refinery industry, which is starting to examine the impact in their long-term planning scenarios. The refiners aren’t being “squeezed” by electric vehicles, yet, according to Stephen Brown, vice president for federal affairs at the large independent refiner Andeavor, formerly Tesoro. “But [we] need to look 15-25-30 years down the road and to work with market forces rather than government mandates supported by subsidies, which is all that EVs have going for them right now.”
US House panel passes bill repealing oil, gas transparency law - The House Committee on Financial Services passed a bill Wednesday that would permanently repeal a federal rule requiring US-traded oil and natural gas companies to disclose payments to foreign governments. If ultimately approved by the House and Senate and signed into law by President Trump, the bill would prevent the anti-corruption transparency rule mandated in 2010's Dodd-Frank Wall Street Reform and Consumer Protection Act from taking effect. The bill, HR 4519, was introduced in the House by Michigan Representative Bill Huizenga, a Republican, on December 1. The 114-word bill, which has no co-sponsors, simply repeals section 1504 of the Dodd-Frank law. Section 1504 requires all companies traded on US exchanges and involved in the commercial development of oil, gas or minerals to disclose payments made to any government and file annual reports with the Securities and Exchange Commission. The law was opposed by the American Petroleum Institute, the oil and gas industry's leading trade group, which sued the SEC in a case that ultimately led the US District Court for the District of Columbia to vacate an earlier payment-transparency rule finalized by the agency in 2012. In February, after Senate and House approval, Trump signed a resolution which repealed the transparency rule as finalized by the SEC in 2016, but it did not change the underlying law within Dodd-Frank. Transparency advocates had hoped the SEC would be able to draft another transparency rule to meet the law. In a statement Wednesday, Senator Ben Cardin, Democrat-Maryland, and former Senator Richard Lugar, Republican-Indiana, urged House leaders to reject the bill repealing the transparency law. Cardin and Lugar co-authored the provision in the original Dodd-Frank bill. "Who benefits from keeping the public in the dark?" Cardin and Lugar asked. "Secrecy breeds corruption."
Investors pour cash into U.S. shale despite questions on returns (Reuters) - Financiers keep pouring cash into the shale oil sector, providing producers with a path to keep U.S. output rising through the middle of the next decade. The United States is on track to deliver up to 80 percent of the world’s oil production gains through 2025, the International Energy Agency estimates, increases fueled in part by easy access to capital. Rising U.S. production is undermining OPEC’s attempts to curb global supply and boost prices, forcing the oil cartel to continue restraining output through the end of 2018. Hedge funds and private equity firms have given producers a range of new and traditional financial levers they can pull as needed to keep shale rigs drilling, according to interviews with more than a dozen financiers, advisers and executives. The money continues to flow despite rising pressure from some investors for drillers to prioritize better profit margins over expanded production. Producers holding land in prime fields with oil trapped in shale rock are having little trouble financing their fracking projects. “If you’ve got the rocks, you can get the money,” The IEA predicts U.S. shale oil output, now about 6.17 million barrels per day (bpd), will rise another 8 million bpd by 2025. That would turn the world’s largest oil-consuming nation into a net exporter of oil. The United States already is a net exporter of natural gas. Through the third quarter of this year, private equity firms have put $20.26 billion into energy-related deals, 36 percent more than all of last year, according to financial data provider Preqin. Initial stock offerings for U.S.-listed oil and gas firms raised $2.93 billion this year, up from $1.52 billion in 2016, according to Thomson Reuters data. Another way to finance drilling - production hedging, or contracts producers use to lock in prices on future output - also is on the rise this year. Hedging acts as insurance against price drops, letting producers drill with more certainty they can earn a profit. Forty midsize producers tracked by researcher PetroNerds LLC hedged 45 percent of their production in the third quarter, up from 36.5 percent a year earlier. Those same companies boosted capital spending by nearly two-thirds this year.
Global oil field spending set to rise by $25 billion in 2018, led by U.S., survey says - Houston Chronicle: The oil industry's capital expenditures – the lifeblood of the oil field service companies that employ thousands of people in Houston and across Texas – will increase by 15 percent in the United States next year, compared with an increase of 49 percent last year, according to a survey of more than 300 companies by investment bank Evercore ISI. That means the U.S. oil industry's capital expenditures will climb by $13.3 billion next year, vaulting above $100 billion from this year's haul of $87.7 billion. And that forecast may have to be revised if oil prices rise further. "2018 could be the first in several years that commodity prices surprise to the upside," Evercore ISI analysts said. Almost two thirds of the oil companies in the investment bank's survey said they were not increasing their budgets to account for service cost inflation. International oil field spending will rise by 4 percent to $268.5 billion, an improvement over this year's 6 percent drop to $258.2 billion. Canadian oil producers could boost investments 9 percent next year to $16.1 billion, compared with a 36-percent boost to $14.8 billion in 2017. All told, global oil field spending could rise 7 percent, or $24.8 billion, next year, to $385.5 billion. That's higher than this year's 4 percent growth, but still 50 percent below the 2014 peak in the oil industry's spending. Global oil field spending fell 33 percent in 2016, the worst year of the oil-market collapse.
The 'Unknown Unknowns' That Threaten U.S. Shale -- Three years after the oil price crash, the U.S. shale patch is on its second growth phase and is expected to continue to increase its production, at least through the next five years. The global oil markets have become increasingly dependent on U.S. tight oil supply - andthe oil industry is still coming to grips with this new reality, Simon Flowers, Chairman and Chief Analyst at Wood Mackenzie, wrote in a recent article.Current projections put the Permian on the forefront of the United States’ ability to deliver increased tight oil supply to the global markets. However, forecasts for the shale patch are as dynamic as production and drilling rates are. And some ‘known unknowns’ have been surfacing such as higher gas-to-oil ratios in some wells, and the parent/child wells issue, Flowers says.Wood Mackenzie said last month that signs had started to show that intensified drilling in the Permian doesn’t deliver commensurate volumes of oil. Although WoodMac thinks that such setbacks could just be growing pains and Permian drillers could indeed ‘change the laws of physics’, it had warned three months ago that drillers might soon start to test the region’s geological limits. If exploration and production companies can’t overcome the geological constraints with tech breakthroughs, Permian production could peak in 2021, putting more than 1.5 million bpd of future production in question and potentially significantly influencing oil prices, WoodMac said in September.In his December article, WoodMac’s Flowers included this observation in the Permian’s ‘known unknowns’:“Growth might also be constrained by shareholders demanding that independents rein back from volume-driven targets.” Those ‘known unknowns’ serve as a warning: the oil market can’t be complacent and just assume that the Permian boom will deliver as expected, according to Flowers. The Wolfcamp may be the star of the Permian, WoodMac says, but “there are more than likely ‘unknown unknowns’ out there too. And if there are, there’s not another Permian ready to step in; and conventional options will take time to crank into action.” The Eagle Ford and the Bakken combined represent nearly half of the current U.S. tight oil production, according to Wood Mackenzie, which is expressing new doubts that those two plays could offer long-term commercial drilling inventory as operators move out beyond the sweet spots. Therefore, the analysts downgraded the growth rates for both plays from the mid-2020s, but have significantly upgraded the Permian growth pace, especially for the Wolfcamp basin.
Will Oil Producers Do As They Say Or Do As They Sell in 2018 -- North America's oil producers have adopted a meek tone of late. But the numbers suggest they're locked and loaded heading into 2018.Bloomberg New Energy Finance on Wednesday released an extensive new database (available only to Bloomberg Terminal clients), compiled by Peter Pulikkan, Bert Gilbert, Daniel McLaughlin and Jacob Fericy, detailing the hedging strategies of 53 U.S. and Canadian exploration and production companies. One thing that leaps out from all the data is just how much of next year's oil and gas production has apparently been locked in already by E&P firms -- with one important caveat. As I detailed here in April, producers often use hedges (such as selling futures) to lock in prices on expected output; managing their market risk and providing a modicum of certainty on cash flows for management, shareholders and lenders. Hedging is, along with the bond and equity markets, a financial mechanism to keep the shale machine running. And, as BNEF's database shows, E&P firms have been cranking that mechanism at a furious pace of late: In the third quarter, E&P firms locked in hedges on a lot more expected production for 2018, including an extra million barrels a day for the first half That surge in hedging in the third quarter was no accident, as 2018 swaps prices for Nymex West Texas Intermediate rallied strongly from June's trough: Oil swaps for 2018 rallied in the third quarter, providing an opportunity to lock in higher prices on future production Oil rallied on a combination of OPEC supply cuts finally coming through and a growing conviction they would be extended (which turned out to be right), along with some geopolitical spice.There is some irony in this. When OPEC, Russia and some other producers originally agreed to cut supplies a year ago, they touched off a rally in oil prices -- and hedging by E&P firms, adding fuel to a recovery in U.S. oil output. OPEC's supply cuts provided fuel for the recovery in U.S. oil output.
- Average Brent crude oil spot prices climbed by $5 per barrel last month, rising from October’s average of $58 to $63 per barrel in November. Our forecast, however, expects that average to retreat in 2018 to an annual average of $57 per barrel.
- U.S. crude oil production increased in November, up roughly 400,000 barrels per day from October’s production levels. EIA attributes a large share of that increase to production in the Gulf of Mexico, which has recovered from the effects of Hurricane Nate. An additional increase of 100,000 barrels per day in December is forecast to put production at 9.77 million barrels per day for the month.
- For 2017, EIA estimates U.S. crude oil production to average 9.2 million barrels per day. The forecast going into 2018 expects to see production increase to 10.0 million barrels per day, which would become the highest average annual production rate of crude oil in U.S. history.
- EIA expects December’s U.S. regular gasoline retail price to average $2.59 per gallon, roughly 34 cents above the average in December 2016, with the increase mostly reflecting higher crude oil prices this year.
- EIA’s last short-term forecast of 2017 projects that U.S. regular retail gasoline prices will average $2.51 per gallon in 2018.
- EIA forecasts U.S. dry natural gas production to average 73.5 billion cubic feet per day in 2017, and EIA models suggest that dry natural gas production levels will approach 80 billion cubic feet per day in 2018.
- Growing production in the Marcellus and Utica shale regions is a large driver of this increase.
- Natural gas and coal’s shares of utility-scale electricity generation are expected to remain relatively unchanged through 2018. Both natural gas and coal are forecast to hover near 32% and 31%, respectively, in 2018.
- EIA forecasts that decreased exports and marginal growth in coal consumption will lower coal production to 771 million short tons in 2018, down about 20 million short tons from the expected 2017 production level of 791 million short tons. Renewables:
- Renewables, not including hydroelectric generation, should gain two percentage points in their share of utility-scale generation from about 8% in 2016 to 10% in 2018. A significant part of that projected increase is tied to the forecasted growth in wind generating capacity during 2018.
Fracking drives US oil exports to record high - NZ Herald: The world's largest oil consumer exported more hydrocarbons than ever before in 2017 and shows no signs of slowing down.You name it - crude oil, gasoline, diesel, propane and even liquefied natural gas - all were shipped abroad by the US at a record pace.While the surge comes many years after the shale boom started, it can be traced straight back to the growth of horizontal drilling and fracking.US exports are poised to expand even further, as the fear of peak oil supply has all but vanished just as a new demand threat emerges in the form of electric vehicles. Americans are expected to end the year pumping oil out of the ground at rates unseen since the early 1970s. More and more of it is going overseas, giving OPEC a headache as the group restrains its own output. Last year the US tested the export waters after a nearly four-decade-old ban was removed. But this year, purchases of US light, sweet crude have skyrocketed as pipeline and dock infrastructure was built out and the wider price spread between Brent and West Texas Intermediate crude coaxed more cargoes abroad. Canada, once the only regular buyer of US crude, finds itself competing with refiners in Europe and Asia. China's appetite for American oil is voracious: in April, China bought more than Canada did for the first time. Of all the emerging trade flows this year, crude deliveries into Europe and Asia are most surprising, according to Smith. And if the price of European oil stays suspended into the New Year - a good possibility after the Forties oil pipeline was shut this week to repair a crack - US exports will continue hold above 1 million barrels a day.
US fuels the world as shale boom powers record oil exports - Crain's Cleveland Business --Americans are expected to end the year pumping oil out of the ground at rates unseen since the early 1970s. More and more of it is going overseas, giving OPEC a headache as the group restrains its own output.Last year the U.S. tested the export waters after a nearly four-decade-old ban was removed. But this year, purchases of U.S. light, sweet crude have skyrocketed as pipeline and dock infrastructure was built out and the wider price spread between Brent and West Texas Intermediate crude coaxed more cargoes abroad.Canada, once the only regular buyer of U.S. crude, finds itself competing with refiners in Europe and Asia. China's appetite for American oil is voracious: in April, China bought more than Canada did for the first time."It's pretty amazing, really," said Matt Smith, ClipperData LLC's director of commodity research. "You learn to never say never in this market."Of all the emerging trade flows this year, crude deliveries into Europe and Asia are most surprising, according to Smith. And if the price of European oil stays suspended into the New Year — a good possibility after the Forties oil pipeline was shut this week to repair a crack — U.S. exports will continue hold above 1 million barrels a day. "The U.S. has fully integrated itself into the global market," Smith said by phone. "You have U.S. crude going into Europe, and European crude heading elsewhere because the U.S. is selling crude into its own backyard."
Huge WTI-Brent Spread Boosts U.S. Crude Exports - CNBC published an article late last week based on our ClipperData, highlighting how deliveries of U.S. crude grades into China climbed to a record in November. As U.S. crude and product export markets evolve, new patterns in loadings, destinations, grades and purchasing present themselves in our granular data.As the chart below illustrates, U.S. crude has arrived at ten different Chinese ports so far this year, with the most heading to the northern port of Qingdao - home to the majority of Chinese independent refiners. The port has discharged a variety of different U.S. grades, including Bakken, Mars, Midland WTI, Southern Green Canyon and Thunderhorse. Total receipts of U.S. crude into China last month climbed to just shy of 300,000 bpd:As the Brent/WTI spread widened out post-Hurricane Harvey in September, an increasingly discounted price for domestic crude has encouraged more barrels to leave the country. October's export loadings correspondingly climbed to a record of 1.4 million barrels per day. Not only have more barrels headed to Asia, but also to Europe. U.S. crude export loadings bound for Europe jumped to nearly 600,000 bpd in October. Eight European countries have received U.S. crude this year. While the U.K. is the leading European recipient in terms of volume this year (with crude predominantly heading to Exxon's Fawley refinery and Valero's Pembroke refinery), Poland has been the latest addition to the list, with four cargoes heading in its direction in recent months. The export boom is not limited to crude. We discussed recently how U.S. product exports of gasoline, diesel and LPG have been booming, while this Bloomberg article includes our observation that U.S. LNG exports to the Middle East are like selling ice to the Eskimos. Nearly thirty countries have already received U.S. LNG since Cheniere Energy's Sabine Pass export terminal started early last year, and export destinations are only likely to grow with the imminent start of exports from Dominion Energy's Cove Point terminal.
Top Oil Buyers Seek Chemistry in Love Affair With U.S. crude - Asian refiners are discovering that the quality of cargoes varies, leading to fluctuations in the type of fuels they can produce. The shale boom and the end of a U.S. oil-export ban have proven a boon to buyers from China to India as traditional suppliers such as Saudi Arabia cut output to clear a glut. And while shipments from the Gulf Coast have soared, refiners are shifting their focus to crudes with consistent characteristics. That’s because varieties such as Eagle Ford are a blend of shale oils pumped from wells in south Texas spanning an area about 65 times the size of New York City. Crude from the Middle East, Africa as well as the U.S. Gulf of Mexico come from a small cluster of fields with more stable chemical specifications. Buyers are now turning to conventional American grades such as Mars and Poseidon, or favoring shale supply piped from specific assets. “The flow of U.S. oil to Asia is here to stay, but Asian importers are learning that not all grades are equally desirable,” says Tushar Tarun Bansal, a consultant from McKinsey Energy Insights. “Buyers are wary of grades such as Eagle Ford and can’t take much more of it.” Three Asian refiners that purchased and refined Eagle Ford shale oil don’t plan to buy significant volumes of the grade due to concerns over the consistency of its quality, according to a Bloomberg survey of officials at the companies. Two of the three respondents said their cargoes -- each between 500,000 and 1 million barrels in size -- yielded more light distillates such as liquid petroleum gas and naphtha than they expected. Companies typically select a mix of different crudes to process, choosing grades based on chemical characteristics that will yield higher volumes of the fuels that are most in demand. When the oil specifications are inconsistent, plants may pump out less of the products that the refiners want and more of what they don’t require at the time.
Upside Down - Condensate Production Decline Hits Splitters And Neat Conde Exports -- The sharp decline in U.S. condensate production since early 2015 and the end to the ban on U.S. crude oil exports a few months later were a one-two punch for the companies that made throughput commitments to condensate splitters and made other conde-related infrastructure investments. In what seemed like a flash, conde supply plummeted and the steep price discount to WTI and other light crude that made conde so attractive for splitting and exporting was gone. Holders of splitter capacity were paying top-dollar for what conde they could corral, and operators were forced to run their brand-new facilities at far less than capacity. And, when the general ban on crude exports was lifted in December 2015, the special status that conde had enjoyed since exports of lightly processed conde were permitted in June 2014 was a thing of the past. Today, we continue our review of a conde world in upheaval, this time with a focus on splitters and exports. As we said in Part 1, superlight crude and conde sit side-by-side at the far end of the crude-oil spectrum. They’re both sweet (low-sulfur) and very pourable — superlight (using EIA’s API gravity breakdown, 50.1 to 55.0 degrees) is like iced tea, and conde (API gravity of 55.1 or more — also EIA’s breakdown) is like cream soda — and they can either be refined, exported, blended with heavier crudes, or (for conde) run through a splitter. A splitter uses atmospheric distillation to separate high-API-gravity conde into its component fractions to produce intermediate, semi-finished blend stocks like naphthas and distillates that are processed further at refineries. (More on splitters in a moment.)
Canada’s pipeline data is full of holes - Spill. Respond. Repeat. Without urgent improvements to Canada’s patchwork approach to collecting information about oil and gas pipeline spills, this approach will continue into the future.That’s the warning sent by a team of researchers who assessed records of pipeline failures from the National Energy Board (NEB). In their paper, the researchers show how the records kept by the NEB—charged with regulating pipelines that cross provincial boundaries—are woefully incomplete. Comprehensive pipeline failure data is vital because it provides the raw material for researchers, regulators, and companies to assess the risks of pipeline failures, Belvederesi says. The study comes in the wake of a number of contentious pipeline proposals in Canada. The most fractious of the projects underway are those that intend to move Alberta oil sands output to the British Columbia coast—such as Kinder Morgan’s Trans Mountain expansion—or to US refineries, which is the plan with Keystone XL.The researchers say the problem with how the NEB documents pipeline failures lies in its piecemeal approach. The NEB monitors just nine percent of the oil and gas pipeline system in Canada—only the pipelines that cross provincial boundaries. The remaining 91 percent is the responsibility of individual provinces. Then there is the quality of the NEB data. A 2015 pipeline failure near Fort McKay, Alberta, for example, was severe enough to be considered an “adverse” incident, but NEB records do not state how much pollutant was released, or what effect the accident had on the environment. Such omissions can affect the prediction of and response to future spills, says Belvederesi, particularly on the same pipeline. If a past failure is well-understood, she says, steps can be taken to prioritize site maintenance and have equipment and plans ready for timely emergency responses in areas prone to problems.
Mexico Says Deepwater Oil Tender Doomed By Brazil Competition | Rigzone: (Reuters) - Mexican national oil company Pemex on Friday blamed the cancellation of a potentially lucrative deepwater Gulf of Mexico project on weak investor appetite due to competition from recent auctions in Brazil and low oil prices.The country's oil regulator on Thursday canceled a tender for its Nobilis-Maximino project, a joint venture with Pemex , as company interest was not as robust as initially expected.On Friday, Pemex, known officially as Petroleos Mexicanos, cited a late October deepwater oil auction in Brazil for lessening interest in its project. Six of eight blocks in Brazil were awarded to majors, including Royal Dutch Shell and ExxonMobil."(One) factor that affected appetite for new projects was the investment commitment recently taken on by possible bidders," Pemex said in a statement. Companies that won blocks in Brazil had looked at the Nobilis-Maximino data, it added.Nearly 30 oil companies had begun the process of pre-qualifying for the Mexican auction, according to data from the National Hydrocarbon Commission, including U.S.-based Chevron and Britain's BP.The failure of the project is a setback for Mexico's energy opening after a decades-long monopoly for Pemex.Nobilis-Maximino sits in Mexico's deepwater Gulf near the U.S.-Mexico maritime border in the productive Perdido Fold Belt, and is estimated to contain reserves of about 502 million barrels of mostly light crude.Nobilis-Maximino was due to be awarded on Jan. 31, along with another 29 similar deepwater projects. Those tenders, which are still going ahead, are potentially more attractive because companies can bid to develop them without tying up with Pemex. Pemex said weak oil prices - with medium- and long-term oil price projections at $50-$65 per barrel - have also been a factor in oil companies exercising caution about taking on complicated, expensive deepwater projects like Nobilis-Maximino. Pemex said it would consider a future farm-out, or joint venture, for the project.
Oil Producers Turning To Crypto To Solve Sanctions Problems -- Last week, Venezuela announced it would develop a national cryptocurrency backed by its oil reserves, the Petro. Now there is a report that Russia is considering the same thing. Iran will likely follow suit. As of right now this is just a rumor, but it makes some sense. So, let’s treat this rumor as fact for the sake of argument and see where it leads us. The U.S. continues to sanction and threaten all of these countries for daring to challenge the global status quo. There is no denying this. And so much of what we see in the geopolitical headlines are knock-on effects of this challenge. From the Middle East to North Korea, the Dutch changing their laws to block Nordstream 2 to the Saudis breaking off relations with Qatar, everything you read about in the news is a move on the geopolitical “Go” board. Because at the heart of this is the petrodollar. Contrary to what many believe, the petrodollar is not the source of the U.S. dollar’s power around the world, but rather the U.S.’s main fulcrum by which to keep competition out of the markets. It is a secondary effect of the dollar’s dominance in global finance today. But it is not the main driver. Financial market are simply too big relative to the size any one commodity market for it to be the fulcrum on which everything hinges. It was that way in the past. But it is not now. That said, however, getting out from underneath the petrodollar gives a country independence to begin building financial architecture that can be levered up over time to threaten the institutional control it helped create. U.S. foreign policy defends the petrodollar along with other systems in place – the IMF, the World Bank, SWIFT, LIBOR and the central banks themselves – to maintain its control. The main oil producers, however, can escape this control simply by selling their oil in currencies other than the U.S. dollar. That’s not enough to dethrone the dollar, but, like I just said, it is where the process has to start. Therefore, any and all means must be employed to defend the dollar empire by keeping everyone inside that system.
UK Heating Gas Prices Spike To 2013 Highs Amid Weather "Yellow Warning" -- The U.K.’s Met Office issued a ‘yellow’ warning after dumps of snow over the weekend disrupted travel, sending the price of same-day heating gas prices to their highest since 2013...The average temperature in the U.K. for the rest of Monday will be 1 degree Celsius (34 Fahrenheit), compared with a 10-year average of 5.2 Celsius, according to Bloomberg’s weather model. Bloomberg also notes that supplies in the system could plunge 11 percent by the end of the day, according to network manager National Grid Plc. Supplies from the Bacton terminal in Norfolk are below the 10-day average after Total SA said exports from the Elgin Franklin field that feed it have been reduced by about 60 percent from normal levels, potentially until Wednesday evening. Flows into the St. Fergus terminal in Scotland also plunged. Storage supply picked up some of the slack, rising to the highest since Dec. 1. “Whilst the weather-related heating demand was expected, the reduction in flows via a number of terminals was not,” Nick Campbell, an energy risk manager at Inspired Energy Plc, said by email.“Therefore this has left the system tight and battling to pull in more gas from the continent.”
Major Forties oil pipeline to be closed for repairs - BBC News: One of the UK's most important oil pipelines is being closed after a crack was discovered in Aberdeenshire. The Forties pipeline carries crude North Sea oil across land for processing at Grangemouth. The crack was discovered last week at Red Moss near Netherley. The pipeline's owner Ineos said on Monday that, despite pressure being reduced, the crack had extended. The Forties pipeline carries about 40% of North Sea crude oil. More than 80 platforms will have to suspend production. The price of Brent crude rose about 2% to $64.69 a barrel amid surprise that the pipeline could be shut for about three weeks - far longer than expected. Ineos said there would be a big impact on the industry but not on consumers.Ineos said in a statement: "Last week during a routine inspection Ineos contractors discovered a small hairline crack in the pipe at Red Moss near Netherley. "A repair and oil spill response team was mobilised on Wednesday, after a very small amount of oil seepage was reported. "Measures to contain the seepage were put in place, no oil has been detected entering the environment and the pipe has been continuously monitored." The company added: "A 300m cordon was set-up and a small number of local residents were placed in temporary accommodation as precautionary measure. The pipeline pressure was reduced while a full assessment of the situation was made. "The incident management team has now decided that a controlled shutdown of the pipeline is the safest way to proceed." Ineos said the shutdown would "allow for a suitable repair method to be worked up based on the latest inspection data, while reducing the risk of injury to staff and the environment".
Britain's biggest oil pipeline shut 'for weeks' for repairs (Reuters) - Britain’s largest oil pipeline could shut down for weeks for unscheduled repair work, sending the price of crude to new two-year highs and triggering a steep rally in natural gas prices, just as a cold snap sweeps the country. The Forties Pipeline System, which carries around 450,000 barrels per day of Forties crude from the North Sea to the Kinneil processing terminal in Scotland, had been operating at reduced capacity since December 7 when a routine inspection revealed a small leak. Ineos, a privately owned Anglo-Swiss chemicals company, owns the pipeline and said it had taken the decision to close the system completely. Oil traders estimated this was the first total closure since 2011, when then-operator BP shut it down while a suspected World War II bomb was removed from the seabed. “It’s early days and it is premature to give a time frame for the repair work. We can’t give a precise estimate other than to say it is a matter of weeks, rather than days,” an Ineos spokesman said. Ineos bought the Forties Pipeline System (FPS) from BP less than two months ago for $250 million. The pipeline, which handles nearly a quarter of total North Sea crude output, is also a major route for bringing natural gas to Britain that has been produced offshore. Britain is in the grip of a cold front that has brought heavy snowfall and prompted the closure of schools and disrupted travel across the country. Ineos, which also owns the 200,000-barrel per day Grangemouth refinery in Scotland, said the plant would have to seek “alternative supplies of crude”, but that there was enough oil currently in storage at Grangemouth for the company to “manage the situation.” Fiona Legate, a senior analyst for the North Sea oil industry at consultant Wood Mackenzie, said even a temporary shutdown of the pipeline would have wide-reaching implications for the UK oil and gas industry. “FPS transports liquids from over 80 fields, including the two largest producers in the UK - Buzzard and Forties,” she said. “The bulk of throughput from FPS comes from 10 fields ... In 2017, FPS transported more than 40 percent of liquids in the UK Continental Shelf.”
Oil, Gas Firms Could Lose Millions Due to Forties Pipeline Shutdown | Rigzone: Independent oil and gas firms EnQuest plc and Premier Oil plc could lose millions of dollars in the event of a prolonged shut down of the Forties Pipeline System, oil and gas analysts at GMP FirstEnergy have confirmed.The analysts highlighted that EnQuest’s operated Greater Kittiwake Area and Scolty/Crathes development, along with Premier Oil’s operated Balmoral area, non-operated Elgin-Franklin asset and other minor fields, would be impacted as a result of a shut down of Britain’s largest oil pipeline.GMP analysts have stated that every month of shut down would reduce the energy investment banking firm’s expected cashflow forecast for EnQuest and Premier Oil by around $7 million and between $10-12 million, respectively.The shut down of the pipeline system would also be felt by a number of other companies, as highlighted by oil and gas analysts at investment banking firm Jefferies. These analysts estimate that thousands of barrels of output from BP plc, Total SA, Chevron Corporation, ExxonMobil, Eni and ConocoPhillips will be affected.“Forties is one of the four components of the Brent pricing system, and if the duration of the outage is for several weeks it should put upward pressure on the Brent price,” Jefferies analysts said in a statement sent to Rigzone.Ineos confirmed Monday that it has decided to implement a controlled shut down of the Forties Pipeline system after a hairline crack was found in the pipe at Red Moss near Netherley, south of Aberdeen.
Ineos begins Grangemouth shutdown after Forties outage: sources (Reuters) - Ineos has begun shutting units at its Grangemouth oil refinery in Scotland due to the unplanned outage at its Forties North Sea crude pipeline, which threatens to choke the plant’s feedstock, industry sources said on Wednesday. The company is also considering bringing forward maintenance work at Grangemouth, originally scheduled for next year, to have it done while units are down, the sources said. The disruption to operations at Grangemouth follows the unexpected shut down of Ineos’s Forties pipeline early this week after a crack was found. The pipeline carries about 450,000 barrels per day (bpd) of Forties crude, roughly a quarter of the North Sea’s total output, and its closure for repairs sent global crude prices soaring to a two-year high. Trade sources said Ineos shut a 65,000 barrels per day crude distillation unit at the Grangemouth refinery on Wednesday and plans to shut another 110,000 bpd unit there early next week. Ineos said it was still considering repair options on the Forties pipeline and reiterated any repairs would take several weeks. “Ineos could keep the Grangemouth refinery running but at a fair cost,” one of the trading sources, familiar with the plant’s operations, said. Moving maintenance forward now appears the most likely option, but nothing has been decided. For one thing, it was unclear if maintenance crews were available on short notice, he said.
Analysis: Forties aftershock ripples through North Sea oil - Several oil cargoes may be deferred to January as the threat of force majeure hangs over the market after a crack shut down the Forties supply pipeline, trading sources said Wednesday. The key 600,000 b/d artery, which transports one of the key blends that make up the Dated Brent pricing benchmark, is likely to remain shut. Pipeline operator Ineos said it's considering a number of repair options. In response, crude buyers have started to look elsewhere for alternative medium-sour blends. With not many prompt oil barrels available, a scramble for cargoes has begun, said trading sources. Forties dominance of flows used to assess Dated Brent The shutdown pushed the physical Dated Brent benchmark to a two-and-a-half-year high of 65.165/b on Monday but prices have backtracked since then as demand for this grade has fallen. Platts Dated Brent was assessed at $64.69/b Tuesday, down $0.475/b from the previous day. The aging Forties pipeline has a capacity of over 600,000 b/d but throughput of the key grade has averaged around 450,000 b/d this year. Forties accounts for about 40% of UK North Sea crude and is one of the five blends that make up the Dated Brent pricing benchmark. Sources told S&P Global Platts that the last ship to load Forties crude from the Hound Point terminal since the pipeline shut will be the Front Jaguar. The vessel is currently at the main loading berth at Hound Point terminal. According to Platts trade flow software cFlow, the Front Jaguar is currently anchored and is expected to be fully loaded with oil by Thursday.
UK turns to Russian project targeted by sanctions for gas supply - British homes are set to be heated over the new year with gas from a Russian project targeted by US sanctions, as the shutdown of a key North Sea pipeline slashes domestic output and sends utilities and traders scrambling for supplies. The first tanker of liquefied natural gas from the Yamal LNG project in Russia’s Arctic, which was opened by President Vladimir Putin last week, is making its way to the Isle of Grain import terminal in Kent as UK gas prices soar. The shipment of the super-chilled cargo to the UK, which was originally expected to go to Asia, will be cheered in the Kremlin, where the Yamal LNG project has been held up as evidence that it can withstand western sanctions. Moscow has insisted that Europe will remain reliant on Russia for gas. The UK government has taken a tough line on Russian sanctions since Moscow first intervened in Ukraine nearly four years ago, and Theresa May, prime minister, has stepped up criticisms more recently, accusing Moscow of meddling in elections and attempting to “weaponise information” to undermine the west. Bringing in the tanker will highlight questions about the UK’s energy strategy and the security of supplies, as it follows the shutdown of a three-decade-old pipeline this week that has cut off 12 per cent of gas from the UK’s portion of the North Sea, sending prices to four-year highs and sparking fears of potential shortages.
What Goes Up Must Come Down: the Challenge of Rig Decommissioning --The cost of decommissioning is rising sharply, with experts predicting it will reach $13 billion a year globally by 2040. Inevitably, the final costs will vary from rig to rig – decommissioning operations in the North Sea are expected to require around 53 billion pounds in total; a huge sum in comparison to deepwater installations in the Mexican Gulf, which are expected to incur approximately $2.4 billion. However, even with less costly decommissioning projects, these are not inconsequential figures that companies can simply brush aside. The cheapest and most straightforward option – simply sinking the rigs – is not feasible. In 1995 when Shell proposed sinking the Brent Spar rig, the result was protests, boycotts, and a substantial fall in share price, ultimately resulting in the Ospar Treaty. Therefore, a range of alternative engineering solutions have been proposed – such as removing platforms in a ‘single lift’ swing, or dismantling the platform piecemeal and shipping in batches. Given the complexities of dismantling an oil rig, decommissioning is a challenging engineering problem with many factors needing to be considered. Yet, with around 600 rigs expected to be taken offline by 2021, it’s also one that oil companies need to get used to tackling. The challenge facing oil companies is to be able to accurately predict the costs for decommissioning these aging structures safely and in environmentally friendly, but cost effective ways.Predicting and addressing the environmental impacts of decommissioning is complex. There can often be competing interests and trade-offs to be considered and evaluated. For example, the most carbon-neutral option might not be the best from a health and safety (HSE) perspective. One example is the current debate within the environmental community about whether it’s best to clean and sink parts of the rig as part of a ‘rig to reef’ program, or, whether this is merely leaving behind waste that will cause unpredictable issues for centuries afterwards. The fact that this rig-to-reef issue is still unresolved – despite first being raised over 20 years ago as per the Brent Spar platform – demonstrates the difficulty of decommissioning.
Austrian Gas Hub Blast Hits Deliveries To South, Southeast -Operator (Reuters) - An explosion and fire at the Baumgarten gas hub has disrupted deliveries to Austria's southern and southeastern borders, operator Gas Connect Austria said on Tuesday.Its markets include Italy, Slovenia and Croatia."Transit through Austria towards the south and southeast is affected until further notice," the company said in a statement, adding that the site, a major regional transfer hub, had been shut down.Domestic deliveries can be provided for the foreseeable future, it said.
Austrian Explosion Rattles Europe’s Gas Market - Natural gas flows were set to recover in Europe after an explosion at an Austrian hub threatened supplies already pinched by a closed pipeline in the North Sea and a cold snap across the continent. Oil company OMV AG, which controls the Baumgarten gas hub, managed to divert international transit pipelines so that flows to Italy, Germany and Hungary can resume before midnight local time, according to an emailed statement. “We managed to technically isolate the affected area,” Stefan Wagenhofer, managing director of OMV unit Gas Connect Austria GmbH, told ORF television. This allows the company to divert international flows and “resume transit within hours.” Natural gas and power prices earlier jumped in Europe after the explosion, and Brent crude oil futures rose above $65 a barrel for the first time since June 2015, extending their premium over the U.S. benchmark. Britain, which is struggling to absorb the impact of a crack that shut down a key North Sea pipeline network, saw some of the biggest increases. A blast about 9 a.m. at the Baumgarten compressor station killed at least one person and injured at least 21 people, interrupting flows at one of the main points where Russian natural gas enters Europe. That followed two days of snow in London and cooler-than-normal temperatures spread from the Alps to Scandinavia, which is raising demand for heating fuels. “The European gas market seems to be going through a perfect storm,” Massimo Di-Odoardo, an analyst at Wood Mackenzie Ltd. in London, said by email. Britain lacks the gas storage sites and web of interconnections that make most continental European markets better able to cope with disruption. Reduced pipeline gas flows may increase competition with Asia for liquefied natural gas cargoes this winter, according to WoodMac. Front-month gas in Britain jumped as much as 23 percent to 73.7 pence a therm ($9.86 a million British thermal units) on ICE Futures Europe, the highest since December 2013. The comparable U.K. power contract rose as much as 15 percent, according to broker data compiled by Bloomberg. Same-day gas soared as much as 46 percent.
Italy declares state of emergency following deadly explosion at Austrian pipeline – DW - Gas has resumed flowing through an Austrian gas hub after an earlier explosion cut off supplies to several European countries. Italy has declared a state of emergency. A major European gas distribution hub resumed operations early Wednesday after an explosion knocked it offline, cutting off gas supplies to several countries. Gas Connect Austria said the flow of gas towards Italy, Germany and Hungary resumed from its hub at Baumgarten an der March after fire and police inspected the site. An explosion rocked the gas distribution center outside of Vienna Tuesday morning, prompting Italy to declare a state of emergency. One person died in the blast while a further 21 were injured, one seriously, according to officials. Austrian authorities said the explosion was triggered by a "technical cause," without providing further details. Located near Austria's eastern border with Slovakia, the Baumgarten gas hub carries about 10 percent of Europe gas supply from from Russia, Norway and other states. It handles some 40 billion cubic meters per year, redistributing it around Europe, including to Germany, France, Italy, Slovakia and Croatia. News of the explosion threw the European gas market into turmoil amid fears that supplies would be tightened during the winter months. Italy, the Baumgarten hub's biggest recipient, declared a state of emergency following the blast, with the country's industry minister warning that it was facing a "serious" energy supply problem. A state of emergency status allows the Italian government to carry out extraordinary measures to try to meet energy demands, such as allowing coal and oil power plants to fire at full blast. According to the Reuters news agency, the Italian wholesale day-ahead supply of natural gas rose 150 percent to €60 ($70) per megawatt-hour (MWh) — an all-time high.
The Arctic Threat to the Price of Oil - Russia has three oil export terminals on its Arctic coast. Shipments began from Lukoil PJSC's 240,000 barrel a day Varandey terminal in 2008. It now handles about 150,000 daily barrels from nearby fields. Gazprom Neft's Prirazlomnoye field produces approximately 80,000 barrels a day, with a target capacity of 130,000. The same company's 170,000 barrel a day Arctic Gate terminal started operations this year and exports about 150,000 barrels a day from the Novoportovskoye field. Crude from all three terminals is shipped in shuttle tankers to Murmansk, from where cargoes are sent on larger vessels to Europe. The terminals' exports hit a new high of almost 385,000 barrels a day in November. This is up by about 100,000 barrels a day from a maintenance-related summer dip. That's equivalent to a third of the output cut pledged by Russia in its deal with OPEC. Russia's adherence to that deal, just extended to the end of 2018, has been pretty good. Over the summer, it cut more than the promised 300,000 barrels a day from its October 2016 production level.But things have started to slip. Maintenance at Prirazlomnoye and at Exxon Mobil Corp's Sakhalin I project off the eastern coast helped lower Russian production between August and October. That's come to an end. Now those fields are back in full production, Russia's aggregate daily oil output has risen by about 50,000 barrels. Compliance with the OPEC deal is below where it was in May and things may get worse over winter. As well as gas, Novatek PJSC's new LNG project will produce about 26,000 barrels a day of condensate -- a very light form of crude. That's not a lot in the grand scheme of things, but this is just one field. As Russia's gas industry targets deeper, liquids-rich reservoirs, its condensate output rises. Gas production in Russia is highly seasonal, so condensate output is too. Cold weather boosts demand for Russian gas from domestic and foreign consumers and the swing in gas production from summer to winter can be as much as 40 percent of the annual average.
Russia Wins in Arctic After U.S. Fails to Kill Giant Gagas project … Building the $27 billion Yamal liquefied natural gas project meant shipping more than 5 million tons of materials to construct a forest of concrete and steel 600 kilometers north of the Arctic circle, where temperatures can drop to -50 degrees celsius and the sun disappears for two months straight. Yet those challenges weren’t as tough as the U.S. sanctions imposed in 2014, forcing a complete refinancing just as construction was about to start. Jacques de Boisseson, head of the Moscow office of French energy giant Total SA, which has a 20 percent stake in Yamal LNG, said there were "various moments" when he thought the project may never happen. "We were too much advanced to stop. We were in a deadlock: we had to go ahead and we didn’t know how," de Boisseson said. Three years later, the first shipment of Yamal LNG’s gas represents a gargantuan effort from the Russian establishment to demonstrate that one of President Vladimir Putin’s flagship projects would not be derailed by sanctions. The launch of the project in the face of sanctions has helped spur Moscow’s political pivot to China, which provided much of the financing. Novatek PJSC, which controls Yamal LNG, is already talking about its next LNG project. London Bound The first cargo is on board a tanker headed for a port near London, helping the U.K. to cope with cold winter weather and an unplanned shutdown of a clutch of its own North Sea fields. That the gas will end up in a European country that’s backed sanctions against Russia may please many in Moscow.
Russia Aims To Win 15-20% Of Global LNG Market - Novatek CEO (Reuters) - Russia's government has set a target of winning between 15 and 20 percent of the global market for liquefied natural gas (LNG), Leonid Mikhelson, the chief executive officer of Russian gas major Novatek, said on Tuesday.Novatek, Russia's biggest private gas producer, meanwhile plans to maintain its own domestic market share, Mikhelson told investors.
Russia May Turn To Oil-Backed Cryptocurrency To Challenge Sanctions & The Petrodollar - The gradual acceptance of digital currencies, with major exchanges about to launch bitcoin futures trading, may prompt some oil producing nations to ditch the US dollar in crude trade in favor of cryptocurrencies, an oil analyst says. As RT reports, Russia, Iran and Venezuela have more than one thing in common.All three are major oil producing nations dependent on the dollar since the global crude market is traditionally dominated by contracts denominated in US currency. Moscow, Tehran and Caracas are also facing US sanctions; penalties which are proving effective since the sanctioned countries are dependent on the US dollar to sell their crude. A decentralized currency – allowing anonymous transactions along with blockchain technology support to facilitate oil contracts – may be the ideal tool to allow the oil producing trio to turn their back on the greenback.“The advent of cryptocurrencies, therefore, represents a fresh catalyst for commodity-producing countries wishing to abandon the dollar as a means of payment for oil,” said Stephen Brennock, oil analyst at PVM Oil Associates, in a research note seen by CNBC. Several oil producers have already voiced plans to ditch the dollar in oil trading.
Japan LNG buyers pay $9/MMBtu for spot contracts in Nov, up 10% on month: METI - Japanese buyers paid an average of $9.0/MMBtu for LNG spot cargoes that were contracted in November, up 9.8% from $8.20/MMBtu in October, as the country enters the winter heating season, Ministry of Economy, Trade and Industry data showed Monday. Japan's average contracted price for LNG spot cargoes has been rising since July. The delivery months for those contracts were, however, not disclosed. S&P Global Platts JKM averaged $9.608/MMBtu in November, reflecting deals for December and January deliveries. METI also released the average price of cargoes delivered into Japan in November, which came in at $7.10/MMBtu, rising 16.4% from $6.10/MMBtu in October. Platts JKM for cargoes delivered in November, assessed from September 18 through October 13, averaged at $8.27/MMBtu. The November JKM steadily rose throughout the assessment period on the back of demand from end-users in Northeast Asia, who were stocking up ahead of winter. Demand from India also emerged via tenders, providing support to the market.
World Bank to stop financing upstream oil, gas after 2019 - The World Bank Group Tuesday said it will stop financing upstream oil and gas after 2019, as part of a wider commitment to global efforts to halt climate change. "As a global multilateral development institution, the World Bank Group is continuing to transform its own operations in recognition of a rapidly changing world," the bank said Tuesday in a statement. "The World Bank Group will no longer finance upstream oil and gas, after 2019," it said. However, in exceptional circumstances, the bank will consider financing upstream natural gas in the poorest countries where there is a clear benefit in terms of energy access for the poor, and if the project fits within the country's commitments under the Paris Agreement, the multilateral lender said. The World Bank Group made the announcement at the One Planet summit in Paris, which it convened along with President Emmanuel Macron of France and United Nations Secretary General Antonio Guterres. Of the bank's total lending of $22.6 billion in fiscal 2017, $4.4 billion went to energy and extractive industries, according to its 2017 annual report. The World Bank Group also said it is on track to meet its target of 28% of its lending going to climate action by 2020 and to meeting the goals of its Climate Change Action Plan, which it developed following the 2015 Paris Agreement on climate change. "In line with countries submitting updated and potentially more ambitious Nationally Determined Contributions, the World Bank Group will present a stock-take of its Climate Change Action Plan and announce new commitments and targets beyond 2020 at COP24 in Poland in 2018," it said. In addition, starting in 2018, the bank will report the greenhouse gas emissions from the investment projects it finances in key emissions-producing sectors, such as energy. The results will be published annually starting late 2018, it said.
China Short of Natural Gas as it Pushes Away Polluting Coal - — Severe natural gas shortages are hitting businesses and residents across China’s industrial heartland as an unprecedented government effort to clean up an environment devastated by decades of unbridled growth backfires. Factories are closing or operating at reduced capacity, business profits are shrinking as supply chains are disrupted, and people are shivering through subzero temperatures without adequate heating at home, according to interviews conducted across the region last week. The gas shortages, which have sent prices soaring nationwide, have undermined a sweeping campaign to switch millions of households and thousands of businesses from coal to natural gas in north China this winter, part of long-running efforts to clean the region’s toxic air. Much of the gasification of the region, involving more than 4 million homes, was rapidly launched by local authorities acting on their own initiatives in response to calls by the central government to control air pollution. But the plan appears to have been overly ambitious. Despite the installation of gas lines and boilers for factories and homes across the northeast, supply has been hampered by insufficient infrastructure to bring the fuel to the industrial region and store it, according to Liang Jin, an independent analyst previously with the oil and gas consultancy JLC. And in some areas, many homes have yet to get the gas boilers needed for heating. The gas plan was also implemented as China tries this winter to reduce production from polluting industries like steel and cut back on the use of diesel trucks. That has raised concerns about whether the anti-pollution campaigns may hit economic growth.
Exclusive: China's CNPC weighs taking over Iran project if Total leaves - sources (Reuters) - China’s top oil and gas company CNPC is considering taking over Total’s (TOTF.PA) stake in a giant Iranian gas project if the French company leaves Iran to comply with any new U.S. sanctions, industry sources said. Total signed the $1 billion deal to develop the South Pars gas field in July. The contract gave CNPC the option to take over Total’s stake if it pulled out, according to sources involved in the talks. The deal was the first major Western energy investment in the Islamic Republic since international sanctions, including most of those imposed by the United States, were lifted as part of a landmark agreement in 2015 over Iran’s nuclear program. But after U.S. President Donald Trump refused in October to certify that Tehran is complying with the deal, Congress will have to vote on whether to reimpose sanctions on Iran. It was unclear when a vote would take place or what sanctions might be imposed, but they could bar companies working in Iran from also operating in the United States. Total has much larger operations in the United States and Chief Executive Patrick Pouyanne said it would leave if it were no longer able to operate in Iran. Under the terms of the agreement to develop phase 11 of South Pars, the world’s largest gas field, CNPC could take over Total’s 50.1 percent stake and become operator of the project if Total is forced to withdraw from Iran, a senior Beijing-based source with knowledge of the joint-venture agreement said. CNPC has a 30 percent stake, while the Iranian national oil company’s subsidiary PetroPars holds the remaining 19.9 percent. CNPC officials have held internal talks in recent weeks to discuss the implications of taking control, according to three industry sources briefed on the talks. Spokespeople for CNPC, Total and Iran’s National Oil Company (NIOC) declined to comment.
Saudi Arabia plans to maintain oil exports in Jan at 6.9 mln bpd -industry source (Reuters) - Saudi Arabia, the world’s top oil exporter, plans to maintain its crude shipments in January at 6.9 million barrels per day (bpd), as it sees healthy demand for its oil, an industry source familiar with the kingdom’s exports plans told Reuters. State oil giant Aramco plans to reduce its January oil shipments to Asia by more than 100,000 bpd from December, while keeping its exports to the United States and Europe steady, the Saudi Energy Ministry said later in a statement on Monday. “Aramco will maintain its overall supply levels next month at their recent low levels,” the ministry said. Five sources with direct knowledge of the matter said on Monday that Saudi Arabia would supply full contractual volumes of crude to five North Asian refiners in January, unchanged from the previous month. Oil demand is “robust and healthy” particularly in Asia and is expected to stay strong on the back of the winter heating season, an industry source familiar with the export plans said. The Organization of the Petroleum Exporting Countries and non-OPEC producers led by Russia agreed last month to extend oil output cuts until the end of 2018 aiming to reduce global inventories and support prices. Saudi Arabia cut crude exports by 120,000 bpd in December from slightly above 7 million bpd in November, reducing allocations to all regions. It cut supplies to the United States by more than 10 percent. A seasonal drop in domestic crude demand is freeing up more oil for export during the winter months. “This is in line with our continued demonstration of keeping to, and in fact, exceeding, our commitments under the Declaration of Cooperation,” a ministry spokesman said in the statement. “We hope that by leading by example, our partners from OPEC and non-OPEC will do the same in order to keep conformity levels above 100 percent and accelerate the rebalancing of the market.”
Indonesia's Pertamina postpones new crude processing deal for 6 months -- Indonesia's state-owned Pertamina will not immediately extend its crude processing deal with Unipec as awaits details of its 2018 equity allocation share of Iraqi Basrah crude following OPEC's recent decision to extend its production cut agreement through to the end of next year, a senior company official said Thursday. Pertamina said the company may hold the CPD for six months and it is open to a new deal with Unipec or other interested companies when the information on next year's Basrah supply becomes more clear. The current deal with the trading arm of Chinese oil major Sinopec ends December 31. "We are waiting for the availability of Basrah crude. Iraq is one of the OPEC member countries. How much production is being cut, they haven't given us any information," the senior vice president of Pertamina's Integrated Supply Chain, Toto Nugroho, said. Pertamina will not sign any CPDs in the first half 2018, but it is likely to start in the second half of next year, with a volume that will match the company's Basrah equity share, Nugroho said. Pertamina has appointed Unipec to process 1 million barrels/month of its equity Basrah crude under the current CPD. The processing deal is valid over July-December this year and the end product is mostly 88 RON gasoline, S&P Global Platts reported earlier. Prior to the deal with Unipec, Pertamina had a deal with Shell to process 1 million barrels/month of its Iraqi crude at the oil major's Singapore refinery over July-December 2016.
UAE Says OPEC, Allies To Announce Exit Strategy From Oil Cuts In June (Reuters) - United Arab Emirates Energy Minister Suhail bin Mohammed al-Mazroui said on Monday that OPEC and non-OPEC oil producers plan to announce in June an exit strategy from global supply cuts, but that does not mean the pact will end by then.Mazroui said it was premature to talk about the form or shape of such an exit strategy before June, when OPEC, Russia and other producers participating in the supply-reduction agreement - aimed at boosting oil prices - are due to meet next."We will announce ... a strategy in the June meeting. That does not mean we will exit in June. That means we will come up with a strategy," he told reporters in Abu Dhabi."Hopefully the market will be in a much better position for us to come and announce an exit strategy," he said."What is that strategy? No one can tell you the shape, the form, how is it going to be done, prior to everyone’s meeting. Every voice counts in this group. It is unfair for anyone to come and predict."The UAE holds the presidency of the 14-nation Organization of the Petroleum Exporting Countries in 2018.Kuwait's oil minister, Essam al-Marzouq, said on Sunday that OPEC and other oil producers would study before June the possibility of an exit strategy from the global agreement."I think the deal has been working perfectly. We are very optimistic about the growth next year, both the growth on the world economy and the growth in demand," Mazroui said, adding that OPEC "will always do what is best for the market".Russia, which this year reduced production significantly with OPEC for the first time, has been pushing for a clear message on how to exit the cuts so the market doesn't flip into a deficit too soon, prices don't rally too fast and rival U.S. shale firms don't boost output further. Russian Energy Minister Alexander Novak said on Wednesday that it was too early to talk about a possible exit from the deal, and the eventual withdrawal should be gradual.
OPEC Wakes Up to the Threat of U.S. Shale 2.0 - OPEC predicted that global oil markets won’t rebalance until late next year after boosting forecasts for supplies from the U.S. and other rivals. The Organization of Petroleum Exporting Countries’ monthly report raised its outlook for non-OPEC supply in 2018 by 300,000 barrels a day, as its projections for American output caught up with those of the U.S. government. As a result, an initiative by OPEC and Russia to clear a global oil glut by cutting production -- previously seen succeeding in the third quarter of 2018 -- will take effect more slowly. Oil prices climbed to a two-year high above $65 a barrel in London this week, supported by a temporary pipeline halt in the U.K. and the Nov. 30 decision by OPEC and Russia to press on with supply curbs until the end of next year. While Kuwait and the United Arab Emirates said this week the group could consider winding down its efforts in mid-2018 if the market is back in balance, Wednesday’s report suggests they’ll need to persevere for longer.“Continued efforts by OPEC and non-OPEC to support oil market stability” should “lead to a further reduction in excess global inventories, arriving at a balanced market by late 2018,” OPEC’s Vienna-based research department said in the report. The cartel’s latest figures showed its strategy is paying off, having reduced the oil-inventory surplus in developed nations to about 137 million barrels as of October, compared with about 380 million before the cuts began. OPEC Secretary-General Mohammad Barkindo, speaking to Bloomberg television in Beijing on Wednesday, said stockpiles have since fallen further to about 130 million. OPEC output fell by 133,500 barrels a day last month to 32.45 million, according to the report. Venezuela’s troubled industry suffered further production losses, the U.A.E. belatedly stepped up efforts to deliver its pledged cutbacks and Saudi Arabia cut deeper than required.
Hedge funds start to take profits after oil rally- Kemp - (Reuters) - Hedge fund managers have started to take profits from the big rise in crude oil and refined products prices since June now the rally has lost momentum and inventories are showing signs of stabilising.Portfolio managers cut their combined net long position in the five major futures and options contracts linked to petroleum prices by the equivalent of 34 million barrels in the week to Dec. 5.Net long positions were reduced to 1,120 million barrels, from the previous week’s record of 1,155 million, according to an analysis of position data published by regulators and exchanges.The biggest reductions in bullish positions came in U.S. heating oil and gasoline, where positions had reached record levels in recent weeks (http://tmsnrt.rs/2BbInbi).Net long positions in heating oil fell by 13 million barrels to 61 million barrels, from a record 75 million the previous week. Long positions were cut by 9 million barrels while short positions were boosted by 4 million barrels.Net long positions in gasoline fell by 8 million barrels, having declined by 3 million barrels and 7 million in the two previous weeks, and were down to just 107 million barrels on Dec. 5 from a record 125 million barrels on Nov. 14.Profit-taking by the holders of bullish long positions rather than short-selling by hedge funds establishing fresh shorts accounted for most of the reduction in net length.The same phenomenon was evident in European gasoil, which is not included in the analysis of the five major petroleum contracts.Net long positions in gasoil fell by more than 1.1 million tonnes to 14.7 million tonnes, with long positions down 0.9 million tonnes while short positions rose by 0.2 million tonnes.On the crude side, the pattern was different. Net long positions declined slightly in both Brent and WTI but the fall was caused by an increase in short positioning rather than profit-taking among the longs.Gasoline and distillate stocks have stabilised in the past fortnight as a result of very heavy crude processing in the United States and elsewhere, which has dispelled some of the earlier concerns about falling inventories.
WTI-Brent Crude Spread Snaps After Forties Pipeline Closure --Following the discovery of a "small hairline crack" in The Forties Pipeline System - one of the most important oil conduits in the world - its operator Ineos has decided a total controlled shutdown is the safest option. This has sent the spread between WTI and Brent soaring... A “small hairline crack” was discovered during a routine inspection last week by Ineos contractors, just south of Aberdeen in Scotland. The pipeline’s pressure was reduced for a full assessment but during that time the crack extended. As Bloomberg reports, Brent futures rose as much as $1.18 to $64.71 a barrel in London -the highest since June 2015... “Despite reducing the pressure the crack has extended, and as a consequence the Incident Management Team has now decided that a controlled shutdown of the pipeline is the safest way to proceed,” Ineos said in a statement.“This will allow for a suitable repair method to be worked up.”The pipeline system feeds crude to the Hound Point export terminal near Edinburgh in Scotland. At over 400,000 barrels a day, the supplies that flow through the link are the single largest constituent part of the Dated Brent grade that helps to settle more than half the world’s physical oil prices.
Oil gains on Forties Pipeline shutdown, New York blast - (Reuters) - Oil prices rose on Monday, overcoming declines early in the session, after a North Sea pipeline shut for repairs and investors focused on commodities following an explosion in New York. Brent crude futures LCOc1 settled up $1.29, or about 2 percent, at $64.69 a barrel. U.S. West Texas Intermediate (WTI) crude futures CLc1 settled at $57.99 a barrel, 63 cents or 1 percent above their last settlement. The difference between the two benchmarks WTCLc1-LCOc1 was the greatest since late October, as Brent rallied after the shutdown of the pipeline that carries the biggest of the five North Sea crude oil streams that underpin the benchmark. The pipeline, which can carry 450,000 barrels per day of Forties crude from the North Sea to the Kinneil processing terminal in Scotland, has been operating at reduced capacity for about four days before the shutdown. “It is a supply concern not only because the pipeline transports a significant portion of North Sea crude oil output, but also because it may take weeks before the issue is resolved,” said Abhishek Kumar, Senior Energy Analyst at Interfax Energy’s Global Gas Analytics in London. The market had expected the pipeline to return to service quickly and was surprised by the extended shutdown, said John Kilduff, partner at Again Capital LLC in New York. “It’s a significant amount of crude oil in a market that has been the tightest for crude oil,” Kilduff said. Earlier in the session, both benchmarks popped higher after an explosion rocked New York’s Port Authority Bus Terminal, one of the city’s busiest commuter hubs. Investors tend to head for hard-asset commodity markets like gold and silver during high-risk events, and oil can also attract investment, Kilduff said. Brent and WTI have gained well over a third from 2017 lows, drawing support from a cut in production by the Organization of the Petroleum Exporting Countries and a group of non-OPEC producers, including Russia, which has been in place since the start of the year.
Forties pipeline shutdown sends Brent spreads soaring: Kemp (Reuters) - Brent futures for delivery in nearby months have jumped to a big premium following the decision to shut the main pipeline bringing crude onshore from the UK North Sea for inspection and repairs. The Forties pipeline system, which carries around 450,000 barrels per day and handles nearly a quarter of North Sea output, is likely to be shut for weeks, owner INEOS said. Forties is the largest component of the Brent-Forties-Oseberg-Ekofisk-Troll (BFOE) complex of crudes that are the basis for the Brent futures contract. Since the closure is expected to be extended but ultimately temporary, the main impact has been on nearby futures contracts for deliveries in February and March. Brent futures prices for deliveries in February have surged by more than $2 per barrel since Friday while March is up by $1.60. In contrast, prices for Brent futures with deliveries in June have risen by $1.25 and increases for later months are smaller. The main impact from the shutdown has therefore been on the calendar spreads for nearby months rather than on outright or flat prices (http://tmsnrt.rs/2BfvjBG ). The calendar spread from February to March has more than doubled to 76 cents on Tuesday from 37 cents backwardation on Friday. The spread from March to April has similarly flared to 45 cents from 27 cents. The longer the pipeline takes to be repaired, the more the tightness in the February-March and March-April calendar spreads is likely to bleed into later months. A prolonged shutdown of the Forties system would accelerate the drawdown in global oil inventories and tightening of the oil market that is already underway. For the moment, however, the price impact has been mostly confined to North Sea crudes, with prices rising against other light crudes as well as medium and heavy grades. Futures prices for U.S. light crude delivered in February rose by less than $1 per barrel between Friday and Tuesday, suggesting traders see only a modest impact on global crude availability.
Brent Pipeline Closure Confuses Oil Markets - Oil prices jumped at the start of the week due to the cracked pipeline in the North Sea (see below). Brent briefly rose to its highest point since 2015. The Forties pipeline system developed a crack last week and its operator, Ineos, said on Monday that it had to shut down the system for repairs, which could take several weeks. The Forties system is an all-important artery in the North Sea, carrying 450,000 bpd to the UK mainland. Its outage could force North Sea oil producers to temporarily shut down output. “Yesterday’s closure of the Forties pipeline system for weeks is one of the most significant unplanned crude oil shortages we have seen this year,” said Tamas Varga, an analyst at PVM Oil Associates Ltd. It is also crucial for the Brent benchmark, and not surprisingly, Brent jumped above $65 per barrel on the news, the highest in more than two and a half years. “It’s more than just a supply disruption because it’s more significant as a price maker,” Olivier Jakob, an analyst at Petromatrix GmbH, said in a Bloomberg interview. “There’s one thing which is the volume of oil which is lost, but it’s also that it’s a key price benchmark.” Longer laterals in thousands of shale wells are pushing pumpjacks (aka nodding donkeys) to the limit. The pump systems that help squeeze out oil can work on vertical wells for years, but Bloomberg reports that the stress of trying to pump from extremely long horizontal wells is leading to a rapidly growing fail rate for these iconic nodding donkeys. That is pushing up costs for some shale wells and could also result in oil being left in the ground. The problem is especially acute at older wells where it becomes more difficult to extract oil because of declining well pressure. The industry is trying to find some workarounds, but there is no silver bullet. Chevron, Valero and Delta Air Lines have lodged a complaint with U.S. FERC over what they say are excessive fees along the crucial Colonial Pipeline that carries gasoline from the Gulf Coast to the Mid-Atlantic and Northeast. The companies argue that Colonial’s fee to transit gasoline “greatly exceed just and reasonable levels.” Colonial argues the case has no merit.
API Reports Huge Crude Draw - The American Petroleum Institute (API) reported a large draw of 7.382 million barrels of United States crude oil inventories for the week ending December 8, making two large draws in back to back weeks. Analysts had expected a much smaller drawdown of 3.759 million barrels.Last week, the American Petroleum Institute (API) reported a large draw of 5.481 million barrels of crude oil, but had dampened any enthusiasm that the oil bulls may have had by countering that with a massive build of 9.196 million barrels of gasoline.This week, the API is reporting another build in gasoline inventories, but this time more moderate, at 2.334 million barrels for the week ending December 8. The results came in very close to forecasts for a 2.457-million-barrel build.Brent crude had jumped in late afternoon trading on Monday and early Tuesday, as reports came in that the Forties pipeline would be shut down for an unspecified timeframe after a crack had been discovered.By Tuesday afternoon at 2:19pm EST, both benchmarks were trading down, with WTI down 1.52 percent ($-0.88) at $57.11 and Brent crude down 2.13 percent (-1.38) at $63.31. Both benchmarks were up from last Tuesday.Distillate inventories, too, saw another build this week, up 1.538 million barrels, against a forecast of a 902,000-barrel build. Distillate inventory has risen three weeks in a row leading up to this week, according to information by the Energy Information Administration, but are still almost 30 million barrels shy of the same week last year. Inventories at the Cushing, Oklahoma, site decreased by 2.704 million barrels this week.
WTI/RBOB Higher After Surprisingly Large Crude Draw -- WTI/RBOB tumbled today after fears about cracks in one of the world's most important oil pipelines faded. Prices were below last week's pre-API levels as hope was high that last week's big surprise product build was a fluke but once again we saw notable product builds, but prices popped higher as a 7.382mm crude draw was much bigger than expected. API
- Crude -7.382mm (-2.89mm exp) - biggest draw in 4 months
- Cushing -2.704mm (-2.5mm exp)
- Gasoline +2.334mm
- Distillates +1.5384mm
Hope was high that last week's unexpectedly large product build was a one-off. WTI/RBOB prices were below the pre-API levels from last week heading into the print.. The Forties outage is “a measurable disruption that the market can apparently cope with,” Thomas Finlon, director of Energy Analytics Group LLC in Wellington, Florida, said by telephone. After the Brent-WTI spread widened to more than $7 a barrel, “the ability to cover shortfalls with U.S. crude is pretty easy.” But after the API data hit, prices moved higher...
Brent oil price jumps above $65, first time since 2015 - Brent oil prices jumped by one percent on Tuesday to their highest since mid-2015, after the shutdown of the Forties North Sea pipeline knocked out significant supply from a market already tightening due to OPEC-led production cuts.Brent crude futures LCOc1, the international benchmark for oil prices, were at $65.32 a barrel at 07:48 GMT, up 63 cents, or one percent, from their last close. The contract hit a high of $65.70 a barrel earlier in the day.That marks the first time Brent has risen above $65 since June 2015. US West Texas Intermediate (WTI) crude futures CLc1 were at $58.38 a barrel, up 39 cents, or 0.7 percent, from their last settlement. "Brent crude raced higher ... as news broke that the North Sea's Forties Pipeline system would have to be shut down for a 'number of weeks' after a hairline crack was found in it," said Jeffrey Halley, senior market analyst at futures brokerage OANDA in Singapore. "The pipeline ... is a significant component underpinning the Brent benchmark."Britain's Forties oil pipeline, the country's largest at a capacity of 450,000 barrels per day (bpd), shut down on Monday after cracks were revealed. "The market reaction shows that in a tight market, any supply issue will quickly be reflected in higher prices," said ANZ bank. Analysts said there was also oil price support from the consumer side."Demand growth across the commodity complex is extremely robust. And inventories across the complex have been declining sharply," US bank Goldman Sachs said in a note to clients. The jump in Brent prices widened its premium to WTI prices to as much as over $7 a barrel CL-LCO1=R, the highest premium since May 2015 and up from around $5 last week, making US oil exports more attractive.
Brent Reaches Highest Since 2015 After Forties Pipeline Shutdown -- Brent crude jumped to its highest since June 2015 as a key North Sea pipeline shut down.The Forties Pipeline System, one of the most important oil conduits in the world, is to be fully halted after a crack was discovered, the link’s operator Ineos said. Repairs will take about two weeks, according to a spokesman. The announcement boosted pricing that had been largely muted over the last week following an OPEC-led agreement by major producers to extend output curbs through the end of 2018. Brent rallied in London, pulling New York futures up to near $58 a barrel. “You really don’t have a lot of spare barrels before the supply situation becomes a problem.” The pipeline system feeds crude to the Hound Point export terminal near Edinburgh. The supplies that flow through the link are the single largest constituent part of the Dated Brent grade that helps to settle more than half the world’s physical oil prices.Brent for February settlement gained $1.29 to settle at $64.69 barrel on the London-based ICE Futures Europe exchange. The global benchmark traded at a premium of $6.64 to February West Texas Intermediate, the largest premium since early November.SEE: Oil Options, Brent calls trade more than twice put volumeThe WTI-Brent spread will “widen and encourage U.S. exports,” Yawger said, in reference to Brent rising on the Forties’ pipeline outage.WTI for January delivery advanced 63 cents to end the session at $57.99 a barrel on the New York Mercantile Exchange, the highest level in more than a week. Total volume traded was about 7 percent below the 100-day average. Prices also received a boost earlier in the session as news broke of an explosion in New York.
OPEC Says Oil Goal's Close as Stockpile Glut Shrinks Further - OPEC is near its goal of rebalancing the oil market as an inventory overhang targeted by its output curbs continues to shrink, according to the group’s secretary general.The stockpile glut -- including crude as well as oil products -- has shrunk to 130 million barrels above the five-year average, Mohammad Barkindo said in a Bloomberg Television interview in Beijing before the release of OPEC’s monthly market report on Wednesday. The group last month estimated the overhang at about 154 million barrels.That’s a sign that the Organization of Petroleum Exporting Countries and its allies including Russia are progressing in their efforts to curb production and end an oversupply that has weighed on prices and battered their economies since 2014. The group plans to meet in June to assess the market and consider halting the cuts, which they agreed last month to extend until the end of next year. “We are beginning to see a return to stable markets,” Barkindo said. “Something that has eluded us for several years.”Barkindo has previously said the inventory glut has shrunk from a record of more than 380 million barrels as OPEC implemented its output cuts. The overhang in oil-product stockpiles is less than 30 million barrels, he said on Wednesday, adding that nations that are part of the production deal have conformed to the agreement by more than 100 percent on average over January to October this year. Brent crude, the benchmark for more than half the world’s oil, rose 1.4 percent to $64.24 a barrel at 9:51 a.m. in London. Prices climbed above $65 for the first time since June 2015 on Tuesday.
OPEC Reports Lowest Oil Output In Six Months; Fears Shale Production Surge -- True to its perpetually optimistic form, OPEC, which last month for the first time conceded the threat posed by rising US shale production... ... sharply raised its demand forecast for cartel oil in 2018, ahead of the OPEC meeting at the end of November.And, according to OPEC's latest market report for the month of December, demand is set to continue rising, with global oil demand projected to grow at around 1.53 mb/d in 2017, in line with last month’s forecast. China is projected to lead oil demand growth in the non-OECD, followed by Other Asia – which includes India – and OECD Americas. Which means that an unexpected Chinese landing, whether hard or soft, will have an adverse impact on oil in addition to all other commodities. Separately, in 2018, world oil demand is expected to grow by 1.51 mb/d according to the latest OPEC forecast. OECD will contribute positively to oil demand growth, adding some 0.28 mb/d, whereas the bulk of the growth will come from the non-OECD with 1.23 mb/d of potential growth. For 2018, the main assumptions behind the forecast are firm economic growth, lending support to industrial and construction fuels in both OECD and non-OECD. Expansion in the transportation sector is expected to provide the bulk of oil demand growth. Growth in petrochemical demand is projected to be one of the fastest-growing contributors in US, China, South Korea and the Middle East. As such, world oil demand growth is estimated at 1.51 mb/d in 2018, compared to 1.26 mb/d in the initial forecast.More important than demand, however, was the November supply of OPEC oil, which declined by 133.5K to below 32.5 million bbl, a fresh six month low if only 195K bbl lower than last year's output, confirming that ahead of last year's production cut agreement, OPEC furiously ramped up production effectively offsetting the subsequent output limit. Crude oil output increase in Nigeria by 95.8kb/d while declining in Suadi Arabia, UAE, Angola and Venezuela.
Oil settles lower after rally on pipeline outage; Brent premium narrows (Reuters) - Oil prices fell sharply on Tuesday, as traders took profits after prices surged early to a two-year high on an unplanned closure of the pipeline that carries the largest North Sea crude oil grade. Brent crude settled down $1.35, or 2 percent, at $63.34. U.S. crude settled at $57.14 a barrel, 85 cents lower, or 1.5 percent. Selling picked up after the U.S. Energy Information Administration said in its monthly short-term energy outlook that U.S. crude oil output will rise by 780,000 barrels per day (bpd) to 10.02 million bpd in 2018. Last month, it expected a 720,000 bpd year-over-year increase to 9.95 million bpd. “The market is respecting what [EIA] is saying but they’re taking it with a grain of salt,” said Phil Flynn, analyst at Price Futures Group. Volume was strong, with U.S. crude seeing more than 780,000 contracts changing hands, compared with the 200-day moving average of 626,000 contracts. The WTI-Brent spread widened to as much as $7 CL-LCO1=R, the highest in more than two years, then narrowed to $6.38. WTI has lagged Brent, and the discount has helped boost U.S. exports. The Forties pipeline, which carries crude from the North Sea to a processing terminal in Scotland, was shut on Monday after cracks were found. Traders believe it is the first unplanned outage for some years in the line, which was scheduled to pump 406,000 barrels per day (bpd) in December. Its closure pushed Brent prices higher on Monday and early on Tuesday, with Brent rising above $65 a barrel for the first time since June 2015. Forties is important for the global oil market because the crude it carries normally sets the price of dated Brent, a benchmark used to price physical crude around the world and which underpins Brent futures. Industry group the American Petroleum Institute said on Tuesday that crude stocks fell by 7.4 million barrels, more than expected.
WTI/RBOB Steady Despite Huge Gasoline Build, New Crude Production Record -- Despite last night's surprisingly large API-reported crude draw, WTI/RBOB prices were sliding in early trading but as the DOE data printed prices stabilized despite a smaller crude draw than API and a much bigger gasoline builds than expected. Production surged on the week to a new record high.Bloomberg's Mitch Martin noted that the Brent pipeline leak and another in Canada haveU.S. refineries running hard to capture the widening crude differentials. That's leading to oversupply in the gasoline market, which has seen inventories build for three straight weeks; a fourth is expected, increasing supply by 1.8 million barrels. Distillates also are expected to build, rising 1.1 million barrels, even as crack spreads recovered to more than $20 a barrel. “We’re seeing U.S. inventories really continue to fall,” Phil Flynn, senior market analyst at Price Futures Group, says. Investors will focus on whether we see large builds in gasoline and distillates, which may hold back crude from rallying strongly, “but I don’t think you can underestimate the strong demand from the refiners.” DOE:
- Crude -5.12mm (-2.89mm exp)
- Cushing (-2.5mm exp) - biggest draw since Sept 09
- Gasoline +5.66mm (+2.3mm exp)
- Distillates -1.37mm (+1.2mm exp)
A 5th weekly build in gasoline inventories (much larger than expected), and unexpected distillates draw, as crude (and Cushing) stocks are reduced... As Bloomberg notes, crude production topped 9.7 million barrels a day in last week's data for the first time since weekly records began in 1983. Even more importantly, the EIA's monthly assessment of crude production - seen as more accurate than the weekly figures - caught up with the more frequent data in September, after lagging for the previous 5 months. The last week saw another surge to record highs... WTI/RBOB prices extended yesterday's losses ahead of the DOE data (despite API's big crude draw) but the algos managed gains after the print even as crude drew less than API and gasoline's build build...
US Shale Output Rises As OPEC Production Falls To 6-Month Low - OPEC’s crude oil production dropped to a six-month low in November, while U.S. and other non-OPEC supply has grown stronger than initially expected this year, which prompted the cartel to revise up on Wednesday its estimates for non-OPEC supply growth in 2018. OPEC’s crude oil production fell by 133,500 bpd from October to stand at 32.448 million bpd in November, OPEC’s Monthly Oil Market Report showed on Wednesday. This was the lowest production the cartel has reported in six months. The largest increase among the members came from Nigeria, whose production in November jumped by 95,800 bpd from October to 1.790 million bpd, according to OPEC’s secondary sources. Angola, Saudi Arabia, Venezuela, and the UAE saw the largest declines in production. The final OPEC monthly report for this year focused on the 2017 highlights and expectations for 2018. In both overviews, the predominant theme was the U.S. shale supply growth that was higher than any initial expectations. “Non-OPEC oil supply growth 2017 performed well above initial market expectations to now stand at 0.81 mb/d. Higher-than-expected supply growth in the US, Canada and Kazakhstan have been the key contributors to the upward revisions, particularly US tight oil. As a result, US oil output is now expected to grow at 0.61 mb/d this year,” OPEC said. The expected non-OPEC oil supply growth for 2017 is an upward revision of 150,000 barrels per day from the previous report. Improved well efficiency and increased investment in U.S. tight oil prompted OPEC to expect the momentum to continue in 2018. Higher production from sanctioned oil sands projects in Canada will also add to increased non-OPEC supply next year. “As a result, non-OPEC supply is expected to grow by 0.99 mb/d in 2018. The forecast is associated with considerable uncertainties, particularly regarding US tight oil developments,” OPEC said.
EIA Reports Major Draw In Crude Inventories - Amid rising oil prices thanks to the three-week suspension of the Forties pipeline and a major inventory draw estimated by API, the Energy Information Administration injected some more optimism in markets with a reported draw of 5.1 million barrels of crude. The authority said that at 443 million barrels, inventories of crude oil were in the middle of the seasonal average. Refineries processed 17 million barrels of crude daily last week, the EIA also said, producing 10.1 million barrels of gasoline, up from 9.8 million bpd last week. Gasoline inventories, which last week pushed prices down after API estimated a massive build—that EIA largely confirmed—this week will probably have the same effect: according to EIA, they rose again, by 5.7 million barrels In addition to the inventory draw, WTI is at the moment benefiting from greater demand for U.S. oil from Asia, following the shutdown of the Forties oil pipeline network in the North Sea, which has taken off more than 400,000 bpd of crude from the market. The shutdown—following the discovery of cracks in parts of the infrastructure—caused Brent crude to temporarily jump above US$65 a barrel and after that continued to trade closer to that than to US$60. This development will naturally increase the appeal of alternatives to Brent-linked oil grades, including U.S. and Russian crude as the spread between the benchmarks widens. The ICE Brent/WTI spread on Monday, for example, after the announcement of the Forties shutdown, widened to over US$6.60 a barrel from less than US$5 last week. Meanwhile, the OPEC camp is quietly discussing its exit strategy from the production cut agreement, likely spurred by Russia’s insistence to have one in place soon, so it can leave the deal at the first opportunity. The strategy will be announced at the June meeting of the Vienna Club. Until then, it will be among the most important factors to watch out for in the oil market.
Oil slips as U.S. gasoline stock build overshadows crude draw (Reuters) - Oil prices slipped for a second straight day on Wednesday, as a slump in U.S. crude stockpiles was offset by a larger-than-forecast rise in gasoline inventories and as U.S. crude output continued to grow to record highs. U.S. crude inventories last week dropped 5.1 million barrels, more than anticipated, and production hit another record high at 9.78 million barrels per day (bpd), government data showed. The U.S. peak, when records were only kept on a monthly basis, is 10.04 million bpd, set in November 1970. Gasoline stocks jumped 5.7 million barrels, more than double analysts’ expectations for a 2.5 million-barrel gain. “It’s kind of a mixed bag across the board - a little bigger than expected draw on crude but gasoline demand was down slightly. Usually in this time of year you see a little bit more demand,” . U.S. West Texas Intermediate crude settled down 54 cents at $56.60 a barrel, a 1 percent decline. Brent crude ended down 1.4 percent, or 90 cents, at $62.44 a barrel. The international benchmark lost 2.1 percent on Tuesday on a wave of profit-taking after an unplanned shutdown of the Forties North Sea pipeline early this week helped send the global benchmark above $65 for the first time since mid-2015. While the Forties shutdown has provided a price floor, early gains quickly evaporated in a global market that is still oversupplied and with output rising in the United States. The U.S. Energy Information Administration on Tuesday forecast that domestic crude oil output will rise by 780,000 bpd to a record high of 10.02 million bpd in 2018. “The fact that the market sold off so much after the Forties outage shows that the market struggles to trend higher. Now, we’re basically where we were a month ago,”
Brent eases as traders become sanguine about pipeline outage (Reuters) - Brent futures for delivery in the first months of next year have given up much of their premium since the announcement on Monday that the Forties pipeline system would be shut for emergency repairs. The Forties pipeline system, which carries around 450,000 barrels per day and handles nearly a quarter of North Sea output, is likely to be shut for several weeks, according to owner Ineos. But traders have become much more sanguine about the impact on benchmark North Sea oil prices as well as the wider oil market (http://tmsnrt.rs/2kqSkar ). Futures prices for Brent crude delivered in February have declined more than $3 per barrel since peaking on Tuesday and are now almost back to their level before the shutdown was disclosed. The calendar spread between Brent futures for delivery in February and March has also softened from 94 cents per barrel backwardation on Tuesday to just 57 cents on Thursday. Brent's premium to WTI has shrunk from $7.26 per barrel to $5.78, also roughly in line with where it was before the pipeline was stopped. The initial surge in Brent futures prices was likely an overreaction to the supply interruption given its time limited nature and the availability of alternatives. But it has already forced refiners to make adjustments to reduce their demand for Forties and other crudes in the Brent-Forties-Oseberg-Ekofisk-Troll complex. Scotland's Grangemouth refinery has initiated a partial shutdown since it is not economic to buy alternative crudes to replace lost deliveries of Forties. In practice, the interruption of the Forties pipeline system, even if it lasts for two to three weeks, is unlikely to have a major impact on the global supply-demand balance in 2018.
Oil prices up on pipeline outage support (Reuters) - Oil prices rose on Thursday as a pipeline outage in Britain continued to support prices despite forecasts showing global crude surplus in the beginning of next year. U.S. West Texas Intermediate futures settled up 44 cents, or 0.8 percent, to $57.04 a barrel. Brent crude futures settled up 1.4 percent, or 87 cents, at $63.31 a barrel. Prices have been supported by an outage on the Forties crude pipeline that was expected to last several weeks. “At present you can’t ignore the impact of the Forties pipeline outage,” said John Kilduff, partner at Again Capital Llc in New York, “It’s a significant amount of oil that the market is going to miss and is missing. And it’s almost surprising it’s not generating more support.” A reformer was shut on Thursday after a fire in the East Plant at Citgo Petroleum Corp’s 157,500-bpd Corpus Christi, Texas, refinery, said sources familiar with plant operations. The Paris-based International Energy Agency (IEA) expects the oil market to have a surplus of 200,000 barrels per day (bpd) in the first half of next year before reverting to a deficit of about 200,000 bpd in the second half. That means 2018 overall should show “a closely balanced market”. The IEA said U.S. crude output next year would increase by 870,000 barrels per day, up from its November forecast of 790,000 bpd. With cash pouring into the U.S. shale oil industry, the United States is on track to deliver up to 80 percent of the world’s oil production gains through 2025, the IEA estimates. Yet after lows of $56.09 earlier in the day for U.S. crude and $62.01 for Brent crude, both grades had rallied again by settlement. “The market seems to have digested (the IEA report) and is turning its attention to the fact that we’re beginning to tighten,” A fall in U.S. crude inventories last week also lent some support. Stocks fell by 5.1 million barrels in the week to Dec. 8, the fourth consecutive week of decline, to 442.99 million barrels, the lowest since October 2015.
Is The Oil Glut Set To Return? - For the second month in a row, the IEA has poured cold water onto the oil market, publishing an analysis that suggests 2018 could hold some bearish surprises for crude. The IEA’s December Oil Market Report dramatically revises up the expected growth of U.S. shale, which goes a long way to torpedoing the excitement around the OPEC extension. Late last month, when OPEC agreed to extend its production cuts through the end of 2018, the U.S. EIA came out with data – on the same day as the OPEC announcement – that showed an explosive increase in shale output for the month of September, up 290,000 bpd from the month before. Although there is a time lag on publishing production data, the huge jump in output in September, plus the spike in rig count activity over the past few weeks, points to strength in the U.S. shale sector. Against that backdrop, the IEA predicted that non-OPEC supply would grow by 1.6 million barrels per day (mb/d) in 2018, a rather significant upward revision of 0.2 mb/d compared to last month’s report. Adding insult to injury for OPEC, the IEA sees oil demand growing by just 1.3 mb/d. In other words, supply will grow at a faster pace than demand next year, opening up a global surplus once again. “So, on our current outlook 2018 may not necessarily be a happy New Year for those who would like to see a tighter market,” the IEA said. The surplus will be front-loaded – the first half of the year will see a glut of about 200,000 bpd. “ A lot could change in the next few months but it looks as if the producers’ hopes for a happy New Year with de-stocking continuing into 2018 at the same 500 kb/d pace we have seen in 2017 may not be fulfilled,” the agency wrote. In the past few months, a sense of bullishness and optimism returned to the oil market for the first time in years, but the IEA warned that it won’t last.
The Biggest Voices in Oil Disagree About 2018 - The two most critical forecasts of global oil markets offer contrasting visions for 2018: one in which OPEC finally succeeds in clearing a supply glut, and another where that goal remains elusive. In the estimation of the Organization of Petroleum Exporting Countries, production curbs by the cartel and its allies will finally eliminate the excess oil inventories that have depressed crude prices for more than three years. But in the view of the International Energy Agency, which advises consumers, that surplus will barely budge. “Both cannot be right,” said Ole Sloth Hansen, head of commodity strategy at Saxo Bank A/S in Copenhagen. “Whichever way the pendulum swings will have a significant impact on the market.” OPEC and Russia have eliminated almost two-thirds of a global glut this year as the former rivals jointly constrict their crude production to offset a boom in U.S. shale oil. At the heart of the clash between the 2018 forecasts is whether the alliance can deplete the rest of the overhang without triggering a new flood of American shale. Late last year, OPEC and Russia set aside decades of rivalry and mistrust to end a slump in global oil markets that has battered their economies. Defying widespread skepticism, they cut oil supplies as promised, and resolved on Nov. 30 to persevere until the end of next year. Brent crude climbed this week to a two-year high above $65 a barrel, although prices had slipped to $63.37 as of 11:32 a.m. in London. Both the IEA and OPEC agree that the coalition’s cuts are working. The surplus oil inventories in developed nations -- OPEC’s main metric for gauging success -- fell to 111 million barrels in October, from 291 million last November, according to the Paris-based IEA, established in 1974 in the wake of the Arab oil embargo. Where they diverge is on what happens next. OPEC predicts the re-balancing will be complete by late next year as those stockpiles plunge by about 130 million barrels in 2018. By contrast, the IEA sees inventories remaining steady as new supply growth surpasses gains in demand. It warned OPEC on Thursday that it may be deprived of a “ Happy New Year.” Although both institutions project that demand for OPEC crude will be about 32.3 million barrels a day on average in the first half of 2018, their views drift apart as the year progresses. OPEC expects it will need to pump about 34 million barrels day in the second half, while the IEA sees a requirement of just 32.7 million a day.
OilPrice Intelligence Report: IEA Dashes Bullish Sentiment In Oil - Oil prices fell back from their highs earlier this week after the Forties outage, as the IEA dashed hopes of continued bullish momentum when it reported that the global supply surplus could return in 2018. OPEC said that the global surplus in oil inventories dropped to 130 million barrels above the five-year average in November, down sharply from 154 million barrels the month before. “We are beginning to see a return to stable markets,” OPEC Secretary-General Mohammad Barkindo said. “Something that has eluded us for several years.” There are growing expectations that OPEC will need to offer details of an exit strategy at its June 2018 meeting. The IEA published a bearish report this week. The headline conclusion was that U.S. shale would grow so sharply that it would help bring back inventory builds in 2018. The Paris-based energy agency predicted that non-OPEC supply would grow by 1.6 mb/d, overwhelming demand growth of just 1.3 mb/d. That would put an end to the strong inventory drawdowns that we have seen this year, and the agency predicted that inventories would rise by a rate of 200,000 bpd in the first half of 2016. The report undercuts the notion that the oil market will reach balance at some point in mid- to late-2018. Meanwhile, OPEC predicts strong inventory declines in the second half of 2018 – a notable difference from the IEA. “Both cannot be right,” Ole Sloth Hansen, head of commodity strategy at Saxo Bank A/S in Copenhagen, told Bloomberg. “Whichever way the pendulum swings will have a significant impact on the market.” A growing number of large financial institutions have pledged to end their support for fossil fuels. The World Bank said earlier this week that it would no longer finance coal plants beginning in 2019. But other examples continue to pop up. BNP Paribas said in October that it would no longer lend to shale and oil sands projects. Dutch lender ING said it would cut off finance for upstream oil and gas by 2019. French insurer AXA said it would no longer insure oil sands or coal projects.
U.S. Oil Rig Count Dips, Ending 5 Week Streak -- While OPEC is busy shackling its members’ production to its lowest level in six months, US oil and gas drillers have been rolling up their sleeves and diving into the shale patch, adding active rigs for five straight weeks—up until today, when Baker Hughes reported that active oil and gas rigs in the U.S. had fallen by 1. The total oil and gas rig count in the United States now stands at 930 rigs, up 293 rigs from a year ago, with the number of oil rigs falling by 4 and the number of gas rigs climbing by 3. The number of oil rigs stands at 747 versus 510 a year ago. The number of gas rigs in the US now stands at 183, up from 126 a year ago.While the US has, at least for one week, seen a dip in the number of oil rigs, Canada came out swinging this week, adding 22 oil rigs. At 12:17pm EST, the price of a WTI barrel was up $0.18 (+0.32 percent) to $57.22, while the Brent barrel was trading down $0.16 (-0.25 percent) to $63.15. The Permian Basin lost 3 rigs for the week, and Cana Woodford lost 4. Granite Wash and Marcellus, on the other hand, gained a total of five rigs collectively. Eagle Ford saw no change to the number of active rigs.U.S. crude oil production continues to climb a weekly basis, placing further pressure on prices. U.S. crude oil production for the week ending December 8 was 9.780 million barrels per day—another record for 2017, and the eighth straight weekly increase. At 12:12pm CST, WTI was trading at $57.27 with Brent trading at $63.23—largely unchanged from last Friday.
Oil Hovers Below 2-Year Highs With Focus On US Output (Reuters) - Oil prices were mixed on Friday, lingering below two-year highs as the continuing outage of a North Sea pipeline gave support, while climbing U.S. output and weak gasoline demand kept a lid on gains. Brent crude futures settled down 8 cents or 0.1 percent to $63.23 a barrel. U.S. West Texas Intermediate (WTI) crude futures settled up 26 cents to $57.30 a barrel. WTI hit a two-year high of $59.05 on Nov. 24. Brent ended the week down slightly with a 0.3 percent fall, while WTI was down 0.1 percent. "There's definitely some pressure on crude," said John Kilduff, partner at energy hedge fund Again Capital LLC in New York. "Demand for gasoline is lower which isn't normally the case in the holiday season and supplies are steadily rising. It's something to watch." Gasoline futures were down 3.5 percent on the week. Hedge funds and other money managers pared their net long U.S. crude futures and options positions in the week to Dec. 12, cutting the holdings for a second week after hitting a record high, the U.S. Commodity Futures Trading Commission (CFTC) said on Friday. The speculator group cut its combined futures and options position in New York and London by 7,542 contracts to 435,200 during the period. The cut was the second in a row. The ongoing outage of the Forties pipeline, which carries North Sea oil to Britain, was a price support for Brent early in the session before the grade fell slightly, traders said. The outage's main physical impact is the North Sea region, but it has global relevance as the crude is used to underpin the Brent price benchmark. Operator INEOS declared force majeure on Forties, the first such declaration in decades. Force majeure is a legal designation that suspends a firm's contractual obligations due to situations beyond its control. Still, U.S. oil production , which has soared 16 percent since mid-2016 to 9.78 million barrels per day (bpd), has undermined OPEC's output curbs. U.S. supply, now close to matching levels of top producers Russia and Saudi Arabia, will likely move oil markets into a supply surplus in the first half of 2018, the International Energy Agency said.
Oil prices pare weekly loss, with U.S. benchmark on the rise --Oil prices settled on a mixed note Friday, notching a third-consecutive weekly loss on nagging concerns over rising U.S. crude production. U.S. benchmark crude, however, climbed for the session, buoyed in part by a fall in the weekly U.S. oil-rig count, which offers a peek at drilling activity.January West Texas Intermediate crude CLF8, +0.56% added 26 cents, or 0.5%, to settle at $57.30 a barrel on the New York Mercantile Exchange after tapping a low under $57. It lost 0.1% for the week. February Brent LCOG8, -0.09% shed 8 cents, or 0.1%, to finish at $63.23, suffering a weekly decline of roughly 0.3%. Both WTI and Brent logged a third-straight week of declines. “It has been a volatile week for oil prices as the shut pipeline in the North Sea spurred an early week rally before a three times larger-than-average increase in weekly U.S. oil production saw futures turn negative on the week,” Tyler Richey, co-editor of the Sevens Report, told MarketWatch.“The dynamics of the oil market are divergent right now as the technical trend remains bullish while fundamentals are less encouraging, mostly thanks to the relentless rise in U.S. oil production,” he said.The Energy Information Administration Wednesday reported that total U.S. crude production rose 73,000 barrels a day to 9.78 million barrels a day for the week ended Dec. 8. That was another weekly record, based on EIA data going back to 1983. But Baker Hughes on Friday reported that the number of active U.S. rigs drilling for oil was down 4 at 747 this week, implying a slowdown in drilling activity. That number had climbed in each of the last three weeks. For now, “the path of least resistance [for oil] remains higher for the near term,” said Richey. “Gains in U.S. output will limit upside to the low $60s for WTI.”“The spread between Brent and WTI has also been volatile this week and that has largely been a function of the pipeline outage in the North Sea,” he said. Prices for Brent saw some support this week on concerns around the Forties North Sea pipeline, which now looks like it may be out of operation for as long as a month. Analysts says the outage could start to have an impact on WTI as it is around $6 a barrel cheaper than Brent, making imports of it more economical, according to a Dow Jones Newswires report. Investors were also assessing a report Thursday from the International Energy Agency, which said that global oil supply has jumped to a one-year high as U.S. shale producers roar back to life. Among other energy contracts, January natural gas slipped 2.7% to $2.612 per million British thermal units, for the lowest most-active contract settlement since February. It ended about 5.8% lower for the week. January gasoline fell 1% to $1.655 a gallon—down roughly 3.6% on the week, while January heating oil HOF8, -0.30% lost 0.3% to $1.904 a gallon, for a weekly loss of around 1.3%.
Saudi king approves $19 billion of economic stimulus steps (Reuters) - Saudi Arabia’s King Salman approved 72 billion riyals ($19.2 billion) worth of measures to stimulate growth in the private sector as authorities seek to pull the economy out of a slump caused by low oil prices. The measures include residential housing loans worth 21.3 billion riyals, a 10 billion riyal fund to support economic projects, and 1.5 billion riyals to support distressed companies, the government announced on Thursday. A 2.8 billion riyal government fund will be created to invest in smaller companies, while the government will adjust the fees which it charges for services to save smaller companies 7 billion riyals. More money would be spent on projects such as developing the kingdom’s broadband infrastructure and promoting advanced construction techniques. Officials did not give details of most of the stimulus measures. The private sector’s growth has slowed to a crawl this year because of government austerity policies designed to curb a state budget deficit caused by low oil export revenues. The economy faces more headwinds early next year in the form of the planned introduction of a 5 percent value-added tax in January and domestic energy price hikes. With unemployment among Saudis officially put at 12.8 percent, authorities are eager to prevent the private sector from slipping into recession. Fahad al-Sukait, a cabinet adviser who briefed reporters on the stimulus plan, said the measures outlined on Thursday were part of a four-year, 200 billion riyal scheme to aid private businesses. Of that amount, 40 billion riyals was allocated this year in the form of capital increases for state funds which support the economy by lending in areas such as housing.
Saudi Arabia said to set up entity for assets taken in purge -- Saudi Arabia is setting up an organisation to manage assets relinquished by detainees as part of settlement agreements in the crackdown on corruption, according to people with knowledge of the matter. The kingdom is talking to consultants about how to set up the entity, which will evaluate and potentially sell holdings handed over by billionaires and princes in exchange for their freedom, said the people, asking not to be identified because the matter is private. Hani Halawani, head of direct investments at Sanabil Investments, part of the Public Investment Fund, will help run the organisation, the people said. The government’s Centre for International Communication didn’t respond to a request for comment. Halawani didn’t immediately respond to a request for comment. Saudi authorities are hoping to reach agreements with detainees “within weeks” after the arrests at the beginning of November, according to the kingdom’s attorney general. Authorities could recover as much as $100 billion from the settlement deals, according to Crown Prince Mohammed bin Salman. Prince Miteb bin Abdullah, one of the most senior Saudi royals detained in the crackdown, was released at the end of November after reaching a settlement deal believed to exceed the equivalent of $1 billion, an official involved in the campaign said at the time.
Cyberattacks: The Biggest Threat To OPEC -- Oil and cybersecurity in one sentence certainly makes for a thrilling read, and there will be an increasing amount of information on the topic as the Internet of Things expands and the global oil industry adopts automation and digital technology. OPEC is no exception in this digitalization drive, but unlike its non-OPEC counterparts, the cartel has emerged as much more vulnerable to cybersecurity threats. An analysis of data collected from 134 countries by the International Telecommunication Union has revealed that some of the world’s biggest oil producers, including Iraq, Saudi Arabia, Venezuela, Iran, and the UAE, are lacking in the cybersecurity department. This means that, compared to European producers and the United States, OPEC members are pretty much unprepared for a major cyberthreat. What is the likelihood of such a threat actually materializing? Well, the general opinion in cybersecurity circles is that everything that can be hacked will be hacked at some point. Saudi Arabia’s oil and gas industry, for example, has been a favorite target for numerous attacks over the last few years, including the Shamoon virus, which in 2012 wiped clean the disks of more than 30,000 computers at Aramco, and according to reports from the cybersecurity industry, reared its ugly head again in 2016. Overall, about half of all cyberattacks in the Middle East target the oil and gas industry, which suggests the answer to the above question is “Pretty high,” but the worse thing is that this likelihood is only going to get higher in the future. Middle Eastern producers are following in the footsteps of their non-OPEC counterparts in adopting digital technology and automation to improve efficiencies in the post-2014 world, where efficiency has come to the fore in oil and gas. The problem, of course, is that the more you digitalize, the more vulnerable you become to attacks through digital channels.
Iraq declares war with Islamic State is over - BBC News: Iraq has announced that its war against so-called Islamic State (IS) is over. Prime Minister Haider al-Abadi told a conference in Baghdad that Iraqi troops were now in complete control of the Iraqi-Syrian border. The border zone contained the last few areas IS held, following its loss of the town of Rawa in November. The US state department welcomed the end of the "vile occupation" of IS in Iraq and said the fight against the group would continue. Iraq's announcement comes two days after the Russian military declared it had accomplished its mission of defeating IS in neighbouring Syria.The jihadist group had seized large swathes of Syria and Iraq in 2014, when it proclaimed a "caliphate" and imposed its rule over some 10 million people. But it suffered a series of defeats over the past two years, losing Iraq's second city of Mosul this July and its de facto capital of Raqqa in northern Syria last month. Some IS fighters are reported to have dispersed into the Syrian countryside, while others are believed to have escaped across the Turkish border. This is undeniably a proud moment for Mr Abadi - a victory that once looked like it might only ever be rhetorical rather than real. But if the direct military war with IS in Iraq is genuinely over, and the country's elite forces can now step back after a conflict that's taken a huge toll on them, it doesn't mean the battle against the group's ideology or its ability to stage an insurgency is finished - whether in Iraq, Syria or the wider world. Attacks may be at a lower level than they once were, but Iraqi towns and cities still fall prey to suicide bombers, while the conditions that fuelled the growth of jihadism remain - even in the territory that's been recaptured.
The pundits were wrong about Assad and the Islamic State. As usual, they’re not willing to admit it - - The Islamic State is a shadow of its former self. In 2014, the extremist group seemed to make substantial inroads in achieving its stated goal of a caliphate. It boasted tens of thousands of fighters and territorial control over an area roughly the size of South Korea. By almost every metric, Islamic State has collapsed in its Syria stronghold, as well as in Iraq. As a former foreign fighter recently admitted, “It’s over: there is no more Daesh left,” using an Arabic acronym for Islamic State. The rollback of Islamic State must come as a shock to the chorus of journalists and analysts who spent years insisting that such progress would never happen without toppling the regime of Bashar Assad — which is, of course, still standing. A cavalcade of opinion makers long averred that Islamic State would thrive in Syria so long as Assad ruled because the Syrian Arab Army was part of the same disease.John Bolton, former United Nations ambassador under George W. Bush, insisted in the New York Times that “defeating the Islamic State” is “neither feasible nor desirable” if Assad remains in power. Writing in the Wall Street Journal, Sens. John McCain and Lindsey Graham asserted that “defeating Islamic State also requires defeating Bashar Assad.” Kenneth Pollack of the Brookings Institution prescribed a policy of “building a new Syrian opposition army capable of defeating both President Bashar al-Assad and the more militant Islamists.” Similarly, Max Boot, a contributing writer to this newspaper, argued that vanquishing Islamic State was futile unless the U.S. also moved to depose the “Alawite regime in Damascus.” Like other regime-change salesmen, he pitched a no-fly zone across the country to facilitate airstrikes against the Assad government, while boosting aid to the so-called moderate rebels.
Iran's Revolutionary Guard Sends Formal Message To US Military: Leave Syria Or Else - Well informed sources have said the commander of the Iranian Revolutionary Guards Corp Brigadier General Haj Qassem Soleimani sent a formal verbal message, via Russia, to the head of the US forces command in Syria, advising him to pull out all US forces to the last soldier “or the doors of hell will open up”.“My message to the US military command: when the battle against ISIS will end, no American soldier will be tolerated in Syria. I advise you to leave by your own will or you will be forced to it,” said Soleimani to a Russian officer. Soleimani asked the Russian officer to make known the Iranian intentions towards the US: that they will be considered as forces of occupation if these decide to stay in northeast Syria where Kurds and Arab tribes cohabit together. The Russians are not necessarily against the US presence and can adapt to this after defining the demarcation lines to avoid any clash, but Iran has a clear position and has decided not to abandon the Syrian President alone to face the US forces, if these stay behind. Soleimani’s message to the US clearly indicated the promise of ‘surprise measures’ against the US: "You shall face soldiers and forces you have not experienced before in Syria and you will leave the country sooner or later."
"ISIS Is Defeated, The US Is Next In Line" - Paul Craig Roberts - Washington has already lost the Syrian war once. Now it is about to lose it a second time. A few days ago the president of Russia, Vladimir Putin, declared a “complete victory” in Syria: “Two hours ago, the (Russian) defense minister reported to me that the operations on the eastern and western banks of the Euphrates have been completed with the total rout of the terrorists.” The Iranian commander of the forces which support the Syrian and Iraqi governments sent a note to the U.S. to let Washington know that any remaining U.S. forces in Syria will be fought down: “The commander of the Iranian Revolutionary Guards Corp Brigadier General Haj Qassem Soleimani sent a verbal letter, via Russia, to the head of the US forces commander in Syria, advising him to pull out all US forces to the last soldier ‘or the doors of hell will open up.'” “My message to the US military command: when the battle against ISIS (the Islamic State group) will end, no American soldier will be tolerated in Syria. I advise you to leave by your own will or you will be forced to it.” According to reports, Russia has confirmed that Iran will stay in Syria as long as Syrian President Assad, who insists on liberating all of Syria without exception for the Americans, decides. Washington’s plan to occupy a corner of Syria and revive ISIS is dead in the water, as will be all US troops sacrificed to this purpose. According to reports, CIA director Mike Pompeo sent a letter to Soleimani expressing his concern about Iran’s intention to attack American interests, declaring Washington “will hold Soleimani and Iran accountable for any attack.” According to reports the CIA’s letter had no effect and was treated with total contempt: “Mohammad Mohammadi Golpayegani, a senior aid to the Grand Ayatollah Ali Khamenei confirmed Pompeo’s attempt to send a letter but said ‘Soleimani refused to read it or to take it because he has nothing further to add.’
Putin Orders Withdrawal Of Russian Troops From Syria During Surprise Visit -- Drawing a stark contrast between himself and his counterpart in the US, Russian President Vladimir Putin made a surprise appearance at Khmeimim Airbase in Syria on Monday morning where he ordered the withdrawal of Russian troops from Syria, now that the ISIS insurgency that once controlled roughly one-third of the country’s land area has been effectively dismantled.The Russian president was met by his Syrian counterpart, Bashar al-Assad, and Russian Defense Minister Sergey Shoigu at the airbase. Russian forces fighting with the Syrian Army during the country's civil war were stationed at the base.Putin ordered the withdrawal of Russian troops to begin immediately, according to Russia Today.“I order the defense minister and chief of the general staff to start the withdrawal of Russian troops to the site of their permanent deployment," Putin said, speaking to a crowd of Russian soldiers. The Russian leader said that during the span of two years, the Russian and Syrian militaries have “defeated the most battle-hardened grouping of international terrorists,” adding that he’s decided a significant portion of the Russian troop contingent should return to Russia. Putin warned that if ISIS tries to “rear their heads” in Syria again, Russia will retaliate with a level of force that “they have never seen before.” The Russian leader added that the conditions for a political settlement under the auspices of the United Nations had been created in Syria, and that refugees were returning home.