US oil prices ended the week 81 cents lower than last week's final quote, but price quotes for Friday of this week really shouldn't be compared to those of last week, because each references a different contract month...i'll explain that oil pricing quirk again, because the change-over of the quoted contract month sometimes even throws me when i'm not watching for it, as it did this week...
at any give time, contracts to buy or sell oil for the coming month and for dozens of months in the future are being traded on the New York Mercantile Exchange (NYMEX), the Chicago Mercantile Exchange (CME), and several other exchanges; for instance, here's a list of contracts for US light oil currently being traded on the CME; you'll see they quote different prices for the same kind of oil, by month, all the way out to December 2025...however, the media and most industry publications will only quote the price of oil for the "front month" contract, or the open contract for the month closest to the current date that's still being traded...when trading in a given front month contract stops trading, several business days before the 1st of that month, the following month's contract becomes the front month contract, and its price is then quoted in the media as the price of oil, usually without much of an indication that the 'price of oil' being quoted is for delivery in a different month than the price that was quoted by the same source 24 hours earlier...at the same time, those sites that display oil price charts will switch the chart of oil prices for the month that expired with a chart of prices for the new front month, and the price history of the new current month shown by those new charts is usually slightly skewed from the prices that had been shown on that same graph over the prior month...
and that change is what happened to oil prices this week....after closing last week at $48.78 a barrel, US WTI oil contracts for April delivery again headed lower on Monday after the prior week's strong drilling & production data, closing down 56 cents at $48.22 a barrel...at the same time, the WTI oil contract for May delivery, also being actively traded, fell 40 cents from the prior week's close of $49.31 a barrel to close Monday at $48.91….however, that trading and those prices for May were not reported anywhere, except for on trading related websites...oil prices for April fell another 88 cents on Tuesday, closing at $47.34 a barrel, the lowest price since the November OPEC deal, as traders anticipated the release of data showing a large increase in US oil inventories...since that was the last day of trading for April oil, a few sites covering the price of oil for that day also reported that the more actively traded May contract was also down 67 cents, or 1.4%, to $48.24 a barrel....then on Wednesday, with the April oil contract no longer being traded, many of the same media sites that had reported oil prices down 88 cents to $47.34 a barrel on Tuesday, reported oil down 20 cents to $48.04 on Wednesday, barely making note of the change in the contract month...with the May contract now being quoted as the price of oil, oil then fell 34 more cents on Thursday, closing at $47.70 a barrel, even as many media reports called it the 3rd oil price decrease in a row, even though prices for each separate contract had deceased every day this week...oil pries then rose a bit on Friday, closing the week at $47.97 a barrel, as oil traders positioned themselves for any possible bullish outcome of the coming OPEC meeting in Kuwait on Sunday to review the current level of compliance to the agreed to cuts...with the mid-week contract expiration, some sites properly explained that May oil prices were down $1.34 or 2.7% for the week, while others reported the 81 cent difference between last Friday's April oil and this Friday's May oil..
in most articles on oil prices, the contract month that is being quoted is further complicated by the wide difference in expiration dates between the US benchmark oil price, West Texas Intermediate, usually just written as WTI, and the widely quoted international price for North Sea Brent oil...contracts for WTI expire on the 4th US business day prior to the 25th calendar day of the month preceding the contract month, whereas contracts for Brent oil expire on the last business day of the second month preceding the relevant contract month; in other words, the April Brent contract expired on February 28th, and the price for the May contract has been the quoted price of Brent oil throughout March...so for most of each month, articles citing the price of the two benchmark oils are not only quoting different oil types, but also different settlement months...May Brent oil closed this week at $50.80 a barrel, down from $51.76 a barrel the prior Friday...
this week's natural gas prices, however, were still referencing the price for natural gas to be delivered in April, and will be until March 29th, as trading in natural gas contracts don't expire until 3 business days before the contract month...those prices were generally up this week, rising 4 out of 5 days, and ending at $3.076 per mmBTU, after closing the prior week at $2.948 per mmBTU...still, as we've noted before, prices at these levels are still low enough to discourage the exploitation industry from starting new drilling projects; leaving them just maintaining what they already have going, and only starting up new rigs when prices approach $4...a chart that came in one of the mailings from John Kemp at Reuters goes a long way towards explaining what has kept natural gas prices at these depressed levels over most of the last two years...
the above graph comes from one of the emailed package of graphs from John Kemp, senior energy analyst and columnist with Reuters (see my footnote below) and it shows the cumulative population-weighted heating degree days for the 2016-17 heating season in red, the same metric for the 2015-16 heating season in yellow, and historical average for the same metric as a white dashed graph...heating degree days are the sum of the average number of degrees below a certain temperature at which it has been determined that buildings need to be heated..,for example, if 65 °F is determined to be the temperature wherein one needs heating, a day with an average temperature of 45 °F would add 20 degree days to the total, while a day with an average temperature of 30 °F would add 35 degree days to the cumulative total...heating degree days are calculated for many areas of the US, and are used by utilities to estimate demand for their output, and are used locally to schedule deliveries of heat oil...this graph shows the result when one takes that heating degree days metric each for area of the US and weighs it based on the population of those areas...ie, if for instance, New York City with a population of 8 million has 25 heating degree days of demand on a given date, it will count for 1000 times more in the total than a county of 8,000 in Wyoming where the measure of their heating demand was 55 degree days on that date...therefore, what this graph shows us is the relative demand for heating for the whole country, from the period beginning in July of each year, a time when there's no demand for heating... so what we see here is that the US heating needs this season remain very close to those of the record warm 2016 heating season, when cumulative heating degree days were 17% below the average...that translates into 17% lower demand for natural gas heat, and 17% lower demand for heat oil...that reduced demand is the reason that natural gas prices have stayed below $3.00 per mmBTU for most of the last two years, and why drilling for natural gas dropped to an all time low last year, and has barely recovered, which you'll see in the next graph...
above, we have a graph of the rig count history from 1991 until last week (ie, this week's rig count is not yet included)...this graph comes from a weekly pdf booklet of petroleum graphs produced by Yardeni Research, a provider of investment and economics research, run by Dr Ed Yardeni, and it shows the oil rig count over that 26 year history in violet, the natural gas rig count over that span in green, and then shows the total rig count, which would also occasionally include a miscellaneous rig or two, in red...you can see that natural gas drilling hit its most recent peak in 2010-2011, when natural gas prices were consistently over $4 per mmBTU, while the drilling peak prior to that, in 2008, saw natural gas prices spike to near $14 per mmBTU....since 2011, however, there was only one period in 2014 that saw natural gas prices top $4 per mmBTU, and if you look close, you can see that natural gas drilling briefly picked up at that time...otherwise, natural gas drilling has been in a long term decline since that 2011 peak of 992 rigs, sliding all the way down to 81 rigs in both the first and last week of August 2016...while they've increased since then, note that they're still far below the 240 to 525 rig range that natural gas drillers were deploying even as far back as the early 90s..
The Latest Oil Stats from the EIA
the oil data for the week ending March 17th from the US Energy Information Administration showed a big jump in our imports of crude oil, resulting in another large surplus of crude for the 10th week out of the past 11, pushing our supplies of oil to yet another an all time high, even as our refineries ramped up production to a more seasonal pace...our imports of crude oil increased by an average of 902,000 barrels per day to an average of 8,307,000 barrels per day during the week, while at the same time our exports of crude oil fell by 167,000 barrels per day to an average of 550,000 barrels per day, which meant that our effective imports netted out to 7,757,000 barrels per day during the week, 1,069,000 barrels per day more than the prior week...at the same time, our crude oil production rose by 20,000 barrels per day to an average of 9,129,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 16,886,000 barrels per day during the cited week...
during the same week, refineries reportedly used 15,801,000 barrels of crude per day, 329,000 barrels per day more than they used during the prior week, while at the same time, 618,000 barrels of oil per day were being added to oil storage facilities in the US....thus, this week's EIA oil figures would seem to indicate that we used or stored 469,000 less barrels of oil per day than were supplied by our net oil imports and oil well production…therefore, in order to make the weekly U.S. Petroleum Balance Sheet balance out, the EIA inserted a phantom -469,000 barrel per day number onto line 13 of the petroleum balance sheet, which the footnote tells us represents "unaccounted for crude oil"...that "unaccounted for crude oil" is further described in the glossary of the EIA's weekly Petroleum Status Report as "the arithmetic difference between the calculated supply and the calculated disposition of crude oil", which means they got that balance sheet number by backing into it, using the same arithmetic we just used in explaining it...
the weekly Petroleum Status Report also tells us that the 4 week average of our oil imports rose to an average of 7,863,000 barrels per day, still 3.0% below that of the same four-week period last year...at the same time, the 4 week average of our oil exports fell to 721,000 barrels per day, still 86.4% higher than the same 4 weeks a year earlier, as our overseas exports of our surplus light oil were barely underway in early 2016...the 608,000 barrel per day increase in our crude inventories included a 708,000 barrel per day increase in our commercially available crude supplies, which was partially offset by an 89,000 barrel per day sale of oil from our Strategic Petroleum Reserve, part of an ongoing sale of 5 million barrels annually that was planned 18 months ago...meanwhile, this week's 20,000 barrel per day oil production increase was all from the lower 48 states, as oil output from Alaska was unchanged from last week...the 9,109,000 barrels of crude per day that we produced during the week ending March 17th was the most we've produced since the week ending February 12th last year, and was more than 1.0% more than the 9,038,000 barrels per day produced during the week ending March 18th, 2016, while it was still 5.0% below the June 5th 2015 record oil production of 9,610,000 barrels per day...
US refineries were operating at 87.4% of their capacity in using those 15,801,000 barrels of crude per day, up from 85.1% of capacity the prior week, but still down from the year high of 93.6% of capacity in the first week of January, when they were processing 17,107,000 barrels of crude per day....their processing of crude oil is now on a par with the 15,820,000 barrels of crude that were being refined during the week ending March 18th, 2016, when refineries were operating at 88.4% of capacity....with the week's refinery pickup, gasoline production from our refineries rose by 231,000 barrels per day to 15,820,000 barrels per day during the week ending March 17th, which was 0.9% more than the 9,683,000 barrels per day of gasoline that were being produced during the week ending March 18th a year ago...in addition, refineries' production of distillate fuels (diesel fuel and heat oil) was also up, rising by 139,000 barrels per day to 4,829,000 barrels per day, which was also up by 1.8% from the 4,742,000 barrels per day of distillates that were being produced during the week ending March 18th last year...
even with the increase in our gasoline production, the EIA reported that our gasoline inventories shrunk by 2,811,000 barrels to 243,468,000 barrels as of March 17th, after they had dropped by more than 9.5 million barrels over the prior 2 weeks....that was despite the fact that our domestic consumption of gasoline fell by 54,000 barrels per day to 9,200,000 barrels per day and remains 3.0% off the year ago pace, and was because our imports of gasoline fell by 247,000 barrels per day to 325,000 barrels per day as our gasoline exports rose by 57,000 barrels per day to 592,000 barrels per day...while our gasoline supplies are now down by nearly 15.6 million barrels from the record high set 5 weeks ago, they're only down 0.7% from last year's March 18th high of 245,074,000 barrels, and are still 4.3% above the 233,386,000 barrels of gasoline we had stored on March 20th of 2015...
our supplies of distillate fuels also fell this week, decreasing by 1,190,000 barrels to 155,393,000 barrels by March 17th, even as the amount of distillates supplied to US markets, a proxy for our consumption, decreased by 397,000 barrels per day to 4,012,000 barrels per day, and as our imports of distillates rose by 48,000 barrels per day to 127,000 barrels per day, because our exports of distillates rose by 253,000 barrels per day to 1,217,000 barrels per day at the same time....while our distillate inventories are now 4.2% below the bloated distillate inventories of 162,260,000 barrels that we had stored on March 18th 2016, at the end of the warm El Nino winter of last year, they are still 23.5% higher than the distillate inventories of 125,849,000 barrels that we had stored on March 20th of 2015…
finally, with the big jump in our net oil imports considerably more than the increase in refinery demand, our commercial inventories of crude oil increased for the 10th time in 11 weeks, increasing by 4,954,000 barrels to a record high 533,110,000 barrels by March 17th...at the same time, 628,000 barrels of oil from our Strategic Petroleum Reserve was sold, which left inventories in the SPR at 693,383,000 barrels, a quantity not considered available for commercial use....thus for current commercial purposes, we finished the week ending March with 11.3% more crude oil in storage than the 479,012,000 barrels we had stored at the end of 2016, 6.3% more crude oil in storage than what was then a record 501,517,000 barrels of oil in storage on March 18th of 2016, 23.1% more crude than what was also then a record 433,217,000 barrels in storage on March 20th of 2015 and 52.0% more crude than the 350,802,000 barrels of oil we had in storage on March 21st of 2014...
This Week's Rig Count
US drilling activity increased for the 20th time in 21 weeks during the week ending March 24th, and we also had the 8th double digit rig increase in the past 10 weeks....Baker Hughes reported that the total count of active rotary rigs running in the US increased by 20 rigs to 809 rigs in the week ending on this Friday, which was 345 more rigs than the 476 rigs that were deployed as of the March 25th report in 2016 and the most since Oct 2nd, 2015, but still far from the recent high of 1929 drilling rigs that were in use on November 21st of 2014 (see graph above)...
the count of rigs drilling for oil increased by 21 rigs to 652 rigs this week, which was up from the 372 oil directed rigs that were in use a year ago, and more that double the 316 rigs working on May 27th 2016, but still down from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations fell by 2 rigs to 155 rigs this week, which was still up from the 92 natural gas rigs that were drilling a year ago, but down from the recent natural gas rig high of 1,606 rigs that were deployed on August 29th, 2008...in addition, another rig that was classified as miscellaneous was added this week, and we now have two of those, in contrast to a year ago, when there were no such miscellaneous rigs at work...
a drilling platform that had been working offshore from Louisiana in the Gulf of Mexico was shut down this week, which reduced the current Gulf of Mexico count to 18 rigs, down from the 27 rigs that were drilling in the Gulf during the same week of 2016...that was also down from a total of 28 rigs working offshore of the US a year ago, when there was also a rig working offshore from California, in addition to the 27 rigs that were drilling in the Gulf of Mexico at the time...in addition, one of the rigs that had been set up to drill through an inland lake in Louisiana was also shut down, leaving the inland waters rig count at 4, the same as it was a year ago..
active horizontal drilling rigs increased by 15 rigs to 673 rigs this week, which is well more than double the May 27th 2016 total of 314 working horizontal rigs...that's also up by 314 horizontal rigs from the 359 horizontal rigs that were in use in the US on March 25th of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, a total of 8 vertical rigs were added this week, bringing the vertical rig count up to 78 rigs, which was also up from the 53 vertical rigs that were deployed during the same week a year ago...meanwhile, the directional rig count was down by 3 rigs to 58 rigs, which was still up from the 52 directional rigs that were deployed during the same week last year....
as usual, the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary 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 March 24th, the second column shows the change in the number of working rigs between last week's count (March 17th) and this week's (March 24th) count, the third column shows last week's March 17th active rig count, the 4th column shows the change between the number of rigs running this Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was for the 25th of March, 2016...
as you can see, the Permian basin of western Texas & southeastern New Mexico saw the largest drilling increase again, after a few weeks where not much changed in that basin...increases in the Eagle Ford of south Texas and the Barnett shale near Dallas also added to the Texas total, while the reasons for the 7 rig increase in Oklahoma aren't so clear, since the two rig increase in the Cana Wordford are the only shale basin targeting rigs added in the state...i'd assume that the other new Oklahoma rigs were of the vertical drilling sort...also note the addition of two rigs in the Marcellus, one in Pennsylvania, and one in West Virginia, which came despite the 2 rig reduction in the natural gas rig count...gas rigs that were removed were not from a major basin, but were rather from a markdown of rigs from "other" areas, the names of which are not included in Baker Hughes summary data..
as noted, a graph that i included above was from an emailed package of graphs from John Kemp, a senior energy analyst and columnist with Reuters, who advises that his mailing list is open to anyone...you can ask for his daily digest by emailing email@example.com or you can follow him on twitter, @ https://twitter.com/JKempEnergy where he seems to post much of what he otherwise emails...
Two Ohio coal-fired plants to close, deepening industry decline | Reuters: Electricity company Dayton Power & Light said on Monday it would shut down two coal-fired power plants in southern Ohio next year for economic reasons, a setback for the ailing coal industry but a victory for environmental activists. Republican President Donald Trump promised in his election campaign to restore U.S. coal jobs that he said had been destroyed by environmental regulations put into effect by his Democratic predecessor, Barack Obama. Dayton Power & Light, a subsidiary of The AES Corporation, said in an emailed statement that it planned to close the J.M. Stuart and Killen plants by June 2018 because they would not be "economically viable beyond mid-2018." Coal demand has flagged in recent years due to competition from cheap and plentiful natural gas. The plants along the Ohio River in Adams County employ some 490 people and generate about 3,000 megawatts of power for coal. The closure follows negotiations between Dayton Power & Light, the Public Utilities Commission of Ohio and stakeholders like the environmental group the Sierra Club over whether the company should be allowed to raise electricity prices to pay for upgrades to keep the plants open. "They are by far our largest employer and it will absolutely be devastating to our community here in Ohio," Michael Pell, president of First State Bank in Winchester, Ohio, said in a telephone interview. Pell, one of several local community leaders who have lobbied to keep the plants going, has become a spokesman for Adams County on the issue. He said that as the industry moves away from coal, state and federal authorities should help the county create other jobs and clean up environmental damage from the plants.
The legacy of Ohio’s abandoned mines - Today, there are few working mines left in southeastern Ohio, but the region still bears the scar from years of extraction. Thousands of mines were opened and closed before there were any environmental protections on the books. They left their mark in the soil and in the streams. That mark can be difficult, if not impossible, to remove. The Ohio Department of Natural Resources partnered with local environmental groups, scientists, engineers and AmeriCorps volunteers to monitor 183 miles of streams, 47 miles of which they have successfully restored. The project took decades and cost more than $30 million, demonstrating the challenges of cleaning up after coal.“It’s really hard, difficult, in some cases impossible to ever restore those streams,” said Natalie Kruse, an associate professor of environmental studies at Ohio University, who was involved in the restoration effort. “We can’t just damage streams through mining and expect it to go back to the way it was.”Coal generates pollution at every stage of its life. Burning coal fuels asthma, bronchitis and global climate change. Mining operations contaminate water supplies in surrounding areas.Iron from coal deposits has colored streams orange. Sulfur has turned water more acidic, impairing its ability to support life. “When the chemistry is that bad, there’s literally no fish life,” said Marissa Lautzenheiser, a watershed coordinator at Rural Action, a nonprofit involved with the stream restoration project. “We’re struggling at reclaiming the ecosystems,” said Lautzenheiser. “Once the industry left, a lot of people didn’t even realize the area once had a lot of coal mining. It’s hard to explain to people. Most people don’t know why the water is orange.”
Bill to weaken clean energy standards progresses despite Kasich opposition - The latest proposal to weaken Ohio's clean-energy standards is on a fast track, as a key lawmaker said today that he wants to see the measure pass on the House floor within a matter of weeks. But that doesn't change the underlying reality that Gov. John Kasich opposes the plan, a stance he reiterated this week. House Bill 114 had its first hearing before the House Public Utilities Committee today. The measure says the renewable-energy mandates would become optional, and energy efficiency standards would be reduced. This is a revision to a 2008 law that set the rules, which must be followed by electricity utilities. The committee chairman, Rep. Bill Seitz, R-Cincinnati, said he intends to move quickly to pass the bill, with votes in committee and on the House floor within weeks. Opponents of the bill say the clean-energy rules should remain in place because they are good for the economy and the environment. Also, opponents note that Kasich vetoed a similar bill in December. "The House is picking a fight it can't win," said Samantha Williams, an attorney for the National Resources Defense Council. "They should be taking the lead to support an industry that employs 100,000 Ohioans and saves money for families and businesses, rather than pulling the rug out from under it." The bill's chief sponsor, Rep. Louis Blessing, R-Cincinnati, said mandates have an "inequitable nature" because some energy sources are favored over others. Lawmakers could try to override a Kasich veto, which requires a two-thirds vote. Some members wanted to attempt an override in December, but no vote took place.
FirstEnergy exec calls for 'urgent' aid - Toledo Blade — Calling warnings of the Davis-Besse nuclear power plant’s premature closure “real” and the need for a bailout “urgent,” FirstEnergy Corp.’s top nuclear official left little doubt Friday that Ottawa County’s largest employer is in trouble. Sam Belcher, FirstEnergy’s chief nuclear officer, said the utility’s other nuclear plants — the Perry nuclear plant east of Cleveland and the twin-reactor Beaver Valley complex northwest of Pittsburgh — are likewise in danger of premature closing by the summer of 2018 unless a buyer emerges or the utility gets help from legislators in Ohio and Pennsylvania. He also cited FirstEnergy’s coal-fired power plants, including its massive Sammis plant in southern Ohio and its Bruce Mansfield plant, which is also northwest of Pittsburgh. The Beaver Valley and Bruce Mansfield plants are both near Shippingport, Pa. The plants are in dire straits because of how fracking has disrupted energy markets. Coal and nuclear power generators are having trouble competing nationally against natural gas and renewable energy, especially after the oil and gas industry developed its game-changing horizontal drilling technique for fracturing, or “fracking,” shale a few years ago. That has unlocked vast reserves of previously inaccessible natural gas, dropping its price to record lows. The hit has been especially hard in Ohio, Pennsylvania, and other states with deregulated electricity markets, where competition is — by design — fiercest. “Our plants have been losing money. We’ve continued to operate them at a loss. But, at some point, those economics don’t make sense,” Mr. Belcher told The Blade during an hourlong telephone interview from his corporate office in Akron. He discussed reasons why FirstEnergy announced just before Christmas it was going to “exit competitive generation.”
Dozens protest two proposed injection wells in Brookfield - Warren Tribune Chronicle — More than three dozen people — most holding signs with slogans about the dangers of fracking — attended a rally Thursday afternoon at the Brookfield Center green to protest two proposed injection wells in the towship.The rally, which drew approximately 40 people, was organized by the Youngstown-based Frackfree America National Coalition. Highland Field Services LLC, a Pittsburgh subsidiary of Houston-based Seneca Resources Inc., is planning to drill two wastewater injection wells north of Wyngate Mobile Home Park, where at least 400 people live. Rob Boulware, manager of stakeholder relations at Highland Field Services LLC, said he understands the issue of fracking is a very passionate subject for people. “I would urge folks to take the time to go through and find some of the facts,” Boulware said. “There’s a lot of misinformation out there.”Trumbull County Commissioners and Brookfield trustees have sent letters to the Ohio Department of Natural Resources, Division of Oil and Gas, opposing the wells. The public has until Tuesday to submit their own comments to the ODNR.A petition against the injection wells was available at the rally for attendees to sign and by 2 p.m. there were approxmately 500 signatures. The petition also will be sent to the ODNR, organizers said. Bill Sawtelle, 67, of Brookfield, said he didn’t understand why the injection wells would be placed in such a populated area, especially where many residents still rely on well water that could potentially be contaminated. While the Wyngate Mobile Home Park uses city water, the road from state Route 7 to the injection well site could see dozens of trucks going past the park 24/7, Sawtelle said.
Firefighters: Increased disclosure needed for fracking emergencies - A Youngstown firefighter urged state lawmakers March 22 to require increased disclosure to emergency responders of chemicals used in horizontal hydraulic fracturing. Sil Caggiano, deputy chief for Mahoning County Hazmat, said a loophole in state law prevents firefighters and others responding to emergencies at fracking sites from accessing complete information about what they're dealing with. "We are asking our first responders to respond to emergencies without key pieces of information to accurately assess the situation and make the best decision possible to help the public .," he said. Caggiano was one of the featured speakers during a midday press conference at the Statehouse, then offered testimony later as part of budget deliberations in the Ohio House. Under current state law, companies aren't required to fully disclose all of the chemicals used as part of fracking activities, with some chemicals protected as trade secrets, Caggiano said He asked members of the Ohio House Finance Subcommittee on Agriculture Development and Natural Resources Wednesday to include an amendment in the biennial operating budget requiring disclosure of all fracking-related chemicals to first responders. "First responders have a huge responsibility to the public, and they carry this responsibility bravely despite the risks," he said in his committee testimony. "We should be striving to make their jobs easier, not putting barriers between them and the information they need to protect themselves and us." Melanie Houston, director of oil and gas for the Ohio Environmental Council, said more than 3 million Ohioans live within half a mile of oil and gas developments. "For millions of our neighbors, oil and gas activity is a fact of life," she said. "Not requiring fracking companies to disclose trade secret chemicals to those we entrust with our safety, even during a disaster, is just plain irresponsible. We must take responsible steps to ensure these communities are safe and protected."
Architect of Federal Fracking Loophole May Head Trump Environmental Council – Steve Horn - Confidential sources have told Politico that Bill Cooper — current congressional staffer and former fossil fuel industry lobbyist and attorney — is under consideration to head President Donald Trump's White House Council on Environmental Quality (CEQ).CEQ works to coordinate various federal agencies dealing with environmental and energy public policy issues and oversees the National Environmental Policy Act (NEPA) review process for proposed infrastructure projects.Cooper served as legal counsel for the U.S. House Energy and Commerce Committee on what is today known as the “Halliburton Loophole,” a clause which exempts hydraulic fracturing (“fracking”) from U.S. Environmental Protection Agency (EPA) enforcement of the Safe Drinking Water Act. The Halliburton Loophole was slipped into the Energy Policy Act of 2005 and became law under President George W. Bush. A 2005 newsletter published by the Interstate Oil and Gas Compact Commission (IOGCC) credits Cooper specifically for his work in getting the clause inserted into the bill. In a Truth in Testimony form Cooper submitted before testifying at a 2013 House Committee on Energy and Commerce hearing, he also cited the central role he played in negotiating and writing the Energy Policy Acts of 2002 and 2003, both of which had Halliburton Loophole provisions. On that form, Cooper also listed his experience as an oil and gas industry attorney.
Why rust belt states are tackling methane when Trump won't - States have different reasons for targeting methane leaks, even if they tend to draw the same conclusion at the end of the day: Methane mitigation is good for the environment and for companies on which tens of thousands of American jobs depend.This was Ohio Gov. John Kasich’s pitch when he proposed common-sense steps the Buckeye State could take to rein in oil and gas pollution.Kasich was able to avoid major opposition to the measure by pointing to environmental and political problems other states were experiencing as a result of their inaction, and by showing that it was in Ohio’s and its industry’s best interest to get ahead of the curve. “We’re going to have to have some additional regulation to make sure that industry stays safe,” he told the Ohio Chamber of Commerce in 2014. That year, the state required companies to reduce leaks at well sites. In February 2017, Ohio expanded these requirements to also cover compressor and transmission stations – the facilities that help push gas through the pipeline, and that account for about one-third of the industry’s total methane leakage. Companies, which must now check their equipment for gas leaks at new or modified equipment once a quarter, have complied and gone about their business. At the same time, new jobs are cropping up in a whole new industry focused on detecting and capping methane leaks. Across the state border in the Keystone State, public concern over hydraulic fracturing, or “fracking,” has already been growing for several years due to insufficient oversight. Environmental violations at drill sites have been well-documented by the state; Pennsylvanians have been shocked by images of oil spills, leaking tanks and dead vegetation. Not surprisingly, Pennsylvania is next in line to tackle methane waste. In January 2016, Gov. Tom Wolf announced his intent to adopt the toughest methane pollution rules in the nation. While welcomed by many, the governor’s approach to reducing methane emissions has run into resistance in the state legislature as of late. Some politicians have apparently been swayed by misleading rhetoric about the costs of reducing gas leaks, and threats that environmental protections “kill jobs.” All these lawmakers need to do, of course, is to peek across the border to Ohio, or call states out West that can attest that methane policies won’t hurt operators’ bottom line. They even spawn new job growth.
Study: Natural Gas Power Plants Emit up to 120 Times More Methane Than Previously Estimated – Steve Horn - Researchers at Purdue University and the Environmental Defense Fund have concluded in a recent study that natural gas power plants release 21–120 times more methane than earlier estimates. Published in the journal Environmental Science and Technology, the study also found that for oil refineries, emission rates were 11–90 times more than initial estimates. Natural gas, long touted as a cleaner and more climate-friendly alternative to burning coal, is obtained in the U.S. mostly via the controversial horizontal drilling method known as hydraulic fracturing (“fracking”).The scientists measured air emissions at three natural gas-fired power plants and three refineries in Utah, Indiana, and Illinois using Purdue's flying chemistry lab, the Airborne Laboratory for Atmospheric Research (ALAR). They compared their results to data from the U.S. Environmental Protection Agency’s (EPA) Greenhouse Gas Reporting Program.“Power plants currently use more than one third of natural gas consumed in the U.S. and the volume used is expected to increase as market forces drive the replacement of coal with cheaper natural gas,” the Environmental Defense Fund (EDF)said in a press release. The nonprofit commissioned and funded the study with a grant from the Afred P. Sloan Foundation.“But if natural gas is going to deliver on its promise, methane emissions due to leaks, venting, and flaring need to be kept to a minimum.”Methane is a more potent greenhouse gas than carbon dioxide but hangs around the atmosphere for a shorter time, with a global warming effect 84–87 times that of CO2 over a 20-year period, according to the EPA. “[Methane is] a better fuel all around as long as you don't spill it,” Paul Shepson, an atmospheric chemistry professor at Purdue, said in a press release. “But it doesn't take much methane leakage to ruin your whole day if you care about climate change.”
Google Street View cars are eyes on the ground for urban methane leaks - A set of Google Street View mapping cars, specially equipped with cutting-edge methane analyzers, are allowing Colorado State University researchers to "see" invisible methane leaks from natural gas lines beneath our streets. The technical and computational challenges of measuring methane, and the complex methodologies used to collect, analyze and publicize the data, are detailed in a new paper in the journal Environmental Science and Technology March 22. The groundbreaking project is led by Joe von Fischer, CSU associate professor in biology, in partnership with the non-profit Environmental Defense Fund (EDF), and Google Earth Outreach. von Fischer's CSU co-authors include researchers from statistics (Dan Cooley), atmospheric science (Russ Schumacher), and soil and crop sciences (Jay Ham), as well as experts from University of Northern Colorado and the nonprofit science collective Conservation Science Partners. Data from the project are helping utilities, regulators and advocacy groups reduce wasteful and environmentally damaging leaks faster and more cost effectively. Besides being the main ingredient in natural gas, methane is also a potent greenhouse gas, with over 80 times the warming power of carbon dioxide over a 20-year timeframe. Growing awareness of this climate risk has spurred new interest in finding and fixing low-level leaks throughout the natural gas supply chain, including local utility systems, where many low-level leaks can persist for many years. That need has spawned a new kind of science.
DEP moves to prevent more fracking-induced quakes - The state Department of Environmental Protection has attached requirements to future permits of Hilcorp Energy for any fracking specific to an area of Lawrence County where mild earthquakes occurred last year. Seth Pelepko of DEP’s Bureau of Oil and Gas Planning and Program Management, addressed the relationship between Hilcorp’s drilling to four low-level earthquakes that began at about 4:15 a.m. April 25 in Mahoning, North Beaver and Union townships. “What we can say based on data that’s available ... is that this is the first time (in Pennsylvania) we have seen that spatial and temporal correlation with operator activity,” he noted, referring to the earthquakes. Patrick McConnell, acting DEP secretary, showed that the earthquakes that occurred in that area of the county on those dates registered between 1.8 and 2.3 on the Richter Scale, and were considered “microseismic.” A microseismic event registers at 3.0 or less and is generally not felt but is recorded by seismometers. Pelepko explained that the occurrences locally that day were from “an induced tectonic seismic event,” meaning that the contributing factors of the quakes were caused, and not naturally occurring. A compilation of observations suggests there was a relationship between the event and operator activities, he said. Hilcorp’s New Castle Development Pad in North Beaver Township lies within a five-mile radius of the reported epicenters. Hydraulic fracturing activities began at the pad on March 30. The Utica Shale was being hydraulically fractured at 7,900 feet below the ground surface, a separation of 2,500 to 3,000 feet from crystalline rock, he said. Hilcorp was using a technique known as “zipper fracturing,” which the DEP explained as hydraulic fracturing operations that are carried out concurrently at two horizontal well bores that are parallel and adjacent.“Hilcorp immediately and voluntarily stopped all activities and discontinued those activities indefinitely as of noon on April 25,” Pelepko said, adding that the last earthquake was on the morning of April 26. Pelepko added that the well site lies north of the Rome Trough, a noted geological feature that is an elongated depression. Fracturing there is much closer to basement rock, he said, making the area more prone to seismic activity.
Can Natural Gas Liquids save PA’s economy? - The Mariner East II pipeline, a $2.5 billion underground pipeline that runs from Ohio to Pennsylvania for more than 300 miles, is well on its way to completion.A recent study conducted by IHS Markit discusses the impact of natural gas liquids (NGL) on the region. One of those impacts, of course, is infrastructure.The Study, titled Prospects to Enhance Pennsylvania’s Opportunities in Petrochemical Manufacturing, forecasts $2.7 to 3.7 billion in investments in NGL. In addition, the region will have a “once-in-a-generation opportunity to develop and implement a strategy that will cultivate a manufacturing renaissance and transform our economy across the Commonwealth,” said Pennsylvania Gov. Tom Wolf.Wolf said that the state must continue the legacy began by Shell Pennsylvania Chemicals to invest in the state in order to “ensure that we make the most of this chance to create good paying jobs for Pennsylvanians.”So when protesters were denied a petition to halt construction of the Mariner II East Pipeline, it’s not surprising in the least. The pipeline will carry approximately 375,000 barrels of NGLs per day in the 20 inch diameter pipeline. The liquids will be fed to the Marcus Hook Industrial Complex in Southeastern Pennsylvania and other destinations for both domestic use and for export.The IHS Markit study forecast that a coordinated strategy in the Marcellus and Utica plays could lead to $3.7 billion in investment into NGL assets alone, including gas processing facilities, NGL pipelines like the Mariner East II, and storage facilities. The Team Pennsylvania Foundation and our board sponsored the IHS Markit study in partnership with DCED to help Pennsylvania maximize the in-state economic benefits of our natural gas resources by generating new, high-paying manufacturing jobs; attracting investment; growing the supply chain and output in the plastics sector; and generating state and local revenue,” said Ryan C. Unger, President and CEO of the Team Pennsylvania Foundation. “We look forward to participating in the strategic planning process as part of a cross-agency and multi-stakeholder effort to ensure that our natural resources are utilized to create jobs right here in Pennsylvania.”
Watchdog piles on criticism of offshore drilling regulator -- A watchdog is alleging numerous problems at the federal government’s offshore drilling regulator, including in its inspection and environmental stewardship programs. A new report from the Government Accountability Office (GAO) is the latest on the Interior Department’s Bureau of Safety and Environmental Enforcement (BSEE) from Congress’s watchdog, which previously identified problems ranging from revenue collection to employee retention and organizational restructuring. BSEE was created in 2011 as part of the reorganization of offshore drilling oversight following the 2010 Deepwater Horizon disaster at a BP-operated well. Since its creation, GAO has issued numerous reports finding deficiencies at the agency, which largely revolve around significant leadership problems and communication problems with lower-level employees. “Leadership seems to be a continual problem at BSEE since its formation after the Deepwater Horizon incident,” Rep. Blake FarentholdR-Texas), chairman of the House Oversight Committee subpanel with authority over Interior, said at a Tuesday hearing on the report. “The GAO has found a disconnect — and more importantly, a distrust — between BSEE headquarters and its region,” he said. “This distrust has caused significant duplication and reduced the agency’s efficiency.” The watchdog in its Tuesday report concluded that BSEE has made “limited progress” in the last five years in implementing reforms in how it oversees offshore safety and environmental compliance, including developing a “risk-based” approach to drilling inspections.
As Trump targets energy rules, oil companies downplay their impact | Reuters: President Donald Trump’s White House has said his plans to slash environmental regulations will trigger a new energy boom and help the United States drill its way to independence from foreign oil. But the top U.S. oil and gas companies have been telling their shareholders that regulations have little impact on their business, according to a Reuters review of U.S. securities filings from the top producers. In annual reports to the U.S. Securities and Exchange Commission, 13 of the 15 biggest U.S. oil and gas producers said that compliance with current regulations is not impacting their operations or their financial condition. The other two made no comment about whether their businesses were materially affected by regulation, but reported spending on compliance with environmental regulations at less than 3 percent of revenue. The dissonance raises questions about whether Trump’s war on regulation can increase domestic oil and gas output, as he has promised, or boost profits and share prices of oil and gas companies, as some investors have hoped. According to the SEC, a publicly traded company must deem a matter "material" and report it to the agency if there is a substantial likelihood that a reasonable investor would consider it important. "Materiality is a fairly low bar," said Cary Coglianese, a law professor at the University of Pennsylvania who runs the university’s research program on regulation. "Despite exaggerated claims, regulatory costs are usually a very small portion of many companies’ cost of doing business."
Mars rallies amid tighter US Gulf Coast sour crude market - With crude imports via Louisiana down 5% year on year, according to US customs data, and a tight Colombian Vasconia market, differentials for Gulf Coast sour benchmark Mars have steadily rallied since late November, according to S&P Global Platts data. Platts assessed prompt Mars at WTI minus $1.55/b on Monday, its strongest level since February 2016. The Gulf Coast has seen less Vasconia in part due to increased exports of the Colombian grade to Asia, as well as tighter volumes in general, due to the Cano Limon pipeline being offline. On Monday, outright Vasconia was assessed at $47.70/b and the cost of freight to ship crude on an Aframax tanker from Covenas, Colombia to the USGC was assessed at 90 cents/b.When compared with the assessed second-month Mars outright value of $47.41/b, the economics for selling Vasconia competitively into the USGC do not line up, even if producers were able to supply higher levels of the grade. It is possible that buyers looking for Vasconia are having to replace those volumes with Mars. While Platts does not currently track Gulf Coast refining margins for Vasconia, coking margins for Mars have pushed above $11/b in February and into March.
Slow US pipeline safety reforms get caught in presidential transition: (podcast) How safe are US pipelines seven years after the fatal natural gas pipeline explosion in San Bruno, California, and the 20,000-barrel heavy crude spill in Marshall, Michigan? Regulations designed in response to the accidents moved so slowly in the Obama administration that they never reached adoption. Now the regulations stand to get caught up in the Trump administration's regulatory purge. Keith Coyle, an attorney at Babst Calland, talks with senior oil editor Meghan Gordon about what changes the industry still wants to make in those rules and what chance they have of being adopted.
Oil Giants Upending Shale Turf Where Wildcat Drillers Once Ruled -- Big Oil is muscling in on shale country. Exxon Mobil Corp., Royal Dutch Shell Plc and Chevron Corp., are jumping into American shale with gusto, planning to spend a combined $10 billion this year, up from next to nothing only a few years ago. The giants are gaining a foothold in West Texas with such projects as Bongo 76-43, a well which is being drilled 10,000 feet beneath the table-flat, sage-scented desert, and which then extends horizontally for a mile, blasting through rock to capture light crude from the sprawling Permian Basin. While the first chapter of the U.S. shale revolution belonged to wildcatters such as Harold Hamm and the late Aubrey McClendon, who parlayed borrowed money into billions, Bongo 76-43 is financed by Shell. If the big boys are successful, they’ll scramble the U.S. energy business, boost American oil production, keep prices low, and steal influence from big producers, such as Saudi Arabia. And even with their enviable balance sheets, the majors have been as relentless in transforming shale drilling into a more economical operation as the pioneering wildcatters before them. Bongo 76-43, named after an African antelope, is an example of a leaner, faster industry nicknamed “Shale 2.0” after the 2014 oil-price crash. Traditionally, oil companies drilled one well per pad—the flat area they clear to put in the rig. At Bongo 76-43, Shell is drilling five wells in a single pad for the first time, each about 20 feet apart. That saves money otherwise spent moving rigs from site to site. Shell said it’s now able to drill 16 wells with a single rig every year, up from six in 2013. With multiple wells on the same pad, a single fracking crew can work several weeks consecutively without having to travel from one pad to other. At Bongo 76-43, Shell is using three times more sand and fluids to break up the shale, a process called fracking, than it did four years ago. The company said it spends about $5.5 million per well today in the Permian, down nearly 60 percent from 2013.
All drill, no frack: U.S. shale leaves thousands of wells unfinished | Reuters: U.S. shale producers are drilling at the highest rate in 18 months but have left a record number of wells unfinished in the largest oilfield in the country – a sign that output may not rise as swiftly as drilling activity would indicate. Rising U.S. shale output has rattled OPEC's most influential exporter Saudi Arabia and pushed oil prices to a near four-month low on Wednesday. U.S. production gains are frustrating Saudi-led attempts by the world's top oil exporters to cut supply, drain record-high inventories and lift prices. Investors watch data on the number of rigs deployed in North American oil and gas fields as a leading indicator for output. But the rising rig count and frenetic drilling activity in the Permian Basin in West Texas is not all about pumping oil. During the 2014-2016 downturn in global oil prices, the number of wells left incomplete grew as companies shut down rigs, laid off workers and retreated from the fields. When prices picked up, operators were expected to pump the oil from those incomplete wells before spending money on drilling new ones. Instead, the number of incomplete wells has risen. A record 1,764 wells were left unfinished in the Permian in February, according to U.S. government data going back to December 2013. In February alone, 395 wells were drilled and only 300 completed. That was the highest drilling rate in the Permian in two years. The surprise surge in unfinished wells indicates that investors, traders and oil market players may need to reinterpret rig count data. "You would now be looking at the number of wells drilled and the uncompleted wells and not necessarily the rig count,"
Marathon buys bolt-on 21,000 acres of Permian - Marathon Oil has snapped up another 21,000 acres of Permian basin for $700million in cash.It brings the American operators position in the oil rich area to over 90,000 net acres.The latest acreage to added to the firm’s portfolio is largely in the Northern Delaware basin of New Mexico and was bought from Black Mountain Oil & Gas and other private sellers.Marathon Oil President and CEO Lee Tillman said: “Today’s 21,000 acre bolt-on in the Northern Delaware is an excellent fit with the basin entry acquisition we announced earlier this month. “The combined deals provide us more than 90,000 acres in the Permian, over 70,000 of which is concentrated in the Northern Delaware,” .“While we expect to pursue additional trades and grassroots leasing, this bolt-on achieves the scale necessary for efficient long-term development in the basin.”The Black Mountain acquisition is expected to close in second quarter 2017 with an effective date of March 1, 2017.
Texas challenges PHMSA underground natural gas storage rule - The Texas attorney general Friday challenged the authority of the US Pipeline Hazardous Materials Safety Administration to enact a rule to regulate underground natural gas storage facilities. Attorney General Ken Paxton filed a petition for review in the 5th Circuit Court of Appeals of the rule, which PHMSA crafted in the aftermath of the massive methane release from the Aliso Canyon storage facility in California in 2015. Paxton claims the final rule, which took effect on January 18, improperly overrides the state's authority to regulate underground storage under the Texas Railroad Commission. "Without completing any notice or comment period, the PHMSA unilaterally and impermissibly converted the American Petroleum Institute's non-mandatory recommendation into mandatory provision," Paxton said in a statement."Despite state laws and programs that regulate these facilities with respect to conservation, environmental protection and protection of property rights, the PHMSA effectively stripped the states of authority over their own natural gas facilities and completely disregarded traditional state regulatory roles," he said. According to the TRC, there are 18 salt cavern storage facilities and 13 facilities that store natural gas in depleted underground reservoirs in Texas. Under the PHMSA final rule the commission would be required to fully adopt PHMSA's regulation of those facilities, Paxton said. The , which was filed within 90 days of the date of publication of the final rule in the Federal Register on December 19, challenges the rule s "arbitrary, capricious, an abuse of discretion, or otherwise not in accordance with the law."
After fracking-caused earthquakes, Pawnee Nation courts to try energy companies - For nearly three decades prior to 2008, Oklahoma averaged only two earthquakes a year of magnitude 2.7 or higher. Then the state experienced a boom in hydraulic fracturing, or fracking. By 2014 the annual number of reported earthquakes had spiked to around 2,500.In 2015 earthquakes in Oklahoma nearly doubled to 4,000, including 857 with a magnitude 3.0 or higher — amounting to more than in the rest of the lower 48 states combined. The quakes, more than three a day, were linked to the underground disposal of wastewater, a byproduct of fracking for oil and gas. After Oklahoma restricted the number and volume of wastewater injection wells, the number of earthquakes dropped to 2,500 in 2016. However, in September 2016 a 5.8-magnitude earthquake struck nine miles from the center of the Pawnee Nation in north-central Oklahoma. It caused extensive damage to buildings in the town of Pawnee, which has about 2,200 residents. The Oklahoma Corporation Commission responded by shutting down 37 injection wells within a 725-square-mile radius of the epicenter. The Pawnee Nation responded March 4 by filing a lawsuit accusing 27 oil and gas companies with causing the earthquakes.The Indigenous tribe is seeking compensation for damage to hundreds of homes and public property, including the former Pawnee Nation Indian School, a nearly 100-year-old building listed in the National Register of Historic Places. The lawsuit is also seeking punitive damages. While other lawsuits have been filed against the gas and oil industry for earthquake-related damage in Oklahoma, what makes this case unique is that it will be heard in the tribe’s district court. The jury will be selected from 3,200 members of the Pawnee Nation.If the oil and gas company defendants appeal the jury’s decision, a five-member tribal Supreme Court gets to hear the case, and their decision will be final. The tribal court’s judgment will then go to a state district court for enforcement. There is no appeal of a tribal supreme court ruling. In 2016 the U.S. Supreme Court upheld the authority of Native American courts to judge complaints against nontribal entities.
SCOOP/STACK gas takeaway needs and the Midship announcement. --Cheniere Energy last Friday announced it has signed precedent agreements (firm capacity deals) with foundation shippers for its 1.4-Bcf/d Midship Pipeline project, which is targeted for an early 2019 in-service date. The announcement marks the latest milestone for midstream companies looking to move natural gas production from the SCOOP/STACK shale plays in central Oklahoma to growing demand markets in the Southeast and along the Texas Gulf Coast. Production from SCOOP and STACK grew by 1.0 Bcf/d, or 60%, in the past three years to 2.7 Bcf/d in 2016 and is expected to grow by another 1.5 Bcf/d by 2021. Besides Midship, there are other projects vying to move SCOOP/STACK gas to market. But how much capacity is really needed and by when? Today we look at the Midship project and its role in alleviating potential takeaway constraints. We’ve written extensively in recent weeks about the growing interest in Oklahoma’s South Central Oklahoma Oil Province (SCOOP) and Sooner Trend Anadarko Canadian Kingfisher (STACK) shale plays. Cheniere’s announcement is the latest confirmation that the market is gearing up for substantial natural gas production growth out of the SCOOP/STACK shale plays. As we’ve described in our “Stardust” blog series, the SCOOP and STACK have emerged as two of the fastest growing shale producing regions in the U.S. Drilling activity in this 11-county tract of central Oklahoma primarily targets crude oil, natural gas liquids (NGLs) and condensates in the Woodford and Meramec formations of the Anadarko Basin (see Scoop-y Doo and All Come to Look for a Meramec), but that brings with it significant volumes of associated natural gas. The value-add of multiple product streams, combined with the well performance and drilling efficiencies achieved in the region, provide some of the most attractive economics in the country for producers, including healthy double-digit internal rates of return (IRRs)—even at sub-$50/bbl crude oil prices. Related analysis of breakeven gas price also shows that even if oil were to drop to $30/bbl and gas prices fell to zero, producers in several of the best counties in SCOOP and STACK still would at least break even (see Part 3).
Forecasting lease operating expenses in the E&P sector, part 3. -- As we have noted in Been Down So Long, You Go Your Way, I’ll Go Mine, and Different Strokes by Different Folks, there has been a sharp decline in E&P capital spending over the past two years. But the decline in production during 2016 was nowhere near the magnitude of the capital-spending cut, and over the past few months U.S. production has been on the upswing. That’s in part because producers have improved their economics through enhancements in drilling and completion (D&C) efficiencies and a focus on production “sweet spots”. This has allowed many E&Ps to survive—and even thrive—during this period of lower prices (see Top 10 RBN Energy Prognostications for 2017, #8). But capital spending is only one part of the story on costs. LOEs also play an essential role when it comes to assessing an E&P’s overall financial health. In Part 1 of this blog series, we covered the basics of what LOEs are (what’s in the LOEs “basket”), why they matter, and why reported LOEs should never be taken at face value. We also provided a clear definition of LOEs to guide us through the process of determining what should and shouldn’t be included in LOEs:Lease operating expenses are the direct and indirect costs incurred to maintain the production of a well on the path (trajectory along decline curve) consistent with the capital investment history of the well. In Part 2, we considered the full scope of LOEs, and provided a table that showed common LOE accounts and explained what types of expenses are included within each of them. We also noted that one category of LOEs—Bulk Fluid Expenses—includes the cost of dealing with the sometimes very large volumes of produced water (wastewater) that come out of the ground with crude oil, natural gas and natural gas liquids (NGLs). As we’ll get to in a bit, produced water disposal costs have become a major and in some cases critically important element of LOEs, particularly in plays like the Permian Basin and Mississippi Lime where the ratio of produced water to crude produced is quite high.
Mammoth's Dealmaking Guarantees Frack Crews 'Always Have Sand' - Natural Gas Intelligence --Oklahoma City-based Mammoth Energy Services Inc., which has seen a mad dash for sand since the start of the year, has snapped up three U.S. oilfield service suppliers, including a major sand operator, to ensure it can feed its fracture crews in Appalachia and Oklahoma's stacked reservoirs.Mammoth is acquiring Sturgeon Acquisitions LLC, which owns Taylor Frac LLC, Taylor Real Estate Investments LLC and South River Road LLC, as well as Stingray Energy Services LLC and Stingray Cementing LLC. The all-stock deal, valued at $133.8 million, should be completed in May.The Stingray businesses operate primarily in the Northeast and would add water transfer, refueling, equipment rentals and cementing to Mammoth's portfolio. Taylor, now a major sand supplier for Mammoth in Appalachia, is the linchpin of the deal, CEO Arty Straehla said during a conference call."We want to make sure our fracking crews always have sand. The market has tightened to a position where we had to do that so we could pull in and supply ourselves."Because of the "increasing demand for sand" by North America's unconventional producers, "we believe this will differentiate our service offering, giving our customers confidence that their wells will be completed without the need to source sand from third-parties," he said.Mammoth's deal is coming in ared-hot market for proppant. As the oil and natural gas recovery has taken hold in North America, sand operators are reporting better-than-expected demand, which in turn is driving up sand pricing and tightening the transportation market.
Fracking Sand Update -- WSJ -- March 23, 2017 --This story has been reported on the blog for at least the past two years -- it began with an article by Mike Filloon. He was a bit early perhaps but now everyone is reporting it: the latest threat to US oil drillers -- the rocketing price of sand. At The Wall Street Journal:
- pushing towards $40/ton
- up from $15 to $20/ton in 2H16
- demand could outstrip supply by 2018 (next year)
- sector will need 120 million tons, double the demand in 2014 at the height of the US drilling boom
- accounts for 5% to 7% of the cost of a well 4Q16
- in 3Q14: record at $50/ton
- Permian: 2,000 lbs/foot on wells that measured 5,500 feet
- Louisiana: Chesapeake record -- 50.2 million lbs; well roughly 1.8 miles long (typical length for a long lateral in the Bakken)
- Pioneer: has its own sand mines; will test at 3,000 lbs/foot this year (2017)
- 5 million lbs: 100 railcars
- West Texas: using twice that amount/well -- requires two mile-long unit trains (a unit train = 100 boxcars)
Repeal of Obama drilling rule stalls in the Senate - The GOP’s effort to roll back contentious Obama-era regulations is hitting a snag. Some Republican senators are coming out against a resolution that would repeal an Interior Department regulation governing oil and natural gas drilling on federal land. The rule is designed to cut down on the release of methane, a potent greenhouse gas. A measure canceling the rule passed the House in February on a vote of 221-191. That’s the slimmest margin for any of the resolutions the House GOP has passed this year under the Congressional Review Act (CRA) reversing regulations from the Obama administration. Despite support from Senate leadership and the oil and gas industry, the methane legislation has not come up for a vote in the upper chamber, and its future there is uncertain. Sen. Lindsey Graham (R-S.C.) told The Hill that a CRA resolution, which prevents the government from writing any future rule that is “substantially the same” as the one overturned, is too blunt an instrument in this case. “I think we can replace it with a better reg, rather than a CRA,” Graham said. Sen. Susan Collins (R-Maine) said she is “leaning against” the resolution. “I have not made a final decision, but I am leaning against it based on what I’ve heard so far,” Collins said last week.
Historic Win in Colorado Fracking Lawsuit - In a 2-1 decision Thursday, the Colorado Court of Appeals reversed the Colorado Oil and Gas Conservation Commission's order denying a youth-brought rulemaking petition against fracking and a lower court's order upholding the denial. The court remanded the case to the district court and the commission, finding that the commission erred in its interpretation of Colorado law: "We therefore conclude that the commission erred in interpreting [the Oil and Gas Conservation Act] as requiring a balance between development and public health, safety and welfare." "The clear language of the act ... mandates that the development of oil and gas in Colorado be regulated subject to the protection of public health, safety and welfare, including protection of the environment and wildlife resources." The commission had argued that the Oil and Gas Conservation Act required it to strike a balance between the regulation of oil and gas operations and protecting public health, the environment and wildlife resources. The six plaintiffs in the case are members of the Boulder-based youth group Earth Guardians . The youth hand-delivered their petition for rulemaking in November 2013 to the commission. Their petition asked the commission to develop and implement a rule to stop the permitting of fracking until and if, oil and gas development can be done without causing harm to humans and without impairing Colorado's natural resources, including atmospheric resources and climate change . "By its decision today, the court has concluded that the commission has full statutory authority to adopt Petitioner's proposed rule," Julia Olson, plaintiffs' counsel and executive director of Our Children's Trust , said. "The commission can no longer decide to prioritize oil and gas development over the health and safety of Coloradans. This is an enormous victory for these youth. We look forward to helping the youth of Colorado go back before the commission on remand."
2016 Colorado Oil and Gas Toxic Release Tracker - In 2016, oil and gas companies reported more than 500 spills in Colorado. Publicly available data from the Colorado Oil and Gas Conservation Commission (COGCC) indicates there were 509 spills in 2016, more than one per day. The number of spills last year marked a decline from the 615 reported spills and incidents in 2015, reflecting the decrease in drilling activity. As drilling and production increase in Colorado — which is expected as the price of oil and gas may increase in the coming years — we also expect to see spills increase. Monitoring these incidents help to inform Coloradans about the impacts of oil and gas development within the state.In 2016, operators reported 257 spills of “produced water,” salty wastewater often laden with toxic chemicals, along with 115 spills involving oil and 60 spills of condensate. Noble Energy reported the most spills, followed by Kerr McGee and Pioneer Natural Resources. Combined, the five companies reporting the most spills accounted for nearly half of all incident reports. The vast majority of spills reported, 82 percent, took place on private land. Nearly half of all spills took place in Weld County. In reporting oil and gas spills, Colorado requires companies to disclose the distance from livestock, wetlands and occupied buildings, something not required by neighboring states, such as New Mexico and Wyoming.Nearly 32 percent of all spills occurred within 1,500 feet of an occupied building, including 50 incidents that occurred less than 500 feet from an occupied building. 58 incidents reported impacts to groundwater and 200 incidents occurred within 1,500 feet of a water well.
Fracking led to more than 6,000 spills in 10 years, study finds —Spills related to fracking are more frequent than previously thought, a new study finds – and understanding the causes of these spills may help prevent future incidents.In a study published Tuesday in the journal Environmental Science & Technology, a team of researchers identified 6,648 spills in Colorado, New Mexico, North Dakota, and Pennsylvania between 2005 and 2014. The researchers calculated that between 2 and 16 percent of wells will spill contaminated water, hydraulic fracturing fluids, or other substances every year, with the majority of incidents occurring in the first three years after a well becomes operational. The definition of a spill varies from state to state, presenting a challenge for the study’s authors in comparing states. But analyzing this data, they say, is vital to addressing the challenges posed by fracking spills and makes a data-driven conversation about fracking possible.“Analyses like this one are so important, to define and mitigate risk to water supplies and human health,” said Kate Konschnik, director of the Harvard Law School’s Environmental Policy Initiative, in a Duke University news release. “Writing state reporting rules with these factors in mind is critical, to ensure that the right data are available – and in an accessible format – for industry, states and the research community.” In its report about the safety of fracking, the US Environmental Protection Agency did not quantify the risk posed by the resource extraction technique, The Christian Science Monitor reported in December. It did, however, point to several cases of drinking water contamination, concluding that there was insufficient evidence to know how widespread a problem contamination was. The EPA itself identified 457 spills across 8 states between 2006 and 2012, because it focused solely on the period when fracking was taking place, rather than looking at the entire life of the well. By providing more comprehensive data on the number of spills, the recent report may offer a starting point for determining the scope of contamination.
North Dakota Oil Spill Vastly Underestimated as Trump Approves KXL - The amount of crude oil that spewed near Belfield, North Dakota from the ruptured Belle Fourche pipeline in December was vastly underestimated. The original estimate was around 176,000 gallons of oil. After further review, pipeline operator True Companies now reports about 12,615 barrels (529,830 gallons) of oil spilled, spokeswoman Wendy Owen told Inforum . The cause of the leak has not been determined. The spill contaminated a hillside and Ash Coulee Creek which empties into the Little Missouri River. The break was also significant because it happened less than 200 miles away from the Oceti Sakowin Camp, where Water Protectors were protesting the heavily contested Dakota Access Pipeline (DAPL). The new number makes the Belle Fourche spill one of the largest in state history and perhaps the largest oil pipeline spill that contaminated a North Dakota water body, Bill Suess, spill investigation program manager for the state's Department of Health, told Inforum. North Dakota's largest spill happened in September 2013 when a Tesoro Corp. pipeline leaked about 840,000 gallons of fracked oil in a wheat field near Tioga, causing one of the biggest onshore oil spills in recent U.S. history. That spill has still not been cleaned up more than three years later.
Appeals Court Refuses to Stop Oil in Dakota Access Pipeline - (AP) — An appeals court on Saturday refused a request from two American Indian tribes for an "emergency" order that would prevent oil from flowing through Dakota Access pipeline. The decision by the U.S. Court of Appeals for the District of Columbia Circuit means the $3.8 billion pipeline to move North Dakota oil to a distribution point in Illinois could be operating as early as Monday, even as the tribes' lawsuit challenging the project moves forward.The Standing Rock and Cheyenne River Sioux tribes have challenged an earlier ruling by U.S. District Judge James Boasberg not to stop final construction of the pipeline, and they wanted the appeals court to halt any oil flow until that's resolved.The appeals court said the tribes hadn't met "the stringent requirements" for such an order.The tribes had asked Boasberg to direct the Army Corps of Engineers to withdraw permission for Dallas-based developer Energy Transfer Partners to lay pipe under Lake Oahe in North Dakota, which the Corps manages for the U.S. government. The stretch under the Missouri River reservoir is the last piece of construction for the pipeline.The company is wrapping up pipe work under the lake and has said oil could start flowing between Monday and Wednesday.The tribes fear the pipeline could harm their water supply and their right to practice their religion, which relies on clean water. ETP disputes that. The tribes' appeal rests on the religion argument. Boasberg has said he doesn't think the tribes have a strong case on appeal. He also said ETP would be "substantially harmed" by a delay in pipeline operations.
Company: Dakota Access pipeline on track, despite 'threats' (AP) — The company building the Dakota Access pipeline said Monday that the project remains on track to start moving oil this week despite recent "coordinated physical attacks" along the line. The brief court filing late Monday from Dallas-based Energy Transfer Partners didn't detail the attacks, but said they "pose threats to life, physical safety and the environment." The filing cited those threats for redacting much of the rest of the 2½-page report, but ended: "These coordinated attacks will not stop line-fill operations. With that in mind, the company now believes that oil may flow sometime this week." A spokeswoman for the company declined to elaborate on the types of attacks. A spokesman for the Morton County sheriff's office, the center of months of sometimes violent conflicts between protesters and law enforcement, didn't immediately respond to an email. The Standing Rock and Cheyenne River Sioux tribes have battled the $3.8 billion pipeline in court for months, arguing it's a threat to water and their right to practice their religion. The company has maintained the pipeline, which will move oil from North Dakota's Bakken oil field more than 1,000 miles across four states to a shipping point in Illinois, will be safe.An appeals court on Saturday refused a request from the tribes for an emergency order to prevent oil from flowing through the pipeline. The tribes have challenged an earlier ruling by U.S. District Judge James Boasberg not to stop final construction of the pipeline, and they wanted the appeals court to halt any oil flow until that's resolved. The appeals court said the tribes hadn't met "the stringent requirements" for such an order.
Dakota Access pipeline vandalism highlights sabotage risks -The developer of the Dakota Access pipeline has reported "recent coordinated physical attacks" on the much-protested line, just as it's almost ready to carry oil. Texas-based Energy Transfer Partners didn't give details, but experts say Dakota Access and the rest of the nearly 3 million miles of pipeline that deliver natural gas and petroleum in the U.S. are vulnerable to acts of sabotage. It's a threat that ETP takes seriously enough that it has asked a court to shield details such as spill response plans and features of the four-state pipeline that the company fears could be used against it by activists or terrorists. Authorities in South Dakota and Iowa confirmed Tuesday that someone apparently used a torch to burn a hole through empty sections of the pipeline at aboveground shut-off valve sites. Mahaska County Sheriff Russell Van Renterghem said the culprit in Iowa appeared to have gotten under a fence around the facility, but Lincoln County Sheriff's Deputy Chad Brown said the site in South Dakota wasn't fenced. The Iowa incident was discovered March 13 and the South Dakota incident Friday. Because pipelines mainly run underground, aboveground shut-off valves are natural targets, according to Jay O'Hara, a spokesman for the environmental group Climate Direct Action. That group targeted valves on pipelines in October in North Dakota, Minnesota, Montana and Washington state, though the pipeline companies said activists didn't succeed because none of the sites were operating when the attacks happened. Explosives, firearms and heavy machinery also have been used to try to sabotage pipelines. Securing pipelines is difficult because they often travel long distances through remote and even uninhabited territory, said Kerry Sundberg, a professor at Mount Royal University in Calgary, Alberta, who studies energy infrastructure security and environmental crime. Sundberg said "it's stupid and dangerous" to tamper with pipeline shut-off valves. Modern oil pipelines are "incredibly sophisticated" systems that move huge volumes of petrochemicals at high pressures, he said. Simply closing a valve can cause the pressure upstream to increase quickly, creating a significant risk of a spill that endangers the environment and anyone in the area where the pipe suddenly bursts, he said.
California regulator to vote on United States' strictest methane rule - (Reuters) - California's air pollution regulator is due to hold a vote on Thursday on methane emission regulations that it says would be the strictest in the United States in controlling the second-most prevalent greenhouse gas in the atmosphere.The new standards, proposed by the California Air Resources Board, would tighten efficiency requirements in the production and transportation of natural gas, and also for some oil-handling equipment, and would mandate prompt repair of discovered leaks, said Dave Clegern, a spokesman for the board.The regulations are expected to pass Thursday's vote by the board, people familiar with the process told Reuters.In October 2015, the massive Aliso Canyon natural gas leak forced thousands to evacuate in Los Angeles' Porter Ranch area. It took nearly four months to plug and has been estimated to have had a larger climate impact than the 2010 Deepwater Horizon oil spill.Methane, the main component of commercially distributed natural gas, is produced at dedicated wells and during the extraction of oil. Pound for pound, it traps significantly more heat in the atmosphere than carbon dioxide, the most prevalent greenhouse gas.Thursday's vote comes shortly after U.S. President Donald Trump proposed major cuts to the Environmental Protection Agency's budget and as the U.S. Senate prepares to vote on repealing a rule limiting methane venting and leaking on federal and tribal lands.Clegern said the timing of the vote was unintentional and that it followed years of active work on the measure.“If the federal government won’t protect the people and the environment from oil and gas pollution, it has to be up to the states,” said Tim O’Connor, a director at the Environmental Defense Fund, which worked with the agency on the rule.
California just put serious limits on methane leaks - The California Air Resources Board voted unanimously on Thursday to enact regulations that will curb the amount of methane the oil and gas industry can leak and vent during production and storage. The new rule — years in the making — requires oil and gas companies to monitor infrastructure and repair leaks. It is a massive step forward for California’s air quality programs, advocates say, and it is the strictest in the nation. The Air Resources Board expects the new rule will reduce methane leaks by 45 percent over the next nine years. The oil and gas industry contributes about a third of the United States’ overall methane emissions. Not only is methane a powerful greenhouse gas, trapping heat 86 times more effectively than carbon dioxide over a 20-year span, but leaking and flaring natural gas also adds benzene (a carcinogen) and NOx compounds (which create ground-level ozone) into the air we breathe. Still, the environmental dangers of leaking methane haven’t stopped Congress or Trump’s Environmental Protection Agency (EPA) from taking steps this year to reduce accountability from the oil and gas industry. In February, the House passed a Congressional Review Act to rescind a Bureau of Land Management rule that required oil and gas operators on public lands to limit their methane leaks and flaring. EPA Administrator Scott Pruitt, who opposed the methane rule in his previous role as Oklahoma attorney general, has also rescinded a request for information from oil and gas operations that would have been used for the EPA to develop rules that could have applied to existing infrastructure.
Another Cook Inlet pipeline feared to be vulnerable, as gas continues to leak - As the wait continues for the ice to melt in Alaska's Cook Inlet so a months-long underwater natural gas pipeline leak can be halted, federal regulators are now raising concerns about an adjacent pipeline owned by the same company. That one carries an even bigger environmental threat: oil.The Pipeline and Hazardous Materials Administration (PHMSA) warned that a 52-year-old oil pipeline could be vulnerable to the same forces that caused the natural gas pipeline to crack and start leaking in late December. The agency ordered the company to conduct inspections beyond its regular oversight and shut down the oil pipeline if deemed unsafe."It appears that conditions exist on the MSG Hazardous Liquid System that pose a pipeline integrity risk to public safety, property or the environment," wrote Chris Hoidal, the western region director of PHMSA.Brutal weather conditions in Cook Inlet—extreme tides, forceful currents and floating ice—are particularly harsh on oil and gas infrastructure, as well as workers.Hilcorp Alaska owns the pipelines and the four oil platforms they connect to. Pipeline A carries the gas that powers the platforms. It is spewing almost pure methane into the inlet. Two of the oil platforms are manned 24 hours a day and pump a combination of oil and water, which is carried back to shore via Pipeline B. "If a leak or rupture of 'B Pipeline' occurred, the environmental damage has the potential to be significantly greater than the presently-known environmental damage from the leak occurring on the 'A Pipeline,'" Hoidal wrote in the letter to Hilcorp. The agency previously orderedHilcorp to fix Pipeline A by May 1 or shut it down, as well as carry out rigorous safety tests.
There’s almost zero rationale for Arctic oil exploration, says Goldman Sachs analyst: Drilling the Arctic region for oil cannot be justified against the background of the major shift in the global oil production paradigm, Goldman Sachs' lead European commodities equity specialist said on Thursday. "Overall the idea that we have to go into the Arctic to find new resources I think has been dispelled by the enormous cheap, easier to produce and quicker time-to-market resources in the Permian onshore U.S.," Michele Della Vigna, commodity equity business unit leader in EMEA at Goldman Sachs, told CNBC's Squawk Box on Thursday. "We think there is almost no rationale for Arctic exploration," he asserted, noting that while certain areas, such as the Russian Arctic, potentially have workable elements given that the location is much closer to the coast and easier to explore, other areas, such as Alaska, can fairly be considered more in the vein of vanity projects. "Immensely complex, expensive projects like the Arctic we think can move too high on the cost curve to be economically doable," Della Vigna explained, pointing to a new "oil order" as represented by a much shorter and cheaper production cycle driven by the U.S.Della Vigna sees rapid ongoing progress being made in power generation, where he says wind and solar energy systems in different regions are already perfectly competitive - even without subsidies - and are now taking more than 1 percent market share each year. The Goldman Sachs specialist noted that these sources of renewable energy are clearly winning out against hydrocarbons. He also pointed to the oversupply of gas, a dynamic which he sees persisting for the next 5 – 6 years due to "massive" LNG (liquid natural gas) capacity coming onstream from the U.S. and Australia, as lowering the price of that energy source. "We think cheap gas with more competitive renewables will be the perfect combination to lower the carbon footprint of the world and shift away a lot of the demand from coal. Coal is going to be the stranded asset," he predicted.
Trump says he told aide to threaten Keystone XL pipeline company over arbitration case - President Trump ordered one of his top economic advisers to threaten a pipeline company that he would “terminate” a project if they didn’t drop what he described as a “$14 billion” lawsuit against the United States, the president told a crowd on Tuesday night. Trump, in a speech at a fundraiser in Washington, said the directive was given to National Economic Council Director Gary Cohn, a former president of Goldman Sachs, though he didn’t specify which company was being told to drop their lawsuit. Trump said the company did drop the lawsuit, adding “Isn’t that easier?” “Being president gives you great power,” Trump said. Cohn has emerged as one of Trump’s top advisers, with an expanding portfolio that includes virtually all economic and jobs-related issues. Trump has personally threatened several companies since winning the election, telling Boeing and Lockheed Martin for example that he might block some of their contracts, but this is the first time he’s revealed ordering a top adviser to deliver such a message. In June, TransCanada, the Canadian firm that has tried to develop the Keystone XL pipeline since 2008, filed a $15 billion claim against the United States, alleging the Obama administration’s refusal to allow the construction of the pipeline was “based on an arbitrary political calculation.” The claim alleged that blocking the pipeline deal was a violation of the North American Free Trade Agreement, and the case was filed in the International Center for the Settlement of Investment Disputes.
Trump State Department to Approve Keystone XL Pipeline Permit by Monday - Nearly a decade after it first applied for a presidential permit, TransCanada is getting the green light from the Trump administration for its $8 billion Keystone XL pipeline . POLITICO reported that the U.S. State Department's undersecretary for political affairs, Tom Shannon, will approve by Monday the cross-border permit needed for the project to proceed. Sec. of State Rex Tillerson , former ExxonMobil CEO, recused himself from the Keystone decision since Exxon stands to profit from the pipeline. The Keystone XL was blocked by President Obama two years ago because the pipeline would "not serve the national interests" of the United States. But the November election changed everything. On Jan. 24, President Trump signed an executive order that invited TransCanada to reapply for a presidential permit. The company did so two days later. Environmental groups and grassroots citizens have long opposed the pipeline, painting it as a symbol of the threat of climate change . Once complete, the 1,200-mile pipeline will carry Alberta tar sands to processing and export facilities in the southern U.S.
Trump administration grants approval for Keystone XL pipeline - President Trump announced Friday morning the granting of a permit for construction of the controversial Keystone XL pipeline, calling it “the first of many infrastructure projects” that he would approve in order to put more Americans to work. The $8 billion project would span 900 miles, connecting Alberta’s massive tar sands crude with pipelines and refineries on the Texas gulf coast. The State Department, as instructed in Trump’s presidential memorandum of Jan. 24, relied on the supplemental environmental impact statement issued in January 2014. In that analysis, the State Department, which oversees applications for cross-border pipelines, had concluded that the tar sands would be developed with or without the pipeline and that as a result the decision would not affect climate change. The department said Friday that “there are no substantial changes or significant new information which affect the continued reliability” of that report. “This is a significant milestone for the Keystone XL project,” Russ Girling, TransCanada’s president and chief executive, said in a video release early Friday. “We greatly appreciate President Trump’s administration for reviewing and approving this important initiative, and we look forward to working with them as we continue to invest in and strengthen North America’s energy infrastructure.”
Trump approves Keystone pipeline | TheHill: The Trump administration gave the Keystone XL pipeline its key federal permit Friday, clearing a major hurdle for the project that former President Barack Obama rejected in 2015. The State Department announced Friday morning that its under secretary for political affairs, Tom Shannon, issued the permit, two months after President Trump signed a memorandum to revive the project after Obama’s rejection. “In making his determination that issuance of this permit would serve the national interest, the under secretary considered a range of factors, including but not limited to foreign policy; energy security; environmental, cultural, and economic impacts; and compliance with applicable law and policy,” State said. The decision closes a significant chapter in the long-running saga over the controversial oil sands pipeline, which has been a flashpoint in the debate surrounding climate change and dependence on foreign oil. Obama rejected the application in November 2015, arguing, in part, that it would harm the United States' standing in the world as a leader in fighting climate change. “Ultimately, if we’re going to prevent large parts of this Earth from becoming not only inhospitable but uninhabitable in our lifetimes, we’re going to have to keep some fossil fuels in the ground rather than burn them and release more dangerous pollution into the sky,” he said at the time.
How drag-reducing agents (DRAs) are changing the economics of pipeline takeaway capacity - The ability to increase the capacity of existing and planned crude oil pipelines with minimal capital expense has genuine appeal to midstream companies, producers and shippers alike. Enter drag reducing agents: special, long-chain polymers that are injected into crude oil pipelines to reduce turbulence, and thereby increase the pipes’ capacity, trim pumping costs or a combination of the two. DRAs are used extensively on refined products pipelines too. Today we continue our look at efforts to optimize pipeline efficiency and minimize capex through the expanded use of crude-oil and refined-product flow improvers.
API: US petroleum demand highest for February since 2008 - Oil & Gas Journal: Total US petroleum deliveries, a measure of demand, moved up 0.1% in February compared with a year ago to average 19.7 million b/d, marking the highest February deliveries since 2008, according to the latest report from the American Petroleum Institute. Total petroleum deliveries also increased in February compared with the month before, rising 2.2%. For year-to-date, total US petroleum deliveries increased 0.7% compared with the same period last year, API said. The overall US economy showed gains for the second time in the year, adding 235,000 jobs, according to the US Bureau of Labor Statistics. The unemployment rate changed little at 4.7% in February. Gasoline deliveries, a measure of consumer gasoline demand, were up in February vs. the previous month, but down from the prior year as well as the prior year-to-date. Total motor gasoline deliveries decreased 3.8% from February 2016 to average 8.9 million b/d—the second highest February demand in 9 years. “Crude oil production broke the 9 million-b/d threshold for the first time since March 2016. This increase in production combined with more widespread jobs gains is good news for the economy, which appears to be moving in the right direction,” said API Chief Economist Erica Bowman. Crude oil production increased 0.7% in February vs. January, but was down 1.3% from February 2016 to average just above 9 million b/d in February. This was the highest crude oil production for any month since March 2016. Production of natural gas liquids fell 2.7% in February vs. January but was up 2.9% from February 2016 to average 3.4 million b/d.US total petroleum imports in February averaged nearly 10.4 million b/d, down 2.7% from the prior month, but up 3.6% from the prior year. These were the highest February imports in 5 years. For year-to-date, total petroleum imports were also higher, up by 6.7% compared with year-to-date 2016.
North American Shale breakeven prices fall by 55% -- Since 2013, the average wellhead breakeven price (BEP) for key shale plays has decreased from US$80/bbl to US$35/bbl. This represents a decrease of over 55%, on average. As Figure 1 indicates, the wellhead BEP decreased across all key shale plays, with the Permian Midland experiencing the largest decrease, falling by over 60% from US$98/bbl in 2013 to US$38/bbl in 2016 (for horizontal wells only). Due to a higher average royalty, different decline profile and hydrocarbon split, the Eagle Ford experienced one of the highest wellhead BEP among the main shale oil plays in 2016. There are several reasons behind the observed drop in BEP. The drop is partly attributable to structural changes such as improved well performance (which can be measured by improvements in the EUR) and the improved efficiency gains (which can be measured by the effect of lower drilling and completion cost, a result of more effective operations). Another set of drivers behind the falling BEP can be referred to as plummeting oil price. With clear cycles describing the petroleum industry historically, the cyclical changes experienced from 2014 will be reverted with an oil price recovery. Among the key cyclical drivers for the shale wellhead BEP are high grading (measuring the effect of operators focusing their drilling operations in the best acreages) and lower unit and production costs. Even though the wellhead BEP is often considered the "raw" or "initial" breakeven, this is not the actual breakeven realized by the companies. If we include the effect of facility costs and the price discounts, we can compare the average acreage BEP across main shale plays, expressed in WTI price. As Figure 2 indicates, in this comparison, the different zones of the Eagle Ford Shale (EFS) – namely the East Oil zone, Dry Gas zone and Wet Gas/Condensate zone, have lower WTI BEP compared to the Permian Delaware's Bone Spring/Avalon or Wolfcamp formations. Note that the differences between the WTI BEP and the wellhead BEP are play-specific and can be within the range of 10-15 dollars.
E&Ps expanding stakes in the hottest plays: winners and losers. - U.S. oil and natural gas exploration and production companies, anticipating continuing low crude oil and natural gas prices, have been reshaping their portfolios to focus on a half-dozen top-notch resource plays whose production economics can hold up even through the roughest of patches. The biggest of these asset purchases and sales grab the headlines, but countless other, smaller deals are having profound effects too. Taken together, this piranha-like devouring of E&P assets in the Permian Basin, SCOOP/STACK and other key production areas is transforming who owns what in the plays that matter most, and positioning a select group of E&Ps for success. Today we review highlights from “Piranha!” —a just-released market study from RBN. If you told U.S. E&Ps three years ago, when crude oil was selling for north of $100/barrel (bbl), that most of them soon would be thriving at crude prices less than half that level they would have questioned your sanity. But that is exactly what happened. Despite predictions of widespread bankruptcies and credit defaults after the plunge in oil prices that started in the summer of 2014, most of the upstream industry has weathered the crisis remarkably well, primarily through the “high-grading” of portfolios, impressive capital discipline, and an intense focus on operational efficiencies. This has certainly been a different kind of rebound than past ones. In stark contrast to major industry consolidations that followed other price downturns, where the largest companies gobbled up smaller and weaker companies in huge merger and acquisition (M&A) deals, this cycle has been characterized instead by hundreds—if not thousands—of small transactions. E&Ps are concentrating their assets, and building out significant contiguous acreage positions in their core operating areas while generating funds for operations and acquisitions through equity offerings, debt refinancings and sales of non-core assets. The strongest and most aggressive of the U.S. E&Ps have been behaving like schools of piranha, eating away at small pieces of other companies and simultaneously fragmenting and reconstituting the E&P sector, with most successful companies focusing their resources, operations and investments on a few attractive plays where an advantageous combination of geology, geography and economics provide attractive investment returns.
U.S. crude oil exports went to more destinations in 2016 – EIA - In 2016, U.S. crude oil exports averaged 520,000 barrels per day (b/d), 55,000 b/d (12%) more than in 2015 despite a year-over-year decline in production. However, the rate of U.S. crude oil export growth has slowed significantly from its pace over 2013-15 when annual U.S. crude production grew rapidly. Meanwhile, increased crude oil imports in 2016 have substituted for some domestic crude oil at U.S. refineries, allowing for increased refinery runs despite lower production and higher exports. Following the removal of restrictions on U.S. crude oil exports in December 2015, the United States exported crude oil to 26 different countries in 2016, compared with 10 the previous year. In 2015, 92% of U.S. crude oil exports went to Canada, which was exempt from U.S. crude oil export restrictions. After the lifting of restrictions, Canada remained the top destination, but in 2016 received only 61% of U.S. crude exports (Figure 1). Aside from Canada, European destinations such as the Netherlands, Italy, the United Kingdom, and France rank high on the list of U.S crude oil export destinations. The next largest regional destination is Asia, including China, Korea, Singapore, and Japan. In 2016, the United States exported to eight different Central and South American destinations including Curacao, Colombia, and Peru (Figure 2). Some nations listed as receiving crude oil exports from the United States in EIA export statistics, such as the Marshall Islands, Bahamas, Panama, and Liberia, are unlikely to be actual final destinations. Ports in the United States are not deep or wide enough to allow safe navigation and loading of the largest and most economic ships to transport crude oil, such as Very Large Crude Carriers (VLCC). Instead, U.S. crude oil is exported on smaller vessels and is then transferred to larger vessels in deeper waters outside of port. The U.S. Customs and Border Protection documentation requires the final destination of an export to be listed, if known. In some cases, cargoes that undergo ship-to-ship transfer or that do not have a buyer prior to loading will cite the jurisdiction of the transfer or the registration flag of the vessel to which the cargo is being transferred, not the cargo's actual final destination. Many vessels are registered in nations such as the Marshall Islands, Bahamas, Liberia, and Panama—meaning the exported crude oil was likely destined elsewhere.
New projects, shale boom could trigger oil oversupply by 2018-19: Goldman | Reuters: New production projects and a fresh shale boom could boost oil output by a million barrels per day (bpd) year-on-year and result in an oversupply in the next couple of years, according to Goldman Sachs. "2017-19 is likely to see the largest increase in mega projects' production in history, as the record 2011-13 capex commitment yields fruit," the U.S. investment bank said in a research note on Tuesday. OPEC's landmark decision to limit output for the first time in eight years in a bid to arrest the existing supply glut reduced price volatility and increased stability, unintentionally helping the shale producers, the bank said. "OPEC's decision in November 2016 to cut production was rational, in our view, and fit into its role of inventory manager of last resort," Goldman said. "However, the unintended consequence was to underwrite shale activity through a bullish credit market at a time when delayed delivery of the 2011-13 capex boom could lead to record non-OPEC production growth in 2018." The Organization of the Petroleum Exporting Countries agreed to curb its output by about 1.2 million bpd from Jan. 1 this year. Russia and 10 other non-OPEC producers agreed to jointly cut by an additional 600,000 bpd. OPEC is likely to weigh the risk of long-term market share loss against the benefit of stability before taking a call on extending production curbs, with the industry expected to bring "onstream a multi-year pipeline of giant developments that tails off only by 2020," Goldman said.
U.S. Shale Is Pushing OPEC To Breaking Point -- The trend in the United States of accelerating oil production does not seem to be slowing down. Recent reports show that oil production from U.S. shale producers will increase in April, according to the Energy Information Administration. High market prices are currently being supported by OPEC cutbacks, and these higher profits are funding the growth of American drilling. The release from the EIA predicts that net oil production will increase by 109,000 barrels per day in April. The seven major oil and gas basins that were included in the report will then have an output over nearly 5 million barrels per day collectively. The monthly projections from the EIA have been climbing month after month since December. In the United States, the main benefactors have been drillers at the Permian Basin, in Western Texas and southern New Mexico. The basin has been producing high volume since the end of 2016. The EIA expects the Permian drillers to see a gain of 70,000 barrels per day next month in their projections.
OPEC Out Of Moves As Goldman Sachs Expects Another Oil Glut In 2018 - Oil prices are heading down again on swelling U.S. crude oil inventories, with Brent dropping below $50 per barrel for the first time this year. The OPEC deal that has taken more than 1 million barrels per day of oil off the market has not succeeded in reversing this bearish trend for inventories. And with the deal at its midway point, focus is shifting towards an extension of the cuts through the end of the year. But OPEC’s usual strategy of jawboning the market back up ahead of these negotiations seems to be wearing thin amid record high crude oil inventories. "OPEC has used up most of its arsenal of verbal weapons to support the market. One hundred percent compliance by all is the only tool they have left and on that account they are struggling," said Ole Hansen, head of commodity strategy at Saxo Bank. "OPEC's market intervention has not yet resulted in significant visible inventory drawdowns, and the financial markets have lost patience,"investment bank Jefferies said in a research note. Although projections from Wall Street banks tend to vary quite a bit, there is a growing chorus warning about another slide in crude prices. At this point, the big variable is whether or not OPEC decides to extend the deal when it meets in May – an extension would likely stabilize prices and might even push them back up into the mid-$50s or higher. No extension and oil could fall much further into the $40s. Looking out a bit further, things get much more complicated. Even if the supply/demand imbalance is taking a long time to correct itself, rising demand and tepid supply growth suggest that the glut will ease over time. At least that is the general consensus. However, Goldman Sachs warns that another downturn could come over the next three years, sparked by a new wave of supply stemming from megaprojects planned years ago. These projects cost billions of dollars and take many years to bring online, and many of them were initiated back when oil prices traded at $100 per barrel. “2017-19 is likely to see the largest increase in mega projects production in history, as the record 2011-13 capex commitment yields fruit,” Goldman said in a note.“This long-lead-time wave of projects and a short-cycle revival, led by U.S. shales, could create a material oversupply in 2018-19.” Goldman identified a handful of projects in Brazil, Russia, Canada and the Gulf of Mexico that will reach completion and add to global supply between 2017 and 2019. Combined with new shale output, these projects could add another 1 million barrels per day next year.
How OPEC Lost The War Against Shale, In One Chart -- At the start of March we showed a fascinating chart from Rystad Energy, demonstrating how dramatic the impact of technological efficiency on collapsing US shale production costs has been: in just the past 3 years, the wellhead breakeven price for key shale plays has collapsed from an average of $80 to the mid-$30s...... resulting in drastically lower all-in breakevens for most US shale regions. Today, in a note released by Goldman titled "OPEC: To cut or not to cut, that is the question", the firm presents a chart which shows just as graphically how exactly OPEC lost the war against US shale: in one word: the cost curve has massively flattened and extended as a result of "shale productivity" driving oil breakeven in the US from $80 to $50-$55, in the process sweeping Saudi Arabia away from the post of global oil price setter to merely inventory manager. This is how Goldman explains it: Shale’s short time to market and ongoing productivity improvements have provided an efficient answer to the industry’s decade-long search for incremental hydrocarbon resources in technically challenging, high cost areas and has kicked off a competition amongst oil producing countries to offer attractive enough contracts and tax terms to attract incremental capital. This is instigating a structural deflationary change in the oil cost curve, as shown in Exhibit 2. This shift has driven low cost OPEC producers to respond by focusing on market share, ramping up production where possible, using their own domestic resources or incentivizing higher activity from the international oil companies through more attractive contract structures and tax regimes. In the rest of the world, projects and countries have to compete for capital, trying to drive costs down to become competitive through deflation, FX and potentially lower tax rates.
Are Banks About To Derail The New U.S. Shale Boom? - Just when international oil benchmarks are sliding down, banks are preparing to review the credit lines of U.S. E&Ps. Starting in April, lenders will reassess companies’ creditworthiness on the basis of reserves, production trends, current prices, and future prospects for the industry, among others. Should anything spark worry, banks will be quick to start reducing their exposure, cutting credit lines and arresting producers’ recovery at a crucial point. This year, U.S. E&Ps have announced an overall spending increase of $25 billion from 2016, an 11-percent rise, as a clear sign of continuing optimism after the November OPEC-non-OPEC deal that aimed to shave 1.8 million barrels of crude off daily global supply. Besides boosting spending plans, producers have been adding rigs at a respectable pace: at the end of last week, active oil and gas rigs in the United States totaled 789, an increase of 313 over a year ago. They are also investing in more efficient drilling technologies, aiming for ever lower production prices in the aftermath of the oil price crash. The banks could put a stop to all this if they deem the outlook for oil prices or any other element of their assessment methodology unfavorable. For oil prices, more bad news seems to be on the way if we are to trust Goldman Sachs.The investment bank said in a note yesterday that record-high investments in 2011-2013 could start bearing fruit this year and the next two, adding around a million barrels of crude to global daily production on an annual basis in the period 2017-2019. That will only happen if the mega projects that swallowed the huge investments deliver as expected, which is by no means certain. This message contrasts with an earlier one, contained in another note to investors, which saw global oil supply tightening thanks to the OPEC deal. In fact, at the time – a month ago – Goldman was of the opinion that the draw in global stockpiles would completely offset the rise in U.S. shale output.But for now, Brent crude is now trading below $51 and WTI has dropped below $48 a barrel.Investors are watching OPEC again for a possible extension of the production cut deal, but it’s still uncertain if it will happen, and even if it does, no one knows what the effect of an extension would be.
Increasing exports contribute to large draw on propane inventories this winter – EIA blog - U.S. propane inventories, which had been above historical norms since mid-2014, declined by 59 million barrels from the beginning of October 2016 through early March 2017, the largest decline on record for this period, despite unseasonably mild temperatures. Inventories at the beginning of October were nearly 29 million barrels above the previous five-year average, but by March 3, fell to just slightly below the preceding five-year average for the first time since May 2014, based on data from EIA’s Weekly Petroleum Status Report. The strong inventory draws occurred despite weak heating demand this winter and mainly reflect rapid growth in propane exports. Although propane has uses in the petrochemical and agricultural sectors, its dominant domestic use is as a heating fuel for homes and businesses during the winter. Because of the seasonal pattern in propane consumption, propane inventories typically peak between late September and mid-October and fall to their lowest levels in March. The inventory draw this winter, as of March 10, was nearly 23 million barrels larger than the draw last winter (2015–16) and 19 million barrels larger than during the winter of 2013–14, which featured several extremely cold weather events. As domestic propane consumption has remained relatively flat or declined on an annual basis, U.S. exports of propane have continued to increase. Rising production and lower seasonal heating demand over the past two winters, in particular, have meant that more propane has been available for export. U.S. propane is exported to many different countries where it is used as a petrochemical feedstock, for transportation fuel, and for space heating. Similar to the United States, the use of propane as a heating fuel in other countries is seasonal, and the destination mix for U.S. exports of propane can be influenced by patterns of seasonal heating demand in different countries. However, most of the growth in U.S. propane exports serves growing demand from the expanding petrochemical sector in Asia.
Market implications of the huge surge in LPG -- mostly propane -- exports. - Five years ago, the U.S. was a net importer of propane and butanes, those products collectively called LPG, or liquefied petroleum gasses. Back then, demand from residential, commercial, refining and chemical markets slightly exceeded supply for the products. But then came shale, and LPG production from natural gas processing more than doubled, from 0.8 Mb/d to 1.7 Mb/d. Suddenly the U.S. was a net exporter—a very big exporter at that. Last year roughly half of all LPG from U.S. gas processing plants was exported, with the vast majority shipped to overseas markets. All those exports are now having an outsized impact on pipeline flows, inventories and prices. Consequently, it is increasingly important to keep close tabs not only on export volumes but on which export terminals are handling all these volumes, and where the LPG is heading. Today we discuss the current state of the LPG export market and insights on it from RBN’s most recent NGL Voyager Report. Warning, today’s blog includes a subliminal promo for the report. At RBN, we define U.S. LPG as three members of the natural gas liquids (NGLs) family of products: propane, normal butane and isobutane. All three are produced from two sources: 1) the 800 or so natural gas processing plants in the U.S., and 2) U.S. refineries. About 75% of LPG production comes from processing plants, and those facilities have been responsible for almost 100% of the growth in LPG production over the past five years. Refinery production has been about flat. On an annual basis, refineries use more normal butane and isobutane than they produce. So really, refinery net LPG production is propane. Note also that the Energy Information Administration (EIA) uses a slightly different definition of LPG, including ethane in the total. Furthermore, when showing product balances, EIA includes the petrochemicals propylene with propane, butylene with normal butane, and isobutylene with isobutane. Just something to keep in mind when you are comparing numbers from one source to another.
U.S. oil and gas industry reaps the benefits of international trade: Kemp (Reuters) - Rising exports have thrown a lifeline to U.S. shale producers and refiners, giving them an additional outlet at a time when the domestic market has been at risk of becoming saturated. The United States exported record quantities of natural gas, propane, gasoline, distillate fuel oil and light crude last year while continuing to import the heavy oils needed by its refineries (http://tmsnrt.rs/2moUMBU). Gas exports increased by almost 30 percent in 2016 and have more than tripled in the last decade, limiting the build up of unused gas and supporting prices in recent months despite the warmest winter on record. Record propane exports eliminated a surplus and returned stocks to average levels despite low heating demand. ("Increasing exports contribute to large draw on propane inventories this winter", EIA, March 17) Exports are also starting to reverse a surplus of domestically refined gasoline and distillate fuel oil despite lacklustre demand for both at the start of 2017. Most of the natural gas and other fuels have been sold to Latin America, where local producers and refineries have been unable to keep up with growing consumption.As a result of the shale revolution, the United States has emerged as the dominant supplier in an increasingly integrated hemispheric fuel market owing to the efficiency and competitiveness of its Gulf Coast refineries. ("Latin America struggles to stem pricey fuel imports", Reuters, March 16)Free trade in both crude and refined fuels, as well as in natural gas, has played a critical role in helping U.S. shale producers and refiners to weather the slump in oil and gas prices since 2014.The United States has benefited from rising exports even in commodities such as crude where it remains a large net importer overall.Crude exports averaged 520,000 barrels per day (bpd) in 2016, up from 465,000 bpd in 2015 and just 25,000 bpd in 2006.Exports are still outnumbered more than 15:1 by imports, which averaged almost 7.9 million bpd in 2016, according to the U.S. Energy Information Administration.But exports have enabled shale producers to avoid a refinery bottleneck and realise higher prices for their oil than would have been possible in the domestic market.Most U.S. refineries are configured to run on a medium-sour blend of crude with an API gravity of around 31-33 degrees and an average sulphur content of about 1.5 percent. Crude from the main shale plays is mostly lighter, with an API gravity of 40 degrees or more, and contains less than 1 percent sulphur. U.S. refiners have mostly replaced imported light crude with domestic shale oil, resulting in a sharp drop in light crude imports especially from Africa (http://tmsnrt.rs/2n3DvLB). Refiners have blended light domestic crude with more heavy sour crudes imported from Canada and the Middle East to maintain their target API gravity and sulphur content. Surplus domestic crude, mostly light and sweet, that U.S. refineries cannot absorb even with blending is being exported in record volumes to refiners as far away as Asia (http://tmsnrt.rs/2moAl8e). Blending explains the apparent paradox that U.S. crude imports and exports have both been rising at the same time.
ICE to launch first ever US LNG futures contract - The Intercontinental Exchange is to launch the first ever US LNG futures contract in May this year, it said Wednesday. In an exchange note to customers, ICE said it planned to list the new contract on May 4, subject to completion of necessary regulatory processes. US LNG supplies are set to grow quickly in the coming years, turning the country into a leading global supplier of destination-free, flexible LNG.The new ICE contract, whose size will for 2,500 MMBtu, will be a monthly cash future settled against the Platts LNG Gulf Coast Marker price assessment. "By providing the marketplace with a US Gulf Coast LNG futures contract, along with the prospect of future additional products, domestic and international market participants now have a risk management solution that lays the foundation for a more effective means of hedging their spot and forward exposure," vice president, North American power and natural gas markets, J.C. Kneale said. Such a tool, Kneale said, would be "particularly useful as the global LNG market continues to evolve and grow." Only one LNG export facility is currently operational in the US, the Cheniere Energy-operated Sabine Pass terminal, but a number of other plants are due to start up in the coming years. US LNG production capacity is expected to rise to some 70 million mt/year by 2020, making it the world's third largest LNG exporter after Qatar and Australia.
World's top LNG buyers form alliance to push for flexible contracts | Reuters: he world's biggest liquefied natural gas (LNG) buyers, all in Asia, are clubbing together to secure more flexible supply contracts in a move which shifts power to importers from producers as oversupply grows. Korea Gas Corp (KOGAS) said on Thursday it had signed a memorandum of understanding in mid-March with Japan's JERA and China National Offshore Oil Corp (CNOOC) to exchange information and "cooperate in the joint procurement of LNG." Together, the three companies purchase a third of global LNG production, giving them a strong hand to challenge restrictive contract terms that have squeezed buyers' finances. Influential buyers' clubs are largely unheard of in commodity markets where it is the producers, such as the Organisation of Petroleum Exporting Countries (OPEC), who wield power, enforcing production quotas to manage prices. A painful period of high LNG prices before 2014 left Asian importers scrambling to contain losses and led to the first talks between India, Japan, South Korea, China and Taiwan about joint purchases. Several joint LNG-buying deals have been set up since then but none approach the scale of the latest agreement, which is the first involving the game's biggest players. Under Thursday's agreement, the buyers aim to extract concessions from producers that would give them supply flexibility, such as having the right to re-sell imports to third parties, something they are not allowed to do currently under so-called destination restrictions.
Tanker's U-Turn Shows How Shale Is Changing World Gas Trade - -- A cargo of chilled natural gas hauled from Louisiana in late December has become a symbol of how global trade is changing for a fuel increasingly seen as a cheap, cleaner-burning option for countries from Latin America to China and India.The tanker Maran Gas Achilles passed through the Panama Canal and was headed toward Asia at a speed of 20 knots when, suddenly, it made a sharp u-turn in the Pacific. Next stop: Mexico’s Manzanillo terminal on the southwest coast, where it unloaded. The abrupt route change shows how the U.S., which began shale gas exports just last year, is creating a new paradigm in an industry that once revolved almost entirely around long-term contracts with set destinations. As the new kid on the block, exporters of U.S. liquefied natural gas -- led by Cheniere Energy Inc. and Royal Dutch Shell SA -- are seeking the best price at any given time. As U.S. exports grow, it’s a strategy that could shift the economics of LNG toward an emerging spot market akin to oil. “The U.S. puts gas into places on short notice at a good price,” said Jason Feer, head of business intelligence at ship broker Poten & Partners Inc., in a telephone interview. “It’s been flexible. The market’s becoming more short term and the U.S. has been very effective at meeting those needs.” The U.S. stands to become the world’s third-largest exporter by 2020, when it’s expected to ship about 8.3 billion cubic feet a day of capacity, or 14 percent of the world’s share, according to London-based consultant Energy Aspects Ltd. That growth is a testament to the power of the shale boom of the last decade, helping to reduce the country’s reliance on foreign energy sources.Drilling technologies such as hydraulic fracturing have made it profitable to tap vast resources of carbon fuels trapped in rock thousands of feet below the surface. The results: A natural gas supply glut stuck stubbornly in place since mid-2015, and billions of dollars redirected toward new export facilities by Cheniere, Dominion Resources Inc., Kinder Morgan Inc. and others.
Latin America struggles to stem pricey fuel imports | Reuters: Latin American countries are becoming more reliant on costly fuel imports amid floundering efforts to bolster domestic oil output and expand refinery capacity. Incomplete reform projects and budget cuts that have stalled investments are aggravating the situation for many Latin American countries. For refiners in the United States, it is a bonus: they have in their own backyard a ready market for rising fuel exports. Overall, the 30 nations in the region bought 2.32 million barrels per day (bpd) of diesel, gasoline and other fuels last year from the United States, up 67 percent from 2011, according to the Energy Information Administration. Demands for United States imports are rising in the region's biggest economies, up 199,000 bpd or 29 percent last year in Mexico and 75,000 bpd or 94 percent in Brazil, contributing to the gains. "We need to build joint ventures to find the capital the refineries require," said the head of Mexico's oil regulator, Juan Carlos Zepeda, referring to his own country. "And we need to produce more gas," he added in comments earlier this month. But getting there will take time and in Mexico, energy reform is likely to lead to more imports as the retail market is liberalized, before upstream reforms can boost domestic production. Cheaper fuel prices have made it easier for these countries to buy in recent years. Latin America's bill for fuel imports from the United States fell to about $47 billion last year from $51 billion in 2015.
Argentina's Tecpetrol plans 150-well Vaca Muerta gas program - - Tecpetrol, the fifth-biggest oil producer in Argentina, plans carry out a large scale development program in the Vaca Muerta shale play, targeting natural gas, the country's government said Thursday. The country's president, Mauricio Macri, said he would meet with Tecpetrol CEO Carlos Ormachea at 4 pm local time (1900 GMT) in Buenos Aires to announce the plan, according to a brief statement. The plan is to drill 150 wells over the next three years on Fortin de Piedra, a block in the wet gas window of Vaca Muerta, one of the world's biggest unconventional plays. The government said the proposed investment comes on the back of a hydrocarbon reform program that has extended licenses for developing unconventional plays by 10 years to 35 years, and the extension of gas pricing incentives program. Earlier this year, the government extended the pricing incentives so that producers with approved investment plans would receive $7.50/MMBtu at the wellhead for output through 2018, $7/MMBtu in 2019, $6.50/MMBtu in 2020 and $6/MMBtu in 2021, before market pricing takes effect in 2022. The average wellhead price in 2016 was $4.76/MMBtu for YPF, the state-run company that produces 34% of the country's 124 million cu m/d of gas, according to company records.
Norway's natural gas output edged down to 10.2 Bcm in February: NPD - Norway's gas production totaled 10.2 Bcm in February, the fifth straight month that Norway produced more than 10 Bcm of saleable gas, but output was down both year-on-year and month-on-month, preliminary data from the Norwegian Petroleum Directorate showed Tuesday. Total gas output last month averaged 365 million cu m/d, down from the average 370 million cu m/d produced in January. The February volume was 3.2% down on the same month of 2016, but was significantly higher than the forecast for last month of 9.8 Bcm.A number of unplanned outages affected output on the Norwegian Continental Shelf last month, including at the Oseberg, Kristin, Kvitebjorn and Troll fields. But supplies are still running at high levels. For March, the NPD is forecasting saleable gas production of 10.8 Bcm, which would be a little less than the same month last year. Across the summer, the NPD sees production at 8.3-9 Bcm/month, when output will be impacted by seasonal maintenance. Production is then expected to rise to 10.5 Bcm in October 2017, comparable with production in the same month last year.
Putin insists Europe needs expanded gas pipeline - -- An expansion to a Russian gas pipeline running offshore to Germany makes sense given production declines in Europe, Russia's president said. Russian natural gas company Gazprom is one of the dominant suppliers of natural gas for the European economy. The company aims to increase its footprint with the expansion to its twin Nord Stream natural gas pipeline system that runs through the Baltic Sea to Germany and then onto the European market. Russian President Vladimir Putin said during a meeting with officials with Germany energy company BASF, a partner to Gazprom, that expanding Nord Stream was a logical solution for the European market. In January, Gazprom said European regulators were needlessly standing in the way of access to the OPAL gas pipeline to Germany. Access to OPAL may be necessary if the Russian natural gas company is to twin Nord Stream. Putin said expanding Nord Stream should not be seen as a move to limit the competition of any transit country or company. “We are ready to maintain ties with all our partners, including Ukraine as a transit country,” he said.
Oil and gas explorers commit to new North Sea projects - In a statement, the Oil and Gas Authority (OGA) confirmed that it has offered a total of twenty-five new licences – made up of 111 blocks or partial blocks – to seventeen operators. For the first time in two decades the new acreage on offer consisted exclusively of frontier and under-explored areas. Successful bids saw explorers pledge to carry out seismic programmes and in some cases firm commitments for new wells. “We are particularly pleased to see firm well commitments, the targeting of new and under-explored plays, and first-time entrants to the basin, alongside a number of established companies, which will help stimulate further activity and value creation,” said Andy Samuel, OGA chief executive. Significantly, the OGA revealed that the group of successful bidders included three new entrants to the UK continental shelf. The batch of exploration licensing is being followed by a further round, comprising more mature areas, which is anticipated later this year.
Chevron Calls End of LNG Mega Project After $88 Billion Spree --Chevron Corp. has signaled the end of major new LNG projects in Western Australia and is unlikely to sanction an expansion of its Gorgon and Wheatstone export developments as it focuses on boosting returns from $88 billion of investment. The climate for developing large greenfield LNG projects has shifted to smaller developments given a slump in the price of oil to under $50 a barrel, according to Nigel Hearne, a managing director with the company’s Australia unit. “The mega projects of the past decade are giving way to smaller, more targeted investments with quicker economic returns,” Hearne said in a speech in Perth on Tuesday. “As it stands there is unlikely to be another large greenfield LNG development” in Western Australia. Chevron’s two major Australian LNG facilities have suffered from cost blowouts, delays and poor timing. Oil’s worst slump in a generation and an LNG supply glut reduced revenue from projects across the industry. While the third LNG train from the $54 billion Gorgon project is in the process of starting up, further expansions are unlikely in the current climate with Chevron focusing future investments on “shorter-term” returns. “I can’t see in the near-term us investing in a fourth train at Gorgon or a third train at Wheatstone,” Hearne said in Perth. Chevron is focused on generating returns on its existing investments and paying a “dividend back for the money” already spent. The first train from the $34 billion Wheatstone project remains on schedule for mid-2017, he said.
India targets national LNG auto fuel norms in fiscal year 2017-18 - Natural Gas | Platts News Article & Story: The Indian government has in-principle cleared the decks for LNG to be used as an auto fuel, with draft norms for its application in road vehicles to be ready in the new fiscal year from April, officials told S&P Global Platts on Monday. As the industry awaits detailed guidelines and the timing for the official implementation of the decision, India's plan to push toward LNG comes at a time when many countries are assessing an array of options to not only reduce transportation costs but also curb emissions as part of their commitment to tackle global warming. The standards for LNG as a transportation fuel will be developed in consultation with the ministries of highways, shipping, and the environment, the officials said, adding that the basic norms for a national auto fuel LNG policy would be ready after internal consultations among the ministries conclude. CNG pumps like diesel and gasoline retail stations would be a reality in the near future, an official said.
Analysis: Indian refiners set sights on Russian crude oil - Two of India's largest refiners, Reliance and the state-owned Indian Oil Corporation, are setting their sights on buying Russian Urals crude as the key export grade shows signs of competing with some Middle Eastern sour barrels, market sources told S&P Global Platts Friday. In what traders are describing as an opportunistic move, the price of Urals crude exported from the Black Sea port of Novorossiisk is becoming more attractive to some refiners in India, as the OPEC-led production cuts have reduced exports of Middle Eastern sour crudes, pushing up their price differentials. It is very unusual for India to buy Russian crude oil, but there are signs the economics are proving more favorable than they have in the past due to more interest from the East for Dated-Brent related crudes, supported by lower freight amid robust demand for sour crudes.Traders said increased interest for Urals oil from Reliance, which runs the world's largest refinery in Jamnagar, and IOC, which operates 11 refineries in the country, bodes well for the Russian Urals market. Traders said IOC had bought a Urals cargo for end-March loading while Reliance was looking for a parcel for end-March/early-April loading dates. Representatives from Reliance and IOC were unavailable for comment. "The Asian grades have really gotten expensive [over the last few months mainly driven by OPEC cuts] and India is now looking for alternative crudes that are cheaper -- Urals is one of them," said a trader. Sources said India has expressed interest for Urals late last year, with a couple of instances seen, but that before that there have been very few cargoes of Urals exported to India in the past five years.
India to supply 2,200 mt/month of gasoil via rail to Bangladesh: BPC official - Oil | Platts News Article & Story: India has agreed to supply 2,200 mt/month of 0.035% sulfur gasoil from the Numaligarh refinery to Bangladesh via rail for 15 years, Bangladesh Petroleum Corporation director of operations and planning Sayed Mohammad Mozammel Haque said Wednesday. State-owned BPC has agreed to pay a premium of $5.50/b to Mean of Platts Arab Gulf gasoil assessments on a CFR basis for the cargoes, Haque said. BPC had earlier imported several gasoil lots via rail from the Numaligarh refinery, owned by Indian state-run Bharat Petroleum Corporation Ltd or BPCL, at a premium of $7/b to MOPAG gasoil assessments, CFR, under a "friendship gesture," he added. BPC and BPCL agreed to lower the premium and continue the trade at a meeting held in India last week, Haque said.
Rosneft Signs Deal To Supply 10 LNG Cargoes To Egypt In 2017 (Reuters) - A trading unit of top Russian oil producer Rosneft has signed a deal to supply 10 liquefied natural gas (LNG) cargoes to the Egyptian Natural Gas Holding Company this year. The first delivery by Rosneft Trading SA (RTSA) is expected in May, Rosneft said. "This agreement will help to further strengthen the strategic partnership between Rosneft and Egypt in an important area of energy security," the company said. RTSA delivered three LNG cargoes to Egypt in 2016. Once an energy exporter, Egypt has become a net importer because of declining oil and gas production and increasing consumption. It is trying to speed up production at recent discoveries to fill its energy gap as soon as possible. Rosneft does not produce its own LNG yet but plans to launch production jointly with ExxonMobil later this decade.
Is A Russian-Iranian Energy Pact In The Making? -- In the lead-up to President Rouhani’s visit to Moscow, expected to take place in late March, a plethora of news regarding joint Russo-Iranian energy projects has been circulating on the Internet. A three-year long negotiation process regarding a 100,000 barrels-per-day swap contract is believed to be agreed upon, premised on Iran providing Russia (most likely, Rosneft) oil from Kharg Island or other hubs in the Persian Gulf in return for cash and Russian goods that Iran would “require”. Teheran also woos LUKOIL, currently Russia’s only major oil producer in the Caspian, to participate in swap deals bound for Iran’s Neka Port (in return for Iranian crude provided from Kharg Island or other Persian Gulf hubs), albeit on a much smaller scale at 4000 to 5000 barrels per day. To top it all up, numerous Russian oil companies have committed themselves to developing Iran’s hydrocarbon fields.The lifting of most of Iran’s sanctions encouraged almost all oil & gas majors to consider investing in its largely untapped oil and gas fields. Total, apart from spearheading Phase 11 of the South Pars development project, now intends to resuscitate the halfway-constructed, currently-frozen Iran LNG initiative. Royal Dutch Shell signed a memorandum of understanding on conducting technical studies at the Azadegan and Yadavaran fields next to the Iraqi border, as well as the offshore Kish field not far away from the supergiant South Pars field. Yet the good will demonstrated by Moscow during negotiations prior to the lifting of nuclear sanctions, as well as Russia’s instrumental role in turning the tide in Syria’s sanguineous civil war in support of President Assad’s regime have elevated the Moscow-Teheran axis to new heights.
Japan's Top Oil Experts Seek Solutions to Chinese Fuel Flood Problem Huddled deep within Tokyo’s government district, nearly two dozen of Japan’s top oil experts pore over a problem plaguing its energy industry: how can they stop China from pushing its crude refiners into a corner? The task force, summoned by the trade ministry, needs a strategy to save oil refiners battered by years of declining demand at home. The processors, including JX Holdings Inc. and Idemitsu Kosan Co., now face rising competition for sales in Asia, the world’s biggest oil market. The ministry fears that China’s move to adopt stricter fuel standards will spur regional rivals into producing higher quality products, forcing Japan out of the market. China is the biggest among a slew of other threats for Japan. The gradual slowdown of economies such as South Korea’s have led to rising exports to an increasingly saturated market. Meanwhile, other developed countries including the U.S. are also fighting for its share in Asia after China’s diesel and gasoline shipments overseas capped a record year in 2016. Members of the task force include Seisuke Iwai, a senior official at industry group Petroleum Association of Japan, Norimasa Shinya, an energy analyst at Mizuho Securities Co., Fuminori Hasegawa, senior vice president at Mitsubishi Corp. and Katsuhiro Sato, a partner at McKinsey & Co. in Japan. Their mission has taken on a sense of urgency following China’s move at the start of this year to curb the amount of sulfur used in vehicle fuels in an effort to reduce air pollution. The new rule has encouraged suppliers like China Petroleum and Chemical Corp., the world’s biggest oil refiner known as Sinopec, to pledge about $29 billion in facility upgrades to enable it to pump cleaner fuel. At the same time in Japan, the popularity of electric hybrid vehicles has reduced the country’s gasoline demand, contributing to an oversupply in refined products.
China’s Crude Oil Production Falls 8% Year Over Year -- China’s crude oil production dropped by 8 percent annually to 31.44 million tons in January and February, as high domestic production costs prompted refineries to import more crude oil. Crude oil imports, on the other hand, rose by 12.5 percent to 65.8 million tons. Despite the higher global oil prices at around $50 this year, compared to last year’s lows, Chinese refineries still preferred to import crude rather than buy domestically produced oil due to the high production costs. China’s domestic crude oil output faltered in 2016, after the oil price slump pushed many of its mature and expensive fields out of the profitability range, and local producers suspended loss-making production from some of those fields. China’s crude oil production dropped by 335,000 bpd last year, or by 6.9 percent. Even with the higher international oil prices at around and above $50 per barrel, the Chinese output is projected to further decline by another 7 percent in 2017, or by around 240,000 bpd.
Beset by delays, Myanmar-China oil pipeline nears start-up | Reuters: Nearly a decade in the making, a project to pump oil 770 km (480 miles) across Myanmar to southwest China is set for imminent start-up, with a supertanker nearing the port of Kyauk Phyu, marking the opening of a new oil trading route. Dogged by sensitive relations between Naypyitaw and Beijing, the $1.5 billion oil pipeline has been sitting empty for two years, but the two sides are now close to a deal, said Myanmar-based government and industry sources, despite some last-minute tensions. An agreement between China's PetroChina and Myanmar's government will allow the state energy giant to import overseas oil via the Bay of Bengal and pump it through the pipeline to supply a new 260,000-barrels-per-day (bpd) refinery in landlocked Yunnan province. The new oil gateway fits with China's "One Belt, One Road" ambitions, linking it with central Asia and Europe, and will provide a more direct alternative route to sending Middle Eastern oil via the crowded Malacca Straits and Singapore. It would also be a rare win for China in Myanmar after a diplomatic offensive aimed at forging better ties with its resource-rich neighbor, which has often been wary of Beijing's economic clout. Aung Myat Soe, deputy director of planning under the state-owned Myanmar Oil and Gas Enterprise (MOGE), said the project was awaiting a final sign-off by the Minister of Electricity and Energy. Major issues including transport tariffs and Myanmar's tax take on the oil have been settled, but port fees have yet to be finalised, said a Myanmar-based industry source familiar with the matter.
Oil theft is fuelling terrorism and drug cartels, says thinktank -- Oil theft is fuelling terrorist groups and drug cartels around the world, according to a new analysis. Mexican drug gangs can earn $90,000 (£72,000) in seven minutes from tapping a pipeline of refined oil, while insurgents in Nigeria financially benefit from a share of the third of the country’s refined oil exports that is lost to theft, said the Atlantic Council. The Washington DC-based thinktank, which mapped the scale of crime in the oil refining and processing end of the sector, said the issue had largely been ignored by authorities and law enforcement agencies so far. “This has been an invisible issue for many years, people do not recognise downstream oil theft as a problem. It’s a multibillion-dollar thing that affects many people all over the world,” said Ian M Ralby, the author of the analysis, which follows up on a study published in January. “These are global concerns because they affect the global economy and they affect global security,” he added. The crimes take many forms, from straightforward theft from pipelines to smuggling to avoid taxes. Donkeys laden with jerry cans are used to smuggle oil across the closed border between oil-rich Algeria and Morocco. As a result an estimated 660,000 cars in Morocco and Tunisia run on fuel smuggled from Algeria, and border cities have sprung up to provide a property market to launder some of the funds. “Many, many drops start to flood a house,” said Ralby of the cumulative impact. Along with Nigeria, Mexico is one of the biggest oil theft hotspots, where an estimated $1bn of oil is stolen each year, with the Zetas cartel controlling nearly 40% of that market alone. Drug barons tapping pipelines in Mexico are also known to leave them open afterwards for farmers to win support. Europe is not exempt from the problem, with the analysis finding the EU lost about €4bn (£3.5bn) in hydrocarbon revenues in 2012. Ralby said a huge industry was taking shape in which refined crude from Libya, which has Africa’s largest oil reserves, was being illegally transferred ship-to-ship in the Mediterranean and passed off as legitimate oil imports to the EU.
Venezuela Scrambles to Sell Off Oil Assets and Avoid Default -- In an effort to handle its overdue debts, Venezuela is all but giving away oil assets. President Nicolás Maduro is reportedly so desperate to pay the US $3.7 billion in debts that he is selling off the assets to Russia. They offered to sell Russia a share of PetroPiar, which is 30-percent owned by Chevron and which PDVSA has a 70-percent stake in. It also expropriated ConocoPhillips’ 40-percent shareholdings, which has not been paid yet. Likewise, PDVSA offered Rosneft 10 percent of a project developed to extract the extra-heavy oil from the Orinoco Oil Belt. If the transactions go through, Chevron would be affected negatively, as it would be associating with Rosneft, a company that faces sanctions imposed by the United States. Venezuela has also reportedly been talking to a Japanese investment bank to try to obtain fresh funds. Venezuela managed to pay US $725 million in overdue debt last month, but with difficulty, as it came 30 days late
Libyan oil output rises to 700,000 barrels per day after port fighting ends: NOC | Reuters: Libya's oil production has reached 700,000 barrels per day (bpd), the National Oil Corporation (NOC) said on Wednesday, recovering from a drop earlier this month caused by fighting at two key oil ports. "We are working very hard to reach 800,000 barrels by the end of April 2017, and, God willing, we will reach 1.1 million barrels next August," NOC Chairman Mustafa Sanalla was quoted as saying in a statement. The NOC said in a separate statement it hoped to produce 55,000 bpd in the coming weeks from the Abu Attifel and Rimal fields, which are currently closed for maintenance. The fields are operated by Mellitah Oil and Gas, a joint venture between the NOC and Italy's ENI. The NOC said Mellitah is currently producing 41,000 bpd from onshore and offshore fields, as well as 43,000 bpd of condensate. Libya's output fell to around 600,000 bpd after eastern security forces lost control on March 3 of the major oil terminals of Es Sider and Ras Lanuf, before regaining them 11 days later. Sanalla has said he expects to retain control over operations at the ports, despite some officials in eastern Libya appearing to cast doubt over continuing cooperation with the NOC in Tripoli. Workers at the ports have been gradually returning to their posts, and a tanker is expected to load of crude at Es Sider on Saturday or Sunday, according to shipping sources. Production at Waha oilfield, which was halted this month, has risen to 35,000 bpd, a field engineer said. Waha Oil Co, which operates the field, is hoping to raise production from all its fields to 80,000 bpd by the end of March and to more than 100,000 bpd by mid April.
Saudi ‘Mission Impossible’ Makes Longer OPEC Oil Cuts Inevitable -- Saudi Arabia has set a near-impossible target to end the current round of OPEC oil-production cuts, indicating that a policy rollover into the second half of the year is a near certainty. OPEC, which pumps about 40 percent of the world’s oil, and several non-OPEC countries including Russia agreed in December to reduce production for six months in an effort to bring supply and demand into balance. At the time, the producers said they could extend the deal for an extra six months. In an interview with Bloomberg Television on Thursday, Saudi Energy Minister Khalid Al-Falih said that OPEC would extend the cuts after they expire in June if oil stockpiles were “still above the five-year average.” Because oil stocks are so far above that level, the target will probably still be out of reach when the Organization of Petroleum Exporting Countries gathers in Vienna on May 25. “It looks impossible for total OECD company stocks on land to fall back by mid-year to the five-year average, which OPEC has set as a key benchmark as to whether it should extend its deal,” oil consultants FGE told clients in a note.
The Single Biggest Threat To An OPEC Deal Extension - If OPEC fails to agree to extend their production cuts for another six months, Iraq could be a major reason why.For many years after the 2003 U.S. invasion, Iraq was exempt from OPEC’s production quotas in order to help the country rebuild. But in recent years, Iraq has succeed in ramping up its output, overtaking Iran to become OPEC’s second largest oil producer. Today, production stands at 4.4-4.5 million barrels per day (mb/d).As OPEC’s second largest producer, Iraq is pivotal to the success of the deal signed late last November to prop up prices.But Iraq has lagged behind other OPEC members in its efforts to reduce output. It agreed to cut production by roughly 210,000 bpd from October levels, requiring it to average an output level of 4.351 mb/d over the course of the six-month compliance period between January and June.Those figures were agreed on an October baseline (although Iraq has argued with OPEC over which numbers to use for months). In December, just before the deal was set to take effect, Iraq ramped up output to 4.642 mb/d. It then cut production by 166,000 bpd in January, but from that higher December level, taking it down to 4.476 mb/d, according to OPEC’s secondary sources, or only slightly below its baseline and still above its targeted level as part of the deal. No matter; the OPEC deal is a six-month average, so Iraq could still lower output in subsequent months and comply with its commitments. Iraqi officials reassured its OPEC peers that further reductions were forthcoming. But in February, the reductions were a bit underwhelming. Iraqi output dropped by just 62,000 bpd to 4.414 mb/d. Again, Iraq has more time to bring its average down, but it is one of the few countries not already complying with its production cap. The other is the UAE – a surprise development considering the country’s close alliance with Saudi Arabia. As a fellow member of the Gulf Cooperation Council, UAE policy closely follows what goes on in Riyadh. So, the UAE is less of a worry for compliance – it will likely fall into line soon.
Oil Shorts Soar By 2nd Most In History As OPEC Hope Fades --During a week that saw WTI crude prices erase all post-OPEC-production-cut-deal gains, after the Saudis admitted 'cheating' (but rapidly back-pedalled), oil speculators added almost 80,000 contracts to their short positions - the 2nd most in 34 years. This surge in shorts reduced the massive record net long crude positioning by the 2nd most in history - but clearly it remains extremely one-sided still... This is the 3rd weekly drop in a row for the net long position, as hedge funds cut their net bullish positions by the most ever to 14-week lows. All of which happened as oil prices drifted lower waiting and watching for OPEC's next move (as OilPrice's Matt Smith explains)... prices are struggling as market participants try to weigh up whether OPEC is going to continue its production cuts (or even implement them in the first place).
Bets soar that NYMEX crude futures will head lower: US CFTC - Money managers' position in NYMEX crude futures took a bearish turn in the latest reporting period, according to US Commodity Futures Trading Commission data released Friday. The CFTC data confirmed what analysts suspected was a drastic shift in speculative positioning recently after crude futures fell sharply March 8 and kept declining until a week later, when prices found some support. A sharp buildup in speculative net length left the market vulnerable to the downside, analysts said. Net length rose after OPEC's supply-cut deal was announced November 30, and accelerated this year. It reached a record-high 405,328 contracts the week ending February 21, according to CFTC data.The following two reporting periods saw money managers cut back slightly on net length, but longs still outnumbered shorts by a nearly 7:1 ratio. But for the week that ended March 14, longs-to-shorts stood at a 3:1 ratio, driven by both long liquidation and shorts entering the market. Speculative length fell 34,579 contracts to 383,767 contracts, while the size of the short position jumped 67,779 contracts to 128,947 contracts, CFTC data showed. NYMEX crude futures fell $5.42 to $47.72/b in the week ending March 14, a low going back to November 29. Crude futures have since been above $48/b, suggesting the selling pressure from money managers has eased.
Hedge funds rush for exit after oil trade becomes crowded: Kemp (Reuters) - Hedge funds cut their bullish bets on oil by the largest amount on record in the week to March 14, according to the latest data published by regulators and exchanges. Hedge funds and other money managers cut their combined net long position in the three main futures and options contracts linked to Brent and WTI by a record 153 million barrels in just seven days (http://tmsnrt.rs/2n6ahxr). The reduction in the net long position coincided with the sharp fall in oil prices, which started on March 8 and continued through March 14. The adjustment was split almost evenly between the liquidation of old long positions and the establishment of new short positions. Hedge fund managers reduced long positions by 84 million barrels while short positions were increased by 70 million barrels.Fund managers' net long position has been reduced by a cumulative total of 230 million barrels over the last three weeks from a peak of 951 million barrels on Feb. 21 (http://tmsnrt.rs/2n0kxpj).Most fund managers are still bullish about the outlook for oil but that bias is less pronounced than it was a month ago. Hedge fund long positions outnumber short positions by a ratio of 4.4:1, but that come down from a ratio of 10.3:1 on Feb. 21 (http://tmsnrt.rs/2mM2e6q). Before the recent sell off, hedge fund managers had boosted their net long position in Brent and WTI by 530 million barrels between the middle of November and the middle of February.Funds amassed a record 1.05 billion barrels of long positions, while short positions were cut to just 102 million barrels, the smallest number since oil prices started slumping in 2014. But large concentrations of hedge fund positions, and an imbalance between the long and short sides of the market, often precede a sharp reversal in oil prices.
Rig count hangover bruises crude oil prices (UPI) -- Under broader pressure from the so-called Brexit, crude oil prices moved lower early Monday on a hangover from higher U.S. exploration and production work.Energy companies working in shale oil basins in the United States have adapted to lower price points so that, once the market does recover, they're more efficient at returning to work. After forecasting production declines for 2017, U.S. federal data instead show steady gains and production so far in March has been at around 9 million barrels per day.Data last week from oilfield services company Baker Hughes showed an increase in the number of rigs deployed in the United States for the ninth week in a row. Rig counts serve as a rough estimate of exploration and production, which in itself is indicative of energy sector spending and confidence.Gains in production from the United States, and producers from the Organization of Petroleum Exporting Countries eager to defend a market share, pushed oil to historic lows last year. OPEC in November agreed to manage collective production, leaving the United States in a unique position to influence crude oil prices.With Baker Hughes data still a factor in trading, the price for Brent crude oil was down 1.3 percent from Friday's close to $51.09 per barrel about a half hour before the start of trading in New York. The U.S. benchmark for the price of oil, West Texas Intermediate, was off 1.7 percent from the previous close to $47.94 per barrel. For the broader economy, concerns could emerge from the British decision to invoke Article 50 of the Lisbon Treaty next week, triggering the official start of negotiations to leave the European Union.
Oil prices continue sliding as production limit optimism fades - Crude prices dipped over a percent on Monday, as investors lose confidence in oil following strong drilling data from the United States and pessimism about OPEC-led output cuts. "Speculative investors have thrown in the towel it seems. We've got record selling in the week ending March 14, and the bleeding has not stopped yet," said Carsten Fritsch, senior commodities analyst at Commerzbank in Frankfurt, as quoted by Reuters."The continued increase in US oil rigs adds to the bearish sentiment," he added.Brent crude was down 58 cents at $51.18 per barrel, while US benchmark WTI slid 74 cents to $48.In the US, drillers added 14 oil rigs in the week to March 17, according to Baker Hughes. At 631 rigs, this is the biggest count since September 2015. This indicates the US shale oil industry, hit by low energy prices, is returning to the market. The recovery is likely to see the biggest increase in shale production in six months in April. The data from the US thwarts the Organization of the Petroleum Exporting Countries (OPEC) deal with Russia and other producers to cut production to prop up prices. “It was obvious that with a reversal in prices, the US shale production was going to pick up. But the magnitude of the improvement was really not known,” said one Gulf delegate, as quoted by the Financial Times.
Oil Heads Lower As Traders Sell The Rumor - Oil prices seesawed a bit to start off the week, awaiting news from the EIA on changes to crude oil inventories. After a sharp decline in prices two weeks ago, WTI and Brent have been hovering in a relatively narrow range – WTI in the upper-$40s and Brent in the lower $50s. That continues to be the trend this week.OPEC sources told Reuters that the group is increasingly leaning towards a six-month extension of its production cuts. However, one major hurdle will be keeping Russia and other non-OPEC countries on board with the reductions. "An extension is needed to balance the market," an OPEC delegate told Reuters. "Any extension of the cut agreement should be with non-OPEC." Another OPEC source agreed that non-OPEC countries are necessary. "The ministers will meet in May to decide, but everyone has to be on board." Russia has not yet met its production cut requirements under the OPEC deal, but Russian officials said that they would meet the promised 300,000 bpd reduction by the end of April, and keep output at that level for the duration of the deal through June. Astute readers might note that Russia would still fall short of its pledge, which was to keep the six-month average 300,000 bpd below October levels. Reducing by 300,000 bpd for only three months is not exactly the same thing. Hedge funds and other money managers recently slashed their bullish bets, achieving the sharpest reduction in net-length on record. The liquidation of bullish positions will continue to put downward pressure on prices. Oil prices are now in a bearish trend and there is still a great deal of downside risk. ExxonMobil, Royal Dutch and Chevron are set to spend a combined $10 billion on drilling in the Permian Basin this year. The majors have been reluctant to go all-in on shale in years past, having traditionally produced their oil and gas from much larger projects, leaving shale production to dozens of smaller and medium-sized companies. But the majors are in the midst of a crucial makeover, backing out of megaprojects and pouring more money into short-cycle shale projects that tie up cash for short periods of time. “The majors arrived late,” Greg Guidry, head of Royal Dutch Shell’s shale unit, told Bloomberg. “We want to be as nimble as the independents but levering the capabilities of a major.” Shell says that it can breakeven with new shale wells in the Permian with oil trading at $20 per barrel.
WTI/RBOB Plunge After Inventory Hits Record High, Production Surges -- After a sizable build in crude and draw in gasoline overnight from API, WTI and RBOB are lower (legged down on Libya production news). DOE data confirmed the API data with asizable crude build and gasoline and distillates extending their draw streak. US crude production rose once again - the highest in 13 months. DOE:
- Crude +4.945mm (+3mm exp)
- Cushing +1.42mm (+1.1mm exp)
- Gasoline -2.81mm (-2.4mm exp)
- Distillates -1.91mm (-1.5mm exp)
Crude inventory expectations had risen into the print and DOE data confirmed a notable build. Gasoline drew down but less than API and Cushing saw another notable build...
Crude Inventory Build Sends Oil Prices Into A Nosedive - Amid growing worry about the direction that oil prices are heading into, the Energy Information Administration reported a 5-million-barrel build in U.S. commercial oil inventories for last week, bringing total US crude oil inventories to 533.1 million barrels.The report comes a day after API’s latest estimate dealt yet another blow to prices, pegging inventories at 4.53 million barrels more than a week before. Last week’s EIA figures were also discouraging: for the seven days to March 10 the authority reported a modest decline of 200,000 barrels, reinforcing concern that the glut will continue despite some cuts in production made by OPEC and 11 non-OPEC producers.In its latest report, the EIA also reported a draw in gasoline inventories of 2.8 million barrels, with refinery processing rates averaging 15.8 million barrels of crude daily. Gasoline production was up to 9.8 million barrels in the period. U.S. inventories have seen major builds over the last few months, contributing substantially to a dampening of optimism for the immediate future of oil prices. The latest news from the OPEC camp as well as a recent note to investors from Goldman Sachs is painting a gloomy picture.While some OPEC members are on board with a production cut extension, Saudi Arabia early this month declared it will not partake in measures that will only support U.S. shale producers’ ramping up of production. It later softened its stance, so the prospects of an extension look brighter. Goldman Sachs warns that mega projects expected to start commercial production this year could add a million barrels to global supply, erasing any gains made thanks to the OPEC cut, extended or not. The extension dilemma is indeed a tough one: OPEC can either agree to extend the cuts and risk losing more market share, or start raising production from July 1, bringing prices further down.Meanwhile, U.S. producers are facing pressure from banks: if WTI falls to $45, lenders are more likely than not to start cutting credit lines, hampering the industry’s recovery. Amid these developments, at the time of writing Brent crude was trading at $50.16 a barrel and WTI was at $47.63.
Oil drops to lowest since November as U.S. inventories swell | Reuters: Oil prices slipped on Wednesday to their lowest since late November, with Brent testing the $50 per barrel support, after data showed record high U.S. crude inventories rising faster than expected, raising doubts over the viability of OPEC-led output cuts. The Energy Information Administration (EIA) said U.S. inventories climbed almost 5 million barrels to 533.1 million last week, far outpacing forecasts of a 2.8 million-barrel build. [EIA/S] "The fact that this supply has increased almost 55 million barrels this year in the face of significant OPEC production cuts is evolving as a major bearish development that poses a significant threat to the viability of the OPEC agreement in our opinion," Jim Ritterbusch, president of Chicago-based energy advisory firm Ritterbusch & Associates, said in a note. Global benchmark Brent shed 32 cents, or 0.6 percent, to settle at $50.64 a barrel, its lowest close since Nov. 30 when OPEC countries agreed to cut output. The contract fell as low as $49.71 in morning trade. On its first day as the front-month, U.S. West Texas Intermediate (WTI) crude futures for May slipped 20 cents, or 0.4 percent, to settle at $48.04 per barrel. The session low was $47.01, its lowest since Nov. 30. A deal between the Organization of the Petroleum Exporting Countries and some non-OPEC producers to reduce output by 1.8 million barrels per day (bpd) in the first half of 2017 has done little to reduce bulging global oil stockpiles. OPEC, which sources say is leaning toward extending cuts, has broadly delivered on pledged reductions, but non-OPEC states have yet to cut fully in line with commitments. "OPEC has used up most of its arsenal of verbal weapons to support the market. One hundred percent compliance by all is the only tool they have left and on that account they are struggling,"
Brent crude oil's dip below $50 adds to pressure on Opec - Brent crude oil fell below $50 a barrel for the first time this year after US crude inventories climbed to a fresh record, raising fears that Opec’s attempts to tighten the market are falling short.US crude inventories rose by 5m barrels in the week ended March 17, the US Energy Information Administration reported on Wednesday, triggering an immediate bout of selling that pushed Brent below $50 for the first time since November.The latest price slump means Brent has reversed all of its gains since Opec agreed to cut production alongside allies like Russia late last year in an attempt to end the two-year price slump that has upended the oil industry.It will heap pressure on the 13-member oil producers cartel to either increase cuts or roll over the initial six-month cut period when it meets in May, as signs of a rebound in US oil output is blunting their efforts. “There are growing doubts among market participants about whether the Opec production cuts will be able to quickly restore balance on the oil market,” Oil company stocks were hit by the latest price drop, which saw Brent hit a low of $49.71 a barrel, while US benchmark West Texas Intermediate dropped as low as $47.01 a barrel. BP, Royal Dutch Shell and ExxonMobil shares all slipped. The rise in US crude stocks comes as shale drillers ramp up efforts after an earlier rebound in prices relieved the pressure on their balance sheets, which had been hard hit by the two-year slump. US drillers have added rigs for nine straight weeks, leading analysts to revise up their forecasts for how much the country might produce this year. That poses a challenge to Opec who hoped the rebound in shale output would be limited. Saudi Arabia, the most powerful member of Opec, has warned other producer nations who signed up to the supply reduction deal that they must comply with the cuts, saying the kingdom — which has shouldered the bulk of cuts so far — will not be taken for granted. A report on Wednesday said that the kingdom may seek the involvement of Opec members that were previously largely exempt from the deal, such as Iran, should any deal be extended.
US rig count increases 20 this week to 809; Texas up 8 - (AP) - The number of rigs exploring for oil and natural gas in the U.S. increased by 20 this week to 809. A year ago, 464 rigs were active. Houston oilfield services company Baker Hughes Inc. said Friday that 652 rigs sought oil and 155 explored for natural gas this week. Two were listed as miscellaneous. Texas increased by eight rigs and Oklahoma added seven. New Mexico rose by three while Alaska, California, North Dakota, Pennsylvania and West Virginia gained one each. Louisiana declined by two and Wyoming by one. Arkansas, Colorado, Kansas, Ohio, and Utah were all unchanged. The U.S. rig count peaked at 4,530 in 1981. It bottomed out last May at 404.
Rig count breaks 800, Permian back on top -- After a small slump last week, the Permian basin is back on top in U.S. rig count gains released March 24. The Baker Hughes U.S. rig count gained a total of 20 new rigs this week, with a total of 809 rigs exploring for oil and gas. Baker Hughes reported 21 new rigs exploring for oil and gas, totaling 652, and one addition labeled as miscellaneous. The gas rig count dropped by 2 to 155. Rig count changes by Basin: By state, only Louisiana and Wyoming lost rigs. Texas gained 8, Oklahoma gained 7, and New Mexico gained 3. Alaska, the state that could see significant gains in upcoming months following a large discovery of oil reserves, gained 1 this week.The price of West Texas Intermediate (WTI) crude oil opened Friday at $47.67. At 3:00 pm EST, oil was up slightly from Thursday at $48.01. However, this is still lower than just a few weeks ago, when WTI consistently hit between $52 and $54 per barrel. The continuing increase in oil inventories is part of the reason for the market dip. U.S. inventories increased by around 5 million barrels from the previous week. At 533.1 million barrels, U.S. crude oil inventories are at the upper limit of the average range for this time of year, according to the latest from the Energy Information Administration (EIA). As forecasters attempt to analyze what’s in store, a meeting of five representatives from Kuwait, Algeria, Venezuela, and the non-OPEC nations of Russia and Oman on Sunday will likely drive oil prices next week. The agreement to cut production among these countries could be extended, helping to keep the price of oil higher and help prevent another deep slip. However, the United States is not among the countries who have agreed to cut production. Naeem Aslam, chief market analyst at Think Markets said, “OPEC has done their part, but U.S. inventory data is still rising, keeping the lid on the oil price,” reported Sara Sjolin from Marketwatch.
U.S. Oil Rig Count Continues To Rise Despite Saudi Warnings -- The United States oil rig count jumped by 21 this week, to its highest level since September 2015, according to Baker Hughes’ latest rig on domestic drilling activity. The number of oil rigs currently active in the United States now sits at 652, which is an increase of 280 year over year. The sizeable jump in rigs signals an indifference by American shale producers towards warnings issued by the Saudi Arabian leadership against increased production. The KSA, which serves as the de facto leader of the Organization of Petroleum Exporting Countries (OPEC), entered into an agreement with its fellow bloc members and 11 NOPEC nations to cut production by 1.8 million barrels. So far, Riyadh has been doing the heavy-lifting, while its partners cut less than expected and enjoyed higher profits from an oil barrel stable above the $55 point. But cheap shale output from the U.S. threatens the effectiveness of the OPEC agreement, which aims to eliminate the supply glut. Gas rigs were down by two to 155, an increase of 63 over a year ago. State-wise, Texas and Oklahoma gained eight and seven rigs, respectively. New Mexico saw a three-rig rise, while Alaska, California, North Dakota, Pennsylvania, and West Virginia gained one each. The Permian Basin saw the most number of rigs added, bringing 7 additional rigs online to reach 315. The Permian Basin now has 168 more rigs in production than this time last year. Cana Woodford, Eagle Ford, and Marcellus Basins all saw 2-rig increases, and Barnett, Granite Wash, Mississippian, and the Williston Basin all added one. There were no decreases this week in the number of operational rigs per basin. By state, Texas was the biggest winner this week with an additional 8 rigs, with Oklahoma coming in a close second with an increase of 7 rigs.
Oil prices ready for 3rd weekly loss in a month - Oil prices edged slightly higher Friday, but were set to log their third weekly loss in a month, as traders continued to weigh signs of OPEC-led cutbacks in global crude production against data pointing to the likelihood of further gains in U.S. output. May West Texas Intermediate crude rose 8 cents, or just under 0.2%, to $47.78 a barrel on the New York Mercantile Exchange. It touched intraday highs above $48 early Friday following news that Saudi Arabia, the Organization of the Petroleum Exporting Countries’ biggest producer, said it cut oil exports to the U.S. in March by around 300,000 barrels a day. For the week, WTI oil prices were poised for a loss of about 2.1%. May Brent crude added 2 cents, or less than 0.05%, to $50.58 a barrel—on pace for a weekly loss of about 2.3%. “In the oil market, it is the upcoming OPEC meeting on Sunday which will drive prices next week,” said Naeem Aslam, chief market analyst at Think Markets. Five representatives of the countries that signed up to the output agreement—Kuwait, Algeria, Venezuela, and non-OPEC nations Russia and Oman—will meet in Kuwait on Sunday to review the current level of compliance. Most members of the Organization of the Petroleum Exporting Countries are adhering to their pledges to make cuts, but data suggest not all non-OPEC producers are sticking to their quotas. And then there’s the U.S., which isn’t part of the agreement. “OPEC has done their part, but U.S. inventory data is still rising, keeping the lid on the oil price,” said Aslam.
Record U.S. Stockpiles Keeping Oil Prices Low - Oil dropped as U.S. crude supplies rose to an all-time high while investors await a meeting between OPEC and its allies that may signal whether they’ll extend output curbs. Futures fell on both sides of the Atlantic, sending Brent to its lowest close since November. American crude output continued to rise along with inventories last week, an Energy Information Administration report showed on Wednesday. While OPEC won’t formally decide until May whether to prolong production cuts, officials will meet this weekend in Kuwait to discuss their deal’s progress. West Texas Intermediate and Brent crudes dipped below $50 a barrel this month for the first time in 2017 as rising U.S. inventories weighed on output cuts by the Organization of Petroleum Exporting Countries and other producers. Saudi Energy Minister Khalid Al-Falih has said the group would extend the deal if oil stockpiles remain high. The Russian cuts are “slower than what I’d like,” Al-Falih said in an interview with CNBC March 7. "There’s a lot weighing on the market and I believe it’s a matter of time before we move lower," John Kilduff, a partner at Again Capital LLC, a New York-based hedge fund that focuses on energy, said by telephone. "Saudi patience is being tried by Russia and others that aren’t abiding by the agreement." WTI for May delivery dropped 34 cents to close at $47.70 a barrel on the New York Mercantile Exchange. Total volume traded was about 20 percent below the 100-day average. Prices are up 20 percent from a year ago. Brent for May settlement fell 8 cents to $50.56 a barrel on the London-based ICE Futures Europe exchange. Its the the lowest close since Nov. 30. The global benchmark ended the session at a $2.86 premium to WTI. Crude supplies rose by 4.95 million to 533.1 million barrels last week, the EIA report showed on Wednesday. Prices tumbled upon the release of the data before erasing most of the loss as attention shifted to fuel stockpile gains. Gasoline inventories fell to 243.5 million barrels, while supplies of distillate fuel, which includes diesel and heating oil, slipped to 155.4 million barrels.
Saudi pledges stable oil supply as market confused by data | Reuters: Output or exports? OPEC members have argued for decades over which of the two they should monitor to gauge compliance with oil-output cuts. This month, Saudi Arabia has thrown a third metric – supply - into the debate. The move saw oil prices declining, with confused traders fearing Riyadh would pump more crude, thus complicating OPEC’s efforts to reduce a global glut and prop up the market. But sources in Riyadh argue that those worries are overblown. They say that while Saudi production could fluctuate slightly from month to month, supply will remain stable at around 10 million barrels per day (bpd), fully in line with the Saudi OPEC quota. "What we are watching closely is the supply. Saudi Arabia will not supply the market more than 10 million bpd," a Saudi-based industry source said. On Jan. 1, a deal between the Organization of the Petroleum Exporting Countries and some non-OPEC states to curb production by 1.8 million bpd came into effect. Production is the volume of crude pumped from the wellhead, while supply is the amount of crude sent to the market, domestically and for export. This may vary from production on a monthly basis based on movement of barrels in or out of storage. For the past couple of years, the difference between Saudi production and supply figures has not been large. Discrepancies in January and February were notable after the OPEC agreement as the market has focused more on production and compliance. Riyadh's plea for OPEC and market watchers to focus on Saudi supply rather than production or exports is driven by the kingdom's unique position in OPEC as a holder of huge stockpiles.Saudi Arabia, the world's top oil exporter, has long been OPEC's only holder of significant spare capacity, a cushion to help smooth possible shortages in global supply.
Exclusive: Saudi exports to U.S. to fall by 300,000 barrels per day in March - official | Reuters: Saudi Arabia's crude exports to the United States in March will fall by around 300,000 barrels per day from February, in line with OPEC's agreement to reduce supply, a Saudi energy ministry official said on Thursday. The United States imported about 1.3 million bpd from OPEC's top exporter in February, according to U.S. Energy Information Administration data. "Exports may fluctuate week on week, but on average in March exports will be down," the official said, responding to a Reuters request to comment on the EIA data. Saudi exports are then expected to remain around March's level for the next few months, the official said. The official noted that export data showed higher Saudi oil exports in January and February, but these shipments were the result of cargo loaded in November and December. Saudi Arabia has made the largest cut in production after the agreement reached last year by both the Organization of the Petroleum Exporting Countries and non-OPEC producers to reduce output by 1.8 million bpd. Oil prices have been in a downtrend for two weeks on concerns that OPEC cuts so far have not dented record U.S. crude inventories. U.S. crude has declined nearly 10 percent since March 7 as speculators reduced big bets that oil would keep rising. It settled on $47.70 on Thursday. Crude stocks in the United States, the world's largest oil consumer, were a record 533 million barrels last week, the EIA said. In the week ended March 17, U.S. imports from Saudi Arabia unexpectedly rose by more than 200,000 bpd to 1.28 million bpd, after a sharp decline the prior week.The official said lower Saudi exports to the U.S. is likely to affect stockpiling in the U.S.
Saudi Arabia tries to drain oil stocks while protecting customer relationships: Kemp - (Reuters) - Saudi Arabia faces a difficult balancing act as it tries to work down excess global crude stocks while protecting relationships with important refining customers in the United States and Asia.Saudi Aramco exports most of its crude direct to refiners under long-term contracts that prohibit resale to other refiners or independent traders.Aramco's business has been built around nurturing strategic relationships with customers and emphasising its reliability as a supplier.The model is very different from most other OPEC and non-OPEC producers that rely more heavily on spot sales to refiners and traders.Aramco's strategic relationships and term contracts help it realise value in the long run but reduce its flexibility in the short term.And Saudi Arabia's commitment to reduce production under the accord with other OPEC and non-OPEC countries reached towards the end of 2016 creates a tension with its customer-focused strategy. The kingdom has an obvious interest in reducing excessive global crude stockpiles in an attempt to push oil prices higher.In fact, Aramco has so far cut production even more than required under the OPEC/non-OPEC agreement to accelerate the rebalancing process.But Aramco is also keen to protect is preferential-supplier status with refiners across Asia and the United States which means protecting volumes as far as possible.Contracts with refiners contain some limited flexibility to vary the volume supplied each month which allows for some adjustment.But Saudi Arabia does not want to cut its own supply if the shortfall will simply be made up by increases from other exporters producing similar crude oils.Iran, Iraq, Oman and Russia all produce medium and heavy sour crudes with similar characteristics to Saudi crude.For that reason, the kingdom insisted they were all bound by production limits in the OPEC/non-OPEC agreement. But even with the OPEC/non-OPEC agreement, it is still difficult to cut exports without leaving important customers disappointed and looking for alternatives.
Saudi Arabia may insist on Iran oil output cuts to continue OPEC deal: sources - Geopolitical rivals Saudi Arabia and Iran may be headed for another OPEC showdown, as the producer group enters negotiations over extending oil production cuts in force since January. Saudi Arabia may demand that Iran, which is allowed a slight rise in output under the deal, commit to an output reduction as a condition of continuing the cuts, people familiar with the kingdom's thinking told S&P Global Platts. The provision is among several that Saudi Arabia, tired of seeing its market share eroded as it bears most of the burden of OPEC's agreed cuts, is likely to come to the table with, sources say. These include stipulations on members who have exceeded their quotas and exempt members nearing full production capacity, notably Nigeria.But it is Iran that is likely to be the biggest sticking point given historic distrust between the two countries, as talks among OPEC members ramp up amid signs that the global inventory glut remains stubbornly high. "We do expect that the Saudis will have demands on both poorly complying deal participants and those exempted like Iran for the second half," said Bob McNally, president of energy consultancy Rapidan Group. "We expect some tension ahead of the May 25 meeting, but as we have seen ministers will temper disgruntlement with supportive public comments so as not to spook investors," he added. Saudi energy officials declined to comment on their plans, with one telling Platts on condition of anonymity that "it is too early" to discuss the particulars of negotiations that have yet to start. Iranian energy officials did not respond to requests for comment. Any move to rein in Iran's production is likely to be met with significant resistance, experts say.
OilPrice Intelligence Report: No OPEC Deal Extension Without Cut From Iran -- Fitch Ratings slashed Saudi Arabia’s credit rating by one notch to A+ from AA- over concerns about public finances. The downgrade comes as Saudi Arabia and other major oil producers struggle with the dilemma of allowing oil prices to sink lower or make painful production cuts in order to keep prices elevated. Fitch also questioned whether or not the proposed economic reforms in Riyadh will be implemented. “The scale of the reform agenda risks overwhelming the government’s administrative capacity,” Fitch said. Speculation about whether or not OPEC will extend its production cut deal for another six months will be one of the most significant variables affecting oil prices in the short run. S&P Global Platts reports that Saudi Arabia might only agree to an extension if Iran agrees to cut its production, something that it did not have to do as part of the initial deal. Iran agreed to a cap on production slightly higher than its October baseline for the January to June period, but Saudi Arabia is growing tired of taking on the bulk of the sacrifice for the market adjustment and might stipulate that other countries make a larger sacrifice if the deal is to be extended through the end of the year. OPEC officials are huddling in Kuwait this weekend to gauge the health of the oil market and figure out next steps. They won’t make any decisions until May at least, but they will likely discuss the painfully slow pace of market adjustment. A survey of 13 oil market analysts by Bloomberg concludes that OPEC has little choice but to continue their production cuts. “They’ll probably think they need to grin and bear it longer,” Citi’s Ed Morse said. “The glue that bound them together to begin with, which was higher prices, is the glue that will continue to bind them together.” Libya offered oil bulls a glimmer of hope in early March when it lost nearly 100,000 bpd in production because of fighting between competing factions over the country’s largest oil export terminals. However, production is back up to 700,000 bpd and Libya’s National Oil Company (NOC) has hopes of making much larger gains this year. If Libya adds another 400,000 bpd by August, it will be hugely bearish for oil prices. The markets are not taking into account this supply potential, and it could blindside investors.
An OPEC Deal Extension Isn't As Simple As It Sounds - It’s been six months now that oil prices have been reacting to OPEC, first to the possibility of an agreement, and then to the production cut deal itself, forged by OPEC to rebalance the market. The deal--initially aired as ‘an agreement to agree on a deal’ in September and signed at the end of November—will likely impact the market for at least the next six months. The agreement clearly states that it is production that OPEC producers are vowing to cut, but Iraqi oil minister Jabbar al-Luaibi has recently claimed—rather emphatically—that it is exports, not production, that serve as the baseline for the cuts. And according to Iraq, the agreed-upon cuts have been all about exports all along. Of course, exports are the logical ‘by-product’ of production of oil exporting nations, but each of those producers feels the weight of production cuts differently. Each OPEC nation has a specific domestic demand for oil based on population numbers and the share of oil and petroleum products in the energy mix and electricity generation. Each member has unique buyers of their crude, along with differing agendas in keeping and/or growing market shares in various corners of the world. To cut exports rather than production would hit hard the bottom lines of those who are heavy exporters, so it’s quite clear why an oil cartel whose self-proclaimed mission is to secure “a steady income to producers” chose to cut “production” instead of “exports” in its latest supply-cut agreement.OPEC producers—especially Saudi Arabia, which shoulders the biggest share of cuts—are desperately trying to maintain their most important market shares such as those in Asia, while measuring exports bound for other destinations in its attempt to comply with the production cuts. The cartel would have never used the language ‘exports’ in a deal to cut supply, because cutting their exports would mean they would hold a smaller market share. Having a smaller footprint globally would, in turn, mean that OPEC would wield less influence over the price of oil. It’s doubtful OPEC would ever agree to such an unappealing scenario.
Saudi king's Asia tour trumpets Aramco's moves downstream | Reuters: Saudi King Salman's lavish tour of Asia, arriving in each country on a golden escalator with 400 tonnes of luggage, had a hardnosed marketing mission - to cement the kingdom's place as leading oil supplier to the world's biggest consumer region. The string of deals inked on his three-week tour to Malaysia, Indonesia, Japan and China also point to a fresh strategy, one to increase Saudi leverage over refined product and petrochemical markets, known as the downstream sector. "Our strategy is about growth in the downstream," said Amin Nasser, chief executive officer of state oil company Aramco, told Reuters on Sunday. "The growth in that sector is very important, and anything integrated between refining, petrochemical, with marketing and distribution, is of interest to us." Saudi Arabia's main influence on oil markets has been via the Organization of the Petroleum Exporting Countries (OPEC), of which it is the de-facto leader. But OPEC's ability to control prices by turning the oil pumping spigots on and off has waned as non-OPEC producers like Russia and, more recently, U.S. shale drillers, have ramped up output and eroded its grip on market share. One indication of a shift in Saudi strategy came on the first leg of the tour in Kuala Lumpur. Aramco signed a deal to take a $7 billion investment, in a joint venture with Malaysia's state oil company Petronas in a refinery and petrochemical project known as RAPID (Refinery and Petrochemical Integrated Development).
Saudi Arabia Downgraded By Fitch To A+ On Soaring Fiscal Deficit, Deteriorating Balance Sheet --With Saudi Arabia scrambling to respond to surging US shale production in what many analysts warn is a lose-lose decision, as either Saudi Arabia will lose market share under the current status quo, or government revenue will tumble should the Vienna 2016 production cut deal be cancelled, moments ago Fitch poured some fuel on the fire, when it downgraded the Saudi Kingdom from AA- to A+, as a result of the country's soaring deficit, declining reserves, and a deteriorating balance sheet.Full report below: Fitch Ratings has downgraded Saudi Arabia's Long-Term Foreign and Local Currency Issuer Default Ratings (IDRs) to 'A+' from 'AA-'. The Outlooks are Stable. The issue ratings on Saudi Arabia's senior unsecured foreign-currency bonds have also been downgraded to 'A+' from 'AA-'. The Country Ceiling has been downgraded to 'AA' from 'AA+' and the Short-Term Foreign and Local Currency IDRs have been affirmed at 'F1+'. The downgrade of Saudi Arabia's Long-Term IDRs reflects the continued deterioration of public and external balance sheets, the significantly wider than expected fiscal deficit in 2016 and continued doubts about the extent to which the government's ambitious reform programme can be implemented. Government deposits declined by SAR240bn to SAR841bn (35% of 2016 GDP) between June 2016 and January 2017, only about half the peak level of SAR1,643bn in August 2014, although this decline partly reflects transfers between the government and the Public Investment Fund (PIF). General government debt rose to 9.7% of GDP, from 4% in 2015. This included sales of local-currency bonds during the first three quarters of last year and a USD17.5bn Eurobond issued in October. The government balance sheet remains strong relative to 'A' and 'AA' category peers but will become less of a support for the rating unless the deterioration in public debt dynamics is arrested.The deterioration in the government balance sheet reflects the large central government budget deficit of SAR416bn or 17.3% of GDP in 2016, up from SAR362bn in 2015 and much higher than the budget target of SAR326bn. The deterioration was mainly due to the clearance of arrears on capital expenditure of SAR75bn. The arrears arose in 2015 because payments for many projects were halted while the government was seeking greater visibility on the entirety of outstanding project commitments.
Are U.S.-Saudi Relations Turning Sour? -- Time will tell, but cries of “victory in Washington” by Saudi Arabian Deputy Crown Prince and Defense Minister Mohammed bin Salman seemed hollow and perhaps even apocryphal. He needed some sign of success when he emerged from his White House meeting with U.S. Pres. Donald Trump on March 14, 2017: Saudi Arabia is running out of options and is pushing its traditional allies - some of which are not happy with it - to show solidarity, particularly over the wars in Yemen, Iraq, Syria, and Libya. And at a time when the Kingdom’s economic fortunes are delicate and worsening, presaging internal political pressures.Prince Mohammed seemed to want to sweep Pres. Trump into the Saudi camp - and to speak for all Muslims and how the Trump Administration would be good for them — but he was, in fact anxious to exorcise the President’s apparently blossoming friendship with Egyptian Pres. Abdul Fattah al-Sisi, now Prince Mohammed’s nemesis. So the Saudi-Egyptian animosity extended to Washington as it became clear that the new U.S. Administration would not automatically continue any Middle Eastern policies of the former U.S. Administration.The stakes are of global significance to the U.S., but if Washington had to choose, it would choose the geopolitical (Mediterranean-Suez-Red Sea) and cultural weight of Egypt. Saudi Arabia’s recent rivalry with Egypt — or, rather, the falling out between Saudi Deputy Crown Prince Mohamed and Egyptian Pres. al-Sisi — has meant that the government of each state has attempted to sway the U.S. to its side, but with Washington giving away little as to its preference. It does not wish to fully alienate Saudi Arabia at this stage, or its neighbor and fellow-Wahhabist state, Qatar, but Egypt’s strategic position cannot be ignored.
800 Families File Lawsuit Against Saudi Arabia Over 9/11 -- Eight-hundred families of 9/11 victims and 1,500 first responders, along with others who suffered as a result of the attacks, have filed a lawsuit against Saudi Arabia over its alleged complicity in the 2001 terror attacks, according to an exclusive report by local New York outlet Pix 11. The legal document, filed in a federal court in Manhattan, describes the Saudi role in the attacks. Pix 11 reports: “The document details how officials from Saudi embassies supported hijackers Salem al-Hazmi and Khalid Al-Mihdhar 18 months before 9/11. “The officials allegedly helped them find apartments, learn English and obtain credit cards and cash. The documents state that the officials helped them learn how to blend into the American landscape.” For years, suspicions have swirled that some Saudi officials had ties to the gruesome attacks. The recent release of FBI reports produced shortly after the attacks provided details to justify growing skepticism against the Saudis. These details were further bolstered by therelease of 28 pages originally withheld from the 9/11 commission report. Though the U.S. government downplayed the findings, even some lawmakers expressed concern.
Aid Officials Beg Congress to Help Yemen, While Trump Sends More Bombs - As the Trump administration resumes weapons shipments to Saudi Arabia for its devastating bombing campaign in Yemen — including precision-guided weapons the Obama administration had suspended on human rights grounds — a State Department official told Congress that the two-year-long conflict has led to the largest starvation emergency in the world. Gregory Gottlieb, an acting assistant administrator for the U.S. Agency for International Development (USAID), told the Senate Foreign Relations Committee Wednesday that the conflict — which the U.S. is a silent partner to — has left the majority of the Yemeni people struggling to find food.“In Yemen, more than 17 million people — an astounding 60 percent of the country’s population — are food insecure, including 7 million that are unable to survive without food assistance,” said Gottlieb. “This makes Yemen the largest food security emergency in the world.”Gottlieb was testifying at a Senate hearing on foreign aid funding and humanitarian crises in Nigeria, South Sudan, Yemen, and Somalia.USAID is the foreign assistance arm of the State Department — the same department that signs off on arms sales to Saudi Arabia. Since Saudi Arabia began bombing Yemen in March 2015, the U.S. has approved more than $20 billion in weapons sales to Saudi Arabia — and looked the other way as the Saudi-led coalition has bombed civilian infrastructure, hospitals, and children’s schools. Last week the UN warned that the majority of Yemen’s population is suffering and on the brink of famine. Stephen O’Brien, the UN’s undersecretary-general for humanitarian affairs, criticized both sides of the conflict for restricting the flow of aid, but said that the Saudi-imposed naval blockade was particularly devastating for the desert country, which imports most of its food. The Saudi-led coalition has persistently attacked fisherman, who account for another major food source in Yemen.
Starving Yemen to Death -- Yemen and Somalia are running out of time to be saved from famine: The world has only three to four months to save millions of people in Yemen and Somalia from starvation, as war and drought wreck crops and block deliveries of food and medical care, the International Committee of the Red Cross said Wednesday. There is urgent need for aid in both countries, as well as in Nigeria and South Sudan, but Yemen’s civilian population faces the most severe and widespread crisis. It is in Yemen where outside intervention and blockade have done the greatest harm. As a result, seven million people are on the verge of starving to death and another ten million people are not far behind. It can’t be emphasized enough that this is something that has been done to the people of Yemen on purpose by the Saudi-led coalition with the political and military support of the U.S. and Britain. All of these governments are not merely allowing millions of Yemenis to starve to death, but have worked to cause their starvation. If Yemen’s war has generally been neglected by the rest of the world, its humanitarian crisis has been similarly ignored. Appeals to fund relief efforts have gone unfulfilled, and the sheer scale and severity of the crisis has been overlooked by most. Even now that the crisis is beginning to receive some attention, it is almost too late. By the time that famine is officially declared in Yemen, it will be too late for millions of people, many of whom will have already died. Unlike in some other conflicts where U.S. influence is limited or non-existent, our government has the leverage to make the coalition halt its campaign and lift its blockade of the country, but it has to be willing to use it. There is no hint that the new administration would even consider this course of action, but if they don’t they will go down along with the previous administration as enablers of one of the worst man-made famines in modern times.
Pentagon Denies Bombing Syrian Mosque, But Its Own Photo May Prove That It Did - The Pentagon spokesperson insisted that the U.S. airstrike in the rebel-held village of Al-Jina in northern Syria on Thursday night did not hit a mosque. “The area was extensively surveilled prior to the strike in order to minimize civilian casualties,” Navy Captain Jeff Davis wrote in an email. “We deliberately did not target the mosque.” He even unclassified and circulated a photo. And he pointed out that on the left, you can see a small mosque, still standing. But to the people on the ground, the photo tells a different story. Activists and first responders say the building that was targeted was a part of the mosque complex — and that the charred rubble shown in the photo was where 300 people were praying when the bombs began to hit. More than 42 people were killed and dozens more injured, according to monitoring groups and local activists. First responders with the Syrian Civil Defence — known as the “White Helmets” — rushed to treat the wounded and dig corpses out of the rubble. An administration official told the Washington Post that two armed, Reaper drones fired “roughly [the] entirety of their Hellfire payload and followed up w/ 500 lb bomb.” The building “was holding a meeting of al Qaeda members,” Maj. Adrian Rankine-Galloway, a Pentagon spokesperson told The Intercept. Davis said military officials “believe dozens of core al Qaeda terrorists were killed.” According to the monitoring group Airwars, locals say the building the drones struck is part of a mosque and religious school, which was built as an expansion several years ago. Local activist Mohamed al Shaghel told the New York Times that the people in the building had “no affiliation with any military faction or any political side.”
Syria war: ‘Worst man-made disaster since World War II’ -- Six years to the day since protesters poured into the streets of Daraa, Damascus and Aleppo in a "day of rage" against the rule of President Bashar al-Assad, Syria's uprising turned global war is far from over. Six years of violence have killed close to half a million people, according to the Syrian Centre for Policy Research, displaced half of the country's prewar population, allowed the Islamic State in Iraq and the Levant (ISIL, also known as ISIS) to seize huge swaths of territory, and created the worst humanitarian crisis in recent memory. International diplomatic efforts have repeatedly failed to bring the protracted conflict closer to an end and the growing role of outside actors has changed the nature and trajectory of the war. The UN estimates the war has pushed close to five million people to flee the country, many of whom have risked their lives seeking sanctuary in Europe. Hundreds of thousands of others exist precariously in tents and tin shelters in Syria's neighbouring countries. An entire generation of Syrian children has either been pushed out of school or forced to cope with interrupted curriculums, makeshift classrooms, or unqualified teachers. According to UNICEF, 2016 was the worst year yet for Syrian children. Nearly three million children - the UN estimated amount of Syrians born since the crisis began - know nothing but war. The country's healthcare system, particularly in places like Aleppo, is decimated. More than four-fifths of the country live in poverty. Basic infrastructure, such as the electricity grid, water lines and roads, is in shambles. As of 2015, 83 percent of Syria's electric grid was out of service, according to a coalition of 130 non-governmental organisations.
US-led coalition air strike in Syria kills more than 30 people in school near Isis-held Raqqa, says human rights watchdog 0 At least 33 people have been killed in an air strike on a school sheltering displaced people near the Isis-held city of Raqqa, Syria, a monitoring group has said. The UK-based Syrian Observatory for Human Rights said it was believed the US-led coalition had carried out the attack. Observatory activists counted at least 33 bodies at the site of the strike, near the village of al-Mansoura, west of Raqqa, Observatory director Rami Abdulrahman told Reuters. The air strike took place earlier this week, he added.
- #Raqqa 1-Airstrikes by Coalition warplanes destroyed completely Al Badia School in Mansora Town the school have more then 50 families #Syria— الرقة تذبح بصمت (@Raqqa_SL) March 21, 2017
- 2-all the families are Displaced civillans from #Raqqa & #Aelppo countryside ,Their fate remains unknown #Syria #ISIS — الرقة تذبح بصمت (@Raqqa_SL) March 21, 2017
"The massacres committed by [the] US-led coalition in Raqqa is unacceptable," the group later tweeted. "The international community must intervene to stop this." The group said families were still unaccounted for.
Air strikes on Isis-held Mosul 'leave 230 civilians dead', reports local media | The Independent: A correspondent for Rudaw, a Kurdish news agency operating in northern Iraq, said that 137 people – most believed to be civilians – died when a bomb hit a single building in al-Jadida, in the western side of the city on Thursday. Another 100 were killed nearby. “Some of the dead were taking shelter inside the homes,” Hevidar Ahmed said from the scene. Women and children treated for chemical weapon exposure in Mosul A spokesperson for Central Command, which coordinates US military action in Iraq, told The Independent they were aware of the loss of civilian life as reported by Rudaw and the information had been passed on to the civilian casualty team for “further investigation”. “[The US-led coalition] takes all reports of civilian casualties very seriously and assesses all incidents as thoroughly as possible. Coalition forces work diligently to be precise in our air strikes and ensure that all strikes comply with the [internationally agreed] Law of Armed Conflict,” Captain Timothy Irish said. A daily assessment report from Central Command stated that five strikes near Mosul on Thursday had destroyed five Isis units and a sniper team, as well as 11 fighting positions, vehicles and artillery equipment. No other fighting force in the country has the capability to launch an aerial attack of the scale reported.
US military investigating if airstrikes caused nearly 300 civilian deaths -- The US military is investigating whether it was responsible for the deaths of nearly 300 Syrian and Iraqi civilians in three different sets of airstrikes this month.Civilian casualties have been alleged in all three instances, but each situation is different and complex, a US defense official said. So far, there is no indication of a breakdown in US military procedures governing airstrikes, the official stressed, and the US is not contemplating a pause in military operations.But the potential that the US is responsible for some, or all, of the deaths is considered serious enough that Central Command, which oversees operations in Iraq and Syria, is working around the clock trying to assess exactly what happened, the official said.The possibility of US military responsibility in civilian deaths illustrates the growing challenge of conducting increased airstrikes in the densely populated neighborhoods of both west Mosul and Raqqa, officials said. The most extensive case involves western Mosul. The US military is trying to determine if sometime between March 17 and March 23, bombs dropped in a neighborhood by US warplanes resulted in the deaths of more than 200 civilians. The incidents military officials are looking into are based largely on local reports and social media accounts of the strikes.
US: Team Up with Kurds Not Turkey to Destroy Islamic State - The problem with letting the Turks hold Raqqa and presumably the entire Euphrates Valley that is now held by ISIS is that the Turks are endeavoring to hem in the Kurds. To do this, Turkey hopes to establish its Arab proxies in a new “Euphrates state” in eastern Syria. This would partition Syria into three states: a western Asad-ruled state; an eastern Turkish and Sunni Arab rebel-ruled state, and a northern Kurdish state.Asad’s army has already taken a large swath of territory east of Aleppo, which cuts off Turkey’s access to Raqqa from al-Bab. Turkey has proposed taking Raqqa from the north at Tel Abyad. This approach would penetrate the Kurdish region at its middle and cut it in two. This objective of splitting the autonomous Kurdish region in two is the main reason Turkey offered to take Raqqa.If the United States helps or allows Turkey to attack the Kurds at Tel Abyad, it will have no Kurdish allies to attack Raqqa or any other part of ISIS territory.Why are the Kurds willing to take Raqqa even though they do not have territorial interests in and around Raqqa? They are investing in their relationship with the United States. They assume that it will serve them well over the long run when it comes to their political aspirations. They will get a lot of good training; they will get a dollop of heavy weaponry from the United States, which I doubt it can reclaim after the fight; they are building a command and control network for their force. By the time this operation is over, one can guess that the Kurds of Syria will have four reasonably well trained, well organized, and well armed brigades that they did not have before. One also suspects that there will be some military loot in Raqqa, which will fall their way.*
Saudi Aramco inks term crude supply with China's CNOOC for Huizhou refining project - Saudi Aramco has signed a one-year crude supply contract with China National Offshore Oil Corp. for its upcoming Phase 2 Huizhou refining project, as Saudi Arabia steps up efforts to secure its share in its largest market, where its top supplier status was recently threatened. Under the contract that was signed earlier this year, the Saudi national oil company will supply one VLCC per month of Arab Medium crude oil to CNOOC for a year, starting from the second half of 2017, sources close to the two companies said Wednesday. CNOOC expects to start up the 200,000 b/d Phase 2 project in Huizhou, southern China, in May 2017. CNOOC may also consider raising the lifting volume of Saudi crude once the Phase 2 project is running, one source said. The initial volume translates to a total supply of 22 million-26 million barrels over 12 months, considering each VLCC can carry around 1.8 million-2.2 million barrels of crude. Unlike the existing Phase 1 crude processing units, which are designed to process heavy, sweet crude, CNOOC's Phase 2 refining project is designed to process sour crude from the Middle East. The plant will also process domestic crude produced at CNOOC's own offshore oil fields, a source with CNOOC said. Once the Phase 2 project starts commercial operations, Huizhou refinery's total primary crude processing capacity will be raised to 22 million mt/year.
Analysis: Chinese independent refiners' crude oil imports set to slow on quota issues - Crude imports by China's independent refiners are expected to slow down in the coming months as several refiners have used up most of their allocation from the first round of import quotas and will need to wait until June for the second round before resuming purchases. Watch Market Movers, Mar 20-25: Potential changes in China's oil, gas sector; OPEC, non-OPEC oil output cut compliance Independent refiners need government-allotted quotas to import crude oil. A total of 45.64 million mt of quotas were allocated to 19 independent refineries in the first round in January. The refiners have submitted applications for a second batch of quotas, but the government is only expected to allocate fresh quotas in June leaving the refiners with the option of either reducing throughput or buying barrels from the domestic spot market, market sources said.China's independent refineries imported a total of 60 million mt (1.2 million b/d) of crude oil in 2016, according to S&P Global Platts estimates. This represented 16% of China's total imports of 381 million mt in 2016. The quota allotted to each refiner in the first round was based on the volume the refiner had imported in the first 10 months of 2016. This resulted in some refiners getting sufficient quotas in the first round to sustain themselves for the entire year, but refiners that imported a relatively small volume in the first 10 months of 2016 are suffering from a quota shortage, especially if they raised runs this year.