US oil prices rose for the 4th week in a row over the past week, blowing through a two year high on Friday after Baker Hughes reported the largest drop in oil rigs since last year....after rising 4.3% last week to a 6 month high of $53.90 a barrel, contracts for US crude for December rose another 25 cents to an eight month high of $54.15 on Monday on further expectations that those OPEC-led production cuts would be extended beyond March...prices then rose 23 cents more on Tuesday, on analyst's reports that the spike in U.S. crude exports over recent weeks would push US crude prices even higher...oil prices then slipped 8 cents to $54.30 a barrel on Wednesday, largely because the EIA's report of a drop in US crude supplies was not as great as has been expected, based on the prior day's report from the American Petroleum Institute...oil prices then returned to the upside on Thursday, increasing 24 cents to $54.54 a barrel, bolstered by indications that OPEC-led output cuts had tightened the market and drained inventories...while oil prices were mixed on Friday morning, they then spiked up more than 2% in the afternoon after the rig count report showed the largest drop in oil rigs this year, with oil closing up $1.10 on Friday at $55.64 a barrel, ending the week with an increase of $1.74 a barrel, a gain of 3.2% on last week's price..
below, i've copied a graph to show this week's drop in the rig count, and the rough relationship between the price of oil and the number of rigs deployed drilling for oil over time...
the above graph was copied from a short post on Friday at Zero Hedge titled "US Oil Rig Count Drops Most Since May 2016 To 5-Month Lows", and it shows the oil rig count, as per Baker Hughes, as a blue graph from roughly mid-April to the present, and then below that, in the form of a red bar graph, the weekly change in the count of the rig count, with an increase in oil rigs represented by a red bar pointing upward from the "0" line, and a decrease in oil rigs represented by a red bar pointing downward from the "0" line...thus this week's decrease of 8 oil rigs is the largest decrease in oil rigs since mid May 2016...the chart also indicates with a charcoal grey line price of WTI, or West Texas Intermediate, the US benchmark price of oil, pulled forward on the graph three months ahead of the rig count dates (calling prices "lagged" is probably a misnomer - it's the drilling that lags)...mislabeling of the graph notwithstanding, what they do show is the rough relationship between the price of oil and the rig count, with it taking about three months for a change in the price of oil to be reflected in the number of active oil rigs; by pulling the price graph forward three months, they're showing that the current downturn in oil drilling is in response to the drop of the price of oil to the $45 a barrel range in August....what that relationship thus portends in light of this week's two year high in oil prices, however, is a return to the oilfields by the drillers sometime around February (lagged 3 months because it takes roughly that long to line up and contract for a rig and a crew and get them in place from the time that the decision to go ahead is made)
The Latest US Oil Data from the EIA
this week's US oil data from the US Energy Information Administration, covering details for the week ending October 27th, showed a large drop in our oil imports while our oil exports rose to a record level, and hence there was a sizable withdrawal of oil from storage to meet the needs of our refineries, which saw little change in throughput from the prior week....our imports of crude oil fell by an average of 552,000 barrels per day to an average of 7,571,000 barrels per day during the week, while our exports of crude oil rose by 209,000 barrels per day to a record 2,133,000 barrels per day, which meant that our effective imports netted out to an average of 5,438,000 barrels per day during the week, 761,000 barrels per day less than during the prior week...at the same time, field production of crude oil from US wells rose by 46,000 barrels per day to an average of 9,553,000 barrels per day, which means that our daily supply of oil coming from net imports and from wells totaled an average of 14,991,000 barrels per day during the reported week...
at the same time, US oil refineries were using 16,015,000 barrels of crude per day, 10,000 barrels per day less than they used during the prior week, while over the same period 461,000 barrels of oil per day were being withdrawn from oil storage facilities in the US....hence, this week's crude oil figures from the EIA seem to indicate that our total supply of oil from net imports, from oilfield production and from storage was 563,000 fewer barrels per day than what refineries reported they used during the week...to account for that discrepancy, the EIA needed to insert a (+563,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, which they label in their footnotes as "unaccounted for crude oil"...
further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports rose to an average of 7,699,000 barrels per day, statistically unchanged from the 7,695,000 barrels per day average imported over the same four-week period last year....the total 461,000 barrel per day withdrawal from our total crude inventories came about on a 348,000 barrel per day withdrawal from our commercial stocks of crude oil and a 113,000 barrel per day emergency withdrawal of oil from our Strategic Petroleum Reserve, which apparently is still being tapped to address short term spot shortages caused by this year's hurricanes...this week's 46,000 barrel per day increase in our crude oil production included a 43,000 barrel per day increase in output from wells in the lower 48 states and a 3,000 barrels per day increase in output from Alaska....the 9,553,000 barrels of crude per day that were produced by US wells during the week ending October 20th was 8.9% more than the 8,770,000 barrels per day we were producing at the end of 2016, and 12.1% more than the 8,522,000 barrels per day of oil we produced during the during the equivalent week a year ago, while it was still 0.6% below the record US oil production of 9,610,000 barrels per day set during the week ending June 5th 2015...
US oil refineries were operating at 88.1% of their capacity in using those 16,015,000 barrels of crude per day, up from 87.8% of capacity the prior week, a fairly normal pace for a fall seasonal maintenance period...the 16,015,000 barrels of oil that were refined this week were 9.6% less than the 17,725,000 barrels per day that were being refined the week before Hurricane Harvey struck at the end of August, but were still 3.7% more than the 15,448,000 barrels of crude per day that were being processed during week ending October 28th, 2016, when refineries were operating at 85.2% of capacity...
even with little change in the amount of oil refined, gasoline output from our refineries was higher, increasing by 251,000 barrels per day to 10,187,000 barrels per day during the week ending October 27th, which was also 3.7% higher than the 9,824,000 barrels of gasoline that were being produced daily during the comparable week a year ago....in addition, our refineries' production of distillate fuels (diesel fuel and heat oil) rose by 241,000 barrels per day to 5,036,000 barrels per day, which was 8.0% more than the 4,662,000 barrels per day of distillates that were being produced during the week ending October 28th last year....
even with the increase in our gasoline production, our gasoline inventories at the end of the week fell by 4,020,000 barrels to 212,849,000 barrels by October 27th, after falling by 5,456,000 barrels the prior week, as our domestic consumption of gasoline rose by 147,000 barrels per day to 9,461,000 barrels per day, as Americans continue to burn far more gasoline than they did last year...meanwhile our exports of gasoline fell by 139,000 barrels per day to 767,000 barrels per day, while our imports of gasoline rose by 307,000 barrels per day to 540,000 barrels per day...with significant gasoline supply withdrawals in 14 out of the last 20 weeks, our gasoline inventories are now down by 12.2% from June 9th's level of 242,444,000 barrels, and 4.9% below last October 28th's level of 223,804,000 barrels, even as they are still roughly 2.7% above the 10 year average of gasoline supplies for this time of the year...
with our distillates production little changed, our supplies of distillate fuels fell by just 320,000 barrels to 128,921,000 barrels over the week ending October 27th, the eighth decrease in nine weeks, after falling by 5,246,000 barrels the prior week...that was as the amount of distillates supplied to US markets, a proxy for our domestic consumption, fell by 567,000 barrels per day to 3,534,000 barrels per day, and as our exports of distillates rose by 237,000 barrels per day to a record 1,685,000 barrels per day, while our imports of distillates rose by 4,000 barrels per day to 137,000 barrels per day...after this week’s decrease, our distillate inventories ended the week 14.4% lower than the 150,550,000 barrels that we had stored on October 28th, 2016, and 6.5% lower than the 10 year average for distillates stocks for this time of the year…if the forecast La Nina materializes, we will see a shortage of heat oil this winter...
finally, with our oil exports hitting a new record high while our oil imports were dropping, our commercial crude oil inventories fell for the 25th time in the past 30 weeks, decreasing by 2,435,000 barrels, from 457,341,000 barrels on October 20th to 454,906,000 barrels on October 27th...while our oil inventories as of October 27th were 5.7% below the 482,578,000 barrels of oil we had stored on October 28th of 2016, they were still 1.5% higher than the 447,994,000 barrels in of oil that were in storage on October 30th of 2015, and 30.4% greater than the 348,935,000 barrels of oil we had in storage on October 31st of 2014...
since the major story in the oil data continues to be our ongoing record exports, we'll again include this week's graph of them so you can see how much they've jumped...
the above graph comes from a weekly emailed package of oil graphs from John Kemp of Reuters, and shows weekly US crude oil exports in thousands of barrels per day over the past 14 months, and also gives us the exact amount of our crude exports in thousands of barrels per day over each of the past 9 weeks...it's clear that our oil exports over the last 6 weeks have breached new levels never seen before, as US drillers would rather sell their oil overseas when the international price continues to be a large premium over the domestic price...
and even while this week our exports were at a record 2,133,000 barrels per day, an article from Reuters appearing at the Christian Science Monitor discussed the logistics of our exporting as much as 3.5 million barrels a day...with total US crude production currently at 9.5 million barrels a day, if we plan to export 3.5 million barrels a day, that will only leave 6 million barrels of our production a day for our own use.....with US refineries typically using 16 to 17 million barrels per day of crude, 3.5 million barrels of exports would mean we'll have to import more than 10 million barrels each day to meet our needs...
now, here's the kicker, right from the scripture of 'the wisdom of markets'...exports from the US are being sold benchmarked to the price of WTI, right now around $55.64 a barrel...but what we import is benchmarked to Brent at $62.07, or to the OPEC basket price, which closed the week at $58.49...so every barrel crude that we export ends up being replaced by more expensive foreign oil...where is the wisdom in that?
This Week's Rig Count
US drilling activity decreased for the 5th week in a row and for 11th time in the past 14 weeks during the week ending November 3rd, with both oil and natural gas rigs seeing cutbacks...Baker Hughes reported that the total count of active rotary rigs running in the US fell by 11 rigs to 898 rigs in the week ending on Friday, which was still 329 more rigs than the 569 rigs that were deployed as of the November 4th report in 2016, while it was well less than half of the recent high of 1929 drilling rigs that were in use on November 21st of 2014....
the number of rigs drilling for oil decreased by 8 rigs to 729 rigs this week, their 11th decrease in 13 weeks and, as we noted earlier, the largest drop in oil drilling since May 2016...that still left active oil rigs up by 279 over the past year, while their count remained far from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations decreased by 3 rigs to 169 rigs this week, which was the smallest natural gas rig deployment since April 21st and just 52 more gas rigs than the 117 natural gas rigs that were drilling a year ago, and way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...
two oil platforms that had been drilling offshore from Louisiana were shut down this week, leaving just 18 rigs active in the Gulf of Mexico, down from the 21 rigs drilling in the Gulf a year ago....the count of active horizontal drilling rigs was down by 5 rigs to 764 rigs this week, which was the smallest number of horizontal rigs active since May 19th...however, the week's horizontal deployment was still up by 305 rigs from the 459 horizontal rigs that were in use in the US on November 4th of last year, while down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014....in addition, the vertical rig count was also down by 5 rigs to 61 vertical rigs this week, which was still up from the 58 vertical rigs that were working during the same week last year....at the same time, the directional rig count was down by 1 rig to 73 rigs this week, which was still up from the 52 directional rigs that were deployed on November 4th of 2016...
the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of November 3rd, the second column shows the change in the number of working rigs between last week's count (October 27th) and this week's (November 3rd) count, the third column shows last week's October 27th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was for the 28th of November, 2016...
as we can see from the difference between the two tables above, this week saw a much larger turnover of rigs on a state basis than would be indicated by the total rig count or by the major basin counts in the second table...despite overall drilling being down by 11 rigs this week, Colorado saw the addition of 4 rigs, Texas added 3 more, and Alaska added two, and only two of those 9 rig increases - in the Niobrara and the Permian - show up in the major basin count variances...similarly, while Oklahoma shed eight rigs, only the single rig decline in the Ardmore Woodford and the 2 rig decline in the Arkoma Woodford are shown in the second table...furthermore, one would think that the 3 rig drop in the Haynesville would account for the 3 natural gas rigs that were shut down, but that's not the case; there had been two oil rigs working in the Haynesville, and now they're both gone; all 38 Haynesville rigs now target gas...the other two natural gas shutdowns were in the Arkoma Woodford...moreover, in addition to the changes shown in the state table above, Alabama also had one rig shut down, and now has just one, which is still up from a year ago, when they had none; Mississippi had two rigs shut down and also have just one left, down from two a year ago; Nebraska saw the lone rig that was started last week shut back down, which had been the only drilling in the state over the past year; while Montana saw a rig start up for the first time in 1 weeks, while a year ago they had none...
Fairmount Santrol Completes Debt Refinancing With a New $700 Million, 5-Year Term Loan Facility and Secures a New $125 Million, 5-Year Revolving Credit Facility --CHESTERLAND, Ohio - Fairmount Santrol, a leading provider of high-performance sand and sand-based product solutions, today announced it entered into a new Term Loan B credit facility to refinance its existing Term Loan B credit facilities and also secured a new revolving credit facility resulting in extended maturities. As part of the refinancing, the Company used cash on hand to continue to reduce its overall debt. The new Term Loan B credit facility retains the minimal covenant features of the Company’s previous loans. As of September 30, 2017, the Company’s outstanding Term B-2 Loans and Extended Term B-1 Loans balance was $781.4 million, which is net of $1.3 million from the original issue discount. The Company entered into an agreement for a new $700 million, 5-year Senior Secured Term Loan B (the “Term Loan B”) and a new $125 million, 5-year asset-based revolving credit facility (the “ABL Revolver”) to refinance the majority of its existing Term B-2 Loans and Extended Term B-1 Loans. The remaining $82.7 million in Term B-2 Loans and Extended Term B-1 Loans were paid off by using $32.7 million of cash on hand and $50 million that the Company borrowed upon closing the new ABL Revolver. The Company also expects to incur approximately $8 million for cash fees and other costs associated with the refinancing in the fourth quarter 2017. In addition, the Company expects to book a non-cash write-off of part or all of the deferred financing fees associated with the prior term loans and revolving credit facility in the fourth quarter 2017. Pro forma total debt following the refinancing is expected to be $752.9 million versus $794.5 million as of September 30, 2017.
City Council Rejects NEXUS Offer For Easement - The Oberlin Review - City Council held an emergency meeting Saturday, deciding to reject a $3,500 offer from NEXUS for means of access. The offer would have given NEXUS the legal right to use city property without owning it, granting the company the ability to begin building its pipeline.The Oberlin Community Bill of Rights, which was created in 2013, prohibits the creation of infrastructure relating to fracking in the city. City Councilmember Bryan Burgess added that the city also does not have authorization to allow oil or gas infrastructure in Oberlin.City council also agreed to authorize the City Manager Rob Hillard to negotiate with NEXUS for an easement on the condition that the pipeline would be rerouted so that it would be farther away from Oberlin homes, businesses, and the local fire station. The current pipeline route runs just north of the homes on Reserve Avenue near the edge of the city, close to New Russia Township.John Elder, vice president of Oberlin’s Citizens for Safe and Sustainable Energy, said that this placement would leave the fire station, businesses, and residences in the “blast zone” in the event of a disaster.According to Elder, other concerns include the possible negative environmental impact of the pipeline. It will move through wetlands and have four compression stations, which would contribute to air pollution. He said another concern is the pipeline’s economic viability. The natural gas the pipeline produces will not have a significant customer base in Ohio, and, therefore, won’t serve Ohians, he added. Embridge, a Canadian energy company, owns the pipeline. One of the biggest customers will be Dawn, which is a storage hub in Canada. “It’s a foreign company pumping gas for foreign use,” Elder said. The pipeline, which will run from Ohio into Canada, has been met with resistance and legal battles from some of the towns it will run through. In other towns, court cases have been filed to delay pipeline construction. Oberlin has retained Carolyn Elefant, an eminent domain lawyer based out of Washington, D.C., to represent it. She has been working for the city for over a year and coordinated with some of the communities the pipeline will affect.
Ohio Court Overturns Law Preventing Cities From Voting on Anti-Fracking Measures - DeSmogBlog -- The state Supreme Court ruling, which came on October 19, is a departure from earlier rulings that prevented the Ohio Community Rights Network from placing county charters and a city ordinance to ban fracking from appearing on ballots. Apparently unfazed by the new law, this year members of the Ohio Community Rights Network advanced county charters in Athens and Medina counties and ballot initiatives for the cities of Bowling Green and Youngstown. These efforts all included “Community Bills of Rights,” which would outlaw fracking, injection wells, and related infrastructure for producing and transporting natural gas in their respective counties and cities. Bowling Green’s ballot initiative, which threatens to complicate the development of the nearby NEXUS natural gas pipeline, proposes an amendment to an existing city charter. Although the NEXUS pipeline is not slated to pass through the city itself, the ordinance would bar the pipeline from a piece of farmland owned by the city, which is key to the pipeline’s proposed route. All of the ballot initiatives gathered the required number of signatures to get on the ballot. And all but Bowling Green’s initiative were opposed and removed by their boards of elections, whom Secretary Husted had appointed. However, Bowling Green’s board voted to allow the people to vote first.Then came the legal challenges. After hearing appeals, the Ohio Supreme Court ruled against the two county charters and the Youngstown initiative. But in each of the rulings the court avoided weighing in on the constitutionality of HB463, instead relying on technical arguments to keep the initiatives off the ballot. But because Bowling Green’s board of elections ruled to allow a vote, in this case it was the board of elections — rather than citizen-petitioners — defending the local ballot process and arguing that HB463 was unconstitutional. The issue was only brought to the state Supreme Court after a private individual appealed the board’s decision to allow voting to take place. (The challenge was defended by a law firm that last year wrote briefs for the American Petroleum Institute and Affiliated Construction Trades Ohio Foundation to defend the practice of keeping anti-fracking initiatives off local ballots.) In a 4-3 decision, the Ohio Supreme Court struck down and ruled unconstitutional the section of HB463 that applied to municipal ballot initiatives, but not county charters. The ruling leaves unanswered how future proposed county charters will be treated. And because of how long the court took to make its decision, according to Terry Lodge, an attorney who represented the petitioners in all the cases, there is no time for Youngstown to use the ruling to return its previously removed initiative to this November’s ballot. That means Bowling Green’s “Citizens Right to a Healthy Environment and Livable Climate” initiative will be the only one in Ohio up for a vote in 2017.
Company to spend $150M on ethane storage facility — Mountaineer NGL Storage officials announced Thursday plans to spend $150 million — and potentially as much as $500 million — on its proposed natural gas liquids storage facility along the Ohio River near Clarington. By 2019, company Managing Director David Hooker hopes to store up to 420 million gallons of ethane, propane and butane in caverns along the river, with the goal of allowing the potential PTT Global Chemical cracker plant to access the product via pipelines that would only need to stretch about 10 miles. Also, the Mountaineer NGL Storage project could be the first part of the Appalachian Storage Hub, or “ethane hub,” which American Chemistry Council officials said could eventually lead to $36 billion worth of investment and about 100,000 permanent jobs.Hooker said he already has a permit from the Ohio Department of Transportation, but is still waiting for authorization from the Ohio Environmental Protection Agency and the Ohio Department of Natural Resources. “We feel like we have a pretty good rapport with the Ohio EPA. They are pretty clear about what they want from us. We need permits from Ohio EPA, ODNR and ODOT, and we have secured all permitting with ODOT already,” Hooker said. “We are working on some issues with ODNR, but they have been very accommodating.” Hooker continues work on his underground storage cavern endeavor, which he hopes to open on former coal mine property along the Ohio River. He has said the plan is to operate three pipelines that will run beneath the river, in addition to those that may run toward the PTT site. Preliminary plans called for these lines to run under the river — one carrying ethane from the Marshall County Blue Race Natrium natural gas processing plant to the Monroe County caverns; one transporting a combination of propane and butane from the Natrium plant to the caverns; and one sending salt brine waste from salt brine from Clarington to a West Virginia chlorine plant.“It will be more than a mile underground. We’ve drilled 48 bore-holes into the ground to make sure it is stable,” Hooker said. Monroe County Commissioner Mick Schumacher said the permitting process for the facility has been relatively slow because the Ohio EPA has had to write new regulations for natural gas liquids storage facilities.
Get Ready for an Appalachian Gas Bonanza - For the past six months, construction crews carved their way through the back of David Rheinlanders property. Now when the 57-year-old looks across his backyard, he sees a line of cut trees, piles of dirt, and stacks of steel pipe where he once envisioned a tiny cabin.The roughly 100-foot-wide path they’re cutting through the rolling hills extends about 700 miles to the west, running through neighboring Ohio and all the way up into Michigan. The pathway is for a pipeline that will bring huge amounts of natural gas out of sparsely populated Appalachia and into big cities across the Midwest. The pipeline, called Rover, is being built by Energy Transfer Partners LP, of Dallas, which has spent three years and a total $4.2 billion on the painstaking process of winning permits, clearing miles of rugged terrain, and fighting a pitched legal battle against environmental groups and landowners. Rover is scheduled to begin shipping as much as 3.25 billion cubic feet of natural gas a day in early 2018. When fed through a natural gas-fired power plant, that’s enough to power about 30 million homes. Rover is one of a handful of pipelines set to open next year that will begin moving natural gas from the massive Marcellus and Utica shale formations that lie beneath parts of Ohio, West Virginia, Pennsylvania, and New York. A relative latecomer to America’s shale revolution, the Marcellus and Utica regions are booming. In the past 10 years, natural gas production there, driven by advances in horizontal drilling, has multiplied by a factor of 10, to about 25 billion cubic feet a day, or roughly a third of U.S. output. Despite the increase in production, the energy companies that drill the wells to produce the gas complain they’ve been bogged down by a thicket of political and regulatory hurdles, as well as opposition from environmentalists and some landowners. These obstacles have prevented the region’s energy industry from reaching its full potential, they argue. Sometimes dubbed the Saudi Arabia of natural gas, the Marcellus is thought to hold a century’s worth of reserves. But after an initial boost of investment and optimism by drilling companies, activity started to stall, mostly because there weren’t enough pipelines to deliver the gas to large markets. “Natural gas production volumes have exceeded available pipeline capacity for several years.”
Mountain Valley sues landowners to gain pipeline easements and access through eminent domain - Mountain Valley Pipeline has filed a federal lawsuit against hundreds of landowners in Virginia to initiate acquiring easements through eminent domain across roughly 300 private properties and to seek a court order granting immediate access to the properties. Both Maureen Brady, a professor at the University of Virginia School of Law, and Chuck Lollar, a Norfolk-based lawyer who specializes in eminent domain, said filing suit against multiple landowners and properties at once is standard procedure for similar projects. Lollar said one reason to file condemnation proceedings against hundreds of landowners at once “is to seek one court order granting entry to begin construction, applicable to all property owners who have refused to sign easements, since they would be the remaining obstacle to commencement of construction of the pipeline.” Mountain Valley’s 196-page lawsuit, filed in Roanoke Tuesday, notes that the project received approval Sept. 13 from the Federal Energy Regulatory Commission. FERC’s order grants Mountain Valley Pipeline LLC the authority through the Natural Gas Act to condemn private property to obtain easements for the pipeline and related access roads and workspaces. “Condemnation is necessary because MVP has been unable to negotiate mutually agreeable easement agreements with landowners,” the lawsuit says. Many property owners opposed to the pipeline have refused to even enter such negotiations. Mountain Valley must still obtain other permits and authorizations, from both state and federal agencies, before launching construction. The company’s lawsuit asks the court to grant Mountain Valley the property rights sought by the litigation and an order granting “immediate access and entry prior to the determination of just compensation upon the posting of an appropriate bond.”
West Virginia again approves Mountain Valley Pipeline — West Virginia environmental regulators on Wednesday lifted their suspension of the permit for building the Mountain Valley Pipeline, which would carry natural gas down the center of the state. The pipeline would extend south for 195 miles (315 kilometers) in north-central West Virginia through 11 counties to the Virginia state line and nearly 110 miles (175 kilometers) through six counties in that state. West Virginia's Department of Environmental Protection first issued the water quality certification in March, which followed public hearings and review of the projected impact on the state's waters. In June, five citizen groups asked a federal appeals court to overturn the state approval. In September, the DEP vacated its approval to re-evaluate the application and determine whether it complied with the federal Clean Water Act. "Our agency developed a revised strategy that will better utilize the state storm water permit to provide significantly stronger safeguards for the waters of West Virginia," he said. The state also has decided chosen to waive its individual certification for the pipeline under the federal Clean Water Act. The DEP noted that U.S. Army Corps of Engineers recently reissued its nationwide permit, with provisions that are specific to West Virginia, saying it will allow for better enforcement capabilities and enhanced protection for West Virginia waters. Two weeks ago, a divided The Federal Energy Regulatory Commission granted its approval. Environmentalists said the state agency is failing to do its duty. "This action suggests that DEP does not believe in the laws, including the anti-degradation policy, that it is charged with enforcing," said Derek Teaney, senior attorney at Appalachian Mountain Advocates. "It also makes you wonder whether DEP intends to give the Atlantic Coast Pipeline, the other ill-conceived pipeline project it is currently reviewing, the same free pass it has just given to MVP."
Lawmakers Hold Hearing on Pocono Fracking | WNEP.com: -- Republican state lawmakers held a public hearing over a proposed permanent fracking ban in part of the Poconos. While the lawmakers will have no say on the ban itself, the hearing near Waymart could be used to influence public opinion. "I'm so pleased to have all of you here today that share in that frustration and disdain," said Republican State Representative Jonathan Fritz at a hearing regarding a proposed permanent ban on natural gas drilling in Wayne and Pike Counties. It's a decision that's up to the Delaware River Basin Commission. Fritz cohosted the hearing near Waymart helping choose who testified before the House GOP policy committee. "We need the jobs that will not just be created within the industry," said Debbie Gillette, Chamber of the Northern Poconos. The Chamber of the Northern Poconos, a lobbyist, and a Republican county commissioner spoke about the potential economic benefits if the region were allowed to have fracking. The Delaware River Basin Commission already has an unofficial ban on natural gas drilling. More than a month ago, the commission started the process of a making that ban permanent.Wayne County Commissioner Brian Smith believes it's a property-rights issue and an opportunity for farmers. "Our farms cannot simply survive today on the price we get for milk. Our farm is suffering,"
Dominion says Cove Point LNG production to start in November - Dominion Energy Monday said it expected to begin production in November at its long-awaited Cove Point LNG export terminal in Maryland, as buyers in Asia look for greater access to growing US supplies.Dominion specified the timing of production at its liquefaction plant in a slide presentation that accompanied the release of its third-quarter financial results. It did not say exactly when it would ship its first cargo, and executives did not address the issue during a conference call to discuss quarterly results. The company has said previously it expects feedgas to flow to the facility by Tuesday. The plant was still not flowing any feedgas to the liquefaction plant as of Monday. However, once flows begin, receipt volumes at both the Loudoun and Pleasant Valley interconnects with Columbia Gas Transmission and Transcontinental Gas Pipeline, respectively, can be expected to increase as the two points are the main supply meters for the liquefaction plant. "The Cove Point Liquefaction construction is effectively complete and the facility is going through its advanced-commissioning phase," CEO Thomas Farrell said.
Court rejects greens’ plea to stop natural gas export projects | TheHill: A federal appeals court Wednesday rejected an environmental group’s lawsuits trying to overturn federal approval for three liquefied natural gas (LNG) export projects. The Court of Appeals for the District of Columbia said that the Sierra Club’s challenges to export facilities in Maryland, Louisiana and Texas, fail for the same reasons that the same court ruled against the group in a similar case concerning a different project in August. “In a very recent case, Sierra Club v. U.S. Department of Energy (Freeport), this court denied a petition by Sierra Club challenging, under the same two statutes, the Department [of Energy]’s approval of an LNG export application from a fourth facility. The court’s decision in Freeport largely governs the resolution of the instant cases,” the court’s three judges wrote in the brief judgment.The cases decided Wednesday were part of a collection of cases the Sierra Club and other groups filed to try to stop approvals of LNG export facilities by the Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC). The greens generally argued that the federal agencies did not sufficiently consider environmental impacts of the approvals, like increases in hydraulic fracturing and greenhouse gas emissions. In June 2016, the D.C. Circuit Court rejected the green’s arguments regarding FERC. And in August, the same court rejected the DOE arguments. “Under our limited and deferential review, we cannot say that the Department failed to fulfill its obligations under [The National Environmental Policy Act] by declining to make specific projections about environmental impacts stemming from specific levels of export-induced gas production,” the court wrote in the August case. While that same argument applied to the three cases in Wednesday’s decision, the judges said that there were some small issues remaining in the Sierra Club’s challenges, regarding environmental reviews and the impacts on low-income households. But none of those issues were convincing, they ruled. The projects at issue in Wednesday’s cases were Dominion Energy’s Cove Point facility in Maryland, scheduled to open within weeks; Cheniere Energy Inc.’s Sabine Pass facility in Louisiana, which opened last year; and Cheniere’s Corpus Christi, Texas, project, due to open next year.
DC Circuit upholds DOE LNG export approvals for three terminals --A US federal appeals court cast aside Sierra Club arguments challenging Department of Energy approval of exports from three more LNG terminals, in a decision further setting back the environmental group's argument that agencies have failed to adequately assess greenhouse gas emissions from upstream production induced by the projects. In a judgment issued Wednesday, a three-judge panel of the US District of Columbia Circuit Court of Appeals Monday denied Sierra Club's petitions challenging authorization of LNG exports from Dominion Energy Cove Point LNG in Maryland, Sabine Pass LNG in Louisiana and Corpus Christi LNG in Texas. Combined, the three facilities will represent peak liquefaction capacity of 5.4 Bcf/d by 2020, more than half of all liquefaction capacity currently under construction. The court said it considered as precedent its own recent ruling denying Sierra Club's petition related to the Freeport LNG facility in Texas, and ruled in DOE's favor on three other remaining "narrow issues." In the August 15 Freeport decision, the court found that indirect effects of gas production induced by the project were not reasonably foreseeable and that DOE did its best to determine the environmental impacts of the project. The decisions add to prior rulings in which the DC Circuit upheld FERC approvals of the terminals. In those cases, the court found FERC's analysis "did not have to address the indirect effects of the anticipated export of natural gas because the Department of Energy and not the commission, has sole authority to license the export of natural gas."
This coastal town banned tar sands and sparked a war with the oil industry -- Can communities say no to energy companies?Hundreds of miles from the nearest oil field or fracking well, the answer to this question is playing out here, as a longrunning David-and-Goliath battle over plans to pipe tar sands oil from Canada to Maine for export nears a pivotal moment.On one side is South Portland, a picturesque waterfront city of 25,000, which approved an ordinance in 2014 to outlaw heavy crude exports from its harbor in an overwhelming City Council vote.On the other is the Portland Pipe Line Corporation, the company behind the project, and its allies, including the American Petroleum Institute, whose members include most major oil and gas companies. API spent hundreds of thousands of dollars to defeat a ballot measure in 2013 that would have blocked the project. The City Council approved the ordinance a year later. The Portland Pipe Line Corporation is now suing the city, with support from API and the U.S. Chamber of Commerce, arguing the ban was unconstitutional. A federal judge is expected to rule in the coming weeks. A decision in favor of the company could effectively open a gateway for the flow of carbon-heavy tar sands oil to one of the East Coast's largest oil ports.For other cities seeking to restrict oil and gas activities, South Portland's four-year fight to fend off the oil industry offers perhaps a cautionary tale. South Portland, with an operating budget of $32.6 million, had spent $1.1 million as of August in legal fees to defend its ban, and the costs continue to rise. "They're getting killed," said Sean Mahoney, executive vice president of the Conservation Law Foundation, who has advised the city on the case.At issue is local control, the right of communities to make their own rules when it comes to oil and gas operations and infrastructure. "This has always been seen by the companies as a beachhead," Mahoney said. "They can't allow communities to pass this kind of ordinance because it could be a model for communities everywhere."
How has air quality been affected by the US fracking boom -- Urban air pollution in the U.S. has been decreasing near continuously since the 1970s. But about 10 years ago, the picture on air pollutants in the U.S. started to change. The "fracking boom" in several different parts of the nation led to a new source of hydrocarbons to the atmosphere, affecting abundances of both toxic benzene and ozone, including in areas that were not previously affected much by such air pollution. In the age of fracking, the large operations at conventional well sites have been replaced by hundreds of well pads dotting the landscape. Each requires the transportation of water, chemicals and equipment to and from these pads as well as the removal of wastewater, and none is regulated like any larger facility would be. As a result, unconventional production has not only increased truck traffic and related emissions in shale areas, but also established a renewed source of hydrocarbons. They enter the atmosphere from leaks at valves, pipes, separators and compressors, or through exhaust vents on tanks. Together with nitrogen oxides emissions, largely from diesel engines in trucks, compressors and drilling rigs, these hydrocarbons can form significant amounts of harmful, ground-level ozone during daytime. The EPA keeps track of methane emissions in its greenhouse gas inventory, but the numbers are based upon estimates developed in the 1980s and 1990s and are compiled through calculations and self-reporting by the industry. In fact, both satellite and atmospheric measurements suggest that the EPA estimates could be underestimating real-world methane emissions by up to a factor of two. And if this is true for methane, co-emitted hydrocarbon gases are likely underestimated as well.
Enbridge: Pipeline had coating gaps for years — Engineers at Enbridge knew about damage to a pipeline running through the Straits of Mackinac for years while the company remained silent about the issue, a company spokesman said Friday.Enbridge spokesman Ryan Duffy said company engineers realized in 2014 that Line 5’s coating was damaged by the installation of a support anchor that year, but they did not inform other company staffers that there was a problem because they did not deem it a safety issue.The news spread after others at the company reviewed documents that were sent to the state on Friday, Duffy said. State officials demanded more detailed information about sections missing coating after learning about the gaps in August.He said the pipe has since been repaired and never presented a safety issue, but Michigan Attorney General Bill Schuette said Enbridge’s disclosure erodes trust in the company, and U.S. Rep. Debbie Dingell called it “disturbing.”“This latest revelation by Enbridge means that the faith and trust Michigan has placed in Enbridge has reached an even lower level,” Schuette said in a Friday statement. “Enbridge needs to do more than apologize, Enbridge owes the citizens of Michigan a full and complete explanation of why they failed to truthfully report the status of the pipeline.” Schuette has called for an eventual discontinuation of the twin 65-year-old pipelines that run under the Straits of Mackinac. The Canadian energy company came under fire in August after Gov. Rick Snyder ordered an “aggressive” review of its Line 5 maintenance following revelations that multiple areas of the pipeline were missing enamel coating. State officials later accused the company of lying to them when they learned that the sections where bare metal was exposed to lake water were much larger than Enbridge had originally said.
Enbridge says it knew about oil pipeline damage 3 years ago - Enbridge Inc., the company that operates twin oil pipelines running under the Straits of Mackinac, said it knew three years ago that protective coating had been damaged but didn't inform regulatory agencies.Enbridge said four gaps were opened in enamel coating on one section of Line 5 as a support anchor was being installed in 2014. The coating gap is one of several that have exposed bare metal on parts of the pipelines.The gaps are being repaired and haven't compromised the pipelines' safety, company spokesman Ryan Duffy said.But state officials are criticizing Enbridge's failure to disclose the damage earlier.Michigan Agency for Energy Director Valerie Brader says her office's trust in Enbridge "has been seriously eroded."The Straits of Mackinac links Lakes Huron and Michigan.Enbridge recently began making repairs to the protective layer of enamel coating on the 64-year-old pipelines.The state Pipeline Safety Advisory Board had said in September it recommended Michigan universities analyze the worst-case scenario of an oil pipeline failure. The two 20-inch pipelines running along the bed of Lake Michigan just west of the Mackinac Bridge carry 23 million gallons of light crude oil daily through the environmentally-sensitive area.
Illinois’ first fracking permit withdrawn -- Hydraulic fracturing -- the controversial oil-and-gas drilling method once promoted as a major new source of jobs, tax revenue and domestic energy -- is again on indefinite hold in Illinois.Woolsey Companies Inc., the Kansas firm awarded the first permit under the state’s 2013 “fracking” law, released a statement Friday citing regulatory compliance costs in the decision to drop drilling plans near the southeast Illinois community of Enfield. The practice relies on high pressure chemical and water injections to release oil and gas from deep-rock formation.“The process we have gone through to receive a permit was burdensome, time consuming and costly due to the current rules and regulations of Illinois,” the company stated, “and it appears that this process would continue for future permit applications.”The company said the area of southeast Illinois known as New Albany Shale had significant energy production potential, but that stringent Illinois rules combined with low oil and gas prices made the project too costly compared with other states.“It is a difficult decision, as the resources we invested were substantial,” the company stated. The Illinois Department of Natural Resources approved the company permit in September.Opponents declared the Woolsey decision a victory in the fight to slow fracking, and vowed to continue work for outright state and federal bans.“They promised all these jobs, and the Illinois legislature fell for that. Now, we think it’s time to put this practice to rest once and for all,” said Dawn Dannenbring with Illinois People’s Action in Bloomington. Enactment of Illinois’ fracking law in 2013 was followed by months of controversy over regulations, including thousands of opponent comments. Jessica Fujan, Midwest Region director for Food and Water Watch, said the Woolsey decision reflected growing public awareness of fracking’s dangers.
Judge OKs environmental assessment of proposed Enbridge pipeline - The state’s environmental assessment of Enbridge’s proposed new Line 3 oil pipeline — heavily criticized by pipeline opponents — has been approved by a state judge.The environmental impact statement (EIS), done by the Minnesota Department of Commerce, was deemed “adequate” in a ruling released Wednesday by Eric Lipman, an administrative law judge.The EIS made no recommendations. Rather, the August report assessed potential environmental damage from the proposed 340-mile pipeline that would replace Enbridge’s current Line 3. The pipeline transports Canadian oil across northern Minnesota to Enbridge’s terminal in Superior, Wis.Administrative law judges rule on aspects of contested cases before the Minnesota Public Utilities Commission (PUC). The PUC itself still must approve the EIS on the way to voting on Line 3 as a whole, but the judge’s decision is likely to play a significant role in that process. A separate administrative law judge is weighing whether a new Line 3 is needed and, if so, which route it should take, based on a separate Commerce Department report plus testimony at public hearings.The EIS has been labeled deficient on several fronts by environmental groups and Indian bands that oppose the pipeline.But in his ruling, Lipman concluded that the EIS met the requirements of Minnesota law and “addressed the potentially significant adverse or beneficial environmental, economic, employment and sociological impacts generated by the project and its alternatives.” The EIS also “adequately presents methods by which adverse environmental impacts can be mitigated,” Lipman wrote.Calgary, Alberta-based Enbridge said the $2.6 billion project is necessary to replace its current Line 3, a 1960s-vintage pipeline that operates at slightly more than half of its capacity due to safety concerns. A new pipeline would allow the company to restore the full flow of 760,000 barrels of oil per day. The new Line 3 would run on a new route that is south of the current Line 3. Opponents said it would cut through an area of pristine lakes, rivers and wild rice waters, exposing them to oil spill damage.
The Rationale For Reversing The Crude Oil Flow On Capline - The three co-owners of the 1.2-MMb/d Capline Pipeline from St. James, LA, to Patoka, IL, have begun assessing whether there is sufficient shipper interest in reversing the flow of one of the U.S.’s largest crude oil pipelines in the early 2020s. There are good reasons both for ending Capline’s long run as a northbound-flowing pipe and for repurposing the pipeline to help transport heavy western Canadian oil and other crudes south to refineries in eastern Louisiana and Mississippi and to export markets. But there also are logical questions to ask, such as why Capline’s owners envision sending only 300 Mb/d south on the pipe, and why they don’t see the reversal occurring for five years. Today, we examine the forces behind Capline’s possible reversal and the benefits that flipping the pipe’s direction might provide. There was also a sense of inevitability in the October 17, 2017, announcement that Capline co-owners Plains All American (which holds a ~54% stake), Marathon Petroleum (~33%) and BP (~13%) had agreed to launch a non-binding open season to assess shipper interest in the proposed reversal of the pipeline. Through the open season, which runs until November 17, 2017, the co-owners and Capline operator Marathon Pipe Line (MPL) are gauging interest to begin southbound service on the pipeline in the second half of 2022 with an initial capacity of 300 Mb/d — only one-quarter of Capline’s northbound capacity. The possible reversal of Capline (yellow line in Figure 1) has been a frequent topic in the RBN blogosphere for several years. The 633-mile, 40-inch-diameter pipeline for a quarter century played a critical role in moving imported, Gulf Coast and Gulf of Mexico-sourced crude oil north to Midwest refineries. But as we said in Livin’ on the Edge, rising production in the Bakken and the Canadian oil sands reduced the need for northbound flows on Capline, which according to Louisiana Department of Natural Resources data have fallen from just over 1 MMb/d in 2000 to an average of 336 Mb/d in the first nine months 2017. Further declines are imminent — within the next few weeks, Plains and Valero Energy Corp. expect to start commercial operation of their new 200-Mb/d Diamond Pipeline (light green line) from the crude oil storage and distribution hub at Cushing, OK, to Valero’s 195-Mb/d refinery in Memphis…
Exxon to pay $300 million on Gulf Coast plants in EPA settlement - Exxon Mobil will shell out $300 million outfitting eight energy facilities in Texas and Louisiana with technology that monitors and controls air pollution, as part of a settlement with the U.S. government announced by the Environmental Protection Agency on Tuesday. The Irving, Texas oil company's settlement with the EPA and other agencies comes after it faced allegations that it failed to monitor flaring at Gulf Coast petrochemical facilities, potentially violating the Clean Air Act. The EPA said the anti-pollution equipment will curb harmful pollution from 26 industrial flares at five of the company's facilities in Texas, near Baytown, Beaumont and Mont Belvieu, and three others in Baton Rouge, Louisiana. Exxon has agreed to cut down on waste gases it sends through its flares and improve the efficiency of the flares. The project could reduce the company's emissions of volatile organic compounds by 7,000 tons a year, and curb toxic air pollutants like benzene by 1,500 tons a year. "This settlement means cleaner air for communities across Texas and Louisiana, and reinforces EPA's commitment to enforce the law and hold those who violate it accountable," EPA Administrator Scott Pruitt said in a written statement.
Exxon Refinery Catches Fire Day After Government Settles Over Pollution From Other Gulf Plants -- Early morning skies Wednesday in Baton Rouge, Louisiana, were alight from a fire that started around 2:30 a.m. at an ExxonMobil refinery, a reminder to the surrounding community of yet another danger of living next to refineries and chemical plants. Exxon's refinery is located along the stretch of Mississippi River between Baton Rouge and New Orleans known as "Cancer Alley" due to the high number of chemical plants and refineries—and illnesses possibly connected to emissions—along the river's banks. Exxon issued a statement to CBS affiliate WAFB while the fire smoldered, saying the community was not impacted by emissions from the refinery fire and that air quality readings were "below detectable limits." Mary Lee Orr, executive director of The Louisiana Environmental Action Network (LEAN), questions the possibility of making such a determination so fast. Her group has been working with Cancer Alley communities, helping to reduce their exposure to pollution f rom the area's oil and petrochemical industry. Exxon's Baton Rouge refinery is adjacent to one of the company's eight facilities named in a settlement reached with the U.S. Environmental Protection Agency (EPA) and the Department of Justice (DOJ) and announced Oct. 31. Last year LEAN filed a lawsuit against an Exxon chemical facility in Baton Rouge, next to the refinery that caught on fire Wednesday. That suit alleges the facility has been violating the Clean Air Act by failing to report pollution releases correctly. Lisa Jordan, director of Tulane University's Environmental Legal Clinic and representing LEAN in this case, said it is too early to say how the recent agreement between the federal government and Exxon will impact their own case. Jordan said LEAN's case encompasses a broader range of issues than those in the one recently settled. According to the DOJ , the settlement "resolves allegations that ExxonMobil violated the Clean Air Act by failing to properly operate and monitor industrial flares at their petrochemical facilities, which resulted in excess emissions of harmful air pollution."
How a 672,000-gallon oil spill was nearly invisible - Mention oil spills, and images of birds coated in black slime and a shiny slick on the ocean’s surface come to mind. But not all oil spills are the same. About 672,000 gallons of oil spilled when a pipeline fractured about a mile below the ocean’s surface this month in the Gulf of Mexico southeast of Venice, La., which is about 65 miles south of New Orleans. Hardly any of it was visible. “The thing that sort of confused people about this one is that we weren’t seeing any oil,” Lt. Cmdr. Steven Youde of the Coast Guard said in a phone interview on Wednesday. Aside from a few areas with a light sheen on the surface of the ocean, the oil seemed to have completely disappeared, and it was not expected to affect the shoreline. The oil spill appeared to be the largest since the Deepwater Horizon explosion in 2010, when four million barrels of oil leaked over nearly three months. This month’s episode was far smaller: 16,000 barrels in less than two days. Even so, 16,000 barrels is “a pretty substantial leak,” said Edward B. Overton, an emeritus professor of environmental sciences at Louisiana State University who is studying the environmental effects of Deepwater Horizon. “But it was not enough on the surface to warrant a cleanup response.” In this case, the oil degraded quickly, in part because of environmental forces. The company that operates the pipeline, LLOG Exploration, believes the pipe fractured in the early morning hours of Oct. 11, a company spokesman, Rick Fowler, said in an email. On Oct. 12, LLOG discovered that the amount of oil leaving its wells was different from the amount of oil leaving the company’s floating production system, Delta House, which is in the Gulf of Mexico, about 40 miles southeast of Venice, La. The small crack in the pipeline has not yet been fixed, Mr. Fowler said, but the wells were shut and the flow through the pipe was stopped. What caused the fracture was unclear. The federal Bureau of Safety and Environmental Enforcement, which has regulatory oversight of the offshore energy industry, is investigating.
Booming US crude oil exports raises questions about infrastructure capability - Tankers carrying record levels of crude are leaving in droves from Texas and Louisiana ports, and more growth in the fledgling US oil export market may before long test the limits of infrastructure like pipelines, dock space, and ship traffic. US crude exports have boomed since the decades-old ban was lifted less than two years ago, with shipments recently hitting a record of 2 million barrels a day. But shippers and traders fear the rising trend is not sustainable, and if limits are hit, it could pressure the price of US oil. How much crude the United States can export is a mystery. Most terminal operators and companies will not disclose capacity, and federal agencies like the US Energy Department do not track it. Still, oil export infrastructure will probably need further investment in coming years. Bottlenecks would hit not only storage and loading capacity, but also factors such as pipeline connectivity and shipping traffic. Analysts believe operators will start to run into bottlenecks if exports rise to 3.5 million to 4 million barrels a day. RBC Capital analysts put the figure lower, around 3.2 million b.p.d. The US has not come close to that yet. A total of the highest loading days across Houston, Port Arthur, Corpus Christi, and St. James/New Orleans – the primary places where crude can be exported – comes to about 3.2 million b.p.d, according to Kpler, a cargo tracking service.But with total US crude production currently at 9.5 million barrels a day and expected to add 800,000 to 1 million b.p.d annually, export capacity could be tested before long. Over the past four weeks, exports averaged 1.7 million b.p.d, more than triple a year earlier. "Right now, there seems to be a little more wiggle room for export levels," said Michael Cohen, head of energy markets research at Barclays. "Two to three years down the road, if US production continues to grow like current levels, the market will eventually signal that more infrastructure is needed. But I don't think a lot of those plans are in place right now." If exports do hit a bottleneck, it would put a ceiling on how much oil shippers get out of the country. Growing domestic oil production and limited export avenues could sink US crude prices.
An increasingly large share of U.S. distillate production is exported – EIA - U.S. distillate exports have continued to increase significantly over the first part of 2017, setting record highs for three consecutive months from May through July (Figure 1) before declining in August (at least partially as the result of hurricane activity). At the same time, U.S. distillate demand was relatively stable, increasing only slightly from January through July 2017 compared with 2016 levels.Although January through July 2017 average exports of distillate to Europe fell compared with the same period in 2016, U.S. refineries in the Gulf Coast are geographically well positioned to export to Mexico and to countries in Central and South America, and distillate exports to these locations increased. In addition to increased export demand, high distillate crack spreads (the difference between distillate prices and crude oil prices) encouraged refinery runs. During this period, overall demand outpaced production and inventories fell. While the January-through-July average distillate product supplied (a proxy for demand) increased slightly, from 3.8 million barrels per day (b/d) in 2016 to 3.9 million b/d in 2017, the growth in exports increased more quickly. From January through July 2017, U.S. distillate exports averaged 1.4 million b/d, nearly 195,000 b/d more than in the same period in 2016. Distillate exports from the United States set record highs in May, June, and July 2017, reaching 1.5 million b/d, 1.6 million b/d, and 1.7 million b/d, respectively. In August, exports of distillate fell to 1.4 million b/d, due at least partially to Hurricane Harvey, which made landfall in Texas as a Category 4 hurricane on August 25 and resulted in port closures. August data reflects the significant impact of hurricanes this year and may not be indicative of distillate demand or export trends. As exports of distillate have increased, they have accounted for a larger share of net production (Figure 2). As of October 30, 2017, residential heating oil prices averaged $2.70 per gallon, nearly 3 cents per gallon more than last week and 36 cents per gallon higher than last year’s price at this time. The average wholesale heating oil price for this week is over $1.95 per gallon, 6 cents per gallon more than last week and 34 cents per gallon higher than a year ago.
Permian Gas Prices Get Spooked As Pipelines To Gulf Coast Markets Fill -- Permian natural gas production recently topped 7 Bcf/d and shows no signs of slowing its growth trajectory. While new pipelines are expected to move additional Permian gas volumes to the Gulf Coast markets by the beginning of 2020, the current paths to those markets are full. Over time, Mexico is expected to export significant volumes directly from Waha, but current amounts are relatively small. As a result, increasing volumes of gas are leaving the Permian on the pipelines that head west to California and north to the Midcontinent. However, the pricing in these markets is downright ghoulish compared to the Gulf Coast and Permian gas is increasingly finding itself in scary market conditions. Today, we analyze recent pricing and flow trends in the Permian natural gas market. Permian natural gas has been a frequent subject in the RBN blogosphere in 2017. This summer we posted a four-part blog series on Waha in which we outlined our view that Permian gas production is set to grow to almost 9 Bcf/d by the end of 2019 and create gas takeaway constraints in the process. Nothing has changed from that general view, but with a few months of time having passed, we thought we’d check in on Permian gas to see how things are playing out.
Crude oil shuttle pipelines and gathering systems in the Permian, Part 5 - Permian crude oil production now tops 2.5 million barrels a day (MMb/d) and is expected to increase to 3.5 MMb/d by 2022 under RBN’s least optimistic price scenario. If prices hold steady or rise, production in the play could easily surpass 4 MMb/d within five years. But the Permian’s output isn’t just dependent on price. It’s also critically important that sufficient gathering capacity is in place to efficiently transport crude from the lease to central points where oil can flow onto shuttle pipelines or takeaway pipes. Today, we continue our blog series on key infrastructure in the nation’s hottest shale region with a look at a number of existing and planned gathering systems. As we said in Part 1, with Permian production on the rise, there’s been a big push on to expand regional pipeline networks’ capacity to move more crude oil out of the play’s Delaware and Midland basins and — just as important — to give producers and shippers as many destination options as possible. Until a few years ago, most of the oil produced in the Permian flowed north to the crude storage and distribution hub in Cushing, OK. By 2011-12, though, rising crude production in the Bakken, western Canada and the Permian itself — combined with too little pipeline capacity from Cushing to the Gulf Coast — caused a supply glut at Cushing. That, in turn, caused heavy discounting for Cushing benchmark West Texas Intermediate (WTI) versus Louisiana Light Sweet (LLS) at the Gulf Coast, and spurred development of new takeaway capacity from the Permian to Houston and other coastal destinations.
Critical U.S. Fracking Equipment Shortages Mean Higher Oil Prices In 2018 - The primary bear thesis on oil currently is that U.S. shale is a new global swing producer, capable of rapidly responding to price and inventory changes to ensure market balance. This thesis, however, is fatally flawed as evidenced by flat-lining Texas and New Mexico production (the two key shale states), and an increase in drilled-but-uncompleted wells. The myth of rapid response U.S. shale production, or the “call on shale” thesis, will be disproven in 2018 as investors realize shale output is dictated by service sector capacity. Shale production is currently constrained by pressure pumping equipment shortages. Aging pressure pumping fleets will only compound this over the next year & significant investment is still required. These are not issues that are solved quickly, and will prove to be a major headwind to shale growth in 2018. The fact is that U.S. shale producers cannot control their output, as it is determined by the capacity, capital availability, and labor market constraints of the oil service industry. These constraints will persist deep into 2018 as fracking horsepower demand exceeds supply by 2 to 4 million hydraulic horsepower, and as companies lack capital to replace & add capacity to quickly remedy the imbalance. The end result is a limited pace of well completions, and another year of disappointing shale growth in 2018. As of the latest EIA Petroleum Supply Monthly with data for July 2017, U.S. production has grown by 467,000 bpd for the first 7 months of the year. This would annualize to 800,000 bpd, far below consensus expectations of 1 - 1.2 million bpd from earlier this year. Most of this growth, however, is from earlier in the year, and production was essentially flat from March-June. Most importantly, however, is that Texas & New Mexico production has disappointing. These two states are home to the Permian & Eagle Ford, the two growth engines of U.S. shale: This is not the surge of production that was anticipated under the paradigm that the U.S. is a rapid response swing producer. The EIA's Drilling & Productivity Report estimates production monthly by shale region. Below is what the EIA's DPR predicted in each months report from January to July, compared to actual growth: The reasoning for why becomes clear when looking at drilled versus completed wells in the Permian. Wells drilled has been adequate, but completions have severely lagged, and the reason is that there is a significant equipment under-supply in the fracking & completions sector. These shortages are not simply,cheaply, or quickly resolved, as I will demonstrate:
China's Sinopec mulls U.S. oil projects ahead of Trump's visit: sources : (Reuters) - China’s state oil major Sinopec is evaluating two projects in the United States that could boost Gulf Coast crude oil exports and also expand storage facilities in the Caribbean, two people familiar with the matter said on Tuesday, with U.S. President Donald Trump set to visit Beijing next week. With U.S.-China energy trade likely to feature prominently during Trump’s visit, the people said one of the projects could see Sinopec partnering with U.S. commodities trader Freepoint Commodities LLC and U.S. private equity firm ArcLight Capital Partners LLC. The trio is mulling building a pipeline to move shale oil from the Permian basin in Texas to the U.S. Gulf Coast for export, the people said. This project also includes the construction of a terminal that can load 2 million barrels of crude onboard a Very Large Crude Carrier (VLCC), they said. This will reduce a big chunk of logistics costs incurred for U.S. crude exports, making the oil more competitive in Asia, the sources said. ArcLight and Freepoint are among the U.S. energy and commodities firms that will make up a major part of a business delegation visiting Beijing when Trump goes to China next week. Sinopec and the U.S. firms have also been exploring an expansion of oil storage at Limetree Bay (LB) Terminals in St. Croix, U.S. Virgin Islands, in the Caribbean, and restarting an idled refinery at the same site, the people said. They declined to be identified because they were not authorized to speak to media.
Now It's Oilmen Who Say Fracking Could Harm Groundwater -- It's no longer just environmentalists who suspect hydraulic fracturing is contaminating groundwater.Oil companies here in Oklahoma — ones that produce from older vertical wells — have raised that prospect as they complain about the practices of their larger brethren.They say hundreds of their wells have been flooded by high-pressure fracturing of horizontal wells that blast fluid a mile or more underground. Some of those "frack hits," they suspect, have reached groundwater."I'm convinced we're impacting fresh water here," Mike Majors, a small producer from Holdenville, said as he drove from well to well on a September afternoon. "If they truly impact the groundwater, we can kiss hydraulic fracturing goodbye."Majors found a burbling mess two years ago when he showed up at his friends' oil well outside Holdenville.Water was bubbling up around the wellhead of the well, named the I. Davis No. A-1, but also flowing out of a nearby embankment leading to a drainage.A company called Silver Creek Oil & Gas LLC had been fracking a well about 2,000 feet away from the well. The frack fluid leaked out of its intended path and flooded into the well, which belongs to a company called Rayland Operating LLC.The older wellbore, drilled in 1928, was not sealed off with cement casing deep enough to prevent the surging flow from reaching groundwater. Majors, a lanky, chain-smoking veteran of the oil field, leaned on the hood of his pickup parked at the well site and explained that with thousands of pounds of upward pressure, there was nothing to stop the fluid from flooding into groundwater. It took months and the threat of a contempt charge to get the monitoring well drilled. The results, filed with the state and obtained by E&E News through state open records laws, shows that chlorides, sometimes a sign of oil and gas contamination, are low. But there wasn't a baseline to measure the chlorides against. And there was no test for fracking chemicals. A list of frack fluid ingredients Silver Creek filed with the FracFocus registry included chemicals such as isopropanol and naphthenic solvents.
Fracking Protesters Wear Face Masks During Oil & Gas Meeting - Dozens of people concerned about the impact of fracking took their message to state regulators on Monday. Some even wore face masks to to the Colorado Oil And Gas Conservation Commission to protest fracking near homes. They want the commission and Gov. John Hickenlooper to do something about fracking near homes and encroaching on neighborhoods, specifically to curb drilling. Several protesters wore medical face masks with messages written on them like “Stop Fracking Us.” They hoped to make a statement about toxic air they say their families breathe every day as a result of fracking. COGCC heard testimony from residents along the Front Range on how fracking has exposed them to hazardous toxins. One of the most powerful comments during the meeting wasn’t made at the podium. During the testimony one commissioner asked a woman who was quietly holding a photo of homes right next to a fracking well to put away the photo. She refused and told him, “We have to look at this every day. Why can’t you?” The meeting comes amid concerns about proposed construction of dozens of drilling sites near homes and schools in Broomfield, Boulder, Erie, Greeley, Longmont and Thornton. This year, the American Lung Association gave 10 counties on the Front Range a failing grade on their clean air report. Weld County, which already has more than 23,000 wells, received an ‘F.’ “Fracking is in my neighborhood. It’s near my backyard, it’s near my children’s favorite playground. Which I don’t take them to much anymore because their asthma has gotten worse in the last few years,” said Weld County resident Megan Meyer.
Congress Works with Big Oil on Letter Suggesting Anti-Pipeline Activists Face Terrorism Charges - Steve Horn - On October 23, 84 Congressional representatives made a splash when they published a letter to U.S. Attorney General Jeff Sessions asking if those engaged in activism disrupting or damaging pipeline operations should face criminal prosecution as an act of terrorism under the USA PATRIOT ACT. Spearheaded by U.S. Rep. Ken Buck (R-CO) and co-signed by dozens of other, primarily Republican, representatives, the letter pays homage to the First Amendment, while also noting that “violence toward individuals and destruction of property are both illegal and potentially fatal.” The letter, covered by several media outlets, was championed by the industry lobbying and trade association, the American Petroleum Institute (API), which said it “welcomed” the letter. But according to a DeSmog review, API and other industry groups were a key part of bolstering the letter itself. API, along with the Association of Oil Pipe Lines (AOPL) and the Interstate Natural Gas Association of America (INGAA), is listed as among the “supporting groups” on the website DearColleague.us, which tracks congressional letters and their backers. This letter’s publishing comes in the aftermath of last year’s major uprising against the Dakota Access pipeline at the Standing Rock Indian Reservation in North Dakota. Emails and memoranda previously obtained and reported on by DeSmog show that law enforcement and contract public relations professionals described those who participated in the Standing Rock protests as potential “terrorists.” Greenpeace USA and activists the organization collaborated with at Standing Rock are likewise being described as partaking in “eco-terrorist” activities in a recent lawsuit filed against the organization for alleged “racketeering,” as defined by the Racketeering Influenced Corrupt Organizations Act (RICO). Importantly, it also follows other anti-pipeline actions by the “valve turners,” or those who participated in acts of non-violent civil disobedience to shut down the flow of Canadian tar sands into the U.S. at several pipeline pump stations. The activists affiliated with the Climate Disobedience Center, in those cases, have used the “necessity defense” to say that their activism was the last line of defense they had to halt runaway climate change which could ensue from the combustion of oil and gas flowing through pipelines.
Trump to Shrink Utah National Monuments to Allow Drilling, Mining - The Trump administration will shrink two national monuments in Utah including the 1.3 million-acre Bears Ears National Monument , opening the lands up for potential industry use. Sen. Orrin Hatch (R-Utah) confirmed in a Friday statement that Trump called the senator to inform him of the Bears Ears decision and that he will also shrink Utah's Grand Staircase-Escalante National Monument, which is thought to contain more than 60 billion tons of coal . Interior Sec. Ryan Zinke recommended downsizing Bears Ears in June, saying that the Antiquities Act should be used to protect the "smallest area" needed to cover important sites. The president will travel to Utah to announce plans to trim the monuments in December. As reported by the Salt Lake Tribune: " ... Sen. Jim Dabakis, D-Salt Lake City, called the move an 'ugly violation of stewardship responsibility' that will undermine Utah's fastest growing industry: tourism. 'Trump, with the conniving help of the Utah congressional delegation, just strangled the golden goose of Utah's future jobs—the outdoor recreation industry,' Dabakis said. 'The winners in the president's decision are the fossil fuels industry, giant international coal companies and the pollution industry. The losers are Utah families, outdoor enthusiasts, hunters, campers, climbers and all who appreciate the unspeakable beauty of our state.'"
Industry tries again to delay federal methane rules in Wyoming court - Industry groups are asking a federal judge in Wyoming to delay some aspects of federal regulations meant to reduce methane emissions from oil and gas operations. In a filing with the U.S. District Court in Wyoming on Friday, the Independent Petroleum Association of America and the Western Energy Alliance argued that key provisions of the Bureau of Land Management’s methane waste rules, including the use of leak detection and repair equipment to find fugitive leaks, would be too costly for industry to implement by an upcoming January deadline. The Obama-era regulations are currently under review by the Interior Department. The regulations are disliked by a number of companies in Wyoming that argue such federal limits affect a wide range of current and potential oil and gas operations in the state. Wyoming regulators wrote the playbook on the venting and flaring rules now being implemented by the BLM, but thus far the state has only applied its strongest provisions in the Upper Green River Basin, an area with a history of ground level ozone spikes.Attempts at a quick solution in industry’s favor have failed so far.Industry unsuccessfully bid for an injunction last January, days before the first compliance date for the Obama-era regs.The Senate could not secure a simple majority vote to axe the rules months later, and a California court invalidated the Interior Department’s initial attempt to stay the rules, because the agency didn’t follow the Administrative Procedures Act.
Fracking Boom Hits Midlife Crisis as Investors, Geologists See Shale Limits - Crude prices bouncing around $50 to $60 a barrel have kept U.S. shale producers stuck on the edge of profitability. That hasn’t been enough to shut down the oil boom in places such as North Dakota, Texas, and New Mexico—at least not yet. Drillers are heading into 2018 on the defensive as they face skepticism from shareholders who want to see less investment and more profit. They may also be finding that much of the easy oil has already been pumped. Output has recently failed to meet expectations. As of June, the U.S. Energy Information Administration expected an average of about 9.3 million barrels a day, more than 220,000 barrels a day higher than companies reported. Investors are demanding that companies sell off weaker holdings, pare spending, and pay down their debt. Shale producers traditionally market themselves as growth companies. With few exceptions, they eschew paying dividends and buying back shares, and instead plow their money into more drilling. Many are still outspending their cash flow. But their shares haven’t cooperated with this strategy: While the stock market has reached record highs this year, an S&P index of oil and gas explorers and producers has plunged about 17 percent. Executive pay incentives for exploration and production companies are under scrutiny from investors, too. “The compensation plans laid out by E&P corporate boards encourage these companies to grow production at almost any cost,” For example, pay may be tied to sales volumes or additions to reserves, rather than measures of cash flow. The strategy “builds the personal net worth of the CEOs but does nothing for the shareholders for whom they are legally fiduciaries,” says Holt. Drillers also face technical questions about the shale boom’s sustainability. Pioneer Natural Resources Co. and Parsley Energy Inc. reported higher-than-expected natural gas output from their wells in August. That sent shares tumbling, because traders took it as a sign that oil flows, which are more lucrative, might peak more quickly than the industry expected. (As wells age, they tend to produce more gas and less oil.) The companies said their oil production hadn’t diminished, while analysts dismissed the worries as overblown.
ExxonMobil's output climbs as it plans to boost capex in 2018 -- ExxonMobil's liquids and natural gas production climbed to nearly 3.88 million b/d of oil equivalent in the third quarter, up nearly 70,000 boe/d from the same quarter last year, the company said Friday. That climb led the company to earn $3.97 billion in the quarter, up $1.32 billion from Q3 2016, despite the impacts of Hurricane Harvey and relatively stagnant global economic growth. Harvey, which made landfall in Texas on August 25, had a roughly $160 million impact on Exxon Mobil in Q3 as the company shut down refining and chemical operations in Baytown, Mont Belvieu and Beaumont. "We acted quickly to bring in gasoline, diesel and jet fuel from other regions in the US and abroad to supplement our production," said Jeff Woodbury, Exxon Mobil's vice president of investor relations, during an earnings call Friday, adding that the company's upstream operations were only minimally impacted by the hurricane. Bolstered by higher crude oil prices, up roughly $6.50/b from Q3 2016, lower operating expenses and higher realizations, Exxon Mobil plans to increase its capital and exploration spending to about $25 billion in 2018, up from an estimated $17 billion this year, he said. Exxon Mobil's capex was nearly $14.1 billion through the first nine months of this year, down nearly $400 million from the first three quarters of 2016.
Alaska orders review of all North Slope oil wells after spill linked to permafrost - Alaska's main oil and gas regulatory body has ordered a review of all North Slope wells after a spill last spring was connected to thawing permafrost, subsidence and a cracked casing.The emergency order, issued Monday by the Alaska Oil and Gas Conservation Commission (AOGCC), said the outer casing that cracked had been set in the permafrost.In April, one of BP's older wells leaked oil and gas for days before it could be shut down. The company reported that roughly 45,000 kilograms of gas and 63 gallons of crude leaked. According to Alaska Public Media, BP blamed the failure then on a piece of a well casing that buckled under pressure from thawing permafrost.As a result, the AOGCC said it has ordered all companies on the North Slope to review their wells to look for similar issues and to shut down any wells that have the same construction.In parts of the Arctic, permafrost is thawing as temperatures warm due to climate change. But on the North Slope, the thawing that can cause problems at oil wells is likely to be attributed to human error.Tim Robertson, an oil spill response and prevention consultant who has worked on the North Slope, said that companies typically use a packing fluid between the pipe that carries the oil or gas and its outer casing. "That fluid is intended to protect the heat transfer from the products being produced so it doesn't transfer out to the permafrost," he said. "It's like an insulation." Failing to protect the permafrost can have extreme consequences. "A well goes thousands of feet through the permafrost, and that whole layer has to be protected or the integrity of the well itself is threatened if the heat transfers and melts."
Canada's Trans Mountain Pipeline expansion faces opposition - These are the Tsleil-Waututh Nation's ancestral lands. Their name means 'people of the inlet' and their creation story is about these waters, just east of Vancouver; they have inhabited this place for thousands of years.. The Trans Mountain Pipeline ends here, filled with oil from the landlocked Alberta Tar Sands, 700 miles away. Kinder Morgan, the Houston-based company which runs the pipeline, is planning to expand it, increasing its capacity threefold. The expansion would mean many more oil tankers moving through these waters, waters the Tsleil-Waututh harvested until the 20th century, when industrial pollution made it impossible."The concerns are the pipeline expansion terminates right — I don't say in our backyard, I say in our kitchen...it's not if a spill happens, it's when it happens," Aleck says. At first contact with Europeans, this community was decimated by small pox and at one point dwindled to a handful of members, though their population was able to recover some. When the original oil pipeline was built in the 1950s, First Nations had no say in how the land was used. "It was against the law for First Nations to speak to a lawyer, to speak our language, to practice our culture," says Reuben George, another Tsleil-Waututh leader. That has changed. Now, they are actively trying to stop the pipeline expansion, partnering with environmental groups and taking the project to court. The Tseil Waututh is not anti-development and profit from real estate development on their land. But they are against fossil fuels and they've joined a lawsuit with other First Nations on the grounds that they weren't meaningfully consulted about the pipeline. Kinder Morgan says it made good-faith efforts to work with the first nation. But the Tsleil-Waututh is not the only group opposed to the expansion, local and regional governments are also speaking out against it. They say they are assuming the all the risks of the project while the province of Alberta gets the financial benefit
Mexico's "Legendary" Oil Hedging Desk Spent $1.25 Billion On 2018 Puts -- Mexico’s "legendary" oil hedgers (profiled her emost recently one year ago and by Bloomberg in this exhaustive article) are confident that prices won’t linger above $50 a barrel, because this summer, which is why the world’s most-active sovereign oil-trading desk spent a near record $1.25 billion on put options to lock in export prices for next year, Bloomberg reported, citing data from the country’s Ministry of Finance. The news is especially notable because, as we pointed out yesterday, with WTI prices holding at 6-month highs around $54 (and Brent at $60), hedge funds have never been more bullish on the entire energy complex, having accumulated a record 1.189 billion barrel equivalent long positions in the five major petroleum contracts (Brent, WTI (x2), RBOB, HO)... ...and that surge comes as oil analysts are following the trend and raising their oil-price forecasts. Last year, Mexican hedging desk spent $1.03 billion to protect itself from a downturn in prices, according to data released in the quarterly budget balance. In recent years,Mexico has spent an average $1 billion buying the hedges. The hedge first appeare in 2001, when Mexico made a tentative showing, spending just $217.3 million on put options, a fraction of the approximately $1 billion a year it would spend later. In 2003 and 2004, with oil prices rising, the country opted not to hedge at all. The strategy came into its own in 2005: Mexico has hedged every year since without interruption. Agustín Carstens, who later became head of the central bank, was finance minister when a massive $5.1 billion payout came in 2009; some government officials also refer to the annual oil bet as “the Agustínian hedge.”
Pemex gas distribution to lowest level since 1996; production rebounds - The volume of natural gas Mexico's Pemex distributed in October to its processing plants and the country's pipeline network reached its lowest level since 1996, the state company has reported. Pemex distributed 3.48 Bcf/d of gas in October, down just 25 MMcf/d from the month before, but down 13.38% year on year, Pemex said in a report. Of this total, the state company only injected 371 MMcf/d into Mexico's pipeline network, up 10 MMcf/d from the month before, but down 17.37% year on year. The volume of gas Pemex distributes has been on a continuous decline since it peaked at 5.78 Bcf/d in 2009. That year Pemex injected 1.32 Bcf/d into the country's pipeline network. The state company's gas production excluding nitrogen recovered in October, reaching 4.27 Bcf/d, up 470 MMcf/d from September, but down 8.4% year on year. In September, Pemex's associated gas production fell as output was constrained by low domestic refinery demand, crimped demand from Hurricane-hit Gulf Coast refiners, as well as export issues at Salina Cruz. The company produced 1.9 million b/d of crude in October, down 9.65% year on year. Production fell to 1.73 million b/d in September, the lowest since 1980. Pemex was able to increase its gas production in October by 100 Mcf/d over August levels despite its overall gas production including nitrogen decreased from 5 Bcf/d during the same period. The increase in Pemex's natural gas production comes hand on hand with a decrease in its nitrogen production. The state company's nitrogen production was 493 MMcf/d in October, the same volume as for September but down 372 MMcf/d from August.
The Return Of Deepwater Oil - In a historic auction for deepwater oil assets in Brazil, the oil majors showed up on October 27 and bought several offshore blocks, indicating a high level of interest in the country after a major policy overhaul allowed private investment.Royal Dutch Shell won half of the blocks that were offered, and Shell was already one of Brazil’s largest foreign investors. After purchasing BG Group for around $50 billion, Shell took a large presence in Brazil. The logic behind Shell’s strategy is that the company argues it can breakeven with oil at $40 per barrel, making Brazil one of the most attractive places to drill offshore in the world.“These winning bids were submitted after our thorough evaluation and add strategic acreage to our ... global deep-water growth options,” Shell Upstream Director Andy Brown said.ExxonMobil took one block, expanding its position after winning six offshore blocks a few weeks earlier. BP added two blocks as well.But what makes the most recent auction different is that it will allow international firms to not only take stakes in offshore projects, but also lead on them. It is the fruit of a major policy overhaul from 2016, which scrapped a law that required Brazil’s state-owned oil company Petrobras to be the operator on all offshore projects in the pre-salt – Brazil’s deepwater reserves located beneath a thick layer of salt. That law also said that Petrobras had to own 30 percent of pre-salt projects. Related: Venezuela Avoids Default With Critical PaymentAfter that law was repealed in 2016, the oil majors started to express a lot more interest in stepping up investments in Brazil.Brazil’s President Michel Temer, instrumental in liberalizing the energy sector, said the latest auction would lead to $30 billion in new investment in Brazil’s oil sector. “We see the government of Brazil being more supportive of foreign companies entering Brazil,” BP Latin America President Felipe Arbelaez said after the latest auction, according to Reuters. “There are high quality assets. We believe that the assets here will be resilient in any price environment.” “Brazil’s offshore is one of the last major plays out there that’s in its infancy,” said Brian Youngberg, an oil industry analyst at Edward Jones, according to Reuters. “Companies that are still interested in the big elephants out there, like Exxon and Shell, are aggressively pursuing them.”
Six years after tremors halted fracking, Britain ready to try again | Reuters: (Reuters) - Six years after Britain’s first fracking operation was stymied by earth tremors, its shale gas industry is poised to try again with a technology that could transform the UK gas market and drastically reduce its reliance on imports. While environmental and community concerns about fracking have not gone away, changes to the energy landscape since 2011 have added even more complexity to the effort to exploit Britain’s shale gas. On the one hand, imports are cheaper, at least for now. Global liquefied natural gas (LNG) prices LNG-AS have more than halved from 2014 peaks as new supply from Australia and the United States saturated key Asian markets. At the same time, last year’s vote to leave the European Union has stoked fears about the security of Britain’s energy supplies. Britain’s main gas storage site is also due to close, which means the market may be vulnerable to price shocks over the winter months. “Not a lot of people think about where gas comes from and what happens if (Russian president Vladimir) Putin or others fall out with us,” said Francis Egan, the CEO of shale gas developer Cuadrilla, the first company to attempt fracking in the UK, near Blackpool in the northwest of England. “They only begin to think about that when the prices are going up,” he said. Natural gas is used to heat as much as 80 percent of British homes, which make up 35 percent of demand, closely followed by electricity generation at 33 percent and 17 percent by industry. Around 60 percent of that gas is currently imported, up from 40 percent less than 10 years ago. The figure is tipped to reach almost 95 percent by 2040 as known reserves in the North Sea run out.
‘Govt fracking jobs figures out by a factor of 10’ - – A report released last night by the NT Fracking Inquiry reveals a massive drop in projected jobs figures if fracking goes ahead across the Northern Territory.The previous Deloitte’s report that has been used to push the fracking industry showed that in 2040 there would be 6,321 jobs in the highest possible fracking scenario.In stark contrast, the new ACIL Allen report shows there will be only 558 jobs in their highest possible development scenario by the year 2043.This new economic report shows will get less than 10% of the jobs we were told we would get in the previous Deloitte’s report if we allow fracking across the NT. The 13,000 jobs figure in the ACIL Allen report is based on adding up the jobs required each year over 25 years. It assumes that every person loses their job after just one year, and then a new position is created. It’s a misleading figure.The report shows that total employment in the Northern Territory was 132,200 in August 2017. So even if we go with the highest number of fracking wells, we’re still only getting an extra 500 jobs in a year. That’s a tiny 0.4% increase in the number of jobs in the Northern Territory. The report shows that even if this risky fracking industry were to proceed, there would be less than half a percent extra jobs created each year in the Territory, and most of these would be for fly in fly out workers from other parts of Australia.
Europe-bound USGC distillates cargoes jump on LR1s: cFlow - Distillates flows to Northwest Europe and the Mediterranean from the US Gulf Coast for November arrival saw a sharp increase over the last seven days, with around 500,000 mt leaving the region, the majority 10 ppm ultra low sulfur diesel, according to data from S&P Global Platts trade flow software cFlow. The high volume is due to a more workable arbitrage on Long Range tankers, which can carry around 60,000 mt cargoes. Three such vessels were observed to leave the US's refining and storage hub, out of a total of 11 departures from the region. The total volume now expected to arrive in November is around 700,000 mt, the highest since August, after the USGC was plagued by disruptions in September due to hurricanes. The majority of the current volume sailing trans-Atlantic is heading to Northwest Europe where the product is likely to go into CIF shorts, according to one source, rather than break-bulked into the Amsterdam-Rotterdam-Antwerp barge market. "Have seen a bit more [US volume], not so much being shown on the market though, looks like they more or less all have a home and mainly into the CIF shorts so far," the source said. .
Indonesia eyes buying more LPG from Saudi Arabia, UAE amid rising demand --Indonesia plans to increase LPG imports from Saudi Arabia and the UAE in a bid to meet rising domestic demand, Energy and Mines Ministry spokesman Dadan Kusdiana said Tuesday. State-owned oil and gas company Pertamina's LPG requirements are currently around 6 million mt/year, he said. "The government of Saudi Arabia is expected to help with a direct purchase of LPG from Saudi Aramco to Pertamina; the portion of Aramco's LPG is only 13% of the company's total needs," he said. Discussions were held between Energy and Mines Deputy Minister Archandra Tahar and Saudi Arabia and UAE officials recently, he said. Indonesia has asked the government of the UAE to facilitate the direct purchase by Pertamina of LPG from ADNOC, Kusdiana said. Indonesia's consumption quota for subsidized LPG was set at 7.06 million mt in the 2017 state budget, up from 6.25 million mt for 2016, SP Global Platts reported earlier. Indonesia and Saudi Arabia had earlier agreed to set up a joint ministerial level commission to help speed up planned investments by Saudi companies in Indonesia, including cooperation between Pertamina and Saudi Aramco in an oil refinery project in Cilacap in Central Java, Kusdiana said.
Iraqi Pipeline Disruption Takes 250,000 Bpd Off The Market --Crude oil from northern Iraq, including from the Kurdistan region, stopped flowing from the oil pipeline between Kirkuk and the Turkish Mediterranean port of Ceyhan early on Monday local time, Bloomberg reports, citing a port agent.According to a Kurdish shipping source who spoke to Reuters, the flows resumed on Monday after a technical stoppage for several hours that had completely halted the flow of crude.The flow was still reduced to 200,000-220,000 bpd, according to the source.The typical flow of the pipeline is some 600,000 bpd, and it has been used by both the Kurdistan Regional Government (KRG) and the central Iraqi government and its North Oil Company (NOC) for exports of crude oil from the fields in northern Iraq.However, following the Kurdistan region’s referendum which Iraq did not recognize, Iraq’s government forces completed in mid-October an operation to seize control of all oil fields that Iraqi state-held North Oil Company operates in the oil-rich Kirkuk region from Kurdish forces. A day later, disruptions in oil flows started, with reports that the flow of crude oil from Kirkuk to Ceyhan had plummeted to some 225,000 bpd, from around 500,000 bpd the previous day.Disruptions continued throughout the following week, and as of October 24, exports were estimated to have been down by 200,000 bpd since the beginning of the month.In the middle of last week, Iraq’s central government started pumping oil from Kirkuk to Ceyhan, as it started exporting from the Avana field in Kirkuk via the Kurd-operated pipeline to Ceyhan. North Oil Company was then said they would also work to begin exporting from the nearby Bai Hassan oil field. Most of Iraq’s crude oil production is shipped from the southern port of Basra, but in the north, the government must rely on the Kurdish Kirkuk-to-Ceyhan route for exports from its fields in the Kirkuk area until a pipeline that bypasses Kurdistan is repaired.
Chad wants to cut off Glencore's oil supplies in debt row (Reuters) - Chad is on a collision course with top creditor Glencore as it wants to divert oil from the Swiss trading house to U.S. energy company ExxonMobil from the new year amid a dispute over debt restructuring. A government document showed that Chad wants to hand over crude oil marketing rights currently held by Glencore under a $1.4 billion loan agreement to Exxon, the biggest oil producer in the Central African country. Three government and industry sources confirmed the details. Sources close to Glencore say they believe the contract does not allow such a change. Under pressure from the International Monetary Fund, Chad is renegotiating its hefty external commercial debt, namely to Glencore, which eats up nearly all of its oil profits - the country’s main source of revenue. The near $1.4 billion debt to Glencore is being restructured for a second time since the 2014 oil price crash, in a move expected to be completed by the year-end or early next year. Weighed down by drought, a refugee crisis and militant group Boko Haram, the government has become frustrated with Glencore and its handling of the debt restructuring, sources in the administration say. Since 2014, Exxon has been paying royalties to the government in physical crude cargoes that were subsequently allocated by state firm SHT to Glencore. But this process will end in early January as the government has asked Exxon to pay royalties in cash instead, according to a letter from the company dating from mid-October. “In this context, we wish to levy in cash, and not in kind, the royalties due by the Consortium on January 2, 2018,” the letter stated. The change will see Exxon replace Glencore as the marketer of the royalty oil.
Saudi oil-to-chemicals project to take first tentative step this year: reports -- Saudi Arabia is close to completing a feasibility study for a pioneering new facility to convert crude oil directly to petrochemicals, bypassing the need for the refining process, senior officials said Wednesday.The study is being jointly carried out by Saudi Aramco and Saudi Basic Industries Corp. Once concluded, the kingdom's two industrial giants will form a joint venture to take the project forward.They are expected to sign a memorandum of understanding for the fully integrated complex's development before the end of the year, and then to appoint a project management consultant for its design.Saudi Aramco's CEO Amin Nasser said Tuesday he expects a final decision to be made by the end of the year, according to media reports from Riyadh. Neither Aramco or Sabic would comment on the project, and its details are still sparse. A member of the project's research team told S&P Global Platts soon after it was first formed last year, the proposed facility would use super-light crude from a field south of Riyadh, possibly the 100,000 b/d capacity Nuayyim field, about 250 km south of the capital. The process involves purifying the crude before sending it to a catalytic cracking unit to maximize light-olefin output, the building blocks for globally important plastics including polyethylene and polypropylene.
New U.S. Sanctions Threaten Russian Oil Projects - Washington’s newest round of sanctions against Moscow’s oil and gas industry targets Russia’s upcoming projects worldwide, according to drafts of the measures introduced at the United Nations by the U.S.The punitive measures – designed to be a political reaction to Russia’s annexation of Crimea in 2014 – will have a limited effect on Moscow’s current operations abroad, experts said.A new provision in a preexisting sanction levied by the U.S. Department of Treasury now prohibits companies from assisting in exploration and production activities in deep waters, the Arctic Ocean, or shale projects initiated after January 29th, 2018. Projects that boast Russian holdings of 33 percent or higher are singled out in the fine print.“Projects currently being implemented do not fall under the sanctions. This includes Lukoil’s projects in Romania and Ghana offshore as well as Rosneft’s projects in Venezuela,” Fitch Ratings analyst Dmitry Marinchenko told Reuters.American sanctions on Russia oil and gas companies have had little effect on Moscow’s leverage in securing lucrative exploration and production deals so far. Current production stands at 10.92 million bpd, which is close to a 30-year record. “The (33 percent) threshold leaves the possibility for sanctioned Russian companies to take part, even in new projects,” Marinchenko said. There are signs that the sanctions are showing limited effectiveness. The measures made the offshore Yuzhno-Chernomorsky oil field economically unfeasible, and Rosneft will now suspend exploration in the area for five years, the company said earlier this week. The EU’s sanctions contain a grandfather clause allowing existing partnerships to continue, but this is not the case with the U.S. sanctions, so Exxon has had to pull out of its joint projects with Rosneft. Earlier this year, the supermajor asked Washington for a sanction waiver in a bid to continue its work in Russia, with a special focus on Arctic drilling, but the request was denied.
Russia Wields Oil Diplomacy, Pushing In on U.S. Interests (NYT) Russia is increasingly wielding oil as a geopolitical tool, spreading its influence around the world and challenging the interests of the United States. But Moscow risks running into trouble, as it lends money and makes deals in turbulent economies and shaky political climates. The strategy faces a crucial test this week in Venezuela, a Russian ally that must come up with a billion dollars to avert defaults on its debts. Russia has been making a flurry of loans and deals all centered on the Venezuelan oil business, money that could make the difference between the government’s collapse and its survival. In return, Moscow is getting a strategic advantage in Washington’s backyard. President Nicolás Maduro of Venezuela was all smiles this month on a visit to Moscow seeking fresh financial backing, thanking Vladimir V. Putin “for your support, both political and diplomatic.” Moscow, through the state oil giant Rosneft, is trying to build influence in places where the United States has stumbled or power is up for grabs. Its efforts are also driven out of necessity, as American and European sanctions have forced Rosneft to find new partners and investments elsewhere. The company, which Russia has long relied on to finance its government and social programs, has been pushing deeply into politically sensitive countries like Cuba, China, Egypt and Vietnam, as well as tumultuous places where American interests are at stake. Rosneft is looking for deals around the eastern Mediterranean and Africa, areas of tactical importance beyond the energy picture. It is wielding economic and political sway in northern Iraq, by making big oil and natural-gas deals in Kurdish territory. And it is angling to bid for control of Iranian oil fields as tensions between Tehran and Washington escalate.
Oil market set to move from rebalancing to tightening: Kemp (Reuters) - The oil market is now well into a cyclical upswing and within the next year the narrative about “rebalancing” is likely to be replaced by one about “tightening”. Rebalancing started well before the production pact between the Organization of the Petroleum Exporting Countries (OPEC) and its allies went into effect in January. OPEC has been open about the fact that the rebalancing process pre-dated its agreement, with officials repeatedly noting the accord was intended to “accelerate” a process that was already underway. The spot price of Brent has been rising since January 2016 and the six-month calendar spread has been increasing since January 2015 (http://tmsnrt.rs/2gVoCMK). Depending on which turning point is used, the rebalancing process has already been underway for 21 months (spot prices) or 32 months (spreads).Like any rebalancing process, adjustment is barely perceptible at first, which is why the turning point is often missed, but tends to accelerate over time.The current rebalancing started with an acceleration in global oil consumption, which was already evident in the first half of 2015 in response to lower prices.Oil production did not decelerate until 2016, because of the lags in the system, and OPEC’s own output restraint did not start until 2017.But with consumption now running faster than production the market is steadily whittling away the excess inventories accumulated in 2015/2016.During the last two rebalancing processes, after oil slumps in 1998/99 and 2008/09, front-month Brent prices took roughly 21 months and 26 months respectively to reach their first major peak.Meanwhile, the calendar spread took 21 months and 34 months respectively to reach its first cyclical peak after each episode.The recent slump was in some ways deeper, and the recovery has certainly been more prolonged, but it can no longer be described as being in its early stages. The current rebalancing process is already therefore fairly mature and at some point in the next six to nine months will be more accurately described as tightening.
ICE Brent crude stays at 27-month highs in Asia trade - ICE Brent crude futures remained at 27-month highs in mid-morning trade in Asia Monday, following the gains last week on the expectation that planned supply cuts will be extended to the end of 2018. At 11:21 am Singapore time (0321 GMT), the ICE December Brent crude futures were down 6 cents/b (0.1%) from Friday's settle at $60.38/b, while the NYMEX December light sweet crude contract was up 4 cents/b (0.07%) at $53.94/b. The expectation that output cuts by OPEC and non-OPEC producers will be extended have firmed up in recent days, amid comments by key officials that the group was inching closer to a consensus. Over the weekend, Saudi Arabia's crown prince Muhammad bin Salman reaffirmed his backing for an extension beyond the current March 2018 deadline. "The kingdom affirms its readiness to extend the production cut agreement, which proved its feasibility by rebalancing supply and demand," the crown prince said in a statement. Similar remarks by him late last week sent crude prices soaring by more than 3% over October 26-27, with ICE Brent now at highs not seen since July 2015. Nonetheless, an agreement is far from certain. Russian energy minister Alexander Novak, who is due to meet Saudi oil minister Khalid al-Falih in Riyadh this week, has said he does not see a need to announce any extension at the November 30 meeting.
Brent crude tries new trading range as funds stay bullish: Kemp - (Reuters) - Hedge funds have added to bullish positions in oil and most refined products even as prices hit their highest since 2015, in a sign investors expect prices to move into a higher range. Hedge funds and other money managers had accumulated bullish long positions in crude, gasoline and heating oil totalling 1.189 billion barrels by Oct. 24, according to regulatory and exchange data. Portfolio managers have increased long positions in the five main petroleum contracts by almost 374 million barrels (46 percent) since the end of June and the number of paper barrels now comfortably exceeds the previous peak set in February.From a pure positioning perspective, the concentration of long positions has become a significant source of downside risk to prices in the event funds attempt to realise some profits.Nonetheless, managers have continued adding to rather than reducing their positions, which strongly suggests many investors see oil prices moving into a new and higher range.For the last 16 months, Brent prices have been trading in a range of about $45 to $55 per barrel, with hedge funds alternately buying and shorting the market when prices move towards the extremes.But hedge fund managers amassed a near-record net long position of 507 million barrels in Brent by Oct. 24 even as prices were on their way to breaking through the $60-mark for the first time since 2015.Sentiment towards Brent remained overwhelmingly bullish, with long positions outnumbering short ones by a ratio of 9.48:1, the biggest imbalance for eight months (http://tmsnrt.rs/2gVxjHb).Fund managers held 567 million barrels of Brent long positions, just 11 million below the record set at the end of September, but less than 60 million barrels of shorts, the lowest since February.The position data indicate fund managers see little risk of Brent prices dropping back below $50 per barrel, or maybe even $55, but a good chance prices will remain above $60, and maybe even climb towards $65.
Saudi crown prince reiterates backing for OPEC oil output cut extension - Saudi Arabia's powerful crown prince Mohammed bin Salman reaffirmed his backing for an extension to OPEC's crude oil output cut beyond its current March 2018 deadline to rebalance the global market. "The kingdom affirms its readiness to extend the production cut agreement, which proved its feasibility by rebalancing supply and demand," the crown prince said in a statement. OPEC members and 10 non-OPEC producers led by Russia, have committed to cut a combined 1.8 million b/d from the market in a bid to lower record high crude oil inventories. The initial six-month deal was extended in May to March 2018. Mohammed bin Salman, the son of the reigning monarch King Salman al-Saud is the key driver of the OPEC kingpin's oil policy. "The high demand for oil has absorbed the increase in shale oil production," he added. "The journey towards restoring balance to markets, led by the kingdom, is proving successful despite the challenges," he said. While he has backed an extension, the details of any deal, including its length, allocations or any other new terms, will have to be negotiated before the coalition's next meeting November 30 in Vienna. An agreement is far from certain. Russian energy minister Alexander Novak, who is due to meet Saudi oil minister Khalid al-Falih in Riyadh this week, has said he does not see a need to announce any extension at the November 30 meeting.
Crude Oil Prices Settle Higher as Optimism on Opec Deal Extension Grows – Crude oil prices settled higher on Monday as concerns over an uptick in Iraqi exports were offset by ongoing speculation that Opec will agree to extend output cuts beyond March. On the New York Mercantile Exchange crude futures for December delivery rose 0.5% to settle at $54.15 a barrel, while on London's Intercontinental Exchange, Brent added 0.45% to trade at $60.59 a barrel. Crude oil prices continued their march higher, rising to an eight-month high amid bullish talk from Opec and non-Opec members on a possible extension to the output-cut agreement. OPEC Secretary General Mohammad Barkindo said Russian-Saudi backing for an extension cleared the fog ahead of the group's meeting in Vienna on Nov. 30. “OPEC welcomes the clear guidance from the crown prince of Saudi Arabia on the need to achieve stable oil markets and sustain it beyond the first quarter of 2018,” Barkindo said weekend. “Together with the statement expressed by President Putin, this clears the fog on the way to Vienna on Nov.30”, he added. Barkindo’s comments came just a few days after Saudi Prince Mohammed bin Salman told Reuters on Thursday, the kingdom would support extending output cuts in order to rid the market of excess supplies. In May, Opec producers agreed to extend production cuts for a period of nine months until March, but stuck to production cuts of 1.2 million bpd agreed in November last year. Growing expectations that Opec will continue to comply with output cuts has forced analysts to lift their forecasts on oil prices amid signs that the Opec-led deal to cut output is narrowing the gap between demand and supply. JP Morgan raised its 2018 Brent and WTI forecasts by $11 and $11.40 to $58 and $54.63 per barrel, respectively. Investor concerns over a potential uptick in global supply, however, capped gains in oil prices after Iraq's southern ports ramp up export capacity by 900,000 barrels per day (bpd) to 4.6 million bpd.
Brent oil ends above $60 on expected OPEC cut extension | Reuters: Brent oil closed on Monday at its highest level since July 2015 and U.S. crude closed at a peak not seen since February on expectations OPEC-led production cuts would be extended beyond March, although such gains are likely to spur more U.S. production.Brent crude futures LCOc1 settled at $60.90 a barrel, up 46 cents. Brent has gained 9.5 percent in the last 16 trading days. U.S. West Texas Intermediate (WTI) crude futures CLc1 settled up 25 cents at $54.15 a barrel, highest since Feb. 23, 2017. The U.S. contract has been strong of late as well, gaining 10 percent in the last 16 trading days. “The market has now held over $49/bbl for over a month, establishing that as the low end of the new range,” wrote analysts at Drillinginfo.com. The Organization of the Petroleum Exporting Countries plus Russia and nine other producers agreed to cut 1.8 million barrels per day from January 2016 to clear a supply glut. The pact, already renewed once, runs to March 2018. But Saudi Arabia and Russia, which are leading the effort, have voiced support for a further extension. OPEC Secretary General Mohammad Barkindo said Russian-Saudi backing for an extension cleared the fog before the group’s meeting in Vienna on Nov. 30.
Are Higher Oil Prices Here To Stay? - Oil jumped to $60 per barrel on Friday, and held those gains on Monday, an early sign that the oil market could be entering a new phase. Brent topped $60 per barrel for the first time in nearly two and a half years. The strong assurances from OPEC and Russian officials has the market assuming that the upcoming OPEC meeting in November will result in an extension of the production cuts, perhaps through the end of 2018. With that extension in hand, the oil bears are in retreat. The powerful crown prince said that he supports an extension of the OPEC cuts, the strongest signal yet that the November OPEC meeting will lead to an extension of the production limits. Third quarter profits for the oil majors jumped, a sign that they have adapted to a world of $50 oil. ExxonMobil, Chevron, BP, Total SA reported strong profit growth, proof that cost-cutting is bearing fruit. The majors have slashed a combined $80 billion in spending since 2013. BP said that it would restart its share buyback program after reporting a replacement cost profit – similar to net income – of $1.4 billion in the third quarter, down a bit from $1.7 billion a year earlier. The company declined to reveal a value on its buyback plans. The British oil giant had scrapped share repurchasing back in 2014 amid falling oil prices, but has made strides in adapting to lower oil prices. BP said that it can breakeven with oil prices at $49 per barrel. Reuters argues that falling U.S. oil inventories are a sign of a shift towards backwardation for WTI, a state in which near-term oil contracts trade at a premium to longer-dated oil futures. With Brent already in a state of backwardation, the downward sloping futures curve for WTI would be another signal that the oil market is tightening. Backwardation tends to appear during periods of market tightening and would suggest higher oil prices are possible.
3 Potential OPEC Deal Killers -- The Middle East isn’t yet ready to agree on the future of OPEC’s output reduction deal as the bloc’s November 30 summit approaches, during which the cartel is set to decide on the depth and length of the cuts one year from their initial approval. Here are the three key geopolitical issues wreaking havoc on the region’s ability to collectively raise the price of oil.
- 1. The Trump Administration’s Ongoing Iran Nuclear Deal Drama. From the day that Donald Trump declared he would run for president, he made it clear that he is firmly against the current deal with Tehran to reintegrate Iran’s economy into the international community in exchange for a smaller and monitored nuclear energy program. Earlier this month, Trump officially decertified the nuclear deal, which doesn’t do much in the way of dismantling the agreement, but does give Congress leeway to authorize further sanctions against Iran. The uncertainty surrounding the U.S. sanctions on Iran leads to uncertainty regarding OPEC’s third largest oil producer’s ability to contribute to or maintain oil output. Tehran’s participation in the oil game has been contingent upon the success of the nuclear deal since January 2016. New sanctions from a Republican congress could undo much of the progress made by engaging the economic pariah.
- 2. Iraq’s Intense Struggle with Kurdistan. The Kurdistan independence referendum last month caused Baghdad to take over key oil fields formerly controlled by the Kurdistan Regional Government (KRG). A fraction of former output (half, or less than half, by most measures) is currently flowing through a pipeline in the area due to a deal between the Iraqi government and the Kurdish KAR group. Last weekend, Iraqi authorities said they increased oil exports from the southern Basra region by 200,000 barrels per day to make up for a shortfall from the northern Kirkuk fields. But this doesn’t promise future output rebuttals if the KRG or its Peshmerga decide to strike back to regain its oil might. A significant loss in output from OPEC’s No. 2 producer could cause an unexpected spike in oil prices, which is what Saudi Arabia, the bloc’s leader, craves.
- 3. A Gulf Blockade Entering its Sixth Month. Despite its standing as top exporter of liquefied natural gas, Qatar is not a significant oil producer. The geopolitical impact of the Gulf’s economic blockade against Doha, however, could have significant geopolitical consequences as it enters into its sixth month with no end in sight. Instead of limiting its ties to Iran, Qatar has spent its political capital strengthening ties with the Shi’ite nation, which rivals Saudi Arabia politically and economically. Escalating tensions between the Gulf and Qatar will further increase the angst between Iran and Saudi Arabia, impacting the future of Iran as a political player and as a major oil producer.
This trio of major regional disputes plaguing the Middle East heavily involve the top three oil producers in the bloc. Iran has been in economic recovery mode since sanctions were lifted back in January, while Iraq’s stability over the course of 2016 and most of 2017 had allowed production to rise steadily. With the trajectory of future output for the neighboring nations unclear, it remains to be seen whether the bloc will find it necessary to tighten quotas. After all, if the production cannot be summoned due to tangential political issues, there may be no need to limit it directly.
U.S. Shale Could Bring Bearishness Back To Markets - Brent oil has breached the technical and psychological barrier of $60, while WTI inched up to $54. The bulls are relishing in the excitement of rising prices. But there’s one pressing question: Is this rally sustainable? The bulls might have to proceed with caution. Recent figures indicate a build-up of 856,000 barrels in crude inventories, with U.S production surging by 1.1 million bpd last week, to a total of 9.5 million barrels per day (bpd). Despite rising production, Baker and Hughes reported a fall in rig count by 4. The total rig count now stands at 737.A driving factor behind the price rally was comments from Saudi Oil Minister Khalid Al-Falih, as he told the world that they will do “whatever it takes” to bring crude inventories back to normal and rebalance the oil markets. The comments were echoed by Crown Prince Mohammed bin Salman and Russian President Vladimir Putin. Subsequently, many observers and traders now think it’s safe to bet on the rising oil prices.When the members of the Vienna accord meet in November, many observers agree that they’ll reach an agreement to extend the deal further than March 2018. Russia and Saudi Arabia are on good terms and the Saudi monarch’s recent visit to Russia cements the fact that with both prime players of the deal on the same page, the extension is almost certain. The extension will likely translate into a price hike. The case could be made, however, that the markets have already discounted the impact of the extension, given its certainty.There’s another side of this bullish development: its impact on shale production. Recently, there have been concerns regarding U.S. shale producer’s profitability and growth, but the news of prices reaching and edging above $60 will certainly be music to the ears of U.S. drillers. This could result in greater production and hence amplify the supply glut.The effect of shale growth and inventory reports after the deal is extended will be more potent than without it. Why? Because market sentiment and expectation play a momentous role in guiding the prices. In this case, the market will, evidently, expect inventories to drain. However, this balance between rising U.S. production and the Vienna extension will certainly have an impact on these expectations.
WTI/RBOB Jump After Major Inventory Draws Across Entire Energy Complex - WTI posted a 5.2% gain in October, the first back-to-back monthly advance this year, and held up near the highs of the day into the API print. WTI/RBOB kneejerked higher as the data hit showing large inventory draws across everything...API:
- Crude -5.087mm (-1.3mm exp)
- Cushing -263k
- Gasoline -7.697mm (-1.55mm exp)
- Distillates -3.106mm
Big product draws in the previous week - and a modest crude build - bucked the recent trend but tonight's API data shows huge draws across everything...Expectations that OPEC’s cuts are “tightening the market supply-demand fundamentals continues to drive prices higher,”
Oil up near two-year highs, analysts see more U.S. crude exports - (Reuters) - Oil prices settled higher again on Tuesday, notching a monthly gain of more than 5 percent, but analysts said bullish sentiment that has driven Brent crude to its highest in more than two years could encourage U.S. producers to export more oil. Brent settled up 47 cents or 0.7 percent to $61.37, close to its July 2015 highs reached earlier this week, and up around 37 percent from its 2017 lows hit in June. U.S. West Texas Intermediate crude (WTI) settled up 23 cents or 0.4 percent to $54.38, still near its highest since February and close to its highest in more than two years. Traders and brokers said investors were adjusting positions after price rises of around 5 percent in October. For the month, Brent was up 6.7 percent, while WTI rose 5.2 percent. WTI’s discount to Brent CL-LCO1=R has widened to nearly $7, making it attractive to exporters. “The large differential has opened the door on regional arbitrage, driving a spike in U.S. crude exports over recent weeks,” BMI Research said in a note. U.S. crude exports have jumped to close to 2 million barrels per day (bpd) and production has risen almost 13 percent since mid-2016 to 9.5 million bpd. “The problem is as soon as prices move up it’s too easy for U.S. producers to add another rig or another completion crew,” , “Then they increase production and you’re back where you started.”U.S. crude and gasoline futures extended gains in post-settlement trade after industry group the American Petroleum Institute said that U.S. oil inventories fell far more than expected. Crude inventories fell 5.1 million barrels in the week to Oct. 27 to 456.8 million, compared with analysts’ expectations for a decrease of 1.8 million barrels. Gasoline stocks plunged 7.7 million barrels, versus forecasts of a 1.5 million-barrel draw, the API said.
US crude oil exports hit all-time high as output closes in on record - Oil prices pulled back on Wednesday after data showed U.S. crude exports surged to an all-time high and American drillers pumped near record levels. The United States exported 2.13 million barrels a day of oil in the week through Oct. 27, the first time the nation has crossed the 2 million-barrels-per-day mark.Meanwhile, weekly figures showed total U.S. crude production at 9.55 million barrels a day, just short of the Sept. 29 high going back to July 10, 2015. The week's total output was not far off the all-time high of 9.61 million barrels per day, struck the week ended June 5, 2015. The preliminary weekly figures are later revised. U.S. West Texas Intermediate crude was trading at $54.52 a barrel, 14 cents higher, after topping out at $55.22 earlier in the session. WTI's discount to international benchmark Brent crude has made U.S. oil more attractive to overseas buyers. Brent was trading at $61.06, up 12 cents, on Wednesday. "Brent above $60 will keep WTI higher as they export it and replace that expensive Brent," Bob Iaccino, chief market strategist at Path Trading Partners, told CNBC's "Futures Now" on Tuesday. American drillers have filled some of the supply gap left this year by OPEC and other oil exporters, who have cut production since January in order to drain a global glut of crude. Oil prices have been rallying on expectations that the producers will extend the deal, which is set to expire in March, through the end of 2018. U.S. oil shipments have surged from roughly 400,000 barrels a day at the end of 2015, when the United States lifted a 40-year ban on crude exports. The trade has been fueled by a boom in U.S. oil output from shale fields, where producers use advanced drilling methods to coax fossil fuels from rock formations.
WTI/RBOB Sink As Inventory Draws Disappoint --WTI/RBOB held on to gains overnight following major draws reported by API and more OPEC jawboning (this time from UAE), but the DOE data disappointed compared to API's huge draws with Crude and Gasoline drawing down but considerably less than API reported (and Distillates barely drawing down at all). DOE:
- Crude -2.44mm (-1.3mm exp)
- Cushing +90k
- Gasoline -4.02mm (-1.55mm exp)
- Distillates -320k (-2.5mm exp)
Following API's major draws, DOE was a big disappointment with smaller draws in crude, gasoline, and distillates than API reported and a build at Cushing... Bloomberg Intelligence energy analysts Fernando Valle and Vince Piazza note that it's the time of year when oil inventories begin to build, and supplies are already almost 17% above the five-year norm. While benchmarks have rallied on heightened geopolitical concerns, sentiment remains unsteady. Oil production is resilient, but exports are offering a key outlet for elevated stockpiles. US Crude production rebounded the prior week from Gulf storm shut-ins and increased once again this week...
Oil slips, erases gains as US crude draw shy of API report (Reuters) - Oil prices dipped in see-saw trade on Wednesday, hitting their highest in more than two years and then retreating after weekly U.S. government inventory data showed the latest crude stock draw was not as big as an industry trade group had reported. While oil settled lower, both global marker Brent and U.S. crude benchmarks remained near the highest levels since July 2015, as lower global supply pushed markets higher. The U.S. Energy Information Administration (EIA) said crude stocks fell 2.4 million barrels last week, exceeding the 1.8 million barrel draw analysts forecast in a Reuters poll, but short of the 5.1 million barrel decline reported late on Tuesday by the American Petroleum Institute (API). "Oil prices fell since the release of the (EIA) report," said Carsten Fritsch, oil analyst at Commerzbank AG in Frankfurt, Germany, noting that the crude draw was "significantly less than the API numbers." Brent futures settled down 45 cents, or 0.74 percent, at $60.49 a barrel, while U.S. West Texas Intermediate crude was down 8 cents, or 0.15 percent at $54.30 a barrel. Before the EIA report, Brent was trading at its highest since July 2015 on data showing OPEC had significantly improved compliance with its pledged supply cuts and Russia was widely expected to keep to the deal. Meanwhile, the WTI "Dec Red" - the spread between December 2017 and 2018 U.S. crude - traded to as high as $1.83 a barrel, the strongest level since February 2014 before the oil price crash. WTI Dec 2017's premium to 2018 suggested that the end of the crude glut may be in sight.
ICE Brent/WTI spread narrows as US crude exports hit record high -- The front-month ICE Brent/WTI spread narrowed below $6/b Wednesday after Energy Information Administration data showed US crude exports exceeded 2 million b/d last week, a record-high. With the premium for Brent over WTI around $5-$7/b most of the time since September, versus a premium of $3/b in mid-August, US crude producers have taken advantage higher prices abroad. Crude exports rose 209,000 b/d to 2.133 million b/d, beating the previous all-time high of 1.984 million b/d set the week ending September 29. The Brent/WTI spread was around $5.98/b Wednesday afternoon, in from $6.99/b Tuesday. The rollover to January as the front-month contract also contributed to the day-on-day decline. US exports should remain solid considering a $6/b spread is still more than enough to cover the related transportation costs, said Kyle Cooper, consultant at ION Energy. "There really isn't an economic justification" for the size of the current spread, he said. Greater exports have helped draw barrels out of storage. US crude stocks fell by 2.435 million barrels last week to 454.906 million barrels, marking the fifth decline over the last six weeks. Crude futures failed to rally, however. NYMEX December crude fell 8 cents to $54.30/b. ICE January Brent declined 45 cents to settle at $60.49/b. Profit-taking likely played a role a day after prompt NYMEX crude settled Tuesday at its highest level since February and prompt ICE Brent settled at its highest level since summer 2015.
Booming oil demand is eroding inventories: Kemp (Reuters) - Global oil consumption is growing rapidly, helping account for the decline in reported inventories, the recent surge in prices and the shift in futures markets from contango to backwardation.Consumption is much harder to measure than production, which is why the demand side of the market receives less attention. Even in the advanced economies, consumption data is only available with a delay of two months or more, and reliable data from emerging economies often not at all. Global demand assessments are therefore often educated guesswork, as analysts try to calculate how much oil has been used and how much is in storage. But strong consumption growth has been at least as important as the restraint of production by OPEC and non-OPEC oil exporters in helping rebalance the oil market. Global consumption rose by 1.6 million barrels per day (bpd) in 2016 and 2.0 million bpd in 2015 as low prices and a synchronised economic expansion in most areas of the world spurred demand (“Statistical Review of World Energy”, BP, 2017).Consumption is forecast to increase by a further 1.6 million bpd this year and 1.4 million bpd in 2018, according to the International Energy Agency (“Oil Market Report”, IEA, Oct 2017). And predictions have been consistently revised higher as demand data has come in stronger than forecast. U.S. gasoline consumption hit a seasonal record in four of the five months between April and August, according to the U.S. Energy Information Administration (“Petroleum Supply Monthly”, EIA, Oct 2017). Strong economic growth, cheap fuel, more driving and purchases of bigger vehicles have offset improvements in fuel economy since 2015. U.S. consumption of diesel has also been running consistently higher than last year, reflecting the increase in oil and gas drilling as well as more freight movements.,With demand growing at home, U.S. refineries have been exporting record quantities of fuel to markets in Latin America and the rest of the world reflecting strong demand overseas as well as refinery problems in some emerging markets.
U.S. oil prices mark highest settlement since 2015 -- U.S. benchmark oil eked out a modest gain Thursday, with concerns surrounding a potential rise in domestic production leaving prices vulnerable to a drop, but recent data showing a decline in crude and product stockpiles help prices rise to their highest finish since 2015. December West Texas Intermediate crude tacked on 24 cents, or 0.4%, to settle at $54.54 a barrel on the New York Mercantile Exchange. That was the highest finish for a front-month contract since July 2015, according to FactSet data. Brent oil for January rose 13 cents, or 0.2%, to $60.62 a barrel on the ICE Futures Europe exchange, but held below the more than 2-year high of $60.94 it hit on Tuesday. Oil prices settled lower Wednesday (http://www.marketwatch.com/story/us-oil-jumps-to-2-year-high-on-signs-opec-deal-is-working-2017-11-01), after U.S. benchmark WTI touched a more than two-year intraday high above $55 a barrel and Brent crude, the global benchmark, retreated from July 2015 highs to post its first decline in seven sessions. A report from the Energy Information Administration on Wednesday (http://www.marketwatch.com/story/eia-data-show-declines-in-us-crude-gasoline-and-distillate-stocks-2017-11-01) offered a supportive inventory picture," with "fairly strong draws to both crude and product stocks," including distillates "holding noticeably below the five-year average," said Robbie Fraser, commodity analyst at Schneider Electric. The EIA report showed that U.S. crude supplies fell by 2.4 million barrels for the week ended Oct. 27, while gasoline stockpiles dropped by 4 million barrels for the week and distillate stockpiles fell by 300,000 barrels. On Nymex Thursday, December gasoline added 1.7% to $1.770 a gallon while December heating oil lost 0.5% to $1.854 a gallon. The impact of the petroleum supplies declines was "countered by rising oil production with lower 48 [states] producers adding nearly 50,000 of new output" for the week,
Top OPEC Ministers Back Longer Cuts But Duration Undecided -- OPEC and its allies agree they need to prolong their output-cut deal as bloated inventories won’t shrink to normal levels by March, but they’ve yet to reach a consensus on how long to extend the pact, according to ministers from three of the top producers. Global stockpiles are declining and demand is increasing, but there’s still a significant inventory overhang in the market, Khalid Al-Falih, Saudi Arabia’s oil minister, said at the Asian Ministerial Energy Roundtable in Bangkok on Thursday. Issam Almarzooq, his Kuwaiti counterpart, said producers are discussing and finalizing a decision on the extension of output curbs by the Organization of Petroleum Exporting Countries and partners such as Russia. “We are looking now for the mechanism for the time, how long that would be and what would be more suitable to achieve the re-balancing of the market,” Almarzooq said in an interview with Bloomberg in Bangkok. While he expects an extension of the output curbs to be announced at OPEC’s Nov. 30 meeting, details about the duration or any changes in conditions may come only in February or March when more information is available, he said. Almarzooq’s comments echo those from the United Arab Emirates’ Energy Minister Suhail Al Mazrouei in Bangkok on Wednesday. In Baghdad, Iraqi Oil Minister Jabbar al-Luaibi told reporters that his country, OPEC’s second-biggest producer after Saudi Arabia, supports extending the cuts accord for nine months and backs any decision by the group to prop up prices. Crude has surged into a bull market amid speculation that OPEC and its allies will prolong their deal as well as a revival in demand. Saudi Arabian Crown Prince Mohammed bin Salman said last month that he backed the extension of the curbs beyond their expiry in March 2018. Russian President Vladimir Putin also gave provisional backing to lengthening the restrictions, a signal that Riyadh and Moscow are ready to prolong their collaboration to lift energy prices.
OPEC likely to keep oil supply curbs for whole of 2018: sources (Reuters) - OPEC is likely to stay the course by keeping its current curb on oil production in place for the whole of 2018 despite potential output disruptions next year, Gulf OPEC sources said. The Organization of the Petroleum Exporting Countries, plus Russia and nine other producers, have cut overall output by about 1.8 million bpd since January. The pact runs to March 2018, but the producers are considering extending it. OPEC is scheduled to next meet at its headquarters in Vienna on Nov. 30. Venezuela’s oil production, which has been falling by about 20,000 barrels per day per month since last year, is on track to fall an additional 240,000 bpd next year as U.S. sanctions and a lack of infrastructure investment hobbles operations. Oil flow from other OPEC members such as Nigeria and Libya continue to see supply disruption. But Saudi Arabia and OPEC are unlikely to raise output elsewhere next year to compensate for this decline as the exporting group wants to remain focused on reducing the level of oil stocks in OECD industrialized countries to their five-year average, one OPEC source familiar with Saudi thinking on its oil policy said. “OPEC is likely to stay the course for the rest of 2018. We want to see commercial stocks going down,” the source said. Another OPEC source said there was a high risk of a supply drop from Venezuela next year but that does not necessarily mean that OPEC will raise output elsewhere to make up for the decline. The first OPEC source said that output from the Latin American OPEC nation could fall in 2018 by 300,000-600,000 bpd, adding that the risk of supply disruptions from other OPEC producers such as Libya and Nigeria also remained high. “The feeling in OPEC is that $60 (a barrel) should be the floor for oil prices next year,”
OilPrice Intelligence Report: OPEC Takes The Lead In Rampant Bull Market: Oil prices were mostly flat this week, but held onto their gains at a roughly two-year high. It is not clear if the gains can continue, but the fact that Brent has avoided a retracement back below $60 per barrel is good news for oil bulls. A strong rig count on Friday drove oil prices higher still – but OPEC will likely be the main driving force behind the oil price narrative for the next few weeks, until their meeting on November 30. The flurry of comments in recent weeks from OPEC officials has steadily ratcheted up expectations for what they will agree to at their upcoming meeting in Vienna. The latest report, from Reuters, suggests that OPEC is likely set to agree to an extension through the end of 2018 rather than just for three months beyond March. “OPEC is likely to stay the course for the rest of 2018. We want to see commercial stocks going down,” a source within OPEC told Reuters. Even more bullish, from the perspective of oil prices, is that OPEC officials want prices to rise even higher. “The feeling in OPEC is that $60 (a barrel) should be the floor for oil prices next year,” the source said. The Venezuelan government said on Thursday that it wants to restructure its debt as the clock ticks on massive debt payments. President Nicolas Maduro promised to pay the $1.1 billion payment due on Thursday, but he vowed that it would be the last. “Venezuela has had to face a genuine financial blockade," Maduro said, referring to U.S. sanctions. Action from the U.S. Treasury has made it extremely difficult for Venezuela to restructure its debt. Confusion reigned, however, as bondholders were unsure if he intended to default on coming debt payments or not. Meanwhile, Reuters estimates Venezuela could lose an additional 240,000 bpd in output next year, in part because of U.S. sanctions, after losing 20,000 bpd each month over the past year. Royal Dutch Shell reported earnings of $3.7 billion in the third quarter, up more than double from the $1.4 billion a year earlier. That rounded out the earnings season for the oil majors, which will go down as the best quarter in years for them. Shell has focused on paying down its massive pile of debt, and it has succeeded in lowering its total debt from $77 billion last year to just $67.7 billion at the end of the third quarter.
US Oil Rig Count Drops Most Since May 2016 To 5-Month Lows - The number of US oil rigs continues to track the lagged price of WTI (lower). For the 4th week in the last 5 (and 10th of last 12), oil rigs declined (down 8 to 729). This is the biggest absolute rig count drop since May 2016 to the lowest total rig count since May 2017.
WTI Soars As U.S. Oil Rigs See Biggest Decline Of The Year - Baker Hughes has reported that the number of oil and gas rigs in the United States fell for yet another week, this time dipping 11 rigs—most of which was a loss to the number of oil rigs—the largest decline in the number of oil rigs this year.WTI and Brent continue on their upward trend as even more analysts agree on the increased likelihood that OPEC will extend their production cut agreement throughout all of 2018, and as EIA reports a continued drawdown of crude oil inventories in the US. Prices will likely increase even more as the Iraq/Kurd situation drags on, and as Baker Hughes reports even further reductions to the number of active rigs in the United States.The total oil and gas rig count in the United States now stands at 898 rigs, up 329 rigs from the year prior, with the number of oil rigs in the United States decreasing by 8 this week and the number of natural gas rigs decreasing by 3. The US oil rig count now stands at 729.The spot price for WTI is also trading up to its highest level in six months, up .86% on the day at $55.01 at 11:05am EST—more than $1 up from last week. Brent crude was trading up 1.02% at $61.24 at that time—also $1 over last week’s price at the same time.Despite the falling oil rig count, US crude oil production was up for the week ending October 27 at 9.553 million barrels per day—a new high for 2017.At 10 minutes after the hour, WTI was trading at $55.01, with Brent crude trading at $61.24.
U.S. oil rig count falls by most in week since May 2016 - (Reuters) - U.S. energy companies cut eight oil rigs this week, the biggest reduction since May 2016, extending a drilling decline that started over the summer when prices slipped below $50 a barrel. The oil rig count fell to 729 in the week to Nov. 3, the lowest level since May, General Electric Co's Baker Hughes energy services firm said in its closely followed report on Friday. The rig count, an early indicator of future output, is still much higher than a year ago when only 450 rigs were active after energy companies boosted spending plans for 2017 in the second half of last year as crude started recovering from a two-year price crash. The increase in drilling lasted 14 months before stalling in August, September and October after some producers started trimming spending plans when prices turned softer over the summer. U.S. oil production dipped to 9.2 million barrels per day (bpd) in August, according to federal energy data released this week. Overall, however, exploration and production (E&P) companies expect to increase the amount of money they plan to spend on U.S. drilling and completions in 2017 by about 53 percent over 2016, according to U.S. financial services firm Cowen & Co. That was up from 50 percent in the firm's prior capital expenditure tracking report last week. That expected 2017 spending increase followed an estimated 48 percent decline in 2016 and a 34 percent decline in 2015, Cowen said. U.S. crude futures , which reached a high of $55.22 a barrel this week, which put them within a few cents of their highest since July 2015, have averaged almost $50 a barrel so far in 2017, easily topping last year's $43.47 average. Looking ahead, futures were trading around $55 for the balance of the year and calendar 2018 . Cowen, which has its own U.S. rig count, said it expects a gradual decline in rigs in the fourth quarter of 2017 and in 2018. There were 898 oil and natural gas rigs active on Nov. 3. The average number of rigs in service so far in 2017 was 868. That compares with 509 in 2016 and 978 in 2015. Most rigs produce both oil and gas.
Oil extends surge as OPEC signals deal, supply threats mount - Houston Chronicle - Oil closed at its highest in more than two years for a second day as support grew for OPEC to prolong output cuts, while supply threats abounded. Futures jumped 2 percent in New York, closing above $55 a barrel for the first time since July 2015. While Nigerian militants and Venezuela’s debt woes imperil crude output from two of the world’s chief suppliers, the overarching bullish factor remained the increasing prospects for an extension of the OPEC-led curbs to be decided as early as this month. In the U.S., oil rigs declined by the most in more than a year, and WTI surpassing Thursday’s intraday high also provided upward momentum later in the session. OPEC has indicated “they are looking to extend the agreement through the end of 2018,” Andrew Lebow, senior partner at Commodity Research Group, said by telephone. “We’ve made a new high and the fundamentals have finally improved.” Oil has surged on signs that global inventories are shrinking and the Organization of Petroleum Exporting Countries and allied producers may stick to their glut-killing accord beyond its March expiration. Saudi Arabia, Iraq and Kuwait -- which together pump more than 50 percent of OPEC’s crude -- signaled firm support for an extension that would forestall a re-emergence of the glut next year. “OPEC chatter also sounds like both the Saudis and Kuwait are both game for extending the deal sooner rather than later,” Bob Yawger, director of the futures division at Mizuho Securities USA Inc. in New York, said by telephone. West Texas Intermediate for December delivery advanced $1.10 to settle at $55.64 a barrel on the New York Mercantile Exchange and climbed for a fourth week. Total volume traded was about 13 percent below the 100-day average. Prices rose as high as $54.84 a barrel on Thursday intraday. Brent for January settlement added $1.45 to end the session at $62.07 on the London-based ICE Futures Europe exchange. The global benchmark traded at a premium of $6.21 to January WTI.
Is Saudi Arabia's Oil Strategy Working? -- The IMF estimated that Saudi Arabia will need oil prices to trade at about $70 per barrel in 2018 for its budget to breakeven, a dramatic improvement from the $96.60 per barrel it needed just last year. Saudi’s improvement is the most dramatic out of all the Middle Eastern oil producers, and it also suggests the combination of austerity, cuts to wasteful subsidies, new taxes and economic reforms are starting to bear fruit. The improvement is all the more important because Saudi Arabia and its fellow OPEC members are restraining output as a way to boost oil prices. Selling fewer barrels means less revenue, although that is offset by the coordinated production cuts through the OPEC deal, which has helped raise prices. Nevertheless, there is something glaring about Saudi Arabia’s breakeven price: It is still far higher than the current oil price, which means Riyadh is still feeling the economic and fiscal pressure from low crude prices. “The reality of lower oil prices has made it more urgent for oil exporters to move away from a focus on redistributing oil receipts through public sector spending and energy subsidies,” the IMF said in its report. Saudi Arabia and other Middle East oil producers “have outlined ambitious diversification strategies, but medium-term growth prospects remain below historical averages amid ongoing fiscal consolidation,” the IMF added. In other words, austerity might help narrow the budget deficit to some degree, but it can also be self-defeating if it slows growth. Saudi Arabia may have posted the largest drop in its breakeven price, but several of its peers have even lower budgetary thresholds. Iran, Iraq, Kuwait and Qatar all breakeven at $60 per barrel or less in 2018, meaning they will likely avoid a fiscal deficit. Saudi Arabia, on the other hand, will take much longer to balance its budget, the IMF warned. It is expected to post a $53 billion deficit this year. That means it will likely have to continue to turn to international and domestic debt markets to plug its budgetary gap, while also burning through cash reserves. Last year, Saudi Arabia issued $17.5 billion in international debt, the largest debt issuance ever sold in emerging markets. Earlier this year it sold $9 billion sukuk, or Islamic bonds. In September, Riyadh sold another $12.5 billion in bonds, the largest global debt sale in 2017. It also has burned through over $200 billion in cash reserves since it hit a peak a few years ago.
Saudi Arabia needs $70 oil to break even - Saudi Arabia needs oil prices at $70 per barrel in 2018 in order to breakeven, the International Monetary Fund (IMF) said on Tuesday in its Regional Economic Outlook on the Middle East and Central Asia. The Saudi breakeven oil price to achieve zero deficit in 2017 is $73.10, according to the IMF, compared to $96.60 for 2016. Among the oil exporters in the region, Saudi Arabia has cut its breakeven oil price by the most between 2016 and 2017, but its budget breakeven price of oil is not the lowest in the region. The lowest breakeven price for 2017 is in Kuwait, $46.50, followed closely by Qatar at $46.80, according to IMF estimates. The medium-term oil price assumption, based on the futures market, is that oil prices will remain broadly with current levels of $50-$60, the IMF says. “Spillovers from the low oil price environment continue to weigh on non-oil growth, which is expected to remain below historical averages,” the IMF noted. Budget deficits in the oil exporters soared to a combined 10.6 percent of GDP last year from 1.1 percent of GDP in 2014. Deficits are now expected to halve in 2017, thanks to a modest recovery in the price of oil and the countries’ efforts to cut budget deficits. “But since oil prices are expected to remain in the range of $50-60 a barrel, oil exporters will need to sustain—and in some cases intensify—their budget deficit-reduction efforts,” the IMF said. Estimates for both oil and non-oil growth of the oil exporters in the Middle East, North Africa and Pakistan (MENAP) region are now “slightly weaker” than IMF’s projections from May this year. Not only are low oil prices leading to deficits, but they are also seen as dampening economic growth in the medium term. Non-oil growth in the Gulf Cooperation Council (GCC) members—Bahrain, Kuwait, Oman, Qatar, Saudi Arabia, UAE—is seen at 3.4 percent in 2020, compared to 6.7 percent in the period 2000-2015, the IMF said.
NSA Document Says Saudi Prince Directly Ordered Coordinated Attack By Syrian Rebels On Damascus --A loosely knit collection of Syrian rebel fighters set up positions on March 18, 2013, and fired several barrages of rockets at targets in the heart of Damascus, Bashar al-Assad’s capital. The attack was a brazen show of force by rebels under the banner of the Free Syrian Army, targeting the presidential palace, Damascus International Airport, and a government security compound. It sent a chilling message to the regime about its increasingly shaky hold on the country, two years after an uprising against its rule began.Behind the attacks, the influence of a foreign power loomed. According to a top-secret National Security Agency document provided by whistleblower Edward Snowden, the March 2013 rocket attacks were directly ordered by a member of the Saudi royal family, Prince Salman bin Sultan, to help mark the second anniversary of the Syrian revolution. Salman had provided 120 tons of explosives and other weaponry to opposition forces, giving them instructions to “light up Damascus” and “flatten” the airport, the document, produced by U.S. government surveillance on Syrian opposition factions, shows.The Saudis were long bent on unseating Assad. Salman was one of the key Saudi officials responsible for prosecuting the war in Syria, serving as a high-ranking intelligence official before being promoted to deputy minister of defense later in 2013. The NSA document provides a glimpse into how the war had evolved from its early stages of popular uprisings and repression. By the time of the March 2013 attack, arguably the most salient dynamic in the conflict was the foreign powers on both sides fueling what appeared to be a bloody, entrenched stalemate. The document points to how deeply these foreign powers would become involved in parts of the armed uprising, even choosing specific operations for their local allies to carry out.
All Of Iraq About To Be Liberated As ISIS Enters The Dustbin Of History --Iraqi forces continue to advance on al-Qaem, the last "Islamic State" (ISIS) stronghold in Iraq,which will put the last stone over the terrorist group’s grave and on the so-called “Islamic State Caliphate” that so much occupied the world’s headlines over the last few years and indeed, large parts of Iraqi and Syrian territories.ISIS is aware that al-Qaem will fall very soon - the city won’t be able to hold for very long. Therefore, many of the group's leaders and militants have fled to the numerous refugee camps which have emerged in the last years – according to intelligence reports – in the Iraqi Anbar desert and the Syrian al-Badiya where ISIS can hide along the tens of thousands of kilometers of sprawling Syrian-Iraqi border areas among refugees.ISIS is expected to lick its wounds to try and re-organize its group following the defeat inflicted upon it as indicated by its shrinking territory (which it has occupied since 2014), as well as its shrinking numbers. Many foreign fighters were either killed or mostly left the group, which has remained largely incapable of recruiting new forces. Moreover, ISIS resources have dried up: no more oil and gas fields under its control, no more taxes to be imposed, no more arts and crafts to steal and sell, and no more “donations” from the Arab world. Furthermore, the terror group has lost its very powerful, efficient, and unique propaganda tools and machine as after the liberation of Mosul and most of Iraq, the liberation of Palmyra, Raqqah, Deir-ezzour, most of al-Badiya, the Syrian Army liberated the city of al-Mayadeen, where ISIS kept its media base. Forces in al-Mayadeen seized a huge stock of ISIS propaganda tools and apparatus, reducing the group’s capability to produce online and offline propaganda. Nevertheless, it must be borne in mind that terrorism can never be totally defeated and it is obvious that cells remain active and will always find societies to host it or cover its back. Therefore, ISIS terrorist attacks in Mesopotamia, the Levant, West Africa, Asia and other parts of the world are expected to take place from time to time. This certainly doesn’t mean ISIS is returning or will become strong again, but on the contrary, it will be the group’s way of saying: “You think I am dead, but can still cause harm.”
Kurds' aims in Syria far more likely to succeed than in Iraq | Asia Times: As planned, three days before Iraqi Kurds went to the polls in a referendum over their own political future, elections for local Kurdish communes in northern Syria took place on September 22. While the latter vote – in which an overwhelming 92% voted in favor of independence – sent shockwaves throughout the Middle East, the Syrian vote passed very smoothly, and Damascus did nothing of any consequence to prevent or obstruct it.Following elections in their communes, Syrian Kurds plan to vote for representatives to their local councils on November 3. Parliamentary elections for the three Kurdish districts of the Syrian north, which the Kurds are calling the Democratic Federal System of Northern Syria, are due to happen on January 19. These back-to-back developments in Syria and Iraq have undoubtedly raised the ambitions of 30 million Kurds throughout the region, whose unconditional support has flooded in. Meanwhile, authorities in Baghdad are determined to prevent Iraqi Kurdistan – which is already a federal part of the country, with its own flag, government and parliament – from becoming an independent entity. Saad al-Hadithi, an adviser to Premier Haidar al-Abadi, said: “All Iraqis must have a say in defending the future of their homeland. No single party can determine the future of Iraq in isolation from the others.”
As Kurdish President Announces Resignation, Supporters Storm Parliament With Knives And Guns -- Iraqi Kurdish leader Masoud Barzani announced his resignation Sunday after the biggest gamble of his 12 years as president of the Kurdistan Regional Government (KRG) not only failed, but utterly backfired as territorial reversals reduced KRG power to its weakest position in decades. Though his push for an independence referendum had overwhelming support among Iraq's Kurds, and with even the encouragement of some external allies, the decisive military response by the Iraqi national government resulted in rapid forced handover of Kurdish-held oil rich areas and a return to pre-2014 borders, prior to the blitz by ISIS which aided Kurdish political expansion. Barzani will step down effective November 1. And now the future of the KRG is itself under threat as reports of inter-Kurdish fighting emerged Sunday night. Multiple international reports characterized Barzani's speech as "bitter" and it further appears that violence erupted during or after his televised speech before parliament. During the speech Barzani proclaimed that, "three million votes for Kurdistan independence created history and cannot be erased" while alsodenouncing rivals who abandoned the fight for Kirkuk as committing "high treason." His supporters, angry at what is essentially a forced resignation after rival Kurdish factions failed to oppose Iraqi national forces as they advanced in Kirkuk and other areas earlier this month, reportedly stormed parliament brandishing knives sticks, and guns. There are also unverified reports emerging that opposition party members were attacked during the chaos, as well as arson attacks on opposition offices in various parts of Erbil.
US Launches First Airstrike Against ISIS Fighters In Somalia -- The Pentagon’s gradually escalating combat mission in Somalia reached another important milestone Friday - one of many that have occurred since the inauguration of President Donald Trump - when the military revealed that it had carried out the first airstrikes against Islamic State-linked fighters in Somalia.The news comes as ISIS forces in Syria were driven out of their last remaining patch of territory as Syrian Army forces retook the eastern city of Deir Ezzor, inspiring even anti-Assad pundits to marvel at the Army’s advance against seemingly insurmountable odds.A US official told the Associated Press the strikes were carried out in northeastern Somalia, with the first around midnight local time and the second later in the morning. The official was not authorized to discuss the mission publicly so spoke on condition of anonymity. But one Somali security official said at least six missiles struck Buqa, a remote mountainous village roughly 60 kilometers (37 miles) north of Qandala town in Somalia's northern state of Puntland. The official spoke on condition of anonymity because he was not authorized to speak to the media.
Russia to Build an Iran-India Gas Pipeline, Empire Loses Again - For those who follow geopolitics closely you will know something about the IPI pipeline. IPI stands for Iran-Pakistan-India. I could write a book detailing the twists and turns of U.S. and Russian foreign policy on the history of the delays to this pipeline. They stretch back a decade at least. So to see RT today run the story that:Moscow and Tehran are about to sign a memorandum of understanding to back a new gas pipeline project, according to Russian Energy Minister Aleksandr Novak. The countries will build a 1,200-kilometer long pipeline from Iran to India with the Russian energy major Gazprom developing several Iranian deposits along the route of the future pipeline.While details are sketchy, it looks like this will not be the classic IPI pipeline that linked Eastern Iran with northern India via the Pakistani port at Gwadar, traversing Baluchistan.There will, apparently, be an underwater segment that goes through the Persian Gulf. While I hate to keep flogging a dead horse, one of the main obstacles to the IPI pipeline of yore was none other than Hillary Clinton. She was a major shareholder in the company that was promoting the competing (and nowhere near as economically viable) TAPI pipeline — Turkmenistan, Afghanistan, Pakistan, India.The TAPI pipeline was a major U.S. foreign policy objective going back to the Clinton Administration and a priority under Bush the Lesser. Clinton made it a major focus of her term as Secretary of State to get the TAPI pipeline finished. But it never happened. In fact, neither IPI nor TAPI have been built. TAPI is the main reason for our sanctioning Iran in 2012 and cutting it out of the SWIFT system, not its nuclear program. After nearly 20 years of wrangling, including invading Afghanistan, TAPI is finally being built. Turkmenistan started constructing its TAPI section in December 2015 and the construction is expected to take three years. Time frame of the Afghan and Pakistani sections’ construction has not been determined yet. Note that this boondoggle won’t get completed for at least another 7 years, if ever. It was never viable which was why it was so hard to put a deal together. In the same way that Iran built its leg of the IPI pipeline during the time of U.S. sanctions, that Clinton stood to make millions from TAPI and the U.S. devoted the resources of nearly three administrations to its construction. It is one of the main reasons why we cannot leave Afghanistan. The costs of the Afghan War are borne on its shoulders as this excerpt from a Wall St. Journal Op-Ed from 2012 makes so clear: After the U.S. military withdrawal next year, the government of Afghanistan will have few legitimate income streams. TAPI can provide Kabul with hundreds of millions of dollars annually and create an estimated 50,000 jobs for Afghans. It will do so in a way that gives three of the key states in the region—Pakistan, India and Iran—a strategic interest in Afghanistan’s success.
Iran, Russia Should Cooperate to Isolate US, Foster Middle East Stability: Khamenei - Iranian Supreme Leader Ayatollah Ali Khamenei told visiting Russian President Vladimir Putin on Wednesday that Tehran and Moscow must step up cooperation to isolate the US and help stabilise the Middle East, state TV reported. Iran and Russia are the main allies of Syrian President Bashar al-Assad, while the US, Turkey and most Arab states support rebel groups fighting to overthrow him. Putin met Iranian political leaders in an effort to nurture a warming relationship strengthened since US President Donald Trump threatened to abandon the international nuclear deal with Iran reached in 2015. “Our cooperation can isolate America … The failure of US-backed terrorists in Syria cannot be denied but Americans continue their plots,” Khamenei told Putin, according to Iranian state television. Since Russia‘s military intervention in Syria’s war in 2015, and with stepped-up Iranian military assistance, Assad has taken back large amounts of territory from rebels as well as swathes of central and eastern Syria from ISIS militants. Moscow is now trying to build on that success with a new diplomatic initiative, including a congress of Syria’s rival parties it plans in the Black Sea resort of Sochi on November 18, though a major opposition bloc has refused to take part. Pragmatist Iranian President Hassan Rouhani echoed Khamenei, saying Iran and Russia together could tackle “regional terrorism” – an allusion to Sunni Muslim armed groups hostile to Iran, Assad and many other Arab states.
Almost 40% of global liquefied natural gas trade moves through the South China Sea - The South China Sea is a major route for liquefied natural gas (LNG) trade, and in 2016, almost 40% of global LNG trade, or about 4.7 trillion cubic feet (Tcf), passed through the South China Sea. The South China Sea is an important trade route for Malaysia and Qatar. The two LNG exporters collectively accounted for more than 60% of total South China Sea LNG volumes in 2016. Almost half of Qatar’s global LNG shipments traveled through the South China Sea in 2016. All of Malaysia’s LNG exports pass through the South China Sea, as the country’s one LNG export complex lies on the South China Sea coast. Several other LNG exporters also use South China Sea trade routes to reach LNG importers. In 2016, Oman, Brunei, and the United Arab Emirates shipped between 84% and 100% of their total LNG exports through the South China Sea. Other LNG exporters in the region, such as Australia and Indonesia, make more use of other trade routes to reach LNG markets. In 2016, about 23% of total Australian LNG exports and about 29% of Indonesian LNG exports were shipped by way of the South China Sea. Much of the remainder of Australia’s and Indonesia’s LNG exports passed to the east of the Philippines and Taiwan, avoiding the South China Sea on the way to customers in Japan, South Korea, and northern China. The four LNG importers with the largest volumes passing through the South China Sea are Japan, South Korea, China, and Taiwan, collectively accounting for 94% of total LNG volumes going through the South China Sea in 2016. Japan is the world’s largest LNG importer, and slightly more than half of all of Japan’s LNG imports in 2016 were shipped by way of the South China Sea. Similarly, about two-thirds of the LNG imported by South Korea—the world’s second-largest LNG importer—was shipped through the South China Sea that year. More than two-thirds of China’s LNG imports and more than 90% of Taiwan’s LNG imports passed through the South China Sea in 2016. EIA projects that China will surpass South Korea as the world’s second-largest LNG importer by 2018 and nearly match Japan’s level of LNG imports by 2040.