oil prices were heading for a modest drop this week, with both international and US prices still falling on Friday morning, when they inexplicably spiked by more than 2% just before noon, with the US price then ending Friday at $62.34 a barrel, a gain of $1.15 for the day but just 30 cents for week...before that Friday jump, oil prices had been down 68 cents at $61.36 a barrel on Monday, after the EIA's monthly drilling productivity report forecast a 131 barrel per day increase in crude production from the major U.S. shale plays in April, and then down another 65 cents to $60.71 a barrel on Tuesday, as a falling stock market dragged commodity prices lower...oil prices were then modestly higher on both Wednesday and Thursday, as the weekly EIA report showed both rising inventories of crude oil and falling inventories of fuel...
meanwhile, natural gas prices first moved higher on Monday on continued forecasts of late-season cold weather throughout much of the country, but then fell later in the week as reports of higher gas production and signs of winter weather fading weighed on prices...the weekly storage report also indicated a smaller than expected withdrawal of natural gas supplies from storage, which precipitated a 5 cent drop in prices on Thursday, as April natural gas went on to end the week at $2.688 per mmBTU, 4.4 cents below last week's close...the week's natural gas storage report indicated that our natural gas in storage fell by 93 billion cubic feet to 1,625 billion cubic feet over the week ending Friday, March 9th, which left our gas supplies 718 billion cubic feet, or 31.9% lower than the 2,250 billion cubic feet that were in storage on March 10th of last year, and 296 billion cubic feet, or 16.1% below the five-year average of 1828 billion cubic feet typically in storage at the end of the tenth week of the year....the average withdrawal of natural gas during the tenth week of the year over the past 5 years has been 97 billion cubic feet, so even though this was the fourth week in a row where our natural gas withdrawals have been below normal, we haven't been gaining much against the long term averages...
The Latest US Oil Data from the EIA
this week's US oil data from the US Energy Information Administration, covering the week ending March 9th, indicated that despite a big decrease in our oil imports and a big increase in refining, we apparently still had oil left over to add to storage for the sixth time in seven weeks...our imports of crude oil fell by an average of 418,000 barrels per day to an average of 7,585,000 barrels per day during the week, while our exports of crude oil fell by an average of 11,000 barrels per day to an average of 1,478,000 barrels per day, which meant that our effective trade in oil over the week worked out to a net import average of 6,098,000 barrels of per day during the week, 407,000 barrels per day less than out net imports during the prior week...at the same time, field production of crude oil from US wells rose by 12,000 barrels per day to a record high of 10,381,000 barrels per day, which means that our daily supply of oil from our net imports and from wells totaled an average of 16,479,000 barrels per day during the reporting week..
during the same week, US oil refineries were using 16,367,000 barrels of crude per day, 432,000 barrels per day more than they used during the prior week, while at the same time 717,000 barrels of oil per day were being added to oil storage facilities in the US....hence, this week's crude oil figures from the EIA seem to indicate that our total supply of oil from net imports and from oilfield production was 605,000 barrels per day less than what refineries reported they used plus what was added to storage during the week...to account for that disparity, the EIA needed to insert a (+605,000) 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, essentially a fudge factor that is labeled in their footnotes as "unaccounted for crude oil"... (how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, is explained here)...this was only the second time in 10 years that the adjustment factor was positive by more than 600,000 barrels per day...since that meant there was a record 1,175,000 barrel per day change in that 'unaccounted for oil' figure, from -570,000 barrels per day last week to +605,000 barrels per day this week, the week over week changes reported here are correspondingly unreliable...even so, the data as it's presented here will often drive the price of oil..
further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports fell to an average of 7,473,000 barrels per day, which was 1.8% less than the 7,608,000 barrel per day average we imported over the same four-week period last year....the 717,000 barrel per day increase in our total crude inventories was all added to our commercial stocks of crude oil, as stocks in our Strategic Petroleum Reserve were unchanged...this week's 12,000 barrel per day increase in our crude oil production included a 20,000 barrel per day increase in output from wells in the lower 48 states, which was partially offset by an 8,000 barrel per day decrease in output from Alaska...the 10,381,000 barrels of crude per day that were produced by US wells during the week ending March 9th was the highest on record, 14.0% more than the 9,109,000 barrels per day that US wells were producing during the week ending March 10th of last year, and 23.2% above the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June, 2016...
US oil refineries were operating at 90.0% of their capacity in using those 16,367,000 barrels of crude per day, up from 88.0% of capacity the prior week, but still down from the wintertime record 96.7% of capacity set ten weeks earlier, as some US refineries are still down due to pre-spring blend changeover and scheduled maintenance...nonetheless, the 16,367,000 barrels of oil that were refined this week was a seasonal record, the first time refineries processed more than 16 million barrels during the usual refinery maintenance season through February and the first three weeks of March...while that high was 7.4% less than the off-season record 17,608,000 barrels per day that were being refined during the last week of December 2017, it was 5.8% more than the 15,472,000 barrels of crude per day that were being processed during the week ending March 10th, 2017, when refineries, still undergoing seasonal maintenance at that time, were operating at 85.1% of capacity....
with the increase in the amount of oil being refined, gasoline output from our refineries also rose, increasing by 357,000 barrels per day to 10,280,000 barrels per day during the week ending March 9th, after our gasoline output had increased by 532,000 barrels per day the prior week....that increase meant our gasoline production was 7.8% greater during the week than the 9,540,000 barrels of gasoline that were being produced daily during the week ending March 10th of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) fell by 118,000 barrels per day to 4,478,000 barrels per day, after falling by 553,000 barrels per day over the prior 4 weeks...that left the week's distillates production 4.5% lower than the 4,690,000 barrels of distillates per day than were being produced during the equivalent week of 2017....
the big increase in our gasoline production notwithstanding, our supply of gasoline in storage at the end of the week still fell by 6,271,000 barrels to 244,758,000 barrels by March 9th, the largest decrease since September, but just the third draw from stocks in 18 weeks....our supplies were down for a second week because our domestic consumption of gasoline rose by 366,000 barrels per day to 9,642,000 barrels per day, after rising by 416,000 barrels per day the prior week....at the same time, our exports of gasoline rose by 25,000 barrels per day to 785,000 barrels per day, while our imports of gasoline fell by 4,000 barrels per day to 604,000 barrels per day...so even after our gasoline supplies have increased 15 of the last eighteen weeks, our gasoline inventories are now fractionally lower than last March 10th's level of 246,279,000 barrels, even as they are roughly 7.5% above the 10 year average of gasoline supplies for this time of the year...
meanwhile, our supplies of distillate fuels fell by 4,360,000 barrels to 133,066,000 barrels over the week ending March 9th, the largest draw since October despite the cold spells in January...in addition to the drop in production, that drop in supplies was because our exports of distillates rose by 477,000 barrels per day to 1,492,000 barrels per day while our imports of distillates fell by 44,000 barrels per day to 223,000 barrels per day, and while the amount of distillates supplied to US markets, a proxy for our domestic consumption, fell by 94,000 barrels per day to 3,832,000 barrels per day...after this week’s inventory decrease, our distillate supplies ended the week 15.4% lower than the 157,303,000 barrels that we had stored on March 10th, 2017, and 5.0% lower than the 10 year average of distillates stocks at this time of the year…
finally, despite the drop in our oil imports up and the increase in refining, we were still able to add to our commercial supplies of crude oil for the 7th time in 17 weeks and for the 16th time in the past year, as our commercial crude supplies increased by 5,022,000 barrels, from 425,906,000 barrels on March 2nd to 430,928,000 barrels on March 9th....but even with increases in six out of the last seven weeks, our oil inventories as of that date were 18.4% below the 528,156,000 barrels of oil we had stored on March 10th of 2017, and 12.4% lower than the 492,160,000 barrels of oil that we had in storage on March 12th of 2016, even as they were still 1.4% greater than the 425,047,000 barrels of oil we had in storage on March 13th of 2015, at a time when the US glut of oil was just beginning to build...
This Week's Rig Count
US drilling activity increased for the 4th week in a row and for the 13th time in the past 19 weeks during the week ending March 16th, a period which has seen the rig increases far exceed the few decreases...Baker Hughes reported that the total count of active rotary rigs running in the US rose by 6 rigs to 990 rigs in the week ending on Friday, which was also 201 more rigs than the 789 rigs that were in use as of the March 17th report of 2017, while it was still down from the recent high of 1929 drilling rigs that were deployed on November 21st of 2014...
the number of rigs drilling for oil rose by 4 rigs to 800 rigs this week, which was 169 more oil rigs than were running a year ago, even while the week's oil rig count still remained well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the number of drilling rigs targeting natural gas formations increased by 1 rig to 189 rigs this week, which was also 32 more gas rigs than the 157 natural gas rigs that were drilling a year ago, but way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...in addition, a rig that was considered "miscellaneous" also began drilling this week, in the first such "miscellaneous" rig operating since October 6th, 2017..
drilling in the Gulf of Mexico was unchanged at 13 rigs, the least rigs working in the Gulf this century, & down by 6 rigs from the 19 rigs that were deployed in the Gulf of Mexico a year ago....meanwhile, the week's count of active horizontal drilling rigs jumped by 17 rigs to 865 horizontal rigs this week, which was also up by 207 rigs from the 658 horizontal rigs that were in use in the US on March 17th of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the vertical rig count was down by 4 rigs to 57 vertical rigs this week, which was also down from the 70 vertical rigs that were in use during the same week of last year...at the same time, the directional rig count was down by 7 rigs to 68 directional rigs this week, which was still up from the 61 directional rigs that were deployed on March 17th of 2017...
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 the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of March 16th, the second column shows the change in the number of working rigs between last week's count (March 9th) and this week's (March 16th) count, the third column shows last week's March 9th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday of 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 17th of March, 2017...
while most of the changes above refer to oil rigs, deployment of natural gas rigs increased by one each in the Haynesville of Louisiana and the Fayetteville of Arkansas, and decreased by one in the Marcellus, with the shutdown of 2 rigs in Pennsylvania, while one was added in West Virginia...meanwhile, the rig that was added in the Utica was an oil rig; hence, of the 24 rigs now working the Utica, 8 are drilling into oil-bearing shale and 16 are targeting wet gas formations...in addition to the major producing states shown above, a rig also began drilling for oil in Nevada this week in the first drilling the state has seen in over a year...
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New West Virginia law seen to help operators boost production - Natural gas producers in West Virginia hope that a new law passed by the state Legislature and signed by the governor will help spur production in the state, which in recent years has seen a dramatic ramp-up in gas output from the Marcellus Shale play. Governor Jim Justice signed Friday the co-tenancy bill, which would allow drilling to take place on a tract of land if 75% of royalty owners agreed. The legislation amends current state law, which had allowed owners of a small minority stake in a given tract block development of that land. The legislation gathered the support of producer groups in West Virginia. Charlie Burd, executive director of the Independent Oil and Gas Association of West Virginia, said the bill would make it easier for operators to acquire more individual tracts of land and to be able to accumulate those contiguous tracts in a way that would allow them to drill longer laterals, which are rapidly becoming the industry norm in the Appalachian Basin. "IOGA West Virginia is very excited to see that bill finally pass," Burd said in an interview. Burd said the legislature forged a compromise bill that would protect the rights of operators and the majority of royalty owners on a given tract of land, while protecting the rights of minority royalty owners and other stakeholders. "There was a lot of confusion in the past about what this bill would do. Those who oppose it still wanted to cause confusion up to the end, but it's a very simple bill," he said. Gas production in West Virginia has grown quickly in recent years as producer-backed pipeline capacity expansions and a buildout in gas processing infrastructure have enabled large Appalachian drillers such as EQT Energy and Antero Resources to bolster their output. A concentration of acreage among the state's top producers has also led to a trend of longer well laterals, driving efficiency gains and boosting initial production rates and ultimately recovered volumes from wells drilled, Platts Analytics has found.
WV DEP orders Rover Pipeline to stop construction, citing multiple violations - State regulators have slapped a cease-and-desist order on a natural gas pipeline, citing multiple water pollution violations, according to a letter made public by the West Virginia Department of Environmental Protection. The 713-mile-long Rover Pipeline, which would transport 3.25 billion cubic feet of natural gas per day from processing plants in West Virginia, Ohio and Pennsylvania, received the order on March 5 from Scott Mandirola, director of the Division of Water and Waste Management, documents show. According to the order, DEP officials conducted inspections on four days in February, during which they said they found 14 violations in Doddridge, Tyler and Wetzel counties. The alleged offenses include leaving trash and construction debris partially buried on site, improperly installing perimeter control and failing to inspect or clean public and private roads around the construction site. The pipeline, owned by Energy Transfer Partners, has been ordered to halt construction until state regulators inspect the site and determine that Rover Pipeline LLC is complying with the Water Pollution Control Permit issued Dec. 15, 2016. Rover also is tasked with submitting a plan of “corrective action,” due March 25, and installing devices to control erosion and sediment-water release. Energy Transfer Partners also owns the Dakota Access Pipeline — the subject of protests in North Dakota last year. The cease-and-desist order is the second the DEP has issued to the Rover Pipeline in the past year; state regulators cited the pipeline builders for similar violations in July 2017. Earlier that year, in April, the pipeline spilled more than 2 million gallons of drilling fluid in Ohio, eliciting scrutiny from regulators there. That’s a red flag, said Angie Rosser, executive director of the West Virginia Rivers Coalition. “When I see repeated violations, I say it’s time for this company to stop doing business in this state if they can’t do it responsibly,” she said.
'The Harms of Fracking': New Report Details Increased Risks of Asthma, Birth Defects and Cancer - The most authoritative study of its kind reveals how fracking is contaminating the air and water – and imperiling the health of millions of Americans "Our examination…uncovered no evidence that fracking can be practiced in a manner that does not threaten human health," states a blistering 266-page report released today by Concerned Health Professionals of New York and the Nobel Peace Prize-winning group, Physicians for Social Responsibility. Drawing on news investigations, government assessments and more than 1,200 peer-reviewed research articles, the study finds that fracking – shooting chemical-laden fluid into deep rock layers to release oil and gas – is poisoning the air, contaminating the water and imperiling the health of Americans across the country. "Fracking is the worst thing I've ever seen," says Dr. Sandra Steingraber, one of the report's eight co-authors, a biologist who has worked as a public health advocate on issues like breast cancer and toxic incinerators. "Those of us in the public health sector started to realize years ago that there were potential risks, then the industry rolled out faster than we could do our science." In recent years, the practice has expanded from rural lands to backyards, farms, and within sight of schools and sources of drinking water. "Now we see those risks have turned into human harms and people are getting sick," says Steingraber. "And we in this field have a moral imperative to raise the alarm."
From Asthma to Cancer, 'Blistering' New Report Details Human Cost of Fracking - A team of researchers on Tuesday released a " blistering " report on the serious public health threats—from headaches to asthma to cancer—posed by hydraulic fracturing, or fracking , a process of injecting a mix of water and chemicals into rocks to release oil and natural gas. The study — described as "the most authoritative" of its kind—was published by Concerned Health Professionals of New York and Physicians for Social Responsibility. Researchers found that "by several measures, evidence for fracking-related health problems is emerging across the United States and Canada." Looking to Pennsylvania—a hotbed for fracking—as an example, the report says that "as the number of gas wells increase in a community, so do rates of hospitalization, and community members experience sleep disturbance, headache, throat irritation, stress/anxiety, cough, shortness of breath, sinus, fatigue, wheezing and nausea.""Drilling and fracking operations are also correlated with increased rates of asthma, elevated motor vehicle fatalities, ambulance runs and emergency room visits and gonorrhea incidence," according to the report, for which researchers analyzed thousands of journalistic investigations, government research and peer-reviewed scientific articles. The report also notes that levels of benzene "in ambient air surrounding drilling and fracking operations are sufficient to elevate risks for future cancers in both workers and nearby residents," and "animal studies show numerous threats to fertility and reproductive success from exposure to various concentrations of oil and gas chemicals, including at levels representative of those found in drinking water ."
'Almanac' Compiles Health Risks From the Drilling Practice. — Health professionals have released their fifth compilation of data and reports showing the risks of fracking. Over the past five editions, scientific and medical findings in the compendium have grown, adding weight to the argument that oil and gas drilling are harmful to communities. One of the authors of the report, Sandra Steingraber, is a biologist and co-founder of Concerned Health Professionals of New York. She said people near fracking sites face the same kind of health risks, whether they're in Texas, Pennsylvania or North Dakota."We see signs of respiratory distress among people living close to drilling and fracking sites,” Steingraber said. “Most alarming to us, we see signs of impaired development among newborns born to pregnant women whose residences are close to drilling and fracking sites during their pregnancies." Steingraber said there are increased rates of illness and cancer near fracking sites, and there are greater risks in the air and water. Radioactive waste also is a concern. She said there are more than 1,000 studies on fracking and 85 percent show the practice is harmful. The American Petroleum Institute disputes these reports, saying fracking is safe and also provides economic benefits to communities. But the compendium found that work in this sector is dangerous, with four to seven times the number of on-the-job fatalities compared with the national average. It's even more dangerous in North Dakota, where fatality rates are seven times the average for the rest of the industry. Steingraber said economic gains for towns and cities usually are temporary because fracking wells don't have long lifespans. She added that the man camps set up for operations fracture family structures and also harm nearby communities. "We see signs of increased sex trafficking, increased drugs, violent victimization, traffic fatalities go up, and so on,” she said. “And so, particularly for women's health and safety, it really takes a hit when fracking companies come into town."
Schwarzenegger planning to sue oil companies for 'knowingly killing people all over the world’ | TheHill - Former California Gov. Arnold Schwarzenegger (R) is planning to sue oil companies, alleging they are "knowingly killing people all over the world." Schwarzenegger said during an interview with Politico's "Off Message" podcast that he is still working on the timing for his push, but he is now speaking with private law firms. "This is no different from the smoking issue. The tobacco industry knew for years and years and years and decades that smoking would kill people, would harm people and create cancer, and were hiding that fact from the people and denied it. Then eventually they were taken to court and had to pay hundreds of millions of dollars because of that,” Schwarzenegger, a global environmental activist, said.“The oil companies knew from 1959 on, they did their own study that there would be global warming happening because of fossil fuels, and on top of it that it would be risky for people’s lives, that it would kill.” Schwarzenegger accused oil companies of being irresponsible and vowed to go after them. "It’s absolutely irresponsible to know that your product is killing people and not have a warning label on it, like tobacco,” he said. “Every gas station on it, every car should have a warning label on it, every product that has fossil fuels should have a warning label on it.” He said he hopes to spread awareness about the harmful effects of fossil fuels. “I don’t think there’s any difference: If you walk into a room and you know you’re going to kill someone, it’s first-degree murder," he said during the interview. "I think it’s the same thing with the oil companies.”
Bottled Water, Brought to You by Fracking? -- The new Food & Water Watch report Take Back the Tap: The Big Business Hustle of Bottled Water details the deceit and trickery of the bottled water industry. Here's one more angle to consider: The bottled water business is closely tied to fracking . The report reveals that the majority of bottled water is municipal tap water, a common resource captured inplastic bottles and re-sold at an astonishing markup—as much as 2,000 times the price of tap, and even four times the price of gasoline. Besides being a rip-off, there is plenty more to loathe about the corporate water scam: The environmental impacts from pumping groundwater (especially in drought-prone areas), the plastic junk fouling up our waterways and oceans, and the air pollution created as petrochemical plants manufacture the materials necessary for making those plastic bottles filled with overpriced tap water. There is a growing international awareness that plastic is a serious problem. In 2016, about 4 billion pounds of plastic were used in the bottled water business, and most of those bottles are not recycled—meaning they often end up in landfills or as litter. There's also the matter of whether we should be putting our drinking water in those bottles in the first place: The most common packaging (polyethylene terephthalate, or PET) includes compounds like benzene, and the bottles can leach toxins like formaldehyde and acetaldehyde. But perhaps the biggest problem is where we get all this plastic in the first place. Many of the raw materials used to create those plastic bottles come from fracking. In addition to air and water pollution, the fracking boom has delivered an abundant supply of the hydrocarbon ethane, which is used in petrochemical manufacturing to create ethylene, which is turned into plastic.
On pipeline route, some well owners ok with Sunoco’s water; others are wary - A field outside Bob and Deborah Hoffman’s Delaware County home is filled with orange construction fencing, a 20-foot industrial curtain blocking their view of some surrounding houses, and hundreds of yards of steel pipeline waiting to be laid as part of the controversial Mariner East project. On the lawn about 50 yards from their front door is a squat black tub known as a water buffalo, from which the Hoffmans get their water while the pipeline company, Sunoco, prepares to drill an underground bore where the pipe will be installed. The temporary water supply is being provided to the Hoffmans and other owners of private water wells along the pipeline route because of concerns that their water could turn cloudy or become contaminated as the company drills a path through the local aquifer. That happened last summer in Chester County’s West Whiteland Township, where some private water supplies turned cloudy after Sunoco punctured an aquifer during horizontal directional drilling for the pipeline. That incident, and others like it along the cross-state pipeline route, led to a court agreement last summer requiring Sunoco to offer temporary water supplies to owners of private wells within 450 feet of a planned drilling operation. Many affected homeowners in West Whiteland were connected to public water instead, at Sunoco’s expense. In Delaware County, the Hoffmans aren’t thrilled by having the black plastic tank on their lawn, but they have no complaints about the quality of the water, which they use for drinking, cooking, bathing and laundry. The couple agreed to compensation from Sunoco, which took about a quarter-acre of their land for construction. “When they started the horizontal drilling process, they gave you the option of whether you wanted to use potable water since they would be coming within 100 feet of the well, and I thought: ‘Sure, why not?’”
Bankrupt Philadelphia refiner settles biofuel obligation with EPA: court filing (Reuters) - The U.S. Environmental Protection Agency granted a bankrupt Philadelphia oil refining company a reprieve from complying with the nation’s renewable fuel laws, according to a settlement agreement filed on Monday. The refiner, Carlyle Group-backed Philadelphia Energy Solutions (PES), filed for bankruptcy protection in January and asked a judge to waive some $350 million in compliance costs under the U.S. Renewable Fuel Standard, or RFS. The EPA and PES agreed on Monday that the refiner would only have to satisfy about half those costs, but would face more scrutiny moving forward, court documents showed. The settlement is facing early opposition from ethanol groups. The settlement comes amid a fight between powerful corn and oil interests in Washington over the future of the RFS program. President Donald Trump has sought to bring the two sides together in recent weeks to come up with reforms that can lower the cost for refiners without hurting demand for biofuels, wading into an issue that divides two important constituencies. The PES bankruptcy - and the potential loss of 1,100 jobs in a key electoral state - had fueled calls for change. The RFS requires refiners to blend biofuels like ethanol into their fuel or buy credits from those who do. PES, which lacks blending facilities, entered into bankruptcy owing 467 million credits from 2016 and 2017, with only 210 million credits in hand, the filing showed. The EPA said PES could comply with the program by turning over its available credits and would be excused from any shortfall, a huge win for the refiner. It said the deal would cover the company up until the point it exits bankruptcy. After exiting bankruptcy, PES would have to comply with the law on a semi-annual basis as opposed to annually and submit itself to more EPA scrutiny. It would face penalties for non-compliance with the agreement.
Murphy Administration Settles MTBE Pollution Cases for $200 Million -The Murphy administration yesterday said it has settled cases with three oil companies who have agreed to pay nearly $200 million for polluting water with a potential human carcinogen. Attorney General Gurbir S. Grewal announced approval of draft settlements reached by the Christie administration to resolve natural-resources damage lawsuits against the three defendants involving contamination of groundwater with an additive to gasoline. The cases involve a decade-old lawsuit filed against nearly 50 companies alleging they were responsible for polluting state waters with the gasoline additive, methyl tertiary butyl ether (MTBE). The state Department of Environmental Protection has found the potential human carcinogen at over 6,000 sites. MTBE was an additive to gasoline approved by the federal Environmental Protection Agency in 1979 to help make the fuel burn cleaner and lower carbon monoxide pollution from vehicles. At the time, the state was not in compliance with federal health-quality standards for the pollutant. "These are important legal settlements on behalf of New Jersey citizens — not only in terms of dollars, but in terms of sending a message that we are committed to working with the DEP to protect our state's natural resources and hold accountable companies that pollute,'' Grewal said in a statement from his press office. The initial lawsuit was brought by the Corzine administration in 2007 under a natural-resources damage case, which allows the state to recover the costs for the spills and to restore the natural resources damaged by the pollution.
The power generation drivers of East Coast gas demand growth - The worst of this winter’s cold has passed, but the impact of structural changes in U.S. power generation will be felt in natural gas markets for years to come. The generation mix has been changing rapidly in recent years, and the switch from coal to gas is happening at an even faster pace on the East Coast than in the country overall. This switch reflects both coal-plant retirements and ongoing competition between remaining coal plants and gas plants. But low-cost gas supplies in the Marcellus and Utica plays don’t always have ready access to the biggest consuming markets, and this winter, we saw how the increasing call on gas for Eastern power generation can stress the gas pipeline grid and cause price blowouts. Today, we continue a series on Eastern power generation and prices by untangling the sources and drivers of gas-fired generation growth in the region. In Part 1 of this series, we looked at the contagion in high East Coast gas prices this winter. We found that U.S. gas demand for power generation is increasing structurally, though volatile weather and gas prices can sometimes obscure this trend. Also, we noted that on the coldest days a high percentage of the gas flowing to areas with limited pipeline capacity is committed to serving residential and commercial heating customers. During these frigid periods, the power sector is sometimes forced to turn to more expensive alternative fuels such as imported liquefied natural gas (LNG) or fuel oil for power generation as far south as the Carolinas. Today, we’ll address the where and why of power demand growth for gas to date along with the prospects for continued growth.
LNG tanker Patris scheduled to arrive at US Cove Point terminal in April: Platts cFlow - As Dominion Energy prepares for commercial service to start at its Cove Point LNG export terminal, a new tanker was listed Monday as headed to the Maryland facility, after a previous one changed its destination, data compiled by S&P Global Platts vessel tracking software cFlow shows.The BP chartered Patris, which entered service in February and was ordered by a partnership between K Line Shipping and Greek vessel owner Chandris, is currently in the Arabian Sea and scheduled to arrive at Cove Point on April 9, the data shows. It has a draught history that indicates the tanker is partly laden, which means it would be in a position to pickup LNG.Cove Point has both import and export capabilities. A Dominion spokesman did not respond to a request for comment, and previously the company has refused to provide any updates to the timing of commercial service. BP officials did not immediately respond to a request for comment on the Patris' plans. The company had previously said that commercial service at Cove Point, under contracts with Gail India and a joint venture involving Japan 's Sumitomo and Tokyo Gas, would begin in early March. There has been reduced feedgas activity at the facility since March 2 when Dominion shipped its first commissioning cargo, joining Cheniere Energy as the only US exporters of LNG produced from shale gas. Cove Point has not reported any feedgas volumes delivered to the plant since Dominion received regulatory approval on March 5 to begin commercial service for exports, data from S&P Global Platts Analytics shows.
New York governor requests to exclude state from offshore drilling program (Reuters) - New York Governor Andrew Cuomo on Friday said he had formally asked for the state to be excluded from a federal offshore drilling program that he said would threaten its ocean resources and endanger efforts toward a cleaner energy economy. “New York State strongly opposes the Department of the Interior’s National Outer Continental Shelf Oil and Gas Leasing Program as it poses an unacceptable threat to New York’s ocean resources, to our economy and to the future of our children,” Cuomo said in announcing the exclusion request. The five-year program, launched by the federal government in early January, proposes to make over 90 percent of the total U.S. offshore acreage available to oil and gas drilling. The plan would open two areas of the North Atlantic coast adjacent to New York State for fossil fuel exploration, according to a statement from Cuomo’s office. “As the number three ocean economy in the nation, New York stands to lose nearly 320,000 jobs and billions of dollars generated through tourism and fishing industries should the exclusion not be granted,” Cuomo said. “Instead of protecting our waters from another oil spill, like the one that devastated the Gulf, this new federal plan only increases the chances of another disaster taking place,” he said. Florida was granted exemption from the program on the grounds that the state relies heavily on tourism. New York is one of several states that has asked to be exempted from the drilling plan, and Interior has said it is considering the requests and holding discussions with states as it finalizes the proposal over the coming months.
U.S. states slow Trump offshore oil drilling expansion plan (Reuters) - The Trump administration’s plan to broadly expand drilling in U.S. offshore waters is moving slowly due to opposition from coastal states and indifference from oil companies that have turned their focus to other opportunities. The administration hopes encouraging U.S. energy development outside of shale oilfields will further its goal of“energy dominance.” But existing Obama administration lease rules remain in place through 2022 unless the new rules gain approval. The Department of the Interior this year proposed opening vast new acreage in the U.S. outer continental shelf to drilling. The comment period wrapped up March 9. Still, Secretary Ryan Zinke said last week he remained deep in discussions with state governors, some of whom have thrown up roadblocks that would impede or bar drilling off their coasts. A new outer continental shelf lease program proposes 47 lease sales, including areas that had not been offered since 1983. At least 12 states have sought exemptions, and Zinke has agreed to exclude areas off Florida. “On the five-year plan we made everything available to look at,” Zinke told Reuters at the CERAWeek energy conference in Houston. Governors from across the West Coast and much of the East Coast are meeting with the Interior and objecting to areas off their states for drilling. State discussions could last through year end. So far, officials in Alaska, Maine, Georgia and U.S Gulf Coast states other than Florida have said they were open to expanding drilling. California and other states have said they would deny needed permits for onshore services or transport. “You can’t bring energy ashore unless you have access to state waters,” Zinke said.
Trump Rollbacks Target Offshore Rules ‘Written With Human Blood’ - While attention has been focused on President Trump’s disputed decision in January to reverse drilling restrictions in nearly all United States coastal waters, the administration has also pursued a rollback of Obama-era regulations in the Gulf. Those rules include safety measures put in place after the explosion and sinking of the Deepwater Horizon rig in 2010, a disaster that killed 11 people and resulted in the largest marine oil spill in drilling history. Smaller oil and gas companies, many backed by Wall Street and private equity firms, say they need the relief to survive financially, and the top safety official at the Interior Department appointed by Mr. Trump has appeared an enthusiastic ally. “Help is on the way, help is on the way,” the official, Scott Angelle, said in September at a gathering in Lafayette, La., of oil and gas executives from so-called independent companies, which focus on drilling alone rather than the extended drilling-to-gas-station operations of bigger competitors. But an analysis of federal inspection data by The New York Times found that several of the independent companies seeking the rollback, including Energy XXI, had been cited for workplace safety violations in recent years at a rate much higher than the industry average. Their offshore platforms suffer in some cases from years of poor maintenance, as well as equipment failures or metal fatigue on aging devices, records show.
Norfolk approves gas pipeline construction beneath drinking water reservoirs -The City Council approved an easement Tuesday night that will allow Dominion Energy and its partners to build a natural gas pipeline underneath two of Norfolk’s drinking water reservoirs in Suffolk. The 600-mile Atlantic Coast Pipeline, which is expected to run between West Virginia and North Carolina, would include a spur through Hampton Roads to a terminal in Chesapeake.To get there, the pipeline would run beneath the Lake Prince and Western Branch reservoirs in Suffolk, which are on property owned by Norfolk and supply much of the city’s drinking water.The council had delayedthe vote twice as Norfolk waited for approvals from the Virginia Department of Environmental Quality, which had been pending for months.The project recently cleared several regulatory hurdles, including with the state agency.The pipeline is being built by Dominion Energy and other companies through a firm called Atlantic Coast Pipeline LLC. On Tuesday, the council voted 5-2, with one abstention, to grant the company easements to build the pipeline beneath the reservoirs. In exchange, the company will pay the city $500,000, up from an initial offer of $150,000.
Dominion fails in attempt to bar testimony on pipeline's potential $2.3 billion hit for ratepayers - Utility regulators at the State Corporation Commission have refused Dominion Energy’s request to strike expert testimony that claims its contentious Atlantic Coast Pipeline will cost its Virginia ratepayers as much as $2.3 billion extra on their bills. In an order released Monday on Dominion’s integrated resource plan, the long-range forecast on how the company will meet customer needs between 2018 and 2032, the commission allowed testimony by natural gas industry analyst Gregory Lander to remain part of the record. Lander, retained by environmental groups opposed to the 600-mile project, which Dominion has said will cut utility bills and boost employment, used the company’s own data to predict the pipeline will increase bills for Dominion’s nearly 2.5 million ratepayers between $1.6 billion and $2.3 billion. Environmental groups, including the Natural Resources Defense Council in Washington and the Southern Environmental Law Center in Charlottesville, took it as vindication of claims that the pipeline is a bad deal for Virginia. Dominion has argued the pipeline, which originated in a 2014 request for proposals issued by Duke Energy and Piedmont Natural Gas, is necessary to provide supply diversity for power plants in Virginia and North Carolina, avoid service shutoffs when demand spikes during cold weather, and aid economic development. Opponents contend that the project — which has swollen from an estimated price tag of $5.5 billion to as much as $6.5 billion and comes with a 14 percent rate of return guaranteed for the developers by the Federal Energy Regulatory Commission — isn’t needed, particularly in Virginia. Potential expansion of the project to South Carolina has driven that argument. “This is a speculative pipeline in search of a market and that market is not Virginia,” said Walton Shepherd, a Natural Resources Defense Council lawyer. “Not only is the proposed pipeline unneeded, it would burden Virginia ratepayers and therefore the Virginia economy.”
GOP now wants federal prosecutors to probe pipeline deal (AP) — North Carolina Republicans continue to attack Democratic Gov. Roy Cooper over a $57.8 million agreement his office reached with utilities poised to build the Atlantic Coast Pipeline. Now, the GOP hopes that criticism will garner the attention of federal prosecutors. State Republican Party leaders asked Tuesday for a federal investigation of whether Cooper broke the law with the memorandum of understanding, calling it possible extortion by the governor for his personal or political benefit. GOP lawmakers and their allies have been persistent in going after Cooper over the agreement, saying it put the governor in control of funds that should be expended by the General Assembly. The legislature passed a law last month taking effect later this week that would intercept money coming from the agreement and earmark it for school districts along the route of the natural gas pipeline.Cooper and his office have defended the agreement and said that nothing unlawful was done. He and other Democrats have dismissed the new law redirecting the funds as a partisan power grab by Republicans.The money in the memo would have gone to environmental mitigation, economic development and renewable energy, but it lacked many details on how the funds would be distributed. Cooper's office announced the agreement the same day as state regulators approved a key permit, leading critics to suggest the permit was conditional upon the agreement."It's an obvious to pay-to-play situation," state Republican Party Chairman Robin Hayes said during a news conference outside a Raleigh federal building before giving a written request for an investigation to the U.S. Attorney's Office. "This is not a message that builds confidence in our citizens and it definitely sends a negative note and message to potential businesses looking at North Carolina."
The North Carolina fracking boom that didn't happen - Once expected to join to join the fracking boom, North Carolina is now farther away from taking the plunge and is now more remarkable for its growth in alternatives like solar and wind.The Oil and Gas Commission, created by the legislature in 2014 during a headlong rush to open up the state to oil and gas exploration, was effectively shut down in 2016 as one of three commissions ruled unconstitutional in the landmark case McCrory v. Berger.The case, filed by then-Gov. Pat McCrory against the legislature, hinged on whether the legislature could make the majority of appointments to a body carrying out executive-branch functions. The outcome of the case, eventually decided by the state Supreme Court, effectively ended the work of the three commissions.In the case of the Oil and Gas Commission, the successor to the state’s Mining and Energy Commission, the main executive-branch function was overseeing inland oil and gas exploration through hydraulic fracturing, or fracking. This form of exploration involves horizontal drilling, a practice that was previously banned in the state under a 1945 law. When the legislature lifted the ban in 2014, the change was heralded as transformational to the state’s economy.McCrory and other supporters of both offshore and onshore oil and gas development said the state would soon be among the top energy producing states.When new rules were announced in 2015, following a public comment period that took in tens of thousands of comments and included four public hearings around the state, North Carolina Petroleum Council (NCPC) Executive Director David McGowan said the shale energy industry would lead to job creation and additional state revenues.“Energy is essential for economic growth and job creation,” said McGowan said in a statement. “Today’s announcement is a win for the people of North Carolina, putting the state on the cutting edge of energy production in America.”Now, just shy of three years later, a court ruling continues to block the state from issuing any drilling permits or receiving applications. The running count for both items remains at zero. Although not specifically addressed by the court, the fracking rules themselves are also on hold and would require further legal action by the state to take effect.
Colonial Pipeline to pay Alabama $3.3 million for 2016 spills: state official (Reuters) - Colonial Pipeline Co will pay $3.3 million to the state of Alabama to cover damages and penalties from an explosion and a spill on its gasoline line in 2016, the state’s attorney general said on Thursday. A combined 11,800 barrels of gasoline were spilled in rural Shelby County, causing pump prices to soar in much of the southeastern United States, which depends heavily for supplies on the Colonial pipeline system, the largest refined product pipeline system in the country. The settlement includes a $1.3 million civil penalty and $1.8 million in projects for the state. “This agreement first and foremost addresses the environmental damage to land and water caused by significant gasoline spills in Shelby County during 2016,” Alabama Attorney General Steve Marshall said in a statement. A nine-man crew was working on the Colonial pipeline system at the time of the Oct. 31 explosion, killing a worker and sending five to the hospital. More than 4,400 barrels spilled. The explosion was caused by an accidental strike to the pipeline by excavating equipment, the statement said. In the September incident, nearly 7,400 barrels leaked below ground, and was discovered by a mining inspector who was nearby doing unrelated work. Reports indicate the leak was caused by pipe fatigue that resulted from improper compaction of soil below that portion of the pipeline, the attorney general’s office said. The 5,500-mile (8,850-km) Colonial Pipeline transports more than 3 million barrels per day of fuel including gasoline, diesel and jet fuel from the U.S. Gulf Coast to the New York Harbor area. The pipelines that were shut run from Houston to Greensboro, North Carolina.
LNG exports driving physical gas flows, constraints at Henry Hub, part 2. - Natural gas flows and market dynamics are shifting at national benchmark Henry Hub. Supply receipts at Henry this year to date have doubled since the comparable period last year to nearly 450 MMcf/d, on average. That’s also a five-fold increase from the same period in 2016. In fact, current gas flows through the hub are the highest we’ve seen since 2009. The last time we saw this level of flows through the hub was when Gulf of Mexico offshore gas production volumes — much of which hit the U.S. pipeline system in southern Louisiana — were still topping 6.0 Bcf/d. That was also before the Marcellus/Utica Shale gas supply ballooned, effectively emptying out the pipeline capacity that used to flow gas north from the Gulf Coast. Now, many of those pipelines have reversed flows and the hub is showing signs of becoming a destination market for that Northeast gas and other supply targeting LNG export demand on the Gulf Coast. Today, we continue our short series looking at the changing physical flows at Henry Hub. In Part 1 of this series, we reviewed the role that Henry Hub — located in Vermillion Parish, LA — has played in the U.S. gas market historically — as a liquid national benchmark and delivery point for futures contracts and physical trades, but one that does not see a lot of physical gas flows. In the physical market, Henry gas volumes change hands innumerable times in a single trading day but, more often than not, only on paper using a unique title transfer mechanism called Intra-Hub Transfer (IHT). Similarly, in the futures market, while the CME/NYMEX Henry Hub natural gas futures contract is grounded by the physical assets in Henry, contract settlements rarely end in physical delivery. Thus, overall, the volume of physical flows of gas through the hub has always been disproportionately much lower than traded volumes, whether in the futures or physical market. Not only that, but as Figure 1 below illustrates, until a couple of years ago, physical flows through the hub were at the bottom of a prolonged decline trend that goes back at least a decade.
Company urges appeals court to lift halt to pipeline work (AP) — A company building a crude oil pipeline in Louisiana asked a federal appeals court Tuesday for an order that would allow it to immediately resume construction work in an environmentally fragile swamp. A three-judge panel from the 5th U.S. Circuit Court of Appeals didn't immediately rule after hearing arguments from attorneys for Bayou Bridge Pipeline LLC and environmental groups opposed to the project. The company is seeking an emergency stay that would lift a court-ordered halt in pipeline construction in the Atchafalaya Basin. Company attorney Miguel Estrada said "time is of the essence" because water levels in the basin are rising due to the rainy reason. A permit issued by the U.S. Army Corps of Engineers requires the company to stop construction if river levels reach a certain height. Estrada said the company could resume work for weeks before water levels reach that threshold and possibly remain above it for several months. "We're hoping we can make up the lost time," he added. In court filings, environmental groups' lawyers said water levels already have reached a level that makes it unlawful for the company to resume pipeline construction in the basin. After the hearing, however, Earthjustice attorney Jan Hasselman said the company can still do "a whole lot of damage" if the 5th Circuit lifts the stay and allows the company to resume clearing a path for the pipeline in most of the basin. "What they wouldn't be able to do is actually finish the pipeline because they're prohibited from digging under the levees in a couple other places," he added. "We're in flood season. They can't finish the project until the end of the year at the very best, so there's no reason to lift the injunction."
Appeals court lifts halt to Louisiana pipeline construction — A company may resume construction of a crude oil pipeline in a Louisiana swamp that has been on hold for nearly three weeks, an appeals court ruled Thursday.A lower-court judge had suspended construction of the Bayou Bridge pipeline in the Atchafayala Basin, but a divided three-judge panel from the 5th U.S. Circuit Court of Appeals agreed to lift that order.It remains to be seen, however, how much work Bayou Bridge Pipeline LLC will be able to complete before rising water in the basin forces another work stoppage, possibly lasting for months. Construction in the basin began in January.On Feb. 23, U.S. District Judge Shelly Dick sided with environmental groups and issued a preliminary injunction stopping all Bayou Bridge pipeline construction work in the basin until a lawsuit the groups had filed against the project is resolved. Sierra Club and other environmental groups sued the U.S. Army Corps of Engineers in January, saying it violated the Clean Water Act and other environmental laws when it approved a permit for the project.The appeals court panel’s majority opinion said the company is likely to succeed on the merits of its claim that Dick abused her discretion in granting the injunction. Dick should have allowed the case to proceed “on the merits” and sought additional information about the “deficiencies” she identified in her ruling, the opinion added.Judge W. Eugene Davis of the 5th Circuit dissented, saying he agreed with Dick that an environmental assessment of the project by the Corps did not comply with the National Environmental Policy Act.Earthjustice attorney Jan Hasselman said the latest ruling is a setback but “not the end of this fight.”“We will keep fighting in court to protect the Atchafalaya Basin and demand that oil and gas companies ... finally be held accountable for decades of carelessness, incompetence and greed,” Hasselman said in an email.
LNG and pipeline reversals turn Louisiana gas market upside down - There was a time many moons ago when vast quantities of natural gas from offshore Louisiana production flowed through scores of gas processing plants along the coast, then moved north and east in pipelines destined for the Northeast and Midwest. Those flow patterns have since been turned on their head, with offshore production steadily declining and the need for gas supplies for LNG exports along the coast ramping up, driving gas southward to meet that demand. That southbound gas includes Haynesville production — now back in growth mode — and a deluge of inflows from the Marcellus/Utica on reversed pipelines and new pipes. Supply in northern Louisiana will continue rising, while demand in southern Louisiana will do the same. With Henry Hub at the epicenter of this transformation, the consequences not only for Louisiana but for the entire natural gas market will be far-reaching. Today, we begin a series to examine how Louisiana natural gas flowed historically, the shifts that have already happened, the impact of more changes just ahead, and what it all means for the future of natural gas in Bayou Country. We’ve been talking a lot about the pieces of this puzzle for the past few months in the RBN blogosphere. Fill Me Up Buttercup covered pipeline projects bringing more gas to the Gulf Coast via routes through Ohio and the Atlantic Coast. In Back With a Vengeance, we examined the who, what, where and how of Haynesville’s natural gas production resurgence. The link between soaring Marcellus/Utica production and LNG exports was the subject of Toe Bone Connected to the Foot Bone, and we covered the critical role LNG exports will play in balancing the U.S. gas market in I'm Movin' Out. In the past couple of weeks, we turned RBN’s analytical microscope on the Henry Hub, in Roll With Me Henry, where we assessed how flow patterns are already shifting around the most important trading hub in North America. But there is far more to this story than these individual market developments suggest. When you put them all together and do a rigorous analysis of Louisiana natural gas pipeline flows and capacity constraints, you reveal a picture of dramatic change, one that effectively turns Louisiana upside-down in terms of gas supply and demand. Which, of course, will have repercussions on prices, transportation values and basis.
US energy pipeline developers to seek exemptions to steel tariff (Reuters) - U.S. energy pipeline developers say they intend to pursue exemptions to the Trump Administration’s proposed steel tariffs, as concerns grow for those companies and from key exporters to the United States like South Korea. “We have a number of pipeline projects that would be impacted significantly by this cost increase,” said Adam Bedard, chief executive of Arb Midstream, an energy transportation and marketing company. If exemptions become available, “we’d certainly try and qualify for it.” He was referring to the U.S. Commerce Department’s effort to devise a procedure for companies to apply to avoid paying a 25 percent tariff on imported steel or 10 percent on imported aluminum. Commerce has 10 days to come up with the procedure to apply for exemptions from the steel and aluminum tariff declaration issued last week. There is a national security exemption for U.S. companies to buy steel items that domestic manufacturers do not produce in the volumes or quality required. The president also said exemptions would be available to certain countries. Imports account for 77 percent of the steel used in U.S. pipelines, according to a 2017 study conducted for the pipeline industry. Some manufacturers already have customers waiting two years for pipeline to construct lines to carry shale oil and gas from West Texas fields to U.S. Gulf Coast export hubs. Energy trade associations fought for a way around the tariff. They argued that U.S. manufacturers either do not offer key metal grades or diameters, or have long production times that would impede development of shale oil and gas pipelines.
Record crude and gas production leads to record NGL production at just the right time, part 2. With U.S. NGL production hitting a record high of just over 4.0 MMb/d in the fourth quarter of 2017 and ethane production also reaching record volumes at 1.6 MMb/d, the price for ethane has remained stuck at about 25 c/gal — where it’s been for the past two years, even though prices for other NGLs are up over the same period. The combination of roaring high-ethane-content Permian and SCOOP/STACK NGL volumes, coupled with steam cracker outages and construction delays due to Hurricane Harvey, have landed us here. So where do we expect the ethane market to go now as incremental cracker and export demand ramp up in 2018 and 2019? Today, we continue a series on our updated NGL market forecast, highlighting the NGL product whose market is going through the most changes: ethane. This is the second blog in our series on growing NGL production. In Part 1, we looked at raw-mix NGL production growth, which we forecast to increase from the 4.0 MMb/d reported in November 2017 to average 4.4 MMb/d for the year 2018, and 5.7 MMb/d of produced NGLs in 2023 under RBN’s Growth Scenario. The biggest driver behind the jumps in NGL production in 2018 and 2019 will be ethane production. Before we get into the details of ethane supply, demand and prices over the forecast period, let’s first look at where we are today and why.
Shell Changes Mind On Convent Refinery -- Louisiana -- You may remember this story, reported some time ago:Shell became the sole owner of the Convent refinery in May 2017 after it completed the transaction for the separation of assets, liabilities, and businesses of Motiva Enterprises LLC with Saudi Aramco. Under that deal, Aramco got the biggest refinery in the U.S., Port Arthur in Texas, while Shell received the Norco and Convent refineries in Louisiana. Shell had planned to permanently decommission the Convent refinery: Initial plans were to permanently decommission the gasoline unit as part of a project to integrate the Convent plant with the 225,800-bpd refinery in Norco, Louisiana, through a network of pipelines.Shell has now changed its mind. The refinery will undergo a major overhaul this summer; gasoline production will halt for an unspecified period of time.Oil major Royal Dutch Shell halted gasoline production at its Convent, Louisiana, refinery between Thursday and Friday.As of Friday morning, it was not immediately clear how long the gasoline producing unit with processing capacity of 92,000 bpd would remain offline.The gasoline-producing unit of the 227,586-bpd Convent refinery was scheduled to undergo a major overhaul this summer, after Shell dropped its plans to decommission it. Shell plans to shut for a planned overhaul the gasoline producing unit at Convent for some six weeks starting in June, sources familiar with the refinery’s plans told Reuters last month.
Top Exxon executive confirms Gulf Coast oil-refining expansion (Reuters) - A top Exxon Mobil Corp official confirmed a multi-billion dollar plan under consideration to double U.S. light crude oil refining capacity along the U.S. Gulf Coast to take advantage of the nation’s growing shale oil production. FILE PHOTO: An airplane comes in for a landing above an Exxon sign at a gas station in the Chicago suburb of Norridge, Illinois, U.S., October 27, 2016. REUTERS/Jim Young/File PhotoExxon’s proposed project, which has not received a final investment decision, would be the first major expansion of gasoline and motor fuels production in the nation in six years. Exxon’s Beaumont, Texas refinery could become the nation’s largest by capacity when the work is complete in the next decade. Exxon expects to add a crude distillation unit (CDU) at its 362,300 barrel per day (bpd) Beaumont refinery and boost refining capacity at plants in Baytown, Texas and Baton Rouge, Louisiana, Senior Vice President Jack Williams said in a presentation to Wall Street analysts last week. “It’s really a full Gulf Coast upgrade,” Williams said, according to a transcript of the meeting confirmed on Monday by Exxon. The project has been under consideration for several years because of the increase in output from Texas and North Dakota shale fields. “We know this is going to be a long-term resource,” he said. Sources familiar with Exxon’s plans told Reuters in February that the company was near a final investment decision for a project to expand crude oil processing capacity at the Beaumont refinery to as much as 850,000 bpd. Williams said the project would increase the integration of Exxon’s Gulf Coast operations by supplying its Baton Rouge and Baytown refineries with products made at Beaumont, reducing third-party purchases. He called the plan “perhaps my favorite example on integration” because it couples production and refining across business groups. Exxon plans to invest $9 billion in six refinery projects globally in the next eight years and forecasts returns from its downstream to grow by 20 percent on average, the company said. The expansion would offer a new outlet for the rising shale oil production from the Permian Basin in west Texas and New Mexico, which is expected to overwhelm U.S. refining capacity in the next few years, said an analyst from energy consultancy IHS Markit.
Refiners, traders brace for fuel-market volatility ahead of sulfur caps (Reuters) - Global executives and traders are bracing for higher volatility in fuel markets as they expect refiners to process more light crude oil in the lead-up to new rules aimed at slashing the use of dirty high-sulfur fuel oil in global shipping. Beginning in 2020, shipping vessels will not be allowed to burn fuel with a sulfur content higher than 0.5 percent, down from 3.5 percent currently. The International Maritime Organization (IMO) plan is among the most significant changes in decades for global shipping and refining. Large shipping vessels have traditionally run on high-sulfur fuel oil, produced after refiners have made higher-quality fuels like diesel or gasoline. High-sulfur fuel emits more pollution. “I think there will be a lot of volatility and uncertainty around this,” Jeremy Weir, chief executive officer of global commodity trading firm Trafigura said at the CERAWeek conference in Houston. The IMO rule changes will likely prompt refiners to boost processing of sweeter crude grades because they produce cleaner, low-sulfur fuels, several executives said. Once the rules take effect, the shipping industry will need to switch to either marine gasoil, low sulfur residual fuel oil or a blend of high sulfur and ultra low sulfur fuel. This could boost margins for companies operating complex refineries with large coking capacity. Refiners will likely process an additional 2.5 million barrels of crude daily to make additional distillate, said Robert Herman, executive vice president of refining at Phillips 66.
Will US shale give the refining industry indigestion? -- By the end of this year, the US oil industry will be pumping 11m barrels a day of crude, the highest in its history and more than either Russia or Saudi Arabia. These barrels, boosted by the shale revolution and increasingly exported, are seen as critical for keeping the market well supplied as a fast-growing global economy lifts demand for diesel, jet fuel and petrochemicals. But in the industry debate is growing, some would say concern, over just how well-suited the shale oil coming out of the US is for meeting this rising demand. The issue, critics say, is that US shale is far lighter — having been released through narrow fissures in rocks by hydraulic fracturing — than gloopy tarry crudes most people think of when they picture a barrel of oil. This has potentially huge implications because refiners, who turn crude into usable products, have spent decades investing in plants capable of processing far heavier oils that were once expected to dominate supply. The lighter shale barrels, some say, are just not as good for making the products — especially diesel, jet fuel and other so-called middle distillates — that the world increasingly needs. They warn of a potential crunch in years to come caused not by an outright shortage of crude, but by refiners scrambling to compete for more conventional barrels as US shale is found wanting. “The dirty secret of US shale oil is not many people want it,” “It’s wrong to say the US can add 1m-plus barrels a day of production capacity a year and it will immediately find a home in the world’s refining system.”
Clean up your old oil pipeline, Minnesotans tell Enbridge -- Enbridge Energy wants to leave its aging Line 3 oil pipeline in the ground if it gets Minnesota regulators' approval to build a replacement across northern Minnesota.But with a decision on whether to approve the contentious project a few months away, a growing chorus of landowners and tribal groups is calling for Enbridge to remove the old pipeline if the new one gets the OK. They're concerned about potential pollution from the old pipe, that it could become buoyant and pop out of the ground or that it could potentially act as a water conduit underground."When you're done with something, clean it up. It's that simple," said Richard Shustarich, 77, who lives along the current Line 3 route just outside Grand Rapids, Minn. He has no problem with pipelines. When he bought his small house on 20 acres a little over a decade ago, five oil pipelines already crossed the property. And he had no problem signing an easement to give Enbridge permission to add another line in 2010. He said they're a safer way to transport oil than trains. "I figured that was a smart way to do it," he said. "But I hadn't thought that Enbridge would disrespect the people who allowed them to go on their property, you know, for a few thousand bucks."
State regulators approve environmental review for proposed Enbridge crude oil pipeline - State utility regulators on Thursday approved the environmental review of Enbridge’s proposed new crude oil pipeline across northern Minnesota, a milestone for the controversial project. By a vote of 5-0, the Minnesota Public Utilities Commission (PUC) deemed the environmental impact statement (EIS) for Enbridge’s proposed new Line 3 to be “adequate.” The PUC in December had voted 4 to 1 against the EIS, saying it was inadequate because of a handful of narrow concerns. The PUC sent the report back to its author, the Minnesota Department of Commerce, to address its questions. PUC members said they were satisfied with the answers. “The revised EIS before us addresses the significant environmental issues,” said PUC Commissioner Matt Schuerger. The EIS looks at myriad potential environmental effects of a new Line 3 but made no conclusions. In June, the PUC is scheduled to decide on a “certificate of need” for the project — essentially giving it a green light or killing it. Environmental groups and Indian tribes that oppose Line 3 have criticized the EIS on several fronts, including not adequately assessing potential oil spills into sensitive waters or wilderness areas. They continue to say the EIS is inadequate, and a legal challenge of the PUC’s decision is in the offing. The environmental activist group Honor the Earth plans to appeal the ruling to the Minnesota Court of Appeals, according to Paul Blackburn, an attorney for the group.
Who will speak for school kids subjected to fracking? -- Karla Scornavacco: My children's school is about to be fracked, and I never thought I'd say that living in Boulder County. "We need you to help us," said my 10-year old and classmates at a community meeting at a local coffee shop a few blocks from the school. She's learning to speak up, even heading to Greeley to support Bella Romero Academy, another school facing a 24-well pad of drills pumping an undisclosed concoction of chemicals into the earth with enough force to fracture rock formations thousands of feet deep. Yet, despite the need, who in the school district is speaking up for her? And what about the kindergartners, or future students? Will they get a chance to go to school free of benzene, toluene, or other cancer-causing chemicals drifting into their playgrounds? The students of Escuela Bilingüe Pioneer are being placed in imminent risk of harm by Extraction Oil & Gas, and I worry that Boulder is overlooking this threat to the health and safety of our county's children. When the drills come to your own backyard, to your children's schools, to the soccer fields where your children play, the veil of denial quickly lifts. Questions for our new superintendent should include what they will do to protect the health and well-being of all the district's children, not just those living closest to the foothills. And how will curriculum leaders support students in learning both the science and politics behind this industry? Why are the wells nearer to a school with a higher percentage of students living in poverty? I'm taken aback that fracking wells dotting our district's borders is the new normal. In east Boulder County, we need the city's help in protecting our children, our schools, our livelihoods
Standing Rock: Dakota Access Pipeline leak technology can't detect all spills - Nine months after oil starting flowing through the Dakota Access pipeline, the Standing Rock Sioux Tribe continues to fight the controversial project, which passes under the Missouri River just upstream from their water supply. In a 313-page report submitted to the U.S. Army Corps of Engineers, the tribe challenged the adequacy of leak detection technology used by pipeline company Energy Transfer Partners. The tribe also questioned the company's worst-case spill estimate and faulted Energy Transfer Partners for failing to provide a detailed emergency response plan to the tribe showing how the company would respond to an oil spill. "We wanted to show how and what we are still fighting here," said Doug Crow Ghost, water resources director for the Standing Rock Tribe. "It's an ominous threat every day that we live with on Standing Rock, not even knowing if the pipeline is leaking." The leak detection system used by Energy Transfer Partners can't detect leaks that are less than 2 percent of the full pipeline flow rate, according to the report prepared by the tribe and outside experts. Assuming a flow rate of 600,000 barrels of crude oil per day, a leak of nearly 12,000 barrels per day could go undetected.
From North Dakota to Puerto Rico, controversial security firm profits from oil protests and climate disasters - TigerSwan, the mercenary security company best knownfor its efforts to suppress indigenous-led resistance to the Dakota Access oil pipeline, is stepping up its pursuit of profits in areas hit by climate change-driven natural disaster. Three blog posts published on TigerSwan’s website in February describe the firm’s response efforts in the aftermath of Hurricane Harvey in Houston, Hurricane Maria in Puerto Rico, and Hurricane Matthew in North Carolina in 2016. TigerSwan, according to the posts, assisted National Guard members in Houston and emergency managers in North Carolina by providing them with access to its GuardianAngel system for monitoring the movement of individuals and sensitive shipments. In Puerto Rico, the company’s work included tracking down the employees of an unnamed client. At Standing Rock, TigerSwan operatives hired by the pipeline company Energy Transfer Partners used militaristic tactics to disrupt the massive opposition to the project, sending infiltrators into resistance camps, conducting aerial surveillance, and engaging in propaganda efforts. The private security firm routinely coordinated with law enforcement, sharing equipment and intelligence and assisting with arrests. Although preventing water pollution was the Standing Rock movement’s rallying call, many of its organizers were also climate activists; the earliest DAPL opponents were veterans of the anti-Keystone XL pipeline movement, which centered on the harmful climate effects of carbon-intensive tar sands oil. In essence, TigerSwan has gone from suppressing a movement seeking to slow climate change to marketing itself as a company that can help clients survive climate change’s most severe consequences.
Idle Chatter About Mark Papa's Concerns About Shale Oil -- March 11, 2018 -- Bruce Oksol -- This is an old story but it's getting a lot of press because Mark Papa spoke about it again at the recent oil conference. One can find the story everywhere; here's one link. I think he first spoke about this about a year ago. I may have even blogged about it then. Simply stated: Mark Papa warns that US shale oil forecasts are too optimistic. He may be right. Look at this graph from this link: Note how "narrow" the band is for "tight oil" (the Permian, Eagle Ford, and the Bakken) compared to that large, large band labeled "other." I assume that's what Papa (former EOG/CEO) is looking at. In the military when we had "information" or "intelligence" a big issue was whether the "information" or "intelligence" was "actionable." We have a lot of information but so what? I'm not sure that Mark Papa's "concern" is actionable. After you read the articles about what he is saying, how will that affect what you do, with regard to anything? I honestly don't know. One source said that Mark Papa said that the Bakken and the Eagle Ford were "long in the tooth." A reader sent me that link. I replied, not ready for prime time (and my reply does indeed miss what Mark Papa seems to be saying, but I will post it anyway): He may be correct. It all has to do with perspective. Oil companies are in the "E & P" business -- "exploration and production." From an "exploration" point of view, I think he's right on track. There's not much more "exploration" needed in North Dakota. And production is going to depend on many factors:
- price of oil
- advances in technology
- skill of geologists
- completion strategies (fracking: number of stages; amount of proppant)
- infrastructure (takeaway capacity)
- state and federal regulations
- extraction and production taxes
To put all this in perspective, the Permian was a legacy play that was considered "dead" some years ago. The Bakken is now in the "manufacturing" stage which was predicted some years ago. I'm not sure what "actionable" information Mark Papa provides by saying the Bakken is long in the tooth without more specifics. I would be more interested in what his thoughts are about the Bakken with regard to max production in a "perfect oil" world. Bentek provided that "analysis years ago: 2.2 million bopd. Right now, the Bakken is stuck at 1.1 million bopd but analysts expect the Bakken to set more production records as soon as this summer.
U.S. Shale's Dirty (Big) Secret -- U.S. shale is surging, threatening to take even more market share away from OPEC. But the prospect of U.S. oil edging out barrels from the Middle East is not nearly as simple as it might seem. Oil coming from the major shale plays in the U.S. is light and sweet, while a lot of oil coming from OPEC is medium or heavy, and often sour. A lot of refining capacity along the U.S. Gulf Coast, built up over years and decades, is equipped to handle heavier forms of oil. Before the shale revolution, refiners made their investments in downstream assets assuming the oil they would be using would come from places like Saudi Arabia and Venezuela. Lighter shale oil is perfectly fine for making gasoline, but not the best for making diesel and jet fuel. Medium and heavy oil is needed for that. But refiners have a tidal wave of light sweet oil on their hands, perhaps too much. The U.S. refining industry could max out its ability to swallow up light sweet oil from the shale patch, as the FT reports, particularly as U.S. shale drillers are expected to add upwards of 4 million barrels per day (mb/d) over the next five years.Meanwhile, heavy crude production has waned as of late, with sharp declines in output in Venezuela and Mexico in the past few years. Shipments from Canada face a bottleneck because of fixed pipeline capacity. The result has been a somewhat tighter market for heavy oil, which refiners want to process into jet fuel and diesel.In the years ahead, demand for gasoline could start to slow down as vehicles become more efficient and EVs start to gain more market share. Meanwhile, diesel demand has grown much faster, and will likely jump in 2020 as new regulations on dirty fuels from the International Maritime Organization take effect. That could force the shipping industry to switch from residual fuels to diesel, perhaps adding as much as 2 mb/d of demand for diesel, the FT reports.In other words, volumes of lighter oil suited for gasoline production are soaring while production of medium and heavy oil used for diesel is flatter, even as diesel demand is poised to grow quickly. And refining capacity capable of handling light oil might not be up to the task.
The US Market for Fracking Fluids 2017-2022 - For the first time in U.S. history, projections of oil and gas production place the U.S. as the largest oil producer in 2017 and a net exporter of natural gas in the early 2020s.1 The uptick in production sees the highest growth rate of oil from the Bakken Shale under the states of North Dakota and Wyoming, and gas from the Marcellus Shale under the states of Pennsylvania, West Virginia, Ohio, Virginia and New York.Fracking fluids mainly consist of a major solvent such as water, a proppant (typically sand), and a number of various additives which include gelling agents, iron controls, breaker fluids, corrosion inhibitors, friction reducers, surfactants, biocides, crosslinkers, acids, solvents, scale inhibitors, clay stabilizers and pH adjusters that all contribute to the efficiency of the fracking process. The fracking fluids are forced down a well with high pressure and aid in breaking through the porous rock formations that hold trapped oil and gas, facilitating their release and capture.Given the important role that the fracking fluids play in the hydraulic fracturing process, this study will provide an overview of the widely used hydraulic fracturing technologies in the U.S. This study provides a comprehensive overview of the fracking fluids market in the U.S., including the hydraulic fracturing technologies most widely used, the amount and type of production, and presents market forecasts over the five-year period from 2017 to 2022 for each major component and the specific additives in use. The research covers the market drivers propelling the growth of the fracking fluid industry, the industry structure, trends, and the company profiles of the major production operators and fracking fluid suppliers for the U.S. domestic market. Extensive analysis of the production of each type of hydraulic fracturing technology supports the estimated production growth rates for the specific fracking fluids presented.
Zinke: Oil and gas exploration off the Pacific coast might not happen - Interior Secretary Ryan Zinke expressed doubt Tuesday that oil and gas exploration will happen off the Pacific coast as part of the Trump administration’s proposal to dramatically expand offshore leasing, saying California, Oregon and Washington have “no known resources of any weight” for energy companies to extract. Discussing the Atlantic coast while testifying before the Senate Energy Committee, the secretary similarly described Maine as a state with little recoverable oil and gas. Zinke stopped short of saying that the three Pacific states would be exempted from the president’s plan to offer leases on 95 percent of the outer continental shelf. But in his reply to a question from Sen. Maria Cantwell (D-Wash.), he acknowledged her state’s deep opposition. “I think I’m going to mark down Washington as opposed to drilling,” Zinke said after Cantwell asked him to extend the public comment period for the drilling proposal. It is clear “the state of Washington is deeply, passionately opposed to oil and gas drilling off the coast,” he continued, promising that will be reflected in the next draft of the plan. California and Oregon also are strongly against drilling off their shores, as are virtually all states along the Atlantic coast. Zinke’s suggestion that the Pacific coast could be spared from drilling came in the last stage of a hearing that at times was heated. The former Navy SEAL commander engaged in several sharp exchanges with Democrats, who criticized the cost of his air travel on private aircraft and seeming favoritism for the oil and gas industry.
US Interior Department to begin ANWR leasing preparations - The US Department of the Interior has begun preparations for oil and gas leasing in the coastal plain of the Arctic National Wildlife Refuge and will use a new, streamlined procedure for its environmental review, a top Interior official said Monday. "We expect to publish a Notice of Intent to begin an Environmental Impact Statement very soon. That will kick off a 60-day series of 'scoping' meetings, after which we begin preparation of the draft EIS," Joe Balash, DOI's assistant secretary for land and water management, said in an interview. Balash said the ANWR Environmental Impact Statement will fall under a new Interior Department policy of completing an EIS within one year and limiting it to 300 pages. In the past, EIS documents have exceeded 1,000 pages and have taken several years to complete. But if the EIS is rushed, it may provide openings for inevitable lawsuits filed by US environmental groups. "If the review is done in a way that circumvents existing laws and procedures, I'm sure our attorneys will consider litigation options," said Tony Iallonardo, spokesman for The Wilderness Society. Exploration in the 1.2 million acre coastal plain within the refuge, considered highly prospective by geologists, has been a political hot button for decades. Congress once granted approval, only to have President Bill Clinton veto the bill. A second attempt came near to passage under the second George W. Bush administration, but was defeated 51-49 in a Republican-controlled US Senate.A provision tucked into the federal tax bill Congress passed late last year granted approval and required the Department of the Interior to hold two lease sales of 400,000 acres within 10 years. The US Geological Survey has estimated the potential for discovery of up to 10 billion barrels of oil in the coastal plain.
The trans-Alaska pipeline fights off 22 million cyber attacks--daily - The trans-Alaska pipeline has dealt with its share of problems — earthquakes, declining oil flow, even gunfire. But today, the pipeline is facing another, more modern threat: cyberattacks. Energy infrastructure is a tempting target for hackers, and the trans-Alaska pipeline is no exception. Alyeska, which operates the pipeline, now ranks cyberattacks as one of its top three risks. In the room where part of the pipeline’s cybersecurity team is stationed, Alyeska’s Bill Rosetti points at a wall of data flowing down three giant screens hanging above the cubicles. It’s all totally incomprehensible to a layperson. But for Rosetti and his staff, weird activity on one of the colorful charts rippling across the screens could indicate something serious. “The idea here is that we are looking for things to be normal,” Rosetti explained. “And anything that’s not normal is something that needs to be investigated.” Rosetti is Alyeska’s chief information officer. He’s in charge of keeping cyberattackers at bay. Rosetti takes that job seriously, because the trans-Alaska pipeline is getting hit by cyberattacks all the time — and not just a few. “We see about 22 million attacks a day,” Rosetti said. And that’s an average. “It can be six or seven million some days and 45 million the next,” Rosetti said. “I wish I could tell you why it changes that way, but I really don’t know.” Of course, there aren’t millions of people carrying out these attacks individually. These are mass, automated attacks, often coming from servers overseas. Rosetti said so far, none of the cyberattacks have been successful; Alyeska has never been breached. But the challenge is growing. Rosetti said the rate of cyberattacks has roughly doubled in the last five years. As the energy industry settles into the Internet age, more of its machinery is controlled remotely by computers. If someone manages to breach those systems, there could be dangerous real-world consequences. “We think about what the worst case is so we can protect against the worst case. And I don’t want to share what that is,” Rosetti said.
Thousands march to protest Canada pipeline expansion project -- — Thousands of demonstrators marched Saturday to speak out against a pipeline expansion project that would nearly triple the flow of oil from Canada’s tar sands to the Pacific Coast. Indigenous leaders led the march in the Vancouver suburb of Burnaby after telling the crowd that the day’s event was a celebration of unity, but they should be prepared in the future to “cross the line” with potential arrests. “Our spiritual leaders today are going to claim back Burnaby Mountain,” Rueben George, a member of Tsleil-Waututh Nation, said before the crowd marched to the steady beat of drums and chants toward a site near Kinder Morgan’s storage tank farm in Burnaby. Many protesters carried signs that read, “Water is life,” ‘’No consent, no pipeline,” and “Keep it in the ground.” Others hoisted inflatable orcas and beat drums. The Trans Mountain pipeline expansion by the Canadian division of Texas-based Kinder Morgan would dramatically increase the number of oil tankers traveling the shared waters between Canada and Washington state. Prime Minister Justin Trudeau approved the project in late 2016, saying it was in Canada’s best interest. Kinder Morgan says it is moving ahead with preparatory work at two terminals in Burnaby but still needs to obtain numerous local permits and federal condition approvals to begin construction. The project has drawn legal challenges and opposition from environmental groups and Native American tribes as well as from municipalities such as Vancouver and Burnaby. It’s also sparked a dispute between the provinces of Alberta, which has the world’s third largest oil reserves, and British Columbia.
First Nations Build a 'Watch House' in Path of Kinder Morgan Pipeline -- The campaign against the controversial Kinder Morgan pipeline escalated Saturday when Indigenous leaders from across Canada and the U.S. came together to inaugurate Kwekwecnewtxw— "the place to watch from"—whilst others started building a traditional Coast Salish "Watch House" near the pipeline route. Although the Watch House stands on the line of exclusion zone surrounding the pipeline, the local community have vowed to not move from the tower until Kinder Morgan is defeated. Building of the Watch House is expected to finish Monday. It will then become a focal point for resistance to the pipeline, which if completed, is expected to bring some 400 tankers a year to the ecologically and culturally sensitive coastline. The highly controversial $7.4-billion project was approved by Canadian Prime Minister Justin Trudeau's government in November 2016. It has subsequently been challenged in court by First Nations, the City of Burnaby, the City of Vancouver and the BC government. And Saturday the local community was out in force. Some 10,000 local supporters marched to the site in solidarity. Speaker after speaker then condemned the pipeline, criticizing Canadian Prime Minister Justin Trudeau's approval of the pipeline "a major step backwards" in both their relations with the Federal Government and also for the climate. Grand Chief Stewart Phillip told the crowd: "We are gathering today to send a clear message to Kinder Morgan and Justin Trudeau that indigenous peoples across North America and British Columbians will never let this pipeline be built. I call on everyone in the crowd today and watching from home to join us in escalating action to stop Kinder Morgan in the coming days. Rachel Notley, we are not in the least bit intimidated by your desperate threats and we will not stop!"
Canadian heavy pipeline crude oil drifts lower amid increased storage, rail drop - Canada's benchmark heavy pipeline crude drifted to the lowest in six sessions Thursday as the market digested news of additional storage tanks in Alberta, an anticipated drop in crude-by-rail volumes and insight into how much crude has flowed on the Keystone Pipeline after a temporary shutdown and restart in November. Crude-by-rail exports out of Canada dropped 11.3% in January from the previous month to 140,959 b/d, according to the latest statistics from Canada's Crude Oil Logistics Committee. Analysts had said they expected volumes to be flat or down in January after Canadian rail operators and clients reported delays due to extreme weather. Producers are counting on increased crude shipments by rail to alleviate inventories in Alberta after the temporary shutdown of TransCanada's Keystone Pipeline on November 16 led to a selloff that saw differentials for Western Canadian Select at Hardisty widen from around WTI CMA minus $14/b to a four-year low of WTI CMA minus $30.55/b on February 5. WCS at Hardisty on Thursday was assessed at WTI WMA minus $27/b. The 600,000 b/d Keystone Pipeline restarted on November 28 at reduced pressure, as mandated by the US pipeline regulator. TransCanada has declined to say what that reduction in pressure has meant for crude flows, but data from Canada's National Energy Board shows the company has the capability to run at normal volumes under the current restrictions. The Keystone Pipeline operated at 565,000 b/d in October, dropped to 298,000 b/d in November and then rebounded to 582,000 b/d in December, NEB data show. Throughput volumes in January are expected to be similar to the previous month, indicating that TransCanada is able to work around the pressure restrictions, said Kevin Birn, a senior analyst with IHS Markit. "The word out there is volumes in February and March will be lower, as TransCanada is carrying out a full integrity check on Keystone," he noted.
Canada Is Facing A Heavy Crude Crisis - Canada’s benchmark heavy crude oil widened its discount to WTI to the largest in six trading sessions on Thursday, as additional storage capacity in Alberta and data about lower crude-by-rail shipments added concerns over the domestic oil glut, as TransCanada’s Keystone Pipeline has yet to return to normal pressure levels following a leak and temporary shutdown last November.On Thursday, Western Canadian Select was trading at a discount of US$27 a barrel to WTI. The discount widened to the biggest level, US$30.55 a barrel, in four years on February 5, after a selloff following the temporary shutdown of Keystone in mid-November.This week, market participants were digesting news about increased storage capacity and January crude-by-rail data. Crude-by-rail exports out of Canada fell by 11.3 percent month on month in January to 140,959 bpd, according to the latest data by Canada’s Crude Oil Logistics Committee, quoted by Platts. Analysts had expected rail crude exports to be either flat or down, because Canadian rail operators and customers had reported delays in shipments due to extreme weather.In addition, Kinder Morgan Canada and Canadian midstream operator Keyera said earlier this week that they added two additional tanks at the Base Line Terminal for service ahead of schedule. The two tanks add an additional 800,000 barrels of crude storage to the 1.6 million barrels currently in operation.Meanwhile, data from Canada’s National Energy Board (NEB) showed that the Keystone Pipeline, which was restarted on November 28 after a shutdown on November 16, had throughput volumes of 582,000 bpd in December, following a slump to 298,000 bpd in November. Keystone was restarted at reduced pressure, as per U.S. regulation. TransCanada has managed to work around pressure restrictions and the January volumes are expected to be close to the December throughput, Kevin Birn, a senior analyst with IHS Markit, told Platts.“The word out there is volumes in February and March will be lower, as TransCanada is carrying out a full integrity check on Keystone,” Birn added. Canada’s heavy crude is expected to remain at hefty discounts to WTI in the next few years, as takeaway pipeline capacity is unable to meet rising production from new oil sands projects sanctioned before the downturn.
Panel of scientists to drill into safety and environmental impact of fracking - Hydraulic fracturing, better known as fracking, is going under the microscope in B.C. as the provincial government forms a review panel to analyze safety and environmental concerns. B.C. Energy Minister Michelle Mungall announced on Thursday that she has appointed an independent scientific review of the natural gas extraction process to ensure it is meeting the province’s safety and environmental standards. Mungall said the panel of three experts in hydrogeology and geological engineering will be taking a further look at some of the issues surrounding gas leakages potentially caused by fracking. “There’s a lot of concerns about methane leakage, as well as water quality and water quantity,” Mungall said. “That’s some of the things that the hydraulic scientific panel is going 0t be looking at.” The energy minister said both industrial and environmental groups are in favor of the review panel being implemented. “I think industry wants to find a way they can reduce the environmental footprint,” Mungall said. “They want to make sure the water quality is strong and so do communities and so do environmental organizations.”
The value of U.S. energy exports to Mexico exceeded import value for third year in a row - In each of the past three years, the value of U.S. energy exports to Mexico has exceeded the value of U.S. energy imports from Mexico. Energy trade between Mexico and the United States has historically been driven by Mexico’s sales of crude oil to the United States and by U.S. exports of refined petroleum products to Mexico. As the United States has reduced crude oil imports from Mexico, the trade balance has shifted. Through 2014, Mexico’s exports of crude oil to the United States were the most valuable component of bilateral energy trade, with the overall value of Mexico’s U.S. crude oil sales far exceeding the value of U.S. net sales of petroleum products, primarily gasoline and diesel fuel, according to data from the U.S. Census Bureau. Starting in 2015, the value of U.S. energy exports to Mexico, including rapidly growing volumes of both petroleum products and natural gas, exceeded the value of U.S. energy imports from Mexico as volumes of Mexican crude oil sold in the United States continued to decline. The value of U.S. energy exports to Mexico increased to a high of $25.8 billion in 2017, including $23.2 billion of petroleum products. Overall, this export value was more than twice as much as the $11.1 billion value of 2017 U.S. energy imports from Mexico. Based on the latest annual data from the U.S. Census Bureau, energy accounted for more than 10% of the value for all U.S. exports to Mexico and 4% of all U.S. imports from Mexico in 2017. Crude oil makes up most of the U.S. energy imports from Mexico, averaging 608,000 barrels per day (b/d) in 2017. In 2017, Mexico was the source of 8% of U.S. imported crude oil, the fourth-largest share behind Canada, Saudi Arabia, and Venezuela. Petroleum products such as finished motor gasoline, distillate fuel oil, and propane account for most of the value of energy exports from the United States to Mexico. In 2017, Mexico was the destination for more than 1 million b/d of petroleum products, up from 880,000 b/d in 2016. This level was 24% of all petroleum products exported from the United States. These exports were valued at more than $23 billion dollars in 2017.
U.S. crude oil exports increased and reached more destinations in 2017 - U.S. crude oil exports grew to an average of 1.1 million barrels per day (b/d) in 2017, the second full year since restrictions on crude oil exports were removed. Crude oil exports in 2017 were nearly double the level of exports in 2016. Increased U.S. crude oil exports were supported by increasing U.S. crude oil production and expanded infrastructure. U.S. crude oil exports went to 37 destinations in 2017, compared with 27 destinations in 2016. Similar to previous years, Canada remained the largest destination for U.S. crude oil exports, but Canada’s share of total U.S. crude oil exports continued to decrease, down from 61% in 2016 to 29% in 2017. U.S. crude oil exports to China accounted for 202,000 b/d (20%) of the 527,000 b/d total increase. China surpassed the United Kingdom and the Netherlands to become the second-largest destination for U.S. crude oil exports in 2017. Many European nations are among the largest destinations for U.S. crude oil exports, including the United Kingdom, Netherlands, Italy, France, and Spain. India, which did not receive U.S. crude oil exports in 2016, received 22,000 b/d in 2017, tying with Spain as the tenth-largest destination. Crude oil now makes up 18% of total U.S. petroleum exports, making it the third-largest petroleum export after hydrocarbon gas liquids (HGL) and distillate fuel. Before the restrictions on domestic crude oil exports were lifted in December 2015, most of the growth in U.S. petroleum exports was petroleum products—mainly HGLs (such as propane), distillate fuel, and motor gasoline. Previously, crude oil’s largest share of total U.S. petroleum exports was 13% in 1999, when total volumes of U.S. petroleum exports were less than 1.0 million b/d, which was much lower than the 6.3 million b/d total in 2017. Increasing U.S. crude oil production and expansions of U.S. pipeline capacity and export infrastructure facilitated increased crude oil exports. U.S. crude oil production reached 9.3 million b/d in 2017, a 0.5 million b/d increase from 2016. Several new or expanded pipelines came online in 2017 to move crude oil from producing regions, primarily the Permian basin of Texas and New Mexico, to the U.S. Gulf Coast. On the U.S. Gulf Coast, recently expanded crude oil export infrastructure in ports such as Corpus Christi and Houston, Texas, and in ports along the Mississippi River in Louisiana allowed larger volumes of crude oil exports.
Investment in tight oil, oil sands, and deepwater drives long-term oil production growth - Upstream investment in crude oil and liquids production is highly sensitive to crude oil prices, particularly production of higher-cost resources from tight rock formations, oil sands, and offshore deepwater. In EIA’s International Energy Outlook 2017 (IEO2017) Reference case, increasing crude oil prices lead to more investment, driving production growth in these higher-cost resources. By 2040, EIA projects that the combined production from tight oil, oil sands, and offshore deepwater will reach 21 million barrels per day (b/d) and will account for almost a quarter of the world's total crude oil production. From 2010 to 2014, global investment in tight oil, oil sands, and offshore deepwater development increased from 20% to 30% of total upstream investment. Over that same period, combined production from these resources increased by 4 million b/d, reaching 12.2 million b/d and accounting for 16% of total global crude oil production. Following the decline in crude oil prices in 2014–2015, global upstream investment in these resources decreased from $280 billion in 2014 to $126 billion dollars in 2016. IEO2017 projects that the Brent global benchmark crude oil price will increase throughout the projection period but will remain lower than prices during 2010–2014 in real dollar terms. For this reason, future investment growth in higher-cost resources is expected to be lower than in recent history. The IEO2017 Reference case projects global production of tight oil will increase by 3.3 million b/d, offshore deepwater by 2.7 million b/d, and oil sands by 1.4 million b/d between 2017 and 2040. Total production increases from these sources makes up nearly half of the long-term global liquids supply growth through 2040. EIA expects a large share of global upstream capital investment to be concentrated in tight oil resources in the United States. Tight oil projects in the United States tend to have shorter payback periods because of lower service costs, high operator efficiency, exploitable resources that can be accessed through new technological advances, and a stable regulatory framework. IEO2017 projects that investment in tight oil plays outside of the United States will be lower than investment in plays in the United States through 2025. Development of tight oil can be hindered by a lack of infrastructure and of experience in developing tight oil resources and by competing oil resources that can be produced at a lower cost than tight oil. After 2030, as oil prices continue to increase, more investment in these resources is expected to result in increased production.
The Power Has Shifted In LNG Markets - One of the most influential figures in the LNG market has claimed that a return to long-term LNG contracts is crucial for the sector. It was a statement that most liquefied natural gas (LNG) buyers don’t necessarily want to hear; in fact, it goes against the fundamental changes currently underway in global LNG markets. Yesterday, Yury Sentyurin, the new head of the Gas Exporting Countries Forum (GECF), an industry group representing gas sellers, said, in comments carried by Bloomberg Markets, that LNG prices still need to be linked to oil prices to keep revenue predictable for producers, particularly since some US$8 trillion worth of investment in the fuel is needed by 2040. GECF members include Russia, Iran, Algeria and Qatar (currently the world’s largest LNG producer), and its headquarters are in Doha, Qatar. Sentyurin said that "[LNG] consumers should understand the peculiarities which producers face. Security of investment and supply can only be on the basis of long-term contracts closely connected to oil prices so we could plan further investments into crucial infrastructure." He added that continued expansion of supply is needed to meet demand that’s forecast to grow at an average of 1.6 percent per year until 2040. While Sentyurin is correct that the global LNG sector will need substantial infrastructure investment in the long term, even if his projection is more than two decades away, his comments that consumers should understand the peculiarities of producers misses the mark.. Since 2016, with Australia now poised to have as many as ten major LNG export projects operational, followed by the U.S. which now has two export projects on-stream and will have five export projects operational by the end of the decade, the market has switched from being stretched thin to being over supplied – all good news for buyers thereby changing the rules of the game. This is a development that has been hard for LNG exporters to accept, apparently including one of its representative groups, the GECF.
LNG is the new shale oil with the U.S. as disruptor-in-chief: Russell (Reuters) - Crude oil is likely to spring to mind if one is asked to name a commodity where the United States is disrupting the market by becoming a swing producer and challenging traditional trade flows, especially in fast-growing Asian markets. But it’s increasingly likely that the United States is about to play the same role in liquefied natural gas (LNG), as it ramps up production in an already well-supplied market. Investment in LNG projects fell off a cliff in recent years as the industry dealt with the ramifications of rapid supply growth, which has seen Australia add eight new large-scale plants, while the United States is busy commissioning the second of its new export projects, with five more to come by 2019. While Shell and others may well be correct about the need for new plants to meet demand by 2030, it’s the next couple of years that could prove challenging for the LNG industry. Most of the new capacity built in Australia was done under the old industry model where long-term offtake contracts, often linked to crude oil prices, allowed for the financing of billions of dollars of capital investment with extended payback terms. The model has been somewhat different in the United States, with far less of the upcoming production committed to buyers, meaning more will be sold at spot prices linked to U.S. benchmark Henry Hub natural gas. This is where the role of the United States in LNG starts to look eerily similar to the role its shale oil producers are playing in crude oil markets. Traditional exporters, such as Saudi Arabia and Russia, have found it tougher than expected to push crude oil prices higher, mainly because customers, especially in Asia have been able to turn to alternative suppliers. While the Organization of the Petroleum Exporting Countries (OPEC) and its allies, including Russia, have met some success in draining excess global crude inventories, it’s come at the expense of market share in the fast-growing Asian demand region.
European traders store gasoline on tankers as glut looms (Reuters) - Traders are storing gasoline on tankers off Europe’s coast as they struggle to contain a steady rise in supplies since the start of the year that has weighed on prices. The unusual move reflects a recent weakening in the margin refiners make from converting crude oil into the road fuel as stocks in the Amsterdam-Rotterdam-Antwerp refining and storage hub in recent weeks reached their highest level since July 2016, according to data from PJK International. At least three 90,000 tonne tankers have been booked in recent weeks to store gasoline for up to 60 days off the Dutch coasts - Maersk Producer, Phoenix Dream and Maersk Promise, according to traders and shipping data. Gunvor had booked the three cargoes, the sources said. Traders said the drop in current gasoline prices had tipped the northwest European market into a contango that made it worthwhile to put cargoes of summer-grade gasoline into storage. Medium-range tanker freight rates have also fallen, making it cheaper to book these ships, ship brokers said. The stored fuel is believed to be summer-grade gasoline which will be kept until demand revives in the United States, which switches from winter-grade on May 1, traders said. “Typically, imports of summer grade product rise from mid-March onwards, with the vast majority of product heading into the Atlantic Coast originating from Europe,” Alphatanker said in a note. Northwest European gasoline refining margins, or cracks, fell to $1.67 a barrel on March 9, the lowest since December 2014, according to Reuters calculations amid a big selloff in winter grade gasoline prices. The selloff triggered strong demand for buying the motor fuel in the barge market with daily trading volumes hitting a record high of 66,000 tonnes on an Argus basis on Monday.
UK Gas Crisis: Out Of The Frying Pan Into The Fire - For the ministers and officials assembled, it was an embarrassment all around. Late last week, as we were at the annual Windsor Energy Consultation (WEC) just outside London, British Gas Plc confirmed that the nation was facing a natural gas shortage as freezing temperatures grip the country. You see, blizzards, strong winds, drifting snow, and bitter cold recently brought Britain to a standstill as the weather system nicknamed the “Beast from the East” combined with winter storm “Emma” to create some of the most testing weather the U.K. has had to face in years.Now, I can attest first hand that this cold snap was not something to take lightly. And nationwide, this “big freeze” has brought to light a very serious problem.And it’s one that is only getting worse… The unfolding gas crisis has brought about a renewed immediacy to a major political issue that has been percolating in the U.K. for some time now. You see, for the third year in a row, a portion of my two briefings (one to the plenary meeting; one to the ambassadors), was devoted to the growing global need for a new “energy balance.” Now, among the assembled officials and sector dignitaries at this year’s Windsor meeting, there was a widespread agreement that a global “energy balance” is necessary.But you wouldn’t know it looking at the situation developing currently. In fact, despite that agreement, the current gas crisis emerging in the U.K. actually results from a shocking referendum decision back in 2016… Delays in moving on still contentious (and well over budget) nuclear power plants combined with ongoing pipeline problems from the North Sea offshore fields has left any “energy balance” forward planning very much in limbo. The majority of demand in the U.K. is still covered by natural gas – both from the North Sea, which is becoming increasingly questionable when it comes to extractable volume, and expanded liquefied natural gas (LNG) imports.Unfortunately, the nation’s supply issues have been complicated by one event that has overshadowed everything else for more than a year and a half.I’m talking about “Brexit,” the British decision to leave the European Union. And the supply issue that followed this landmark decision is creating a major problem for British energy consumers.
Britain at the mercy of Russian gas giants as gas reserves in Europe reach record lows - A cold snap next week could leave the country at the mercy of Russian gas suppliers, experts have warned. Plunging temperatures on Sunday and Monday are likely to send demand for gas soaring across the UK and Europe to heat and light homes. A report from the analysts S&P Platts warns that relying on Russia may be the only option for European nations if they suddenly need more as other suppliers are already running at or near capacity. Gas reserves across the continent are at record lows after cold spells and the closure of British storage facilities. But the report said: ‘Gas demand is set to rise again from the end of the week across north-western Europe, bringing potential large-scale gas withdrawals back into play and prompting a likely increase in nominations for Russian gas imports. ‘Given the surge in demand, Russian gas supplies are considered the only swing source of gas under current conditions. Domestic production and other import sources are effectively maxed out.’ Campaigners fear the growing reliance on imports leaves the UK vulnerable at a time of heightened political tension with Russia in the wake of the row over the poisoning of former double agent Sergei Skripal and his daughter in Salisbury. Official figures suggest only a small proportion of Britain’s gas comes from Russia directly. But many major pipelines across Europe start in Russia. This allows state-backed giants such as Gazprom effective control of European gas supplies.
US gas cargo turns towards UK as Russia spat intensifies - The first tanker of liquefied natural gas to depart a new facility on the US east coast has changed course mid-Atlantic and is heading for the UK. The Gemmata LNG tanker, which left the newly opened Cove Point terminal in Maryland roughly 10 days ago, has turned north east 1,500km off the coast of Suriname and is said to be heading for the Dragon LNG terminal in south Wales. The FT reported this week that of the six LNG tankers that have made deliveries into the UK so far in 2018 three have carried cargoes originally from Russia, leading to questions about whether Moscow was gaining a foothold in the UK gas market after starting up the Yamal LNG facility in Siberia late last year. With tension between the UK and Russia at the highest level since the cold war, following the alleged nerve agent attack by Russia on a former spy in Salisbury, prime minister Theresa May said on Wednesday that “in looking at our gas supplies we are indeed looking at other countries”.
NYMEX Apr natural gas up 1.5 cents at $2.747/MMBtu on lingering cold -- NYMEX April natural gas futures ticked higher in overnight US trading Monday on recent and expected late-season cold. At 7:20 am EDT (1120 GMT) the contract was 1.5 cents higher at $2.747/MMBtu. Colder weather bolstered heating demand to start March. The US Energy Information Administration's latest "Natural Gas Weekly Update" for the week ended March 7 reflects a 2% week-on-week rise in US gas consumption led by a 10% increase in residential/commercial demand attributed to a cool-down throughout much of the country. The National Weather Service sees below-average temperatures holding over most of the Northeast, a small area of the Midwest and nearly the entire West in the six-to-10-day period, then expanding to encompass all of the Northeast, much of the Mid-Atlantic and most of the Midwest in the eight-to-14-day period.
NYMEX Apr natural gas little changed at $2.678/MMBtu as market eyes weather -NYMEX April natural gas futures were little changed in overnight US trading as traders considered changing weather that spells diverging demand patterns. At 6:50 am EDT (1050 GMT) the contract was 0.3 cents lower at $2.678/MMBtu. Below-average temperatures continue to hold over much of the US in the latest projections from the National Weather Service, encompassing the entire eastern third of the US into most of the Midwest and a large section of the West in the six-to-10-day period then shifting in scope to grip nearly the entire northern US and the bulk of the Southwest in the eight-to-14-day period. Average to above-average temperatures span most of the west-central US and the balance of the West in the shorter-range view then settle over the south further out. Although lingering cold in store looks to generate late-season heating demand, higher outright temperatures look likely to limit this.
Platts JKM: Apr LNG cargoes fall on weaker demand; May starts at $7.525/MMBtu -The Platts JKM for LNG cargoes delivery in April ended its assessment period at $8.15/MMBtu Thursday, dropping 55 cents/MMBtu from Friday last week, as warmer weather and weak demand continued to weigh on the market. The Platts JKM for cargoes delivery in May, the new front month, was assessed $7.525/MMBtu Friday. As the market enters the shoulder months, downward pressure mounted with some cargoes heard remaining on offer for H2 April and May delivery. April requirements were heard largely covered and end-users appeared willing to postpone their procurements for better terms, adding downward pressure on the front end of the curve. In Japan, Kansai Electric restarted Ohi No.3 1.18-GW nuclear reactor Wednesday this week and plans to bring another one, Ohi No.2 1.18-GW reactor, online in mid-May. Indonesia's Bontang LNG was heard to have short-listed two April cargoes for potential award, with price level heard at $7.60-$7.80/MMBtu on a FOB basis, subject to government approval, market participants said. The potential loading dates remained unclear but expectations pegged the cargoes to likely be for late-April loading. The sell tender offered zero to one cargo a month between April and June and closed on March 13, with validity until April 11. The status of the remaining cargoes offered in the tender remained unclear.
Exclusive: Vitol targets Southeast Asia's LNG boom with import projects (Reuters) - Vitol is targeting Southeast Asia’s booming liquefied natural gas (LNG) markets to boost sales and catch up with rival commodity traders by developing import projects in Pakistan and Bangladesh. In its biggest potential project, the trader is teaming up with France’s Total on a floating LNG import facility in Port Qasim, Karachi, industry and government sources said. The unusual alliance between the Swiss trade house and oil major shows how emerging markets’ appetite for gas is becoming a focal point for the global LNG industry as it faces years of strong supply growth. Rival trading houses Trafigura [TRAFG.UL] and Gunvor [GGL.UL] are already developing LNG projects in Pakistan and Bangladesh, betting the countries will account for a rising share of future profits and LNG trade. The Vitol-Total project joins around eight other proposed LNG terminals in Pakistan - largely clustered around Port Qasim - vying to tap into a market set to expand five-fold by 2022 to 30 million tonnes per annum. Floating terminals, known as FSRUs, are faster and less costly to set up than traditional land-based units and offer commodity traders a route into new markets, helping to absorb a growing LNG surplus on international markets. FSRU projects tend to cost around $250 million which factors in the full range of costs including chartering, port and pipeline infrastructure. In Bangladesh, Vitol is going it alone to develop a small-scale FSRU alongside the ageing Sangu gas platform in the Bay of Bengal, government officials and industry sources told Reuters. With long-standing oil trading ties in Pakistan, Vitol aims to sell its gas through a nationwide network of 400 retail stations owned by local partner Hascol Petroleum. Pakistan boasts the region’s biggest natural gas-fueled vehicle fleet after China and Iran. A Pakistani official confirmed Vitol and Total were working together after their earlier attempts to join more advanced projects fell through.
Huge Chinese Demand Fuels The Next U.S. Gas Boom - China’s push for cleaner air and fuel is driving an unprecedented demand for natural gas, and the United States is well-positioned to seize this opportunity and export even more of its growing gas production to the thirsty nation. U.S. companies have plans for even more liquefied natural gas (LNG) export trains and facilities to come online in the coming years, and this winter’s surge in Chinese LNG demand and imports underpins a second wave of LNG investment in the United States, analysts and company executives believe. The Chinese push to cut pollution and make millions of households switch to natural gas from coal for heating resulted in China becoming the world’s second-largest LNG importer in 2017, outpacing South Korea and second only behind Japan, the U.S. EIA said last month. Chinese LNG imports surged 46 percent last year. And while China increased its domestic production and pipeline imports last year, it was not enough; natural gas shortages in northern China led to record levels of LNG imports during the winter. Overall, natural gas imports accounted for 40 percent of China’s 2017 natural gas supply, and LNG made up more than half of those imports. True, China is planning to hit an all-time high for natural gas production this year, which includes raising the share of gas in its energy mix—still, domestic production growth will be woefully insufficient compared to its soaring consumption. So, the United States is all too happy to step in to supply part of that demand. Cheniere Energy is one such supplier, which signed last month two long-term deals—through 2043—to supply LNG to China National Petroleum Corporation (CNPC), with the LNG price indexed to the Henry Hub price plus a fixed component.
China data: Jan-Feb crude throughput rises 7.3% on year to 11.6 mil b/d - China's refinery crude throughput rose 7.3% year on year to 93.4 million mt, or an average 11.6 million b/d, over January-February, according to preliminary data released Wednesday by the National Bureau of Statistics. The year-on-year growth over the two months was higher than the increase of 4.3% seen for the same period of 2017, while the total was just below China's record high refinery throughput of 12.08 million b/d last November. As a result of higher crude throughput over January-February, the country's gasoline, jet/kerosene and gasoil production increased 6.4%, 8.8% and 2.4% year on year, respectively, NBS said, without providing detailed numbers. The NBS combines preliminary data for January and February because of the Lunar New Year holiday, which usually falls on one of the two months and lasts seven days. More detailed data from the bureau, including production figures for oil products, is expected to be released in the next few days. According to an S&P Global Platts survey, Chinese state-owned refineries ran at an average rate of around 80% and 84% in January and February, respectively, compared with around 82% and 84% in the same period last year. Although state-owned refineries did not raise their run rates in January and February, the startup of two new units -- PetroChina's 13 million mt/year Yunnan refinery and CNOOC's expanded 10 million mt/year Huizhou phase 2 refinery -- in the second half of 2017 was believed to have pushed up the country's total refinery crude throughput since then. Meanwhile, China's independent refineries in eastern Shandong province ran at an average rate of 67.9% and 67.5% in January and February, respectively, both up more than 11 percentage points year on year, Platts calculations based on data from domestic information provider JLC showed.
Venezuela’s crude oil production declines amid economic instability - Venezuela’s crude oil production has been on a downward trend for two decades, but it has experienced significant decreases over the past two years. Crude oil production in Venezuela decreased from 2.3 million barrels per day (b/d) in January 2016 to 1.6 million b/d in January 2018. A combination of relatively low global crude oil prices and the mismanagement of Venezuela’s oil industry has led to these accelerated declines in production. Several factors indicate that Venezuela’s crude oil production will likely continue to decline. The number of active rigs has fallen from near 70 in the first quarter of 2016 to an average of 43 in the last quarter of 2017. Recent reports indicate that missed payments to oil service companies, a lack of working upgraders, a lack of knowledgeable managers and workers, and declines in oil industry capital expenditures have also contributed to production declines. Venezuela produces extra-heavy crude oil in the Orincoco Oil Belt area and heavily relies on imports of lighter liquids (diluents) to blend with this crude oil to make it marketable. Financial difficulties recently have occasionally prevented the state-owned oil company, Petroleos de Venezuela SA (PdVSA), from importing the necessary volumes of diluent to sustain production and exports.In addition to falling production, refiners in the United States and Asia have reported crude oil quality issues with imported crude oil from Venezuela, resulting in requests for discounts or discontinuation of purchases. In EIA’s Short-Term Energy Outlook, Venezuela’s crude oil production will continue to fall through at least the end of 2019. Crude oil production losses are increasingly widespread and affecting joint ventures. With the reduced capital expenditures, foreign partners are reducing activities in the oil sector. Venezuela’s economy is heavily dependent on the oil industry, and production declines result in reduced oil export revenues. Venezuela’s economy contracted by nearly 9% in 2017, based on estimates from Oxford Economics.
Venezuela’s Meltdown Comes At Convenient Time For OPEC - The pending collapse of Venezuela poses serious short- and long-term challenges for oil markets, but it also contains a silver lining for the OPEC cartel.Venezuelan oil production has been in decline for the past decade, but output has plunged rapidly in recent months as the OPEC member’s political and economic crisis intensifies bringing state oil company PDVSA to its knees. Venezuela production hit a three-decade low of 1.6 million barrels a day in January, down 20% from the same month a year earlier and off a whopping 600,000 barrels a day from its 2016 average of nearly 2.2 million barrels a day.The country’s situation will only get worse.Venezuelan production is likely to fall another 400,000 to 600,000 barrels a day this year – and that assumes President Nicolas Maduro’s beleaguered regime survives. Total collapse of the regime, which the United States could help bring about by imposing tough new sanctions on Venezuela’s oil sector, could see output ground to a complete halt.Much hinges on Venezuela’s presidential elections on May 20. If Maduro uses the election to further consolidate his grip on power, it could prompt Washington to slap the harshest of measures on Caracas. These could include an outright ban on imports of Venezuelan crude, or, more likely, an embargo on U.S. exports of light oil and refined products to the South American country.Venezuela’s woes have been flagged by the International Energy Agency as a major wild card in oil markets this year that have contributed to the recent firming of crude oil prices, which are sitting at comfortable $65 a barrel on the international benchmark. Recent gains by crude have been supported by over-compliance by Saudi-led OPEC with its production cut deal involving non-OPEC producers, including Russia, which has helped tighten supply-demand fundamentals significantly. But much ofOPEC’s stellar compliance lies with Venezuela’s faltering production.
How Will OPEC React To Soaring Shale Production? --OPEC has finally acknowledged what everybody else had concluded some time ago: U.S. shale output is soaring. In its March Oil Market Report, OPEC revised up its forecast of non-OPEC supply for 2018 by 280,000 bpd, a major revision. That equates to year-on-year growth of 1.66 million barrels per day (mb/d). The group couched the change in boring technical jargon, noting that “the upward revision is mainly due to higher-than-expected output in 1Q18 by 360 tb/d in OECD (Americas and Europe), FSU and China.” But make no mistake, OPEC is conceding that U.S. shale is surging, which complicates the cartel’s calculations for rebalancing the oil market.Crucially, the forecast now acknowledges that oil supply will outpace demand this year, a conclusion that the IEA had been predicting for a few months.The trend is worrying for OPEC. The effects of the production cuts of 1.2 mb/d (plus nearly 0.6 mb/d from Russia and other minor partners) had little effect in early 2017, likely because of the ramp up in production and exports just prior to the implementation of the deal.However, as 2017 wore on, the cuts started to really bite. Inventories plunged toward the end of last year, tightening the market and forcing up oil prices. Some analysts have even predicted that the oil market could already be rebalanced.The IEA was an early spoilsport, however, predicting at the start of 2018 that despite the run up in prices, inventories would start climbing again in the first half of the year. In January, oil traders shrugged off this bearish assessment, driving Brent up to $70. From there, the rally stalled, and U.S. shale began to take off again, pushing prices back down. In subsequent weeks, the forecasts for U.S. shale growth have been ratcheted up leaps and bounds, and the expected strong gains in output from shale have transformed into expectations of a tidal wave of new supply that will push U.S. production over 11 mb/d by the end of this year. Most analysts have since followed in the IEA’s footsteps and offered their own takes on how fast U.S. shale would grow. OPEC is just getting around to acknowledging this fact. OPEC now says that global oil demand will rise by 1.6 mb/d this year, which will be more than offset by a global supply increase of 1.66 mb/d. Ultimately, this means that a little less OPEC production will be needed. The group revised down the need for its production by 200,000 bpd for 2018.
Is OPEC moving the goalposts for its oil market scoreline? (Reuters) - Saudi Arabia’s proposals of new metrics to determine when the oil market is balanced signals a shift in OPEC’s targets for a pact on supply cuts that has almost achieved the initial aim of reducing bloated inventories. The Organization of the Petroleum Exporting Countries, Russia and nine other producers cut output from January 2017 by 1.8 million barrels per day (bpd) with the aim of reducing crude stocks in industrialized OECD nations to the five-year average. From a record 3.1 billion barrels in July 2016, OECD stocks dropped to 2.851 billion barrels in December, falling 216 million barrels during 2017 and now stand just 52 million barrels above the five-year average, International Energy Agency (IEA) data show. OPEC and its allies have been helped because the five-year average is a moving target and has risen even as output curbs were in place. The average climbed to 2.86 billion barrels in September 2017 from about 2.73 billion barrels when the supply pact was sealed in late 2016. “After a period of surplus, the target becomes easier over time as more surplus years are included,” said Standard Chartered head of commodities research Paul Horsnell. But as the OECD inventory target has shifted so has thinking in Saudi Arabia, the world’s biggest oil exporter that worked with Russia to forge the global pact on cutting supplies. Saudi Energy Minister Khalid al Falih says OPEC and its partners should look at metrics such as non-OECD inventories, oil in floating storage and crude in transit as they consider the future of the pact that is due to expire at the end of 2018. Those measures, however, are more difficult to monitor. Non-OECD oil demand has outstripped OECD consumption since 2014. But inventories in non-OECD nations tend to be held as strategic not commercial assets, making them less transparent and less likely to shift with changes to demand or supply.
The OPEC Deal Could Fall Apart In June - OPEC’s oil production cut agreement could start falling apart soon, as Saudi Arabia and Iran once again face off. This time, however, the spat is over determining what the best price level is for the commodity. That’s what Iran’s Oil Minister Bijan Zanganeh told the Wall Street Journal in an interview. The split, apparently, stems from Saudi Arabia’s insistence that crude oil should be kept closer to US$70 a barrel - a level Brent touched briefly early this year - and Iran’s equal insistence that US$60 is a better place for oil to trade at.This disagreement could see the cartel start unwinding the cuts as early as June, when it will meet with its partners to discuss progress and next steps. Zanganeh’s explanation of the Iranian stance is anything but a surprise: “If the price jumps [to] around $70 ... it will motivate more production in shale oil in the United States,” he told the WSJ.Zanganeh is not wrong, but the problem is that U.S. drillers have demonstrated that they could pump more at US$60 a barrel, too, so bringing prices closer to that level is not a guaranteed way to stymie U.S. oil production growth. Production has been growing steadily, last week hitting 10.37 million bpd. The oil production in the United States is not the only problem. The bigger problem is soaring U.S. exports that are eating away the market share of OPEC members. This could be the last drop to swing OPEC in Iran’s favor.Bloomberg quoted an ING analyst yesterday as saying that crude could fall below US$60 a barrel because of rising U.S. exports to Asia, a key market for every producer. The OPEC deal is under threat, ING commodities strategist said, because U.S. crude supplies are displacing OPEC’s. “The longer the deal goes on, it’s going to start falling apart. They continue to give market share away to the U.S.”
Hedge funds resume liquidating bullish oil positions: Kemp - Hedge funds and other money managers cut their combined net long position in the six most important futures and options contracts linked to petroleum prices by 50 million barrels in the week to March 6. The reduction largely reversed an increase of 68 million barrels the previous week, according to position records published by regulators and exchanges (http://tmsnrt.rs/2DmlwXg). Portfolio managers have now reduced their net long position in petroleum in five of the last six weeks by a total of 245 million barrels since Jan. 23.The most recent week saw a reduction in net length in NYMEX and ICE WTI (-17 million barrels), Brent (-5 million), U.S. gasoline (-10 million), U.S. heating oil (-5 million) and European gasoil (-13 million).Some of the froth has blown off the market in the last six weeks but the hedge fund community still has a very bullish bias towards oil prices. Fund managers hold a net long position in the six major petroleum contracts amounting to 1,239 million barrels of oil, a level of bullishness that had never been seen until four months ago. Long positions still outnumbered short positions by a ratio of 10:1, down from a peak of almost 12:1 in January, but again a level of bullishness that was unprecedented until this year. With so many long positions already established, and few remaining short positions to cover, oil prices have struggled to rise further in recent weeks.Instead the market has seen a slow but steady liquidation with existing longs cut by a total of almost 250 million barrels (15 percent) since Jan. 23.
How tight oil changed global petroleum pecking order --Times of India - A recent International Energy Agency report has said the US will account for most of the world's growth in oil supply in coming years. American output was at a record 10 million barrels a day November last, and expected to exceed 11 million this year. Here's how US became a big oil producer: Contrary to popular notions, only two of the world's five largest oil producers are from West Asia. The US, Canada and Russia make up the Big 5 of petroleum producers and the US is expected to overtake both Russia and Saudi Arabia in oil production in 2018. Wars in Iraq and Libya in late 2000s, and the West's sanctions on Iran took away millions of barrels of crude from the market. That pushed its price to over $100 a barrel. The price shock came as a boon for US shale (tight oil). Unlike conventional production methods for oil wells, where break-even is much lower, shale oil companies require a certain threshold. This impetus came from the high crude prices, leading to US's shale oil boom. Oil extraction by fracking is highly controversial because of the adverse environmental impact, including ground- and surface-water contamination, and air and noise pollution. There is tremendous opposition to extraction of oil by this method in other countries. Critics point out that the environmental impact far outweighs economic benefits.
Oil prices settle lower as EIA data point to further gains in U.S. shale output - Oil futures settled lower Monday, as the latest data fed expectations that U.S. output will continue to rise this year, erasing some of the price gains scored late last week on a lower weekly U.S. oil-rig count. April West Texas Intermediate crude lost 68 cents, or 1.1%, to settle at $61.36 a barrel. The contract on Friday jumped over 3% to settle at $62.04 a barrel on the New York Mercantile Exchange, turning what would’ve been a weekly loss into a climb of roughly 1.3% from the week-ago settlement. May Brent crude fell 54 cents, or 0.8% to $64.95 a barrel. The contract rose 3% Friday, to end at $65.49 a barrel on the ICE Futures Europe exchange—up 1.7% for the week. Both WTI and Brent as recently as Thursday had marked their lowest settlements since mid-February. Crude production from seven major U.S. shale plays is expected to see a climb of 131,000 barrels a day in April to 6.954 million barrels a day, according to a monthly report from the Energy Information Administration released Monday. “The big take away is the implied annual rate of change,” James Williams, energy economist at WTRG Economics, told MarketWatch. “In the shale plays, the expected April production will increase oil at the annual rate of 1.5 million” barrels a day.Williams also pointed out that based on the figures, U.S. shale plays this year will “add enough to U.S. production to match all the oil Venezuela currently produces.”The report followed data from the EIA last week, which showed an increase of 86,000 barrels a day in total U.S. crude output for the week ending March 2. “That figure was close to in line with the February average weekly increase of 91,000 [barrels a day] and is still more than four times greater than the pace of production growth in 2017,” said Tyler Richey, co-editor of the Sevens Report.
Crude oil futures markets await OPEC and IEA monthly reports -- Crude oil futures were slightly lower at midday in Europe Monday as the market awaited signals from the release of monthly reports from OPEC on Wednesday and the International Energy Agency Thursday. At 1129 GMT, May ICE Brent crude futures were down at $65.17/b, while the NYMEX April light sweet crude contract was lower at $61.79/b. "The inventory data will have some sort of effect but nothing major is scheduled that will really rock the boat," Global Risk Management's Michael Poulsen said. The next trigger for the industry will be the OPEC meeting on June 22 in Vienna, giving the market direction as to whether the existing production cuts will continue into 2019, Poulsen said. Should the cuts be eased, as suggested by Iranian oil minister Bijan Zanganeh to the Wall Street Journal over the weekend, that would curb the profitability for shale producers, lowering shale output. "If the price jumps [to] around $70/b, it will motivate more production in shale oil in the United States," Zanganeh told the WSJ, adding Iran would prefer an oil price of about $60/b.
Oil prices fall on relentless rise in US crude output (Reuters) - Oil prices fell on Tuesday, extending losses from the previous session, as the inexorable rise in U.S. crude output weighed on markets. . West Texas Intermediate (WTI) crude futures were at $61.25 a barrel at 0414 GMT, down 11 cents, or 0.2 percent, from their previous close. Brent crude futures were at $64.85 per barrel, down 10 cents, or 0.2 percent. Both crude benchmarks dropped by around 1 percent in their Monday sessions. “Oil prices fell on the back of concerns that surging U.S. production ... could push inventories in the U.S. higher,” ANZ bank said on Tuesday. U.S. crude oil production C-OUT-T-EIA soared past 10 million barrels per day (bpd) in late 2017, overtaking output by top exporter Saudi Arabia. U.S. production is expected to rise above 11 million bpd by late 2018, taking the top spot from Russia, according to the International Energy Agency (IEA). The rising U.S. output comes largely on the back of onshore shale oil production. U.S. crude production from major shale formations is expected to rise by 131,000 bpd in April from the previous month to a record 6.95 million bpd, the U.S. Energy Information Administration (EIA) said in a monthly report on Monday. “Oil prices moved lower ... after (the) Energy Information Administration published a report that crude production from seven major U.S. shale plays is expected to see a climb,” said Stephen Innes, head of trading for Asia/Pacific at futures brokerage OANDA in Singapore. That expected increase would top the 105,000 bpd climb in March from the previous month, to what was then expected to be a record high of 6.82 million bpd, the EIA said.
US shale oil will surge to nearly 7 million barrels a day in April - American shale drillers will take aim at the seven million barrels-per-day mark next month, as U.S. oil production continues to hit new record highs. Output from the nation's shale oil regions is poised to grow by 131,000 barrels a day next month, according to the U.S. Department of Energy's statistics arm. The Energy Information Administration sees drillers in the seven shale regions pumping 6.95 million barrels a day in April, up more than 25 percent from a year ago. April's forecast got a boost from upward revisions to EIA's projections for previous months. The Permian Basin in Texas and New Mexico will see production jump by 80,000 barrels a day, according to EIA's outlook. The basin remains the biggest driver of a recovery in U.S. shale output that began in late 2016. The Eagle Ford shale, also in Texas, is seen kicking in 23,000 barrels a day towards the regions' growth. Meanwhile, North Dakota's Bakken shale and the Niobrara region in Colorado and surrounding states will each grow output by 12,000 barrels a day, EIA projects. Drillers across these regions use advanced technology like hydraulic fracturing and horizontal drilling to fracture rock formations and extract oil and gas from the basins.
March Madness Starts Early As Oil Price Fall On Relatively Light Volume -- March Madness started early in oil as prices fell on relatively light volume and focused on bearish news about ignoring bullish news at its own peril. Traders sold oil off on a report that showed an increase in supply in Cushing Oklahoma, but it is about time. The Nymex Storage hub has seen supply fall at a record pace in recent weeks and seeing that we are deep into refinery maintenance we should start to see the supply recover. Yet, they ignored a report about global oil inventory tightening. According to a report, OECD oil inventories for the first time in 3.5 years have fallen below normal because of a massive inventory draw of 46 million barrels in February which is 6 times the normal draw rate. The global oil balance remains in a sharp deficit despite gains in U.S. production. Oil bears have been bearish on hopes of rising shale production but what we are finding that light shale oil is not what refiners want. A must read in The Financial Times reports “In the oil market, not all barrels are created equal. “The issue, critics say, is that U.S. shale is far lighter — having been released through narrow fissures in rocks by hydraulic fracturing — than gloopy tarry crudes most people think of when they picture a barrel of oil. This has potentially huge implications because refiners, who turn crude into usable products, have spent decades investing in plants capable of processing far heavier oils that were once expected to dominate supply. The lighter shale barrels, some say, are just not as good for making the products — especially diesel, jet fuel and other so-called middle distillates — that the world increasingly needs.” They warn of a potential crunch in years to come caused not by an outright shortage of crude, but by refiners scrambling to compete for more conventional barrels as U.S. shale is found wanting. This is another reason why we have warned not to put too much trust in shale. Shale oil is giving bears a false sense of security while we are seeing the demand for diesel rise and supply stay below normal. So, when we talk about global inventory we must remember that some of those lighter grades may not get used. It may give us an overinflated view of oil storage, meaning that supply is tighter than many thinks.
Crude Oil Prices Turn Higher Ahead of API Report - Crude oil prices turned higher on Tuesday, as investors turned their attention to this week's U.S. supply reports, although ongoing concerns over U.S. production levels continued to weigh. The U.S. West Texas Intermediate Crude Oil WTI Futures April contract was up 50 cents or about 0.81% at $61.86 a barrel by 03:35 a.m. ET (07:35 GMT), off session lows of $60.80. Elsewhere, Brent oil for May delivery on the ICE Futures Exchange in London advanced 58 cents or about 0.89% to $65.53 a barrel. Oil prices initially came under pressure after the International Energy Agency (IEA) said in its monthly report on Monday that U.S. crude oil production jumped above 10 million barrels per day (bpd) at the end of 2017, overtaking output by top exporter Saudi Arabia. The IEA also said that U.S. production is expected to rise above 11 million bpd by late 2018, outpacing Russia. Separately, the U.S. Energy Information Administration (EIA) said that U.S. shale production is expected to rise by 131,000 bpd in April from the previous month to a record 6.95 million bpd. That would top the 105,000 bpd climb in March to what was then expected to be a record high of 6.82 million bpd. Fears that rising U.S. output could dampen global efforts to rid the market of excess supplies persist. The Organization of the Petroleum Exporting Countries (OPEC), along with some non-OPEC members led by Russia, agreed in December to extend oil output cuts until the end of 2018. Elsewhere, gasoline futures gained 0.41% to $1.904 a gallon, while natural gas futures were up 0.32% to $2.785 per million British thermal units.
WTI/RBOB Rise After Smaller Than Expected Crude Build - Anxiety over Rexit and growing concerns that global demand might not absorb swelling US supplies sent WTI/RBOB notably lower today but prices rebounded modestly after API showed notable product draws and smaller than expected crude build. “The EIA report yesterday about the expected increase in shale output next month certainly weighed on things,” John Kilduff, founding partner at Again Capital, said in a phone interview to Bloomberg. API:
- Crude +1.156mm (+2.5mm exp)
- Cushing -155k (unch exp)
- Gasoline -1.262mm
- Distillates -4.258mm - biggest draw since Oct 2017
12th week in a row of Cushing stock declines but what was notable was a smaller than expected crude build and sizable product draws... WTI/RBOB prices lifted off the day's lows after the API data...
Uncertainty Grips Oil Markets Ahead Of EIA Report -- Oil prices were flat on Monday before rising and falling on Tuesday morning. The uncertainty in markets is sure to continue as analysts await more direction from the upcoming EIA weekly data release. The dip in the rig count last week provided a jolt on Friday, but concerns about surging U.S. shale supply continue to linger. President Trump’s decision to fire Sec. of State Rex Tillerson and replace him with current CIA Director Mike Pompeo caught the world (and Rex Tillerson) by surprise. The move is significant because Trump specifically cited his disagreement with Tillerson over the Iran nuclear deal as a key reason in the former Exxon CEO’s ouster. Replacing him with Mike Pompeo does not bode well for the nuclear deal, as Pompeo is a notorious hawk vis-Ã -vis Iran. The move increases the odds of confrontation between the U.S. and Iran, although Pompeo still needs to be confirmed by the Senate. . With U.S. oil production soaring, more of that oil will be exported. Some of it will head to Asia, where it will edge out OPEC for market share. This trend could begin to undermine the resolve of OPEC to continue the production cuts, according to ING Groep NV. “The longer the deal goes on, it’s going to start falling apart,” Warren Patterson, commodities analyst at ING, told Bloomberg. “They continue to give market share away to the U.S.” BP and Shell said that they have seen improved performances from legacy oil fields, which typically suffer from steeper decline rates. The IEA estimates that overall, the decline rate at mature fields was 5.7% last year, the lowest in a decade. The better performance comes as the industry tries to become more efficient at existing operations. “Companies are focusing on the basics,” Wael Sawan, executive vice-president for deep water at Shell, told Bloomberg. “So there was a massive re-focus on existing wells. It’s the cheapest and most profitable barrel that companies can access.”
Oil market shrugs off rising threat to Iran deal: Kemp - (Reuters) - President Donald Trump's decision to replace his secretary of state with a more hawkish figure should have been bullish for oil prices since it increases the probability the nuclear deal with Iran will be abandoned in May. Failure to recertify the deal could lead to the re-imposition of secondary sanctions and pressure from the United States on other countries to reduce their purchases of Iranian crude again. But the decision to replace the secretary of state barely registered on the spot price of Brent crude and the six-month calendar spread continued to soften, suggesting that traders see little impact for the moment. In theory, failure to recertify could remove hundreds of thousands of barrels of crude from the market and cause a significant tightening of the supply-demand balance. For the time being, however, the Trump administration's increasingly hawkish position on Iran has not been enough to offset the impact of increasing supply from shale. Crude traders may be under-estimating the president's determination to end what he has termed a "terrible" deal and ratchet up the pressure on Iran. But the president and his new secretary of state, assuming the nominee is confirmed by the U.S. Senate, will still face the same diplomatic constraints in ending the deal and renewing the boycott of Iranian oil. European countries, including Britain, France and Germany, are no more eager than before to abandon the nuclear deal or re-impose broad economic sanctions. Russia is also unlikely to cooperate since relations and cooperation with the United States are at the lowest ebb since the end of the Cold War. And the United States has embarked on a trade war with China, which is further complicating a relationship already beset by multiple other disputes. In the circumstances, traders may have concluded even a failure to recertify the deal will not lead to the removal of a significant amount of crude from the market. They may also have concluded any loss of crude from Iran would be made up by increased production and exports from Saudi Arabia, Kuwait, the United Arab Emirates, Iraq and Russia.
WTI Down, RBOB Up After Huge Gasoline Draw, Crude Build, Record Production - WTI/RBOB prices held gains from last night's smaller-than-expected crude build from API, but prices action was mixed after DOE reported a bigger than expected crude build and bigger than expected gasoline draw (as production hit a new record high).Bloomberg Intelligence's Valle notes that maintenance season for refiners will deplete gasoline inventories over the coming weeks as the plants open space for summer components. Despite an improving outlook for demand, crack spreads haven't meaningfully recovered after falling more than $1.20 a barrel over the past month, though they may recoup some of their losses in coming weeks. Demand is up 3% in 2018 vs. the five-year average.“The oil market is more fragile than it seems,” said Norbert Ruecker, head of commodity research at Julius Baer Group Ltd. in Zurich. “Demand growth is strong, but supply is catching up.” DOE:
- Crude +5.022mm (+2.25mm exp)
- Cushing +338k (unch exp) - first build since Dec 2017
- Gasoline -6.27mm - biggest draw since Sept 2017
- Distillates -4.36mm - biggest draw since Oct 2017
Some stunning numbers here with a much bigger than expected crude build as products saw a huge draw (and Cushing stocks actually increased for the first time this year)... Bloomberg does have one major concern. Javier Blas issues a "statistical warning"... The EIA is again running a huge adjustment factor to hammer down its supply, demand, and stocks balance sheet into place. The adjustment was last week positive to the tune of 605,000 b/d (the only second time in 10 years the adjustment factor is positive by more than 600,000 b/d). The previous week, the adjustment was -570,000 b/d.
Oil Prices Rise on Falling Fuel Inventory -- Oil prices rose Wednesday, recovering from losses in earlier trading as a drop in fuel stockpiles outweighed larger-than-anticipated increase in crude inventories and relentlessly rising U.S. production.Light, sweet crude for April delivery rose 25 cents, or 0.41%, to $60.96 a barrel on the New York Mercantile Exchange. Brent, the global benchmark, rose 25 cents, or 0.39%, to $64.89 a barrel on ICE futures Europe.U.S. crude futures initially tumbled after the U.S. Energy Information Administration reported that inventories of crude oil rose by 5 million barrels—double what analysts surveyed by The Wall Street Journal had anticipated, and significantly more than the 1.2 million-barrel build reported by industry group the American Petroleum Institute on Tuesday. But on the positive side for oil prices, consumers soaked up large amounts of fuel. Gasoline stockpiles dropped by 6.3 million barrels and diesel stockpiles fell by 4.4 million barrels—outpacing the drops analysts had been expecting. Gasoline futures rose 3.8 cents, or 2.01%, to $1.9243 a gallon. Diesel futures rose 1.32 cents, or 0.7%, to $1.8871 a gallon. The oil market continued to be caught between rising U.S. output and efforts by the Organization of the Petroleum Exporting Countries and other major producers to cut output. The EIA reported that U.S. production continued its relentless march higher, rising by 2 million barrels a day to yet another weekly record of 10.38 million barrels a day.The International Energy Agency and the EIA have both recently revised their U.S. oil production forecasts higher. Output has been helped by the 25% rise in oil prices over the past year, along with improvements in efficiency and technology. OPEC crude production continued to fall in February, dropping by 77,000 barrels a day compared with the prior month, to average 32.19 million barrels a day, the cartel said Wednesday in its closely watched monthly oil market report. But the group said total global oil supply rose last month, in a sign that U.S. shale production is undermining Saudi efforts to rebalance the market.In an unusual news release Wednesday, Saudi Arabia’s national oil company said it would continue cutting crude oil production, signaling its commitment to a production cap agreement after Iran called for gradually lifting output curbs.
Oil edges up but rising crude supply checks gains (Reuters) - Oil prices edged higher in choppy trade on Thursday after the International Energy Agency said global oil demand is expected to pick up this year, but warned supply is growing at a faster pace. Prices notched their second consecutive day of gains, as West Texas Intermediate (WTI) crude CLc1 futures rose 23 cents to settle at $61.19 a barrel, a 0.4 percent gain. Brent crude LCOc1 futures rose 23 cents to settle at $65.12 a barrel. Rising global oil demand, along with supply constraints from the Organization of the Petroleum Exporting Countries, has helped keep oil above $60 a barrel. The IEA said global crude demand would pick up this year, which was “reassuring” to investors. However, the IEA also noted rising supply, limiting crude gains. The IEA believes non-OPEC supply, led by the United States, will grow by 1.8 million bpd this year, while demand will grow by about 1.5 million bpd. The relentless climb in U.S. crude output C-OUT-T-EIA has loomed over markets, as production hit another record last week at 10.38 million bpd. OPEC on Wednesday raised its forecast for non-member oil supply this year to almost double the growth predicted four months ago. OPEC and other producers led by Russia began cutting supply in January 2017 to erase a global crude glut that had built up since 2014. This has been somewhat offset by surging U.S. crude production. Prices bounced around after the United States announced new sanctions against Russian individuals and groups, including Moscow’s intelligence services and a Russian propaganda organization. “The rising tensions between the West and Russia raise the potential for reduced trade flows and economic activity, which would diminish energy demand growth,” Prices were supported in the morning by a pickup on Wall Street, but U.S. stocks retreated throughout the day. The Dow Jones Industrial Average was still up about 0.5 percent, but the S&P 500 edged lower.
Oil price volatility at lowest since before the slump: John Kemp (Reuters) - If the oil market has felt unusually quiet in recent weeks and months, that probably reflects the almost complete lack of sharp daily price movements. While prices have soared by more than 40 percent since the middle of 2017, day-to-day volatility has fallen to its lowest level since 2014, with a relatively smooth and orderly upward adjustment in prices. Short-term volatility has been trending downwards since early 2016 and in January fell to its lowest since August 2014 (http://tmsnrt.rs/2FFcbQp). The 20-day standard deviation of daily price moves expressed at an annualised rate -- one common measure of volatility -- dropped to only 13 percent in January from 80 percent almost two year earlier. Volatility in early and mid-January was in the bottom fifth percentile for any 20-day period since the start of 1990. The relatively sharp drop in oil prices at the start of February has since pushed volatility slightly higher, at least temporarily, but even that decline was relatively smooth. Volatility is still only in the 28th percentile of the post-1990 distribution and is set to decline again if the market’s more recent calm is sustained. There have been no significantly large daily price movements in Brent, up or down, since June 2017, which was the last time there was a daily move exceeding 2 standard deviations. The last really abnormal price move, exceeding 3 standard deviations and nearing 4, was all the way back in November 2016, when OPEC announced that it had reached agreement on cutting production.
Bearish News Fails To Subdue Oil Prices -- OPEC acknowledged this week that U.S. shale production was rising quickly, and suggested that supply growth would surpass demand this year. Trump’s recent tariffs have created fears of a global trade war, inventory declines have slowed and the rig count has risen once again. Despite all this bearish news, oil prices jumped on Friday, with WTI breaking above $62 and Brent nearing $66. Saudi Arabia dismissed concerns of a fraying OPEC deal, stating that the country would remain committed to the production limits this year. The response came after the Iranian oil minister suggested his country wanted to ramp up production, sparking speculation that the OPEC deal could begin to suffer, but Saudi Aramco said on Wednesday that its output would remain below 10 million barrels per day (mb/d). “Saudi Arabia continues to lead by example by producing below the production targets it agreed to,” the Saudi energy ministry said in the news release. That statement was unusual because the company typically does not publish what it will produce ahead of time. The U.S. EPA chief Scott Pruitt indicated that the agency would battle with California over the state’s tighter fuel efficiency requirements for passenger vehicles. The EPA has an April 1 deadline to decide whether or not it wants to try to revise Obama-era fuel efficiency standards for cars and light trucks for model years 2022-2025. California has often led the nation in such standards, which have been credited with dramatically improving the efficiency of the nation’s auto fleet and slowing the growth of gasoline consumption.
Oil prices set for weekly drop as concerns about rising supply - (Reuters) - Oil prices were set to fall this week, with both benchmarks dropping slightly on Friday, on concerns among investors about rising supply from the U.S. and other nations threatening to undermine efforts by OPEC and other producers to tighten the market. West Texas Intermediate (WTI) oil futures for April delivery fell 3 cents, or 0.1 percent, to $61.16 a barrel at 0354 GMT, after settling up 23 cents on Thursday. WTI is set to fall 1.4 percent this week, reversing the previous week's 1.3 percent gain. Brent crude futures trading in London fell 7 cents to $65.05 a barrel after settling up 23 cents. Brent is down 0.7 percent for the week. Several reports this week renewed investor focus on the potential for rising supply to overwhelm the expected gains in crude demand for 2018. On Thursday, the International Energy Agency (IEA) said global oil supply increased in February by 700,000 barrels per day (bpd) from a year ago to 97.9 million barrels per day. The IEA also said supply from producers outside of the Organization of the Petroleum Exporting Countries (OPEC), led by the United States, will grow by 1.8 million bpd this year versus an increase of 760,000 bpd last year. The supply increase is more than the IEA's expected demand growth forecast for this year of 1.5 million bpd. The agency also reported that commercial oil inventories in industrialized nations rose in January for the first time in seven months. That directly undermines the efforts of producers led by OPEC and Russia, the world's biggest oil producer, to cut supply in order to reduce global stockpiles.
Oil Prices Rise Despite Climbing Rig Count | OilPrice.com - Baker Hughes reported another 6-rig increase to the number of oil and gas rigs this week. The total number of oil and gas rigs now stands at 990, which is an addition of 201 rigs year over year.The number of oil rigs in the United States increased by 4 this week, for a total of 800 active oil wells in the U.S.—a figure that is 169 more rigs than this time last year. The number of gas rigs rose by 1 this week, and now stands at 189; 32 rigs above this week last year.The oil and gas rig count in the United States has increased by 66 in 2018.Canada continued its severe losing streak, with a decrease of 54 oil and gas rigs on top of last week’s loss of 29 oil and gas rigs. Canada now has 57 fewer rigs than it did a year ago. Oil prices managed to climb this last week and were up today without any clear catalyst. What is clear is that while the threat of steel tariffs and strong U.S. crude oil production, which rose again in the week ending March 09 to 10.381 million bpd, seems to be limiting gains, there are insufficient catalysts to bring oil prices down.At 12:28 pm EST, the price of a WTI barrel was resilient, trading up $0.98 (+1.60%) to $61.84—a ~$.30 increase over last week’s prices. The Brent barrel was also trading up on the day, by $0.84 (1.29%) at $65.78—an increase of about $0.40 over last week’s level. At 1:07pm EST, both benchmarks had gained ground, with WTI trading at $62.29 (+$1.10) and Brent trading at $65.88 (+$0.93).
Baker Hughes: US rig count gains 6 units to 990 - The US drilling rig count gained 6 units to 990 working during the week ended Mar. 16, data from Baker Hughes indicate. This total is up 201 units from a year ago.Offshore units were unchanged from last week with 13 rigs working in the Gulf of Mexico. A total of 973 rigs were drilling on land, up 6 from last week. The number of rigs drilling in inland waters was unchanged at 4 units.Rigs targeting oil were up 4 units to 800 and also up from the 631 rigs drilling for oil this week a year ago. Gas-targeted rigs were up 1 unit to reach 189. This time a year ago, 157 units were drilling for gas.Among the major oil and gas-producing states, Oklahoma saw the largest increase in rigs week over week with a 4-unit gain to reach 124 rigs working. North Dakota, at 53 units this week, was up 3. Texas was up 2 units this week to 492. New Mexico, Ohio, West Virginia, and Arkansas were each up 1 unit to respective counts of 88, 23, 17, and 1. California and Utah, at respective counts of 14 and 9, were both unchanged this week. Louisiana, at 57, and Wyoming, at 30, were down 1 unit each. Pennsylvania, Colorado, and Alaska were all down 2 rigs to respective counts of 40, 29, and 7. Canada lost 54 rigs to 219 working from a week ago. There are 57 fewer rigs working than this week a year ago. Oil-directed rigs decreased 52 units this week to 144, while those targeting gas fell 2 units to 75.
WTI Suddenly Spikes Above $62 | Zero Hedge - WTI Crude futures just suddenly spiked above $62 (with no obvious news catalyst)... Bloomberg points to today's gains (pre-spike) as being driven by investors weighing surging U.S. crude production against a warning from the International Energy Agency of an impending shortfall in global supplies.“The market is probably less concerned about the rise in U.S. oil production because the global economy is doing quite well, so there is demand for the additional oil,” said Jens Pedersen, senior analyst at Danske Bank A/S.“It seems like oil has found its feet following a volatile start to the year.”But this is not the first sudden spike to run stops above $62.. “When the market falls into sideways trading in a band, you get a lot of price fluctuations that you have to turn a blind eye to,” s ays Gene McGillian, a market research manager at Tradition Energy in Stamford, Conn. Perhaps of note is the 50-day moving average is at $62.61 (which would run the stops above this week's highs). RBOB and Energy stocks are also spiking... And Breakevens have picked up as oil spikes...
Oil prices jump, Brent hits highest in more than 2 weeks - (Reuters) - Oil prices jumped on Friday, with Brent crude futures hitting their highest in more than two weeks as U.S. stock prices rose and investors covered short bets ahead of a weekend in which the U.S. news program “60 Minutes” will air an interview with Saudi Arabia’s crown prince. Saudi Crown Prince Mohammed bin Salman will be on “60 Minutes” on Sunday “comparing Iran’s Ayatollah to Hitler, and the battle in Ghouta, Syria, is ramping up,” sa “You can’t be short oil over the weekend with all that going on in the region.” Brent futures rose $1.09 to settle at $66.21 a barrel, a 1.7 percent gain. During the session, Brent hit $66.42, its highest since Feb. 28. U.S. West Texas Intermediate (WTI) crude futures for April, which will expire on Tuesday, rose $1.15 to settle at $62.34 a barrel, a 1.9 percent gain. WTI hit a high of $62.54, its highest since March 7. Brent futures gained 1 percent for the week, while WTI marked a weekly rise of 0.4 percent. It was the second straight weekly rise for both contracts. Gains on Wall Street also supported crude futures, which have recently been moving in tandem with U.S. stock indices. Hedge funds and other money managers cut their bullish bets on U.S. crude oil futures and options in the week to March 13, as crude prices fell for a second week, the U.S. Commodity Futures Trading Commission (CFTC) said. The speculator group cut its combined futures and options position in New York and London by 24,667 contracts to 453,864 during the period. The cuts marked the second consecutive week in which speculators cut their net long positions in the market. U.S. drillers added four oil rigs this week, bringing the total count to 800, General Electric Co’s Baker Hughes energy services firm said. It was the seventh U.S. rig count rise in eight weeks. On Thursday the International Energy Agency (IEA) predicted global oil demand would pick up this year, but supply is growing at a faster pace, which should boost inventories. The agency raised its forecast for oil demand this year to 99.3 million barrels per day (bpd) from 97.8 million bpd in 2017, and said it expected supply from non-OPEC nations to grow by 1.8 million bpd in 2018 to 59.9 million bpd, led by the United States.
OPEC Feb oil output 32.19 mil b/d, down 80,000 b/d from Jan: secondary sources - Months of confidence that global demand growth in 2018 will amply absorb any increases in non-OPEC supply appear to have finally eroded, with OPEC's analysis arm on Wednesday issuing its first mildly bearish outlook for the year. In its closely watched monthly oil market report, OPEC projected a year-on-year rise of 1.66 million b/d in non-OPEC supplies in 2018, while demand is seen increasing by 1.60 million b/d. This is the first report since OPEC began forecasting 2018 figures in July 2017 that its estimate of non-OPEC supply growth has exceeded its prediction of global demand, and it indicates that the bloc will have to maintain its production discipline if it wants the market's rebalancing to continue, though continued declines in Venezuelan output provide some cushion for other members. Non-OPEC supply in 2018 "is now expected to grow at a faster pace," the report stated, and will average 59.53 million b/d, a 280,000 b/d upward revision from last month's forecast, largely due to an increase in forecast US output. The report noted that oil prices over the past few months have been higher than they have been in more than two years "For 2018, higher growth is expected on the back of the projected increase in US shale production following a better price environment, not only for shale producers, but also for other countries, such as Canada, UK, Brazil and China," the report said. Global demand will hit 98.63 million b/d in 2018, a 30,000 b/d upward revision from February's report as OPEC continues to see healthy economic growth driving greater consumption, though it warned that rising interest rates and the recent decision by the US to impose steel and aluminum tariffs could dampen that momentum.Demand for OPEC crude will average 32.61 million b/d in 2018, the organization calculated, a 200,000 b/d decrease from last month's projection. Assuming OPEC keeps its production at the 32.19 million b/d in February as estimated by secondary sources used to track output independently in the report, the market will tighten significantly in the second half of the year, following stock builds in the first half. OECD commercial oil inventories rose 13.7 million barrels in January and remain 50 million barrels above the five-year average, OPEC estimated. The stocks represent 60.0 days of forward cover, 0.6 days lower than the five-year average.
Saudis To Join The Fracking Revolution - Saudi Arabia, the world’s third largest oil producer, plans to further its fossil fuel industry and invest in unconventional natural gas production, Bloomberg reported. Saudi Arabia’s state-owned oil giant Saudi Aramco will spend $300 billion over the next decade to boost natural gas exploration and production while maintaining spare oil production capacity. Part of the money will fund fracking projects in a shale field comparable to Texas’ Eagle Ford Shale — the most invested in oil and gas development in the world. Aramco General Manager of Unconventional Resources Khalid Al Abdulqader said Wednesday Saudi shale supplies are “huge.” Production will begin this month and hit target capacity by 2018’s end, Abdulqader said. The target capacity Saudi Arabia is aiming for is unclear, according to Bloomberg.Saudi Arabia has been trying to diversify its energy production for years in order to curb its reliance on oil while freeing up some of its reserves for export out of the country.“Saudi Arabia has an absolute dire need for gas. They want to shift their power more toward gas-based sources so they can free up oil for exports,” London-based BMI Research Oil and Gas Analyst Emma Richards told CNBC in 2015 when Saudi Arabia was starting up a pilot fracking project. “They’ve been investing quite heavily over the last few years in R&D in different kinds of fracturing technologies.”
Saudi Aramco international listing looks increasingly difficult: sources (Reuters) - Saudi Arabia is increasingly looking to just float oil giant Saudi Aramco locally as plans for an initial public offering (IPO) on an international exchange such as London or New York hang in the balance, sources close to the process said. The kingdom is counting on being awarded emerging market status by index complier MSCI in June to help Saudi Aramco attract Western funds, in addition to cornerstone investors from China, Japan and South Korea, the sources said. “I would guess it is about evens that there will be no international IPO,” said a high-level source familiar with the preparations, saying they were proving to be a disappointment. Saudi Arabia is planning to list up to 5 percent of Saudi Aramco in an initial public offering that could value it at up to $2 trillion and make it the world’s biggest oil company by market capitalization. Saudi Energy Minister Khalid al-Falih said last week that Aramco was too important to risk listing in the United States because of litigation concerns, such as existing lawsuits against rival oil companies for their role in climate change. British officials have been told by Saudi counterparts London has a chance to secure the listing but only in 2019 at the earliest, according to the Financial Times, and sources told Reuters the kingdom was now focusing on a listing on the local exchange, or Tadawul. “The only thing we know today is that Tadawul will be the key listing location as our national exchange,” Falih told CNN. “We are waiting for the reforms to be in place and to join MSCI and Aramco listing in Tadawul will be catalytic for that capital market as we bring international capital to the kingdom,” he told the U.S. channel last week.
Aramco IPO Delayed Until 2019 As New York Listing Grows Increasingly Remote - For more than two years, investment bankers in the US and London have been salivating over the prospect that Aramco, the state-owned Saudi oil company that’s believed to be one of the most valuable companies in the world, could choose to list shares representing a 5% stake in the company on the London Stock Exchange, New York Stock Exchange, or Nasdaq. But despite reports that the royal family had “shortlisted” New York, London and Hong Kong as possible venues for the offering - news that intensified an already escalating geopolitical “Game of Thrones” between bankers and politicians - the Kingdom is continuing with a Financial Times-assisted campaign of mixed messaging, suggesting that the IPO could either be delayed for another year or two, or possibly being shelved indefinitely in favor of a direct sale to a coterie of Asian sovereign wealth funds or possibly even directly to the Chinese government (much to the US's chagrin). In its latest inside-baseball report on the endlessly fraught back-and-forth, the Financial Times is saying a public offering won’t happen until 2019 at the earliest - if it happens at all. However, in an unusual twist, the paper is sourcing its story to UK officials, not the Saudis, as has often been the case in the recent past.Saudi Aramco’s listing is unlikely to go ahead this year, according to British officials who have been warned by their Saudi counterparts that the world’s biggest flotation was expected to be delayed.Several people briefed on the talks said London still had a good chance of securing the listing, which Riyadh said could value the state energy company at $2tn, but any foreign flotation was likely to happen in 2019 at the earliest.Saudi Arabia wants to sell 5 per cent of the world’s largest oil-producing company as part of an economic reform programme driven by Mohammed bin Salman, the Saudi crown prince, who visited the UK this week.
The Saudi Aramco IPO Math Problem: Cash > Barrels - Rule number one with an IPO: Don't announce a target value years ahead of the actual sale -- especially if one is tempted to use the word "trillion." That rule was broken way back with Saudi Arabian Oil Co., or Saudi Aramco. In early 2016, when Prince Mohammed bin Salman first unveiled plans to list shares in the oil behemoth, he boasted about a price tag of $2 trillion. A couple of years on, the IPO hasn't yet happened, and there are now signs it could be pushed into 2019. Naturally, it takes time to organize the sale of a company as big and complex as Aramco. But that $2 trillion figure may also be an obstacle in itself, especially as Aramco's IPO isn't just any share sale but a milestone in the prince's plans to remake his country. The figure looks like it resulted from a highly scientific process of multiplying Saudi Arabia's roughly quarter-trillion barrels of proved oil reserves by a multiple of $8. But the fact that Aramco is being privatized in the first place undercuts such simple valuation by reserves, because the IPO acts as a hedge against weaker long-term oil demand. It makes little sense to apply such blanket valuations against 60 years' worth of production (companies usually carry about 10 - 15 years of proved reserves on the books). As oil enters an era of greater competition between producers and with other fuels, investors largely want one thing from the majors: yield. Growth is nice to have, but what counts is how much free cash flow they can generate to fund dividends (hence, Exxon Mobil Corp.'s big spending plans have met with disdain). Aramco's stock would need to compete on those terms. Here are the free cash flow yields -- as a percentage of market capitalization -- for a selection of Aramco's likely peers: Applying this to Aramco is tricky until that IPO prospectus turns up. Still, I've got an envelope on my desk, so I can sketch out some rough numbers on the back of it. WARNING: assumptions dump ahead.
Cash-Flush Saudi Arabia Gifts Iraq World's Biggest Soccer Stadium - In mid-January, the Saudi government netted more than $100 billion in cash, stock, real estate and other assets stemming from the 2017 Saudi Arabian purge. We reported the total amount raised could have been enough to cover the country’s 2017 budget deficit, and then some.Last week, Saudi Arabia’s King Salman bin Abdulaziz Al Saud and Saudi Arabia’s Crown Prince Mohammed bin Salman went on a spending spree — purchasing $10 billion worth of Eurofighter Typhoon jets from the United Kingdom. Moreover, King Salman promised to construct the world’s largest football stadium in Baghdad.It is still unclear if the king or prince tapped into the $100 billion of purged assets or used their American Express Centurion card, also dubbed “The Black Card,” to buy Eurofighter jets and or the world’s largest stadium, as cardholders have no preset spending limit.There are many unanswered questions regarding how these deals transacted... Besides the acquisition of the Eurofighter jets - most likely headed to participate in the Yemeni Civil War, King Salman gifted Baghdad a monstrous 135,000-seat stadium after a friendly soccer match resulted in Iraq defeating Saudi Arabia 4-1, in late February. . According to Arab News, the official headline was announced on March 05 that King Salman would fund the construction of the new football stadium following a telephone call with Iraqi Prime Minister Dr. Haider Al-Abadi on March 04.
Analysis: Iran reopens split with Saudis over OPEC oil output policy - Iran is stirring up potential OPEC trouble by reopening the debate over when to signal an end to the group's current production cut deal with Russia. There are good arguments for it to end soon if crude bursts through the $70/b level, but Tehran's dilapidated fields are in no shape to win a new market share battle. Iranian oil minister Bijan Zanganeh argues higher prices are reviving US shale at OPEC's expense. In a recent interview with The Wall Street Journal, he said the 14-member group may agree at its next meeting June 22 on a strategy for ending its cuts starting in 2019. Zanganeh insists Saudi is onboard with the idea, but his message contradicts recent signals of longer term cooperation between OPEC and producers outside the group led by Russia. Although Zanganeh may have a point about shale, Iran is powerless to halt its revival. The Islamic republic can probably only pump an additional 100,000 b/d above its current output level of around 3.83 million b/d, according to the latest S&P Global Platts OPEC survey. "I don't think Iran has the power to ruin the party," said Bassam Fattouh, director of the Oxford Institute for Energy Studies, noting that the normally hawkish country has not voiced concern about the impact of higher prices on supply and demand in the past. "Maybe it is an effort to present itself as a reasonable producer given that it has no real influence on market dynamics." Nevertheless, Zanganeh's remarks were enough to spook traders. Brent futures fell more than $1/b early Monday to approach $64/b before recovering later in the day. The International Energy Agency, in its medium-term oil market forecast released last week, is even less optimistic about Iran's oil industry. The Paris-based agency estimates Iran could sustain a crude production level of 3.85 million b/d in 2018 and 3.90 million b/d in 2019. Incremental gains, but hardly the heft to undo the cuts by Saudi Arabia alone.
Post Tillerson: Is The Iran Nuclear Deal (& Its Oil Production) At Risk? - President Donald Trump sacked Secretary of State Rex Tillerson via Twitter on Tuesday, replacing him with current CIA Director Mike Pompeo. The move has some grim implications for the U.S.’ approach towards Iran in the months ahead. Sec. of State Rex Tillerson has been panned as “at or near the bottom of the list of secretaries of state, not just in the post-Second World War world but in the record of US secretaries of state,” according to Paul Musgrave, a scholar of US foreign policy at the University of Massachusetts Amherst. Other foreign policy scholars came to the same conclusion. Tillerson presided over a dismantling of the U.S. diplomatic corps – upwards of 60 percent of the agency’s top career diplomats resigned – and will exit Foggy Bottom without any notable accomplishments. But, the dismal tenure for Tillerson could be followed by an even darker period in which the U.S. steps up confrontation on multiple fronts around the world. For all his faults, Tillerson, at least by comparison, was viewed as a relative moderate. He will be replaced by the current CIA Director Mike Pompeo, a notorious hawk who has politicized the CIA to great degree. And one of Pompeo’s top targets could be Iran. Pompeo has previously called for tearing up the 2015 Iran nuclear deal. “Pompeo has done nothing but talk about how we need to take the gloves off,” Stephen M. Walt, a professor of international relations at Harvard’s Kennedy School, told the New York Times. Indeed, the NYT notes that just days after Trump was elected, Pompeo wrote in Twitter, “I look forward to rolling back this disastrous deal with the world’s largest state sponsor of terrorism.” Pompeo has repeatedly signaled support for a harder line, whereas Tillerson appeared to be one of the few figures holding the administration back from taking aggressive action on Iran and North Korea. As such, heightened confrontation or outright conflict with Iran appears more likely. The President has to periodically recertify that Iran is complying with the terms of the deal, waiving U.S. sanctions for several months. Trump has done this several times, begrudgingly, in part due to Tillerson’s persuasion. With Tillerson out and Pompeo in, all signs pointing to the U.S. trying to rip up the agreement when the next recertification deadline arrives in May.
Saudi Crown Prince Says Will Develop Nuclear Bomb If Iran Gets One; Compares Ayatollah To Hitler - In a "60 Minutes" interview set to air on Sunday, the de facto leader of Saudi Arabia, Crown Prince Mohammed bin Salman, said his country would quickly obtain a nuclear bomb - if arch rival Iran successfully develops its own nuclear weapon.The Saudi crown prince, currently on a whirlwind global PR tour to relieve his western allies of the bitter aftertaste that resulted from last year's unprecedented extortion crackdown on Saudi Royals, which left many of them imprisoned in the Riyadh Ritz Carlton for months until they "agreed" to hand over their loot to the cash-depleted government, said that "Saudi Arabia doesn’t want to own a nuclear bomb. But without a doubt, if Iran develops a nuclear bomb, we will follow suit as soon as possible.”This is not surprising: last month we reported that Saudi Arabia is moving swiftly to become the next country in the Middle East with nuclear power. The Kingdom is on the verge of striking a deal with the US for the purchase of nuclear reactors despite concerns over its refusal to accept stringent restrictions against the proliferation of nuclear weapons. Although the Saudis have insisted that their programme will be peaceful, they have also refused to rule out the right to enrich uranium to weapons grade. A senior Saudi official was quoted by the Wall Street Journal admitting as much: “I’m not saying Saudi would want to enrich uranium tomorrow or anytime soon but they don’t want to be committed to anything that bans them from doing it. It is quite political,” the unnamed senior official said.His comments have stirred speculation that one of the purpose of the nuclear program is to compete with Iran and maintain an option to develop nuclear weapons. Today's MbS comments confirm that the nuclear arms race between Iran and Saudi Arabia is officially on, even as much of the Middle East is rapidly breathing down their neck.
NATO Relocates Middle East Airbase from Turkey to Jordan - At least one substantial part of an incredibly deadly and aggressive force has been gradually relocated, from an ‘uncertain’ and according to the West suddenly ‘unreliable’ country (Turkey), to the impoverished but obedient Kingdom of Jordan. It is now clear that NATO is not sure, metaphorically speaking, which direction is Turkey going to fly in, and where it may eventually land. It is panicking and searching, ‘just in case’, for an exit strategy; almost for an escape plan from the most important regional power. Entrance to Incirlik airbase, Turkey. Is the West really losing Turkey? Nobody knows. Most likely, nobody in Ankara is sure, either, including Mr. Erdogan. But what if … What if Erdogan moves closer to Russia, even to China? What if Turkey’s relationship with Iran improves? What if Ankara has finally gotten tired of being humiliated, for years and decades, by the European Union? And what if it does not want to follow Washington’s diktat, anymore? These ‘nightmarish’ scenarios are most likely turning many apparatchiks in Brussels, Washington and London, into insomniacs. NATO does not want to leave anything to chance. If not Turkey, then where? Where should all those nukes, fighter jets, bombers and ‘Western military advisors’ go? The Kingdom of Jordan seems to be the best candidate. Conveniently, it is greatly impoverished, and it has been historically submissive to its Western handlers. It is essentially dependent on foreign, mainly Western, aid and would do just about anything to please the rulers in Washington, London or Berlin. Most importantly for the West, Amman is sufficiently oppressive, lacking any substantial opposition. If dissent gets too vocal, its members get kidnapped and tortured. Therefore, it is natural that both Europeans and North Americans feel safe and at home here.
Russia threatens counter-strikes on US forces in Syria --Amid rapidly escalating provocations against Russia by the US, Britain and other allies, General Valery Gerasimov, the chief of general staff of the Russian Armed Forces, vowed on Tuesday to attack any forces that directly or indirectly target Russian troops operating in Syria.Gerasimov told a gathering of his top commanders: “If the lives of Russian officers are threatened, the Armed Forces of the Russian Federation will retaliate against missile and launch systems.”The general’s statements are a direct warning that Russia will attack American warships or airbases that are responsible for any strikes. They were made in response to a series of unsubstantiated accusations by American officials that the Russian-backed Syrian government has used chemical weapons in its operations against US-backed rebel militias. On April 6, 2017, such allegations were used as the pretext by the Trump administration to fire dozens of cruise missiles against one of the Syrian military’s main airbases. According to reports at the time, Russia was informed shortly before the attack, so it could evacuate any personnel it had in the vicinity. On Sunday, US Defense Secretary Jim Mattis cited unconfirmed reports of chlorine attacks on the rebel-held Damascus suburb of eastern Ghouta and threatened the Syrian government with retaliation if they were confirmed. He said that President Donald Trump had “full political maneuver room” to take whatever decision he believed was appropriate.
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