Sunday, September 24, 2017

US oil prices still at a discount to those overseas; heat oil supplies shrinking heading into winter

US oil prices closed above $50 a barrel for the first time since May this week, but the real story continues to be that the international price for the same grade of oil remains more than 12% higher...while US WTI for November delivery closed on Friday at $50.66 a barrel, an increase of 22 cents on the week, the international benchmark of North Sea Brent for November, an equivalent grade of light sweet crude, was closing in London at $56.86 a barrel, an increase of $1.24 a barrel...as we pointed out last week, that price spread between the US benchmark and the international price also carries well into 2018 oil contracts; for instance, a contract to deliver US crude to Cushing Oklahoma in April of 2018 will get you $51.60 a barrel, whereas the equivalent Brent contract price for April of 2018 will get you $55.70 a barrel...since the cost of shipping oil overseas runs between a dollar and 2 dollars a barrel, depending on the distance shipped, that price difference of more than $4 a barrel creates a strong incentive for those who own US oil in storage to contract to export it at a better price than they can get by contracting to sell it domestically, to US refineries for example...

early this week it appeared that we might have a natural gas price rally on our hands too, but that blew out when a much above normal addition of gas to storage sent prices tumbling...the contract price for natural gas for October delivery had generally stayed in a narrow range between $2.90 per mmBTU (million British Thermal Units) and $3 per mmBTU through most of August, a price generally unprofitable for most Marcellus and Utica exploitation...last week, however, natural gas staged a 4 day mini-rally that added 18 cents per mmBTU to the price, which lasted until a bearish natural gas storage report knocked 4.6 cents off the Friday price and it closed the week at $3.024 per mmBTU...however, by Monday of this week, the weather forecasts had changed, with warmer-than-normal temperatures expected to persist through the end of September across the eastern half of the US, and hence the October natural gas futures contract jumped 12.2 cents to settle at $3.146/MMBtu in anticipation of a late-season demand for cooling...prices then drifted lower, giving up 2.4 cents on Tuesday and another 2.8 cents on Wednesday, while traders waited for the weekly natural gas report....prices then plunged almost 5% on Thursday when that Weekly Natural Gas Storage Report from the EIA showed that utilities added 97 billion cubic feet of gas to storage during the week ended Sept. 15th, compared to a 54 billion cubic feet increase during the same week a year ago and the five-year average increase of 73 billion cubic feet for the same period, as October natural gas futures settled down 14.8 cents, or 4.8 percent, at $2.946 per million BTUs...while prices inched up 1.3 cents on Friday, they still closed the week down 6.5 cents at $2.959 per mmBTU, just about the midpoint of their two month price range...

The Latest US Oil Data from the EIA

this week's US oil data from the US Energy Information Administration, covering details for the week ending September 15th, showed that oil production and imports were close to returning to normal after Hurricane Harvey's disruptions, but refineries still lagged their pre-Harvey pace, and as a result our crude oil supplies rose for the third week in a row...our imports of crude oil rose by an average of 888,000 barrels per day to an average of 7,368,000 barrels per day during the week, while at the same time our exports of crude oil rose by 154,000 barrels per day to an average of 928,000 barrels per day, which meant that our effective imports netted out to an average of 6,440,000 barrels per day during the week, 734,000 barrels per day more than during the prior week...at the same time, our field production of crude oil rose by 157,000 barrels per day to an average of 9,510,000 barrels per day, which means that our daily supply of oil coming from net imports and from wells totaled an average of 15,950,000 barrels per day during the reported  week... 

during the same period, US oil refineries were using 15,172,000 barrels of crude per day, 1,094,000 barrels per day more than they used during the prior week, and at the same time 426,000 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 352,000 more barrels per day than what refineries reported they used during the week plus what was added to storage...to account for that discrepancy, the EIA needed to insert a (-352,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, which they label in their footnotes as "unaccounted for crude oil"...

further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports fell to an average of 7,209,000 barrels per day, which was 10.9% below the imports of the same four-week period last year....the 462,000 barrel per day increase in our total crude inventories came about on a 656,000 barrel per day addition to our commercial stocks of crude oil, which was partially offset by a 230,000 barrel per day emergency withdrawal of oil from our Strategic Petroleum Reserve, which is presently being tapped to address temporary spot shortages caused by Harvey...this week's 157,000 barrel per day increase in our crude oil production was the result of a 179,000 barrels per day rebound in oil output from wells in the lower 48 states and a 22,000 barrel per day decrease in oil output from Alaska...the 9,510,000 barrels of crude per day that were produced by US wells during the week ending September 15th was still slightly less than the 9,530,000 barrels of crude per day being produced during the pre-hurricane week ending August 25th, but it was 8.4% more than the 8,770,000 barrels per day we were producing at the end of 2016, and 11.7% more than the 8,512,000 barrels per day of oil we produced during the during the equivalent week a year ago, while it was 1.0% below the record US oil production of 9,610,000 barrels per day set during the week ending June 5th 2015...  

US oil refineries were operating at 83.2% of their capacity in using those 15,172,000 barrels of crude per day, up from the of 77.7% of capacity the prior week, but down from the 96.6% capacity utilization rate in the week before Harvey struck....the 15,172,000 barrels of oil refined this week was up 7.8% from the 14,078,000 barrels of crude per day that was being processed the prior week, but still 14.4% less than the 17,725,000 barrels per day that was being refined three weeks earlier, and 8.5% less than the 16,587,000 barrels of crude per day that were being processed during week ending September 16th, 2016, when refineries were operating at 92.0% of capacity...

even with the increase in US oil refining, gasoline production from our refineries slipped by 95,000 barrels per day to 9,793,000 barrels per day during the week ending September 15th...that left this week's gasoline output 2.7% lower than the 10,083,000 barrels of gasoline that were being produced daily during the comparable week a year ago....however, our refineries' production of distillate fuels (diesel fuel and heat oil) jumped by 570,000 barrels per day to 4,543,000 barrels per day at the same time, which was still 8.7% less than the 4,978,000 barrels per day of distillates that were being produced during the week ending September 16th last year....   

with the ongoing reduced level of gasoline production, our end of the week gasoline inventories fell by 2,125,000 barrels to 216,185,000 barrels by September 15h, the 11th decrease in gasoline inventories in 14 weeks...that was despite the fact that our domestic consumption of gasoline fell by 178,000 barrels per day to 9,441,000 barrels per day, while our imports of gasoline rose by 131,000 barrels per day to 687,000 barrels per day and while our exports of gasoline rose by 16,000 barrels per day to 544,000 barrels per day....with significant gasoline supply withdrawals in 11 out of the last 14 weeks, our gasoline inventories are now down by 10.8% from June 9th's level of 242,444,000 barrels, and 4.0% below last September 16th's level of 225,156,000 barrels, even as they are still roughly 1.8% above the 10 year average of gasoline supplies for this time of the year...   

even with the big increase in our distillates production, their output still remained well below normal, and hence our supplies of distillate fuels fell by 5,693,000 barrels to 138,859,000 barrels over the week ending September 15th, the largest one week drop since November 2011...that was as the amount of distillates supplied to US markets, a proxy for our domestic consumption, rose by 207,000 barrels per day to 4,264,000 barrels per day, and as our exports of distillates rose by 666,000 barrels per day to 1,177,000 barrels per day, while our imports of distillates fell by 51,000 barrels per day to 85,000 barrels per day...after this week’s big decrease, our distillate inventories ended the week 15.8% lower than the 164,992,000 barrels that we had stored on September 16th, 2016, and 3.5% lower than the 10 year average for distillates stocks for this time of the year…since our distillates supplies have now dropped to below normal for the first time since we've tracked them, we'll take a look at a picture of what that looks like compared to their recent history:

September 20 2017 distillate supplies as of Sept 15

the above graph comes from a weekly emailed package of oil graphs from John Kemp, senior energy analyst and columnist with Reuters...this graph shows US distillate fuels inventories in thousands of barrels by "day of the year" for the past ten years, with the past ten year range of our distillates supplies on any given day of the year shown in the light blue shaded area, and the median of our distillates inventory, or the middle of the 10 year daily range, traced by the blue dashes over each day of the year...the graph also shows the number of barrels of distillates we had stored for each week in 2016 traced weekly by a yellow line, with our 2017 year to date distillates supplies for each week traced in red...from this graph we can initially see there is an obvious seasonality to distillates supplies, as they're built up during the summer then consumed during the winter months, when demand for heat oil is greatest...however, this summer, when supplies of distillates should be increasing like they have every other year, they're collapsing instead, even before the post-Harvey refinery shut downs... and as you can also see from the above, they're at their lowest level in over two years, at a time of year when they should be peaking...unless refineries can turn this around, we could be heading into a heating season of what looks to be a colder than normal winter with very tight heat oil supplies...

finally, with another big drop in use of crude by our refineries, our commercial crude oil inventories rose for the 3rd week in a row, increasing by 4,591,000 barrels to 472,832,000 barrels as of September 15th, still just the 5th increase in the past 25 weeks...while our oil inventories as of September 15th were still fractionally below the 473,966,000 barrels of oil we had stored on September 16th of 2016, they were more than 12.0% higher than the 422,033,000 barrels in of oil that were in storage on September 18th of 2015, and much higher than the normal level for our oil supplies in the years before the oil glut started building up, ie., 44.7% greater than the 326,828,000 barrels of oil we had in storage on September 19th of 2014...   

This Week's Rig Count

US drilling activity decreased for the 9th time in the past 13 weeks during the week ending September 22nd, after a string of 23 consecutive weekly increases earlier this year, with oil drilling down while gas drilling increased....Baker Hughes reported that the total count of active rotary rigs running in the US fell by 1 rig to 935 rigs in the week ending Friday, which was 424 more rigs than the 511 rigs that were deployed as of the September 23rd report in 2016, while it was less than half of the recent high of 1929 drilling rigs that were in use on November 21st of 2014....

the number of rigs drilling for oil was down by 5 rigs to 744 rigs this week, their 7th week without an increase, which nonetheless still left oil rigs up by 326 over the past year, while their count remained far from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations increased by 4 rigs to 190 rigs this week, which was 98 more rigs than the 92 natural gas rigs that were drilling a year ago, but still way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...in addition, one rig that was classified as miscellaneous was still drilling this week, same as a year ago...

drilling started from 2 additional platforms off the Louisiana coast this week, and hence the Gulf of Mexico rig count increased by 2 to 19 rigs this week, which was still down from the 20 rigs that were drilling in the Gulf a year ago...with no offshore drilling other than in the Gulf now or a year ago, those totals are also those given as the total US offshore count....at the same time, a platform that had been drilling on an inland lake in southern Louisiana was shut down this week, leaving an 'inland waters' count of 3 rigs, the same as a year ago... 

the count of active horizontal drilling rigs fell by 5 rigs to 790 rigs this week, which was still up by 388 rigs from the 402 horizontal rigs that were in use in the US on September 23rd of last year, but was also down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014....on the other hand, the directional rig count was up by 3 rigs to 77 rigs this week, which was also up from the 49 directional rigs that were deployed on September 23rd of 2016.....at the same time, the vertical rig count was up by 1 rigs to 68 vertical rigs this week, which was also up from the 60 vertical rigs that were deployed during the same week last year...

the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of September 22nd, the second column shows the change in the number of working rigs between last week's count (September 15th) and this week's (September 22nd) count, the third column shows last week's September 15th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was for the 23rd of September, 2016...       

September 22 2017 rig count summary

we would note that after 8 weeks with little change, the Permian basin of western Texas and southeast New Mexico bucked the trend with an increase of 6 rigs this week, their biggest jump since May 12th...that was just barely enough to increase the Texas count, however, as the state saw decreases in the Eagle Ford in the south and the Granite Wash of the eastern panhandle area...with the increase of two rigs in the Gulf, Louisiana with 3 new rigs saw the largest increase, while major producers Oklahoma and North Dakota both shed three...meanwhile, there were no changes in activity in the Utica or the Marcellus, as all the gas well increases were in "other" basins, unnamed in Baker Hughes summary data...meanwhile, outside of the major producing states shown above, Alabama also added a rig this week and now has 2 active, also up from just 1 rig a year ago..

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Report Highlights Fracking's Threat to Ohio's National Forest -– Ohio's Wayne National Forest is among the country's public lands most threatened by fossil fuel interests, according to a new report. "Too Wild to Drill," released Tuesday by The Wilderness Society examines 15 unique places across the United States that researchers say are at high risk of drilling and mining. Nathan Johnson, the public lands director for the Ohio Environmental Council, says folks trying to enjoy the natural beauty of the forest's 250,000 acres don't want to breathe in toxic air pollution or hear the constant noise of trucking and compressor stations. "If you've got a family that's playing or fishing in a stream there, the last thing you want folks to worry about is chemicals being in the water or even chemicals in the fish their son or daughter just caught in the stream," he says. "Those are all really big concerns we don't want to see in the Wayne." The Ohio Environmental Council and other groups are legally challenging the Bureau of Land Management's recent lease of nearly two thousand acres of the Wayne National Forest, as well as an oil and gas leasing plan for 40,000 acres of the land. The BLM contends an environmental assessment found the leasing will not significantly affect the quality of the environment in the area. Supporters of oil and gas drilling contend it creates economic opportunities. But Johnson says the risks to Ohio's only national forest are just too great. He points to the 2014 Monroe County well pad fire that occurred near the Wayne National Forest. "Fortunately no one died," he adds. "Twenty-five families had to be evacuated, 70,000 fish were killed in a stream. So these threats are not just purely idle or speculative - they're real and they happen and it's something we really have got to be careful about and aware of." The report's release comes as federal officials review public land policies, and a 180-day review of regulations that could burden fossil fuel development ends at the end of September. 

Ohio increases fines to $2.3M against pipeline developer | Fox Business: – Ohio's environmental regulators have more than doubled the proposed fines against a company building a natural gas pipeline from West Virginia to Michigan, saying Wednesday the two sides are at an impasse. Continue Reading Below The fines now stand at $2.3 million and stem from what the Ohio Environmental Protection Agency says are numerous water and air pollution violations during construction of the $4.2 billion Rover Pipeline. The twin pipelines are being built across Ohio to carry natural gas from Appalachian shale fields to Canada and states in the Midwest and the South. Dallas-based developer Energy Transfer Partners, which also was behind the Dakota Access oil pipeline, has resisted attempts at resolving the fines, said Craig Butler, director of Ohio's Environmental Protection Agency. Butler said he is now asking the state's attorney general to get involved. Energy Transfer Partners said it will continue to work with the Federal Energy Regulatory Commission to meet its requirements. The federal commission that oversees gas pipelines this week gave the company the approval to restart drilling operations. New drilling on unfinished sections had been halted after 2 million gallons (7.6 million liters) of drilling mud seeped into a wetland in the spring. Energy Transfer Partners spokeswoman Alexis Daniel said the project now is expected to be completed and operating by the end of March. The head of the Ohio EPA said the pipeline company doesn't think the state has authority to impose regulations because the Federal Energy Regulatory Commission already gave the company approval on the project.

Ohio EPA Hikes Penalties Against Rover Pipeline To $2.3 Million -- The Ohio EPA on Wednesday turned over of $2.3 million in civil penalties against the owners of the Rover pipeline enforcement to the Ohio Attorney General’s office. Ohio EPA Director Craig Butler says he had no choice but to bring -in the state attorney general’s office to force a settlement with Energy Transfer Partners, and other owners of the Rover pipeline over civil penalties. He says Rover has logged dozens of environmental violations, including open burning, a massive spill in a sensitive wetland and dumping drilling mud mixed with diesel fuel in a quarry near where Canton draws its drinking water. At an event Wednesday on the banks of the Cuyahoga River, Butler said the fines against Rover kept snowballing. “As time goes by it went from $400,000 to $900,000 and now we believe it’s justified to ask for a $2.3 million penalty.” Butler says Rover’s owners have refused to pay any penalties but that clean-up of contaminated sites has gone forward. 

Ohio agency wants troubled Rover Pipeline to pay $2.3 million in fines - The Ohio Environmental Protection Agency is once again squaring off with Rover Pipeline LLC officials. On Wednesday, the state agency asked the Ohio attorney general’s office to hold pipeline officials financially responsible for $2.3 million in fines related to numerous environmental violations which have occurred during the $4.2 billion underground natural gas pipeline’s construction. Rover’s parent company is Dallas-based Energy Transfer Partners. An analysis last month found the 710-mile-long Rover project has already piled up 104 “noncompliance incidents” so far — more than any other interstate natural gas pipeline in the past two years. Along its Ohio stretch, the pipeline razed a historic house, leaked 2 million gallons of drilling sludge into protected wetlands and dumped contaminated slurry in quarries near water wells used by the Canton Water Department and Aqua Ohio. In May, the Federal Energy Regulatory Commission ordered a halt to new drilling activity along the troubled project.  Since then, the company has done its part to clean up the releases, install a groundwater monitoring network and develop plans to remediate impacted wetlands, Ohio EPA Director Craig Butler told reporters Wednesday. But the company refuses to pay the millions in civil penalties ordered by the state, he said. “Negotiations just in general with Rover have been quite difficult ... We’ve reached an impasse and have to ask for assistance,” he said. “We believe it’s fair that they owe the state of Ohio in compensation.” Environmental groups applauded the agency’s move to refer the case to state Attorney General Mike DeWine. “Simply put, when a mess is made, a penalty is appropriate. If the Rover Pipeline project followed the rules and respected Ohioans and our natural resources, these things wouldn’t happen,” said Heather Taylor-Miesle, executive director of the Ohio Environmental Council.

Far away from any witnesses, my small town is being poisoned by fracking waste  - My south-eastern Ohio town in the Appalachian foothills is a small, rural place where the demolition derby at the county fair is a hot ticket, Walmart is the biggest store, and people in the even smaller villages surrounding the county seat must often drive for 30 minutes to grocery shop. We hold the unfortunate distinction of being the poorest county in the state: an area that is both stunning – rolling hills, rocky cliffs, pastures and ravines – and inaccessible, far from industry.  It’s here that fracking companies dump their waste. The Hazel Ginsburg well, an injection well built in the hillside decades ago, was meant to deposit saline and sand underground into porous rock. For the last few years, however, the well has held waste from out-of-state fracking operations done in Pennsylvania, West Virginia and other states.  A forgotten byproduct of fracking is the waste. What goes into the ground must come out: a sludge of toxic chemicals and undrinkable water, which trucks ship across the country. Far from the drill pads, far from the cities that profit from fracking, far from any city at all, the leftover wastewater is injected into the ground – my county’s forgotten ground. Some streams in the woods run red from the acid leaking from abandoned shafts. My step-grandmother, the daughter of a Kentucky miner, used to tell me stories of washing her clothes in red water, downstream from mines.  But the Hazel Ginsburg well has a long history of violations, so many that the Ohio department of natural resources (ODNR) ordered it shut. It was not. It’s a pit well, which looks like an old swimming pool, covered by a tarp. No sign indicates the presence of chemicals, just a “no trespassing” sign on a gate across a gravel driveway, near a wooden shack where a security guard sits. Allegedly, the guard will snap your picture if you stop or turn your car around. The well is located in a residential area, with houses – some with swing sets – just down the road.

Toxic town: West Virginia community where cancer rates are FOUR TIMES the national average and residents point to chemical dumps as the cause as they attend 'one funeral after another'. Now nearby fracking fuels fears of MORE contamination

  • Minden, West Virginia is a riverside town which once thrived on coal mining. Residents have noticed elevated sickness rates for at least the past 30 years
  • One 62-year-old grandmother, Susie Worley-Jenkins, has been diagnosed with cancer four times; her husband survived leukemia and multiple skin cancer diagnoses; and her best friend died of a brain tumor
  • Worley-Jenkins and other residents have banded together to form a grassroots effort with the hope of pressuring authorities to identify and stop the cause
  • Dr Hassan Amjad dedicated his life to documenting the cancer rates and calling for justice before his death from a sudden illness in August
  • The Environmental Protection Agency found now-defunct company Shaffer Equipment dumped electrical equipment laden with toxic chemicals on the coal company’s mine site, which is now abandoned, in the center of Minden
  • Minden received Superfund money, designated for toxic cleanup sites, in the 1980s but residents fear chemicals remain and fracking could be further contaminating the area
  • One state statistician wrote, in an email seen by DailyMail.com, that the 'much higher cancer death rate' in Minden than the surrounding county was 'concerning,' given the tiny population rate
  • Authorities have repeatedly insisted that water levels are safe but the EPA conducted testing again this summer, though results for Minden have not been released
  • The national average cancer mortality rate is 171 per 100,000 - while figures have placed Minden's rates at 642.1 per 100,000 and Dr Amjad found rates in previous years as high as 2,092 per 100,000
  • The real rates in Minden could be even higher as a result of flawed reporting and residents moving, he said

Angry officials ask: Can Enbridge be trusted on Mackinac Straits pipeline safety? - Damaged pipeline protection — and damaged trust — filled the agenda at the Michigan Pipeline Safety Advisory Board meeting in Lansing on Monday as concerns grow about the condition of two oil pipelines running under the Straits of Mackinac.State officials flashed anger with Canadian oil transport giant Enbridge, after the company disclosed late last month that areas of missing protective coating — bare metal — exist on their 64-year-old oil and gas pipelines that lie underwater in the straits, which connect Lake Michigan and Lake Huron.  Particularly drawing ire were original Enbridge public statements that the areas missing coating were "Band-Aid sized." The company has since disclosed to the state that seven of the eight affected areas are 7 inches in diameter or more, including some more than a foot in diameter."Frankly, I think we really need to know that what Enbridge is telling us is the truth, and that it is accurate,"  . "Because, we were not really told the truth, nor was it really accurate — especially with they characterization about Band-Aid-sized impacts."   State officials also expressed concern that at least one of the areas of damaged, missing protective coating on the pipelines appears to have been caused during the installation of a support anchor on the pipe, yet was not immediately disclosed or repaired. Enbridge currently has a permit before the state DEQ to install 22 additional anchor supports on Line 5, to address areas where the span between anchor supports now exceeds 75 feet, the maximum allowable distance in Enbridge's 1953 easement with the state of Michigan allowing for the Straits pipeline."With how the damage to the coating on the pipeline was reported, and that the outer coating damage apparently occurred during preventative measures, causes me not only great concern, but honestly, I’m angered and actually annoyed at how this has transpired, from inspection, identification, and notification regarding the affected areas," said State Police Capt. Chris Kelenske, a pipeline safety board member and the deputy state director of emergency management and homeland security. "The question I have is, how is it the damaged areas were not identified earlier, nor immediately reported to the state? Looking at the pictures from that report, it’s obvious that there are gaps in this outer coating."

Plum residents, experts debate safety of Marcellus shale fracking dump site | TribLIVE: Plum's follow-up meeting Thursday night to the federal Environmental Protection Agency's public hearing in July to express concerns over a proposed injection well was less passionate. Around 100 residents from Plum and surrounding communities gathered in Plum Council's chambers Thursday to hear how a five-member panel answered questions about the injection well, which is used in the Marcellus shale fracking process. Panelists included experts from the oil and gas industry and environmental advocates. Questions, which were read by a moderator, ranged from wanting to know how much noise pollution caused by increased truck traffic residents can expect to what local governments can do to limit oil and natural gas activity. But among the biggest concerns were whether injection wells like the one being proposed cause earthquakes and contaminate drinking water. Dale Scoff, an industry geologist and consultant, said the question of whether injection wells cause quakes depends on an area's geology and if the wells reach pre-Cambrian rock — which can sit to around 18,000 to 20,000 feet within the earth, he said. “The potential here, and throughout most of Pennsylvania, I think it's very minimal for induced seismicity from these injection well operations,” he said. Matt Kelso, with environmental group FracTracker Alliance, said he has heard that before. “This is not an area known for earthquakes, but then again neither was northeastern Ohio,” Kelso said, referencing the bout of quakes that hit Youngstown over several recent years. Doug Shields, an outreach liaison for Western PA Food & Water Watch, was also not convinced. “It's a roll of the dice as far as I'm concerned,” he said.

Regional gas pipeline projects move forward  - The installment of a new natural gas compressor station in the Grayson area is almost complete. The station, located on Beckwith Branch Road beside I-64, is part of TransCanada Corporation’s Rayne XPress project and is one of many that are currently ongoing. The facility will help the transportation process of natural gas that serves Kentucky markets as well as markets further south, according to Scott Castleman, Manager of U.S. Gas Communications. The Rayne XPress is a $400 million project with a purpose of adding new compressor stations on TransCanada’s existing Columbia Gulf System. Another compressor station being constructed in Means is part of the project as well.  Castleman said the project was approved by the Federal Energy Regulatory Commission (FERC) in January and anticipates construction will be completed in November. He described the appearance of the station saying it somewhat appears like a “green barn.” “Typically it’s something that once it’s running in service people are not going to notice or think much about,” he said. In terms of new employment opportunities with the station, Castleman said there are usually two to four employees who will be needed to be onsite during work hours, adding a lot of the positions have already been filled.  The Gulf XPress project is another project that is currently ongoing in the Tri-State region which includes the installation of seven compressor stations. Three of the stations are in Morehead, Paint Lick and Goodluck. Castleman said there has been some misconceptions about the construction work with the projects, explaining there is no actual pipeline work going on in Kentucky. There is, however, pipeline work being done in West Virginia under the Leach XPress and Mountaineer XPress projects. Castleman explained the Leach XPress project starts in Marshall County at the Pennsylvania and West Virginia border and travels 160 miles through southeastern Ohio, delivering gas to the existing Ceredo compressor station.   The Mountaineer XPress project starts in the same area in Marshall County and travels about 165 miles down through the state, delivering gas to the existing Ceredo compressor station as well.

Controversial Atlantic Sunrise pipeline gets green light from feds to start digging - Three years after it was proposed, the controversial Atlantic Sunrise pipeline on Friday was given federal approval to begin moving dirt. The Federal Energy Regulatory Commission issued its notice to proceed for the entire 197-mile, $3 billion natural gas project, including the laying of 37 miles of 42-inch pipe in Lancaster County. Williams Partners spokesman Christopher Stockton said work will likely begin on the pipeline the week of Sept. 25 because the contractor needs time to mobilize equipment and begin site preparation. In Lancaster County specifically, he said, the majority of work will not begin for another month or so. That’s because more heavily wooded counties north of Lancaster County need considerably more tree clearing on rights of way. “The first activity people will see is site grading and the establishment of erosion control devices,” Stockton said. A religious freedom lawsuit against pipeline owner Transcontinental Gas Pipe Line Co. and FERC in federal court has been filed by a Catholic order of nuns near Columbia. But Stockton said the lawsuit by the Adorers of the Blood of Christ “does not affect our right to start pipeline construction as scheduled.” 

Nuns build chapel — and file lawsuit — to block a natural gas pipeline - A convent of elderly nuns supported by a group of local activists are all that stand in the way of a billion dollar pipeline company drilling through almost 200 miles of Pennsylvania countryside. The Adorers of the Blood of Christ own a plot of land in Lancaster County, Pennsylvania, that includes a nursing home, their convent and a field of corn plowed by a local farmer. But now the sisters have erected an outdoor chapel among the cornstalks: Wood pews and an arbor, adjacent to a city park and a subdivision. The chapel and a corresponding religious-freedom lawsuit are intended to stop the natural gas-pumping Atlantic Sunrise pipeline, an addition to Williams Partners' Transco pipeline system currently under construction. Play Facebook Twitter Embed Nuns and Activists Join Together to Protect Chapel in Path of Pipeline 5:33 autoplay autoplay Copy this code to your website or blog “It’s not a traditional chapel, but it’s a marker. It’s a place that says, ‘This is sacred,’ as was the mountaintop with Moses and the burning bush,” explained Sister Sara Dwyer, noting that 300 people attended the chapel’s dedication last month. “It’s just a place for us to be able to come, to be calm, to be focused, to be intentional about our resistance and our willingness to go very, very public with that resistance in a prayerful, nonviolent way,” she added. And it’s also going to be key in the local resistance to the pipeline, although the elderly nuns will likely attempt to maintain the property through stayed and dutiful prayer.

Construction begins on Atlantic Sunrise Pipeline - Williams Partners has announced construction is officially underway on its multi-billion dollar Atlantic Sunrise Pipeline, which is being built to connect Marcellus Shale gas in northeastern Pennsylvania to markets along the eastern seaboard.“We are committed to installing this infrastructure in a safe, environmentally responsible manner and in full compliance with rigorous state and federal environmental permits and standards,” Micheal Dunn, Williams’ executive vice president and chief operating officer said in a press release. “Our construction personnel are experienced, highly-qualified professionals who have undergone extensive training to ensure that this important project is installed safely and responsibly.”The company broke ground Friday on two new natural gas compressor stations in Orange Township, Columbia and Clinton Township ,Wyoming county. Work on the pipeline itself is expected to begin September 25. Once completed, the line will run underground, through 10 Pennsylvania counties: Columbia, Lancaster, Lebanon, Luzerne, Northumberland, Schuylkill, Susquehanna, Wyoming, Clinton and Lycoming.The project has been met with considerable public push-back, especially in Lancaster County. Hundreds of people have pledged to engage in civil disobedience in an effort to block the project.A Williams spokesman says some preliminary work is beginning in the Lancaster area, but most of it will get underway in mid-to-late October.“We are always disappointed when the regulatory agencies give another approval or permit for the industry to violate the rights of the people,” says Malinda Clatterbuck of the protest group, Lancaster Against Pipelines. “That is how we see this decision, as an outright violation of our communities’ constitutional rights to clean air and clean water, and a healthy and sustainable future.”  The pipeline is part of a broader network of controversial new natural gas infrastructural projects under construction throughout the Northeast to connect natural gas production in the Appalachian Basin to new markets within the U.S. and abroad.

Conflicting decisions on pipelines frustrate industry, landowners - In March 2016, workers for one of the nation’s largest natural gas pipeline companies cut down a large swath of maple trees in Susquehanna County–a rural patch of northeastern Pennsylvania. A video shot by an activist shows the trees crashing down as chainsaws buzz.Cathy Holleran was powerless to stop it. At the time, she was tapping the trees for her family’s maple syrup business, but the pipeline company condemned her land using the power of eminent domain. Driving around a year-and-a half later, she’s still in disbelief. A court order had prevented her from interfering, and law enforcement officers came to protect the pipeline workers.By her count, she lost more than 550 maples, “I went through with my camera and took pictures from every angle and counted them by hand to make sure I was accurate.”She says her family’s maple syrup business has been cut in half. But the real shame of it all, Holleran adds, is this may all have been for nothing.The Constitution Pipeline was supposed to emanate from northeastern Pennsylvania, and run 121 miles through New York State. Federal regulators gave their blessing to the project. So did Pennsylvania regulators. But New York State (whose border is about 20 miles from Holleran’s land) refused to grant a necessary water permit.The pipeline company, Williams, sued, but a federal court recently sided with New York. Holleran says she’d warned the company of this possibility.“All along we kept saying, ‘You might not get through New York. You might not get your permits. You’re gonna come through here and cut our land?’”Williams spokesman, Chris Stockton, says at the time the company was working with New York’s Department of Environmental Conservation, and the permit was advancing. “We were addressing their concerns as they came up,” he says. “We had no reason to think we would not receive that permit. We were playing by the rules and doing everything we needed to do.”

Pipeline agency fails to explain how it assesses risk, prioritizes inspections - It’s unclear whether federal regulators are properly prioritizing safety inspections on the nation’s massive network of natural gas and hazardous liquids pipelines,according to a recent report from the U.S. Government Accountability Office.Pipeline safety is overseen by the Pipeline and Hazardous Material Safety Administration (PHMSA), which is part of the U.S. Department of Transportation. With a safety staff of about 200 people covering 2.7 million miles of pipelines, PHMSA must pick and choose where it sends inspectors. Weld failures and corrosion are among the leading causes of significant incidents, according to the GAO.In order to assess the risk of pipeline segments, PHMSA relies on data from pipeline companies and plugs it into its so-called, Risk Ranking Index Model (RRIM). Each year, the model produces a score which puts them into a high, medium, or low risk category—prompting inspections every three, five, or seven years, respectively.But the GAO says PHMSA was unable to document or explain the rationale behind the RRIM model, and the agency has not used data to track its effectiveness. The situation is inconsistent with federal management principles, says the GAO.“Because PHMSA has not documented the basis for the design and key decisions of RRIM… it is unclear how effectively the model has helped PHMSA manage its inspection resources or maximize safety benefits to the public,” the report says.For example, the model inexplicably places a greater weight on longer pipeline segments, assuming they have higher relative risk than shorter segments. PHMSA officials also told the GAO the thresholds for the risk tiers were “determined based on their professional judgement that 25 percent of inspection systems should be considered high risk, 50 percent medium risk, and 25 percent low risk, to ensure a relatively consistent workload across regions.”

FERC overrides New York pipeline permit denial (Argus) — The US Federal Energy Regulatory Commission (FERC) today overruled New York's denial of a permit needed to expand the Millennium natural gas pipeline after finding the state waited too long to make a decision. FERC found the New York Department of Environmental Conservation waived its authority to approve or deny a water permit for a 123mn cf/d (3mn m³/d) pipeline extension by exceeding a one-year decision deadline. The state should have reached a permitting decision by 23 November 2016, the agency said, but instead waited an additional nine months before denying the permit. The New York Department of Environmental Conservation said it was reviewing the decision and would consider "all legal options to protect public health and the environment." The decision marks a major win for the natural gas sector, which argues New York has been using its water permitting authority under the Clean Water Act as an effective veto against pipelines. FERC's decision moves Millennium closer to being able to construct an 8-mile (13km) extension to the CPV Valley Energy Center, a 630MW power plant set to begin operations in February 2018. Millennium said FERC's decision was "positive step forward" for the project and said it planned to request permission to start construction next week. The company said it wanted to fully cooperate with New York on "all issues related to water" and would uphold an earlier agreement to minimize effects on water crossings and wetlands. The permitting dispute centered on when the one-year deadline began for New York to act. Millennium said the clock started on 23 November 2015, when the state received the permit application. But the state argued the application needed changes and was not "complete" until 31 August 2016, which it said allowed it an additional nine months to finish its review. New York denied the permit on 30 August for reasons unrelated to water quality. The state said that FERC's review of the project was "inadequate and deficient" because it did not estimate the greenhouse gas emissions from burning natural gas at the CPV Valley Energy Center. It based its decision on a recent court ruling regarding an unrelated pipeline in Florida.

In ‘aggressive move,’ federal agency overrules New York on pipeline permit - Federal energy regulators undercut a New York environmental agency Friday, allowing a pipeline company to go forward with a project the state had previously blocked. The Federal Energy Regulatory Commission (FERC) granted a natural gas pipeline company permission to move forward with its project, even though the New York State Department of Environmental Conservation refused to grant the company a water quality permit required under the Clean Water Act. Under section 401 of the Clean Water Act, states must certify that a pipeline will not violate clean water standards before construction on that pipeline can begin. FERC ruled the state failed to meet a statutory one-year deadline to act on the permit request and therefore waived its authority to issue a decision on the application. Pipeline opponents criticized the federal commission’s ruling to overturn the state environmental agency’s decision.“FERC’s reversal of Governor Cuomo’s decision is an insult to New Yorkers and our right to protect our communities and our water,” Roger Downs, director of the Atlantic chapter of the Sierra Club, said in a statement. “States unquestionably have the authority to rule whether a dirty, dangerous fracked gas pipeline violates clean water laws, and nowhere is FERC granted the right to override that authority.” The New York State DEC said in a statement that it is reviewing FERC’s decision and “will consider all legal options to protect public health and the environment.”

FERC picks up where it left off, tackles backlog - The US Federal Energy Regulatory Commission renewed its monthly meetings Wednesday, with commissioners applauding efforts that kept the agency moving through its workload during the unprecedented six-month lapse of a quorum and acknowledging the still-hefty backlog of draft orders awaiting their decisions. "To say first part of this year until my friends arrived was an odd and unusual time at FERC would be an understatement," said Commissioner Cheryl LaFleur, who steered FERC through the quorum lapse, directing staff to ready draft orders for consideration. "I think Chairman [Neil] Chatterjee and his team are doing an excellent job mowing down the considerable backlog that we have," she added. The new commissioners have faced hundreds of backlogged draft orders. Chatterjee for his part told reporters after the meeting, "our primary focus is to work through the backlog and we continue to do that." FERC has approved 158 notional orders, which are those requiring votes, since its last meeting in January, he said. In addition, staff has issued 200 orders under the new delegation authority allowed by a special order since February. Some 68 of those were subject to further commission order, according to a staff presentation Wednesday that cataloged the work FERC has done during the quorum lapse.

Study slams FERC scrutiny of 'self-dealing,' demand for gas pipelines - Regulators are falling short of their duty to assess whether new interstate natural gas pipelines are supported by long-term demand, creating the potential for corporations to shift financial risks to utility ratepayers, a study by three non-profit groups released Tuesday contends. The report, dubbed "Art of the Self-Deal" by Oil Change International, Public Citizen and Sierra Club was released in advance of the Federal Energy Regulatory Commission's first monthly meeting in seven months. FERC is slated to decide on a slew of pending gas projects in the coming months. The study points to the 14% return on equity FERC has tended to allow for greenfield pipelines, saying the "excessive rate" distorts market signals, luring utility holding companies to invest in pipeline projects. That rate, first set in 1997 when interest rates were double today's average, exceeds what is typical for other major utility investments, it argues. It calls particular attention to projects that lean heavily on utility affiliates of project owners as customers, warning that FERC needs to scrutinize "self-dealing." Utility holding companies "are launching their own projects to cash in on the high returns associated with pipeline development," the report contends. It raises doubts about whether the projects will be underutilized, increasing financial risks for ratepayers. "FERC fails ratepayers when it takes at face value pipeline company estimates of future gas demand while the momentum behind clean energy's disruption of fossil fuel markets is accelerating," said Lorne Stockman, senior research analyst at Oil Change International and co-author of the report. The main regulatory agency is performing an "entirely superficial analysis," he contends, pointing to a dynamic energy landscape that makes demand for gas over the next 20 years highly uncertain. The report was met with a quick rebuke from gas industry officials who said it is little surprise groups opposed to fossil fuels or gas pipelines would conclude that they are unneeded.

High returns on new pipelines spur unnecessary capacity, report argues - Consumer and clean energy advocates say high rates of return on new interstate pipelines have led to a slew of unnecessary capacity proposals, including several which are now before the Federal Energy Regulatory Commission. A new report from Oil Change International, the Sierra Club and Public Citizen notes that pipelines already approved or pending before federal regulators this year could add more than 2,400 new miles of pipeline. Returns on pipeline investments can be as much as 40% higher than on other utility projects, the report notes, driving more companies to propose pipelines that the clean energy groups say are unnecessary.   Oil Change International's new report argues that pipeline proposals continue to pile up because the rate of return is so lucrative.  FERC allows a return on equity of 14% for new interstate gas pipelines, a rate set in 1997 when interests rates were much higher than they are today. "This comparatively high return provides an incentive for utility holding companies and gas producers to enter into the pipeline business, especially as utilities face stagnant or declining revenues from electricity sales," the report concluded. "It also incentivizes the building of new infrastructure over the efficient use of existing pipelines, which have been paid off by previous ratepayers." The return on pipeline investments is about 40% higher than for other utility-type spending, the report noted.Warnings against pipeline overcapacity have gained traction in the Northeast, where the Massachusetts Attorney General Maura Healey has questioned utility assessments of pipeline need.  A report in Platts' Gas Daily appears to support the argument. The outlet reported this week that planned pipeline capacity will add 17 Bcf/d to the Northeast by 2020, but gas demand is only expected to increase 2 Bcf/d. "FERC must overhaul its pipeline permitting process to protect the interests of U.S .consumers from the profit motives of pipeline developers," the Oil Change report concluded.

Virginia's environmental agency to press ahead on pipeline permits as other states hit the brakes | News | richmond.com: Facing a legal challenge, the West Virginia Department of Environmental Protection last week asked a federal court to vacate the water-quality certification it issued in March for the Mountain Valley Pipeline. A day later, the North Carolina Department of Environmental Quality delayed its pending decision on water-quality certification for the Atlantic Coast Pipeline, sending developers of the project, which is being led by Dominion Energy, a four-page request for more information. “The project involves numerous stream crossings that have the potential to affect downstream water quality both temporarily during construction and permanently,” the North Carolina regulators wrote. “Your application and responses to the division provide thorough general descriptions of the plans for the project. However, more site-specific detail is necessary to ensure that downstream water quality is protected.” Yet in Virginia, the state Department of Environmental Quality, which has been heavily criticized for its handling of the water-quality risks posed by the two pending natural gas pipelines, says it has no plans to slow down the process for either project. The pipelines face major resistance from environmental groups and some landowners and state lawmakers of both parties have asked the DEQ to slow the process. “The process for these proposed pipelines has been unprecedented in its scope and depth,” said Virginia DEQ spokeswoman Ann Regn. “DEQ is taking the time it needs while meeting the agency’s obligations to address these certifications in a timely manner.”

NC fracking commission plans illegal meeting on moratorium challenges, state officials say - The state’s Oil & Gas Commission appears ready to put fracking back on the political radar, in defiance of a warning from Gov. Roy Cooper’s administration that the commission lacks the legal authority to conduct state business. Jim Womack, appointed to the Oil & Gas Commission by state Sen. Phil Berger, said state law requires the Oil & Gas Commission to meet at least once a quarter. Womack noted that the matter has gained urgency since the board received five petitions requesting public hearings to challenge a pair of fracking moratoriums adopted by Chatham and Lee counties. Womack, a vocal advocate of shale gas exploration, has set up a meeting on Wednesday in Lee County to pick a chairman, swear in the members and set a hearing schedule and discuss complaints. No action is expected at the first meeting but the commission could ultimately decide the local moratoriums are illegal – a decision that would surely send the matter to court. The N.C. Department of Environmental Quality contends Womack is not even a member of the commission he purports to be organizing. In a letter to Womack sent Friday, the agency’s chief deputy secretary, John Nicholson, also noted that other Oil & Gas nominees have not been cleared to serve by the State Board of Elections and Ethics Enforcement. The ethics board is attempting to get all conflict of interest disclosures reviewed ahead of Wednesday’s meeting, said spokesman Patrick Gannon. Womack, a former Lee County Commissioner who is now chairman of the Lee County Republican Party, is prepared to proceed with the meeting without any legal or staff support from the state Department of Environmental Quality. Womack has published a meeting notice online, arranged for the meeting to be recorded, and lined up a public official to swear in the Oil & Gas commissioners at the Lee County government complex in Sanford. 

North Carolina fracking panel's 1st meeting delayed - A retooled state panel responsible for regulating North Carolina's potential fracking industry won't meet this week for the first time after all, avoiding possible legal showdowns involving Gov. Roy Cooper's administration and drilling opponents.The state Oil & Gas Commission was set to hold its first meeting Wednesday in Sanford as a commission appointee tried to jumpstart its work, which included addressing outside challenges to local fracking moratoria approved by two Piedmont counties.But Jim Womack, the appointee, said Tuesday that the meeting was postponed until late October or early November to give time for state ethics officials to review economic disclosure statements of commission appointees for conflicts of interest. Two or three commissioners filed these statements very late, Womack said.The Department of Environmental Quality's chief deputy wrote Womack late last week questioning whether the commission was legally able to convene in part due to pending ethics reviews. He said DEQ staff members weren't going to attend Wednesday's meeting."Rather than make this a legalistic battle, we would rather postpone the meeting and make sure those concerns are addressed, and then we'll proceed," Womack said in a phone interview.

FERC OKs Elba Island LNG liquefaction trains (Argus) — The US Federal Energy Regulatory Commission (FERC) today authorized Georgia's Elba Island LNG export project to install its planned 10 modular liquefaction trains. Elba Island would be the third major LNG export project to come on line in the contiguous US. The initial trains are scheduled to start operating in mid-2018, with full production by mid-2019, Kinder Morgan told Argus today. Kinder Morgan previously said the initial trains would start operating in mid-2018 and full production would be reached by early 2019. Louisiana's Sabine Pass LNG export terminal started exporting in February 2016 and Maryland's Cove Point LNG facility is on track to start service late this year. FERC said Elba Island needs separate approvals to start construction of other facilities at the site. Elba Island is the only major LNG export terminal being built in the contiguous US that will use small movable modular liquefaction trains. The trains will be built off site and delivered to the Elba Island facility near Savannah, Georgia, which houses an existing LNG import terminal. The modular trains are being built by Shell, which has a 20-year take-or-pay contract for all the planned liquefaction capacity at Elba Island. The use of modular technology will allow Elba Island to have a lower total cost and a faster construction schedule than the other projects being built in the US, but it would not necessarily provide Elba Island a lower unit cost. The estimated cost of the Elba Island project, including capitalized costs and associated pipeline expansions, is about $2.2bn. The 10 modular trains would have combined baseload liquefaction capacity of 2.5mn t/yr, equivalent to 350mn cf/d (9.9mn m³/d) of gas, and peak capacity of 4mn t/yr. The estimated cost of the 25mn t/yr Sabine Pass facility is about $20bn. Shell also has 20-year contracts for a combined 5.5mn t/yr of capacity at Sabine Pass. The six facilities being built would have combined baseload capacity of about 64mn t/yr and peak capacity of about 75mn t/yr, almost equaling Qatar capacity of 77mn t/yr. 

September Basrah Light imports at LOOP rebound from August hiatus - The Louisiana Offshore Oil Port has received a flurry of Iraqi crude imports in the past few weeks, with more expected, which could be behind a recent 30% jump in open interest on the CME’s LOOP Sour futures contract.In the initial two weeks of September, LOOP has received 2.135 million barrels of Iraqi Basrah Light in three imports, according to Platts Analytics and the latest US Customs data available. Marathon was the consignee for 550,000 barrels of 28.4 API Basrah Light, which arrived September 5 on the tanker Dilong Spirit. Valero imported a further 584,000 barrels of 29.3 API Basrah Light on September 6 on the Ilma and 1.001 million barrels of 28.8 API Basrah Light on September 7 via the tanker Solana.Platts vessel-tracking software cFlow shows another two VLCCs laden with Iraqi crude are expected to arrive at LOOP in the next month. The New Achievement is expected to arrive October 8 while the Leo Voyager will arrive October 19, both having sailed from Al Basrah, Iraq.This represents a sudden rebound in Iraqi crude arriving at LOOP. LOOP receipts of Basrah Light averaged 4.5 million b/month in January-June; however, July’s roughly 3.07 million barrels was the lowest amount since February, while none was imported in August, data shows.Just shy of September’s midpoint, LOOP has received 70% of July’s total imports and 54% of June’s total.If the barrels are not stored in leased tanks, they could find a home in one of two caverns. LOOP allocates storage of Basrah Light to a cavern called Segregation 17 — comprised of Basrah Light, Arab Medium and Kuwait Export Crude — and a second cavern for the blend LOOP Sour. LOOP Sour is a blend of US Gulf of Mexico grades Mars and Poseidon, and the blend of Middle East crudes Segregation 17.

Caribbean, USGC hurricanes could result in USGC fuel oil glut: sources  -- An active hurricane season this summer in the Caribbean region has put strain on fuel oil storage and interrupted normal flows, which could result in an influx of supply headed to the US Gulf Coast, sources said. The landfalls of hurricanes Irma and Maria over the past two weeks damaged several terminals in the Caribbean. The terminals receive fuel oil from the US Atlantic Coast, Europe, and Latin America, and frequently exports to Panama, the US Gulf Coast, and Asia. US fuel oil traders said normal exports of fuel oil out of the Atlantic Coast to Caribbean terminals have hit snags this week in the wake of the landfall of Hurricane Maria. With operations at terminals at St. Eustatius and St. Croix suspended since early September, it has left traders looking to find new homes for fuel. One USAC trader said a cargo of HSFO that normally exports to the Caribbean ended up going to Panama. Two US fuel oil traders said any diversion of fuel oil out of the Caribbean could result in fuel oil going to Houston or New Orleans, adding additional fuel to what has already been described as a growing supply glut in the USGC. A US fuel oil broker said while refineries are mostly back online following Hurricane Harvey, some cokers at refineries are still down or not operating at full capacity. US Energy Information Administration data showed Wednesday that refinery yield of fuel oil in the USGC for the week ended Friday was 3.8%, the highest in the region since January 2014. USGC fuel oil prices spiked in the wake of Hurricane Harvey as suppliers sought limited fuel to fulfill contracts. The physical USGC HSFO market was assessed Thursday at a premium of $1.80/b to the October USGC HSFO swap, an indication of extreme market backwardation. Several sources said the high premiums attracted offering interest of spot cargoes to Houston. Four sources said a cargo from Venezuela containing 500,000 barrels of HSFO was set to arrive in Houston at the end of September. The broker said that if significant quantities of fuel oil are sold into Houston instead of the Caribbean, the swap markets could flip to a contango this month. On Tuesday, USGC HSFO was assessed at a discount to the front-month swap for the first time since August 18, S&P Global Platts data showed. 

US Haynesville gas production hits 4-year high - Natural gas producers in the US Southeast are beginning to yield dividends from a bid to reverse declining production in one of the region's seemingly forgotten shale plays. Recent data from the Haynesville of Arkansas, Louisiana and Texas show production there at its highest since mid-2013. As output continues to rebound from a record low in August 2016, production from the Haynesville is already up by nearly 15%, Platts Analytics data shows. That spectacular turnaround comes amid a rapid expansion in drilling activity which has rivaled that of even the Utica or the Marcellus. In just 12 months, rig count in the Haynesville has more than tripled. Leaseholders' renewed devotion to the play comes in spite of relatively weak internal rates of return or IRRs there, which have averaged just 11% over the last year. Those returns have paled in comparison to Appalachian plays where IRRs averaged roughly 14%, in both the Utica and the Marcellus, according to data from Platts Well Economics Analyzer.

NYMEX October gas jumps 12.2 cents to $3.146/MMBtu on warmer forecasts - The NYMEX October natural gas futures contract jumped 12.2 cents Monday to settle at $3.146/MMBtu, with warmer-than-average weather expected to persist through the end of September across major demand areas.The 12.2-cent climb brings the front-month contract to its highest point since May 26, when the gas contract settled at $3.236/MMBtu.Gene McGillian, manager of market research at Tradition Energy, said "late-season cooling demand" is driving the market jump.The most recent six- to 10-day outlook from the National Weather Service calls for a high likelihood of warmer-than-average weather across the eastern half of the country, including major demand areas Chicago and New York. This continued late-season cooling demand could be giving a boost to the market as storage sits at an estimated 1.3% surplus to the five-year average, according to Energy Information Administration data. McGillian said it is possible stocks will be at their lowest point in three years heading into the winter months.Although weather outlooks currently are bullish, McGillian said production is at record levels, which could put pressure on any gains seen from the boost in cooling demand.According to Platts Analytics' Bentek Energy data, US dry production climbed to 74.4 Bcf/d Saturday, well above the 71.5 Bcf/d year-to-date average. Mexican exports and LNG feedgas have been more prevalent through 2017 than what was seen this time last year, totaling 5.9 Bcf/d year to date, 1.8 Bcf/d above this time in 2016, according to Platts Analytics.

U.S. natural gas prices rise as winter stocks look tight: Kemp (Reuters) - U.S. natural gas stocks look somewhat tight after low prices this summer worked off the excess stocks that built up in the first half of the year.  Current stocks are in line with the five-year seasonal average but that may not be enough given the increase in exports and the number of additional combined-cycle power plants that have become operational in 2017.   The last two winters have been exceptionally mild; if this winter proves colder, which is likely simply on the basis of probabilities, inventories could come under pressure. To ration power burn this winter the price of gas for delivery at Henry Hub in January 2018 has already risen by 29 cents per million British thermal units or 9 percent since early last month.  U.S. electricity producers sharply curtailed gas consumption in the first half of 2017 amid competition from alternative power sources and mild temperatures that cut overall power demand. Consumption fell by 682 billion cubic feet or 14 percent compared with the same period in 2016, according to the U.S. Energy Information Administration (“Electric Power Monthly”, EIA, Aug. 2017). First-half heating demand was almost 11 percent lower when weighted for the share of homes in each region relying on electricity for space heating. Reduced gas consumption caused stocks to rise significantly relative to the five-year average, despite a big increase in gas exports. With gas futures prices below $3 per million British thermal units for most of the summer, power burn appears to have increased during the third quarter, although detailed data have not been published yet.

Gas Producers Boost Their Already Bold 2017 Production Outlook -- An analysis of mid-year 2017 guidance shows that the nine natural gas-focused exploration and production companies we’ve been tracking are still fully committed to the very aggressive exploration and development spending they outlined at the beginning of the year. These Gas-Weighted E&Ps slightly upped their total 2017 capital budgets to $8.87 billion, a whopping 59% boost from their 2016 investment — well above the 44% and 29% increases announced by the Oil-Weighted and Diversified E&P peer groups, respectively. The gas-focused producers also increased their 2017 production guidance by 1% to 1.046 billion barrels of oil equivalent (Bboe), in contrast to the mid-year reductions in 2017 output announced by the other two peer groups. Today, we continue our review of updated capital spending plans by 43 U.S.-based E&Ps, this time with a look at companies that focus on natural gas.  Monitoring the capital spending plans and production forecasts of a sizable and representative group of U.S. E&P is helpful in assessing the status and outlook of the energy sector as a whole. In Piranha!, our market study of 43 top U.S.-based E&Ps, we examined the strategies that the companies are adopting to thrive in a world of $50/bbl crude oil and $3/MMBtu natural gas. Of that universe of companies, 21 focus on oil (60%+ liquids reserves), nine are gas-weighted producers (60%+ natural gas reserves) and 13 are diversified producers. An update of our 43 companies’ 2017 capex plans and production forecast is timely now that the E&Ps have wrapped up their second-quarter/first-half earnings announcements and conference calls. We started in Rock Steady with a big-picture look at all the companies we track. Then, in Sail On and Hold the Line, we analyzed the individual investment and production guidance for the Oil-Weighted and Diversified E&P peer groups, respectively. Today, we’re finishing up this blog series by analyzing the mid-year guidance of the Gas-Weighted Peer Group.

The narrowing light-heavy crude oil spread and what it means for US refineries - Since last winter, the price gap between light crude oil and heavy crude — otherwise known as the light-heavy differential — has narrowed considerably. In February, the price difference between Louisiana Light Sweet crude (LLS) and heavy Maya crude on the Gulf Coast was almost $10/bbl, providing an advantage to refiners who have invested in cokers and other equipment that allows them to run a heavier crude slate. But since June Maya has on average sold for only about $5/bbl less than LLS. Today we examine the shrinking price gap between light and heavy crude and its effect on coking and cracking margins. Crude oils come in a variety of qualities such as light, medium, or heavy (measured by API gravity), sweet or sour (referring to sulfur content), acidity level (denoted by total acid number), etc. Refineries are designed to process crude oils (or a mix of crude oils) meeting certain qualities to utilize their downstream processing units most efficiently while maximizing their profitability. Obviously, crude oil cost is an important factor in selecting crude oils. Heavy crude oil (with lower API gravity; see Don’t Let Your Crude Oils Grow Up to Be Condensates for more on API gravity) is more difficult and expensive to refine because it requires more complex processes to create finished refined products. Therefore, heavy crude oil is generally sold at a discount to light crude oil to account for the extra operating costs and larger investments made in downstream processing units. Lately, that discount has declined due to a number of factors –– mostly on the supply side as operational issues in key producing areas have reduced the heavy oil supply, resulting in too few barrels for too many cokers. As a result, the prices for heavier crudes like Maya (see It Ain’t Heavy, It’s My Maya) have been bid up to approach breakeven with lighter crudes. The dashed red line in Figure 1 shows the Maya price as a percentage of the price of LLS, and the solid blue line shows the discount on a $/bbl basis.

US EPA eases rules for Texas fuel storage facilities hit by Harvey - The US Environmental Protection Agency has eased several rules for gasoline storage facilities and bulk fuel terminals in Texas that were affected by Hurricane Harvey. The agency late Friday issued "no action assurance" letters waiving the rules through September 22. EPA said it would not take enforcement action against:

  • Tanker trucks for certain standards of the Clean Air Act related to tank tightness and registration.
  • Gasoline storage tank emissions during "roof landings" caused by low supplies at refineries.
  • Bulk fuel terminals that cannot operate devices to capture or recover certain air pollutants.
"Under EPA's no action assurance letters, the facilities must continue to exercise good air pollution control practices and comply with all other federal, state and local environmental laws," the agency said.

Eagle Ford Shale's big operators getting output back to pre-Harvey levels - Three weeks after Hurricane Harvey slammed into the lower Texas coast and caused widespread production shut-ins, although little actual damage, in the Eagle Ford Shale play, several big upstream operators say they are at or nearly at pre-storm levels. Devon Energy said Friday its production is at pre-storm levels in the South Texas play. The Oklahoma City-based company produced 63,000 b/d of oil equivalent in the second quarter, including 36,000 b/d of crude oil and 96,000 Mcf/d of natural gas. Devon estimated Harvey's total impact on its net liquids production in the Eagle Ford and selected other US areas to be a 15,000 b/d reduction in the third quarter, about two-thirds of it oil. The impact should be restricted to the third quarter and Devon said it represents 0.5% of its total expected volumes for full-year 2017. Hurricane Harvey tore into the Texas Coast late August 25 near Corpus Christi as a Category 4 hurricane -- the second-most powerful on the five-level Saffir-Simpson wind scale. According to one reported estimate by IHS Markit, at one point a third of the Eagle Ford's 1.254 million b/d of August crude oil production and 4.835 Bcf/d of gas output -- figures projected by Platts Analytics -- was shut in. Platts now estimates September Eagle Ford production at 1.273 million b/d of oil and 4.896 Bcf/d of natural gas. On Thursday, SM Energy said its Eagle Ford production had also returned to pre-storm levels. The company produced 88,000 b/d of oil equivalent in the Eagle Ford in the second quarter. Harvey's total effect on its production is estimated at 200,000 boe or 2,174 boe/d, effectively reducing total previous Q3 guidance to 10.6-11 million boe (115,200-119,500 boe/d). SM also said its Eagle Ford daily operations are run from its field office in Catarina, Texas, on the western end of the Eagle Ford further inland from the coast, and was not affected by the storm. In addition, BHP Billiton's Eagle Ford fields "have returned to near pre-storm levels of production and we sustained no damage from the storm," company spokeswoman Judy Dane told Platts in an e-mail.

Expect A Major Leap In U.S. Oil Exports -- Harvey knocked out more than 4 million barrels per day (mb/d) of refining capacity for a few days, but three weeks on from the storm, there is still some refining capacity offline. As of September 19, an estimated 15 of the 20 refineries affected in Texas and Louisiana were back to normal production, or close to normal production, according to IHS Markit. Another four were planning to restart operations.But that does not mean that all is well. For example, the U.S.’ largest refinery, the Motiva facility in Port Arthur, is still producing below capacity. Valero’s Port Arthur refinery caught fire earlier this week, an example of the perils of restarting a major refinery. ExxonMobil’s Baytown complex has restarted some production but is also not back to full capacity. The refinery disruptions have led to much smaller pool of refined products than would have otherwise been the case. That, in turn, has led to a buildup in crude stocks – the EIA reported another 4.6 million barrel increase in crude inventories in mid-September, the third consecutive week of sizable increases. But because global demand is still strong, the downstream bottleneck has led to a disconnect between the U.S. crude benchmark and its international counterpart. The discount for WTI relative to Brent is at its widest point in more than two years at nearly $6 per barrel, only slightly down from earlier this month. That makes sense – there is something of a surplus trapped within the U.S., while supplies are much tighter internationally. That wide disparity between Brent and WTI probably won’t last because U.S. crude is now incredibly competitive, and will likely be snatched up by buyers around the globe. “The export window is wide open,” Michael Wittner, global head of oil research at Société Générale, told the Wall Street Journal. The cost of transport has to be factored in, a matter of a couple of dollars per barrel. But that spread looks wide enough to make U.S. crude worth the trouble. “Get to a $4 spread and you can take it anywhere in the world," R.T. Dukes, an oil expert with Wood Mackenzie, said in an interview with the WSJ. The WSJ said that Occidental Petroleum has seen an uptick in exports recently, inking new deals with buyers in South Korea, India and China.

The New Texas Gold Rush: Buying Sand for Fracking; Suppliers, Wall Street firms and investors are buying up large areas of the West Texas desert to sell sand to drillers in the Permian Basin -- There is a new land grab going on in the oil-rich fields of West Texas. This time it is over sand. Big oil-field sand suppliers, Wall Street firms and other investors have been buying up swaths of the West Texas desert. These investors aim to mine and sell the sand to drillers in the region's booming Permian Basin, who need large quantities of sand to extract oil and gas from shale formations. Texas energy producers have typically bought the millions of pounds of sand that each well requires from mines located far from their drilling fields. After oil prices collapsed in late 2014, though, cost-conscious drillers reconsidered their well designs and recipes for the slurries they blast underground to unleash fuel from shale formations. Many West Texas drillers discovered that they could replace sand they had been shipping from mines 1,300 miles away in Wisconsin with finer grades found in dunes nearby. Doing so eliminates rail costs that sometimes are equal to or more than the sand itself. Now investors are lining up to supply local sand to West Texas drillers.  The Atlas mine is one of at least 18 under way or proposed for the desert outside Midland, Texas, according to Jefferies analyst Brad Handler. The first, Hi-Crush Partners LP's 3-million-ton-a-year facility, began operations in July. More than a dozen plan to open over the next year. The prospect of tens of millions of tons of Permian sand coming to market could drive down sand prices that have been rising nationally, Mr. Handler said. Analysts say that prices rose to as much as $45 a ton earlier in the year, from as little as $15 a ton last year. The sheer number of trucks needed to move the sand around the Permian is daunting. Robert Rasmus, Hi-Crush's chief executive, recently told investors that it would take 120,000 truckloads to deliver the Permian facilities' annual output.

Far from the Texas coast, Hurricane Harvey hits oil refiners -- Three weeks after Hurricane Harvey ravaged the massive fuel-making industry along the Texas coast, the region’s recovery from storm damage is starting to disrupt plans for crucial maintenance at refineries thousands of miles away from the flood zones. Harvey knocked out almost one-quarter of U.S. refining capacity in late August, sending gasoline and diesel prices soaring. The storm hit a few weeks before most of the nation’s fuel makers were set to begin seasonal shutdowns. Demand usually slows at this time of year, so it’s a good time to make repairs and install new equipment at plants that typically run all day every day. But at least 13 refineries from Louisiana to Montana with a combined 3.27 million barrels a day have delayed maintenance for weeks or months, according to company statements and people familiar with the situation. Some are churning out more fuel to take advantage of strong margins, while others simply don’t have the personnel because workers were dispatched to help repair and restart storm-hit facilities along the Gulf of Mexico. “Any plant that has the option of pushing back the work is probably going to do so,” Robert Campbell, head of oil-products analysis at Energy Aspects Ltd. in New York, said by telephone. "You have really good margins. There would be concerns about some of the skilled trades, some of the services required." The largest U.S. refinery, owned by Motiva Enterprises LLC in Port Arthur, Texas, is said to have pushed back maintenance on a crude unit to April from September, while Exxon Mobil Corp. said it delayed work at three refineries to divert workers to Texas, where it’s trying to restart its Beaumont and Baytown plants. While refiners such as Valero Energy Corp., Citgo Petroleum Corp. and Flint Hills Resources LLC were able to quickly restart plants in the Corpus Christi, Texas, area shortly after Harvey rolled through, Motiva Port Arthur, Total SA Port Arthur and Exxon Beaumont are among those still working to reach normal operations. At one point during the hurricane, at least 17 refineries either shut or operated at reduced rates. 

House votes to block funding for EPA methane pollution rule | TheHill: Lawmakers voted Wednesday to block implementation of a key Environmental Protection Agency (EPA) pollution rule. The House voted 218-195 to strip funding for an Obama-era EPA effort to limit methane emissions from new oil and gas drilling sites. Eleven Republicans voted against the amendment, and 3 Democrats voted to block funding for the regulation. “This rule is currently facing litigation and uncertainty, and Congress must act to block this job-killing regulation estimated to cost the U.S. economy $530 million annually,” Rep. Markwayne Mullin (R-Okla.) said during debate on the measure last week.“Methane emissions from oil and natural gas have significantly declined in recent decades without multiple, overlapping federal regulations, and this is no exception.” The EPA finalized its methane rule in early 2016 as part of an Obama administration effort to reduce emissions of the pollutant, which has significantly more global warming potential than carbon dioxide. The rule was a critical part of Obama’s second-term climate agenda. Stripping the methane rule from the books has been a leading goal of the oil and gas industry. Drillers have argued they are able and willing to reduce methane emissions on their own and under state regulations. They say that federal rules will harm their bottom lines. Republicans have largely backed the industry on the rule.

Leaked Zinke Memo Urges Trump to Shrink National Monuments, Allow Drilling -- Despite receiving 2.8 million comments from the public in support of our national monuments , U.S. Department of the Interior Sec. Ryan Zinke has advised President Trump to change the way at least 10 of these treasured areas are managed and to shrink the boundaries of at least four of them.Zinke's report , submitted to Trump in late August and leaked Sunday night , didn't address more than a dozenother monuments that had been under official review ."If President Trump accepts Zinke's advice and moves to eviscerate monument protections, he'd be ignoring the law—and the will of the American people," NRDC president Rhea Suh said. The monuments in question were established in previous administrations under the Antiquities Act, a 1906 law authorizing presidents to set aside federal lands for protection.The memo called for reductions to Bears Ears and Grand Staircase Escalante, both in Utah; Cascade Siskiyou in Oregon; and Gold Butte in Nevada, but it didn't include specific recommendations for their boundary changes. He also urged change in the use and/or management of six other monuments: Katahdin Woods and Waters in Maine; Organ Mountains-Desert Peaks and Rio Grande, both in New Mexico;Northeast Canyons and Seamounts Marine National Monument ; Pacific Remote Island Marine National Monument; and Rose Atoll Marine National Monument.Zinke also proposed opening these publicly held national monuments up to drilling, logging, commercial fishing and other activities for private profit. Suh emphasized NRDC's commitment to keeping these cherished lands and waters safe from destruction. "We will stand up for the nearly three million people who urged the administration to protect these monuments—in court, if necessary," she said. "We will not allow these special lands and waters to be handed over to private interests for drilling, commercial fishing, logging and other extraction."

Anti-fracking suit seeks to block BLM oil drilling in Nevada - (AP) — Environmentalists have filed an anti-fracking lawsuit in Nevada to block an effort to expand oil and gas drilling on federal land. Two national conservation groups say the Bureau of Land Management is reversing course from policies it enacted in the final weeks of the Obama administration that limited drilling on a vast stretch of federal land in Nevada.The Sierra Club and Center for Biological Diversity say the government failed to consider potential consequences of hydraulic fracturing ranging from harm to sage grouse to contamination of water resources. They say it’s the first time the BLM has specifically reversed a draft proposal to keep some otherwise unprotected lands off limits to energy exploration since President Donald Trump assumed office in January.

US court scraps limits on fracturing oversight — An appeals court today threw out a 2016 ruling that had blocked the US Interior Department from enforcing first-time hydraulic fracturing regulations on millions of acres of federal and tribal land. The 10th US Circuit Court of Appeals reached its decision after finding industry and state challenges to the regulations had become moot, now that President Donald Trump' administration has proposed to rescind them entirely. The disputed issues in the case had become a "moving target" that were not ready for legal challenges, the court found. The decision marks a major victory for environmentalists, who said that keeping the 2016 ruling intact would have stripped the government's authority from regulating fracturing. Sierra Club staff attorney Nathan Matthews said the decision would reinstate regulations that were developed under former president Barack Obama but never came into force. Even though the Trump administration proposed rescinding the fracturing regulations, it is still taking comment and will be unable to finalize a full repeal for weeks or months. Interior did not immediately respond for comment. The regulations were developed in response to concerns that some oil and gas companies were not taking sufficient steps to protect water resources when using fracturing to stimulate their wells. Interior set minimum standards for construction, wastewater storage and fracturing chemical disclosure that were supposed to apply starting in June 2015. But district court judge Scott Skavdahl issued a preliminary injunction putting the regulations on hold days before the enforcement deadline, in response to a lawsuit from oil industry groups and states. The next year he threw out the regulations because he said the US Congress had never given Interior the authority to regulate fracturing on federal lands. The Obama administration and environmentalists appealed that decision. Interior began to reconsider the fracturing rule after Trump took office. The agency proposed to rescind it entirely on 25 July and will accept public comments through 25 September. 

Safety agency cracks down on crude, petroleum pipeline spills - The Pipeline and Hazardous Materials Safety Administration is cracking down on smaller violations in the crude oil, petroleum, and hazardous liquid industries to combat a slow rise in the number of pipeline accidents. High-profile incidents that have spilled about a million gallons of crude oil have led PHMSA to scrutinize hazardous liquid pipelines more closely, lawyers say. The agency is asking more companies that operate those types of pipelines—including Anadarko Petroleum, Sunoco, Frontier Energy and Dakota Midstream—to fill gaps in their safety procedures. Companies that handle hazardous liquids, such as petroleum products, crude oil, anhydrous ammonia, biofuel, and carbon dioxide, are getting more letters and notices from the agency than gas and liquid natural gas companies are, data show. “The focus on warning letters and notices of amendment is kind of like ‘an ounce of prevention is worth a pound of cure,’” Indianapolis-based Paul Drucker, leader of Barnes & Thornburg’s pipeline practice team, told Bloomberg BNA. “They’re trying to correct smaller problems before they turn into big problems.” The American Petroleum Institute, Anadarko Petroleum, Sunoco, Frontier Energy and Dakota Midstream didn’t immediately respond to Bloomberg BNA’s requests for comment.In notices of amendment, PHMSA tells a pipeline operator that it lacks a particular safety procedure, or that an existing procedure lacks what the agency considers to be an important detail. The agency may then request that the operator revise, or amend, that procedure. The notices don’t carry penalties or mandatory compliance steps. 

Oil and Gas: 4 years later, cleanup nears end for big North Dakota spill  (AP) — Cleanup is finally in sight four years after a pipeline break sent more than 20,000 barrels of oil oozing across a wheat field in northwestern North Dakota, state regulators said Friday.Excavation of the affected site is scheduled for completion by the end of the month, with the land ready for replanting next spring, North Dakota Health Department environmental scientist Bill Suess said. The massive spill from the Tesoro pipeline was discovered by a Tioga farmer in September 2013 and has been called one of the largest onshore spills in U.S. history, covering 13 acres of land — or about the size of 10 football fields. Suess said about 1 million tons has been excavated from the site, and crews working round-the-clock over the years have had to dig as deep as 60 feet to remove oil-tainted soil. Tesoro, now known as Andeavor, would not confirm the state's completion timeline.  The Texas-based company and federal regulators have said a lightning strike may have caused the rupture in the 6-inch-diameter steel pipeline, which runs from Tioga to a rail facility outside of Columbus, near the Canadian border. Less than a third of the 840,000 gallons of spilled oil was recovered, and the remainder has been removed by a process called thermal desorption that cooks hydrocarbons from crude-soaked soil, Suess said. That process will continue over the winter, he said. The spill wasn't reported to the public until after state regulators — who had known about the spill for nearly two weeks — were questioned by The Associated Press. The company originally estimated just 750 barrels of oil was involved in the spill. Even after the size of the spill was increased to more than 20,000 barrels, the company said it expected the cleanup to cost $4 million, with a completion in two years. The company estimated cleanup costs at $73 million. State Environmental Health Chief Dave Glatt said cleanup costs could top $100 million for the company. The state fined the company $454,000 for the spill. "We saw the cost of the cleanup as a significant penalty," Glatt said.

Settlement with Dakota Access calls for industry education, planting of trees - North Dakota regulators approved a settlement agreement Wednesday with Dakota Access Pipeline that involves no fines for the pipeline developer but requires the company to plant additional trees and meet other requirements. The settlement approved unanimously by the Public Service Commission resolves a dispute over whether Dakota Access violated state law when the company failed to notify regulators after rerouting the pipeline to avoid Native American artifacts discovered in the route. The agreement also cancels an investigation into whether the pipeline developer removed too many trees and shrubs and mishandled soil during construction.Attorneys for pipeline developer Energy Transfer Partners and the Public Service Commission had been discussing the deal in recent weeks, and the company indicated shortly before Wednesday’s meeting that the provisions were acceptable, said PSC attorney Zack Pelham. The deal calls for Dakota Access to develop an industry reference manual for managing unanticipated discoveries and pipeline route changes during construction. Commissioners emphasized that Dakota Access did notify the State Historic Preservation Office last year when it discovered artifacts in Morton County and protected the cultural resources by rerouting the pipeline. The issue was with company’s failure to notify the Public Service Commission before rerouting the pipeline. The education manual is supposed to include an explanation of the importance of communication and transparency with the commission. Dakota Access also will be required to distribute the manual to all North Dakota pipeline companies, conduct training at the next Williston Basin Petroleum Conference and pay for a speaker to present to State Historic Preservation Office staff in Bismarck. 

San Francisco and Oakland sue top five oil and gas companies over costs of climate change - San Francisco City Attorney Dennis Herrera and Oakland City Attorney Barbara J. Parker announced today that they had filed separate lawsuits on behalf of their respective cities against the five largest investor-owned producers of fossil fuels in the world. The lawsuits ask the courts to hold these companies responsible for the costs of sea walls and other infrastructure necessary to protect San Francisco and Oakland from ongoing and future consequences of climate change and sea level rise caused by the companies’ production of massive amounts of fossil fuels. The defendant companies — Chevron, ConocoPhillips, Exxon Mobil, BP and Royal Dutch Shell — have known for decades that fossil fuel-driven global warming and accelerated sea level rise posed a catastrophic risk to human beings and to public and private property, especially in coastal cities like San Francisco and Oakland, who have the largest shoreline investments on San Francisco Bay. Despite that knowledge, the defendant companies continued to aggressively produce, market and sell vast quantities of fossil fuels for a global market, while at the same time engaging in an organized campaign to deceive consumers about the dangers of massive fossil fuel production. Like the tobacco companies who were sued in the 1980s, these defendants knowingly and recklessly created an ongoing public nuisance that is causing harm now, and in the future risks catastrophic harm to human life and property, including billions of dollars of public and private property in Oakland and San Francisco.

California refiners struggle in a state that wishes they would go away. - California refiners are under siege. State regulators seem to view crude oil refining as a nasty habit that needs to be broken. There’s an important catch, though: car-happy California is not only the nation’s largest consumer of gasoline — and second to Texas in diesel use — it allows only special, superclean blends to be sold within its boundaries. And California’s 12 remaining refineries need to meet tougher emission standards, too, making it difficult for them to expand their business or even modernize their plants. Today we discuss the irony that sophisticated refineries producing the cleanest fuels in the U.S. are faced with a shrinking market and no real hope of expansion. This blog is based on Morningstar Commodities & Energy’s recently published Outlook on California refineries. Please contact commoditiesdata@morningstar.com to request a copy of the full report. We’ve only covered California refineries peripherally in the RBN blogosphere. That’s probably a reflection of how isolated the state’s refining industry is from the rest of the Lower 48. California refineries have largely missed out on surging domestic shale crude supply — for two main reasons. First, there is a lack of pipeline capacity to ship shale crude across the Rockies (despite some projects being floated — see Is The Price of Freedom Too High). Second, there has been a lot of environmental pushback within California to proposals for alternative transport such as crude-by-rail (see Slow Train Coming). Initial hopes that shale crude from the state’s Monterey Formation would prove a big bounty were dashed by technical challenges (seeDo You Know The Way to Monterey). On the downstream side of the business, California’s refiners have had to contend with a heavy burden of regulatory constraints, including the tightening grip of the state’s Low Carbon Fuel Standard (LCFS) that we first covered soon after it came into force in 2013 (see Aargh Matey! Cap’n Trade Sets Sail in California). More on the LCFS in a moment.

Are Higher California Margins Worth The Hassle For Refiners? - California’s 12 remaining refineries don’t feel much love from their native state. The refinery fleet is particularly sophisticated — capable of refining mostly heavy and sour crude oil into the ultra-clean transportation fuels that state rules require. But state regulators seem to treat refiners like unwanted guests, to the point that rules have been put in place to actively encourage the shift from petroleum-based fuels to lower-carbon alternatives. The reward for refiners’ pain comes in the form of higher refining margins — particularly during unplanned outages. Today we weigh the rewards of higher gasoline and diesel prices today against a questionable future for refining in the Golden State tomorrow.  In Part 1, we identified and described California’s 12 refineries, which taken as a group have a throughput capacity of 1.86 MMb/d, according to the Energy Information Administration (EIA). Of the dozen refineries, 10 have coking units used to process heavy oil; only Kern Oil’s small Bakersfield refinery and Chevron’s Richmond refinery do not have cokers. We also noted that the state’s refineries now get most of their crude oil from overseas (primarily Latin America and the Middle East), with most of the rest coming from either California or Alaska. Refiners in the Golden State are subject to a stifling array of regulations, from the unique low emission fuels mandated by the California Air Resources Board (CARB) to the Low Carbon Fuel Standard (LCFS) that seeks to squeeze out fossil fuels altogether in favor of renewable alternatives. Unsurprisingly, the gasoline market is shrinking — the California Energy Commission (CEC) forecasts a 17% drop in gasoline demand (to 815 Mb/d) by 2030 — and the unique CARB fuel formulas make products too expensive to sell outside California. That means there are few prospects for California refineries to expand sales elsewhere to make up for declining in-state demand. As we discuss this time, about the only upside is higher retail prices and refining margins. 

Trump admin wants to allow seismic study of Alaska refuge for oil drilling - The US Department of the Interior (DOI) is moving to open up the Arctic National Wildlife Refuge to oil exploration, which could reverse 30 years of conservation efforts in the far north of the 49th state. According to a document obtained by The Washington Post that was written in mid-August, the DOI requested that the US Fish and Wildlife Service update a 1980s provision to allow new seismic exploration in the Alaska refuge. The efforts to conduct new studies of the oil and gas under the refuge’s coastal plain are still in preliminary stages—the DOI’s draft rule allowing seismic imaging study would be subject to a public comment period and would certainly face lawsuits from environmental groups if approved. Even then, exploration efforts wouldn’t automatically trigger well-drilling in the area—extraction in the Arctic National Wildlife Refuge requires the approval of Congress as well as a market environment favorable to drilling in the remote and challenging tundra region. Currently, oil is trading for around $50 a barrel, and the price isn’t expected to rebound quickly with a glut of supply in the world oil market. Without a clear way to profit off that oil, expensive tundra drilling operations are less economically attractive compared to easier-to-tap oil fields around the world.Still, the low prices may not last, and allowing companies to do exploratory studies would be a first step toward potential drilling. A 1987 study suggested that the coastal plain in question could have a vast amount of oil underneath it, and fossil fuel advocates say that if new studies are carried out, those estimates could show even more oil than previously expected. But even without drilling, seismic studies alone could threaten Arctic ecosystems. The dramatic reductions in summer sea ice that the area has experienced as a result of climate change have driven animals like polar bears ashore. Although proponents say 3D seismic imaging studies can be conducted in ways that aren't overly invasive, the exploration activities can still disrupt pristine wildlife areas and the habitats of polar bears, musk oxen, and caribou, according to a 2001 paper from Environmental Science and Technolog

Trump administration working toward renewed drilling in Arctic National Wildlife Refuge - The Trump administration is quietly moving to allow energy exploration in the Arctic National Wildlife Refuge for the first time in more than 30 years, according to documents obtained by The Washington Post, with a draft rule that would lay the groundwork for drilling. Congress has sole authority to determine whether oil and gas drilling can take place within the refuge’s 19.6 million acres. But seismic studies represent a necessary first step, and Interior Department officials are modifying a 1980s regulation to permit them. The effort represents a twist in a political fight that has raged for decades. The remote and vast habitat, which serves as the main calving ground for one of North America’s last large caribou herds and a stop for migrating birds from six continents, has served as a rallying cry for environmentalists and some of Alaska’s native tribes. But state politicians and many Republicans in Washington have pressed to extract the billions of barrels of oil lying beneath the refuge’s coastal plain. Democrats have managed to block them through votes in the Senate and, in one instance in 1995, by a presidential veto. In an Aug. 11 memo, U.S. Fish and Wildlife Service acting director James W. Kurth instructed the agency’s Alaska regional director to update a rule that allowed exploratory drilling between Oct. 1, 1984, and May 31, 1986, by striking those calendar constraints. Doing so would eliminate an obstacle that was the subject of a court battle as recently as two years ago. “When finalized, the new regulation will allow for applicants to [submit] requests for approval of new exploration plans,” Kurth wrote in the memo. 

Trump Aims For Arctic Oil And Gas -- The Trump administration is trying to lay the groundwork to open up the Arctic National Wildlife Refuge (ANWR) for oil and gas drilling, according to a report last week from the Washington Post.It won’t be easy, and it is not guaranteed to work, but the Department of Interior is hoping to crack open the door to drilling in ANWR, which has been off limits for decades. The Post reports that the Department of Interior is working to authorize seismic testing, a necessary precursor to new drilling. The agency does not have the authority to greenlight drilling itself – only legislation passed by Congress can officially open up ANWR to the industry.But the Department of Interior is clearly betting that they can start the process by allowing seismic testing, in the event that Congress acts at some point in the future to offer up ANWR to oil and gas companies. “When finalized, the new regulation will allow for applicants to [submit] requests for approval of new exploration plans,” U.S. Fish and Wildlife Service acting director James W. Kurth wrote in an August 11 memo.Drilling in ANWR has been extremely controversial and a highly partisan issue, something that Democrats and Republicans have fought over for years, across multiple administrations. But with Republicans in control of both houses of Congress and the White House, the prospect of finally allowing drilling in ANWR seems closer to a reality than ever before.“The administration is very stealthily trying to move forward with drilling on the Arctic’s coastal plain,” Defenders of Wildlife President Jamie Rappaport Clark, who led the Fish and Wildlife Service under President Bill Clinton, told the Washington Post. “This is a complete about-face from decades of practice.” It’s a gamble that will certainly run into lawsuits from environmental groups who will fight tooth and nail to keep drillers away from the unspoiled wilderness. “ANWR is an American Serengeti. You can have the oil. Or you can have this pristine place. You can’t have both. No compromise,” Robert Mrazek, a former New York congressman and chair emeritus of the Alaska Wilderness League, told Fortune.

British Columbia sees another LNG project cancellation - The province of British Columbia was dealt another blow last week when the consortium behind the proposed Aurora LNG facility announced it would not move forward with the C$28 billion (US$23 billion) project.  Nexen Energy – the Canadian subsidiary of China’s CNOOC Ltd – and its partner, Inpex Gas British Columbia, evaluated the project over a four-year period. In a statement posted on its website, Nexen said the consortium had decided that the current macroeconomic environment was not conducive to the development of a large LNG project on Digby Island, near Prince Rupert.  This latest development followed another consortium’s decision to withdraw from an LNG venture near Port Edward, BC. Malaysia’s Petronas led a consortium that sought to develop the Pacific NorthWest LNG project, which was anticipated to have a total cost of C$36 billion (US$29 billion). A downturn in market conditions compelled the consortium to scrap the project, which included a planned natural gas export terminal on BC’s northern coast and a pipeline. A GMP FirstEnergy commodity analyst, Martin King, told the Canadian Press that companies’ decisions to back out of LNG projects were not surprising. A market surplus has triggered a drop in global LNG prices to roughly US$6 per mmBtu (US$165.96 per 1,000 cubic metres).

Potential Scenarios for the 2017-18 Natural Gas Market Withdrawal Season - Three weeks ago, Hurricane Harvey threw a wrench into the natural gas market, curbing gas demand for power generation, curtailing pipeline exports to Mexico and stymieing LNG exports. The market is still digesting the full impact of these disruptions and their potential effects on the gas market balance and storage. Adding to recent market shifts is the start-up of Energy Transfer Partners’ (ETP) Northeast-to-Midwest Rover Pipeline Phase 1A on September 1, which already is flowing 0.7 Bcf/d and lifting gas production out of Ohio. In Part 1 and Part 2 of this series, we looked at the U.S. natural gas supply and demand balance for the injection season to date. While export demand has been strong this summer, gas consumption, particularly from power generators has been down hard, trailing 2016 by nearly 4.0 Bcf/d. Supply has also lagged behind last year, not nearly as much as demand.   In Part 3, we looked at the various factors at play for the balance of injection season and some scenarios for where natural gas inventories could peak. At the time, RBN’s NATGAS Billboard storage model, which assumes the 15-day weather forecast and the 10-year average temperatures beyond the 15-day period, estimated that the inventory would peak this year at around 3,780 Bcf. That would be 267 Bcf lower than last year’s record peak of 4,047 Bcf.   But we noted a variety of factors, including the effects of Hurricane Harvey and its aftermath, that could change the trajectory of injections between now and early- to mid-November, when the inventory typically peaks. We then turned to historical storage data for some potential injection scenarios. We projected that after the 15-day outlook, if the market injects at the five-year minimum, the inventory would peak right around 3,764 Bcf, not much lower than our Billboard projection.  Since we wrote about these scenarios, the fundamentals already have shifted. The EIA reported a 91-Bcf injection for the week ended September 8, a level that is indeed in line with the five-year high for the same week and about 30 Bcf higher than last year in that week. That’s pushed the inventory up to 3,311 Bcf as of September 8th, and also pushed up the Billboard projection for the season-ending peak inventory closer to 3,800 Bcf. At the same time, the market also has yet to fully assess the impacts of Hurricane Irma, which made landfall in Florida last week and temporarily doused power burn across the U.S. Southeast. Moreover, there are several more tropical storms swirling in the Atlantic — Hurricane Jose moving north off the Atlantic Coast, Hurricane Maria barreling towards the Caribbean, and Tropical Depression Lee making its way east across the Atlantic behind Maria — that could suppress power burn levels, or stall the movement of LNG tankers in and out of the Gulf of Mexico, or both.

The quest for 10 million b/d of US oil production -- The US will produce an average 9.25 million b/d this year and the number will continue to grow over the next few years, according to the US Energy Information Administration. When will US oil producers reach 10 million b/d? And what will determine whether — or how — that benchmark is reached? Senior oil editors Meghan Gordon and Brian Scheid talk with Rusty Braziel, president and CEO of RBN Energy, andJenna Delaney, a senior energy analyst with Platts Analytics, about the output goal. Did Hurricanes Harvey and Irma impact that quest, and what areas will likely contribute to the increased production?

Plastics Won’t Save Oil - Petrochemicals are Big Oil’s big hope for the future—the distant future. Petrochemicals are used in thousands of products, with the biggest group among these being single-use plastic products. The bad news for oil is that green initiatives around the world are mounting and many of them are targeting precisely this group of products.The latest such initiative came from Kenya. Last month, the East African country introduced what is considered one of the toughest bans on plastic bags globally. The making, marketing, and use of plastic bags carry fines of up to US$38,000 or up to four years imprisonment. It’s a decisive step in tackling the piles of plastic bags that so often end up inside cows, raising fears of plastic contamination of beef. Praiseworthy as this ban may be (although some bag manufacturers have warned that the new rules could result in the loss of 80,000 jobs), it’s only a small step in the right direction. Bloomberg Gadfly’s Julian Lee, an oil strategist, points out that plastic bags represent just 1 percent of all the disposable plastic trash that enters the world’s oceans and collects in one of several notorious garbage patches. The problem for the oil industry is that small steps like this could go a long way toward stymieing the growth in global oil demand. According to estimates from the International Energy Agency, plastics production will account for 4.9 million bpd in oil demand growth until 2040, followed by aviation, accounting for 3.5 million bpd, and freight, which will account for 3.4 million bpd in demand growth in the period.  With the growing number of initiatives aimed at curbing and eventually eliminating the use of disposable plastic products or finding alternatives to them, the oil industry’s focus on petrochemicals might need to shift towards a more biodegradable future, just like their focus on crude oil is having to shift to natural gas and renewables.

Venezuela to End Dollar-Denominated Oil Deals, Currency Exchanges - The Venezuelan government moved this week to phase out the use of US dollars in oil deals and official currency exchanges. President Nicolas Maduro’s government has ordered oil traders to use other international currencies such as the euro in any crude oil deals, the Wall Street Journal reported on Wednesday. According to the report, the government has ordered traders to halt all payments denominated in US dollars, while state oil firm PDVSA has asked joint venture partners to convert existing holdings to euros. The claims were based on interviews with unnamed government officials, according to the Wall Street Journal. The Maduro administration hasn’t publicly announced such a decision, though in recent weeks top government officials have argued the country should move away from the dollar. “The market is dominated by transactions with the US dollar, and we must develop other ways to conduct international transactions,” Finance Minister Ramon Lobo told state broadcaster VTV over the weekend. “We must resort to other convertible currencies: the euro, the [Chinese] yuan, the pound sterling,” he said. Then on Thursday, Lobo announced the government’s foreign currency auctions will start offering buyers currencies such as the euro and Russian rouble. “We are making the technical and technological adjustments … so that Dicom, which is our main space for auctioning currencies, develops towards [currencies] other than the dollar,” he told teleSUR. The announcement was made amid reports the government’s main currency auction system, Dicom, had abruptly stopped selling dollars. Lobo confirmed the auction house had been closed, but said it will restart operations soon. 

Scottish North Sea oil and gas sales rise by 15.2% -  An increase in production and prices has boosted the value of Scottish North Sea oil and gas, according to new figures. Official statistics showed oil and gas production in Scotland rose year-on-year by 2.9% in 2016-17 to about 74.7 million tonnes of oil equivalent. The figure, which represented 82% of total UK production, was the highest since 2011-12. The approximate sales value was £17.5bn – 15.2% higher than in 2015-16. Scottish government statisticians attributed the rise in revenues to the increase in production and a rise in prices towards the end of last year and during the first quarter of 2017. Energy Minister Paul Wheelhouse said: “Scotland’s oil and gas industry has a bright future, and it is encouraging to see this continued increase in production which has risen by a total of 25% over the last two years. These figures show that confidence is continuing to return to the sector after a number of challenging years.”

UK oil and gas production to only last another a decade -- UK oil and gas industries are reportedly entering the last decade of production due to depleting resources, according to research conducted by the University of Edinburgh. Researchers assessed the output from the offshore fields and found resources have depleted significantly, with just 11% of oil and 9% of gas currently available for recovery. Furthermore, it revealed that fracking within the UK will not be economically viable in the long-term due to the absence of suitable locations and geological features. Published by the Edinburgh Geological Society, the study recommended increasing the use of renewable energy primarily derived from offshore wind and solar sources. University of Edinburgh School of GeoSciences professor Roy Thompson said: “The UK urgently needs a bold energy transition plan, instead of trusting to dwindling fossil fuel reserves and possible fracking”.

World Wildlife Fund sues over Greece oil spill from tanker (AP) — The World Wildlife Fund filed a lawsuit Monday over extensive pollution to the coastline outside Athens following the sinking of a tanker near Greece’s largest port. The environmental group’s Greek branch filed the lawsuit in the port city of Piraeus against “anyone found responsible,” a common practice when a party that could be held legally accountable has not been identified formally. The Agia Zoni II tanker sank Sept. 10 while anchored in calm seas and carrying 2,200 tons of fuel oil and 370 tons of marine gas oil. The ship’s cargo spilled into waters where dolphins, turtles, seals and a variety of fish and sea birds feed and live. Oil slicks have extended from the island of Salamina, near where the tanker went down, to the entire length of the Athens coast. The World Wildlife Fund said it considered the case to be “an environmental crime deserving exemplary punishment.” The Greek government has faced criticism for what many observers said was a slow, inadequate response that allowed leaking oil to spread along the greater Athens area’s coastline. The tanker sank very near Piraeus, the country’s largest and best-equipped port. The government has rejected the criticism, insisting it did everything possible to contain and clean up the slick. “The effort to tackle the pollution is a difficult affair that requires the immediate mobilization of all the responsible bodies,” Prime Minister Alexis Tsipras told his Cabinet ministers in televised comments Monday. “Already, all available counter-pollution means have been mobilized and great efforts are being made.” Demetres Karavellas, chief executive of the World Wildlife Fund’s Greece office, said it was essential to identify where responsibility lies. “Through a thorough analysis of the causes, we will emerge better prepared to avert or control similar accidents in the future,” Karavellas said.

Russia’s Gazprom Rediscovers It Needs Ukraine - Gazprom has rediscovered it needs Ukraine. With the Nord Stream pipeline down for maintenance in the Baltic Sea, Russia’s only real alternative into Europe’s lucrative gas market is via Ukraine. Russia’s biggest gas exporter needs its old partner Naftogaz, at least until it finishes building the Nord Stream II line right besides the existing one that connects north Russia to Germany. Gazprom submitted an increased order of 315 million cubic meters (mcm) for gas to be shipped through Ukrainian pipelines into Europe over the weekend. The daily order for transmission of Russian gas through Ukraine has increased by 47 mcm over the past week alone, throwing Ukraine a much-needed cash infusion from Russia. For its part, Naftogaz said it was ready to “carry out the increased order in full”, even though the order size is not stipulated by the existing contract between Naftogaz and Gazprom, the company said in a press release today.

Russia set to pipe more oil to China, stepping up race with Saudis   (Reuters) - Chinese oil refineries are gearing up to receive more Russian oil transported through an expanded Siberian pipeline network from January, likely cementing Russia’s position as China’s largest oil supplier in a close race with Saudi Arabia. The planned ramp-up in pipeline supplies agreed in contracts signed in 2013 comes amid a pledge by producers to cut output to tighten global markets and illustrates the nip-and-tuck contest between the world’s top oil exporters, Russia and Saudi Arabia, for dominance in the biggest crude importer, China. Russia’s top oil producer Rosneft said it is set to supply under government agreement 30 million tonnes of ESPO Blend crude to PetroChina in 2018, or 600,000 barrels per day (bpd), an increase of 50 percent from this year, after completion of the second East Siberia Pacific Ocean (ESPO) pipeline, which has a main spur to Chinese border town Mohe. “Rosneft has enough resources to supply under all its existing contracts, including the planned increase of supplies to China by 10 million tones next year,” Rosneft said in a statement emailed to Reuters on Thursday. Top state oil firm PetroChina has designated three refineries in northeast China as the main receivers of Russian oil, with one of them undergoing an $880 million upgrade. Liaoyang Petrochemical Corp, in Liaoning province, already a regular processor of Russian oil, is expected to double its refining capacity with the upgrade to 400,000 bpd by the end of 2018, said two refinery sources. “Plants were told to be prepared for more Russian oil next year ... Liaoyang will be the main participant as it’s poorly located for seaborne shipments,” said one of the refinery sources.

China’s Oil Demand Is Growing At More Than Double Last Year’s Pace - Last week OPEC released its Monthly Oil Market Report which covers the global oil supply and demand picture through July. OPEC crude oil production decreased by 79,000 BPD in August to average 32.8 million BPD. This marks the first OPEC production decline since April and was primarily driven by sizable outages in Libya.  The cartel revised global oil demand growth for 2017 upward by 50,000 barrels per day (BPD) to 1.42 million BPD. The group reports strong growth from the OECD Americas, Europe, and China. Global oil demand for 2018 is expected to grow by 1.35 million BPD, an upward revision of 70,000 BPD from the previous report. Growth next year is expected to be driven by OECD Europe and China. China’s oil demand rose by 690,000 BPD in July, marking a 6% year-over-year (YOY) increase. China’s total oil demand reached 11.67 million BPD in July. Year-to-date data indicates an average growth of 550,000 BPD, more than double the 210,000 BPD growth recorded during the same period in 2016. China’s gasoline demand was higher by around 0.10 million BPD YOY, driven by robust sports utility vehicle (SUV) sales, which were around 17% higher than one year ago. China’s overall vehicle sales in July rose by 4% YOY, with total sales reaching 1.7 million units. The numbers from China are interesting given the constant refrain of weakening Chinese demand. This seems to be wishful thinking based on China’s investments in clean technology. China is the world’s top market for electric vehicles, and they recently announced that they have started “relevant research” and are working on a timetable for implementation of a ban on vehicles powered by fossil fuels. China may indeed join the ranks of countries banning fossil fuel vehicles. This news helps drive the narrative that the age of oil is nearing its end, but China is a long way from reining in its oil consumption growth.

Oil Traders Empty Key Crude Storage Hub - Oil traders are emptying one of the world’s largest crude storage facilities, located near the southernmost tip of Africa, as the physical market tightens amid booming demand and OPEC production cuts.Total SA, Vitol Group and Mercuria Energy Group Ltd. are selling crude they hoarded in Saldanha Bay, South Africa, during the 2015-2016 glut when the market effectively paid traders to store oil, according to people familiar with the matter, who asked not to be named discussing private operations. Crude demand is now seasonally outstripping supply, tightening the physical market for some crude varieties to levels not seen in the last two years and encouraging traders to sell their stored oil.“The market is selling inventories from everywhere,” Mercuria Chief Executive Officer Marco Dunand said in an interview in Geneva.Although largely unknown outside the oil trading industry, Saldanha Bay is one of the world’s largest crude storage facilities, with the capacity to hold 45 million barrels in just six gigantic, partially-buried concrete tanks. By comparison, Cushing, the better-known U.S. oil storage center in Oklahoma that serves as the pricing point for the West Texas Intermediate oil benchmark, can hold about 75 million barrels in more than 125 tanks. Mercuria, which operates a blending operation at the South African terminal, has been offering cargoes from the facility, with China the likeliest destination, according to traders with knowledge of matter. Total has also been seeking tankers primarily to load Nigeria’s Escravos crude from its tank in Saldanha Bay. In addition, Vitol has been unwinding its crude stores at both Saldanha Bay and in northwest Europe, the traders said. Vitol and Mercuria declined to comment on their Saldanha operations. Total didn’t immediately respond to a request for comment.

LNG growth to propel oil and gas industry's carbon emissions - (Reuters) - Liquefied natural gas will be the biggest source of carbon emission growth for the world’s top oil and gas companies by 2025, according to a new study by Wood Mackenzie, as demand for the super-chilled fuel is set to rise sharply. Oil and gas companies such as Exxon Mobil, Royal Dutch Shell and Total have promoted natural gas as a cleaner fossil fuel that will displace coal to meet growing demand for energy as the world shifts away from fossil fuels in the coming decades. But converting natural gas into LNG by cooling it to minus 160 degrees Celsius in order to transport it to demand centres is a highly energy-intensive and therefore emission-intensive process, according to WoodMac analyst Amy Bowe. Capping emissions of heat-trapping gases by the oil and gas industry has moved to the forefront of investors’ agendas in the wake of the 2015 Paris climate agreement to limit global warming to below 2 degrees Celsius by the end of the century. Companies are coming under growing pressure to tackle emissions from flaring excess gas at oil fields as well as limiting the emissions of methane, a highly potent greenhouse gas, from pipelines and LNG terminals. The Edinburgh oil and gas industry consultancy said in a study that emissions from oil and gas production operations of 25 of the world’s top energy companies are nevertheless expected to rise by 17 percent by 2025. Fossil fuel output will increase by 15 percent over the same period. Emissions resulting from LNG production are forecast to grow by 43 percent over the period compared with a 22 percent increase in supply, “representing the largest absolute increase in emissions,” according to the report. Around 10 percent of gas processed by an LNG terminal is lost into the atmosphere, Bowe said in an interview. “If you look at the emissions produced just through the extraction and production of it, LNG is more emissions-intensive than pipeline gas and that is largely due to the liquefaction process,” Bowe told Reuters.

“Super Critical” Coal Shortage Sends India Scrambling For NatGas - Local media reported this week that India’s power generators are seeing a sudden surge in natgas buying because of an “acute” shortage in the country’s go-to energy fuel: coal. With ten major power plants classified as “critical”, with less than seven days of coal stocks — and five of those being “super critical” with less than four days of coal supply. And that drastic shortage has reportedly turned these generators to natural gas in a major way. India in fact has over 25 GW of installed gas-driven generating capacity. But here’s the thing: 55 percent of that capacity usually never runs. Because it’s “technically stranded” — having no access to natgas feed at commercially-competitive prices. But the coal crisis is changing the economics here. Power operators are so desperate to keep the lights on, they’re willing to pay the higher prices required to deliver gas to the stranded power plants — causing this week’s major surge in natgas buying. If the coal shortage persists, that demand could become permanent.

World’s largest LNG buyer posts decline in August imports | LNG World News: Japan’s liquefied natural gas (LNG) imports dropped by 6 percent in August year-on-year, according to the provisional data released by the country’s Ministry of Finance. The world’s largest buyer of the chilled fuel imported 7.26 million mt of LNG last month as compared to 7.72 million mt in August 2016. This is Japan’s second monthly decline in LNG imports this year. Japan paid about $3.1 billion for LNG imports in August, a rise of 27.4 percent when compared to the same month in 2016. On the other hand, the country’s coal imports for power generation rose by 23.5 percent to 10.1 million mt, the data showed. To remind, the average price of spot LNG imported into Japan that was contracted in August was at $5.8 per million British thermal units (mmBtu), reaching a five-month high. The arrival-based price was at $5.6 per mmBtu, the same as the previous month that was the lowest since August 2016.

South Korea's Kogas August LNG sales fall 11.8% on year -- South Korean state-owned Korea Gas Corp's LNG sales dropped 11.8% year on year in August due to mild summer weather, the company said Monday. Kogas, which has a monopoly in domestic natural gas sales, sold 1.94 million mt last month, from 2.2 million mt a year earlier, the utility said in a regulatory filing. It marked the fourth consecutive decline after rising for three months in a row early this year. August sales were also down 9.3% from 2.14 million mt in July. Kogas did not disclose how much LNG it sold for the first eight months, but S&P Global Platts calculations based on Kogas' previous report showed it sold 20.73 million mt over January-August, down 1.9% from 21.14 million mt in the year-ago period.

Middle East 2018 LPG term supply volume set to be stable on year - The 2018 LPG term supply volume from the Middle East is expected to hold stable from 2017, despite expectations of lower LPG production due to the crude oil output cut agreement among OPEC and non-OPEC members, traders said this week, as the term contract renewal negotiations kicked off."There is no big reason why the term volumes might change from this year to the next," a Middle Eastern trader said. His views were echoed by other Asian term lifters and Persian Gulf producers as well.Saudi Aramco's 2018 LPG exports would be largely steady from this year, a company source said Wednesday. "The term volume next year would be similar to this year's, around 8.5 million to 8.9 million mt," the Aramco source said. He added that there will be little impact on LPG production from the OPEC-led crude output cuts, as most of the LPG produced in Saudi Arabia is from associated gas.

Oil revenues real motive for Kurdistan independence vote -- Iraq's semi-autonomous Kurdistan region is to hold an independence referendum on September 25 -- a move that the central government in Baghdad is strongly opposed to. Regional players like Iran and Turkey have also raised the alarm about the planned referendum, arguing that it could create further instability in the region. Press TV has discussed the issue with Sa'ad al-Muttalibi, a member of the State of Law Coalition, as well as Nabil Mikhail, a professor at George Washington University.Sa’ad al-Muttalibi believes the leader of Iraq’s Kurdistan region, Massoud Barzani, has been using the referendum to further blackmail the political system in the country to gain higher oil revenues.He went on to say that Barzani’s main aim is to add the Kirkuk region, which accounts for about 40 percent of Iraq’s total oil production, to the new Kurdish independent state.Authorities in the Iraqi Kurdistan want Kirkuk, which is divided along ethnic lines between Turkmen, Kurds and Arabs, to be included in their autonomous protectorate, but Baghdad rejects it.The province is aggressively coveted by Kurdish authorities because it holds more than 9 billion barrels of oil reserves, with a capacity to produce more than 1 million barrels a day.The analyst also asserted that Barzani is well aware that the establishment of an independent Kurdish state will definitely constitute a threat to the national security of Iraq and the neighboring countries in the Middle East. However, he said, the Kurds are planning to go ahead with the referendum which is “illegal and unconstitutional” without considering its “serious threats.”

OPEC’s No. 2 Faces Civil War Threat -- Tribal violence in the southern regions of Iraq is erupting on sectarian lines, threatening safety and security at oil facilities, officials told Kurdistan24.A majority of Iraq’s law enforcement network has congregated in the northern and western portions of the country to contain the efforts of the Islamic State to restart the reign of its illicit organization, giving Shia and Sunni the leeway to reignite previous rivalries. “We need larger forces to control rural areas and restrain lawless tribes in the south,” Army Lieutenant Colonel Salah Kareem said. “This is a difficult job for now as most troops are busy with fighting [IS].” The religious disputes turn legal as members quarrel over farmland, construction contracts, and other land ownership issues, security courses said. The net impact of the disagreements disrupts Baghdad’s efforts to bring new investments to the oil and gas sector in areas affected by three years of domestic strife. Stable oil output from Basra is key to Baghdad’s wealth, which accounts for 95 percent of the government’s revenues. Recent encroachments on the peace in the area have jeopardized key oil facilities on the northern and westerns sides of the city.“Tribal feuds have been exacerbating recently, and such a negative development could threaten the operations of the foreign energy companies,” Ali Shaddad, the head of Basra’s oil and gas committee on the provincial council, said.Groups in the area seized heavy weaponry from Saddam Hussein’s army back when the dictator’s regime collapsed in 2003. The presence of these military-grade guns makes any conflict in the area that much more deadly.

The Most Bullish Oil Report This Year - Despite the huge uncertainties related to the two massive hurricanes that hit the U.S., the global oil market looks tighter than it has in a long time, according to a new report from the International Energy Agency. Global oil supply fell in August for the first time in four months, the IEA said, a result of a dip in OPEC’s oil production, combined with refinery maintenance and sizable outages from Hurricane Harvey. World oil supply fell by 720,000 barrels per day (bpd) in August compared to July, a significant decline that will aid in the market’s progress towards rebalancing.Multiple outages contributed to the decline in global output. Hurricane Harvey resulted in U.S. oil production falling by 200,000 bpd in August—outages that occurred mostly in the Eagle Ford shale and offshore in the Gulf of Mexico. But OPEC also saw its collective output fall by 210,000 bpd in August, mainly from disruptions in Libya.The supply outages will go a long way toward adding some momentum to the rebalancing effort, even if some of them are only transitory.Another notable issue, the IEA said, was that U.S. oil supply is quite a bit lower at this point than it expected, and not just because of Harvey. The agency singled out the fact that U.S. oil production actually declined in June from a month earlier, an unexpected development. That meant that the Harvey disruptions resulted in output declines from a lower-than-anticipated base. The demand side of the equation also looked bullish. The IEA revised up its forecast for oil demand growth this year, upping it to 1.6 million barrels per day (mb/d) from its July estimate of just 1.5 mb/d. The second quarter stood out, with quarterly growth of 2.3 mb/d year-on-year—the highest in two years. The Paris-based energy agency said that demand in OECD countries (i.e., rich industrialized countries that tend to have weak demand growth rates) “continues to be stronger than expected, particularly in Europe and the U.S.” The stronger forecast is notable not just because it puts oil demand growth at its hottest in a long time, but also because the IEA essentially shrugged off any lingering effects from the storms in the U.S., concluding that the “impact on global markets is likely to be relatively short-lived.”

OPEC, non-OPEC ministers mull oil output cut extension through 2018: Luaibi -- Ministers in the OPEC/non-OPEC coalition are considering various options to extend their crude oil output cut deal, including an additional 1% reduction in supplies and a continuation of the deal through the end of 2018, Iraq's oil minister said at a conference Tuesday. But no firm decisions have yet been reached, Jabbar al-Luaibi told delegates at the Gulf Intelligence Energy Markets Forum in Fujairah, adding on the sidelines that he personally did not see the need for further cuts but would support any OPEC consensus on the issue. It would be "premature" to make any changes to the agreement, seven months before its March expiry, he said. The agreement, which went into force January 1, calls on OPEC and 10 non-OPEC producers, led by Russia, to cut a combined 1.8 million b/d in output through March 2018 in order to rebalance the market and induce draws of oil from storage. The Joint Ministerial Monitoring Committee overseeing the deal, consisting of ministers from Kuwait, Russia, Venezuela, Algeria and Oman, will meet Friday in Vienna to assess compliance and review market conditions, including the impact of hurricanes Harvey and Irma. Representatives from Nigeria and Libya, both of which are exempt from the cuts as the nations' recover from civil unrest, will also attend to provide their production outlooks. No decisions on the cuts are expected at the meeting, with OPEC sources having said that any changes to the agreement likely will not be voted on until the bloc's next full summit on November 30. "This is a routine meeting of the JMMC," one OPEC delegate told S&P Global Platts. OPEC's total crude oil output fell in August for the first time in five months to 32.65 million b/d, down 170,000 b/d from June, according to the latest Platts OPEC survey, which is one of six secondary sources used by the organization to monitor production. The fall in output came as outages in Libya interrupted the country's recent dramatic recovery, more than offsetting gains in Nigeria.

OPEC says it is winning the battle to curb the oil glut. (Reuters) - Output cuts by OPEC and other oil producers are clearing a supply glut that has weighed on crude prices for three years, ministers said at a meeting on Friday to review the pact that expires in March 2018. The Organization of the Petroleum Exporting Countries, Russia and several other producers have cut production by about 1.8 million barrels per day (bpd) since January. The group is considering extending the deal beyond its March expiry, although two sources said Friday's gathering was unlikely to make a specific recommendation on an extension. Ministers on a panel monitoring the pact, comprising Kuwait, Venezuela and Algeria, plus non-OPEC Russia and Oman, were meeting in Vienna after oil prices gained more than 15 percent in the past three months to trade above $56 a barrel. "Since our last meeting in July, the oil market has markedly improved," Kuwaiti Oil Minister Essam al-Marzouq said in an opening speech at the meeting he is chairing. "The market is now evidently well on its way towards rebalancing." Russian Energy Minister Alexander Novak said OPEC and other producers now needed to work on strategy beyond March. "We need not only to keep up the pace but continue our coordinated joint actions in full, but also work out a strategy for the future, to which we will stick starting from April 2018,” he said, adding oil demand was rising at a "high pace". Officials said before Friday's meeting that the Joint Ministerial Monitoring Committee would consider extending the supply cut pact. But two OPEC sources said the ministers were not likely to make a specific recommendation for an extension. The committee can make policy recommendations for the wider group of OPEC and non-OPEC producers, which meets in November. Global oil inventories have shown signs of falling, although OPEC-led efforts to cut stockpiles to their five-year average has taken longer than expected. Oil prices remain at only half their level of mid-2014.

Storms worsen unprecedented summer slump in U.S. diesel supply (Reuters) - U.S. diesel stockpiles did something this year that has never happened in the summer before: They shrank. And that was even before Hurricane Harvey landed, knocking out a quarter of U.S. refining capacity, crippling production of fuel products. Thanks to surprising summer demand, particularly from exports, inventories of diesel, jet fuel and heating oil were heading into the busy winter at their lowest levels in three years. Harvey’s effects cost refiners even more production of fuel, raising the possibility of shortages and higher prices if the United States suffers another major disruption or an unexpectedly frigid winter. Since 2000, between June and September distillate inventories have risen by an average of 10 percent, but this year, they fell by 2.2 percent, the first decline since 1982 when record-keeping began, a Reuters analysis of U.S. Energy Information Administration data shows. The summer is typically when refiners build stocks of distillates to meet growing fall and winter demand for heating oil and crop harvesting. “If we get another hurricane or similar event, things could get real tight,” said Robert Campbell, head of oil products markets at London-based Energy Aspects. Inventories typically remain flat or rise modestly through September, and while some refiners delayed scheduled work, the loss of the Gulf has hit overall U.S. refining. As a result of Harvey, distillate stocks fell another 4.6 million barrels in the first two weeks of September, EIA data shows. U.S. distillate stocks are now at three-year lows for this time of year, and 5.2 percent below their historical average. The last two winters have been among the warmest ever recorded, but forecasters this year are predicting a colder, more typical season, according to Reuters data. 

Hedge funds crowd in to bet on gasoline and diesel: Kemp (Reuters) - Hedge funds continue to wager on a shortage of refined fuels driving prices higher, even as U.S. refineries gradually restart operations in the aftermath of Hurricane Harvey.Hurricane-related flooding caused extensive disruption to the major U.S. refining centre along the Gulf of Mexico in the first half of September. But most Gulf Coast refineries have begun to restart and should be fully operational within the next few days, with only limited outages lingering for longer.And exceptionally high refining margins are encouraging refineries in the rest of the world to maximise output to cover the supply shortfall.The post-hurricane bet on fuel shortages therefore risks becoming a crowded trade with a sharp price reversal when portfolio managers try to take some profits and exit.Hedge funds and other money managers raised their net long position in U.S. gasoline futures and options to 69 million barrels in the week to Sept. 12, the highest level since May 2014.Sentiment has experienced a sea change since mid-June, when portfolio managers were running an overall short position of 21 million barrels (http://tmsnrt.rs/2xKUtGV).  Hedge funds also lifted their net long position in U.S. heating oil by 5 million barrels to 46 million barrels last week, the highest since February 2013, according to the latest data from regulators and exchanges.And fund managers boosted their net long position in European gasoil by 1.2 million tonnes to a record 17 million tonnes.Hedge fund positioning in all fuels appears very stretched with long positions outnumbering shorts by 19:1 in gasoil, 4.4:1 in gasoline and 3.5:1 in heating oil.In contrast, positioning in the main crude oil contracts linked to Brent currently appears much less lopsided and there is an unusually low ratio in WTI.The likely outcome is a sharp narrowing of gasoline and distillate cracks when the post-hurricane trades unwind, with crude and especially WTI prices rising while gasoline and diesel come under pressure.

IEA: Oil Price Spike Coming In 2020 - The oil market has been awash in crude for more than three years, and OPEC has struggled to accelerate the rebalancing effort, but the world could be heading for a supply crunch in a few years due to the sharp fall in industry spending.The halving of oil prices from $100 per barrel before 2014 down to just $50 today has led to a corresponding plunge in upstream investment. But even as benchmark prices seem to have stabilized over the past year, with most analysts predicting gradual and modest gains in the year ahead (depending on OPEC’s actions), there’s still no sign of a serious rebound in spending levels.The problem of a shortage of supply seems very far off today, given the swift turnaround in U.S. shale and persistently high levels of crude storage.But demand continues to rise—the IEA just upgraded its demand growth estimate for 2017 to 1.6 million barrels per day (mb/d). If that level of demand growth continues for a few years, it will more than devour the excess supply on the market. Even a more tempered growth rate would strain supplies toward the end of the decade, absent a corresponding uptick in production.“There are still not enough signs of investment beginning to return, and that raises the risk of tightening of the market in the next five years and a risk to the stability of oil prices,” Neil Atkinson, head of the IEA’s oil markets and industry division, said at a conference in Bahrain.“There is at least a possibility of going back to the situation we had 10 years ago where oil prices were very, very high at a time when demand was growing.”Atkinson warned that the market’s spare capacity—largely concentrated in Saudi Arabia—will dwindle as demand keeps rising at a time when supply remains stagnant. The market will tighten and OPEC will have to abandon its production limits in order to satisfy demand. After that, rising consumption could whittle away at the latent surplus capacity. At that point, the market will hit a supply crunch, which would likely result in higher volatility and higher prices. The one difference between the mid-2000s and today, however, is that the market is sitting on near record levels of oil in storage, which will act as a sort of second form of spare capacity. It could take a few years to draw down those stockpiles. On the other hand, unlike 10 years ago, the industry today isn’t spending huge sums to develop new sources of supply.  Spending has increased a bit this year, but the IEA still warns that it is insufficient to meet future demand.

Have Oil Markets Reached A Turning Point? - WTI and Brent hit fresh highs in early trading on Tuesday, with oil demand looking particularly robust and fears over hurricane damage to the market having receded. Both benchmarks were at their highest levels in months but saw a slight drop off as trading continued.. After a quarter of U.S. refining capacity was knocked offline, fuel shortages cropped up, creating a unique opportunity for unaffected refiners. “You’ve got a lot of refiners running at full tilt, and they’re going to make better margins,” Sandy Fielden, an energy analyst with Morningstar Inc., told the WSJ. “Supply and demand is effectively telling the market that there’s a big incentive to produce more.” Refining margins for some East Coast and Midwestern processors have jumped by as much as a third, the WSJ says. PBF Energy (NYSE: PBF), a company with refining assets in the Northeast and the Midwest, has seen its stock price surge by as much as 26 percent since August 21.   The WSJ reported over the weekend that the U.S. might not actually withdraw from the Paris climate accord, despite President Trump’s decision to do so in June. The Trump administration denied any change in policy, and the President’s top economic adviser, Gary Cohn, met with climate ministers from around the world on Monday. He told them that the U.S. would only stay in the Paris climate pact if the terms of doing so were more favorable. However, the administration routinely fails to recognize the fact that the pact consists of voluntary, not mandatory, targets. In theory, the administration could revise its commitments and stay in the pact.   Iraq’s oil minister hinted that OPEC might consider deeper and longer cuts, pushing the current output limits out through the end of 2018. Jabbar al-Luaibi said the group could take an additional 1 percent off of global supply, which would help to further rebalance the market. Still, he said there is “no firm decision yet.”

WTI/RBOB Jump After Smaller Than Expected Crude Build --After last week's record-breaking draw in Gasoline stocks, and big crude build, the noise from Harvey and Irma disruptions continues to add volatility to the data. API reported asmaller than expected crude build and bigger than expected gasoline (and distillates) draw sent prices for both WTI and RBOB higher. API:

  • Crude +1.43mm (+3.9mm exp)
  • Cushing +420k (+900k exp)
  • Gasoline -5.063mm (-2.13mm exp)
  • Distillates-6.13mm

A smaller than expected crude build and considerably bigger than expected draws in gasoline and distillates...WTI and RBOB prices slipped lower on the day heading into the API print with Crude glued at $50...The kneejerk reaction was a spike in both WTI/RBOB...

Oil Price Volatility Is Set To Return - Oil markets could experience more intense price volatility in the coming years because of insufficient investment in new production, according to the head of the International Energy Agency’s oil market and industry unit, Neil Atkinson.  Over the next five years, it is not impossible to see a return to the high oil prices from a decade ago, Atkinson said.In its latest Oil Market Report, released last week, the IEA said crude oil demand had grown by 2.3 percent on an annual basis in the second quarter, which prompted an upward revision of the overall growth rate for 2017 to 1.6 million bpd. The revision boosted oil prices, with Brent once again above US$55 a barrel for the first time in about five months. Atkinson noted at the Manama conference that although over the medium term the rate of demand growth will slow, it may do so from a higher point than previously forecast, in tune with the new demand growth revision. What’s more, over the longer term, to 2040, the IEA forecast the share of oil in the global energy mix will decline only slightly, from 33 percent in 2015 to 31 percent in 2040, which means stable growth in demand as part of the growth in wider energy demand. The problem with new investments, however, remains. Bahrain’s oil minister, speaking at the same event as the IEA official, said that although prices have improved lately, they are not high enough to motivate sufficient investment in new production. Bahrain’s top oil man is not the only one warning about a possible supply crunch, but given these officials’ vested interest in the effect of supply crunches on prices, their comments are better taken with a pinch of salt.

Weekly Petroleum Report -- September 20, 2017 Weekly petroleum report, highlightsRe-balancing: 46 weeks.

  • crude oil inventories increased by 4.6 million bbls from the previous week
  • at 472.8 million bbls, US crude oil inventories are in the upper half of the average range for this time of year; two points to consider:
  • number of years to determine the average not stated
  • the huge glut of crude oil inventories since 2014 have skewed the average upwards
  • gasoline inventories decreased 2.1 million bbls, but gasoline also remains in the upper half of the average range;
  • gasoline supplied: average 9.5 million bbls per over the past four weeks
  • distillate fuel product was up 14.5% from the same period last year
  • refinery operating capacity clawing back from a recent low of 79% to 83% this past week
  • gasoline production continues to decrease on a weekly basis while distillate fuel production is increasing
  • US crude oil imports increased by almost one million bopd (actual: 888,000 bopd)

WTI/RBOB Drop After Smaller-Than-Expected Gasoline Draw, Big Crude Production Rebound --API data (smaller than expected build) and a weaker dollar have supported WTI overnight but as the DOE data hits, we are reminded that the impact from hurricane season lingers. WTI/RBOB prices kneejerked lower after DOE reported a bigger than expected crude build and a gasoline draw that was considerably smaller than API's reports. Crudeproduction continues to rebound back near cycle highs. DOE:

  • Crude +4.59mm (+3.9mm exp)
  • Cushing +703k (+900k exp)
  • Gasoline -2.13mm (-2.13mm exp)
  • Distillates -5.693mm (-1.95mm exp) - biggest since Nov 2011

A big Distillates draw (most since Nov 2011) is being ignored for now as gasoline's draw was considerably less than API reported and crude's build more than expected... Distillates stockpiles are now lower than the five-year average and totals are at the lowest level since July 2015.As Bloomberg's Laura Blewitt notes, as expected, refinery runs rocketed up last week. Both crude inputs and gross oil inputs rose by the most since 2008 as Gulf Coast refiners got back online. Production continues to rebound as more of Texas comes back online (despite the stagnation of oil rig counts)... Heading into the DOE print, WTI was higher and RBOB lower since API (helped by a slightly weaker dollar) but both weakened on the DOE print kneejerk...

Refinery margins to benefit from low product, high crude oil stocks levels - Refinery margins in the US and Europe will remain supported by increasing crude and decreasing product stocks levels, according to data by PJK International."Th outlook is quite positive," Patrick Kulsen, managing director of PJK International told Platts annual refining conference in Brussels Friday. “We expect refinery margins to remain strong for the medium term," Kulsen added.Crude stocks have been growing as US production remains strong in a move similar to the end of 2014 when crude oil was sold at discounts "to stimulate higher utilization rates," said Kulsen.2015 saw refineries ramp up their utilization to capture the healthy margins, which in turn brought up higher stocks levels in 2016 which pushed both refinery runs and margins down. But this year "product stocks have been lowered significantly," Kulsen said, while product demand is up "with European economic growth and international trade gaining momentum." Distillate demand has increased both in the US and Europe, Kulsen said.

U.S. heating oil market looks tight this winter: Kemp (Reuters) - U.S. stocks of distillate fuel oil, which have been trending downwards all year, now look tight following disruption to major refineries caused by Hurricane Harvey.The position is a marked turnaround from the start of the year, when distillate stocks were at record levels following the second warm winter in a row and a prolonged slowdown in freight movements since 2015 (http://tmsnrt.rs/2xXkH9p).Distillate fuel oil is used mostly for high-horsepower diesel engines used in trucks, trains, barges and pipelines as well as some industrial engines, so demand is closely linked to manufacturing activity and freight movements.Distillates are still used as heating oil for some homes, schools and commercial buildings, especially in the Northeast, though this source of seasonal demand has become less important in recent years.By the second week of February 2017, distillate stocks stood at 170 million barrels, which was 8 million higher than at the same point in 2016 and 33 million above the 10-year seasonal average.But a recovery in freight, coupled with a boom in oil and gas drilling, which relies heavily on diesel, and record exports to Latin America and other markets have steadily whittled away the surplus.By the end of August, stocks had fallen almost 14 million barrels since the start of the year, were 5 million barrels below the corresponding point in 2016, and just 8 million above the long-term average.Refinery outages in Texas and Louisiana following Hurricane Harvey have caused stocks to decline by another 10 million barrels since the start of September, leaving inventories looking tight with winter approaching.Distillate stocks had fallen to just 139 million barrels by the end of last week, which was 25 million barrels below 2016 and 5 million barrels below the long-term seasonal average. In response, futures prices for ultra-low sulphur diesel (ULSD) this winter have moved in a big backwardation since the end of August, reflecting concerns about scarcity. .. U.S. distillate prices are already rising to reduce exports and encourage refineries in the United States and elsewhere to ramp up production.The last two winters have been exceptionally mild in most of the United States which has limited heating oil demand.But if temperatures in the forthcoming winter are closer to the long-term average, distillate stocks could become very tight without very high refining runs.

Commentary: Looking for balance in the oil market – IEA -  There is more than one way to look at oil-market balances. The IEA uses a straightforward approach: supply minus demand, which we report in the monthly Oil Market Report as “Total stock changes and Miscellaneous.” Part of the calculation can be easily explained by changes in OECD stocks, floating storage and oil in transit. The remaining “miscellaneous to balance” is less clear. This element, which implies unreported non-OECD stock changes, has come under scrutiny recently particularly as Chinese crude-oil balances have risen to unprecedented levels. The following commentary expands on the analysis we provided in the September issue of the Oil Market Report, where we took a close look at our “miscellaneous to balance” and drew a distinction between crude oil and product balances to have a clearer view of oil market developments. The world oil market appears to have returned to balance this year, thanks to a substantial stock draw in the second quarter. As global demand exceeded supply, our balances in 2Q17 implied a 0.9 million barrels a day (mb/d) decline in inventories, the first draw since 4Q13. Somewhat counter-intuitively, the price of Brent was $4/bbl below the first quarter.   In 2Q17, refined product markets drew nearly 1 mb/d of stocks, as refining activity lagged demand growth. The OECD refined product stocks drew by 0.3 mb/d, implying a 0.6 mb/d draw from non-OECD countries. There is no comprehensive non-OECD stocks data to confirm this, however non-OECD total demand grew by 1.1 mb/d year-on-year in 2Q17 while refining throughput was flat. A 0.6 mb/d draw was close to the 0.5 mb/d implied build in 1Q17, so the stock draw would have been technically possible. Forecasts of refinery runs and demand for 3Q17 and 4Q17 imply continued refined product stock draws. Even in 3Q17, when global headline oil balances show an oversupply of 0.4 mb/d, refined products are forecast to draw by a counter-seasonal 0.4 mb/d, in part due to the hurricane outages in the US Gulf Coast. The draw accelerates in 4Q17 and is double the size of our headline total oil balances.

OilPrice Intelligence Report: Is $50 Oil The New Normal?: OPEC met on Friday to consider the possibility of extending the production cuts beyond March 2018. The meeting was uneventful, with no decision taken in regard to recommendations on extending or deepening the production cut deal. The recent uptick in oil prices will provide OPEC members with a bit of confidence as they sort out their next steps, but pitfalls remain for 2018. “The bull run in the oil market is running out of steam as unease builds” Stephen Brennock, analyst at London brokerage PVM Oil Associates, told Reuters on Thursday. While oil markets did not react too negatively to the lack of news, all eyes will be on OPEC as the production cut deal nears its agreed upon deadline. In preparation for its IPO next year, Saudi Aramco is stepping up its oil trading arm, buying and selling oil produced outside of Saudi Arabia. Crude marketing and refined product trading will fall under the same unit, Bloomberg reports. “We’ll keep selling our own oil as normal, and we want to get into trading third-party crude,” Ibrahim Al-Buainain, who will head the expanded unit, told Bloomberg. Aramco is hoping to get into a business that the international oil majors are already involved in. . Bloomberg Gadfly points out that some large oil companies are trapped between pure-play E&Ps and the absolute largest oil companies, offering up a rather unappetizing opportunity for investors. Companies like Anadarko (NYSE: APC) are too large to offer the huge upside potential that small shale drillers have, but they are also not as safe as the likes of ExxonMobil (NYSE: XOM), leaving them with a tricky investment case. As such, the share price of Anadarko has sagged, and in fact, the company just decided buy back shares as a way of appeasing restless investors. Bloomberg Gadfly suggests Anadarko’s predicament is illustrative of a broader problem with oil companies of similar size, who are posting disappointing cash flow figures as they drill more and grow larger. . The EIA reported another significant drawdown in gasoline stocks, which is in part due to the lingering refinery outages in Texas, but also because demand is proving to be robust. U.S. gasoline stocks are now well within the five-year range, and globally, OECD refined product stocks are closing in on five-year averages. Refineries around the world are going to need to pick up the pace, which means crude drawdowns should be forthcoming. “If OPEC is really still willing to commit to extending production cuts, that gives this market some room to test the upside here,” Rob Haworth of U.S. Bank Wealth Management, told Bloomberg.

Oil Steady At $50 Amid Falling U.S. Oil Rig Count - The number of active oil and gas rigs in the United States fell this week by 1 rig.  The total oil and gas rig count in the United States now stands at 935 rigs, up 424 rigs from the year prior, with the number of oil rigs in the United States decreasing by 5 this week and the number of natural gas rigs increasing by 4. Canada’s rig count additions appears to be leveling off, and despite its large swings in the number of active rigs on a weekly basis, has roughly the same number of oil rigs in operation that it had back at the end of July. Canada’s natural gas rigs, on the other hand, are still upwardly mobile, climbing by almost 30 rigs since mid-June. This week, Canada added 10 oil rigs for the week ending September 22, and lost 2 gas rigs.Oil rigs in the United States now number 744—326 rigs above this time last year. Although the number of oil rigs are still up significantly year on year, the increases slowed in the Q2 2017, and have reversed in Q3. The first quarter 2017 saw 137 oil rigs added in the United States, while the second quarter 2017 saw 97 rigs added. In stark contrast, the third quarter, for which there is still one week to go, has seen the total number of rigs decrease by 12. The signs are clear—US drillers are no longer adding rigs at breakneck paces, despite the rise in oil prices.The spot price for WTI fell earlier on Friday, down 0.12% to $50.49 at 12:10pm. Brent crude, however, was trading up 0.18% on the day at $56.53—the second week in a row that Brent was up while WTI was down.All eyes are on OPEC as well as the Baker Hughes rig count today, and while OPEC has concluded its meeting, it has left the market wanting. Both Russia and OPEC, post-meeting, assured the market that it had won the battle over the oil glut, but pushed out until November the decision on whether it should extend the production cuts beyond March 2018. The disappointment from the lack of decision regarding the output cut was tempered as few expected such decisive action. What little disappointment did exist was likely already priced into the market. Both OPEC and Russia added that they were about halfway finished with clearing the global oil glut, and encouraged members to remain vigilant and set upon their task of reining in production. At 10 minutes after the hour, WTI was trading at $50.46 with Brent crude trading at $56.60—both up from last week.

Baker Hughes: US rig count drops for sixth time in 8 weeks - Oil & Gas Journal: The US rig count during the week ended Sept. 22 declined for the sixth time in 8 weeks, again anchored by a drop in oil-directed rigs.Baker Hughes’ overall tally of active rigs in the US edged down a unit to 935, down 23 units since a peak of the drilling rebound on July 28 (OGJ Online, Sept. 15, 2017). The count is still up 531 units from a modern-day bottom in Baker Hughes data during the weeks ended May 20-27, 2016. US oil-directed rigs dropped by 5 to 744, down 22 units since Aug. 11 and up 428 units since May 27, 2016. That loss was mostly offset by a 4-unit gain in gas-directed rigs to 190, their second-highest total since 2015. The highest occurred on July 28. One rig considered unclassified remains drilling. Two onshore rigs went offline, with rigs engaged in horizontal drilling losing 5 units to 790, down 20 units since July 28 and up 476 since May 27, 2016. Rigs drilling directionally increased 3 units to 77. The count of rigs drilling in inland waters dropped by 1 to 3. Two rigs started work offshore Louisiana, bringing the overall US offshore count to 19. The offshore gain propelled Louisiana to No. 1 among the major oil- and gas-producing states in increases. Up 3 units this week, Louisiana now has 65 rigs working. Texas, New Mexico, and Alaska each rose a unit to 453, 68, and 5, respectively. [Native Advertisement] Despite losses in most of the other major oil and gas regions, the Permian spiked 6 units to 386, its highest point since Feb. 6, 2015. Since its low point in recent Baker Hughes data on May 13, 2016, the Permian has risen 252 units. Permian growth, however, has slowed since the beginning of the summer. The Eagle Ford dropped 3 units to 68, down 18 units since the peak of its rebound on June 2. The Haynesville and Granite Wash each lost a unit to respective counts of 45 and 14. Colorado and the DJ-Niobrara each fell 2 units to 33 and 26, respectively. Oklahoma and North Dakota each declined 3 units to respective totals of 127 and 49. The Cana Woodford edged down 1 to 63, while the Arkoma Woodford gained 1 unit to 9. As with its home state, the Williston fell 3 units to 49. The Cana Woodford and Williston are yet to take big losses during the recent US drilling decline.

Mission accomplished? OPEC banishes contango: John Kemp - (Reuters) - “There is no doubt that the oil market is moving in the right direction,” the Organization of the Petroleum Exporting Countries noted with satisfaction in its most recent bulletin published on Wednesday.“The rebalancing process was never going to happen overnight; it was never going to happen in a linear fashion; and it was always going to require a concerted effort,” OPEC observed.“Patience and perseverance are still required”, the bulletin warned, but the organisation is well on the way to achieving the objectives it set when announcing output cuts in November 2016.Reported oil inventories in the advanced economies have begun to decline towards their five-year average while oil stored at sea and in remote locations has also fallen sharply.Contango, a symptom of an oversupplied market, has gradually disappeared from most crude markets to be replaced by backwardation, a sign of tightness (http://tmsnrt.rs/2jKOQSM).OPEC has often stated that it wants to see the contango narrow as part of the rebalancing process.Contango enables traders to profit from storing crude in excess of their immediate operational requirements by selling oil for deferred delivery at prices above the spot market.So its disappearance has coincided with an accelerated draw down in inventories held in floating storage and in onshore tanks.Crude in floating storage has fallen by 30 million barrels since the start of the year, according to industry sources surveyed by OPEC.Paris-based cargo tracking firm Kpler estimates floating storage has fallen sharply in recent weeks to the lowest level for more than two years.Oil traders are also emptying one of the world’s largest onshore crude storage facilities at Saldanha Bay in South Africa, according to Bloomberg. Global crude stocks are gradually being drawn towards the major refining centres as the surplus inherited from 2015-2016 is absorbed.

Aramco Plans to Buy Non-Saudi Crude in Global Trading Expansion --Saudi Aramco plans to expand its trading business by buying and selling non-Saudi crude as the world’s biggest exporter prepares for what could be a record initial public offering.The state-owned company is putting crude marketing and refined-product trading under the same management, according to Ibrahim Al-Buainain, chief executive officer of Saudi Aramco Products Trading Co. The enlarged unit will trade crude that it doesn’t own, helping Saudi Aramco supply refineries more efficiently and make more profit, he said.“We’ll keep selling our own oil as normal, and we want to get into trading third-party crude,” Al-Buainain, who will head the expanded unit, said in an interview in Fujairah in the United Arab Emirates. Aramco, known formally as Saudi Arabian Oil Co., is joining other state-controlled oil companies in taking a greater interest in trading crude and not just supplying it. The move comes as the kingdom prepares to sell about 5 percent of Aramco. The government has previously said the valuation may reach $2 trillion, while analysts, including those at Sanford C. Bernstein & Co. and Rystad Energy AS, have tended to give lower estimates.

Saudis May Hike Domestic Gasoline Prices by 80% -  Saudi Arabia is considering a plan to phase out subsidies for gasoline and jet fuel in November at the latest, as the world’s biggest oil exporter pushes a program to curtail spending after a global slump in prices. The government would boost gasoline to parity with varying international prices under the plan, according to a person with knowledge of the matter. At current levels, this could result in a hike of about 80 percent for octane-91 grade gasoline to about 1.35 riyals per liter (0.36 cents), the person said on condition of anonymity. The government plans to delay increases in other energy prices until early 2018, the person said. Authorities are expected to make a final decision on the plan in September or October, the person said. The Saudi finance, economy and energy ministries didn’t immediately respond to requests for comment. Energy-subsidy reform is a key part of Saudi Arabia’s plan to overhaul the economy, along with the sale of stakes in state-owned entities, including the world’s biggest crude exporter known as Saudi Aramco. The kingdom raised fuel prices in December 2015 and announced plans for further increases. Authorities have also announced plans for a cash transfer program that would start before further subsidy cuts to help Saudis cope with the impact as the economy struggles with the worst slowdown since the global financial crisis. “It is important for the Saudi government to cut subsidies in order to ease pressures on budget deficit,” “Not only the transportation and logistics sectors will be affected significantly, any company that is involved in production and needs to transfer their end products to consumers will be affected.” 

Saudi Arabia Cracks Down on Dissenting Clerics Amid Rumors of Crown Prince’s Rise to Throne - Saudi Arabia arrested a trio of prominent clerics last weekend, a sign that the kingdom may be preparing for the formal ascendance of Crown Prince Mohammed bin Salman, known as MBS, who is a key decision-maker on the country’s domestic and international affairs but is technically subservient to his father, King Salman. Salman al-Odah, Awad al-Qarni, and Ali al-Omary were arrested with little explanation over the weekend, but activists suspect that their failure to follow MBS’s hawkish line on Qatar played a role in their imprisonment. Human rights activists told the Wall Street Journal that Odah’s arrest came after he declined to come out in support of the Saudi government’s actions against Qatar. On September 8, Odah tweeted a fairly banal message hoping for reconciliation between the kingdom and Qatar. “May God harmonize between their hearts for the good of their people,” he wrote: Odah, who has 14 million followers, has not tweeted since September 9, the day he was swept up with the others. “The Qatar crisis, a tribal dispute with potential global implications, is a key reason. This ‘kerfuffle’ is now very serious. MBS is showing that he can clean house in terms of those who may express sympathy to any opening of dialogue thru the new Saudi State Security Presidium,” Ted Karasik, a senior adviser at Gulf State Analytics who has spent years in the region, told The Intercept in an email. “Importantly, the cleavage between Qatar and the ATQ is now directly impacting Saudi society — the arrests were across a broad swath of clerics, poets and television personalities,” Karasik added, referring to the Anti-Terror Quartet, a name used to refer to Saudi Arabia, the United Arab Emirates, Bahrain, and Egypt, the four countries that initiated the months-long blockade of Qatar. “Thus, some may say these arrests are a purge.”

Yemen’s Appalling Cholera Epidemic Keeps Getting Worse - The World Health Organization (WHO) reports that there are now more than 680,000 suspected cases of cholera, an increase of 40,000 in just the last week:In Yemen, the most explosive outbreak on record has caused 686,783 suspected cases and 2,090 deaths since late April. The number of deaths has slowed but the spread of disease has not: in the past week there were 40,000 suspected cases, the most for seven weeks.Last week, I wrote about the Red Cross’ projection that there could be as many as 850,000 cases of cholera by the end of the year. In that post, I noted that the final figure would likely be much higher because the epidemic is spreading much more quickly than anticipated. Five days later, the number of cases is already closing in on 700,000. If the number of new cases keeps growing like this, there could easily be over a million by the start of 2018.Yemen’s cholera epidemic was already the worst on record two months ago, and it had become the worst contemporary epidemic of its kind a few weeks before that. In the months that have followed, the spread of the epidemic has not slowed, and it continues to spread more quickly than expected. If the latest report is any indication, the spread of the epidemic is faster than before. While we can be grateful that the number of deaths has so far remained low, that should not make us ignore the vast scale of Yemen’s cholera crisis, especially since it is paired with the world’s worst hunger crisis. All of this is a man-made crisis, and it has been produced by a war that the Saudi-led coalition needlessly escalated two and a half years ago with Washington’s approval and full support. The U.S. and Britain, among others, have been arming and fueling the coalition war effort, including an indiscriminate bombing campaign that has wreaked havoc on infrastructure and health care facilities, and they have supported the coalition blockade that continues to starve Yemenis and deprive them of basic necessities.

As Cholera-Wracked Yemen Starves, Saudis Paint Rosy Picture of Their Relief Efforts - Saudi Arabia’s king sent a senior advisor to the United States this week to paint a picture of a generous nation working to ensure food and medicine reaches the suffering civilians of Yemen, even as it pursues a devastating air war against Houthi rebels. But international relief organizations, human rights advocates, and a growing number of U.S. lawmakers say Saudi Arabia and its military partners are aggravating the mounting humanitarian catastrophe in Yemen by delaying or blocking access for emergency aid to areas controlled by Houthis, including a crucial port and the country’s airport.At public events on Wednesday and Thursday in Washington, Abdullah Al Rabeeah, the director of the country’s main aid organization, offered a different version of Riyadh’s actions in Yemen that flew in the face of accounts from U.N and U.S. officials and aid workers. “We have proven to our partners that we are impartial in our work in Yemen,” said Rabeeah, who handed out charts and a brochure detailing Riyadh’s relief work. But U.N. officials say Yemen represents the world’s largest humanitarian crisis, with nearly seven million civilians on the brink of starvation and a record-setting cholera outbreak affecting more than 600,000 people. Much to the frustration of aid organizations, the Saudi-led coalition has barred relief flights into Yemen’s airport and blocked the delivery of four large cranes to the port of Hodeida that could move food and medical supplies off of cargo ships on a much larger scale. “We need Yemen’s airspace, its airport, and its main sea port reopened urgently,” said Ruairidh Villar, spokesperson for the London-based charity Save the Children. “If the cranes were able to operate at Hodeida, it is undeniable that the flow of humanitarian aid and medical supplies, food and fuel, could restart again at a much higher level than we are currently seeing,” Villar said. 

Good news from Syria -- "The US and Russia rejected an Israeli request to prevent the presence of any Iranian forces or Iranian-backed militias near the Israeli border as a part of the ceasefire agreement in south Syria, the Israeli Haaretz newspaper reported on Thursday.According to the report, Israel demanded to create a 60-80km wide buffer zone inside Syria against Iranian-backed forces. The supposed buffer zone would spread from the Golan Heights to the west of the Damascus-al-Suwayda highway in southwestern Syria.Israel proposed its idea to Russia and the US during the talks that preceded the cease-fire agreement in southern Syria. According to the report, Russia refused the Israeli proposal, while the US didn’t back it for real mostly. However, Russia promised Israel that the Iranians and their allies will not move any closer to Israel than five kilometers in the areas held by the Syrian government. The report noted that no Iranian presence was notified on the frontline with Syria for months now."  SF 

The Race For Deir Ezzor: Russian Jets Strike US-Backed Forces In Syria --One week ago we wrote that in "The Race For Deir Ezzor: US And Syrian Forces Are About To Collide", explaining that "as ISIS continues to rapidly collapse in its last two strongholds (Raqqa and Deir Ezzor cities), the competition for recovery of territory seems in full gear between the US-SDF and Syria-Russia alliances." More importantly, "Deir Ezzor province happens to be Syria's most oil-rich territory, which means the future of some of Syria's largest oil fields remains up for grabs." Furthermore, we added that "it looks increasingly like US-backed SDF forces and the Syrian Army could be set to clash as both roll back ISIS lines from either side of the Euphrates.  One week later, that's precisely what happened, and overnight we got the first glimpse of just what this next stage of the Syria proxy war, now largely devoid of ISIS, will look like, when according to Reuters "U.S.-backed militias", which have included various and assorted Al-Qaeda offshots, spinoffs and reverse mergers, said they came under attack on Saturday from Russian jets and Syrian government forces in Deir al-Zor province. The Syrian Democratic Forces - an alliance of Kurdish and Arab militias fighting with the U.S.-led military coalition -  said the strikes wounded six of its fighters. In a statement carried by Reuters, the SDF said that "our forces east of the Euphrates were hit with an attack from the Russian aircraft and Syrian regime forces, targeting our units in the industrial zone."

Syria – Russia Accusing U.S. of Attacks, Abduction Attempts, Team-play With Al-Qaeda - The situation in Syria is reaching another critical point. There is an increased possibility of a large scale clash between U.S. and Russian forces. We had warned of such a clash over control of the rich fields east of Deir Ezzor. At least three incidents over the last days point to more significant escalations.

  • On the 17th the U.S. accused Russia of a light air attack on its proxy forces north of Deir Ezzor. Russia denied that it had attacked those forces.
  • On the 18th and 19th large contingents of Russian and Syrian troops crossed the Euphrates at Deir Ezzor in east-Syria. The U.S. Kurdish/Arab proxy force in the area actively tried to hinder that movement.
  • In parallel a large al-Qaeda attack was launched in west-Syria. The Russian forces accuse U.S. intelligence services of having initiated that campaign. (The Syrian-Russian forces defeated the attack.)
  • Today the Russian military accused the U.S. Kurdish proxies near Deir Ezzor of firing artillery on its forces. It threatened massive retaliation.

The most dramatic incident was the al-Qaeda attack in Idleb.Al-Qaeda in Syria, renamed to Hay'at Tahrir al-Sham, currently controls Idleb governate and Idleb city in north-west Syria. On September 19 it launched a large scale attack on Syrian government positions in north Hama, south of Idleb provinces. The al-Qaeda forces gained significant grounds before being stopped and forced to retreat. Nearly all the heavy weapons, tanks and artillery, that al-Qaeda had in the area were used and in the attack.The spokesperson of the Russian military said (vid with English subtitles) that, according to Russian intelligence reports, al-Qaeda's attack was made on behalf of the U.S. to slow down the Syrian-Russian campaign in the eastern province Deir Ezzor. A subtask for the terrorists was to capture a platoon of Russian soldiers. This is, to my knowledge, the first time that Russia made such a direct and extremely grave accusation against the U.S. forces and intelligence services in Syria.

Russian Special Forces Repel a US-Planned Attack in Syria, Denounce the USA and Issue a Stark Warning - Something rather unprecedented just happened in Syria: US backed “good terrorist” forces attempted a surprise attack against Syrian government forces stationed to the north and northeast of the city of Hama.  What makes this attack unique is that it took place inside a so-called “de-escalation zone” and that it appears that one of the key goals of the attack was to encircle in a pincer-movement and subsequently capture a platoon of Russian military police officers deployed to monitor and enforce the special status of this zone.  The Russian military police forces, composed mainly of soldiers from the Caucasus region, fought against a much larger enemy force and had to call for assistance.  For the first time, at least officially, Russian special operations forces were deployed to rescue and extract their comrades.  At the same time, the Russians sent in a number of close air support aircraft who reportedly killed several hundred “good” terrorists and beat back the attack (Russian sources speak of the destruction of 850 fighters, 11 tanks, three infantry fighting vehicles, 46 armed pickup trucks, five mortars, 20 freighter trucks and 38 ammo supply points; you can see photos of the destroyed personnel and equipment here).  What also makes this event unique is the official reaction of the Russians to this event. Head of the Main Operations Department at Russia’s General Staff Colonel General Sergei Rudskoi declared that: “Despite agreements signed in Astana on September 15, gunmen of Jabhat al-Nusra and joining them units that don’t want to comply with the cessation of hostilities terms, launched a large-scale offensive against positions of government troops north and northeast of Hama in Idlib de-escalation zone from 8 am on September 19 (…) According to available data, the offensive was initiated by American intelligence services to stop a successful advance of government troops east of Deir ez-Zor“.Today, other Russian officials have added a not-so-veiled threat to this accusation.  The Russian Defense Ministry’s spokesman, Major General Igor Konashenkov has declared that:Russia unequivocally told the commanders of US forces in Al Udeid Airbase (Qatar) that it will not tolerate any shelling from the areas where the SDF are stationed (…)  Fire from positions in regions [controlled by the SDF] will be suppressed by all means necessary. This is unprecedented on many levels.  First, the Russians clearly believe that this attempt to kill or capture a platoon of the Russian military police was planned by the United States.  The fact that they are making this accusation officially shows the degree of irritation felt by the Russians about the duplicity of the Americans.  Second, this is the first time, at least to my knowledge, that Russian Spetsnaz forces had to be sent in to rescue a surrounded Russian subunit. 

Russia Warns US In Unprecedented "Secret" Face-To-Face Meeting Over Syria, But What's The Endgame? --  The moment the first Russian jet landed in Syria at the invitation of the Assad government in 2015, Putin placed himself in the driver's seat concerning the international proxy war in the Levant. From a strategic standpoint the armed opposition stood no chance of ever tipping the scales against Damascus from that moment onward. And though US relations with Russia became more belligerent and tense partly as a result of that intervention, it meant that Russia would set the terms of how the war would ultimately wind down.  Russia's diplomatic and strategic victory in the Middle East was made clear this week as news broke of "secret" and unprecedented US-Russia face to face talks on Syria. The Russians reportedly issued a stern warning to the US military, saying that it will respond in force should the Syrian Army or Russian assets come under fire by US proxies. The AP reports that senior military officials from both countries met in an undisclosed location "somewhere in the Middle East" in order to discuss spheres of operation in Syria and how to avoid the potential for a direct clash of forces. Tensions have escalated in the past two weeks as the Syrian Army in tandem with Russian special forces are now set to fully liberate Deir Ezzor city, while at the same time the US-backed SDF (the Arab-Kurdish coalition, "Syrian Democratic Forces") - advised by American special forces - is advancing on the other side of the Euphrates. As we've explained before, the US is not fundamentally motivated in its "race for Deir Ezzor province" by defeat of ISIS terrorism, but in truth by control of the eastern province's oil fields. Whatever oil fields the SDF can gain control of in the wake of Islamic State's retreat will then used as powerful bargaining leverage in negotiating a post-ISIS Syria. The Kurdish and Arab coalition just this week captured Tabiyeh and al-Isba oil and gas fields northeast of Deir Ezzor city.

Israel Strikes Damascus After Syrian Missile Defense Fires On Aircraft -- For the third time in as many weeks Israel has reportedly bombed positions inside Syria. Syrian state media along with multiple regional outlets showed fires burning at a facility near the Damascus international airport in the early hours of Friday. Israeli newspaperHaaretz reports that like with previous attacks, Israel jets fired from over Lebanese airspace. But it appears the latest exchange was part of a tit-for-tat exchange of fire between Syria and Israel in a situation that continues to dangerously escalate. Multiple reports are circulating that the Israeli attack was initiated after Syria's aerial defense missile system engaged and fired on an Israeli aircraft in the area. Video of what purports to show Syrian missiles firing on the aircraft circulated widely in Syrian social media and was picked up by Lebanese and Israeli news outlets. Early reports indicate that an Israeli drone was likely the target. #Syrian air defense downing an #Israeli drone over #Syria tonight.pic.twitter.com/yWCKZSzrCR— Hamosh (@Hamosh84) September 22, 2017It appears that Israel's attack came in response to Syria's engaging the unidentified aircraft - though it's unclear if the target was hit. This latest incident is unique for the fact that Syria quickly publicized that its missile defense system engaged the Israeli target. The Facebook page of a prominent Syrian pro-government militia reported in the early morning hours that, “an area near the Damascus international airport was attacked by a hostile missile." Israeli newspapers are claiming the site to be an ammunition storage depot.

Pressure Mounts on Iraqi Kurds to Cancel Independence Vote - NYT — In a region where few people concur on anything, adversaries and enemies in the Middle East find themselves agreeing on one goal: to stop Iraq’s Kurds from forging ahead with a vote for independence on Monday.As the Kurds rush headlong to embrace their region’s first steps toward independence, their neighbors and allies, led by the United States, are ratcheting up demands to cancel a referendum on independence from Iraq. They warn that it could unleash ethnic violence, tear Iraq apart and fracture the American-led coalition fighting Islamic state militants.It is difficult to reconcile the fierce international objections with the euphoric flag-waving celebrations in Kurdish cities, where residents are convinced they will be voting for independence next week no matter what the world thinks. In Erbil, the capital of Iraqi Kurdistan, fireworks streak across night skies and young men cruise past in cars, honking horns and chanting Kurdish national slogans. Red-white-and-green Kurdish flags snap in the wind beside posters and banners that implore Kurds – in four languages – to vote “yes” to pursue independence. But almost every day for the past week, Kurds have been buffeted by jarring new demands from outside their autonomous enclave to cancel the vote. The White House has called the vote “provocative and destabilizing.” Brett H. McGurk, the United States envoy to the region, has described it as “a very risky process” with “no prospect for international legitimacy.”

Digging In for Next Decade, U.S. Expands Kabul Security Zone - NYT — Soon, American Embassy employees in Kabul will no longer need to take a Chinook helicopter ride to cross the street to a military base less than 100 yards outside the present Green Zone security district. Instead, the boundaries of the Green Zone will be redrawn to include that base, known as the Kabul City Compound, formerly the headquarters for American Special Operations forces in the capital. The zone is separated from the rest of the city by a network of police, military and private security checkpoints. The expansion is part of a huge public works project that over the next two years will reshape the center of this city of five million to bring nearly all Western embassies, major government ministries, and NATO and American military headquarters within the protected area. After 16 years of American presence in Kabul, it is a stark acknowledgment that even the city’s central districts have become too difficult to defend from Taliban bombings. But the capital project is also clearly taking place to protect another long-term American investment: Along with an increase in troops to a reported 15,000, from around 11,000 at the moment, the Trump administration’s new strategy for Afghanistan is likely to keep the military in place well into the 2020s, even by the most conservative estimates. No one wants to say when any final pullout will take place, because the emphasis now is on a conditions-based withdrawal — presumably meaning after the Afghan government can handle the war alone. But President Trump has kept secret the details of those conditions, and how they are defined.

Taiwan Cuts Off Fossil Fuels To North Korea - Taiwan will no longer offer its fossil fuels to North Korea, the island announced on Tuesday in a bid to emerge as a responsible member of the international community. Taiwan also said it would immediately halt any remaining clothing and textile imports from North Korea, in line with recent economic sanctions against Pyongyang for its missile tests over Japan. Preexisting contracts in force before September 11th would continue to be honored until December 10th, a notice from the economics ministry said.The bans hope to “denounce North Korea’s recent successive nuclear tests and actions that jeopardize regional security,” the economics ministry said in a statement.The island is not officially a member of the United Nations apart from Beijing, which insists Taiwan is just one of China’s provinces.Taiwan and North Korea have seen bilateral trade fall 90 percent in volume in the first six months of this year, compared to the year prior. This is mostly due to the increasing scope of punitive sanctions against Pyongyang in recent months.Russia and China have previously made a commitment never to support sanctions against Pyongyang that could negatively impact the civilian population, a stance that would almost certainly include a full-scale oil embargo. Even prior to the new threat of sanctions, North Korea has been increasingly self-sufficient in beginning to tap its still largely unused oil reserves. However, the country’s political climate, including the sanctions currently in force, and water depths of up to 2,500 meters off the east coast present barriers to development. A shortage of funds is likely to further hamper development.

China limits oil trade to North Korea and bans textile trade - China has moved to limit North Korea's oil supply and will stop buying textiles from the politically isolated nation, it said on Saturday. China is North Korea's most important trading partner, and one of its only sources of hard currency. The ban on textiles trade will hurt Pyongyang's income, while China's oil exports are the country's main source of petroleum products. The tougher stance follows North Korea's latest nuclear test this month. The United Nations agreed fresh sanctions - including the textiles and petroleum restrictions - in response. A statement from China's commerce ministry said restrictions on refined petroleum products would apply from 1 October, and on liquefied natural gas immediately. Under the UN resolution, China will still be able to export a maximum of two million barrels of refined petroleum to North Korea annually, beginning next year. North Korea is estimated to have imported 6,000 barrels of refined petroleum daily from China in 2016 - the equivalent of nearly 2.2 million in total for the entire year. But China has not published data on oil exports since 2014. The ban on textiles - Pyongyang's second-biggest export - is expected to cost the country more than $700m (£530m) a year.