Sunday, April 2, 2017

the looming natural gas supply crunch, and yet another record for US crude supplies in an otherwise slow week

oil prices opened the week lower, but then rose daily the rest of the week, after new data showed a smaller than expected addition to our oil supplies and rather large decreases in our supplies of gasoline and distillates...after closing last week 2.7% lower at $47.97 a barrel, pricing for the benchmark US crude oil for May delivery fell almost 2% on Monday morning, as hedge funds continued to unwind their record bullish positions...that selling ran into renewed buying by noon, however, as other traders focused on an agreement by OPEC and non-OPEC producers to look at extending their oil output cuts by another six months, and oil prices reversed and went on to close just 26 cents lower on the day at $47.73 a barrel...prices then rallied 64 cents to close at $48.37 a barrel on Tuesday, underpinned by news reports that production from western Libyan fields had been reduced by 252,000 barrels per day on renewed fighting...oil prices then rose Wednesday morning after Tuesday afternoon's American Petroleum Institute report showed a modest increase in US oil inventories, then spiked higher yet on Wednesday afternoon after data from the Energy Information Administration showed a weekly increase in U.S. crude inventories that was less than half of market expectations, and went on to close the day 2.4% higher at $49.51 a barrel ...that confluence of bullish news carried oil prices higher the remainder of the week, as they closed over $50 a barrel for the first time in over three weeks at $50.35 a barrel on Thursday, and then went on to close the month at $50.60 on Friday, up 5.5% for the week but still 6% lower for the year to date..

natural gas prices also moved higher this week, as trading for the April delivery contract expired and prices for May gas became the widely quoted front month price...April gas started the week lower, however, falling 2.4 cents to $3.052 per mmBTU (million British Thermal Units) on Monday...April prices then rose 4.4 cents to $3.096 on Tuesday, while natural gas for May was up 4.6 cents to $3.177 per mmBTU....the April natural gas contract then expired at an eight-week high of $3.175 per mmBTU on Wednesday, up 7.9 cents on the day, while the May contract rose 5.4 cents to close at $3.231 per mmBTU...with only May gas trading on Thursday, natural gas prices then fell 4 cents to close at $3.191 per mmBTU on Thursday, after the EIA's Weekly Natural Gas Storage Report showed that natural gas in storage in the US fell 43 billion cubic feet to 2.049 trillion cubic feet in the week ended March 24th, roughly in line with expectations...natural gas prices were then little changed on Friday, shedding a tenth of a cent to close the week at $3.190 per mmBTU...

that Weekly Natural Gas Storage Report is about the only data underpinning natural gas prices at this time of year, since both demand for heating and demand for cooling are not major factors in the trading of May gas, and hence weather forecasts are barely mentioned....John Kemp of Reuters included several graphs derived from data from that EIA storage report in his Thursday mailing, one of which we'll include and explain below..

April 1 2017 natural gas supply history as of March 24

the above graph comes from an emailed package of graphs from John Kemp, senior energy analyst and columnist with Reuters, wherein the red line shows our natural gas supplies in billions of cubic feet from January 2015 to March 24th of this year...the yellow line, for the prior year, thus shows our natural gas supplies in billions of cubic feet from January 2014 to the end of 2016, thus retracing some of what the red line shows...the light blue band then shows the prior 5 year range of our natural gas supplies, and thus from the left shows the range of our natural gas supplies from January 2010 through January 2014, extending to the right where it ends with the range of our natural gas supplies from the end of 2012 through the end of 2016...lastly, the blue dashes show the average of that 5 year range of our natural gas stocks that's indicated by the light blue shading...note the obvious seasonal pattern; surplus natural gas is injected into storage each the spring and summer, then withdrawn for use during the heating season.....

by following the red line, we can see that our natural gas supplies were at least at a 5 year high for the time of year from October 2015 through November 2016, with October 2016 being the first time in our history that natural gas supplies topped 4 trillion cubic feet...however, since December of 2016, our natural gas supplies have been falling at a faster rate than normal, despite a warmer than normal winter (recall last week we showed that heating demand was down by 17%) and by the end of January had returned to merely average...supplies of gas have since recovered to above average, largely because of a record warm period that led to the first weekly injection into storage in February history, but they're still more than 400 billion cubic feet below where they were at the same time in March a year ago....what that means is that at the current pace of natural gas production, we are not covering our needs from production at a normal pace even while winter temperatures have remained above normal...

going forward, we know that demand for our natural gas supplies will be greater than it was in the past ...for starters, there are those 13 natural gas export trains now under construction that we looked at 4 weeks ago....when completed, they're projected to be exporting roughly 9.4 billion cubic feet of natural gas per day, or about 10% of our current natural gas production...in addition, with natural gas prices depressed, US electric utilities have been retiring their old coal generation capacity and replacing it with natural gas generation....according to the EIA, gas-fired generating capacity is expected to rise by a further 8 percent before the end of 2018....but even this past year, before this new demand for natural gas comes online, our current field production of natural gas has been unable to maintain our natural gas supplies at an above normal level during a winter when heating demand was 17% below average...and as we have repeatedly stressed, and as was evident from the natural gas rig count graph we showed last week, natural gas drillers will not expand their drilling operations while prices for natural gas are below their break-even point...furthermore, natural gas futures prices are even lower, with most contract prices beyond April 2018 below $3 per mmBTU...so they continue to frack more wells than they are drilling, reducing their uncompleted well backlog as needed, just to maintain their cash-flow...thus, there is not as yet any sign that any of the natural gas that exporters and utilities expect will be there in the future will materialize....to put it quite simply, something's gotta give...

The Latest Oil Stats from the EIA

the oil data for the week ending March 24th from the US Energy Information Administration showed that a combination of a big increase in the amount of oils refineries used and a big jump in our exports of crude oil used up almost all the oil we imported or produced, but we nonetheless still saw a small increase in our record high oil supplies for the 11th week out of the past twelve...our imports of crude oil decreased by an average of 83,000 barrels per day to an average of 8,224,000 barrels per day during the week, while at the same time our exports of crude oil rose by 460,000 barrels per day to an average of 1,010,000 barrels per day, which meant that our effective imports netted out to 7,214,000 barrels per day during the week, 543,000 barrels per day less than the prior week...at the same time, our crude oil production rose by 18,000 barrels per day to an average of 9,147,000 barrels per day,  which means that our daily supply of oil, from net imports and from wells, totaled an average of 16,361,000 barrels per day during the cited week...

during the same week, refineries reportedly used 16,226,000 barrels of crude per day, 425,000 barrels per day more than they used during the prior week, while at the same time, 20,000 barrels of oil per day were being added to oil storage facilities in the US....thus, this week's EIA oil figures would seem to indicate that we used or stored 115,000 less barrels of oil per day than were supplied by our net oil imports and oil well production…therefore, in order to make the weekly U.S. Petroleum Balance Sheet balance out, the EIA inserted a phantom -115,000 barrel per day figure onto line 13 of the petroleum balance sheet, which the footnote tells us represents "unaccounted for crude oil"...that "unaccounted for crude oil" is further described in the glossary of the EIA's weekly Petroleum Status Report as "the arithmetic difference between the calculated supply and the calculated disposition of crude oil", which means they got that balance sheet number by backing into it, using the same arithmetic we just used in explaining it...

the weekly Petroleum Status Report also tells us that the 4 week average of our oil imports rose to an average of 8,022,000 barrels per day, now 0.7% above that of the same four-week period last year...at the same time, the 4 week average of our oil exports rose to 794,000 barrels per day, now 105.0% higher than the same 4 weeks a year earlier, as our overseas exports of our surplus light crude oil were barely underway in early 2016...the 20,000 barrel per day increase in our crude inventories came about on a 124,000 barrel per day increase in our commercially available crude supplies, which was partially offset by an 103,000 barrel per day sale of oil from our Strategic Petroleum Reserve, part of an ongoing sale of 5 million barrels annually that was planned 18 months ago...

meanwhile, this week's 18,000 barrel per day oil production increase resulted from a 25,000 barrel per day increase in output from the lower 48 states, while oil output from Alaska fell by 7,000 barrels per day from last week...the 9,147,000 barrels of crude per day that we produced during the week ending March 24th was up by 1.4% from the 9,022,000 barrels per day we produced during the equivalent week a year ago and the most we've produced in any week since the week ending February 5th 2016, while it was still 4.8% below the June 5th 2015 record oil production of 9,610,000 barrels per day...

US refineries were operating at 89.3% of their capacity in using those 16,226,000 barrels of crude per day, up from 87.4% of capacity the prior week, but still down from the year high of 93.6% of capacity in the first week of January, when they were processing 17,107,000 barrels of crude per day....their processing of crude oil continues to be on a par with the 16,234,000 barrels of crude that were being refined during the week ending March 25th, 2016, when refineries were operating at 90.4% of capacity....with the week's big refining increase, gasoline production from our refineries rose by 257,000 barrels per day to 10,028,000 barrels per day during the week ending March 24th, the highest this year, and 6.3% more than the 9,430,000 barrels per day of gasoline that were being produced during the week ending March 25th a year ago...in addition, refineries' production of distillate fuels (diesel fuel and heat oil) was also up, rising by 43,000 barrels per day to 4,872,000 barrels per day, which was nonetheless 1.1% lower the 4,927,000 barrels per day of distillates that were being produced during the week ending March 25th last year...

even with the large increase in our gasoline production, the EIA reported that our gasoline inventories again shrunk, decreasing by 3,747,000 barrels to 239,721,000 barrels as of March 24th, after they had already dropped by more than 12.4 million barrels over the prior 3 weeks....that was as our domestic consumption of gasoline rose by 324,000 barrels per day to a seasonal high of 9,524,000 barrels per day and as our gasoline exports rose by 16,000 barrels per day to 608,000 barrels per day, while our imports of gasoline rose by 196,000 barrels per day to 521,000 barrels per day....while our gasoline supplies are now down by more than 19.3 million barrels from the record high set 6 weeks ago, they're only down 1.2% from last year's March 25th high for the date of 242,560,000 barrels, and are still 4.6% above the 229,128,000 barrels of gasoline we had stored on March 27th of 2015... 

our supplies of distillate fuels also fell this week, decreasing by 2,483,000 barrels to 152,910,000 barrels by March 24th, as the amount of distillates supplied to US markets, a proxy for our consumption, increased by 210,000 barrels per day to 4,222,000 barrels per day, even as our imports of distillates fell by 12,000 barrels per day to 115,000 barrels per day, and as our exports of distillates fell by 97,000 barrels per day to 1,120,000 barrels per day at the same time....while our distillate inventories are now 5.1% below the bloated distillate inventories of 161,185,000 barrels that we had stored on March 25th 2016, at the end of last year's warm El Nino winter, they are still 20.2% higher than the distillate inventories of 127,174 ,000 barrels that we had stored on March 27th of 2015…  

finally, our commercial inventories of crude oil increased for the 11th time in the past 12 weeks, increasing by 867,000 barrels to another record high of 533,977,000 barrels by March 24th...at the same time, 724,000 barrels of oil from our Strategic Petroleum Reserve was sold, which left inventories in the SPR at 692,659,000 barrels, a quantity not considered available for commercial use....thus for current commercial purposes, we finished the week ending March 24th with 11.5% more crude oil in storage than the 479,012,000 barrels we had stored at the end of 2016, 6.0% more crude oil in storage than what was then a record 503,816,000 barrels of oil in storage on March 25th of 2016, 21.9% more crude than what was also then a record 437,983,000 barrels in storage on March 27th of 2015 and 53.3% more crude than the 348,423,000 barrels of oil we had in storage on March 28th of 2014...

This Week's Rig Count

US drilling activity increased for the 21st time in the past 22 weeks during the week ending March 31st, and this week's increase was also the 9th double digit rig increase in the past 11 weeks....Baker Hughes reported that the total count of active rotary rigs running in the US increased by 15 rigs to 824 rigs in the week ending Friday, which was 374 more rigs than the 450 rigs that were deployed as of the April 1st report in 2016, and the most drilling rigs we've had running since Oct 2nd, 2015, but still far from the recent high of 1929 drilling rigs that were in use on November 21st of 2014....

the number of rigs drilling for oil increased by 10 rigs to 662 rigs this week, which was up by 300 from the 362 oil directed rigs that were in use a year ago, and more than double the 316 rigs working on May 27th 2016, but still down from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations rose by 5 rigs to 155 rigs this week, which was also up from the 88 natural gas rigs that were drilling a year ago, but down from the recent natural gas rig high of 1,606 rigs that were deployed on August 29th, 2008...in addition, there are also now 2 rigs deployed that are classified as miscellaneous, compared to a year ago, when there were no such miscellaneous rigs at work...  

there were four additional drilling platforms that started operating in the Gulf of Mexico offshore from Louisiana this week, which boosted the Gulf of Mexico count to 22 rigs, still down from the 24 rigs that were drilling in the Gulf during the same week of 2016...that was also down from a total of 26 rigs that were working offshore of the US a year ago, when there were also rigs working offshore from Alaska and California, in addition to the 24 rigs that were drilling in the Gulf of Mexico at the time...

active horizontal drilling rigs increased by 12 rigs to 685 rigs this week, which is well more than double the May 27th 2016 nadir of 314 working horizontal rigs...that's also up by 339 horizontal rigs from the 346 horizontal rigs that were in use in the US on April 1st of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, a total of 12 directional rigs were also added this week, bringing the directional rig count up to 70 rigs, which was also up from the 49 directional rigs that were deployed during the same week a year ago...meanwhile, the vertical rig count was down by 9 rigs to 58 rigs, which was still up from the 55 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 March 31st, the second column shows the change in the number of working rigs between last week's count (March 24th) and this week's (March 31st) count, the third column shows last week's March 24th active rig count, the 4th column shows the change between the number of rigs running this Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was for the 1st of April, 2016...           

March 31 2017 rig count summary

it's fairly obvious that almost all the increases can be accounted for by the 7 rig increase in Texas and the 6 rig increase in Louisiana, where the four new Gulf of Mexico rigs are included in the state count...what happened in the major basins is less obvious, however, because the increases in the Permian, the Eagle Ford, the Haynesville of Louisiana, and the Granite Wash of the Texas panhandle are almost entirely offset by decreases in active rigs in the Cana Woodford of Oklahoma, the Denver-Julesburg Niobrara chalk of the Rockies front range, the Williston of North Dakota and the Mississippian of the Kansas-Oklahoma border....the summary data tells us that there were 10 oil rigs and 4 gas rigs added in "other" basins , which are not named, and shall remain so for now, unless someone wants to dig through the individual wells records in the North America Rotary Rig Count Pivot Table (XLS)...also note that outside of the major producing states listed above, Mississippi also added a rig this week; they now have 5 rigs active, up from 2 rigs a year ago....

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Quote of the Day: "The fact is places like Ohio were getting dramatically cleaner anyways" -- From the front page of the Columbus Dispatch: As President Donald Trump signed an executive order Tuesday easing environmental regulations, he said to coal miners standing nearby: "You know what it says, right? You're going back to work.”  But it's not quite that simple.The announcement could have mixed effects in Ohio, where cheap natural gas, mechanization and competitive renewable technologies have contributed to an industry wide move away from coal.  "That's going to happen no matter what. That's just economics," said Brent Sohngen, an environmental and resource economist at Ohio State University."The fact is places like Ohio were getting dramatically cleaner anyways. This just makes it 10 percent slower, 20 percent slower." Brent is a colleague here at Ohio State.  He is also conservative (for an academic environmental economist), studies climate change, and has won a Nobel Prize*. *Nobel Peace Prize...along with 1500 of his close colleagues as a member of the IPCC writing team.

Ohio's renewable energy rules on the chopping block, again | cleveland.com: -- Ohio lawmaker William Seitz of Cincinnati has been trying for at least the past four years to modify or eliminate state rules requiring power companies to offer "green" electricity. His latest effort, House Bill 114, is scheduled for a vote today. The legislation comes at the same time Seitz expects to benefit from a federal tax credit on his new home solar array and to sell the "renewable energy credits" the array will produce if electric utilities continue to have to meet the state's renewable energy mandates. The legislation would eliminate the mandates, replacing them with a goal that by 2027 power companies consider supplying 12.5 percent green power and that they consider reducing peak demand by offering energy efficiency programs. There are no penalties for ignoring the goals, meaning there won't be much demand, at least in Ohio, for solar renewable energy credits. Opponents, including scores of businesses, as well as environmental groups, have fought Seitz throughout all of his legislative efforts, including this latest round, against renewable energy rules and parallel rules requiring electric utilities to help customers use less power.If the H.B. 114 emerges from the House today, it faces an uncertain future in the Senate. And it probably faces another veto. Gov. John Kasich vetoed a similar bill over the waning holiday days of 2016. Approved by both the House and Senate in the middle of the night earlier that month, Senate Bill 320 would have watered down the mandates and made them voluntary for two years. Kasich reasoned that progressive companies which have embraced the use of renewable energy as part of their corporate sustainability commitment would not be interested in developing facilities in Ohio had the mandates been weakened.

Letter: Shale development threatens forest - The Columbus Dispatch - I respectfully disagree with Supervisor Tony Scardina’s assessment of oil and gas leasing in the Wayne National Forest (“Forest service keeps eye on oil, gas development,” op-ed, Thursday). The Bureau of Land Management and the Forest Service want to open 40,000 acres of the Wayne to oil and gas development. This is a terrible idea, and it puts nearly two-thirds of the Wayne’s Marietta Unit at risk. This is a massive chunk of Ohio’s only national forest.Large-scale shale operations and their associated well pads, pipelines, compressor stations, and frack-water impoundments remove significant amounts of tree cover, break up forests into small patches that can’t support wildlife, and release substantial amounts of pollution. Heavy shale gas development is incompatible with public recreation, habitat, and wildlife values. It should stay out of our already limited public lands. Ohio ranks 47th in the nation in public land per person. Additionally, the BLM’s lease sales are unlawful. The BLM and the Forest Service are duty-bound by federal law to closely review the environmental consequences of leasing the Wayne. The agencies failed, and in some cases evidently refused, to do the legally required homework before leasing. For example, it’s widely acknowledged that pipeline construction is the single-largest source of ground disturbance (i.e., forest destruction) associated with oil and gas development. Nevertheless, or perhaps even because of this, the agencies simply shrugged off the pipeline issue in their environmental reviews. The BLM claimed, without substantiation, that pipeline impacts would be minimal. In fact, the Ohio Environmental Council and several concerned stakeholders repeatedly presented the BLM and the Forest Service with empirical field data showing that pipeline impacts would be highly significant. While federal law requires the agencies to closely consider and evaluate this pipeline data, neither the BLM nor the Forest Service even bothered to acknowledge its existence. We can say with absolute certainty that air pollution, forest fragmentation, degradation of aesthetic and recreational values, and harm to wildlife will occur if shale operations come to the Wayne. It’s sad to say, but serious accidents are a very real risk, too. Having these risks near our public forests is bad enough. Inviting them in is the last thing we should want to do. -- Nathan Johnson, Attorney, Ohio Environmental Council

Pennsylvania OKs new injection wells for oil and gas wastewater --Pennsylvania environmental regulators have approved two new underground injection wells to take in wastewater from the oil and gas industry. Pennsylvania already has six active injection wells, according to Scott Perry, who runs the Office of Oil and Gas Management at the state Department of Environmental Protection. He says new injection wells are needed as gas drilling activity has slowed. In busier times, the wastewater was often reused in the next well.“Pennsylvania has been leading the nation, if not the world, in recycling flowback water,” says Perry. The two new injection wells will be operated by different companies. Seneca Resources will have a well in Elk County, and another will be run by Pennsylvania General Energy Company in Indiana County. Both have faced significant pushback from the local municipalities. “This project began in earnest in 2012 and has been subject to lengthy and intense scrutiny by all interested parties,” Seneca spokesman Rob Boulware writes in an email. “As the EPA did before it, Pa. DEP carefully considered Seneca’s application and confirmed through its approval that the project met all lawful regulations. Seneca looks forward to implementing this project.”   PGE declined to comment, citing ongoing litigation.Amid problems with underground injection wells in other states like Oklahoma, the DEP is trying to allay fears the wells could trigger man-made earthquakes “The operators have proposed to use depleted oil and gas reservoirs for their disposal wells,” says Perry. “That’s what gives DEP a lot of confidence in how they can be operated in an environmentally sound and safe manner. These same reservoirs have held a very buoyant material– like oil and natural gas– in place for literally, a millennia.” More disposal wells are in the works, according to Perry. The DEP is currently reviewing two more applications. He believes as many as a dozen are pending before the EPA.

Natural gas, oil, coal reserves could power next industrial revolution - There is little doubt that coal — and the people who mined it — played a huge factor in this country’s development as an industrial power, as well as subsequent victories in world conflicts. Now as a new age dawns in which coal’s value has decreased but vast reserves of natural gas and oil are reachable through fracking, the state is poised again to enjoy newfound wealth and prosperity. It couldn’t come at a better time, as coal’s decline, as well as other market forces, has state leaders struggling to balance the budget. So it was with great anticipation that we began work on this year’s Annual Report section on Energy and Industry, which appears in today’s edition. We, along with the majority of our readers, know that development of the Atlantic Coast Pipeline, which is nearing the start of construction, as well as other pipelines, will fuel a boom in the natural gas industry that will rival and likely surpass the one seen earlier this century. Not surprisingly, local and national companies are ramping up operations, preparing for the jobs that will develop with pipeline construction and with increased drilling and operations. North Central West Virginia has become home to a number of national powerhouses in the energy field, including Dominion, EQT, Antero, Southwest, MarkWest and others. The region is also home to local and relocated companies that subcontract with major corporations, providing invaluable services — and jobs — to power the industry to success. It is exciting to watch this development unfold, and encouraging to listen as industry and community leaders work together toward a successful path. A boom of this size will require a dramatic increase in workforce, which requires training, living quarters, food and amenities.Once the pipeline is built, some of those jobs will go away, but they will be replaced with other, more permanent ones, like jobs drilling and maintaining wells, as well as jobs in industries that should “follow the gas” to the Mountain State.

Major Fracked-Gas Pipeline Leak Shuts Down Rhode Island Interstate - A major natural gas leak caused parts of Providence, Rhode Island to shut down Wednesday night. The leak, which shut down Interstate 195 and city streets for several hours, was caused by a ruptured high-pressure gas line near a National Grid take station plant at Franklin Square around 8:15 p.m. Local witnesses reported "a loud sound of rushing air" and "a faint smell of natural gas" coming from the Allens Ave. plant. According to The Providence Journal , a dramatic scene unfolded in the area: "The break in the underground pipe caused havoc for a large portion of Wednesday night. Frustrated motorists were forced to take detours off a jammed Route 195 and National Grid workers scrambled to shut down the gas, which was escaping with such force that witnesses said it sounded like a jet engine. The roar continued for several hours." Emergency vehicles swarmed the scene and nearby businesses had to evacuate. Providence Public Commissioner Steven Pare described the leak as "highly explosive" and said "we have to keep any ignition source away from this leak" at around 9:35 p.m. There were no reported injuries and the leak has been contained. Interstate 195 reopened around 11 p.m. and the affected streets reopened around 5 a.m. Thursday. Officials said during a news conference that mechanical equipment failure lead to the leak. Danielle Williamson, a spokeswoman for National Grid, told Rhode Island Public Radio that roughly 50 customers lost service and technicians have been fixing the leak since early Thursday morning. Williamson explained that restoring gas takes longer than r estoring electricity because "technicians have to go to from home to home, business to business and relight appliances that go into the homes or businesses."

Maryland Senate approves fracking ban; governor to sign bill -- (UPI) -- Maryland's Senate approved a ban on fracking in the state, a bill Gov. Larry Hogan has pledged to sign.  Senators voted 35-10 Monday to approve the legislation that prohibits drilling for natural gas known as hydraulic fracturing. Earlier, the House of Delegates had approved the same bill 97-40.Earlier this month, Hogan announced his support of the legislation.Maryland would join Vermont as the only states that ban fracking through legislation. Vermont does not have the shale formations containing natural gas where fracking could be done but Maryland has it in the western part of the state.New York, which also has shale gas, banned it by executive order."This vote confirms the power of participant democracy," Ann Bristow, a resident of Garrett County in Western Maryland and a member of a state commission that studied fracking told The Washington Post. "Never believe when someone tells you that an organized movement can't produce change against overwhelming odds. We are proving otherwise."  Water contamination, greenhouse-gas emissions and earthquakes are problems associated with fracking, according to opponents."This ban is a major step for Maryland's path to a clean energy economy," said Josh Tulkin, director of Maryland's Sierra Club, one of the groups in the Don't Frack Maryland Coalition, said in a statement. "We commend the Maryland General Assembly for this bipartisan victory, and we thank Governor Hogan for his support, but the real congratulations go the thousands of people across the state, particularly those in Western Maryland, who stood up for their beliefs, who organized, lobbied and rallied to get this legislation passed," he also said.

Maryland Bans Fracking -- Maryland is on track to become the third state to ban hydraulic fracturing, or fracking , for oil and natural gas, after the Senate voted 35-10 on Monday for a measure already approved by the House . The bill is now headed to Republican Gov. Larry Hogan, who is in favor of a statewide fracking ban. Hogan, who once said that fracking is " an economic gold mine ," stunned many with his complete turnaround at a press conference earlier this month. "We must take the next step to move from virtually banning fracking to actually banning fracking," the governor said. "The possible environmental risks of fracking simply outweigh any potential benefits." Once signed into law, Maryland would be the first state with gas reserves to pass a ban through the legislature. Don't Frack Maryland , a coalition of more than 140 business, public interest, community, faith, food and climate groups, has campaigned vigorously for a statewide ban through rallies, marches, petition deliveries and phone calls to legislators. "Today's vote is a result of the work of thousands of Marylanders who came out to town halls, hearings and rallies across the state. The grassroots movement to ban fracking overcame the high-powered lobbyists and deep pockets of the oil and gas industry," said Mitch Jones, Food & Water Watch senior policy advocate. "We worked tirelessly to make sure our legislators and the governor were held accountable to the demands of voters and followed the science. Now we look forward to Governor Hogan signing this bill into law and finally knowing that our water, climate and families will be protected from the dangers of fracking."

Enbridge buys Spectra, strengthens hold in North America -- Enbridge Inc. ENB has become one of the largest energy companies in North America following its acquisition of Spectra Energy. Under the terms of the all-stock buyout, Enbridge gained 57% ownership of the merged entity while the remaining 43% is to be held by Spectra shareholders. The merger resulted in the conversion of each share of Spectra’s common stock into 0.984 of an Enbridge share. The $126 billion merger brings together Enbridge’s liquid-weighted midstream assets from Western Canada and the U.S Midwest and Spectra's network of primarily gas-related midstream assets. The assets include Spectra’s holdings in the U.S. North, Midwest and Gulf Coast and the British Columbia’s Canadian province. We note that a total of 1,000 jobs were cut by the merged company.  The merged company has $74 billion in secure projects and inventory. By 2019, the company is expected to start up $26 billion worth projects. Enbridge believes that the company will yield a 3–5% compound annual growth rate with the inclusion of Spectra’s projects. The company is also expanding its platform for renewable power generation.

In search of a quorum: 3 potential FERC nominees bring business and deep energy backgrounds - Utility Dive --The Federal Energy Regulatory Commission needs a few good candidates. Three, to be exact.  The five-member agency has been lacking a quorum since Commissioner Norman Bay resigned at the end of January in the wake of President Donald Trump’s appointment of Cheryl LaFleur as acting chairman.  Three names have been widely mentioned in the media to fill the open positions. All three presumptive nominees all seem to fit well with the president’s agenda of reducing regulation, strengthening the nation’s infrastructure and providing support for the coal industry.  “The administration seems to be working through a lot of hurdles,” said Frank Maisano, a senior principal at Bracewell LLC, but the delay is “unfortunate,” he said, “because of the urgency. We need a quorum of folks.” FERC could play an important role in moving forward some of the new administration’s agenda items. The federal agency regulates the interstate transmission of electricity, natural gas, and oil and reviews proposals to build liquefied natural gas terminals and interstate natural gas pipelines. FERC also licenses hydropower projects and reviews certain mergers and acquisition and corporate transactions by electric companies.Without a quorum, FERC is limited to what it can do, despite recent action delegating some additional authority to staff. Progress on several natural gas pipeline projects in the Northeast already have been stalled by the lack of a quorum, including Spectra Energy’s NEXUS pipeline in Ohio, the PennEast pipeline in Pennsylvania and New Jersey, and National Fuel’s Northern Access pipeline in Pennsylvania and New York.Lack of a quorum could also upset capacity auctions in the PJM Interconnection and New York. Pending filings at FERC argue that recently enacted nuclear subsidies interfere with those processes. If FERC is not able to rule on those issues, the petitioners might contest the auction results.

USGC gasoline prices reach multi-month highs on strong domestic, export demand -- Substantial demand and bullish data propped up US Gulf Coast gasoline prices Wednesday, lifting primary grade outright values to their highest levels in months. Conventional 9 RVP gasoline (M2) for Colonial Pipeline loading in Pasadena, Texas, rose 5.2 cents compared with Tuesday to $1.6159/gal, the highest outright price since January 13's $1.6262/gal. CBOB at 9 RVP (A2) increased as well, jumping 5.45 cents to $1.5509/gal. The last time CBOB barrels were more expensive was February 27, when they were $1.5642/gal. The majority of the move came in the late morning after the release of weekly US Energy Information Administration data. Before the Platts Market on Close assessment process, M2 was heard bid up to the NYMEX May RBOB futures contract minus 6 cents/gal from Tuesday's assessment at NYMEX May RBOB minus 7.25 cents/gal. Likewise, late morning trading and an offer left standing in the Platts assessment process moved the A2 differential 1.75 cents/gal higher day on day.One source pointed to Wednesday's EIA data as the likeliest cause for the strength. The data showed Gulf Coast gasoline stocks fell about 1.5 million barrels in the week that ended March 24 to 78.489 million barrels, a five-month low. Conversely, US product supplied -- a proxy for national demand -- rose 324,000 b/d to 9.524 million b/d, a more than six-month high.

LOOP Sour crude oil benchmark reflects imports, exports needed by USGC refiners – (Platts Snapshot video with transcript) While US crude production is up roughly 70% from 2007, US Gulf Coast refiners are still largely consumers of medium-to-heavy sour crude — much of it imported from the Middle East help fill their needs. John-Laurent Tronche examines why the area needs a new LOOP Sour benchmark to better represent the domestic and imported sour crude barrels that are a key part of US refining crude slates.
Read the full special report here: Loop Sour Crude: A benchmark for the future
See the subscriber note: Platts to launch USGC LOOP Sour crude assessments March 27
Read the press release: S&P Global Platts to launch new blended sour crude price reference to aid US Gulf Coast imports and refining complex
Read the FAQ: FAQ: USGC LOOP Sour crude

Shell's New Permian Play Profitable At $20 A Barrel - OPEC’s worries about the booming U.S. oil production have increased significantly with the big three oil companies’ interest in shale. Exxon Mobil Corp., Royal Dutch Shell Plc, and Chevron Corp., are planning $10 billion of investments in shale in 2017, a quantum jump compared to previous years. All the naysayers who doubted the longevity of the shale oil industry may have to modify their forecasts.OPEC lost when they pumped at will as lower oil prices destroyed their finances, and now they are losing their hard-earned market share as a result of cutting production. Shell’s declaration that they can “make money in the Permian with oil at $40 a barrel, with new wells profitable at about $20 a barrel” is an indication that Shell is here to stay, whatever the price of oil.The arrival of the big three oil companies with their loaded balance sheets is good news for the longevity of the shale industry.The oil crash, which started in 2014, pushed more than 100 shale oil companies into bankruptcy, causing default on at least $70 billion of debt, according to The Economist. Even the ones that survived haven’t been very profitable, according to Bloomberg, which said that the top 60 listed E&P firms have “burned up cash for 34 of the last 40 quarters”.Therefore, during the downturn, the smaller players had to slow down their operations, but this will not be the case with the big three.“Big Oil is cash-flow positive, so they can take a longer-term view,’’ said Bryan Sheffield, the billionaire third-generation oilman who heads Parsley Energy Inc. “You’re going to see them investing more in shale,” reports Bloomberg.The majors are attempting to further improve the economics of operation. Shell said that its cost per well has been reduced to $5.5 million, a 60 percent drop from 2013. Instead of drilling a single well per pad, which was the norm, Shell is now drilling five wells per pad, 20 feet apart, which saves money previously spent on moving rigs from site to site.Shell is not the only one—Chevron expects its shale production to increase 30% every year for the next decade. Similarly, Exxon plans to allocate one-third of its drilling budget this year to shale, and it expects to quadruple its shale output by 2025.  “The arrival of Big Oil is very significant for shale,” said Deborah Byers, U.S. energy leader at consultant Ernst & Young in Houston. “It marries a great geological resource with a very strong balance sheet.”

Land Swaps Let Permian Drillers Expand Shale Wells on the Cheap | Rigzone- Horizontal drilling in the Permian Basin is creating a new kind of swap meet. Working with fresh technology that lets producers drill longer wells than ever before, companies such as Pioneer Natural Resources Co., Parsley Energy Inc. and Double Eagle Energy Permian LLC are increasingly haggling with other producers for slivers of land that allow them to extend the reach of their drilling with hardly any acquisition costs. Prices for Permian drilling rights can run as high as $60,000 an acre. Trading land allows companies to drill the longer wells using ground a second company probably won’t develop, a win-win situation, said Bryan Sheffield, Parsley’s chief executive officer. But developers should take advantage now, because the practice likely has a low life expectancy. "The trade rush is happening now," said John Sellers, co-chief executive officer at Fort Worth-based Double Eagle, which built much of its current position in the Permian from dozens of trades. "The golden era of trades is probably going to happen over the next 18 to 24 months. Then people are going to really have their positions buttoned up more." Double Eagle, which is in the process of selling about 71,000 acres in the Permian to Parsley for $2.8 billion, has found that trading is the best way to catch the attention of larger players whose mineral rights he covets. "Land is really a currency out here," Sellers said. "Without it, it’s really difficult to do trades. Opening up your wallet doesn’t really get it done. You have to have acreage they need as much as you need acreage from them." Like the general manager of a pro sports team trading players, Sheffield said explorers keep tabs on competitors’ assets. In a field that’s been drilled for decades, there are virtually no more secrets in the Permian. Therefore, it’s in everyone’s interest to trade. "The play is already proven," Sheffield said in an interview Tuesday at the Scotia Howard Weil Energy Conference in New Orleans. "If you slow it down and restrict a trade, you’re destroying value on your acreage, and the other guy is destroying value on their acreage, because their acreage is going to get trapped in between two long laterals."

Halliburton Warns Of First-Quarter Profit Miss As Costs Rise - Halliburton warned on March 24 that its first-quarter profit would likely miss analysts' expectations due to higher costs and weak demand in markets outside North America.Shares of the company, which forecast higher revenue from its U.S. land operations, were up about 1% in early trading on the New York Stock Exchange.The company expects its earnings per share to be in low-single digits in the quarter ending March, CEO David Lesar said on a conference call on March 24.Analysts on average expect earnings of 13 cents per share, according to Thomson Reuters. The rise in costs is essential because of the company's move to reactivate more equipment and expand its headcount, in response to increased activity in shale fields across the U.S."By doubling this rate of activation and accelerating it to the front half of the year, we are in effect front loading much of the hit to income at the beginning of the year," Lesar said.Halliburton said it planned to hire more than 2,000 field employees in its U.S. land operations by the end of the quarter. The company also said it was being impacted by higher costs for sand—used to keep wells open after fracking.U.S. shale producers have rapidly ramped up drilling over the past six months, encouraged by a near 50% rise in oil prices since February 2016, when they hit 13-year lows.Halliburton, the world's second-largest oilfield services provider, said it expected its first-quarter revenue from its U.S. land operation to surge by 25% from the fourth quarter. Activity in international markets, in contrast, remains sluggish, and an "inflection" is unlikely until later in the year, Lesar said.

Halliburton Doubling U.S. Frack Capacity, Hiring 2,000, Warns on Rising Costs - Halliburton Co. is bringing back double the U.S. pressure pumping capacity it had expected to reactivate for the entire year and is hiring people as quickly as possible, as customer animal spirits "run hard," CEO Dave Lesar said Friday. In a domestic market rapidly short fracture (frack) sand, equipment and experienced personnel, the No. 1 North American pressure pumper is adding 2,000 people to the payroll and putting idled equipment back to work at a frenetic pace, Lesar said during a conference call to provide an update on operations. "Based on current customer demand, we are deploying nearly double the pressure pumping equipment than we originally anticipated reactivating for the entire year and we are bringing that reactivated equipment out in the first six months of the year, instead of over the course of the year," he said. Coming off a historic trough, "what we have to add back is almost unprecedented." Since the downturn began in late 2014, Halliburton had stacked horsepower and hardware, and it had culled its global workforce by 35,000 people, ending 2016 at about 50,000 worldwide. The rapid restart has repercussions and is expected to dent 1Q2017 performance because of the higher costs. The plan now is to front load costs as much as possible to improve margins through the second half. Halliburton's customer base, Lesar said, now has separated itself into three main groups, "those looking to grow production by outspending cash flow, those looking to improve returns by living inside their cash flow, and finally, those companies that are proving up reserves and preparing themselves for sale...This diverse and exciting market has created a surge of activity and supports my thesis that the animal spirits are back in U.S. land. And today they are continuing to run hard."      In addition to reactivating fracking equipment, it also is bringing back other stacked land-based equipment, particularly from the cementing business, "where we are adding nearly 30% more equipment to meet increased demand in the first half of the year," Lesar said.   Besides equipment and personnel, Lesar said Halliburton's largest source of cost inflation is sand, a business that has seen a sharp uptick as producers increase their frack stages and proppant loads.

As oil output grows, BP keeps refining stable, expands retail | Reuters: BP has no plan to build new refineries despite growing oil production and will focus on modernizing existing plants while expanding its network of filling stations to generate $3 billion in additional cash. The group's head of refining told Reuters that even though BP's output was set to spike as new fields become operational, its attitude to refining remains more cautious. "Are we going to invest in more greenfield refining in BP? Probably not," said Tufan Erginbilgic, who has worked in refining since 1990. He said BP was happy with its refining portfolio although it could sell some assets in downstream - which combines refineries with chemicals plants and infrastructure such as storage. Refining of crude oil into fuels such as gasoline, diesel and jet fuel has for years been the industry's problem child, having to grapple with weak and volatile profit margins as well as competition from modern refineries built in China, India and the Middle East. The problems are compounded by the prospect of more energy-efficient cars, aircraft and heating, tighter marine fuel standards, the rise of electric vehicles and slowing consumption growth. A push to modernize and streamline BP's refining, trading and marketing - known as downstream activities - generated $5.6 billion in free cashflow last year, up 25 percent from 2014 despite refining margins at 12-year lows, Erginbilgic said.

US producers build up sales hedges as oil falls - US independent oil companies have used derivatives to protect much more of their expected revenues against a fall in crude prices than they had a year ago, helping them sustain capital spending and production even if the market continues to weaken. Filings from the leading US exploration and production companies show they have hedged the revenues from about 27 per cent of their expected 2017 oil production, according to Wood Mackenzie, the research firm. This time a year ago, they had protected just 17 per cent of their revenues for 2016. Crude prices jumped in the final two months of last year as 13 Opec member countries and 11 non-members agreed to cut production, and US companies were quick to take advantage by locking in those levels. In the fourth quarter of 2016, the 33 small and midsized oil companies surveyed by Wood Mackenzie put on hedges for 648,000 barrels per day of oil production, almost four times as much as they hedged in the equivalent period of 2015. The hedges, which include swaps and collars using options, typically have strike prices of $50-$60 per barrel of benchmark Brent crude, and an average price of $54. That compares with an average strike price of $42 per barrel for new contracts in the first quarter of last year. Anadarko Petroleum and Apache, two of the larger independent oil producers that have assets offshore as well as in US shale reserves, were the most active in the fourth quarter, accounting for about 28 per cent of the oil hedges taken on in the quarter. Andrew McConn of Wood Mackenzie said that if oil prices continued to decline after their $5-a-barrel drop this month, companies that had hedged would be better placed to stick to their capital spending plans. The number of rigs drilling the horizontal wells used in shale oil production has more than doubled from its low point last May, and recorded another strong increase last week, rising 13 to 543, according to Baker Hughes, the oilfield services group. Many companies have been telling investors that they plan to increase production this year.

Huge 300,000 Bpd Fracklog Could Derail Oil Price Recovery --Thousands of drilled shale wells are sitting idle, unfracked and uncompleted. The backlog of drilled but uncompleted wells (DUCs) grew dramatically beginning in 2014, as low oil prices forced drillers to hold off on completion in hopes of higher prices at a later date. After all, why bring production online in a low price environment when the same oil could earn more in the future if prices rebound. That calculation is particularly important given that a shale well typically sees an initial burst of production in its first few months of operation followed by a precipitous decline in output. The surge in DUCs created an enormous backlog of wells awaiting completion. This “fracklog” loomed over the oil market, threatening to derail any sign of an oil price recovery. As soon as oil prices rebounded to some higher point, the shale industry would bring thousands of already-drilled wells online, and that sudden rush of new supply would push prices back down.But that was a necessary process in order to shrink the huge inventory of DUCs – and that’s exactly what started to play out last year. As oil prices moved up from $27 per barrel in February 2016 to around $50 per barrel by early summer, the industry began completing a lot of wells. The DUC inventory fell from over 5,600 to just over 5,000 between January and August, a decline of 10 percent, according to the EIA’s Drilling Productivity Report. By late November, when OPEC announced an ambitious plan to take 1.2 million barrels per day off of the market, combined with nearly 600,000 bpd of non-OPEC cuts, oil prices shot up. One would have thought that the DUC inventory would see another round of completions, reducing the backlog even further. But that didn’t happen. The DUC list has grown since then, increasing to 5,443 as of February 2017, an increase of roughly 8 percent since October. Why did this happen even though WTI and Brent moved up well into the $50s per barrel? The rig count has increased sharply since the OPEC deal was announced, but why are companies adding rigs back into operation if they are not completing the new wells that they are drilling? For example, in the Permian Basin, the industry drilled 395 new wells, but they only completed 300 of them.

Is the US Producing Too Much Oil? - OPEC's production cut had many investors excited for a recovery in oil prices, but the U.S. seems determined to fill in that supply gap.In this clip from Industry Focus: Energy, Fool energy analysts Sean O'Reilly and Taylor Muckerman discuss how much production is set to increase in 2017, what it means for the oil industry in the next few years, and why so many U.S. companies are making a less-than-opportune decision.A full transcript follows the video. This podcast was recorded on March 23, 2017.

Will The Oil Price Slide Lead To A Credit Crunch For U.S. Drillers? - The recent drop in oil prices, which has almost wiped out the price gains since OPEC announced its supply-cut deal, is coming just ahead of the spring season when banks are reassessing the credit lines they are extending to support drillers’ growth plans.WTI front-month futures have been trading below $50 a barrel for a couple of weeks, while Brent crude slipped briefly below $50 on March 22, dropping below that psychological threshold for the first time since November 30, the day on which OPEC said it agreed to curtail collective oil production in an effort to rebalance the market and lift prices.Lenders review the oil and gas companies’ creditworthiness twice a year, in April and in October, in the so-called borrowing base redetermination. The recent drop in the price of oil may prompt banks to be more cautious in their assessments, but still, things look brighter for oil firms than they did in March last year when oil prices were consistently below $40 a barrel.This time around, analysts expect reductions in credit lines should oil prices drop below $45 until creditworthiness reviews are over, according to Bloomberg. These assessments are closely connected to the price of oil, given the fact that the value of the companies’ oil and gas reserves serve as the basis for their creditworthiness assumptions.

Company signals new fracking plans in eastern Boulder County  -- Crestone Peak Resources applied to the Colorado Oil and Gas Conservation Commission last month with a proposal to drill on roughly 12 square miles of Boulder County land.The application is the first in five years, when, in 2012, county commissioners placed a moratorium on accepting and processing new oil and gas development applications in unincorporated Boulder County. The often-scrutinized embargo, currently the subject of a lawsuit from Colorado's attorney general, is slated to expire on May 1.The Denver-based company is proposing up to 216 wells near U.S. 287 and Colo. 52 between Longmont and Lafayette, where an invisible border of grazing fields meet against a slew of oil and gas wells that dot its eastern half.As the industry finds itself increasingly competing for land, the expiration could spur a rush of oil and gas competition to the county."With so much (oil and gas) interest in the area, it's a way for Crestone to stake their claim early on these 12 square miles," Matthew Sura, a Boulder attorney who represents Colorado citizens and communities facing neighborhood drilling, said Thursday. With a halt still in place for new applications at the county level, Crestone turned to a relatively obscure approach known as a comprehensive drilling plan (CDP) application.

Whiting Petroleum: Will Investments In Redtail Niobrara or Bakken Pay Off? - Whiting Petroleum's massive CapEx plan for 2017 surprised the market. The plan calls for $420 million to be spent in Colorado's Redtail field and $580 million in North Dakota's Williston Basin. In the Bakken, the 2017 allocation represents a threefold increase compared to $182 million targeted for 2016. In Redtail Niobrara, a comparable rise by 158% is planned from 2016 level of $163 million. In this article, I will analyze the merits of capital expenditures in both locations, with special attention paid to Redtail. In particular, I will consider profitability of new wells currently being drilled. In view of a sizable part of CapEx likely being deferred to Q4 2017, I will contemplate the impact of Dakota Access pipeline.  Whiting has operated in Redtail for many years. When we examine the decline curves of company-operated wells of different vintages (well groups, segmented by the first year of production), we see consistency year after year. Ignoring the sub-par production of wells that came online in 2016 (on account of a limited number of wells), the output from wells that began producing in 2011, 2014, and 2015 looks remarkably alike. This is true for both oil and natural gas. The uninspiring results in Redtail stand in sharp contrast to the firm's performance in the Bakken, where steady improvements have been seen year after year.  […] Comparing economics of drilled and uncompleted wells in the Redtail field to those in the Williston Basin, I do not agree with Whiting Petroleum's claim that "Redtail DUC, in terms of returns and whatnot, is similar to a Bakken drill and complete". On the contrary, I see Redtail DUCs as inferior to newly drilled wells in the Bakken, and regard CapEx allocation to Redtail as potentially destroying shareholder value. Whiting's relatively greater optimism about Redtail EURs as compared to Bakken EURs is a likely explanation of the firm's view on Redtail. The company may be in a lose-lose position, the choices being completing Redtail wells that might never earn back the invested capital, or losing acreage and/or having to de-book proved reserves. The upside of Whiting's strategy of completing Redtail wells consists of being able to show production growth, at least until the firm exhausts its DUC inventory by year-end. In contrast, Whiting's increased investment in the Bakken may be justified as long as oil prices do not go through another downturn. There is much room in improving Whiting's oil realizations. The rising tide brought about by Dakota Access Pipeline should lift all boats, even if Whiting fails to achieve the same discount to WTI as, for instance, Continental Resources.

Trump order could ease restrictions on oil and gas drilling in some national parks - When President Donald Trump signed his “energy independence” executive order on Tuesday, he made no mention of making it easier for energy companies to drill for oil in national parks. But tucked into his 2,300-word order is a sentence that could do just that, potentially affecting national park lands in Florida, Kentucky, Texas and other states. At issue are national parks where the federal government owns the surface lands but private entities retain the underground mineral rights. Some 42 park properties nationwide fall into this category, and energy companies are drilling for oil and gas in 12 of those, according to the Interior Department.  Last year, the Obama administration finalized rules aimed at regulating drilling operations on national park land that previously had been exempt. The new rules also required energy companies to provide adequate bonding to ensure that spills would be cleaned up and drilling sites restored to their natural look once operations ceased.Trump’s order directs the interior secretary to review and possibly rescind those rules – known as the 9B rules, or “General Provisions and Non-Federal Oil and Gas Rights” – if they are inconsistent with his energy goals.Environmental groups are protesting the move, saying it conflicts with the National Park Service’s mandate to protect the nation’s parks.Nicholas Lund, a senior manager with the National Park Conservation Association, said it was “inconceivable” that Trump would seek to turn back the clock on regulating oil rigs in national parks. “These rules are not overly burdensome and they go a long way to ensuring our parks have the protection they deserve,” he said.  A spokeswoman for Interior Secretary Ryan Zinke suggested that critics are overreacting.

LETTER: Do Nevada lawmakers who oppose fracking ride their bikes to work? | Las Vegas Review-Journal: Would you please publish the names of all the legislators in addition to Assemblyman Justin Watkins who support the bill to ban fracking. Do they ride their bicycles to work and turn off their air conditioning in July and August? Where do these people think their energy comes from? Robert E. Pribila Las Vegas

Hoeven: Interior Department Begins Process to Roll Back Methane, Hydraulic Fracturing Rules and Rescind the Moratorium on Federal Coal Leasing -- Senator John Hoeven, a member of the Senate Energy Committee, today joined Interior Secretary Ryan Zinke to begin implementing the President's executive order promoting domestic energy production. Secretary Zinke signed orders reviewing, revising and rescinding the Bureau of Land Management's (BLM) duplicative regulations for methane and hydraulic fracturing on federal lands, and rescinding the moratorium on federal coal leasing.  'We appreciate that Secretary Zinke is working to restore regulatory certainty for our nation's energy producers,' said Hoeven. 'Rolling back the methane rule and hydraulic fracturing regulations will ensure that we don't have duplicative regulations causing uncertainty and preventing economic growth. Restoring a states-first approach to regulating energy development will enable us to develop our state's unique energy resources and to do so with good environmental stewardship.'  The Interior Department began the process of unwinding the BLM's regulation for hydraulic fracturing of oil and gas wells on federal lands. The BLM's rule is duplicative with state regulations, which creates unnecessary delays and increased costs. Hoeven pressed the previous Administration to work with states to remove overlapping regulation and provide greater regulatory certainty for the nation's energy producers.  According to Hoeven, 'North Dakota is best suited to regulate hydraulic fracturing in our State, rather than a federal, one-size-fits-all approach. We are leading the way forward in oil production with new technologies that produce more energy with better environmental stewardship.'  The Secretary's order begins the process of reviewing and rescinding the BLM methane rule, which is duplicative and creates conflict within the regulatory process. This regulatory uncertainty imposes unnecessary costs for the nation's energy producers. Hoeven has called for the BLM and Environmental Protection Agency (EPA) to allow states to take the lead in the regulatory process to reduce natural gas flaring and to address the BLM's backlog in permit applications for gas gathering infrastructure. While today's action begins efforts to stop the rule, Hoeven continues working to pass a Congressional Review Act (CRA) to rescind the methane rule permanently to more expeditiously stop the duplicative rule.

Why midwest refiners passed up local Bakken bounty -- According to Energy Information Administration data, the 26 refineries in the Midwest/PADD 2 region processed an average 3.6 MMb/d of crude oil in 2016—up 300 Mb/d from the 3.3 MMb/d refined in 2010. Over the same six-year period, production of light oil production in the region shot up by over 1 MMb/d, mostly from the prolific Bakken formation in North Dakota. Yet Midwest refiners did little to take advantage of the sudden abundance of “local” production, increasing instead their appetite for imported heavy crude from Western Canada by nearly 1 MMb/d—from 800 Mb/d in 2010 to 1.8 MMb/d in 2016. Today we explore the trend for PADD 2 refineries to run more heavy crude even as shale output surged in their backyard.  Much of the reason why PADD 2 refiners focused on heavy crude when light-oil shale supplies arrived on their doorstep was timing. Just before domestic production in the Bakken and other shale plays took off in 2011, several large refineries in PADD 2—including the largest, the 414-Mb/d BP Whiting plant in northwestern Indiana—underwent major upgrades to increase their coking capacity (see I’d Like To Buy The World A Coke for more on cokers) to process heavy crude. These expensive investments (BP spent $4.2 billion) were made in a world before shale, when the prevailing opinion was that lighter crudes that are easier to process were running out and likely to get more expensive. Heavy crude requires more complex and expensive equipment to refine (see Complex Refining 101 for more on refinery upgrading processes), but is (the theory went) more abundant and expected to be cheaper to buy than light crude.  Around the same time, heavy bitumen crude producers in Western Canada were bringing several new projects online (see We Are The Champions). These projects targeted the same Midwest refinery upgrades, in some cases through joint ventures. Which is why the largest refineries in PADD 2, having made significant investments, increased their consumption of imported heavy Canadian crude at the expense of light crude from the Bakken.

December North Dakota Oil Spill More Than 3 Times Larger Than Initial Estimate -  A crude oil spill in western North Dakota in December is now believed to be about three times bigger than originally estimated, pipeline owner True Companies said on Friday, making it the largest crude leak to affect water in the state in over a decade.The Belle Fourche crude oil pipeline spilled an estimated 12,615 barrels of oil, more than the December estimate of 4,200 barrels, spokeswoman Wendy Owen said in a phone call.The spill is the second-largest crude spill in the state in more than 15 years, behind a 20,600-barrel leak by a Tesoro Logistics LP pipeline in 2013, according to data from the Pipeline and Hazardous Materials Safety Administration.Around 80 percent of the cleanup is complete, Owen said, noting the incident occurred following ground movement. Oil from the pipeline leaked into the Ash Coulee Creek and on a hillside.The pipeline operator has collected around 3,900 barrels of oil from the creek by skimming and vacuuming, Owen said. No oil moved further down the creek, which feeds into the Little Missouri River and eventually flows into the Missouri River, a major source of drinking water, she said.The North Dakota Department of Health has not yet completed a subsurface investigation on the hillside affected by the leak to confirm how much oil remains, agency program manager Bill Seuss said by phone on Friday.The spill was not originally detected by monitoring equipment, which True Companies has said was likely due to its intermittent flow.

Company: Oil in pipeline under Missouri River reservoir -  bismarcktribune.com: The Dakota Access pipeline developer said Monday that it has placed oil in the pipeline under a Missouri River reservoir in North Dakota and that it's preparing to put the pipeline into service. Dallas-based Energy Transfer Partners made the announcement in a brief court filing with the U.S. District Court for the District of Columbia. The announcement marks a significant development in the long battle over the project that will move North Dakota oil 2000 miles (1930 kilometers) through South Dakota and Iowa to a shipping point in Illinois. The pipeline is three months behind schedule due to large protests and the objections of two American Indian tribes who say it threatens their water supply and cultural sites. ETP's filing did not say when the company expected the pipeline to be completely operating, and a spokeswoman did not immediately return an email seeking additional details. "Oil has been placed in the Dakota Access Pipeline underneath Lake Oahe. Dakota Access is currently commissioning the full pipeline and is preparing to place the pipeline into service," the filing stated. Despite the announcement, the battle isn't over. The Standing Rock and Cheyenne River Sioux tribes still have an unresolved lawsuit that seeks to stop the project. The Standing Rock chairman did not immediately return a call seeking comment on ETP's announcement. The tribes argue that a rupture in the section that crosses under Lake Oahe would threaten their water supply and sacred sites and would prevent them from practicing their religion, which requires clean water. The company disputes the tribes' claims and says the $3.8 billion pipeline is safe.

Dakota Access puts oil in pipeline | TheHill: The company that built the Dakota Access pipeline has filled the pipe with oil and is making the final preparations to start moving the oil. The development is a significant milestone in the life of the highly controversial project, which stalled last year amid intense protests by American Indians and their allies who opposed running the pipeline under Lake Oahe in North Dakota. Energy Transfer Partners revealed the progress late Monday in a federal court filing.ISEMENT“Oil has been placed in the Dakota Access Pipeline underneath Lake Oahe,” the company said. “Dakota Access is currently commissioning the full pipeline and is preparing to place the pipeline into service.” The company did not say exactly when it expects to start making deliveries through the line. The update comes days after President Trump gave approval to the Keystone XL pipeline, another controversial pipeline planned to carry oil sands petroleum. The 1,172-mile Dakota Access pipeline runs from North Dakota to Illinois, serving a route key to the growing oil industry in North Dakota and neighboring states, with a capacity of 570,000 barrels of oil a day. Two American Indian tribes with reservations near Lake Oahe are still working in federal court to have the pipeline shut down, saying it could harm their water supplies and violate their religious freedom. Those tribes, and thousands of their allies, protested for months in a camp near the lake last fall. They succeeded in convincing the Obama administration in December to withhold the easement that Energy Transfer needed to build under the federally owned lake. But Trump signed a memorandum days after taking office asking the Army Corps of Engineers to reconsider. The Army Corps issued the easement last month.

Dakota Access Line Outlasts Protests, Readies for Service - In the end, the pipeline won.Dakota Access, which became a rallying point for tens of thousands of anti-fossil fuel and Native American-rights protesters, is preparing for service, a court filing on Monday showed. Now that the last segment built underneath Lake Oahe has been filled with oil, it’s only a matter of time before the line delivers crude from North Dakota’s once-booming Bakken shale region. That’ll be a boon to drillers there who’ve lost market share amid low oil prices to rivals in Texas and elsewhere with better access to Gulf Coast refineries and terminals.“No doubt, this makes the Bakken more competitive,” said Rob Thummel, managing director at Tortoise Capital Advisors.  The filing, by Dakota Access’s developer, came just three days after the State Department issued a presidential permit approving the controversial Keystone XL oil pipeline, which when completed would run from Canada into America’s heartland. President Donald Trump’s support of both pipeline projects represents a dramatic reversal from former President Barack Obama’s opposition to them on environmental grounds.  Until now, Bakken crude has had to travel through a circuitous network of other pipelines and by pricier rail, one reason production has fallen in North Dakota as explorers shifted their focus to cheaper Texas reserves. It’s been a long and ugly fight bringing to life one of the most contentious pipeline projects in recent memory. Just a few years ago, the Bakken was the Wild West of oil, with boom towns, man camps and casinos fueled by speculative plays on soaring oil prices. Following the crash in prices, drillers of the remote northern plains hoped new transport options like Dakota Access would help them remain competitive -- only to be stymied by fierce protests. In early 2016, members of the Sioux nation and hardy environmentalists began camping out along the proposed route in protest. Their ranks swelled in late summer after construction crews bulldozed a site sacred to Native Americans. Hollywood celebrities including Mark Ruffalo and Leonardo DiCaprio flocked to the Standing Rock reservation to lend support. Shailene Woodley was arrested and led away in handcuffs. It all went viral on social media.  But after Trump’s election, the government swept away protesters, at one point with high-pressure water hoses in the icy North Dakota winter. And soon thereafter Trump signed an executive order clearing the way for the pipeline’s final segment to be built.

North Dakota oil output set to rise as controversial pipeline opens | Reuters: North Dakota oil production will get a shot in the arm next month as a pipeline comes online despite opposition by environmental groups and Native Americans, allowing the energy industry to save at least $540 million in annual shipping costs. The Dakota Access Pipeline gives the state's producers cheaper access to refineries and other customers on the U.S. Gulf Coast. Market players said they expect this will hasten a revival of output from the Bakken region which fell sharply along with global oil prices during the past two years. "We're back to growth in the Bakken," Hess Corp (HES.N) Chief Executive Officer John Hess said in a recent interview. The New York-based company has contracts to send roughly half its daily North Dakota output through DAPL. For 2017, Hess has said its Bakken production could grow more than 10 percent. President Donald Trump approved the $3.7 billion pipeline in February, reversing the prior administration which had blocked it last December with a decision by the U.S. Army Corps of Engineers. Energy Transfer Partners LP (ETP.N), which operates the 1,100 mile (1,770 km) long DAPL, has begun filling the line with crude and could reach full operating capacity by late April, based on industry estimates. DAPL "will provide a safer, more environmentally responsible and more cost-effective transportation system to move crude across this country as opposed to truck or rail," said ETP spokeswoman Vicki Granado. The pipeline will carry about 500,000 barrels of oil per day, more than half of North Dakota's daily output, cutting reliance on riskier rail-cars and reducing transport cost by roughly $3 to $5 per barrel, analysts estimate. That should help level the playing field between Bakken producers and rivals in other U.S. shale plays, many of which are closer to refineries and other customers.The state's drilling rig count has jumped 40 percent since early February, when Trump gave final approval to the pipeline. By the end of the year, analysts expect the rig count to rise another 10 percent or more.

Tribes' battle over Dakota Access pipeline not over (AP) - American Indian tribes fighting the $3.8 billion Dakota Access pipeline said Tuesday that the pumping of oil into the pipe under their water source is a blow, but it doesn't end their legal battle. Industry groups say the imminent flow of oil through the pipeline is good news for energy and infrastructure. The comments come after Texas-based developer Energy Transfer Partners said Monday that it has placed oil in a section of the pipeline under a Missouri River reservoir that's upstream from the Standing Rock Indian Reservation in North Dakota. It was the final piece of construction for a pipeline that will carry crude from western North Dakota's Bakken oil fields 1,200 miles (1930 kilometers) through South Dakota and Iowa to a distribution point near Patoka, Illinois. The pipeline should be fully operational in about three weeks, according to company spokeswoman Vicki Granado. "We need to build pipelines, roads, rail and transmission lines to grow our economy and secure our nation's energy future," North Dakota Republican U.S. Sen. John Hoeven said. Cheyenne River Sioux Chairman Harold Frazier said Sioux tribes in the Dakotas still believe they ultimately will persuade a judge to shut down the pipeline that they maintain threatens cultural sites, drinking water and religion. "My people are here today because we have survived in the face of the worst kind of challenges," he said. "The fact that oil is flowing under our life-giving waters is a blow, but it hasn't broken us." Standing Rock Sioux Chairman Dave Archambault called oil under the lake "a setback, and a frightening one at that." But he and Phillip Ellis, spokesman for the Earthjustice environmental law nonprofit, which is representing that tribe, said they are confident in the court case. "The flow of oil under Lake Oahe is a temporary reminder of the pain this pipeline has perpetrated to those that have stood with Standing Rock and the devastation it has wreaked on sacred tribal sites, but hope remains," Ellis said. ETP maintains the pipeline is safe and disputes the tribes' claims.

Trump administration grants pipeline permits without all his promised conditions   - President Donald Trump vowed to win a "better deal" for Americans before approving the Keystone XL and the Dakota Access oil pipelines, promising to extract concessions and force the builders to use U.S. steel. Now his administration has authorized both projects -- with those conditions mostly unmet. The outcomes illustrate the limits of the president’s power and poke holes in the carefully crafted image of Trump as a dealmaker so good at twisting arms that he wrote a book about his negotiating prowess. “Donald Trump’s promises on these pipelines are like the pipelines themselves: hollow," said Senator Ed Markey, a Democrat from Massachusetts. "The only promises being kept with approval of these pipelines will be the ones made to Big Oil who want to export this dirty oil to thirsty foreign markets at the expense of our environment and our economy." TransCanada Corp. says it has agreed to increase the amount of U.S. steel in the pipeline, after diverting some of the foreign-made stock it planned to use to other projects. And White House press secretary Sean Spicer called it "an even better deal for the American people than before he took office." Trump had conditioned his support for Keystone XL even before he moved in to the White House. In North Dakota last May, Trump said he would approve TransCanada’s proposed pipeline in exchange for a "better deal" that ensures U.S. taxpayers get "a significant piece of the profits." Even as he revived consideration of Keystone XL and the Dakota Access pipelines in January, Trump said authorizations were "subject to terms and conditions to be negotiated by us." The same day, Spicer said Trump would "make sure that he is looking or working with all parties involved" in the fight over the Dakota Access Pipeline, including tribes that were opposed to the project.  But approval for the Dakota pipeline was announced as Standing Rock Sioux Tribe chairman Dave Archambault II was on an airplane heading for Washington and what he said he believed would be negotiations. The chairman canceled his meeting with administration officials after learning of the decision.

The Fight is Not Over,' Groups Vow, as State Dept Poised to Approve Keystone XL -- The State Department will announce its approval of the controversial Keystone XL pipeline on Friday, unnamed government sources told the Associated Press, after President Donald Trump ordered the department to reopen its review of the pipeline.The decision will clear the way for construction to begin on the "zombie pipeline," which would transport 35 barrels of oil a day from Canada's tar sands to refineries in south Texas.Environmental groups are unanimous in their outrage."The Keystone XL pipeline is a disaster for people, wildlife and the planet," said KierĂ¡n Suckling, executive director of the Center for Biological Diversity. "The Trump administration is taking us dangerously off course by approving this dirty, dangerous pipeline." Friends of the Earth (FoE) president Erich Pica added in a statement: "For almost a decade, Americans have fought to stop the dirty Keystone XL pipeline from polluting their air and water. We banded together to turn this pipeline into a leadership test on climate change and Trump flunked the exam." Environmentalists and progressives also took to social media to voice their condemnation:  The Ogallala aquifer and the proposed Keystone XL pipeline route. It will leak & ruin US food & water supply. #NoKXL pic.twitter.com/KNNdFfi5W7  A rupture in the #KeystoneXLpipeline would pollute fresh drinking water for 20 million people: https://t.co/CdWYLoUCwX #ThursdayThoughts pic.twitter.com/Yc7ALRPSrr  Aside from its dire climate ramifications, the Natural Resources Defense Council (NRDC) pointed out earlier this week that troubling things are happening behind the scenes of the pipeline decision. The pipeline won't be made of U.S. steel, as Trump promised during the presidential campaign—in fact, pipeline company TransCanada has threatened to continue suing the U.S. under NAFTA if the Trump administration forces the company to make Keystone XL out of American steel. "Meanwhile, this zombie project remains what it always was for Americans: all risk and no reward," writes NRDC's Josh Axelrod. "It remains an environmental catastrophe waiting to happen: a risk to our shared global climate, our precious fresh water sources, and our farms and ranches across America's heartland. And more Americans are opposed to it than in favor: 48 percent to 42 percent."

Billionaires vs. Billionaires: How TrumpCare's Defeat Was Actually a Victory for the Koch Brothers -- Greg Palast - When RyanCare-TrumpCare finally ended up face-down in the swimming pool, triumphalist Democrats whooped and partied and congratulated themselves on defeating the Trump-Ryan monstrosity. But deep in their counting house, counting their gold, three brothers cackled with private jubilation. David and Charles Koch knew the day was theirs. Joining them in the celebration was Brother Billy, William Koch, who will share in their $21 billion windfall that the President arranged for them only hours before TrumpCare crashed--when Trump announced his State Department had formally approved the Keystone XL Pipeline. .  The XL Keystone Pipeline would take the world's heaviest, filthiest crude from Canada's tar sands, and snake with it all the way down to Texas. Exactly why are we sending oil all the way across the United States to Texas?  In fact, Texas is drowning in oil, choking in it. But the Kochs' Texas refinery can't use much local crude. The Koch Industries Flint Hills refinery on the Texas Gulf Coast was designed specifically to crack only the world's "heaviest" (i.e. filthiest) crude.Texas crude ain't heavy enough, ain't dirty enough, for the Kochs' Gulf Coast operation, originally designed for imports for the world's major source of heavy crude: Venezuela. The price the Kochs paid for Venezuela's oil was set by its President Hugo Chavez, and now, by Chavez' chosen successor, Nicolas Maduro. Chavez and Maduro both told me they'd squeeze the Kochs by their tankers. They have.  Canadians sell their super-heavy crude at a $12 to $30 a barrel discount to the Venezuelan price. If the XL Pipeline is complete, the Kochs can suck down Canada's cheap cruddy crude for a minimum savings of $1.27 billion in a single year. […} When TrumpCare breathed its last, the President blamed Democrats for its untimely demise.A stunned by-stander, Democratic Minority leader Nancy Pelosi, went for it: "We'll take credit for that." Sorry, Nancy, you can't. Because it was the Kochs' brownshirts, the self-styled "Freedom Caucus," that, in a bestial assault, crushed a sitting President and their own leader of Congress, Paul Ryan. The thugs' secret weapon: heavy bags of cash, Koch cash.   The Kochs' Freedom Partners Executive Director told members of the uber-right Congressional Freedom Caucus, "We will stand with lawmakers who keep their promise and oppose this legislation" with a "seven-figure" war chest. In the old days, that was called "bribery." But today it's called, "Koch." The Kochs don't want ObamaCare, TrumpCare, nor any care at all for Americans that add to their tax bill. Call it KochDon'tCare. But keen observers of TrumpCare would note that it was not really a health care bill, but a tax bill--specifically, a tax cut of some $157 billion that has been charged to the richest Americans to fund ObamaCare through a 3.75% tax on passive investment income--that is, money earned, not by working, but by speculating.  But to the Kochs, this tax break is nearly worthless. So, behind the curtain, this was a fight of billionaires versus billionaires.

Environmental groups sue Trump administration for approving Keystone pipeline | Reuters: Several environmental groups filed lawsuits against the Trump administration on Thursday to challenge its decision to approve construction of TransCanada Corp's controversial Keystone XL crude oil pipeline. In two separate filings to a federal court in Montana, environmental groups argued that the U.S. State Department, which granted the permit needed for the pipeline to cross the Canadian border, relied on an "outdated and incomplete environmental impact statement" when making its decision earlier this month. By approving the pipeline without public input and an up-to-date environmental assessment, the administration violated the National Environmental Policy Act, groups including the Center for Biological Diversity, Sierra Club and the Northern Plains Resource Council said in their legal filing. "They have relied on an arbitrary, stale, and incomplete environmental review completed over three years ago, for a process that ended with the State Department’s denial of a cross-border permit," the court filing says. In the other filing, the Indigenous Environmental Network and North Coast Rivers Alliance sought injunctive relief, restraining Transcanada from taking any action that would harm the "physical environment in connection with the project pending a full hearing on the merits." U.S. President Donald Trump announced the presidential permit for the Keystone XL at the White House last week. TransCanada's Chief Executive Officer Russ Girling and Sean McGarvey, president of North America's Building Trades Unions, stood nearby.

Opinion: Oh no! Not again with fracking -  - I was astounded when I learned from a friend that the BLM (Bureau of Land Management) was holding a series of three meetings in the tri-county area of Monterey, San Benito and Santa Cruz. "How can that be?" I asked myself?  During the 2014 campaign to ban fracking in San Benito County, the BLM assured us at the Hollister Office that they had our backs and would do what they could to fulfill their mission statement which is: TO SUSTAIN THE HEALTH AND DIVERSITY AND PRODUCTIVITY OF PUBLIC LANDS ENTRUSTED TO THEM FOR THE USE AND ENJOYMENT OF THE PRESENT AND FUTURE OF ALL PEOPLE. Since 2014, two measures have been passed by the voters of San Benito, Santa Cruz and Monterey counties to ban fracking and steam injection methods of oil and gas extraction in all three counties. By the vote of the people, these measures became the law of the state of California. This was due to the BLM being sued for an inadequate environmental impact statement on their lands and the overwhelming majority of people in the three counties who did not want any fracking in their counties. This seemed settled until the new administration entered the picture. It is interesting how fast the oil and gas corporations got to work to present a revised EIR indicating new methods of fracking and extraction of oil and gas that would not harm the environment or the creatures living in the area including humans: No poisoning of the aquifers, no pollution in the drinking and irrigation wells, no polluting of the air or surface land and of course no earthquakes to damage the well casings! This is preposterous and contradicts thousands of pages of scientific investigations into fracking and injection methods over the past 20 years in this country.  These lands are OUR lands held in trust for the millions of us who want to preserve and protect our dwindling resources of recreation and renewal for the human spirit and for all the animal and plant spirits that dwell therein. Fracking and extraction are against everyone of us who want a sustainable and peaceful planet. This is the last gasp of the fossil fuel monopolies who will squeeze the  last drop and make as many billions as then can before they are stopped by the people of this planet,

Market realities weight heavily on the Canadian oil sands -- On Friday, TransCanada finally secured a Presidential Permit for the U.S. portion of its Keystone XL pipeline, and the company committed to pursuing the state approvals it still needs to build the project. But three hard truths—crude oil prices below $50/bbl, the high cost of producing bitumen and moving it to market, and more attractive energy investments available elsewhere—have thrown a wet blanket on once-ambitious plans to significantly expand production in Western Canada’s oil sands, the primary source of the product that would flow through Keystone XL. Today we begin a series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines. The three oil sands areas in northern Alberta—the giant Athabasca deposits and the smaller Peace River and Cold Lake areas—together cover only ~55,000 square miles (about one-fifth the size of Texas, or of Alberta) but they contain proven reserves equivalent to more than 160 billion barrels of crude oil, according to the International Energy Agency and other sources. As the Shale Era has reminded everyone though, simply having vast hydrocarbon reserves in the ground isn’t enough­­. Production costs and the cost of delivering product to market need to be competitive if an area is to continue drawing investment—at least over the long-term in the case of areas with higher upfront development costs like the oil sands and the Gulf of Mexico.

British Columbia secures 90% of First Nations agreements needed for LNG-related pipe projects - The British Columbia government has entered into 64 natural gas pipeline benefits agreements with 29 eligible First Nations, more than 90% of the agreements that need to be negotiated along the routes of four pipelines proposed to carry gas to planned LNG export terminals along the province's western coast. The agreements are part of the Canadian province's plan to partner with First Nations on LNG opportunities, the BC Ministry of Aboriginal Relations and Reconciliation said in a statement Thursday. The four pipeline projects are: Prince Rupert Gas Transmission Pipeline, Coastal GasLink Pipeline, Westcoast Connector Gas Transmission and the Pacific Trail Pipeline. Under the agreements, the First Nations will allow the pipeline to traverse their traditional territories, to which they hold aboriginal rights and title.In exchange for entering into agreement with the province, each First Nations group will receive "milestone" payments at certain points along the pipeline process, a ministry spokesman said Friday. These include: an initial payment and subsequent payments when the pipeline starts construction and when it goes into production, as well as ongoing benefit payments for the life of the project, a spokesman said. To date, 17 of the 19 First Nations along the Prince Rupert Gas Transmission pipeline route have pipeline benefits agreements in place with the province.

Greens call on public to push government towards fracking ban --It's more important than ever that communities make their voices heard about fracking. Mark Ruskell MSP  Public participation in a fracking consultation could be the key to finally seeing the Scottish Government ban the hazardous practice, a Green MSP has said at Holyrood. Mid Scotland and Fife MSP, Mark Ruskell responded to a ministerial statement on 'Unconventional Oil and Gas' by saying that the government's current, 'legally shaky' moratorium' must become a ban 'as soon as possible'. The statement repeated previous ministerial commitments that the government will present its 'recommendations' to Holyrood when the 'consultation closes'.  The Scottish Greens' energy and environment spokesperson, Mark Ruskell MSP, said:

Eni CEO Says Mexico Oil Find Likely Bigger Than Estimates | Rigzone Italy's Eni said on Wednesday it expected that its recent discovery off the coast of Mexico would hold more than the 800 million barrels of oil it originally estimated. "This is an important find and we've found new layers of good light oil that make us think there's more," Chief Executive Claudio Descalzi said at an oil and gas conference. Eni said earlier this month it had found "meaningful" reserves of oil off the coast of Mexico after becoming the first international oil company to drill a well in the country after a 2013 reform opening up the sector to investors. State-controlled Eni, which in recent years has made major gas finds in Mozambique and Egypt, holds one of the best discovery track records in the industry. Its organic reserve replacement ratio -- a measure of its ability to find hydrocarbons -- stood at 193 percent in 2016 compared to a 35 percent peer average. "Eni's Zohr discovery is a game changer," Egypt's oil minister Tarek El Molla said on Wednesday, referring to Eni's discovery in Egyptian waters of the biggest gas field ever found in the Mediterranean. Descalzi said Eni would follow the same strategy in Mexico as it had adopted in Egypt, using infrastructure already in place to help speed up time to market. He said the discovery, some 6-7 km from the coast, was close to installations owned by Mexico's state-owned oil company Pemex. He added he would speak to Pemex in coming months to discuss using some of their infrastructure in the area.

Country With The World's Largest Oil Reserves Runs Out Of Gasoline --  Venezuela has long prided itself on selling its citizens the world's cheapest gasoline... that is when it has gasoline to sell. While fuel supplies in the country with the world's largest proven oil reserves...... have continued flowing despite monetary collapse and hyperinflation, a domestic oil industry in turmoil and a deepening economic collapse under President Nicolas Maduro that has left the South American country with scant supplies of many basic necessities, that changed last Wednesday when Venezuelans faced their first nationwide shortage of motor fuel since an explosion ripped through one of the world's largest refineries five years ago. At the time, the government of then-President Hugo Chavez curbed exports to guarantee there was enough fuel at home.  This time, however, the problems were all man made and the shortage was mainly due to problems at refineries, as a mix of plant glitches and maintenance cut fuel production in half.In the immediate aftermath of the shortage, Venezuela’s state oil company, Petroleos de Venezuela, rushed to replenish gasoline supplies in various neighborhoods of Caracas as drivers lined up at filling stations amid a worsening shortage of fuel. While Petroleos de Venezuela, or PDVSA, says the situation is normalizing and blamed the lines on transport delays, the opposition says the company has had to reduce costly fuel imports as it tries to preserve cash to pay its foreign debt. The opposition was likely right.According to Bloomberg, tanker trucks were seen in several neighborhoods of the capital city resupplying filling stations after local newspaper El Nacional reported widespread shortages across the country.  As the company’s crumbling refineries fail to meet domestic demand, imports have become a major drain of cash as the country buys fuel abroad at market prices only to sell it for pennies per gallon at home, unless, of course, one buys abundant gasoline on the black market where its cost is orders of magnitude higher than what one would pay at the gas station. “Yesterday, I went to three filling stations and I couldn’t fill my tank,” Freddy Bautista, a 26-year-old student, said in an interview while waiting outside of a gas station in the Las Mercedes area of eastern Caracas on Thursday. “I’ve been waiting 30 minutes here, and it seems like I’ll be able to fill up today.”

Market implications of the 2017 oil and gas recovery.-- If you have spent much time with us in the RBN blogosphere, you know how we like to understand the supply/demand balance in the context of price trends, and vice versa. So we’ll start there by examining both recent history and the forward curve for U.S. domestic crude oil—West Texas Intermediate (WTI) at Cushing, OK. In the left graph in Figure 1 we have the trend line—or lack thereof—for WTI since January 2015. On average, the price for WTI has been $47/bbl (orange line); at one point “zooming” up to $60/bbl and last year at this time dropping briefly below $30/bbl (blue line). But for the most part, WTI has been hanging in a range pretty close to $50/bbl.  And then on the Figure 1 right graph there is the forward curve—or, again, lack thereof. Same story. Fifty bucks in 2017, all the way out to 2021 and beyond.  For a long time after crude prices crashed, the forward curve was in “contango” —futures prices rising steadily over time. And that was the case whether the spot price was $50/bbl or $30/bbl. But no longer. You can sell or buy $50/bbl U.S. crude oil for five years out, and even further into the future if you wish. And it is not just crude oil. The closing price on Friday for Henry Hub natural gas for June 2027 (that would be more than 10 years from now!) closed at $2.964/MMbtu, 11 cents below the closing price for April 2017.  Now that’s a sobering statistic.   So have those sobering forward prices resulted in curtailments of spending and drilling? Hardly. Figure 2 shows the Baker Hughes rig count from January 2016 to last Friday. On the oil side to the left, since the low in May 2016 the rig count has more than doubled, from 316 up to 652. It’s about the same story for gas (on the right), up from 81 in August of last year to 155 on Friday.  U.S. producers are putting rigs back to work at a rate almost as fast as the rate they idled those rigs back in 2015 and early 2016.

Spot LNG trading makes up 18% of total LNG volumes in 2016: GIIGNL -  Pure LNG spot trading -- trades where cargoes are delivered within three months of the transaction date -- made up 18% of total imported LNG volumes in 2016, an increase from 15% the year before, industry group GIIGNL said Monday in its latest annual review. Spot trade volumes were estimated at around 47 million mt last year, up from 37 million mt in 2015, with the main drivers of the growth being China, India and Egypt, GIIGNL said. Combined, the three countries accounted for 30% -- or 15 million mt -- of the pure spot LNG volumes imported in 2016."Signs indicate an evolution towards a greater flexibility in [LNG] trade, and the commercial patterns are evolving as destination-free volumes increase and as new buyers and sellers join the market," GIIGNL said. With many longer term LNG supply contracts also due to expire in the coming years, the move toward more spot trading is likely to gather pace, GIIGNL president Jean-Marie Dauger said. "In order to respond to market changes and cope with the uncertainty of future supply and demand, LNG contracting strategies have grown in importance," he said in the report. "In this respect, most buyers pay particular attention to flexibility -- in terms of destination as well as offtake obligations -- and price competitiveness," he said.

NYMEX April gas futures expire at $3.175/MMBtu, up 7.9 cents - Natural Gas | Platts News Article & Story: The NYMEX April natural gas futures contract expired on a high note, with the prompt-month contract settling at an eight-week high of $3.175/MMBtu, up 7.9 cents day on day. The contract, which tore through major resistance at $3.08 and then again at $3.147/MMBtu Wednesday, was fueled by supportive storage report expectations and book-squaring as markets prepare to enter an injection season clouded by bullish supply and demand fundamentals. Where book-squaring ahead of the contract's roll provided some support, weather forecasts effectively capped upside movement.The latest National Weather Service temperature forecasts call for above-average temperatures overtaking all but small portions of the Northeast and Northwest in both the six- to 10-day and eight- to 14-day periods. Markets are more focused on Thursday's storage report though, with the Energy Information Administration expected to report a 43-Bcf net withdrawal for the week ended March 24, according to a consensus of analysts surveyed by S&P Global Platts. That would be slightly bullish compared with the corresponding five-year average withdrawal of 27 Bcf. After Thursday's report, gas storage levels are on track to enter injection season at around 2 Tcf, significantly below the 2.46 Tcf at the 2016 season close. "Ideally the market would like to see 3.6 or 3.9 [Tcf] at the end of the injection season, and accordingly we will need more injections than last year to reach that level," Thomas Saal, senior vice president of energy trading at INTL FC Stone, said Thursday. While markets were able to inject nearly 1.6 Tcf of natural gas during last year's injection season, meeting that target this year may be tricky given that production currently sits over 2 Bcf/d lower than year-ago levels and LNG exports are expected to grow 92% between March and October to 3.89 Bcf/d, Platts Analytics data shows.

US natural gas in storage falls 43 Bcf to 2.049 Tcf: EIA - US natural gas in storage fell 43 Bcf to 2.049 Tcf in the week ended March 24, Energy Information Administration data showed Thursday. The pull was exactly in line with an S&P Global Platts' survey of analysts calling for a 43-Bcf withdrawal. The withdrawal proved stronger than both the five-year average draw of 27 Bcf and the 19-Bcf pull reported in the corresponding week in 2016, according to EIA data. It was the second consecutive weekly draw larger than both the five-year average and that in 2016. It also likely marked the end of the withdrawal season as net injections are expected for the next few foreseeable weeks. As a result, stocks were 413 Bcf, or 17.1%, less than the year-ago level of 2.472 Tcf, but 250 Bcf, or 13.9%, more than the five-year average of 1.799 Tcf. The NYMEX May natural gas futures contract slipped 3 cents to $3.201/MMBtu in the minutes following the 10:30 am EDT (15:30 GMT) storage announcement. The EIA reported a 31-Bcf withdrawal in the East to 278 Bcf, compared with 441 Bcf a year ago; a 20-Bcf pull in the Midwest to 486 Bcf, compared with 557 Bcf a year ago; a 4-Bcf build in the Mountain region to 141 Bcf, compared with 147 Bcf a year ago; a 4-Bcf injection in the Pacific to 212 Bcf, compared to 262 Bcf a year ago; and zero net storage activity in the South Central region to remain at 932 Bcf, compared to 1.064 Tcf a year ago. Total inventories now are 64 Bcf less than the five-year average of 342 Bcf in the East, 104 Bcf more than the five-year average of 382 Bcf in the Midwest, 20 Bcf more than the five-year average of 121 Bcf in the Mountain region, 15 Bcf less than the five-year average of 227 Bcf in the Pacific, and 205 Bcf more than the five-year average of 727 Bcf in the South Central region.

Natural Gas Prices Move Lower in Today's Session - Natural gas prices continue to find resistance near the $3.25 level, as the contract for May delivery on the New York Mercantile Exchange moved to $3.24/MMBtu in today’s trading, but is currently off the high of the session, trading at $3.18/MMBtu, a loss of 0.50% from Thursday’s close. For the week overall, however, the contract is nearly up 1%.With a negative divergence still in place between price action and the Stochastic, a price momentum indicator, it appears further downside could characterize price action heading into next week.On the downside, for the May contract, support comes in at the $3.05 level, which is near the mid-point of March 20th’s long green candle. As long as this level remains intact, the broader bias will remain to the upside. According to natgasweather.com, weather systems will track across the country the next several days with slightly cool conditions. The most notable storm is currently sweeping over the East with heavy showers and thunderstorms, but only modestly cool, highlighted by snowfall over only potions of New England. A second storm is rolling through the West with a track toward the Plains. The combination of the two systems will result in slightly stronger than normal national demand through early Sunday. The southern US will remain warm into next week with highs of upper 60’s to 80’s, locally 90’s. Demand will drop back to near or below normal Sunday-Wednesday as mild conditions return to the North and East.

U.S. natural gas prices rise to limit summer power burn: Kemp (Reuters) - The U.S. gas market is looking a little tight despite another record warm winter that limited heating demand. Growing structural consumption from electric power producers as well as increasing exports are significantly changing the balance between supply and demand. Consumption (including exports) is now running higher for any given level of heating and cooling demand with the result the market wants to carry a higher level of inventories. Stocks of working gas in underground storage stood at 2,049 billion cubic feet on March 24, according to the U.S. Energy Information Administration. Stocks are 425 billion cubic feet, around 17 percent, lower than at the corresponding point in 2016 (http://reut.rs/2ooOkZf). Stocks have generally remained lower this winter even though temperatures broadly matched the record warmth in 2015/16 (http://tmsnrt.rs/2mVt7sx). Inventories are still 250 billion cubic feet (14 percent) above the five-year average, according to the U.S. Energy Information Administration. But stocks do not look excessive given the underlying increase in consumption from new and planned gas-fired power plants and scheduled increases in export capacity. Gas-fired generation capacity has increased from 432 gigawatts (GW) at the end of 2014 to 447 GW at the end of 2016 (http://tmsnrt.rs/2mVnnPP). Capacity has increased in the last two years by the equivalent of the entire generation capacity of the state of Minnesota ("New wave of power plants if fuelling U.S. gas demand", Reuters, Oct. 2016). Most of new gas units are super-efficient combined cycle plants designed to operate for thousands of hours each year as baseload (http://tmsnrt.rs/2nqxTL3). And U.S. power producers are planning to add 37 another gigawatts of gas-fired capacity during 2017/18, roughly equivalent to the entire generating capacity of the state of Georgia. Gas-fired capacity is set to rise by a further 8 percent before the end of 2018 ("Natural gas-fired generating capacity likely to increase over next two years", EIA, Jan. 30). "Depending on the timing and utilization of these plants, new additions could help natural gas maintain its status as the primary energy source for power generation, even if natural gas prices rise moderately", according to EIA. U.S. gas exports are also rising, hitting a record 248 billion cubic feet in December 2016, up more than 50 percent compared with the same month a year earlier (http://tmsnrt.rs/2ogPg4w). Underlying demand from power plant operators and exporters is making the market much tighter than the level of stocks implies on its own.

Warm winter keeps natural gas prices subdued, production growth in question - The Barrel Blog: The natural gas market has worked itself into an interesting situation recently. The combination of a warm winter in 2015-16, declining associated production, lack of new infrastructure and coal retirements have created a perfect storm for a very challenging year to evolve in 2017. Although many of the potential issues were alleviated by yet another warm winter, attention is now starting to turn toward the supply side of the equation, and it’s having an impact on the shape of the natural gas forward curve. The problem is simple: production needs to grow in 2017, and the growth needs to come from somewhere other than the Northeast, something that has not happened on an annual basis since 2011. Production will be called upon in a major way this year, but associated gas may be largely left out of the mix as oil prices have stagnated around $50/barrel.However, the market is asking for dry gas production to grow in the face of a backwardated curve, as natural gas prices beyond 2017 have stubbornly hung below break-even drilling costs for the majority of basins in the US. The specter of new infrastructure and inexpensive Northeast production hitting the market has pulled the back end of the curve lower, creating a paradox for producers. Why ramp up production throughout 2017 when the prospects over the next three to four years seem to challenge returns? Or rather, could the recent momentum we’ve seen in dry gas basins be short-lived as producers try to capture as much of the short-term rally as possible before pulling back over the next few years?The recent rally and subsequent pullback have been driven by several factors. After reaching all-time highs in November, storage inventories quickly normalized due to a colder-than- normal December. However, a warm second half of January and an extremely warm February has helped quell any concern about inventories, but arguably it is doing more harm than good. Market fundamentals are decidedly tighter this year despite a significant reduction in power burn demand, driven by higher natural gas prices and higher hydro output along the Pacific Coast. Most notably, production has been lagging significantly behind year-ago levels, and export demand is trending more than 2.3 Bcf/d higher than a year ago.

US natural gas supply / demand scenarios for injection season. After exceptionally mild weather nearly derailed the U.S. natural gas market earlier this year, the gas supply/demand balance is set to end the 2016-17 withdrawal season relatively bullish compared to last year. Storage is finishing the season more than 400 Bcf lower than last year, albeit still 260 Bcf/d above the 5-year average. In addition, gas exports are continuing to ratchet higher. The April 2017 CME/NYMEX Henry Hub natural gas futures contract expired Wednesday (March 29) at $3.175/MMBtu, nearly $1.30 (67%) higher than the April 2016 contract settlement of $1.90/MMBtu and also about 55 cents higher than the March 2017 contract settlement. Yet, with the storage inventory still higher than the 5-year average and production growth on the horizon, the market remains susceptible to downside risk if incremental demand doesn’t show up. In today’s blog, we look at potential supply/demand scenarios for injection season. The U.S. natural gas market exited the first quarter of 2016 from one of the most bearish winters on record, with more than an 800-Bcf “surplus” in storage compared to the 5-year average, about 1,000 Bcf more than the prior year, and gas prices depressed below $3.00/MMBtu. Nevertheless, by the end of the year, the market had not only managed to wipe out the surplus versus both the prior year and the 5-year average but also ended up net short supply on average for the year and prices were approaching $4.00/MMBtu. Both the supply and demand sides of the balance equation contributed to this remarkable shift. In 2016, total supply including imports averaged 77.5 Bcf/d, down 1.3 Bcf/d from 2015. Total demand including exports averaged 78.5 Bcf/d, up 1.3 Bcf/d year on year. So the resulting net balance (supply minus demand) went from positive 1.6 Bcf/d in 2015 to negative 1.0 Bcf/d in 2016. In other words, the gas supply and demand balance ended up averaging 2.6 Bcf/d “shorter supply” in 2016 versus 2015. We walked through each component of the 2016 balance in “You Keep Me Hanging On” Part 1, but here’s a brief recap of the biggest drivers:

USGC LNG market has potential to become key anchor for prices: Commodity Pulse video -- With more liquefaction terminals in the US slated to hit the market by 2020, the US will have an opportunity to become a hub for both supply and pricing of LNG. Shelley Kerr, global director for LNG, and Kwhame Gittens, commodity risk solutions manager, evaluate why the US is critical to the development of liquidity in the global market and how spot pricing and derivative contracts can play into that evolution. Could the history of the Japan Korea Marker give clues about the future of the Gulf Coast Marker and its use?

LNG to be part of seasonal natural gas storage play in Europe: Snam CEO -   LNG supplies to Europe can increasingly be diverted into storage in the summer, giving storage operators the ability to then release the gas in the higher-demand winter months, the head of Italian TSO Snam said Wednesday. Speaking at FT Commodities Global Summit in Lausanne, Switzerland, Snam CEO Marco Alvera said LNG would become "hugely seasonal" and that Italy in particular could take advantage of these market dynamics. LNG, he said, is likely to play a key role in gas supply into Europe but "will need to be tied into storage." "Europe has a huge opportunity in storage," Alvera, who is also a director on the board of S&P Global, said. "LNG is going to become hugely seasonal," he said, adding that the majority of LNG demand is in the northern hemisphere. "You will have very distressed LNG available in the summer and people will capture that if they have storage," Alvera said. Alvera said Italy in particular could play an important role in importing LNG for seasonal storage. "Italy is in a unique position for gas storage reserves and ability to export gas," he said. "It can really be the hub where people import LNG in the summer and export it out to the rest of Europe in the winter." Italy has a current gas storage capacity of some 16.5 Bcm, second only to Germany in terms of size within the EU.

Russian tanker forges path for Arctic shipping super-highway | Reuters: An ice-breaking tanker docked for the first time at Russia's Arctic port of Sabetta to test a new route that could open the ice-bound Arctic Ocean to ships carrying oil and liquefied gas. The route is eagerly anticipated by energy firms that want to develop resources in the Arctic but face obstacles in getting oil and gas from remote and freezing fields to world markets. Environmental activists fear commercial shipping in the Arctic -- now possible because climate change has thinned the ice for part of the year -- will allow exploitation of a region that up to now has been a pristine wilderness. The 80,000 tonne-capacity Christophe de Margerie, an ice-class tanker fitted out to transport liquefied natural gas, docked in the icy port of Sabetta, with Russian President Vladimir Putin watching via live video-link. Putin congratulated the crew and energy company officials gathered on the ship's bridge, saying: "This is a big event in the opening up of the Arctic." The South Korean-built vessel was not picking up a cargo on its maiden voyage, but will eventually be used to transport gas from Russia's Yamal LNG plant, which is near the port. The project, scheduled to start production in October, is led by Russian firm Novatek and co-owned by France's Total, and China's CNPC and the Silk Road Fund..

Chevron starts production from third train at $54bn Gorgon LNG project in Australia - Chevron has started production from the third of the three liquefied natural gas (LNG) production units at the $54bn Gorgon LNG project located off Western Australia. The Gorgon LNG project, which is operated by Chevron, is located on Barrow Island off the northwest coast of Western Australia. The project involves three production trains which have a combined capacity of 15.6 million tons per year. It also comprises a domestic gas plant with the capacity to supply 300 terajoules of gas per day to Western Australia. First production from the Gorgon Project started in March 2016. However, production was closed subsequently due to technical problems and was resumed in May in the same year. Gorgon Project is a joint venture between the Australian subsidiaries of Chevron with 47.3% stake, ExxonMobil 25%, Shell 25%, Osaka Gas 1.25%, Tokyo Gas 1% and JERA 0.417%. Meanwhile, Chevron has reportedly suspended LNG production, temporarily, at the Gorgon Train Two line due to a planned turnaround. Chevron spokesman was reported by Reuters as saying in an email statement: "Production at Gorgon Train Two is being temporarily suspended for a planned turnaround to enhance the train's reliability in alignment with previously arranged strategies. "The remainder of the plant production continues to be steady.” The Gorgon gas project involves development of the Gorgon and Jansz-Io gas fields located within the Greater Gorgon area in the Barrow sub-basin of the Carnarvon Basin. The Greater Gorgon area is estimated to have proven hydrocarbon reserves of 13.8 trillion cubic feet.

Growing global liquefied natural gas trade could support market hub development in Asia - EIA - Asia is the world’s largest consumer of liquefied natural gas (LNG), accounting for three-quarters of global LNG trade and one-third of total global natural gas trade. However, the region lacks a pricing benchmark that can reliably reflect supply and demand changes in Asia’s natural gas markets. Natural gas market hubs, such as Louisiana’s Henry Hub or the United Kingdom’s National Balancing Point (NBP), have been a key feature of competitive gas markets in the United States and Europe. These hubs provide locations—either physical, in the case of Henry Hub, or virtual, in the case of NBP—for trading natural gas and ultimately for determining price. The most important hubs have publicly reported price indexes that are benchmarks for the value of natural gas in the larger regional market. Currently, no location in Asia has sufficiently developed physical infrastructure or regulatory frameworks to accommodate the creation of a natural gas trading hub, but the governments of Japan, China, and Singapore are each exploring the possibility of establishing an LNG market hub. Given the emergence of the United States as a major LNG supplier and the potential impact on the structure of future LNG trade in Asia, EIA commissioned a contractor study that examines efforts to establish regional LNG trading hubs and price benchmarks in Asia and some of the inherent challenges they face. Fully established natural gas market hubs, such as the United States’ Henry Hub, have high liquidity, with a high volume of trades; open access to transport facilities; and transparent price and volume reporting, index pricing, and futures contracting. In comparison, hubs such as those in France and Italy have lower trading volumes and less liquidity in forward pricing.  While natural gas hubs in North America and Europe are pipeline-based (for example, Henry Hub is located in Louisiana, close to natural gas infrastructure on the U.S. Gulf Coast), major countries in Asia rely on LNG as the primary source of natural gas.  LNG-based hubs present a number of challenges compared to pipeline-based hubs. Pipeline hubs rely on continuous flows of natural gas, daily scheduling of receipts and deliveries, standardized natural gas specifications, uniform transportation and contracting rules, and diligent regulatory oversight. In contrast, LNG shipments can be large and difficult to store, there can be significant time between contracting and delivery, and cargoes can differ in LNG specifications. Asian LNG import terminals have limited pipeline interconnectivity and operate primarily under long-term bilateral contracts between multiple suppliers and buyers, which limits transparency, third-party access, and publically available price benchmarks.

SA not ready for fracking due to lack of scientists and infrastructure -  Fracking should not be considered for SA because of a lack of qualified scientists and laboratories‚ incomplete information on water sources, and a shortage of "institutional capacity to ensure proper water management". These are the findings of a desktop study conducted by AgriSA into the controversial mining method. The nine-page report — Fracking and Water: Is there enough to go around? — was released on Wednesday morning. Fracking is currently being considered across the country‚ particularly in the Karoo Basin‚ which was the chief focus area of AgriSA’s study. While shale gas has been tipped as a potential boon for the country’s economy‚ communities have reacted negatively‚ citing pollution to water sources and the water-intensive nature of the mining as chief concerns. AgriSA researcher, Gregory Smith, wrote: "The concern around shale gas development is very real‚ understandable and cannot be ignored." He said SA was a water-scarce country and that water supplies in the Karoo were under "continuous stress" due to pollution and depletion — and that demand was on the rise because of population growth‚ industrialisation‚ mechanisation and urbanisation. "Shale gas development is a water-intensive process and would increase pressure on the availability of sufficient water of an acceptable quality with a reasonable surety of supply in an already dry Karoo‚" wrote Smith. He cites figures provided by the Mineral Resources Department which claim that each fracking well would use about 24‚000m³ of water — the equivalent "to the irrigation of 3ha of lucerne for one year".

Govt gives green light for shale gas fracking in Karoo -  The government has given the go-ahead for shale gas development in the Karoo region, Mineral Resources Minister Mosebenzi Zwane said on Thursday.He revealed this during a community engagement on shale gas development in Richmond, in the Northern Cape. "Based on the balance of available scientific evidence, government took a decision to proceed with the development of shale gas in the Karoo formation of South Africa," he said in a speech. He said the regulatory framework would ensure that shale gas was "orderly and safely developed" through hydraulic fracturing, commonly known as fracking. "The finalisation of Mineral and Petroleum Resources Development Act (MPRDA) amendments will also help to expedite the development of shale gas," Zwane said. The department estimated that up to 50-trillion cubic feet (Tcf) of shale gas was recoverable in the Karoo Basin, especially in the Eastern, Northern, and Western Cape provinces.  He said it was in their interests to ensure all South Africans benefited socially and economically from the mineral wealth. The country had been largely dependent on coal as a single source of energy for many years.Government had decided to diversify the energy basket to provide "cost-competitive energy security" and to "significantly reduce the carbon footprint"."Government will ensure that you are kept up to date about the exploration method and benefits that can be realised from the development of shale gas and informed about the mechanisms and instruments that seek to augment existing laws for the protection of water resources and for the protection of the environment," he said. A year ago, government ended speculation over the project after it announced that exploration for shale gas would begin in the next financial year, according to the AFP. Zwane said on Thursday that they were mindful of the risks and challenges of the development, especially on water and the environment. He said a socio-economic and environmental assessment had been conducted beforehand. Assurances were made that the farming community would benefit from shale gas development, while the Square Kilometer Array would not be affected.

Angola heavy-light crude spreads widen as Asian oil demand softens - Oil | Platts News Article & Story: After a couple of months of increasing values, Angola's heavy crudes, which had been outperforming lighter barrels, have seen demand falter, allowing the heavy-light spread to widen again. "The heavies have to come off now -- the spread has to return to where it was," said a West African crude trader. The price spread between the two ends of the complex had reached multi-year lows on strong Chinese demand for heavy grades during the past two trading cycles in March and April. This came as Chinese buyers looked to find alternatives to heavy, sour Middle East crudes whose supply has been limited by OPEC's production cut agreement and with strong fuel margins in the region.But the heat has dissipated from the market for the heaviest Angolan grades such as Dalia, which has seen spot offers from state-owned company Sonangol drop from an initial offer of Dated Brent plus 10 cents/b to Dated Brent minus 20 cents/b. Other medium-light grades such as Girassol and Cabinda, have not seen the same pressures, said traders, with both grades grades clearing cargoes at a faster pace than Dalia. Dalia was assessed Wednesday at a discount of 80 cents/b FOB to the 30-60 day Dated Brent strip, S&P Global Platts data showed. Girassol, a light grade, was assessed at a discount of 5 cents/b to the 30-60 day Dated Brent strip. The spread is currently at a 70 cents/b discount, but reach its narrowest point during January 26-February 2, when it was at a 20 cent/b spread.

Asia refiners snap up cheap light oil to reap higher fuel profits | Reuters: As the cost of light crude drops, some refiners in Asia are snapping up cargoes of the oil that is easier and cheaper to process than their usual diet of heavy crude, chasing profits from making diesel and gasoline. As a result of the OPEC production cuts, the world's oil supply has become more light and those oil types yield more diesel and gasoline, the fuels that command the highest margins, when processed in a crude distillation unit, the most basic unit a refinery uses to make fuels. Since purchasing the lighter oil makes it easier to extract diesel and gasoline, Asian refiners have jumped on the crude supply trend by buying light oil from Russia, Africa and even from as far as the United States to bolster their profits. "Korean buyers are buying light crude because its price competitiveness is improving," a local South Korean refining source said on the condition of anonymity as he was not authorized to talk publicly about trading. "Light crude used to be pricey and now as it's oversupplied, it's great for refiners. We can buy it at cheaper prices, save costs and produce more high value-added products like light naphtha and gasoline. We're hoping this trend will continue." South Korean refiner Hyundai Oilbank bought Sakhalin Blend crude for April and May, several market traders said, using the light oil to blend with its typically heavy crude slate. Taiwanese refiner CPC added up to two more light oil cargoes in the second quarter and bought Algeria's Saharan Blend to partly replace heavier Angolan oil and for processing at its new splitter, said a company spokesman. Meanwhile, Thai Oil bought Sakhalin Blend and U.S. Eagle Ford crude for the first time ever in the second quarter, while Thailand's PTT also bought the Russian grade.

Oman to cut crude supplies to Asia by up to 15% from June: market sources - Oil | Platts News Article & Story: Oman is expected to cut its crude oil exports to Asia by as much as 15% from June onward to meet rising domestic demand, but the move is likely to have limited impact given slowing imports from China's independent refiners. "The Ministry of Oil and Gas has informed its customers on contract in Asia that it will reduce supply by 15% starting in June. The supply cut is to meet rising demand at the state-owned Sohar Refinery", the Times of Oman reported Sunday, citing an unnamed oil ministry official.Oman Oil Refineries and Petroleum Industries Company, or Orpic, is currently expanding the Sohar refinery, raising capacity to 198,000 b/d, from 116,000 b/d at present. Orpic completed the mechanical work on the crude and vacuum distillation units, as well as a kero-merox unit in January. The refinery had already completed a revamp of the residue fluid catalytic cracker last year. One Singapore-based crude trader said Monday: "They have been telling term lifters before 2017 renewal that with Sohar [refinery coming online], they will cut term exports, but they just could not confirm which month [at that point]." The ministry could not be reached for a comment. However, market sources said they had been expecting the cuts with new units at Oman's Sohar refinery due online this year.

Genel Shares Hit All-Time Low As Oil Reserves Disappear  (Reuters) - Genel Energy's market value collapsed to an all-time low on Tuesday after it said for a second time that its flagship oilfield contains less crude than expected, dealing another blow to chairman Tony Hayward to rescue the indebted Kurdish producer. Since listing in 2011 and claiming to be the largest independent UK listed firm by reserves, Genel has been hit by a string of unsuccessful exploration campaigns in Africa and reserves at its largest Iraqi Kurdistan field shrinking to just a tenth. Investors who bought into Genel at 11 pounds ($13.8) a share in early 2014 were left with 60 pence on Tuesday as reserve cuts, an oil price collapse and Iraq's fight against Islamic State hammered the stock. By comparison, investors who bought into Shell or BP, where Hayward was CEO until 2010, saw the value of their shares declining by only 10 percent over the same period. Analysts from UBS said that even though they had expected another reserve downgrade at its Taq Taq field after repeated warnings about difficult geology, the cut was worse than anticipated. Hayward, who drew heavy criticism over his handling of the BP's Deepwater Horizon blowout and by stating "I want my life back", departed from BP in 2010 and bought into Genel, then a private company, in 2011 together with financier Nat Rothschild. Their goal was to develop assets in Kurdistan and Africa at a time when oil prices stood above $100 per barrel. But its searches for oil in Malta, Angola and Morocco ended with little success and a writedown of $480 million. That left its main investments in Kurdistan, where it has a 44 percent stake in Taq Taq. China's Petroleum & Chemical Corp holds 36 percent and Kurdistan the rest.

Libya's NOC locked in new battle over oil sector powers - Oil | Platts News Article & Story: Libya's National Oil Corp, or NOC, has become embroiled in a new political battle as it seeks to defend its role as both policy setter and regulator in the oil and gas sector. NOC chairman, Mustafa Sanalla rejected plans from the internationally recognized government in Tripoli which would divide the state-owned company's powers. The UN-backed Presidency Council (PC) issued an order Monday dividing the authority of Libya's oil ministry between the prime minister's office and the NOC. It also stripped Sanalla of his position as oil minister, a role he inherited by default in 2014 when nobody was nominated to fill the position. "I have asked the Presidency Council to withdraw its recent resolution. It has exceeded its authority," Sanalla said in a statement late Monday on the NOC's website. Under the order, the prime minister's office will assume the role of a traditional oil sector regulator -- signing contracts, supervising investments, approving projects, developing new legislation, and setting price policy. NOC would be left to execute the PC's plans. "The NOC will monitor the production and exportation processes, name Libya's representatives to attend meetings and conferences in the Arab world and all over the world, after consulting the prime minister. It will also suggest giving or taking away investment licenses, and specifying the daily oil and gas production in the country," the order said. Sanalla has sought to remain neutral through Libya's political turmoil over the last three years. "NOC has long supported the establishment of a genuine government of national accord able to speak for all Libyans," he said.

Oil output deal needs more compliance, Opec and non-Opec ministers say | The National: The committee of Opec and non-Opec oil ministers overseeing compliance with their output-cutting deal noted some progress but also room for improvement after their regular monthly meeting in Kuwait City yesterday. Essam Al Marzouq, Kuwait’s oil minister, told reporters after the meeting that "more has to be done" for all participants to comply with their pledged cuts. The monitoring committee is made up of three oil ministers from Opec, including Venezuela and Algeria, as well as Kuwait, plus their non-Opec counterparts from Russia and Oman. The deal reached by Opec at the end of November and followed by commitments from 11 non-Opec members, led by Russia, pledged total cuts of about 1.8 million barrels per day from last October’s levels to speed along a reduction in world inventories which had depressed prices for more than two years. The meeting is their third since the deal began officially in January and comes with oil prices under renewed pressure because of doubts about its effectiveness. Oil prices had been trading in a fairly steady range for the past three months, with North Sea Brent crude futures between US$55 and $58 per barrel. But prices fell sharply early this month on a combination of mounting evidence that higher US shale production has been filling the gap left by Opec and non-Opec cuts, as well as some confusing comments from Opec ministers about how well their deal is holding together and whether it is likely to be rolled over when its initial six-month run expires in June. News agencies reported that an early draft statement called for a rollover of the deal. But that was not in the final statement and the Kuwait oil minister stated the obvious when he noted that only the Opec/non-Opec group as a whole will decide that.

OPEC, non-OPEC to look at extending oil-output cut by six months | Reuters: A joint committee of ministers from OPEC and non-OPEC oil producers has agreed to review whether a global pact to limit supplies should be extended by six months, it said in a statement on Sunday. An earlier draft of the statement had said the committee "reports high level of conformity and recommends six-month extension". But the final version said only that the committee had requested a technical group and for the OPEC Secretariat to "review the oil market conditions and revert ... in April, 2017 regarding the extension of the voluntary production adjustments". Oil sector analysts said the lack of an immediate extension could drag on crude prices. "The dropping of the recommendation to extend cuts in favor of technical review committee is likely to lead to a lot of disappointment and potential further liquidation of long positions by money managers that will put downward pressure on oil prices," said Harry Tchilinguirian, head of commodities strategy at BNP Paribas in London. It was not immediately clear why the wording had been changed, although a senior industry source said the committee lacked the legal mandate to recommend an extension. The Organization of the Petroleum Exporting Countries and rival oil-producing nations were meeting in Kuwait to review progress with their global pact to cut supplies. "Any country has the freedom to say whether they do or they don't support (an extension). Unless we have conformity with everybody, we cannot go ahead with the extension of the deal," Kuwaiti Oil Minister Essam al-Marzouq said, adding that he hoped a decision would come by the end of April.

OPEC, Non-OPEC Oil Producers Recommend Extending Production Cuts By Six Months - Having failed to "rebalance" the oil market in the first six months following the implementation of the Vienna production cut agreement, with crude inventories in the US hitting all time highs in the interim... OPEC and non-OPEC oil producers found themselves in the unpleasant position of scrambling for solutions at this weekend's Kuwait meeting - in which Saudi Arabia was conspicuously missing - where just two things were discussed: deal compliance, which OPEC paradoxically claims is more than satisfactory despite the relentless climb in inventories, and whether to extend the production cuts by another six month. And as the Kuwait meeting in which OPEC and rival N-OPEC producing countries met to review progress with their pact to cut supplies drew to a close, a joint committee of ministers from OPEC and non-OPEC oil producers recommended extending by six months the global deal to reduce oil output by 1.8 million barrels, a draft press release from their meeting on Sunday showed.

OPEC under pressure as oil price gains fade - video - The OPEC/non-OPEC monitoring committee which met in Kuwait this week concluded that it needs more data to evaluate the cuts. Platts senior editor Eklavya Gupte, looks at some of the options OPEC now has as it faces a market that harbors significant doubts over the effectiveness of the oil output cuts.

Analysis: OPEC/non-OPEC committee punts decision to extend cuts to build case -   Platts - To many market watchers, it seems a foregone conclusion that OPEC and its 11 non-OPEC partners will have to extend their production cut agreement past its June expiry if there is to be a realistic hope of drawing down inventories to their five-year average in 2017. Politically, however, a deal to prolong the 1.8 million b/d in combined OPEC and non-OPEC cuts is not so straightforward. Faced with a market that has significant doubts over the effectiveness of the output cuts, but with few options to impress with confidence, members of the producer coalition's monitoring committee on Sunday gamely announced they would keep observing supply and demand fundamentals for another month.Only then, after the committee meets again in late April -- exact date and venue still to be announced -- might a recommendation on a path forward, including a potential extension of the deal, emerge. The deal will officially be up for review at OPEC's next ministerial meeting May 25 in Vienna. "OPEC has to choose between higher prices or market share," said Kamel al-Hamari, an independent oil analyst in Kuwait. Kuwaiti oil minister, Essam al-Marzouq, acknowledged as much, telling reporters at Sunday's committee meeting that "with any increase in oil prices, there will be an increase in shale [production]." Traders have taken that reality to heart, as oil prices have given up much of their gains since the OPEC/non-OPEC coalition announced late last year their deal to cut a combined 1.8 million b/d in supply.

NY Fed: "Oil Prices Fell Due To Weakening Demand" - When it comes to the price of oil, both the sellside and oil producers have been adamant that the only variable that matters is supply, i.e., how much oil is produced at any given moment which was also the justification behind the Vienna production cut deal: reduce supply enough, and the record global inventory glut will decline by bringing markets into equilibrium, boosting prices in the process. Alternatively, another explanation has been the recent liquidation of oil positions by speculators (read hedge funds), who tend to amplify moves in the world's most financialized commodity. Indeed, the sharp move lower over the past three weeks was largely attributed to selling be levered entities who unable to push the price of oil higher, had no choice but to take the other side of the trade.Throughout this, one aspect of price formation that is rarely mentioned is demand, which is generally assumed to be unwavering and trending higher with barely a hiccup. The reason for this somewhat myopic take is that while OPEC has control over supply, demand is a function of global economic growth and trade (or lack thereof) over which oil producers have little, if any control.And yet, according to the latest oil price dynamics report issued by the Fed, it was declining global demand that pushed prices lower in the most recent, volatile period.As the New York Fed report in its March 27 report, "Oil prices fell owing to weakening demand" and explains as follows: "A decline in demand expectations together with a decreasing residual drove oil prices down over the past week." While there was some good news, namely that "in 2016:Q4, oil prices increased on net as a consequence of steadily contracting supply and strengthening, albeit volatile, global demand" offsetting the "modest decline in oil prices during 2016:Q3 caused by weakening global demand expectations and loosening supply conditions," the Fed's troubling finding is that the big move lower since 2014 has been a function of rising supply as well as declining demand:

Russia and Iran say will continue efforts to curb oil output | Reuters: Russia and Iran have pledged to continue efforts to rein in oil production and stabilize markets, the presidents of both countries said in a joint statement on Tuesday. The Organization of the Petroleum Exporting Countries (OPEC) and other large producers, led by Russia, had agreed in December to cut their combined output by almost 1.8 million barrels per day (bpd) to reduce bloated oil inventories and support prices. Iran, however, successfully argued that it should not limit production that was slowly starting to recover after the lifting of international sanctions in January last year. "Russia and Iran will continue cooperation in this sphere (in oil output cuts) in order to stabilize the global energy market and ensure stable economic growth," the statement from Russian President Vladimir Putin and Iranian counterpart Hassan Rouhani said. They two presidents met in the Kremlin and also discussed Syrian crisis among other issues. Russia has pledged to cut oil output by 300,000 bpd in the first half of the year. On Sunday OPEC and non-OPEC oil ministers, including Russian Energy Minister Alexander Novak, discussed the implementation of the December deal but stopped short of recommending that cuts be extended into the second half of the year. Earlier on Tuesday Iranian Oil Minister Bijan Zanganeh told reporters in Moscow that a global deal is likely to be extended, but time was needed to discuss the subject thoroughly. "It seems that most of the OPEC and non-OPEC (countries) are going to extend the agreement, but time is needed to evaluate the situation and to have face-to-face meetings and discussions with others," Zanganeh said.

Market share or higher prices? The Saudi, Russia oil dilemma | Reuters: Saudi Arabia and Russia are likely to discover that when pursuing two incompatible goals, the one deemed less important will ultimately be sacrificed. The world's top two oil exporters appear to be chasing both higher crude prices through their curbs to production and market share by increasing exports, at least in Asia, the world's biggest crude importing region and the fastest growing. The question is which of these two goals will ultimately be abandoned in favour of the other, and how long will it take for Saudi Arabia and Russia to realise the incompatibility of their dual ambitions? The crude import data from Asia's biggest buyers show the scale of the challenge facing Saudi Arabia and Russia, the two countries that are the lynchpins of the November agreement between the Organization of the Petroleum Exporting Countries (OPEC) and its allies to cut output by 1.8 million barrels per day (bpd) in the first six months of 2017. That agreement, which provided an initial boost to crude prices, may be extended for another six months after ministers from OPEC and non-OPEC producers agreed on March 26 agreed to conduct a review. While OPEC and its allies have had success in ensuring high compliance with the deal, which has started the process of drawing down high global oil inventories, they have also opened the door to producers outside the agreement to raise output. Chinese customs data for the month of February highlight how at risk OPEC and its allies are from cutting their own output while their rivals are free to pump as much as they want. China imported 4.77 million tonnes, or about 1.24 million bpd, from top supplier Saudi Arabia in February, down almost 13 percent from the same month a year earlier.

Hedge funds unwind record bullish position in oil – Kemp (Reuters) - Hedge funds have unwound much of the concentration of bullish positions that contributed to a fall in oil prices this month, suggesting a broader range of views about where prices go next.Hedge funds and other money managers now hold a combined net long position in Brent and WTI of 684 million barrels, down from a record 951 million on Feb. 21, though still well above the recent low of 422 million on Nov. 15 before OPEC announced output cuts. Fund managers reduced their net long position in the three main futures and options contracts linked to Brent and WTI by 38 million barrels in the week to March 21.They have cut their net long position by a total of 268 million barrels over the last four weeks, according to an analysis of data published by regulators and exchanges (http://tmsnrt.rs/2o9bWk8).Fundmanagers have unwound half of the 529 million barrels of extra net long positions they accumulated between the middle of November and the middle of February (http://tmsnrt.rs/2o99z11).The hedge fund community remains bullish overall towards crude but there is now a much wider range of opinions about whether prices will rise or fall in the short term.Bullish long positions outnumber bearish short positions by a ratio of almost 4:1 but the ratio has dropped from more than 10:1 just four weeks ago (http://tmsnrt.rs/2mHKHQA).Hedge funds hold 918 million barrels of long positions in Brent and WTI, down from a record 1.05 billion barrels on Feb. 21. But managers have more than doubled the number of short positions from 102 million barrels to 235 million barrels over the same period.The more balanced distribution of hedge fund positions should reduce the risk of further sharp oil price moves in the short term.There are still a large number of long positions that could be liquidated in the coming weeks if prices drop further and managers are forced to sell.But the emergence of a substantial number of short positions that will ultimately need to be bought back should help counteract further price falls. Hedge fund managers appear to have embarked on a new cycle of short selling, which would be the sixth since the start of 2015 (http://tmsnrt.rs/2mHQRjK). But the down-cycle could prove more short-lived than earlier cycles, with Brent prices no longer falling and finding some support just above $50 per barrel (http://tmsnrt.rs/2nEuP0w).

Oil trading surge strengthens grip of big commodity houses -The world’s largest independent commodity houses have expanded their oil trading volumes by more than 65 per cent during crude’s near three-year slump, marking them out as the biggest beneficiaries in the industry from oil’s protracted downturn. Vitol, Glencore and Trafigura together trade more than 17m barrels of crude oil and refined fuels every day, according to company statements and industry sources, handling daily volumes equivalent to more than half the Opec cartel’s output. Their rapid expansion, up from a little over 10m barrels a day in combined oil volumes in 2014, underlines the rising influence and power of a trading industry that for decades tried to shun close scrutiny. Together with Gunvor and Mercuria, the other two top-five independent oil traders, they account for 22m barrels a day. “There is a huge race between them,” said Jean-Francois Lambert, a former head of commodity trade finance at HSBC and consultant. “You need to trade a lot of barrels to make a big profit.” Their growth highlights how trading houses have developed from their roots as buccaneering merchants to playing an increasingly influential role in global trade. One of the drivers of their growth has been cash-for-crude deals, where they provide multibillion-dollar loans to cash-strapped commodity producers and national oil companies to secure long-term supplies.Rising US production and the lifting of restrictions on exporting crude from the country last year has also boosted volume growth for independent traders, while higher global demand means they are chasing a bigger slice of an expanding market.

Column: Goldman takes on the Brent spreads: Kemp -- (Reuters) - Progress towards oil-market rebalancing and the need for an extension of production cuts by OPEC and non-OPEC countries has become the most contentious issue in the oil market. "We believe that the rebalancing of the oil market is in fact making progress despite the record high U.S. crude inventories," Goldman Sachs analysts said in a note to clients on Sunday. Goldman expects oil stocks in the OECD to fall to the five-year average in terms of demand cover by the end of 2017, even if OPEC brings production back on line in the second half. Goldman projects crude prices will move into backwardation and an extension of the cuts would exacerbate the feared shortfall in supplies. ("Data dependent OPEC unwise to let the stock draws run hot", Goldman Sachs, March 26) The bank says an extension would not be warranted and would ultimately be self-defeating if it pushed prices towards $65 per barrel and caused an even-faster recovery in oil drilling. Goldman is one of the most influential banks in the oil market and among the hedge-fund community so the view of its respected research team carries considerable weight. But the bank's confidence in rebalancing during the second half of 2017 without an extension of the production deal puts it in a minority. Most traders have become much less sure the market will enter a persistent period of undersupply with a sharp reduction in oil inventories. Brent calendar spreads for the six months between June and December have weakened sharply over the last four weeks (http://tmsnrt.rs/2mLRatT). The calendar spread between June and December has shifted from a backwardation of 21 cents on Feb. 21 to a contango of 92 cents on March 27. Contango is generally associated with a well-supplied market and high and/or increasing stocks, while backwardation is associated with an undersupplied market and low and/or falling stocks. The calendar spread for the second half of 2017 is now trading at the widest contango since OPEC's deal was announced on Nov. 30.

RBOB Tumbles After Lower Than Expected Gasoline Draw --After an early spike on Libya production fears and OPEC production cut extension hope, WTI and RBOB faded all day on dollar strength ahead of the API data. The trend of builds in Crude and draws in gasoline and distillates continued but the gasoline draw was notably less than expected and has sparked selling in RBOB. API:

  • Crude +1.91mm (+2mm exp)
  • Cushing -576k
  • Gasoline -1.104mm (-2mm exp)
  • Distillates -2.035mm

Cushing saw a draw for the first time in 5 weeks but crude builds continued their streak. The most notable print was lower than expected gasoline draw...

4 Factors Driving Oil Prices This Summer Uncertainty is dominating today’s oil markets, with production cuts, ballooning inventories and a rising rig count all adding to oil price volatility. And as the summer driving season approaches and oil companies return to their projects here are four key factors to watch closely.

  • Inventory, Rig counts – An significant inventory build on the 7th of March sent oil prices tumbling, ending a period of relative stability for oil markets. The build-up of 8.2 million barrels at Cushing, Oklahoma sent prices below the psychological level of $50. The next week saw a draw of 237,000 barrels, providing the investors and market with some much needed breathing space. The most recent inventory report saw a 5-million-barrel build, adding yet more downward pressure to oil prices. The inventory level now rests at 533 million barrels, the highest in history. At the same time, we have seen a rapid increase in the number of active oil rigs in U.S. The total number now stands at 652 after an increase of 21 rigs last week according to Baker Hughes. This is the highest level since September 2015. Given the remarkable adaptability of shale producers to low prices, these trends are likely to continue, adding yet more downward pressure to oil prices.
  • The OPEC deal-Extension or no Extension: Questions surrounding the possibility of an extension to the current OPEC deal can be heard in all corners of the oil market. But attempting to make sense of the mixed signals coming from OPEC’s various members is not only a fool’s errand, but an insignificant one. The outcome of both scenarios: extension or no extension, are going to yield the same results. If OPEC does extend the production cut we will see the same vicious cycle: prices will rise, more rigs will be added in U.S., production will increase and prices will stall. On the contrary, if the OPEC and NOPEC members do not reach an agreement then we will see what we saw in 2014-16, each producer will ramp up production vying for the market share. This will cause prices to either go down or to once again be stuck in limbo. A third scenario may see OPEC members agreeing while NOPEC nations leave the table.
  • Summer Driving Season: This summer driving season might provide some cushion for oil prices. According to Jason Schenker “This year, the seasonal upside could be even greater than normal. With the lowest U.S. unemployment rate since before the recession of 2008, and two consecutive years of record SUV and light truck sales in 2015 and 2016, the coming summer driving season is likely to show records for miles driven and gasoline demand.
  • E&P Projects: While the IEA recently stated its concerns about a lack of new projects creating a lack of supply, the recent uptick in prices has led many oil majors to restart their once abandoned projects. There are not only more projects coming on-line but the payback time has also decreased significantly. Goldman Sachs reports that the rising Shale production and the flurry of new oil projects may “result in an oversupply in the next couple of years”. Wood Mackenzie predicts that new oil projects will double in 2017 as it sees spending getting a 3 percent boost this year.

WTI/RBOB Spike On Inventories Data, Despite Production Surge To 14 Month Highs -- WTI and RBOB prices have drifted higher after modest weakness following API's inventory data overnight and then spiked after DOE reported a smaller than expected crude build, and bigger than expected gasoline and distillate draws. Following the lage rig count data, US crude production rose once again to its highest since Feb 2016. DOE

  • Crude +867k (+2mm exp)
  • Cushing -220k (+1mm exp)
  • Gasoline -3.747mm (-2mm exp)
  • Distillates -2.483mm (-1.2mm exp)

The trend of gasoline and distillate draws contoinue and a much smaller than expected build in crude was a surprise...

Oil Prices Spike On Lower Than Expected Inventory Build -- Amid supply disruptions in Libya and strengthening expectations of an OPEC production cut extension, the Energy Information Administration reported commercial oil inventories in the U.S. had gone up by 900,000 barrels in the week to March 24.Yesterday, the American Petroleum Institute estimated inventories had added 1.91 million barrels in the reporting period, largely in line with analyst expectations of a 2-million-barrel build.The EIA also said that total commercial inventories stood at 534 million barrels, close to the seasonal upper limit. In the previous week, these stood at 533.1 million barrels.Refineries processed an average of 16.2 million barrels daily, compared with 15.8 million bpd in the previous week, producing 10 million barrels of gasoline, up from 9.8 million barrels in the week to March 17. Inventories of the fuel went down by a hefty 3.7 million barrels, giving some cause for optimism.The last four months have seen mostly builds in U.S. inventories, as reported on a weekly basis by both the EIA and the API, contributing substantially to the rise of bearish sentiment among investors and dampening hopes of further oil price strengthening.However, the recent clashes between armed groups in Libya eventually led to a suspension of production at two fields, together producing 252,000 bpd – almost a third of the country’s 700,000-bpd production rate. The news sparked some optimism among traders, but that will be short-lived unless OPEC decides to extend its production cut agreement into the second half of the year. Related: OPEC Weighs Extension As Oil Markets Start To Lose Their Nerve The chances of this happening are increasing, although Saudi Arabia has declared it will only sign up for it if global inventories continue to exceed the five-year average when the cartel meets next in late May. Meanwhile, UAE’s Oil Minister Suhail Al-Mazrouei said that the current glut is a result of seasonal factors in the U.S.: it is refinery maintenance season and crude oil stockpiles are increasing. Once maintenance ends, inventories should start going down.

Oil rallies to 3-week high as traders cheer U.S. supply data -  Oil prices rallied Wednesday, settling at their highest level in roughly three weeks after data from the Energy Information Administration showed a weekly rise in U.S. crude inventories that was below some market forecasts, along with bigger-than-expected declines in gasoline and distillate stockpiles. Disruptions to crude output in Libya, as well as hopes for a six-month extension to the production cut agreement, led by the Organization of the Petroleum Exporting Countries, added further support to oil prices.Combined, the upbeat factors “offered the market a touch of optimism that perhaps things are headed in the right direction for global balance,” said Jenna Delaney, senior oil analyst at Platts Analytics, a unit of S&P Global Platts. May West Texas Intermediate crude rose $1.14, or 2.4%, to settle at $49.51 a barrel on the New York Mercantile Exchange. The contract settled at its highest level since March 9, according to FactSet data. May Brent gained $1.09, or 2.1%, to $52.42 a barrel.The EIA reported that crude inventories rose by 900,000 barrels to a weekly record 534 million barrels for the week ended March 24. But that rise was less than half the 1.9 million-barrel climb posted by the American Petroleum Institute late Tuesday.Analysts polled by S&P Global Platts forecast a climb of 300,000 barrels, while others expected an even larger increase, with Citi Futures forecasting a 2 million- to 3 million-barrel rise. “An extremely big jump in refinery activity on the Gulf Coast, a tick lower in imports and a rebound in exports has led to a lower-than expected-build to crude inventories,” said Matt Smith, director of commodity research at ClipperData. But that’s “an increase nonetheless—lifting oil inventories to a further new record.” Still, Phil Flynn, senior market analyst at Price Futures Group, pointed out that supplies in the Strategic Petroleum Reserve fell by more than 700,000 barrels and “if you add that to commercial-oil inventories, the increase in supply looks smaller.”

OilPrice Intelligence Report: The Bulls Are Back: Oil Rebounds On OPEC Optimism: Oil prices rebounded at the end of the week on news that a growing number of OPEC countries are supporting an extension of their cuts for another six months. Kuwait is lending its weight to the cause and so are a half dozen other members. Of course, the official decision won’t come until May, but the markets are growing confident in an extension. Meanwhile, the EIA reported a solid drawdown in gasoline inventories even as crude stocks saw a slight uptick. The data is being interpreted as a sign of solid demand. Oil prices jumped to three-week highs on the news. ConocoPhillips announced a deal to sell most of its oil sands assets to Cenovus Energy, a deal worth as much as $13.3 billion. The sale reflects a remarkable difference in opinion between the two companies. Conoco wants to offload highly costly oil sands that are much less competitive in a world of cheap oil. Cenovus is so optimistic about the assets that it was willing to take on a massive amount of debt to secure the deal. The stock markets appeared unanimous in their belief that Conoco got the better of this deal – Conoco’s stock jumped on the news while Cenovus’ sank more than 13 percent on Thursday.  The WSJ reports that shale drillers such as EOG Resources continue to tweak their drilling techniques, finding ways to become more efficient. EOG is using software that gathers data while drilling a well, which can be used to make directional drilling much more precise. The upshot is that shale drillers could end up producing more oil at lower prices, and could do so for years to come. That would undermine the influence of OPEC over the long-term and make global supplies more flexible to marginal changes in prices and demand.   Even as some argue that shale could be a long-term phenomenon, some of the world’s largest oil traders are cautioning against too much reliance on short-cycle projects in Texas. At the FT’s Commodities Global Summit, two executives from Mercuria Energy Group and Trafigura Group said that the market could see a supply crunch towards the end of the decade because of a shortage of investment today. That echoes a warning from the IEA in early March.

U.S. Shale Ignores OPEC’s Warning: Oil Rig Count Soars By 10 - The United States oil and gas rig count jumped by 15 this week, to its highest level since September 25, 2015, according to Baker Hughes’ latest report on domestic drilling activity. The number of oil and gas rigs currently active in the United States now sits at 824, which is an increase of 374 year over year. The steady and sizeable jump in rigs signals an indifference by American shale producers towards warnings issued by the Saudi Arabian leadership against increased production. The KSA, which serves as the de facto leader of the Organization of Petroleum Exporting Countries (OPEC), entered into an agreement with its fellow bloc members and 11 NOPEC nations to cut production by 1.8 million barrels. But cheap shale output from the United States is now threatening the effectiveness of the OPEC agreement, diminishing the likelihood of ending the supply glut. Most of this week’s increases were to the number of active oil rigs, which increased by 10 to 662, compared to 362 a year ago. The number of gas rigs also increased by 5 to 160, up from 155 last week and 88 a year ago. The Permian Basin saw the most number of rigs added again this week, bringing 4 additional rigs online after adding 7 last week, now at 319 versus only 145 rigs a year ago. Cana Woodford and DJ-Niobrara each lost two rigs, while Eagle Ford, Granite Wash, and Haynesville all added a rig. A half hour prior to the data release, WTI was trading up $0.08 (.16%) at $50.43 per barrel, with Brent trading up $0.19 (.36%) at $53.32 per barrel. After the impressive increases to the number of rigs now in production, WTI began to fall and had slid 10 cents within 15 minutes.

Oil Prices Hold Key Level Even As Rig Data Offer 'Arguments To Sell' -- The number of U.S. oil rigs in operation rose by 10 to 662 this week, according to Baker Hughes (BHI) data, marking the 11th consecutive gain and adding to concerns that growing U.S. production would mute OPEC production cuts. Oil rigs in the Permian Basin rose by 4 to 319, and Eagle Ford rigs rose by 1 to 66, while rigs in Colorado's DJ Niobrara fell by 2 to 23. But U.S. oil futures closed up 0.5% to $50.60 a barrel on Friday. Crude rose 5.5% for the week, helped by protests at Libyan oilfields sending output to a six-month low while U.S. oil inventories rose less than expected. Still, prices fell more than 6% in March and nearly 6% so far in 2017. Dow Jones Industrial component Exxon Mobil (XOM) shares fell 2% on the stock market today, surrendering Thursday's 2% gain, and fellow Dow stock Chevon (CVX) dipped 0.4%. Among top U.S. shale producers, EOG Resources (EOG) edged up 0.4%, Continental Resources (CLR) rose 1.8%, and Diamondback Energy (FANG) climbed 1%. Carsten Fritsch, a commodity analyst at Commerzbank, told Reuters ahead of the Baker Hughes report that a higher U.S. rig count would put more pressure on oil prices providing "some arguments to sell at last."On Wednesday, the Energy Information Administration said U.S. crude stockpiles only rose by 867,000 barrels last week vs. the 2 million barrels that analysts expected, and gasoline stockpiles fell by 3.7 million barrels, lifting crude prices. But production rose to 9.147 million barrels per day, the highest since February 2016. Meanwhile, oil prices could receive some support as OPEC and top non-OPEC producers consider extending their agreement to reduce output by 1.8 million barrels per day past its expiration in June.

Rig Count Continues To Threaten Oil Price Recovery, Saudis Cut Prices To Asia (Again) --For the 11th week in a row, the number of US oil rigs rose (up 10 to 662 - the highest since September 2015). US Crude production continues to track the lagged rig count, pouring more cold water on OPEC's production cut party. The rig count grows, tracking the lagged oil price in a self-defeating cycle... And crude production appears to have plenty more room to run... And don't forget, as Nick Cunningham detailed, there are thousands of drilled shale wells are sitting idle, unfracked and uncompleted.  Once the DUCs are completed, new production will come online. And just as before, that backlog still weighs on the market. Wood Mackenzie estimates that if the Permian Basin’s DUC list was completed, it would add 300,000 bpd in new supply.That supply sitting on the sidelines will put downward pressure on any new oil price rally. And worse still, as OilPrice.com's Tsvetana Paraskova, it seems the Saudis are starting to panic at the loss of market share... Abundant supply of light oil in Asia and weaker demand amid some seasonal refinery maintenance will likely prompt Saudi Arabia to cut the official selling price for most of its crude varieties bound for Asia in May.  At the beginning of March, Saudi Arabia unexpectedly lowered the April price for the light crude it sells to Asia. According to trade sources who spoke to Reuters, Saudi Arabia’s official selling price (OSP) for Arab Light was set for April at the low end of the range expected by a Reuters survey. At that time, the price for Arab Extra Light was cut by $0.75, which was more than expected. For the May OSP, according to a Reuters survey of four Asian refiners, Saudi Arabia would likely cut the price of its Arab Light crude by $0.10-$0.40 per barrel from the April OSP. “I’m seeing price reductions across the board,” one of the refiners surveyed told Reuters. OPEC’s output cuts have made it profitable for oil traders to send crude from as far as the U.S., the North Sea and West Africa to Asia, and this has weakened demand for spot market purchases from Middle Eastern grades.

Oil prices end higher, but lose nearly 6% for the quarter -- Oil futures settled higher Friday, with U.S. prices holding ground at a more than three-week high, but still logging a loss of almost 6% for the first quarter.Traders questioned the sustainability of the OPEC-led production cut agreement and prospects for U.S. output growth.West Texas Intermediate crude futures gained roughly 5% in the previous three sessions after prices last week hit their lowest levels since before the pact between the Organization of the Petroleum Exporting Countries and other heavyweight producers such as Russia.  May WTI crude rose 25 cents, or 0.5%, to settle at a more than three-week high of $50.60 a barrel on the New York Mercantile Exchange. Prices, based on the settlement of the front-month contract finish at $53.72 on Dec. 30, finished about 5.8% lower for the first quarter and year to date. They’re down more than 6% for the month, but up about 5.5% for the week, according to FactSet data. May Brent oil on London’s ICE Futures exchange fell by 13 cents, or 0.3%, to $52.83 a barrel, after a volatile trading session that ended with the contract’s expiration. Compared with the settlement of $56.63 for the front-month contract at the end of last year, prices have lost about 6.7% for the quarter. The June contract ended at $53.53, up 40 cents, or 0.8%.  “The largest bearish factor over the first quarter has been noncompliance from producers subject to the OPEC agreement,”  “Our export data continue to show volumes hold up from key global suppliers like Saudi Arabia, Venezuela and Iraq,” he said. “This will continue to be the hottest topic heading into Q2, as an extension of OPEC’s agreement will likely grow further scrutiny given how little supposed production cuts have filtered through to global waterborne supply.”

Foreign Investors Flock to Iran as US Firms Watch on the Sidelines -- After years shunning Iran, Western businesses are bursting through the country's doors. France's Peugeot and Renault SA are building cars. The U.K.'s Vodafone Group PLC is teaming up with an Iranian firm to build up network infrastructure. Major oil companies including Royal Dutch Shell PLC have signed provisional agreements to develop energy resources. And infrastructure giants, including Germany's Siemens AG, have entered into agreements for large projects. After Iran's nuclear accord with world powers lifted a range of sanctions, many foreign investors began to push into the promising market of 80 million people, setting off skirmishes among European and Asian companies eager to gain a step on more cautious American rivals. Peugeot Middle East chief Jean-Christophe Quemard says his company's early entry has left American competitors in the dust. "This is our opportunity to accelerate," he said in February. U.S. companies are at risk of losing lucrative deals to early movers into the Iranian market, analysts say. But as latecomers, the companies likely won't face a learning curve in dealing with the political risks and the bureaucratic difficulties in Iran. Apple Inc. explored entering Iran after the Obama administration allowed the export of personal communications devices in 2013, according to people familiar with the matter. But the company decided against it because of banking and legal problems, these people said. Apple declined to comment. U.S. companies usually need special permission from the Treasury Department to do business with the country. So though the Chicago-based Boeing Co. got the go-ahead to sell 80 craft worth $16.6 billion to Iran last year, the list of American firms with significant Iranian deals is a short one. Further complicating matters for U.S. firms: President Donald Trump threatened to rip up Iran's nuclear deal during his campaign and he hit the country with new sanctions shortly after taking office. On Sunday, Iran imposed its own sanctions on 15 American companies, mainly defense firms.

OPEC In Trouble As Saudis Becoming Weary Of “Free Riders” - From casual observation, one might be forgiven for referring to the OPEC production cut in place since November 2016 as the “Saudi production cut.” That’s because Saudi Arabia, OPEC’s leading producer and de facto leader, has reduced its crude production by the biggest margin, shouldering the bulk of the burden for the rest of OPEC and striving the hardest to bring prices back up.But how long will Riyadh choose to maintain this strategy? Saudi energy minister Khalid al-Falih said definitively that his country will abide no “free riders” hoping to take advantage of Saudi cuts to ramp up their own production, as OPEC and non-OPEC producers did in the 1980s. It now seems possible that OPEC may agree on an extension of the production cuts past June 2017, but with its own agenda and an eye towards an “oil-less” future, Saudi Arabia may choose to pull back from its over-exertions on behalf of world oil markets and look after its own interests.Analysis found that Saudi cuts were actually deeper than the OPEC deal had stipulated. In February, Riyadh reported that it cut 717,600 bpd, bringing production down to 9.748 million bpd, which was more than 300,000 bpd below the limit specified by the OPEC deal. Reported cuts in January totaled 3.8 percent of OPEC output, and Saud exports fell to 7.7 million bpd.In the aftermath of the deal, WTI and Brent shot up and confidence in long-term price outlooks were boosted. Yet bullish gave way to bearish in March when high inventories and signs of a resurgent U.S. shale sector sent prices down ten percent.Events in Libya, including the imminent re-opening of a major oil port, as well as the increasing U.S. rig count indicates that the initial effect of the OPEC deal has worn off. On March 16 Al-Falih said that OPEC would extend cuts past June to return prices above their five-year average. But realistically, for that to happen, Saudi cuts will have to deepen. This will hurt the country’s financial situation. In 2015 the official budget deficit was $98 billion, though cuts to infrastructure projects, slashed salaries, wage freezes and the introduction of new taxes, including the Persian Gulf’s first value-added tax, brought the deficit down to $79 billion in 2016.

U.S. To Escalate Its Two Years War On Starving Yemen - The picture shows yesterday's rally in Sanaa,Yemen where up to 1 million people were condemning the war Saudi Arabia, the United Arab Emirates, the UK and the U.S. have been waging on them for two years.  Nether the New York Times nor the Washington Post reported of the million strong rally. Both though reported widely of a 8,000 strong demonstration in Moscow led by the ultra-nationalist anti-semitic racist Alexey Navalny (vid). Navalny, who polls less than 1% in Russia, is their great and groundless hope to replace the Russian President Putin. The war on Yemen was launched to show the manliness of the Saudi princes. Well, that may not be the proclaimed reason but it is the only one that makes sense. The U.S. takes part in the war because ... well - no one knows: The morning after that NSC news release was posted on the White House webpage two years ago, Gen. Lloyd J. Austin, commander of the U.S. Central Command, was asked about the objectives of the U.S. support. His stunning reply remains the most accurate characterization from a U.S. official: “I don’t currently know the specific goals and objectives of the Saudi campaign, and I would have to know that to be able to assess the likelihood of success.” Other than dropping weapons with an unconscionable lack of discrimination and proportionality, it appears there are no clear goals and objectives to this day.  The Saudis claim their coalition has dropped 90,000 bombs during the two year war. That are 123 bombs per day. 5 each and every hour for no good reason. It hasn't helped them at all. The Houthi/Saleh alliance the Saudis fight claims (vid) to have destroyed 176 AFVs, 643 MRAPs, 147 MBTs, 12 Apaches, 20 drones, 4 aircraft. Additionally 109 tactical ballistic missiles were fired. Many of those (certainly exaggerated) Houth/Saleh successes happened on Saudi ground. Its southern desert does not protect Saudi Arabia, it opens it up to attacks.

Yemen: Trump Expands U.S. Military Role in Saudi War as Yemenis Brace for Famine - Democracy Now! (video & transcript) The U.S. is also rapidly expanding military operations in Yemen. The U.S. has reportedly launched more than 49 strikes across the country this month—according to The New York Times, that’s more strikes than the U.S. has ever carried out in a single year in Yemen. While the U.S. airstrikes have been targeting suspected al-Qaeda operations in Yemen, The Wall Street Journal is reporting the U.S. is now offering even more logistical and intelligence support for the Saudi-led war against Yemen’s Houthi rebels, who are accused of being linked to Iran. More than 10,000 people have been killed since the U.S.-backed, Saudi-led bombing campaign in Yemen began two years ago this month. Meanwhile, The New York Times is reporting today that the Trump administration has approved the resumption of sales of precision-guided munitions to Saudi Arabia. President Obama froze some of these weapons sales last year due to concern about civilian casualties in Saudi Arabia’s expanding war in Yemen. We speak to Iona Craig, a journalist who was based in Sana’a from 2010 to 2015 as the Yemen correspondent for The Times of London.

Aiding Saudi Arabia’s Slaughter in Yemen - Saudi Arabia continues to escalate its war against Yemen, relying on the strong support of the U.S. government even as the poverty-stricken Yemenis are pushed toward starvation, according to investigative reporter/historian Gareth Porter.  Porter says the U.S. corporate press has failed to report the Saudi slaughter in a way in which it could be fully understood. I spoke with Porter, an independent investigative journalist who wrote  Manufactured Crisis: The Untold Story of the Iran Nuclear Scare and whose articles on Yemen include “Justifying the Saudi Slaughter in Yemen.”

  • Dennis Bernstein: Is Saudi Arabia using starvation as a weapon of war against Yemen where there is mass hunger bordering on a famine? Gareth Porter has been writing extensively about this for Consortiumnews and other sources. I want to … begin with a bit of an overview because a lot of people don’t really understand the level of suffering, and the situation in Yemen. So, just give us a brief overview of what it’s like on the ground now. How bad is it? And then I want to talk to you about this new policy about starvation as a weapon.
  • Gareth Porter: Sure. Well, unfortunately the way this war in Yemen has been covered, thus far, with a few exceptions, of course, the public does have the impression that this is a war in which a few thousand Yemenis have been killed, and therefore, it’s kind of second to third tier, in terms of wars in the Middle East. Because people are aware that Syria is one in which hundreds of thousands of people have died. So, and I think that’s the frame that most people have on the conflict in Yemen. And that’s very unfortunate, because maybe it’s true that it’s only been several thousands, or let’s say ten thousand plus people, who have been killed by the bombs, directly. But what’s really been happening for well over a year, I think it’s fair to say a year to a year and a half, is that more people are dying of starvation-related or malnutrition-related diseases and starvation, than from the bombs themselves. And this is a fact which I’m sorry to say simply has not gotten into the press coverage of the war, thus far.

US Confirms Coalition Airstrike In Mosul May Have Killed As Many As 240 Civilians --The US military confirmed on Saturday that a coalition airstrike had hit an Islamic State-held area of Iraq's Mosul where as many as 240 civilians may have been killed as result of the air raid. What happened in the incident on March 17 in Mosul al-Jadida district is still unclear according to Reuters. Some residents say a coalition air strike hit an explosive-filled truck, detonating a blast that collapsed buildings packed with families. Mosul municipality chief, Abdul Sattar al-Habbo, who is supervising the rescue, said 240 bodies had been pulled from the rubble of collapsed buildings. Previous estimates from local officials had said around 130 people had died. While US officials say they are investigating, initial reports from residents and Iraqi officials in the past week said dozens of people had been killed after air strikes by U.S.-led coalition forces.The US said the strike was at the request of the Iraqi forces. The American confirmation followed a decision by Iraqi government forces to pause their drive to recapture west Mosul on Saturday because of the high rate of civilian casualties.“An initial review of strike data from March 16-23 indicates that, at the request of the Iraqi Security Forces, the Coalition struck ISIS fighters and equipment, March 17, in West Mosul at the location corresponding to allegations of civilian casualties,” US Central Command said in a statement issued on Saturday.Videos of the deadly aftermath of the airstrike released on Friday show scores of dead bodies being pulled out of a completely destroyed building in western Mosul. There have also been reports by eyewitnesses who say over a hundred civilians were either killed or buried under rubble in the bombing raid.

If Aleppo Was a Crime Against Humanity, Isn’t Mosul? - Mosul, Iraq’s second largest city and the last major Islamic State stronghold in the country, is nearly under Iraqi government control.The Islamic State, or ISIS, has occupied the city since June 2014. Now, with the help of U.S. airpower, the entire eastern portion of the city has been retaken, and roughly 33 percent of Mosul is in Iraqi government hands. ISIS is “completely surrounded,” according to Western-coalition officials.But what’s happening in Mosul could be called “massacre” just as easily as it could be called “liberation.” And the choice of words and focus is instructive. Compare it to the feverish Western coverage of the siege of rebel-held Aleppo by Russian and Syrian government forces.Just three months ago, on the eve of Aleppo’s fall to the Syrian regime, the New York Times declared that Syrian leader Bashar al-Assad, Russian president Vladimir Putin, and Iran were “Aleppo’s destroyers,” and decried the slaughter of civilians and intense shelling of residential neighborhoods. There was little discussion of the rebels, many of which had received U.S. funding or weapons at some point during the conflict — and almost all of which had engaged in severe violations of human rights of their own. The Times assigned complete responsibility for the disaster to the Syrian government, which it said had “ignored the demands of peaceful protesters and unleashed a terrifying war.” That position unsurprisingly mimicked the U.S. government’s. (The U.S. ambassador to the UN, Samantha Power, even compared the fall of Aleppo to the Rwandan genocide and the massacre at Srebrenica.) If stripped of the hyperbole, the Times was not wrong. The population of Aleppo had been subjected to a brutal siege carried out by the Syrian military and its allied militias. Barrel bombs had devastated the city for years, destroying primarily civilian infrastructure such as mosques,hospitals, and schools. Humanitarian access to the eastern half of the city was made difficult by regime checkpoints and attacks. Meanwhile, in government-held areas of Aleppo, the Syrian regime operated as a police state usually does: by arresting and torturing dissenters. The report released by the UN Human Rights Council on March 1 makes it clear that that the Syrian regime is guilty of heinous crimes in Aleppo, including summary execution and the use of chemical weapons. The obvious distinction between the two battles is that eastern Aleppo was occupied by U.S. and Gulf-backed rebels, while the universally despised Islamic State occupies Mosul.

Iraq Denies US Air Raid Killed Over 200 Civilians In Mosul -- Two days after the US military confirmed that a coalition airstrike may have killed as many as 240 civilians in a March 17 Mosul air raid, the Pentagon found an unexpected defender when the Iraqi military said on Sunday a blast that killed scores of civilians in western Mosul was triggered by an Islamic State booby trap, contradicting local officials and residents who claimed a U.S.-led coalition airstrike caused the deaths. The Iraqi military statement, based on an initial assessment, came a day after the U.S.-led coalition acknowledged it carried out an airstrike on March 17 at the request of Iraqi security forces against Islamic State fighters in western Mosul, the WSJ reported. The location corresponded to allegations of mass casualties. As we reported on Saturday the US-led coalition, which is backing Iraqi troops that are engaged in fierce fighting to retake the entire city from Islamic State, said it is investigating to determine if the strike caused several houses to collapse, trapping what local officials said could be up to 200 people. As the WSJ adds, the coalition, which is backing Iraqi troops that are engaged in fierce fighting to retake the entire city from Islamic State, said it is investigating to determine if the strike caused several houses to collapse, trapping what local officials said could be up to 200 people. As we reported on Saturday, some residents had said a coalition air strike hit an explosive-filled truck, detonating a blast that collapsed buildings packed with families.

Syria: Final evacuation of Homs begins under close Russian supervision | The Independent: They came out of the dawn. Young men dressed and scarved in black and carrying Kalashnikovs, old men in wheelchairs, mothers in midnight niqabs, a teenager with a child in one arm and a strapped rifle draped over the other, a serious man with a big gold and green Koran in his right hand and a small figure with a vast shaggy beard, the very last Che Guevara, walking and limping and sometimes marching almost nonchalantly onto the buses. They came from the very last rebel enclave in Homs. And they were, some of them, going to fight another day. They didn’t look at us. They didn’t look at the Russian soldiers or the Syrian troops or the policemen or the plain clothes Syrian cops or the Red Crescent women; they didn’t bother to glance at the cameras that whirred and clicked their faces off to posterity; not that you could see many of the women behind their face covers and black scarves as they climbed slowly onto the buses. But one young man in a red and white track suit who glowered towards us, turned back once he was on the bus, behind the safety of the window. And he grinned and put his right finger in the air above his head and turned it round and round for his audience on the street outside. "We are coming back," it said. We are not leaving. We are not surrendering. But of course, no-one had asked these hundreds of men and women to surrender. Months of negotiations and trust and a lot of suspicion are slowly emptying the withered, smashed suburb of al-Wa’er of its armed men. Al-Wa’er means a barren place, a place without flowers, a place where nothing grows.So what might grow after this exodus of people – Syrians for the most part, although one man must have been a Sudanese and Che Guevara looked as though he was probably a Saudi – and what peace might it bring to central Syria? All were sent in their fleets of buses north to Jerablus on the Turkish border where the Syrian government hopes, without saying so, that they will seep across into Turkey and never return. But that wasn’t what the governor of Homs was telling them. He walked to the buses and pleaded with the departing thousands to stay. You will be safe, he told them. You can stay in your homes. You will not be arrested.

McCain Furious At Rex Tillerson For Saying Assad Can Stay -- The six year Syrian proxy war to dethrone president Bashar al Assad quietly ended with a whimper yesterday when at a news conference in the Turkish capital, Secretary of State Rex Tillerson suggested the end of Bashar Assad’s presidency is no longer a prerequisite for a way out of the Syrian crisis, in a dramatic U-turn from Washington’s long-held policy.“I think the longer term status of President Assad will be decided by the Syrian people,” said Tillerson at a joint conference with Turkish Foreign Minister Mevut Cavusoglu on Thursday, AFP reported. Later, UN Ambassador Nikki Haley echoed Tillerson, saying "Our priority is no longer to sit and focus on getting Assad out.""You pick and choose your battles and when we're looking at this, it's about changing up priorities and our priority is no longer to sit there and focus on getting Assad out," U.S. Ambassador Nikki Haley told a small group of reporters."Do we think he's a hindrance? Yes. Are we going to sit there and focus on getting him out? No," she said. "What we are going to focus on is putting the pressure in there so that we can start to make a change in Syria."Under President Barack Obama, the United States made Assad’s departure one of its key objectives. The Syrian armed opposition also insisted upon the longtime leader’s resignation as one of the conditions during the Astana peace talks.For those unaware, allowing the people of Syria to decide the fate of President Assad has been Russia's stance since the conflict began. Moscow has repeatedly rebuffed any preconditions for Assad to step down before a political settlement of the crisis.

China steps up Americas oil imports, Unipec backs 'new frontier' | Reuters: China's largest crude oil buyer Sinopec aims to ship more cargoes from Brazil, the United States and Canada, to help ensure stable crude supplies as the Middle East boosts refining capacity and Africa suffers disruptions. Shipments from the Americas hit an all-time high in March, boosting the region's share of the Chinese market by 1.1 percentage points in the first quarter to close to 14 percent, data from Thomson Reuters Oil Research & Forecasts showed. "We're facing a big challenge on the supply side," said Chen Bo, president at Unipec, which purchases crude for Asia's largest refiner Sinopec (0386.HK)(600028.SS). Asia needed to step up crude imports from the "new frontier", the greater U.S. Gulf Coast region made up of the United States, Canada and Latin America, to meet its growing demand, he told a seminar this week. China is on track to overtake the United States as the world's largest oil consumer this year, Chen added. China will add just under 2 million barrels per day (bpd) of refining capacity between 2016 and 2020, taking its total capacity to nearly 12.5 million bpd by the end of this decade. Also, by end-2018, the total crude import quota for independent refineries will grow to 2 million bpd, about 500,000 bpd more than March 2017 as government approvals flow through, he said.

Tankers: WAF-China VLCC crude oil route hits six-month low - The cost of sending crude oil from West Africa to China on VLCCs has dropped to a six-month low due to weak export demand and a rising number of VLCC vessels, sources said. The WAF-China VLCC route, basis 260,000 mt, was assessed at $11.42/mt on March 28, a six-month low since the route was assessed at $11.30/mt on September 13 last year, according to S&P Global Platts data. There have been a number of fixtures at this level, including Unipec, which was heard to have BW Bauhinia on subjects at w53, which equates to $11.42/mt, for a WAF to China stem with April 26-28 loading. Demand from Asia for heavy Angolan crude has cooled, and there is refinery maintenance coming up which might be the cause of this drop, sources said. There have been 28 VLCC stems fixed out of West Africa for April loading dates so far, compared with 37 for all of January, according to shipbroking sources. However, the VLCC fleet has also been growing rapidly for the last year and many owners have an increasingly bearish outlook for 2017, which is not helped by the recent OPEC cuts.

China likely to keep oil product exports steady to lower in H1 2017: sources - : China is highly likely to restrict oil product exports in the first half of 2017 to flat or below H1 2016 levels amid growing focus on pollution control, curbing excess capacity and international trade flows, sources with knowledge of the matter said this week. The total export quota for the second quarter was likely to be calculated based on the actual outflow in H1 2016 minus the quota allocated in Q1 2017, a Beijing-based senior product trader with a state-owned oil giant said. China exported 16.817 million mt of oil products in H1 2016 and awarded 12.4 million mt of quotas in Q1 2017, implying that the Q2 2017 oil product export quotas will be somewhere between 4 million mt to 5 million mt, according to calculations by sources. This is only one third the volumes allocated in Q2 2016, which was at 14.59 million mt, and is a continuation of the trend seen in Q1, when the quota allotted was 40% below Q1 2016's 20.93 million mt.Sinopec is estimated to get around 3 million mt quota in Q2 -- mostly for jet fuel, PetroChina around 1.2 million mt, while Sinochem and CNOOC are likely to get 450,000 mt each, according to two Beijing-based product traders with state-owned companies. Independent refineries are unlikely to be on the quota allocation list, they said. "This is a rough estimate for each company, which could be different from the actual allocation. But I am quite sure the actual quota will be cut significantly from last year to cap the outflows," one of the Beijing-based traders said.

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