Sunday, April 9, 2017

oil spikes on Trump's warmongering; US horizontal drilling doubles from last year, global rigs drop 1st time in 10 months

after falling 36 cents to $50.23 a barrel on Monday, oil were prices were higher daily for the rest of the week, and ended the week up more than 3%, as the US missile strike on Syria boosted prices on Friday, despite somewhat bearish inventory data...US contract prices for May delivery rose 79 cents to 51.03 a barrel on Tuesday, on growing support for an OPEC production cut extension and perceptions that the oil market is tightening...oil then rallied Wednesday morning after the late Tuesday American Petroleum Institute report showed the largest drawdown of US crude supplies so far this year, with prices running up as high as $51.88 a barrel by early afternoon, before the EIA report showed a surprise increase to a new record for crude inventories and smaller than expected draws in gasoline and distillates, sending oil prices tumbling back to close at $51.15 a barrel...oil prices then recovered and moved up steadily on Thursday to close at $51.70 a barrel, on expectations that a seasonal pickup in refining activity would help draw down massive U.S. crude stockpiles...oil prices then spiked more than a dollar in overnight trading on Friday morning after the news broke that US warships in the Mediterranean fired 60 Tomahawk missiles at an airbase in Syria, reaching as high as $52.94 a barrel in early trading before settling back to close the week at $52.24 a barrel, the highest closing price since March 7th... 

the ostensible reason for Thursday night's US missile attack on Syria was a reported chemical gas attack on Tuesday in the rebel held northern Syrian town of Khan Sheikhoun, where dozens of people, including children, died after writhing, choking, gasping or foaming at the mouth, after breathing in poison that probably contained a nerve agent or other banned chemicals...despite offering no clear proof, President Trump blamed Syria's president Assad for the attack, (he also blamed Obama) and requested a Pentagon briefing on what military options were available...since Russians were still on the ground in Syria in support of Assad, he opted for the cruise missile strike from the US warships in the Mediterranean, and after warning the Russians in advance, ordered the strike against the Syrian airfield where the military believed the jets that participated in the Tuesday attack were based...

i don't believe that Assad or the Syrian government were responsible, at least not directly, for the chemical gas deaths that occurred on Tuesday, and i believe it's possible that Trump doesn't believe they were either, and it's also apparent that neither does CIA Director Mike Pompeo....the explanation of that Syrian catastrophe that the Russians offered was far more plausible than Trump's allegations; the Russian defense ministry explained that the Syrian airstrike hit a large terrorist ammunition depot which included the chemical weapons, which were thereby released as a result of the bombing raid, thus killing nearby civilians...furthermore, there is no conceivable reason that Assad would order such an attack on his own people...with the support of the Russians and Iran, he was already clearly winning the long civil war that had consumed his country over the past 6 years, ISIS and Al-Qaeda were already on the run, and the few pockets of various rebel groups that remained in Syria were no longer a serious threat to his government...Trump, on the other hand, has been seeing his approval ratings badly slumping, and was closing in on a hundred days in office with not a single item on his agenda passed through congress...furthermore, he was about to meet with Chinese President Xi Jinping, after warning that the US would take unilateral action against North Korea if the Chinese did not reign in Kim making a high profile strike from miles away with cruise missiles on a small Syrian airbase, he immediately convinced the Chinese that he's serious about using force in North Korea, and simultaneously rallied the hawkish Democrats in Congress to his side, and is also likely to see a significant boost to his record low approval ratings..

Be prepared, there is a small chance that our horrendous leadership could unknowingly lead us into World War III.” -- Donald J. Trump (@realDonaldTrump) August 31, 2013

The Latest Oil Stats from the EIA

the oil data for the week ending March 31st from the US Energy Information Administration showed another increase in the amount of oil US refineries used, and an even larger drop in our oil imports, but because of an even larger drop in our exports of crude oil, we still saw another small increase in our record high oil supplies for the 12th week out of the past thirteen...our imports of crude oil decreased by an average of 374,000 barrels per day to an average of 7,850,000 barrels per day during the week, while at the same time our exports of crude oil fell by 435,000 barrels per day to an average of 575,000 barrels per day, which meant that our effective imports netted out to 7,275,000 barrels per day during the week, 61,000 barrels per day more than the prior the same time, our crude oil production rose by 52,000 barrels per day to an average of 9,199,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 16,474,000 barrels per day during the cited week...

meanwhile, refineries reportedly used 16,429,000 barrels of crude per day, 204,000 barrels per day more than they used during the prior week, while at the same time, 149,000 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 104,000 more 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 +104,000 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 7,947,000 barrels per day, now 2.3% above that of the same four-week period last the same time, the 4 week average of our oil exports fell to 713,000 barrels per day, 90.1% 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 149,000 barrel per day increase in our crude inventories came about on a 224,000 barrel per day increase in our commercially available crude supplies, which was partially offset by an 75,000 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 52,000 barrel per day oil production increase resulted from a 40,000 barrel per day increase in output from the lower 48 states and a 12,000 barrels per day increase in oil output from Alaska...the 9,199,000 barrels of crude per day that we produced during the week ending March 31st is now up by 4.9% from the 8,770,000 barrels per day were producing at the end of 2016, and the most we've produced since the last week of January 2016...while the week's production was up by 2.1% from the 9,008,000 barrel per day output during the during the equivalent week a year ago, it was still 4.3% below the June 5th 2015 record oil production of 9,610,000 barrels per day...

US refineries were operating at 90.8% of their capacity in using those 16,429,000 barrels of crude per day, up from 89.3% 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... the amount of crude oil processed by refineries continues to be on a par with the 16,433,000 barrels of crude that were being refined during the week ending April 1st, 2016, when refineries were operating at 91.4% of capacity, but they did set a new record high for throughput for any week ending in March....

however, even with the week's refining increase, gasoline production from our refineries fell by 513,000 barrels per day to 9,515,000 barrels per day during the week ending March 31st, which left it 1.1% lower than the 9,617,000 barrels per day of gasoline that were being produced during the comparable week a year ago (much of that drop was due to a 439,000 barrel per day swing in the "adjustment to correct for the imbalance created by the blending of fuel ethanol and motor gasoline blending components)....on the other hand, refineries' production of distillate fuels (diesel fuel and heat oil) increased by 95,000 barrels per day to 9,617,000 barrels per day, which was 2.7% more than the 4,838,000 barrels per day of distillates that were being produced during the week ending April 1st last year...

even with the big drop in our gasoline production, the EIA reported that our gasoline inventories were only reduced by 618,000 barrels to 239,103,000 barrels as of March 31st, after they had already dropped by more than 16.1 million barrels over the prior 4 weeks....that was because our domestic consumption of gasoline fell by 279,000 barrels per day to 9,245,000 barrels per day, and because our gasoline exports fell by 19,000 barrels per day to 589,000 barrels per day while our imports of gasoline rose by 86,000 barrels per day to 607,000 barrels per day....while our gasoline supplies are now down by nearly 20 million barrels from the record high set 7 weeks ago, they're just 2.0% lower than last year's April 1st record high for any April of 243,998 ,000 barrels, and are still 4.0% above the 229,945,000 barrels of gasoline we had stored on April 3rd of 2015... 

our supplies of distillate fuels also fell a bit for the week, decreasing by 536,000 barrels to 152,374,000 barrels by March 31st, as the amount of distillates supplied to US markets, a proxy for our consumption, decreased by 124,000 barrels per day to 4,098,000 barrels per day, and as our imports of distillates rose by 16,000 barrels per day to 131,000 barrels per day, while our exports of distillates fell by 43,000 barrels per day to 1,077,000 barrels per day at the same time....while our distillate inventories are now 6.5% below the bloated distillate inventories of 162,984,000 barrels that we had stored on April 1st 2016, at the end of last year's warm El Nino winter, they are still 20.1% higher than the distillate inventories of 126,924,000 barrels that we had stored on April 3rd of 2015…  

finally, our commercial inventories of crude oil rose for the 12th time in the past 13 weeks, increasing by 1,566,000 barrels to yet another record high of 535,543,000 barrels by March the same time, 524,000 barrels of oil from our Strategic Petroleum Reserve were sold, which left inventories in the SPR at 692,135,000 barrels, a quantity nonetheless not considered available for commercial use....thus for current commercial purposes, we finished the week ending March 31st with 11.8% more crude oil in storage than the 479,012,000 barrels we had stored at the end of 2016, 7.4% more crude oil in storage than the 498,598,000 barrels of oil in storage on April 1st of 2016, 19.1% more crude than what was then a record 449,662,000 barrels in storage on April 3rd of 2015 and 52.0% more crude than the 352,341,000 barrels of oil we had in storage on April 4th of 2014... since our oil supplies have hit a new record high in 7 out of the last 8 weeks, we'll include a picture of what that looks like, and show you why we go back three years with our comparisons...

April 6 2017 oil supplies as of March 31

the above graph is from a picture of the interactive graph that accompanies the ending stocks of crude oil page at the EIA, which fairly clearly shows the end of the week supplies of commercially available crude oil stored in the US (or nearby offshore) weekly since 2000...we can clearly see that oil supplies over the recent weeks were at record levels, but to compare those levels to levels of a similar period of 2016 would be comparing to what were in that year also record levels at the time...similarly, new records for US oil supplies were being set weekly for several consecutive weeks in early 2015, so when we're comparing today's supplies to that year, we're also comparing to what was then already a glut of oil.,'s only when we compare today's supplies to those of the same date in 2014 that we're making a comparison to what we could consider a normal level of oil supplies for the time of year, and it's with that in mind that we can say that throughout 2017, US oil supplies have consistently remained more than 50% above the historical norm...

This Week's Rig Count

US drilling activity increased for the 22nd time in the past 23 weeks during the week ending April 7th, and this week's increase was also the 10th double digit rig increase in the past 12 weeks....Baker Hughes reported that the total count of active rotary rigs running in the US increased by 15 rigs to 839 rigs in the week ending Friday, which was 396 more rigs than the 443 rigs that were deployed as of the April 8th report in 2016, and the most drilling rigs we've had running since September 18th, 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 672 rigs this week, which was up by 318 from the 354 oil directed rigs that were in use a year ago, and well more than double the low of 316 oil rigs that were working on May 27th 2016, but it was still way down from the recent high of 1609 rigs that were drilling for oil on October 10, the same time, the count of drilling rigs targeting natural gas formations rose by 5 rigs to 160 rigs this week, which was also up from the 89 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, addition, there remains 2 rigs deployed that are classified as miscellaneous, compared to a year ago, when there were no such miscellaneous rigs at work...  

active horizontal drilling rigs increased by 10 rigs to 695 rigs this week, which is also well more than double the May 27th 2016 nadir of 314 working horizontal's also more than double the 341 horizontal rigs that were in use in the US on April 8th of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of the same time, a net of 4 vertical rigs were added this week, bringing the vertical rig count up to 73, up from the 50 vertical rigs that were deployed during the same week last addition, a single directional rig was also added this week, bringing the directional rig count up to 71 rigs, which was also up from the 52 directional rigs that were deployed during the same week a year ago...

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 both tables, the first column shows the active rig count as of April 7th, the second column shows the change in the number of working rigs between last week's count (March 31st) and this week's (April 7th) count, the third column shows last week's March 31st 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 8th of April, 2016...           

April 7 2017 rig count summary

once again, the majority of the net increase in drilling is taking place in the Permian basin of west Texas, where at 331 rigs they're now up by 189 rigs from a year ago and account for almost half of the horizontal drilling activity in the US...increases of 2 rigs in both the Cana Woodford and the Mississippian account for the 4 rig increase in Oklahoma, while the 4 rig decrease in the Granite Wash is the apparent reason that the state of Texas's increase was reduced to 7 rigs...increases in rigs targeting natural gas were seen in the Arkoma Woodford of Oklahoma, in the Marcellus in West Virginia, in the Barnett of north Texas, where a gas rig was added while a oil rig was shut down, and in two unnamed locations include in "other basins' on the Baker Hughes basin summary table...

International Rig Counts for March

Baker Hughes also released the international rig counts for March on Friday, which unlike the weekly North American count, is an average of the number of rigs that were running in each country during the month, rather than the total of those rig drilling at month end....Baker Hughes reported that an average of 1985 rigs were drilling for oil and natural gas around the globe in March, which was down from the 2,027 rigs that were drilling around the globe in February, but up from the 1,551 rigs that were working globally in March of last year....a seasonal pullback in Canadian drilling was the reason for that, the first  global decrease in 10 months, as the average Canadian rig count fell from 342  rigs in February to 253 rigs in March, which was still up from the 88 Canadian rigs that were deployed in March a year earlier, while the average US rig count rose from 744 rigs in February to 789 rigs in March, which was also up from the average of 478 rigs that were working in the US in March a year ago....outside of Northern America, the International rig count rose by 2 rigs to 943 rigs in March, still down from 1,018 rigs a year ago, as increases in drilling in Latin America , the Middle East, Asia and Africa were offset by a sharp drop in drilling activity in Europe..

the number of drilling rigs deployed in the Middle East was up by 4 rigs to 386 rigs in March, after their drilling activity had been unchanged in February, which still left them down from 397 rigs a year earlier...Egypt added 7 rigs for the month, which brought their total up to 23 rigs, still down from 31 rigs a year earlier....OPEC member Iraq, who has indicated they'll boost their crude oil production by 600,000 bpd to 5 million bpd by the end of this year, activated 3 additional rigs in March, and thus had 43 rigs deployed, still down from 48 rigs a year earlier...Abu Dhabi of the United Arab Emirates, also an OPEC member, also added a rig in March and thus had 48 rigs working, unchanged from the number they had drilling new wells a year ago...on the other hand, the Kuwaitis shut down 5 rigs during the month, after they had added 7 rigs in February, and now have 54 rigs active, which is up from the 41 rigs they had working a year addition, Pakistan and the Saudis each shut down one rig in March, which left the Saudis with 119 rigs, down from the 127 rigs they were running a year ago, and which left Pakistan with 20 rigs running, down from the 24 rigs they had deployed in March of 2016

at the same time, the Latin American region saw their active drilling rig count increase by a net of 6 rigs to 185 rigs, down from 218 rigs in March of last year, and down from 321 rigs as recently as September of 2015, as the region idled 92 rigs over the first 6 months of 2016...Argentina added 4 rigs during the month, which brought their total back up to 58 rigs, still down from 68 rigs a year ago...Mexico added 2 rigs and thus have 18 rigs active, still down from 2 rigs a year earlier...the Brazilians also added 2 rigs, bringing their total to 16 rigs, down from 28 rigs a year earlier.. .in addition, both Peru and Bolivia added a rig each, giving Peru 6 rigs and Bolivia 5 rigs, with drilling in neither country much changed over the past year...Latin American countries reducing their rig count included Columbia, who was down 3 rigs to 19 rigs but still up from 4 rigs a year ago, and Chile, a minor producer who shut down 1 rig and had one remaining...

drilling activity in the Asia-Pacific region was up by a net of 2 rigs to 198 rigs in March, which was also up from the 183 rigs working in the region a year earlier...India added two rigs and now have 117 rigs active, up from 104 rigs a year ago...Malaysia also added 2 rigs and now have 5 rigs working, up from 3 rigs a year ago...Thailand and Indonesia each added one rig, bringing them up to 14 rigs and 24 rigs respectively, with Thailand unchanged from a year ago and Indonesia's drilling up from last year's 19 rigs...on the flip-side, single rigs were taken out of service in Australia, Brunei, Vietnam and offshore of China... that left Australia with 13, still up from 9 rigs a year ago, left Brunei with 1 rig, down from 2 last March, left Vietnam with 2 rig, up from 1 rig last March, and left China with 17 offshore platforms working, down from 26 a year ago....

in addition, drilling on the African continent outside of Egypt saw a net increase of 3 rigs to 80 rigs in March, which was still down from the 91 rigs working in Africa last year at this time...OPEC member Nigeria, who is not yet subject to the agreed production cuts, increased their active rigs by 3 to 10 rigs, which was up from 8 rigs in March of last year...OPEC member Algeria added 1 rig, giving them 51 rigs working in March, down from the 54 rigs they had running a year ago....meanwhile, OPEC member Angola shut down 1 rig, and now has just 2 rigs active, down from the 8 rigs they had active a year earlier..

on the other hand, drilling activity was lower Europe, decreasing by 13 rigs to 94 rigs in March, which was also down from the 96 rigs that were working in Europe last March...Turkey shut down 6 land based rigs, leaving 23, which left them down from 28 rigs a year addition, offshore platforms were idled in several countries...the U.K. shut down 3 offshore rigs, leaving them with 8 rigs still drilling in the North Sea, now down from 9 offshore a year ago...the Dutch shut down both of their active rigs, and now have none, compared to the 3 offshore and 1 land rig they were running last March...Norway shut down one, but they still have 15 rigs drilling offshore, down from 19 offshore a year ago...and the Danes also shut down their only offshore platform, and thus had no drilling in March for only the 3rd month in the last 4 years...the only other change in European activity was on land, where France added a rig and now have 4 rigs running, still down from 5 rigs a year ago...

finally, note that Iranian, Russian, and Chinese rig counts are not included in this Baker Hughes international data, although we did note that China's offshore area, with an average of 17 rigs active in March, were included in the Asian totals here, apparently based on satellite intel, which is the way much of the international oil data is collected...  


Stark County man accused of polluting river - A Lawrence Township resident faces federal charges on allegations he dumped wastewater into tributaries of the Tuscarawas River. A Stark County man was supposed to be hauling wastewater to Pennsylvania for proper disposal. But instead, Adam D. Boylen, 45, of Lawrence Township, was steering a tanker truck to remote areas of Tuscarawas County and central-eastern Ohio, illegally discharging the wastewater and pollutants into tributaries of the Tuscarawas River, according to allegations in a federal indictment filed in U.S. District Court.The dumping killed fish and destroyed vegetation, federal authorities said Tuesday. Boylen was charged with four counts of violating the Clean Water Act, according to an indictment announced in a news release from the U.S. Attorney’s office in Cleveland. The Tuscarawas River extends more than 100 miles and is a popular canoeing and kayaking destination in Central Ohio, court records note. The river “maintains a diverse fisheries stock,” according to the indictment. “This defendant willingly dumped wastewater into streams, fouling the water and killing aquatic life,” Carole S. Rendon, U.S. Attorney for the Northern District, said in a statement. “He put his convenience ahead of the public’s welfare. We remain committed to protecting our environment, and this defendant will now be held accountable for his actions.”  Boylen was a driver employed by an Ohio-based trucking company, according to federal prosecutors. His job was to load wastewater generated from corporate facilities into a tanker truck and to drive the material to a designated facility located in Pennsylvania for proper disposal, the news release said. The wastewater was capable of killing vegetation and fish, according to court records. Instead of driving the wastewater to Pennsylvania, Boylen drove the tanker truck to Tuscarawas County and central-eastern Ohio and emptied the wastewater containing the substances (technically known as surfactants) into the streams, records said. Boylen is accused of dumping the wastewater into two tributaries of the Tuscarawas River: A wetland adjacent to the river and the Beach City Reservoir. The illegal discharges occurred numerous times between April 18 and May 4 last year, according to investigators.

Report raises questions about Ohio utilities’ renewable credit deals | Midwest Energy News: Shortcomings in the way that regulators report on compliance with Ohio’s clean energy standards make it difficult to determine why utilities paid average prices that were about 70 percent more for each renewable energy credit than competitive suppliers spent in 2015. The Sierra Club lodged that complaint and other concerns with the Public Utilities Commission of Ohio late last month after the regulators invited comments on their draft report on the state’s compliance with the renewable portfolio standards. “It’s not clear what happened here,” because much of the information is not available for review in public reports, noted Dan Sawmiller of the Sierra Club. “But we can say this looks suspicious, and it warrants further exploration by the Commission to find out who did this.” Under Ohio’s renewable portfolio standard, the state’s utilities and competitive electric suppliers must provide or obtain credits representing a specific portion of their electricity from renewable sources. In turn, they must report compliance and purchase data to the PUCO. Under state law, the PUCO then submits a report summarizing all of that information to the state’s lawmakers. Information in the PUCO’s draft filing shows that in 2015 Ohio utilities paid an average price of $15.47 for each renewable energy credit, or REC. In contrast, competitive suppliers paid an average price of just $9.07.Moreover, the state’s electric utilities accounted for about 30 percent of the total compliance obligation for the non-solar renewable standard. Those electric utilities are Duke Energy, Dayton Power & Light, American Electric Power’s Ohio Power Company and FirstEnergy’s three Ohio utility subsidiaries. Competitive suppliers are responsible for the remaining 70 percent.

Ohio lawmakers introduce bill to support FirstEnergy's nuclear plants - Ohio is the latest state to catch ZEC fever. Zero emission credits are designed to aid nuclear plants at risk of early closure in the nation's wholesale markets by paying them for their zero-carbon generation. But critics, ranging from consumer advocates to gas generators, have opposed them, saying they threaten price formation in organized power markets. In a recent filing, the PJM Interconnection’s market monitor wrote that “subsidies are contagious."Connecticut late last month introduced legislation that would create a solicitation that could provide a power purchase agreement for the state’s sole nuclear plant, Dominion Energy’s Millstone station.New Jersey is also considering a ZEC proposal. Prior to that, New York’s Public Service Commission and Illinois’ legislature passed ZECs aimed at keeping nuclear plants in their states operating. Both efforts are being contested. The bill that is soon to be introduced in Ohio uses a different name, ZEN, but it is similar in many respects to the efforts in other states. SB 128 would create a Zero Emission Nuclear Resource (ZEN) program to compensate the FirstEnergy’s nuclear plants for the “clean, reliable and secure power they generate.” A press release from Sen. John Eklund (R), the bill’s sponsor, said customers with a nuclear plant in their service territory would see a “small increase” in their monthly electric bills.

Our limited public forests should be protected, not industrialized | Letters | - The federal Bureau of Land Management (BLM) 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. Ohio ranks 47th in the nation in public land available 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 prior to leasing. For example, it’s widely acknowledged that pipeline construction is the single largest source of ground disturbance associated with oil and gas development. Nevertheless, the agencies simply shrugged off the pipeline issue in their environmental reviews. 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. Case in point: the June-July 2014 “Eisenbarth” well-pad fire that poisoned a waterway near the Wayne and blackened parts of the Monroe County skyline for days. Having these risks near our public forests is bad enough. Inviting them in is the last thing we should want to do.

Harrison County, Ohio, residents concerned about speeding oil and gas trucks— The Harrison County Sheriff's Office held its monthly oil and gas meeting on Monday. One of the concerns expressed not only by a county resident in attendance but the mayor of Deersville to Sheriff Ronald Myers was speeding on county roads by oil and gas company trucks, specifically County Road 2. Myers says it's a problem everybody has to work on. “We have to drive defensively because you never know when that truck’s going to come around that turn and that trailer could be swinging wide,” Myers said. “They’re out of the lane of travel and we understand that, but we only have so many guys throughout the day, at night, afternoon that can be out there, and try to be out there. Safety is the No. 1 priority.”

Earthquake Strikes Wayne National Forest Near Fracking Operations - The U.S. Geological Survey reported an earthquake Sunday in Monroe County with the epicenter located at 39.6663º N, 81.244º W. The 3.0 magnitude earthquake was located in the Marietta Unit of the Wayne National Forest. Approximately 40,000 acres of the forest are slated for fracking by the Bureau of Land Management.  Earthquakes in the area are fairly unusual, especially at such a magnitude. The U.S. Geological Survey has linked induced seismicity to wastewater injection facilities and active oil and gas fracking wells. There are four wastewater injection sites located within 20 miles of the epicenter. In 2016, these injection wells accepted 8.3 million barrels of wastewater polluted with a dangerous mix of salt water, hazardous chemicals and radioactive compounds and approximately 90 percent of this waste is trucked in from out of state. Additionally, seven utica shale fracking sites are within five miles of the epicenter.  The science is clear, cradle-to-grave fracking is risky and dangerous to our air, water and communities. Yet, fracking activity continues near two of our state's most precious resources—the Wayne National Forest and the Ohio River and, if the Bureau of Land Management has its way, will expand.  We call upon the U.S. Forest Service and the Bureau of Land Management to cease and withdraw all plans for fracking in Ohio's only national forest.  We ask the Ohio Department of Natural Resources and Gov. Kasich to work with federal authorities to fully investigate its causes and to protect the public from any serious risks that fracking in the area could cause.  Furthermore, we ask the governor to keep our clean energy progress going, because energy efficiency renewable energy are clean, safe and cheap.

Ohio investigates cause of weekend earthquake in drilling region - State officials are investigating whether a magnitude 3.0 earthquake in the Wayne National Forest was caused by nearby oil and gas operations.  It wouldn’t be the first time: Hundreds of temblors have been linked to drilling operations and injection wells in Ohio and other states. The Ohio quake occurred about 8 a.m. Sunday near Graysville in Monroe County in the national forest’s Marietta Unit. Activity at nearby wells was halted within an hour after the quake, according to the Ohio Department of Natural Resources, whose seismologists are investigating the quake’s potential sources. According to the state, eight permitted Utica shale well sites are within 5 miles of the epicenter of Sunday’s earthquake, which is about 120 miles southeast of Columbus; the quake was not related to Monroe County’s sole, inactive injection well. Fracking involves pumping a mixture of water, sand and chemicals deep underground to fracture rock formations and release trapped oil and gas. The wastewater that comes up with the oil and gas can be reused, but disposal eventually is necessary. Frequently, that wastewater is injected deep underground. “Review of the seismic data placed the event ... in proximity to ongoing oil- and gas-well completion operations,” Department of Natural Resources spokesman Steve Irwin said in an email. “The division continues to evaluate seismic data and completion operations in the area.” It’s too soon to connect regional hydraulic fracturing with Sunday’s quake, said Miami University seismologist Mike Brudzinski. “I think it’s natural to think of this as a potential relationship. The next step is trying to do the science to make sure that’s true,” he said. Brudzinski said Ohio typically experiences earthquakes of this magnitude a couple of times a year. Still, he noted that the state’s southeastern region is not one with a long history of seismic activity.

3.0-Magnitude Earthquake Strikes Wayne National Forest, Fracking Operations Temporarily Halted - The eyes of the seismological and environmental worlds have focused on Wayne National Forest this week, the sight of a 3.0-magnitude earthquake on Sunday. For now, fracking operations in the forest have stopped. The earthquake's epicenter was not within any of the forest's recently leased parcels, but it was located in and near parcels that have been requested for future lease opportunities by private drilling companies. (See the map below.)  Within 20 miles of the epicenter, four wastewater injection wells thrust high-pressure fracking wastewater into the ground. In 2016, those wells injected 350 million gallons of fracking wastewater — most coming from out of state. Multiple fracking sites are set up within five miles of the Sunday earthquakes's epicenter.  In all, some 40,000 acres of the forest have been earmarked for private natural gas drilling — some of which was formerly federal land sold off by the Federal Bureau of Land Management. “This earthquake is a clear example of the risks involved in fracking,” said Melanie Houston, the director of the Ohio Environmental Council's oil and gas team, in a public statement this week.  Highly fracked eastern Ohio counties, like the Wayne's Monroe County, are increasingly affected by earthquakes — in alarming contrast to the rest of the state. FracTracker maps seismological data, and the correlation is hard to ignore.

ODNR: Was earthquake connected to fracking? - Athens NEWS - Anti-fracking activists are linking a 3.0 magnitude earthquake that shook the earth early Sunday in Monroe County to nearby oil and gas horizontal fracturing operations and waste-injection wells. They claim that such hazards will only increase if and when oil and gas development begins on the surrounding national forest. Within an hour of the earthquake, the Ohio Department of Natural Resources ordered fracking operations close to the quake’s epicenter, near the county seat of Woodsfield, to stop temporarily, according to ODNR spokesperson Stephanie Leis. She said the agency’s seismologists are investigating the quake’s possible links to oil and gas development in the nearby area, where eight permitted deep-shale oil-gas wells are operating. Links between earthquakes and oil-and-gas extraction and waste-injection wells have been established in other arts of Ohio and the nation. Monroe County Commissioner Carl Davis, who lives near Woodsfield, was quoted in the Wheeling Intelligencer as saying he didn’t notice the earthquake, and that nobody had reported damages to the local Sheriff’s Office. The U.S. Geological Survey likewise said no damage had been reported after the quake, the newspaper reported. Monroe County is two counties northeast of Athens County, just north of Washington County, the county where Marietta is located. In the article, ODNR’s Leis said, “As is ODNR protocol in regards to seismic occurrences, operations were halted. Ohio has some of the most comprehensive seismic monitoring operations and requirements in the country, which helped detect this unfelt event, and ODNR seismologists quickly began investigating potential sources. The division continues to evaluate seismic data and completion operations in the area. While Leis initially was quoted as saying only one oil-and-gas fracking operation was sufficiently near the earthquake epicenter to require being shut down, environmentalists claimed that seven fracking operations are located within five miles of the quake location. Leis, in an article in Tuesday’s Columbus Dispatch, acknowledged that eight permitted extraction wells had been operating within five miles of the earthquake site. The article, however, reported the ODNR as stating that the quake was not connected to Monroe County’s “lone, inactive injection well.”

Ohio, Monroe County Officials Comment on Sunday Earthquake   --The Ohio Department of Natural Resources halted fracking operations in the vicinity of the site of the 3.0 magnitude earthquake that took place near Woodsfield early Sunday.The U.S. Geological Survey and the Monroe County Board of Commissioners both said no damage was reported from the quake. Commissioner Carl Davis, who lives in Woodsfield, said he felt nothing.“I didn’t notice the quake, and I haven’t talked with anyone so far who has. There were no reports of any damage to the sheriff’s department,” Davis said.However, Ohio Department of Natural Resources spokeswoman Stephanie Leis said fracking operations near the earthquake site “were halted within an hour of the seismic occurrence.” “As is ODNR protocol in regards to seismic occurrences, operations were halted. Ohio has some of the most comprehensive seismic monitoring operations and requirements in the country, which helped detect this unfelt event, and ODNR seismologists quickly began investigating potential sources. The division continues to evaluate seismic data and completion operations in the area. Leis said she believed only one fracking operation was close enough to the earthquake site to require a shutdown. However, Melanie Houston, director of Oil and Gas for the Ohio Environmental Council advocacy group, said she believes there are seven fracking operations within five miles of the earthquake site.  “This earthquake is a clear example of the risks involved in fracking,” she said. “Instead of charging ahead with leasing in the Wayne National Forest, the Bureau of Land Management and the U.S. Forest Service should be considering what dangers we’re inviting into Ohio’s only national forest.”

Investigation Continues Into Earthquake Near Wayne National Forest Fracking Sites – WOSU  - Oil and gas drilling operations in southeastern Ohio were shut down on Sunday after a 3.0 magnitude earthquake hit the Wayne National Forest, according to the Ohio Environmental Council. The state continues to investigate the causes. "Earthquakes in the area are uncommon, especially at such a magnitude," the release read. Ohio's Department of Natural Resources said that the earthquake was not felt but the department immediately went to work to determine the source. Spokesperson Steven Irwin said once the investigation is complete, drilling operations near the epicenter might be modified."We will evaluate the geography of the area, and then create a plan, likely with reduced pressure, reduced volume, reduced activity, on those horizontal wells," Irwin says. A map from FracTracker shows several hydraulic fracturing - or fracking - sites within miles of the epicenter, in the Sycamore Valley area of Monroe County: [see map] “This earthquake is a clear example of the risks involved in fracking,” said Melanie Houston, OEC's director of oil and gas, in the release.  In 2016, around 719 acres of Wayne National Forest were made available for lease by oil and gas drilling companies despite opposition from environmental advocates.

While cause remains unclear, earthquake prompts new look at Ohio fracking | Midwest Energy News: Regardless of how regulators resolve their investigation into an April 2 earthquake in southeastern Ohio, drilling and well operators in the area will almost certainly need to do more careful monitoring and reporting in the future, now that there’s a known seismic risk. “Any time an earthquake occurs, that’s an indication that there’s a fault there,” said geologist Michael Brudzinski at Miami University in Oxford. The magnitude 3.0 quake on April 2 took place at 7:58 a.m. in the Marietta unit of Wayne National Forest in southeastern Ohio. “We hadn’t really seen [an earthquake] in the area where this one occurred” in April, with the exception of the two events of magnitudes of 2.3 and 1.8 on December 12, 2016, Brudzinski noted. Nearby oil and gas activities are on hold pending further investigation by the Ohio Department of Natural Resources. “Review of the seismic data placed the event in Monroe County in proximity to ongoing oil and gas well completion operations,” ODNR spokesperson Steve Irwin said. “Those activities were halted within an hour of the seismic occurrence.” The April 2 earthquake “is a concern because it shows we don’t have a handle on all of the risks involved in this industry,” said Melanie Houston of the Ohio Environmental Council. That worry is heightened by the fact that the federal government wants to open up more of the Wayne National Forest area for oil and gas development. “We’re inviting it into our only national forest, and it is really a concern and a problem for us,” Houston said.

$5.2 million fracking bid sets its sights on Wayne National Forest -  New drilling wells may dot the landscape of Monroe County following a $5.2 million bid in March for the rights to explore and drill for oil and gas on 1,180 acres of land in the Wayne National Forest.The Wayne National Forest, which covers over a quarter million acres of Appalachia, has seen such bids before; the U.S. Bureau of Land Management previously leased more than 1,600 acres of the forest to private oil and gas companies in December 2016. The move comes amidst a boom for fracking across the U.S., which now accounts for about half of the current domestic crude oil production.Although the recent bids have been for access to subterranean mineral rights on federally-owned land, almost 60 percent of the subterranean mineral rights below the forest are privately owned. Nearly 65 percent of active wells are found on these areas.Wayne National Forest Supervisor Tony Scardina stressed the guidelines companies must follow when pursuing oil and natural gas leases.  “All requirements are based on the best available science, extensive knowledge and experience of our staff and multiple layers of environmental study,” Scardina said. “At every stage of the oil and gas-leasing process, we apply these requirements, and once drilling is approved, we monitor ongoing operations to ensure requirements are properly implemented.”

Trump’s failure to fill key government posts is stalling key pipeline projects -  Without a quorum, the Federal Energy Regulatory Commission can’t approve energy-infrastructure projects expected to create thousands of high-paying blue-collar jobs.   The Federal Energy Regulatory Commission is not the country’s most well-known or controversial government agency. But if you care about building natural gas and oil pipelines or expanding the American power grid, it’s pretty important. FERC consists of five members who can approve or reject plans for major energy-infrastructure projects. The Trump administration has been slow to nominate candidates to some of the 600 or so significant positions in the executive branch, including the three empty spots on FERC, which has been short of a quorum since President Obama’s appointed chairman, Norman Bay, resigned on February 3. This doesn’t mean FERC shuts down entirely; inspections, safety reviews, audits, and all the traditional duties of its staff continue even when it lacks enough commissioners for a quorum. The legalese determining what staff may do is complicated, but the upshot is simple: The less controversial a decision, the more likely that the staff can legally make it. FERC does need a quorum of commissioners to vote on bigger matters, however, including new rules, applications for infrastructure projects such as natural-gas pipelines and liquid natural-gas facilities, petitions for rehearing or appeal of previous commission orders, and appeal of initial decisions by an administrative law judge. The lack of a quorum thus puts an indefinite delay on some vital projects as they await the final green light from FERC.For example, Enbridge Energy wants to build a new pipeline to transport Appalachian shale gas to high-demand markets in Canada and the Midwest, including Ohio, Michigan, Illinois, and Ontario. In addition to 255 miles of pipeline that is three feet in diameter, the project would involve the construction of “four new compressor stations, six new metering and regulating stations, and 17 new mainline valves in Ohio and Michigan.” Once completed, it would be capable of transporting 1.5 billion cubic feet of natural gas per day.

Pipeline plans heat up in W.Va. - - With growth of natural gas in West Virginia, there are a number of new pipeline projects proposed for the state, raising a range of debates about the benefits and the risks. In recent years, the shale revolution has opened access to abundant gas supplies within the state and the region, which has created the need for more infrastructure, according to industry officials. "Marcellus and Utica gas has been a game-changer for this region," said Scott Castleman, communication manager for TransCanada, which now owns Columbia Pipeline Group. "We have 31,000 miles of pipeline, with 15,000 miles on the East Coast that is at capacity," he said. "We need to increase that capacity." The United States already has a massive system of pipelines built over the past 100 years, and they carry various types of oil and gas products. "Nationwide, some 300,000 miles of natural gas transmission pipelines provide a vital link between producers and consumers," Castleman said. "Many people are unaware of the presence of this large pipeline network that is operating safely and reliably underground." "Pipelines have been transporting hydrocarbons all over the world for nearly 100 years, including across the Ohio River," said Anne Blankenship, executive director of the West Virginia Oil & Natural Gas Association. Dramatic gains in crude oil and natural gas production in the U.S. and Western Canada in the past decade has reshaped energy markets and increased demand for pipelines. "Natural gas has an important role to play in complementing low-carbon energy solutions by providing flexibility needed to support a growing renewables component in power generation," the International Energy Agency said in a recent report. The West Virginia Chamber of Commerce says building new, highly efficient pipelines will increase the use of West Virginia's natural resource and greatly increase its value.

Economic impact, safety drive pipeline debate - Oil and gas industry officials say the newly proposed pipelines for West Virginia are safe and essential to economic growth, but environmental groups contend the benefits do not outweigh the costs and the risks. Scott Castleman, TransCanada/Columbia Gas Group communications manager, said according to an economic impact study conducted by Witt Economic, LLC, close to 9,000 jobs will be created during the length of just the Mountaineer Xpress Pipeline project alone and it will also create additional tax revenue for the state and counties. "The overall economic investment is $2.1 billion and the MXP projected expenditures will have a direct economic impact on the counties crossed by the pipeline," he said. "These counties will benefit from increased property tax revenues both during construction and after the pipeline is place in service. Upon completion of the project, these counties will have a permanent increase in their property tax revenues, which can be used to support county services and local education." Despite the positive economic impacts, the Ohio Valley Environmental Coalition says the public health and environmental impacts of these proposed pipelines far outweigh any benefits. "As of now, the plans are to pipe all of that through the Huntington Tri-State area, and link with other pipelines near the Marathon Petroleum Refinery on the West Virginia and Kentucky border," said Dianne Bady, OVEC's founder. "Imagine the large area that the gas would come from as the wide end of a funnel. So the wide area of the funnel would narrow dramatically as it would pipe massive volumes of gas and liquids through our immediate areas. This seems dangerous and downright stupid for those of us who make our lives in what could become a very concentrated transport region for explosive and dangerous natural gas products." Castleman says pipelines are the best way to transport energy. "Studies show that transporting energy via pipeline is 4.5 times safer than moving the same volume across the same distance by other means, like truck or rail, and 99.999 percent of resources moved through pipelines safely reach their destination," he said.

Joint development law needs updated to help West Virginia -- With an unemployment rate stuck stubbornly higher than the national average, opportunities are hard to come by for West Virginia families. And it’s no secret that we lag behind just about every other state in the nation, ranking last or near the bottom on key economic measures. This is a tough reality facing families who understandably feel forgotten. The good news is that our state has opportunities to create good-paying, family-sustaining jobs. Thanks to natural gas development, West Virginia — which sits atop the Marcellus Shale — is the nation’s eighth largest natural gas producing state. In fact, West Virginia produced more than 1 trillion cubic feet of natural gas last year, or nearly four times as much gas produced in 2008. The Senate this week passed a crucial update in the law that allows for joint development and increased job growth and we need the House to act quickly on this bill. Our leaders in Charleston can work together to modernize West Virginia’s outdated, decades-old oil and gas law. Updating our existing gas production law — as countless other energy-producing states have done — to reflect current drilling technologies is a winner for the state, our workforce and our environment. Joint development is a commonsense policy that reduces aboveground land disturbance by allowing more efficient natural gas development of existing leases. This shale revolution couldn’t have come at a better time as it was the natural gas industry that lifted us through the Great Recession’s financially painful depths. Employing the hard-working West Virginians who build well pads, safely lay pipe and transport fluids, our companies have begun to realize the economic opportunity that natural gas development can deliver.

It's Official: Republican Governor Bans Fracking in Maryland - Maryland's fracking ban is the latest milestone in a strong and growing movement to resist fossil fuels throughout the country. This is a huge victory for public health, common-sense environmental protection, climate stability and, not least, the power of grassroots organizing. This bold turn will reverberate nationally at a time when the Trump administration seeks to decimate environmental protections for the sake of corporate polluter profits. Gov. Hogan's opposition to fracking demonstrates that matters of public health and our environment need not be partisan. Hogan has suddenly joined the ranks of national environmental leaders, vaulting ahead of many pro-fracking Democrats in the process.  With Gov. Hogan's signature, Marylanders can feel safe knowing their air, their water and their health will now be protected from the inherent dangers of fracking . We are confident that as scientific analysis and public opinion continue to move decisively against fracking, victories of this scale will be emulated in many more states in the coming years.

Bowen: Push for fracking ban is no joke | Tampa Bay Times: It's not easy being a mayor or any locally elected officeholder these days. The contempt from Tallahassee is never-ending. There are bills to restrict community redevelopment agencies, curb future revenue for local governments via larger property tax exemptions, gut home rule authority and even to take away the local ability to regulate vacation rentals. Remember when the Republican mantra was local control? Not anymore. Against that backdrop of undermining local governments, Dade City Mayor Camille Hernandez joined Dr. Lynn Ringenberg, immediate past president of Physicians for Social Responsibility, and Brooke Errett of Food & Water Watch at City Hall in Dade City last week to talk about a local environmental worry. Specifically, they want House Speaker Richard Corcoran, R-Land O'Lakes, to let the House address a proposed fracking ban before the end of the state legislative session. More than 90 communities across the state support the ban. Uh oh. If the locals like it, what will they think in Tallahassee? One of the standard pro-fracking arguments is that the controversial process can be controlled by the state's environmental regulators. "Bottom line is, fracking just can't be done safely. It can't be regulated,'' Ringenberg told about a dozen environmental activists and a handful of reporters last week. Ringenberg will tell you no more studies are needed. She'll point to the peer-reviewed medical articles that say fracking is a serious public health threat because of chemical contamination to water supplies. It is an imperative point locally, said Hernandez, because Tampa Bay Water's underground wells in Pasco help provide drinking water to more than 2 million people in the region.

Sabal Trail: Pipeline brings natural gas and protests - A pipe as big around as a semi-truck tire is on the verge of pumping natural gas under high pressure from Alabama, across a corner of Georgia, through Florida’s swamps, ranches, suburbia and a tourist strip to the heart of Central Florida. To big utility companies, the 515-mile, $3.2 billion Sabal Trail pipeline is an essential artery, the cleanest, cheapest and safest way to guarantee around-the-clock electricity for more than a million homes in Florida. For environmentalists who have staged weekly protests, the steel pipe armored in green plastic is a threat to the planet’s health on par with the reviled Keystone XL and Dakota Access oil pipelines in the works. And safety advocates warn that pipes can fail, and when they do, gas leaks can injure or even kill. Then there are people like Jorge Rosario, who isn't as caught up in the pipeline politics as he is with the rumbling that shook the walls of his house as workers constructed Sabal Trail just feet from his backyard. He and his neighbors wondered what the noisy construction was about. New apartments? Another road?   He learned from a reporter that it was a natural gas pipeline. “No one informed anyone of anything at all,” he said. “Natural gas can cause a very substantial-sized explosion if something goes wrong. It just takes a small mistake and people can get hurt.”   Sabal Trail joins more than 5,000 miles of large natural gas transmission lines already underground in Florida. Those end in hubs that spur a network of some 40,000 miles of smaller underground pipes that deliver gas to homes and businesses throughout the state; 500 miles of buried pipe in Florida are dedicated to hazardous liquids such as jet fuel or other petroleum products. With the petroleum industry’s embrace of hydraulic fracturing, or fracking, natural gas has become the nation’s and, far and away, Florida’s top choice for generating electricity. The new Sabal line, starting this summer, each day will import as much as 1.1 billion cubic feet of natural gas, or enough to fill the Superdome in New Orleans nearly 10 times with the gaseous fossil fuel, to feed Duke Energy Florida and Florida Power & Light Co. electric plants. Pumping all that gas through a pipe 36 inches wide will require a network of factory-like compressor stations to maintain a pressure of as much as 1,456 pounds per square inch. Even without a spark of ignition, that tremendous pressure alone is capable of blowing a pipe apart.

Thirteen gigawatts of natural gas-fired power generating capacity to be added in 2017 -- In 2017, 13 gigawatts (GW) of natural gas-fired generating capacity is scheduled to come online in the United States, adding to total end-of-2016 natural gas-fired capacity of 431 GW. More than 90% of these capacity additions are coming from combined-cycle power plants, which offer improved efficiency over simple-cycle combustion turbines or steam turbines alone. So far in 2017, two combined-cycle facilities—over 1 GW in total—have been completed and put into service:

  • In a March 14 press release, Competitive Power Ventures announced that the St. Charles Energy Center in Charles County, Maryland, began commercial operations. The new facility can generate 725 megawatts (MW) of power using two gas turbines (205 MW each) and one steam turbine (316 MW).
  • The Polk Power Station near Tampa, Florida, completed a 460 MW expansion on January 16, converting four natural gas-fired combustion turbines into a combined-cycle unit.
  • The 1100 MW Paradise combined-cycle plant in Drakesboro, Kentucky, is expected to be completed in April and will replace two of the three older Paradise Fossil coal-fired units.
  • The 1000 MW Wildcat Point combined-cycle generating facility in Cecil County, Maryland, is expected to be in service by June 2017. The facility is adjacent to the Rock Springs Generation Facility, a 672 MW natural gas peaking facility.

Total planned retirements of natural gas-fired generating capacity for 2017 are less than 2 GW, with 1.7 GW coming from older steam turbines. In 2016, 8.9 GW of natural gas-fired generating capacity was added, and 4.3 GW was retired (4.1 GW steam turbine), with a net gain of 4.6 GW. The amount of natural gas consumed for electricity generation has generally increased year over year, while total U.S. net generation across all fuels has remained relatively flat. However, in the fourth quarter 2016, consumption decreased below 2015 levels for the same period as natural gas prices for electricity generators rose. According to the Short Term Energy Outlook, EIA expects the share of U.S. electricity generation from natural gas to decrease from an average of 34% in 2016 to 32% in 2017 because of an expected 23% increase in the average annual natural gas price for electric generators. In 2018, the natural gas share of generation is expected to rise to 33%.

U.S. natural gas storage capacity increased slightly in 2016 – EIA - For the past three years, underground natural gas storage capacity in the Lower 48 states has changed by relatively small increments compared to the changes in 2012 and 2013. No new storage facilities have entered service since 2013, so recent annual changes in both storage design capacities and demonstrated maximum working gas volumes reflect the aggregate effect of small changes at existing facilities. The relatively small change in natural gas storage capacity over the past three years is likely a reflection of long-term trends, such as higher levels of natural gas production, the proximity of production to consuming markets in the Northeast and Midwest, and the lower price premium for natural gas during the winter. These trends may reduce reliance on storage as a source of supply during periods of elevated demand, such as during cold winter months. EIA has published updated estimates of storage capacity based on data for the end of November, which is approximately when storage levels have reached their highest points for the year. EIA uses two distinct measures of natural gas storage capacity: design capacity and demonstrated working natural gas volume. Design capacity is the sum of the 385 active storage fields’ working gas design capacity, as of November 2016, as reported in EIA’sUnderground Natural Gas Working Storage Capacity. Design capacity is based on the physical characteristics of the reservoir, installed equipment, and operating procedures particular to the site that are often certified by federal or state regulators. Design capacity increased slightly, growing 0.7%, from 4,658 billion cubic feet (Bcf) in November 2015 to 4,688 Bcf in November 2016. This increase resulted from a combination of expansions at existing facilities, reclassifications from base gas to working gas, and the restoration of an inactive facility to service.

US natural gas storage injection and inventory scenarios for 2017 -  At this time last year, the U.S. natural gas market was exiting an extremely bearish winter, the gas storage inventory was nearly 500 Bcf higher, and prompt month prices for the CME/NYMEX Henry Hub natural gas futures contract were more than $1.00/MMBtu lower. The question on our minds then was how far would production have to decline or how much demand was likely to show up to prevent storage capacity constraints by fall. In either case, the overarching sentiment was that prices would have to remain relatively low to balance the market. Now we’re exiting an almost equally mild winter, but a combination of lower production and higher exports has drawn down storage to well below year-ago levels, and the question occupying the market is more along the lines of, just how bullish could the market get this year? Today, we wrap up our look at injection season storage scenarios for the next seven months. To understand how natural gas storage and prices could play out later this year, we started in the last episode of “You Keep Me Hangin’ On” by looking at some plausible supply/demand balance scenarios for the 2017 injection season (April through October). Since the relative strength or weakness of the market compared to history can tell us a good deal about storage and price direction, we compared those possible scenarios to the same period in 2016 to get the year-on-year changes in the balance. For the first set of scenarios, we assumed gas production—the biggest driver on the supply side—imports and exports remain flat, either to the recent 30-day average, as in the case of production and exports (given they are less seasonal), or to the same period in 2016 in the case of imports, since those volumes are seasonal. We then applied these assumptions against different scenarios for U.S. demand (i.e. power generation, industrial and residential/commercial usage). Since these demand sectors are highly susceptible to weather and weather will always be the big natural gas wildcard, we used recent historical data to represent a spectrum of possible demand outcomes, including: last year, 3-year average, 3-year high and 3-year low.  You can see the details of each scenario in that last episode, but in short what we found is that if production and exports remain flat to recent levels through injection season, and imports are flat to the same period in 2016, it would only take U.S. demand coming in slightly above the 3-year average to result in a tighter gas market balance in 2017 versus 2016.

Inside FERC Henry Hub April index up 56 cents to $3.18/MMBtu - The Inside FERC's Gas Market Report April bidweek national average natural gas price rose 48 cents to $2.93/MMBtu, S&P Global Platts data show, as the market rallied from first quarter of 2017 lows, bolstered by more supportive fundamentals and a strong end the storage withdrawal season. The April bidweek price at the benchmark Henry Hub point rose 56 cents to $3.18/MMBtu, a more than 20% increase from the March price. The price rally came as the NYMEX April natural gas futures contract settled at $3.175/MMBtu, up almost 55 cents from the March contract's settlement. The increase of 55 cents by the futures contract came as the second half of March saw a string of strong weekly storage withdrawals, with the US Energy Information Administration's final two reports of the month both showing storage pulls exceeding both the prior year and five-year average. In the Northeast producing regions, the bidweek price at Dominion Appalachia jumped 65 cents, or almost 32% compared with its March counterpart, to $2.71/MMBtu.However, the year-on-year comparison saw a more than 127% increase as pipeline capacity has come online this past winter, providing a much needed outlet for regional production. According to Platts Analytics' Bentek Energy unit, roughly 1.5 Bcf/d of new takeaway capacity has entered service in the Northeast since October. The increase in takeaway capacity has pushed Dominion April basis down to around minus 47 cents/MMBtu, a nearly 25 cents/MMBtu improvement from the same month last year. Meanwhile, in premium downstream markets in the Northeast, Algonquin city-gates had one of the few bidweek declines, slipping 3 cents to $3.23/MMBtu as the market priced in milder weather and lower demand expectations for April.

Cheniere Energy exports 100th LNG cargo | Fuel Fix: Cheniere Energy said Monday it exported its 100th cargo of liquefied natural gas, even as the Houston company remains the nation’s sole exporter of LNG. Cheniere recently completely and began operating a third LNG liquefaction unit at its Sabine Pass terminal near the Texas-Louisiana border. A fourth unit, called an LNG train, is expected to come online this fall. In February 2016, Cheniere became the first company to ship LNG from the contiguous United States in more than 50 years. Other companies are developing LNG export projects, but they’re yet to come online. In just more than a year, Cheniere has delivered cargoes to 18 countries on five continents. At the Sabine Pass terminal, a fifth train is expected to be finished in 2019, while the sixth doesn’t yet have a timeline. Each train has the capacity to process 4.5 million metric tons of LNG. Cheniere also is building a Corpus Christi LNG export terminal that’s expected to start operations in 2019. The first two Corpus trains are about 50 percent complete, while a third is the next project the company expects to announce. Cheniere officially became profitable for the first time at the end of last year, turning a $110 million net gain in the fourth quarter.

As US LNG volumes increase, trading optionality expands -- The optionality of US LNG, combined with a growing trend for more LNG to be traded on a shorter term basis, has presented an opportunity for the market to expand the way LNG is traded. In response to these market trends and growing US LNG exports volumes, the Intercontinental Exchange will list a US Gulf Coast LNG futures contract for trading beginning on trade date May 4, subject to the completion of necessary regulatory processes. So what incentivized ICE to launch a futures contract for US LNG? To answer this question, it’s important to take a look at how the US LNG industry has evolved over the past 15 months. While the US exported its first commercial cargo of LNG last February, the market is still trying to gauge how big of an impact US LNG it will have on the global market. Since February 2016, the nation’s sole LNG export terminal, Sabine Pass, has managed to export LNG to 17 different countries, about half of the total number of countries that are capable of importing commercial levels of LNG. Over the next three years, four more projects are expected to begin operations, increasing global capacity by 25%. By 2020, the US will be the third largest LNG exporter, behind Australia and Qatar. While the sheer volume of new LNG supplies coming out of the US is impressive, the real story in the global LNG market is how unique US LNG is compared to today’s global supply. US LNG has distinct attributes: It has no destination restrictions and there is much more flexibility in terms of offtake volumes. The LNG market is dominated by long-term take-or-pay contracts with destination restrictions, making US LNG even more attractive to trade. Put simply, the US will rival Qatar as the producer with the most flexible gas. Looking at the companies that have signed long-term contracts with US LNG projects, the destination and offtake flexibility complements the overall objectives of most offtakers. Shell/BG and Gas Natural, two currently active long-term offtakers of US LNG, are utilizing the flexibility of their US LNG supply to strategically optimize their global LNG portfolio.

LNG producers turn to trading, risk taking to maintain market share | Reuters -- Producers of liquefied natural gas (LNG) have shot themselves in the foot with oversupply, and face calls for flexibility and greater competition from other fuels that may force them to take more risks and start trading just like other commodity dealers. That's a big change for a market long dominated by large producers such as Royal Dutch Shell and BP who provide major importers with fixed volumes under multi-decade contracts linked to the price of oil LCOc1. Under the protection of these lucrative locked-in deals, producers in Australia, Qatar, Russia and elsewhere went on an investment spree that left them with a huge supply overhang when demand in China and India developed more slowly than expected. That, together with rising fuel competition from coal and renewables, contributed to a more than 70 percent crash in spot Asian LNG prices LNG-AS to under $6 per million British thermal units (mmBtu), increasing the pressure to grant more flexible contracts and better pricing options. "The LNG market is changing rapidly, (and) the large volume long-term contracts that traditionally underpinned the development of the industry are today much more difficult to obtain," said Steve Hill, executive vice president of Shell Eastern Trading, during a gas conference in Japan on Wednesday. "LNG projects ... need to take more market risks," he said. In a sign of what might be ahead, Japan's JERA - the biggest single importer of LNG - and France's Total are set to strike its first deal soon with flexible volumes that are based on Asia LNG spot prices. JERA's chief fuel transactions officer, Hiroki Sato, confirmed the imminent deal to Reuters on Wednesday in an interview at the Gastech conference. "There is no price war, but there is clearly competition under way to create a structure that answers the varying buyer needs," he said. Total did not respond to queries for comment on the deal. Another thing about to change is that trading specialists - who buy commodities from producers to sell on to importers at a profit and who have so far played a smaller role in LNG than they do in oil or coal - are jumping into the game. "People need to sit in the middle of the chain (to) provide the flexibility and meet the different customer needs," said Mike Utsler, chief operations officers for Australia's Woodside Petroleum.

Several US gas export projects delay planned start dates - Several US gas export projects have pushed back the expected start of their commercial operations, according to company updates that began posting this week on the US Department of Energy's website. LNG terminal developers must provide semiannual progress reports for their facilities in April and October, as required by the department. Not all projects have posted April reports yet. LNG projects must secure numerous regulatory approvals before they can begin exports, and progress is often held up by regulatory or commercial issues. April updates published on the department's website showed later dates for six projects: SCT&E LNG's export terminal in Cameron Parish, Louisiana; SeaOne Gulfport's CGL terminal at Gulfport, Mississippi; Texas LNG Brownsville's terminal in Brownsville, Texas; Gulf LNG Liquefaction's terminal at Pascagoula, Mississippi; Freeport-McMoRan's Main Pass Energy Hub Deepwater facility off the Louisiana coast; and the Venture Global Calcasieu Pass export project in Cameron Parish, Louisiana. SCT&E LNG anticipates it will begin full operations at its 12 million mt/year Monkey Island facility in 2023-2024, after approvals are secured. In October, it said it expected full operations by 2022. SeaOne Gulfport expects it will start operations at its compressed gas liquids export facility in the second quarter of 2020. In October, it reported a commercial date of 2019. Texas LNG Brownsville has pushed the operations start date at its 4 million mt/year facility to 2022. In October, it listed a 2020-2021 date. Gulf LNG Liquefaction said it plans to place phase one and two of its total 11.5 million mt/year facility in service before the end of 2022 and 2023, respectively. In October, it listed dates of 2021 and 2022 for the phases. Freeport-McMoRan now expects its first floating liquefaction storage and offloading vessel to begin exporting LNG during 2022. In the October filing, it said it expected exports to begin in 2021. And Venture Global Calcasieu Pass anticipates it will begin full operations in late 2020 at its 10 million mt/year facility. In October, it said it expects full operations in the first half of 2020. 

Jones Act change could dip Gulf of Mexico supply 500,000 b/d: study - A pending US Customs and Border Protection action to reverse longstanding Jones Act exemptions could reduce oil and natural gas production in the Gulf of Mexico by about 500,000 b/d over the next 13 years, according to a study paid for by the American Petroleum Institute. The study, which was conducted by energy advisory firm Calash, claims that if the exemptions are dropped, offshore oil and gas spending in the Gulf will decrease by about $5.4 billion per year between 2017 and 2030 while production will fall by 500,000 b/d over that time period. "The [Jones Act] proposal would likely negatively influence development, as projects that are under development or have not been installed are delayed, and project economics and risk profiles are negatively impacted," the report states. "The largest impact of the proposed changes is likely to be due to the inability to use foreign flagged subsea construction, reel lay, and heavy lift vessels to develop US offshore oil and natural gas projects." Less than two days before the end of the Obama administration unveiled a proposal that would revoke Jones Act waivers, some dating back four decades.These Jones Act waivers allowed foreign-built vessels to transport certain equipment, including heavy lift crane equipment, between a port and an offshore drilling operation. The Jones Act, which is nearly 100 years old and has broad bipartisan support, requires vessels transporting goods between US ports to be US-flagged, US-built and majority US-owned.

New US Gulf fields add to oil production; operators eye exploration - It may be more than a year before US Gulf of Mexico oil exploration begins to ramp up in any noticeable way, but several new deepwater fields are adding to production and there seems to be sparks of interest in developing recent offshore finds. Platts Analytics Bentek Energy is forecasting a rise in US offshore production to 1.868 million b/d by year-end and to 2.296 million b/d by end-2022 from 1.669 million b/d at end-December 2016. The reason? Several new fields are slated to come online this year, including Barataria and South Santa Cruz, operated by small privately held Deep Gulf Energy, and Crown and Anchor by LLOG Exploration. Those will bring a combined 15,000 b/d of oil equivalent production. But the Tornado Field, at around 9,000 boe/d, came onstream in November and other large fields that came on in 2016 such as Anadarko Petroleum's Heidelberg, Shell's Stones, ExxonMobil's Julia and Noble Energy's Gunflint, are still ramping up, sources said. Also, new wells are expected this year from Anadarko's Lucius Field (online since early 2015), and Hess' Tubular Bells (online since late 2014).Even though sanctioning of large projects are few in number these days, some are still being advanced. For instance, Chevron's long-awaited Big Foot development will come online in late 2018. And Shell's Appomattox field is set to come online in 2020. Shell's Kaikias Field, to be tied back to its Ursa production hub, comes on in 2019. RigData shows just six semisubmersible rigs and 22 drill ships under contract in the US Gulf of Mexico as of the end of March, down from 10 and 29, respectively, year on year.

Offshore wells are what’s really behind the recent US oil production boom - When OPEC points at U.S. oil producers, it always blames the shale drillers for oversupplying the world market. But while shale is in resurgence, the real source of recent growth has been the offshore drillers in the Gulf of Mexico. According to Bank of America Merrill Lynch, U.S. oil production growth between September and December was almost entirely the result of offshore wells, which increased production by 220,000 barrels a day in that period. Bank of America points out that offshore rigs — Royal Dutch Shell’s Stones field and Noble Energy’s Gunflint — began production in the second half of last year. BP also started the Thunder Horse expansion project in January, adding 50,000 barrels a day of capacity to the existing field. Bank of America said offshore production should remain above 1.7 million barrels a day through 2017, in line with record levels in the third quarter of 2009. BofA analysts said shale production stopped declining in the fourth quarter, but the fact that shale has not broken out of its current range suggests it has not yet recovered. It said the EIA forecasts a 110,000 barrel-a-day increase in April, but that is mostly seen coming from the Permian Basin, while output from the three other main shale regions is expected to decrease or remain steady.

Deepwater Will Soon Challenge Shale -- Just when the focus in oil seemed to be firmly fixed on shale as the cheapest kind of crude, Wood Mackenzie went and ruined it for shale producers with a report claiming that deepwater developments are turning increasingly competitive. According to the report, Big Oil, which seems to be the only kind of oil remaining in deepwater exploration, has done some impressive work regarding costs, such as improving project designs and well performance, aiming for fewer wells and more subsea tiebacks. Thanks to this, output may be lower than it would otherwise be, but costs are also lower—in some cases falling below $50 a barrel. According to Wood Mac’s upstream oil and gas research director Angus Rodger, this shift is essentially a shift in the mindset of Big Oil rather than a shift in innovation, with producers foregoing maximum profits for a more stable revenue stream. Still, innovation has its part to play when it comes to deepwater developments. Two engineering majors, Siemens and ABB, are working on a new type of offshore platform that is entirely built on the seafloor. These self-sufficient oil and gas extraction factories, as Siemens calls them, will have no crew and will not be subject to weather changes, which is expected to save a lot of money that would normally be paid out in wages and on maintenance, not to mention the savings on safety expenses. This would be on top of boosting well yields. Shell is boasting future profitability at $15 a barrel from its Mars platform in the Gulf of Mexico. The company is adopting drilling techniques from smaller, independent energy firms, which have left the Gulf after finding themselves unable to withstand the investment pressure, and is also transforming its corporate structure, which has already borne fruit.  Meanwhile, shale-patch costs are rising, and Rodger expects an even playing field for deepwater and shale projects soon. Oilfield service providers have seen their chance in the recovering market with a huge demand for their services and are raising their prices in a not-too-subtle way, after years of being forced to discount everything in order to stay in business.

Trump Preparing Order to Expand Offshore Oil Drilling - President Donald Trump is preparing to issue an executive order with the goal of giving oil companies more opportunities to drill offshore, reversing Obama-era policies that restricted the activity. The offshore drilling directive is set to be issued soon, Interior Secretary Ryan Zinke told an industry conference in Washington on Thursday, according to three attendees who spoke on condition of anonymity to discuss a session closed to the press. Zinke did not provide specific details on the executive order during his presentation to the National Ocean Industries Association.The coming order is set to push the Interior Department to schedule sales of new offshore oil and natural gas rights in U.S. Atlantic and Arctic waters, amending a five-year Obama administration leasing plan that left out auctions there, according to an industry representative who has discussed it with officials. The order is also expected to begin the process of revoking former President Barack Obama’s decision to indefinitely withdraw most U.S. Arctic waters and some Atlantic Ocean acreage from future leasing. Environmentalists say it would be unprecedented for any president to rescind such a designation, and the reversal would almost certainly be challenged in court. Spokesmen for the Interior Department and White House did not respond to emailed requests seeking comment.

US government website that used to warn about the risks of oil and gas drilling was changed to promote their economic benefits - Until recently, the US Government Accountability Office’s website described oil and gas drilling on federal lands as posing an “inherent risk” to human health and the environment. Now, that language has been replaced with wording about the economic benefits of oil and gas activity. The edits—made between midday on Feb 15 and midday Feb 16, 2017—were spotted by the Environmental Data & Governance Initiative (EDGI), a group of programmers and researchers who are tracking changes to federal websites since president Donald Trump took office. They are the latest in a litany of similar modifications, many of which have involved public-health or climate-change science. The edited page is part the Government Accountability Office’s “High Risk List,” updated every two years with federal agencies or programs the GAO believes are vulnerable to “fraud, waste, abuse, and mismanagement, or are most in need of transformation.” Oil and gas resources on federal lands were part of that list under the Obama administration—and remain on it, but without mention of the environmental and public health risks that originally drove their placement there. The GAO says the change in language was not to de-emphasize the health and environmental risks of oil and gas drilling, which the GAO described in a 2012 report, but rather to point to a more recent set of reports that emphasize weaknesses in the government’s oversight of the industry—like, for example, the inability to ensure that companies that use federal land have paid royalties completely.

Chevron pivots to Permian shale as mega-project era fades | Reuters: Nearly a century after Chevron Corp amassed the No. 2 stake in America's largest oilfield, Chief Executive John Watson is hitting the accelerator on developing the company's vast Permian Basin holdings. In an interview, Watson made clear his desire to put the West Texas to New Mexico expanse in the ranks of Chevron's biggest ventures. That is a stark change from just five years ago, when Chevron executives rarely mentioned the shale basin. But with low oil prices, the company is now spending more than it makes to cover its prized dividend and find new reserves. Now, those 2 million Permian acres have emerged as to way to help fund both goals. "Some of the best things we have in our portfolio are the shales," Watson said during an interview on the 48th floor of the company's Houston office tower. "My employees in the Permian know I'm featuring it as something very important." Gone, for the next few years at least, are plans for any new multi-billion-dollar mega-projects, he said. To survive and grow, San Ramon, California-based Chevron is turning to acreage it has always controlled and that largely is free of royalties to landowners. "We're just in a period now where markets are weak and everyone is focused on controlling costs," Watson said. Within a decade, Watson expects Chevron's production in the Permian to grow eightfold to more than 700,000 barrels of oil per day. By the end of next year, nine drilling rigs will join the 11 that Chevron already has poking holes into Permian land. It is all part of Watson's plan to methodically pump Chevron's more than 9 billion barrels of Permian oil, most of it owned outright by the company. That gives Chevron a cost advantage over rival Permian producers as the region in the past year has become the epicenter for the U.S. shale resurgence.

Stiff Competition - The Race to Build More Permian-to-Corpus Gas Pipeline Capacity -- The combination of rising production of “associated” natural gas in the Permian Basin and rising exports of pipeline gas to Mexico—and soon, LNG on ships out of planned South Texas export terminals—is driving the need for new gas pipelines from the Permian to the Corpus Christi area, including the all-important Agua Dulce gas hub in Nueces County, TX. Yesterday (Monday, April 3), NAmerico Partners unveiled plans for Pecos Trail, a proposed 468-mile, 1.85-billion-cubic-feet-a-day pipeline aimed squarely at linking emerging gas supply with emerging gas demand. Pecos Trail joins two other projects announced within the past few weeks that target the same opportunity. Today we look at the gas side of the need for new takeaway pipelines out of the U.S.’s hottest shale play, and NAmerico’s newly announced plan to address it. Two of the hottest energy stories of the past several months (and maybe for the next few years as well!) are 1) the crude oil production boom in the Permian Basin in West Texas and southeastern New Mexico, and 2) the boom in U.S. exports of natural gas—pipeline exports to Mexico and LNG exports by ship. In fact, there is a real connection between these two headline-grabbers; that is, growing crude production in the Permian will lead to the production of vast quantities of associated gas, and the proximity of the Permian to export markets (Mexico and planned LNG terminals along Texas’s Gulf Coast) make the Permian a logical supplier of a substantial portion of the billions of cubic feet a day of gas that will be needed to keep pace with export demand. The Permian has been a frequent topic in the RBN blogosphere. Last week, in Back in the Saddle Again (our preview of RBN’s upcoming School of Energy in Houston on April 25-26), we discussed the likely need for additional crude pipeline takeaway capacity out of the Permian (beyond the four projects already scheduled to come online later this year and in 2018). Before that, in our Still the One blog series, we discussed rising production of associated gas (and natural gas liquids, or NGLs) in the Permian and all the gas processing capacity being developed in the play.’

How new Permian-to-Corpus gas pipelines will affect coastal flows. Rising natural gas exports from South Texas and increasing production of “associated” gas in the Permian Basin are driving the development of several new gas pipelines from West Texas to the Agua Dulce gas hub and nearby Corpus Christi. The age-old questions apply: How much new pipeline capacity will be needed, and how soon? The construction of these new pipelines also raises the question of how a potential flood of new gas supply from the Permian to the South Texas coast might affect plans by others to flow gas down the coast from Houston. Today we continue our look at proposed gas pipelines from the Permian to Agua Dulce and Corpus Christi with a review of two more projects and their potential impact.  In Part 1 of this series we discussed the fact that two of today’s hottest energy stories—the crude oil production boom in the Permian and the boom in U.S. exports of natural gas (pipeline exports to Mexico and LNG exports by ship) —have, in a way, converged. The production economics in parts of the Permian are so favorable that significant crude production growth is likely under even pessimistic oil-price scenarios, and with that incremental crude output will come big volumes of associated gas and natural gas liquids (NGLs). Due to the Permian’s long history as a major producing area, there is sufficient gas pipeline takeaway capacity for now, but probably not for long—and, with South Texas demand for export gas growing, the logical direction to move incremental Permian-sourced gas is southeast to the Agua Dulce gas trading hub in Nueces County, TX and to Corpus Christi, about 30 miles east of the hub.

Dakota Access Campaign Seen as a Model for Pipeline Resistance Nationally - The tactics used in North Dakota – resistance camps, prominent use of social media, online fundraising – are now being used against several projects. They include the Sabal Trail pipeline that will move natural gas from Alabama to Florida; the Trans-Pecos natural gas pipeline in Texas; the Diamond pipeline that will carry oil from Oklahoma to Tennessee; and the Atlantic Sunrise pipeline that will move natural gas from Pennsylvania to Virginia. They’re also being used against projects that are still in the planning stages, including the proposed Pilgrim oil pipeline in New York and New Jersey and the proposed Bayou Bridge Pipeline in Louisiana. Dakota Access opponents have also vowed to fight against the resurgent Keystone XL pipeline, which would move crude oil from Canada to Nebraska and on to Texas Gulf Coast refineries. The influence of the Dakota Access protest is evident in various forms. For example, some who protested in North Dakota have gone to Texas and Florida to help with those demonstrations, according to Goldtooth. The Red Warrior Society, a pipeline protest group that advocated aggressive tactics in North Dakota, is promoting resistance in other states via social media. There are nearly a dozen accounts on the GoFundMe crowdfunding site seeking money to battle the Sabal Trail and Trans-Pecos pipelines. The Society of Native Nations, which is fighting the Trans-Pecos, used the protest camp model from North Dakota to set up a camp in Texas, according to Executive Director Frankie Orona.

The Rough Waters of Western North Dakota -- The first in a 5-part series on the controversial water industry of western North Dakota. The state of North Dakota is now experiencing a serious crossroads situation regarding the Western Area Water Supply Authority (WAWSA) and its future path.  Uncertainty is nothing new to WAWSA and its project as controversy, a questionable business plan and forceful government politics have followed this project since its very beginning. According to WAWSA website, the domestic water project utilizes Missouri River water that is treated partially at the Williston plant to meet municipal, rural and industrial water needs for Burke, Divide, McKenzie, Mountrail and Williams counties. Residential water services include the cities of Williston, Watford City, Ray, Tioga, Stanley, Wildrose, Crosby, Fortuna, Noonan, Columbus and Ross. The idea was to provide affordable water to the residents of western North Dakota.  In order to offset costs to the residents, WAWSA would sell water to the oil industry. The WAWSA website also states that currently the project is providing water to over 70,000 people and are estimating 160,000 people will received water by 2038. So how did WAWSA go from a water infrastructure concept everyone seemed to support to questioning and changing its business plan? Let’s start from the beginning and find out how WAWSA’s original projection of $150 million in 2011 became a current reality of $292 million and a new completion projection of $400 million, according to public records.    According to Wirtz, the decision to move ahead with WAWSA wasn’t fleshed out completely due to the speed of the Bakken in 2011. “The business model they proposed was that the infrastructure would be paid for largely by selling industrial water to the oil industry,” Harms said. “Then the water industry was mature, well developed.  Six years ago 80% of the water that was provided to the oil industry was private with the other 20% was provided by communities like Watford City, Williston,Tioga, Stanley, Crosby, they all sold the balance to the oil industry.”

Small California Towns Are Facing Off Against Oil Companies — And Winning -- Last fall, as presidential candidate Donald Trump promised America more oil and coal production, a small refinery town in Northern California stood up against its biggest employer and taxpayer. Valero, the Texas-based petroleum giant, had sought routine approval for a huge crude-by-rail project. The city council of Benicia, however, decisively rejected Valero’s proposal. The project proposed to take crude oil from what is described in an environmental impact report as “sites in North America” — a possible euphemism for Bakken crude — and roll it in rail cars to Benicia. But the project proved so unpopular among the city’s nearly 27,000 residents that three of the five city council members who had started out backing the project joined in a unanimous vote against it. An energized group of local administrators and activists had managed to derail a project that national policy makers couldn’t touch. But Benicia wasn’t the only place this happened last November. Across California, new organizing efforts zeroed in on small-town elections as a strategy to thwart big fossil-fuel infrastructure projects. Oxnard officials, for example, are battlingCalifornia Energy Commission plans to site a huge gas-fired power plant on a local beach, and opponents to the plan were overwhelmingly favored in the fall elections. In the Kern County town of Arvin, which 10 years ago won the dubious distinction of having the smoggiest air of any U.S. city, a 23-year-old city councilman was elected mayor on a promise to regulate the oil industry and protect the city’s water and air — a huge task in California’s biggest oil-producing county. And on March 14, the San Luis Obispo County Board of Supervisors shut down a Phillips 66 crude-by-rail plan to bring oil into its Nipomo Mesa refinery. The 3-to-1 vote (with one recusal) against the proposal represented a huge change in a county that for years had supported refinery projects.

Owner of leaking Alaska gas pipeline now dealing with oil spill in same area - Hilcorp Alaska, owner of an underwater pipeline leaking natural gas into Alaska's Cook Inlet, is now responding to a second pipeline spill in the same vicinity. That one was spewing oil. The pipeline, which connects two oil platforms, released an unknown amount of crude oil into the inlet before the flow of oil was halted Sunday. Oil sheens appeared as far as three-and-a-half miles away from the source of the spill. The leak was discovered and reported to the state Department of Environmental Conservation (DEC) midday Saturday. The two oil platforms, called the Anna and Bruce platforms, are on the western side of Upper Cook Inlet. The natural gas leak is on the eastern side of Upper Cook Inlet, where the company owns two pipelines and four oil platforms. The gas pipeline has been leaking almost pure methane since late December. The two leaks are unrelated. The gas leak has raised concerns for regulators and environmentalists, particularly because the area is home to an endangered population of beluga whales. The first water samples showed levels of methane high enough to be dangerous to fish. Oil carries an even bigger environmental threat. Hilcorp personnel aboard the Anna platform reported the oil spill on Saturday after they felt an impact around 11:20 a.m., according to a report released by the DEC. When they looked over the edge of the platform, they saw an oil sheen and bubbles surfacing near one of the platform legs, where the pipeline is located. The cause of the impact isn't yet known. In response to the oil leak, Hilcorp shut down oil production on both platforms, and reduced pressure on the line from 70 psi to 5 psi. The company also conducted flights around the area. On a flight at 12:30 p.m. Saturday, an hour after the spill was first observed, Hilcorp reported seeing six oil sheens. The largest was 10 feet by 12 feet. Two others were three to four feet by 20 to 25 feet, according to the DEC. An oil spill response ship arrived to the Anna Platform to look for sheens at 12:45 p.m., but did not find any. On Sunday, response crews sent a "pig" through the pipeline to push the remaining oil in the line past the spot where it was believed to be leaking, and then out of the line. "The crude oil pipeline between the Anna and Bruce platforms has been shut-in and the pressure to the line has been reduced to zero pounds per square inch," the DEC said in a report released at 4.30 p.m. Sunday. The 8-inch pipeline's capacity is 461 barrels of oil. It sits roughly 75 feet below the surface of Cook Inlet. Both leaking pipelines were built in the 1960s.

340 Beluga Whales Threatened by Another Pipeline Leak in Alaska's Cook Inlet -- Hilcorp Alaska reported Saturday an oil leak from a pipeline in Alaska's Cook Inlet. The oil spilled from the offshore pipeline south of Tyonek is in a critical habitat for the gravely endangered Cook Inlet beluga whales , whose numbers have dwindled to 340 individuals. This leak is unrelated to the gas leak from another one of its pipelines that has been ongoing since December .  "At first, I hoped that news of this latest oil leak was an April fool's joke because it seemed like Hilcorp couldn't spring another leak so soon," said Miyoko Sakashita, oceans program director for the Center for Biological Diversity . We're really worried about what this means for Cook Inlet belugas with the double whammy of an oil spill and gas leak in the same season."  The cause of the leak is unknown and oil sheens have been reported in the area. The company said it has shut-in production at the platforms, known as Anna and Bruce, that are connected by the leaking pipeline. Reports this morning confirm that the leak has stopped, but the risk to wildlife is unknown. These platforms were installed in 1966 and aging infrastructure and severe tides in the Cook Inlet make them vulnerable to incidents. The Alaska Oil and Gas Conservation Commission has also repeatedly cited Hilcorp for violating safety regulations for its oil and gas operations in the state.  "It's clear that there's no safe way to drill for oil in the ocean. This is the same company that plans to drill for oil in the Arctic Ocean, a place that is much more dangerous for oil drilling with severe storms and ice," Sakashita said. "Hilcorp keeps springing leaks in Cook Inlet and it should certainly not be allowed to build the Liberty project in the Beaufort Sea." The Center for Biological Diversity has sent Hilcorp a 60-day notice of its intent to sue for the ongoing gas leak and it is monitoring the new oil leak to determine whether legal action is warranted.

Potentially explosive methane gas mobile in groundwater, poses safety risk: study -- Potentially explosive methane gas leaking from energy wells may travel extensively through groundwater and pose a safety risk, according to a new study by University of Guelph researchers. Researchers at the U of G-based G360 Institute for Groundwater Research found the gas is highly mobile in groundwater, travelling far beyond the shale wells where it is drilled and changing the water chemistry. It will also escape into the atmosphere as a powerful greenhouse gas. The findings were published recently in the journal Nature Geoscience. Besides posing an explosion risk and degrading groundwater quality, methane can contribute to climate change when released to the atmosphere, said G360 director and principal investigator Beth Parker. The researchers injected methane over 72 days into a shallow sand aquifer and monitored it for more than eight months at Canadian Forces Base Borden in Ontario. They found the gas travelled through the ground, was sometimes released into the atmosphere and dissolved extensively into the groundwater, where it changed water chemistry. "If this water is extracted, say, by a farmer, the dissolved gas can be released and form an explosion risk or change the taste of the water," Parker said. "Depending on conditions of groundwater and aquifer minerals, microbes can 'eat' the methane and generate undesirable by-products such as hydrogen sulphide, and induce the release of trace metals into the water."

U.S. oil producers increased investment in fourth quarter of 2016 -- Capital expenditure for 44 U.S. onshore-focused oil production companies increased $4.9 billion (72%) between the fourth quarter of 2016 and the fourth quarter of 2015 based on their public quarterly financial statements. This increase in investment spending was the largest year-over-year increase for any quarter by these 44 companies since at least the first quarter of 2012.  Higher oil prices are contributing to an increase in upstream earnings for U.S. producers, prompting some companies to increase their investment budgets. Company announcements and increases in the number of active oil rigs suggest U.S. oil production companies are continuing investment growth in the first quarter of 2017. The U.S. active oil-directed rig count reached 662 on March 31, 2017, up from 525 at the end of 2016. Lower investment levels over the previous two years likely contributed to a reduction in cash from operations for these 44 companies despite an increase in crude oil prices. The reduction in cash from operations for these 44 companies totaled $475 million year-over-year in the fourth quarter of 2016. Significant reductions in exploration and development spending in 2015–16 led to less drilling, which reduced oil production in the fourth quarter of 2016, offsetting increased revenue that came from higher prices. Cash from operations lags capital expenditure for these companies because they invest to develop reserves that will increase oil production and cash flow in the future.  Many of these companies use oil futures and options to hedge their investment in production into the future. Financial hedging for producers reduces the effect of a fall in revenue if prices were to decline. A measure for the amount of future production oil companies have hedged is the number of short positions, or future sales into these markets. These short positions consist of futures and option contracts held by producers and merchants. Producers have begun using them more since crude oil prices rose above $50 per barrel in the fourth quarter of 2016. In mid-February 2017, the number of short positions in U.S.-based futures and options reached 756,000 contracts, close to the 10-year high of 802,000 contracts.

US exploration and production companies budget strong rebound in 2017 -  In connection with 2016 earnings releases, U.S. exploration and production companies (E&Ps) have announced a surge in capital spending for 2017 after slashing investment by an average 70% from 2014-16.  Our “Piranha” universe of 43 E&Ps is budgeting a 42% gain in organic capital outlays with a strong focus on the major U.S. resource plays. Despite crude prices languishing at an average of ~$47/bbl since January 2015, most of the upstream industry has weathered the crisis remarkably well, primarily through the “high-grading” of portfolios, impressive capital discipline, and an intense focus on operational efficiencies. Today we review the overall outlook for 2017 upstream capital spending and oil and natural gas production, and take an initial look at expectations for our group of companies. A year ago, E&Ps were still in full retreat, announcing an average 50% reduction in investment from 2015, as we documented in It’s An Uphill Climb To The Bottom. But oil prices rose steadily from early-2016 lows as companies continued to slash costs and increase output per well. Mid-year announcements contained harbingers of change, as we reported in Been Down So Long. Next, we drilled down to look at spending aggregated into three peer groups: oil-weighted, gas-weighted and diversified E&Ps. We noted substantial increases in activity and rising production forecasts for Permian producers in You’ll Go Your Way, I’ll Go Mine. In Different Strokes by Different Folks, we illustrated how the Diversified E&Ps who were targeting the hot Permian and SCOOP/STACK plays had more positive capital spending and production profiles than the rest of that peer group. Finally, we found a more positive outlook for gas prices and found that demand was rekindling activity in the Gas-Weighted E&P peer group in Back in the Saddle Again

Oil Majors Are Struggling to Break Even - -- Despite billions of dollars in spending cuts and a modest oil-price rebound, Exxon Mobil Corp. , Royal Dutch Shell PLC, Chevron Corp. and BP PLC didn’t make enough money in 2016 to cover their costs, according to a Wall Street Journal analysis. To calculate each companies’ free cash flow—the excess cash remaining after costs—the Journal deducted the firm’s dividends and capital expenditures from its cash from operations. All four firms fell short of cash flow for the year, although Exxon said it broke even by its own metrics, which exclude dividends. The analysis also showed that the four companies ended last year with more debt than they began it. For companies once known as profit machines—whose executives were hauled before Congress in 2005 to explain their enormous earnings—their cash problems demonstrate just how unprepared they were for a historic crash and tepid recovery in oil prices. They have maintained the same large dividends they had when oil prices were over $100 a barrel, piling on debt and selling off assets to prioritize shareholders above all else. The result is that spending on dividends and capital investments has ballooned above cash generated from their businesses. The issue has worried investors who expect those steady dividends because oil giants don’t have the capacity to grow much. Exxon, Shell and their competitors are under pressure to show they can drum up cash to keep shelling out dividends. Exxon, Shell and their peers spent much of the past three years scrambling to reassure investors that their dividends were safe amid the oil-price crash. These companies were already struggling to live within their means at elevated oil prices.

Glencore to sell 51 percent of oil products storage business | Reuters: Swiss-based trading and mining giant Glencore has agreed to sell a 51 percent stake in its oil products and logistics business for $775 million to China's HNA Innovation Finance Group Ltd, the company said on Friday. Reuters earlier exclusively reported that Glencore was in talks to sell a bundle of its global oil storage stakes, following similar moves by rivals as a boom period for storage shows signs of nearing to an end. Glencore said the deal was expected to close in the second half of 2017 and that the transaction would result in a new company called HG Storage International Ltd with a presence across Europe, Africa and the Americas. Dutch bank ING was the sell-side adviser to the deal, a spokeswoman for the bank said.

Big Oil could be ready for a big comeback - Oil prices are down so far this year -- and so are energy stocks. But some experts think that won't last for long. President Trump is clearly a fan of the traditional oil and gas sector. His secretary of state, Rex Tillerson, used to be the CEO of ExxonMobil. Trump also just rolled back some of President Obama's climate control rules, which should be a gift to Big Oil. And Trump has also declared an end to Obama's "war on coal." Still, the S&P Energy Sector ETF (XLE) is down more than 6% in 2017, while the S&P 500 is up 5%. That's despite the fact that earnings for oil companies are expected to be solid in the first quarter. Analysts are predicting that sales at Exxon (XOM), for example, will be up 40% from a year ago and that profits will nearly double. Why? Even though crude prices are down year-to-date, a barrel of oil is around $50 -- and that's nearly double the price from a year ago. Oil hit a 13-year low of just above $26 a barrel in February 2016. So it's a lot more profitable to pump now than this time last year. Despite this, Exxon shares are down 9% in 2017, making it the worst performer in the Dow. Rival Chevron, also a Dow component, is down more than 8%.

Oil Production Vital Statistics March 2017 - In February OPEC remained largely compliant with the production cuts with OPEC 12 production (ex Gabon) down 1.11 Mbpd compared to October 16 according to IEA data. Oman has offered solid support with a production cut of 50,000 bpd from a production base of ~ 1 Mbpd. Russia + FSU has done little (yet) with a 50,000 bpd reduction from a level ~15* larger than Oman. Russia + FSU were supposed to cut >300,000 bpd. The IEA has a somewhat different view that can be read in the OMR on page 24.  Global total liquids remain up 20,000 bpd YOY. The oil price stepped down in March to ~$50 / bbl, confronted with a continuing glut and growing uncertainty but has since recovered to ~ $55. OPEC drilling remains close to a cyclical high while US drilling continues to recover. Total US rigs were up 68 to 824 for the month to the end of March. The Canadian rig count is sharply lower marking a seasonal cycle. Drilling in Mexico and throughout the rest of the world remains at rock bottom. The following totals compare February 2016 with Februray 2017:

  • World Total Liquids 96.48/96.50/ +20,000 bpd
  • OPEC 12: 31.83/31.81/-20,000 bpd
  • Russia + FSU 14.21/14.46/ +250,000 bpd
  • Europe OECD  3.61/3.59/ +20,000
  • Asia 7.64/7.43/ -210,000
  • North America 19.84/19.60/ -240,000 bpd

The following totals compare October 2016 with February 2017 and monitor compliance with the OPEC + others production cuts.

  • OPEC 12: 32.92/31.81/ – 1,110,000 bpd
  • Russia + FSU 14.51/14.46/ -50,000 bpd
  • Oman 1.02/0.97/ -50,000 bpd

Down 10%, Mexico Oil Reserves Gone In 9 Years Without New Finds -- Mexico’s existing oil reserves are dwindling so fast the country could go dry within nine years without new discoveries. That’s the message from the National Hydrocarbons Commission, which said Friday that the reserves fell 10.6 percent to 9.16 billion barrels in 2016, from 10.24 billion barrels a year earlier. Once the world’s third largest crude producer, Mexico’s proven reserves have declined 34 percent since 2013. The decline in proven reserves is driven by record-low drilling activity the last three years, according to CNH Commissioner Hector Acosta. State-owned producer Petroleos Mexicanos drilled 21 wells last year, a record low, after averaging 31 per year since 2010. “If there isn’t drilling, it is going to be difficult to incorporate new finds,” Acosta said. “The production figures and indicators that we are observing, tell us that there are flaws in the drilling activities being carried out by Pemex.”  The diminished production comes from a combination of reduced investment and the continued maturation of fields, said Cesar Alejandro Mar, Adjunct Director of Reserves. He set 8.9 years as a time frame for the reserves to run out if no new exploration occurs. Pemex, meanwhile, said in an e-mailed statement that it added 684 million barrels of probable crude to the reserves last year, and “will continue working to increase reserves and restitution rates to higher levels.” Monopoly End Mexico ended Pemex’s production monopoly in 2013 to let private operators develop oil in the country for the first time since the 1930s. Production is set to fall below 2 million daily barrels this year, the lowest levels since 1980, Pemex has said. Overall, crude production has declined every year since 2004. Given increased crude development activity anticipated in the deep waters of the Gulf of Mexico by private producers, the country’s production is forecast to climb to 3.4 million barrels a day by 2040, according to a report by the International Energy Agency.

Are Mexico’s Oil Reserves Almost Depleted? Mexico’s oil and gas regulator said last week that the country’s proved hydrocarbon reserves will drop by 10.6 percent in 2017. This forecast, coupled with the lower oil production that state company Petroleos Mexicanos (Pemex) reported for yet another year in 2016, is painting a rather bleak picture of Mexico’s reserves.Without resumption in investments and more drilling, and if no significant finds occur, Mexico will be running out of reserves within 9 years, according to an official from the National Hydrocarbons Commission.However, the energy reform that ended Pemex’s monopoly and allowed foreign companies to invest in Mexico’s oil exploration and production is expected to start yielding results by the end of this decade. The deepwater bidding round last December attracted major international oil companies, and Mexico awarded blocks to consortia including Chevron, Exxon, Statoil, BP, Total, and China Offshore Oil Corporation.In addition, the analysts are now largely calling the end of the downturn and expect deepwater investment to pick up in coming years.Mexico’s National Hydrocarbons Commission said last week that as of January 1, 2017, the country’s proved oil and gas reserves are estimated at 9.16 billion barrels of oil equivalent, down by 10.6 percent from the 10.243 billion boe as of the beginning of 2016. Proved oil reserves were down 7.9 percent to 7.037 billion barrels from 7.641 billion barrels estimated as of 2016.In its 2016 results release, Pemex reported crude oil production of 2.154 million bpd last year, down by 5 percent over 2015, mostly due to natural declines of a number of producing fields.  According to the EIA, Mexico’s crude oil production has been steadily dropping since 2005 as a result of natural production declines from Cantarell and other large offshore fields.  Surely, the oil price slump has not helped Mexico’s output either, and has complicated the energy reform that the country started implementing in 2013. But now, steadier prices and new projects involving international oil companies are expected to start offsetting declines after 2020, according to the International Energy Agency (IEA).

Brazil Reports 14.6% Jump In February Oil Output, Exports Almost Double -  Brazilian oil output in February was 14.6 percent higher year-over-year, according to the latest data released by ANP, the South American country’s petroleum regulator. February production touched 2.676 million barrels per day, an ANP statement said, adding that natural gas output also rose 9.2 percent compared to the same month last year. Figures released earlier in March from the nation’s Trade Ministry said that oil exports had jumped 94 percent year-over-year in February at 45.7 million barrels – a figure that topped the January 2017 record by 12 percent. The surge in oil exports was a function of higher production from the offshore areas in Brazilian waters, where huge oil finds were made in the pre-salt and sub-salt layers in the past few years.Brazil – which is not part of the non-OPEC group that signed up to OPEC’s concerted efforts to cut global supply – had said that it planned to increase its oil production in the coming years, even before the cartel decided to commit to cuts.Brazil announced last week that it expected to see its first profits from projects finalized under new profit-sharing agreements (PSAs) in September.The PSAs were introduced by the government of Ignacio Lula da Silva to replace previous royalty payments and to ensure the state gets a bigger portion of the revenues derived from the deposits in Brazil’s presalt layer.The announcement of profits from the new framework comes just as oil prices recover from 2.5 years of volatility. New foreign investment is also a national priority for Brazil’s authority figures. After removing the requirement calling for Petrobras to be operator of all new projects in the presalt layer, last month the government also relaxed local content requirements for foreign energy companies, which they saw as a stumbling block for foreign investors. The move comes in preparation for new oil and gas block tenders scheduled for this year and next.

Petrobras says Exxon expressed 'strong interest' in pre-salt oil | Reuters: U.S. oil company Exxon Mobil Corp expressed to Brazil's state-controlled company Petrobras "strong interest" in the exploration of deep-water oil fields off the Brazilian coast, Petrobras Chief Executive Pedro Parente said on Tuesday. "Considering movements towards a strategic partnership, we have nothing concrete with Exxon, but they have certainly expressed strong interest in the Brazilian pre-salt exploration," Parente told reporters. Earlier on Tuesday, The Wall Street Journal reported that Exxon was in talks to gain access to Brazil's deep-water oil resources, citing people familiar with the matter. Petroleo Brasileiro Sa Petrobras, familiarly known as Petrobras, and Exxon initially declined to comment on the report, but later Parente briefly spoke about it on his way out of a seminar in Sao Paulo. Exxon is one of the few major oil companies still with no presence in the exploration of the recently discovered large fields off the coast of Brazil. Royal Dutch Shell Plc (RDSa.L) sharply increased its operations in the area after acquiring BG Group last year. French oil major Total SA (TOTF.PA) did the same recently by closing a strategic partnership with Petrobras. Norway's Statoil has also bought stakes in the oil region. Petrobras is looking for partners for some of its projects. Earlier on Tuesday Parente said pre-salt yields have been above the company's expectations, boosting Petrobras cash generation and helping the company to cut its debt load, still one of the highest in the global oil industry at slightly below $100 billion.

Fracking giant Ineos buys North Sea pipeline in £199m deal - Yorkshire Post: Energy giant Ineos has struck a deal to acquire the Forties Pipeline System in the North Sea from BP for 250 million US dollars (£199 million). The transaction, which also includes the Kinneil Terminal, will see Ineos take control of a system that delivers almost 40% of the UK’s North Sea oil and gas.The Forties pipeline was opened in 1975 by BP and today consists of more than 100 miles (161km) of pipes with the capacity to transport 575,000 barrels of oil a day from fields in the North Sea and several Norwegian fields. Ineos chairman and founder Jim Ratcliffe said: “The North Sea continues to present new opportunities for Ineos. “The Forties Pipeline System is a UK strategic asset and was originally designed to work together to feed the Grangemouth refinery and petrochemical facilities. “We have a strong track record of acquiring non-core assets and improving their efficiency and reliability, securing long-term employment and investment.” Under the terms of the deal, Ineos will pay BP 125 million US dollars (£99.5 million) on completion and an earn-out arrangement over seven years that totals up to a further 125 million US dollars. BP chief executive Bob Dudley said: “While the Forties pipeline had great significance in BP’s history, our business here is now centred around our major offshore interests west of Shetland and in the Central North Sea.” Forties employs around 300 BP staff at Kinneil, Falkirk, Dalmeny, Aberdeen and offshore. Ineos is best known in Britain for its shale gas fracking operations.

It Is Now Or Never To Stop Fracking In Its Tracks -- This week I will take direct action to target the fracking industry. I'll put my body on the line to obstruct, protest and oppose shale gas extraction. I will be joining others from grassroots network Reclaim the Power in the Break the Chain fortnight of action to expose and disrupt the fracking supply chain. I have better things to do than this; a life to live, ends to meet, commitments to honour. Taking direct action can be stressful, risky, and I wish it was not necessary. But I believe it is. The UK has been frack free for nearly six years since earthquakes caused by fracking in the Lancashire Fylde prompted a moratorium. British public opinion has remained set against fracking since then, preventing the industry from gaining a toehold in this country.  Lately, however, the government has disregarded this national opposition and set about instead creating as attractive an environment as possible for the fracking industry. New laws have removed important legislative checks and balances. Tax incentives have created "the most generous [tax regime] for fracking in the world." Most damagingly for democracy , planning regulations have been changed which enable government to overrule regional planning decisions. This has already happened in Lancashire. There the County Council rejected Cuadrilla's application to frack near the Fylde resort of Blackpool only for Secretary of State Sajid Javid to reverse that decision last autumn.  As a result, the Fylde has become a fracking frontline once more. My grandfather laboured on the Fylde's farms, my great uncle dug its ditches, my great grandfather was a salt miner here. They lived hard lives, but loved this land and respected its limits. They would have had no truck with fracking's extreme physical intrusion, chemical meddling, reckless risks and drastic industrialisation of the landscape. Evidence of the dangers posed to our environment and health has persistently emerged in from countries such as the USA and Australia where it is practised commercially. There, sickness and pollution have followed close on the trail of the frackers. In the far more densely populated UK those impacts stand to be amplified.

Second Northern Territory gas pipeline not viable without fracking, APPEA says - - A second gas pipeline connecting the Northern Territory to South Australia would not be viable without fracking, the oil and gas peak body has said.The Federal Government backed a feasibility study into a north-south gas pipeline in exchange for independent senator Nick Xenophon's support for company tax cut changes.The NT currently has a moratorium on hydraulic fracturing while an inquiry into the technique is underway.But the NT and SA branch of the Australian Petroleum Production and Exploration Association (APPEA) said it would not be realistic to have a new pipeline without fracking."The identified new resources of natural gas in the Northern Territory are predominantly in shale rock, very deep below the surface that cannot be produced without fracking," NT-SA APPEA director Matthew Doman said."That's why this inquiry is so important, that's why it's also important we keep a balanced discussion around something that's part-and-parcel for safe and sustainable natural gas."Construction for the Jemena Northern Gas Pipeline connecting the NT gas fields from Tennant Creek with the east-coast gas market at Mount Isa in Queensland, is expected to get underway in mid-2017.Mr Doman said even though offshore gas could be made available to that pipeline, as well as sources of g as in Central Australia, fracking would still be required to sustain it.

Did the U.S. Just Pull Out of a Global Anti-Corruption Group? - There is a mystery unfolding in the U.S. Department of the Interior. Officials there seem to have removed the United States from a singularly successful anti-corruption effort. This has happened largely in secret, aside from a few public statements in legalese that are nearly impossible to parse. At times, bureaucrats in the department have behaved in ways that—it’s hard to think of another word—seem un-American, literally silencing dissent in open forums and abruptly cutting off contact with the public.The controversy centers on the Extractive Industries Transparency Initiative, a remarkable global project with a very boring name that has become a model for the fight against some of the worst forms of corruption. Countries where economies are built on oil, gas, diamonds, or other natural resources are frequently subject to what is known as the “resource curse.” Those countries are often run by autocrats who use the wealth in the ground to enrich themselves and crush opposition. This is not merely a local concern. There is a well-established link between global terrorism and the regions of the world—the Middle East, Nigeria—most susceptible to extractive-industry corruption. Money from oil-and-gas wealth has flowed into Saudi Arabia, Iraq, Iran, Libya, Nigeria, and other nations. Imagine the past few decades if those nations had been well-governed democracies, instead of places that breed resentment, funnel money to bad actors, attack neighbors, and in other ways destabilize their regions and the world.The first step to ending this age-old problem is fairly simple: a bit more information. Typically, a private company, such as ExxonMobil or BP, will pay a huge and secret amount of money to a government for access to fossil fuels or minerals. Nobody, aside from insiders, will ever know how much money the government received and how that money was spent. The E.I.T.I. changed that.

Asian arbitrage becomes dominant driver for Atlantic Basin crudes - The landmark agreement between OPEC and non-OPEC producers to coordinate a six-month crude production cut had ramifications for crude markets through the first quarter, with tighter sour crude supply in the Middle East helping to boost the value of Dubai relative to Dated Brent and consequently encouraging arbitrage flows from across the Atlantic Basin to Asia. The front-month Brent/Dubai Exchange of Futures for Swaps -- which is used to price arbitrage opportunities for Brent-related crude grades to the Far East -- narrowed rapidly as the production cuts got underway in January, dropping to an 18-month low of $1.11/b on March 22 from $2.60/b on December 1, shortly before the agreement was signed. The EFS looks set to remain narrow moving into the second quarter, with OPEC's current production cut due to remain in place until the end of June. The subsequent direction of the spread between Brent and Dubai will be largely determined by whether OPEC decides to maintain, or even extend, the production cut at its Vienna meeting on May 25. Price volatility in the North Sea physical crude oil market has been relatively restrained so far in 2017, in contrast to the large swings in differentials that were a feature of 2016. The complex's performance through the first quarter was closely linked to the arbitrage of Forties crude to Asia, with differentials rising during periods of heavy outflows and dropping when the medium sweet grade had to find homes in the local Northwest European market, where demand was largely tepid. Differentials traded within a fairly narrow band of Dated Brent minus 61 cents and plus 4 cents over Q1, having ranged between minus 95 cents and plus 33.5 cents in 2016.

Did fracking in Botswana cause Johannesburg to tremble? - In 2015 Mira Dutschke and I released our film The High Cost of Cheap Gas about the secret roll-out of gas developments in Southern Africa.  The film and it’s revelations published in the UK Guardian outlined a new drilling plan in Botswana.  Companies had been hydraulic fracturing, or fracking, in protected areas like the Central Kalahari Game Reserve for years, exploring for good gas returns from Botswana’s coal layers.It was denied by the government at the time. We had on-the-ground interviews, photographs from the companies' own websites and reports that you can download here, all clearly showing an ongoing gas exploration programme that included fracking with water and chemicals. The government finally conceded it may have happened and later went further, saying companies there had also used explosive charges to frack, as reported in Mining Weekly. Apparently Botswana has stopped fracking for natural gas (if it was ever officially allowed) after our follow-up story in the UK Guardian about possible drilling in the nearby Kgalagadi Transfrontier Park, according to regional drillers we spoke to last month.This sent companies like Botswana-based DeWet Drilling to more unregulated places like Mozambique, where they have recently been drilling as many as 76 gas wells for Sasol on-shore near Inhassoro, which their workers say will be fracked by French oil services company Schlumberger. According to our team’s research, today there is only one current working operation in Botswana producing gas from the original drilling plan. Outlined in their own corporate report from 2015, it is Australia’s Tlou Energy. On page 24 of this publicly available document it shows their ongoing gas project in the lower south-eastern corner inside and outside the Central Kalahari Game Reserve, (CKGR) called the Lesedi and Mamba areas, where they are apparently currently operating their ongoing gas project. Their 2013 report shows the position better, and we overlaid it onto the Botswana map here, so you can see where in the lower right of the CKGR. At the US Government Survey, they map exact earthquake locations worldwide with precision. According to their latest calculation, the tremor which shook much of the subregion this week is underneath the gas well drill sites where Tlou has been operating for at least the last five years.

Nigerian oil output slumps to 1.676 mil b/d in March: ministry - Oil | Platts News Article & Story: Nigeria's crude oil and condensate production averaged 1.676 million b/d in March, a fall of over 200,000 b/d from the previous month, the country's petroleum ministry said Tuesday. The ministry said the country's oil output was 1,676,045 b/d in March, down from around 1.9 million b/d in February, but it did not provide the reason for the sharp month-on-month fall. However, sources close to the matter said output was down mainly due to maintenance at the Bonga field, which averages around 150,000-200,000 b/d. Shell said in early-March that Bonga production would be shut in for about four to five weeks due to turnaround maintenance and engineering upgrades at the Bonga floating, production, storage and offloading (FPSO) vessel. Nigerian oil production still remains sharply below its capacity of 2.2 million b/d, with the main export grade Forcados still shut in. But Nigerian oil output has recovered gradually this year as militant attacks have fallen substantially since early January after the government stepped up peace talks with leaders and youths in the Niger Delta to end militancy in the region.

Qatar restarts development of world's biggest gas field after 12-year freeze | Reuters: Qatar has lifted a self-imposed ban on development of the world's biggest natural gas field, the chief executive of Qatar Petroleum said on Monday, as the world's top LNG exporter looks to see off an expected rise in competition. Qatar declared a moratorium in 2005 on the development of the North Field, which it shares with Iran, to give Doha time to study the impact on the reservoir from a rapid rise in output. The vast offshore gas field, which Doha calls the North Field and Iran calls South Pars, accounts for nearly all of Qatar's gas production and around 60 percent of its export revenue. "We have completed most of our projects and now is a good time to lift the moratorium," QP Chief Executive Saad al-Kaabi told reporters Monday at Qatar Petroleum's headquarters in Doha. "For oil there are people who see peak demand in 2030, others in 2042, but for gas demand is always growing." The development in the southern section of the North Field will have a capacity of 2 billion cubic feet per day, or 400,000 barrels of oil equivalent, and increase production of the field by about 10 percent, when it starts production in five to seven years, he said. Qatar is expected to lose its top exporter position this year to Australia, where new production is due to come on line. The LNG market is undergoing huge changes as the biggest ever flood of new supply is hitting the market, with volumes coming mainly from the United States and Australia. President Vladimir Putin said on Thursday Russia aimed to become the world's largest LNG producer. The flurry of LNG production has resulted in global installed LNG capacity of over 300 million tonnes a year, while only around 268 million tonnes of LNG were traded in 2016, Thomson Reuters data shows. That has helped pull down Asian spot LNG prices by more than 70 percent from their 2014 peaks to $5.65 per million British thermal units (mmBtu). Qatar's decision to lift the moratorium on new gas development now could help the tiny Gulf monarchy maintain a competitive edge after 2020, when the global LNG market is expected to tighten.

Gas giants share OPEC's shale pain as US supply flows east -- OPEC isn’t the only decades-old energy hegemony being turned on its head by U.S. shale.Liquefied natural gas sellers from Qatar to Malaysia that dominated gas sales to Asia for years are facing the prospect of rising American exports. While less than 30 U.S. cargoes have landed in Asia, their effect was felt even before they arrived. LNG trade in 2016 jumped the most in five years, contract lengths were sliced in half in the past decade, and spot prices slumped more than 60 percent in the past three years.That means the global LNG titans gathering in Tokyo this week for Gastech are in the midst of the biggest shakeup since the industry was founded in the 1960s. Just as American crude is increasingly making its way to Asia, the world’s biggest oil market, the burgeoning armada of gas cargoes from the U.S. and elsewhere are poking holes in the financial system on which the industry’s multi-billion plants are funded.“As U.S. exports ramp up, we’re going to see even more flexibility with more people trying to buy and trade volumes. The old models of stable long-term contracts will really have to change,” said Zhi Xin Chong, a gas analyst for Wood Mackenzie Ltd. in Singapore. “We’ve already seen the impact of U.S. LNG on contract trends, with more destination flexibility coming into play.”Since the 1960s, when projects in Algeria and Alaska started chilling natural gas to temperatures colder than the dark side of the moon, the LNG trade was as simple as the industry’s engineering was complex. Energy companies borrowed heavily to develop gas fields and build liquefaction plants, and to pay off the debt they signed decades-long contracts with electric utilities to buy the fuel at a fraction of the price of oil. Now, with hydraulic fracturing lowering production costs, U.S. exporters are setting the price of LNG based on natural gas trades at Henry Hub in Louisiana. They’re also eliminating destination restrictions that require ships arrive at a specific port, which most previous contracts included, meaning traders can buy cargoes and flip them to whatever market needs them the most.

Global LNG trade reaches record 258 million mt in 2016: IGU -  Global LNG trade in 2016 reached a record 258 million mt, up 5% from 2015, according to the International Gas Union's 2017 World LNG Report published Wednesday. LNG trade expanded by an average of only 0.5% a year over the previous four years, the IGU said. Short- and medium-term LNG trade grew by only 0.56% in 2016 to 72.3 million mt, accounting for 28% of total trade. The report said: "the share of LNG traded without a long-term contract as a percentage of the global market has tapered off since 2013. Short and medium-term trade, as a share of total traded LNG, fell by 4%." This reflects partly the existence of long-term contracts for the new LNG capacity that has come on stream in the last 12 months, as well as the spike caused in short- and medium-term LNG trade in the aftermath of the 2011 Fukushima nuclear disaster in Japan and the later onset of drought conditions in Latin America. The increase in overall LNG trade can be attributed to a significant rise in new supply, said the IGU, owing to the start of exports from the US Gulf of Mexico and Australia Pacific LNG, among other projects. The report also notes significant rises in demand, most notably from Asian markets; China's LNG consumption rose by roughly 35% to 27 million mt in 2016, the report said.However, it also notes that some markets, including Japan and South Korea as the two largest, may have passed peak LNG demand as other forms of energy come to the fore. Total liquefaction capacity was put at 339.7 million mt/year in 2016, an addition of 35 million mt. The IGU estimates that 114.6 million mt of new capacity was under construction as of January 2017, indicating LNG supply will continue to rise rapidly in coming years.

LNG bunkering set to witness steady growth despite odds - As the marine industry gears up for stricter environmental regulations, particularly the upcoming 2020 global sulfur cap, attention turned once again to prospects for LNG as a marine fuel, with attendees of an LNG bunkering symposium in Japan assessing the merits and impediments in its uptake. Most LNG has no detectable sulfur, and LNG-fueled vessels' emission of particles and nitrogen oxide are considerably lower than that of vessels using other marine fuels. "I believe this momentum [for LNG-fueled vessels] is set to increase in the coming years," Michael Chia Hock Chye, managing director of marine and technology at Singapore's Keppel Offshore & Marine, said at the event. As of January 24, 99 LNG-fueled vessels operated globally, with 93 more in the order book and approximately 70 "LNG-ready" vessels on order, according to DNV-GL data shared at the event by a panelist. "These statistics are encouraging, as they show that ship-owners are beginning to adopt, or are considering adopting, LNG as their preferred fuel. As you know, it has been a chicken-and-egg situation, [with people pondering] which comes first, LNG ships or LNG bunkering [facilities]," he said. As ports in Europe and the US are embracing LNG as a marine fuel, Asian ports too are doing the same. Japan, for its part, has already done a feasibility study for the development of an LNG-bunkering hub at Yokohama port, located on the Pacific side.

LNG suppliers propose non-traditional contract ideas to improve flexibility - LNG suppliers Tuesday floated proposals for innovative supply contracts, including fixed-price term contracts and smaller-scale deliveries, to facilitate deal-making and to keep up with evolving market requirements. Tellurian Chairman Charif Souki, speaking at the Gastech conference in Tokyo, said his company planned to offer 7 million mt of LNG for five years, for deliveries starting in 2023, at a fixed-price of $8/MMBtu. The volumes would be supplied by the Tellurian's planned Driftwood LNG project in Louisiana and delivered into Japan. Souki claimed his proposal will "take the volatility out of the market." Regarding evolving structures that are non-price related, Woodside CEO Peter Coleman focused on reduced LNG contractual quantities. Coleman said this could include delivering to into "a small-scale market that will be serviced by smaller vessels," such as within Indonesia's archipelago.Alternatively, LNG deliveries into India could be in conventional-sized cargoes, which would then be broken down "almost at the port" and delivered to customers, he said. In turn, new liquefaction trains could become smaller scale and more commoditized, helping reduce their capital intensity, Coleman said. For example, he said, the next expansion train at Woodside LNG's Pluto LNG in Western Australia could be 1.5 million mt, a significant reduction from the original Pluto train's capacity of around 4 million mt/year.

LNG swap trades in Japan: A question of when, not if? -- Gone are the days when LNG procurement was relatively straightforward for Japanese utilities and security of supply concerns dominated everything else. Now the Japanese domestic gas and power retail markets are deregulating and global LNG demand and supply dynamics are shifting, with more focus placed on managing risks and ensuring profitability. The listing of Platts JKM™ swaps on the Tokyo Commodity Exchange (TOCOM), through the Japan OTC Exchange, JOE, from April 3 comes when price risk is at the forefront of Japanese minds.The question then may become how fast Japanese needs for LNG hedging will grow.The deregulation of Japan’s electricity and gas markets is slowly but surely progressing. Since April 2016 when Japan’s retail electricity market began opening up, new suppliers have gained about 3% of the market share as of October 2016, according to the Ministry of Economy, Trade and Industry (METI). For the power market for large-scale factories or commercial buildings, the first sector that was liberalized in 2000, new suppliers hold more than 10% of market share, according to the METI.Trading electricity is also gaining currency. Annual trade volume on Japan’s Electric Power Exchange (JEPX) from April 1 2016 to March 25, 2017, stood at 2.25 billion kWh, on its way to a record high since its inception in 2005. In the previous fiscal year 2015-2016 (Apr-Mar),  the annual volume was 1.54 billion kWh, according to JEPX.  Still, trading on the JEPX currently only accounts for 3% of the country’s overall power sales. METI plans to introduce a gross bidding system whereby Japanese incumbent power utilities are obliged to trade certain volume on the exchange starting from April 2017, as the METI tries to boost liquidity and aims for trade on the JEPX to represent 20% to 30% of overall sales volumes in the next  few years.

Seeking higher revenues, Saudi sets out stall for light crude | Reuters: Despite OPEC's oil output curbs, Saudi Arabia has been offering its customers more light crudes while cutting heavy grades, a trend that could increase as the kingdom wants to maximise revenue and needs more heavy oil to power its own refineries. This trend, if sustained, will impact refining margins particularly in Asia, and narrow the spread between light and heavy crude globally, industry sources and analysts said. That would be bad news for sophisticated refiners, which value heavy grades because the lower cost of such oil results in higher margins, and good news for older, simpler plants that generally need light, sweet crude. Saudi Arabia cut the April prices of light crude it sells to Asia for the first time in three months in an effort to shore up demand. The spread between Arab Light and Heavy was at $2.45 a barrel, the narrowest since September. Before the OPEC output pact, in mid-November 2016, Brent futures for delivery in June 2017 were trading at a premium of around $4 per barrel over Oman futures. That has since narrowed to around $1.25. The Organization of the Petroleum Exporting Countries, Russia and a number of other producers pledged to cut output by about 1.8 million barrels per day (bpd) from Jan. 1, the first curb in eight years, to boost prices and erode a glut. Saudi Arabia, the world's top oil exporter, accounts for some 40 percent of the pledged OPEC curbs and has reduced output by more than 500,000 bpd to slightly below 10 million bpd, with cuts concentrated mainly in medium and heavy grades.

Saudi Aramco Cuts Oil Pricing for Europe Where Russia Dominates -- Saudi Arabia lowered oil pricing for European customers, a sign the world’s biggest crude exporter is seeking to expand market share in the region dominated by Russia.State-owned Saudi Arabian Oil Co. lowered its official selling pricing for all grades to northwest Europe for the second straight month, along with all prices to the Mediterranean and some to Asia, against regional benchmarks. It raised the pricing of all sales to the U.S., it said Wednesday in an emailed statement.European oil demand posted two consecutive years of growth in 2015-16, something last seen in the mid 1990s, the International Energy Agency said in a March report. Saudi Arabia supplied 42.5 million metric tons of crude, natural gas liquids and refinery feedstocks to European nations in the Organisation for Economic Cooperation and Development last year, ranking fourth after the former Soviet Union, Norway and Iraq, according to IEA data.“European markets had been written off for a couple of years but now are seeing a decent size of demand growth,” Edward Bell, commodities analyst at Emirates NBD, said by phone from Dubai. “Holding on to that at the expense of pushing Russian barrels out will be quite important” to Saudi Arabia.Saudi Arabia’s pricing in Europe caught Russia’s attention less than two years ago before the two nations started talks to curb crude output. State-run Rosneft PJSC, Russia’s biggest crude supplier, in 2015 said the Saudis were “ dumping’’ in Europe to expand market share. There is a risk price wars may resume in Europe, raising the possibility the output cut agreement won’t be extended to the second half of this year, Rosneft said last month.Aramco cut the May pricing of Arab Light crude to northwest Europe by 45 cents a barrel from April, to a $4.35 discount to the benchmark. It cut Arab Light to Asia by 30 cents, to a 45-cent discount. The company was forecast to cut the Asia pricing by 35 cents a barrel, according to the median estimate in a Bloomberg survey of five refiners and traders.

Russian Siberian Light at lowest in over six months on low demand -  Russia's Siberian Light shed 30 cents/b over the past week to its lowest in over six months as a downturn in demand met an increasing length in the Siberian Light program in 2017. Siberian Light was assessed at Dated Brent minus 70 cents/b Tuesday, a level not seen since September 30 when the grade was last assessed lower at Dated Brent minus 90 cents/b. One cause of the price fall was the continuous rise in Mediterranean sweet crude supply with KazTransOil starting to ship Kashagan crude in the form of Siberian Light from the Russian port of Novorossiisk while, at the same time, demand for the grade was sluggish. Further, weakness in Urals loading out of the Black Sea port of Novorossiisk was said by one trading source to be a reason for the drop in differentials. "Chinese demand is not there for Urals in April and hence differentials for the heavier Russian crude slid. [That] also impacted buyers' willingness to pay for Siberian Light," the trading source said. Since December, the Siberian Light program has consistently been showing over 130,000 b/d being loaded onto Aframax vessels, up around 25,000 b/d from the average in 2016. According to trading sources, there are currently still four cargoes available to trade in April with the first three cargoes of the program having traded.

Iran struggles to expand oil exports as sea storage cleared | Reuters: Iran has sold all the oil it had stored for years at sea and Tehran is now struggling to keep exports growing as it grapples with production constraints, shipping and oil sources say. Since the easing of international sanctions in January 2016, Iran tried to make up for lost sales by releasing millions of barrels parked on tankers offshore. Tanker tracking and oil sources said Iran had sold its last stocks from the floating storage in the past two weeks. Much of the oil stored was condensate, a very light grade of crude. With no more stocks at sea, Iran has lost a vital resource that had propped up exports. "We do think that (floating storage) has been the primary cause of the boost in exports," Energy Aspects analyst Richard Mallinson said, adding that now floating storage had ended total exports of crude and condensate were likely to slip. "We see a very difficult path for Iran to raise crude output until it can get the Western expertise and investment back into the upstream, which has been notably slow to materialize," he added. After Western sanctions were eased, Iran's output jumped from about 2.9 million barrels per day (bpd) to about 3.6 million bpd in June. But it has barely risen since - fluctuating between 3.6 million and 3.7 million bpd - even though Iran fought hard with fellow OPEC members to be excluded from production cuts that came into effect on Jan. 1 and will last till June. The Organization of the Petroleum Exporting Countries pledged to reduce output by about 1.2 million bpd, but Iran was allowed a small increase to compensate for years of isolation. Yet it has produced less in the past three months than it was allowed.

More Chinese crude oil imports coming from non-OPEC countries -- China, the world’s largest crude oil net importer, increased the share of its crude oil imports from countries outside the Organization of the Petroleum Exporting Countries (OPEC) in 2016. Of the country’s 7.6 million barrels per day (b/d) of 2016 crude oil imports, 57% came from OPEC countries, led by Saudi Arabia (13% of total imports), Angola (11%), Iraq (10%), and Iran (8%). Leading non-OPEC suppliers included Russia (14% of total imports), Oman (9%), and Brazil (5%). While total crude oil imports from OPEC exceed those from non-OPEC sources, crude oil from non-OPEC countries made up 65% of the growth in China’s imports between 2012 and 2016. Recent Chinese import data, crude oil price spreads, and non-OPEC production trends suggest continued growth in non-OPEC countries’ share of China’s growing crude oil imports. China’s crude oil imports increased by 2.2 million b/d between 2012 and 2016, with the non-OPEC countries’ share increasing from 34% to 43% over the period (Figure 1). Since the beginning of 2012 through February 2017 (the latest month for which data are available), the market shares of three of the top four OPEC suppliers to China (Saudi Arabia, Angola, and Iran) fell when measured using rolling 12-month averages. Over the same period, however, market shares for China’s top four non-OPEC suppliers (Russia, Oman, Brazil, and the United Kingdom), increased. While still comparatively small as a share of China’s crude oil imports, imports from Brazil reached a record high of 0.6 million b/d in December 2016, while imports from the United Kingdom reached their all-time high of 0.2 million b/d in February 2017.

The End of OPEC is near - OPEC, which has far exceeded the average life of cartels, is on the brink of failure. Though cracks have been developing in the cartel since the start of the current oil crisis, the group has managed to stay together so far. Nevertheless, the success of the current OPEC deal for production cuts will decide its future as a cartel. A cartel is a group of like-minded producers, who act in concert—or collusion—to achieve a shared goal of increasing their profits by means of restricting supply, fixing prices, or destroying their competition by illegal means. The average life of the 20th Century cartels has been 3.7 to 7.5 years, according to various studies by Margaret Levenstein and Valerie Suslow. In the past two centuries, cartels have been able to influence prices by an average of 25 percent.Since its inception, OPEC has been fairly successful in boosting prices by various means. A few of the price increases, however, were due to reasons other than direct OPEC action, nevertheless benefitting their members. A cartel is able to hold its members only when it fulfills their objective of higher prices, which has not been the case with OPEC. The member nations will now look to fulfill their objective by cheating and acting individually, according to their requirement.Saudi Arabia, which was the leader of OPEC and the price setter of the world, is losing its clout in OPEC. Even in the current round of production cuts, most of the work is being done by Saudi Arabia, whereas the other members are shying away from their designated quotas.OPEC has far outlived the average lifespan of a cartel, but if the OPEC members don’t regroup and act together, chances are that the cartel will come to an end very soon.

Oil’s seaborne picture suggests Opec cuts taking effect --For traders trying to decipher if Opec’s output cuts are finally tightening the oil market, the evidence may lie out at sea.  Data provided to the Financial Times show that crude oil being shipped over the oceans or stored on supertankers has dropped by as much as 16 per cent since the beginning of the year, in a signal that supplies could be dropping faster than many in the market believe. Vortexa, an oil tracking start-up founded by BP’s former head of trading technology and a one-time JPMorgan commodity executive, says its numbers indicate Opec’s cuts with big producers like Russia have been clouded by a surge in US production that is not reflective of supplies in the rest of the world.“Water is where the market changes first,” said Fabio Kuhn, Vortexa chief executive and co-founder, who ran BP’s trading technology programme until 2015. “We think this is some of the first evidence that supply cuts are having a major effect.”Vortexa says its data show seaborne oil shipments on April 3 totalled 759.6m barrels of crude in transit from producers to refineries or storage farms, with an additional 52m barrels still held at sea on supertankers globally.That is down from 899.4m barrels in seaborne transit on January 1 when 78.4m barrels was also held in floating storage. The combined total from April 3 is also down by 17 per cent from the same day a year ago, suggesting the supply drop is more than just a seasonal fall, despite many refineries carrying out maintenance in the spring months.For the data analysis, Vortexa defined floating storage as any laden tanker stationary for seven days or more.While seaborne shipments and storage do not capture the entirety of the 98m-barrel-a-day oil market, as it excludes pipeline flows and production that goes straight from the wellhead to refineries or on land storage, it does cover a significant percentage.Although the supply cuts agreed last November only total 1.8m b/d, or about 2 per cent of global supplies, the producers taking part are some of the world’s biggest exporters, with the majority of their crude sent by sea. Saudi Arabia, Opec’s largest producer, ships roughly three-quarters of its near 10m b/d oil supplies by tanker.

Hedge funds square up most of their former record bullish position in oil: Kemp (Reuters) - Hedge funds have continued liquidating their large bullish position in crude amid doubts about the pace and timing of any rebalancing in the oil market.Hedge funds’ net position in Brent and WTI has been cut to 642 million barrels, down from a record 951 million barrels on Feb. 21 ( spread of risks between further long liquidation and new short covering now looks more balanced than at any point since OPEC’s production deal was announced at the end of November.Hedge funds and other money managers cut their net long position in the three major futures and options contracts linked to Brent and WTI by a further 41 million barrels in the week to March 28.Fund managers have cut their net long position for five consecutive weeks by the equivalent of 309 million barrels, according to an analysis of records published by exchanges and regulators ( have reversed more than half of the extra 529 million barrels of net long positions accumulated between the middle of November and the middle of February.Hedge funds have cut long positions by 170 million barrels over the last five weeks while adding 139 million barrels of extra short ones.The result is that the ratio of long to short positions in Brent and WTI has fallen to 3.7:1, down from a recent high of 10.3:1 on Feb. 21 ( build up of a record concentration of hedge fund long positions prior to Feb. 21 became a major downside risk to oil prices in January and February (“Hedge fund positioning in oil looks stretched”, Reuters, Feb. 7). The liquidation of long positions and establishment of fresh shorts likely contributed to the sharp drop in oil prices starting on March 8.But by the end of March 28, the previous congestion of hedge fund long positions in the oil market seems to have dissipated.The squaring up of positions coincided with an easing of persistent selling pressure, with Brent and WTI prices staging a modest recovery from March 28 through March 31 ( most but not all long positions liquidated, and a moderate number of short positions already in the market, the outlook for oil prices now appears more balanced than at any time in the last three months.

One of the world's best-known oil traders is predicting oil will recover to $70 a barrel -- Oil prices are not capped around $55 as is widely assumed but rather are on track to hit $70 per barrel later this year, according to Pierre Andurand, managing partner at Andurand Capital Management. We're currently at a crossroads from where oil prices should significantly rebound, Andurand told CNBC on the sidelines of an event Thursday evening where he was crowned the winner of the EMEA Investor's Choice Awards for 2017. "I think oil prices are likely to recover to around $70 … I think the market will switch to backwardation – sustainable backwardation – by late summer and that will bring the next wave in oil prices," he said, referring to the situation where nearer-term spot price oil contracts are more expensive than longer-dated forward contracts. Andurand is widely known for his bearish call on oil prices in the mid-2000s, delivered ahead of the drastic sell-off which saw WTI prices plummet from close to $150 in July 2008 to trade in the $30s a mere five months later. Hence why his switch from oil bear to oil bull has particularly caught the market's attention. Andurand worked up his position last year and said that while he has been surprised by the somewhat rangebound nature of trade so far in 2017 – indeed, during the first two months of this year his fund position suffered from being caught off-guard by this dynamic - he believes there is a solid explanation for why it will not persist. "U.S. shale producers have been hedging a lot of their production, capping prices, so the improvements in fundamentals were not priced in at all, but I believe that now when people will really see that inventories are going down fast, that eventually the fundamentals will win and prices will go higher," he suggested.

Is Gasoline Demand On The Rise? -- A common refrain one hears these days from market bulls and reads in long-term analyses is that by 2020, the current glut in supply and decline in prices will be reversed: that the current drought in exploration and capital investment in new production will send available supply plummeting, with a complimentary spike in prices. This was the prediction of a recent IEA report, which guessed that oil prices would reach $70 by 2020.Whether this reversal in the market occurs or not will depend in large part on global demand. In the United States, around 40 percent of crude is refined into motor fuel and gasoline, to feed the American people’s favorite gas-guzzlers.Crude prices picked up this week, rising above $50 thanks to signs that U.S. demand for refined products is strengthening. Higher-than-expected inventory drops, together with outages in Libya, pushed the oil price up. But can the American consumer, who is the single largest consumer of gasoline on the planet, keep the momentum going?According to numbers compiled by Bloomberg, U .S. gasoline demand is down from 2016 and consumption has fallen by 1.7 percent from last year, when prices cratered in January-February 2016 and gasoline could be had for $1.70 per gallon. Today gasoline prices are up in every US region according to the EIA by 20-30 percent, with diesel up as much as 50 percent.   Gasoline inventories hit their all-time high in February, topping out at 259.1 million barrels, according to EIA data. They’ve since declined about 8 percent, and are currently set to maintain the high levels reached in 2016. When crude oil stocks surged in early March, gasoline inventories went the other direction, posting the largest single draw-down in six years.Some are worried that gasoline demand may have peaked in 2016, where a record of 9.33 million barrels a day was hit, the highest level since 2007, followed by the sharp decline in January and February. Goldman sounded an alarm bell in February, when US inventories reached their record level and expected American gasoline demand dropped to its lowest point since 2012. The Goldman prognosis was chilling: “A 6 percent fall in US demand would require a US recession.”

Oil Traders Drain Hidden Caribbean Hoards as OPEC Cuts Bite --  During the oil price rout, islands in the Caribbean were exhibit A for the longest-lasting glut in three decades, with millions of barrels stored there. Now, that oil is flowing again, a sign the market is rebalancing. Since mid-February, between 10 million and 20 million barrels have left the Caribbean, according to estimates from traders who asked not to be named because their data is proprietary. The draw, hardly noticed by most in the market, reflects the impact of the output cuts orchestrated by OPEC and Russia. Low taxes and the Caribbean’s proximity to U.S. and Latin America oil centers have made it into one of the world’s largest oil storage centers, holding as much as 140 million barrels. While a lack of official data can make the area invisible to some, the information is key in framing a full picture of global supply and demand at a time of market uncertainty. "Caribbean and other storage has drawn down rapidly over the past weeks," said Amrita Sen, chief oil analyst at Energy Aspects Ltd., in a note to clients. "The first indications that the rebalancing has begun are here." On Sunday, Mohammad Barkindo, OPEC’s Secretary-General, said he remained "cautiously optimistic” the gap between supply and demand was starting to tighten. The Organization of Petroleum Exporting Countries and the 11 countries that agreed to trim production in the first half of the year are now weighing whether to extend the cutbacks to the end of 2017. West Texas Intermediate oil fell 0.7 percent to $50.24 a barrel in New York on Monday. Oil prices have fallen about 10 percent this year as crude stockpiles in the U.S. have since December grown by almost 55 million barrels to 534 million barrels, the highest since 1929.

Oil Jumps On Growing Support For OPEC Deal Extension -  Oil prices showed gains in recent days and held onto them to start off the week. There is growing confidence in an OPEC extension and also there are finally some signs that the market is tightening. The head of OPEC says that the production cuts from the cartel are starting to bear fruit. “I remain cautiously optimistic that the market is already rebalancing," OPEC’s Secretary-General Mohammad Barkindo told reporters Sunday in Baghdad. “We have started seeing stock levels coming down.” Investment bank UBS said in a recent report that the oil market is heading towards balance even after taking into account rising U.S. output. UBS says demand will soak up the excess supply, and as a result of a tighter market, oil could be heading towards $60 within three months. BNP Paribas also made a bullish call, expecting inventory drawdowns every quarter of this year. The bank says Brent could average $60 per barrel this year. Pierre Andurand of Andurand Capital Management expects oil to hit $70 before the end of the year. "I think oil prices are likely to recover to around $70 … I think the market will switch to backwardation – sustainable backwardation – by late summer and that will bring the next wave in oil prices," he said on CNBC. His switch from bearishness to bullishness is notable, given his track record at successfully predicting some previous swings in the market. The FT reports that the volume of oil moving on tankers at sea has declined by 16 percent so far this year compared to a year earlier, a sign that the OPEC cuts are having a tangible effect. The rise of U.S. shale output could be distracting from a tighter market in the rest of the world. “Water is where the market changes first,” Fabio Kuhn, CEO of Vortexa, an oil tracking company. “We think this is some of the first evidence that supply cuts are having a major effect.”   U.S. crude inventories are at record levels, but that is not reflective of global conditions. Bloomberg reports that oil storage in the Caribbean has seen inventories decline by between 10 and 20 million barrels since mid-February. This can be interpreted as another sign of a tightening market.  Iraq said that it cut production to 4.46 million barrels per day in March, taking output down closer to its promised target. The reduction puts Iraq close to 98 percent compliant with the 4.351 mb/d it pledged to reach over the course of the six-month deal. The cuts made by Iraq – one of the biggest laggards on the OPEC deal – will boost confidence in the group’s cooperation. It could also build trust in the run up to negotiations over a six-month extension.  The unexpected outage of 252,000 bpd of Libyan oil production last week sent a jolt through the oil market, providing some unanticipated bullishness. But one of the disrupted fields brought 120,000 bpd back online by Monday, deflating some of the confidence around prices.

WTI/RBOB Slide Despite Biggest Crude Draw Since 2016 -- With oil surging back above $51 on hopes of a seasonal inventory drawdown, tonight's API data showed a bigger than expected draw in crude (biggest since 2016 and gasoline. The reaction was a kneejerk higher in WTI as RBOB slipped lower, but amid a big build at Cushing (+1.3mm), WTI also slipped. API:

  • Crude -1.8mm (-150k exp)
  • Cushing +1.3mm
  • Gasoline -2.6mm (-1.75mm exp)
  • Distillates -2mm

Biggest draw of 2017 for crude but Cushing saw a notable build...

Tanker Traffic Points At Much Tighter Oil Markets - Oil prices have rallied more than 6 percent since last week, which has largely been attributed to growing confidence in a six-month extension from OPEC combined with a temporary outage in Libya and slightly better numbers from the EIA regarding refined product inventories. It still seems that the oil market is woefully oversupplied, but there are growing bits of evidence that when stitched together, start to resemble a market on the mend.For example, the Financial Times reported that seaborne oil tanker traffic is down this year by 16 percent, a sign that the OPEC cuts are showing up at sea. Not all oil is traded at sea, obviously – some is shipped via pipeline or moved directly from the wellhead to refineries, processing facilities or storage. But such a drop off in the volume of oil moved at sea suggests that the supply cuts are being felt in the market.It may seem curious then that oil investors are not picking up on this fact but Vortexa, an oil tracking firm, told the FT that the record high levels of inventories in the U.S. are probably disguising tightening conditions elsewhere. That is compounded by the fact that the U.S. provides the most thorough and timely data, while data tracking is much trickier elsewhere. That results in the U.S. having an outsized impact on the market narrative.Vortexa says their data suggests that a fall in maritime trade this year is evidence of a tightening market. “Water is where the market changes first,” Fabio Kuhn, Vortexa CEO, said in an interview the FT. “We think this is some of the first evidence that supply cuts are having a major effect.” Another small piece of evidence of a tightening global market can be found in the Caribbean, where oil inventories have already declined substantially. Bloomberg reports that crude inventories at Caribbean storage facilities have dropped by 10 to 20 million barrels over the past month and a half, a development that oil traders attribute to the OPEC cuts. Overlooked by the market until now, the drawdown suggests global supplies are moving closer to balance. "Caribbean and other storage has drawn down rapidly over the past weeks," Amrita Sen, chief oil analyst at Energy Aspects Ltd., wrote in a research note. "The first indications that the rebalancing has begun are here."

WTI/RBOB Tumble After Surprise Inventory Build Sends Crude Glut Back To Record High -- Following last night's API-reported unexpected draw in crude, the energy complex was on a tear heading into the DOE data... but that ended quickly with a surprise build in crude and smaller than expeccted draws in gasoline and distillates. WTI/RBOB are notably lower on the data. Another rise in production further stressed markets. DOE

  • Crude +1.566mm (-150k exp)
  • Cushing +1.413mm
  • Gasoline  -618k (-1.975mm exp)
  • Distillates -536k

Product stocks have been falling consistently since the beginning of February, but the surprise crude buuld shocked markets after last night's API print.

Oil eases off one-month high on surprise rise in US crude stockpiles: Oil prices eased from one-month highs on Wednesday, as a surprise increase in U.S. crude inventories to a record high offset support from an outage at the largest UK North Sea oilfield. Prices rose early, then turned negative after the U.S. government reported a weekly rise in crude inventories of 1.6 million barrels. Analyst had expected a decrease of 435,000 barrels, and the build reported by the Energy Information Administration came as a double surprise after an industry group had reported a draw. "The crude build caught the market leaning the wrong way. Crude exports dropped to 575,000 bpd this week, versus over 1 million bpd last week," said David Thompson, executive vice-president at Powerhouse, a commodities-focused broker in Washington. "The selling most likely includes a fair number of sell stops being hit." Brent crude had risen 22 cents to $54.39 a barrel by 2:34 p.m. ET (1834 GMT), having earlier risen to $55.09, its highest level since March 8. U.S. crude settled Wednesday's session 12 cents higher at $51.15, after hitting a session peak of $51.88. U.S. gasoline prices fell into negative territory and heating oil futures pared gains as EIA reported less-than-expected decreases in gas and distillate fuel oil inventories. Oil prices had risen early after the American Petroleum Institute reported late on Tuesday that inventories fell by a more-than-expected 1.8 million barrels last week. "Yesterday's API report gave the market a bullish head-fake via three chunky draws, hence a build to crude stocks and minor draws to the products is causing a tempering of bullish optimism,"

Information asymmetry bedevils the oil market - Reliable and timely data on US oil inventories contrasts with patchy information elsewhere. - Opec’s biggest problem is that in its tug of war with US shale no one really knows for certain which is winning. The oil cartel last year appeared to capture a major victory by corralling some of the world’s biggest producers to join it in cutting output to finally end a near three-year-old oil glut. But four months on, despite trumpeting figures suggesting the group has adhered more rigidly to its cuts than ever before, the crude price is still stuck near $50 a barrel. The issue for the cartel is not just one of a resurgent shale industry propelling US crude inventories to record levels, but an information asymmetry that gives the US an outsized importance to traders beyond its status as the world’s largest oil consumer. The US is the only country where close to real-time information is freely available on the state of oil inventories, due to the government’s decision to fund the Energy Information Administration after the first Arab oil embargo of the 1970s. Weekly and monthly reports published by the EIA have for years been a lodestar for traders navigating an otherwise opaque market. But as surging US production has made the country less reliant on oil imports — and fast-expanding emerging markets such as China and India become the dominant centres of oil demand growth — the focus on the gold standard data of the US may mask the reality of what is happening to the oil market beyond its shores. US stockpiles may be rising as supplies there grow, with cheap and abundant land-based storage also luring international customers. Elsewhere the market is starting to tighten, many traders believe. Now, short of every major oil importer outside the US deciding they have the money to fund an EIA equivalent, from cash-strapped European nations to transparency phobic states in Asia, the issue is not easily resolved.

Saudi crude price cut to add to Asia light oil glut: Russell | Reuters: Saudi Aramco's decision to cut prices for lighter grades of oil for customers in Asia is a sign of just how seriously the world's top crude exporter is taking its battle with U.S. shale and other producers outside last year's move to cut output. The Saudi Arabian state oil company lowered the official selling price (OSP) of its benchmark Arab Light grade by 30 cents a barrel for May cargoes destined for Asia, which buys about two-thirds of the kingdom's exports. This took the OSP to a discount of 45 cents a barrel to the regional benchmark Oman-Dubai. It was the second straight month that Aramco cut the price, even though the Saudis are the major player in the agreement between producer group OPEC and its allies to cut output by 1.8 million barrels per day (bpd) in the first six months of the year. Aramco also reduced the OSP for its Arab Extra Light grade by 35 cents a barrel to a premium of 60 cents over Oman-Dubai for May-loading cargoes for Asian customers, and for Super Light by 20 cents. In contrast, the OSPs for Arab Medium and Heavy were left unchanged. It's worth noting that Arab Light isn't actually a light crude in the mould of global benchmark Brent, as its API gravity of 32-33 degrees makes it a medium grade, compared with Brent's light 38.3 degrees. But Arab Extra Light and Super Light are more directly comparable to Brent, and they both saw price reductions. It's appears that Aramco, mainly a producer of medium to heavy grades, is responding to the light grades of crude swamping Asian markets as U.S. producers ramp up shale output and West Africa increases production.

Oil, gold jump as missile attacks on Syria trigger safe-haven rush - Crude oil prices surged more than 2% in Asian trade Friday as jittery investors, fearing potential supply disruptions, stepped up purchases after the US launched missile attacks on Syria, while gold surged more than 1% with investors queueing up for safe-haven assets. The US fired a barrage of cruise missiles at Syria following this week's chemical weapons attack in the country as Washington intensified its efforts to mobilize a coalition to remove Syrian leader Bashar al-Assad. "In the short term, oil prices could spike due to potential short squeezes from geopolitical risks, especially ahead of Friday's US non-farm payroll data," Gordon Kwan, head of oil and gas research at Nomura, said in a research note.About 60 US Tomahawk missiles, fired from warships in the Mediterranean Sea, targeted the airbase in Syria, according to media reports. "Iran and Russia are big supporters of [Syrian President] Bashar al-Assad. There might be retaliation in the form of them cutting off supplies," OANDA senior market analyst Jeffrey Halley said in a report. "There is an implied potential threat to supplies from the Middle East. Most of the crude comes from there. I expect WTI and Brent to remain very well elevated," he added. Following news of the US missile attack, crude futures soared in Asia. At 11:37 am Singapore time (0337 GMT), the ICE June Brent crude futures were up 80 cents/b (1.46%) from Thursday's settle to $55.69/b, while the NYMEX May light sweet crude contract was 86 cents/b (1.66%) higher at $52.56/b. Front-month ICE Brent hit an intra-day high of $56.08/b following the news, while NYMEX light sweet crude contract rose to $52.94/b.

OilPrice Intelligence Report: Geopolitical Risk Is Back: Oil Up On U.S. Airstrikes: The U.S. launched airstrikes on a Syrian airbase late Thursday in response to the alleged use of chemical weapons by the Syrian government. The attacks come despite comments as recently as last week from the Trump administration that removing Syrian President Bashar al-Assad was not a priority. Secretary of State Rex Tillerson is scheduled to meet with his Russian counterpart in Moscow next week amid deteriorating U.S.-Russian relations. Syria produces only marginal volumes of oil, some of which has been under ISIS control. Nevertheless, due to its proximity to Iraq, a widening of the military conflict could induce a higher risk premium on oil prices. If action from the U.S. is limited to these airstrikes, oil prices won’t be affected much, but the upside risk is there if the U.S. gets more involved. WTI and Brent jumped to one-month highs on the news.  Iran will struggle to grow its exports from current levels without large levels of new investment and technology from international companies, according to Reuters. Iran succeeded in ramping up exports last year, but much of those gains came from emptying out storage that had built up after years of sanctions. Iran resorted to stashing oil on tankers in the Persian Gulf when sanctions were tightened in 2012, and had amassed 40 million barrels of oil on the eve of the removal of sanctions. That provided an injection of cash in 2016. Iran was able to boost output from 2.9 mb/d to 3.6 mb/d by last summer but then output flattened out. "Iran needs billions of dollars of investment to boost crude oil production and natural gas capacity," . "Most of the fields were discovered many decades ago and are way beyond their production capacity," he said.  Saudi Arabia has long maintained a fixed currency peg, but low oil prices have forced the government to burn through foreign exchange in order to keep up government spending and keep the currency stable. Cash is down to about $500 billion from a peak of $737 billion in 2014. The rate of decline is worrying although not yet a crisis. 

US oil rig count rises for 12th straight week - US drillers added oil rigs for the 12th consecutive week, taking the number of active oil rigs to 672 — a 90 per cent increase from a year ago and the highest level since August 2015.US oil producers brought 10 oil rigs back online last week, oilfield services company Baker Hughes said on Friday. Drillers have now added oil rigs every week this year barring one.Crude prices — which have been rallying today on supply disruption fears after the US launched a missile strike against Syria — held onto their gains following the report.Brent crude, the global benchmark, is trading 0.6 per cent high at $55.12 a barrel, down slightly from the $55.31 a barrel it was trading at ahead of the release. West Texas Intermediate is u p 0.9 per cent at $52.17 a barrel.

BHI: Seasonal Canadian drilling dive pushed down global rig count in March - Oil & Gas Journal -- The average worldwide rig count for March fell by 42 month-over-month to 1,985, but remained up 434 units compared with the March 2016 total, according to Baker Hughes Inc. data. The first decline in 10 months primarily reflected Canada’s 89-unit month-over-month drop to an average of 253, which is still up 165 year-over-year. The country’s average count went from 42 in May 2016 to 342 in February. The dramatic fluctuations in Canadian drilling throughout the course of a year primarily relate to weather and resulting road closures. During the spring, road restrictions are put into place as snow and ice thaw, limiting movement of rigs, accompanying equipment, and field personnel. Benefitting from a warmer year-round climate, the US continued a steady climb that began in May 2016 with a 45-unit month-over-month increase in March to 789, up 311 year-over-year. Europe was the only other region to shed rigs during March, losing 13 units to 94, down 2 compared with its March 2016 total. Turkey led the way with a 6-unit drop to 23, down 5 year-over-year. Offshore UK relinquished 3 units to 8, down 1 from its year-ago total. The Netherlands lost both of its active rigs. Asia-Pacific gained 2 units during the month to 198, up 15 year-over-year. India rose 2 units to 117, up 14 year-over-year. Africa increased 3 units in March to 80, down 11 year-over-year. Nigeria increased 3 units to 10, up 2 year-over-year. The Middle East climbed 4 units during the month to 386, down 11 year-over-year. Egypt jumped 7 units to 30, down 1 year-over-year. Iraq rose 3 units to 43, down 5 year-over-year. Kuwait, meanwhile, decreased 5 units to 54, still up 13 year-over-year. Latin America led all regions outside the US with a 6-unit March rise to 185, down 33 year-over-year. Argentina gained 4 units to 58, down 10 year-over-year. Mexico rose 2 units to 18, down 9 year-over-year. Brazil increased 2 units to 16, down 12 year-over-year. Colombia, meanwhile, dropped 3 units to 19, still up 15 year-over-year.

BHI: Permian leads 15-unit jump in US rig count - The US drilling rig count’s surge continued during the week ended Apr. 7 with another 15-unit increase, according to Baker Hughes Inc. data. Twelve of those units started up in the Permian basin.The overall count has now risen by double-digits 10 times during its 12-week streak of gains (OGJ Online, Mar. 31, 2017). At 829 rigs working, the count is up 443 units year-over-year and 425 units since the bottom of the drilling downturn on May 20-27, 2016.US oil-directed rigs gained 10 units for the second straight week to 672, up 354 year-over-year and 356 since May 27, 2016. Gas-directed rigs increased 5 units to 165, up 84 since Aug. 26, 2016. Two rigs considered unclassified remained active this week.US crude oil production is climbing alongside the rig count and is now on the cusp of 9.2 million b/d, according to data from the US Energy Information Administration. Output gained 52,000 b/d during the week ended Mar. 31, with 40,000 b/d coming from the Lower 48 and 12,000 b/d from Alaska.All 15 of the rigs added this week are land-based, bringing that tally to 813. Horizontal drilling rigs rose 10 units to 695, up 381 since May 27. Directional rigs edged up a unit to 71. Offshore rigs remain at 22, while the count of rigs drilling in inland waters stood still at 4.  The Permian received yet another boost with a 12-unit increase to 331, up 197 since May 13. Texas, however, gained just 7 units, bringing its tally to 418, up 245 since May 27. The Granite Wash lost 4 units to 10, and the Eagle Ford edged down a unit to 72, still up 43 since June 3.Recently surging Oklahoma added 4 units to bring its count to 122, up 68 since June 24. The Cana Woodford gained 2 units to 50, up 26 since June 24. The Arkoma Woodford edged up a unit to 10. The Mississippian rose 2 units to 8. Wyoming increased 2 units to 18. Louisiana, New Mexico, and West Virginia each edged up 1 unit to reach 60, 51, and 12, respectively. The Marcellus also added 1 unit and now totals 45, up 24 since Aug. 12. Alaska was the only state to post a decline, edging down a single unit to 7.Canada’s dive continued this week by shedding 23 units to 132, up 41 units year-over-year. Oil-directed rigs dropped 13 units to 42, while gas-directed rigs decreased 10 units to 90.

Oil rises after U.S. missile strike in Syria, weekly gain 3 percent | Reuters: Oil prices rose on Friday, trading near a one-month high and closing the week up 3 percent after the United States fired missiles at a Syrian government air base, raising concern that the conflict could spread in the oil-rich region. The toughest U.S. action yet in Syria's six-year-old civil war has heightened geopolitical uncertainty in the Middle East. This supported oil futures, along with signs of higher U.S. demand. "It's back to the old adage of don't go home short the weekend," said Carl Larry, oil and gas consultant at Frost and Sullivan. "There's a lot going on here: Syria and talks with China." Larry noted that many in the market also believe Venezuela could be producing below reported levels. "Venezuela could turn out to be another Iraq where they say they've been pumping 1.5 million bpd and it turns out to be nothing. It could get ugly, and markets could jump quickly." The market shrugged off a report showing U.S. drillers added oil rigs for a 12th straight week to cash in on a recovery in crude prices. Oil drillers increased the number of active oil rigs by 10, according to Baker Hughes. [RIG/U] Although Syria is not a major oil producer, any escalation of the conflict feeds fears about oil supplies due to the country's location and alliances with big oil producers in the region. Brent crude futures settled up 35 cents at $55.24. Brent reached a session high of $56.08, the highest since March 7, shortly after the U.S. missile strike was announced. For the week, Brent was up 4.4 percent. U.S. West Texas Intermediate (WTI) crude futures were up 54 cents at $52.24 a barrel, off the session high of $52.94.

If Saudis Extend Oil Cuts, Will Russia Agree? - Saudi Arabia and some Gulf State oil producer-allies appear likely to extend the six-month oil production cut that expires in June, according to SGH Macro Advisors. But will Russia agree?  SGH writes that Russia appears to be complying with agreed-to production cuts, which have kept prices closer to $50 per barrel, rather than the $60-plus hoped. But Russia is not a member of the Organization of Petroleum Exporting Countries and in February, oil-production cuts among non-OPEC producers including Russia stood at 64% compliance while OPEC members were at 106% compliance. Iraq has also lagged in compliance too, according to SGH. OPEC ministers will meet in Vienna on May 25 to decide what’s next. CEO Sassan Ghahramani and senior analyst Kevin Muehring write:“We understand Saudi oil policy officials have reaffirmed the Kingdom and its key Gulf oil producing allies are highly likely to extend the Vienna agreement on output cuts for another six months, and stand ready to cut output by more in the second half of this year.But the Kingdom is putting the onus for extending the Vienna agreement entirely on Russia: the Saudi and Gulf Cooperation Council commitment is conditional on clear evidence Russia has reached at least 250,000 barrels per day of the promised 300,000 barrels per day in output cuts by the time of the next meeting of the five-nation joint technical committee on April 21 … Riyadh sees its alliance with Moscow on oil policy as a cornerstone to its efforts to stabilize oil prices at a $50 to $60 target range over the medium term. But Saudi officials are nevertheless becoming increasingly frustrated with how Russia seems to be dragging its feet on meeting their commitments … Iran has affirmed it will adhere to a production cap of 3.8 million barrels per day, which the Saudis took as an important statement of intent. Saudi and Iranian cooperation on oil policy seems to be already spilling over into a thaw in diplomatic relations, such as the opening of the hajj to Iranian pilgrims this year …”

Saudi Arabia Vs. Russia: The Next Oil Price War International oil markets could be heading towards a new war, as leading OPEC and non-OPEC producers are vying for increased stakes. The unexpected cooperation between OPEC and non-OPEC countries, instigated by the full support of Saudi Arabia (OPEC) and Russia (non-OPEC) has brought some stabilization to the crude markets for almost half a year. The expected crude oil price crisis has been averted, it seems, leaving enough room when looking at the fundamentals to a bull market in the coming months. As long as Saudi Arabia, Russia and some other major producers (UAE, Kuwait), are supporting a production cut extension, financials will be seeing some light at the end of the tunnel.The effects of the 2nd shale oil revolution, as some have stated, have been mostly mitigated by a reasonably high compliance of OPEC and non-OPEC members to the agreed upon cuts, while geopolitical and security issues have prevented Libya, Iraq, Venezuela and Nigeria, from entering with new volumes. Stabilization in the crude oil market, as always, is not only fundamentals but also geopolitics and national interests. The latter now could also be the main threat to a successful extension of the OPEC production cuts in the coming months.Fears are growing that OPEC’s leading producer, Saudi Arabia, is no longer happy with the overall effects it is generating by taking the brunt of the production cuts, while at the same time, other OPEC members, such as Iran and Iraq, are looking at production increases. Saudi Arabia’s other main rival Russia is also not sitting idle. Even if Moscow is still fully behind the official production cuts, Russian oil companies have been aggressively fighting for additional market share in Saudi Arabia’s main client markets, China, India and even Japan. Iraq and Iran, in contrast to what was expected, have been cutting away share in Europe. Threatened by its own successful agreement, Saudi Arabia is now feeling the heat on all sides.Some analysts are even proponing a doomsday scenario, implying that Riyadh has lost its grip on the largest oil markets. U.S. shale oil is increasing its market share, while addressing European options at the same time. Russia, Iran and Iraq have been pushing for market share in Asia, while taking up Saudi share in Europe. Until now, Saudi officials such as minister of petroleum, Khalid Al Falih, and Aramco’s Nasser, have been keeping quiet. No real hardline stance has been publicized until now by the OPEC leader. This could however change dramatically if recent indicators are correct.

OPEC's No.2 Goes Rogue: Plans 600,000 Bpd Oil Output Increase - Iraq has plans to boost its crude oil production by 600,000 bpd to 5 million bpd by the end of this year, regardless of its participation in OPEC’s production cut deal. Iraq is the cartel’s second-biggest exporter of crude and has been the most disinclined of all parties to the agreement since its inception, with a lot of observers expecting it to be the first one to cheat.Iraq’s first problem is that as much as 95 percent of its budget revenues come from crude oil. There are no viable alternatives in sight for revenues at the moment. The second problem that the country has to contend with is its war with Islamic State, which makes these revenues more important than ever.Amid the final push against IS in Mosul, Iraq is working hard to ensure the sustainable growth of its oil and gas industry—OPEC deal or no OPEC deal. Three months ago, Oil Minister Jabar al-Luaibi said that Baghdad is planning to build five new refineries on an investment basis, in addition to fixing and expanding existing refineries that were damaged in the war with IS.While Al-Luaibi has repeatedly assured media - and indirectly, investors - that Iraq will stick to its OPEC commitment, Iraq is doing whatever it can to boost its returns from its only significant natural resource.As part of these efforts, the government recently started a review of the contracts it has with foreign oil companies operating local fields in a bid to better match its interests to those of the operators. Currently, international oil companies in Iraq are working under the so-called technical service contracts, which a few years ago, forced them to reduce production from some of the country’s biggest fields because Baghdad had no money to pay them for operating the fields.Baghdad is also cooperating with Tehran to make the most of the oil finds that the two neighbors share. Bilateral relations have been uneven historically but now that both Iraq and Iran are scrambling with their respective problems, a partnership has emerged as the mutually beneficial way to proceed. It is also strengthening its ties with other neighbors and farther countries such as Egypt, European Union members, and the U.S. A 600,000-bpd production increase would be substantial, but Al-Luaibi did not disclose the source of this increase. Huge fields such as West Qurna, Rumaila, and Majnoon are nowhere near depletion, so Iraq could significantly boost production in these fields.

The $2tn Saudi Aramco question - Its backers expect a valuation of $2tn. Even a partial slice of its business is likely to add up to the biggest ever initial public offering. And as a byproduct, it offers the prospect of a glimpse into the inner workings of one of the world’s most closed societies. The part privatisation of Saudi Aramco, Saudi Arabia’s national oil company, is causing a huge stir well beyond the energy market and the offices of bankers and lawyers vying for contracts. A $2tn valuation would be equivalent to two-thirds the size of the London Stock Exchange, one of the markets on which Aramco may list. And it would make Aramco more than twice the size of Apple, the world’s biggest company. But that $2tn figure is hard to believe. The company has disclosed very few financial details and its annual report lacks figures such as group sales or profits. Instead an FT analysis points to a valuation roughly half that size, reflecting the difficulties faced by the Saudi authorities in selling even a sliver of Aramco on international markets, given the company’s complex structure, its unique and sensitive role in the country and the legal issues that will surround its planned listing. That is even without looking at the question of how much oil actually lies beneath the desert kingdom’s sands. Mohammed bin Salman, the kingdom’s deputy crown prince and the power behind the throne of his father, King Salman, revealed the IPO idea in January 2016. It was initially proposed as a sale of just 5 per cent of Aramco, with perhaps more to follow, and came as a response to falling crude prices which have damaged the oil-dependent Saudi finances and accelerated the drive to diversify the economy.  The kingdom needs to shrink its enormous fiscal deficit of $75bn, well over a tenth of gross domestic product last year. In the five years to 2015, the government exceeded its budgeted expenditures by a quarter on average. Even with a recovery in oil prices to about $50 a barrel this year, the country will struggle to close that gap.  Privatising Aramco is the first step in rebalancing the economy. By disentangling the company, which accounts for more than two-thirds of government revenues, from the state, Prince Mohammed hopes to make Riyadh less oil-reliant, while providing capital for investment in new industries, ranging from technology, where it is pumping $45bn into the SoftBank Vision Fund, to mining. The privatisation of its national champion is crucial to this process.

Congress Members Call Out Trump for Violating War Powers as He Considers Pushing Yemen Into Famine -- The White House is scheduled to consider this week a proposalfrom Defense Secretary Jim Mattis to directly engage the US military in Saudi Arabia's war against the Houthis in Yemen, including a planned United Arab Emirates attack on the port of Hodeida.  On Friday, March 31, the UN special envoy for Yemen warned against a military attack on Hodeida: "We as the United Nations are advocating that no military operations should be undertaken in Hodeidah." He warned that military action on the port could "tip the country into famine," according to Bloomberg Government. Former US officials have also warned that this attack could push Yemen into famine: There was an internal debate over the final year of the Obama administration about whether the United States should support potential future efforts by the coalition to take the Hodeidah port, but ultimately the administration decided against it, said Jeremy Konyndyk, a former top USAID official. "From USAID's perspective, we thought the US should strongly oppose this," Konyndyk, the former director of USAID's Office of Foreign Disaster Assistance, told Al-Monitor. ... He said, "From our point of view, it would be disastrous in terms of humanitarian impact if the coalition were to disrupt the aid pipeline and commercial pipeline that moves through that port. ... The view that we had at AID -- among AID leadership -- was that if that port were to be lost, it would likely be enough to tip the country into famine," Konyndyk warned. As Senate Foreign Relations Chair Bob Corker recently affirmed, US participation in this war has never been authorized by Congress: "Certainly engaging in a war against a group outside of ISIS [the Islamic State] is a step beyond the current authorization," Corker told Al-Monitor.

Trump Administration Stops Disclosing Iraq And Syria Troop Deployments In Bid To "Surprise" ISIS --The Trump administration has stopped disclosing material information about the size and nature of the U.S. commitment to military action in Iraq and Syria, including the number of U.S. troops deployed in either country, in a bid to "surprise" the Islamic State with the number of US troops in the region the LA Times reports.Earlier this month, the Pentagon quietly dispatched 400 Marines to northern Syria to operate artillery in support of Syrian militias that are cooperating in the fight against Islamic State, according to U.S. officials. That was the first use of U.S. Marines in that country since its long civil war began. In Iraq, nearly 300 Army paratroopers were deployed recently to help the Iraqi military in their six-month assault on the city of Mosul, according to U.S. officials.The decision appears to be making good on Trump’s promise as a candidate to insist on more of an “element of surprise” in battle tactics.“In order to maintain tactical surprise, ensure operational security and force protection, the coalition will not routinely announce or confirm information about the capabilities, force numbers, locations, or movement of forces in or out of Iraq and Syria,” said Eric Pahon, a Pentagon spokesman.While neither of those deployments were officially announced prior to their implementation, Gen. Joseph Votel, the top US commander in the Middle East did acknowledge the additional troop presence in Syria to the House Armed Services committee on Wednesday.  “They have deployed,” Votel said, adding that there were likely more troops headed for deployment. “We have recognized that as we continue to pursue our military objectives in Syria, we are going to need more direct all-weather fire support capability for our Syrian Democratic Force partners,” Votel told the committee. “We have not taken our eye off what our principle mission is, which is to advise and assist and enable our partners... Help our partners fight, but not fight for them.”A  representative of Operation Inherent Resolve (OIR) confirmed that “routine” troop deployment announcements will stop under Donald Trump as US forces want the Islamic State terrorists to be the “first to know about any additional capabilities the Coalition or our partner forces may present them on the battlefield.”

Civilian Casualties in Iraq, Syria Undercut US Victories | -- Islamic State group and al-Qaida-linked militants are quickly moving to drum up outrage over a sharp spike in civilian casualties -- said to have been caused by U.S. airstrikes in Iraq and Syria -- by posting photos online of a destroyed medical center and homes reduced to rubble. "This is how Trump liberates Mosul, by killing its inhabitants," the caption reads. The propaganda points to the risk that rising death tolls and destruction could undermine the American-led campaign against the militants. During the past two years of fighting to push back the Islamic State group, the U.S.-led coalition has faced little backlash over casualties, in part because civilian deaths have been seen as relatively low and there have been few cases of single strikes killing large numbers of people. In Iraq -- even though sensitivities run deep over past American abuses of civilians -- the country's prime minister and many Iraqis support the U.S. role in fighting the militants. But for the first time anger over lives lost is becoming a significant issue as Iraqi troops backed by U.S. special forces and coalition airstrikes wade into more densely populated districts of Iraq's second-largest city, Mosul, and U.S.-backed Syrian fighters battle closer to the Islamic State group's Syrian stronghold of Raqqa. That has the potential to undercut victories against the militants and stoke resentments that play into their hands. At least 300 civilians have been killed in the offensive against IS in the western half of Mosul since mid-February, according to the U.N. human rights office -- including 140 killed in a single March 17 airstrike on a building. Dozens more are claimed to have been killed in another strike last weekend, according to Amnesty International, and by similar airstrikes in neighboring Syria in the past month.

Brazen Overnight Attack in Tikrit Signals IS Resolve: Islamic State’s brazen overnight attack on Tikrit, killing at least 31 security personnel and civilians, is part of a series of diversionary attacks designed to mask its mounting losses in Mosul and portray that it has strength elsewhere in Iraq, analysts say. “IS might carry these attacks everywhere in Iraq,” said Michael Knights of the Washington Institute for Near East Policy, a research institution. Eighteen Iraqi police officers were among the dead in a series of coordinated strikes claimed by Islamic State (IS) late Tuesday and into Wednesday. Disguised as police Authorities say the attackers disguised themselves in police uniforms and drove police cars to gain access to the city – once a Baathist stronghold of former Iraqi leader Saddam Hussein. The militants stormed the residence of the city’s police colonel, killing him and several members of his family, according to reports. Two of the suicide bombers killed themselves, exploding the munitions in their vests after they ran out of firepower, according to officials. Five attackers were killed in clashes with Iraqi security forces.

Iraqi WMDs Anyone? Washington Post Makes Unfounded Claims Of Iranian Supplies To Insurgencies -- The Washington Post falls back into its 2005 mode of blaming Iran for the capabilities of a local insurgency. This time it is not Iraq where Iran is allegedly providing to insurgents, but Bahrain. Old and debunked claims are hauled up and propaganda from the U.S. proxy Sunni dictatorship is cited as "evidence". It is a top-right front-page story in the Sunday edition and thereby "important". It is also fake news.The headline: U.S. increasingly sees Iran’s hand in the arming of Bahraini militants.The core: The report, a copy of which was shown to The Washington Post, partly explains the growing unease among some Western intelligence officials over tiny Bahrain, a stalwart U.S. ally in the Persian Gulf and home to the Navy’s Fifth Fleet. Six years after the start of a peaceful Shiite protest movement against the country’s Sunni-led government, U.S. and European analysts now see an increasingly grave threat emerging on the margins of the uprising: heavily armed militant cells supplied and funded, officials say, by Iran. The authors insert caveats:While Bahraini officials frequently accuse Tehran of inciting violence, the allegations often have been discounted as exaggerations by a monarchy that routinely cites terrorism as a justification for cracking down on Shiite activists.But after noting that Bahraini authorities notoriously lie the authors regurgitate approvingly the claims of exactly those authorities: ... the country’s investigators said in a confidential technical assessment ... a copy of which was shown to The Washington Post ... That is supported, the authors say, by:  interviews with current and former intelligence officials ... Surly, "current and former intelligence officials" are paragons of truth and veracity and whatever they claim MUST be true.

Assad tells paper he sees no 'option except victory' in Syria | Reuters - Syrian President Bashar al-Assad said there is no "option except victory" in the country's civil war in an interview published on Thursday, saying the government could not reach "results" with opposition groups that attended recent peace talks. The interview with Croatian newspaper Vecernji List appeared to have been conducted before U.S. President Donald Trump accused Assad of crossing "many, many lines" with a poison gas attack on Tuesday. Assad was not asked about the chemical attack in the northwestern Syrian town of Khan Sheikhoun, a text of the interview published by the Syrian state news agency SANA showed. The government has strongly denied any role. More than six years into the Syrian conflict, Assad appears militarily unassailable in the areas of western Syria where he has shored up his rule with decisive help from the Russian military and Iranian-backed militias from across the region. The interview published on Thursday underlined Assad's confidence as he reiterated his goal of dealing a total defeat to the insurgency. He also reiterated his rejection of federalism sought by Kurdish groups in northern Syria. "As I said a while ago, we have a great hope which is becoming greater; and this hope is built on confidence, for without confidence there wouldn’t be any hope. In any case, we do not have any other option except victory," he said. "If we do not win this war, it means that Syria will be deleted from the map. We have no choice in facing this war, and that’s why we are confident, we are persistent and we are determined," he said.

Syria gas attack prompts France to call for emergency meeting of UN Security Council -- France has called for an emergency meeting of the UN Security Council following the suspected chemical weapons attack by the Syrian government on the northern province, Idlib.An estimated 65 citizens are dead, including 11 children under the age of eight, and another 300 are reportedly wounded. This marks the third report of a chemical attack in just one week in Syria.France’s Minister of Foreign Affairs, Jean-Marc Ayrault, called the attacks “atrocious,” and went on to describe them as a threat to national security.France, which is a permanent member of the UN Security Council, has supported Syrian rebels against President Bashar al-Assad for years and lobbied for an international military campaign against Assad over the use of chemical weapons in 2013.Despite the Syrian government denying responsibility, French President François Hollande didn’t mince words when blaming Assad for the attack.Hollande said in a statement that: “Once again the Syrian regime will deny the evidence of its responsibility in this massacre. Like in 2013, Bashar al-Assad counts on the complicity of his allies to act with impunity…Those who support this regime can once again assess the magnitude of their political, strategic and moral responsibility.”

Russia warns it will shoot down alliance jets over Syria if US launches air strikes against Assad - Russian forces could shoot down coalition jets if the United States launches airstrikes against pro-government forces in Syria, the Russian ministry of defence has said.American officials have reportedly discussed using limited airstrikes to force Bashar al-Assad’s government to halt its assault on Aleppo and return the negotiating table after a ceasefire collapsed last month. In Moscow’s starkest warning yet against Western intervention in the war, Russia’s chief military spokesman said that any airstrikes on government-held territory in Syria would be considered a “clear threat” to Russian servicemen.  US military planners should “carefully consider the possible consequences” of such action, Major General Igor Konashenkov said in a statement on Thursday.“Today, the Syrian army has effective S-200, Buk and other air defense systems, which have undergone technical renovation in the past year,” he said.“I remind US 'strategists' that air cover for the Russian military bases in Tartus and Hmeymim includes S-400 and S-300 anti aircraft missile systems, the range of which may come as a surprise to any unidentified flying objects,” he added. Russian air defence troops would not have time to identify the flight path of incoming rockets or aircraft that fired them, and would respond immediately, Maj. Gen. Konashenkov added.

U.S. strikes Syrian military airfield in first direct assault on Bashar al-Assad’s government WaPo. The U.S. military launched 59 cruise missiles at a Syrian military airfield late on Thursday, in the first direct American assault on the government of President Bashar al-Assad since that country’s civil war began six years ago. The operation, which the Trump administration authorized in retaliation for a chemical attack killing scores of civilians this week, dramatically expands U.S. military involvement in Syria and exposes the United States to heightened risk of direct confrontation with Russia and Iran, both backing Assad in his attempt to crush his opposition.Syria and Russia swiftly denounced the attack.A statement by Syria’s military said the U.S. “aggression” had killed at least six people and indirectly aided militant factions such as the Islamic State by weakening Syrian forces. Separately, Syria’s state news agency SANA reported that at least nine civilians, including four children, were killed near the air base. Neither report could be independently verified. In Moscow, Russia announced it was pulling out of a pact with Washington to share information about warplane missions over Syria, where a U.S.-led coalition is also waging airstrikes on Islamic State targets. Russian President Vladi­mir Putin called for an immediate meeting of the U.N. Security Council and his spokesman, Dmitry Peskov, called the U.S. missile strikes “violations of the norms of international law, and under a far-fetched pretext.”

ISIS, Al-Qaeda Praise Trump's Attack --Having perhaps lost the support of much of his anti-war base, President Trump appears to have won praise from two new groups... Ahrar Al-Sham, Tahrir Al-Sham (#AlQaeda) and #ISIS private Telegram channels praising #UnitedStates attack tonight.— Aldin ???????? (@CT_operative) April 7, 2017   Even even more ironic, today is the 100th anniversary of the United States entering World War One.

Russian PM: "US On Brink Of Military Clash With Russia" - In a statement on Friday morning, Russian Prime Minister Dmitry Medvedev said that the US missile strike violated not only international, and added that the attack “was on the brink of military clashes with Russia.”  “Instead of their much-publicized thesis about a joint fight with a common enemy, Islamic State [IS, formerly ISIS/ISIL], the Trump administration has proven that it will fiercely fight against the legal government of Syria,” Medvedev wrote on his Facebook page. Meanwhile, the International Committee of the Red Criss told Reuters that the situation in Syria "amounts to an international armed conflict" following U.S. missile strikes on a Syrian airbase. "Any military operation by a state on the territory of another without the consent of the other amounts to an international armed conflict," ICRC spokeswoman Iolanda Jaquemet told Reuters in Geneva in response to a query. "So according to available information - the U.S. attack on Syrian military infrastructure - the situation amounts to an international armed conflict." Previous air strikes on Syrian territory by a U.S.-led coalition have been against only the militant group Islamic State, which is also the enemy of the Syrian government. Russia has carried out air strikes in tandem with its ally Syria since Sept. 2015, while Iranian militias are also fighting alongside the troops of Syrian President Bashar al-Assad. ICRC officials were raising the U.S. attack with U.S. authorities as part of its ongoing confidential dialogue with parties to the conflict, Jaquemet said, declining to give details. The ICRC, guardian of the Geneva Conventions setting down the rules of war, declared Syria an internal armed conflict - or civil war, in layman's terms - in July 2012.,Under international humanitarian law, whether a conflict is internal or international, civilians must be spared and medical facilities protected. Warring parties must observe the key principles of precaution and proportionality and distinguish between combatants and civilians.

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