this past week saw oil prices crash back to levels we last saw before OPEC announced their production cuts at the end of November, which, if it holds, should serve to take some wind out of the sails of that drilling surge we've been seeing in this country over the last 6 months...the ability of OPEC 's cuts to relieve the oil glut had been questioned for some time now, but it was questions as to whether Russia would cooperate or not that precipitated the big Thursday selloff, that temporarily saw oil prices fall more than 8% in one day, before recovering a bit...
after closing last week at $49.33 a barrel, the price of US crude oil for June delivery continued falling on Monday, ending the day at $48.84 a barrel, as rising crude output from Libya and increased U.S. drilling threatened to reverse the effects of the OPEC production cuts...prices then tumbled $1.18 a barrel in a late day selloff on Tuesday, as the latest Reuters survey of OPEC production that showed compliance had fallen slightly was accompanied by a slew of other bearish news, including soaring fuel oil exports from Iraq and ongoing elevated crude exports from other OPEC countries, with June oil closing at $47.66 a barrel, the lowest front-month contract price since March 21st...oil prices then inched back up on Wednesday, closing at $47.82 a barrel, even as the EIA inventory data showed a lower than expected drawdown of 930,000 barrels, against market estimates of as much as 3 million barrels...oil prices then crashed on Thursday to their lowest level since the OPEC deal was announced, apparently after a Russian spokesman said no decision had yet been made on extending the oil output cut production deal, with US crude closing down $2.30 a barrel, or 4.8% at $46.47...prices continued falling in after hours trading Thursday evening, and were down as much as 3.9% more to $43.76 a barrel during Friday morning trading in Asia, before recovering to above the prior close before the US markets opened on Friday...US oil prices then bounced back from those 5 month lows in US trading on Friday, following assurances by the Saudis that Russia was ready to join OPEC in extending production cuts, as bargain hunters pushed prices back up 70 cents to close the week at $46.22 a barrel, still a loss of 6.3% for the week...
since we're just off of 5 month lows for the price of oil, we'll take a quick look at what a graph of the track of recent prices looks like....
the above graph below is a screenshot of the interactive oil price graph at Trading Economics, an online platform that provides historical data, economic forecasts, and trading recommendations...each bar on the above graph represents oil prices for one day of oil trading between November 10, 2016 and May 5th, wherein green bars represent days when the price of oil went up, and red bars represent days when the price of oil went down...on green or up days, the day's starting oil price is at the bottom of the bar and the price at the end of the day is at the top of the bar, while on red down days, the starting price is at the top of the bar and the price at the end of the day is at the bottom of the bar...this type of graph is called a candlestick, as the range of oil prices outside of the opening and closing price for any given period is indicated by a thin 'wick' above or below the "candlestick" part of the graph...thus we can see that on Friday morning, even though the price of oil was up 70 cents on the day, the price had briefly dipped below $44 a barrel in off hours trading...this graph also includes trading at the end of November, just before OPEC announced their production cuts on November 30th...after that announcement, prices jumped 14.2% in three days, and then continued to rise to $54 by late December, staying in the $51 to $54 range for 3 months….although we've just seen oil price drop around 15% over the past three weeks, my sense is that the bloom came off the OPEC rose in early March, when the price of oil broke out of its trading range and fell nearly 10%, as US crude supplies ran a streak of nine new record highs in a row....i think oil prices would have stayed below $50 a barrel since then, had it not been for the US missile attack on Syria, which precipitated the 10% price spike that you see on the chart above at the end of March into early April...absent that, this week's drop can be seen as a confirmation and continuation of the price drop that started in early March…
The Latest US Oil Data from the EIA
this week's US oil data for the week ending April 28th from the US Energy Information Administration indicated a substantial drop in our oil imports, which was offset by an almost as large drop in our oil exports, and a modest pullback in our refining of crude from last week's record levels, with the net result that we had to take a small amount of oil out of storage to meet refining needs for the fourth week in a row...our imports of crude oil fell by an average of 648,000 barrels per day to an average of 8,264,000 barrels per day over the week, while at the same time our exports of crude oil fell by 614,000 barrels per day to an average of 538,000 barrels per day, which meant that our effective imports netted out to 7,726,000 barrels per day during the week, just 34,000 barrels per day less than during the prior week...at the same time, our field production of crude oil rose by 28,000 barrels per day to an average of 9,293,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 17,019,000 barrels per day during the cited week...
at the same time, refineries reportedly used 17,177,000 barrels of crude per day, 108,000 barrels per day less than they used during the prior week, while 343,000 barrels of oil per day were being pulled out of oil storage facilities in the US....thus, this week's EIA oil figures seem to indicate that our total supply of oil from net imports, production and from storage was 185,000 more barrels per day than what refineries used...to account for that discrepancy, the EIA inserted a -185,000 barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the supply of oil and the consumption data balance out, which they label in their footnotes as "unaccounted for crude oil"
details from the weekly Petroleum Status Report show that the 4 week average of our oil imports rose to an average of 8,216,000 barrels per day, still 4.9% above the imports of the same four-week period last year...the 343,000 barrel per day decrease in our total crude inventories came about on a 133,000 barrel per day withdrawal from our commercial stocks of crude oil and a 210,000 barrel per day sale of oil from our Strategic Petroleum Reserve, part of an ongoing sale of 5 million barrels annually that was planned 19 months ago...this week's 28,000 barrel per day crude oil production increase resulted from a 25,000 barrel per day increase in oil output from wells in the lower 48 states and a 3,000 barrels per day increase in oil output from Alaska...the 9,293,000 barrels of crude per day that we produced during the week ending April 28th topped last week's 20 month high and is now up by 6.0% from the 8,770,000 barrels per day we were producing at the end of 2016, and up by 4.0% from the 8,938,000 barrel per day output during the during week ending April 29th a year ago, while it was still 3.3% below the June 5th 2015 record oil production of 9,610,000 barrels per day...
US oil refineries were operating at 93.3% of their capacity in using those 17,177,000 barrels of crude per day, which was down from 94.1% of capacity the prior week, even as this week's oil throughput was still the 2nd most oil we've refined in any week on record...the 17,177,000 barrels of crude per day refinery throughput was also 7.4% more than the 15,986,000 barrels of crude per day.that were being processed during week ending April 29th, 2016, when refineries were operating at 89.7% of capacity...
even with the week's nominal refining pullback, gasoline production from our refineries increased by 73,000 barrels per day to 9,783,000 barrels per day during the week ending April 28th, which was still a bit less than the 9,811,000 barrels of gasoline that were being produced daily during the comparable week a year ago....in addition, refineries' production of distillate fuels (diesel fuel and heat oil) increased by 38,000 barrels per day to 5,101,000 barrels per day, which was 11.2% more than the 4,589,000 barrels per day of distillates that were being produced during the week ending April 29th last year.....
with the increase in gasoline production, our gasoline inventories increased by a nominal 191,000 barrels to 241,232,000 barrels as of April 28th, after they had increased by more than 4.9 million barrels over the prior two weeks....this week's lower gasoline surplus came about because our imports of gasoline fell by 223,000 barrels per day to 693,000 barrels per day, while our gasoline exports rose by 107,000 barrels per day to 732,000 barrels per day....meanwhile our domestic consumption of gasoline fell by 50,000 barrels per day to 9,156,000 barrels per day, and continues to run at a pace 3% below that of a year ago... with the increase in our gasoline supplies, they are now just a small fraction off the 241,795,000 barrels that we had stored on the equivalent day a year ago, while they are 5.9% higher than the 227,852,000 barrels of gasoline we had stored on May 1st of 2015, and 13.2% more than the 213,180,000 barrels of gasoline we had stored on May 2nd of 2014…
meanwhile, even with the nominal increase in distillates production, our supplies of distillate fuels still fell by 562,000 barrels to 150,355,000 barrels during the week ending April 28th, because the amount of distillates supplied to US markets, a proxy for our consumption, increased by 589,000 barrels per day to 4,256,000 barrels per day...that was even as our exports of distillates fell by 34,000 barrels per day to 1,037,000 barrels per day and as our imports of distillates rose by 58,000 barrels per day to 112,000 barrels per day at the same time...while our distillate inventories are still 4.2% below the 156,979,000 barrels that we had stored on April 29th, 2016, following last year's warm El Nino winter, they remain 15.0% higher than the distillate inventories of 130,773,000 barrels that we had stored on May 1st of 2015, following a more normal winter…
finally, with a near record amount of crude still going to our refineries, our commercial inventories of crude oil fell for the 4th week in a row, as they decreased by 930,000 barrels to 527,772,000 barrels as of April 28th....nonetheless, we still finished the week with 10.2% more crude oil in storage than the 479,012,000 barrels we had stored on December 30th, and 3.1% more crude oil in storage than what was then a record high of 512,095,000 barrels of oil in storage on April 29th of 2016...we also ended the week with 16.2% more crude than the 454,079,000 barrels in storage on May 1st of 2015, and 44.2% more crude than the 366,004,000 barrels of oil we had in storage on May 2nd of 2014...
This Week's Rig Counts
US drilling activity increased for the 26th time in the past 27 weeks during the week ending May 5th, but it was the smallest increase in the past 9 weeks....Baker Hughes reported that the total count of active rotary rigs running in the US increased by 7 rigs to 877 rigs in the week ending Friday, which was 462 more rigs than the 415 rigs that were deployed as of the May 6th report in 2016, and the most drilling rigs we've had running since August 28th, 2015, while it was 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 6 rigs to 703 rigs this week, which was more than double the 328 oil directed rigs that were in use a year ago, and the most oil rigs that were in use since April 24th 2015, while it was still down by more than half from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations also rose by 2 rigs to 173 rigs this week, which was also more than double the 86 natural gas rigs that were drilling a year ago, but down from the recent natural gas rig high of 1,606 rigs that were deployed on August 29th, 2008...meanwhile, one of the rigs that was classified as miscellaneous was shut down this week, leaving one, same as the miscellaneous rig count of a year ago...
one of the idled offshore drilling platforms offshore from Louisiana in the Gulf of Mexico started back up this week, which bought the the Gulf of Mexico count back up to 18 rigs, still down from the 23 working in the Gulf of Mexico a year earlier....the week also saw the first drilling offshore from Alaska this year, which brought the total offshore count up to 19 rigs, also still down from a total of 24 offshore a year ago...in addition, there was an additional drilling platform set up on an inland lake in southern Louisiana this week, which took the inland waters rig count up to 5 rigs, up from the 3 rigs on inland lakes a year ago...
rigs that were drilling horizontally increased by 4 to a two year high of 734 horizontal rigs this week, which was up from the the 318 horizontal rigs that were in use in the US on May 6th of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, a net of 4 directional rigs were added this week, bringing the directional rig count up to 67, which was also up from the 44 directional rigs that were deployed during the same week last year....however, 1 vertical rig was pulled out this week, reducing the vertical rig count down to 76 rigs, which was still up from the 53 vertical 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 basins...in both tables, the first column shows the active rig count as of May 5th, the second column shows the change in the number of working rigs between last week's count (April 28th) and this week's (May 5th) count, the third column shows last week's April 28th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 6th of May, 2016...
as you can see, there were a lot of changes this week, despite the smaller net increase...by itself, that 7 rig increase in the Permian basin of western Texas and southeast New Mexico could have accounted for the entire week's increase, while other Texas basins saw no net change...the 4 rig increase in Louisiana includes the one in the Haynesville, and the aforementioned Gulf of Mexico and inland lakes rigs...meanwhile, the 7 rig drop in Oklahoma looks like it can be accounted for in total by rig shutdowns in the three Woodford basins and in the Mississippian, which straddles the Kansas border...the 3 rig drop in the Marcellus includes one in Pennsylvania, one in West Virginia, and one in New York...i had missed that the March 17th startup of that well in New York had targeted the Marcellus, assuming they wouldn't try fracking in a state where it was banned; now that rig has shut down....also note that the total count for the major basins is negative; that's because 6 oil rigs and 4 gas rigs started drilling in other unnamed basins...we would venture a guess that one of them is on the Alaskan north slope, where they are trying fracking for the first time...another might be in the Rogersville shale, since Kentucky, not shown above, also added a drilling rig this week, in their first drilling since December 2nd...(NB: after further research, the new Kentucky rig proved to be a directional rig in Bell county, outside of the Rogersville on most maps)
International Rig Counts for March
Baker Hughes also released the international rig counts for April 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 1,917 rigs were drilling for oil and natural gas around the globe in April, which was down from the 1985 rigs that were drilling around the globe in March, but up from the 1,424 rigs that were working globally in April of last year....another Spring-thaw related pullback in Canadian drilling was the reason for the drop, the 2nd global decrease after 9 months of increases, as the average Canadian rig count fell to 108 rigs in April from 253 rigs in March, which was still up from the 41 Canadian rigs that were deployed in March a year earlier, while the average US rig count rose from 789 rigs in March to 853 rigs in April, which was also up from the average of 437 rigs that were working in the US in April a year ago....outside of Northern America, the International rig count rose by 13 rigs to 956 rigs in April, which was also up from 946 international rigs a year ago, as increases in drilling in the Middle East, Asia and Africa were only partially offset by smaller decreases in drilling activity in Latin America and Europe..
drilling rigs deployed in the Middle East increased by 3 rigs to 389 rigs in April, up from 384 rigs a year earlier, after their drilling activity had increased by 4 rigs in March...both Pakistan and OPEC member Iraq added 3 rigs for the month, as the Pakistan count rose to 24 rigs, up from 23 rigs a year ago, while the Iraqis had 46 rigs deployed, up from 43 rigs a year earlier...on the other hand, Egypt shut down 3 rigs over the month, which cut them back to 27 active rigs, down from 30 rigs a year earlier...other drilling rig changes in the region included OPEC members Qatar and Abu Dhabi, who added one rig each, bringing them up to 12 rigs and 49 rigs respectively, while Kuwait and Oman shut down one rig each, cutting them back to 53 rigs and 56 rigs respectively...the Saudis stood pat with 119 rigs, which was down from the 123 rigs they were operating a year ago..
at the same time, drilling activity in the Asia-Pacific region was up by a net of 7 rigs to 205 rigs in March, which was also up from the 179 rigs working in the region a year earlier...Australia added 3 rigs and now have 16 rigs active, up from 6 rigs a year earlier...the Japanese started drilling for the first time this year with 3 rigs, also up from none a year ago...2 rigs were started offshore from China, where there are now 19 rigs active, down from 26 offshore rigs a year ago...Myanmar also added 2 rigs and now have 3 rigs working, same as a year ago...the Philippines also added a rig and now have two, same as a year ago...on the other hand, Brunei, Bangladesh, and Thailand all pulled out rigs in April, which left Brunei and Bangladesh with none, and left Thailand with 13 rigs still working...
meanwhile, the Latin American region saw their active drilling rig count decrease by a net of 3 rigs to 182 rigs, down from 203 rigs in April of last year, and down from 321 rigs as recently as September of 2015, as the region had idled 92 rigs over the first 6 months of 2016...Argentina shut down 9 rigs during the month, which cut their total back to 49 rigs, down from 73 rigs a year ago...Bolivia pulled out 2 rigs and thus had 3 active during the month, also down from 5 rigs a year ago, and Brazil cut back one rig and now has 15 active...on the other hand, Mexico added 4 rigs and thus had 22 rigs active, still down from 23 rigs a year earlier...OPEC member Venezuela added 2 rigs, bringing their total to up to 56 rigs, down from 69 rigs a year earlier.. .in addition, Trinidad added a rig and now has 7 rigs active, both Peru and Chile added a rig each, giving them both 2 rigs, with Peru up from 1 rig a year ago and Chile still down from 3 rigs a year ago...
drilling activity was also lower Europe, decreasing by 3 rigs to 91 rigs in April, which was still up from the 90 rigs that were working in Europe last April...Turkey shut down 2 rigs, leaving 21, which left them down from 29 rigs a year ago...in addition, offshore platforms were idled in several countries...Germans also shut down 2 rigs, leaving 2 active, down from 4 rigs a year earlier....Italy and Sakhalin Island also shut down 1 rig each, leaving them with 3 rigs and 11 rigs respectively...at the same time, Norway added two offshore figs and now have 17 rigs offshore, same as a year ago, and Austria started up their first rig in 2 years...
meanwhile, drilling on the African continent outside of Egypt saw a net increase of 9 rigs to 89 rigs in April, which was still down from the 90 rigs working in Africa last year at this time...OPEC member Algeria added 6 rigs and now have 57 rigs active, up from 55 a year ago...OPEC member Angola added two rigs and now has 4 rigs active...in addition, Gabon added their first rig since June of last year...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 19 rigs active in April, were included in the Asian totals here, apparently based on satellite intel, which is also the way much of the international oil production and export data is collected...
Coal-rich, but job-hungry, Appalachia waits for Donald Trump to deliver - cleveland.com - Coal employment also has fallen, across all of Ohio. In 2013, there were nearly 3,000 coal miners in Ohio, according to the Ohio Department of Natural Resources. By 2015, there were about 2,352. People here blame coal's demise and the region's overall industrial decline on government "over-regulation," which they blame on Democrats. They say: Federal subsidies for wind and solar farms are wrong-headed and not pro-job. Climate change is a distant issue. Good-paying jobs are the issue. "Forty years ago, you could get a job almost anywhere. The Valley was home to steel, coal and the chemical industry," said Dave Humphreys, Sr., a former coal employee who founded a metal fabricating company, Lion Industries, 22 years ago in nearby Bellaire, Ohio. Lion supplies coal mines with stamped steel parts. In recent years, Humphreys has had to lay off workers for the first time ever, as power plants began closing and coal production slowed across the region. "What people don't understand is that the economy here has been based on coal. Obama said he would regulate coal out of business. He practically did. I don't think politicians really understand the effect of regulations on business and on people. We need sensible regulations." Energy market analysts, however, say coal has suffered mostly because other forms of electrical generation, including wind and solar, are cheaper than coal. Natural gas has been especially cheap in the Ohio-Pennsylvania-West Virginia region, and, like coal, it can power plants around the clock.
Door to fracking in Ohio state parks could be re-opening - The Columbus Dispatch - For more than five years, Ohio Gov. John Kasich in effect has enforced a moratorium on fracking and other drilling in Ohio’s state parks. That could soon change. House Republicans have added a little-noticed provision into the state budget slated for passage today that would give the legislature, not the governor, the power to pick the members of a key commission. The General Assembly approved fracking in Ohio’s parks in 2011, and Kasich signed the bill. Under that law, a newly created Oil and Gas Commission was given the responsibility of approving potential drillers after completion of environmental and geological studies, determining the potential impact on visitors, seeking public input and meeting other requirements. But Kasich had a change of heart on allowing drilling on public lands. Even though the drilling law gave him until November 2011 to appoint commission, which then had until June 2012 to come up with rules, to this day he has not chosen a single member — meaning that nobody could get an OK to drill in parks. However, if the legislature gives itself the authority to pick the commission, the process toward fracking in Ohio’s parks presumably could get underway again. “This amendment is an effort to grant more legislative authority for filling the commission, with the goal of spearheading public discussion on these issues,” said Brad Miller, spokesman for Republicans who control the House 66-33. “The intention is not to steer the committee in any particular direction, but rather to fulfill a commission that was created by the General Assembly years ago.” A similar attempt was thwarted two years ago, when GOP lawmakers gave up on an attempt to remove the commission from the decision-making process, which also would have ended Kasich’s unofficial moratorium. A spokeswoman says Kasich still opposes fracking in Ohio parks. Before he changed positions, Kasich’s staffers and leaders of the Ohio Department of Natural Resources had prepared a detailed marketing plan to sell fracking in state parks to Ohioans.
Ohio House moves to bypass Gov. Kasich to OK drilling in state parks - Defying Gov. John Kasich, Ohio legislators took a key step Tuesday toward bringing fracking to state parks. House Republicans added a little-noticed provision to the state budget that would give the legislature, not the governor, the power to pick members of the state Oil and Gas Commission.That’s important because for more than five years, Kasich has effectively imposed a moratorium on fracking and other drilling in Ohio’s state parks by refusing to put anyone on the commission.The legislature approved fracking in Ohio’s parks shortly after Kasich took office in 2011, and the new governor signed the bill. Under that law, the Oil and Gas Commission was given the responsibility of approving potential drillers after completion of environmental and geological studies, determining the potential impact on visitors, seeking public input and meeting other requirements.But Kasich had a change of heart on allowing drilling on public lands. Even though the drilling lawgave him until November 2011 to appoint members of the commission, which then had until June 2012 to come up with rules, he has never chosen a member. The upshot is that no one could get an OK to drill in parks. However, if the legislature gives itself the authority to pick the commission, the process to permit fracking in Ohio’s parks could resume.“This amendment is an effort to grant more legislative authority for filling the commission, with the goal of spearheading public discussion on these issues,” said Brad Miller, the spokesman for House Republicans, who control the chamber 66-33. “The intention is not to steer the committee in any particular direction, but rather to fulfill a commission that was created by the General Assembly years ago.”
Ohio lawmakers add budget provision that could open state parks to fracking | Reuters: - legislators took a step toward allowing fracking in state parks, adding a provision in a pending budget that would strip the governor of the ability to control the issuing of licenses for the oil and gas drilling practice that has raised environmental concerns. The provision, added on Tuesday by the Republican-controlled House, would allow the state legislature instead of the governor to control appointments to the Oil and Gas Commission responsible for issuing drilling licenses for state lands. Governor John Kasich, a Republican, has not named any members to the four-member commission since signing the bill that created the group in 2011. This has effectively halted any fracking in parks. Fracking opponents complained that the legislature was now trying to find a way to allow fracking without the proper safeguards to ensure public safety. “It is an end run by Republicans in the legislature to facilitate more fracking and drilling in Ohio state parks,” David Leland, a Democratic state representative from Columbus who voted against the budget partly due to the measure, said on Wednesday.Proponents of the provision said it would not necessarily result in widespread drilling and fracking in state parks. “The provision is simply an attempt to fill that committee,” Ben Miller, spokesman for the Ohio House Republicans, said on Wednesday. Separately, four conservation groups have sued the U.S. Forest Service and Bureau of Land Management in an attempt to halt fracking plans in Ohio's only national forest. Nearly a fifth of Ohio has geographical potential for shale gas drilling, said Nathan Johnson, public director of the Ohio Environmental Council, an environmental group. The proposed budget must be approved by the Republican-controlled state senate by July 1.
Ohio City Plans Lawsuit to Stop Nexus Pipeline – EcoWatch - The battle over the controversial Nexus pipeline is heating up. Following a city council vote on Tuesday, the city of Green in Ohio will be spending $100,000 to hire an environmental law firm in Cleveland to stop its construction, the Associated Press reports. Canadian pipeline operator Enbridge and Detroit's DTE Energy plan to build the high pressure, 36-inch natural gas transmission line through 8 miles of the middle-class community. But the city of Green, located in northeast Ohio between Akron and Canton, has been working hard to stop the project. Just a few weeks ago, city council donated $10,000 to another group preparing its own lawsuit over the Nexus pipeline. According to Green's Planning Department, the pipeline encounters a large wetland as it enters the city, crosses nearly three streams for every mile and would be in close proximity to homes. The route would also cross a large agricultural farm that is being considered for future residential development.An analysis from Cleveland State University calculated that Green stands to lose $52 million over the course of 50 years due to the project, mostly due to a loss of income tax.The route also travels near or crosses several of Green's 10 city parks. Mayor Gerard Neugebauer told the AP that he could not allow families to use parks inside the estimated 1,500-foot blast zone a pipeline explosion could create. The city previously proposed an alternate route that would move the pipeline south into farmland but the Federal Energy Regulatory Commission (FERC) ruled against the plan in its final environmental impact statement. The proposed 255-mile Nexus pipeline will carry about 1.5 billion cubic feet of Appalachian shale gas per day from through Ohio and Michigan before ending at a hub in Ontario, Canada owned by Enbridge. Neugebauer told the AP that the Canadian company should not be allowed to take property from U.S. landowners.
Mayor Stands Up to Gas Pipeline Build - Green City, Ohio sits midway between Akron and Canton, has a population around 26,000, and has been named a Best Places by Sperlings website. The city also has Mayor Gerard Neugebauer who is taking on Big Energy by filing a lawsuit to stop Nexus Gas Transmission from burying 8 miles of pipeline in the middle-class community of Green .Neugebauer told The Associated Press that he will exhaust all options to stop Nexus Gas Transmission from burying 8 miles of pipeline in the middle-class community of Green . He said the pipeline could cost the city millions of dollars annually in tax revenues from lost economic development opportunities, lead to the abandonment of city parks and harm environmentally fragile wetlands.Neugebauer has the backing of the Green City council who authorized $100,000 this week to hire a Cleveland firm that specializes in environmental law.The high pressure natural gas pipeline proposed by Nexus Gas Transmission would be 255 miles long and would carry up to 1.5 billion cubic feet of gas per day from the Utica and Marcellus shale areas to the company's Dawn Hub in Ontario, Canada.Nexus Gas Transmission is a partnership of Canadian Enbridge and Detroit's DTE Energy . Enbridge merged this year with Houston -based Spectra Energy, DTE's original partner.Pipeline opponents argue that a Canadian company like Enbridge shouldn't be allowed to take property from U.S. landowners. An unknown number of property owners have refused to allow surveyors onto their property or negotiate easements for the pipeline and construction period. "I don't have animosity toward foreign companies," Neugebauer said. "But our government shouldn't be giving a foreign company more rights to property than the people who own the property."
Conservationists Sue to Halt Fracking in Ohio's Only National Forest - (Reuters) - Four conservation groups on Tuesday sued the U.S. Forest Service and Bureau of Land Management in an attempt to halt fracking plans in a portion of Ohio's only national forest. The suit, filed in U.S. District Court in Columbus, argues that the federal agencies failed to sufficiently analyze risks to watersheds, public health, climate and endangered species, including Indiana bats, before auctioning 670 acres (270 hectares) in December of the Wayne National Forest in Southeast Ohio for eventual hydraulic fracturing, or fracking, of underground shale. The groups are seeking an injunction to halt oil and gas leasing and development until a new assessment can be made. Fracking involves injecting water, sand and chemicals into wells to fracture shale and release natural gas and oil. U.S. Forest Service spokeswoman Babete Anderson declined to comment, citing pending litigation. Bureau of Land Management officials could not be reached immediately for comment. The Ohio Oil and Gas Association declined to immediately comment on the suit, but argued in a recent post on its website that fracking does not harm groundwater and increased natural gas use across, driven partly by fracking, has helped reduce air pollution. The portion for forest in question, known as the Marietta Unit, is located near Ohio's border with West Virginia along the Ohio River. The Bureau of Land Management's environmental assessment previously found no significant impact in opening leasing to gas and oil companies. Conservation groups who filed the suit, including the Ohio Sierra Club and the Ohio Environmental Council, argued fracking would bring roads, well pads and gas lines into the state's only national forest, destroy Indiana bat habitat and other threatened species and pollute watersheds and water supplies.
Ohio Environmental Council challenges fracking at Wayne National Forest | WSYX: The Ohio Environmental Council (OEC) announced they have filed a lawsuit against the U.S. Forest Service (USFS) and the U.S. Bureau of Land Management (BLM) over plans to frack the Wayne National Forest, the only national forest in Ohio. lawsuit was filed in federal district court in Columbus. “The Wayne is a public forest owned by every Ohioan and every American. The OEC is bringing this lawsuit because we want our children and grandchildren to know a Wayne that’s full of towering trees and thriving wildlife, not one that’s scarred by frack pads and pipelines,” said Nathan Johnson, Attorney and Public Lands Director for the Ohio Environmental Council. Johnson said he believes the law is on the OEC's side. “The agencies are required to closely review the environmental consequences of their leasing decisions, and they didn’t do their required homework," he added. "They refused to even acknowledge that oil and gas pipelines will be a major disruptive presence in the forest. We’re looking at a textbook legal failure on their part.” According to OEC, the BLM's stated intention is to lease off 40,000 acres of the Wayne National Forest’s Marietta Unit to oil and gas operators. They said this sets up approximately two-thirds of the Unit to be auctioned off in upcoming quarterly BLM lease sales. The Ohio Environmental Council said they are a not-for-profit, 501(c)(3) conservation organization whose mission is to secure healthy air, land, and water for all who call Ohio home.
Enviros Fight Fracking in Ohio National Forest - Courthouse News Service (CN) – Four environmental groups sued the U.S. Forest Service and Bureau of Land Management over their authorization of oil and gas leases that allow fracking of shale formations in Ohio’s only national forest. The Center for Biological Diversity, Sierra Club, Ohio Environmental Council and regional environmental organization Heartwood filed a lawsuit Tuesday in Columbus federal court challenging the legality of the new leases. The conservation groups say the Bureau of Land Management, or BLM, approved a plan to lease oil and gas companies 40,000 acres of federal land inside Wayne National Forest without taking a “hard look” at the consequences, environmental impacts and adverse effects of its actions. According to the lawsuit, BLM and Forest Service relied on an outdated, decade-old land and resource management plan – as well as a 2012 supplemental information report that was never subject to public notice and comment – when they authorized the new oil and gas leases in October. The conservation groups also claim BLM rushed the preparation of a 2015 environmental assessment and then determined that the plan would “not significantly affect the quality of the human environment” without properly analyzing threats to watersheds, public health, climate and endangered species like Indiana bats. The groups argue that hydraulic fracturing, or fracking, will industrialize Ohio’s only national forest with roads, well pads and gas lines. Such infrastructure, they say, would destroy animal habitats and pollute water supplies. “Both humans and wildlife species such as the endangered Indiana bat, river otter, bobcat, and Cerulean warbler, rely on the Wayne National Forest’s undeveloped woods, streams and rivers, and peace and quiet,” the lawsuit states. They’re also concerned about contamination from fracking chemicals and wastewater transported by trucks and pipelines. In their complaint, the groups highlight four times within the last three years that fracking activity near Wayne National Forest has contaminated streams and harmed wildlife.
Study Finds Fracking Is Strongly Related to Increased Infant Mortality: A new study of Pennsylvania counties published this week in the Journal of Environmental Protection shows for the first time that contamination from fracking kills babies. The Marcellus shale area of Pennsylvania was one of the first regions where novel gas drilling involving hydraulic fracturing of sub-surface rock, now termed 'fracking', was carried out. The epidemiological study by Christopher Busby and Joseph Mangano examines early infant deaths 0-28 days before and after the drilling of fracking wells, using official data from the US Centre for Disease Control to compare the immediate post-fracking four-year period 2007-2010 with the pre-fracking four-year period 2003-2006Results showed a statistically significant 29% excess risk of dying age 0-28 days in the ten heavily fracked counties of Pennsylvania during the four-year period following the development of fracking gas wells. Over the same period, the State rate declined by 2%. They conclude:"There were about 50 more babies died in these 10 counties than would have been predicted if the rate had been the same over the period as all of Pennsylvania, where the incidence rate fell over the same period."
US gas producer Consol lifts production guidance for 2017, 2018 -- US Appalachian gas producer Consol Energy raised its 2017 and 2018 production guidance Tuesday, with company executives saying it is poised for a two-year period of output growth as it reaps the benefits of improved drilling operations and cycle times, among other factors. Consol now expects production of approximately 420-440 Bcf of natural gas equivalent for 2017 and 490-520 Bcfe for 2018, company officials said during a first-quarter results conference call. This compares with the previous guidance of 415 Bcfe for 2017 and 485 Bcfe for 2018. The company reported strong natural gas production growth from its operations in the Marcellus Shale, where Q1 output jumped 17.3% year on year to 52.9 Bcf (588,000 Mcf/d). But production in the dry Utica Shale segment disappointed, falling 34.5% to 11.6 Bcf (129,000 Mcf/d) versus 17.7 Bcf (197,000 Mcf/d) in the year-ago quarter.Total oil, gas and natural gas liquids production produced for sales in Q1 fell 2.6% to 95 Bcfe (1.06 Bcfe/d), compared with the 97.5 Bcfe (1.08 Bcfe/d) in the same period of last year. Consol said this overall decline was driven primarily from the output drop in the dry Utica Shale segment.
Southwestern Energy, Ohio County Jostle Over Fire Service Fee - Wheeling Intelligencer — Accidents at Marcellus and Utica shale drilling pads can put a strain on the small volunteer fire departments assigned to cover the countryside. Although Ohio County has seen no large-scale problems at its several well sites, its Commission and Fire Board in 2015 voted to impose an annual fire service fee of $5,000 per well pad, regardless of how many wells are on the pad in question. Therefore, the county sent a $145,000 bill to Southwestern Energy Co. — the only company with active horizontal drilling and fracking operations in the county — for 2016. Instead of paying the bill, however, Southwestern officials hired legal counsel to challenge the county’s right to impose such a fee. The Houston, Texas-based firm is questioning whether the county met the state-imposed threshold for the required number of signatures to impose the fee, while also calling the fee “arbitrary and excessive.” The legal battle is now set in Ohio County Circuit Court, although there have not yet been any hearings scheduled. “Southwestern Energy supports local first responders.. We are supportive of an equitable and reasonable fire fee, but as it is written, natural gas producers are not being treated fairly,” company spokeswoman Christina Fowler said. “The industry has been singled out and charged an arbitrary and excessive fee. In 2014, Southwestern paid $5 billion to acquire the West Virginia assets of Chesapeake Energy. County officials in 2010 signed a lease agreement for several hundred acres in the vicinity of The Highlands with Chesapeake, while the Wheeling Park Commission and city of Wheeling also leased the mineral rights under Oglebay Park to Chesapeake.
Daily Mail editorial: Fracking not the problem some make it out to be - Hydraulic fracturing of natural gas wells has not contaminated groundwater in northwestern West Virginia, according to a study by Duke University scientists released this month. But accidental spills of fracking wastewater may pose a threat to surface water in the region, the scientists said.The three-year study, funded by the National Science Foundation and the Natural Resources Defense Council, concluded what many in the natural gas industry have been saying for years: The extreme risks opponents claim fracking poses aren’t true.That’s not to say the industry shouldn’t continue to be careful and deliberate in its fracturing process. And gas drillers and their associates must learn to be more careful when handling fracking wastewater, which comes back out of the gas well after the hydraulic fracturing procedure and must be disposed of in permitted facilities. While natural gas and oil wells have been fractured for generations, the technology of hydraulic fracturing to access huge gas reserves in the much more compact Marcellus, Utica and other shales came into use in the late 2000s. Fear combined with considerable misinformation has caused a subculture of hysteria about fracking, yet study after study has shown problems with fracking during drilling are minimal. “Currently there is no scientific data that demonstrates that hydraulic fracturing is intrinsically unsafe compared to other oil and gas wells,” said Timothy Carr, professor of geology at West Virginia University in December 2014. At that time, he called for more research, which the Duke study has provided.“Based on consistent evidence from comprehensive testing, we found no indication of groundwater contamination over the three-year course of our study,” said Avner Vengosh, professor of geochemistry and water quality at Duke’s Nicholas School of the Environment in a news release. “However, we did find that spill water associated with fracked wells and their wastewater has an impact on the quality of streams in areas of intense shale gas development.” “The bottom-line assessment,” he said, “is that groundwater is so far not being impacted, but surface water is more readily contaminated because of the frequency of spills.”
More Rigs Don't Mean More U.S. Gas - U.S. natural gas producers are running hard to stand still. The number of rigs drilling for gas has almost doubled since August, but output continues to fall. Even accounting for a lag between the start of drilling and first production, the drop in output is striking -- a well in the Marcellus Shale, America’s most prolific reservoir of the fuel, is producing about half of what it yielded a year ago, according to Bloomberg Intelligence. Companies are struggling to overcome steep decline rates -- the natural decrease in production -- from shale formations that were the source of huge added supplies in years past. The slowdown could signal an end to a glut that’s sent prices down 12 percent since the beginning of the year, making gas one of the worst performers in the Bloomberg Commodity Index. Hedge funds have boosted bullish bets that output will fall short of demand as cheap U.S. supplies head to Mexico and overseas buyers.as production has been “pretty abysmal,” Tom Ward, chief executive officer of Mach Resources LLC and co-founder of Chesapeake Energy Corp., said in an interview Wednesday with Bloomberg Television. Unless prices rise enough to boost output, “we’re going to be short gas going into the winter.” Producers have to drill at a breakneck pace just to keep output stable -- a phenomenon known as the Red Queen, after the character in Lewis Carroll’s “Through the Looking-Glass” who tells Alice, “It takes all the running you can do, to keep in the same place.” While the number of gas rigs has climbed 90 percent over the past year, output of the fuel in the lower-48 states is down 1.1 percent, data from Bloomberg and Baker Hughes Inc. show. “The life cycle of the wells that have been drilled are coming to an end,” said John Borruso, director of natural gas trading at Consolidated Edison Inc.’s Con Edison Energy in Valhalla, New York. “I see production coming online slowly.” For gas wells brought online since 2014 in the Marcellus, located primarily in Pennsylvania and West Virginia, the average 12-month decline rate is 51 percent, said Will Foiles, an analyst with Bloomberg Intelligence in New York. That means that a well in the reservoir that started producing a year ago at 10 million cubic feet a day is now yielding only 4.9 million.
What if Fracking the Marcellus Shale Doesn't Pan Out? -- For the gas industry and some utilities that are racing to build as much gas infrastructure as possible, there's a lot riding on a shale gas "play" known as the Marcellus. U.S. shale gas production (i.e. from hydraulically fractured wells) has grown steeply over the past 17 years and is now 67 percent of total U.S. natural gas. Gas prices have historically been extremely volatile, but gas companies and utilities are saying that it will stay low for a long time—almost indefinitely—and they base much of that argument on the Marcellus, the largest source of fracked gas in the U.S. The chart below shows the volatility of natural gas since 1997. The two biggest spikes are Hurricane Katrina (August 2005) and the run-up in oil and gas costs which peaked in July 2008 with oil at $147/barrel and natural gas at $13/MMBtu. Despite the extreme ups and downs of natural gas pricing, the U.S. Energy Information Administration's (EIA) 2017 Annual Energy Outlook projects that the cost of natural gas will remain at bargain-basement levels from 2030 to 2040 at $5.00 per MMBtu. This is 20 percent below what EIA forecast in its 2015 Annual Energy Outlook price forecast over the 2015-2040 period. While the increase in U.S. shale gas production is stunning, so are the decline rates for individual wells, which average 75-85 percent decline over the first three years. As geoscientist David Hughes points out, a steep decline rate for each well means that 30-45 percent of a play's production must be replaced each year by more drilling. In some areas of the U.S., spacing of gas wells has dropped from 1 well pad per 240 acres to 1 well pad per 10 acres. A good example is the Haynesville shale play, which started at nearly zero in 2006 and shot up quickly until peaking in early 2012. As of 2017, the Haynesville is down by 52 percent. Despite the obvious decline in production, the EIA recently predicted an ever-higher output from the Haynesville, so that it will nearly double its 2012 peak and continue producing gas past 2040. The Marcellus shale play currently provides over a third of total U.S. shale gas produced and is mainly in Pennsylvania but also includes eastern Ohio, northern West Virginia and southern New York state. The top five shale-producing counties in Pennsylvania have accounted for 65 percent of cumulative production from the Marcellus play, demonstrating the fact that most gas is produced from a few "sweet spots." The EIA's overblown estimate of future gas supplies is higher for the Marcellus shale than any other play.
U.S. lower 48 natgas output up by most in nearly 3 years in February: EIA | Reuters: U.S. gross natural gas output in the lower 48 states jumped by the most in almost three years to 80.2 billion cubic feet per day in February, the U.S. Energy Information Administration (EIA) said on Friday in its monthly 914 production report. The 1.8 bcfd increase in February over January was the biggest monthly increase since April 2014 and the first monthly increase in three months. Gross production in February climbed to its highest since August 2016. That compares with the record 82.6 bcfd hit in February 2016. Output increased in all three of the biggest lower 48 producing states - Texas, Pennsylvania and Oklahoma. In Texas, the largest gas-producing state, output in February increased for the first month in 10, up 0.7 bcfd to 21.3 bcfd. That was the biggest monthly increase in the state since March 2011. In Pennsylvania, output rose by 0.3 bcfd to a monthly record high of 15.2 bcfd in February. That was the fourth monthly increase in a row. Production in Oklahoma increased by 0.2 bcfd to 6.5 bcfd in February. That was its biggest monthly increase since March 2015.EIA also reported dry gas production for February, but did not break out individual states. U.S. dry production, including Alaska, increased to 72.1 bcfd in February from 70.7 bcfd in January. Monthly dry gas production peaked in April 2015 at 75.0 bcfd. Gas production declined in 2016 for the first time since the start of the shale revolution a decade ago as low energy prices reduced drilling activity. Next-day gas prices at the Henry Hub benchmark in Louisiana averaged $2.49 per million British thermal units in 2016, the lowest annual average since 1999. Prices averaged $2.61 in 2015, which before last year was also the lowest since 1999.
Natural Gas Prices In Peril, As Production Rises Most In Three Years - The U.S. Energy Information Administration (EIA) announced the biggest jump in the natural gas output rate for the lower 48 states in three years on Thursday in the agency’s monthly production report. Production stood at 80.2 billion cubic feet per day (bcfd) in February, up 1.8 bcfd from January. Gross gas production figures for February stood at their highest since August 2016, but February 2016 still holds the record for most production at 82.6 bcfd.Texas, Pennsylvania, and Oklahoma – the three most prolific gas-producing states – all saw new gas production, the latest numbers show.Texas gas figures jumped by the first time in 10 months, marking the biggest increase since March 2011. Pennsylvania saw the fourth month of production spikes in a row and Oklahoma witnessed the largest output increase since March 2015.While natural gas production declined in 2016, the agency said in its April Short Term Energy Outlook report that it expects this trend to be reversed in 2017, with natural gas production increasing by 0.8 billion cubic feet per day. The forecast for 2018 predicts an additional increase of 4 bcf/d. Higher prices in natural gas, expected to rise from the March level of $2.88 to an average of $3.10 in 2017, with a further increase to $3.45 in 2018, will likely contribute to a decline in the share of electricity supplied by natural gas in the coming years, as gas loses its competitive edge. Surprisingly, the EIA predicts that natural gas’ share will fall from 34 percent to 32 percent by 2018, while that of coal will increase from 30 percent to 31 percent. Non-hydropower renewable energy (solar and wind) will see a modest increase from 9 percent to 10 percent, the STEO added.
The Northeast Desperately Needs More Pipelines – IER - In a new report, the Chamber of Commerce quantified the economic and job losses arising from limiting natural gas infrastructure development in the U.S. Northeast where several states, including Massachusetts, Connecticut, and New York, have denied construction of natural gas pipelines. According to the report, if no new pipelines are built, it would cost the region over 78,000 jobs and $7.6 billion in GDP by the year 2020,[i] and the displacement of over $4.4 billion in labor income.[ii] In New York, Governor Cuomo’s Administration denied permits to natural gas pipelines, after banning hydraulic fracturing in the state. His state could be drilling its own natural gas if it were not for the ban on hydraulic fracturing. Now, the state’s Department of Environmental Conservation has denied certification to the proposed Northern Access pipeline and water permits sought by the Constitution Pipeline.[iii] Cuomo has also fought the Algonquin Pipeline expansion and has been dawdling on an 8-mile spur to a new power plant in Wawayanda.[iv] In Massachusetts, the Supreme Judicial Court ruled against energy companies having electricity consumers pay for the costs of new natural gas pipelines.[v]Without additional pipelines, New England will be importing higher cost liquefied natural gas (LNG) to its terminal on the Mystic River in Boston Harbor. That terminal is the only LNG facility in the United States importing LNG; the others are being converted to export facilities. New England is over 50 percent dependent on natural gas for its electricity as coal and nuclear plants have been shuttered.Specifically, the Massachusetts ruling blocks a financing plan for a $3 billion regional gas pipeline, the Access Northeast pipeline project, which was intended to expand the existing Algonquin gas pipeline in Massachusetts, Rhode Island, and Connecticut. Access Northeast was expected to save New Englanders approximately $1 billion a year. This is the second project to be blocked. Kinder Morgan, the nation’s biggest energy infrastructure company, dropped its plan for the Northeast Energy Direct project because of a lack of assurances that electricity ratepayers would pay for the $3.3 billion pipeline. The Northeast Energy Direct plan would have included a spur line into Connecticut to bring natural gas from the Marcellus shale regions of Pennsylvania.[vi]
Va. climate protesters say Dominion gas pipeline requires ‘mountaintop removal’ - Bill and Lynn Limpert rallied outside Gov. Terry McAuliffe’s Capitol Square offices Thursday with a poster-sized photo of themselves back home in rural Bath County, standing at the foot of a massive sugar maple. Measuring 12 feet around, the tree is part of an old-growth forest that the Limperts said would be removed — along with 38 miles of mountaintop — if Dominion Power is allowed to build a natural gas pipeline through rural Virginia. The two retirees were part of an environmental protest that claimed Dominion’s proposed Atlantic Coast Pipeline will require “mountaintop removal” — something the company says is not true.The environmental group Chesapeake Climate Action Network organized the protest to draw attention to a new study it conducted. It concluded that Dominion would have to “decapitate” some mountains along the pipeline’s 600-mile route, which would begin in north-central West Virginia, cross through western and southern Virginia, and end at the southernmost end of North Carolina.“Dominion Resources intends to blast away, excavate, and partially remove entire ridge tops along 38 miles of Appalachian Mountains as part of the construction of the Atlantic Coast Pipeline,” the study said.Aaron Ruby, media relations manager for Dominion Energy, said the group is wrong. “The claims that Chesapeake Climate Action Network has made about mountaintop removal are just totally false,” he said. “It’s a total mischaracterization of how we build pipelines on ridge tops.” The demonstration came at an awkward time for McAuliffe (D) and the Democrat he would like to succeed him, Lt. Gov. Ralph Northam. Both have said they would support the pipeline if it can meet tough environmental standards. Northam’s rival in the June 13 Democratic primary, former congressman Tom Perriello, opposes the project and has been trying to use his stance to woo liberal voters.
An LNG export terminal on the Chesapeake Bay -- The contiguous U.S. natural gas market is on its way to having its second major LNG export terminal and a new source of demand in the Northeast region by the end of the year. Dominion’s Cove Point liquefaction project, located on the Chesapeake Bay in Calvert County, Maryland, last month received approval from the Federal Energy Regulatory Commission (FERC) to introduce fuel gas, signaling the start of commissioning activities, a precursor to start-up activities for the liquefaction train itself. Dominion also last November applied for permission from the Department of Energy to export up to 250 Bcf of LNG during pre-commercial operations starting as early as fourth-quarter 2017, and is awaiting a response. Once operational, the facility, which is located within just a few hundred miles of the Marcellus/Utica shales — will have access to one of the primary southbound pipeline corridors for Marcellus/Utica takeaway capacity and add nearly 0.8 Bcf/d of demand to the Northeast gas market. Today we provide a detailed look at the Cove Point LNG facility. Cove Point’s liquefaction project — a single-train facility with a nameplate capacity of 5.25-million ton per annum (MTPA) — is poised to be the second LNG export terminal to come online in the contiguous United States, following Cheniere Energy’s Sabine Pass LNG, which first began exporting cargoes in February 2016. Cove Point also will be the first export train on the East Coast. Like Sabine Pass, the Cove Point liquefaction project is a brownfield project, meaning it is being built at an existing facility with a long history of LNG import and regasification. The terminal was originally designed to regasify imported LNG and move it into the U.S. gas pipeline system to serve regional demand. Figure 1 shows a map of the existing LNG facility and interconnecting pipelines. The import terminal itself, the green diamond in Figure 1, comprises seven storage tanks totaling 14.6 Bcf, six electric generation units and a tunnel that connects the onshore facilities with an offshore pier, which can receive and offload LNG cargoes carrying as much as 267,000 cubic meters of LNG per ship. The peak send-out of Cove Point (i.e., east to west flows) is 1.8 Bcf/d.
Trump admin's push for gas exports faces market glut — The Trump administration is moving to make the United States the world’s leading exporter of natural gas as a central component of both energy and trade policy. But whether global markets, currently awash with gas, will play along remains a long shot over the next several years. Any breakdown of talks to remodel the North American Free Trade Agreement, which set the regulatory framework that allowed gas exports to Mexico to triple over the last six years, could also get in the way. The administration’s ambitions were explained emphatically last month by Gary D. Cohn, director of the National Economic Council, and they were followed up by the Energy Department’s authorization last Tuesday for a Texas export terminal that Exxon Mobil and Qatar Petroleum have pursued for years. Other administration plans include opening the way for more gas exports from Oregon to serve Asia. In recent years, there was strong domestic opposition to the exports, from manufacturers and others, out of fear that domestic gas prices would rise, and the Obama administration moved cautiously before increasing the pace of export terminal permit approvals during its second term. With supplies appearing bountiful, and other countries aiming to increase their own production, opposition has mostly abated, except in pockets of the East Coast and Pacific Northwest. There remains enthusiastic support along the gulf coasts of Louisiana and Texas, where there is substantial room for more growth. For the Trump administration, the economic benefits of gas export infrastructure are paramount. Each natural gas export terminal can require an investment of $10 billion or more, produce thousands of construction jobs and consume millions of pounds of steel. Then there is the additional drilling and production of gas, which is then cooled to minus 260 degrees, condensing it to a liquid known as liquefied natural gas, or L.N.G., to be shipped on giant tankers to Asian, European and Latin American markets. The recent expansion of the Panama Canal has quickened the route to growing markets in Japan, South Korea and elsewhere in Asia, making American gas more competitive. “Exporting L.N.G. meets many objectives, including helping to address the trade imbalance,” said Daniel Yergin, the energy historian and vice chairman of IHS Markit, a consultancy. “This supports jobs, this supports investment in energy, this supports exports, a whole host of administration objectives.”
Panama Canal to see daily LNG carrier transits within 4 years, says CEO - The number of LNG carrier transiting the Panama Canal could average one a day by 2021 as more US supply comes on stream and targets demand in North Asia, according to Panama Canal Authority CEO Jorge L. Quijano. "During the past nine months of operation of the Panama Canal we have seen LNG flows that we never expected a few years back," Quijano said on the sidelines of the Sea Asia Conference, held in conjunction with the Singapore Maritime Week 2017 last week. The initial projection was for one LNG ship a week but this had already reached three to four ships, he said. Much of the future traffic will be driven by emerging LNG exports from the US, of which some will pass through the canal, he said. Cheniere has three fully operational LNG trains at Sabine Pass on the US Gulf Coast, with a fourth train undergoing commissioning expected to reach substantial completion in second half 2017, the company said in April. Train five is currently under construction and slated to become operational in 2019, and train six fully permitted and being commercialized, it added. Cheniere also has two trains under construction at its liquefaction project near Corpus Christi in Texas, with operations at both trains expected to begin in 2019, the company said. Other US LNG projects slated to start production in the near future include Freeport LNG, Cameron LNG in Louisiana and Cove Point LNG. "The prospects are really good for LNG transits for us and as you have more LNG and more fracking, there will be more LPG as well," Quijano said.
Texas economy could boom with Gulf Coast LNG export projects, group says | MDU Message Board Posts: LNG export projects planned for Texas' coast could have a total economic impact of about $145 billion of dollars and create thousands of jobs if approved by federal regulators, according to an industry group courting support for the proposed ventures. Texans for Natural Gas said in a report that seven LNG export projects proposed or under construction in the state could raise $20 billion or more in tax revenue, create more than 135,000 jobs and have a total economic impact of roughly $145 billion. In addition to regional benefits, projects like the Freeport LNG export expansion could slightly reduce the U.S. trade deficit, the group said. Roughly a third of U.S. LNG export projects are planned for Texas, which along with Louisiana has a natural gas pipeline network that can feed liquefaction and export terminals along the Gulf Coast. Freeport LNG Development LP's Freeport and Cheniere Energy Inc.'s Corpus Christi LNG export projects are both under construction, and the Exxon Mobil Corp.-linked Golden Pass project recently received the last of its major regulatory permits. Three export projects for Brownsville, Texas, are in review at the Federal Energy Regulatory Commission, as is the Port Arthur LNG export terminal proposed to be constructed along the Sabine-Neches Waterway. The Trump administration has latched onto LNG export terminals as a way to fuel job creation and economic growth. Energy Secretary Rick Perry touted Golden Pass as a way to bolster the economy while making the U.S. "an energy dominant force."
Chemical industry split about the case for more US plants - The surge in investment into the US petrochemicals industry over the past seven years has been one of the biggest spending booms in a developed country this century. A series of giant new plants that will make chemicals used to produce plastics, from companies including Dow Chemical and ExxonMobil, are about to come online. A second wave of projects is now being proposed, as some chemicals producers become increasingly confident that the cheap gas feedstock that makes their spending possible will last for a long time. But the industry is split, with some companies questioning whether the market is strong enough to justify a fresh investment surge. A decade ago, the US petrochemicals industry seemed doomed to long-term decline, eclipsed by rivals in the Middle East, which had cheap oil and gas for feedstock, and in Asia, where the market growth was strongest. The US shale revolution transformed that outlook, unleashing a flood of cheap natural gas liquids such as ethane and propane, which are key chemical feedstocks. Since 2010 $85bn worth of petrochemicals projects have been completed or started construction, with about a further $100bn proposed, according to the American Chemistry Council. Together, these plants would employ more than 60,000 people when in service, the industry group has estimated. “We are the low-cost producer.” The biggest new opportunity in the US has been for ethylene “crackers”: plants that take ethane and convert it into ethylene, a building block for plastics. Dow, Exxon, Sasol of South Africa, and CP Chem, the joint venture of Chevron and Phillips 66, have built large crackers along the US Gulf of Mexico coast that will be starting up in 2017 and 2018. US ethylene production is set to rise from 25.8m tonnes last year to 34.2m tonnes next year, an increase of 33 per cent, says S&P Global Platts. Most of the additional output will go for export, typically after being converted to polyethylene pellets. As emerging economies adopt the habits of developed countries, their demand for plastics is growing 1.5 to 2 times as fast as their gross domestic product.
After DAPL, Pipeline Fight Moves to Louisiana - The next big pipeline battle is shaping up in the marshes of southwestern Louisiana. The 162-mile Bayou Bridge Pipeline is the last of a network of oilfield arteries that includes DAPL. The project would run from southeastern Texas to a Mississippi River terminal in St. James Parish, west of New Orleans, after crossing the Atchafalaya River basin—a 1.4 million-acre swath of cypress marsh and wetland forest that's a key rest stop for birds moving north and south along the Mississippi Flyway. "It's the largest swamp left in North America and it's historically the most critical habitat for migratory birds in the entire hemisphere," said Dean Wilson, executive director of Atchafalaya Basinkeeper. The murky waters of the Atchafalaya are teeming with fish, crawfish and crabs, making them a rich source of food for animals and people alike. Wilson's organization is part of a coalition of Louisiana environmentalists seeking to block the pipeline, which includes the Sierra Club's Delta Chapter . They're trying to prevent further injury to a state where the oil industry puts food on many tables, but also has inflicted deep and dramatic losses on the landscape. The Atchafalaya watershed is already crisscrossed with thousands of miles of pipe; one more "is one too many," said Darryl Malek-Wiley, a Sierra Club organizer in New Orleans. "As an ecosystem, it's actually more productive than the Everglades, as far as food value," Malek-Wiley said. "It's time to focus in on this and move forward in a positive way to protect the area, rather than to put more pipelines across it, which cause sediment backup and disturb the water flow through the basin." As an offshoot of the Mississippi River, the Atchafalaya is a major part of southern Louisiana's flood protection system. In 2011, when rising waters threatened Baton Rouge and New Orleans, the Army Corps of Engineers opened spillways that diverted some of that flow through the basin. It's also the only part of coastal Louisiana that gained land area over the past several decades, as a combination of sinking land, sea-level rise and erosion accelerated by industrial canals eats away at the rest of the state's shoreline. And it's not just the watershed that would be affected. Opponents say the 24-inch-diameter line would cross about 700 bodies of water, from bayous to backyard wells.
US' Mars heard at narrowest discount to cash WTI since Sept 2015: trade - The US Gulf of Mexico medium sour crude Mars traded Wednesday afternoon at its highest value relative to domestic benchmark West Texas Intermediate since fall 2015, a reflection of the global shortage for medium sours brought on by OPEC and non-OPEC production cuts. June-delivered Mars was heard to have traded at June cash WTI minus $1.10/b and minus $1.05/b after the NYMEX 1:30 pm CT close. Prior to the close, Mars was last heard to have traded at June cash WTI minus $1.15/b, equaling the April 6 and April 7 high values. The last time Mars was higher than cash WTI minus $1.05/b was September 1-2, 2015, when it traded at a roughly 75-cent discount to cash WTI, Platts data show. Mars hit a low of minus $5.40/b shortly after, in October 2015, and over 2016 averaged a $3.20 discount to cash WTI. Differentials generally trended higher with the overall crude market last year.
Little fanfare, but Gulf of Mexico oil still growing steadily | Reuters: As rapid growth in U.S. shale production grabs headlines and threatens to upend attempts by OPEC to balance oil markets, a more unsung sector of the U.S. industry is also hitting new output highs - the offshore Gulf of Mexico. While attention and investment is focused on shale, the Gulf is the among the most prolific oil source in the United States, producing more than Alaska, the West Coast and Rocky Mountains combined. The region churned out a record 1.76 million barrels per day of crude in January, trailing only Texas onshore production, which includes the growing Permian Basin. “The business can compete with tight onshore oil any day,” said Richard Morrison, regional president for the Gulf of Mexico for BP Plc (BP.L) speaking at the annual Offshore Technology Conference in Houston, where nearly 70,000 people from 120 countries are attending. The Gulf region is expected to add another 190,000 bpd before the end of the year, according to the U.S. Energy Information Administration. Growth should continue, according to consultancy RBN Energy, which expects production to rise by 300,000 bpd in 2018 from current levels. To get similar 2017 growth in Texas's Permian Basin, for example, drillers would need to double the current rig count from the current 342, according to a Reuters analysis of U.S. EIA data. Even if that were possible, incrementally added rigs might not be as productive as those currently drilling, as prime locations have already been claimed. Unlike shale, where price immediately governs production, Gulf production has proved relatively resistant to fluctuations in prices, fueled by projects approved before oil lost 80 percent of its value in less than two years.For production to ramp up further in the Gulf, however, producers will have to reckon with the idea that the more active shale region - where time horizons are shorter - might keep crude oil prices overall lower for longer, with little chance to break out of the $45 to $55 per barrel range.
Interior secretary starts process for offshore drilling expansion plan | TheHill: Interior Secretary Ryan Zinke officially began the process Monday to expand offshore drilling for oil and natural gas. At an industry conference in Houston, Zinke signed a secretarial order for the Bureau of Ocean Energy Management (BOEM) to start formulating a new five-year plan for drilling rights sales. Following on President Trump’s executive order Friday on the same topic, Zinke is asking BOEM specifically to consider allowing new offshore drilling in the Arctic Ocean, the mid- and south-Atlantic Coast and the entire Gulf of Mexico. BOEM is instructed to give expedited consideration of companies’ applications for seismic testing on the outer continental shelf, to study where and how much oil and natural gas exists in those areas. The agency will also review numerous regulations on the industry, including safety rules instituted after the 2010 BP Deepwater Horizon disaster, for potential changes or repeal. “You should be excited,” Zinke told the attendees at an event hosted by the industry-based Consumer Energy Alliance during the Offshore Technology Conference. “If you’re in the oil and gas and energy segment in this society … the stars are lined up,” he said. “We’re going to make jobs, we’re going to bring the economy ahead.” He said producing more offshore oil and gas is good for the economy, national security and even the environment, since the United States has strong safeguards for drilling.
Oil lobby pushes for offshore drilling in the eastern Gulf of Mexico -- The nation’s top oil group wants the Trump administration to allow offshore drilling in the eastern Gulf of Mexico. Bolstered by last week’s offshore drilling order from President Trump, the American Petroleum Institute (API) said Monday it wants regulators to consider allowing drilling in new tracts of the oil-rich Gulf of Mexico. “The eastern Gulf is in close proximity to existing production and infrastructure, and opening it would spur investment and economic activity that could create thousands of jobs and provide billions of dollars in government revenue,” Erik Milito, API’s upstream and industry operations group director, said during a conference call with reporters. Federal law prohibits oil drilling in the Gulf within 125 miles of the coast of Florida. That moratorium is due to expire in 2022, the same year the federal government is scheduled to finalize a new five-year drilling plan, though Milito said he expects Trump’s Interior Department to release a new drilling blueprint before then. Trump’s order, signed Friday, instructs the Interior Department to reconsider the offshore drilling restrictions the Obama administration put in place on Arctic and Atlantic drilling. It does not explicitly list the eastern Gulf of Mexico as an area where regulators should consider allowing drilling, but Milito said API hopes the administration will consider the region in its review. “We’re optimistic — we think that it would be essential, from an energy security standpoint, both for national security reasons and for the continuing demand for oil and gas that we’re going to see for a long time, for Interior to take a serious look at the eastern Gulf of Mexico," he said.
Pentagon wants offshore drilling ban maintained in eastern Gulf - The Pentagon wants to continue a ban on offshore drilling in the eastern Gulf of Mexico that’s set to expire in five years. A.M. Kurta, the acting under secretary of Defense for personnel and readiness, told a Florida lawmaker in a letter publicly released Monday that military training and related exercises in the eastern Gulf, which borders Florida, necessitate a continuation of Congress’s ban on drilling. The letter Kurta wrote to Rep. Matt Gaetz (R-Fla.) adds a new wrinkle to the Trump administration’s drive to dramatically increase offshore oil and natural gas drilling. Trump ordered the Interior Department to write a new plan for offshore drilling rights sales and to consider areas currently off-limits to drilling. An order signed Monday by Interior Secretary Ryan Zinke says the department will look at the entire Gulf of Mexico for potential drilling. And the oil industry is gunning for the eastern Gulf, telling reporters yesterday that drilling there could create thousands of new jobs and billions of dollars in new investment. But the Pentagon is pushing back against drilling in the eastern Gulf, near Florida. “The moratorium … ensures that these vital military readiness activities may be conducted without interference and is critical to their continuation,” Kurta wrote to Gaetz in response to a letter inquiring about the drilling ban. “Emerging technologies such as hypersonics, autonomous systems, and advanced sub-surface systems will require enlarged testing and training footprints, and increased DoD reliance on the Gulf of Mexico Energy Security Act’s moratorium beyond 2022. The moratorium is essential for developing and sustaining our nation’s future combat capabilities.”
Will Trump Spark An Offshore Drilling Boom? --- In a bid to fend off criticism over a dearth of achievements in his first 100 days in office, President Trump plans to sign a flurry of executive orders this week.Among them is an executive order intended to open up new areas of offshore oil and gas drilling. "This builds on previous executive actions that have cleared the way for job-creating pipelines, innovations in energy production, and reduced unnecessary burden on energy producers," a White House official told the Reuters earlier this week.The order calls for a “review of the locations available for offshore oil and gas exploration and of certain regulations governing offshore oil and gas exploration.”Specifically, the Trump administration is hoping to open up new areas to drill in the Gulf of Mexico, plus areas in the Atlantic and Arctic Oceans. The Obama administration had previously designated the Atlantic and the Arctic off limits, and did so in such a way as to make it legally very difficult for subsequent administration’s to reverse.The road to new drilling in the Arctic and Atlantic Oceans will be long and bumpy, for several reasons. First, any attempt to open up the Arctic and Atlantic Oceans will be met with tough litigation. The President’s authority to reverse the Obama administration’s move is debatable. Second, the Interior Department will have to include tracts of drilling in its Five-Year plan, and putting acreage into the plan requires extensive environmental analysis that could span several years, especially for the Atlantic Ocean, where no drilling has taken place yet. On top of that, even if the administration succeeds in leasing offshore acreage – which will be years from now at the earliest – who will be interested? Royal Dutch Shell already had a crack at the Arctic, spending $8 billion and almost a decade of work with nothing to show for it. In 2015, after completing one well in the Chukchi Sea with disappointing results, Shell abandoned the Arctic and wrote down its assets. Shell’s Arctic program came to a halt because of low oil prices and poor prospects in the Chukchi – President Obama shut down the Arctic only after Shell had given up on it. It was a colossal failure for a region that has routinely been hyped as the next big thing in oil exploration.
Trump’s reckless ocean drilling order imperils coastlines - The Trump administration will begin the process of allowing drilling off the Atlantic, Pacific and Arctic coasts, according to reports. The executive order will allow Interior Secretary Ryan Zinke to roll back protections on drilling for fossil fuels. The order could allow new oil drilling off the Pacific coast for the first time since the 1980s. Marcie Keever, Friends of the Earth Oceans and Vessels Program Director, issued the following statement: Trump’s effort to look busy on his 100th day in office by giving away our oceans to Big Oil is yet another example of how out of touch he is with the American people. From the 1969 Santa Barbara oil platform blowout, to the 1989 Exxon Valdez spill and the Deepwater Horizon disaster in 2010, we know that oil spills happen, and can never be fully cleaned up.The next oil spill is inevitable and will wreak havoc on our oceans, local economies and the lives of people who live on our coasts. Over and over again, oil companies have been irresponsible and reckless, endangering the livelihoods of people living near the ocean. The American people deserve an energy future that protects our oceans and our land, not one that devastates it. New federal offshore drilling leases have not been granted for the Pacific Ocean since the early 1980s, but that didn’t stop Trump and Zinke from turning back the clock today on decades of environmental protections. We will stand with communities in the Pacific, Atlantic and Arctic to fight against this giveaway of our oceans to Big Oil.
Environmental groups sue Trump administration over offshore drilling - A coalition of environmental groups on Wednesday sued the Trump administration over its efforts to expand offshore drilling, arguing the move violates the president’s legal authority, threatens a multitude of wildlife and could harm the fishing and tourism industries.The lawsuit, filed in a federal court in Alaska, comes days after President Trump signed an executive order aimed at jump-starting offshore drilling in the Arctic and Atlantic oceans, as well as assessing whether energy exploration can take place in marine sanctuaries in the Pacific and Atlantic. The policy could open millions of acres of federal waters for oil and gas leasing, just months after President Barack Obama withdrew the areas from possible development.At a signing Friday in the Roosevelt Room, Trump emphasized that the United States has abundant offshore oil and gas reserves and made clear his intention to tap them if possible. “We’re opening it up,” he said.Wednesday’s lawsuit argues that Trump’s executive order exceeds his constitutional and statutory authority. It notes that Obama used his authority under the Outer Continental Shelf Lands Acts to permanently end drilling in much of the Arctic and key parts of the Atlantic but says that no president has ever undone or reversed such a decision and that the law “does not authorize the president to reopen withdrawn areas.” “The permanent protections President Obama established for the Arctic and Atlantic Oceans were won with years of research, lobbying and organizing,” Gene Karpinski, president of the League of Conservation Voters, said in a statement. Until Wednesday, his group had never filed a legal challenge. “Offshore drilling and the associated threat of devastating oil spills puts coastal economies and ways of life at risk while worsening the consequences of climate change. Now, President Trump is trying to erase all the environmental progress we’ve made, and we aren’t about to go down without a fight.”
Trump's U.S. Looks Past Energy Independence to Global Dominance -- The U.S. is in the position to be energy-dominant, not just independent, thanks to fracking and plans to loosen drilling regulations, Interior Secretary Ryan Zinke said Monday. Oil production across the U.S. may increase by 17 percent to a record 10.24 million barrels a day by the end of next year as companies cut costs and become more efficient in drilling, especially in areas such as West Texas and North Dakota. Domestic output hasn’t surpassed 10 million barrels a day since 1970. At a time when OPEC and other producers are cutting output, U.S. exports surged above 1 million barrels a day for the first time. “In 1983, I was told we’re going be out of oil and fossil fuels definitively in 2003. That’s not true,” Zinke said at the Offshore Technology Conference in Houston. “And, you know, I always say God’s got a sense of humor -- he gave us fracking. And fracking is a game-changer -- certainly a global game-changer.” Zinke is pushing forward President Donald Trump’s plans to expand oil and natural gas drilling and reconsider regulations that might limit development of U.S. natural resources. Trump on Friday ordered Zinke to revise a five-year schedule for auctioning offshore drilling rights with the aim of potentially including territory left out by former President Barack Obama. “My task is to look at it look at where we’re going to make changes, recommendations across the board,” Zinke said. “The stars have lined up so we can create energy jobs."
The World Is Buying American Diesel as Fast as Refiners Can Make It - The international market has a message for American refiners: Stay calm and keep turning crude into diesel.While a global glut has pushed crude prices down to five-month lows, manufacturers of middle distillates can’t make enough to satisfy demand. A combination of seasonal events is giving refiners on both the Atlantic and Gulf coasts a chance to boost exports to Europe and South America.“Everybody is freaking out about high refinery rates” in the U.S., said Robert Campbell, head of oil products research for Energy Aspects in New York, as plants in the U.S. processed record levels of crude into refined products last month. Domestic demand for gasoline may be slipping in the U.S., but there’s no reason to panic when it comes to distillate.Argentine diesel demand peaks in the second quarter, and Brazil’s buying strengthened after late April when Petroleo Brasileiro SA raised wholesale prices 4.3 percent, Campbell said. Meanwhile, maintenance in Russia, the Middle East and Algeria has kept Atlantic Coast refiners busy sending diesel cargoes to Europe. Preliminary weekly data from the Energy Information Administration show that exports of distillate advanced to a record in mid-April. U.S. refiners were shipping 1.42 million barrels a day, or roughly five medium-sized tankers, abroad, mostly from the Gulf Coast. These shipments are run-of-the-mill for facilities in Texas and Louisiana, but it’s less common to see deliveries leave from the Atlantic Coast, which sent at least 1.55 million barrels to Europe and Algeria since April, Bloomberg shipping analysis shows. The surge in overseas demand is helping clear a domestic glut for middle distillates, a category that includes diesel and heating oil. U.S. diesel days of supply fell in April to 34.6, the lowest level since November 2015 and down from a 52-week high of 49.3 in January. There’s “no incentive” now to ship the middle distillate fuels from Houston to New York on their typical route along the Colonial Pipeline, Campbell said. And at least four more distillate tankers are booked to haul Atlantic Coast diesel to Europe in the next week, according to preliminary shipping fixture reports.
Saudis complete takeover of largest US refinery -- The Saudi national oil company Aramco took full ownership Monday of the largest U.S. oil refinery in the country at Port Arthur, Texas. Aramco and Shell founded the 50-50 joint venture called Motiva over two decades ago to build and operate the giant refinery, and had been in intense talks about dissolving the venture since last year. The deal was completed Monday with Aramco taking full ownership of the refinery, considered the crown jewel of the Gulf Coast, through its wholly-owned subsidiary Saudi Refining. The deal came two weeks after Trump administration officials met with a Saudi business delegation in Washington hosted by Secretary of State Rex Tillerson. The delegation was led by the Saudi foreign ministry to discuss U.S. investment opportunities in the Gulf kingdom as part of a plan to restructure the Saudi economy by 2030, including privatizing Aramco in 2018. Aramco said in a statement that the Saudi oil giant, the largest oil company in the world, owns the entire Motiva complex and its 24 fuel terminals. It also owns the rights to exclusively sell Shell-branded gasoline and diesel in Georgia, North Carolina, South Carolina, Virginia, Maryland, Washington, D.C., the eastern half of Texas and most of Florida, it said in a statement.
Looming Takeaway Constraints Out of the Hottest Shale Play - The highly attractive production economics of the Permian’s multistacked, hydrocarbon-packed Delaware and Midland basins all but guarantee that the region’s output of crude oil, natural gas and natural gas liquids will continue rising—possibly at an even faster rate than what we’ve seen lately. That raises an all-important question: Will there be sufficient pipeline takeaway capacity in place to keep pace with all that growth? If there isn’t, some Permian producers will suffer from downward pressure on local prices—and that may cause them to have second thoughts about the big bucks they paid to gain access to the best Permian acreage in the first place. A production-growth forecast and a deep-dive assessment of existing and planned pipeline takeaway capacity are at the heart of RBN’s new Drill Down Report on the Permian. Today we provide highlights from the new report. All you’ve heard is true: The Permian is back, bigger and badder than ever. Producer economics in the play’s Delaware and Midland basins are the best in the U.S., and half of all rigs drilling for crude oil in the U.S. are in the region. Put simply, the Permian, which covers parts of West Texas and southeastern New Mexico, has been the engine that has propelled U.S. crude oil production upward. As shown in the left graph in Figure 1, total production from all of the other major shale/tight oil basins—Eagle Ford, SCOOP/STACK, Niobrara, Bakken and Offshore Gulf of Mexico—is down from about 5 MMb/d in 2015 to about 4.3 MMb/d today. The number has been flat for the past six months. But there are potential problems looming on the Permian horizon. There is simply not enough midstream infrastructure to accommodate this astronomical growth. Even though almost 100 years of oil and gas production have supported the development of thousands of miles of crude, gas and NGL pipelines that crisscross the region, midstream developers are having a hard time keeping up with today’s incredible rate of production increases.
Once again, Permian producers fear takeaway constraints, price hits - Crude oil production in the Permian’s Midland and Delaware basins continues to rise, and producers in the red-hot shale play are hoping there will be enough pipeline takeaway capacity to handle all that growth. This is serious stuff—the Permian’s success the next few years will depend to a considerable degree on whether producers and the midstream sector can avoid the major constraint-driven price differentials between the Midland, TX hub, and destination markets like the Gulf Coast and Cushing, OK, that already have hit the Permian twice this decade. Today we discuss the prospects for another round of takeaway/price-differential trouble in the Permian as soon as late 2017/early 2018 and again in 2020-21. In our new Drill Down Report, “With a Permian Well, They Cried More, More, More,” we said that the Permian for the past two years has been the engine that has propelled U.S. crude oil production upward. As we’ve seen in fast-growing plays in the past, though—including the Permian itself—production growth sometimes outpaces the ability of takeaway pipelines to transport hydrocarbons to market, resulting in price differentials between the local hub and other, destination hubs that (1) hurt producers and (2) spur them to rein in output gains until enough incremental pipeline capacity comes online to bring production and takeaway capacity into balance. Fortunately for today’s Permian producers, the region has been a significant producer of crude oil (and natural gas and natural gas liquids—NGLs—for decades), and therefore had significant pipeline takeaway capacity in place before the play entered the current period of renewed growth. Conventional drilling in the Permian peaked in the mid-1970s at just over 2.0 MMb/d and then started a long, steady decline that accelerated when oil prices collapsed in 1986; by the mid-2000s, Permian crude oil production was down to less than 900 Mb/d. But then in 2010, the first significant use of the newly developed techniques—a combination of horizontal drilling and hydraulic fracturing—to produce hydrocarbons from previously unrecoverable formations started to show results. By the end of that year, Permian production was back over 1.0 MMb/d, and over the next six-plus years, volumes more than doubled. Today the Permian is producing more than 2.2 MMb/d—an all-time record—with more than 200 Mb/d in growth in the last six months alone.
In a Twist, Snow Is Keeping Natural Gas Prices Down in Texas -- Natural gas in balmy Texas is feeling the chill of California’s snowy peaks 1,200 miles away. West Coast power producers are ditching gas in favor of cheap, plentiful hydroelectric power, which is surging after the wettest year ever across the Northern Sierra Nevada range. Much of that moisture fell as snow which is now melting, soaking fields, filling reservoirs and, to the consternation of the Texas gas market, furiously spinning turbines. All that has left gas backed up in Western Texas with nowhere to go. Flows along Kinder Morgan Inc.’s El Paso pipeline, the main shipper of Texas gas to California, are down 28 percent since the start of the year. As California enjoys its bounty of water, Texas gas prices are sinking. “The snow pack in the middle to lower elevations is melting quite rapidly in the last two weeks,” “It’s a pretty good situation for hydro power.” Since the start of the year, California gas demand has plummeted 34 percent while hydro generation in the state is up 93 percent, according to data compiled by Bloomberg. Gas prices May 1 at the Waha Hub in West Texas fell to a discount of 42 cents per million British thermal units to benchmark Henry Hub gas in Louisiana, the biggest spread since March 2014, based on Intercontinental Exchange data as of Wednesday. The past winter left twice as much snow on the ground in parts of the Sierra Nevada as normal. Snow is like water in the bank and as temperatures reach into the 70’s and 80’s Fahrenheit, nature is making withdrawals. "California solar, and in this case, California hydro are starting to ramp up generation levels, which is starting to eat into gas demand in California," said Jacob Fericy, analyst at Bloomberg New Energy Finance. In the last two weeks, satellite measurements show that the equivalent of about 16 to 20 inches (41 to 51 centimeters) of rain has melted off the snow pack at elevations of 6,000 to 7,000 feet, or about the same level as Lake Tahoe, according to Molotch who is in California watching the progress. There’s about one inch of rain locked up in every 10 inches of fresh snow.
Lower Cleveland play grows along Oklahoma-Texas line - Oil & Gas Journal: Operators have reported 28 horizontal completions in southern Ellis County, Okla., in the past 18 months in a low permeability play for oil and gas in the lower member of the Pennsylvanian Cleveland formation. The 28 completions, some reported as Marmaton in regulatory filings, have averaged an initial 514 b/d of oil and 1.3 MMcfd of gas. Exploration and production companies have drilled more than 1,070 horizontal wells in the Cleveland reservoir in the Texas Panhandle and western Oklahoma since 1995, but most of the wells have been drilled and completed in the Upper Cleveland reservoir. Participants in the Lower Cleveland play include EOG Resources Inc., Chesapeake Energy Corp., Mewbourne Oil Co., Primary Natural Resources III LLC, and Plano Petroleum LLC. The Lower Cleveland sand at an average depth of 9,400 ft is 50-120 ft thick. It produces at higher average oil rates than the Upper Cleveland, and there is no depletion risk from prior production, said Plano Petroleum, a private Plano, Tex., independent. Geologic limits of the Lower Cleveland sand have yet to be defined by drilling, but mapping from deeper subsurface control indicates the best quality Lower Cleveland sand appears to be centered in southern Ellis and northern Roger Mills counties, Okla. Strong results have been reported with open-hole, packer-type completions and cemented completions. Plano Petroleum started a five-well horizontal program in mid-2011 and has completed two Lower Cleveland horizontal wells and one horizontal well in the shallower Tonkawa reservoir. The company has spudded two more Cleveland wells. The company’s first Lower Cleveland well, Nelwyn 1H-7 in 7-17n-24w, Ellis County, had an initial flow rate of 570 b/d and 1.7 MMcfd and recovered 31,315 bbl of oil, 10,727 bbl of natural gas liquids, and 69 MMCF of dry gas in its first 90 days on production.
Oklahoma's Largest Earthquake Linked to Oil and Gas Industry Actions 3 Years Earlier -- The strongest earthquake in Oklahoma's history likely was caused by oil and gas operators injecting vastly increased amounts of toxic wastewater underground three years before it struck, a new study suggests. Scientists from the U.S. Geological Survey analyzed injection data from the most active disposal wells in the area where the 5.8-magnitude earthquake hit last September. They found that there had been a sudden and dramatic increase in the amount of wastewater injected in the first half of 2013 at some of the wells. That contributed "a fair amount of stress on the fault and would have accelerated the natural faulting process significantly," said Andrew Barbour, a USGS geophysicist who led the study. The research was published Tuesday in a special edition of the journal Seismological Research Letters that focused on the earthquake, which struck the town of Pawnee on Sept. 3, damaging dozens of buildings. The findings expand on the growing consensus among scientists that the earthquake spike rattling America's midsection is linked to the oil and gas drilling boom. The research suggests that even years after heightened activity takes place, the risk of a big earthquake can remain.
Hundreds show up to take stand on Keystone XL - The five-member Nebraska Public Service Commission limited testimony to five minutes per person and as many people as could be heard in 10 hours, which turned out to be 135. Each person was allowed to speak only once. Commission member Tim Schram chaired the proceedings, calling each person forward to give testimony. Their words were recorded by Lincoln-based Latimer Reporting and now are part of the record that the commission will use in deciding whether the proposed route for TransCanada's pipeline through Nebraska is in the public interest. The approval process breaks new ground for Nebraska. It's the first time it has been used since the 2011 Major Oil Pipeline Siting Act gave oversight of routes to the Public Service Commission. Testimony proceeded orderly but at times drew out emotion, as landowners choked back tears while speaking of the generations who have farmed the fields that the $8 billion pipeline project would cross to connect Canadian oil to refiners on the U.S. Gulf coast. Pipeline opposition groups and labor unions both rallied large turnouts and had people lined up to testify on either side of the project. Bold Nebraska and the Sierra Club’s Nebraska chapter chartered buses that brought people from Omaha, Lincoln and the Atkinson area.
Ethanol fight complicates push to repeal Obama drilling rule | TheHill: A handful of GOP senators have said they might hold up legislation to repeal an Obama administration oil and natural gas drilling rule to secure a vote on an ethanol policy change. The group, led by Sens. Chuck Grassley (R-Iowa) and John Thune(R-N.D.), have long pushed legislation to overturn federal policy that effectively prevents sales of gasoline with 15 percent ethanol — known as E15 — during the summer months due to volatility concerns. Now they want to trade a Senate vote on that bill for a vote on a resolution that would overturn limits on methane emissions from oil and natural gas drilling on federal land. = Thune said Wednesday that he and his allies tried and failed to get the provision into the omnibus spending bill that was unveiled Sunday and will get a vote this week. Since the methane legislation is a Congressional Review Act (CRA) resolution, it cannot be combined into a single bill with the ethanol policy change. “We tried to get it included in the omni, unsuccessfully. So we’re looking now for other vehicles and seeing … how methane fits into that picture,” Thune said. Lobbyists familiar with the discussions say that Thune, Grassley, Sen. Joni Ernst (R-Iowa) and Sen. Deb Fischer Deb Fischer (R-Neb.) are leading the charge for the ethanol vote.
Boulder County's moratorium ends; opponents continue to want fracking ban - Boulder Daily Camera -- With the expiration of more than five years of Boulder County oil and gas moratoriums only a few hours away, opponents of oil and gas development gathered on the Boulder County Courthouse plaza on Monday to repeat their demands for county government to continue to prohibit fracking.About 50 people showed up for the noon-hour rally organized by Frack Free Colorado, chanting and carrying signs — many of which focused on their alarms at the process of hydraulic fracturing that's used to free up underground oil and gas deposits."We will, we will protect this place! It violates our rights to frack on open space!" went one of the chants.Boulder County has had a series of consecutive moratoriums in place since February 2012 against accepting and processing new applications for oil and gas development in unincorporated parts of the county. The latest one ended at the conclusion of the workday on Monday."We're here," Frack Free Colorado's Suzanne Spiegel told the crowd at the start of the rally, "because Boulder County commissioners are leaving us in a position where we're not protected from fracking." Spiegel said her organization and other anti-fracking groups are preparing to push what she said will be a legal strategy to prevent oil and gas development in Boulder County, particularly on county-owned open space lands.
FRACTURED: Showdown in Boulder County - The Colorado Independent - This morning, Boulder County’s five-year ban on new oil and gas development officially expired. In its place, new rules governing oil and gas development in the county will take effect, which county commissioners say are the “strongest set of regulations on oil and gas development in the State of Colorado.”Oil and gas industry officials have already vowed to challenge the new rules, saying they are essentially a ban by another name.Meanwhile, “fracktivists” in Colorado’s most politically progressive county say that lifting the ban defies the will of the people who live here, and are planning everything from civil disobedience to mass meditation to prevent new drilling. Conflicts over oil and gas development in Colorado have escalated over the past decade, generating discord even in much less liberal strongholds such as Broomfield, Battlement Mesa, Greeley, Ft. Collins, and Colorado Springs. The rapid implementation of horizontal drilling technologies and hydraulic fracturing, or “fracking,” has propelled an increase in industrial activity closer to where people have been flocking to live. At the same time, as the recent fatal house fire in Firestone demonstrates — investigators are still searching for the cause, including examining a possible link to an older well about 170 feet from the explosion — there has also been a huge increase in housing developments sprouting near existing oil and gas development. A single modern drilling pad can launch dozens of horizontally drilled wells, with associated compressors, truck traffic, drilling rigs, separators, condensate tanks, noise, and other industrial activity. The result over the past decade, in Colorado and around the country, is a gusher of new wells and an almost unfathomable flow of money into energy industry coffers. Exxon and Chevron just reported a combined profit of $6.68 billion for the first quarter of 2017. There are more than 54,000 active wells in Colorado today, compared to about 22,500 in 2002, according to the Colorado Oil and Gas Conservation Commission (COGCC), Each successful well can produce millions of dollars of profit for a company. The resulting tax revenue and jobs have garnered substantial support for the industry at the statehouse and Gov. John Hickenlooper’s office. This gush of money has also fueled what some people see as asymmetrical warfare in the political sphere, as the industry wields its substantial clout and resists change even as its impacts have generated deep – and widening – resistance.
Colorado OKs deal for comprehensive development of controversial Boulder County oil field --Crestone Peak Resources and two of its competitors, Anadarko Petroleum Corporation and Extraction Oil and Gas, reached a last-minute deal Sunday night that will allow Crestone to move forward with plans to develop a 12-square-mile oil field in eastern Boulder County.The Colorado Oil and Gas Conservation Commission signed off on the agreement Monday morning, paving the way for the first-ever use of a new planning tool created by state regulators in 2008 to encourage oil companies to include communities in oil and gas planning.The approval means Denver-based Crestone Peak Resources, which hopes to develop a 12-square-mile oil field in east Boulder County near Erie, will have nine months to come up with a Comprehensive Development Plan. The idea is to ensure community participants — including Boulder County, the Colorado Department of Public Health and Environment, landowners and others — have a say in how wells are spaced and operated, among other things, before the plan is approved. The proposal, unveiled by Crestone in March, had been deadlocked because Crestone had asked the state to OK a "stand still" agreement that bars other oil companies in the area — in this case, Anadarko Petroleum Corporation and Extraction Oil and Gas — from applying to drill in the region while Crestone crafted its plan. Anadarko and Extraction Oil and Gas had protested the move, but agreed to it in a last-minute deal reached Sunday night, according to COGCC Executive Director Matt Lepore. Crestone has proposed up to 216 wells for the area. The move comes amid heightened scrutiny of oil and gas operations after a devastating house explosion in Firestone killed two people and injured two others April 17. An oil well located less than 170 feet from the home is being examined as part of the investigation into what caused the explosion.
Controlling radicals in Boulder County want to stop fracking … They call it the "People's Republic of Boulder" as a joke aimed at the perpetual shenanigans of the most liberal city and county in Colorado. But Boulder County and the city of Boulder, for all their leftist leanings, are still political subdivisions of the state of Colorado and the United States of America and are subject to all the laws and regulations thereof. East Boulder County United and Boulder County Protectors on the other hand aren't government agencies; they are anti-fracking groups whose spokesperson Cliff Willmeng said, "We do not recognize the authority of this body, we do not recognize the authority of those industries to override the free people of Boulder County. We will not be allowing a single well in Boulder County" at a May 1 meeting of the Colorado Oil and Gas Commission. The members of the COGC tolerated Willmeng's tirade with stone-faced bemusement and then went on about their state-authorized business of regulating the extraction of oil and gas statewide. Willmeng is a radical activist who was the driving force behind the attempt to pass an ordinance in Lafayette that would have made physical attacks and obstruction against oil and gas employees and operations legal, an absurdity fronted by his mother, Lafayette City Councilperson Merrily Mazza. That unconstitutional ordinance was defanged by more rational voices on the City Council back in January, just as Boulder County's five-year moratorium on oil and gas development was overturned by the courts and expired on May 1. Groups like East Boulder County United and Boulder County Protectors aren't really all that concerned about fracking itself. Fracking is being used as a propagandistic buzzword and stalking-horse for an anti-technological Luddite return-to-primitivism effort to completely stop the extraction of fossil fuels. Now Willmeng is once again trying to forward the fiction that Boulder County is a sovereign nation not subject to American law. Engaging in a bit of bald-faced cultural misappropriation Willmeng and his fellow radicals invoke a mish-mash of Native American theology and socialist ideology as justification for their plan to balkanize Boulder County to "create democracy in our municipalities and counties within the State of Colorado." Their manifesto claims "our communities are under siege from a structure of law that has bestowed greater rights on corporations than on the communities in which they operate." What they actually mean is that private property rights, in this case the rights of those who own the oil and gas are an impediment to their socialist desire to turn Boulder County into Venezuela. They want to amend the state constitution to dispose of private property rights by making "local laws that elevate the rights for Colorado residents and communities above the rights of the State of Colorado, including legal rights for the natural environment." To socialists, when individual rights conflict with their collectivist ideology, those individual rights must be discarded in the name of social democracy.
Colorado gas blast idles second company -- All natural gas lines within 250 feet of occupied buildings in parts of Colorado are closed while investigations into a fatal blast continue, a company said.Great Western Oil & Gas Co. follows Anadarko Petroleum with a response to a blast in late April in Firestone, Colo., that left two people dead. Anadarko said last week it closed more than 3,000 wells in response to the incident in Weld County.Anadarko operated the well in connection to the incident, which was situated about 200 feet away from the home tied to the fatalities. The original well was drilled by a previous operator in 1993. Local authorities said the cause of the incident was under investigation, but there was no immediate threat to the community.Great Western Oil & Gas Co. said the integrity of its gas lines in Colorado routinely passed inspections by Colorado authorities."While we are confident our operations do not present a danger to the public, we are proactively taking the necessary steps to ensure the public that our facilities continue to be safe," the company said in a statement. "Even though an oil and gas well flowline has not been determined to be the cause of the Firestone incident, in an abundance of caution, Great Western has inventoried all well gas lines within approximately 250 feet of occupied buildings and identified 61 gas lines within that distance." All of those operations were closed as of Thursday.
Pipeline Leak Caused Deadly Colorado House Explosion -- The deadly April 17 explosion in the town of Firestone, Colorado, was caused by a leak from a small, abandoned pipeline that was still connected to a natural gas well owned by Anadarko Petroleum , investigators announced Tuesday. The 1-inch, underground pipeline had been cut about 10 feet from the recently built home on Twilight Avenue where two men died and one woman was severely injured, Frederick-Firestone fire department officials said. Why the flow line was cut off, left uncapped and still connected to the producing well is currently unclear. Frederick-Firestone Fire Protection District chief Ted Poszywak said at a Tuesday press conference that the pre-refined gas was not odorized for safety as it seeped from the cut-off line into the home through French drains and a sump pit. "Those inside the home would not have smelled it," he said. Mark Martinez and his brother-in-law Joseph William Irwin III, both 42, were killed in the explosion. Mark's wife, Erin Martinez, was injured as well her 11-year-old son. The Anadarko well was less than 200 feet from the home. The well was drilled in 1993 and had previous owners. It was in place before the Twilight home was built. Poszywak stressed that it was not the well's proximity to the home that caused the explosion, rather it was the pipeline leading to the well head that caused the buildup of methane that led to the explosion. He said no adjacent homes are in any danger as a result of the severed line. According to the Associated Press , Colorado Oil and Gas Conservation Commission director Matt Lepore said that the flow line was cleanly cut, meaning it could have been severed by construction equipment while the neighborhood was being built. Lepore said that a line taken out of service should be disconnected and sealed at both ends and all flammable gas is supposed to be removed.
North Dakota Plagued by Oil Spills: 745 in One Year --Energy companies say that pipelines are the safest way to transport oil, but a number of recent spills plague the now-completed Dakota Access Pipeline (DAPL), which could start service as soon as May 14. KCET environment editor Chris Clarke calculated that in the year ending on May 1, 2017, North Dakota's oil and gas industry reported 745 involved oil spills—that averages to a spill every 11 hours and 45 minutes. The figure was based on data from North Dakota's Department of Health. The spills range in size, from smaller 20-gallons spills to ones that are much larger. Just two weeks ago , a Continental Resources pipeline in western North Dakota spilled an estimated 756 gallons of oil and 294 gallons of saltwater, a drilling byproduct, into a tributary of the Little Missouri River. Continental Resources, the largest operator in the Bakken shale formation, leads North Dakota in active wells, spills of all kinds, and wastewater or brine spills. And in December, a ruptured Belle Fourche pipeline spilled 529,830 gallons of oil , contaminating a hillside and Ash Coulee Creek which empties into the Little Missouri River. The break was significant because it happened less than 200 miles away from the Oceti Sakowin Camp, where the Standing Rock Sioux and fellow Water Protectors were protesting the DAPL. In 2014, the New York Times reported on the energy industry's increasing number of spills in North Dakota as a result of the area's fracking boom: "Over all, more than 18.4 million gallons of oils and chemicals spilled, leaked or misted into the air, soil and waters of North Dakota from 2006 through early October 2014. (In addition, the oil industry reported spilling 5.2 million gallons of nontoxic substances, mostly fresh water, which can alter the environment and carry contaminants.)"
Minnesota Republicans attempt to skirt environmental review of new tar sands pipelines - Late last year, Canada’s prime minister, noted internet bae and progressive cabinet-appointer Justin Trudeau, approved two new tar sands oil pipelines. Not only did the move complicate the country’s efforts to reduce its greenhouse gas footprint, but it also paved the way for a pipeline project through northern Minnesota, through native treaty land, and through some of the only wild rice waters in the world. Now, a rider on an energy omnibus bill, which must be signed to continue funding the state government, calls for circumventing Minnesota’s regulatory body and unilaterally approving a replacement project for Enbridge Energy’s Line 3—connecting one of the Canadian pipelines to U.S. refineries. Many say the rider, and a slew of others like it, are the Republican-controlled legislature’s attempt to do an end-run around the environmental review process, and environmentalists want to know why, amid a troubled oil industry outlook, lawmakers would seek to prop up an oil transmission project. Over two years ago, Enbridge applied to the Minnesota Public Utility Commission (PUC) for a permit to relocate and expand Line 3, which runs from the Canadian border to refineries and a pipeline hub near Superior, Wisconsin. The expansion will allow Enbridge to transport more than twice as much oil through “Line 3.” The 60-year-old existing pipeline is on its last legs. Enbridge was directed years ago to reduce pressure on the line, so it no longer operates at full capacity. And the company’s own records show 900 integrity “anomalies” — such as corrosion and seam cracking — on the old line. To help move things along, state representative Pat Garofalo (R) recently attached a rider to the state’s omnibus energy bill that would immediately authorize the pipeline project, without approval from the PUC, and would allow Enbridge to start construction as soon as July. Opponents to the pipeline say Garofalo’s rider violates the state constitution and that it is an inappropriate use of the budgetary process. The state constitution holds that it is illegal to make laws “granting to any private corporation, association, or individual any special or exclusive privilege.” Garofalo’s rider specifically names the PUC docket number he wants approved.
Do Socially Responsible Investors Have It All Wrong? - Fossil fuels divestment is a widely debated topic at many college campuses, including my own. The push, often led by students, to divest from fossil fuels companies is an example of the socially responsible investing (SRI) movement. SRI strategies seek to promote goals like environmental stewardship, diversity, and human rights through portfolio management, including the screening of companies involved with objectionable products or behaviors. It seems intuitive that the endowment of a foundation of educational institution should not invest in a firm whose activities oppose the foundation's mission. Why would a charity that fights lung cancer invest in tobacco, for example? But in a recent Federal Reserve Board working paper, "Divest, Disregard, or Double Down?", Brigitte Roth Tran suggests that intuition may be exactly backwards. She explains that "if firm returns increase with activities the endowment combats, doubling down on the investment increases expected utility by aligning funding availability with need. I call this 'mission hedging.'" Tran uses the Capital Asset Pricing Model to show that this mission hedging strategy "increases expected utility when endowment managers boost portfolio weights on firms whose returns correlate with activities the foundation seeks to reduce." More specifically, "foundations that do not account for covariance between idiosyncratic risk and marginal utility of assets will generally under-invest in high covariance assets. Because objectionable firms are more likely to have such covariance, firewall foundations will underinvest in these firms by disregarding the mission in the investment process. SRI foundations will tend to underinvest in these firms even more by avoiding them altogether."
Surge Seen In Crude By Rail To U.S. Gulf From 2017-2021 - Growing Canadian heavy production, coupled with a shortage of pipeline capacity, offers a window of opportunity for crude by rail from Western Canada to the Gulf of Mexico from now until about 2021, a Canadian crude oil conference heard Tuesday. Youll see a big surge and then by the end of the surge there will still be some crude by rail into niche markets similar to what is happening today, Terry Doherty, director of rail strategy and commercial development for Genesis Energy, told the Argus Canadian crude summit. Depending upon pipeline capacity out of Canada until new pipelines come onstream, crude-by-rail could increase to probably eight, or perhaps 12, unit trains from two to three trains today, he said. We believe that Keystone [XL] will get built but we dont think that Keystone and Energy East will get built. Genesis estimates that another 835,000 bbls a day of production will be coming onto the market over the next five years. Pipelines will get built but we definitely will have delays so dont count on a lot of pipelines by 2019, said Doherty. He also believes there currently is enough rail terminal capacity in Canada to accommodate the growth in unit trains and that any future expansions will be developed by companies already in the business. The Gulf Coast has 18 rail unloading terminals, mainly in the eastern Gulf, with the ability on paper to unload 1.7 million bbls a day of crude oil, Sandy Fielden, director, oil and products research, for Morningstar Commodities and Energy Ltd., told the conference. Most were built since 2012 in response to the need to get stranded and discounted Bakken light crude to market. Fielden said there has been a 50 per cent increase in crude oil storage in the Gulf to 291 million bbls from 192 million bbls because much of the new shale production needs to be blended ” it is too light to run through a refinery on its own. Canadian crude imports into the Gulf increased to 352,000 bbls a day in 2016 from 144,000 bbls per day in 2010 with the increased pipeline capacity to the Gulf ” most of those bbls were heavy crudes.
Shale investments surge by $100 billion - Ever since OPEC began cutting oil production, drilling in the United States has surged. Norwegian consultancy Rystad Energy estimates $100 billion in investment funds has flowed into the U.S. shale industry over the past year, propping up domestic drilling by 60 percent. So-called completion activity – procedures like hydraulic fracturing that stimulate shale wells – has gone up 30 percent, Rystad said. And there’s no sign things will slow down. Shale investments could climb another 50 percent this year, Rystad analyst Espen Erlingsen said in a written statement. Rystad believes daily U.S. oil production could jump from 8.9 million barrels in November to 9.3 million barrels next month, getting ever closer to the nation’s recent peak of 9.6 million barrels in mid-2015.
Oil's Big American Glut Is Resting Elsewhere -- Excess crude oil inventories in the U.S. are finally and clearly in retreat as OPEC's output agreement nears the end of its fourth month. But those oil bulls looking for higher prices shouldn't get too excited just yet -- the surplus may just be moving elsewhere. True, the crude stockpile fell in each of the first three weeks of April, and the 3.64 million-barrel decline in the last of those was the biggest weekly drop of the year, according to the Energy Information Administration. Over the period, inventories were drawn down at an average rate of 326,000 barrels a day, and a further 63,000 barrels a day have been drawn from the Strategic Petroleum Reserve (SPR) as part of a program of sales put in place last year. This is far from spectacular, but it does buck the seasonal trend. U.S. crude oil inventories typically rise during the first four months of the year, so the draw this year has begun about a month earlier than usual. U.S. refineries are helping to drain the glut. The amount they processed has soared as plants have come back into operation after normal seasonal maintenance. Volumes have climbed to 17.285 million barrels a day, the highest in data that goes back 35 years. Rates could climb even further in the weeks ahead -- expansions at several plants across the country have boosted capacity to 18.62 million barrels a day, up by around 300,000 barrels over the same time last year. In the most recent week's data, the volume of gasoline and middle distillates in storage rose, more than offsetting the draw down in crude stockpiles. Gasoline stores have been increasing for the last two weeks, bucking seasonal trends. Excluding the SPR, total U.S. oil inventories, including crude and refined products, rose by more than 6.6 million barrels in last week's data -- their biggest increase since early February. Hardly evidence of a rebalancing. In order to really clear the glut, crude must first be processed into products and then those products need to be consumed. But the early surge in U.S. oil use seems to be waning. Although four-week-average gasoline deliveries -- a proxy for demand -- soared in February and March, they have plateaued at around 9.3 million barrels a day since late March, down around 100,000 barrels a day year on year.
Are Gasoline Prices About To Crash? Glut Moves Downstream -- U.S. crude oil inventories have finally started to decline, a potentially momentous turning point in the three-year market downturn. Oil storage levels have been climbing relentlessly since the end of last summer, but inventories have been dropping ever so slightly since early April. That should be cause for celebration. Surely the end of one of the biggest headaches for oil markets should spark an oil price rally? While the data seems to be encouraging, there are growing fears that the glut could simply be shifting from upstream to downstream.The U.S. refining industry has ramped up processing over the past month, boosting processing by more than 1 million barrels per day (mb/d). For the week ending on April 21, U.S. refineries churned out an average of 17.285 mb/d, “a record for any time of year and coming well in advance of the summer driving season,” as Reuters recently described it. Maintenance season has come to a close and refineries are operating full tilt, sucking crude oil out of storage and spinning it into gasoline and diesel at a record pace. That has helped bring crude inventories down from an all-time high of 535 million barrels at the end of March, falling to 528.7 million barrels as of April 21, a small but meaningful decline. Oil traders have been anxiously awaiting such declines in storage, a key metric supporting the theory that the supply glut is coming to an end. But what if the extraordinary surge in refining is merely shifting the supply surplus downstream? For evidence of that, gasoline inventories (as opposed to crude oil inventories) started rising again in April – after months of declines – just as refiners started ramping up. Total gasoline stocks jumped from 236 million barrels in early April to 241 million barrels two weeks later. Gasoline stocks had been converging comfortably back into the five-year average range, but in April they began to climb once again.
Oil explorer plans first test of fracking potential on North Slope - - An oil explorer hoping to bring the Lower 48's fracking revolution to Alaska will take a big step this week when it launches an effort to determine the production potential of crude oil locked in North Slope shale. The process is expected to start Wednesday, when Accumulate Energy Alaska begins drilling an exploration well along the Dalton Highway about 40 miles south of Prudhoe Bay. In June, it plans to hydraulically fracture that vertical well, using water, chemicals and sand to crack and hold open rock so oil flows from the shale. A production test to determine how the well oil flows is also expected this summer. Paul Decker, a state petroleum geologist, said this will be the first test of its kind on the North Slope. Accumulate Energy will target residual oil and gas that never migrated out of rocks that are considered one of the sources for the crude oil at the giant Prudhoe Bay oil field. Similar efforts, using long-distance horizontal wells and hydraulic fracturing, have sharply boosted oil and gas production from shale in Texas and other states. Alaska officials, facing a future of falling oil production and revenues, have waited years for a similar turnaround on the North Slope. Sen. Bill Wielechowski, D-Anchorage, said he's been hoping for unconventional shale production to take off in Alaska since exploration company Great Bear Petroleum told lawmakers about six years ago that shale oil could boost daily oil production by hundreds of thousands of barrels. Great Bear, which holds large chunks of land, is now targeting more economic, conventional oil prospects at its leases. The company hopes those prospects can help foot the bill for the costlier shale-oil extraction that requires multiple wells.
Petronas Subsidiary Built Unauthorized Dams For Fracking - A subsidiary of the Malaysian oil giant and LNG proponent Petronas has been building unauthorized dams to trap water for mega-fracking that has triggered unprecedented seismic activity in northeastern British Columbia. Progress Energy has built at least 16 unauthorized dams in the Montney basin, says a report by journalist Ben Parfitt for the Canadian Centre for Policy Alternatives. The structures are among “dozens” of unauthorized dams built by industry in the region, the report found. Two of the earth dams constructed by Progress Energy are higher than a five-storey building, the report says. Due to their size and water-holding capacity, the report says, these dams should have triggered an automatic review by the province’s Environmental Assessment Office (EAO) prior to construction. But Parfitt found there was no review before the dams were built. Only now is the office investigating the unauthorized dams. Progress Energy built the dams between 2012 and 2014 on Treaty 8 land north of Fort St John in order to store surface water to supply its extensive hydraulic fracturing operations in the Montney basin gas fields.The controversial fracking technology injects a high-pressure mix of water, chemicals, gases and sand into the ground to fracture rock so it can release methane and natural gas and associated liquids.Fracking has triggered more than a thousand earthquakes in the region since 2008 and changed seismic patterns so dramatically that experts are increasingly concerned about the safety of dams in the region.“Either the regulator knew these dams were being built and didn’t do anything or they didn’t know and didn’t do anything. In either case we are experiencing a meltdown in regulatory oversight,” Parfitt told The Tyee. Progress Energy issued a statement saying the dams complied with BC Oil and Gas Commission requirements when built.
Canadian Oil Patch Shrugs Off Trumps Trade War Threat | OilPrice.com: Despite the recent flight of investment from the west Canadian tar sands, Canada hasn’t deviated from its course and continues to embrace major energy projects, particularly the ones designed to facilitate exports to the United States. And while U.S. President Donald Trump slaps tariffs on imported Canadian wood and threatens economic warfare with the single largest U.S. trade partner, energy links between the United States and Canada are solidifying. According to an EIA report, owners of the Alliance pipeline, a 2400-mile natural gas line carrying unprocessed natural gas from production sites in Alberta and British Columbia to extraction and fractionation plants near Chicago, are planning an expansion. They hope to add 0.5 bcf/d of capacity to the line, which at the moment has a capacity of 1.6 bcf/d, for a total throughput of over 2 bcf/d by November 2020. The demand for natural gas plant liquids (NGPL) derived from wet natural gas is low in Western Canada, particularly now that tar sands activity looks to be falling off, so Alliance is betting on greater demand in the United States. From its plants near Chicago, Alliance can send products to the Alliance Chicago Exchange and thence to other pipelines accessing other markets. If interest from investors is sufficient for the pipeline expansion, Alliance will accept bids in fall 2017, though it is not yet known how much the project will cost.On April 20, Calgary-based electricity provider TransAlta announced it would be phasing out eight coal-fired power centers and converting six of them to natural gas by 2023. The transition would cost around $CA300 million and cut emission between 30 and 40 percent per megawatt hour, but the principal reasons for the transition are economic and political. Alberta announced a mandatory phase-out of coal-fired power plants in 2015, mandating the existing plants would be shut down or transitioned by 2030. Coal has also become uncompetitive compared to natural gas and renewables, further encouraging the transition. A significant amount of Canada’s natural gas production, roughly one-third by one estimate, is used to produce oil from the tar sands. That sector has seen its fortunes dip in recent years, as high costs and low prices push out major companies. In the last year, five major companies have sold off assets worth $25 billion, with ConocoPhillips joining the exodus in March: the company sold off $13.3 billion in assets to Cenovus. Now BP is considering a departure, as it shifts money away from non-core businesses. The British energy company owns stakes in three different tar sands plays and is considering shifting its attention towards more profitable areas, such as the Permian Basin in the U.S., according to Reuters. Consequently, the re-investment rate into tar sands projects has fallen to nearly 50 percent, though optimists see signs of a resurgence ahead. Tar sands oil production has come under more intense political pressure in Canada, as environmental concerns and public discomfort with major investments into energy production has caused support for the project to dwindle. That, combined with the high cost of tar sands production relative to other North American areas, particularly the Permian Basin, has fueled the recent exodus.
CNR's Alberta oil sands output 13% above capacity, but bottlenecks ahead -- Canadian Natural Resources' Horizon facility in Alberta is sustaining output at 205,000 b/d of synthetic crude oil -- nearly 13% above its nameplate capacity -- with a further surge in production expected later this year that could result in a bottleneck in pipeline takeaway capacity from the province, CEO Steve Laut said Thursday. Horizon output in the first quarter was 192,491 b/d, still above its nameplate of 182,000 b/d, primarily due to operational efficiencies that also led to a lowering of operating costs to C$22.08/b ($16.06/b) of SCO, he said on an earnings webcast. Output from the facility is set to increase further by 80,000 b/d by the fourth quarter, as CNR plans to complete a third-phase expansion and target an operating cost of less than C$20/b, Laut said. "In today's oil price environment, transition to a low-risk and long-life asset is important," he said. "And along with our planned acquisition of the AOSP facility, Horizon and Albian projects will be very competitive as oil sands assets." CNR is due to close in the summer a C$12.74 billion acquisition of Shell's 60% interest in the Athabasca Oil Sands Project, or AOSP, which comprises of the Albian oil sands mining facility of capacity 250,000 b/d. "With the [closure of AOSP] deal, we will be taking another significant step upwards. For our oil sands operations, we will be able to use size and scale of operations to further lower our operating cost," he said without giving a figure. Along with the phase 3 expansion, CNR is also planning a debottlenecking of the facility that could add 5,000 b/d of 15,000 b/d of new capacity, COO Tim McKay said on the same webcast. He did not indicate a timeline to add the new capacity, but said the focus is now on a full engineering study targeted to be complete by the second quarter. The study examine optimizing output from the fractionation tower, which includes taking a closer look at naphtha distillate, gas oil, natural gas and coke output, McKay said. Besides oil sands, CNR also has a portfolio of heavy oil projects in Western Canada that utilize the steam, water and polymer flooding technologies to produce a total of 174,989 b/d in the first quarter.
Canada's missing barrels - This era of lower-for-longer oil prices has raised a thorny question for Canada's oil sands producers: at what point does oil in the ground cease to exist on the balance sheet? The answer is when the US Securities Exchange Commission(SEC) says so. The question became more acute after ExxonMobil was forced to write off 3.5bn barrels of its oil sands reserves in its annual 10-K filing. It amounts to the entire booked reserve base of its Kearl oil sands mine that was commissioned in 2013 at a cost of C$12.9bn ($9.81bn) and another 200m barrels of bitumen at its Cold Lake in situ project. The oil sands writedown slashed ExxonMobil's proved reserves by around 20%.ConocoPhillips followed suit, cutting its proved oil sands reserves by half, effectively eliminating 1.3bn barrels of oil sands and another 1bn barrels of bitumen resources. These barrels have disappeared from the accounting ledger without a trace. All told, it amounts to about 3% of Canada's entire proved reserves, which has been touted as the third largest in the world after Saudi Arabia and Venezuela.The writedowns, however, don't mean that Exxon and ConocoPhilips are packing up and going home. Exxon's Kearl oil sands mine—operated by its Canadian subsidiary Imperial Oil—continues to produce unabated at 170,000 barrels a day. And Exxon insisted in the wake of the writedowns that it is forging ahead, and expects to bring those reserves back onto its books eventually. The problem is how the SEC requires companies to tally up their reserves. The accounting rules are complex, but essentially say that companies have to use the average price for each month in the previous full year to determine the economic viability of a resource ever being developed. If that price falls below the cost of production, companies must remove the reserves from the books. The price for 2016 after a brutal price crash in the first half of the year was $29.49 a barrel for Western Canadian Select. ExxonMobil reported average production costs for its Canadian synthetic oil projects at $33.64/b for 2016. This is not an easy decision to make for companies, because it essentially reduces the net asset value of the company. This has been a sticking point with the oil companies for years given that oil sands are capital-cost intensive and so developers would prefer to amortise those costs over the 25-30 years of the asset's producing life.
Does slow growth in oil sands output justify new pipeline capacity? --Production volumes in the Alberta oil sands continue to inch up as production expansion projects sanctioned in better times — almost all of the projects small in scale — come online. However, several major pipeline projects remain on the drawing board; taken together, they would appear to provide far more pipeline takeaway capacity than the oil sands will need. Which raises two questions: how much incremental pipeline capacity is needed, and which pipeline project or projects are most likely to advance? Today we continue our series on stagnating production growth in the world’s premier crude bitumen area, the odds for and against a rebound any time soon, and the need (or lack thereof) for more pipelines. In Part 1, we started with a reminder that while the three oil sands areas in northern Alberta — the giant Athabasca deposits and the smaller Peace River and Cold Lake areas — contain proven reserves equivalent to more than 160 billion barrels of crude oil, simply having vast hydrocarbon reserves in the ground isn’t enough. Production costs and the cost of delivering product to market need to be competitive if an area is to continue drawing investment — at least over the long-term in the case of areas with higher upfront development costs like the oil sands and the Gulf of Mexico (see Don’t You Forget About Me). Oil sands producers have been especially hard-hit by the collapse in oil prices, in part because their hydrocarbon-extraction process is more complicated and costly than their shale-play counterparts, and because the oil sands are far away from most major refinery centers. And it’s not only a matter of having to transport product longer distances — oil sands producers also need to either add diluent to their bitumen to allow it to flow through pipelines, or transport high-viscosity bitumen in special, high-cost coil rail cars that can be heated before unloading, and none of that comes cheap. Then there’s the matter of takeaway capacity. When oil sands production took off in 2010-13, the midstream sector struggled to keep up, and when midstreamers couldn’t build new pipeline capacity quickly enough (or, more precisely, couldn’t win governmental approvals for big projects like TransCanada’s Keystone XL or Enbridge’s Northern Gateway), a couple of dozen crude-by-rail (CBR) facilities were constructed or upgraded to help move Alberta-sourced hydrocarbons to market — much like what occurred in the Bakken in North Dakota (see Slow Train Coming).
Mexico invites nominations for deepwater blocks to include in December auction -- Mexico is inviting domestic and international oil companies to submit nominations from among the 119 deepwater blocks available on its side of the Gulf of Mexico, some of which may be included in a bid round this December, the country's deputy energy secretary for hydrocarbons said Monday. The nomination process, which began in mid-March and will be open for three months, will help the state decide which and how many blocks to offer in the late-year auction, Aldo Flores Quiroga told an audience at the opening of the Offshore Technology Conference. Mexico's top energy officials from the Energy Ministry (SENER) and the National Hydrocarbons Commission (CNH) will reveal in June which blocks will be offered, Flores said, adding Mexico also plans a deepwater auction for October 2018. "We're offering a predictable calendar for tenders, and also on-demand seismic data," he said. All deepwater blocks will be 1,000 sq km, which is also part of the energy authorities' process that will standardize block sizes. Flores said that despite low oil prices -- currently teetering slightly under $50/b -- Mexico's deepwater offers an relatively attractive breakeven price under $60/b. Oil prices are widely expected to rise in the next year, and deepwater blocks awarded in 2017 would not likely be developed for at least five years and potentially longer.
ConocoPhillips Still Can't Dig Out of the Red - Heading into the first quarter, there was growing optimism that ConocoPhillips (NYSE:COP) would finally return to profitability. Unfortunately, that didn't happen as the company reported yet another adjusted loss, this time losing $19 million, or $0.02 per share. While that's a meaningful improvement from last year's $1.2 billion adjusted loss and last quarter's $318 million loss, it still wasn't the minuscule profit that analysts expected to see. That said, there were several positives in the quarter, and they do suggest that the company is heading in the right direction. Operationally, ConocoPhillips performed well during the quarter. Production, for example, was 1.584 million barrels of oil equivalent per day (BOE/D), which came in above the high end of the company's guidance range of 1.54 million to 1.57 million BOE/D. Driving that result: the ramp-up of several major projects, the impact of multiple development programs, and improved well performance. That helped the company more than offset a production curtailment at its Surmont joint venture in Canada with Total. That's after the companies had to cut production at the facility due to a fire at Suncor Energy's Syncrude facility, which impacted the partners' ability to transport oil produced at Surmont.In addition to that higher production, ConocoPhillips also benefited from an improvement in realized oil prices during the quarter, which jumped from $22.94 per BOE in the year-ago quarter to $36.18 per BOE in the first quarter. At the same time, the company continues to push down costs, evidenced by a 4% year-over-year decrease in production and operating expenses. These factors helped drive earnings within striking distance of profitability.
BP profits surge after rebound in oil prices - BP almost tripled its profits in the first quarter, adding to signs of recovery among the world’s biggest oil producers after a two-year slump. Like its US peers ExxonMobil and Chevron last week, BP beat market expectations with first-quarter results that showed the benefits of sharply higher oil prices compared with the 12-year lows recorded in the same period of 2016. The UK group on Tuesday reported profits of $1.5bn on an underlying replacement cost basis, the main measure watched by analysts. This was up from $532m in the first three months of last year and higher than the $1.26bn consensus forecast by analysts. The results promised to reinforce investor confidence that BP was gradually escaping the financial shadow of the 2010 Deepwater Horizon oil spill in the US as it entered the final stages of paying off $62bn of associated clean-up and compensation costs. BP’s shares were up 1.6 per cent at £4.49 in London on Tuesday. “We’ve got a good quarter under our belts but it’s just one quarter and there’s no complacency,” said Brian Gilvary, BP chief financial officer. “We’ve still got a lot of work to do and major projects to bring on stream.”
Oilfield services groups struggle outside the US - It would be easy to conclude from the first-quarter results of two of the world’s largest oilfield services companies that recovery is under way in their sector. Halliburton and Schlumberger in recent days both announced their first quarterly revenue growth since the oil market crash of 2014. Yet, the rebound is far from universal. Almost all the renewed growth in the oilfield services industry — activity which spans everything from drilling wells to maintaining production platforms — is coming from one place: onshore shale oil and gas developments in the US. Other parts of the sector, particularly the offshore element, remain mired in recession after exploration and production groups responded to the drop in oil prices by demanding big reductions in charges by service companies in relation to many existing developments, and by putting other projects on hold. “We are in the midst of a unique and challenging cycle with very different dynamics between the North American and international markets,” said Jeff Miller, Halliburton’s president, last week. This mixed picture is causing divergence between groups such as Halliburton with strong exposure to US shale drilling and other service companies more dependent on offshore or conventional onshore work elsewhere in the world. Saipem of Italy, one of the world’s biggest offshore engineers, in April revealed its weakest order intake since 2001 and its lowest work backlog since 2006 after first-quarter revenues and profits both fell by a fifth compared with a year ago.
Global oil discoveries and new projects fell to historic lows in 2016 -- Global oil discoveries fell to a record low in 2016 as companies continued to cut spending and conventional oil projects sanctioned were at the lowest level in more than 70 years, according to the International Energy Agency, which warned that both trends could continue this year. Oil discoveries declined to 2.4 billion barrels in 2016, compared with an average of 9 billion barrels per year over the past 15 years. Meanwhile, the volume of conventional resources sanctioned for development last year fell to 4.7 billion barrels, 30% lower than the previous year as the number of projects that received a final investment decision dropped to the lowest level since the 1940s. This sharp slowdown in activity in the conventional oil sector was the result of reduced investment spending driven by low oil prices. It brings an additional cause of concern for global energy security at a time of heightened geopolitical risks in some major producer countries, such as Venezuela. With global demand expected to grow by 1.2 mb/d a year in the next five years, the IEA has repeatedly warned that an extended period of sharply lower oil investment could lead to a tightening in supplies. Exploration spending is expected to fall again in 2017 for the third year in a row to less than half 2014 levels, resulting in another year of low discoveries. The level of new sanctioned projects so far in 2017 remains depressed.
Oil Production Vital Statistics April 2017 - The oil price recovery to $56 (Brent) through the first half of April was short lived and it has since returned to $50. According to OilPrice.com, Russia is now compliant with its 300,000 bpd production cut. OPEC production is now down 1.43 Mbpd compared with October 16 (including Libya and Nigeria) and the group is over-compliant with the agreed cuts and must be disappointed in the continuing weak oil price.IEA data shows Russia produced 11.6 Mbpd in October 2016 and 11.42 Mbpd in March 2017, a cut of 180,000 bpd. We must therefore assume that Russia has cut deeply during April. At end March, FSU production was up 30,000 bpd on October. If OPEC does not renew or expand production cuts in the second half of 2017 then the oil price is widely expected to collapse. OPEC drilling remains close to a cyclical high while US drilling continues to recover. Total US rigs were up 46 to 870 for the month to the end of April. Drilling remains stuck on a cyclical low everywhere else. According to PennEnergy Global oil discoveries and new projects fell to historic lows in 2016 and this will be storing trouble in the years ahead when a lack of investment eventually works through the system emerging as reduced production creating a new cycle of scarcity and a new price spike.The following totals compare March 2016 with March 2017:
- World Total Liquids 96.11/95.96 -150,000 bpd
- OPEC 12: 31.70/31.49 -210,000 bpd
- Russia + FSU 14.19/14.36 +170,000 bpd
- Europe OECD 3.59/3.58 -10,000
- Asia 7.59/7.39 -200,000
- North America 19.86/19.62 -240,000 bpd
The net YOY change for OPEC, Russia, Europe, Asia and N America is -480,000 bpd while world total liquids is only down -150,000 bpd. This is explained by a 420,000 bpd YOY rise in Brazilian production (Figure 21). The following totals compare October 2016 with March 2017 and monitor compliance with the OPEC + others production cuts.
NYMEX June gas dips 4.2 cents amid larger-than-expected storage injection - The NYMEX June natural gas futures contract fell Thursday as US Energy Information Administration storage data showed higher-than-expected injection numbers. The NYMEX June natural gas futures contract settled at $3.186/MMBtu, down 4.2 cents. EIA data released Thursday showed that US stocks grew 67 Bcf for the week ended April 28. That is 6 Bcf higher than the 61-Bcf injection expected by a consensus of analysts surveyed by S&P Global Platts. The build was higher than the five-year average of a 63-Bcf injection and 1 Bcf lower than the 68-Bcf injection reported at this time last year. Stocks grew in every region, with the largest gains occurring in the East and South Central. Total stocks reached 2.256 Tcf, down 13.7% from year-ago levels of 2.615 Tcf. Stocks are one of the main indicators under close watch as decreased production, increased exports to Mexico and LNG exports have tightened supply. Data from Platts Analytics' Bentek Energy showed a 1.8 Bcf/d decrease in dry production to date in 2017 compared with a year ago, but a year-on-year increase of 2.1 Bcf/d for exports to Mexico and LNG exports. Platts Analytics expects Thursday power burn to decrease 1.3 Bcf/d from Wednesday, with power burn demand decreasing in nearly every region, with most of the decline attributed to the Southeast and Texas. Conversely, with cooler-than-average temperatures forecast for the Northeast and Southwest on Thursday, Platts Analytics expects a 1 Bcf/d increase in demand from Wednesday.
Platts JKM: June LNG eases 5 cents to $5.70/MMBtu on returning supply -- S&P Global Platts JKM for LNG cargoes delivered in June slipped 5 cents week-on-week to close at $5.70/MMBtu on Friday, following returning supply from projects in the US and Australia. Spot prices were depressed by re-emerging supply from Train 2 of Australia's Gorgon project, as well as the resumption of output from Sabine Pass Train 3 in the US after a planned maintenance last week, sources said. All three trains at Gorgon are operational and running at over 85% of nameplate capacity in aggregate, a Chevron spokesman confirmed early in the week. The project is currently loading a ship about every two days and has shipped 67 cargoes to date, according to Chevron. Buying activity was limited in Asia with biggest buyers Japan and South Korea absent due to public holidays over most of the week. South Korea's Kogas awarded more than 10 cargoes to RasGas, Shell, Vitol, Marubeni, Petrobras, Engie and other sellers at prices from $5.70/MMBtu to around $5.85/MMBtu. Qatargas had been awarded one cargo for the most recent buy tender from Thailand's PTT, with prices reported at $5.75/MMBtu and below. In India, Gail issued a tender seeking one cargo a month for delivery in July, September and November. Bids into the tender are due by May 8, with submissions remaining valid until May 9. Submissions into the tender are to be made on a Brent-linked basis
Australian government shocks the natural gas market - Share prices are crumbling, buyers are scrambling, and industry is raging after a shocking turnaround from the world’s largest exporting nation for liquefied natural gas (LNG). Prime Minister Malcom Turnbull announced on public radio Thursday morning that his government will take the right to restrict LNG exports. As he explained, “It is unacceptable for Australia to become the world’s largest exporter of liquefied natural gas but not have enough domestic supply for Australian households and businesses.” The export restrictions will reportedly come in the form of a “gas security mechanism” to be enacted as of July 1. Under these rules, the federal government will have the right to block exports during times of high demand and rising prices at home. Few details were given beyond this — such as how producers might be compensated for lost revenue and broken contract commitments due to export restrictions. But the reaction from investors and industry was decidedly negative. With share prices of producers falling as much as 7.5% on the announcement — and oil and gas executives calling the new policy “unprecedented”, raising “sovereign risk”.
Aussies oppose fracking but govt wants it | SBS News: Most Australians support bans on new unconventional gas exploration but the federal government has told the states to "get off their backsides" and end them. More than twice as many Australians support moratoriums on fracking (56 per cent) than those who oppose them (20 per cent), according to an Australia Institute survey of 1420 people conducted over a week in March. That majority in favour of bans on new unconventional gas extractions including hydraulic fracturing (fracking) was evident across all states. And the opposition crossed party lines, with Labor, Liberal and minor party voters all expressing concern. But federal Resources Minister Matt Canavan was out again on Sunday morning blaming state policies for a looming gas shortage. The federal government last week announced export controls to protect domestic gas supplies. "Hopefully it's a wake-up call to the states and territories to get off their backsides and develop their own resources," he told Sky News on Sunday.He noted his criticism was bipartisan - calling the Victorian Labor government's ban on all gas exploration, even for conventional sources, "absurd" while telling off the NSW coalition government for too many delays in approval processes. Gas companies have also been quick to blame states hindering new developments for the shortage of supply on the domestic market while they prepare to export record amounts of the fuel. Australia Institute deputy director Ebony Bennett said industry demands to open more land to fracking were not about reducing energy prices but maximising profits. "The current gas crisis and high gas prices are not an unintended consequence, but the result of linking Australia to the international gas market," she said.
Shell's realized natural gas price in Europe rises in Q1 to $5.08/Mcf - Shell saw its average realized gas price in Europe in the first quarter of 2017 edge up to $5.08/Mcf ($4.94/MMBtu) compared with the previous quarter, the company said in its Q1 earnings statement Thursday. The gas price increase was triggered by increased demand on cold weather across Europe in January and the early part of February, which saw wholesale gas prices surge. Its European realized price was $4.94/Mcf in Q4 2016. However, Shell's realized European price in Q1 was still below the spot price average in Q1. According to Platts assessments, the Dutch TTF spot price averaged $5.77/MMBtu in Q1, up from $5.41/MMBtu in Q4 2016, while the UK NBP spot price averaged $6.00/MMBtu in Q1 compared with $5.62/MMBtu in Q4 2016. Shell's European gas price boost helped push its global average realized gas price to $4.29/Mcf in the last quarter, up from $4.03/Mcf in Q4 last year. Europe accounts for a significant chunk of Shell's gas production -- it averaged 3.43 Bcf/d in Q1 out of a total of 10.94 Bcf/d.
Colombian president announces largest gas find in decades - Colombian President Juan Manuel Santos and state-controlled oil company Ecopetrol Wednesday announced the country's largest natural gas discovery in 28 years, but stopped short of quantifying the Caribbean deepwater find or declaring it to be a commercially viable. The discovery comes as Colombia is experiencing an ongoing decline in domestic gas reserves and output. Earlier this year, the country lost its self sufficiency in gas production and was forced for the first time to import an LNG cargo from Trinidad and Tobago to a new regasification facility in Cartagena in order to meet domestic gas demand. At a press conference in Bogota, Santos said the deepwater well Gorgon-1, drilled by Ecopeterol and its 50-50 operator partner Anadarko, had found natural gas at a depth of 2,316 meters. The gas-bearing sand layer was measured at between 260 and 360 feet of natural gas pay. In a release shortly before the president spoke, Ecopetrol said the well represents a continuation of the "geological train" of gas discovered previously in the adjacent Kronos deep water block in 2015 and Purple Angel deep water block in March of this year off Colombia's Caribbean coast. Both blocks are also owned by Ecopetrol and Anadarko.
Nigeria pays initial $400 mil owed foreign oil partners, eyes 2.5 mil b/d output by 2019 - Nigeria has made an initial payment of $400 million, out of the $5.1 billion debt owed to its foreign oil partners, as it kickstarted a new funding mechanism for upstream ventures aimed at boosting investment in the oil and gas sector, oil minister Emmanuel Kachikwu said Wednesday. In December 2016, the government signed a new funding arrangement with Shell, ExxonMobil, Chevron, Total and Eni, that would see Nigeria exit the system of contributing money to fund its average 57% equity in the ventures, known locally as cash call, and allow producers to independently source funds and control their own budgets. "The first payment of $400 million was paid last week to the IOCs [International Oil Companies]. The $400 million payment was part of cash call debt owed the IOCs in 2016," a statement Wednesday from the oil ministry quoted Kachikwu saying. "The sustainable funding of the [joint ventures] will lead to an increase in national production from the current 2.2 million b/d to 2.5 million b/d by 2019," the minister said. Nigerian oil production still remains sharply below its capacity of 2.2 million b/d, with the main export grade Forcados still shut in. Output has recovered gradually this year as militant attacks have fallen substantially since early January after the government stepped up peace talks in the key producing Niger Delta to end militancy in the region. Nigerian crude oil and condensate production is currently around 1.9 million b/d, with almost 350,000 b/d comprising condensates like Akpo, Agbami and Oso Condensate, according to S&P Global Platts estimates.
OPEC output cuts whet Asia's appetite for North Sea oil | Reuters: OPEC production cuts have created record Asian demand for European oil and made China the second biggest consumer of North Sea crude as flows from its usual Middle East suppliers dip. Rising Asian appetite for North Sea crude has largely been fueled by the falling premium charged for North Sea crude over rival Middle East oil and this demand could last beyond OPEC's supply cuts if that favorable pricing persists. Thomson Reuters Eikon data shows China imported almost 38 million barrels of North Sea crude from the start of the year until late April, compared with about 8 million barrels by the same point in 2016. China now lies second to Britain, the biggest consumer of North Sea crude, which had bought 49.7 million barrels by late April this year. In January to April 2016, China ranked seventh. The Organization of the Petroleum Exporting Countries, Russia and other non-OPEC producers agreed to cut output by 1.8 million barrels per day (bpd) in the first half of 2017 to lift prices and reduce global inventories. With stockpiles still bulging, Gulf producers and other producers say cuts could be extended to December, adding a further incentive for Asian buyers to look beyond their usual suppliers. "East of Suez, crude balances look like they will get progressively tighter year-on-year all the way through to the end of 2017," FGE analyst James Davis said. "We suspect there will be, from a supply perspective, a need for crude to move across to Asia from the North Sea," he said.
Russian oil output declines, almost at global pact target | Reuters: Russian oil production edged down to 11.00 million barrels per day (bpd) in April from 11.05 million bpd in March, just short of full compliance with the targets of a global deal to cut oil output, Energy Ministry data showed on Tuesday. The Organization of the Petroleum Producing Countries with Russia and other leading oil producers agreed to cut oil production by almost 1.8 million bpd in the first six months of this year to tackle bloated inventories and prop up weak prices. Of that amount, Russia undertook to reduce its output by 300,000 bpd by the end of April to a target of 10.947 million bpd from a 30-year high of 11.247 million bpd in October. In April, its compliance with its target was 95.2 percent. In tonnes, oil output in April reached 45.002 million versus 46.739 million in March. Investors are now focusing on whether the OPEC and other producers will extend cuts into the second half of the year. OPEC states and others meet on May 25 to discuss the issue. Russia has yet to state publicly whether it backs an extension but has said it was studying the market and had held talks with some OPEC ministers to determine its position. Rosneft, Russia's largest oil producer, contributed the most to Moscow's cuts last month with a 1 percent reduction from March. Almost all other Russian majors, apart from Gazprom Neft, also curtailed output in April. Gazprom Neft, the oil arm of Russian gas giant Gazprom, ratcheted up oil production in April by 2.9 percent as it continued to pump more from its newly launched fields. Smaller producers cut output by 2.1 percent.
Extension of OPEC/non-OPEC crude oil production cut deal near certain: analysts --- The likelihood of OPEC and major non-OPEC producers agreeing to extend their ongoing crude oil output cut is near certain, two prominent analysts said Monday. OPEC producers are "100% certain" to extend their end of the output cut deal at a May 25 OPEC ministerial meeting in Vienna, Fereidun Fesharaki, chairman of consultants FGE, told the Middle East Petroleum and Gas Conference in Dubai. In December, OPEC teamed up with major producers such as Russia to cut production by nearly 1.8 million b/d compared with October 2016 levels starting January 1. While a six-month deal was initially envisaged, OPEC may need to keep a lid on its production until well into 2018, Fesharaki said, as work on trimming global crude inventories continues, or they risk oil prices dropping back to $40/b if stocks, particularly in the US, increase. "The cuts will have to be extended even beyond this year, to the middle or even the end of next year", he said. The market is watching carefully for signs of when the build up in inventories stops and drawdowns begin, he said. Oil prices of $50/b-$60/b could be sustainable, he added, but there was a risk that US production volumes could be higher than expected, pushing prices back as low as $40/b over the next 12 months.
Why the crude rally has fizzled, concluded: Market analysis series - The Barrel Blog: This is the third and final segment of a three-part look at why oil prices have failed to rally despite OPEC’s best efforts at managing supply cuts. Not only have prices failed to rally, both NYMEX WTI and ICE Brent have fallen around 9% over the past three weeks. In case you missed them, be sure to read part 1 and part 2. Refiners do what is in their best interest, too. Bank of America Merrill Lynch analysts recently said that refiners the world over need to weigh capitalizing on current strong margins — and risk dumping products into an already glutted market — or forgo profits now in the hopes of rescuing global product prices. “Refiners need to be careful not to repeat last year’s mistake and raise production in response to high margins only to add to already high inventories,” the analysts said. “In a way, they face a big dilemma: be penny wise now and possibly look pound foolish later, essentially run harder now and suffer in six months, or run softer now and forgo profits.” The recent strength in refining margins across much of the world suggests refiners, like many of the world’s oil producers, will continue to do what is in their best interest: use cheap crude to make refined products for profit.So what is the current state of the global refined product market? While product cracks have kept refining margins profitable, it is more likely than not that they have already peaked at levels largely below those seen last year. European gasoline had strengthened on the seasonal pull from the US, but even this seems to have already dried up. In Asia, gasoline cracks could have peaked for the season at just over $10/b. In 2016, gasoline cracks peaked at just under $12/b in late-March. Distillate cracks the world over are better, but last year was a particularly bad year for distillate sellers. So, why are refiners continuing to churn out products? Because they’re getting a great deal on all this relatively cheap crude! With refining margins where they are right now, it’s little wonder product stocks can’t clear. It would help if forecast demand lived up to expectations, but so far, this has not happened. For crude prices specifically, hurdles remain. US, North Sea, West Africa and Latin crudes will continue to displace OPEC barrels for as long as freight stays cheap and the OPEC cuts themselves keep Dubai comparatively strong. In its latest crude oil market outlook, Platts Analytics’ Bentek Energy analysts acknowledged as much.
Oil production cuts: Fool me once...no, make that any number of times -- The jawboning of oil prices by the Saudi Arabian/Russian tag team should be wearing off after more than a year of actions that don't measure up to the words. Oil prices slumped recently, dropping from around $54 per barrel to just below $50 as of Friday's close. As if on cue, the Russian energy minister announced Friday that Russia has now met its target of reducing oil production by 300,000 barrels per day. It only took four months to do something that should have taken just weeks. (The agreement came into force on January 1.) And, of course, we'll have to see if the Russians have actually done what they say they've done. Only a week earlier, the Saudi energy minister indicated that there is momentum growing in OPEC for extending production cuts beyond June for another six months. This announcement comes only six weeks after the same minister said that OPEC would NOT be considering extending the cuts. This is reminiscent of last year's run-up to the production agreement in which Russia and Saudi Arabia kept alternating in making often contradictory announcements to sow confusion about the possibility of a production agreement and keep markets on edge without actually having to do anything. The Saudis and the Russians want to appear to being "doing something" about low oil prices. But they and their fellow producers aren't really doing enough to push prices higher. And, that may suit the Saudis and the Russians just fine. Meanwhile, U.S. tight oil producers keep touting ever lower "breakeven" prices for their relatively expensive oil. But as petroleum consultant Art Berman has been pointing out for some time, these lower breakeven prices are almost completely the product of crashing oil service costs rather than technological miracles. And, they aren't limited to tight oil producers, but rather reflect conditions across the entire industry. One thing all this talk has done is fan speculative interest in the oil futures market where open interest has soared even as prices have traced out a mostly sideways pattern. Clearly, many speculators believe the hype about sharply higher oil prices. I believe they are going to wait quite a while longer--at least until Saudi Arabia and Russia are satisfied that the investment capital flowing to tight oil drillers in the United States has been largely shut down.
Hedge funds lose faith in OPEC: Kemp (Reuters) - Hedge funds are losing faith that OPEC can accelerate the rebalancing of the oil market even if the group agrees to extend output cuts when it meets later this month.Hedge funds and other money managers cut their combined net long position in the three main futures and options contracts linked to Brent and WTI by 139 million barrels in the week to April 25 (http://tmsnrt.rs/2p10Ih8).The reduction was one of the largest weekly falls on record, and reverses a cumulative increase of 140 million barrels over the previous three weeks, according to data from regulators and exchanges (http://tmsnrt.rs/2oSQUu5).Fund managers are now much less bullish about the outlook for crude oil prices than they were back at the start of the year.Bullish long positions outnumber bearish short positions by a ratio of 4:1, down from 7:1 at the start of the year and a peak of more than 10:1 in late February (http://tmsnrt.rs/2p4eu32).The number of long positions has fallen to the lowest level since before OPEC announced its output agreement on Nov. 30 (http://tmsnrt.rs/2pDvctm).At the same time, the number of short positions has been trending higher since late February, despite periodic short-covering rallies.Fund managers have become less bullish despite increasingly strong indications from OPEC that it will roll over production cuts for another six months.Traders no longer believe the cuts will be enough to rebalance the market in the second half of the year even if they are extended.In the three months from the end of November to the end of February, fund managers increasingly bet OPEC's output cuts would work.An informal understanding between OPEC and the hedge fund community helped boost prices and give oil producers an early payback. But the continued rise in reported crude stocks and the futures market's failure to switch from contango to backwardation has forced a reassessment. In addition, the continued rise in shale drilling has created concerns about a big increase in oil production from the United States later in the year. Since March, hedge fund managers have increasingly wagered OPEC's rebalancing effort will fail, weighing on prices. Hedge funds are now less bullish even though prices are lower, which shows how much confidence in the OPEC/non-OPEC accord has fallen.Simply announcing OPEC and non-OPEC compliance figures and an extension of the agreement is no longer enough. Traders and fund managers are demanding evidence the agreement is working in the form of a reduction in reported stockpiles and a cut in tanker exports.
Rising U.S. oil production knocks OPEC off course: Kemp | Reuters: U.S. crude production is surging, complicating OPEC’s efforts to rebalance the oil market. U.S. production rose by more than 450,000 barrels per day (bpd) in the five months ending in February, according to the U.S. Energy Information Administration (EIA) (tmsnrt.rs/2p1SftR).Total U.S. crude production has increased from a recent low of 8.567 million bpd in September to 9.031 million bpd in February (“Petroleum Supply Monthly”, EIA, April 28).Production continued rising in March and April, and now stands at over 9.2 million bpd, according to weekly estimates published by the agency (“Weekly Petroleum Status Report”, EIA, April 26).Weekly estimates are considered less reliable than the monthly numbers, but the two series have tended to follow one another closely, so there is no reason to doubt the continued growth in output (tmsnrt.rs/2p4R11K).U.S. crude production is increasing at an annual rate of more than 1 million bpd, comparable to the boom of 2012-2014 (tmsnrt.rs/2oTK6MV).The rapid recovery in U.S. output is one of the factors making market rebalancing slower than OPEC anticipated.Most of the increase so far has come from non-shale producers in the Gulf of Mexico and Alaska. But the massive increase in the number of rigs drilling onshore should ensure shale output rises substantially in the remainder of 2017. Gulf of Mexico output rose by 228,000 bpd in the five months to February, while onshore production from the lower 48 states increased by 175,000 bpd and Alaska’s output rose 61,000 bpd. U.S. production will continue increasing for at least the next few months as the lagged impact of earlier increases in the onshore rig count filter through.From a cycle low in May 2016, the number of rigs drilling for oil in the United States has risen by 380 or around 120 percent (tmsnrt.rs/2oTKD1h).Exploration and production firms are still adding drilling rigs at an average of almost 10 per week, according to oilfield services company Baker Hughes (tmsnrt.rs/2p4EThd).Rig counts generally affect production with a lag of about six months so the full impact of all those extra rigs has yet to be reflected in the production statistics. Crude output is already rising much faster than predicted by any of the major statistical agencies at the start of the year. EIA has already raised its year-end forecast from 9.22 million bpd in January to 9.64 million bpd in April (“Short-Term Energy Outlook”, EIA, Jan and Apr 2017). By the end of the year, production is predicted to have fully recovered from the slump and to surpass the previous peak set in April 2015.
The Four Charts That Prompted An Oil Analyst To Declare The OPEC Deal A Failure -- As JPMorgan wrote back in February, while IEA estimated the OPEC crude oil production fell by 1mbd to 32.06mbd in January, suggesting an initial compliance of 90% with the output agreement reached end 2016, the latest oil supply details released by China customs today suggest a reduction of supplies was not yet seen by China, the world’s largest oil importer. Fast forward two months when Reuters analyst Clyde Russell looks at the same data and asks whether "it is time to call the crude oil output cuts by OPEC and its allies a failure?" Echoing what we cautioned two months ago, Russell said that "certainly there is an increasing disconnect between the rhetoric of OPEC and other producers cutting output on the one hand and the reality of a well-supplied crude oil market and mixed signals on the level of global inventories on the other." The math is simple: for OPEC and its allies to achieve their aim of sustainable higher prices, both global supplies and inventories have to be reduced, the so-called market re-balancing. Yet "it's here that the main evidence of the failure of the OPEC agreement is to be found."\ As the charts below demonstrate, oil shipments by tanker around the globe were at a record high in April, according to vessel-tracking data compiled by Thomson Reuters Supply Chain and Commodity forecasts. As of last week, the data shows that an average 50.3 million barrels per day (bpd) of crude is being shipped in April, up from the previous record 46.1 million bpd in January. While the data excludes crude moved by pipelines, it's extremely unlikely that pipeline supplies have been cut by more than seaborne cargoes have increased.Worse, the data also show that Saudi Arabia, which undertook to make the largest output cut among those producers party to the November deal, is actually increasing tanker shipments in recent months, to levels well above those that prevailed late last year. In short, OPEC may be producing less - if only believes the OPEC-sourced data - but actual global deliveries of oil have never been higher!
Iraq's fuel oil exports soar despite OPEC supply cut | Reuters: Iraqi fuel oil exports have soared since January despite a reduction in the country's crude production in line with OPEC supply cuts, industry sources said, in what could be a way to boost output of refined products and maintain oil revenues. Iraq on average exported between 80,000 and 160,000 tonnes of fuel oil per month in 2016, data collected by Thomson Reuters Oil Research showed. But volumes sold to Asia have jumped this year, with Iraq's global exports of fuel oil reaching more than 500,000 tonnes in March alone, according to Reuters data. The soaring exports of high-quality straight-run fuel oil (SRFO) are an attempt to support revenues amid the OPEC cuts in which Iraq reluctantly agreed to participate, saying it would reduce crude output by 210,000 barrels per day (bpd). Iraq has processed more crude through its refineries, turning it into fuel oil for export, five industry sources with knowledge of the matter said. "The Iraqis have been processing more crude internally than exporting it, hence there are more fuel oil exports," said one Middle East-based industry source, speaking on condition of anonymity as he was not authorised to talk to the media. A manager at an Iraqi-headquartered energy trading company said: "The Iraqis have been working on optimising fuel oil exports ... in a move to compensate for the OPEC (crude) cuts." Other Middle East trade sources said Iraq had been blending the high-quality fuel oil it produces with either crude or naphtha before exporting it.The effect has been felt as far as Singapore, Asia's main oil-trading and storage hub. Trade data compiled by Reuters shows imports of Iraqi fuel oil at 0.94 million tonnes in the first quarter of 2017, nearly double the 0.48 million tonnes imported during the whole of 2016.
Opec oil exports under scrutiny as crude price sags - As oil prices languish near $50 a barrel, energy traders are starting to point the finger at one previously overlooked culprit: exports. For all Opec’s self-imposed production restraint the group’s exports have fallen by less than their output cuts might imply. Morgan Stanley analysts say that while Opec has hit its target by cutting as much as 1.4m barrels a day of output to try and support the market, shipping data suggests the group’s exports have declined by less than 1m b/d since the start of the year. Consultancy Energy Aspects echo this view, arguing the discrepancy between the group’s production and exports risked being seen as “disingenuous” by a market that has been rapidly “losing faith” in the group. Analysts at Energy Aspects say tanker tracking data suggests Opec’s exports have fallen by as little as 800,000 b/d so far in 2017 as some members have supplanted oil lost to production cutbacks with crude from storage, or have freed up barrels for export as they carry out maintenance at domestic refineries. The relatively high export levels are likely to come under scrutiny when Opec ministers meet on May 25, when they will decide whether to extend the production deal for another six months. While a continuation of the deal appears close to being rubber-stamped, with Opec ministers and non-Opec participants such as Russia largely agreeing more needs to be done to tighten the market, the export levels may raise tensions between a group that has fought hard to maintain cohesiveness during a near three-year old oil slump. One Gulf Opec delegate said he remained confident the rebalancing the cartel is trying to achieve is “under way” but admitted “the impact of output cuts on exports will be lagged behind”.
All Eyes On Saudi Arabia As OPEC Begins To Unravel - Has OPEC failed? That’s the question analysts have begun to ask, approaching the group’s next meeting later this month. When the members gather at their headquarters in Vienna, it will likely be to agree on an extension of production cuts in place since January.Those cuts, originally intended to re-balance markets and boost prices, had an initial positive effect but their ultimate impact has been difficult to measure, as inventories have declined only gradually while global oil shipments have increased. New production from outside of OPEC, particularly in the United States, has kept global inventories high.It’s generally believed that OPEC members will recognize the need to extend cuts, with one observer calling it a “100 percent” probability. There is some speculation that Russia, a non-OPEC state whose cooperation is crucial to the overall success of OPEC’s strategy, may prove intransigent when it comes to cutting more production, but that skepticism was partly assuaged last week when Russia’s government indicated their compliance had neared one hundred percent.As far as major OPEC producers, such as Saudi Arabia, Iraq and Iran are concerned, an extension of the existing arrangement makes sense. Riyadh has been over-cutting and wants higher prices to support the partial IPO of Saudi Aramco next year. Iran and Iraq were both partly exempt from the production cuts, with Iran successfully recovering production to 3.8 million bpd. While it’s unlikely Iran or Iraq would agree to reducing production, there’s little reason for them to protest an extension of the deal, especially when they’ve been able to seize market share from others, like Saudi Arabia, who have had to cut more. Fears that oil could plunge below $40 a barrel if no extension is agreed upon have begun to percolate, putting pressure on OPEC to deliver an extension at their May meeting.
Oil Seen at or Below $40 If OPEC Doesn’t Extend Output Cuts -- Crude will probably drop to $40 a barrel or below unless OPEC and allied producers extend their collective cuts in output beyond June, according to analysts including the Abu Dhabi Investment Authority’s head of research. The six-month cuts that took effect in January have set a floor for prices, but an increasing supply of U.S. shale oil together with record-high inventories are keeping the per-barrel price of crude from rising beyond the upper $50s, Christof Ruehl said Wednesday at a conference in Dubai. “If OPEC and the coalition don’t extend the agreement to continue cuts, that price floor will go,” he said. “Without it, prices would fall, and there’s nothing to stop oil going below $40 a barrel.” “The market is looking for a direction right now and ending the production cuts would be a negative for oil prices,” said Edward Bell, a commodities analyst at Dubai-based bank Emirates NBD PJSC. “Without a deal, oil could certainly be pushed below $40.” A drop to $40 a barrel is “a clear option” should OPEC not agree to extend cuts next month, Eugen Weinberg, head of commodities research at Commerzbank AG in Frankfurt, said Wednesday.
Oil Tumbles To $48 Handle Again After Libyan Output Surge -- The dead cat bounce of early April is officially dead... again. Following headlines proclaiming Libyan crude output exceeding 760k barrels per day - the highest since Dec 2014 - WTI prices have broken back below $49 and erased the entire move post-OPEC deal last year...
Oil Prices Weighed Down by Libya's Output Resumption - Higher-than-expected production in Libya and soft manufacturing activities indicators in the US and China dented hopes of demand improvement. Trump's suggestion or raising gas tax to fund infrastructural spending has also vexed the market. The front-month WTI crude oil contract initially dropped to a 5-week low of 48.59 before ending the day at 48.84, down -0.99%. The Brent contract also slipped to as low as 51.22 before settling at 51.52, down -0.41%. Gasoline and heating oil prices plunged more than +1%. The RBOB gasoline contract extended weakness for 4 days in row, losing an aggregate -6%. With the European market closed on public holiday, the US equity market was mixed. Trumps' idea of breaking up large banks, separating commercial and investment banking operations triggered a short-lived selloff in the financials. In Wall Street, DJIA moved within a narrow range before adding +0.1% at close, while S&P 500 gained +0.2%.US Treasury prices dropped, sending yields higher, as traded lightened positions ahead of the FOMC meeting and the April employment report. The market also needs to digest the potential impacts of Trump's signal that he's considering breaking up the big banks. National Oil Corporation of Libya reported that the country's oil production has risen above 0.76M bpd, the highest since December 2014, due to the reopening of the major western field of Sharara last week. The field has the production capacity of more than 0.2M bpd. Disruption by pipeline blockades over the past two months has cut the country's total production to less than 0.5M bpd. Lifting of the blockade does not only resume production Sharara, but also helps resume production to resume at the nearby El Feel field, which can pump 0.08M bpd. Before the civil war in 2011, Libya was producing around 1.6M bpd. Note also that Libya is excluded from the OPEC agreement so it has not obligation to restrain production.
Oil up as OPEC, Russia cuts outweigh output elsewhere | Reuters: Oil prices rose on Tuesday on news of lower production by Russia and OPEC, and expectations that major exporters would extend output cuts into the second half of the year. Benchmark Brent crude oil LCOc1 was up 30 cents at $51.82 a barrel by 1230 GMT (8.30 a.m. ET). The futures contract hit a one-month low of $50.45 last week after the restart of two Libyan oilfields. U.S. light crude CLc1 was 20 cents higher at $49.04. The Organization of the Petroleum Exporting Countries and other producers including Russia have agreed to cut output by 1.8 million barrels per day (bpd) for the first half of 2017 to try to reduce a global glut. OPEC oil output fell for a fourth straight month in April, a Reuters survey showed on Tuesday, dropping to 31.97 million bpd as Nigeria and Libya pumped less crude. Russian oil production fell slightly last month to 11.00 million bpd, almost hitting its output target under the deal with OPEC, Energy Ministry data showed on Tuesday. OPEC and other producers plan to meet on May 25 and are widely expected to keep output limits for the rest of the year.
Oil Prices Fall As Hedge Funds Throw In The Towel -- Oil prices dropped by another 1 percent on Monday, hitting fresh one-month lows. WTI dropped below $49 per barrel and Brent sank below $52. Things looked slightly better on Tuesday, as crude benchmarks added some small gains on a softer dollar and more OPEC production cuts. Another 9 oil rigs were deployed in America’s shale fields, a sign that the industry is undaunted by flagging oil prices. But the ability to produce profitably at $50 per barrel suggests downward pressure on prices, as more production is slated to come online later this year. “The U.S. rig count indicates that there is plenty more to come," analysts at JBC Energy said in a recent report. First quarter earnings continue to show strong performances from the oil majors. ExxonMobil said its earnings doubled from a year earlier to $4 billion. Chevron saw its shares surge by 2 percent after it beat expectations by a large margin, posting earnings of $1.23 per share compared to consensus estimates of $0.86 per share. The $2.3 billion quarterly profit was up from a loss of $725 million a year earlier. BP (NYSE: BP) swung to a profit in the first quarter as well, taking in $1.4 billion compared to a loss of $485 million a year earlier. BP’s share price jumped by more than 2 percent on the news on Tuesday. Still, BP’s net debt rose sharply in the first quarter because of payments related to the 2010 Deepwater Horizon disaster. In an interview with CNBC, in which he was aggressively pressed to say that U.S. shale had “defeated” OPEC, Chevron CEO John Watson demurred, saying that while shale “can help,” it cannot supply the world for the long-term by itself. “[U]ltimately oil fields decline, and we're going to need all sources of supply, including the shales, but also deepwater and other sources around the world," Watson said. The comments echo the IEA and a growing number of other top voices in the industry, predicting a supply crunch towards the end of the decade.
OPEC oil output falls in April but compliance weakens - Reuters survey | Reuters: OPEC oil output fell for a fourth straight month in April, a Reuters survey found on Tuesday, as top exporter Saudi Arabia kept production below its target while maintenance and unrest cut production in exempt nations Nigeria and Libya. But more oil from Angola and higher UAE output than originally thought helped OPEC compliance with its production-cutting deal slip to 90 percent from a revised 92 percent in March, according to Reuters surveys. The Organization of the Petroleum Exporting Countries pledged to reduce output by about 1.2 million barrels per day (bpd) for six months from Jan. 1 - the first supply cut deal since 2008. Non-OPEC producers are cutting about half as much. OPEC wants to get rid of excess supply that is keeping oil LCOc1 below $52 a barrel, half the level of mid-2014. With the oversupply proving hard to shift, OPEC is expected to prolong the agreement. Compliance of 90 percent is still higher than OPEC achieved in its last cut in 2009, Reuters surveys show. Analysts including those at the International Energy Agency have put adherence in 2017 even higher, with the IEA calling it a record. April's biggest production gain came from Angola, which scheduled higher exports and where output started at the East Pole field in February. The increase brought Angolan compliance down to 91 percent, from above 100 earlier in the year. Other, small increases came from Kuwait and Saudi Arabia, the survey found, although their compliance was the second-highest and highest respectively in OPEC.
Market sentiment mixed after Saudi Aramco cuts June OSPs for Asia --Market sentiment was mixed on Tuesday, after Saudi Aramco cut the June official selling price differentials of its Asian-bound crude grades by 20-70 cents/b late Monday. Aramco lowered the price of its Asia-bound Arab Light crudes by 40 cents/b to a discount of 85 cents/b to the Platts Oman/Dubai average in June, it said in a statement late Monday. The OSP was the lowest since September 2016, when it was at a discount of $1.10/b, S&P Global Platts data showed. It also lowered the price of Arab Medium by 45 cents/b to a discount of $1.30/b to Oman/Dubai, the lowest since January this year. Aramco lowered the price of its Arab Super Light by 70 cents/b to a premium of $3.05/b to the Platts Oman/Dubai average in May, the lowest since the beginning of the year. It lowered the price of its Arab Extra Light by 60 cents/b to be equal to the Platts Oman/Dubai average in June, and the price of Arab Heavy crude by 20 cents/b from May to a discount of $2.80/b to the Platts Oman/Dubai average in June. Traders surveyed by S&P Global Platts last week said they expected Aramco to cut the June OSP differentials of its Asia-bound crudes by up to 40 cents/b from May. "[The June OSPs showed] much bigger cuts than I expected. I would say refiners should be pretty pleased," said a Singapore-based crude trader.
Oil prices end at multiweek lows - Oil on Tuesday registered back-to-back declines as rising output in Libya and the U.S., and a survey showing a fall last month in compliance with the Organization of the Petroleum Exporting Countries’ production cut, sent futures to their lowest settlements in several weeks. Investors will also look to coming weekly data on U.S. crude and petroleum-product supplies, as well as talk from major oil producers ahead of a much-anticipated OPEC meeting late this month. June West Texas Intermediate crude fell $1.18, or 2.4%, to settle at $47.66 a barrel on the New York Mercantile Exchange. Based on the front-month contracts, that was the lowest front-month contract finish since March 21, according to data from Dow Jones. Based on the most-active contracts, however, it was the lowest since Nov. 29, according to FactSet data. July Brent on London’s ICE Futures exchange lost $1.06 cents, or 2.1%, to $50.46 a barrel. Brent prices settled at the lowest for a front-month and most-active contract since late November, FactSet data showed. OPEC member compliance with the production-cut agreement that began on the first day of this year has seen a month-on-month decline, according to a Reuters survey published Tuesday. Member compliance was at 90% in April—a bit below a revised-down 92% in March. “Overall compliance remains high, especially relative to OPEC’s previous coordination efforts,” Robbie Fraser, commodity analyst at Schneider Electric, told MarketWatch. “The problem OPEC is facing is commitment levels haven’t really changed, but U.S. production has.”“Restoration of Libyan output” has also weighed on the market over the past week, he said in an earlier note. Still, “an extension of the current OPEC production deal appears to have a high likelihood of success heading into the group’s formal meeting” set for May 25, Fraser said. “At the same time, the demand for refined crude products should see a steady seasonal rise over the weeks ahead, leading to more reliable stock draws.”
WTI/RBOB Pop After Biggest Crude Draw Since 2016, Surprise Gasoline Draw Following last week's surprise builds in Gasoline and Distillates, API reported a bigger than expected crude draw of 4mm barrels (which will be the biggest since 2016 if it holds for DOE). Furthermore,RBOB jumped after gasoline (and distillates) inventories fell (against expectations of a modest build). API:
- Crude -4.158mm (-3.5mm exp) - biggest since 2016
- Cushing -215k
- Gasoline -1.93mm (+1mm exp)
- Distillates -436k
Inventory draws across the board...
WTI/RBOB Tumble After Surprise Inventory Data, Production Rise -- Following API's surprisingly large drawdowns, DOE almost completely refuted it with an inventory build for gasoline and a very small draw for crude. WTI and RBOB prices dropped on the headlines, not helped by yet another increase in US crude production to cycle highs. API:
- Crude -4.158mm (-3.5mm exp) - biggest since 2016
- Cushing -215k
- Gasoline -1.93mm (+1mm exp)
- Distillates -436k
- Crude -930k (-3mm exp)
- Cushing -728k (-900k exp)
- Gasoline +191k (+1mm exp)
- Distillates -562k (+2mm exp)
3rd weekly build for gasoline and notably small draw for crude...
Shenanigans -- Oil Numbers -- May 3, 2017 -- Earlier this morning I posted this: The big question is: how did the crude oil market react to the news that there was a paltry drawdown in US crude oil storage this week? The price of WTI dropped below $48 yesterday. Traders are obviously seeing the same problem. The bigger question is: when did traders get this information? Based on the time of the price move, it is clear to me that "inside" traders got this information yesterday; the rest of us got it today. The big move in WTI pricing was yesterday. Today, the price of WTI moved just one cent -- WTI is down $0.01 today (at this moment -- May 3, 2017; 12:35 p.m. CDT). Just saying. The point is this: this morning I suggested that "inside" traders knew yesterday that the drawdown in US crude oil supplies that wold be reported today. Today we see further proof -- from Twitter: Yesterday afternoon, "inside" traders got the news. The "official" report was embargoed until today for the rest of us.
Oil Prices Crash To Pre-OPEC Deal Levels -- Oil prices dropped on Thursday to their lowest level since last November, with Brent breaking below $50, amid concerns of rising global supply and still high inventories. At 11:22am EDT, WTI Crude was trading down 2.82 percent at $46.47, while Brent was down 2.62 percent at $49.46 -- with both WTI and Brent having effectively wiped out all the price gains since OPEC announced on 30 November 2016 the output cut deal aimed at reducing oversupply and propping up prices. On Wednesday, a day after the American Petroleum Institute (API) injected a bit of optimism among traders by reporting a crude oil inventory draw of 4.2 million barrels, the EIA once again poured cold water on the oil bulls by reporting a much smaller decline, of 900,000 barrels, against expectations for a decrease of 2.3 million barrels. While U.S. crude oil inventories have declined in the past couple of weeks, stocks are still at 527.8 million barrels, near the upper limit of the average range for this time of year. In addition, production from countries not signatories to the OPEC/NOPEC deal – most notably the U.S. – is on a continuous rise since that very same deal managed to lift oil prices and keep them steadier at above $50 for a few months. “At some point, the market should recognize OPEC isn't the most important player in the market any more. That is non-OPEC, and, above all, U.S. shale,” Commerzbank analyst Eugen Weinberg told Reuters. Comments and speculation ahead of OPEC’s meeting on May 25 would likely bring prices back to the $50s, according to Weinberg. “Still, the damage is there and I wouldn’t be surprised to see lower levels this summer after the meeting,” he noted.
Brent Crude Drops Below $50 After Russian Comments, Sliding Demand Forecast -- For the first time since mid-March, Brent Crude prices tumbled below $50 after Russia said no decision had been made yet on extending the oil output cut production deal. This came after the 11th weekly rise in US crude production and concerns from JBC that oil demand is declining rapidly.Russia Says No Decision Yet on Extending Oil Output Cut W/ OPEC - Russia will make announcement if decision is taken, Kremlin spokesman Dmitry Peskov tells reporters on conference call.US Crude production rose once again to August 2015 highs...And demand forecasts are tumbling:And the result... Brent back below $50... A further decline to below $49.71/bbl would take Brent to lowest since Nov. 30, day of OPEC meeting where group decided on production cuts strategy. For WTI, a drop to below $47.01/bbl would take commodity to lowest since same date.
Oil prices have plunged 14% in 3 weeks -- Renewed fears about the oil supply glut have sent crude prices plunging 14.5% from their peak in mid-April to below $46 a barrel on Thursday. It's the weakest level for oil since November 30, the day OPEC finalized a deal to slash production in a bid to end the epic oil glut. The landmark OPEC agreement, the cartel's first cut since 2008, initially sent oil bulls into a frenzy. Crude prices spiked and many predicted a speedy return to $60-plus prices as excess supply would finally be drained. Flash forward five months and the epic supply glut continues to cast a shadow. A combination of resilient US shale output and surprisingly sluggish demand for gasoline from American drivers has led US stockpiles of oil to remain at historically-high levels. Oil prices plunged another 4% on Thursday, dragging energy stocks like ExxonMobil (XOM) even further into the red this year. "Today is a real scary day for the billions of dollars invested in higher oil prices," said Tom Kloza, global head of energy analysis at Oil Price Information Service. "We continue waiting for this slow-motion, almost glacial rebalancing of crude." The explosion in US shale oil output over the past decade has reshaped the global energy landscape, catapulting America to the upper echelon of the list of global producers. The glut in oil sent oil prices crashing in late 2015 and early 2016 and US shale production, especially in areas like the Bakken fields of North Dakota, took a hit. But shale is on the comeback trail now, aided by technological advances and leaner business models that have allowed companies to pump profitably at far lower prices than before. Just look at how the tally of US oil rigs has more than doubled from last year.
Oil prices plunge 4% below $46 a barrel, dropping to a five-month low --Oil prices collapsed on Thursday to their lowest since late November as investor worries about the world's stubbornly persistent glut of crude erased most of the gains that followed last year's OPEC's output cut. The slide worsened after OPEC delegates downplayed the chance that their group and other producing countries would deepen their output cuts when they meet on May 25. They did say current output cuts were likely to be extended. Brent crude oil futures were down $2.31, or 4.6 percent, at $48.48 a barrel by 1:27 p.m. (1727 GMT). U.S. West Texas Intermediate (WTI) crude futures fell $2.25, or 4.7 percent, at $45.57 a barrel. Both contracts slid during the session to the lowest since Nov. 30, the day OPEC agreed to cut supply. They were on track for their biggest daily percentage declines March 8. Late last year, the Organization of the Petroleum Exporting Countries and other producing countries announced oil output cuts of 1.8 million barrels per day (bpd) for the first six months of this year. Even so, McGillian said, "We still have a near record overhang and signs of increasing production in areas of the world outside the producers that agreed to the cuts." Crude output has surged in the United States, with increasing rig counts for the past 11 months. Weekly U.S. government data on Wednesday showed crude stocks fell 930,000 barrels, less than half the 2.3 million barrel drop analysts had expected. Stocks stand just 7 million barrels off a record high. U.S. gasoline futures were down about 4 percent after the stockpile report indicated continued weakness in gas demand. They are have fallen more than 8 percent this year.
Oil Tumbles Amid Oversupply Fears, Unlikelihood Of Deeper OPEC Cuts (Reuters) - Oil prices plunged to five-month lows on Thursday amid record trading volume in Brent crude, as OPEC and other producers appeared to rule out deeper supply cuts to reduce the world's persistent glut of crude. Closing prices, below $50 a barrel, were the lowest since Nov. 29, thereby erasing all the market gains that followed a late 2016 announcement by the Organization of the Petroleum Exporting Countries it would cut output. The slide steepened after the OPEC delegates downplayed the chance that their group and other producing countries would deepen their output cuts when they meet on May 25. They did say current output cuts were likely to be extended. But analysts say non-OPEC members may struggle to extend production cuts. U.S. crude ended the session 4.81 percent lower at $45.52 per barrel after falling as much as 5.29 percent to an intraday bottom of $45.29, the lowest since Nov. 29. Brent crude settled at $48.38, or 4.75 percent lower, after tumbling as much as 5.17 percent during the session. Front-month Brent crude trading volume rose to the highest on record with nearly 525,000 lots changing hands, according to Reuters data that extends back to 1988. Front-month WTI volume rose to more than 898,000 contracts, the highest in nearly two months. Commodity Trading Advisors were among those liquidating their contracts in the day, traders said. "While the cartel is expected to extend a self-imposed production cap by another six months, it will be a challenge to convince several non-OPEC members to follow suit," said Abhishek Kumar, senior energy analyst at Interfax Energy’s Global Gas Analytics. "Persistent growth in US oil production ... will also make extensions of the OPEC cap beyond 2017 unlikely.” There was also a sign of slowing energy demand in China, the world's second largest oil consumer, when a survey showed growth in that country's services sector in April was at its slowest in almost a year.
Oil prices drop as OPEC loses control of narrative: Kemp - Oil traders have finally given up on an early rebalancing of the crude market, with flat prices and calendar spreads plunging to the lowest level since OPEC’s agreement was announced.OPEC has lost control of the oil market narrative, after successfully shaping it in an informal alliance with hedge funds in the last part of 2016 and the first few months of 2017.Controlling the narrative provides an important source of short-term influence over prices (“Narrative economics”, Presidential Address to the American Economic Association, Shiller, 2017).Senior OPEC and non-OPEC officials have dropped strong hints that current production cuts will be extended for a further six months, but oil traders seem increasingly sceptical about the effectiveness of prolonging the curbs until the end of 2017.Brent prices for the futures contract nearest delivery closed at $48.38 per barrel on Thursday, the lowest since Nov. 29, the day before OPEC’s last meeting (http://tmsnrt.rs/2pg4KmJ). Brent calendar spreads for the six months from July 2017 to January 2018 fell to $1.19 contango, which was also the lowest since Nov. 29 (http://tmsnrt.rs/2pHfjBV). The informal understanding on market rebalancing between OPEC and some of the most important hedge funds reached late last year finally unravelled this week.OPEC committed to implement credible and transparent production cuts and to reduce global crude stocks while hedge funds responded by establishing long positions in both flat prices and calendar spreads.The initial results from the understanding were positive for both sides, with hedge funds establishing a record bullish position in crude by the middle of February and futures prices rallying.Brent’s flat price rose by around $10 per barrel, or more than 20 percent, and the market structure swung from contango into backwardation.But flat prices and spreads have been progressively softening since the second half of February (“Hedge fund confidence in OPEC starts to fray”, Reuters, April 20). Global crude inventories have not fallen as fast as OPEC or the hedge funds anticipated, putting the understanding under pressure. Market expectations for a normalisation of crude stockpiles have been pushed back from the first half of 2017 to the second half or even into 2018.
Why Are The Oil Markets Crashing? - WTI and Brent continued to tumble on Thursday, dropping to their lowest levels since the announcement of the OPEC deal back in November. Brent actually dipped below $49 per barrel, raising fears of another downturn. Both WTI and Brent were off by nearly 4 percent during midday trading on Thursday.Oil traders have been patient, hoping that despite the rapid rebound in U.S. shale production, the OPEC cuts would take a substantial volume of oil off the market and correct the supply/demand imbalance. But it has been a painful and protracted process.U.S. crude oil inventories hit a record high of 535 million barrels as recently as the end of March. Several consecutive weeks of drawdowns in April again raised hopes that the market is heading towards balance, but the most recent data release from the EIA on May 3 disappointed yet again, and it was apparently the last straw for some. Market analysts predicted a drop in oil inventories by about 2.3 million barrels, but the EIA said stocks only fell by 930,000 barrels. WTI sank to $46 per barrel and Brent fell into the $40s for the first time in 2017.Worse, gasoline stocks increased slightly, offering more evidence that motorists are not willing to burn through all the refined products that the downstream sector is producing. Even if refiners suck more crude out of storage, consumers won’t sufficiently burn through all of the additional refined product.But the most bearish part of the report came from the upstream figures, which once again showed dramatic growth in U.S. oil production. In the last week in April, the industry added another 28,000 bpd, taking U.S. output up to 9.293 million barrels per day (mb/d), up more than 200,000 bpd since the beginning of March, and up more than 450,000 bpd since the start of the year. Output is now the highest since the summer of 2015, and if current trends continue, the industry could break all-time production records before we know it.U.S. oil production “continues to grow hand over fist, and the market will remain well oversupplied given the lack of” demand for gasoline and diesel, Roberto Friedlander, head of energy trading at Seaport Global Securities, told CNBC. It is growing more difficult by the day to make the case that oil prices will post strong gains this year. A WSJ survey of 14 investment banks finds an average projected Brent oil prices for this year at $57 per barrel, an estimate that is starting to look a bit overly optimistic.
Oil price collapse is ‘permanent’; analyst says fossil fuel has had its day - “I usually put a £5 bet on the oil price — and I’m collecting,” smiles Professor Dieter Helm. It’s not difficult to imagine his tally of modest wagers adding up. The highly regarded Oxford University economics professor is a long-time industry observer. Today, he is in central London after taking meetings with major oil executives. He is also a familiar face in Whitehall and Brussels, where he advises, both formally and informally, on the trends reshaping the global energy markets. Still, his stakes will be trillions of dollars lower than the energy leaders he advises. If Helm is to be believed the oil market downturn is only getting started. The latest collapse is the harbinger of a global energy revolution which could spell the end-game for fossil fuels. These theories were laughable less than a decade ago when oil prices grazed highs of more than $140 a barrel. But the burn out of the oil industry is approaching quicker than was first thought, and the most senior leaders within the industry are beginning to take note. In the past, the International Energy Agency (IEA) has faced down criticism that its global energy market forecasts have overestimated the role of oil and underplayed the boom in renewable energy sources. But last month the tone changed. The agency warned oil and gas companies that failing to adapt to the climate policy shift away from fossil fuels and towards cleaner energy would leave a total of $1 trillion in oil assets and $300bn in natural gas assets stranded. For oil companies who heed Helm’s advice, the route ahead is a ruthless harvest-and-exit strategy.This would mean an aggressive slashing of capital expenditure, pumping of remaining oil reserves while keeping costs to the floor and paying out very high dividends. “They’d never do it because no company board would contemplate running a smaller company tomorrow than today. It’s not in the zeitgeist of the corporate world we’re in, but that’s what they should do,” Helm says.
OilPrice Intelligence Report: Crude Drawdowns Can’t Save Oil Prices - Oil prices crashed on Thursday, erasing all the gains made since the OPEC deal was announced, with WTI and Brent dropping to six-month lows. Fears over persistent oversupply, a renewed glut for refined fuels, and the inadequately slow pace of adjustment stemming from the OPEC cuts all forced a selloff. Major oil benchmarks lost 5 percent on Thursday, but have since seen a bounce back as hedge funds have now dumped all long positions. Although the drop in prices underscores the poor market fundamentals, the suddenness of the decline and quick recovery bears all the markers of a technical selloff. Plunging oil prices are at least in part attributable to the selloff in the futures market from hedge funds and other money managers. Reuters reported that famed hedge fund manager Pierre Andurand, who has been bullish on crude, liquidated his long positions on crude over the past week. The move highlights the growing bearishness for crude oil. It happened at the end of 2016 and into the early part of this year – and it’s happening again. Refiners are ramping up their processing, but there isn’t enough demand in the market for all the gasoline and diesel they are producing, leading to another strong buildup in refined product inventories. For diesel, at least, global demand is robust and American refiners will likely have an easy time finding buyers overseas. Preliminary data suggest U.S. exports of diesel hit a record high in April. However, it is the glut of gasoline that is worrying everyone else. The increase in gasoline inventories is especially troubling because this is a time of year in which gasoline stocks typically fall as motorists take to the roads. Three OPEC sources told Reuters on Thursday that the group is likely to extend its cuts for another six months when it meets later this month. But the sharp selloff in crude prices this week raises questions about whether that will even be enough. Still, deeper cuts are unlikely. Shale gets all of the attention, but production from the U.S. Gulf of Mexico is still on the rise. The Gulf of Mexico produced 1.76 million barrels per day in January and could add another 190,000 bpd by the end of the year. RBN Energy estimates that output will jump again next year by another 300,000 bpd. Offshore drilling is still a long-term, capital intensive proposition, but costs have come down with improved technology. Still, production gains are largely coming from projects planned years ago that are only now reaching fruition.
Suddenly, Oil Below $40 a Barrel Doesn’t Seem So Far-Fetched -- It’s come to this for the beleaguered oil market: a big bet that prices are about to sink to their lowest level in more than a year.About $7 million worth of options changed hands Friday that will pay off if West Texas Intermediate crude falls beneath $39 a barrel by mid-July, according to data compiled by Bloomberg. WTI, which hovered around $46 Friday, hasn’t traded below $39 since April 2016, though it’s been dropping like a stone in recent weeks.More than 14,000 August $39 puts changed hands, almost 20 times the number of contracts previously outstanding for the bearish option. The trade was a sign of the “crescendo of negativity" that’s washing over the oil market, said James Cordier, founder of investment firm Optionsellers.com in Tampa, Florida. Prices have plunged about 13 percent in the last three weeks, amid fears that OPEC-led production cuts aren’t doing enough to stem a global supply glut. For Friday’s bet to work, prices would have to match that drop in the next few weeks, during a time when summer driving typically pushes demand higher, Cordier said by telephone. “That’s just a huge speculative bet that tells me that the fear is at its heights and we’ll probably see oil recover," he said. “It’s a hell of a lottery ticket that the market’s going to keep falling."
16th Straight Build In Oil Rig Count Increases Pressure On Oil Prices - The number of active oil and gas rigs in the United States rose by 7 on Friday, according to oilfield services provider Baker Hughes, delivering a severe blow to oil prices, which were already down to new lows for 2017.The total oil and gas rig count in the US now stands at 877 rigs, or 462 above the count a year ago. Oil rigs increased by 6, while gas rigs bumped up 2; a single miscellaneous rig was taken out of production. At 12:39pm EST, WTI was trading up 1.25 percent for the day at $46.09, while Brent Crude traded up 1.07 percent at $48.90—about a $3.00 per barrel loss from last Friday. Those prices reflect almost a total reversion to the price points prior to the OPEC agreement announcement on November 30, 2016. This week marks the sixteenth straight build for oil rigs (+181 or +34.7% since January 13). Gas rigs climbed 11 of the last sixteen weeks, for a total gain of 37 (+27.2%). Some in the industry see this as a complete failure on OPEC’s part, who set out a monumental effort to stabilize the market through “rebalancing” the oil market in hopes of lifting prices. While OPEC—and its non-OPEC counterpart—has indeed shaved about 1.8 million barrels per day off their October 2016 production levels, it has done little, if anything, to oil inventories globally, and as of today, has done little, if anything, to boost prices.Meanwhile, U.S. shale is carrying on, after enjoying what was a temporary lift in oil prices during the last 4 months thanks to OPEC’s production cuts. Shortly after data release, WTI was trading at $46.29 +1.69% with Brent trading at $49.15, up 1.59%.
U.S. Oil Rig Count Climbs To 703 As Crude Falls 6.3% For Week -- The number of oil rigs operating in the U.S. rose by 6 to top 700 for the first time since April 2015, according to Baker Hughes (BHI), as prices recouped some of their steep losses this past week amid growing concerns over U.S. production gains. The count in Colorado's DJ Niobrara was flat at 25 rigs. Eagle Ford in south Texas saw rigs fall by one to 75. In the Permian Basin, oil rigs jumped by 7 to 349. The Cana Woodford formation in Oklahoma saw a decline to 51 from 55. U.S. crude, which tumbled just below $44 a barrel overnight, rose to close up 1.5% to $46.22. That followed Thursday's 4.8% dive to $45.52 to its lowest since the end of November, when OPEC and top non-OPEC producers agreed to a production cut that would remove 1.8 million barrels of oil from the market. Crude oil still fell 6.3% for the week.OPEC and other top non-member producers will meet on May 25 to discuss extending the output cuts. Saudi Arabia's OPEC Governor Adeeb Al-Aama told Reuters that "there's a growing conviction that a six-month extension may be needed to rebalance the market, but the length of the extension is not firm yet." While the cut is likely to be extended, producers won't take more barrels of oil off the market, sources told Reuters earlier this week. OPEC is feeling the squeeze as U.S. production continues to rise and as worries persist over slowing demand. On Wednesday, the Energy Information Administration said that U.S. crude production hit 9.29 million barrels a day last week. Output is on pace to exceed peak production levels in July and could hit 10 million barrels per day in August, according to analysts. Production projections are fueled by a growing rig deployment. The U.S. oil-rig count has risen for 15 straight weeks with only one down week so far this year.
OPEC Apr output 31.85 million b/d, unchanged from Mar: Platts survey -- OPEC crude output in April averaged 31.85 million b/d, flat from March, an S&P Global Platts survey found, with the bloc still showing high compliance with its production cut agreement, as increases in Angola and Nigeria were offset by declines from Libya and Iraq. OPEC ministers will meet in Vienna on May 25 to review the agreement and potentially extend the cuts past their June expiry. Thus, the April production figures in the Platts survey and the five other secondary sources used by OPEC to monitor output will be some of the final data points that the organization considers at its meeting. OPEC's collective April output was some 80,000 b/d above its stated ceiling of 32.5 million b/d, when Indonesia, which typically produces about 730,000 b/d, is added in. Indonesia suspended its OPEC membership in November and is not included in the Platts survey estimates for 2017. OPEC's largest producer Saudi Arabia averaged 9.97 million b/d in April, according to the survey, below its quota under the deal of 10.058 million b/d. The kingdom is seen as a driver of OPEC's production cut deal, with energy minister Khalid al-Falih saying at a conference in Abu Dhabi last month that there appeared to be a growing consensus on a need to extend the cuts, as global inventories remain stubbornly high. Iraq, which has faced criticism for not fully complying with its required cut, produced 4.36 million b/d in April, the survey found, as the Taq Taq field in the Kurdistan Region of the country has seen output decline, while exports from Iraq's Persian Gulf terminal also fell during the month. The country's April output is 9,000 b/d above its quota under the deal, the closest it has been to compliance. Over the January through April period, however, its average remains 60,000 b/d above its quota, the highest among OPEC members. Iran, which is allowed a slight output increase under the deal, held production steady in April at 3.77 million b/d, the survey found, below its quota of 3.797 million b/d. The UAE, also under pressure from fellow OPEC members to come into compliance with its quota, lowered production slightly to 2.84 million b/d, down 10,000 b/d from March, the survey found.
Analysis: As prices fall, OPEC looks to Q3 for optimism - The price swoon of the last few weeks has no doubt disappointed -- if not frustrated -- OPEC's 13 members, who have seen their efforts to cut production to support prices seemingly thwarted by stubbornly high inventories. But all along, OPEC officials have maintained that their goal with the production cut deal can not and should not be measured by how the market reacts day to day, or even week to week. Their eyes are focused on the third quarter, when OPEC's own analysis, as laid out in its most recent monthly oil market report, estimates global demand for OPEC crude will rise to 33.13 million b/d, some 1.3 million b/d above current levels. OPEC will issue its newest monthly oil market report next Thursday. "The good news is that the market is moving towards rebalancing," Saudi Aramco CEO Amin Nasser said at the International Oil Summit in Paris last week. "There has also been a rapid drawdown of floating storage in the first quarter of this year. This is being driven by improving fundamentals and the OPEC deal." Iranian deputy oil minister Roknaddin Javadi added: "I am very optimistic that good days for the oil and gas industry are ahead." The deal, signed late last year, calls on OPEC to cut 1.2 million b/d from its October levels, while 11 non-OPEC countries led by Russia agreed to cut 558,000 b/d in concert. To be sure, OPEC had intended its production cuts to have brought down global oil stocks to their five-year average by mid-year. That has not been the case, particularly in the US, where bloated gasoline stocks, in particular, has given the market jitters.
OPEC likely to extend output pact, bigger oil cut unlikely: delegates | Reuters: OPEC and non-OPEC oil producers look likely to extend their agreement to limit supplies beyond its June expiry to help clear a glut, three OPEC delegates said on Thursday, downplaying the chance of additional steps such as a bigger cut. The Organization of the Petroleum Exporting Countries, Russia and other producers originally agreed to curb production by 1.8 million barrels per day (bpd) for six months from Jan. 1 to support the market. Oil prices have gained support but stockpiles are still high and production from non-participating countries such as the United States has been rising, keeping crude below the $60 level that OPEC kingpin Saudi Arabia would like to see. However, OPEC officials generally believe the agreement is helping to bring the market closer to balance between supply and demand and that it should be extended into the second half of the year with the same numbers. "The willingness to extend the current understanding is strong among OPEC and non-OPEC participants," an OPEC delegate said, declining to be identified by name. "I have doubts that more cuts will be discussed as the current agreement is yielding a positive outcome." Officials from the 13-country OPEC - which accounts for a third of global oil production - are in Vienna on Thursday and Friday to attend a meeting of the group's governing board. Such meetings provide an occasion to chat informally, but they deal with administrative matters and do not decide policy.
OPEC Deal Backfires: Saudis Lose Market Share To Iran, Iraq --Since the start of OPEC’s production cuts, oil market analysts and experts have been focusing on how U.S. shale would respond to the relatively higher and stable oil prices, possibly eating up some of the cartel’s global market share while the cuts last.The market share war is also going on a micro level within OPEC itself – a diverse group of producers, with each pushing and pursuing their own agenda in every meeting and collective decision. This time around it is no different.Saudi Arabia, OPEC’s biggest producer and de facto leader, is losing market share, while Iran and Iraq have so far emerged as winners of the cuts with in the cartel in a battle for market share, according to Christof Ruehl, former chief economist at BP who is currently Global Head of Research at the Abu Dhabi Investment Authority (ADIA).“If you’re talking about winners, you can count Iran and Iraq,” Ruehl said at a Dubai conference last week, as quoted by Bloomberg.The Saudis were aware that they would be ceding some market share with the OPEC deal, but opted for higher and more stable oil prices by signing up to a deal that allowed Iran to slightly lift its output, while others— especially Riyadh—would have to cut. The lower-for-longer oil prices have led to a considerable deficit in Saudi Arabia’s budget, and the Kingdom had to draw from reserves and increase the issue of debt to finance the gaps in its oil-dependent government revenues.The Saudis now need higher oil prices if they want their oil giant Aramco to be valued in next year’s IPO anywhere in the vicinity of US$1 trillion, let alone the US$2-trillion valuation that Deputy Crown Prince Mohammed bin Salman has mentioned.The Saudi 2017 budget sees higher oil prices this year lifting oil revenues by 46 percent compared to the 2016 estimates.So, the Saudis entered the OPEC production cut deal knowing that Iran might use the leeway it was given to slightly raise its production, and Iraq might not fully comply with the cuts.
Do Saudi Arabia And Russia Really Want Higher Oil Prices? - The jawboning of oil prices by the Saudi Arabian/Russian tag team should be wearing off after more than a year of actions that don't measure up to the words. Oil prices slumped recently, dropping from around $54 per barrel to just below $50 as of Friday's close.As if on cue, the Russian energy minister announced Friday that Russia has now met its targetof reducing oil production by 300,000 barrels per day. It took four months to do something that should have taken just weeks. (The agreement came into force on January 1.) And, of course, we'll have to see if the Russians have actually done what they say they've done.Only a week earlier, the Saudi energy minister indicated that there is momentum growing in OPEC for extending production cuts beyond June for another six months. This announcement comes only six weeks after the same minister said that OPEC would NOT be considering extending the cuts. This is reminiscent of last year's run-up to the production agreement in which Russia and Saudi Arabia keptalternating in making often contradictory announcements to sow confusion about the possibility of a production agreement and keep markets on edge without actually having to do anything. I continue to question the sincerity of Saudi Arabia and Russia who I believe remain committed to undermining the production of tight oil (shale oil) in the United States.Despite the cuts agreed to for this year through June, the March numbers suggest substantial non-compliance among non-OPEC signers of the production agreement and a reminder that major producers Libya, Nigeria and Iran have been exempted from cuts. Do Saudi Arabia and Russia really want prices to rise enough to make tight oil profitable all across the United States (and not just sweet spots in the Permian Basin)? I'm not convinced. The Saudis and the Russians want to appear as though they are "doing something" about low oil prices. But they and their fellow producers simply aren't doing enough to push prices higher. And, that may actually suit the Saudis and the Russians just fine. Meanwhile, U.S. tight oil producers keep touting ever lower "breakeven" prices for their relatively expensive oil. But, as petroleum consultant Art Berman has been pointing out for some time, the lower breakeven prices are almost completely the product of crashing oil service costs rather than technological miracles. And they aren't limited to tight oil producers, but rather reflect conditions across the entire industry.
The smell of burnt rubber: Saudi Arabia’s young prince U-turns on reform | The Economist - In a kingdom which acts like a (heavily armed) charity doling out cradle-to-coffin welfare, few see a reason to upset the felafel stand. Two-thirds of Saudi Arabia’s 21m citizens are employed by the government and expect annual pay rises whether working or not. Confronted with vast deficits after the oil price collapsed in 2014, the king’s favoured son, Muhammad bin Salman (pictured centre), set out to change all that. The 31-year-old, who serves as deputy crown prince, defence minister and head of the committee that runs the economy, is widely considered to be Saudi Arabia’s de facto ruler, given the great age (81) of his father. His ministers called civil servants lazy and not only unveiled a transformation plan with austerity measures, but actually began implementing them. The slashing of housing, vacation and sickness allowances last September reduced some salaries by a third. Utility bills rose as subsidies fell. This was not popular. If they had to tighten their belts, many muttered, why shouldn’t the prince himself, who reportedly paid half a billion dollars for a yacht in 2015? Activists on social media compared him to Gamal Mubarak, the ravenous son of the deposed Egyptian president. The prince’s primacy, already dented by the bloody mess that his intervention in next-door Yemen’s war has become, seemed in danger of being weakened. On April 22nd the government performed a screeching U-turn, restoring most of the perks and bonuses enjoyed by all those government employees. By reducing the grumbling, Prince Muhammad may hope to regain the middle-class support he needs to bolster his position against opposition from senior princes who would rather that the king’s nephew and crown prince, Muhammad bin Nayaf, succeeds Salman when the time comes.
Saudi Arabia says Trump visit to enhance cooperation in fighting extremism | Reuters: Saudi Arabia's foreign minister said on Thursday that an upcoming visit to the kingdom by U.S. President Donald Trump would enhance cooperation between the United States and Muslim countries in the fight against extremism. Speaking to reporters after the Trump administration said the president would visit Riyadh as well as Israel later this month, Adel al-Jubeir said Trump had a high probability of succeeding in his efforts to secure a peace deal with Israelis and Palestinians because of his "fresh" approach. Saudi Arabia, the birthplace of Islam, will be Trump's initial stop on his first international trip as president. The move signifies the new administration's intent to reinforce a relationship with a top ally in the Middle East, where the United States is leading a coalition against Islamic State and seeking to counter Iranian influence. Saudi Arabia is part of that coalition. Describing the visit as historic, Jubeir said Trump's visit to Saudi Arabia would include a bilateral summit, a meeting with Arab Gulf leaders and another with leaders of Arab and Muslim countries. "It’s a clear and powerful message that the U.S. harbors no ill will” toward the Arab and Muslim world, he said. "It also lays to rest the notion that America is anti-Muslim. ... It's a very clear message to the world that the U.S. and the Arab Muslim countries can form a partnership." The Republican president has been criticized for immigration policies that have been characterized as anti-Muslim. "It will lead to, we believe, enhanced cooperation between the U.S. and Arab and Islamic countries in combating terrorism and extremism, and it will change the conversation with regards to America's relationship with the Arab and Islamic world," Jubeir said.
Yemeni Al-Qaeda Leader: We’re Fighting Alongside US-Backed Forces --While the Pentagon often presents the war in Yemen as being against al-Qaeda by way of trying to justify ever deeper direct US involvement, al-Qaeda in the Arabian Peninsula (AQAP) leader Qasim al-Rimi was a bit more frank about the situation, noting AQAP forces regularly fight “alongside” the US-backed Sunni forces. That’s an often unspoken reality of the Yemen War, of course, as Sunni tribal forces which are often presented as allies to the Saudis, supported by US-coordinated airstrikes, and “militias” loyal to the Saudi-backed government, regularly coordinate wtth AQAP in fighting against the Shi’ite Houthis. This is something the Saudis have preferred not to make a public fact, as the war is already sectarian enough in nature without having direct al-Qaeda involvement, but policy was established very early in the war to attack the Shi’ites wherever they could be found, and to look the other way when AQAP ended up taking over territory in the process. AQAP doesn’t see it as fighting alongside the US, of course, they see it as fighting with “fellow Muslims” against the Shi’ites,, who they consider heretics. With the Pentagon looking to get more deeply involved in a direct way in the war, however, they may find themselves with some uncomfortable allies.
Debunking the French Report on Syrian Chemical Weapons - The French government released a report blaming the Syrian government for this month’s chemical weapons incident. The report states: According to the intelligence obtained by the French services, the process of synthesizing sarin, developed by the Scientific Studies and Research Centre (SSRC) and employed by the Syrian armed forces and security services, involves the use of hexamine as a stabilizer. *** The presence of the same chemical compounds in the environmental samples collected during the attacks on Khan Sheikhoun on 4 April 2017 and on Saraqib on 29 April 2013 has therefore been formally confirmed by France. The sarin present in the munitions used on 4 April was produced using the same manufacturing process as that used during the sarin attack perpetrated by the Syrian regime in Saraqib. Moreover, the presence of hexamine indicates that this manufacturing process is that developed by the Scientific Studies and Research Centre for the Syrian regime. Sounds convincing, right? But the report falls apart upon closer scrutiny … Specifically, the head of the United Nations’ team investigating the possible use of chemical warfare in Syria (Åke Sellström) wrote an email to MIT rocket scientist Ted Postol in 2014 stating: Hexamine … is a product simple to get hold of and in no way conclusively points to the [Syrian] government. In addition, hexamine found in samples may be derived from other sources for example, explosives. This week, Washington’s Blog wrote the following email to Dr. Sellström seeking confirmation: However, my understanding is that it is easy to acquire hexamine, and so the presence of the substance does not indicate state-sponsored manufacture. I also understand that hexamine is a common byproduct from explosives. Is that right? Dr. Sellström responded:It is really a question of the meaning of the word indicating. The presence of hexamine could, indeed, indicate that the source is the government. Leaving out who actually used it. But it could also indicate a lot of other things, like someone using the same recipe for example. I think the phrasing in the statement is clever.
The Flawed Chemical Analysis in the French Intelligence Report of April 26, 2017 Alleging a Syrian Government Sarin Nerve Agent Attack in Khan Sheikhoun of April 4, 2017 -- Theodore Postol, MIT - In this short note I describe why the chemical forensic analysis and logic described in the French Intelligence Report of April 26, 2017 (FIR) could lead to a high confidence conclusion that an indigenous nerve agent attack in Denver, Colorado was perpetrated by the Syrian government. Such an obviously flawed investigative finding would be a product of the same combination of irrational arguments and unsound scientific evidence that the FIR used as its basis to reach a conclusion that the Syrian government must have executed in nerve agent attack on April 4, 2017 in Khan Sheikhoun. We start from quoting directly from page 2 of the French intelligence report, which can be found in a PDF file at :
Turkey threatens to strike U.S. forces partnered with Kurds - The war of words between Washington and Ankara over the U.S. military’s partnership with Kurdish paramilitaries in Syria escalated Wednesday, when a senior aide to Turkish President Recep Tayyip Erdogan suggested American troops could be targeted alongside their Kurdish allies in the country’s ongoing air war against the militias. Senior presidential aide Ilnur Cevik said U.S. forces who are teamed up with members of the Kurdish People’s Protection Units, or YPG, were in danger of being hit by Turkish fighters patrolling the volatile border region with Syria. If YPG units and their American military advisers “go too far, our forces would not care if American armor is there, whether armored carriers are there,” Mr. Cevik said during an interview on Turkish radio station CRI TURK Wednesday. “All of a sudden, by accident, a few rockets can hit them,” he added, referring to partnered U.S. forces. When asked to clarify that U.S. advisers or artillery positions would be in danger from Turkish warplanes, if they continued to support YPG operations in northern Syria, Mr. Cevik replied bluntly that they would. Later, Mr. Cevik attempted to walk back his comments on social media, regarding U.S. forces working with Kurdish militias. “Turkey has never and will never hit its allies anywhere, and that includes the U.S. in Syria,” he said in a tweet posted shortly after Wednesday’s radio interview.
US-led coalition warplanes banned from Syria safe zones – Russian envoy - The four safe zones to be established in Syria will be closed for flights by US-led coalition warplanes, said the Russian envoy to the Astana peace talks, where the zones were agreed upon. “As for [the coalition] actions in the de-escalation zones, starting from now those zones are closed for their flights,” Aleksandr Levrentyev told journalists in the Kazakh capital. He added that the flight ban was not part of the memorandum establishing the safe zones, but assured the coalition would not fly over them. “As guarantors we will be tracking all actions in that direction,” he remarked. “Absolutely no flights, especially by the international coalition, are allowed. With or without prior notification. The issue is closed.” He added that the US-led coalition would continue airstrikes near Raqqa, the Syrian stronghold of Islamic State (IS, formerly ISIS/ISIL), near some towns near the Euphrates River and close to the city of Deir ez-Zor. The Russian Foreign Ministry was less definitive on the alleged ban of US warplanes, stating that “these issues are being discussed at the military level.” On Thursday, a memorandum was signed in Astana establishing four “safe zones” in Syria, where so-called “moderate opposition” fighters are expected to stay safe from airstrikes and keep jihadist groups out. The zones are set in provinces of Idlib, Latakia and Homs, as well as parts of Aleppo. Russia, Iran and Turkey serve as guarantors of the arrangement, which carries hopes of deescalating violence in the war-torn country.