oil prices moved higher for a 2nd week this week, amid crosscurrents of concerns about Iran sanctions, global trade tensions, and oil supply issues... after closing the prior week $3.51 a barrel or 5.4% higher at $68.72 a barrel, US oil for October delivery rose 15 cents to $68.87 a barrel on Monday, supported by a strengthening stock market and news that the US and Mexico had completed a trade deal to replace NAFTA...however, with oil prices up more than $4 over 8 trading sessions, profit-taking set in on Tuesday, pushing oil prices 34 cents lower to $68.53 a barrel, with losses limited by the positive developments on the trade front...oil prices then rose 98 cents to a three week high of $69.51 a barrel on Wednesday, after the EIA reported a drawdown of U.S. crude and gasoline supplies, and reports indicated reduced Iranian crude exports in advance of US sanctions...oil prices rose again on Thursday, extending the gains on the fall in US supply, on growing evidence of disruptions to crude output from Iran and Venezuela, with oil ending Thursday's trading up 74 cents, or 1.1 percent, at $70.25, the highest closing price in six weeks...while oil prices fell 45 cents to $69.80 a barrel on Friday on renewed trade war concerns, they still ended both the week and the month higher, with oil prices for October delivery 1.6% higher than a week ago, and 3.2% higher than a month ago, although we should note that oil prices were being quoted just 1.5% lower at $68.76 a barrel on July 31st, when September oil was the front month contract at the time...
meanwhile, while price quotes for natural gas appeared to end the week a tenth of a cent lower than last week at $2.916 per mmBTU, that was also a function of a midweek change in the quoted front month contract...natural gas for September delivery, which had closed last week at 2.917 per mmBTU, fell 6.5 cents over Monday and Tuesday before rising 4.3 cents on Wednesday as trading in September natural gas contracts expired at $2.895 per mmBTU...after that, natural gas for October delivery, which had started the week priced at $2.913 per mmBTU, became the widely quoted 'price of natural gas' and rose 1.1 cents to $2.874 per mmBTU on Thursday and 4.2 cents on Friday, to end the week $2.916 per mmBTU, three-tenths of a cent higher than what that contract had started the week at...
meanwhile, this week's EIA natural gas storage report for week ending August 24th indicated that natural gas in storage in the US rose by 70 billion cubic feet to 2,505 billion cubic feet during that cited week, which still left our gas supplies 646 billion cubic feet, or 20.5% below the 3,151 billion cubic feet that were in storage on August 25th of last year, and 588 billion cubic feet, or 19.0% below the five-year average of 3,093 billion cubic feet of natural gas that are typically in storage heading into the fourth weekend of August....this week's 70 billion cubic feet increase in natural gas supplies was above expectations of a mid-60s bcf increase and was also above the 59 billion cubic foot average of natural gas that has typically been added to storage during the third full week of August in recent years, thus breaking this summer's string of seven consecutive below average inventory increases...mild temperatures and low humidity in the Midwest during that week were the major factor in the above average build; 35 billion cubic feet of this week's increase was added to natural gas storage facilities in the Midwest...Canadian imports returned as well, likely contributing to supplies in the Midwest and in the East, where 27 billion cubic feet cubic feet of natural gas were added to storage, reducing that region's deficit to just 13.2% below normal... on the other hand, only 2 billion cubic feet cubic feet of gas were added to storage in the South Central region, where supplies of gas remain 22.3% below their five-year average, and only 2 billion cubic feet cubic feet of gas were added to storage in the Pacific region, where supplies are 25.4% below normal for this time of year...so while imports from Canada may backstop natural gas shortages in the Midwest and East this winter, they are unlikely to be of much help to natural gas supplies in the southern parts of the country, should those regions experience a colder than normal winter..
The Latest US Oil Data from the EIA
this week's US oil data from the US Energy Information Administration, covering the week ending August 24th, indicated that despite a significant pullback in our oil refining, a large increase in our oil exports while our oil imports remained depressed meant that we still had to withdraw oil from our commercial crude supplies to meet the needs of our refineries for the sixteenth time in the past thirty-one weeks... our imports of crude oil fell by an average of 33,000 barrels per day to an average of 7,485,000 barrels per day, after falling by an average of 1,496,000 barrels per day the prior week, while our exports of crude oil rose by an average of 624,000 barrels per day to an average of 1,779,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 5,706,000 barrels of per day during the week ending August 24th, 657,000 fewer barrels per day than the net of our imports minus exports during the prior week...over the same period, field production of crude oil from US wells was reportedly unchanged at a record 11,000,000 barrels per day, which means that our daily supply of oil from the net of our trade in oil and from wells totaled an average of 16,706,000 barrels per day during the reporting week...
meanwhile, US oil refineries were using 17,566,000 barrels of crude per day during the week ending August 24th, 324,000 barrels per day less than the amount of oil they used during the prior week, while over the same period 367,000 barrels of oil per day were reportedly being pulled out of the oil that's in storage in the US....hence, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 493,000 fewer barrels per day than what refineries reported they used during the week....to account for that disparity between the supply of oil and the disposition of it, the EIA needed to insert a (+493,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as "unaccounted for crude oil"...since that "unaccounted for crude" figure was at -305,000 barrels per day during the prior week, we know that the week over week changes for one or more of this week's EIA oil metrics must be in error by a statistically significant amount...(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports fell to an average of 7,987,000 barrels per day, now 1.9% less than the 8,146,000 barrel per day average that we were importing over the same four-week period last year....the 367,000 barrel per day decrease in our total crude inventories was all withdrawn from our commercially available stocks of crude oil, as the amount of oil in our Strategic Petroleum Reserve remained unchanged, even as a sale of 11 million barrels from those reserves had been announced during that week....this week's crude oil production was reported as being unchanged at 11,000,000 barrels per day despite a rounded 100,000 barrels per day decrease to 10,500,000 barrels per day in the output from wells in the lower 48 states, because oil output from Alaska rose by 33,000 barrels per day, which was enough to keep the national total, which is now being rounded to the nearest 100,000 barrels per day, unchanged at 11,000,000 barrels per day....US crude oil production for the week ending August 25th 2017 was reportedly at 9,530,000 barrels per day, so this week's rounded oil production figure was roughly 15.4% above that of a year ago, and 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
meanwhile, US oil refineries were operating at 96.3% of their capacity in using 17,566,000 barrels of crude per day during the week ending August 24th, down from 98.1% the prior week but still higher than normal, even at this time of year....however, the 17,566,000 barrels per day of oil that were refined this week dropped below last year's total for this time of year, thus ending a 12 week streak of refining at seasonal record levels....this week's refinery throughput was 0.9% lower than what had been a record 17,725,000 barrels of crude per day that were processed during the week ending August 25th 2017, when US refineries were operating at 96.6% of capacity....
even with the reduction in the amount of oil being refined this week, gasoline output from our refineries was nonetheless higher, increasing by 86,000 barrels per day to 10,237,000 barrels per day during the week ending August 24th, after our refineries' gasoline output had decreased by 83,000 barrels per day during the week ending August 17th...even with this week's increase, however, our gasoline production during the week was still 3.4% lower than what had been a record 10,602,000 barrels of gasoline that were produced daily during the same week of last year...meanwhile, our refineries' production of distillate fuels (diesel fuel and heat oil) fell by 247,000 barrels per day to what was still a high for the date of 5,179,000 barrels per day, after they had risen by 89,000 barrels per day over the prior week...hence, this week's distillates production was still 2.5% higher than the 5,055,000 barrels of distillates per day that were being produced during the week ending August 25th, 2017...
with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week fell by 1,554,000 barrels to 232,774,000 barrels by August 24th, the 16th decrease in 27 weeks, but just the 17th decrease in 42 weeks, as gasoline inventories, as usual, were being built up over the winter months....our supplies of gasoline also fell this week because the amount of gasoline supplied to US markets rose by 446,000 barrels per day to a record 9,899,000 barrels per day, after rising by 59,000 barrels per day the prior week, while our imports of gasoline rose by 51,000 barrels per day to 868,000 barrels per day, and while our exports of gasoline fell by 59,000 barrels per day to 585,000 barrels per day...but even after this week's decrease, our gasoline inventories were still 1.2% higher than last August 25th's level of 229,937,000 barrels, and roughly 9.4% above the 10 year average of our gasoline supplies for this time of the year...with 'gasoline product supplied', often seen as a measure of gasoline consumption, at a record high this week, we'll take a look at a graph of that metric and explain what it means...
the above graph came from a the set of oil graphs on this report that John Kemp of Reuters emailed out two weeks ago (available as a pdf here), on which i've penciled in an extension to bring it up to date, as John had not produced graphs on this metric this week or last...the graph shows gasoline supplied to US markets in thousands of barrels per day by "day of the year" for the past ten years, with the past ten year range of our domestic gasoline demand for any given date shown in the light blue shaded area, and the median of domestic gasoline supplied, or the middle of the 10 year daily range, traced by the blue dashes over each day of the year....the graph also shows the number of barrels of gasoline supplied for each week in 2017 traced weekly by a yellow line, and the year to date number of barrels of gasoline supplied for prior 2018 weeks represented by the red graph...as you can see by following the red and yellow graphs, the weekly change in "gasoline product supplied" is quite volatile, often hitting multi-week lows one week, and multi-week highs the next, or vice versa...that's because this metric does not directly track our demand for gasoline at the retail level, but rather the amount of gasoline supplied by refineries to large bulk terminals and distributors...thus, in anticipating an increase in demand over the Labor Day holiday weekend, these gasoline distributors increased their inventories at a record pace in the week ending August 24th, resulting in the new record for this metric...we thus expect that as those distributor's inventories are drawn down over the holiday weekend, "gasoline product supplied" will return to its baseline, much as occurred during the week after Memorial Day, when we saw the largest one week increase in oil & oil products inventories in 10 years as the product supplied metrics reversed...
meanwhile, with the decrease in our distillates production, our supplies of distillate fuels were likewise lower, decreasing by 837,000 barrels to 130,001,000 barrels during the week ending August 24th, the 4th decrease in 14 weeks...our distillates supplies also decreased because the amount of distillates supplied to US markets, a proxy for our domestic demand, rose by 372,000 barrels per day to 4,437,000 barrels per day, after increasing by 106,000 barrels per day the prior week, while our exports of distillates fell by 106,000 barrels per day to 1,136,000 barrels per day, and our imports of distillates rose by 129,000 barrels per day to 274,000 barrels per day....with our distillate supplies still recovering from the 14 year seasonal low that they hit 5 weeks ago, this week's inventory decrease means our distillates supplies are now 12.8% below the 149,163,000 barrels that we had stored on August 25th, 2017, and also roughly 12.8% lower than the 10 year average of distillates stocks for this time of the year...
finally, with this week's big increase in our oil exports, our commercial supplies of crude oil decreased for the 18th time in 2018 and for the 30th time over the past year, falling by 2,566,000 barrels during the week, from 408,358,000 barrels on August 17th to 405,792,000 barrels on August 24th....with that decrease, our crude oil inventories have now dipped a bit below the five year average of crude oil supplies for this time of year, even as they are still roughly 20.1% above the 10 year average of crude oil stocks for the 4th week of August, because it wasn't until the oil glut of the past 3 years that our inventories first rose above 400 million barrels...but since our crude oil inventories have now been falling through most of the past year and a half, our oil supplies as of August 24th were 11.3% below the 457,773,000 barrels of oil we had stored on August 25th of 2017, 18.1% below the 495,238,000 barrels of oil that we had in storage on August 26th of 2016, and 4.2% below the 423,657,000 barrels of oil we had in storage on August 28th of 2015...
This Week's Rig Count
US drilling activity increased for the sixteenth time in twenty-three weeks during the week ending August 31st, although the steady increases in drilling for oil we saw with higher oil prices during the first half of this year have stalled, with oil futures' prices remaining in deep backwardation.... Baker Hughes reported that the total count of rotary rigs running in the US rose by 4 rigs to 1048 rigs over the week ending on Friday, which was 105 more rigs than the 943 rigs that were in use as of the September 1st report of 2017, but was still down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began their attempt to flood the global oil market...
the count of rigs drilling for oil was up by two rigs to 862 rigs this week, which was also 103 more oil rigs than were running a year ago, while it was still well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the number of drilling rigs targeting natural gas formations also rose by 2 rigs to 184 rigs this week, which was just 1 more than the 183 natural gas rigs that were drilling a year ago, and way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008...meanwhile, two rigs drilling exploratory wells considered to be "miscellaneous" continued to operate this week, up from just one such "miscellaneous" rig a year ago...
one of the rigs that was added this week began drilling through an inland body of water in southern Louisiana, where there are now two such rigs operating, down from the 4 rigs that were drilling through inland waters there a year ago...the week's Gulf of Mexico rig count was unchanged at 16 rigs, the same number as were drilling in the Gulf a year ago...however, two rigs continued drilling offshore from Alaska this week, so the total national offshore count is at 18 rigs, which is thus up from last year's total of 16 offshore rigs, as a year ago there was no offshore drilling other than in the Gulf..
the count of active horizontal drilling rigs was down by 2 rigs to 917 horizontal rigs this week, which was still 123 more horizontal rigs than the 794 horizontal rigs that were in use in the US on September 1st of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the vertical rig count increased by 3 rigs to 66 vertical rigs this week, which was still down from the 68 vertical rigs that were in use during the same week of last year...at the same time, the directional rig count also increased by 3 rigs to 65 directional rigs this week, which was also still down from the 81 directional rigs that were operating on September 1st of 2017...
the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of August 31st, the second column shows the change in the number of working rigs between last week's count (August 24th) and this week's (August 31st) count, the third column shows last week's August 24th active rig count, the 4th column shows the change between the number of rigs running on Friday and those on the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was on Friday the 1st of September, 2017...
there is not much to note on this week's tables, and we can also quickly see that neither the state table nor the basin table reflect the national rig count changes which we have just reviewed...the state count is short because it does't include Mississippi, which saw their rig count rise from 3 rigs last week to 6 rigs this week, which was up from 4 rigs a year ago, and the most rigs that were drilling in Mississippi since January of 2016...meanwhile, the total count on the basin table above reflects a net increase of one horizontal rig, while we know from the summary that horizontal rigs were down by two, which means there was a net decrease of 3 horizontal rigs in other basins not tracked separately by Baker Hughes...with Oklahoma and New Mexico the only states showing rig count decreases, we might speculate that it's possible horizontal rigs could have been shut down in New Mexico's San Juan Basin or in the Oklahoma Anandarko basin outside of the Woodford basins tracked above...but without digging through the individual well logs in the Baker Hughes pivot table we can't know for sure; ie, it's also possible that a horizontal rig could have been shut down in almost any other basin, such as the Powder River basin of Wyoming, while a vertical or directional was started in the state at the same time, to net at a zero...meanwhile, the rig added in Pennsylvania's Marcellus is the only natural gas rig addition indicated above; the other natural gas rig was also in a basin not tracked separately by Baker Hughes...
++++++++++++++++++++++++++++++++++++++++
Oil, Natural Gas Production Increases in Utica Shale - – Two horizontal wells in Columbiana County yielded significant production during the second quarter of 2018, as oil and gas exploration in this part of the Utica shale continues to ramp up. According to production data on the quarter ended June 30 provided by the Ohio Department of Natural Resources, two wells operated by Chesapeake Exploration LLC at its Paige well pad in Franklin Township yielded more than 800 million cubic feet of natural gas apiece. Chesapeake’s Paige 3H well produced 844.052 million cubic feet of gas over 88 days, while the Paige 1H yielded 836.414 million cubic feet over 87 days – the best production numbers from single Utica wells in Columbiana County yet. Chesapeake reported 52 producing wells in the county that yielded a combined 5.771 billion cubic feet of gas during the period. Hilcorp Energy Co. also reported strong results from its Columbiana County wells in Fairfield and Elk Run townships.The Elkrun-Scheel 11H well yielded 537.077 million cubic feet over 91 days, while the 13H well produced 562.306 million cubic feet over the same period.In Fairfield Township, Hilcorp’s Fairfield-Unkefer 14H well produced 347.981 million cubic feet with just 31 days of recorded production during the quarter, according to ODNR. Hilcorp reported eight Columbiana County wells in production during the quarter that yielded a total of 2.573 billion cubic feet of gas.Another operator, Atlas Noble LLC, reported its seven wells in the county produced 647.810 million cubic feet of gas. Together, the 67 wells reporting production in Columbiana County delivered 8.992 billion cubic feet of natural gas during the quarter, while oil production was negligible. Natural gas production in Mahoning and Trumbull counties proved below average, as wells there did not produce significant quantities of oil or gas. Hilcorp’s seven wells in Poland Township together elicited 350.1 million cubic feet of gas, Northwood Energy’s three wells in North Jackson and Ellsworth townships produced 58.9 million cubic feet, while Pin Oak Energy’s two wells in North Jackson yielded 28.2 million cubic feet during the quarter, according to ODNR. In Trumbull County, Pin Oak reported five operating wells that together produced 99.4 million cubic feet of gas, while Enervest Operating LLC reported a single well in operation that produced 10.4 million cubic feet of gas. Overall production of natural gas and oil in Ohio’s Utica shale skyrocketed by 42.25% versus the same period in 2017, ODNR reported. Wells across the Utica yielded a total of 554.306 billion cubic feet of natural gas during the second quarter of 2018 compared to 389.662 billion cubic feet of gas produced during the second quarter of 2017, the agency said. Utica wells across Ohio pumped out 4.488 million barrels in the second quarter – nearly an 11% increase from the year prior. During the second quarter of 2017, Utica wells produced 4.044 million barrels of oil.ODNR said 2,002 horizontal wells in the Utica reported production during the period, the bulk of which occurred in the southern sector of the Utica, mostly encompassing hot spots in Belmont, Noble and Guernsey counties.
Ohio's natural gas production up 42% — Ohio’s horizontal shale well oil and gas production continues to climb, as the Ohio Department of Natural Resources reports in its release of the second quarter production figures.Natural gas production from the second quarter of 2018 showed a 42.25 percent increase over the second quarter of 2017, while oil production increased 10.98 percent for the same period.Ohio’s horizontal shale wells produced 4,488,104 barrels of oil and 554,306,916 Mcf (545 billion cubic feet) of natural gas in the second quarter, according to figures released Aug. 28 by the ODNR.Five years ago, in 2013, those second quarter figures were 574,440 barrels and 15,065,106 MCF. Experts say production has increased in part because of new drilling and completion techniques, including longer well laterals, which can now stretch more than 19,000 feet.Nationally, natural gas production from the Marcellus and Utica shale plays in the Appalachian basin accounted for about 29 percent of U.S. total production in July 2018.The ODNR quarterly report lists 2,035 horizontal shale wells, 2,002 of which reported oil and natural gas production during the quarter.The top two gas-producing wells come from the 1H and 3H legs of the Borovich well in Belmont County’s Richland Township. The top-producing well yielded 3,168,398 MCF, up from the first quarter’s production of 2,705,060, which also led the state. A second Borovich leg produced 2,974,278 MCF. (Scroll down to see lists of top 10 wells.)Guernsey County’s Millwood Township is home to the top six oil-producing wells, and three of the quarter’s top producers came from the Yanosik wells. The Yanosik A 2H leg produced 100,723 barrels, compared to 168,493 barrels produced in the first quarter’s top well. Of the wells reporting oil and natural gas results:
- The average amount of oil produced was 2,242 barrels.
- The average amount of natural gas produced was 276,877 Mcf.
- The average number of second quarter days in production was 85.
Ohio reports 42.3% increase in Utica natural gas production - Production of natural gas in Ohio’s Utica Shale grew by 42.3% in the second quarter of 2018, according to the Ohio Department of Natural Resources.Production was a record high 554.31 billion cubic feet of natural gas, the state agency said Tuesday in releasing the latest data.That is a big jump from the 389.66 Bcf projected in 2017, it said. Oil prices fell Tuesday as some investors took profits on recent strong gains, but losses were limited the day after a U.S.-Mexico trade agreement eased worries about tensions between the two countries.It was also up from the 531.3 billion cubic feet produced in Q1 2018.The top-producing well for natural gas was an Ascent Resources well in Belmont County’s Richland Township, with nearly 3.2 billion cubic feet of natural gas in the quarter.Ascent also has the No. 2 well in Belmont County and the third and fourth biggest gas wells in Jefferson County.Chesapeake Energy had the fifth biggest gas well in Harrison County.No. 6 and 7 were Ascent wells in Belmont and Jefferson counties, respectively.The eighth best gas well was an Eclipse well in Monroe County and No. 9 and 10 were Ascent Resources’ wells in Jefferson County.Oil production in the Utica Shale also increased, ODNR said.It was up 10.98% in 2Q 2018. Production was 4,488,104 barrels of crude oil, up from 4,044,072 barrels in 2Q 2017. Production was 3,942,251 barrels in 1Q 2018. The top oil well in Ohio in 2Q was an Eclipse well in Guernsey County’s Millwood Township with 100,723 barrels of production.
Ohio Reports Sharp Uptick in Unconventional Oil Production -- Ohio’s unconventional oil production bounced back in the second quarter, reaching 4.5 million bbl, an 11% increase from the year-ago period, according to data released by the Ohio Department of Natural Resources (ODNR). Oil volumes were also up from 1Q2018, when they came in at 3.9 million bbl. Oil production has fluctuated over the last several quarters, reflecting a broad shift to dry gas production that occured about two years ago across much of the Appalachian Basin when oil prices were lower. But operators have returned to wetter areas in Ohio and elsewhere in the basin, stoked by higher oil prices.Unconventional natural gas production, meanwhile, continued to climb, setting a new record. ODNR said. Driven by the Utica Shale, gas production was 554.3 Bcf in the second quarter, up from 389.7 Bcf in the year-ago period and 531.3 Bcf in 1Q2018.ODNR’s quarterly report listed 2,035 horizontal shale wells, 2,002 of which reported oil and natural gas production. Ohio law does not require separate reporting of natural gas liquids or condensate. Those totals are included in natural gas volumes.The average amount of oil produced by each well during the second quarter was 2,242 bbl, while the average amount of natural gas produced was 276.9 MMcf. The average number of second quarter days in production was 85. To date, the state has issued 2,873 Utica Shale permits and 2,402 of those wells have been drilled. That’s compared to the 2,589 Utica permits and 2,104 that were drilled at about the same time last year. Fifty-two Marcellus Shale permits have also been issued to date, while 36 Marcellus wells have been drilled in the state.
Ohio Oil and Gas Industry Rebounds, Needs Workers - – The oil and gas industry across the state of Ohio is on the rebound and is searching for workers to staff positions representatives say will be in demand for the future.Pipeline construction workers, rig operators, welders and thousands of assorted jobs connected with oil and gas processing and end use are among the areas where industry specialists see the most opportunity for employment, industry specialists add.“We’re coming out of a downturn, which is really exciting and starting to see some reinvestment,” Mike Chadsey, director of public relations for the Ohio Oil and Gas Association, told about 25 guests during a question-and-answer session with representatives of organized labor, faith-based groups and educators.The event was held at the International Brotherhood of Teamsters Local 322 in Youngstown and organized by Strategic Resources Consulting.Critical job shortages at the moment are evident in transportation, Chadsey said, since the industry depends heavily on moving materials during the construction phase of well pads, for example. “Well pads require 500 to 600 trips, hauling in equipment, water, sand, then hauling it back out again,” he said.Chadsey told the group that should a prospective worker earn their commercial driver license, or CDL, then a job is waiting for them. “If you were to come up to one of our companies and say ‘I’m drug free and have a CDL,’ I could guarantee you would be walking out with a job,” he said.Other positions such as industrial engineers, petroleum engineers and diesel mechanics are also in high demand at the moment as energy programs accelerate their drilling programs, Chadsey said.However, it’s likely demand for workers will increase substantially should related developments such as Royal Dutch Shell’s $6 billion ethane cracker plant in Monaca, Pa., and new combined-cycle electrical plants that are fueled by natural gas take shape across the region. “Our feet are planted firmly back on the ground,” Chadsey said of the industry. “We’re going to see the opportunity for increased employment as cracker plants and power plants come online. That’s going to require more drillers to drill more holes to produce more gas, and more pipelines to deliver that gas to downstream opportunities.”
Fracking not the problem with water in Youngstown | vindy.com: For the umpteenth time, Youngstown residents will be asked to ban fracking, and for the umpteenth time – eighth – The Vindicator will oppose the foolhardy Home Rule Charter amendment. That said, we do have a suggestion for Ray and Susie Beiersdorfer and their anti-fracking cohorts: Turn your attention to the real issue that poses a threat to the city’s water. It’s called House Bill 602 and is sponsored by Republican Mike Duffey of Worthington, R-21st. To put it simply, Duffey is proposing a snatch-and-grab of this valuable commodity. If the bill becomes law, the cities of Youngstown and Niles, which paid for the construction of Meander Reservoir and the creation of the Mahoning Valley Sanitary District, would be placed in financial jeopardy. That’s because Duffey’s legislation would ban the surcharges cities like Youngstown and Niles levy on suburban water customers. The two communities, along with the village of McDonald, buy drinking water in bulk from the MVSD, which operates a water purification plant in Mineral Ridge. The cities then sell the water to their customers within their boundaries and in the suburbs. The surcharges paid by the suburbanites are designed to cover the additional costs of supplying water and maintaining the delivery network. The legislation proposed by Rep. Duffey would financially punish communities for charging suburbanites more for water. Although the bill would allow municipalities to recoup costs tied to the maintenance of their water systems, it doesn’t say what constitutes maintenance.
Five New Horizontal Wells Approved for Columbiana County – The Ohio Department of Natural Resources has approved five horizontal wells in Columbiana County, according to the latest data released from the agency.Houston-based Hilcorp Energy Co. secured three new permits during the week ended Aug. 25 to drill horizontal wells in Fairfield and Elk Run townships, according to ODNR. Two Fairfield wells are slated for the Tarka pad and the Elk Run well is planned for the Johnston pad, ODNR reported.Chesapeake Exploration LLC, whose parent Chesapeake Energy Corp. last month announced a deal to sell its Utica assets for $2 billion to Encino Acquisition Partners, received two permits to drill wells in Washington Township. Those wells are targeted for the Sevek pad.ODNR issued two additional permits to Chesapeake for wells in Jefferson County and a single permit to XTO Energy for a well in Belmont County.As of Aug. 25, ODNR had issued 2,873 permits in the Utica shale region of eastern Ohio. There are 2,402 wells drilled in the oil and gas play and 1,957 wells in production.The number of rigs operating in the Utica region of Ohio stood at 20 during the week, ODNR reported. There were no new permits issued in the upper Utica section of western Pennsylvania, which includes Lawrence and Mercer counties, according to the Pennsylvania Department of Environmental Protection.
Construction Continues on Shell’s Ethane Cracker Complex — Motorists who travel along Ohio Route 7 and W.Va. Route 2 may have noticed very large pieces of equipment traveling via barge on the Ohio River last week. The parts are being shipped to the construction site of the ethane cracker plant at Monaca, Pa. Pike Island Locks & Dam officials confirmed the shipments were headed to Monaca and moving through their locks on the river. One piece came through Wednesday afternoon, while another load arrived at the locks at about 11 p.m. Thursday.Thursday night’s pieces, which appeared to be two large, white tanks on top of a barge-like container, were being pushed north by a vessel owned by Louisiana-based McDonough Marine Service. The $6 billion Monaca plant is being built by Shell Chemical with construction expected to last for a few years before it is complete. The plant is expected to manufacture 50 different products, all of which are types of plastics for manufacturing. Planned construction of the Monaca plant was announced in 2016 with work getting underway about 18 months later.Meanwhile, residents of Belmont County and beyond are awaiting news on PTT Global Chemical’s final decision on whether to build a similar plant at Dilles Bottom south of Shadyside. Preparations have been underway for the possibility of a cracker in Belmont County, including the purchase of land in the area of Dilles Bottom. The first announcement about potential construction of the plant by Thailand-based PTT came about three years ago. In January, word was released that South Korea’s Daelim Industrial Co. was partnering with PTT on the project — a collaboration that was officially announced in March.
No Signs Of Slowing The Marcellus-Utica -- The beast in the East continues to grow. Despite takeaway capacity challenges in the Northeast, especially in Pennsylvania, where a lack of available pipeline is pushing up inventories and keeping natural gas prices low, production continues to escalate to record levels. In a recent report charting the growth of natural gas production in the Appalachia region, Deloitte noted that in 2007 Appalachia was the world’s 32nd largest natural gas producing region. By 2017 it was the third largest, trailing only all of the U.S. and Russia.“The speed and magnitude of Appalachia’s emergence onto the global natural gas scene is unprecedented and due mainly to the Marcellus and Utica shale plays,” Deloitte reported.According to the U.S. Energy Information Administration’s (EIA) Drilling Productivity Report, gas production in Appalachia has grown to 28.8 Bcf/d through August, significantly more than the next-closest basin, the Permian, which produced 10.8 Bcf/d that month. According to the Pennsylvania Department of Environmental Protection, first-quarter 2018 natural gas production in the state was 1.4 Tcf, an increase of 10% over the same period last year. Meanwhile, the Ohio Department of Natural Resources reported that the state produced 531 Bcf of natural gas in the first quarter of the year, an increase of 42.85% over the first of quarter 2017. The EIA attributes the remarkable production gain— the average production per rig in the Marcellus-Utica has increased by 13 Bcf/d since 2012—to efficiency improvements in horizontal drilling and hydraulic fracturing capabilities in the region, which include faster drilling, longer laterals, advancements in technology and better well targeting. The EIA reported in December that the average lateral length per well in West Virginia had increased from about 762 m (2,500 ft) in 2007 to more than 2,134 m (7,000 ft) in 2016. The leader in lateral length in the Marcellus-Utica—and everywhere else—is Eclipse Resources, which, according to the company, has through June drilled 15 super laterals averaging 5,600 m (18,375 ft) in length.
Rover seeks go-ahead from FERC to start remaining supply laterals — Energy Transfer Partners asked US regulators on Friday to approve startup of the final two laterals on its 3.25 Bcf/d Rover natural gas pipeline as it seeks to create additional capacity to meet downstream demand. The operator said in a filing with the Federal Energy Regulatory Commission that shippers have "urgently requested" that Rover place into service the CGT and Sherwood laterals, as well as associated compression and metering stations, to allow their stranded Appalachian Basin gas supplies to be delivered to Midwest markets. The filing seeks approval of commencement of service by September 15. The pipeline is designed to move gas from the Marcellus and Utica shale production areas across the US as well as to the Dawn Hub in Ontario. It is among a handful of infrastructure projects meant to boost takeaway capacity from the prolific producing region. "The project schedule for rehabilitation and restoration of the remaining ground movement areas outside of the construction right-of-way for the CGT lateral and the Sherwood lateral forecasts completion by December 18, 2018, and January 2, 2019, respectively," the operator said. The latest request followed FERC's August 23 approval of the start of service on Rover's Burgettstown and Majorsville supply laterals as well as associated compression and metering stations (CP15-93). That was expected to allow for 100% of long-haul contractual commitments to begin Saturday. The Sherwood lateral will tie into the Sherwood processing complex, although a significant production uplift is likely contingent upon the in-service of additional processing capacity at the facility. Sherwood processing plant owner MPLX's second quarter earnings call indicated the facility was running at a 92% utilization rate during the April-June period. MPLX said it was planning to bring two additional trains online by the end of 2018 with a combined 400 MMcf/d of processing capacity. Rover's CGT lateral connects to TransCanada's Columbia Gas Transmission system.
Court removes playgrounds from drilling consideration list - A Pennsylvania court last week largely backed a move by the state environmental agency to consider the potential impact of a shale gas well on public natural resources before drilling is allowed. But it removed the agency's attempt to add playgrounds and common areas at schools to the list of resources.That part of the measure was "vague," according to the court.It also removed language defining "critical" ecosystems because the agency's definition may have included species that do not justify "conservation measures."The state's revision of the drilling law requires companies to display potential impacts on public goods, while allowing state agencies to consider implications for resources. An industry trade group has sued to block the changes. The case is ongoing, with oral arguments set for this fall (Laura Legere, Pittsburgh Post-Gazette, Aug. 25).
Hydraulic Fracturing Should Be At Least 1/4 Mile From Residential Areas; Report - Current laws in Pennsylvania allow hydraulic fracturing operations to occur too close to homes and businesses, according to a new report that suggests individuals who reside or work in the area may be placed at risk for serious health side effects. In a study published in the medical journal PLOS One on August 16, researchers from the Southwest Pennsylvania Environmental Health Project determined that hydraulic fracturing gas extraction operations should be at least a quarter of a mile away from homes and businesses. They should likely be even further away from facilities with more vulnerable populations, such as schools, the report indicates. Problems from fracking have previously been linked to negative environmental effects to the surrounding communities, due the impact on drinking water, as well as increased dust and exhaust from drilling rigs, compressors and the transportation of the water, sand and chemicals. The process has also been linked to increased earthquake activity. The extent of the potential harm to humans living close to these fracking sites has yet to be determined.This latest report was created by a panel of 18 experts, including scientists, researchers, health experts and environmental advocates, who looked at the minimum setback requirements and compared them to what was known about the health risks of fracking. The panelists could not agree on how far minimum setback requirements should keep fracking operations from homes and businesses, with preferred distances ranging from 1/4 to two miles. However, the panel agreed that the current laws were not protective enough, given the health risks previous studies and research has linked to hydraulic fracturing. “The results suggest that if setbacks are used the distances should be greater than ¼ of a mile from human activity, and that additional setbacks should be used for settings where vulnerable groups are found, including schools, daycare centers, and hospitals,” the researchers concluded. “The lack of consensus on setback distances between 1/4 and 2 miles reflects the limited health and exposure studies and need to better define exposures and track health.”
Three (3) ‘Mama Bears’ Arrested Protesting the Mariner East 2 Pipeline - The Battle of Mariner East 2 continues to heat up. Three “Mama Bears” – local moms who fiercely oppose Sunoco’s pipeline plan – were arrested and led to off to jail in handcuffs early Saturday while protesting the massive Sunoco project near Glenwood Elementary School.More than two dozen fellow protesters supported the three Mama Bears – two of whom are senior citizens – who sat in the Sunoco right-of-way while holding a “bake sale” or “picnic” on a pleasant morning.The Mama Bears waited for about an hour, just 300 yards from the school, which is located in what pipeline foes often refer to as the “blast zone.” They were surrounded by dozens of stuffed teddy bears and even handed out homemade cookies.Police led Abbie Wysor and Barbara Montabana, both of Delaware County, and Ann Dixon, of Philadelphia, to jail after they were ordered by police to dismiss. The three women refused to leave. They were charged with a summary offense, defiant trespass, and released after less than two hours.The Mama Bear’s lawyer, Tanner Rouse, said the protesters have “tremendous gratitude” for law enforcement. “The state police treated them with great respect,” Rouse said. “These are people who respect the law but the law has left them exposed – with a great risk to the elementary school.”
Transco Seeks FERC OK to Start Up Atlantic Sunrise by Sept. 10 - Transcontinental Gas Pipe Line Co. LLC (Transco) has asked FERC for authorization to begin full service on its 1.7 million Dth/d Atlantic Sunrise expansion by Sept. 10, bringing the project a step closer to uncorking more Northeast production attempting to reach East Coast markets.In a Federal Energy Regulatory Commission filing Friday, Transco said the remaining portions of its 200-mile project are wrapping up construction and will be ready for service early next month, including the greenfield 30-inch diameter Central Penn Line North and 42-inch diameter Central Penn Line South segments; the Chapman and Unity Loops on Transco’s Leidy Line; and the greenfield Compressor Station 605 (30,000 hp) and Compressor Station 610 (40,000 hp).Transco is also already ready to place around 62,000 hp of additional compression online across three existing stations in Pennsylvania and Maryland, along with two new meter stations and various other facilities and modifications related to the project, the operator told FERC.Transco previously added interim service associated with the completion of brownfield portions of the project, including an incremental 400,000 Dth/d that came online last August, and another 150,000 Dth/d approved to enter service in May. Atlantic Sunrise would create an additional path for constrained gas in northeast Pennsylvania to reach markets in the Mid-Atlantic and Southeast via the Transco mainline that runs along the Atlantic seaboard. The project could provide a key capacity upgrade for Transco’s Zone 5 and Zone 6 market areas in time for the 2018/19 winter, helping to address the constraints that sent spot prices skyrocketing this past January.
Eclipse, Blue Mountain to Merge, Creating $1.4B Appalachia Focused Company Two E&P companies with heavy focus in the Utica and Marcellus have agreed to a merger.Independent exploration and production companies Eclipse Resource Corporation (based in Pennsylvania) and Blue Ridge Mountain Resources (based in Irving, Texas) have agreed to a merger with an enterprise value of $1.4 billion.The all-stock deal was announced August 27 and will result in Blue Ridge becoming a subsidiary of Eclipse. The deal’s equity value is $908 million.The merger positions the newly formed company to be a top-tier energy company with a strong focus on the Appalachian region. Currently, Eclipse focuses on the Utica and Marcellus shale plays in southeastern Ohio. And Blue Ridge has 34 currently producing operated wells within the Marcellus, according to the company’s website. The Utica has been identified as a significant growth area.The deal is expected to create one of the largest Utica-focused operators with 4Q 2018 estimated production of 500-560 MMcfe per day and 227,000 net undeveloped core acres providing more than 20 years of wet and dry gas inventory. Eclipse president and CEO Benjamin W. Hulburt described the merger as a “compelling opportunity” for both companies. Blue Ridge president and CEO John Reinhart will become president and CEO of the new company.“We believe the combined company will possess a substantial scale advantage and an excellent foundation for significant organic growth with attractive cash flows while maintaining the optionality for bolt-on value-accretive acquisitions within the basin,” Reinhart stated in a release. The deal is scheduled to close in the fourth quarter of 2018.
PennEnergy To Buy Bankrupt Rex Energy For $600.5 Million - After more than a decade operating as a public oil and gas producer, State College, Pa.-based Rex Energy Corp. has agreed to sell itself to fellow Appalachia shale player PennEnergy Resources LLC for $600.5 million. As part of the agreement, PennEnergy will acquire substantially all of Rex’s assets plus assume certain liabilities of the company which filed for bankruptcy earlier this year, according to filings with the U.S. Securities and Exchange Commission on Aug. 27. Rex is a pure-play Appalachian Basin-focused company targeting wet gas windows in the Pennsylvania Marcellus and Ohio Utica shales.
PA Supreme Court Victory for ME2 Pipeline re Two Zoning Cases -- Two different townships in the Philadelphia area, amped-up by and using money from Big Green groups like THE Delaware Riverkeeper (aka Maya van Rossum), tried to stop Sunoco Logistics Partners’ Mariner East 2 (ME2) pipeline project by claiming it violated local zoning ordinances. The construction of ME2 is governed by the PA state Public Utility Commission and the state Dept. of Environmental Protection. It is not a federal (i.e. FERC) project. Because it is a state-oversight project, the issue of primacy (whose rules and regulations govern) resides at the state level and not at the local level. Two local townships–one in Chester County the other in Delware County–argued in separate cases before PA Commonwealth Court that local zoning regulations for siting the pipeline should still apply. Commonwealth Court, in a pair of decisions earlier this year, ruled against that view (see PA Town Loses Appeal to Block ME2 Pipe with Local Zoning Ordinance and PA Appeals Court Rules ME2 Pipe NOT Under Local Zoning). Using Big Green money, both towns appealed their cases to the PA Supreme Court. On Tuesday, the Supremes declined to hear either case, meaning the Commonwealth Court ruling stands and this issue is now, finally, done. Antis’ attempts to stop the ME2 project by using local zoning ordinances is a closed door…The PA Supreme Court Tuesday declined to hear the appeal of two Commonwealth Court decisions finding local zoning ordinances do not apply to the Mariner East Pipelines in Chester and Delaware counties.The Court denied the appeal of Delaware RiverKeeper v. Sunoco Pipeline (No. 952 C.D. 2017) and denied the appeal of Meghan Flynn, et al v. Sunoco Pipeline (No. 942 C.D. 2017).
Eyes trained on natural gas project through Finger Lakes - — The $141 million Empire North project that would pump more natural gas from fracking operations in Pennsylvania through the Finger Lakes region has caught the attention of local environmentalists.High-volume hydraulic fracturing, also known as “fracking,” was banned in New York state in 2014 over health risks. The process involves injecting large amounts of water, sand and chemicals deep underground at high pressures to release oil and natural gas from rock formations.Despite the ban, fracked gas is what’s piped through the state and supplies New Yorkers. Concerns center on emissions, oversight and the impact on climate change.For some, it also presents an ethical issue.“Yes, we did ban fracking,” said Sue Dazie, a Victor resident involved with environmental causes in the region. “So, why should we allow (natural gas from fracking) through our state? We have already turned it down and now they want us to pay a price through our towns.”Drawing attention are plans to build a natural g as compressor station in Farmington that lies along the route the Empire North project takes through Ontario County. In the Finger Lakes region, Empire runs 249 miles of pipeline transporting natural gas to more than 1 million customers, according to project parent company National Fuel. Any natural gas in New York state is now due to the abundance and cost of natural gas from the Marcellus Shale and Utica Shale that is hydraulically fractured, said Karen Merkel, corporate communications for National Fuel. “All of our gas is coming from Northeast production,” Merkel said, citing states such as Pennsylvania, Ohio and West Virginia, where fracking takes place. “It is most economical, so 100 percent of what’s transported today across New York state is hydraulically fractured.”
Appalachia, Permian, Haynesville drive U.S. natural gas production growth - EIA - Gross production of natural gas in the United States has generally been increasing for more than a decade and in recent months has been more than 10% higher compared with the same months in 2017. This growth has been driven by production in the Appalachian Basin in the Northeast, the Permian Basin in western Texas and New Mexico, and the Haynesville Shale in Texas and Louisiana. These three regions collectively accounted for less than 15% of total U.S. natural gas production as recently as in 2007, but now they account for nearly 50% of total production. Production in these regions has increased in part because of new drilling and completion techniques, including longer well laterals that have increased well productivity. By contrast, the Gulf of Mexico's share of total production, which was 12% in 2007, has fallen to just 3% in recent months, and the share of production in the rest of the United States has declined from 60% to 28%. Growth in natural gas production in the Northeast has come mainly from the Marcellus and Utica shale plays in the Appalachian basin, which collectively accounted for about 29% of total production in July 2018. Recent infrastructure buildout in the region has allowed natural gas to move out of the region and has reduced the prevailing discount to the national benchmark price at Henry Hub and to regional prices. Natural gas production in the Permian Basin has also grown in recent years, largely in the form of associated gas accompanying the region’s rising crude oil production. Similar to the Appalachian Basin, natural gas in the Permian trades at lower prices relative to Henry Hub because of regional infrastructure constraints. A number of new natural gas pipelines are planned or under construction that will help move natural gas out of the region, and several of them will expand liquefied natural gas export capability. EIA projects that July 2018 production in the Permian Basin will account for about 11% of total U.S. gross production. Production in the Haynesville region has also increased. After decreasing from its peak in 2012, increasing production in the Haynesville region since 2017 has been driven by improving initial production rates and increasing rig counts. Higher rig counts are likely a result of recovering crude oil prices, which have been generally increasing since early 2016. Together, the Haynesville and the Permian regions accounted for nearly 20% of total U.S. natural gas production in 2017.
Three regions account for half of US natural gas production - Three regions are driving the growth of U.S. natural gas production as the Gulf of Mexico claims a smaller share of the total.The U.S. Energy Department reported that the Appalachian Basin in the Northeast, the Permian Basin in West Texas and the Haynesville Shale straddling Texas and Louisiana have grown to account for almost 50 percent of domestic production, up from 15 percent in 2007. The Gulf of Mexico, meanwhile, accounts for 3 percent of U.S. natural gas production, down from 12 percent in 2007. Producers have shown greater interest in offshore projects in recent months but new wells remain pricier to drill than those onshore. U.S. natural gas production has surged during the last decade alongside crude oil production, which topped 11 million barrels a day last month for the first time. Tapping gas-rich shale rock with hydraulic fracturing, or fracking, has unleashed a cheap and steady supply of natural gas that has fed a petrochemical boom along the Gulf Coast and boosted domestic exports to Mexico and overseas.U.S. natural gas production in the last several months has approached 100 billion cubic feet a day, roughly 10 percent higher than the same period last year. The Appalachian Basin, which includes the Utica and Marcellus shale basins in Pennsylvania and Ohio, accounted for 29 percent of total production last month. The Permian, meanwhile, accounted for an estimated 11 percent.
Shale boom zaps volatility in US natural gas market - When US natural gas futures passed a milestone this month, they did so quietly: volatility fell to the lowest levels since the market’s debut nearly 30 years ago. The event seemed improbable. Volatility usually fades when commodity stocks are ample. Yet US gas stocks are 19.5 per cent below average. When the winter starts they are set to be at their lowest in more than a decade. This situation is the latest example of how the world’s largest gas market has been transformed by shale drilling. While demand for gas is galloping, it has been met by waves of supply that show no sign of abating. Conditions that put traders on edge a decade ago get shrugs. Like much of the northern hemisphere, the US this year is experiencing extremely hot weather. Cooling degree days — a measure of air-conditioning demand — are expected to top 1,000 by the end of the season, ranking the summer of 2018 among the top five for heat, according to Commodity Weather Group. That has required more generation from electric power plants that increasingly run on gas. Natural gas “power burn” surged to a record 37.7bn cubic feet per day during July, according to S&P Global Platts. Exports have also fed demand. The US is now a net exporter of gas to the tune of 2bn cu ft/d, the Energy Information Administration estimates. The volumes flow through new pipelines to Mexico and liquefied natural gas export terminals recently opened on the coasts of Louisiana and Maryland. The strong summer use of gas follows a winter when heating demand left gas stocks depleted. While producers will bank additional supplies over the summer and autumn, EIA forecasts that stocks at the end of the “injection season” in October will amount to just 3.3tn cu ft — the lowest for that month since 2005. “It does create some concern that under the right conditions we could see some fireworks for prices,” said Rich Redash, head of North American gas and power research at S&P Global. For now, though, gas prices have been a damp squib. Nymex September gas futures on Monday settled at $2.930 per million British thermal units, inside its range of $2.50-$3.50 over the past year.
Natural gas production up 10 percent in 2018 - Natural gas production in the United States is up 10 percent so far in 2018 compared to the previous year, according to the U.S. Energy Information Administration (EIA). The growth has been primarily driven by higher production in the Appalachian Basin in the Northeast, the Permian Basin in western Texas and New Mexico, and the Haynesville Shale in Texas and Louisiana. In 2007, these three regions accounted for less than 15 percent of total U.S. natural gas production, but now they account for nearly 50 percent of total production. New drilling and completion techniques, including longer well laterals, have increased well productivity in these regions. In stark contrast, the Gulf of Mexico’s share of natural gas production was 12 percent in 2007, but now it is down to just 3 percent. Additionally, the share of production in the rest of the United States has declined from 60 percent in 20017 to 28 percent today. The Marcellus and Utica shale areas in the Appalachian basin accounted for about 29 percent of total production in July 2018. In the Permian Basin, several new natural gas pipelines are planned or under construction that will help move more natural gas out of the region. EIA projects that production in the Permian Basin will account for about 11 percent of total U.S. gross production in July 2018. Increasing production in the Haynesville region has been fueled by improving initial production rates and increasing rig counts. Combined, the Haynesville and the Permian regions accounted for nearly 20 percent of total U.S. natural gas production in 2017.
Natural Gas Pipelines 'Weak Link' in U.S. Energy Infrastructure, Says IECA -- The North American Electric Reliability Corp. (NERC) has set mandatory standards that are enforced to secure the reliability of the nation's electric grid, but security requirements under the Transportation Security Administration (TSA) are voluntary, not mandatory, making natural gas pipelines "the weak link in U.S. national energy infrastructure," according to the Industrial Energy Consumers of America (IECA). In letters sent Wednesday to the chairmen of both the Senate Committee on Energy and Natural Resources and the House Committee on Energy and Commerce, IECA called for oversight hearings and "appropriate action to ensure that Congress has done all that is reasonable and cost-effective to ensure the security of natural gas pipelines." IECA said it supports an enforceable nationwide pipeline security standard with accountability resting "on the pipeline companies.” However, it does not support creating an organization like the North American Electric Reliability Corp. (NERC) only for natural gas pipelines. “One could make the argument that NERC's responsibilities could be changed to include natural gas pipelines, given their in-house knowledge and the importance of the gas/electricity interface issues." In June, FERC Commissioners Neil Chatterjee and Richard Glick said regulation of natural gas pipeline security should be shifted from TSA to the Department of Energy (DOE). Electricity grid operators are required to comply with Federal Energy Regulatory Commission security standards, but there are no comparable standards for the nation's network of natural gas pipelines, they said. DOE established a cybersecurity office in February.
Natural Gas Inventories “Dangerously Low" - Futures markets are suggesting the currently benign level of natural gas price volatility may not remain through the winter months. According to the Financial Times, market volatility this year has been the lowest on record despite inventory levels falling 19.5 percent below average and by the time winter starts are set to be at their lowest in more than a decade. The Financial Times puts this down to investors being lulled into complacency by a seemingly unstoppable wave of new supply from the shale market rising inexorably to meet rising demand. The government last week forecast 81.1 billion cubic feet per day in dry gas production for 2018 — a record high — and up by 7.5 billion cu ft/d from 2017, the Financial Times reports. But is the market safe to assume shale gas will supply regardless of demand? Natural gas producers are systematically hedging their sales throughout next year, often a sign they plan to continue an aggressive policy of drilling and expansion. That activity has contributed to a dipping of forward prices, as there are more sellers in the futures market than buyers. But inventory levels are low — some would suggest dangerously low — after a high summer demand due to hot weather increasing demand for air conditioning. Natural gas “power burn” surged to a record 37.7 billion cubic feet per day during July, the Financial Times reports. Such strong demand comes after a cold winter depleting stocks to unusually low levels. Inventory levels were low at the end of the summer and have not managed to be replaced during the normally slacker summer months. High demand is not helped by exports of natural gas and distillates running at record levels, aided by strong international demand and low U.S. domestic prices relative to global markets. Forward market spreads suggest there is already competition between companies buying gas for anticipated stronger winter-month demand are meeting power companies also trying to hedge their requirements.Volatility is traditionally lower in the slacker summer months and rises as demand ramps up in the winter. If inventory levels are high, investors are less prone to panic, rightly seeing ample supply. But when inventory levels are low, volatility is placing complete faith in the shale producers to meet rising demand — a faith that may yet prove misplaced.
EIA Shocks With 70 Bcf Injection; Natural Gas Futures Too Stunned to React - The Energy Information Administration (EIA) reported a 70 Bcf injection into storage inventories for the week ending Aug. 24, well above market consensus of a mid-60 Bcf build.The Nymex October gas futures contract, which took over the prompt-month position on Thursday, had a fairly muted reaction to the surprisingly bearish injection, slipping only nine-tenths of a cent to $2.854 just after the EIA print hit the screen. By 11 a.m. ET, the prompt month had moved back up to $2.863, flat with Wednesday’s settle. The rest of the futures curve through the March 2019 contract had a similar response to the inventory report.The net of the last two weeks yields a better reading of balance, according to Bespoke Weather Services, which had projected a 66 Bcf build. Given the miss, however, this indicates “weekly noise” in EIA data may be playing a role in these misses.“This print confirms much of the demand-side loosening we observed last week that appears to have carried into this week, and also reflects the recent surge in production,” Bespoke chief meteorologist Jacob Meisel said.The 70 Bcf build was significantly larger than both last year’s 32 Bcf build for the week, and the five-year average injection of 59 Bcf. Traders scoured the EIA data to find the missing link that caused the discrepancy between the estimated storage injection and the actual print. The Midwest region appeared to be culprit as mild temperatures and low humidity led to a 6 Bcf increase in injections week/week. Broken down by region, the EIA reported a build of 35 Bcf in the Midwest, 27 Bcf in the East, 4 Bcf in the Mountain, and 2 Bcf each in the Pacific and South Central regions. Inventories as of Aug. 24 stood at 2,505 Bcf, 646 Bcf below last year and 588 Bcf below the five-year average. Looking ahead to next week’s EIA report (for the week ending Friday), Meisel said that power burns tightened slightly, but Canadian imports returned as well, indicating another loose print is likely.
Another Appalachian NGL Storage Project Selects EPC Contractor -- Appalachia Development Group LLC (ADG), which was formed last year to build underground natural gas liquids (NGL) storage facilities in West Virginia, has selected California-based Parsons Corp. to oversee engineering, procurement and construction (EPC). ADG said Parsons would focus on the $3.4 billion NGL hubs’ front-end engineering and design, including project management and execution planning.“Identifying and selecting an EPC partner is a significant milestone in our progress to develop the hub,” ADG CEO Steven Hedrick said. Hedrick told NGI earlier this year that the company wants to build a series of underground NGL storage facilities and related pipeline infrastructure in West Virginia’s Ohio and Kanawha river valleys. He said at the time the hub could eventually be expanded in Kentucky, Ohio and Pennsylvania to serve production from the Marcellus, Utica and Rogersville shales, but he stopped short of offering further details about specific sites as detailed engineering needed to be completed.The project cleared a hurdle in January, when the U.S. Department of Energy (DOE) invited ADG to submit a Part II application for a $1.9 billion loan guarantee that, if approved, would help support the project. The loan guarantee would hedge a lender's risk by ensuring that the federal government pays back the money if ADG or another company defaults. ADG said in making the EPC announcement that work is ongoing to secure another $1.4 billion equity investment. The company added that it is working closely with the DOE on Part II of the loan guarantee application process.
FERC Approves 49% Increase in Mountaineer XPress Pipeline Rates - With the cost of construction skyrocketing, FERC has approved a request from Columbia Gas Transmission (CGT) to increase the initial monthly incremental recourse reservation rate on the Mountaineer XPress Project by 49% from the $9.827/Dth originally authorized.The $14.663/Dth approved by the Federal Energy Regulatory Commission is meant to cover increased costs for the pipeline, which would increase natural gas pipeline capacity out of the Appalachian Basin by expanding the TransCanada Corp. affiliate's system in West Virginia [CP16-357].Estimated cost of construction has increased from $2.06 billion to $3.03 billion since the filing of the original application in April 2016, CGT said in its FERC filing."Columbia states the primary reason for the increase in costs is related to contractor labor costs, inspection costs, and outside services costs that substantially exceeded the contingency established for such charges," FERC said. "According to Columbia, the recent surge of pipeline construction activity in the Marcellus and Utica Shale regions caused costs associated with land acquisition and contractor services for the Mountaineer XPress Project to increase.“Columbia also reports that unexpected permitting delays further increased the cost of constructing the project in accordance with shippers' requested in-service dates."
MVP Gets Another Win as Fourth Circuit Lifts Stay of Water Permit; Obstacles Still Ahead - The U.S. Court of Appeals for the Fourth Circuit on Wednesday lifted a stay of Mountain Valley Pipeline LLC’s (MVP) water crossing permit in West Virginia, providing further good news for sponsors recently beset by unfavorable decisions handed down by the court.The Fourth Circuit granted a motion filed by the U.S. Army Corps of Engineers to lift a stay of the Nationwide Permit 12 (NWP 12) it issued. The Army Corps issues the NWP 12, which allows contractors to trench through streams and rivers, under Section 404 of the Clean Water Act.In June, the Fourth Circuit granted a motion to stay MVP’s NWP 12 pending a ruling on a legal challenge brought by the Sierra Club and other groups. The environmental groups had challenged the validity of MVP’s NWP 12, arguing that the project could not meet a special condition in West Virginia requiring all stream crossings be constructed within 72 hours.After voluntarily suspending and then reinstating the NWP 12 with modifications relating to four river crossings, the Army Corps told the Fourth Circuit in a July 11 motion that it had addressed the permit’s deficiencies and asked for the stay to be lifted.“Upon consideration of submissions relative to the government’s motion to lift the stay, the court grants the motion,” the Fourth Circuit ruled Wednesday.The order comes as FERC has effectively lifted a sweeping stop work order imposed on the 303-mile, 2 Bcf/d project that attempted to address the Fourth Circuit’s decision to vacate separate federal approvals from the U.S. Forest Service and Bureau of Land Management (BLM) covering a proposed crossing of the Jefferson National Forest along the Virginia/West Virginia border. With the orders issued by the Federal Energy Regulatory Commission and the circuit court, “MVP is now able to return approximately 1,000 workers who have been suspended from their duties on the project,” the operator said Thursday. “As we continue with safe and responsible construction activities along the vast majority of the route, we will coordinate with the agencies to address the court's concerns with the federal land permits. We appreciate the collaborative and concerted efforts by all state and federal agencies and look forward to the in-service of this important infrastructure project.”
US FERC allows Mountain Valley Pipeline to resume construction on most of gas pipeline's route — The US Federal Energy Regulatory Commission on Wednesday lifted a stop-work order affecting most of the route of the 2 Bcf/day Mountain Valley Pipeline. The commission in early August placed much of the work on the 300-mile project on hold, following an appeals court ruling that vacated federal permissions to cross national forest land. The project would move West Virginia production to downstream markets in Transcontinental Gas Pipe Line's Zone 5 near the Virginia-North Carolina border. In a letter order Wednesday, FERC said a new determination by the US Bureau of Land Management ended questions about whether a route change would be needed to allow an alternative crossing of the federal land. BLM found that greater use of existing rights-of-way across federal lands would be impractical. The FERC letter order kept on hold work in two areas where permits are still needed: a crossing of the Weston and Gauley Bridge Turnpike on lands owned by the US Army Corps of Engineers in Braxton County, West Virginia, and a 25-mile stretch including two watersheds and containing the Jefferson National Forest crossing, in Monroe County, West Virginia, and Giles County, Virginia. EQT, a lead sponsor of the project, said in a statement it was pleased by the determination and "will soon be able to bring back a significant amount of workers who were temporarily suspended from their duties on the project."
Atlantic Coast Water Crossing Permit Holds Up as Court Denies Enviro Challenge - A federal appeals court has shut down an effort by environmental groups to stall Atlantic Coast Pipeline LLC’s (ACP) construction plans over a condition in its West Virginia water crossing permit, a tactic that had more success against the Mountain Valley Pipeline (MVP).The U.S. Court of Appeals for the Fourth Circuit, which has handed down its fair share of unfavorable rulings to ACP and MVP in recent months, last Thursday denied without prejudice a motion filed by the Sierra Club and other groups to stay ACP’s Nationwide Permit (NWP) 12. The NWP 12 covers waterbody crossings and is issued by the U.S. Army Corps of Engineers under Section 404 of the U.S. Clean Water Act.The Fourth Circuit had previously granted a stay of the similarly routed MVP’s NWP 12, determining that the project could not meet a condition in its permit in West Virginia that stipulated all stream crossings be constructed within 72 hours.Environmental groups quickly adopted the same tactic in challenging ACP, but their argument that ACP couldn’t complete a planned crossing of the Greenbrier River in 72 hours did not persuade the court. “The record lacks clear evidence that ACP is unable to comply with the 72-hour condition,” the court concluded. In addition, the Huntington District of the Army Corps “has voluntarily suspended all NWP 12 verifications for ACP in West Virginia pending ACP’s provision of additional information to ensure its compliance with all NWP 12 conditions.”
Fourth Circuit Blocks Enviros, Denies Stay of Atlantic Coast Water Crossing Permit - A federal appeals court has shut down an effort by environmental groups to stall Atlantic Coast Pipeline LLC’s (ACP) construction plans over a condition in its West Virginia water crossing permit, a tactic that had more success against the Mountain Valley Pipeline (MVP).The U.S. Court of Appeals for the Fourth Circuit, which has handed down its fair share of unfavorable rulings to ACP and MVP in recent months, last Thursday denied without prejudice a motion filed by the Sierra Club and other groups to stay ACP’s Nationwide Permit (NWP) 12. The NWP 12 covers waterbody crossings and is issued by the U.S. Army Corps of Engineers under Section 404 of the U.S. Clean Water Act.The Fourth Circuit had previously granted a stay of the similarly routed MVP’s NWP 12, determining that the project could not meet a condition in its permit in West Virginia that stipulated all stream crossings be constructed within 72 hours.Environmental groups quickly adopted the same tactic in challenging ACP, but their argument that ACP couldn’t complete a planned crossing of the Greenbrier River in 72 hours did not persuade the court.“The record lacks clear evidence that ACP is unable to comply with the 72-hour condition,” the court concluded. In addition, the Huntington District of the Army Corps “has voluntarily suspended all NWP 12 verifications for ACP in West Virginia pending ACP’s provision of additional information to ensure its compliance with all NWP 12 conditions.” The court also cited a commitment from ACP to provide written notice to the petitioners in advance of resuming any work authorized under the NWP 12.
All-volunteer groups patrol construction of gas pipeline projects in Virginia, North Carolina - After the Mountain Valley Pipeline (MVP) and Atlantic Coast Pipeline (ACP) projects were proposed almost five years ago, residents in rural western Virginia fought hard to persuade state and federal regulators to reject the companies’ requests to build the pipelines through their communities.When regulators gave the two massive construction projects green lights to proceed almost a year ago, the residents didn’t concede defeat. They grew even more determined to stop the pipeline construction in its tracks.After the MVP was approved in October 2017, “we decided that we weren’t going to sit by idly and let them run over us with their construction equipment,” Kirk Bowers, pipeline program coordinator for the Sierra Club of Virginia told ThinkProgress. Bowers is one of the leaders of Mountain Valley Watch, a group created to monitor construction of the pipeline. Residents have signed up to serve as volunteer monitors and scouts for what have essentially become citizen regulatory agencies. Mountain Valley Watch was formed earlier this year as was the Pipeline Compliance Surveillance Initiative (Pipeline CSI), which is keeping a close eye on the the ACP. The dual monitoring efforts involve hundreds of volunteer observers and collaboration with environmental organizations and citizen groups — such asFriends of Nelson County and Augusta County Alliance — formed years ago to protect the property rights, rural heritage, and environment of the region.In some cases, these volunteer monitoring groups have g athered more information on the pipelines’ impact on the environment and private lands than the regulators that are paid to monitor the projects.
Environmental groups sue US Coast Guard over Great Lakes oil spill response plans - Two environmental groups are suing the U.S. Coast Guard for its admitted inability to respond adequately to a Great Lakes oil spill and, by extension, the lawsuit seeks to invalidate the response plans for facilities such as Enbridge, which operates Line 5 beneath the Straits of Mackinac. The lawsuit filed Wednesday in Detroit federal district court stems from comments former Coast Guard Commandant Adm. Paul Zukunft made during a November congressional committee hearing, when he told lawmakers the agency is not prepared for a major pipeline oil spill in the Great Lakes. His comments, the lawsuit said, belie and invalidate the Coast Guard-approved Northern Michigan Area Contingency Plan and violate the Oil Pollution Act of 1990, according to a statement from the National Wildlife Federation and the Environmental Law & Policy Center. The current plan leaves the Coast Guard unprepared to address a worst-case spill from Enbridge's Line 5, which could affect more than 400 miles of shoreline and 60,000 acres of wildlife habitat, said Oday Salim, a staff attorney for the National Wildlife Federation. “Until we decommission this aging, risky pipeline, we need the best-possible spill response plan to protect our Great Lakes, our communities, our wildlife and our economy,” Salim said in a statement. The Oil Pollution Act of 1990 was created after the Exxon Valdez oil spill in Alaska and requires oil spill contingency plans in areas where oil is transported through waterways, said Margrethe Kearney, senior attorney for Chicago-based Environmental Law and Policy Center. The U.S. Coast Guard signed off on the North Michigan Area Contingency Plan in June 2017, certifying the agency could respond to a worst-case discharge. In November, however, Zukunft told Congress the Coast Guard is "not semper paratus for a major pipeline oil spill in the Great Lakes,” referring the agency's Latin motto, "always ready." "It was unlawful for them to approve it when in fact they’re not able to remove the discharge from a worst case oil spill," Kearney said. The lawsuit asks the judge to declare the approval of the Northern Michigan contingency plan a violation of the Oil Pollution Act and invalidate sections of the plan that relate to open waters and any facility-specific response plans created in coordination with the plan, including Enbridge's facility response plan.
Trump's trade war puts energy jobs at risk - This summer, China and the United States launched the opening salvos in a trade war that has been brewing for months. America imposed a 25 percent tariff on $34 billion of Chinese goods. In response, China slapped tariffs on U.S. products and agricultural goods such as soybeans and pork. President Trump escalated things by announcing another $200 billion in tariffs on Chinese goods. Chinese officials, who had previously proposed to increase natural gas purchases in an effort to reduce the U.S. trade deficit, have already vowed to retaliate with a similarly sized tariff on U.S. exports, including crude oil and natural gas. If the administration doesn't defuse this conflict, China's retaliatory tariffs could hammer America's booming energy industry. They could wipe out thousands of current or future oil and gas jobs, and prevent the United States from achieving energy independence. America's energy renaissance has made the United States less reliant on rivals such as Russia and Saudi Arabia. American imports of Russian crude oil in April 2018 was a third of what it was in April 2010. The United States is nearing complete energy independence — a feat thought impossible just a few years ago. American firms have been spending heavily to build the infrastructure necessary to sustain these exports. Until recently, only one terminal to export liquefied natural gas existed in the United States. But several new terminals are currently under construction, which will create even more export opportunities. And just last year, Trump approved two major pipelines—the Dakota Access Pipeline and the Keystone XL Pipeline—to transport oil to refineries. This infrastructure spending — all of it with private, not taxpayer, dollars — could come to a screeching halt if China shuns our energy exports. China is the largest net buyer of U.S. crude oil in the world—one fifth of all U.S. crude oil exports in 2017. China also imported more than $1 billion of American liquefied natural gas in 2017, and that figure is projected to increase nine-fold by 2021, according to a Morgan Stanley estimate.
Shipments to gas stations before certain holidays affect gasoline product supplied - EIA - U.S. holiday weekends associated with increased driving, such as Labor Day and Memorial Day, often result in large swings or changes in gasoline product supplied. EIA uses product supplied as a proxy for U.S. gasoline consumption. Some of the largest weekly decreases in gasoline product supplied often occur during the weeks of these holidays, reflecting the timing of shipments to retail gasoline stations. EIA’s estimate of product supplied published in the Weekly Petroleum Status Report measures the volume of petroleum products from the primary supply chain. Although these products are ultimately consumed, EIA’s product supplied series measures their volumes further up the supply chain and not at the point of consumption. For example, gasoline inventories at large bulk terminals are included in EIA’s measure of gasoline product supplied, but inventories at retail gasoline stations are not surveyed or included in this measure. For motor gasoline, the primary supply chain includes refineries, bulk terminals and blenders, importers, exporters, and pipelines. All of these primary supply chain components handle large volumes of gasoline on a daily basis. Retail stations are defined as secondary storage—the portion of the overall distribution network that falls between producers and end users. Product supplied captures the transfer of supplies from the primary supply chain to these secondary storage facilities. The existence of significant amounts of secondary storage means that these transfers between the primary and secondary supply chains can result in large week-to-week swings in product supplied that do not reflect actual consumption patterns. Because EIA’s survey measures the status of product in the primary supply chain as of Friday morning each week, many of the transfers from the primary supply chain (in particular, from bulk terminals to retail stations) occur before these holiday weekends, when stations prepare to serve the expected increase in drivers filling up their vehicles, and not in the week of the holiday itself. Other variables such as the timing and scale of imports or exports can lead to large weekly changes in product supplied that do not necessarily reflect actual gasoline sales volumes at retail stations in any given week. Because of these dynamics, EIA uses a four-week rolling average of product supplied, which can smooth out short-term fluctuations and highlight longer-term trends in gasoline consumption. Furthermore, gasoline consumption patterns should be considered within the context of other factors that can influence motor gasoline demand, such as retail gasoline prices, macroeconomic changes, and weather.
Cheniere prepares for flowing feedgas to fifth train at Louisiana LNG export terminal — Cheniere Energy wants permission from the US Federal Energy Regulatory Commission by next week to begin flowing feedgas to its fifth liquefaction train at its Sabine Pass LNG export terminal, as it prepares to begin production on that unit and the first at its Corpus Christi, Texas, facility before the end of the year. The company is eager to stay ahead of schedule on its construction plans and maintain its growth trajectory as several other US developers are expected to start up their terminals in the months ahead and into 2019. Cheniere is targeting first production at Sabine Pass Train 5 and Corpus Christi Train 1 for the fourth quarter, a similar timeframe for when Kinder Morgan expects initial in-service at its Elba Island export terminal in Georgia. Sempra Energy said earlier this month that it remains on track for all three trains at its Cameron LNG facility in Louisiana to produce LNG in 2019. Freeport LNG in Texas also is expecting to see service in 2019. (Infographic: US LNG exports expected to ramp up sharply through 2019) In a filing Monday afternoon, Cheniere asked FERC for feedgas and refrigerants authorization for the Sabine Pass unit by September 6. It was recently granted feedgas authorization for the Corpus Christi unit. A company spokesman declined Tuesday to provide a more precise update to timing of initial production from the two units. Deliveries to Corpus Christi have averaged 4 MMcf/d since the beginning of August and have yet to go over 11 MMcf/d, suggesting that the facility is still flowing just fuel gas, S&P Global Platts Analytics data shows. Platts Analytics is forecasting Sabine Pass Train 5's first substantial feedgas delivery in November. For comparison, Cheniere received authorization to begin flowing feedgas to Sabine Pass Train 1 on November 19, 2015. The first time over 100 MMcf/d of feedegas was delivered to the facility occurred on December 22, 2015, just days before the unit registered its first production. As for cargoes, Platts Analytics assumes that initial feedgas deliveries begin four months before exports begin, and subsequent trains receive feedgas deliveries three months before exports begin. Cheniere exported its first cargo from Sabine Pass in February 2016, three months after feedgas approval for Train 1.
Permian oil, gas and NGLs target export markets. - It seems like everyone wants production out of the Permian these days — at least everyone who works for a pipeline company. The addition of five major greenfield crude oil pipes plus a host of expansion projects could bring Permian takeaway capacity up to 8.0 MMb/d from only 3.3 MMb/d today, with almost all of the incremental barrels destined for export markets. It’s a similar story for natural gas, with seven new pipes in the works to bring 2.0 Bcf/d each to Corpus Christi, Houston, or Louisiana, again with most of the molecules targeting exports. Not to be left behind, at least 27 new Permian gas processing plants are in development, and five new pipeline projects could bring 1.6 MMb/d of y-grade NGLs to the Gulf Coast. It’s a darned good thing that everyone in the global energy markets wants all that Permian production, right? What will this mean for the Permian and, for that matter, for the rest of the U.S. and the world? The only way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for PermiCon 2018. Warning! Today’s blog is a not-so-subliminal advertorial for our upcoming conference. The Permian isn’t just a basin. It’s a phenomenon. Over the past five years, the increase in Permian crude oil production has been more than three times the rate of all the rest of the U.S. put together, and the Permian will continue to dominate U.S. production growth. Figure 1 shows that essentially all of the growth in U.S. crude oil production since 2014 (between red dashed and blue dashed vertical lines) has come from the five big shale basins — Eagle Ford, Anadarko (STACK/SCOOP), Niobrara, Bakken and Permian — but that the Permian (orange layer) dwarfs them all. (The area from the top of the Permian to the red line is the sum of all other basins, including the Offshore Gulf of Mexico.) It’s a similar story going forward in RBN’s “Mid-Curve” scenario (shown in area to right of dashed blue vertical line), which assumes a price outlook similar to today’s forward curve. By 2023, Permian production will exceed volumes from all four of the other big shale basins combined.
New pipelines to boost U.S. natural gas exports to Mexico - U.S. natural gas exports to Mexico by pipeline are expected to jump in the coming months as several long-awaited projects are placed into service to feed growing demand across the border and potentially ease bottlenecks in the Permian Basin in West Texas. The U.S. Energy Department reported that four major pipelines are scheduled to begin commercial operations by the end of the year to supply Mexico's power generation and industrial sectors. The country has emerged as one of the largest customers of U.S. natural gas after overhauling its energy policies five years ago. The pipelines, which include Enbridge's Nueces-Brownsville project in the Rio Grande Valley and three projects in Mexico, are expected to start up in October and November. They'll help bring gas from West Texas, where there is a pipeline shortage, and elsewhere in the state to central and western Mexico. Already, exports have ramped up in recent months. Natural gas shipments to Mexico by pipeline exceeded 5 billion cubic feet per day for the first time last month, up from an average of 4.2 billion cubic feet per day in 2017. U.S. natural gas exports to Mexico surged after 2013 and 2014, when Mexico opened its energy market to foreign investment and intensified its focus on using cleaner-burning fuel sources such as natural gas. It sought to buy gas from the U.S., where the shale boom in West Texas and elsewhere had unleashed a cheap and plentiful supply, and pushed to expand its pipeline network as its own oil and gas production declined.
Big oil calls proposed NAFTA agreement with Mexico encouraging | TheHill: One of the leading oil lobbyists said it is "encouraged" by news that the Trump administration has reached an agreement with Mexico to update the North American Free Trade Agreement (NAFTA). The American Petroleum Institute (API) said Monday that the industry relies on open trade and modernized relationship with Mexico."We are encouraged that negotiators have reached a preliminary agreement to modernize our trade relationships,” said API President and CEO Mike Sommers in a statement. “America’s natural gas and oil industry depends on trade to continue to grow U.S. jobs and our economy, and deliver for consumers.” Mexico in 2017 was the leading importer of American oil and petroleum products, according to the U.S. Energy Information Administration. President Trump said Monday the U.S. has reached an agreement with Mexico amid contentious talks on revamping NAFTA "It’s a big day for trade. It’s a big day for our country," the president told reporters in the Oval Office, who were summoned to watch Trump speak by phone with outgoing Mexican President Enrique Peña Nieto. The president said he plans to "terminate" the existing NAFTA agreement, which currently includes Canada.
Texas Oil, Natural Gas Output Takes U-Turn in June, Lowest Reported Since February 2017 - The Lone Star State’s oil and natural gas output in June retreated from a year ago and month/month, with production at the lowest level in 16 months, according to preliminary data by Texas regulators.The Railroad Commission of Texas (RRC) production report for June, issued late Thursday, said combined crude oil and condensate output fell to 98.8 million bbl from 101.32 million bbl in June 2017 and from May 2018’s total of 106.48 million bbl.Combined, natural gas well and casinghead gas also fell from a year ago to 615.21 MMcf from 661.54 MMcf, and output declined from 663.88 MMcf reported in May.Crude oil/condensate production in June was the lowest reported since February 2017, when output totaled almost 92.01 million bbl. Gas well/casinghead gas also hit a low not seen since February 2017, when production was 603.97 MMcf.State officials did not speculate on why output fell. However, the Permian Basin for the last few months has seen increasing signs of tightening pipeline capacity for gas and for oil, and prices have been squeezed.The RRC said production in June flowed from 181,669 oil wells and 91,665 gas wells. In addition, the RRC reported that the percent of produced gas exported from Texas increased 34% from June 2017, likely the result of increasing pipeline exports to Mexico.Regulatory officials cautioned that the June production data was preliminary, and said “significant changes” could occur because of late filings or corrected reports. According to the initial data, crude oil production alone declined in June year/year (y/y) to 88.86 million bbl from 90.09 million bbl and from 95.57 million bbl in May. Condensate production was down from a year ago to 10.06 million bbl from 11.22 million bbl and off from 10.91 million bbl in May. Gas well production in June was off y/y at 391.15 MMcf from 442.03 MMcf and from almost 423.20 MMcf in May. Casinghead gas, aka oil well gas, was the only category that climbed y/y to 224.06 MMcf from 219.51 MMcf, but it was down from 240.69 MMcf reported in May. Between July 2017 and June, total crude oil production in Texas was estimated at 1.146 billion bbl. Crude oil production reported by the RRC is limited to oil produced from oil leases and does not include condensate, which is reported separately. Total natural gas output between July 2017 and June was estimated at 8 Tcf, according to the data.
The Permian Could Soon Have Too Much Pipeline Capacity - The Permian could soon have too much pipeline capacity, a glut that will present problems for midstream companies. You could be forgiven for doing a double take on that sentence. There has been a lot of attention paid to the pipeline woes in West Texas, but because of the unfolding shortage, not a surplus. The flood of supply over the past few years suddenly ran up against a wall of fixed takeaway capacity in 2018. The result has been maxed out pipes, painful discounts for crude in Midland and concerns about a production slowdown sweeping over the basin. Now there is a rush to build more pipelines to load up all of that crude coming out of the ground. But with several projects in the works and set to come online essentially at the same time – late 2019 and early 2020 – the Permian could see a massive increase in pipeline capacity, hitting the market in lump-sum fashion at the same time. The Permian has around 3.1 million barrels per day (mb/d) of takeaway and local refining capacity, plus some 300,000 bpd of local refining capacity. The Permian is producing just around 3.4 mb/d, which means the pipelines are nearly full or already at capacity. Production is expected to continue to rise over the next year, although pipeline constraints could curtail output by around 200,000 to 300,000 bpd, Barclays said a few weeks ago. Still, the EIA sees the region adding around 600,000 bpd in 2019, which will be difficult for the midstream sector to digest. But over the next two years, a series of new pipelines will come online, with in-service dates scheduled close together. According to S&P Global Platts, an estimated 2.6 mb/d of pipeline capacity will come online by 2020, with a further 1 mb/d on the drawing board but lacking a timeline. With benchmark WTI trading in the upper-$60s, Permian producers that have not secured pipeline space or hedged their production are selling oil in the mid- to low-$50s. That discount should worsen over the next year until new pipelines come online. But when the wave of takeaway capacity does hit the market, the discount should narrow considerably. For that reason, most analysts still see robust production growth in the Permian
Report: Fracking Stresses Texas Water Supplies – The oil and gas industry’s thirst for water – a critical component of hydraulic fracturing – has skyrocketed, according to a Duke University report. Industry use increased by more than 700 percent between 2011 and 2016. If current trends continue, Avner Vengosh, the report’s co-author, says there could be clashes in the not-so-distant future over finite water supplies that communities rely on for drinking water, crops and livestock. Vengosh says the situation in the eastern U.S., where water is more abundant, is markedly different than western states experiencing prolonged drought. “It’s a totally different ballgame if you go to western Texas, where water is so important for the livelihood,” he points out. “And the idea that the oil and gas industry would continue to take fresh water, it could be problematic.” Vengosh says early research suggested that fracking did not require more water than other energy development. But he explains that since the production at fracked wells drops dramatically after a few months, the most economical way to extract oil and gas is to drill more wells, which requires more water. . Most of the water used for fracking is captured deep within the earth, which means it’s lost for any other use. Vengosh notes that wastewater released through the fracking process still needs to be disposed of, and the primary way to do that – through deep well injections – has been shown to cause earthquakes. “The water that you put in is not the water that’s coming out after hydraulic fracturing,” he explains. “It’s water that would be highly saline with a lot of chemicals. Some of them are toxic chemicals, some of them are radioactive.” Salts and toxic elements in the flowback water also pose contamination risks to local ecosystems from spills. While energy production currently is responsible for 15 percent of water use globally, the study notes water supplies also are diminishing at a rapid rate across the planet because of climate change and population growth.
Drowning in Dirty Water, Permian Needs $22B to Stay Afloat - -- In the dry, dusty plains of West Texas, home to America’s most prolific oil play, the problem isn’t too little water, it’s too much of it. Just ask Will Hickey, the 31-year-old chief executive officer of Colgate Energy. Standing on a 26-foot high rig platform in Texas’s Reeves County, Hickey watches as contractors maneuver drilling pipe almost 10,000 feet underground in search of oil. Just a half-mile away, another rig is equally hard at work. But this one, operated by WaterBridge Resources LLC, isn’t seeking oil. It’s making a hole to dispose of the vast amount of water generated from local wells. ‘‘If we don’t have a water solution we can’t produce the well, it’s as simple as that,’’ Hickey said in an interview. “It used to be that each operator handled water themselves. But the sheer volume of what’s now being produced has created an opportunity for specialized water companies to step in.” With fracking, explorers blast water, sand and chemicals down wells to crack open the oil-bearing shale below. As oil is pumped up, so is the water, combined with salt-laden water from underground reservoirs to create a toxic mix that would devastate farmland if released on the surface. With as many as four barrels of water produced for every barrel of oil, it’s a disposal nightmare that could add as much as $6 a barrel to company break-evens by 2025, according to a recent Wood Mackenzie study. Overall, the region will pull up enough water this year alone to cover all of Rhode Island nearly a foot deep. Wall Street is well aware of the threats posed by the Permian Basin’s pipeline and labor shortages, key side effects from the region’s rapid buildup. But investors “aren’t as well apprised of some of the other risks and challenges that could be just as material, if not more so,” said Gabriel Collins, a fellow in energy and the environment at Rice University. “I’d put water right at the top of that list," he said How material? Spending on water management in the Permian Basin is likely to nearly double to more than $22 billion in just five years, according to industry consultant IHS Markit. The reason is twofold. The rig count is rising, and many of the "workhorse" disposal formations used for decades are starting to fill up, said Laura Capper, an industry consultant. That means explorers have to move water further to find a home for it. It’s a problem "that’s just going to get bigger and bigger," said Wood Mackenzie analyst Ryan Duman, "Operators are victims of their own success."
Injecting wastewater underground can cause earthquakes up to 10 kilometers away - Earthquakes in the central and eastern United States have increased dramatically in the last decade as a result of human activities. Enhanced oil recovery techniques, including dewatering and hydraulic fracturing, or fracking, have made accessible large quantities of oil and gas previously trapped underground, but often result in a glut of contaminated wastewater as a byproduct. Energy companies frequently inject wastewater deep underground to avoid polluting drinking water sources. This process is responsible for a surge of earthquakes in Oklahoma and other regions. The timing of these earthquakes makes it clear that they are linked with deep wastewater injection. But earthquake scientists like me want to anticipate how far from injection sites these quakes may occur. We examined injection wells around the world to determine how the number of earthquakes changed with the distance from injection. We found that in some cases wells could trigger earthquakes up to 10 kilometers (6 miles) away. We also found that, contradictory to conventional wisdom, injecting fluids into sedimentary rock rather than the harder underlying rock often generates larger and more distant earthquakes.Assessing how far from a well earthquakes might occur has practical consequences for regulation and management. At first glance, one might expect that the most likely place for wastewater disposal to trigger an earthquake is at the site of the injection well, but this is not necessarily true. Since the 1970s, scientists and engineers have understood that injecting water directly into faults can jack the faults open, making it easier for them to slide in an earthquake. More recently it has become clear that water injection can also cause earthquakes in other ways. For example, water injected underground can create pressure that deforms the surrounding rock and pushes faults toward slipping in earthquakes. This effect is called poroelasticity. Because water does not need to be injected directly into the fault to generate earthquakes via poroelasticity, it can trigger them far away from the injection well. Deep disposal wells are typically less than a foot in diameter, so the chance of any individual well intersecting a fault that is ready to have an earthquake is quite small. But at greater distances from the well, the number of faults that are affected rises, increasing the chance of encountering a fault that can be triggered.
How energy companies set off earthquakes away from their waste dumps - Washington Post - Each day across the United States, 2 billion gallons of fossil-fuel-industry wastewater flies through thousands of underground tubes. The injection wells descend into porous rock, filling gaps with brine and chemicals that are the result of extracting oil and gas from the ground. The goal of the wells is for the wastewater to be out of sight, out of drinking water and out of harm’s way.Except the wells can cause earthquakes. In some cases, the quakes begin as far as 15 miles from the wells. In a new study in the journal Science, scientists describe for the first time how earthquakes can be triggered so far away from the wells. An efficient practice by the oil and gas industry is creating a ripple effect far beyond its drilling locations. Geologists have linked injection wells to quakes, with findings based on years of observation. Human-made earthquakes, though most are moderate in size, put 1 in 50 people in the United States at risk, according to a recent U.S. Geological Survey analysis. Wastewater injection wells are concentrated in Oklahoma, Texas, California and Kansas, according to the Environmental Protection Agency. “Induced earthquakes are becoming more and more of an issue in central and the eastern U.S.,” said University of California at Santa Cruz seismologist Thomas Goebel. In 2011, an injection well in Oklahoma was responsible for a magnitude-5.6 earthquake that damaged a highway, shook buildings and generated a dozen aftershocks. To figure out how there could be such a distance between well and earthquake, Goebel, along with fellow UC-Santa Cruz earthquake expert Emily Brodsky, sifted through quakes triggered by dozens of waste injection sites in several states as well as in Australia and Europe. (There are so many wells in Oklahoma they could not link an individual well to the surrounding earthquakes.) The study authors were able to identify two types of earthquakes triggered by wastewater wells, having everything to do with what kind of rock the water is being injected into.One kind of earthquake formed close to the injection well but stopped abruptly at about a half-mile from the site, Goebel said. If a well dumped its wastewater into rigid bedrock, earthquakes occurred within a close distance. There, pressure from water that spilled into a fault triggered the earthquake.The other kind had a “very long-distance tail” — the quakes could appear far from the well, with the triggers petering out only after several miles. This occurred if a well dumped its wastewater into softer sedimentary rock. This was a result of what the researchers called "poro-elasticity."
In the rural West: more oil, more gas, more ozone - “It was like flying back into Los Angeles on the worst days of the L.A. smog,” Nelson said. “There was brown haze everywhere.” A cold air inversion had trapped polluted air in the Grand Valley that encompasses the city. The 2013-2014 inversion was the worst the area had seen in recent years, but the resident activists are fearful that a growing population, a seemingly endless wildfire season, and the Trump administration’s push to expand oil and gas drilling could make those smoggy days a regular occurrence. According to data compiled by the left-leaning Frontier Group, part of the larger Public Interest Network of advocacy organizations, Grand Junction had 86 days in 2016 in which the air quality index for ozone or particulate matter registered “moderate” or higher, a designation that the air could be unhealthy for people with some respiratory conditions. That was the fourth highest in the state, and only 12 fewer such days than the much bigger city of Denver experienced the same year. But it’s not just Grand Junction: In 2013, an ozone monitor in Rangely, Colorado (population 2,400) spiked to more than 100 parts per billion (ppb), on par with levels measured in Los Angeles the same year. Over the past decade, monitors in the Upper Green River Basin in Wyoming and the Uinta Basin in Utah have registered pollution levels above the Environmental Protection Agency’s health standards, and swaths of rural Texas have seen high ozone levels. Rural monitors have also reported increases in southwestern Colorado and along the New Mexico-Texas border. Ozone doesn’t come from any one source. Rather, it’s a mix of three ingredients: nitrogen oxide pollution from motor vehicles, power plants, and industrial operations; volatile organic compounds (VOCs) from household products and other anthropogenic sources, as well as plants; and sunlight. Rural areas in the Far West have historically had fewer emission sources, and yet they have been seeing high ozone readings in the winter, when the air should be cooler and cleaner.
Colorado to vote in November on proposal to toughen oil drilling rules (Reuters) - A Colorado ballot initiative that would sharply increase the required distance between new oil wells and populated areas will go before voters in November, Colorado officials said on Wednesday. The proposal, opposed as anti-fracking by oil and gas producers, would require new projects to be at least 2,500 feet (762 m) from buildings, parks and certain wildlife areas. The state currently requires as little as 500 feet (152 m) of separation. A 2,500-foot setback would render about 85 percent of all new oil and gas development on non-federal lands in the state off-limits to drilling, according to a 2016 study by the state’s oil and gas conservation commission. Colorado Rising submitted 123,195 verified signatures to get the initiative on the ballot, above the 98,492 required, state officials said on Wednesday. A similar initiative failed to get on the 2016 ballot. The following April, two men were killed in an explosion caused by gas from an abandoned well about 170 feet (52 m) from a Firestone, Colorado, home. Supporters of the initiative say there have been 13 explosions and fires since then. “The climate in regards to oil and gas has really shifted quite a bit since the Firestone explosion,” Anne Lee Foster, a volunteer with Colorado Rising, said on Wednesday. Opponents argue the proposal would cost Colorado’s economy between $169 billion and $217 billion over the next 12 years, and reduce state and local tax revenues by between $7 billion and $9 billion. It would also affect an estimated 147,800 jobs, a July 2018 report by free-enterprise group Common Sense Policy Roundtable said. “The impact of the measure would ripple through the whole economy,” said Karen Crummy, a spokeswoman for Protect Colorado, a group backed by the oil and gas industry. “It’s just hard to conceive that the intent of this is anything other than to get rid of oil and gas development,” Crummy said.
Colorado Measure Would Make Most of State Off Limits to Drillers - Colorado voters in November will consider banning oil and gas drilling within 2,500 feet of homes, businesses and many green spaces, a move that would effectively prohibit it in most of the U.S.’s seventh largest oil-producing state. The Colorado Secretary of State’s office said Wednesday that antifracking activists had collected enough valid signatures from state voters to put the issue on the fall ballot. That sets the stage for a heated political battle in a fast-growing state where suburban development and oil and gas production have been steadily encroaching on one another, exacerbating tensions. Colorado requires oil and gas wells to be located at least 500 feet from buildings and 350 feet from recreation areas like playgrounds. The ballot initiative would increase those setbacks to 2,500 feet, or nearly a half mile. That would ban drilling on 85% of the state’s nonfederal land, according to an analysis by state regulators. “This is a ban. It’s to drive you out of the state,” Chip Rimer, a senior vice president at Noble Energy Inc., NBL -0.57% said at an industry conference in Denver this month where companies sought to underscore the measure’s possible economic impacts. If the measure passes, it would reduce state and local tax revenue by $201 million to $258 million in the first year, and result in 33,500 to 43,000 lost jobs, according to a study by the REMI Partnership, a public policy research group. Activists have campaigned for years for such limitations in Colorado, where wells commonly abut densely populated areas. Similar statewide initiatives failed to make the ballot in 2014 and 2016. Since then, however, crude production has increased 44% in Colorado, federal data show, as oil’s rebound to nearly $70 a barrel made it more economical to drill in the state. That production surge coincided with rapid population growth in the suburban communities north of Denver where drilling is most prevalent. Recent deadly explosions also have brought increased attention to the safety of oil and gas operations.
Industry Gears Up For Fight As 2,500-Foot Oil And Gas Setback OK’d For 2018 Ballot - Coloradans will now get a front row seat for one of the most contentious ballot issue battles in recent memory. On one side are environmentalists who believe the state should have more space between oil wells and homes. The other is an industry with seemingly limitless financial resources, seeking to protect the status quo. Initiative 97 — which will appear as Proposition 112 on the ballot — would increase setbacks between new wells and homes, offices, rivers and playgrounds to 2,500 feet. Current oil and gas setbacks range between 500 feet for homes and 1,000 feet for higher occupancy buildings.“We’re really looking to protect the health and safety of Coloradans from toxic benzene exposure, from explosions, from contamination of our water, from a highly dangerous industrial fracking industry,” said Anne Lee Foster with the environmental group Colorado Rising.Up until this point, it had been a difficult road for Colorado Rising. First, paid protesters harassed Colorado Rising signature gatherers and then boxes of signatures disappeared in a dispute with their canvasser. The proposal also faced opposition from Democratic Gov. John Hickenlooper and both candidates for governor, Walker Stapleton and Jared Polis. The initiative is supported by some local governments like the Boulder County Commissioners, local control groups like Broomfield Clear Air and Water and environmental groups like the Sierra Club.
Interior Adviser to Join BP After Pushing to Open National Monuments to Fossil Fuel Development -- A Department of the Interior (DOI) official who played an important role in opening public lands to fossil fuel interests has left the federal government to accept a job at BP, The Washington Post reported Monday. Former DOI Deputy Chief of Staff Downey Magallanes led the review that resulted in Secretary of the InteriorRyan Zinke's plan to shrink the Bears Ears and Grand Staircase-Escalante National Monuments in Utah by 85 and 46 percent respectively, Think Progress pointed out. "Her prior work on behalf of oil, gas and coal, her family's ties to the coal industry, and the fact that she is headed to BP all point in one direction: that she came to Interior with an agenda to promote fossil fuel development over the interest of the American public," Southern Utah Wilderness Alliance legal director Stephen Bloch told The Washington Post in an email.Documents made public in March and June confirmed that allowing access to coal, oil and gas reserves was a large part of the decision to reduce the monuments' size, as was enabling mining, Think Progress reported.Magallanes also worked on regulatory reform and offshore oil drilling, according to The Washington Post. Her father worked as a lobbyist for Peabody Energy Corp. for 14 years, according to The Hill. Magallanes met three times with BP officials between Jan. 30 and Aug. 31, 2017 while working for DOI, according to an official calendar obtained using the Freedom of Information Act. The Trump administration's ethics pledge bans former employees from lobbying either their former agencies or anyone in the executive branch for five years after departure, but anonymous sources told The Washington Post that Magallanes will work with Congress. BP has confirmed she will be part of its government affairs team.
Utah asks agency to resume permitting for pipeline project (AP) — The state of Utah wants the federal government to resume its work permitting the Lake Powell Pipeline project. Utah water officials in January asked to halt the project, worried over jurisdictional questions about whether the Federal Energy Regulatory Commission would continue to act as the permitting agency, The Spectrum reported .The state still hasn't received any answers, and attorneys for the Utah Board of Water Resources and the Washington County Water Conservancy District filed a letter Wednesday with the commission asking it to proceed."Because it is extremely important that the licensing of this critical infrastructure project for the State of Utah move forward expeditiously, UBWR and WCWCD desire to now have the procedural schedule reinstated," according to the letter.State water officials have spent more than $30 million over the past decade readying its proposals for the pipeline, which would carry water some 140 miles (225 kilometers) out of Lake Powell and across parts of Utah and Arizona to communities in Washington and Kane counties. State officials applied for the project through the Federal Energy Regulatory Commission because of proposed hydroelectric facilities that would be built along the pipeline. The water would be pumped out of Lake Powell to a high point within the Grand Staircase-Escalante National Monument area, then flow downhill toward St. George, passing through a series of hydroelectric turbines along the way. Local water managers say the pipeline is needed to keep up with growing demands for water in the fast-growing St. George area, where the population is forecast to balloon from about 165,000 today to more than 500,000 over the next 50 years. The pipeline has been the target of controversy among conservationists. It is one of a series of projects states have proposed to pull more water from the Colorado River system despite evidence that the river's supplies are overdrawn and that climate change is likely to dry the region further in the future.
Feature: Powder River Basin seems poised for an oil and gas comeback despite some drawbacks — Wyoming's Powder River Basin appears on the verge of a comeback as companies unveil plans to use horizontal drilling to further develop the play's oil and gas resources. Even as some of industry's biggest operators have shown interest in the basin recently, some of its key financial metrics appear lower on average than other areas, and experts project only a modest rise in oil production over the next five years. So what is the draw for some of industry's biggest independent producers? For one thing, the PRB offers "optionality" at a time when the giant Permian Basin in West Texas and New Mexico is struggling to provide enough output takeaway capacity, S&P Global Platts Analytics analyst Matt Andre said. "While some of the other major plays are dealing with constraints and rising differentials, the [PRB] has benefited from favorable well economics along with the promise of expanding infrastructure (in the future)," Andre said. "It's not quite the Permian, but you don't run into the oil price differential issues and land costs of the Permian, either," he said. Also, the PRB has a high oil production mix, with companies citing 60%-80%, strong initial well production rates and low acreage costs, he added. For example, Anadarko Petroleum recently said it has established a core PRB position of 300,000 gross acres at $2,500/acre. In addition, some producers "actually compare the [PRB's] economics to the Permian" which are at or near the top of US plays, Andre said. "Realistically that is probably only the top wells, but it is still interesting."
Geologists study ND sand for use in fracking | Grand Forks Herald: — North Dakota geologists are re-evaluating whether local sources of sand could be used for hydraulic fracturing as oil industry demand increases. Oil companies now use greater volumes of sand for fracking, averaging about 2,500 to 5,000 tons per well, according to the Department of Mineral Resources. Operators are interested in finding a North Dakota source of sand to save on transportation costs rather than importing it by rail, said Ron Ness, president of the North Dakota Petroleum Council. "This would be absolutely another game-changer for the Bakken," Ness said.Fred Anderson, geologist with the North Dakota Geological Survey, authored a study in 2011 that said North Dakota sand sources approach oil industry standards for use in fracking but are lower in overall quality than other U.S. sources. There's a renewed interest in that research, however, as demand for sand increases and companies experiment with lower-cost options. "They're accepting sands that we probably never would have accepted 10 to 15 years ago," said Monte Besler, owner of FRACN8R Consulting in Williston. Now the Geological Survey is conducting a second phase of research, with a focus this summer and fall on collecting sandstone samples from Billings and McKenzie counties in western North Dakota. Previously, the Geological Survey collected samples from wind-blown sands in north-central and eastern North Dakota.
"Green" California Is More Reliant On Foreign Oil Than Ever Before - There’s a growing call for California Gov. Jerry Brown to stop issuing oil and natural gas leases in the state, with some even arguing that all state fossil fuel production should be shuttered.Yet continuing the current trend of dwindling in-state crude production wouldn’t mean California stops using oil. The state, ranked as one of the “greenest” in the country, would still use lots of oil, it would just come from other countries.In fact, more than 56 percent of the crude oil received by California refineries were extracted in foreign countries, according to California Energy Commission data. California, once the third-largest oil state, is now more reliant than ever on foreign oil.The biggest share of California’s oil imports come from Saudi Arabia, which makes up 29 percent of foreign crude flowing into the state. More than 70 percent of foreign oil imports to the state come from OPEC members, including Iraq, Kuwait and Ecuador.California’s share of oil coming from foreign sources has ballooned since the late 1990s. Decades of state policies restricting drilling played a role, as did declining production in Alaska.The state legislature also completely banned new offshore drilling leases in 1994, decades after the massive Santa Barbara oil spill. Geological factors also make it expensive to pump out crude compared to other states.While environmentalists have chastised California for its oil production, the state’s eschewing of crude extraction has contributed to its increased reliance on foreign oil. California’s oil production has fallen 56 percent since 1985, according to state data. Much of that is being replaced by oil imports from countries without the same level of environmental and public health protections that U.S. agencies require.
What If There Isn't Enough Energy Going Forward? - Currently the media is breathlessly cheering the record amounts of US oil production. Stories like this one get top billing on major news websites:Texas Gulf Coast exports more oil than it imports for the first time (CNN) It's a big achievement that highlights a surge in US oil exports, and that shows how the shale boom can make America less reliant on foreign oil. Texas is the epicenter of the shale revolution, with soaring production in the oil-rich Permian Basin leading the United States to record output. Texas is now on track to produce more oil than either Iran or Iraq. That would make Texas No. 3 in the world if it were a country. Sounds pretty wonderful, right? Technology advances in the fracking process have enabled the "shale miracle", resulting in the US producing over 10 million barrels per day for the first time since the 1970s. Think of all the incremental GDP growth that excess oil will power! If these trends continue, CNN goes on to tell us, the US will become an net energy exporter soon: The gap between oil imports and exports shrank to a 24-year low of 6.8 million barrels per day in 2017, according to the EIA. Even though the economy is stronger, US oil imports fell to 7.8 million barrels per day in May. That's down from more than 9 million barrels per day as recently as mid-2012. OK, let's take a moment to conduct a little reality-check of the hype. First off, notice how the CNN article above mentions that the US is still importing 7.8 million barrels per day. That's not much less that the record levels we're currently extracting from our own soil. So domestic oil production would have to nearly double from here to turn the US into a net oil exporter. Translation: we're not weaning ourselves off of foreign oil anytime soon, under the best of conditions.Next, a key assumption the shale cheerleaders are making is that current output trends will continue. That shale basins like the Permian will yield increasing volumes of crude from here well into the future.As petroleum geologist Art Berman has explained to us in numerous podcasts, shale oil (called "tight oil") wells deplete very differently than conventional oil wells. Oil extraction from a conventional well over time follows a bell curve (left), where it takes roughly as many years as it did to the hit the apex of production as it does for the well to peter out. Shale wells on the other hand, deplete on a hyberbolic curve (right). Roughly 80% of a shale well's total output is exausted by the end of Year 2(!):
Canada could use oil as a weapon in a trade war: Expert – CNBC interview- John Kilduff of Again Capital discusses the impact of trade uncertainty with Canada on oil markets.
Mega-Fracking Brings Big Jump in Industry Water Use - The water used by North America’s controversial fracking industry has dramatically increased since 2011 as the industry “supersizes” its oil and gas wells. A new study in the journal Science Advances found water use per well has jumped by 14 to 770 per cent. This has “serious implications” for communities which will face increasing water demands from the industry, researchers warned. The production of highly saline wastewater has also increased significantly, according to the study, which looked at water use in six different shale basins in the U.S., including the Permian and the Marcellus. The Permian Basin, which sprawls over the deserts of west Texas and New Mexico, reported the largest increase in water use, from 4,900 cubic metres per well in 2011 up to 42,500 cubic metres per well. The current consumption for fracking one well is the equivalent of the water used in a year by more than 425 Greater Vancouver residents. Canadian fracking operations can use between 10,000 and 80,000 cubic metres in the Montney and Duvernay formations in Alberta and northeastern B.C. — among the most water intensive shale formations in the world. One frack job in Canada triggered a 4.6 earthquake in British Columbia by injecting more than 160,000 cubic meters of fluid into a well in 2014. To accommodate growing water demands in northeastern B.C. the industry built as many as 92 unauthorized dams to impound water for use in fracking. The BC Oil and Gas Commission didn’t regulate the activity until Ben Parfitt reported on the dams. Only a small fraction of the fresh water injected into a fracked shale formation ever comes back to the surface. Most of the water that returns to surface is highly saline and can contain radioactive material. It is expensive to treat and often disposed in deep injection wells. There are 200 such wells in northeastern B.C., for example.Accurate and complete figures for the industry’s wastewater production in Canada aren’t readily available.
Court Quashes Canadian Approval Of Trans Mountain Oil Pipeline (Reuters) - A Canadian court on Thursday overturned approval of the Trans Mountain oil pipeline expansion, ruling that Ottawa failed to adequately consider aboriginal concerns, putting the future of the C$7.4 billion ($5.71 billion) project in jeopardy. The decision is a blow to Prime Minister Justin Trudeau's government, which agreed in May to buy the pipeline from Kinder Morgan Canada for C$4.5 billion, and to the country's oil sector. Oil producers say the expanded pipeline is needed to address bottlenecks that have sharply reduced prices for their heavy crude. The Federal Court of Appeal ruled that the National Energy Board (NEB) regulator wrongly narrowed its review of the project to exclude related tanker traffic. Since that is a major concern of some aboriginal people, the federal government therefore was not seen to have adequately consulted First Nations, as required by law, said Andrew Leach, associate professor of business economics at University of Alberta. "The big takeaway is the duty to consult (indigenous people) is still the most important step in any major project," Leach said. Trudeau has portrayed himself as a friend to aboriginal people and tried to build national support for a carbon emissions reduction plan, even while backing Trans Mountain to support the oil industry. “Thankfully, the court has stepped in where Canada has failed to protect and respect our rights and our water," Coldwater Indian Band Chief Lee Spahan said in a statement. "Our members will be hugely relieved.” Trudeau's Finance Minister, Bill Morneau, said he would speak about the decision on Thursday afternoon. Canada has the option to appeal the ruling to the Supreme Court. The court's ruling is likely to amplify sentiments expressed by oil producers, such as Suncor Energy Inc, that they would hold off on further major investments in Canada's oil patch until regulatory challenges abated.
Stunning Victory for Indigenous Nations as Canada Halts Trans Mountain Pipeline Expansion - A Canadian court "quashed" approval of the Trans Mountain pipeline expansion on Thursday, a major setback for Prime Minister Justin Trudeau, whose government agreed to purchase the controversial project from Kinder Morgan for $4.5 billion Canadian dollars (U.S. $3.5 billion) in May.It's a stunning victory for Indigenous groups and environmentalists opposed to the project, which is designed to nearly triple the amount of tar sands transported from Alberta to the coast of British Columbia.The Federal Court of Appeal ruled that the National Energy Board's review—as explained by the Canadian Press—"was so flawed that the federal government could not rely on it as a basis for its decision to approve the expansion."The project has been at the center of widespread protests from environmental groups and First Nations ever since November 2016, when Trudeau approved a $7.4 billion expansion of the existing Trans Mountain pipeline that would increase the transport of Alberta tar sands oil from the current 300,000 barrels per day to 890,000 barrels per day and increase tanker traffic nearly seven-fold through the Burrard Inlet.Specifically, the court said it was an "unjustifiable failure" that the National Energy Board did not consider the environmental impacts of the increased tanker traffic.The court additionally concluded that the government "fell well short" with properly consulting with the Indigenous groups involved in the case, including the Tsleil-Waututh and Squamish on British Columbia's south coast.The ruling will force the National Energy Board to redo its review of the pipeline and the government to restart consultations with the Indigenous groups. It also means that the construction that has already began in central Alberta must cease.In effect, the court has halted the 1,150-kilometer project indefinitely and it will remain in "legal limbo until the energy regulator and the government reassess their approvals to satisfy the court's demands," CBC wrote about today's decision.
Five things about the Trans Mountain pipeline ruling - The Federal Court of Appeal on Thursday released its long-anticipated decision on the Kinder Morgan Trans Canada pipeline. The ruling pleased environmentalists and other anti-pipeline protesters, and shocked proponents of the project such as business and trade organizations. Here are five key details: The Federal Court of Appeal quashed approval of the $9.3-billion Trans Mountain oil pipeline expansion on two grounds. First, the court found Canada had inadequate consultation with First Nations at the final stage, concluding Ottawa “failed to engage dialogue meaningfully and grapple with the real concerns of the Indigenous applicants so as to explore possible accommodation of those concerns.” Second, the scope of the review “unjustifiably” did not include project-related tanker traffic, even though the National Energy Board was “legally obligated” to consider environmental effects. “The unjustified exclusion of project-related marine shipping from the definition of the project rendered the board’s report impermissibly flawed,” the court ruled. The pipeline is owned by U.S. and Canada-based Kinder Morgan Ltd., but the federal Liberal government announced in the spring it’s plans to buy Trans Mountain and Kinder Morgan Canada’s core assets for $4.5 billion to ensure the oilsands pipeline expansion gets built. Also on Thursday, Kinder Morgan’s shareholders voted more than 99 per cent in favour of the sale to Ottawa. The court decision was clear that Ottawa must re-do its consultations with First Nations before the project can be considered for approval again. Morneau said his government will review the court’s decision and will “respond promptly,” but added it was too soon to comment on whether Ottawa would appeal. Premier John Horgan said Thursday that the ruling vindicates the criticisms that the National Energy Board approval process was flawed because, in part, marine traffic was not adequately considered. He said it was a good day for the Tsleil-Waututh and other First Nations who mounted this fight. When asked if the pipeline project is dead, he said it will no longer be “top of mind for British Columbians.” Alberta Premier Rachel Notley, with whom Horgan has vehemently disagreed about this pipeline, waited until Thursday evening to make a live broadcast to her constituents. Political analysts in Alberta predicted the ruling will be disastrous for Notley’s NDP, and could have a major impact on the provincial election less than a year away. The Union of B.C. Indian Chiefs applauded the ruling, and demanded the pipeline be shutdown immediately, even though some First Nations were supporters of the project. Environmental groups celebrated the decision because it requires new consultations with First Nations and new environmental assessments. The cities of Burnaby and Vancouver both oppose the pipeline, and Vancouver Mayor Gregor Robertson on Thursday hailed the court’s conclusion because the project “put our coast at huge risk of oil spills.”
Alberta pulling out of federal climate change plan until pipeline construction resumes --In the wake of the Federal Court's bombshell decision to quash cabinet approval of the Trans Mountain expansion project, Alberta Premier Rachel Notley is pulling her province out of the national climate change plan. Citing inadequate consultations with Indigenous peoples, Justice Eleanor Dawson nullified licensing for the $7.4 billion project Thursday, halting construction only days after shovels hit the ground on the 1,150-km project.Notley said until construction restarts, Alberta will not be party to the pan-Canadian climate framework negotiated by Prime Minister Justin Trudeau and the provinces.The court ruling was a major victory for some B.C. Indigenous peoples and environmentalists — who have long opposed twinning the pipeline — and a nightmare scenario for Alberta's oil patch, which was counting on a new line to tidewater to help fetch world prices for Canadian crude."As important as climate action is to our province's future, I have also always said that taking the next step, in signing on to the federal climate plan, can't happen without the Trans Mountain pipeline," Notley told reporters Thursday. "So today I am announcing that with the Trans Mountain halted, and the work on it halted, until the federal government gets its act together; Alberta is pulling out of the federal climate plan," she added. "And let's be clear, without Alberta that plan isn't worth the paper it's written on."
Is This North America's Next PetChem Hub? - Alberta is poised to find a booming market supplying petrochemical companies from its natural gas shale fields -- and cost-competitive enough to potentially take away some of the U.S. oil and gas market's share. . Alberta sees real potential in mov-ing beyond the primary use of its extracted oil and gas -- such as motor fuels, heating, and power genera-tion -- into petrochemicals used in plastics, fertilizer, fuel, and other products. That's been the case in the U.S., especially in the south. Since 2010, U.S. Gulf Coast shale fields have gen-erated $194 billion in capital investments to build or expand chemical plants. As for Alberta, a real competitive advantage will be charging prices that are about one-third the cost in the U.S. In land-locked Alberta, the province expects that its low prices will attract investors willing to spend billions to expand the Canadian petrochemical market and reach buyers around the world. The province has been supporting diversifying its oil-based economy for the past two years. In 2016, Alberta initiated incentives supporting petrochemical plants. Two projects have been approved to share C$500 million in royalty credits. One of them, Inter Pipeline Ltd, is investing C3.5 billion ($2.7 billion) to build a petrochemical plant near Edmonton. In June, Alberta solicited bids in a second subsidy round for petrochemical plants. Alberta's Athabasca oil sands (or tar sands) have become a major supplier of petroleum and natural gas to global markets such as the U.S. Canadian oil has become vital to the U.S. reducing imports from OPEC. Canada supplied 40 percent of U.S. oil imports in 2017, reports the U.S. Energy Information Administration. A partnership between the two countries to expand Canada's oil and gas reserves in Alberta has been slowed down again. Efforts over the past decade to build the Keystone XL pipeline to refine tar sands by shipping them through the pipelines between Alberta and U.S. facilities has hit another legal snag. It could delay pipeline construction yet again.
Mexican Pemex's oil output falls 145,000 b/d on year in July amid declines at aging fields — Mexican state oil company Pemex said Monday its oil production dipped 5,400 b/d month on month to 1.840 million b/d in July, and was down 145,000 b/d year on year, due to a decrease in production at mature fields in southern Mexico. Pemex's production has been in constant decline since peaking at 3.4 million b/d in 2004. The company is still mainly responsible for Mexico's oil and gas output as no significant production has been added by private companies since the country ended its state monopoly over the energy sector in December 2013. Production at shallow water fields offshore Tabasco in southern Mexico was down 53,800 b/d year on year at 304,200 b/d in July. Xanab is Pemex's largest field in this region; output there fell 41,900 b/d on year to 120,500 b/d in July. Xanab began production in 2010 and peaked at 175,100 b/d in May 2017. The field still has over 236 million barrels of 2P reserves, according to Mexico's National Oil Commission, and Pemex awarded contracts in the first half of the year to install a new pipeline sand platform in the field. Pemex has said it expects to increase production towards year end to 1.95 million b/d by fast-tracking the development of heavy oilfield complexes Ek-Balam and Ayatsil-Tekel-Utsil in H2. Both groups of shallow water fields are located in Campeche Bay along with the giant Ku-Maloob-Zaap or KMZ and Cantarell complexes. KMZ is Mexico's largest producing asset, responsible for almost half of the country's output. Its production remained stable on month at 876,700 b/d in July, and was up 6,000 b/d on year. The complex is expected to begin terminal decline next year. Pemex plans to reopen a closed well and enhance oil recovery techniques such as water injection at onshore fields like San Ramon and Blasillo in a bid to boost output. Its onshore oil output in southern Mexico fell 42,200 b/d to 227,400 b/d in July. The company's most substantial decrease was for light crude, which fell 148,165 b/d on year to 563,600 b/d in July, impacting the utilization rate at its simple configuration refineries in Mexico.
Mexico’s New Government May Halt Oil Auctions Indefinitely -Mexico’s incoming government is considering indefinitely suspending auctions for oil and gas projects, and giving state-owned Pemex authority to pick its own joint-venture partners rather than holding competitive tenders, according to policy guidelines seen by Reuters. The document, drafted by energy advisers to leftist President-elect Andres Manuel Lopez Obrador, also recommends forging closer ties with leading oil producer cartel OPEC while withdrawing from the International Energy Agency (IEA), which represents the interest of oil-consuming countries. Lopez Obrador aims to boost Mexico’s oil production by a third to 2.5 million barrels per day as well as increase very low refinery processing rates and build at least one new refinery.
Mexico’s Dramatic Energy Reform - Mexico is considering a dramatic policy shift, inserting the state into the energy sector in a major way while also flirting with the idea of moving closer to OPEC.A document seen by Reuters, drafted by advisors to incoming Mexican president Andres Manuel Lopez Obrador (AMLO), proposes withdrawing Mexico from the International Energy Agency (IEA) and moving closer to OPEC.The proposal also calls for scrapping future oil and gas auctions, which would close off Mexico’s oil and gas reserves to international companies beyond what was already awarded. Unlike previous reports, which suggested that AMLO’s government might suspend auctions for two years, the document seen by Reuters calls for an indefinite suspension of new auctions.The move would be a nearly 180-degree turn from the current government of President Enrique Pena Nieto, whose legacy will be defined at least in part by the reforms and partial privatization of Mexico’s energy sector, while stopping short of complete reversal, which would require constitutional changes. Over 100 contracts were inked with international oil and gas companies, and Pena Nieto’s government has said those will pave the way for tens of billions of dollars’ worth of investment.Instead of greater in volvement from oil and gas multinationals, Pemex would return to its former role as the central pillar in Mexico’s energy industry. The state-owned oil company held a monopoly over the country’s oil and gas reserves for seven decades, but has been bogged down under a massive pile of debt. AMLO wants to inject new life into the company and elevate it back into a powerful position, acting somewhat as a gatekeeper for the country’s energy sector by having the ability to make its own decisions about joint venture partners.
Mexico's New President To Deal Blow To Oil Industry --- Mexico will likely halt oil auctions for at least two years, dealing a blow to its oil industry. Mexico’s president-elect Andres Manuel Lopez Obrador (AMLO) will reportedly suspend oil auctions for at least two years, according to the Wall Street Journal, with some experts believing that his administration won’t hold any new oil auctions at all during his six-year term. He has also vowed to review the 107 contracts already awarded to companies through auctions over the last few years to check for corruption, although he has said he would not try to invalidate them so long as they check out.Also, AMLO wants to revise some of the energy laws that govern the oil and gas sector, which could dramatically alter the landscape for foreign oil and gas companies. He long opposed the historic reforms that ended seven decades of state control over the energy sector, although he moderated his position during this year’s presidential campaign. Rolling back the reforms would be exceedingly difficult, requiring a change to the country’s constitution.Instead, AMLO wants more modest, though still significant, legislative changes. The WSJ reports that he will pursue legislative tweaks that bolster the power of state-owned Pemex, while weakening the regulatory body that has pursued a technocratic approach and presided over the oil auctions over the last three years.AMLO’s desired changes include allowing Pemex to choose its own private-sector partners, without needing the approval from regulators. Current rules require Pemex to partner with the highest bidder for blocks put up for a farm-out. He wants the government to be able to award Pemex with oil blocks directly. And he wants to make Pemex the sole marketer of oil produced by private firms, the WSJ reports.These changes would amount to a partial rollback of the energy reforms, re-empowering Pemex and government control over the oil sector. Moreover, as president, AMLO chooses the head of Pemex, granting him a lot of leverage over the company.
Venezuela's main oil port partially operating after tanker hits dock - (Reuters) - Venezuela’s main oil port of Jose is operating partially after a tanker collided with a dock at the weekend, curtailing state-run PDVSA’s ability to export upgraded crude and receive imported diluents, three sources with knowledge of the incident said on Tuesday. PDVSA has been struggling this year to deliver exports on time to most customers because of falling oil output, legal actions by creditors aimed at seizing overseas assets and U.S. sanctions. In July, Venezuela’s crude production fell to its lowest level in over 60 years. Crude exports from Jose were running earlier this year at about 900,000 barrels per day (bpd), according to Thomson Reuters data. Some 60,000 bpd of naphtha imports, which is used to dilute Venezuela’s extraheavy crude for export, also are received at the terminal. The collision shut the South dock, one of Jose Offshore Platform’s three oil berths, East, West and South, used to ship crude from the Orinoco Belt, Venezuela’s main producing region, and to discharge imported diluents, the sources said. Jose also has two monobuoy systems, which continue operating normally. The South dock was refurbished in 2016. The Greek-flagged tanker Meganisi was bringing imported heavy naphtha from the United States when it struck the dock, one of the sources said. PDVSA did not immediately reply to a request for comment. It was unclear how long it will take to repair the damage.
In Brazil, Equinor Aims To Repeat Norway's Oil Boom (Reuters) - Norway's Equinor will invest up to $15 billion in Brazil over the next 12 years to develop oil, gas and renewable energy sources, the company said on Wednesday. Coinciding with an expected drop in output from many ageing oilfields off the cost of Norway, Brazil is expected to become a core region for Equinor as the firm takes advantage of the country's opening in recent years to more foreign investment. The company plans to raise its Brazilian output to between 300,000 and 500,000 barrels of oil equivalent per day (boepd) by 2030, from 90,000 boepd today by developing new fields, including the giant Carcara discovery. "Brazil is a perfect match for Equinor with our operational, technical competence that we have built over decades on the Norwegian continental shelf," said Anders Opedal, Equinor's head of operations in the South American country. The Norwegian oil and gas company has already invested around $10 billion in Brazil since 2001, acquiring stakes in a variety of discoveries and fields. Carcara, estimated to hold similar volumes of oil as Norway's 2.2 billion-3.2 billion barrels Johan Sverdrup discovery, is expected to start production in 2023-24, making it the first time a foreign firm operates a so-called pre-salt field. "We call Carcara our new Johan Sverdrup ... Our portfolio in Brazil will have high value, we see very good break-evens," Opedal said, referring to the oil price levels at which Equinor expects to earn a profit. The Equinor-operated Peregrino II development is on track to start production at the end of 2020, with its break-even price reduced to below $40 a barrel versus the original estimate of $70, he added. Equinor last year took a 25 percent stake in the Roncador field, aiming to boost output by around 500 million barrels over the lifetime of production, equivalent to the size of Equinor's Johan Castberg field in the Barents Sea. The Norwegian company now plans a multi-year drilling campaign to firm up its Brazilian resources, exploration chief Tim Dodson told Reuters on the sidelines of an energy conference.
Fall of the 'Frack Master': apostle who briefed parliament lands in jail - The self-appointed evangelist of the Texas fracking boom launched into a jargon-laced monologue, prompting the chairman of the UK parliament’s Welsh affairs committee to request he speak in plain English. “We’re not technical animals here, most of us,” said David TC Davies, Conservative MP for Monmouth. “So you may need to imagine you’re explaining it to somebody who doesn’t have a scientific oil background.” Chris Faulkner, an intense, balding, bearded figure in a charcoal suit and blue tie, leaned forward and continued. He spent 40 minutes educating MPs about his state’s embrace of hydraulic fracturing, including the marvel of horizontal drilling in urban areas. “We’ve drilled … underneath downtown Fort Worth, underneath hospitals, schools,” he said. In the autumn and winter of 2013, the so-called “Frack Master” was one of 16 witnesses who appeared before the committee, which was considering the economic and environmental impact of drilling potentially thousands of shale gas wells. “Thank you for your answers and general enthusiasm,” Davies told him. In June 2014, the MPs issued a cautiously supportive report that cited Faulkner five times.But Faulkner was not in fact much of a “technical animal” with a “scientific oil background”. According to the US government, he is a fraudster who ran an investment scam worth between $60m and $80m. Hosting websites for oil and gas companies was Faulkner’s only experience with the energy sector before 2009, federal authorities claim. In the mid-2000s, he was an internet entrepreneur listed as the president of a website that sold adult movies and a company called Porn Toys Corp. In June this year, Faulkner was arrested by federal agents as he attempted to board a flight from Los Angeles to London. Charged with securities fraud, mail fraud and illegal monetary transactions, he could face decades behind bars. Deemed a flight risk, he is currently detained in a Texas prison.
Russian gas supplies to Europe up in August, prices remain competitive— Russian gas supplies to Europe and Turkey rebounded in August, according to data released Thursday by gas giant Gazprom, after a dip the previous month during the planned outage of the main Nord Stream gas pipeline to Germany. According to preliminary data cited by Gazprom CEO Alexei Miller, Gazprom's sales in the "Far Abroad" -- Europe plus Turkey but not the countries of the former Soviet Union -- are set to amount to 133.3 Bcm in the first eight months of 2018. Miller, cited by news agency Prime, said supplies in the January-August period were set to rise 5.6% -- or 7 Bcm -- from the same period of 2017. According to S&P Global Platts calculations, this means August supplies are expected at 16.2 Bcm, or an average of 523 million cu m/d. This is the highest monthly average since April, meaning Gazprom gas remains in high demand for power generation and for storage injection in Europe. Gazprom's sales in Europe and Turkey in July averaged 513 million cu m/d, according to Platts' calculations, as the gas giant made up for the two-week Nord Stream outage by selling gas from its European storage facilities and increasing flows via Ukraine. Gazprom supply data classify volumes sold to customers, including from storage, not just physical export volumes. Gazprom's supplies to the Far Abroad hit a new record high of 194.4 Bcm last year, and are on track to break through the 200 Bcm level if current supply rates are maintained. Miller said last month supplies to Europe and Turkey were set to reach the maximum foreseen in all of its contracts combined this year and that total sales could reach "205 Bcm or more." OIL-INDEXED GAS VS But pricing will likely be the most significant factor in determining how much Russian gas is sold in Europe and Turkey over the remainder of 2018. Prices on the main European gas hubs have risen sharply in recent weeks, with the Dutch TTF day-ahead and Q4 prices moving above Eur26/MWh. This means Russian gas with oil indexation -- which still plays an important role in many long-term European gas supply agreements with Gazprom -- remains competitive versus the hubs despite rising sharply itself, according to Platts estimates and the current forward curve.
The Bullish Case For Gas In Europe - European natural gas pricing is amongst the highest seen in recent years, as unseasonably high demand and the long-term ramifications of the pan-European cold snap are priced into the European market.Whilst analysts and traders alike anticipate a strong demand ahead of the coming heating season (Bloomberg), this article is primarily concerned with the overall tightness of the European natural gas market.In contrast to previous years, the Day Ahead price across European hubs has remained strong throughout the summer months, largely due to the previous uncharacteristically cold winter. The past European heating season was amongst the coldest in recent history, with European domestic gas demand responding accordingly, draining natural gas storage facilities throughout Europe. When temperatures eventually recovered, natural gas demand remained robust throughout Europe in order to replenish the storage which had been depleted throughout the cold weather, providing an unseasonably bullish sentiment across the European market. Following this, a pan-European heatwave exacerbated demand throughout July and August, although European LNG still traded at a substantial discount to Asian LNG pricing. The determination of wholesale market prices of natural gas within Europe has historically been driven by two factors; European LNG imports and flexible oil-indexed pipeline gas from Russia and Norway above take or pay levels. Whether LNG imports or Russian gas acts as a price setter within Europe is typically dependent on Asian hub prices. As a rule of thumb, as Asian and European hub pricing diverges, LNG cargoes are drawn away from Europe by arbitrageurs, leaving Russian and Norwegian pipeline gas, indexed to oil or oil products, to act as the price setter. Conversely, weakness in Asian hub pricing pushes LNG cargoes into Europe, displacing pipeline gas as the price setter for marginal supplies in Europe.
Equinor considers constructing a floating wind farm to power North Sea oilfields -- Norwegian energy powerhouse Equinor is investigating the possibility of building a floating offshore wind farm to power oilfields in the North Sea. In a statement Tuesday, the business — formerly known as Statoil — said the project could cut carbon dioxide emissions by over 200,000 tons each year. Equinor said that preliminary capital and development expenditures on the project amounted to around 5 billion Norwegian krone ($602.2 million).
The idea being explored is the creation of an 11-turbine wind farm modeled on Hywind, Equinor's floating offshore wind concept. The world's first floating wind farm, Hywind Scotland, started to send electricity to the Scottish grid last October.The new concept, called Hywind Tampen, would have a combined capacity of 88 megawatts. It's estimated it would meet around 35 percent of the yearly power demand at the Gullfaks and Snorre oilfields."Reducing the use of gas turbines by supplying platforms with power from floating offshore wind is a challenging and innovative project," Pal Eitrheim, executive vice president for New Energy Solutions at Equinor, said. The Gullfaks oilfield is owned by Equinor, OMV and Norway's state-owned Petoro, according to Reuters. The Snorre field is owned by Equinor, Petoro, ExxonMobil, Idemitsu, DEA and Point Resources.
Iran Urges EU To Provide More Oil Purchase Guarantees - Iran’s Foreign Minister has reminded the European Union that Iran is still waiting to receive guarantees that the EU will continue to buy Iranian oil even after U.S. sanctions kick in on November 4, Reuters reports, citing the Iranian Students’ News Agency.Mohammad Javad Zarif said, “We are still waiting for Europe to take action on the sale of Iranian oil and the preservation of banking channels,” highlighting once again the tough choice the European Union is facing. Some, such as President Trump’s national security adviser John Bolton, have put it bluntly: the EU must choose between Iran and the United States. Yet the EU seems loath to make such a crude choice and is trying to maneuver between the two.After triggering legislation known as the blocking statute, which effectively prohibits European companies from complying with third-party sanctions, the EU last week approved an aid package of about US$21 million (18 million euro) for Iran to mitigate the effect of the U.S. sanctions. The package is part of a bigger one to the tune of US$58 million (50 million euro) in a bid to stop Iran from dropping the nuclear deal.Zarif, however, rejected any suggestion that the aid package had anything to do with the nuclear deal: “This is a package that will help both sides have communication with each other and it doesn’t have anything to do with the nuclear agreement and other hype,” he said.Keeping its oil export channel to Europe open is almost as important for Iran as keeping exports to China and India. The matter is quickly becoming urgent as Iraq and Saudi Arabia eye Iran’s market share in Europe and taking over it. An earlier Reuters report this month cited shipping data, which revealed that Iranian oil shipments to Europe had fallen by 35 percent since the start of the year, to 415,000 bpd, while Saudi exports to the EU had doubled and Iraqi shipments had added 30 percent.
Can The U.S. Bring Iranian Oil Exports To Zero? - The U.S. wants Iran’s oil exports to drop to zero, according to a recent statement by National Security Advisor John Bolton. The question is: can the U.S. pull it off?The pressure has been on Iran’s customers since May, to cut their purchases of Iranian oil and freeze out the oil producer, OPEC’s third largest, from the world oil market. The U.S. is re-imposing sanctions on Iran following the U.S. withdrawal from the 2015 nuclear deal, and has threatened secondary sanctions on any country that continues to buy oil from Iran.The campaign has proven effective thus far. In the first half of August, Iran’s oil exports fell by 600,000 bpd, plunging from 2.32 million bpd to 1.68 million bpd. Iran’s exports have been falling all year, and reached their lowest level in four months by July, before taking a real plunge in August.Major customers, including South Korea, have suspended imports. China, despite some defiant posturing in the face of U.S. challenges, scaled back its purchases. While China has given no sign that it will comply with the U.S. directive, reports indicate that it is willing to at least halt any increase in Iranian purchases after sanctions are re-imposed on November 4. But the big cuts were by India, Iran’s second-largest importer, which reduced its purchases from Iran from 706,452 bpd to 203,938 bpd during the August 1-16 period. India has been trying to keep a middle-ground between the U.S. and Iran, as it navigates the new sanctions regime while still preserving access to cheap Iranian oil and gas imports. India imports 80 percent of its energy and Iran is its third-largest supplier. Trade links between Tehran and New Delhi have strengthened in the last several years, but now India faces considerable pressure to cut its ties with Iran as the U.S. seeks to reduce Iranian oil exports to zero. Iran has offered cargo insurance and freedom to use Iranian tankers to India as a way of enticing it to keep buying. If India were to comply with U.S. sanctions, Iran’s oil exports would fall to around 1.5 million bpd. Reports indicate India doesn’t want to cut its purchases completely, and that like China it will continue buying Iranian oil. But India may pivot towards new sources of supply, including American crude, to make up the difference.
Iran says it has full control of Gulf and U.S. navy does not belong there - (Reuters) - Iran has full control of the Gulf, and the U.S. Navy does not belong there, the head of the navy of Iran's Revolutionary Guards, General Alireza Tangsiri, said on Monday, according to the Tasnim news agency. The remarks come at a time when Tehran has suggested that it could take military action in the Gulf to block oil exports of other regional countries in retaliation for U.S. sanctions intended to halt its oil sales. Washington maintains a fleet in the Gulf which protects oil shipping routes.Tangsiri said Iran had full control of both the Gulf itself and the Strait of Hormuz that leads into it. Closing off the strait would be the most direct way of blocking shipping."We can ensure the security of the Persian Gulf and there is no need for the presence of aliens like the U.S. and the countries whose home is not in here," he said in the quote, which appeared in English translation on Tasnim.Tension between Iran and the United States has escalated since President Donald Trump pulled out of a 2015 nuclear deal between Iran and world powers in May and reimposed sanctions.Senior U.S. officials have said they aim to reduce Iran's oil exports to zero.Iran's Supreme Leader Ayatollah Ali Khamenei, the most senior authority in the Islamic Republic, said last month that he supports the idea that if Iran is not allowed to export oil then no country should export oil from the Gulf.
Confusion Looms As Iran Claims Control Over Key Oil Waterway - A Reuters headline early Monday sparked fears that Iran could be in control of the Strait of Hormuz, a key narrow waterway in the Persian Gulf through which about one-third of the global supply of oil passes. Reuters reported in its story headline, Iran says it has full control of Gulf and U.S. navy does not belong there, while citing the head of the navy of Iran's Revolutionary Guards (IRGC), General Alireza Tangsiri.According to the report, "Tangsiri said Iran had full control of both the Gulf itself and the Strait of Hormuz that leads into it," and further cited the general as saying, "Closing off the strait would be the most direct way of blocking shipping". "We can ensure the security of the Persian Gulf and there is no need for the presence of aliens like the U.S. and the countries whose home is not in here," General Alireza Tangsiri said in the quote, which appeared in English translation via Iranian state media. This sparked subsequent reporting that Iran had effectively blocked the strait; however, a FOX story noted, "A check of conditions on MaritimeTraffic.com on Monday showed that conditions appeared to be normal, with heavy maritime traffic through the strait." Secretary of State Mike Pompeo responded Monday night: "The Islamic Republic of Iran does not control the Strait of Hormuz. The Strait is an international waterway. The United States will continue to work with our partners to ensure freedom of navigation and free flow of commerce in international waterways."But the elite IRGC naval commander's words are likely to raise tensions with Washington further, after prior remarks from both President Rouhani as well as other IRGC generals in early July suggesting that should White House sanctions seek to devastate Iranian oil exports, then no oil at all should pass through the area. The Monday statement from General Tangsiri appears to be a reaffirmation Iran's prior position of possessing sole "rights" over the strait. The United States for its part, has maintained a fleet in the Gulf seeking to protect oil shipping lanes even as Iran has ratcheted up military "show of force" exercises of late.
OPEC to discuss compensating for Iranian supply drop after U.S. sanctions (Reuters) - OPEC will discuss in December whether producers can compensate for a sudden drop in Iranian oil supply after U.S sanctions against Tehran start in November, the head of Iraq’s state-oil marketer SOMO, Alaa al-Yasiri, told Reuters on Wednesday. Yasiri said a sudden drop in Iran oil exports will have a negative impact on prices and market fundamentals. “A sudden drop in Iranian crude shipments from the market will cause big shortages and a negative impact on oil prices,” he said, referring to a possible increase in prices. “It’s very difficult to predict what’s going to happen in next OPEC meeting but producers must find ways to make up for Iranian crude that the market will lose.” “The major issue during next OPEC meeting will be are producers really ready to pump more oil to compensate Iran’s share,” he added. Iraq has resumed crude shipments to Iran from its Kirkuk oil fields following a few days stoppage due to logistical issues, he said, adding that so far Iraq had only shipped 500,000 barrels and hopes to ship a total of 1 million before the November U.S. sanctions against Iran kick in. SOMO is studying a request from Jordan to resume crude supplies of 10,000 to 15,000 barrels per day via trucks, Yasiri said, and the Jordanian energy minister is expected to visit Baghdad to finalize the deal. Iraq’s August crude oil exports are nearing 3.595 million barrels per day, the SOMO chief said. Saudi Arabia and Russia have recently increased crude supplies, but it hasn’t affected the market because customers needed the extra barrels, he said. Analysts have been uncertain about Iraq’s ability to raise production quickly, amid investment constraints and hold-ups that have seen Royal Dutch Shell Plc exit one of the country’s biggest oil projects.
OPEC, non-OPEC seek to formalize oil policy coordination: draft charter (Reuters) - OPEC and non-OPEC oil producers will aim to formalize their long-term cooperation later this year by approving a charter that will make possible further joint action on output, according to a draft charter seen by Reuters. Russia and several other non-OPEC countries have joined OPEC producers in reducing oil output since 2017 in a move that has helped raise oil prices to $80 per barrel from less than $30. Moscow and Riyadh have said they want to maintain a close level of cooperation even after the oil market stabilizes and the current output reduction deal expires. The draft charter, to be discussed by OPEC and non-OPEC minister later this year, said its fundamental objective is to coordinate policies aimed at stabilizing oil markets in the interest of producers, consumers, investors and the global economy. The charter also aims to promote better understanding of oil market fundamentals among participants as well as to promote oil and gas in the global energy mix for the long term. It said ministers of participating countries shall meet once a year while experts should meet twice a year. The ministers shall propose actions including possible summits by heads of state. The charter’s secretariat will be hosted by the OPEC secretariat in Vienna but will be independent.
Iraq ready to boost oil exports once OPEC gives green light = Iraq sees a need to increase crude exports and says it’s ready to ship more as soon as OPEC agrees how members will share a collective supply boost, according to the acting director-general of the state-run Oil Marketing Co. Exports will be close to 3.595 million barrels a day this month, Alaa Al-Yasiri said Wednesday in an interview in Baghdad. That would be a record, he said, up from 3.54 million barrels a day in July. OPEC and allies agreed two months ago to increase oil production, with Saudi Arabia and Russia saying about 1 million barrels a day will be added to the market. But they didn’t detail how the production increase would be split between OPEC and non-OPEC nations. A committee of OPEC and allies is scheduled to meet in Algeria next month to discuss allocations.
Rival Libyan militias vying for control of Tripoli reach truce -- A truce has been reached between rival militias in Tripoli after a deadly face off saw five killed and over 30 wounded on Monday. Clashes broke out early on Monday in Libya’s capital city as competing authorities continue to vie for power in the country. Rival militias linked to the UN-backed Government of National Accord (GNA) in Tripoli exchanged gunfire in the south of the city. The fighting pitted the Seventh Brigade from the town of Tarhuna - to the southeast of Tripoli - against a coalition of armed brigades working under the interior ministry, including Misrata’s 301 Brigade, and the Ghnewa Brigade. The capital is an important target for warring sides in the region, offering control over strategic assets such as the Libyan Central Bank, the air and sea ports in the city, as well as all other institutions. Guma el-Gamaty, a Libyan academic and analyst, told Middle East Eye on Tuesday: “Tripoli is important because it is where key institutions concerned with budgets and money are located.” The Seventh Brigade has been stationed in the southeastern Gasir Benghashir district of Tripoli for over year, operating under the GNA’s defence ministry. “Some militias are flexing and using their military power to exploit such institutions for financial gains,” Gamaty said, adding that fighting between militias for Tripoli should be seen with this in mind as they are looking to access “easy money.” The GNA has relied on local militias to enforce law and order in the capital, as the UN-backed government has been unable to find a solution to the widespread arms in the country. Armed militias are in control of the airport. The GNA, as well as other transitional authorities, has tried and failed to integrate the armed forces into a regular army, relying on militias to ensure the capital’s security.
JKM Weekly: October LNG prices strong on supply outage, strong crude, NBP — Asian spot benchmark Platts JKM prices ended the week August 24 at $11.484/MMBtu for October deliveries, up 25.9 cents/MMBtu week on week, on strong crude oil and NBP prices, as well as supply outages. Stronger crude and NBP prices across the week hoisted price expectations. Dated Brent crude prices rose $4.435/b across the week to end the week at $75.06/b. This significantly softened oil-slope equivalent levels from the high-15% at the start of the week to the low-15%. Across the week, oil-slope equivalent levels softened and came in slightly below the top end of the seasonal average range. However, oil-slope levels in the low-15% start the week August 27 at the top end of the seasonal average range. NBP month-ahead and two-month ahead prices both rose approximately 38 cents/MMBtu, narrowing the arbitrage gap to Northeast Asia to slightly below $3/MMBtu. Supply side issues were significantly supportive across the week. In Russia, Sakhalin LNG experienced a one-train production outage, project operator Sakhalin Energy confirmed. Market participants had earlier in the day Thursday, reported a possible one-train outage at Train 1 on August 20, with potential scheduling delays as well as potential production losses.Market participants had also reflected that possibly one to three cargoes might have been secured on the prompt by an equity holder as well as an offtaker but details remained scarce.In the Atlantic, market participants reported potential production issues at Sabine Pass LNG and Cove Point LNG, but were however, unsure of the extent of the impact on the market. All eyes in the Pacific remain set on forward winter price expectations. Vitol Asia issued the first firm December bid on August 21, seeking a December 1-5 delivery into Japan or South Korea at $12.10/MMBtu. The trader subsequently submitted a firm bid on August 24 for December 1-5 delivery into Japan, South Korea, China or Taiwan at $12.70/MMBtu.
Thailand's exports of most oil products rise in Jul; heavy fuel oil exports dip — Thailand exported more automotive diesel, naphtha and jet fuel in July, but reduced shipments of heavy fuel oil, the Customs Department's latest data showed. During the month, the country exported 88,906 b/d of automotive diesel, up 54.7% year on year, mainly to Vietnam, Cambodia and Laos. It exported 55,427 b/d of naphtha, more than 3.5 times higher than a year ago; and 21,335 b/d of jet fuel, up 71.3% year on year. Thailand exported 61,290 b/d of heavy fuel oil in July, down 1.4% year on year, mostly to Singapore and Cambodia. Thailand's shipments of automotive diesel, jet fuel, heavy fuel oil and naphtha all rose in the first seven months compared with a year ago. According to data from the Energy Policy and Planning Office released on August 12, the country's domestic consumption of oil products in the first half of 2018 climbed 2.7% year on year to 1.16 million b/d. Currently, Thailand has a total refining capacity of 1.234 million b/d, unchanged from 2017, the data showed.
India is set to overtake China as the top driver of global oil demand growth - India is set to overtake China as the biggest source of growth for oil demand by 2024, according to a forecast announced Monday by research and consultancy group Wood Mackenzie. The country's oil demand is set to increase by 3.5 billion barrels per day from 2017 to 2035, which will account for a third of global oil demand growth. India's expanding middle class will be a key factor, as well as its growing need for mobility, according to Wood Mackenzie. On the other hand, China — currently the second-largest oil consumer in the world — may soon need less oil. In 2017, it overtook the U.S. as the biggest importer of crude oil, but it's set to see a decline in oil demand growth from 2024 to 2035, Wood Mackenzie Research Director Sushant Gupta told CNBC. That's due to two trends: Alternative energy sources such as electricity and natural gas are displacing the need for gasoline and diesel. And, a more efficient freight system and truck fleet will also result in sluggish road diesel demand, Gupta said. For India, as demand grows, an oil shortage is already imminent. The country is only expected to add 400,000 barrels per day in firm refinery capacity out to 2023 — paling in comparison to demand growth — warned Wood Mackenzie. "We think the most likely situation is that India would need between (3.2 million and 4.7 million barrels per day) of new capacity out to 2035 to remain self-sufficient in transport fuels. So we are talking about a future capacity which is 1.7 to 2.0 times the current. This is clearly an uphill task, unless domestic refiners can commit to their planned capacity additions," Gupta said in a Wood Mackenzie release accompanying the India demand projection.
India expects clarity on Iran oil cut after U.S. meeting: source (Reuters) - India will not completely halt Iranian oil imports and will finalize its strategy on crude purchases from Tehran after a meeting with top U.S. officials next week, a senior government official said. U.S. Secretary of State Mike Pompeo and Defense Secretary Jim Mattis will hold high-level talks with India’s Foreign Minister Sushma Swaraj and Defence Minister Nirmala Sitharaman on Sept. 6, in what is known as a 2+2 dialogue. “Definitely we are not going to zero” (purchases), said the official, who has direct knowledge of India’s oil purchase policy and did not wish to be identified. When asked if more clarity on India’s Iranian oil purchases would emerge after the dialogue, the official said “yes, that is the highest level of meeting we will have with the U.S.” The United States is pushing all countries to halt oil imports from Iran after President Donald Trump withdrew from a 2015 deal between Iran and six world powers and ordered a re-imposition of sanctions on Tehran. India, Iran’s top oil buyer after China, has so far not decided on the size of any cut to Iranian imports and continues to seek a waiver from the United States. Trump has threatened that anyone trading with Iran will not do business with America. U.S. sanctions on Iran’s energy sector are set to be re-imposed after a 180-day “wind-down period” ending on Nov. 4. Several countries that were involved in the 2015 nuclear deal had attempted to lessen the blow of fresh sanctions on Iran, and urged their firms not to pull out. But that has proven difficult: several European companies have cut ties with Iran, arguing they cannot risk losing their U.S. business as the sanctions deadline approaches. India has already asked its refiners to prepare for a drastic reduction in imports of crude from Tehran from November, sources told Reuters in June. New Delhi has so far not committed to complying fully with the new U.S. sanctions, but is prepared to cut Iran oil imports to protect its wider exposure to the U.S. financial system. During the previous round of sanctions, India was one of the few countries that continued to buy Iranian oil, although it had to reduce imports as shipping, insurance and banking channels were choked off due to the European and U.S. sanctions.
Top US, India officials to discuss Iran sanctions waiver next week in New Delhi — High-level talks between the US and Indian governments next week in New Delhi will likely include discussion of India's request to continue importing some Iranian crude oil after US sanctions resume in November. As one of Tehran's top oil customers, India's post-sanctions import plans will play a major role in how much Iranian exports drop in the coming months. India recently signed its first term contract for US crude exports to lock in low prices, a topic that might also come up during the meeting between the US and Indian defense and foreign ministers. "We have been discussing regularly with India issues related to both Iran and [US sanctions against Russia] and are looking, as with other partners, to identify ways to cooperate to support our policy goals with regard to both those issues," a senior State Department official said Thursday during a background briefing, on condition of anonymity. Iran is already seeing its oil exports fall ahead of the November 5 resumption of US secondary sanctions as a result of President Donald Trump pulling the US out of the Iran nuclear deal in May. S&P Global Platts Analytics estimates Iranian crude and condensate exports will fall to 1.47 million b/d in November, a cut of 1.44 million b/d from April levels and a cut of 874,000 b/d from July. US Secretary Mike Pompeo and Defense Secretary Jim Mattis will meet their Indian counterparts External Affairs Minister Sushma Swaraj and Defense Minister Nirmala Sitharaman during the "2+2 ministerial dialogue" on September 6. The State Department would not say if India has formally requested a waiver to the Iran sanctions in exchange for making significant cuts to its Iranian imports, but one of the senior officials said the two countries have engaged frequently on the issue in recent weeks.
Japan remains firm on seeking US exemption for Iran oil imports: top official — Japan remains firmly committed to seeking US exemption for Iranian oil imports as it sees the supplies as important for the country's energy security and businesses, a top government official told S&P Global Platts on Thursday. "Japan's position remains firm even after the second round of talks [with the US government]," Ryo Minami, the director-general of oil, gas and mineral resources at the Ministry of Economy, Trade and Industry said in an interview. "Our basic principle is to seek an exemption [from the US]," Minami said. Asked whether Japan was also looking to reduce its Iranian oil imports in order to secure US sanction waivers, Minami declined to comment. Japan and the US held a second round of talks on the US' Iran sanctions in Washington over August 1-2, when the two sides agreed to continue bilateral discussions. "During the second round of talks Japan clearly explained its position to continue [Iranian oil] imports to the US in an effort to gain their understanding," Minami said. "Looking forward, we will inevitably have to hold talks with the US government solidly to obtain their understanding," he said. "From the Japanese perspective, we see the import of Iranian crude oil as necessary to continue Japan's energy security, as well as considering the impact on Japanese companies."
More than 30% of global maritime crude oil trade moves through the South China Sea – EIA - The South China Sea is a major trade route for crude oil, and in 2016, more than 30% of global maritime crude oil trade, or about 15 million barrels per day (b/d), passed through the South China Sea. More than 90% of crude oil volumes flowing through the South China Sea in 2016 transited the Strait of Malacca, the shortest sea route between suppliers in Africa and the Persian Gulf and markets in Asia, making it one of the world’s primary oil transit chokepoints. In addition, a significant amount of crude oil (about 1.4 million b/d) passes through the strait on its way to Singapore and the west coast of Peninsular Malaysia, where it is refined before transiting the South China Sea in the form of petroleum products. The South China Sea is a major trade route for the Middle East, which accounted for more than 70% of total South China Sea crude oil shipments in 2016. Saudi Arabia is the largest source of crude oil, making up almost one-fourth of crude oil volumes traversing the South China Sea. More than half of Saudi Arabia’s global crude oil shipments traveled through the South China Sea in 2016. Before the lifting of United Nations sanctions on Iran’s crude oil exports in January 2016, Iran relied heavily on Asian markets for most of its exports. After the sanctions were lifted, Iran could once again export crude oil to Europe. However, the South China Sea route still accounted for 52% of Iran’s crude oil exports in 2016. In addition to Middle Eastern and North African volumes, some regional countries bordering the South China Sea contribute to the overall shipments of crude oil through the region. Indonesia and Malaysia together accounted for 5% of crude oil loadings that passed through the South China Sea in 2016 and 2% of crude oil receipts. Most of the crude oil from these countries that passes through the South China Sea is exported to other countries. However, some intra-country trade also crosses the southern portion of the South China Sea as cargoes move between eastern and western ports within each country. The three crude oil importers with the largest volumes passing through the South China Sea—China, Japan, and South Korea—collectively accounted for 80% of total crude oil volumes transiting the South China Sea in 2016. About 90% of China’s 2016 maritime crude oil shipments were transported through the South China Sea. China’s crude oil imports have increased substantially over the past few years as a result of the country’s robust energy demand growth and stagnant crude oil production, and the country recently surpassed the United States as the world’s largest crude oil importer.
China's Falling US Crude Imports May Have More To Do With Money (Reuters) - One of the side effects of President Donald Trump's escalating trade dispute with China is that U.S. exports of crude oil to the world's biggest importer are now viewed through the prism of politics. However, this ignores that buyers and sellers of crude are generally more motivated by profit margins and getting the right grades of oil to maximise the productivity of their plants. While it's true they can't disregard politics, and this is especially the case for the state-controlled Chinese majors, it's worth looking at the economics of the U.S.-China crude trade as well. U.S. crude exports to China appear set to slow dramatically in September, with vessel-tracking data compiled by Thomson Reuters Oil Research and Forecasts showing about 6.12 million barrels, or about 204,000 barrels per day (bpd), scheduled for arrival. This would be down from around 363,000 bpd in August, and would also be the weakest month since March this year. The slowdown in China's imports of U.S. crude has coincided with the imposition of tit-for-tat trade tariffs and speculation that Beijing would add crude to its list of U.S. products to be hit with import taxes. That hasn't happened yet, although it would have been understandable for Chinese refiners to be wary of buying from the United States in recent weeks. However, the pricing of the various grades of crude oil also offers an explanation as to why China stocked up on U.S. crude in August, and appears to have shied away in September, and probably October as well. Chinese traders would have been keen to buy West Texas Intermediate (WTI) types of U.S. crude for August delivery, given these cargoes would have been arranged in late May and early June. The discount of front-month WTI crude oil futures to Brent futures widened to $11.39 a barrel on June 6, and traded close to level for around a three-week period from late May to mid-June. This means that Chinese refiners could buy WTI at a substantial discount to Brent in the paper market, which would encourage them to take physical cargoes from the U.S. Gulf.
China's July oil product consumption rises 7% on year: NDRC — China's consumption of oil products rose 7.2% year on year to 27.54 million mt in July, data released Tuesday by the National Development and Reform Commission showed. The growth was mainly led by gasoline demand, which rose 14.1% year on year, while gasoil consumption was only up 1.4% year on year, NDRC said, without providing a breakdown of volumes for the two grades. July oil product consumption was also up 7.6% from June, according to S&P Global Platts calculations based on the NDRC data. Gasoline consumption rose in July as higher temperatures boosted demand for car air conditioning, market sources said. Meanwhile, gasoil consumption was still lackluster last month as outdoor projects and transportation was affected by the hot and wet summer season, sources noted. The country processed 48.65 million mt of crude oil in July, up 7.6% year on year, NDRC data showed. As a result of the higher crude throughput in July, the country's oil product output rose 9.7% year on year to 30.43 million mt in the month, according to NDRC. Meanwhile, China produced 15.57 million mt of crude oil in July, down 4.4% year on year, it added. Over January-July, China processed 342.53 million mt of crude, up 6.8% year on year, while its oil product output rose 8.8% at 213.76 million mt, NDRC's data showed. China's oil product consumption was up 5.8% year on year at 185.49 million mt over the same period, of which gasoline consumption rose 6% year on year while gasoil increased 4.7% on the year, NDRC said, without providing a breakdown of volumes for the two grades. The growth of oil product consumption was slower than that of oil product output in the past seven years, which implies more oil product was exported or went into storage, according to market sources.
Water pollution lays waste to Iraq's oil-rich south - Sitting in an emergency ward in Basra, along with patients on drips suffering from severe diarrhoea, Younes Selim said he had no choice but to drink from the tap despite knowing the risk."We only give mineral water to our three children, but my wife and I often have to drink tap water," he told AFP, waiting for one of the hospital's overwhelmed doctors to treat him.Since August 12, "more than 17,000 patients have been admitted for diarrhoea, stomach pains and vomiting," said Ryad Abdel Amir, head of Basra's health department He said that in his 11 years in the job he has never before seen such a crisis, which has been exacerbated by a lack of public services and rising prices. Umm Haydar said she also struggles to provide drinking water for her family of 30."A thousand litres cost 20,000 dinars ($17) and once we have all drunk and washed the children, in half an hour there's nothing left," the grandmother said.Until recently, the same amount of water cost 5,000 dinars. While Iraq's water shortages are not just confined to Basra, the region suffers from a toxic mix of polluted and salty water, dismal public services, power cuts and open sewers.The province has abundant energy resources and Iraq's only stretch of coastline, but it is also heavily populated and has creaking infrastructure. It has been shaken by weeks of protests over the lack of basic services, despite government pledges to pump billions of dollars into the neglected south.
OPEC And Allies Further Eased Oil Production Cuts In July - OPEC and its Russia-led non-OPEC partners in the production cut deal reduced their total oil production in July by 9 percent more than what they had agreed upon, Reuters reported on Monday, citing two sources familiar with the findings of an OPEC/non-OPEC monitoring committee on compliance.The committee—consisting of representatives from the two leaders of the OPEC and non-OPEC groups, Saudi Arabia and Russia, respectively, as well as from Kuwait, the UAE, Algeria, Venezuela, and Oman—found on Monday that total production was just 9 percent above the agreed upon compliance of 100 percent, and compares with a compliance rate of 120 percent in June and an overzealous 147 percent in May, so the parties to the pact have been raising production, according to Reuters.In June, OPEC and its non-OPEC partners agreed to work toward an overall conformity level of 100 percent as of July 1, 2018, compared to the 147-percent compliance rate in May. OPEC-only production in July rose by 40,700 bpd from June, to 32.323 million bpd, according to secondary sources in the cartel’s Monthly Oil Market Report. While falling production in Libya and Iran was not so surprising, Saudi Arabia’s production dropped in July by 52,800 bpd from June to average 10.387 million bpd last month, according to OPEC’s secondary sources. Some analysts attributed the lower Saudi production to a lower than previously expected demand for Saudi crude. While OPEC and allies report on their overall compliance levels, the two archrivals in the Middle East and major oil producers within the cartel—Saudi Arabia and Iran—have quite different views on what the vague June agreement actually means. The Saudis say that it implies a redistribution of quotas with individual caps on production, along with a collective 100-percent compliance rate. Iran, however, insists that no country can compensate for others. Last week, Iran warned OPEC that “no country can overtake the production and export quotas of other member states under any circumstances,” while Iran’s Oil Minister Bijan Zanganeh was quoted as saying that “Some members are interpreting the latest OPEC decision on oil output differently ... and are acting in accordance with the policies of the U.S.”
Bullish hedge fund managers continue to pull oil positions (Reuters) - Hedge fund managers continued to liquidate their bullish positions in crude and fuels, amid negative sentiment towards petroleum, before prices rallied sharply in the second half of last week. Hedge funds and other money managers cut their combined net long position in the six most important petroleum futures and options contracts by another 49 million barrels in the week to Aug. 20. Fund managers have reduced their net long position in 13 of the last 18 weeks, by a total of 508 million barrels (36 percent), according to an analysis of records published by regulators and exchanges. Total long positions have been slashed by 494 million barrels, while short positions have increased by 14 million barrels, since April 17 (https://tmsnrt.rs/2LyoJY3 ). As a result, portfolio managers' combined net long position in petroleum has been cut to just 903 million barrels, the lowest for almost a year. And the ratio of long to short positions has fallen from almost 14:1 to just over 8:1, leaving the market looking much less lopsided than before. The most recent week saw continued liquidation of net length in Brent (-12 million barrels), NYMEX and ICE WTI (-16 million), U.S. gasoline (-10 million), U.S. heating oil (-6 million) and European gasoil (-5 million). As in previous weeks, most of the changes came from the long side of the market, with fund managers trimming old bullish long positions rather than adding new bearish short ones. But there was a notable increase of 15 million barrels in short WTI positions on NYMEX, the largest one-week rise for 10 months.
Crude Oil Prices Settle Higher, but Rising Production Limits Gains - - WTI crude oil prices settled higher Monday, but gains were kept in check by rising oil output from major producers as market participants awaited updates on supply this week. On the New York Mercantile Exchange crude futures for October delivery gained 15 cents to settle at $68.87 a barrel, while on London's Intercontinental Exchange, Brent rose 0.45% to trade at $76.47 a barrel. Members of an OPEC and non-OPEC monitoring committee revealed producers, part of the production-cut agreement, reduced their oil output cuts in July. Opec and non-OPEC members achieved a 109% compliance rate with the production-cut agreement, below the 120% rate seen June, when OPEC and non-OPEC members agreed to return to 100% compliance with oil output cuts that began in January 2017. OPEC's efforts to return to agreed production limits have been stifled by production disruptions in Libya and Venezuela. The pledge to return to agreed production limits was brought on by fears that U.S. sanctions against Iran's oil exports would pressure already low global spare capacity, which would likely fuel an oil price increase, hurting demand. President Donald Trump pulled the United States out of the Iran nuclear agreement in May, allowing sanctions against Iran to snap back into place. The first wave of sanctions went into effect last month and a second set of sanctions on Iran's crude exports are slated for early November. The outlook on oil demand has also been rattled amid investor fears a further deterioration in U.S.-China trade relations could spark a full-blown trade war. This could force China, the world's largest oil importer, to cut crude purchases as its economy would likely face further pressure. U.S. oil prices added to gains from last week when they ended a string of weekly declines on lower U.S. oil inventories and a decline in the Baker Hughes weekly oil rig count, pointing to tightening U.S. output. Baker Hughes reported on Friday that the number of U.S. oil drilling rigs in operation fell by 9 to 860. Analysts continued to tout a bullish outlook on oil, citing the U.S. oil price's ability to remain above $65 a barrel during declines earlier this month. "Crude oil prices have successfully held the $65-dollar range (WTI) and are now poised to test the higher end of the trading range," Spartan Capital said. "We look for prices to move back to the low $70 range with Brent spiking towards the $80 range."
Oil prices rise on expectations of market tightening -- The oil price rose towards its highest since early July on Tuesday, thanks to evidence of still-modest increases in output from OPEC and improving Chinese refining demand.Brent crude oil futures were at $76.65 a barrel by 0913 GMT, up 44 cents from their last close and at their highest since July 11, while U.S. crude futures were up 17 cents at $69.04 a barrel.The monitoring committee of the Organization of the Petroleum Exporting Countries (OPEC) found that oil producers participating in a supply-reduction agreement, which includes non-OPEC member Russia, cut output in July by 9 percent more than called for.Investors are now more confident that supply is likely to fall short of demand in the coming months, as reflected by a narrowing in the discount, or spread, between the October and November Brent futures contracts to around 26 cents a barrel, half of what it was a month ago."We were of the view earlier that we are expecting prices to edge a bit lower over the rest of this year, but I struggle to see that. I see the market remaining well supported, with potential shocks to the upside, depending on what we get from Iran," ING commodities strategist Warren Patterson said."Looking at the spreads, it is starting to appear that the market (balance) is somewhat tightening."When the price of a prompt contract is at a premium to the price of a longer-dated contract this indicates a belief that oil demand will outpace supply. The findings of the OPEC monitoring committee for last month compare with a compliance level of 120 percent for June and 147 percent for May, meaning participants have been steadily increasing production, but at a more modest pace than some had expected.
Oil Prices Edge Lower Despite Reports of Supply Disruptions - Oil prices edged lower on Tuesday despite the International Energy Agency (IEA) warning of further supply disruptions. Brent Oil Futures for November delivery went down 0.03% to $76.48 at 12:42AM ET, while Crude Oil WTI Futures for October delivery also slipped 0.04% to $68.84. On Monday, the IEA warned an economic crisis in Venezuela has cut deep into the OPEC-member's oil output. Venezuelan crude oil exports have halved in the previous two years to just 1 million bpd by mid-2018, according to trade flow data. "We can expect a further fall," the IEA's Executive Director Fatih Birol told Reuters in Norway on Monday. Birol also warned that African OPEC-members Libya and Nigeria "seem both still fragile countries" despite some recent improvements. However, Birol said it was too early to assess any potential impact of the U.S. sanctions that will target Iran from November. “The weaker U.S.-dollar helped commodities in general," Traders also await further developments in the China-U.S. trade relations. The two-day trade talks between China and the U.S. ended last week with no major breakthroughs. "We concluded two days of discussions with counterparts from China and exchanged views on how to achieve fairness, balance, and reciprocity in the economic relationship," White House spokeswoman Lindsay Walters said in a brief statement. Meanwhile, a new round of U.S. tariffs on $16 billion worth of imports from China kicked in last week, followed immediately by reciprocal tariffs from China.
Oil dips on profit-taking, trade deal limits decline (Reuters) - Oil prices fell on Tuesday as some investors took profits on recent strong gains, but losses were limited the day after a U.S.-Mexico trade agreement eased worries about tensions between the two countries. Brent crude LCOc1 futures fell 26 cents to settle at $75.95 a barrel. The global benchmark touched $76.97 early in the session, the highest since July 11. U.S. West Texas Intermediate (WTI) crude CLc1 futures fell 34 cents to settle at $68.53 a barrel. Last week Brent marked a 5.6 percent gain, while WTI increased 4.3 percent. “The market was due for a correction,” said Phillip Streible, senior market strategist at RJO Futures. Oil prices extended losses slightly in post-settlement trade after industry group the American Petroleum Institute said that U.S. crude inventories rose unexpectedly by 38,000 barrels last week to 405.7 million. Analysts had expected a decrease of 686,000 barrels. Official weekly stock data is due at 10:30 a.m. EDT (1430 GMT). News that workers at Total’s North Sea oil platforms no longer plan to strike on Sept. 3 also weighed on the market. Limiting losses, however, was Monday’s news that the United States and Mexico agreed to overhaul the North American Free Trade Agreement (NAFTA). “It paves the way for the energy industry in both countries to coexist rather freely, and that should be good for demand,”
WTI Dips After Surprise Inventory Builds Across-The-Board - WTI closed lower on the day as the USD ticked up ahead of API inventory data that showed inventory builds across the board, sending prices marginally lower.API
- Crude +38k (-1.49mm exp)
- Cushing +130k (+50k exp)
- Gasoline +21k
- Distillates +982k
The flip-flopping crude draw/build continued last week with an unexpected build. In fact we saw builds across the board... WTI dipped on the unexpected builds across the board...“The market is shaking off some of the excitement of the Mexico free trade deal,” said Phil Flynn, senior market analyst at Price Futures Group Inc. in Chicago.Also, “there is a concern that maybe we’ll see an increase in inventories today as opposed to the expectation of a slight draw. People are all over the board on this inventory report.”
Crude futures trend higher, unaffected by API stock build - — The crude complex was trending higher on Wednesday morning in early European trading, despite US crude inventory data showing a build in stocks, with the market likely more focused on tightened market fundamentals, analysts said. At 1110 GMT, ICE October Brent crude futures were up 24 cents/b from Tuesday's settle at $76.19/b, while the NYMEX October light sweet crude contract showed an increase of 34 cents/b to $68.87/b.Oil prices were initially lower on Tuesday and during Asian trading hours, following the release of American Petroleum Institute weekly numbers, which showed a small but unexpected build of 38,000 barrels versus the previous week. However, the dip was shortlived, with levels rising from the beginning of European trading hours. The more definitive numbers from the US Energy Information Administration will be published later Wednesday.According to a survey conducted by S&P Global Platts Monday, analysts were divided on crude inventory levels, with some expecting a drawdown of 3 million barrels or more for the week to August 24, while other expected a slight build.On average, however, analysts were expecting a 1 million barrel crude draw in US inventories."That data doesn't seem to have done much but we'll see more official figures later -- after last week's massive drawdown, it will be interesting to see what happens," said Geordie Wilkes, commodity analyst at Sucden Financial in London.On the supply side, the approaching deadline for Iranian oil sanctions continues to provide a floor for the market, said analysts."The Iranian wildcard continued to keep selling pressures in check. A general consensus is emerging that Iran's oil shipments are losing momentum at a faster-than-expected clip ahead of November's deadline," said Stephen Brennock, in the PVM Fundamental report on Wednesday, adding that further declines are "pencilled in."
Oil Prices Hold Firm Ahead Of US Inventory Report – RTTNews - Oil markets held steady on Wednesday as signs of falling supplies from Iran ahead of U.S. sanctions were offset by rising non-OPEC oil production. Benchmark Brent crude oil futures were up 16 cents at $76.45 per barrel while U.S. West Texas Intermediate (WTI) crude futures were up 25 cents at $68.78 a barrel. With U.S. sanctions against Iran set to begin in November, market participants expect Iranian oil exports to drop at a faster-than-expected pace. Imports by its key customers have all dropped in August as many crude buyers reduced orders, fearing Washington's penalties. Political instability in Venezuela has also triggered expectations of a tightening global oil market. Meanwhile, according to Bank of America Merrill Lynch, supply outages from non-OPEC countries are expected to be resolved soon with Canada's Syncrude facility bringing production back online. A new agreement between Sudan and South Sudan on a peace deal as well as production increases expected in Canada, Brazil and the U.S. will add new supply in the second half of 2018, BofAML wrote in a note. After the American Petroleum Institute (API) reported a surprise oil inventory build for the week ending August 25, the official data on U.S. inventory levels is due for release by the Energy Information Administration (EIA) later in the day.
Oil prices stabilize on Iran sanctions and rising global supply - Oil prices rose on Wednesday, supported by news of a fall in Iranian crude supplies as U.S. sanctions deter buyers, but gains were limited by evidence of a rise in U.S. inventories. Benchmark Brent crude oil rose 36 cents to $76.31 a barrel by 10:20 a.m. ET (1420 GMT). U.S. light crude was 52 cents higher at $69.05 a barrel.Iran's crude oil and condensate exports in August are set to drop below 70 million barrels for the first time since April 2017, well ahead of the Nov. 4 start date for a second round of U.S. economic sanctions, preliminary trade flows data on Thomson Reuters Eikon show.Bowing to pressure from Washington, many crude buyers have already reduced orders from Iran, OPEC's third-biggest producer.Although Tehran is offering steep discounts, Iran's August crude oil and condensate loadings are estimated at 2.06 million bpd, versus a peak of 3.09 million bpd in April."U.S. sanctions towards Iran are now increasingly kicking in which will help to dry up the physical crude oil market," said SEB Markets commodities analyst Bjarne Schieldrop.U.S. crude inventories rose by 38,000 barrels to 405.7 million barrels in the week to Aug. 24, the American Petroleum Institute said on Tuesday. Official U.S. fuel inventory and crude production data will be published later on Wednesday by the Energy Information Administration (EIA).
WTI Spikes On Surprise Crude Draw As Gasoline Demand Hits Record High - WTI rallied overnight, in the face of dollar gains, as Iran supply fears reignited, dominating API inventory builds across the board, and spiked notably after DOE reported a bigger-than-expected 2.566mm crude draw.But bear in mind that seasonal refinery maintenance is about to start, which will “begin to affect the crude stocks and refined product output,” Kyle Cooper, a consultant at ION Energy, says . DOE
- Crude -2.566mm (-1.49mm exp)
- Cushing +58k (+50k exp)
- Gasoline -1.554mm
- Distillates -837k
Crude inventories fell for the 2nd week in a row... Crude production was unchanged last week (remember, the data only moves in 100k increments now, so unless a decent shift, then no change occurs).East Coast weekly crude imports dropped to their lowest since 2015.And Gasoline Demand hit a record high...
Crude Oil Prices Settle at 3-Week Highs as Supplies Sink, Iran Exports Ease - - WTI crude oil prices settled at three-week highs Wednesday on a government inventory report showing U.S. crude supplies fell sharply last week, and signs U.S. sanctions on Iran were starting to hurt the Islamic Republic's crude exports. On the New York Mercantile Exchange crude futures for October delivery rose 1.4% to settle at $69.51 a barrel, while on London's Intercontinental Exchange, Brent rose 0.98% to trade at $77.04 barrel. Inventories of U.S. crude fell by 2.566 million barrels for the week ended Aug. 24, greater than expectations for a draw of just 0.686 million barrels, according to data from the Energy Information Administration (EIA). The large draw in crude supplies comes as imports fell by about 0.657 million bpd, while exports rose by 0.624 million bpd, data from EIA showed. Production was unchanged at 11.0 million barrels a day (bpd), which also supported the draw in crude supplies, after rising for two-straight weeks. Gasoline inventories fell by 1.554 million barrels, confounding expectations for a build of 0.370 million barrels, while supplies of distillate -- the class of fuels that includes diesel and heating oil -- fell by 0.837 million barrels, against expectations for a build of 1.592 million barrels. The draw in products came as refinery activity fell to 96.3% of their capacity last week from 98.1% the prior week, with inputs averaging about 17.57 million barrels per day during, down 0.326 million barrels from the prior week, the EIA said. The bullish inventory report helped oil prices add to their earlier gains, which followed data showing a drop in Iranian crude exports as U.S. sanctions forced buyers to seek alternatives. Iran’s crude oil and condensate exports in August are set to drop below 70 million barrels for the first time since April 2017, well ahead of the Nov. 4 start date for a second round of U.S. economic sanctions, preliminary trade flows data on Thomson Reuters Eikon show.
Oil prices nod up as US fuel supply falls and sanctions on Iran loom -- Oil prices rose on Thursday, extending gains on growing evidence of disruptions to crude supply from Iran and Venezuela and after a fall in U.S. crude inventories. Brent has risen by almost 10 percent over the past two weeks on widespread perceptions that the global oil market is tightening and could run short in the next few months as U.S. sanctions restrict crude exports from Iran. Benchmark Brent crude oil was up 56 cents a barrel at $77.70 by 2:29 p.m. ET. U.S. light crude ended Thursday's session up 74 cents, or 1.1 percent, at $70.25, the highest closing price in six weeks. "The oil market is once again tightening," . "Iranian oil export declines are already visible well in advance of U.S. oil-related sanctions, which enter into force in November." Iranian crude exports will likely drop to just over 2 million barrels per day (bpd) in August, versus a peak of 3.1 million bpd in April, as importers bow to American pressure to cut orders. The Organization of the Petroleum Exporting Countries, in which Iran is the third-biggest producer, will discuss in December whether it can compensate for a sudden drop in Iranian supply after sanctions start in November, the head of Iraq's state oil marketer SOMO, Alaa al-Yasiri, said on Wednesday. Crude exports from crisis-struck OPEC member Venezuela have also fallen sharply, halving in recent years to around 1 million bpd.
Oil prices dip on concerns Sino-US trade conflict could escalate -- Oil prices slipped but remained near $70 a barrel on Friday as impending U.S. sanctions on Iran and falling Venezuelan output offset concerns over the impact of a global trade war. Benchmark Brent crude oil was down 33 cents a barrel at $77.44 by 8:29 a.m. ET (1229 GMT). U.S. light crude was 24 cents lower at $70.01.Despite Friday's losses, both Brent and U.S. light crude have jumped about 2 percent this week after strong gains in the last two sessions. Brent is on track for a rise of more than 4 percent in August with U.S. light crude gaining nearly 2 percent this month.Many analysts say the uptrend in crude prices will continue."Brent prices will exceed $80 per barrel before the end of the year," U.S. bank Jefferies forecast on Friday.Oil markets are tightening with a recent surplus draining, trade figures show. The volume of unsold crude stored in the Atlantic basin has dwindled from around 30 cargoes to just a handful in recent weeks, a Reuters analysis showed."The contracts are in a strong up-trend," said Robin Bieber, who watches price charts for brokerage PVM Oil Associates.Investors are worried that, with Venezuelan supply falling sharply, Iranian crude supply will be cut sharply ahead of the imposition on U.S. sanctions on Tehran in November."The November deadline to comply with the U.S. demands for an Iran oil embargo is moving closer, and in anticipation, buyers seemingly have begun reducing their purchases," said Norbert Ruecker, commodity analyst at Swiss bank Julius Baer. "Venezuela remains equally concerning," he added.
Analysts Forecast Average Price of Brent Crude in 2019 - The average price of Brent Crude will be between $70 and $80 per barrel in 2019, according to a new Rigzone poll on social media site Twitter. Forty-percent of the 231 poll respondents said the average price would fall within this range next year, with 23 percent stating that the average price would be between $80 and $90 per barrel. An identical percentage thought the average price would be below $70 per barrel and the remaining 14 percent of voters said the average price of Brent Crude would be above $90 per barrel in 2019.Fitch Solutions Macro Research is forecasting the average price of Brent Crude to be $82 per barrel next year, according to a report from the company dated August 14, which was sent to Rigzone.The report highlighted that the Bloomberg Consensus forecasted an average Brent Crude price of $69.50 per barrel in 2019.Looking further ahead, Fitch Solutions Macro Research forecast that the average price of Brent will be $85 per barrel in 2020, $89 per barrel in 2021 and $91 per barrel in 2022.“In the short term, prices will struggle for direction, as uncertainty around both the impact on supply from the Iranian sanctions and escalating trade tensions between the U.S. and China persists,” oil and gas analysts at Fitch Solutions Macro Research said in the report. “Returning OPEC+ barrels and strong U.S. onshore production will offset output losses in Iran, Venezuela and Angola. However, global spare capacity will shrink substantially as a result,” the analysts added.
Bouncing Back, BHGE U.S. Rig Count Climbs by Four - Drilling activity in the United States rebounded on Friday modestly from a steep drop one week earlier, picking up four rigs to finish at 1,048, according to data from Baker Hughes, a GE Company (BHGE).After adding two gas-directed rigs and two oil-directed rigs for the week, the United States is outpacing its year-ago tally by a little more than 100 units.Three directional rigs and three vertical rigs returned to action for the week, while two horizontal units packed up. Three rigs were added on land, along with one in inland waters. The Gulf of Mexico finished flat for the week at 16 rigs, according to BHGE.Canada saw a net loss of one rig for the week as two oil units departed, offsetting the addition of one gas-directed. Canada finished the week at 228 rigs, up from 201 a year ago. The combined North American rig count finished at 1,276, versus 1,144 at this time last year.Among plays, the Cana Woodford posted the largest net gain for the week at two, finishing at 67, just ahead of its year-ago tally of 65. A more detailed breakdown of BHGE data by NGI’s Shale Daily indicates the two rigs added went to work in the STACK (aka, the Sooner Trend of the Anadarko Basin, mostly in Canadian and Kingfisher counties), with the the SCOOP (South Central Oklahoma Oil Province) finishing flat week/week.Meanwhile, the Marcellus Shale and Permian Basin each picked up one rig for the week to end at 53 and 486 active units, respectively. The Granite Wash saw two rigs pack up shop, while one exited the Eagle Ford Shale.Among states, Louisiana and Pennsylvania each added one rig for the week, while New Mexico and Oklahoma each saw a net decrease of one rig. Kansas saw one rig go to work, the only active rig in the state as of Friday, according to BHGE. The Lone Star State, home to a large portion of the U.S. onshore’s most active play, the Permian, saw its oil and natural gas output in June retreat from a year ago and month/month, with production at the lowest level in 16 months, according to preliminary data by Texas regulators.
Crude Oil Prices Settle Lower, but Post Monthly Gain - WTI crude oil prices settled lower Friday, on signs of expanding U.S. output and fears over lower oil-demand growth amid rising global trade tensions. On the New York Mercantile Exchange, crude futures for October delivery fell 45 cents to settle at $69.80 a barrel, while on London's Intercontinental Exchange, Brent fell 0.55% to trade at $77.59 a barrel. Oilfield services firm Baker Hughes reported on Friday that the number of U.S. oil drilling rigs in operation rose by 2 to 862. The rise in rig counts, pointing to signs of expanding output, comes as data, released earlier this week, showed rising U.S. output steadied at 11.0 million barrels a day, unchanged from the prior week. Renewed concerns over an escalation in the U.S.-China trade war stoked fears of lower oil demand growth, adding to downside momentum in oil prices. China, the world's largest commodity importer, has seen economic growth dwindle since the trade war with the U.S. kicked off, and a further escalation could dent growth, forcing Beijing to rein in crude imports. Oil prices ended the month nearly 2% higher amid renewed bets on a global supply shortage as U.S. sanctions on Iran's crude exports are expected to reduce crude from market, underpinning higher crude prices. "Press reports indicate that Iranian crude oil and condensate exports in August are poised to drop below 2.25 million barrels a day – marking three straight monthly declines, a 600,000bpd drop versus April and helping crystallize the risk that US sanctions squeeze global oil supply placing upward pressure on international prices," Bank of American Merrill Lynch said in note to clients. Both WTI and Brent crude are expected gain on a potential slump in Iranian exports, although gains in WTI prices will be limited as the refinery maintenance season is set to get underway. "An active maintenance season in the US Mid-Continent may prevent the WTI benchmark increasing," according to Bank of American Merrill Lynch. Maintenance season tends to halt refinery activity, slowing demand for crude stockpiles used as inputs in the production of product inventories like gasoline. Oil prices were also helped earlier in the week by an EIA report showing crude oil stockpiles fell much more than expected.
Saudi crude oil output in August rises to 10.424 million b/d: OPEC source— Saudi Arabia will report August crude oil production of 10.424 million b/d, an OPEC source told S&P Global Platts on Friday. The figure represents a 136,000 b/d increase from July, when Saudi Arabia, OPEC's largest producer and the world's largest crude exporter, self-reported production of 10.288 million b/d. The kingdom supplied to market 10.467 million b/d in August, the source added on condition of anonymity. That means the sum of crude exported to customers, consumed by Saudi refineries and burned by domestic power plants, slightly exceeded the amount of crude that was pumped out of the ground in the month, indicating a draw of barrels held in storage. The August figures reflect Saudi customer demand, the source said. July production had been down partly because of a July 25 attack on two VLCCs in the Red Sea owned by state oil company Saudi Aramco, the source said. The attack prompted the company to suspend shipments through the Bab al-Mandab strait until August 4. OPEC on June 23 agreed with 10 non-OPEC partners to end overcompliance with their production cuts and boost output by a collective 1 million b/d to replace barrels expected to be shut in by the reimplementation of US sanctions on Iran and Venezuela's economic freefall. Saudi Arabia's quota under the deal was 10.06 million b/d. The market has been closely watching Saudi production, as it holds the bulk of global spare capacity and has indicated its willingness to serve as the world's primary swing producer. OPEC is set to reveal its August production figures in its monthly oil market report September 12.
No Saudi Aramco IPO? No problem, potentially, for Saudi Arabia’s investment dreams - The world's largest initial public offering is on hiatus. The spending it was to enable may not be. Saudi Arabia planned to take its giant oil company, Saudi Aramco, to the public markets. It was to be the linchpin of a grand economic vision, generating billions of dollars to pay for future-proofing the kingdom's economy, including huge investments in technology. It is now postponed, leaving a large funding shortfall. But Saudi Arabia is pursuing alternative transactions that could ensure its dreams aren't dashed:
- • Saudi Aramco is in discussions to buy a large stake in Sabic, a publicly traded chemical company. Sabic's controlling shareholder is Saudi Arabia's sovereign wealth fund, the Public Investment Fund. While the size of that potential acquisition is unclear, media reports say it could be as big as $70 billion.
- • The Public Investment Fund is in talks to raise $11 billion in bank loans from international lenders, according to The Financial Times. It would be the first time the sovereign wealth fund borrowed money.
- • Saudi Aramco could still sell a stake in itself. Big companies in China and Russia reportedly expressed interest in an investment in the past. It isn't clear how much a sale would raise, but it would almost certainly run to billions of dollars.
Exclusive: Saudi king tipped the scale against Aramco IPO plans (Reuters) - The king spoke, and a $2 trillion dream went up in smoke. For the past two years, Saudi Arabia has prepared to place up to 5 percent of its national oil company on the stock market. Officials talked up the Saudi Aramco initial public offering (IPO) with international exchanges, global banks and U.S. President Donald Trump. The planned listing was to be the cornerstone of the kingdom’s promised economic overhaul and, at a targeted $100 billion, the biggest IPO ever. It was the brainchild of 32-year-old Crown Prince Mohammed bin Salman, heir apparent of the world’s largest oil exporter. But after months of setbacks, the international and domestic legs of the IPO were pulled. The reason: the prince’s father King Salman stepped in to shelve it, three sources with ties to government insiders told Reuters. The decision came after the king met with family members, bankers, and senior oil executives, including a former Aramco CEO, said one of the sources, who requested anonymity. Those consultations took place during Ramadan, which ended in the middle of June. The king’s interlocutors told him that the IPO, far from helping the kingdom, would undermine it. Their main concern was that an IPO would bring full public disclosure of Aramco’s financial details, the sources said. In late June, the king sent a message to his diwan, or administrative office, demanding that the IPO be called off, the three sources said. The king’s decision is final, a second source said. “Whenever he says ‘no’, there is no budging,” the source said. After Reuters reported last week that the deal had been shelved, Energy Minister Khalid al-Falih said the government was committed to conducting the IPO at an unspecified date in the future. A senior Saudi official referred Reuters to that statement and repeated that the government, Aramco’s shareholder, was working toward an IPO when conditions were right. “We are surprised that despite this statement, that the Government continues actively to plan for the IPO, Reuters persists in asking questions alleging that plans are halted.” “Aramco’s shareholder is the Government of Saudi Arabia. His majesty, King Salman, has delegated management of the IPO to His Royal Highness the Crown Prince, and a Committee which includes the Ministers for Energy, Finance and Economy. Therefore, decisions around the nature and timing of the IPO, will be decided by the Committee for the Government’s approval,” the official said.
Saudi King Shelved Aramco IPO To Teach Son, Prince Bin Salman A Lesson - Less than a year after Saudi Arabia's unprecedented monetary shakedown of wealthy princes and other Saudi oligarchs in November 2017, which among others ensnared Prince Alwaleed bin Talal who was an involuntary "guest" at the Riyadh Ritz-Carlton for months - until he emerged a free man after an undisclosed settlement - and also eliminated potential threats to the ruling family including close family members, Reuters is out with a fascinating report according to which new splinters may be appearing inside Saudi society, in this case involving a schism between the Saudi King Salman, and his 32 year old son and de facto ruler, Crown Prince Mohammed bin Salman.As was first reported in early 2016, for the past two years Saudi Arabia had been preparing to place up to 5% of its national oil company, Saudi Aramco, on the stock market. Officials talked up the Aramco initial public offering with international exchanges, global banks and President Donald Trump.The planned listing was supposed to be the cornerstone of the kingdom’s promised economic overhaul and, at a targeted $100 billion, the biggest IPO ever. More importantly, it was the brainchild of 32-year-old Crown Prince Mohammed bin Salman, heir apparent of the world's largest oil exporter and the effective head of OPEC.However, after months of setbacks, the deal came to a crashing halt after the international and domestic legs of the IPO were pulled earlier this month.The reason, according to Reuters: King Salman - the prince's father - stepped in to shelve it.The decision came after the king met with family members, bankers, and senior oil executives, including a former Aramco CEO, said one of the sources, who requested anonymity. Those consultations took place during Ramadan, which ended in the middle of June.Having been seemingly asleep for the prior two years, The king's interlocutors told him that the IPO, far from helping the kingdom, would undermine it. Their main concern was that an IPO would bring full public disclosure of Aramco's financial details, something we knew from prior reports on why the IPO was problematic.Then, in late June, the king sent a message to his administrative office, demanding that the IPO be called off: the king's decision is final, a Reuters source said."Whenever he says 'no', there is no budging,"
Mohammed Bin Salman Of Saudi Arabia In Trouble? -- Barkley Rosser - This is what Juan Cole reports today from several sources. Supposedly, as I reported here earlier, even though it was supposedly denied, the Saudi ARAMCO IPO deal is off. The new reports have it that the final decision on this came from King Salman of Saudi Arabia, the father of the power hungry Crown Prince, Mohammed bin Salman (MbS), who has been the main advocate of the IPO as part of his Vision 2030 plan. The king has up until now pretty much let MbS have his way on many matters, from economics, to foreign policy, to social policies (some of this good, e.g. letting women drive and putting the religious police in a book), and to dissent, including jailing lots of leading Saudi figures as well as womens’ rights advocates, including havint a 29 years female Shia activist beheaded.In terms of the IPO, supposedly Salman was unhappy about the required transparency on financial and oil reserves issues. There are rumbles that he is unhappy about some of the other matters, with indeed MbS making major messes of a number of things, such as the disastrous war in Yemen and the failed embargo against Qatar, still stupidly in place. He is also probably not happy about some of those arrests last year, although much of this is murky. However, the most important bit in these rumors is that King Salman iis reportedly so unhappy that he is contemplating replacing MbS with somebody else as Crown Prince. Indeed, MbS is in trouble.Now probably this last part is just wishful thinking by some in Saudi Arabia, leaking such rumors. Very likely the family link will dominate, unless Salman were to replace MbS with one of his full brothers. But it is believable that MbS may be facing some reining in, especially if indeed Salman was responsible for the ultimate cancellation of the ARAMCO IPO deal.
Aramco To Lose 'Forever-Right' To Saudi Oil Resources - In what could be a power struggle between Saudi Aramco and the Saudi government, the Kingdom has altered the concession contract with the oil giant to 40 years with an option for renewal from a previous deal for oil and gas rights ‘in perpetuity’, the Financial Times reported on Monday, quoting three people briefed on the issue.The changes were reportedly made as Saudi Arabia was making procedural, tax, and governance changes in preparation of the initial public offering (IPO) of Saudi Aramco, which now, it seems, is indefinitely postponed, or even called off.Last Wednesday, reports emerged that Saudi Arabia had called off its highly anticipated, US$100-billion IPO, Reuters sources said, with even plans to list the state-run oil company on its domestic bourse, Tadawul, being scrapped. The listing was expected to be the world’s largest IPO, and the Saudis pegged a large part of the Vision 2030 economic agenda on proceeds from the IPO.Saudi Arabia immediately denied the reports that the listing was canceled, with Energy Minister Khalid al-Falih saying in a statement carried by the Saudi Press Agency: “The Government remains committed to the IPO of Saudi Aramco at a time of its own choosing when conditions are optimum. This timing will depend on multiple factors, including favorable market conditions, and a downstream acquisition which the Company will pursue in the next few months, as directed by its Board of Directors.” In that same statement, al-Falih said that in order to prepare for Aramco’s listing, the Saudi government had taken several steps in that direction, including “reissuing a long-term exclusive concession,” without specifying details.
Will Saudi Arabia’s Geopolitical Strategy Backfire? --Russian Deputy Foreign Minister Mikhail Bogdanov said on Friday that Vladimir Putin is preparing to visit Saudi Arabia. The statement comes after the Russian president received an invitation from Saudi King Salman at an unspecified time, according to reports. Bogdanov added that the visit is pending on Putin’s schedule. King Salman became the first Saudi monarch to visit Russia last October, meeting Putin in the Kremlin. The disclosure on Friday also comes just months after Saudi Crown Prince Mohammed bin Salmon visited Moscow to attend the opening of the 2018 World Cup. He also meets with Putin during this visit. While Bogdanov declined to disclose what the talks would be about, it’s apparent that global oil markets will be on the top of the agenda as will developments in Syria (where Moscow and Riyadh are on opposing sides in the ongoing Syrian Civil War), as well as talk about fresh U.S. sanctions on Iran that could remove, according to many estimates, up to 1 million barrels per day of oil from global markets. It was Russia that came to the aid of Saudi Arabia after the kingdom had for all practical purposes lost its decades long ability to play global oil markets swing producer as U.S. shale oil production revolutionized markets.Earlier this year, there was talk about a more permanent, 10 or even 20-year, Saudi-Russian oil production agreement, bin Salman told Reuters news agency. What remains to be seen however, in spite of the successful recent Saudi-Russian agreement to take back control of global oil markets, is whether or not a permanent so-called expanded OPEC, non-OPEC cartel would even work long term. While both countries seem to be putting aside stark differences over Syria (where Russia supports the country’s embattled president Bashar al-Assad, while Saudi Arabia, along with Qatar and Turkey, support the Syrian rebels) it has nonetheless strained relations. Russia and Saudi Arabia also have differences over how to handle Iran’s nuclear power development ambitions.
US-backed Saudi regime set to behead female activist and four others -- State prosecutors in Saudi Arabia have called for the execution by beheading of 29-year-old political activist Israa al-Ghomgham, her husband, Moussa al-Hashem, and three others for the “crimes” of peacefully demonstrating against the country’s monarchical dictatorship, chanting slogans against the regime and posting videos of their protests on social media. The death sentences, including the first for a Saudi woman based on alleged political offenses, are emblematic of a criminal regime that counts as Washington’s closest ally in the Arab world.The protests that led to the charges took place in the port city of Qatif in the Saudi kingdom’s oil-rich Eastern Province, home to the bulk of the country’s Shia minority population. Beginning in 2011 and continuing since, the protests have challenged the systematic discrimination against and oppression of the Shia population by a monarchy that is bound up with the official, state-sponsored religious doctrine of Wahhabism, an ultra-conservative Sunni sect.The demonstrations, demanding equality, improved social conditions in a region that remains deeply impoverished despite its oil wealth, freedom of expression and the release of political prisoners, have been answered with a police state crackdown that has seen entire communities subjected to military siege.Israa al-Ghomgham and her husband were arrested on December 6, 2015 when security forces staged a night raid on their home. They have been imprisoned ever since, held for 32 months, most of that time without access to a lawyer and without being presented with any formal charges against them. From a working class background, Ghomgham’s family did not have the money to pay for a lawyer. It was only after her father began a public attempt to raise funds that an attorney volunteered to defend her. She and her co-defendants were tried in the Saudi regime’s Specialized Criminal Court, set up in 2008, ostensibly to try terrorism cases. The court’s proceedings, in which the rights of defendants are virtually non-existent, amount to a show trial, with the verdict as well as the sentence determined in advance by the monarchy.
U.N. Report Flags Possible War Crimes in Yemen Conflict – WSJ - Members of a Saudi-led coalition and allied forces fighting Houthi rebels in Yemen may be guilty of torture, using child soldiers and attacks on civilians that amount to war crimes, a United Nations report said Tuesday, adding to international criticism of the group.The U.N. report also found that Houthis could be guilty of war crimes due to their blockage of goods into civilian areas, and cited evidence that the rebels tortured detainees and recruited child soldiers.The Saudi-led coalition referred the U.N. report for review by its legal team, and would take a position following that process, according to a Saudi state television report. A Houthi representative also said the issue had been sent to the rebels’ legal office for review, but declined further comment. The report, by a panel of three experts, focused in part on the U.S.-backed coalition’s airstrikes, which have killed hundreds of civilians. The U.S. supplies many of the precision weapons used in Saudi coalition airstrikes, and provides other limited support, including aerial refueling for coalition jets.In Washington, Defense Secretary Jim Mattis said the U.S. hadn’t seen any “callous disregard” by the Saudis toward civilians in Yemen. “Our goal is to reduce this tragedy, and to get it to the U.N.-brokered table as quickly as possible,” Mr. Mattis said.The coalition—which includes Saudi Arabia, the United Arab Emirates and Yemeni allies—has waged a war against the Houthis since 2015, using a combination of airstrikes and ground forces in a bid to oust the Iran-allied rebels from the Yemeni capital of San’a and restore the internationally recognized government of President Abed Rabbo Mansour Hadi. While the coalition has taken over swaths of Yemeni territory, the Houthis remain in control of San’a and other areas in the north and west. At least 6,660 civilians have been killed in the conflict, according to the U.N., many allegedly from the coalition air campaign. Other allegations in the report included accusations of sexual violence and severe restrictions on the flow of commercial goods and people through ports and airports. The report, for example, alleged the coalition’s effective closure of the airport in San’a led to the death of the founder of Yemen’s Red Crescent Society last year because he wasn’t able to travel abroad for lifesaving treatment.
Furious Saudi Arabia Condemns UN Report On Yemen War Crimes A Tuesday report released by the UN confirmed in considerable detail misdeeds by the Saudi-led coalition in Yemen, killing thousands of civilians in Yemen, raping and torturing detainees, and using child soldiers. The report warned these may amount to war crimes.While they didn’t specifically dispute any of this, Saudi Arabia was predictably furious about the report, angrily condemning it as having “misconstrued the facts of the conflict… ignoring the true reasons for the conflict,” while saying that it was an Iranian coup against the “legitimate government in Yemen.” While previous UN resolutions more or less accepted the Saudi narrative that the war is meo reinstall the Hadi government, that massive death toll and the many, many war crimes committed have fueled a lot of international consternation.Still, UN reports detailing war crimes by the Saudi coalition have been met by Saudi condemnation, and in the past that, combined with US support for the war, has been enough to keep the UN from doing anything in particular about the situation. The UN General Assembly has repeatedly acquiesced to demands that the Saudis be allowed to investigate themselves on the war, which has meant probes are rare, and never come up with anything meaningful.
Why Americans Can't Understand The Middle East - A recent editorial in the Washington Post, written by columnist David Ignatius, offers a shining example of the United States’ difficulty in understanding today’s world and, most of all, the Arab world. The journalist expresses uneasiness about the fact that “American power and values won’t matter the way they once did”. His position is steeped in the typical intellectual milieu of American exceptionalism, a position based on the hardwired assumption that the condition for an ideal existence and a stable world order are ensured only when American power and values are strong and shared. The article emphasises that, at the moment, there would be “…no constituency in the US for…doing more in the Middle East”. Quoting the same Arab source, Ignatius affirms that US disengagement could imply that Arab nations will need to do things on their own. So far nothing wrong, except that, for Ignatius and his source, Arab nations going it alone has only one meaning: “closer relations with Russia and China”. Another depressing and frustrating example of Western binary thinking. It could be argued that the columnist’s conclusion is neo-colonial, orientalist, or too patronising; but what appears incontrovertible is that it does not put an inch of trust in Arab will and capabilities to find their own way in managing their own foreign policy in their own region and in the rest of the world.The American columnist adds:“Maybe I’m a foreign policy dinosaur. But I still want a modernizing Middle East that shares America’s value, and I regret our loss of influence – and even more, the way that decent people and ideas suffer when the umbrella of US hegemony is withdrawn and discarded…. I’ve seen new examples of bad decisions when leaders decide that Uncle Sam doesn’t matter.” This set of statements is so absurd that it deserves to be analysed, sentence by sentence: “Maybe I’m a foreign policy dinosaur.” At least, Ignatius seems assaulted by some doubt. This is probably the most truthful sentence in his whole article. Losing influence is part of an historical cycle that has occurred to every great nation. This process could be accelerated when this influence is badly and unwisely used, as appear to be have been the case for the United States in the last 25 years.
UAE Buys World's Largest Rocket Launcher "Jobaria" From Turkey - One of the leading firms in the Turkish defense industry, Roketsan, set a record with world’s largest rocket artillery, capable of launching hundreds of rockets in 2 minutes from a single military vehicle, the company announced on Saturday. Jobaria, a Multiple Cradle Launcher (MCL), was developed by Roketsan for the United Arab Emirates (UAE), has achieved legend status with Guinness World Records for the world’s largest rocket artillery in terms of the number of barrels, the company said in a statement sent to journalists. The UAE requested the large rocket artillery battery on one vehicle since its military is phasing out the older, BM-21 Grads, a Soviet truck-mounted 122 mm multiple rocket launcher. The MCL has a significant advantage over the BM-21 Grads; it replaces the use of six launcher vehicles which require a team of over 30 troops, whereas the MCL only needs a group of three to operate and launch the same number of rockets (240). The system has four rocket launchers attached to the trailer each carrying sixty 122mm rockets. It can fire 240 Roketsan 122mm T-122 Sakarya rockets fitted with a high-explosive warhead at targets with a maximum range of around 37 kilometers (23 miles). All missiles can be fired in under two minutes, making the rate of fire two rounds per second. After launching the rockets, a support team can reload the missile system in about 30 minutes. While it is still unclear why the UAE would need the world’s most massive rocket launcher, perhaps, the missile system may find a new home in the Saudi-led alliance against Yemen. There is also another possibility the country is gearing up for conflict in the Strait of Hormuz, as Washington and Tehran bicker over who controls the strait between the Persian Gulf and the Gulf of Oman. In any case, war is coming, and the world’s largest rocket launcher will be used.
Pushing Beirut And Baghdad To Comply With Iran Sanctions Is Risky Business - President Donald Trump has reimposed an old set of American sanctions on Iran, as well as new ones following his abandonment of the Joint Comprehensive Plan of Action (JCPOA) last May. For regional neighbours Lebanon and Iraq, these sanctions could not have come at a worse time. Both are in the throes of political crises that threaten their fragile democracies. Both need to avoid the complications arising out of a poorly-thought-out Trump decision. In fact, if the Trump administration wants to help its friends in the Arab world, it would do well to try to blunt the impact of these sanctions on these two countries. On August 6, the US reimposed sanctions on the use of dollar bank notes in Iran’s trade transactions, which had been permitted when the Islamic Republic signed the JCPOA, or Iran nuclear deal, in July 2015.Another oil-related batch of sanctions will be imposed on November 5 and are likely to reduce Iran’s exports by about 500,000 barrels per day, thus disrupting international energy markets and causing a price increase of about $20 per barrel.In fact, aside from the domestic impact in Iran, these measures are likely to cause global financial and commodity disruptions that will be felt by large and small economies. Given their economic relationship with the United States and the American currency, Lebanon and Iraq have no recourse but to abide by what Washington wants. But, unfortunately for the two countries, the devil is in the details of their political realities. Both currently have caretaker governments that prevent them from making firm decisions on compliance with sanctions.Both have pro-Iranian political forces that oppose the sanctions – seeing them as a foreign tool to effect regime change in Tehran – and consider it their duty to help defend current regime.
Iran Continues to Comply With Nuclear Deal, U.N. Atomic Agency Says —Iran continues to fulfil the key requirements of the 2015 nuclear deal, the United Nations atomic agency said Thursday, despite the U.S. withdrawal from the agreement. The report comes as tensions between Iran and the West have sharpened, amidst rising U.S. economic pressure on Tehran and allegations that Tehran was involved in a terror plot in Europe. In a confidential quarterly report sent to member states, seen by The Wall Street Journal, the International Atomic Energy Agency reported that Iran was honoring its pledges to limit stockpiles of key nuclear materials and maintain IAEA inspectors’ access to sites. It signaled no other breach of the accord’s requirements by Tehran. Iran’s stockpile of enriched uranium rose to 139 kilograms from 124 kilograms in May, but remained well within the 202-kilogram limit. A kilogram is 2.2 pounds.
Exclusive: Iran moves missiles to Iraq in warning to enemies (Reuters) - Iran has given ballistic missiles to Shi’ite proxies in Iraq and is developing the capacity to build more there to deter attacks on its interests in the Middle East and to give it the means to hit regional foes, Iranian, Iraqi and Western sources said. Any sign that Iran is preparing a more aggressive missile policy in Iraq will exacerbate tensions between Tehran and Washington, already heightened by U.S. President Donald Trump’s decision to pull out of a 2015 nuclear deal with world powers. It would also embarrass France, Germany and the United Kingdom, the three European signatories to the nuclear deal, as they have been trying to salvage the agreement despite new U.S. sanctions against Tehran. According to three Iranian officials, two Iraqi intelligence sources and two Western intelligence sources, Iran has transferred short-range ballistic missiles to allies in Iraq over the last few months. Five of the officials said it was helping those groups to start making their own. “The logic was to have a backup plan if Iran was attacked,” one senior Iranian official told Reuters. “The number of missiles is not high, just a couple of dozen, but it can be increased if necessary.”
Iran Stuns Enemies By Moving Ballistic Missiles To Iraq - Within Easy Striking Distance of Tel Aviv - In what is sure to be a realization of one of Netanyahu's worst nightmares, and deeply awkward for US advisers to Baghdad, Iran has transferred ballistic missiles to Shia proxy forces in Iraq, according to Western and Iraqi intelligence sources cited in a new Reuters report. The revelation comes as tensions between Washington and Tehran are already at their highest point in years as aggressive sanctions continue crippling Iran's economy, and after threats and counter-threats over Tehran laying claim to the vital Strait of Hormuz oil waterway over the past weeks, through which some one-third of the world's oil passes. The Reuters report cites multiple officials and intelligence sources, including Iranian officials who seem willing to inform the world of the provocative move:According to three Iranian officials, two Iraqi intelligence sources and two Western intelligence sources, Iran has transferred short-range ballistic missiles to allies in Iraq over the last few months. Five of the officials said it was helping those groups to start making their own.“The logic was to have a backup plan if Iran was attacked,” one senior Iranian official told Reuters. “The number of missiles is not high, just a couple of dozen, but it can be increased if necessary.”The news is sure to cause a stir for European signatories to the 2015 nuclear deal (JCPOA) like Germany, the UK, and France, who are still trying to salvage it, as it is a clear sign that the deal which the Trump White House pulled out of is in tatters. Reuters identifies the Zelzal, Fateh-110 and Zolfaqar missile systems as among those transferred — with ranges of between 200 and 700km, which puts "Saudi Arabia’s capital Riyadh or the Israeli city of Tel Aviv within striking distance if the weapons were deployed in southern or western Iraq".And notably the elite Islamic Revolutionary Guard Corps (IRGC) Quds force head, Gen. Qassem Soleimani, is overseeing the missile transfers and their operation in what regional foes Saudi Arabia and Israel are sure to interpret as the most provocative and escalatory move by its archenemy in recent years.
Israel renews threat to attack Iran targets in Syria -- Israel on Wednesday renewed its threat to attack Iranian military targets in Syria, after the two Muslim allies signed an accord on security cooperation. “The IDF (Israel Defence Forces) will continue to take strong and determined action against Iran’s attempts to station forces and advanced weapons systems in Syria,” Prime Minister Benjamin Netanyahu said. “No agreement between Syria and Iran will deter us; neither will any threat deter us,” he said at a ceremony naming Israel’s nuclear facilities after late president Shimon Peres. Iran’s military attache to Damascus said on Tuesday that his country’s military advisers would remain in Syria under the defence agreement signed the previous day. “Support for Syria’s territorial integrity and the independence of Syrian sovereignty were also emphasised in the agreement,” Brigadier-General Abolghasem Alinejad said. Tehran has provided steady political, financial and military backing to Assad as he has fought back against a seven-year uprising.
Israeli Reports Claim New Images Confirm Iranian Surface-to-Surface Missile Facility In Syria - At the end of a week where tensions with Iran and Syria have reached a high point of late, and as the final showdown between the Syrian Army and al-Qaeda insurgents in Idlib looms, multiple Israeli media reports claim Iran is constructing new surface-to-surface ballistic missile factories in Syria.What's more, the reports claim, Iran's military is taking advantage of Russia's sophisticated antiaircraft defense missile systems in Syria to build the sites within range of the their protective defense umbrella. The Jerusalem Post, for example, echoing other Israeli outlets, relies on the open-source satellite image analysis site ImageSat to claim Iran is taking advantage of Russian defenses to avoid Israeli retaliation. According to the Jerusalem Post report:According to ImageSat, both the facility in Masyaf and the one in Wadi Jahannam are located within the operational range of a Russian S-400 deployment, showing that Iran is “utilizing or exploiting the defense abilities of Russia.”Russia deployed the advanced mobile S-300 and S-400 anti-aircraft batteries to Syria in October 2017. The batteries are capable of engaging multiple aircraft and ballisti c missiles at a distance of up to 380 kilometers, covering virtually all of Syria as well as significant parts of Israel and neighboring countries such as Turkey and Jordan.
Syria Spurns US Offer to Pull Out Troops as Trade for Iran Withdrawal – Report - Syria turned down an offer from the US to withdraw their forces from Al Tanf, a US base in the southeast and the East Euphrates zone in exchange for three concessions from the Assad government, according to a report from Lebanese daily Al Akhbar. Officials of "several US intelligence and security agencies" reportedly landed in a private UAE plane at Damascus International Airport in late June. They then took off in a convoy towards the center of Damascus for a meeting with the head of Syria's national security office, Major General Ali Mamlouk. The meeting reportedly lasted for four hours. The sides discussed multiple aspects of the seven-year war in the country before the Americans made their offer: a withdrawal of its troops from Al Tanf and the East Euphrates on three conditions, including a complete Iranian withdrawal, a share in Syria's oil spoils, and intelligence on terrorists. The first condition was that Iran also withdraw fully from the country. Unlike the United States, Iran was invited by the Syrian government to help it fight Islamist insurrectionists and foreign proxies. As a second concession for an Al Tanf withdrawal, Al Akkbar said that the Americans also demanded a share in the oil sector of eastern Syria, which until recently was occupied by Daesh militants with a stronghold in Deir ez-Zor. Third, the US officials also reportedly sought Syrian intelligence on terrorists who could present threats to Western countries in the future.
Is Washington on the brink of a major attack on Syria? --The US and its allies are systematically putting into place all the elements needed to justify and carry out a major new act of aggression against Syria, according to reports from Moscow and the Middle East.The charges that Washington is preparing an unprovoked attack followed warnings made by US National Security Adviser John Bolton, as well as by British and French officials, that their governments would retaliate sharply against any use of chemical weapons by the government of President Bashar Assad in the northern Syrian province of Idlib.Recent bombing and shelling by the Syrian military, as well as the reported transfer of the Syrian army regiment based in the city of Homs to the southern border of Idlib, have raised speculation that Damascus is on the verge of launching an offensive to retake one of the last territories still under the control of Al Qaeda-linked Islamist militias. These forces were armed and funded by Washington, Turkey, Saudi Arabia and Qatar to wage a seven-year-long proxy war for regime change aimed at installing a more pliant pro-imperialist regime in Damascus.The Assad government has denied employing chemical weapons in its campaign to reassert control over areas of the country seized by the Western-backed “rebels.” It has accused the Al Qaeda-linked forces of staging chemical weapons incidents with the aim of provoking US military attacks on the regime, like the ones carried out last April and in 2017. Speaking at a press conference in Jerusalem last Wednesday, Bolton declared: “We are obviously concerned about the possibility that Assad may use chemical weapons again. Just so there’s no confusion here, if the Syrian regime uses chemical weapons we will respond very strongly and they really ought to think about this a long time.”
Russian Official Shocks By Urging Tactical Nuke Deployment In Syria After Bolton Warning - The long-running US and Russian proxy war in Syria has been largely forgotten of late, but suddenly snapped back into international headlines with John Bolton's warning Assad and Russia this week that Washington will respond with "greater military force" should claims of a Syrian government chemical attack emerge in Idlib. In response, Russia subsequently warned of a staged "chemical provocation" coming and it appears a war of words is yet again ratcheting up over Syria, which has the very real potential of turning into an actual war.It fits a familiar pattern on Syria since Russian intervention at the invitation of President Bashar al-Assad in 2015: just when it appears the jihadists are on the brink of final defeat, and as stability is returning after seven years of grinding war, something happens to bring things right back to the brink of global crisis and escalation. And now, a senior Russian lawmaker in the Federal Assembly (Duma) has called on his government to draw its own "red lines" while suggesting the use of tactical nuclear weapons against United States forces in Syria. The Russian official news agency TASS reports Vladimir Gutenev's shocking words spoken on Friday. Gutenev is the first deputy head of the economic policy committee of the State Duma, the lower chamber of the Russian parliament.Gutenev said, “I believe that now Russia has to draw its own ‘red lines.’ The time has come to ponder on variants of asymmetric response to the US, which are now being suggested by experts and are intended not only to offset their sanctions but also to do some retaliatory damage.” Among such measures, the official named the deployment of tactical nukes, saying that Russia should "follow the US example and start deploying our tactical nuclear weapons in foreign countries." While it's unclear what Gutenav meant by his citing "the US example", on a few occasions unverified accusations have emerged alleging the US and its allies like Israel have used small nuclear devices in places like Syria and Yemen, echoed also among pro-Russian sources.
Russia Sends Largest Naval Armada Of Syrian War Amidst New Chemical Attack Warnings - We observed previously after John Bolton's threat late this week of "greater military force" should chemical weapons allegations emerge against Damascus, that a familiar pattern has long been in play on Syria: just when it appears the jihadists are on the brink of final defeat, and as stability is returning after seven years of grinding war, something happens to bring things right back to the brink of global crisis and escalation. Russia has built up its forces around the Mediterranean Sea in response to reports that the U.S., France, and Great Britain could be preparing to attack Syria after US National Security Advisor John Bolton informed Russia that America is prepared to respond with greater military force than it has used against Assad’s regime in the past, according to Bloomberg. According to Yoruk Isik of the Bosphorus Observer, the Russian Navy has sent another armada of ships towards Syria’s territorial waters in order to increase the strength of their forces around the country. Isik said that the powerful Russian warships, Admiral Grigorovich and Admiral Essen class frigate, were spotted transiting the Bosphorus Strait en route to the Port of Tartous.This latest move by the Russian Navy comes just 24 hours after they sent three ships en route to the Port of Tartous in western Syria. New & powerful: Armed with Kalibr SS-N-27 missiles, #ВМФ #ЧФ second Admiral Grigorovich class frigate AdmIral Essen redeployed to Mediterranean after 58 days & transits Bosphorus en route to #Tartus #Syria pic.twitter.com/lnflQbZJzx — Yörük Işık (@YorukIsik) August 25, 2018 The Turkish coast guard monitored the frigates as they passed through the Bosporus toward the Mediterranean, reportedly en route to Russia's only major deep-water port in the region along the Syrian coast.
Russia’s fleet to counter US moves ahead of Syrian offensive -- Russia has beefed up its naval presence in the Mediterranean amid claims by Moscow that the United States is poised to launch a strike at Syrian forces preparing for a major offensive in Idlib.Up to 11 Russian warships have crossed the Bosphorus as tensions between the US and Syria continue to rise.“It included at least 10 vessels and two submarines – with more on the way,” the Russian daily newspaper Izvestia stated, adding that most of the flotilla is carrying Kalibr cruise missiles. If the reports are correct, this would be the biggest task force sent by President Vladimir Putin’s government since Russia’s intervention in the Syrian conflict in 2015. It also comes at a time when Moscow’s ally, Syrian President Bashar al-Assad, is believed to be on the brink of launching an assault on the last big rebel-held enclave of Idlib in the north of the country.Russia has already accused the Washington administration of President Donald Trump of building up its own forces in the Middle East in preparation for a possible strike on Syrian government forces if they use chemical weapons. On Aug. 25, the USS Ross entered the Mediterranean, according to the Russian Ministry of Defense. The guided-missile destroyer is armed with 28 Tomahawk cruise missiles capable of hitting any target in Syria.
Russia sent a massive naval armada to Syria — and looks to be readying to fight the US - Russia has positioned a considerable naval armada in the Mediterranean near Syria after accusing the US of plotting a false-flag chemical-weapons attack in rebel-held areas — and it looks as if it's preparing for war with the US. A Russian Defense Ministry spokesman, Maj. Gen. Igor Konashenkov, recently said the US had built up its naval forces in the Mediterranean and accused it of "once again preparing major provocations in Syria using poisonous substances to severely destabilize the situation and disrupt the steady dynamics of the ongoing peace process." But the Pentagon on Tuesday denied any such buildup, calling Russia's claims "nothing more than propaganda" and warning that the US military was not "unprepared to respond should the president direct such an action," CNN's Ryan Browne reported. Business Insider reviewed monitors of Mediterranean maritime traffic and found only one US Navy destroyer reported in the area. The same naval monitors suggest Russia may have up to 13 ships in the region, with submarines on the way. This time, Russia looks as if it's up to more than simply conducting a public-relations battle with the US. Russia's navy buildup around Syria represents the biggest since Moscow kicked off its intervention in Syria with its sole aircraft carrier in 2015.But even with its massive naval presence, Moscow doesn't stand a chance of stopping any US attack in Syria, Omar Lamrani, a military analyst at the geopolitical-consulting firm Stratfor, told Business Insider."Physically, the Russians really can't do anything to stop that strike," Lamrani said. "If the US comes in and launches cruise missiles" — as it has in past strikes — "the Russians have to be ideally positioned to defend against them, still won't shoot down all of them, and will risk being seen as engaging the US," which might cause US ships to attack them.
Caught On Video- Syrian Convoy Heads For Idlib Final Battle -- As speculation mounts that the Syrian army is preparing for a Russia-backed "anti-terror operation" in Idlib, dubbed by one army officer as "the final battle," video has emerged of a convoy of Syrian Army troops heading towards the frontline. As they passed through Maar Shahour village in Hama Governorate, soldiers rode on top of lorries carrying tanks, artillery and armored personnel carriers. One army officer said his troops were ready for the "final battle" against militants in Idlib province.This clip comes as Russian foreign minister Sergei Lavrov warned/asked the West not to intervene: "I hope our Western partners will not give in to (rebel) provocations and will not obstruct an anti-terror operation" in Idlib, foreign minister Sergei Lavrov said at a press conference with his Saudi counterpart Adel al-Jubeir in Moscow.Lavrov also said that there is "full political understanding" between Russia and Turkey, who support opposing sides of the Syrian civil war but are currently in intense negotiations to ensure Idlib does not become a breaking point in their alliance."It is necessary to disassociate the so-called moderate opposition from terrorists and at the same time prepare an operation against them while minimising risks for the civilian population," Lavrov said."This abscess needs to be liquidated."Lavrov went on to accuse the West of "actively heating up" the idea of a "so-called planned chemical attack by the (Syrian) government."As we detailed previously, over the last week, Moscow has accused Syrian rebels of planning to stage a chemical attack in the northwestern province that would "provoke" Western strikes on its ally Damascus. This month Syrian and Russian air attacks and shelling began targeting al-Qaeda held Idlib in what is likely a prelude to a full-scale ground offensive.
Russia Attached 12 Flamethrowers To A Battle Bot And Set It Loose In Syria - Russia has created a 12-ton "battle bot" which has been equipped with 12 Shmel-M man-portable rocket launchers classified as Rocket-propelled Infantry Flamethrower by their maker. Those can be fitted with destructive thermobaric and incendiary warheads. The flamethrowers are fitted on top of the vehicle’s turret into two, presumably revolving, assemblies and appear to be a permanent add-on to the robot’s firepower, reports state-owned news agency Tass. The "Uran-9" battle bot can also be configured with the standard armament of four "Ataka" anti-tank missiles, as well as 7.62mm and 30-millimeter guns. As RT adds, the 12-tonne vehicle has also retained its main armament, allowing it to take on tanks and light fortifications. Uran-9 has a 30mm 2A72 automatic gun, a 7.62mm PKTM machine gun, as well as four Ataka anti-tank guided missiles. The robot can be also fitted with Igla MANPADs, boosting the anti-aircraft capabilities of the unit it’s deployed with.While Russia says it has tested the bot in Syria and it "showed itself well," according to Defense Blog - citing a presentation at a February Russian security conference, the battle bot performed poorly. In addition to losing contact with ground control stations, the Uran-9 reportedly suffered from an unreliable gun and suspension system, and had difficulty targeting while in motion.
In Rare Meeting, Russia Delivers Intel To US Officials Showing "Planned Chemical Provocation" In Syria -- Russia says that its diplomats in Washington formally reached out to US officials and have briefed them on an impending plan by al-Qaeda insurgents in Idlib to stage a false flag chemical attack in order to provoke a Western military strike on Damascus. This week Moscow has claimed to be in possession of firm intelligence that it says shows armed groups in Idlib are transporting chemicals to area sites, in preparation for the coming major Syrian Army and Russian offensive on the contested province in northwest Syria. According to RT News, it appears that the State Department previously confirmed that the rare meeting did take place: Anatoly Antonov, the Russian ambassador in Washington, confirmed to the media on Wednesday that he had met with the US special representative to Syria, James Jeffrey, and David M. Satterfield, acting assistant secretary of state for near eastern affairs. The attendees of the rare meeting and the fact that it had taken place earlier this week was revealed by US State Department spokesperson Heather Nauert during a daily briefing. The meeting was reportedly held this past Monday, according to Russian Ambassador Antonov, who told RT it was "constructive and professional". We noted previously that Pentagon and US officials have continued pushing the gambit on Syria, with multiple statements last week and this week which appear to be setting the stage to play the "Assad is gassing his own people" card should so much as an inkling of an allegation emerge. With the dominant al-Qaeda group in control of Idlib, Hay'at Tahrir al-Sham (HTS), facing imminent defeat in what is likely to be a lengthy, grinding final showdown, they have every incentive to claim Syrian government forces are using sarin or another internationally banned substance. But it appears Monday's meeting constitutes a back-channel attempt to calm the fast intensifying situation.
Russia's "Nuclear Combat" War Games Largest In Nearly 40 Years --Russia's upcoming joint military exercise with China and Mongolia, set for September 11 - 15, will be the largest Russian drill in nearly 40 years according to Russian Defense Minister Sergei Shoigu, who said they will be larger than the Soviet military's 1981 Zapad-81 (West-81) exercises. "In some ways they will repeat aspects of Zapad-81, but in other ways the scale will be bigger," Shoigu told reporters from the Russian region of Khakassia. The exercise, Vostok-2018 (East-2018), will occur in central and eastern Russian military districts, and will involve nearly 300,000 troops, over 1,000 military aircraft, two of Russia's naval fleets, and their entire airborne forces, Shoigu said in a Tuesday statement. "Imagine 36,000 armored vehicles — tanks, armored personnel carriers and armored infantry vehicles — moving and working simultaneously, and that all this, naturally, is being tested in conditions as close as possible to military ones," said Shoigu. Also included in the drills, as we mentioned Friday, will be the inclusion of simulated nuclear weapons attacks. And according to the South China Morning Post (SCMP) the People's Liberation Army (PLA) will participate by sending about 3,200 elite forces troops, along with 30 fix-wing aircraft and helicopters to the Russian-hosted exercises. Japanese Prime Minister Shinzo Abe is scheduled to attend a forum in the Russian city of Vladivostok during the exercises, according to Reuters, while a Japanese Foreign Minister official said on Tuesday that Tokyo is monitoring developments between Beijing and Moscow. The war games, which will take place from Sept. 11-15, are likely to worry Japan, which has already complained about a Russian military build-up in the Far East, something Moscow has linked to Tokyo’s roll-out of the Aegis U.S. missile system. –Reuters The SCMP cites one Beijing based military expert, Zhou Chenming, to explain that the PLA is seeking to gain greater military experience as its last major combat theater stretches all the way back to the Vietnam War.
No comments:
Post a Comment