oil prices fell by more than 4% by midweek of the past week, but then recovered most of their earlier losses on Friday to end the week little changed...after sliding 1.4% to $48.82 a barrel last week on increased OPEC production, contract prices for WTI oil for September delivery fell 2.5% on Monday, the largest drop in 5 weeks, after Chinese refineries reported their lowest demand for oil in 3 years against the backdrop of rising crude output from OPEC and U.S. shale-oil producers, with oil prices settling at $47.59 a barrel, a loss of $1.23 on the day...oil prices then hit a three week low of $47.02 a barrel on Tuesday on ongoing demand concerns and strength in the US dollar, before recovering to settle little changed for the day at $47.55 a barrel...oil prices then tanked again on Wednesday, falling 1.6% to $46.78 a barrel by the close, largely on the EIA's report that US crude production rose to the highest level in over two years, while traders ignoried that the same report showed the largest weekly decline in U.S. crude supplies since last September...prices ended their three session slide on Thursday, rising 31 cents to close at $47.09 a barrel, on expectations of a hefty draw of crude from the U.S. oil storage hub at Cushing, Oklahoma, where US light sweet crude prices are benchmarked from...while little changed on Friday morning, oil prices took off on Friday afternoon after Baker Hughes reported that US oil rig count dropped by 5 rigs, the largest drop in 7 months, with near panic buying of crude futures pushing oil for September delivery up $1.42, or more than 3%, to $48.51 per barrel, which noneheless still left it down 31 cents on the week, for the 3rd consecutive weekly decline...
The Latest US Oil Data from the EIA
this week's US oil data from the US Energy Information Administration, covering details for the week ending August 11th, showed a modest increase in our imports of crude oil, ongoing near-record amounts of crude oil being used by US refineries, and a large withdrawal of oil from our commercial stocks, with all the data called into question by a large swing in unaccounted for crude oil...our imports of crude oil rose by an average of 364,000 barrels per day to an average of 8,126,000 barrels per day during the week, while at the same time our exports of crude oil rose by 170,000 barrels per day to an average of 877,000 barrels per day, which meant that our effective imports netted out to 7,249,000 barrels per day during the week, 194,000 barrels per day more than during the prior week...at the same time, our field production of crude oil rose by 79,000 barrels per day to an average of 9,502,000 barrels per day, which means that our daily supply of oil coming from net imports and from wells totaled an average of 16,751,000 barrels per day during the cited week...
during the same week, refineries used 17,565,000 barrels of crude per day, just 9,000 barrels per day less than they used during the prior record week, while at the same time 1,278,000 barrels of oil per day were being pulled out of oil storage facilities in the US...hence, this week's crude oil figures from the EIA seem to indicate that our total supply of oil from net imports, from oilfield production, and from storage was 464,000 more barrels per day than what refineries reported they used during the week...to account for that discrepancy, the EIA needed to insert a (-464,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, which they label in their footnotes as "unaccounted for crude oil"...that's a swing of 638,000 barrels per day from the "unaccounted" +173,000 figure of last week, and hence that discrepancy underlies all of this week's crude oil changes...
details from the weekly Petroleum Status Report (pdf) show that the 4 week average of our oil imports rose to an average of 8,046,000 barrels per day, which was still 4.7% below the imports of the same four-week period last year...the 1,278,000 barrel per day decrease in our total crude inventories was all withdrawn from our commercial stocks of crude oil, since the amount of oil stored in our Strategic Petroleum Reserve remained unchanged....this week's 79,000 barrel per day increase in our crude oil production resulted from a 54,000 barrel per day increase in oil output from Alaska and a 25,000 barrels per day increase in oil output from wells in the lower 48 states...the 9,502,000 barrels of crude per day that were produced by US wells during the week ending August 11th was the most we've produced since July 2015, 8.3% more than the 8,770,000 barrels per day we were producing at the end of 2016, and 10.5% more than the 8,597,000 barrel per day of oil we produced during the during the week ending August 12th a year ago, while oil output was still 1.1% below the June 5th 2015 record US oil production of 9,610,000 barrels per day...
US oil refineries were operating at 96.1% of their capacity in using those 17,565,000 barrels of crude per day, which was down from 96.3% of capacity the prior week, which had been the highest refinery utilization rate in 12 years...the amount of oil refined this week was 4.7% more than the 16,865,000 barrels of crude per day.that were being processed during week ending August 12th, 2016, when refineries were operating at 93.5% of capacity, and roughly 11.9% above the 10 year average of 15.7 million barrels of crude refined per day at this time of year...
even with oil refining little changed this week, gasoline production from our refineries decreased by 253,000 barrels per day to 10,048,000 barrels per day during the week ending August 11th, which left this week's gasoline output 2.3% lower than the 10,280,000 barrels of gasoline that were being produced daily during the comparable week a year ago....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) fell by 18,000 barrels per day to 5,287,000 barrels per day, which was still 7.0% more than the 4,939,000 barrels per day of distillates that were being produced during the week ending August 12th last year....
in spite of the decrease in our gasoline production, our end of the week supply of gasoline increased by 22,000 barrels to 231,125,000 barrels by August 11th, the 2nd increase in gasoline inventories in 9 weeks...that was as our domestic consumption of gasoline fell by 275,000 barrels per day to 9,522,000 barrels per day, while other factors worked to reduce supplies; ie, our imports of gasoline fell by 441,000 barrels per day to 667,000 barrels per day, and our exports of gasoline rose by 216,000 barrels per day to 670,000 barrels per day...however, with significant gasoline supply withdrawals in 7 out of the last 9 weeks, our gasoline inventories are still 0.7% below last August 12th's level of 232,659,000 barrels, even as they are still 8.6% higher than the 212,774,000 barrels of gasoline we had stored on August 14th of 2015, and almost 9% above the 10 year average for gasoline supplies for this time of the year...
similarly, even with the decrease in our distillates production, our supplies of distillate fuels rose by 702,000 barrels to 148,387,000 barrels over the week ending August 11th…that was as the amount of distillates supplied to US markets, a proxy for our domestic consumption, fell by 288,000 barrels per day to 4,222,000 barrels per day, and as our imports of distillates rose by 126,000 barrels per day to 167,000 barrels per day, even as our exports of distillates rose by 49,000 barrels per day to 1,132,000 barrels per day....even after this week’s increase, our distillate inventories were still 3.1% lower than the 153,135 ,000 barrels that we had stored on August 12th, 2016, and fractionally lower than the distillate inventories of 148,400,000 barrels of distillates that we had stored on August 14th of 2015, even as they remain roughly 5.7% above the 10 year average for distillates stocks for this time of the year…
finally, in light of this week's big swing in "unaccounted for crude oil", our commercial crude oil inventories fell for the 17th time in the past 19 weeks, apparently decreasing by another 8,945,000 barrels to 466,492,000 barrels as of August 11th, leaving us with the least oil we've had in storage since january 22nd 2016...thus, our oil inventories as of August 11th were also 4.9% below the 490,461,000 barrels of oil we had stored on August 12th of 2016, even as they were still 9.9% more than the 424,442,000 barrels in of oil that were in storage on August 14th of 2015...compared to historical quantities of oil we've had in storage at the same time of year, before our oil glut began to build up, this week's oil supplies were still 39.0% higher than the 335,568,000 barrels of oil we had in storage on August 15th of 2014, and about 40.3% above the 10 year average of our oil supplies for the second week of August ...
This Week's Rig Count
US drilling activity decreased for the 5th time in 8 weeks during the week ending August 18th, following a string of 23 consecutive weekly increases earlier this year, as drilling for oil slowed while rigs drilling for natural gas inched higher....Baker Hughes reported that the total count of active rotary rigs running in the US fell by 3 rigs to 946 rigs in the week ending Friday, which was still 455 more rigs than the 491 rigs that were deployed as of the August 19th report in 2016, even though it was still less than half of the recent high of 1929 drilling rigs that were in use on November 21st of 2014....
the number of rigs drilling for oil decreased by five rigs to 763 rigs this week, the largest drop in oil rigs since January 13th, which still left oil rigs up by 357 oil rigs over the past year, while their count remained far from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations increased by 1 rig to 182 rigs this week, which was also 99 more rigs than the 83 natural gas rigs that were drilling a year ago, but way down from the recent high of 1,606 natural gas rigs that were deployed on August 29th, 2008...in addition, one rig that was classified as miscellaneous started drilling this week, compared to the 2 miscellaneous rigs that were working a year ago..
the Gulf of Mexico rig count fell by one rig to 16 offshore rigs this week, which was down the 18 rigs that were working in the Gulf during the same week last year...in addition, the rig that had been drilling offshore from Alaska was also shut down, and thus the total US offshore rig count was down 2 to 16 rigs...
active horizontal drilling rigs fell by 2 rigs to 799 rigs this week, which left the horizontal rig count still up by 417 rigs from the 382 horizontal rigs that were in use in the US on August 19th of last year, while their count was also still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014....in addition, the vertical rig count was down by 6 rigs to 66 vertical rigs this week, which was still up from the 64 vertical rigs that were deployed during the same week last year...meanwhile, the directional rig count was up by 5 rigs to 81 rigs this week, which was also up from the 45 directional rigs that were deployed on August 15th of last year....
the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of August 18th, the second column shows the change in the number of working rigs between last week's count (August 11th) and this week's (August 18th) count, the third column shows last week's August 11th active rig count, the 4th column shows the change between the number of rigs running on Friday and the equivalent Friday a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was for the 19th of August, 2016...
it's odd to see a decrease in the Oklahoma rig count even as the Cana Woodford count is up by 4 and while the Ardmore Woodford also added a rig....that strongly suggests that the rig that was shut down in the Granite Wash was on the Oklahoma side of the Texas panhandle border, and that the two rigs that were idled in the Mississippian were similarly on the Oklahoma side of the Kansas border where that field lies...otherwise, changes in most other states match the basins; 2 rigs came out the Williston in North Dakota, and shutdown of 2 offshore platforms accounts for the rig count decreases in Alaska and Louisiana...meanwhile, the rig that was added in the Ardmore Woodford accounted for the natural gas addition; note that drilling in the 3 major natural gas basins, the Utica, the Marcellus, and the Haynesville, was unchanged from a week earlier...and there were also no changes in the number of rigs drilling in states other than those shown above..
DUC well report for July
Monday of this week saw the release of the EIA's Drilling Productivity Report for August, which includes the EIA's July data for drilled but uncompleted oil and gas wells in the 7 most productive US shale basins...commencing with Monday's report, the EIA has begun coverage of drilling productivity and drilled but uncompleted wells (DUCs) in the Anadarko region, which includes 24 Oklahoma and 5 Texas counties, and, which, based on their mapping, would apparently include the STACK and SCOOP reservoirs in the Woodford shale, and the Granite Wash tight sands band transversing the Oklahoma - Texas Panhandle border....by adding this region, this report now covers 87% of all U.S. onshore drilling operations....at the same time, they have consolidated their reporting on the Utica shale and the Marcellus into a single geographic unit labeled the Appalachia region...their reason for doing this appears to be a rather simplistic state border consideration; as they explain: "With the increasing number of wells in Pennsylvania being drilled into the Utica formation and some wells in Ohio producing from the Marcellus shale, the previous regional definitions based on surface boundaries are becoming less meaningful, especially where the two plays overlap."...as a result of this consolidation, the Appalachia region will refer to a wide geographical region that includes almost all of West Virginia, most of Pennsylvania, southeastern Ohio, and western New York..
after those changes, this report once again showed a large increase in uncompleted wells nationally, mostly because of dozens of newly drilled but uncompleted wells (DUCs) in the Permian basin of west Texas, but also because of proportional growth in uncompleted wells in the Eagle Ford of south Texas and the newly covered Anadarko region...for all 7 sedimentary basins covered by this report, the total count of DUC wells increased by 208, from 6,851 wells in June to 7059 wells in July, the ninth consecutive monthly increase in uncompleted wells, and, with the addition of the Anadarko, the highest number of such unfracked wells in the short history of this report....as we've seen from the weekly rig counts, US horizontal drilling expanded rapidly in the year thru June, more than doubling over that period, and as a result a shortage of competent fracking crews has developed, such that existing fracking crews have been unable to keep up with the number of newly drilled wells...moreover, the last month of trading for the July oil contract, which would govern prices received for oil produced during that month, saw prices average $46 a barrel, below the average breakeven price for most US basins, which probably discouraged any new production that hadn't been contracted for at a better price earlier...
with the addition of the Anadarko, a total of 1,224 new wells were drilled in the 7 basins now covered by this report during July, but only 1,016 drilled wells were completed in the same areas, thus accounting for the 208 DUC well increase for the month....as has been the case all year, the July DUC increases were predominantly oil wells, with most of those in the Permian basin...the Permian saw its total count of uncompleted wells rise by 135, from 2,195 DUC wells in June to 2,330 DUCs in July, as 485 new wells were drilled into the Permian but only 350 wells in the region were fracked...at the same time, DUC wells in the Anadarko region rose by 42, from 906 DUC wells in June to 948 DUCs in July, as 162 wells were drilled in the Anadarko region in July but only 120 drilled wells were completed....similarly, DUCs in the Eagle Ford of south Texas rose by 42, from 1,385 DUC wells in June to 1,420 DUCs in July, as 180 wells were drilled in the Eagle Ford during July, while just 145 Eagle Ford wells were completed....in addition, DUC wells in the Niobrara chalk of the Rockies front range increased by 6 to 674, as 148 Niobrara wells were drilled but just 142 Niobrara wells were fracked, while the Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 5 wells to 194, as 49 wells were drilled into the Haynesville, while 44 Haynesville wells were fracked during the same period.....on the other hand, the drilled but uncompleted well count in the Appalachian region fell by 13 wells, from 624 DUCs in June to 611 DUCs in July, as 71 wells were drilled into the Marcellus while 73 Marcellus were fracked, and as 29 new wells were drilled into the Utica during the month while 40 Utica wells were completed....the Utica now has just 43 DUC wells remaining, down from 126 DUC wells in January, so if the Utica frackers intend to keep Ohio gas production at their recent levels, more Utica wells would have to be drilled shortly....in the remaining region covered by this report, DUC wells in the Bakken of North Dakota decreased by 2 to 782, as 100 wells were drilled into the Bakken while 102 Bakken wells were fracked...thus, for the month of July, DUCs in the 5 oil basins tracked by in this report (ie., Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) increased by 213 wells to 6,154 wells, while the DUC count in the natural gas regions (the Marcellus, Utica, and the Haynesville) decreased by 8 wells to 905 wells, although as the report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
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Fracking issue in Youngstown could ignite fight in the courts: A vote from the Mahoning County Board of Elections to keep a Youngstown anti-fracking charter amendment off the Nov. 7 ballot isn’t going to happen for a few more weeks. And the board won’t even begin discussing it until Tuesday at the earliest. But it appears the board will decide to not put the proposal on the ballot for a seventh time. A bill signed by Gov. John Kasich in January that took effect in April on revising foreclosure laws included a number of amendments. One requires a board of elections or the secretary of state to invalidate a local initiative petition if either determines any part of the petition falls outside the local government’s constitutional authority to enact it. If the board of elections rejects the proposal, it can be appealed to the secretary of state, under the state law. After the secretary renders a decision, it would head to court. When that amendment was included, a state legislator said it was done largely to stop the anti-fracking proposal in Youngstown from getting on the ballot again. The citizens initiative, backed by the Youngstown Community Bill of Rights Committee, bans fracking in the city as well as anything remotely related to it including the storage or transportation of fracking waste-water. State law gives control over fracking to the Ohio Department of Natural Resources and not municipalities. Opponents of the proposal have long said that the requested ban isn’t enforceable because of that state law. Supporters say that would be determined after the proposal is passed and challenged in court. We’ve been uncertain about this since the first anti-fracking charter amendment was rejected by city voters in May 2013. It also lost in November of that year, twice in 2014, and once each in 2015 and 2016. If the board does reject the charter amendment, supporters of the proposal say they will take the matter all the way to court.
State parks likely safe from fracking - -- When the Ohio Senate returns on Aug. 23, it's likely to be only the third time in 38 years that the legislature voted to successfully override a governor's veto. The Senate is likely to override at least a handful of Gov. John Kasich's budget vetoes. But the chamber also is expected to pass on some of the 11 veto overrides approved by the House on July 6, including one that would give lawmakers the authority to appoint members to a commission that approves permits to allow fracking in state parks and other public lands. For five years, Kasich has refused to appoint members to the board, in effect creating a fracking moratorium on public lands. Senate President Larry Obhof, R-Medina, said his caucus has not finalized its veto override list, but he expects "several." However, Obhof said it's unlikely there is enough support to override items that were not included in the original Senate-passed version of the budget. That would include the Oil and Gas Leasing Commission, and a provision giving the legislature oversight of Medicaid rate increases. Other potential override votes could come on several other Medicaid bills where the House already has approved an override, such as requiring the state to seek a federal waiver requiring certain Medicaid enrollees to pay into a modified health savings account, allocating an additional $237 million for nursing homes, and mandating Controlling Board oversight of about $260 million of state-share Medicaid spending.
Blackstone’s New Pipeline Asset Is Wreaking Environmental Havoc - In the energy business, it’s one of the biggest projects going today: construction of a 710-mile pipeline to transport natural gas from America’s most prolific shale deposit in the eastern U.S. to consumers in the Midwest and Canada. Even Blackstone Group LP has agreed to take a sizable stake.But it holds another, more dubious, distinction. The Energy Transfer Partners LP pipeline has racked up more environmental violations than other major interstate natural gas pipelines built in the last two years, according to a Bloomberg analysis of regulatory filings during that period. And that’s all since U.S. regulators approved the $4.2 billion project in February.“Not only is it a situation where there are probably more incidents and more headlines than any other pipeline, on a project basis it’s a magnitude that we haven’t seen in years,” said Kyle Cooper, director of research with IAF Advisors in Houston.In Ohio, Energy Transfer has been cited for damaging protected wetlands and improperly disposing of wastewater, among other things. In West Virginia, a state regulator temporarily ordered the company last month to cease and desist activities after it inadvertently polluted streams. And in Washington, the Federal Energy Regulatory Commission has halted horizontal drilling on certain segments of the pipeline, following a massive 50,000-barrel spill of diesel-tainted drilling fluid. The Rover pipeline, running from the Marcellus shale deposit, is Energy Transfer’s biggest project since its controversial Dakota Access oil pipeline. Chief Executive Officer Kelcy Warren said on July 31 that he was “baffled” by regulators’ allegations. That same day, his company reached a deal to sell a 32 percent stake in the Rover unit to Blackstone for about $1.57 billion in cash. It’s expected to close in the fourth quarter. Blackstone spokeswoman Paula Chirhart said the firm declined to comment.
Rover Pipeline Sets Record for Environmental Violations - Energy Transfer Partners ' controversial $4.3 billion Rover pipeline has more negative inspection reports than any other major interstate natural gas pipeline built in the last two years, according to a new Bloomberg analysis. The 713-mile pipeline, which will carry fracked gas across Pennsylvania, West Virginia, Ohio and Michigan and Canada, has been stalled from numerous environmental violations, including a 2 million gallon drilling fluid spill into an Ohio wetland in April. Rover has accrued 104 violations since construction of the $4.2 billion project in started in March. That's more negative reports than the next four pipeline projects combined, including William's Virginia Southside Expansion (26 reports), Enbridge's Algonquin Incremental Market (24), Williams' Dalton Expansion (23) and Endbridges Sabal Trail (18). In May, the Federal Energy Regulatory Commission rejected Energy Transfer's request to resume horizontal directional drilling at two sites for the Rover Pipeline after numerous leaks into Ohio's wetlands as well as various Clean Air and Clean Water act violations across the state. Blackstone announced last month it was spending $1.57 billion for a 32 percent stake in the troubled project. "Rover will be built in compliance with all safety and environmental regulations and in some instances we will exceed those requirements," Energy Transfer spokeswoman Alexis Daniel told Bloomberg in response to the violation tally. Energy Transfer owns about 71,000 miles of natural gas, natural gas liquids, refined products and crude oil pipelines across the country and is the same company behind the Dakota Access Pipeline . Citing numbers from the Pipeline and Hazardous Materials Safety Administration, TheStreet reported in June that the Dallas-based firm spilled hazardous liquids near water crossings more than twice the frequency of any other U.S. pipeline company this decade.
Fracking Jobs Prove Elusive for Coal Miners Looking to Switch -- Robert Dennis has mined coal in West Virginia for 10 years but a recent evening found him in a classroom at his local community college. He came to learn about opportunities in fracking, a drilling technique used to produce natural gas — the very fuel that is threatening coal’s future.“I know mining inside and out,” said Dennis, a 41-year-old shift foreman from Wetzel County, adjusting the black Adidas cap on his head. But now, “I just want more doors to be open.”He has earned a certificate in chemical and industrial operations, diligently searched job boards and filled out applications. So far, no luck. Dennis is learning a hard lesson of fracking: While it has created a bonanza of jobs, displaced coal miners and their communities are sometimes left out of the boom. That’s because many of the jobs require highly technical skills and are often going to experienced workers brought in from out of state who then move on to the next job without sinking roots. When the “shale gale” hits, hotels, trailer parks and restaurants get a boost. And some landowners make money for letting drillers extract oil and gas from their property. In that way, fracking has “created a lot of millionaires in West Virginia,” said Jeff Kessler, a former state senator from the state’s northern area that has both coal and natural gas. “But it has not created the employment opportunities” area residents had hoped for, he said. “The ongoing benefits are relatively minute compared to the amount of land under lease.” That’s bad news for towns like Wetzel County’s New Martinsville where Dennis attended the community college session. While coal mines provide decades of steady work and sustain communities, a crew can frack a well in a month and leave behind automated machinery to recover the oil and gas.
Fracking Giant Sues Dimock Resident for $5M for Speaking to Media About Water Contamination -- Ever since the dangerous consequences of natural gas extraction via hydraulic fracturing—popularly known as " fracking "—entered the national consciousness, the small town of Dimock, Pennsylvania has arguably been "ground zero" for water contamination caused by the controversial practice. Now Cabot Oil & Gas, the massive energy company responsible for numerous fracking wells near Dimock, is suing one of the town's residents for $5 million, claiming that his efforts to "attract media attention" to the pollution of his water well have "harmed" the company. According to the lawsuit, Dimock resident Ray Kemble's actions breached an earlier 2012 settlement that was part of an ongoing federal class action lawsuit over the town's water quality. Kemble has stated that Cabot's fracking turned his groundwater "black, like mud, [with] a strong chemical odor." Earlier this year, Kemble filed a follow-up lawsuit against Cabot, which was based on new findings that could help him prove the link between Cabot's fracking operation and the contamination of his well. Cabot, at the time, argued that the case was built on "inflammatory allegations" intended to "poison the jury pool" and "extort payment" from the company. Kemble eventually dropped his lawsuit, acting in response to new information that he thought might negatively affect the case. Kemble's lawyers have declined to comment on the nature of that information. Cabot alleged that this lawsuit was a breach of the 2012 settlement contract Kemble had signed, prompting them to counter-sue Kemble. In context, Cabot's decision to sue Ray Kemble appears meant to intimidate and "send a message" to Kemble and any other resident thinking of voicing similar concerns and objections.
Trump order aims to speed pipeline reviews, approvals - The Trump administration plans to quicken the review process for oil and natural gas pipelines in federally-designated energy corridors, according to an executive order signed by President Trump Tuesday. Trump announced the order at a press conference at Trump Tower Tuesday, but the text of the order was not released until early Wednesday. Related: Find more content about Trump's administration in our news and analysis feature. The order is aimed at quickening the pace of environmental reviews and federal permitting for pipelines and other infrastructure projects, part of an effort to remove regulatory uncertainty for projects, Trump said. "So it's going to be quick, it's going to be a very streamlined process," Trump said. "And, by the way, if it doesn't meet environmental safeguards, we're not going to approve it. Very simple." The order calls for making the federal environmental review and permitting process "coordinated, predictable, and transparent," according to the text, setting a goal for federal authorization decisions for major infrastructure projects of two years. Such infrastructure projects include roads, bridges, railroads and ports, but also infrastructure for "energy production and generation, including from fossil, renewable, nuclear and hydro sources," according to the order. The order calls on the US Interior and Agriculture departments to lead an effort to identify "energy right-of-way corridors" on federal lands that would be subject to "expedited" reviews for energy infrastructure projects.
Natural gas pipeline projects lead to smaller price discounts in Appalachian region - As new pipeline projects and expansions are completed, the difference between the Henry Hub national benchmark price and daily spot natural gas prices at pricing hubs in the Appalachian region has narrowed. Through the first seven months of 2017, the difference between prices at the Henry Hub in Louisiana and at Dominion South in southwestern Pennsylvania averaged $0.53 per million British thermal units (MMBtu), about two-thirds the average difference of $0.76/MMBtu during the first seven months of 2016. The differences between the Henry Hub and other Appalachian region price points followed similar trends. Appalachian regional prices are influenced by regional production rates and the availability of infrastructure to transport natural gas to demand centers. Production in Ohio, Pennsylvania, and West Virginia from the Marcellus and Utica shale plays has grown rapidly over the past several years, and infrastructure to deliver natural gas to consumers has not kept pace. While the average difference between natural gas prices at the Henry Hub and Appalachia have generally narrowed over the first 7 months of 2017 relative to the comparable year-ago period, the Appalachian region can become oversupplied at times when production exceeds pipeline capacity, driving producers in the region to lower their prices relative to Henry Hub. As of July 31, the natural gas price at Dominion South in southeast Pennsylvania traded at $1.85/MMBtu, about $1.00/MMBtu lower than the natural gas price at Henry Hub. During 2016, 11 interstate pipeline projects in the Northeast were completed, adding just over 4.0 Bcf/d of interregional capacity. Much of this capacity came on between July and December, as only 0.9 Bcf/d of capacity was completed in the first half of the year. With limited infrastructure to deliver the available supply to consumers and high regional natural gas inventories, the difference between prices at Dominion South and Henry Hub widened from an average of $0.62/MMBtu in the first half of 2016 to $2.55/MMBtu at the end of September. Starting in October 2016, more pipeline projects were completed, including two of the biggest projects in the region, the Equitrans expansion of the Ohio Valley Connector and the Rockies Express Pipeline Zone 3 Capacity Enhancement. This growth in pipeline capacity likely contributed to a narrowing of the spread between the Henry Hub and Dominion South price points, which reached $0.49/MMBtu at the end of the year.
America's Shale Natural Gas Production Is Taking Off - Sort Of - (Bloomberg) -- America’s shale gas production is about to surge 12 percent. Sort of. The Energy Department issued a report Monday estimating that the nation’s prolific shale formations will yield 59.4 billion cubic feet a day in September, a massive jump from the roughly 53 billion projected for August. The difference: The agency began including the more than 6 billion cubic feet a day of gas flowing out of the Anadarko basin of Oklahoma and Texas. The addition of the Anadarko is testament to the flood of gas flowing out of shale formations known better for their oil riches. Almost half of the country’s shale gas is now being produced in crude plays, pulled out of oil wells as a byproduct. These supplies, known as associated gas, threaten to quash any meaningful recovery in an already-glutted market. “This is again telling us why we are in a perpetual bear market in natty gas,” said Stephen Schork, president of Schork Group Inc., a consulting group in Villanova, Pennsylvania. “We are finding more and more gas. It’s giving the bears more ammo.” Better drilling and well completion techniques have revived the Anadarko, which the Energy Department described as an “already well-established oil and gas producing basin.” The region was home to 129 active drilling rigs as of July, second only to Texas’s oil-rich Permian Basin, the agency’s monthly report showed. Gas futures have meanwhile been battered this year by a shale-driven supply glut that has persisted for much of the past two years. Prices have dropped 21 percent this year, settling Monday at $2.96 per million British thermal units on the New York Mercantile Exchange.
NYMEX September gas rises as storage revision trumps bearish build -The NYMEX September natural gas futures contract rose Thursday as revisions to the previous weeks' stocks data overshadowed a larger-than-expected storage build in the most recent week.The September contract settled at $2.929/MMBtu, up 3.9 cents from Wednesday's close.The impact of the first above-average storage injection that the US Energy Information Administration announced in six weeks was curbed by EIA's revisions for the weeks ending June 30 through August 4. The revisions cut stocks for the week that ended August 4 to 3.029 Tcf, down 9 Bcf from what EIA previously estimated. The revisions were due "in large part because of restatements of natural gas in storage from working gas to base gas," according to the EIA. Prices initially dipped as the market reacted to the estimated 53 Bcf storage build EIA announced for the week that ended August 11, 6 Bcf above the 47-Bcf build expected by a consensus of analysts S&P Global Platts surveyed.But prices moved into positive territory as the revision was taken into account. The bearish build was above the 50-Bcf average injection for the most recent reporting week over the past five years, the first time in six weeks a build has outpaced the five-year average, according to EIA data. Because of the revision, natural gas stocks now only have a 55 Bcf, or 1.8%, cushion over the five-year average, according to EIA data. There has been sentiment in the market that a colder-than-average winter could boost prices if the surplus to the five-year average continues to dwindle. Looking ahead, the most recent six- to 10-day weather outlook from the US National Weather Service continues to call for warmer-than-average weather across the Northeast, with the Midcontinent expected to see average temperatures.
Virginia governor opposes offshore drilling plan | TheHill: Virginia Gov. Terry McAuliffe (D) on Thursday came out against expanding offshore drilling in the Atlantic Ocean waters off the coast of his state. McAuliffe had previously said he could support drilling near Virginia on the condition that the federal government expand a royalty sharing program that would supply coastal states with revenue from drilling operations. But, in a letter to Interior Department officials and a statement released Thursday, McAuliffe said he doesn’t believe the Trump administration will agree to such a plan, and he said he opposes oil and natural gas drilling in the Atlantic without one.“President Trump’s proposal to end the revenue sharing agreement with the Gulf States is a clear indication that we cannot trust the president to give Virginia its fair share of the revenues that would result from offshore exploration,” McAuliffe said in a statement, noting a provision in Trump’s budget proposal that would end a revenue sharing program in the Gulf of Mexico. “Additionally, the president’s administration is actively working to cut funding from the very agencies that would be charged with protecting Virginia’s coastal environment in the event that exploration went forward,” he added. McAuliffe’s announcement comes as the Interior Department finishes hearing comments on a proposal to reopen the Outer Continental Shelf leasing program for oil and gas drilling.
Professor: pipeline brings adverse impact on economy via climate change — A proposed pipeline will have an adverse impact on the economy because of its contribution to climate change, a university professor said Thursday. Ryan E. Emanuel, associate professor at N.C. State University’s Department of Forestry and Environmental Resources, spoke at a “listening session” held by state officials to get feedback on the proposed Atlantic Coast Pipeline. He said he was speaking as a private citizen and not as a representative of the school. Emanuel, who described himself as an expert on water, carbon and climate issues, said he wanted to give an independent, scientific perspective on the pipeline. He said the cumulative impacts project on climate change are unambiguous and shouldn’t be ignored. “The best science available today, including the National Climate Assessment, says that we should back away, immediately from new fossil fuel infrastructure, including major pipelines,” he said. “This is our only hope to keep climate change in check.” Emanuel also questioned the pipeline’s economic impact. He said research shows that climate change is expected to cost the United States about 1 percent of its gross domestic product by the end of the century. That would cost North Carolina about $4 billion a year, Emanuel said. Since poorer areas likely would feel the impact more, Robeson County could see a 10 percent to 15 percent impact, he said. Revels said Native Americans were not informed that the pipeline was going through their land. He asked state officials to consider the impact that the project might have on the next seven generations.
Oil Industry, Trump Administration Plan to Drill Off Florida’s Coast -The Trump administration is putting energy industry special interests ahead of public health. Its latest awful proposal? Open up more of our coasts to offshore drilling, including Florida’s coasts.The Department of the Interior is taking public comments on this plan until Thursday, August 17. Make sure they hear us loud and clear: Drilling off Florida’s coasts is too risky! In 2006, a moratorium on drilling in the Gulf within 125 miles of Florida’s coast was put in place until 2022. But Trump wants to ignore the moratorium and open it up to Big Oil anyway, putting our environment and way of life at risk.The BP Deepwater Horizon disaster in 2010 wreaked havoc on the Gulf of Mexico, killing 11 workers and spewing nearly 5 million barrels of oil over the course of 3 months. The spill caused massive wildlife die-offs, including the largest dolphin die-off ever recorded in the Gulf of Mexico.The BP oil spill wrecked our economy in the Sunshine State: even south of the Panhandle, where the impacts were less severe, we lost 50,000 jobs as a result of the economic backlash from the spill. Simply put, tourists did not want to vacation near an oil spill. And in the Panhandle, where tarballs from the spill regularly washed ashore, the economic impacts were even greater. This proposal is part of a larger plan to massively expand oil drilling across the country. Donald Trump recently authorized drilling to begin in the Arctic and has already given Eni, an Italian oil company, permission to drill exploratory wells off the coast of Alaska.
Oil terminal launches weekly quality report for LOOP Sour blended crude: --- The Louisiana Offshore Oil Port launched Monday the first of what will be weekly quality reports on its medium sour blended crude LOOP Sour, a move to bring more up-to-date information to market participants that runs counter to current practices. LOOP said Monday it will publish a rolling one-year graph containing weekly breakdowns of API gravity and sulfur for LOOP Sour deliveries ex-cavern. LOOP will continue to publish its monthly quality report, which is typically released on the first business day of the month and lists quality information for deliveries made during the prior month. LOOP Sour is a blend of US Gulf of Mexico grades Mars and Poseidon, and a blend of Middle East crudes called Segregation 17, comprised of Arab Medium, Basrah Light and Kuwait Export Crude. It is stored in cavern at the Louisiana Offshore Oil Port terminal. In Monday’s report, LOOP said LOOP Sour’s API gravity had a one-year low of 28.9 and high of 31.4, while its sulfur content spread was 2.02% and 2.96%. According to monthly reports, the average from August 2016 through July 2017 was 30.2 for API and 2.53% for sulfur. The move to publish weekly reports is notable because regular quality reports are often rare for crudes marketed around the world. In the US Gulf Coast, stakeholders for medium sour grades Poseidon and Mars used to publish monthly assays for those grades but ultimately stopped. For Mars, majority stakeholder Shell does list an assay on its website while minority partner BP’s latest assay is dated September 2012. Poseidon Oil Company’s website has not had updated quality information for that grade since February 2015. API gravity and sulfur are just two of many characteristics refiners look at when deciding what crudes to run in order to maximize or minimize production of particular refined products. Other factors include acidity, metals content, presence of asphaltenes and ultimately a distillation curve.
Are the Capline Pipeline and LOOP About to Enter a New Era? -- The stars may finally be aligning for two related crude oil infrastructure projects that, if undertaken, would provide an important new pathway to overseas markets for Bakken, western Canadian and other North American crude. The first would involve reversing the Capline Pipeline, which was built to transport crude north from the U.S. Gulf Coast to Midwest refiners; the second would make modest physical changes to the Louisiana Offshore Oil Port — better known as LOOP — to allow the crude import facility off the Bayou State coast to load crude onto ships, including Very Large Crude Carriers (VLCCs). Today we look at the new infrastructure and market forces that may finally spur Capline’s reversal and lead imports-focused LOOP to enable exports. We noted more than five years ago in the opening line of Draggin’ the Capline that “Crude oil wants to flow south to the U.S. Gulf” and that the utilization of the 1.2-MMb/d Capline Pipeline (yellow line in Figure 1) from the St. James, LA crude oil hub to the Patoka, IL hub (which is connected to more than 2 MMb/d of Midwest refining capacity) had fallen to only 14%. This decline was largely because Midwest refineries had gained access to the increasing volume of crude available from western Canada and the Bakken. This low rate of Capline utilization raised questions about whether the pipeline’s flow should be reversed to help move Bakken and western Canadian crude south. (Capline is co-owned by Plains All American, with a ~54% stake; Marathon Petroleum, with ~33%; and BP, with ~13%.)
A Venezuelan Tanker Is Stranded Off The Louisiana Coast -- A tanker loaded with 1 million barrels of Venezuelan heavy crude has been stranded for over a month off the coast of Louisiana, not because it can't sail but as a result of Venezuela's imploding economy, and its inability to obtain a bank letter of credit to deliver its expensive cargo. It's the latest sign of the financial troubles plaguing state-run oil company PDVSA in the aftermath of the latest US sanctions against the Maduro regime, and evidence that banks are slashing exposure to Venezuela across the board as the Latin American nation spirals into chaos.As Reuters reports, following the recently imposed US sanctions, a large number of banks have closed accounts linked to officials of the OPEC member and have refused to provide correspondent bank services or trade in government bonds. The stranded tanker is one direct casualty of this escalation.The tanker Karvounis, a Suezmax carrying Venezuelan diluted crude oil, has been anchored at South West Pass off the coast of Louisiana for about a month, according to Marinetraffic data. For the past 30 days, PBF Energy, the intended recipient of the cargo, has been trying unsuccessfully to find a bank willing to provide a letter of credit to discharge the oil, according to two trading and shipping sources. The tanker was loaded with oil in late June at the Caribbean island of St. Eustatius where PDVSA rents storage tanks, and has been waiting for authorization to discharge since early July, according to Reuters. It is here that the delivery process was halted as crude sellers request letters of credit from customers that guarantee payment within 30 days after a cargo is delivered. While the documents must be issued by a bank and received before the parties agree to discharge, this time this is impossible as the correspondent bank has decided to avoid interacting with PDVSA and running afoul of the latest US sanctions. It was not immediately clear which banks have denied letters of credit and if other U.S. refiners are affected.
Known Gulf of Mexico deepwater areas most attractive in modest lease sale - US Gulf of Mexico Lease Sale 249 on Wednesday was not a barn-burner, but it did show a measure of competitive bidding in the deepwater and even boasted two eight-figure bids and dozens more that topped $1 million each. The sale appeared to highlight majors' preferences for known deepwater areas, since shallow-water bidding accounted for a scant 10 blocks and offers received for these were mostly under $200,000 each. But sale sponsor Bureau of Energy Management officials expect interest in shallow water bidding to improve in subsequent sales, owing to the agency's recent lower royalty relief reduction aimed at drumming up more development in that arena. "We only provided a month's time for [operator] interest in the lower royalty," said Mike Celata, BOEM Gulf regional director, in a post-sale telephone press conference. "My expectation is that in March we'll have greater interest." In July, the agency reduced the royalty rate for leases in water depths less than 200 meters to 12.5% from 18.75%. High bids in Sale 249 totaled $121 million, while the sum of all bids including those apparently not successful, was $137 million, BOEM statistics showed. That compares to $275 million and $315 million respectively at the last US Gulf sale in March 2017. At Wednesday's auction, France's Total made the sale's apparent high bid of $12.1 million for a deepwater lower-Garden Banks area bid in the Gulf's remote Lower Tertiary play, out-elbowing Cobalt International Energy which offered $3.5 million for it.
Lawmakers push Interior to expand offshore drilling - More than 100 lawmakers are urging the Trump administration to consider allowing oil and natural gas drilling in more areas off the coast of the United States. In a Wednesday letter to Interior Secretary Ryan Zinke, the members said officials should consider a more expansive drilling programs when it rewrites a five-year leasing outline, a key goal for Zinke and President Trump. "Just as today's energy security is the result of production set in motion by decisions made years ago, the decisions on [Outer Continental Shelf] leasing and development facing the department today will lay the groundwork for our energy and national security for decades,” said the letter, led by House Natural Resources Chairman Rob Bishop (R-Utah) and signed by 118 members. “There is demonstrated interest in the leasing and development of previously excluded areas and we must consider these areas for development to optimize our nation’s resource potential.” The letter comes as the Interior Department takes public comments on a new leasing plan, including the potential for drilling in all areas currently set aside for oil and gas production in the Atlantic and Arctic Oceans and the Gulf of Mexico. Another group of 69 lawmakers, led by Rep. Jared Huffman (D-Calif.), told Interior to block drilling in the Arctic and Atlantic Oceans as part of the review. “The risks are simply too high, and the consequences too severe,” they wrote in a letter. “It is time to preserve and protect this vital part of America’s national heritage for future generations.”
Yet Another Reminder that Dirty Oil Pipelines Are Never Safe -- In March of 2013, ExxonMobil's Pegasus Pipeline sprung a leak, spilling an estimated 210,000 gallons of toxic tar sands crude into a residential neighborhood of Mayflower, Arkansas. This week, a federal court ruled that the Obama administration over-penalized Exxon for dumping hundreds of thousands of gallons of a pollutant onto the streets of Mayflower and threw out a number of safety violations levied against Exxon on the basis that the company met its legal obligations to consider the risks associated with the pipeline . In the court's decision, Judge Jennifer Walker Elrod noted, "The unfortunate fact of the matter is that, despite adherence to safety guidelines and regulations, oil spills still do occur." Just think about that for a minute. The court ruled that even if a pipeline spill devastates a community, if the company can prove they followed safety guidelines, they shouldn't be held accountable for the damage they caused. That oil spills that threaten communities across the country are to be expected—just the "unfortunate" price we all have to pay for oil companies to transport their dirty product to market. We've long argued that it's never a question of if a pipeline will spill, but when, and how much damage it will cause when it does. A recent report from Greenpeace bears this out, analyzing the track records of the companies behind major proposed tar sands pipeline projects including Keystone XL and the Line 3 pipeline expansion. These three companies, TransCanada, Kinder Morgan, Enbridge, and their subsidiaries, have had 373 spills from their pipelines in the U.S. since 2010. That's an average of one significant incident and a total of about 570 barrels of oil spilled per year for every 1,000 miles of pipe. Based on these rates, Keystone XL could expect 59 significant spills over its 50-year lifetime and the Line 3 expansion could expect about 51.
Fracking Debate Ramps Up Again in Illinois With First Permit Application Under New Rules – Four years ago, the Illinois legislature passed a law to regulate high volume hydraulic fracturing, or fracking , after months of contentious negotiations between oil industry interests, environmental watchdogs and community groups. Leading up to the law's passage, companies had secured hundreds of leases to potentially frack in Southern Illinois. But then oil prices dropped, and the eagerness to tap the state's New Albany Shale faded. This summer, the filing for the first permit under the new rules has reignited debate over fracking in Illinois and concerns over the law's ability to protect citizens and the environment. Environmental and citizen groups say that this permit will be a test case as to how rigorously the Illinois Department of Natural Resources (IDNR) will seek to enforce the law. In the spring, the Kansas-based, family-owned company Woolsey Energy filed for a permit to frack in White County in southeastern Illinois. Advocates criticized that permit as incomplete and inconsistent, and the department sent Woolsey back to the drawing board. Woolsey submitted a revised permit application this summer, with the public comment period closing this month. Environmental advocates say the revised permit is still sorely lacking required information, and they are urging the IDNR to reject it. "The company still did not provide the required information, putting public health and safety, groundwater, topsoil and other resources at potential risk," said Karen Hobbs, senior policy analyst for the water program of the Natural Resources Defense Council 's Midwest office. "How IDNR handles this application will set the benchmark for the program's future and ultimately determine if it is successful."
Permian takeaway update, part 4. -- Nearly two-thirds of the effective NGL pipeline takeaway capacity out of the Permian is controlled by Energy Transfer Partners and DCP Midstream. But there are several other NGL pipelines used to flow Permian NGLs to faraway storage facilities and fractionators — assuming, that is, that their natural gas processing plants are connected to the pipe alternatives in question. Today we continue our blog series on the NGL side of the Permian with a look at Enterprise Products Partners’ Chaparral and Seminole pipelines and Enterprise’s and BP’s Rio Grande Pipeline, including the volumes of NGLs that have been flowing through them. Exploration and production companies (E&Ps) active in the Permian are primarily in pursuit of crude oil, but as we said in Part 1 of this series, oil wells in the play also produce large volumes of associated natural gas and natural gas liquids (NGLs) that add considerable monetary value of their own. The region already is producing 2.3 million barrels a day (MMb/d) of crude oil and 6.6 billion cubic feet per day (Bcf/d) of dry natural gas, and under RBN’s Growth Scenario those numbers are expected to rise to 3.7 MMb/d and 12 Bcf/d, respectively, by 2022. The growth outlook for Permian NGLs is similar. Nearly 800 Mb/d are being produced today, and five years from now the region’s NGL output could top 1.4 MMb/d, a prospective increase of nearly 80%. Almost all of the associated gas that emerges from Permian wells needs to be run through natural gas processing plants (which separate raw gas into dry gas and mixed NGLs), and then the dry gas and NGLs (also known as y-grade or raw mix) need to flow through takeaway pipelines — gas to storage or directly to end users, and NGLs to storage for subsequent fractionation into purity products: ethane, propane, normal butane, isobutane and natural gasoline.
NGL pipelines out of the Permian, part 5. - Production of natural gas liquids in the Permian is growing so quickly that within a year or two some parts of the super-hot play may experience NGL takeaway constraints. That is good news for the owners of the eight existing NGL pipelines out of the Permian, which are likely to see flows on their pipes increase as NGL production rises — assuming, that is, that they have capacity to spare and that they are connected to natural gas processing plants within the faster-growing parts of the region. Today we continue our blog series on Permian NGL production, processing and pipelines with a look at ONEOK’s West Texas LPG Pipeline and the Chevron Phillips Chemical EZ Pipeline. The Permian is a crude oil-focused play, but as we said in Part 1 of this series, oil wells in the play also produce large volumes of associated natural gas and natural gas liquids (NGLs) that add to the bottom lines of exploration and production companies (E&Ps) there. The region already is producing 2.3 million barrels a day (MMb/d) of crude oil and 6.6 billion cubic feet per day (Bcf/d) of dry natural gas, and under RBN’s Growth Scenario, those numbers are expected to rise to 3.7 MMb/d and 12 Bcf/d, respectively, by 2022. Production of NGLs is expected to rise nearly 80% over the same period, from almost 800 Mb/d today to about 1.4 MMb/d five years from now.
Pullback in U.S. fracking sand use pressures producers - U.S. shale oil companies are pulling back on the amount of sand they use to hydraulically fracture new wells, responding to rising prices of the material that are driving up costs. Investors worry a slowdown in sand use, combined with new mining capacity coming online, could lead to a glut of the material and bring down prices. The worries have pressured shares of sand companies. Sand prices soared in the last year as oil companies ramped up shale drilling and production. But with crude prices below where they started the year, oil producers are employing new well designs and chemical agents that lessen the use of sand that represents around 12 percent of the cost of drilling and fracturing. The price of frack sand is expected to rise 62 percent this year to average $47 a ton, according to researcher IHS Markit. That is expected to drive oilfield service price inflation to 15 percent over 2016, according to researchers at Wood Mackenzie. Oilfield services provider Halliburton, which buys sand for its drilling customers, last month reported its first decline in average sand used per well, saying customers wanted designs that consumed less of the material. Average sand volumes for each foot of a well drilled fell slightly last quarter for the first time in a year, said exploration and production consultancy Rystad Energy. Volumes are expected to drop a further 2.5 percent per foot in the current quarter over last, Rystad forecast.
West Texas sand rush exposes faults in state's lizard protection plan - State officials responsible for species protection concede new mining operations caught them by surprise.The scope of the industry’s plans for the Permian Basin is still unknown. By exposing weaknesses in Texas’ plan to protect the lizard, sand mining could revive legal challenges.A sudden influx of mining companies scraping the West Texas oil patch for sand to use in fracking operations has disrupted nearly as much highly sensitive habitat of a rare lizard in the last three months as the oil and gas industry had in the previous five years, according to state officials and a conservation group that monitors the area.The development, they say, exposes deep, and potentially fatal flaws in the state’s much-vaunted private-public plan to protect the rare dunes sagebrush lizard.The Texas Conservation Plan was adopted in 2012 as a way to avoid the land-use restrictions that would accompany the U.S. Fish and Wildlife Service officially designating the small brown lizard as endangered. Pushed by then-Comptroller Susan Combs, an outspoken critic of such listings, the deal enlisted oil and gas companies to protect the species by paying to monitor and minimize damage to its Permian Basin habitat. Conservation groups who challenged it in court as unenforceable because it was voluntary ultimately lost their case.The agreement was hailed as a victory that would protect the lizard while allowing Texas’ powerful oil industry to operate with minimal restrictions. Yet the arrival of the sand companies has provided a stark illustration of the plan’s limitations.The Texas plan did not anticipate the possibility of another large industry threatening the lizard’s habitat. So the comptroller’s office, which oversees the state’s endangered species, was caught by surprise when the frac-sand companies started churning up sand earlier this summer. Even now, with the threat in view, the plan supplies state officials with no tools to compel the sand mining companies to join the effort to protect the lizard. The comptroller “has no authority to stop the development of frac-sand operations,”
Evolving Oklahoma STACK play continues to draw interest as E&P operators seek sweet spots, IHS Markit says -- Despite the fact that the Oklahoma STACK oil and gas play is still evolving and its total potential is undetermined, evidence thus far indicates the play is delivering impressive results, leading operators to commit significant 2017 CAPEX to its development, according to new analysis from IHS Markit. “The Oklahoma STACK (Sooner Trend Anadarko Basin Canadian and Kingfisher County) play is early in its development but wells have shown great productivity,” said Imre Kugler, associate director, energy research at IHS Markit and author of the IHS Markit Plays and Basins: Oklahoma STACK analysis. “Questions still remain regarding potential across various horizons; however, for operators with acreage and capital to test the play, economic upside exists so the biggest six operators in the play are on track to invest more than $2.5 billion during 2017.” Whether the play will be a major contributor to domestic supply is still undetermined, Kugler said. “To date, fewer than 1,000 wells have been brought online in the liquids-rich STACK play, but estimated break-evens for first quintile wells in the play are quite low and competitive with top Permian plays. First quintile wells in the STACK for both short- and long-laterals are estimated to break even under $30 per barrel.” The early stage of the STACK play equates to some variance in well performance as operators seek to optimize development. The spread between first and second quintile wells is wider when compared with the relatively more well-known Permian plays, with second quintile STACK wells estimated to break even near $41 per barrel for longer laterals, and $55 per barrel for shorter laterals, IHS Markit said.
Anadarko shale basin lands Oklahoma on EIA map - (UPI) -- With more than 10 percent of the new wells drilled in U.S. shale basins, Oklahoma has earned a place in new monthly data reporting, the government said.The U.S. Energy Information Administration said it was adding the Anadarko region to its monthly drilling report. The shale basin covers 24 counties in Oklahoma and five in Texas."The Anadarko region accounts for approximately 450,000 barrels per day of oil production, 5.7 billion cubic feet per day of natural gas production, 13 percent of new wells drilled, and 13 percent of drilled but uncompleted wells as of July 2017," EIA reported.Oklahoma is home to about 4 percent of the total petroleum reserves in the country and accounts for as much as 5 percent of the total crude oil production in the United States. The EIA said the Anadarko basin is a legacy producer that's seen an uptick in activity from the STACK and SCOOP reservoirs within the broader shale area. Shale work in Oklahoma is under close monitoring because of a new fault located in the region by the U.S. Geological Survey. At least eight earthquakes were recorded Aug. 3 in the state, the largest of which was a magnitude-4.2 event. EIA estimates August oil production from the Anadarko shale at 447,000 barrels per day and output should increase about 2.5 percent in September. Gas production should average 5.9 million cubic feet for August and increase 1.3 percent next month. On natural gas in particular, EIA said it was consolidating data from the Marcellus and Utica shale basins that cover states from Ohio to New York.
Fracking boom: US shale oil output to top 6 million barrels a day in August and September -- U.S. shale drillers will keep posting strong gains in August and September, with production from shale regions topping 6 million barrels a day, the Department of Energy projected. The department's Energy Information Administration projected output in several key oil producing regions will grow by 117,000 barrels a day to 6.15 million barrels a day in September. The region's output is seen topping 6 million barrels a day in August. The forecast for this month is significantly higher than a prior estimate, primarily because the EIA began projecting output for the Anadarko region, which covers parts of Oklahoma and Texas, in its August Drilling Productivity Report. Drillers have recently flocked to the Anadarko because the cost of producing oil there is relatively low. The latest Drilling Productivity Report from EIA marks the sixth straight month the agency has forecast production growth above 100,000 barrels a day. Oil prices have averaged approximately $49.50 this year, jumping above the key $50 level at times, allowing U.S. drillers to lock in higher prices for future deliveries. That has allowed them to increase output in America's shale regions, where producers rely on expensive drilling methods to free oil and gas from rock formations. Drillers in Texas and New Mexico's Permian Basin, the center of the shale oil recovery, are on pace to boost drilling by 64,000 barrels a day in September to a total of 2.6 million barrels a day, EIA forecasts. Output from the Niobrara region underlying northern Colorado and neighboring states is set to rise by 15,000 barrels a day, EIA said. The Eagle Ford region in South Texas is likely to see output rise 14,000 barrels day. The Anadarko and North Dakota's Bakken region are tracking for growth of 12,000 and 10,000 barrels a day, respectively.
Wyoming Fugitive Sought For Dumping Radioactive Oilfield Waste --The U.S. Environmental Protection Agency’s criminal investigation division has issued a bulletin about a fugitive last seen in Wyoming wanted on federal fraud charges of illegally dumping radioactive waste in North Dakota.James Kenneth Ward was last seen in March 2013 during a prison transport from Phoenix when he escaped custody in the Wyoming desert, according to the EPA’s wanted poster and news release. The poster does not identify the desert.Ward, 55, is considered violent and dangerous and should not be approached, according to the EPA.He was already a fugitive. He was returned to the United States to face larceny charges in Wyoming when he escaped.In April, a grand jury for the U.S. District Court in Montana indicted Ward on one count of conspiracy to commit wire fraud and one count of wire fraud. The indictment says Ward, sometimes with his company “JK Services” and others, contracted with a Colorado-based corporation, Zenith Produced Water, LLC. Zenith owned and operated saltwater disposal wells that injected wastewater into the ground. The wastewater is a byproduct of water used in hydraulic fracturing, or “fracking.” That water has solids that are pollutants and radioactive substances that are trapped in tubular nets called “filter bags” or “filter socks.”According to the contract, Ward, JK Services and others were supposed to dispose of the filter socks in a proper facility licensed by North Dakota. Instead, Ward dumped them in an abandoned gas station in Noonan, N.D. From April 2011 through February 2014, Ward and others sent invoices to Zenith for totaling $9,970 for the disposals.
California Drinking Water Advocates Fight Fracking - California regulators are not doing enough to protect groundwater from wastewater injection by the energy industry, according to a new report by KQED.“Oil companies in California produce tons of wastewater. On average, for every barrel of oil, a California oil well produces 19 barrels of water, often laden with salts, trace metals and chemicals like benzene,” the report said.To discard the wastewater, energy companies pump it into the ground.“It’s the standard way in which oil companies dispose of wastewater in California: using injection wells, which are not much more than a pipe going into the ground with a gauge to monitor water pressure,” the report said.“The wastewater is deposited pretty deep, below the usable groundwater, into aquifers that are already too salty to be drinkable,” the report said.The question is whether the wastewater is being disposed of at a sufficient depth. “Groundwater that’s potentially drinkable is automatically off limits for oil companies for wastewater disposal. But if groundwater quality is already tainted by oil or salts, then companies can get permission from state agencies and the federal Environmental Protection Agency to put wastewater there,” the report said. Briana Mordick of the NRDC said the problem is widespread.“There are thousands of wells spread all across the state that are potentially impacting clean drinking water,” she said, per the report.Poor data is part of the problem, per KQED: State oil regulators grant permits for wastewater injection wells, so knowing the boundaries between protected and unprotected aquifers is crucial. But for decades, Mordick says, state regulators confused those boundaries.
Federal judge clears way for completion of Missouri River water project in North Dakota (AP) — A federal judge has cleared the way for completion of a $244 million project to bring Missouri River water to residents of northwestern North Dakota, though the state of Missouri and the Canadian province of Manitoba can appeal.U.S. District Judge Rosemary Collyer in Washington, D.C., ruled Thursday that the Northwest Area Water Supply project complies with federal environmental law. "This court's work is done because the Bureau of Reclamation has finally done its work," Collyer wrote.NAWS was first authorized by Congress in 1986, but it's been tied up in the courts the last 15 years. Manitoba sued in 2002, when construction began, over concerns about the pipeline's possible transfer of harmful bacteria or other agents from the Missouri River Basin to the Hudson Bay Basin north of the border. Missouri sued in 2009 over fears that the pipeline would deplete one of its key sources of water. The Missouri River provides water to 3 million Missouri residents and is vital to the state's shipping and agriculture industries. The federal Bureau of Reclamation in 2015 released its final environmental study on the project, calling for more stringent water treatment. Collyer said the study satisfies federal law requirements, and she ruled in favor of the U.S. government while rejecting Manitoba's claim and dismissing Missouri's.Both plaintiffs can appeal. Attorneys for Manitoba and Missouri didn't immediately respond to requests for comment Friday.
As Dakota Access comes online, America’s most pipeline-constrained shale play sees new life -- Ian Dundas expects to see far fewer oil trains rumbling across the sprawling farmlands of North Dakota in coming years. Dundas is the chief executive of Calgary-based Enerplus Corp., one of the first companies to enter the Bakken, an oilfield spanning southern Saskatchewan, North Dakota and Montana. In the absence of available pipeline capacity, companies operating in the region had for years moved oil on an existing rail network in Canada and the United States. As production boomed, producers began investing more in oil-by-rail terminals, paying a premium to get their product to market. But the completion of the highly contentious Dakota Access pipeline in June, a major oil conduit carrying some 570,000 barrels per day of crude from North Dakota to Illinois, has upended the region’s dependence on rail. The pipeline has dramatically reduced shipping costs for Bakken companies, bringing overall costs in line with other U.S. shale producers, like those in the highly prolific Permian Basin in Texas and New Mexico. “It’s going to be a pretty powerful advantage that we haven’t had for the past six or seven years,” Dundas said in an interview Thursday.Production in the Bakken began to rocket upward around 2009, growing from roughly 200,000 barrels per day to more than one million bpd in less than five years. The rapid growth did not come alongside an equally fast expansion of pipelines, however, and the pipeline system in the region quickly became congested. By 2014, Bakken producers were shipping around 500,000 barrels per day of crude by rail car, nearly half of the 1.2 million bpd total production. Before Dakota Access, about 25 per cent of the oil shipped out of the state travelled by rail. Now that figure is closer to seven per cent, according to recent data. The higher availability of pipeline capacity has translated into much lower shipping costs for producers, giving companies more value for every barrel of oil.
Minnesota releases review on disputed Enbridge oil pipeline - Minnesota regulators on Thursday released the final environmental review of Enbridge Energy's proposal to replace its aging Line 3 oil pipeline, which carries Canadian tar sands crude across northern Minnesota to Wisconsin. The state Commerce Department has updated and expanded the massive document since it released the draft for public comment in May. Changes include additional discussion of the socioeconomic impact of the project, the potential impact on tribal resources and the potential impact of oil spills, as well as the inclusion of public comments, the department said. In the process, the main document grew to just over 2,000 pages, plus around 12,000 pages of appendices. The review will inform the state Public Utilities Commission as it decides whether the project is needed and what route it should take. The commission is scheduled to decide by Dec. 11 whether the final review meets the legal requirements, and to decide on April 30 whether to give its ultimate approval to the pipeline and its route. Administrative law judges will hold hearings and take more public testimony along the way. Calgary, Alberta-based Enbridge proposed the $7.5 billion project because the old pipeline is now restricted to 390,000 barrels per day and its maintenance needs are growing. The replacement would restore the original capacity of 760,000 barrels per day. The company says Line 3 is a vital link in its network, and the replacement would help it continue to meet the demand for Canadian oil from refineries in Minnesota, Wisconsin and elsewhere. Tribal and environmental groups are fighting the project. Like the draft, the final review says any of the routes "would have a disproportionate and adverse effect on tribal resources and tribal members."
Trump Green Lights Arctic Drilling Project in Polar Bear Habitat - The Trump administration released an environmental review Thursday of Hilcorp Alaska's Arctic offshore drilling development. Hilcorp plans to build a 9-acre artificial island and 5.6-mile pipeline in the Beaufort Sea for its offshore drilling project. The Trump administration's draft environmental impact statement proposes to greenlight the dangerous drilling plan, which would be a first for federal waters in the Arctic . Previous Arctic project studies have warned that offshore drilling in those remote, treacherous waters carries a 75 percent chance of a major oil spill. Concerns about the Liberty project were heightened this year when Hilcorp struggled for months to fix leaks in its underwater pipelines in Cook Inlet and meet basic regulatory requirements. "Arctic offshore drilling can't be done safely, particularly by this company. The icy, stormy waters make Arctic drilling inherently hazardous, and Hilcorp has a history of spills and regulatory violations," said Kristen Monsell, an attorney with the Center for Biological Diversity. "Polar bears, bowhead whales and other imperiled Arctic species will be in terrible danger if the Trump administration allows this reckless project to move forward." Hilcorp's Liberty project is poised to be the first oil development project in federal Arctic waters. It was originally proposed by oil giant BP, but it is now being pursued as part of the Texas-based company's rapid expansion of its fossil fuel holdings in Alaska, including leasing 14 new federal offshore tracts in Cook Inlet for more than $3 million this summer. In recent years federal regulators have warned the company to improve maintenance of its gas pipelines, and Alaska's state regulators have fined Hilcorp more than any other company and said "disregard for regulatory compliance is endemic to Hilcorp's approach to its Alaska operations." The Alaska Oil and Gas Conservation Commission has repeatedly cited Hilcorp for violating safety regulations for its oil and gas operations in the state. "Nobody needs Arctic oil. Most of the world understands that, but Trump and Hilcorp just don't get it," Monsell said. "The Arctic has largely been off limits to dangerous oil drilling, and it has to stay that way."
An Arctic Offshore Drilling Plan Advances, but Impact Statement Cites Concerns - A proposal for the first oil and gas drilling in federal offshore waters of the Arctic took a step forward Thursday as regulators released a draft environmental impact statement, which reflects concerns about the effects of the project on marine life and local communities. The so-called Liberty project, proposed by Houston-based Hilcorp, would have the company build a 24-acre gravel island in about 19 feet of water, from which they would drill up to 16 wells. Once it's up and running, the federal Bureau of Oceans and Energy Management (BOEM) expects the project to produce 58,000 barrels a day. The release of the environmental assessmentincorporates months of public comments about the project, including fears that it could negatively impact marine mammals and the communities that rely on them. It kicks off the next phase of the regulatory process, brings the company one step closer to realizing a project that has been in the works for decades. An InsideClimate News investigation published last week revealed that privately owned Hilcorp has a troubling track record in Alaska, with dozens of environmental and safety violations since the company began work in the state in 2012. Those violations gained a national profile earlier this year after the company said it was unable to stop a months-long natural gas leak in Alaska's Cook Inlet as long as there was ice on the water. "Given Hilcorp's history of two recent major pipeline leaks in Alaska's Cook Inlet, an oil spill in Louisiana, and a number of significant fines for violating state drilling requirements, there are many reasons to doubt the company's ability to safely mobilize and operate in the challenging conditions of the Arctic Ocean," said Lois Epstein, the Arctic program director for The Wilderness Society.
Greenpeace Activists Interrupt Operations at an Arctic Oil Drilling Site - Peaceful activists, including one American, from a Greenpeace ship, the Arctic Sunrise, have stalled Statoil's oil operations in the Barents Sea off the Norwegian coast. The activists entered the exclusion zone of Statoil's oil rig, Songa Enabler in the Barents Sea with kayaks and inflatable boats, while swimmers protested in the water with banners. The activists plan to sustain the peaceful protest to stall Statoil's oil drilling as long as possible to send a message that the Norwegian government is failing its commitments to Norway's constitution and the Paris agreement . They are also displaying a constructed giant globe in front of the rig with written statements to the government. Thirty-five activists from 25 countries are escalating a peaceful protest after tailing the rig for one month in the Barents Sea. The Norwegian government has recently opened up a new oil frontier in the Arctic . The state-owned oil company has just started to drill for oil at the Korpfjell well, a controversial site 415 kilometers from land. It is close to the ice edge and an important feeding areas for seabirds. This is the first opening of new areas for oil drillings in 20 years and it is the northernmost area licensed by Norway.
U.S. Oil Drillers Keep Pressure on OPEC With Record Shale Output -- Oil output from major U.S. shale plays is poised to reach a fresh record next month, further complicating OPEC’s efforts to support prices. The gain is being led by the oil-rich Permian basin of Texas and New Mexico, where production has risen steadily over the past two years. The Energy Information Administration projects Permian output to rise by 64,000 barrels in September, reaching a record of 2.6 million barrels a day. The forecast comes just as Saudi Arabia and Iraq, the two biggest producers of the Organization of Petroleum Exporting Countries promised to strengthen their commitment to cutting production. Crude output in the U.S. meanwhile has climbed in nine of the last 10 months. Prices declined to a three-week low Monday as the growing U.S. output and signs of lower demand from China stoked concern that a global oversupply will linger.Shale drillers such as Pioneer Natural Resources Co. and Devon Energy Corp. have been taking advantage of price rallies near $50 a barrel to hedge their output for next year and beyond, with some producers locking in prices as far out as 2023, according to data compiled by Bloomberg. The EIA expanded its monthly forecasts to include the Anadarko shale region, which spans 24 Oklahoma and five Texas counties. The region, a well-established oil and gas producing area, has seen an uptick in improved drilling and completion technology, the agency said in its monthly Drilling Productivity report released Monday. The agency also made another change to reflect shifts in oil and gas production: The EIA consolidated data from the Marcellus and Utica areas, known for their natural gas production, and classified it as a single Appalachia region. "Combining the relatively small number of active rigs across the broader Appalachia region should improve the precision of our productivity estimates," the EIA said, noting that drilling patterns no longer align with previous regional definitions. Crude output from the Eagle Ford and Bakken regions are also expected to rise in September, with Eagle Ford projected to produce 1.39 million barrels a day and Bakken forecast to produce 1.05 million. Daily output in the newly included Anadarko region is poised to reach 459,000 barrels.
Analysis - When will tight oil make money? | Wood Mackenzie --Tight oil profitability has been the focus of much debate since the oil price collapse of 2014. Its ability to scale down (and up) quickly and break even at low price points has made the Permian the star of the show for investors — but there are still plenty of sceptics when it comes to tight oil profitability.We believe tight oil producers will begin generating significant free cash flow in 2020.Tight oil specialists failed to generate positive cash flow in 28 of the 29 quarters since 2010. We've found that tight oil requires as much upfront investment as conventional projects, and like most early-life operations, comes with its own learning curve and infrastructure development – as well as being highly sensitive to the downturn in price. It will take a while to generate returns. Andy McConn, Principal Analyst, discusses why we shouldn't have expected tight oil to deliver profitability right out of the gate:
Bakken and western Canadian producers wrangle for gas takeaway capacity - Associated natural gas production from North Dakota’s oil-focused Bakken Shale is rising as rigs are being added in the region. Bakken gas output reached a record 1.18 Bcf/d this past May. The incremental gas production in the area is intensifying competition with imports from the already-beleaguered Western Canadian Sedimentary Basin (WCSB), which share the same pipeline capacity and target the same Midwest demand markets. The trend also is prompting calls for more pipeline capacity out of the Bakken. How much more capacity is needed and by when? Today, we look at existing natural gas takeaway capacity and flows out of the Bakken. We first wrote about rising Bakken gas production and the impending battle with Canadian gas for pipeline takeaway capacity in a July 2012 blog, Border Wars. At the time, crude oil was trading at upwards of $80/bbl. Oil production from North Dakota’s Bakken Shale had just climbed above 600 Mb/d. Associated gas volumes, including the natural gas liquids content, were just barely approaching 700 MMcf/d, and nearly 40% of that gas was being flared because of midstream capacity constraints, allowing little more than 400 MMcf/d of dry gas to hit the pipelines. But at $80/bbl, oil production was slated to climb rapidly, and with it came increasing volumes of associated gas. By late 2014, Bakken oil output had doubled to 1.2 MMb/d, dry gas volumes were approaching 900 MMcf/d, North Dakota implemented new restrictions on gas flaring to be phased in over a few years and consequently the market was becoming concerned about pipeline takeaway capacity. But about that time, the 2014 oil-price collapse took a severe toll on rig counts, Bakken crude output declined slowing the growth in associated gas volumes, and for a little while concerns about the possibility of insufficient gas takeaway capacity were deferred — at least until now.
The keys to Keystone XL success are in oil supply and demand, flows and prices - Keystone XL faces a final regulatory hurdle in Nebraska, and there are still concerns whether the crude oil pipeline makes economic sense for TransCanada. Senior oil editor Meghan Gordon delves into whether recent news events and an ever-changing supply and demand situation will justify the controversial pipeline. She speaks with Allan Fogwill, president and CEO of the Canadian Energy Research Institute, about production from Western Canada's oil sands, Venezuela potentially leaving a need for heavy crude and how prices factor into decisions.
Are Investors Bailing On U.S. Shale? -- U.S. oil production continues to grow, with the EIA reporting a shocking jump in output last week. Total U.S. production rose to 9.5 million barrels per day (mb/d) for the week ending on August 11, up 79,000 bpd from a week earlier. That puts U.S. output at the highest level in nearly two and a half years. The U.S. shale industry has been adding new supply pretty much uninterrupted since late last year, despite volatile swings in oil prices over the course of 2017. To be sure, some shale drillers have breakeven prices well below the prevailing market price, allowing them to make money even during those tough times. But in the aggregate, the industry needs something around $50 per barrel to be sustainable, or perhaps even $55 per barrel. If that is the case, how is it that the U.S. oil industry continues to add new supply, even when some companies are not even making money? The short answer is that they have been given a long leash by Wall Street. Generous financing, high levels of debt, and repeated equity issuance has given shale drillers a lot to work with. Many of them have seen their debt levels climb, but major investors have been patient, hoping that the growth-before-profits model will eventually pay off. But there are several problems with that. First, the conundrum for shale E&Ps is that they have not successfully lowered the breakeven price on a structural basis. A lot of the “efficiency gains” were the result of cyclical – and temporary – declines in the cost of labor and services. The market downturn led to price deflation for oilfield services – equipment and rig rates, completion services, frac sand, etc. Those costs are rising again as activity picks up. Oilfield services companies will demand higher prices, labor shortages will inflate wages, and so on. As the price of oil ticks up, so will breakeven prices. The second problem is that most analysts do not see oil prices really staging a rally, at least anytime soon. Just to take one example, Citigroup estimates that WTI will not average $52 per barrel…until 2020. The third, and perhaps most glaring, problem with the growth-first shale model is that shale companies were burning through cash when oil prices were $100 per barrel, and they are still burning through cash even after the much-heralded efficiency gains achieved over the last three years. According to Bloomberg and Bloomberg Gadfly, the free cash flow after capex for a collection of 33 shale E&Ps has been profoundly negative over the past 12 months.
UK shale geology structurally potentially unproductive: study -- The UK's geology is unlikely to be suitable for hydraulic fracturing, according to research released Thursday by John Underhill, Chief Scientist at Edinburgh's Heriot-Watt University. The report said that while fracking in the UK has largely been stymied by environmental and political opposition, unfavorable geology means that the technology would be unproductive in any case.An estimate by the British Geological Survey found in 2013 that Central Britain, which includes the prospective Bowland basin, could hold between 822 and 2,281 Tcf (23.3-64.6 Tcm) of gas-in-place, the lower figure representing P90 reserves -- a 90% probability -- and the higher figure P10 reserves -- a 10% probability. Although these figures are huge in comparison with the UK's proved conventional gas reserves, which at end-2016 were just 7.3 Tcf, they do not represent recoverable gas. The BGS stressed in the report, as it does in others, that assessments of the UK's recoverable shale gas resource remain in their infancy. Also in 2013, a much more modest although still substantial figure for the UK's unproved technically recoverable wet shale gas reserves was provided by the US Energy Information Administration of 25.8 Tcf.
Oil traders expect Asia to import more Venezuelan crude if U.S. sanctions kick in - Asia would be the biggest beneficiary of any potential sanctions by the United States on Venezuela's oil sector, said traders and analysts, as exports from the South American OPEC member could be redirected to the region, filling a vacuum left by producer supply cuts. Washington is considering sanctions on Venezuela's oil industry in response to the ruling Socialist Party's crackdown on officials and parties opposed to the government. An embargo against Venezuelan crude could block imports of about 740,000 barrels per day to the U.S. Asian refiners would welcome the so-called heavy, or higher density, crude since production cuts by the Organization of Petroleum Exporting Countries (OPEC) have mainly curtailed this type of oil. At the same time, the start-up of new refining capacity is boosting demand. China and India, the two biggest buyers of Venezuelan crude after the United States, have room to increase imports while other north Asian refiners, with equipment sophisticated enough to handle heavy Venezuelan oil, are seeking opportunities to tap this supply, analysts and traders said. "Whatever oil that the United States doesn't want will find its way into the global market," a trader with a north Asian refiner said, adding that Venezuelan oil could be a good fit for the company's plant. A trader with another north Asian refiner said he is also looking for opportunities to import Venezuelan crude if the U.S. imposes sanctions. The sources spoke on the condition of anonymity because they were not authorized to speak to media.Venezuela's main creditors China and Russia will have first priority to its oil if sanctions are imposed, the sources and analysts said, and the countries would likely make the surplus cargoes available in the spot market.
Oil and gas companies pull foreign personnel out of Venezuela -- Major international oil and gas companies are withdrawing their foreign staff from Venezuela following the country’s growing political crisis and a rapidly deteriorating law and order situation, according newswire and regional media reports. Spanish oil giant Repsol is among the oil and gas companies withdrawing foreign workers from its oilfields in Venezuela. French oil major Total has asked for a number of its employees to leave Venezuela, while Italy’s Eni is only keeping “essential expatriate personnel” in the country. Bloomberg reports that Norway’s Statoil withdrew its “last three foreign workers” before the July election, while US giant Chevron has removed fewer than 10 foreign employees and retains a substantial expatriate workforce there. Bloomberg added that employees whose assignments were scheduled to end within the next six months had their contracts cut short, while some were asked to do “Venezuela-related work remotely” from the US or other countries the company has bases in. Executives already outside Venezuela have been ordered not to return to the country.
Vladimir's Venezuela - Leveraging loans to Caracas, Moscow snaps up oil assets (Reuters) - Venezuela’s unraveling socialist government is increasingly turning to ally Russia for the cash and credit it needs to survive – and offering prized state-owned oil assets in return, sources familiar with the negotiations told Reuters. As Caracas struggles to contain an economic meltdown and violent street protests, Moscow is using its position as Venezuela’s lender of last resort to gain more control over the OPEC nation’s crude reserves, the largest in the world. Venezuela's state-owned oil firm, Petroleos de Venezuela (PDVSA), has been secretly negotiating since at least early this year with Russia's biggest state-owned oil company, Rosneft (ROSN.MM) - offering ownership interests in up to nine of Venezuela's most productive petroleum projects, according to a top Venezuelan government official and two industry sources familiar with the talks. Moscow has substantial leverage in the negotiations: Cash from Russia and Rosneft has been crucial in helping the financially strapped government of Venezuelan President Nicolas Maduro avoid a sovereign debt default or a political coup. Rosneft delivered Venezuela’s state-owned firm more than $1 billion in April alone in exchange for a promise of oil shipments later. On at least two occasions, the Venezuelan government has used Russian cash to avoid imminent defaults on payments to bondholders, a high-level PDVSA official told Reuters. Rosneft has also positioned itself as a middleman in sales of Venezuelan oil to customers worldwide. Much of it ends up at refineries in the United States – despite U.S. sanctions against Russia – because it is sold through intermediaries such as oil trading firms, according to internal PDVSA trade reports seen by Reuters and a source at the firm.
Putin nominates German ex-chancellor Schroeder to Rosneft board -- Vladimir Putin has nominated former German chancellor Gerhard Schroeder to the board of its biggest oil producer Rosneft as an independent director, according to a government decree published late on Friday.Chancellor from 1998 to 2005, Schroeder is currently the chairman of the shareholders’ committee of Nord Stream AG, a Gazprom-led consortium established for construction of pipeline carrying Russian natural gas across the Baltic.Rosneft, in which Russia has a 50 percent plus one share, is under Western sanctions over Moscow’s role in the Ukraine crisis.Schroeder, who calls Russian President Vladimir Putin his friend, has criticized moves to impose sanctions on Russia. Rosneft has been targeted by Western sanctions over Russia’s seizure and illegal annexation of Ukraine’s Crimea region and its support for pro-Russia separatists in eastern Ukraine. Schroeder, a Social Democrat who was German chancellor from 1998 to 2005, celebrated his 70th birthday with Putin at St. Petersburg’s Yusupov Palace in April 2014 as the crisis over Ukraine was deepening.
America can’t substitute Russian gas in Europe even if it ships it for free – diplomat - The United States will most likely fail to oust Russia as the main supplier of gas to Europe, according to the Russian envoy to the European Union Vladimir Chizhov. "And if even Americans supplied liquefied natural gas (LNG) to Europe free of charge, they simply would not have had enough opportunity to replace Russian supplies," Chizhov said in an interview with Sputnik radio.The envoy suggests three reasons why the US cannot replace Russian gas supplies."In the United States there is currently a single export terminal for LNG shipments in Louisiana, they plan to build another half-dozen terminals in different parts of the country, but this will take time,” Chizhov said.“Second, the amount of gas produced in the United States may not be enough for the European market,” he added.The third reason is that Europe does not have enough terminals to receive LNG or tankers for its transportation, said the Russian diplomat.Over the last year, the US has increased LNG supplies to Europe. However, it now has only six percent of European LNG imports, which doesn't take into account natural gas supplies through pipelines.Royal Dutch Shell and BP have confirmed Russia would continue to be Europe's top gas supplier at least through 2035. The Russian share of the European gas market increased to 34 percent last year, according to Gazprom. Europe also imported 24 percent from Norway, 13 percent came in LNG supplies, and 11 percent from Algeria.
Analysis: Panama Canal toll hike unlikely to impact LNG: data - A move to hike tariffs on vessels transiting the Panama Canal, approved by the Cabinet Council of the Republic of Panama Tuesday, is unlikely to significantly alter export decisions or even shipping routes for LNG cargoes loading on the US Gulf Coast, according to S&P Global Platts data. For LNG vessels, the revised toll structure effectively raises the cost of transiting the canal to an estimated 23 cents/MMBtu, representing a 15% hike over the current tariff of 20 cents/MMBtu, data compiled by Platts Analytics show. The revised fees become effective October 1. The modifications to the existing toll structure for vessels follows an analysis of the potential impact on supply chain logistics and end-user costs and after formal and informal consultations with customers and industry representatives in Europe, Asia and North America, the Panama Canal Authority said Tuesday. But analysis suggests that small changes in the Panama Canal's tariff structure are unlikely to alter export calculations. Even significant changes in the FOB cost of an LNG cargo loaded from the US Gulf Coast have been largely secondary in export calculations, Platts data shows. Over the 18-month period since Gulf Coast LNG exports began, destination market prices have figured prominently in offtakers' export calculations. Despite a brief spike last winter in the price of the Platts Japan Korea Marker, the benchmark index for spot cargoes delivered to east Asia, global gas prices have remained largely depressed since US exports began, hovering in a narrow range around the high-$4s/MMBtu to low-$6s/MMBtu. Faced with weak prices in traditional export markets, offtakers from Cheniere Energy's Sabine Pass terminal have opted largely to ship cargoes to emerging gas markets that, although illiquid and opaque, have offered higher destination-market prices. Since Gulf Coast exports began, over 67% of US LNG cargoes have landed in developing markets outside of Japan, South Korea, China, Taiwan and western Europe, while some 40% of US cargoes have been shipped to Latin America, Platts Analytics data show.
Australia notches up record high for LNG exports in July: EnergyQuest -- Australia's LNG exports were at a record high in July, with strong performance from operations on the west coast and stable volumes on the east coast, consultancy EnergyQuest said Tuesday.The July exports stood at 5.4 million mt with 81 cargoes, which was up from 4.9 million mt via 74 cargoes in June, it said. This reflected higher output from Chevron's Gorgon LNG project and Woodside's North West Shelf LNG, with total west coast projects shipping 3.7 million mt during the month, up from 3.2 million mt in June, the company said.On the east coast, the Queensland-based Gladstone LNG, Australia Pacific LNG and Queensland Curtis LNG projects' total was unchanged month on month at 1.7 million mt, it said. "On average, west coast projects operated at 108% of nameplate capacity on an annualized basis, but Queensland projects only operated at 81%, notwithstanding APLNG averaging 110%," it said. APLNG was in the midst of a 90-day operational test for most of the month, during which it had to run at full capacity. The 7.8 million mt/year nameplate capacity GLNG facility, meanwhile, is expected to only ramp up to 6 million mt/year by the end of 2019. Japan, China and South Korea continued to be the dominant destinations for Australian exports, comprising 89% of deliveries in July against 92% in June, EnergyQuest said. Meanwhile, gas production from the upstream processing plants averaged 3,631 Tj/d in July, up from 3,570 Tj/d in June. The higher production appears to reflect higher domestic demand, it said.
From leader to loser: Australia risks missing next LNG wave (Reuters) - Should the arrival of the last major piece of kit in Australia's $180 billion liquefied natural gas (LNG) spree be a cause for celebration or for a wake? It may seem that the arrival of the Ichthys Venturer floating production, storage and offloading facility would be worthy of breaking out the champagne. The vessel, which will be moored some 220 kilometers (132 miles) off the northwestern coast as part of Inpex's Ichthys project, is the final piece of the jigsaw that completes eight massive new LNG ventures. These projects, when in full production, will see Australia overtake Qatar as the world's largest producer of the super-chilled fuel, and become an energy export superpower when one considers the country is already the world's biggest shipper of coal and a significant producer of uranium. While these accomplishments are worthy of a toast or two, there are also factors that serve to put a dampener on the party. The first is that Australia's rise to the top of the global LNG tree may be short-lived, as Qatar has announced plans to boost its output beyond the 85.7 million tonnes of LNG capacity already operating or scheduled to start up by the end of next year. Qatar announced on July 4 it planned to raise its capacity by 30 percent, which would take it to around 100 million tonnes per annum, enough to take back the crown from Australia. The problem for Australia is not the loss of prestige, it's the fact that Qataris are able to boost capacity by doing brownfield expansions of existing facilities, which is considerably cheaper than building new projects from scratch. No new LNG project has reached a final investment decision in Australia since 2012, even though at one stage there were five ventures with a capacity of 31.5 million tonnes a year under consideration.
Indonesia's oil and gas sector slumps, falling to 3% of nation's GDP --Once a cornerstone of the economy, Indonesia's oil and gas sector is in a slump, even as the country's appetite for energy soars. Hit by a drop in global prices, changing regulations and competition from neighbours that are proving more attractive to international energy companies, South-east Asia's biggest economy is facing a decline in oil revenue and steadily rising fuel imports. With an economy growing at a 5 per cent clip and the government embarking on a vast infrastructure roll-out, the oil and gas industry is sounding alarm bells over the decline of a sector that five years ago accounted for almost 6 per cent of Indonesia's gross domestic product (GDP) but, last year, contributed only 3 per cent.Investment for exploration in Indonesia shrank to US$100 million (S$137 million) last year from US$1.3 billion in 2012, according to government data. A lack of drilling success and commercialisation issues have weakened Indonesia's outlook, and spending is likely to drop further, said Mr Johan Utama, a South-east Asia oil analyst with Wood Mackenzie. The decline has also reduced the industry's contribution to state coffers, which accounted for a quarter of the government's revenue a decade ago. Last year, that had fallen to 3 per cent. Indonesia's Energy and Mineral Resources Minister Ignasius Jonan said in April that the government was planning for expansion and aimed to lure as much as US$200 billion in investment over the next decade, offering incentives such as tax-free import of drilling equipment and simpler cost recovery.
Indonesian Pertamina's H1 oil output rises 12% to 343,000 b/d, on track to hit 2017 target - Indonesia's state-owned Pertamina has produced 343,000 b/d of crude oil in the first-half of 2017, up 12% year on year, upstream director Syamsu Alam said late Wednesday. "I think the crude production this year can meet our 2017 target of 354,000 b/d. But gas production may be ... lower compared with the target of 2.08 Bcf/d, due to lower demand and some gas fields [not being able to] produce," he said. The company produced 2.022 Bcf/d of natural gas in H1 2017, up 4% from 1.938 Bcf/d in the same period a year ago, Alam said. Meanwhile, Pertamina's H1 2017 net profit slid 24% year on year to $1.4 billion, despite revenue rising 19% to $20.5 billion, the president director of Pertamina Elia Massa Manik said. "In the first half of 2017, the external environment was still very 'volatile' with the world oil price continuing to rise. The rising of crude oil price has become an incentive for the upstream business. It has, however, also affected the increase in cost of goods sold in the downstream sector, which has a significant impact on the company's net profit," Manik explained in a statement released Wednesday. The Indonesian Crude Price in H1 reached $48.9/b, compared with $36.16/b in the same period a year ago, Manik said. Pertamina forecasts that its net profit this year may reach only $2.3 billion, down from the original target of $3.04 billion, finance director Arief Budiman said.
Market Movers - Asia, Aug 14-18: Asian crude buyers digest IEA oversupply worries (video) In its latest report, the International Energy Agency said that global market oversupply remained a cause for worry. Crude buyers in Asia will be looking at how the market reacts to these comments as they set their buying strategy for the coming months. Meanwhile, extensive flooding in Russia is affecting coal supply to Asia. And Taiwan's increasing demand for refined sugar has boostedThai white sugar cash premiums. Associate editor Kevin Seoexplores these and other topics that may impact Asia’s commodity markets this week.
India's IOC buys first US sweet crude for end-October delivery -- State-run refiner Indian Oil Corp. has for the first time bought 950,000 barrels of light sweet Eagle Ford shale oil from the US, company officials said Friday. It also bought 950,000 barrels of US Gulf Coast medium sour crude Mars, the second such purchase of the grade. A total of 1.9 million barrels of both US crude grades will be shipped by the end of October. No pricing details were provided. In July, IOC sealed its first deal to import 1.6 million barrels of crude from the US for delivery in the first week of October to its Paradip refinery on India's east coast. The July deal made IOC the first state-run refiner in India to buy US crude. This deal came shortly after Indian Prime Minister Narendra Modi's visit to the US in June, where both countries discussed the possibility of boosting cooperation in the energy sector. The recent OPEC/non-OPEC capacity cuts have meant that India has had to diversify its crude suppliers, with state-run refiners making purchases of US crude grades.Bharat Petroleum Corp. Ltd., a state-run refiner, has been regularly buying US crude since July.Hindustan Petroleum Corp. Ltd., another state-run refiner, plans to import US sweet crude in the next few months for its Vizag refinery in southern India, company officials said recently. India currently depends on OPEC countries for 86% of its oil imports, with Iraq, Saudi Arabia, Iran, and UAE its major suppliers.
Analysis: Jet fuel a winner as India's love affair with flying intensifies -- Jet fuel has been witnessing the sharpest growth among all oil products in India so far this year, with a double-digit growth in the January-July period, as the aviation sector expands capacity to keep up with the steep growth in demand for air travel in one of the world's fastest-growing markets. India's oil products demand - January to July 2017A more affluent middle-class, intense competition among low-cost airlines, and robust economic growth -- all these factors are contributing to an exponential growth in air travel in the country. To sum up, air travel, which was a luxury in India a couple of decades ago, is not so anymore. "The ramping up of capacities by airline players is expected to result in a 10%-11% growth in demand for aviation turbine fuel this year," said Rahul Prithiani, director of research at CRISIL, an S&P Global company. Jet fuel consumption in India grew more than 11% year on year to 4.31 million mt in the January-July period, compared with 3.88 million mt in the same period a year earlier, data from the Petroleum Planning and Analysis Cell showed. In July alone, demand for jet fuel grew 10.4% to 617,000 mt, from 559,000 mt in the year-ago period. According to CRISIL estimate, Available Seat Km -- the number of seats available multiplied by the number of miles or kilometers flown, which is used as a measure for growth in air travel -- is expected to increase by 18% in fiscal 2017-2018 (April-March) in the country. This in turn will strongly support the growth in aviation fuel demand. "Air tickets are getting increasingly affordable because of intensifying competition between budget airlines," said Lim Jit Yang, director for oil market analysis for Asia-Pacific at PIRA Energy Group, a unit of S&P Global Platts. "Rising incomes and strong GDP growth are also helping the aviation sector to post robust growth." Indian government officials believe that the country has the potential to become the biggest aviation market by 2030. Low-cost airlines hold the largest share of the aviation market in India.
India says LNG import deal with Qatar remains in place, new deal unlikely - India will continue its 8.5 million mt/year LNG import deal with Qatar without any change in contract clauses, oil ministry officials said Thursday. "There is no proposal to sign any fresh import contract with Qatar," said one official. Qatar is India's largest source of natural gas. Designated importer state-owned Petronet LNG signed a long-term deal with Qatar's RasGas in 1999 for 7.5 million mt/year of LNG on an FOB basis. In 2015, it struck a deal with RasGas to import an additional 1 million mt/year for a 12-year period from January 1, 2016. India in recent years has wanted Qatar to explore the option of investing in India's downstream power sector, and in particular in a stranded gas-based power project. Petronet runs LNG receiving and regasification terminals at Dahej in Gujarat and Kochi in Kerala, and is building a third in Andhra Pradesh. It posted a 12% year-on-year jump in regasification volumes to 192 trillion Btu for the April-June quarter at its flagship terminal at Dahej, the highest on record for the terminal, company officials said. The 10 million mt/year Dahej terminal operated at 97% of capacity in the quarter. The Kochi Terminal also processed its highest ever volume of LNG over April-June, at 8 trillion Btu.
China to build new shale gas bases, offer more oil and gas block tenders (Reuters) - China is likely to build two shale gas bases in the south of the country and open up tenders for more oil and gas exploration blocks in the world's biggest energy producer, the Ministry of Land Resources said on Tuesday. At a news conference in the capital, ministry officials said China is likely to start commercial production of shale gas in southern city of Anye in Guizhou province and Yichang in Hubei province. The ministry did not give a timetable for the start date. The steps come as China ramps up its exploration efforts as crude oil production from ageing wells drops. Beijing is also on a mission to lift natural gas consumption to help combat smog. In the north of the country alone, China's crude oil and gas exploration efforts cover a vast 500,000 square kilometers, with new natural gas and light crude reserves having already been discovered there, the ministry said. In the shale gas expansion, China is seeking to encourage private firms to take part in a tender for shale gas exploration right in Guizhou on Aug. 18. The ministry said it will also consider more auctions of shale gas blocks outside Guizhou. Meanwhile the government of Xinjiang region in northwestern China is also planning to start a second round of oil and gas block auctions, while Sha'anxi province is also preparing to offer coal-bed methane blocks.
China’s oil, gas exploration investment up 12.6% -- China’s oil and natural gas exploration investment rose 12.6 percent during 2012-2016 period when compared with the previous five years, the Ministry of Land and Resources (MLR) said Tuesday. With the stable investment increase during the past five years, China saw continuous growth in oil reserves, according to Yu Haifeng, a MLR official. CNPC Economics and Technology Research Institute estimated China’s reliance on oil imports exceeded 65 percent in 2016. China aims to increase domestic crude oil output to 200 million tons by 2020, while supply capacity for natural gas should exceed 360 billion cubic meters, according to the five-year plan released by the National Development and Reform Commission and the National Energy Administration in January this year. Official data showed China’s crude oil output totaled 181.21 million tons in the first 11 months of 2016 while natural gas output came in at 121.1 billion cubic meters.
Saudi Aramco to complete first phase expansion of natural gas network by year end - Saudi Aramco plans to complete the first phase of expansion of its master gas system that supports industry and utilities, lifting its capacity to 9.6 Bcf/d, by the end of the year, the state oil giant told S&P Global Platts Sunday. Aramco built the original master gas system in the 1970s, with gas-gathering and processing facilities as the backbone of the kingdom's industry, allowing Aramco to use or market nearly all the produced gas associated with oil production. As gas demand continues to rise, Aramco has launched a two-phase initiative to expand gathering and processing capacity, adding two booster gas compressor stations in the Red Sea region, the first facilities of their kind in the kingdom, which will help supply natural gas to the Saudi Electric Company Rabigh-2 power plant and the new King Abdullah Economic City. The new facilities will also support future utilities and industrial sectors, primarily in the Rabigh area. The first booster gas compressor is now at the pre-commissioning stage, Aramco said, after it accelerated the first phase to meet the scheduled date of operations at Rabigh-2 power plant so it can avoid burning liquid fuel. A second phase of expansion will increase capacity to 12.5 Bcf/d by 2020, along with the installation of nearly 1,000 km of 56-inch diameter pipelines linking the eastern and western coasts. "This is a strategic transformation project that targets substituting oil with gas," said Saleh al-Wadei, the acting project manager. "It will save the crude oil that would have been burned to generate power."
Hedge funds gamble for a third time on oil rebalancing: Kemp -- Hedge funds and other money managers raised their net long position in the three major futures and options contracts linked to Brent and West Texas Intermediate (WTI) to 705 million barrels in the week to Aug. 8. (http://tmsnrt.rs/2hYVRPj)Fund managers have boosted their net long position in Brent and WTI by the equivalent of 347 million barrels over the six weeks since June 27, according to regulatory and exchange data.Managers have nearly doubled their net long position in crude since the end of June and now have the largest net position since April.Long positions outnumber their short positions by a ratio of 5.19:1, up from a recent low of just 1.95:1 on June 27, displaying a pronounced bullish bias.But in the most recent week, the extra net length all came from the ICE Brent contract, where long positions were increased by 40 million barrels while short positions were trimmed by 19 million.By contrast, net positions in NYMEX and ICE WTI were little changed, with long positions trimmed by 2 million barrels and short positions actually up by 1 million.Increased net length in Brent is likely connected to a sudden tightening of the calendar spreads, which has seen Brent move from contango into backwardation between October and December 2017 (V7-Z7).More generally, Brent calendar spreads have tightened much more than WTI since the last week of July, which has made Brent more profitable for hedge fund managers with long positions.Increased bullishness towards crude has also been mirrored in hedge fund positions for U.S. gasoline and heating oil.Hedge funds raised their net long position in gasoline by 2 million barrels to 47 million barrels in the week to Aug. 8. Fund managers are now more bullish on gasoline prices than at any time since the middle of February.Portfolio managers also raised their net long position in U.S. heating oil by 6 million barrels to almost 25 million barrels. Positioning in heating oil is only slightly less bullish than on gasoline, with net length the highest since April and the long/short ratio the highest since February.
Problems For Oil - The importance of oil should not be underestimated as an energy source – and a pollutant. Almost every form of transport is dependent on it and its refined products and the present economy would not have been created without it. Most of it is burned by vehicles propelled by the Internal Combustion Engine (ICE), enabling transport of people and goods world-wide. As the number of vehicles increases, so does demand for oil and its derivatives. With thawing in the Arctic, new oil deposits are likely to become available, giving the oil industry additional confidence that it will be able to sustain production for at least the next 50 years. Were the industry to think of Peak Oil in terms of the point at which demand for oil begins to decline, then its confidence in being able to sustain production for the next 50 years would seem misplaced for some, if not all kinds of oil.Table 1 above shows oil is not a uniform product. Some oils are heavier, more difficult to extract and require greater energy to transport and refine. Lighter oils are easily pumped and refined and these oils are the most keenly sought by consumers. Were demand for oil to decline, the first to be affected would be those which are more expensive to extract and refine – the heavier oils – but ultimately all oil production would be affected by a sustained reduction in demand and this would have a significant affect on the economies of oil producing countries, particularly those most dependent on oil revenue.Why would reduction in demand occur? Improvements have been made to the efficiency with which ICE vehicles burn fuel, thus lowering emissions but this has been off-set my an increase in the number of them in use. At present there are over 1 billion ICE vehicles in use with an additional 80 million vehicles being built each year. There has also been a trend towards production and refining of oils with higher emissions, particularly in North America. The problem with ICE vehicles are thee-fold:
- Oil and gas extraction and refining emit greenhouse gases, particularly methane (CH4) which over its 12 year lifetime in the atmosphere is far more potent than CO2:
- Combustion of oil-based fuels in ICE and jet engines emits CO2, Nitrous Oxides and CH4 contributing to global warming and:
- As a result of combustion, micro-particles are emitted to the atmosphere which are inhaled and impair human health, causing cancer and cardio-pulmonary diseases.
OPEC's long-sought success spoiled by 2018 oil supply worry --(Bloomberg) -- Oil investors are already worrying over the potential fallout when OPEC’s deal to cut output expires, marring emerging signs that the accord to shrink a glut is finally succeeding. Uncertainty about how supplies curbed by the Organization of Petroleum Exporting Countries and its allies will be returned to the market in 2018 is clouding the outlook for crude, according to BMI Research. Prices remain vulnerable even though demand is strong, production gains are largely exhausted in Libya and Nigeria, and U.S. shale output is slowing, the unit of Fitch Group said in a report.Crude fell the past two weeks as bullish signals went unheeded: Saudi Arabia cut sales to the world’s top oil market, prompt supply turned costlier than later shipments, OPEC boosted demand estimates for its crude, and U.S. inventories slid. Apart from the concern over what happens when the output accord expires in March, there are other worries. The International Energy Agency cut estimates for the amount of oil needed from OPEC and warned of doubts over the commitment of nations involved in the production deal.“OPEC is walking a tight rope,” said Ehsan Ul-Haq, London-based director of crude oil and products at Resource Economist. “If prices are above $60 a barrel then shale oil will come back. If OPEC producers decide to reduce more, prices will go above $60 a barrel. If they don’t comply fully, then prices will go below $50. It’s very difficult for them.”West Texas Intermediate, the U.S. marker, is trading near $47.50 a barrel and Brent crude, the benchmark for more than half the world’s oil, is near $51. Both are down more than 10 percent this year even as OPEC has curbed output since the start of 2017 to help lift prices from the worst crash in a generation. Futures were at more than $100 a barrel in mid-2014. BMI doesn’t expect market sentiment to return to “bullish extremes,” and said that Brent is vulnerable to short-term pullbacks over the coming months. That echoes industry researcher JBC Energy GmbH’s warning that prices are at risk of falling back without deeper output curbs by OPEC and after demand in the U.S. weakens following the end of the summer driving season that’s been spurring the declines in American inventories.
Big Red Flag For Crude Bulls: Chinese Oil Refining Tumbles Most In Three Years As Fuel Demand Slides --Slowly but surely, what we have claimed for the past year - that it is the demand side of the oil equation, not the supply, and especially the "Chinese wildcard" that is the critical factor in setting prices - is starting to emerge and be factored in by markets. And so, just days after we posted "Another Red Flag For Oil? China’s Crude Imports Slump To 7-Month Low" arguably catalyzed by the increasingly full Chinese Strategic Petroleum Reserve, overnight we got another major red flag - once again out of China - when Bloomberg reported that China’s oil refining dropped the most in three years for the month of July, while crude output retreated from the highest this year, "as the world’s largest consumer showed signs of losing momentum." According to Bloomberg calculations based on NBS data released on Monday, as shown in the chart below oil processing in July dropped 4.4 percent from the previous month to about 10.76 million barrels a day. While daily refining output typically falls from June to July on maintenance, last month’s fall was the biggest seasonal decline since 2014. Crude oil output fell 3% to 3.84 million barrels a day. Separate data from industry consultant SCI99 revealed that state refineries in northwest and southern China at the end of July cut runs to 66.9% and 64.68% of capacity, respectively, the lowest since 2014, while independent refiners, known as teapots, were operating at around 58.78% near the lowest since May 5.
The plight of the light sweet crude barrel - The word ‘glut’ is one of the more overused words in news stories to describe the global oil markets, but in the case of light sweet crude the moniker is true—much to the chagrin of OPEC. This oversupply has persisted for over three years and despite recent moves by OPEC and 10 other oil producers, it continues with somewhat reckless abandon. Refining oil that’s low in sulfur and boasts of high specific gravity can yield a good amount of gasoline and middle distillates, which are the main profit making products for the world’s refiners. Specifically, crude oils with an API gravity of more than 31.10 and a sulfur content of less than 0.5% are considered light and sweet. A decade or so ago, refineries wanted to process light sweet oil in order to reap the benefits of substantial volumes of middle distillates and gasoline. As a result, the crude held a premium price over heavier or sourer grades. But this oil is no longer as attractive as it used to be. Many older refiners upgraded facilities by adding cokers, while newer ones have been made with better technology that have complex distillation units, which can process heavy sour crudes and still get a lot of gasoline and diesel, at much cheaper costs. As a consequence demand for light sweets fell. Now eight months into the OPEC/non-OPEC deal, and the agreement has not yielded the desired affects, particularly because the cuts have proved toothless in tackling the imbalance of light and heavy crudes. The cuts have largely come from oil producers that produce heavy and sour oil, and the glut of light sweet oil remains. Libya and Nigeria, the two countries exempt from the deal, produce mainly light sweet crude, and with production in both recovering, this imbalance has been further skewed. Libyan output is now at four-year highs and Nigerian production is close to 18-month highs.
Oil Falls by Most in Five Weeks Amid Fear of Chinese Demand Drop (Bloomberg) -- Oil tumbled by the most in more than five weeks as fears of falling oil demand in China overshadowed news that Libya’s crude supply was disrupted. Futures fell 2.5 percent in New York. China’s oil refining dropped the most in three years in July, while crude output retreated from the highest this year. Libya’s biggest oil field, Sharara, cut output by more than 30 percent because of security threats, a person familiar with the matter said. Meanwhile, the dollar strengthened, eroding the lure of commodities as a store of value. "We’re seeing some strength in the dollar, and the preponderance of news seems to be favoring the bears right now," Phil Flynn, senior market analyst at Price Futures Group Inc. in Chicago, said by telephone. "If you look at the China data this morning, when it came to the China refinery runs being down in July, that’s adding to the perception of slowing demand, and it’s offsetting the concerns about Libyan oil production." Oil has lingered below $50 a barrel in New York this month as investors weigh rising global supply against output curbs from the Organization of Petroleum Exporting Countries and its allies. Data on China’s sliding refinery runs are stoking fears that the world’s second-largest oil consumer will taper its appetite. In the U.S., producers keep drilling for more oil, with the number of active rigs at its highest since April 2015 and the Energy Information Administration forecasting crude output at major shale plays reaching an all-time high of 6.15 million barrels a day in September. West Texas Intermediate for September delivery fell $1.23 to settle at $47.59 a barrel on the New York Mercantile Exchange, the lowest level in three weeks. Total volume traded was about 3 percent above the 100-day average. Brent for October settlement declined $1.37 to end the session at $50.73 a barrel on the London-based ICE Futures Europe exchange. The global benchmark crude traded at a premium of $3 to October WTI. Chinese oil processing in July dropped 4.4 percent from the previous month to about 10.76 million barrels a day, according to Bloomberg calculations based on data released Monday by the National Bureau of Statistics.
Oil settles at 3-week low as OPEC and U.S. crude output grow - Oil fell sharply Monday, with concerns over rising crude output from OPEC members and U.S. shale-oil producers pushing prices to their lowest finish in three weeks.Losses for oil intensified after a report from the U.S. Energy Information Administration revealed expectations for a monthly rise in domestic shale-oil output.“U.S. production remains the single biggest headwind for the oil market right now, and until we begin to see signs that domestic output growth is fading, [West Texas Intermediate oil] will have a very hard time rallying through the $50 mark in the absence of an unrelated bullish catalyst,” Tyler Richey, co-editor of the Sevens Report, told MarketWatch.WTI crude oil for September delivery dropped $1.23, or 2.5%, to settle at $47.59 a barrel on the New York Mercantile Exchange. That was the lowest settlement July 24, according to FactSet data. Brent oil for October fell $1.37, or 2.6%, to $50.73 a barrel on ICE Futures Europe, with prices also settling at their lowest since late July.In a report Monday, the EIA said it expects to see a climb of 117,000 barrels a day in September to 6.149 million barrels a day The report has shown increases in shale-oil production every month so far this year. “This is not the report that [the Organization of the Petroleum Exporting Countries] wanted to see,” said James Williams, energy economist at WTRG Economics. “It is far more optimistic than the EIA’s Short-Term Energy Outlook, which only anticipated a 10,000 [barrel-per-day] increase in September lower-48 [states] onshore production.” Williams pointed out the regions covered in EIA’s Drilling Productivity Report Monday cover 85% of the onshore production in the lower 48 states.The report also showed that the number of drilled, but uncompleted wells, or DUC, climbed by 208 in July from June to 7,059. “This is also bearish because the more DUC wells there are, the more capacity is ready to come online in the face of any sort of price rally,”
The Oil Price Tug Of War - Oil prices started the week down from last week, with WTI dipping back below $48 per barrel. There is not a ton of direction for the market right now, with expectations of rising U.S shale weighing on the benchmark prices. “Shale is still rising strongly,” said Olivier Jakob, an oil analyst at Petromatrix, according to the WSJ. There are doubts over whether WTI can “move above $50, with the capacity how it is in the U.S.,” he said. He went on to add that trading was flat on Tuesday because “there is nothing really new.”. The EIA forecasts that U.S. shale production will grow by 117,000 bpd in September compared to August. The gains come from the Permian (+64,000 bpd), plus smaller contributions from the Niobrara (+15,000 bpd), the Eagle Ford (+14,000 bpd), the Bakken (+10,000 bpd) and the Anadarko (+12,000 bpd). For the Permian, it will rise to an overall output of 2.6 million barrels per day, a new record high. Hedging by shale companies has locked in future sales, providing certainty around $50 per barrel for them to ramp up production. There are rumblings of unrest in Nigeria again, as protestors stormed a crude oil facility owned by Royal Dutch Shell last week, raising fears that Nigerian oil production could once against suffer disruptions. The facility feeds Shell’s Bonny export terminal.. Shell’s massive platform set sail from South Korea to Texas, moving the oil major one step closer to completing its giant Appomattox project in the U.S. Gulf of Mexico. The project was given the greenlight 2 years ago and is expected to come online before the end of the decade. Shell insists that it can breakeven with oil at $50 per barrel. A new report from Dallas law firm Haynes & Boone finds that the number of oil and gas companies declaring bankruptcy has slowed to a crawl this year. Only 14 companies filed for Chapter 11 bankruptcy in the first half of 2017, down from 50 in the same period in 2016. The improvement is in part due to the rise of oil prices, but also because some of the weaker oil and gas companies were already pushed out of the market. The FT reports on the strategic shift underway at Royal Dutch Shell (NYSE: RDS.A), which is moving to sell electricity to industrial consumers. The move highlights the potential for an oil major to adapt to a rapidly changing energy landscape. Beginning next year, Shell will sell electricity in the UK, but the company has said it would like to expand to the U.S.
WTI Lifts Towards $48 After Biggest Crude Inventory Draw Since September -- WTI slipped back to almost a $46 handle today before bouncing modestly into the close ahead of tonight's API report, with all bullish eyes hoping last week's surprise gasoline build was a 'blip'. API reported a much larger than expected crude draw (biggest since Sept 2016)and while WTI rallied on the print, it was a very modest move (that for now failed to achieve $48) as we suspect the fact that gasoline saw another surprise build weighed on sentiment. API:
- Crude -9.2mm (-472k exp) - biggest draw since Sept 2016
- Cushing +1.7mm (+700k exp)
- Gasoline +301k (-450k exp) - second weekly build in a row
- Distillates -2.1mm (-250k exp)
Last week's surprising gasoline inventory build was overwhelmed by a much larger than expected crude draw reported by API... and the same appears to have happened this week - big crude draw, modest gasoline build... Additionally, the DOE confirmed it will sell 14 million barrels of crude from the SPR later this month. WTI was hovering around $49 ahead of last week's API data and is hovering just above $47 into today's print... futures rose very modestly as the crude draw exuberance was offset by the gasoline build.
Goodbye contango? Oil's long march toward backwardation: Kemp (Reuters) - “The rebalancing of the oil market desired by the leading producers has been a stubborn process,” the International Energy Agency wrote in its latest monthly oil market report. The agency’s evident frustration about the slow and uneven pace of rebalancing, and the conflicting signals about whether it is happening at all, is shared by many traders, analysts and investors. “The medium-term outlook for oil still looks challenging with, if anything, balances for 2018 having deteriorated in recent weeks,” hedge fund manager Andy Hall wrote to investors this month. The combination of a trendless market and the growing number of computer-driven trading programmes has made trading strategies based on supply and demand fundamentals increasingly difficult: “Investing in oil under current market conditions using an approach based primarily on fundamentals has therefore become increasingly challenging,” Hall wrote as he explained why he was shutting his main fund. The problem is immediately clear if the current price of oil is compared with prices a year ago. Front-month WTI futures are currently trading at $47.87 per barrel which is almost unchanged from $46.58 on Aug. 16, 2016. Brent prices too are almost back where they were a year ago. Front-month Brent is currently trading around $51.24 which is just $2 or 4 percent higher than on the same day last year. For all the meetings of OPEC and non-OPEC ministers, technical committees and monitoring groups held in the meantime, not to mention the flights and hotel bills, the oil price is right back where it started. Millions of words have been written in the analysis of a market that has gone basically nowhere overall, while sharp price reversals in a trendless market have repeatedly wrong-footed investors. Hedge funds now appear somewhat more confident that rebalancing is finally happening than they were this time last year, but the confidence is not universal, as illustrated by Hall’s pessimistic comments. Hedge funds have a total net long or bullish position in the main futures and options contracts for crude, gasoline and heating oil of 777 million barrels, up modestly from 516 million barrels in mid-August 2016.
WTI/RBOB Slide After Oil Production Surge Offsets Biggest Crude Draw Since Sept --Following last night's mixed mesage from API (crude draw, gasoline build), WTI prices have gone nowhere as all eyes focus on DOE data this morning. Confirming API's trend, crude saw its biggest draw since Sept 2016 but Gasoline, Distillates, and Cushing (most since March) saw builds which upset the machines and sent prices lower. Crude production rose once again to its highest since July 2015. DOE:
- Crude -8.945mm (-3.38mm exp) - biggest draw since Sept 2016
- Cushing +678k (+700k exp) - biggest build since March
- Gasoline +22k (-450k exp)
- Distillates +702k (-250k exp)
Last week's surprise build in gasoline (confirmed by API) and big draw in crude (also confirmed by API overnight) remains the big focus and DOE data confirmed it with thebiggest crude draw since Sept 2016 but builds in products and at Cushing... While the builds in product were modest, they were nevertheless a surprise shift in trend from draws to builds...
Oil Prices Rise On Hefty Crude Inventory Draw -- Another week, another draw – this seems to be the refrain this driving season, with the API and the EIA in sync with their weekly figures most of the time.This week has been no exception, with the EIA reporting a hefty draw in U.S. commercial oil inventories a day after the API surprised analysts by estimating inventories had declined by 9.2 million barrels.The authority calculated commercial inventories of crude oil had gone down by 8.9 million barrels in the week to August 11, after a draw of 6.5 million barrels a week earlier.API’s report lent some support to international prices on Tuesday amid a stronger U.S. dollar and concern about flagging demand in China. The EIA’s figures will most probably strengthen the positive effect despite the persistent glut.The EIA also said there was no change in gasoline inventories for the week to August 11, which might be a cause for worry, after last week it said inventories of the fuel had jumped up by 3.4 million barrels, which offset the positive news of the crude inventory draw. Refinery runs averaged 17.6 million barrels last week, the authority said in its weekly report, versus 17.4 million bpd in the week before. Daily gasoline production fell to 10 million barrels, compared with 10.3 million bpd a week earlier.Whatever effect the EIA’s figures have on prices is bound to be short-lived as oil’s fundamentals remain largely unchanged, with rising U.S. shale output offsetting OPEC’s and its partners’ cuts that should together take off 1.8 million bpd from global supply. Oil demand prospects are not too rosy either, despite the IEA recently revising its 2017 demand growth outlook to 1.5 million bpd from 1.4 million bpd. Improving fuel efficiency and increased adoption of EVs in the U.S. will be largely responsible for the trend.
Oil prices settle lower as U.S. output hits 2-year high -- Oil settled lower Wednesday after the Energy Information Administration report revealed a weekly climb in domestic production to the highest level in over two years. The government data also showed the largest weekly decline in U.S. crude supplies since September of last year and they have now fallen seven weeks in a row, but those figures failed to offer any lasting price support for oil during the session. September West Texas Intermediate crude shed 77 cents, or 1.6%, to settle at $46.78 a barrel on the New York Mercantile Exchange. The decline marked the third-consecutive loss for WTI, which stands at its lowest finish since July 24, according to FactSet data. October Brent crude on London’s ICE Futures fell 53 cents, or 1%, to $50.27 a barrel. Data from the Energy Information Administration on Wednesday showed a rise of 79,000 barrels a day in total crude-oil production to 9.502 million barrels a day last week. That was the highest output figure since mid-July 2015, according to EIA figures, based on weekly reports.U.S. production “increased at a pretty good clip,” and demand for gasoline and distillates was also down, said Tariq Zahir, a managing member at Tyche Capital Advisors.The EIA also said, however, that supplies of crude oil for the week ended Aug. 11 fell by 8.9 million barrels. That was more than double than the decline of 3.6 million barrels expected by analysts polled by S&P Global Platts, but below the 9.2 million-barrel decrease reported by the American Petroleum Institute late Tuesday. “A combination of record refinery runs for the time of year and strong exports have encouraged the largest draw to crude inventories in eleven months,” said Matt Smith, director of commodity research at ClipperData.
The Single Biggest Bullish Catalyst For Oil -- One of the key objectives for OPEC is to bring down inventories, a goal that has been elusive this year. But if the oil futures curve is anything to go by, the oil market is showing signs of tightening.Brent futures have recently begun to exhibit a state of backwardation, which is when near-term oil futures trade at a premium to contracts dated further off into the future. This is the first time in years that backwardation has occurred, and most analysts are taking it as a sign that the oil market finally could be getting closer to rebalancing. In the past, backwardations have accompanied a rebound in the oil market after a bust, while a contango (the opposite of backwardation) tends to occur when the market crashes because of a supply glut.There are several reasons why backwardation is bullish, which has been discussed in previous articles. A declining futures curve makes it uneconomical to store oil, so backwardation could accelerate the drawdown in inventories. It also complicates the hedging strategies of shale producers, which could hold back expansion plans. It also is a symptom of tightening near-term supplies, although, to be sure, the flip side of that argument is that it could merely be a reflection of expectations that the supply glut will reemerge at some point in the future. Still, backwardation is occurring at a time when there are other bullish indicators starting to crop up. The U.S. has seen a sharp drawdown in inventories in recent months, down more than 60 million barrels since March. The IEA and OPEC both recently upgraded their oil demand estimates. "World economic growth has gained momentum," OPEC said. "With the ongoing growth momentum and an expected continued dynamic in second-half 2017, there is still some room to the upside." The view of Wall Street is also becoming more bullish. Hedge funds and other money managers have amassed a large number of long positions on recent weeks. For the week ending on August 8, investors stepped up their bullish bets on Brent by the equivalent of 58 million barrels, according to the FT, which was the largest weekly increase towards net length since December.
OilPrice Intelligence Report: Oil Prices Boosted By String Of Bullish News - Oil prices fell significantly this week, although they regained some ground on Friday. Reports of weak Chinese demand deflated the market, but a rather bullish EIA report, a weaker U.S. dollar and a falling rig count provided a bit of a lift. . The rapid decline of U.S. oil inventories in recent months suggests the market is tighter than everyone thinks. “Prices should be $10 higher given where the fundamentals are,” Amrita Sen, chief oil analyst at Energy Aspects, told the WSJ. She said that investors have been too worried about rising U.S. oil production. “The market is so obsessed with supply. If U.S. output is going up and stocks are drawing that is an extremely bullish development,” she said, arguing that rising demand is being overlooked. Citi says that oil will be stuckwithin the range of $40 to $65 through 2022, although the bank said that this assumes “smooth sailing” for the oil market. In other words, some unforeseen shocks could temporarily push prices outside of that range. If disruptions are resolved, which restore supply to the market, prices could crash below $40, but outages could cause prices to jump above $70. But beyond that, prices will be range bound.. Blackstone is set to buy Harvest Fund Advisors LLC, an investment-management firm with more than $10 billion in assets under management, which will bring midstream energy assets under the private equity giant’s portfolio. The move seeks to profit off of rising natural gas production – the midstream assets benefit from fees, like tolls, so they would make money on the rising volume of gas moving around, regardless of the market price for that gas. Goldman Sachs lost $100 million in the past quarter after wagering that natural gas prices in the Marcellus Shale would rise. However, pipeline problems prevented that from happening, causing Goldman’s bet to sour. The WSJ reported that natural gas and LNG traders around the world are increasingly using the Henry Hub benchmark, based in the U.S. Gulf Coast, for natural gas pricing. The growing importance of the benchmark is a reflection of the expansion of U.S. LNG exports, as well as the shifting nature of LNG markets. That is, with more supplies coming online from various sources, the LNG market is increasingly similar to that of crude oil, with the disparities in regional prices narrowing. . For the first time in years, the Brent futures curve has flipped into backwardation, a sign that the oil market is healing. Backwardation – when front month contracts trade at a premium to futures further out – will help drain inventories as it becomes uneconomical to put oil in storage. The backwardation is a significant development, which many analysts say is a sign that the oil market is progressing towards some sort of balance.
Oil Prices Climb As Oil Rig Count Drops -- The number of active oil and gas rigs in the United States fell this week by 3 rigs as drillers in the United States proceed more cautiously as oil prices fail to sustain any significant increase. Combined, the total oil and gas rig count in the US now stands at 946 rigs, up 455 rigs from the year prior, with oil rigs in the United States decreasing by 5 and gas rigs increasing by 1. Oil rigs in the United States now number 763—357 rigs above this time last year.Canada lost 6 oil rigs this week, with the number of gas rigs holding steady—for a total of 214 oil and gas rigs—93 above the year ago levels.Prices fell on Friday despite the Energy Information Administration’s Wednesday report that the United States’ crude oil inventory had fallen by 8.9 million barrels of inventory—after last week’s report of a 6.5-million-barrel decline. Thursday’s report that Saudi Arabia’s oil exports had hit a 33-month low—and that it had likely fallen further in July and would continue in August—had also failed to sustainably lift prices. Barrel prices for WTI is more than $1 lower on the week—for a second week in a row, and .17% down on the day, trading at $47.01 at 11:44am EST. Brent was trading down 0.43% at $51.25, with the spread reaching more than $4 between the two—almost a four-fold increase from a year ago.Related: Russia Claims To Have Invented Alternative To Fracking The rise in the number of active rigs in the US has slowed in recent weeks, with the 5-week average gain for US oil rig count falling into negative territory, compared to the previous 5-week average gain of 5 rigs. Despite the falling average weekly gain in active US oil rigs, US crude oil production continues to increase, with average production averaging 9.502 millionbarrels per day for the week ending August 11, according to the Energy Information Administration (EIA), who now expects US production to reach an average of 9.9 millionbarrels per day in 2018.
Rig Count Drops Most In 7 Months As 'Traders' Panic-Buy Crude Futures -- The US oil rig count dropped 5 to 763 last week, the biggest drop in 7 months. However,crude production from the Lower 48 has surged (rising the most since June last week) to the highest since July 2015. Even with today's sheer farce panic-buying squeze higher in WTI crude, oil looks set for its 3rd weekly close lower as BNP notes the "whole supply surplus story is not likely to go away anytime soon." *U.S. OIL RIG COUNT DOWN 5 TO 763 , BAKER HUGHES SAYS :BHGE US As we have noted previously, this inflection point in the rig count fits with the rollover in crude prices... While the rig count growth has stabilized, crude production continues to rise in the Lower 48 (though had dropped in Alaska for 3 straight weeks) but both saw a rise this week (total production up 79k) as Lower 48 production hit its highest since July 2015... Bloomberg notes that U.S. oil production from major shale plays is set to hit another record at 6.15 million barrels a day next month, according to the EIA. It's not just the Permian that's growing, as the agency sees higher output across the board. WTI Crude remains lower on the week despite the panic-buying... with no catalyst at all except bannon momentum ignition in USDJPY. Some chatter on the crude curve - “Flat price is finally catching up with some of the signs we’ve seen that the physical market is tightening,” Clayton Rogers, an energy derivative broker at SCS Commodities, says.
Oil Rig Count Slips by 5, Total Now Up 455 Year Over Year - In the week ended August 18, 2017, the number of rigs drilling for oil in the United States totaled 763, down by five compared with the prior week and up by 357 compared with a total of 406 a year ago. Including 182 other rigs drilling for natural gas and one listed as miscellaneous, there are a total of 946 working rigs in the country, down by three week over week and up by 455 year over year. The data come from the latest Baker Hughes North American Rotary Rig Count released on Friday.West Texas Intermediate (WTI) crude oil for September delivery settled at $47.09 a barrel, up 0.7% on Thursday. Crude prices were trading up about 2.8% Friday afternoon at around $48.40 and rose to around $48.45 after the rig count data were released.The natural gas rig count increased by one to a total of 182. The count for natural gas rigs is now up by 99 year over year. Natural gas for September delivery traded about 1.1% at around $2.90 per million BTUs before the count was released and remained essentially flat afterward. Reuters energy industry analyst John Kemp notes that WTI futures for September delivery are priced at a discount of 77 cents a barrel compared to March 2018 futures contract. At the same time last year, September 2017 futures traded at a discount of nearly $3.50 to the March 2017 futures price. Historically, the price spread between months is more closely related to the basic supply-demand situation than is the current price. The current swing in price spreads is, according to Kemp, “a strong signal that the market is rebalancing (or most traders believe it is rebalancing).”Among the states, North Dakota lost two rigs last week while Alaska, Louisiana and Oklahoma lost one each. One rig was added in New Mexico. In the Permian Basin of west Texas and southeastern New Mexico, the rig count now stands at 377, unchanged compared with the previous week’s count. The Eagle Ford Basin in south Texas has 75 rigs in operation, also unchanged week over week, and the Williston Basin (Bakken) in North Dakota and Montana now has 51 working rigs, down two for the week.
Analysis: OPEC caught in limbo as options to change status quo limited - As OPEC and non-OPEC nations meet for another joint technical committee meeting on August 21, the oil producer group's options seem limited, leading to a preoccupation with ensuring compliance with output cuts and hoping that the strength of the oil markets lasts longer. This upcoming meeting in Vienna, following on from a similar meet-up in Abu Dhabi earlier this month in which Iraq, Kazakhstan, Malaysia and UAE were scrutinized, highlights OPEC's commitment to the pact but also the fact that its hands are somewhat tied. Analysts have said that this need for patience is a "fact of life" that the group and even the oil market will have to live with. OPEC production starts to climbThere also seems to be a consensus that if deeper cuts aren't invoked then the rebalancing could drag on much longer, placing even greater pressure to maintain conformity. But deeper cuts could compound the problem. "The conundrum OPEC and Russia face is as follows: more aggressive supply cuts may raise the oil price but will only invite more US shale production. Abandoning supply cuts will no doubt lead to a price correction into the $40/b [territory] and maybe lower," according to Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas. "This catch-22 situation may leave no other option than continue current supply policy and see where oil inventories end up by March 2018," he said. Saudi Arabian Oil Minister Khalid al-Falih recently said that the possibility of continued production cuts is still on the table and repeated the line that the door to an extension has not been closed, in a bid to keep the recent rebalancing narrative momentum.
Exposing The OPEC Deal Saboteurs -- Oil prices have been under pressure again this week. With West Texas Intermediate yesterday falling 2 percent, to below $49 per barrel. And some surprising numbers this week show that slide is likely to continue. With the world’s largest oil-producing nations pumping out more crude than many energy observers are expecting. That’s OPEC. A group oil investors have been looking to as a saviour — expecting that production cuts from key nations like Saudi Arabia will help support global oil prices. But a survey released this week by Platts shows that OPEC output is far from declining. In fact, OPEC production in July hit its highest level for 2017 — coming in at 32.82 million barrels per day, up 330,000 b/d from June. There’s one big reason for OPEC’s surging production: Libya. A nation that saw its July production rise 180,000 barrel per day — as key oil fields across the country restart under ceasefire deals between the central government and local rebel factions. All told, Libya’s July production rose to just under 1 million barrels per day. A big jump from the 700,000 barrels per day the country was producing as recently as March. The concerning thing for OPEC is that Libya is exempted from the recent agreement on production cuts — and thus free to ramp up output. Which has put OPEC as a whole well above its quota for total production, with July’s output being 920,000 b/d above the agreed-upon ceiling of 31.9 million barrels. Libyan officials have said they want to increase production further. With the government targeting 1.25 million barrels by the end of this year. At the same time, production from the U.S. is also rising. With the U.S. Energy Information Administration this week increasing its forecast for 2017 domestic output. All of which suggests that OPEC’s much-lauded cuts are fading as a driver for higher crude prices. Watch for more numbers on Libya’s production to see if output could go higher from here — and for potential new action from the cartel to address the recent surge. Here’s to living outside the law.
Saudi Crude Exports Fall Just as Domestic Stockpiles Dwindle - Saudi Arabia, the world’s biggest crude exporter, shipped the least oil in almost three years in June, just as domestic stockpiles are dwindling. Exports fell to 6.9 million barrels a day, the lowest since September 2014, from 6.92 million in May, according to data Thursday on the Joint Organisations Data Initiative website. Domestic stockpiles stood at 256.6 million barrels, the lowest since January 2012, the data show.“You can assume exports will fall even further going forward because they can’t keep running down stockpiles,” said Amrita Sen, an analyst at Energy Aspects in London. “It is clear that the rebalancing process is in full swing, we are drawing down stockpiles everywhere.” Saudi Arabia’s Energy and Industry Minister Khalid Al-Falih last month promised even deeper cuts to crude exports for August, with shipments capped at 6.6 million barrels a day. The kingdom and Russia are leading the charge of major oil producers seeking to curb a global glut of crude by cutting output through the end of the first quarter of 2018. Benchmark Brent crude prices have dropped 11 percent since the cuts took effect on Jan. 1.
Saudi Arabia's Budget Deficit Narrows as Crude Revenue Rises -- Saudi Arabia’s second-quarter budget gap narrowed to 46.5 billion riyals ($12.4 billion) after income from oil advanced. Total revenue climbed 6 percent in the second quarter to 163.9 billion riyals after income from crude jumped 28 percent, the finance ministry said in a statement. That helped narrow the deficit from 58.4 billion riyals in the same period last year, even though revenue from non-oil sources fell by 17 percent. Spending dropped 1.3 percent, to 210.4 billion riyals. “It’s really a story of stronger oil revenue and ongoing fiscal restraint,” said Monica Malik, chief economist at Abu Dhabi Commercial Bank. “Much of the narrowing in the deficit seen in the first half of 2017 is due to higher oil revenue, versus in 2016.” Saudi Arabia is reporting quarterly budget figures for the first time this year in an effort to increase government transparency, part of Crown Prince Mohammed bin Salman’s “Vision 2030” plan for life after oil. He has promised to overhaul the Saudi economy by cutting energy subsidies, privatizing state entities and selling shares in state giant Saudi Arabian Oil Co., known as Aramco. Raising non-oil revenue through taxes and fees is central to that plan.The government said in December that it planned to spend a total of 890 billion riyals this year, with an expected end-of-year deficit of 198 billion riyals. The budget deficit for the first quarter was 26.2 billion riyals. The "quarterly update presents clear evidence of progress toward achieving fiscal balance by 2020,” Minister of Finance Mohammed Al-Jadaan said in the statement. “Whilst economic challenges remain, we are confident in achieving our fiscal deficit projections for 2017.”
With a wary eye on Iran, Saudi and Iraqi leaders draw closer (Reuters) - It was an unusual meeting: An Iraqi Shi'ite Muslim cleric openly hostile to the United States sat in a palace sipping juice at the invitation of the Crown Prince of Saudi Arabia, the Sunni kingdom that is Washington's main ally in the Middle East. For all the implausibility, the motivations for the July 30 gathering in Jeddah between Moqtada al-Sadr and Crown Prince Mohammed bin Salman run deep, and center on a shared interest in countering Iranian influence in Iraq. For Sadr, who has a large following among the poor in Baghdad and southern Iraqi cities, it was part of efforts to bolster his Arab and nationalist image ahead of elections where he faces Shi'ite rivals close to Iran. For the newly elevated heir to the throne of conservative Saudi Arabia, the meeting - and talks with Iraqi Prime Minister Haider al-Abadi in June - is an attempt to build alliances with Iraqi Shi'ite leaders in order to roll back Iranian influence. "Sadr's visit to Saudi Arabia is a bold shift of his policy to deliver a message to regional, influential Sunni states that not all Shi'ite groups carry the label 'Made in Iran'," said Baghdad-based analyst Ahmed Younis. This policy has assumed greater prominence now that Islamic State has been driven back in northern Iraq, giving politicians time to focus on domestic issues ahead of provincial council elections in September and a parliamentary vote next year. "This is both a tactical and strategic move by Sadr. He wants to play the Saudis off against the Iranians, shake down both sides for money and diplomatic cover," said Ali Khedery, who was a special assistant to five U.S. ambassadors in Iraq.
Saudi Arabia ‘seeks Iraq’s help’ to mend ties with Iran -- The government of Saudi Arabia has sought the help of Iraq's prime minister to mend relations between Riyadh and Tehran, according to news reports. Citing Qasim al-Araji, Iraq's interior minister, the Iraqi satellite channel Alghadeer reported that Mohammed bin Salman, the crown prince of Saudi Arabia, had asked Haider al-Abadi to lead the mediation with Iran. "During our visit to Saudi Arabia, they also asked us to do so, and we said that to [the] Iranian side. The Iranian side looked at this demand positively," Araji was quoted as saying by Alghadeer on Sunday. "After the victories that Iraq has achieved, it [Saudi Arabia] began looking to Iraq, at its true size and leading role. "The calm and stability and the return of relations between Iran and Saudi Arabia have positive repercussions on the region as a whole." Araji visited the Iranian capital, Tehran, on Saturday to discuss "several issues" with top Iranian officials, according to reports. He also visited Saudi Arabia in July.The Iranian news agency ISNA quoted Araji in Farsi as saying that Mohammed bin Salman wanted to "ease tensions" with Iran.Separately, Muqtada al-Sadr, the influential Iraqi Shia leader, announced on his website that he would be visiting the UAE on Sunday.In July, Sadr made a rare visit to Saudi Arabia, where he met Mohammed bin Salman and other officials.Sadr, an anti-American figure, commands a large following among the urban poor of Baghdad and the southern cities, including Saraya al-Salam, or Peace Brigades armed group.He is now seen as a nationalist who has repeatedly called for protests against corruption in the Iraqi government, and his supporters have staged huge protests in Baghdad calling for electoral reform.
Saudis in talks over alliance to rebuild Iraq and ‘return it to the Arab fold’ - Iraq and Saudi Arabia are negotiating a new alliance that would give Riyadh a leading role in rebuilding Iraq’s war-torn towns and cities, while bolstering Baghdad’s credentials across the region. Meetings between senior officials on both sides over the past six months have focused on shepherding Iraq away from its powerful neighbour and Saudi Arabia’s long-time rival, Iran, whose influence over Iraqi affairs has grown sharply since the 2003 ousting of Saddam Hussein. Iraq and Saudi Arabia have long been considered opponents in the region, but a visit by the Iraqi Shia cleric Muqtada al-Sadr to Riyadh last week and a follow-up trip to the UAE further thawed relations which had already been much improved by high-profile visits between the two countries. The arrival in the Saudi capital of Sadr – a protagonist in the sectarian war that ravaged Iraq from 2004-08 and who has enduring ties to Iran – highlights a new level of engagement which could see Riyadh play a significant role in the reconstruction of the predominantly Sunni cities of Mosul, Fallujah, Ramadi and Tikrit. “This visit was an important step in ensuring that Iraq returns to the Arab fold and is supported in doing so by friendly partners,” said the former Saudi minister of state Saad al-Jabri. “This necessitates limiting Tehran’s continued attempts to dominate Iraq and spread sectarianism. Broader engagement between Riyadh and Baghdad will lead the way for enhanced regional support for Iraq, especially from the Gulf states. This is essential after the capture of Mosul from Isis and as Iraq looks towards national reconstruction.”
Cox: Qatar kerfuffle could tip Aramco to New York | Reuters: - Economic boycotts are usually designed to force dramatic change. They deprive enemies of income that can be used to finance armies, feed propaganda machines and sustain populations - with the hope of provoking the target's people to overthrow their leaders. Saudi Arabia, the UAE, Egypt and Bahrain have followed much of this playbook since early June in their ostracism of Qatar, which they accuse of financing terrorism. The four Arab neighbors have cut diplomatic ties and trade links with Doha, and suspended air and shipping routes with the gas-rich nation. They issued a 13-point ultimatum insisting, among other things, that it scale back ties with Iran and muzzle the Al-Jazeera cable network. Thus far, Western companies have not been overtly punished for maintaining their ties with Qatar. And U.S. companies will not be, according to a letter the quartet of nations sent to Secretary of State Rex Tillerson in July, Reuters reported over the weekend. One exception may be companies who count entities controlled by the Al Thani monarchy, primarily through Qatar's $300 billion-plus sovereign wealth fund, as important shareholders. If so, these regional grievances may alter the trajectory of one of the biggest deals in the history of global capital markets, the planned initial public offering sometime next year of the $2 trillion Saudi Aramco. The Qatar Investment Authority was founded in 2000 "for the purpose of investing Qatar's revenue surplus." It began aggressively acquiring big stakes in European and U.S. companies around the financial crisis. Among its largest holdings today are chunks of Volkswagen, Iberdrola, Barclays, Vinci, J Sainsbury, Tiffany & Co, and Credit Suisse, according to Reuters Eikon data. Two of those firms, Credit Suisse and Barclays, were particularly welcoming to the Qataris in 2008 when capital was scarce. The fund bought into the Swiss bank early that year and owns 4.2 percent today. It snaffled up Barclays stock when its own shareholders shunned a capital call in July 2008, giving it a stake of just under 6 percent at present. Those two investments are now worth $4.3 billion.
If you're wondering why Saudi Arabia and Israel have united against Al-Jazeera, here's the answer - There are still honourable Israelis who demand a state for the Palestinians; there are well-educated Saudis who object to the crazed Wahabism upon which their kingdom is founded; there are millions of Americans, from sea to shining sea, who do not believe that Iran is their enemy nor Saudi Arabia their friend. But the problem today in both East and West is that our governments are not our friends. When Qatar’s Al Jazeera satellite channel has both the Saudis and the Israelis demanding its closure, it must be doing something right. To bring Saudi head-choppers and Israeli occupiers into alliance is, after all, something of an achievement. But don’t get too romantic about this. When the wealthiest Saudis fall ill, they have been known to fly into Tel Aviv on their private jets for treatment in Israel’s finest hospitals. And when Saudi and Israeli fighter-bombers take to the air, you can be sure they’re going to bomb Shiites – in Yemen or Syria respectively – rather than Sunnis. And when King Salman – or rather Saudi Arabia’s whizz-kid Crown Prince Mohammad – points the finger at Iran as the greatest threat to Gulf security, you can be sure that Bibi Netanyahu will be doing exactly and precisely the same thing, replacing “Gulf security”, of course, with “Israeli security”. But it’s an odd business when the Saudis set the pace of media suppression only to be supported by that beacon of freedom, democracy, human rights and liberty known in song and legend as Israel, or the State of Israel or, as Bibi and his cabinet chums would have it, the Jewish State of Israel. So let’s run briefly through the latest demonstration of Israeli tolerance towards the freedom of expression that all of us support, nurture, love, adore, regard as a cornerstone of our democracy, and so on, and so on, and so on. For this week, Ayoob Kara, the Israeli communications minister, revealed plans to take away the credentials of Al Jazeera’s Israeli-based journalists, close its Jerusalem bureau and take the station’s broadcasts from local cable and satellite providers.This, announced Ayoob Kara – an Israeli Druze (and thus an Arab Likud minister) who is a lifelong supporter of the colonisation by Jews of Israeli-occupied Arab land in the West Bank – would “bring a situation that channels based in Israel will report objectively”. In other words, threaten them. Bring them into line.
Yemen’s Cholera Epidemic Continues to Spread - Yemen’s cholera epidemic has now infected half a million people:The number of suspected cases of cholera resulting from an epidemic in war-torn Yemen has reached 500,000, the World Health Organization (WHO) says.At least 1,975 people have died since the waterborne disease began to spread rapidly at the end of April.The cholera epidemic in Yemen was already the worst on record three weeks ago when there were more than 360,000 infected, and the epidemic has spread to almost half again as many people since then. In just four months, Yemen has suffered from a larger cholera epidemic than Haiti did earlier this decade during an entire year. Like Yemen’s other overlapping humanitarian disasters, the cholera epidemic is man-made and was entirely preventable. The coalition war has devastated the country’s infrastructure and health care system, the blockade is depriving the country of basic food and medicine needed to stave off both starvation and preventable disease, and the “legitimate government” caused a collapse in public services in rebel-controlled areas with the decision to relocate the central bank. I’ll quote something here that I wroteat the start of this year:The Hadi government and its coalition and Western backers have inflicted all of this on the civilian population of Yemen for more than twenty-one months in the service of an atrocious war effort that has failed in all of its stated objectives. Unfortunately, U.S. and coalition policies have not changed at all in the seven months since I wrote that, and conditions in Yemen have significantly worsened in the meantime.
Leaked UN Report: Saudi Coalition Responsible For Mass Child Deaths In Yemen --A leaked United Nations report finds that Saudi Arabia has massacred thousands of children in Yemen since the start of its air campaign in the impoverished country and now the Saudis are using their vast wealth and influence to suppress the document's findings in order to stay off of a UN blacklist identifying nations which violate child rights. On Wednesday Foreign Policy published a bombshell report, based on its possession of a leaked 41-page draft UN document, which found Saudi Arabia and its partner coalition allies in Yemen (among them the United States) of being guilty of horrific war crimes, including the bombing of dozens of schools, hospitals, and civilian infrastructure. Foreign Policy reports:“The killing and maiming of children remained the most prevalent violation” of children’s rights in Yemen, according to the 41-page draft report obtained by Foreign Policy. Virginia Gamba, the U.N. chief’s special representative for children abused in war time, informed top U.N. officials Monday, that she intends to recommend the Saudi-led coalition be added to a list a countries and entities that kill and maim children, according to a well-placed source. The UN report further identifies that air attacks "were the cause of over half of all child casualties, with at least 349 children killed and 333 children injured” during a designated time period recently studied. While it is unclear what specific window of time the UN assessed for these figures, the AP (also in possession of the leaked document) reports further of the secret U.N. findings that, "the U.N. verified a total of 1,953 youngsters killed and injured in Yemen in 2015 — a six-fold increase compared with 2014" - with the majority of these deaths being the result of Saudi and coalition air power. Also according to the AP:It said nearly three-quarters of attacks on schools and hospitals — 38 of 52 — were also carried out by the coalition. Meanwhile, Saudi Arabia is reportedly bringing immense pressure to bear against the UN and the commission responsible for the report, with the United States also working behind the scenes to mitigate the public embarrassment and fallout that is sure to come should Saudi Arabia receive formal censure in the U.N.’s upcoming annual report of Children and Armed Conflict.
War Crimes: Saudi Arabia Should Pay the Penalty for Catastrophe in Yemen - One year ago Saudi Arabia’s air force bombed the Sana’a International Airport in Yemen. This salvo came as part of a broad assault on Yemen’s capital, Sana’a, which the Saudis have been bombing since 2015. The Ansarullah movement, the umbrella group that is dominated by the Houthis, holds Sana’a. The day after the bombings, Saleh al-Samad, who heads the Political Council of the Ansarullah movement, said that the Saudi strikes would create a catastrophe. Sana’a International Airport provided an essential lifeline for the civilian population of northern Yemen. Food and medical supplies came through the airport. These would now be halted as a result of the strikes. A year later, 15 relief agencies joined together to condemn the destruction of the airport. ‘The official closure of Sana’a airport,’ they note, ‘effectively traps millions of Yemeni people and serves to prevent the free movement of commercial and humanitarian goods.’ Yemen’s Ministry of Health estimates that at least 10,000 Yemenis died from lack of access to the international medical treatment that they had sought. Each year, before the conflict, about 7,000 Yemenis traveled abroad annually for medical treatment. Many of them used Sana’a International Airport as their point of departure. They have now been trapped to die. The 15 relief agencies note that more people have died because they have been denied access to international medical care than those killed by the fighting. These numbers, they point out, represent the 'hidden victims of the conflict in Yemen.’ Wael Ibrahim of Care International pointed out that the road to the other airports are dangerous, with armed men at checkpoints and with Saudi aircraft liable to bomb civilians in their cars. Yemen is at the brink of cholera and famine driven mass death. There is little Western media coverage of this atrocity. Dr. Homer Venters of Physicians for Human Rights said that Yemen is the frontline for the ‘weaponization of disease.’ War crimes abound.
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