oil prices tumbled this week, giving up all the gains they'd seen since Trump's strike on Syria and then some, as fears of further Mideast disruptions subsided, while US drilling productivity advanced again and traders became concerned that OPEC could not follow through on an extension of their output cuts...after closing last week with a 2% gain at $53.18 a barrel, US crude prices for May delivery fell on Monday to $52.65 a barrel, their lowest close in over a week, as traders noted that the EIA's monthly drilling productivity report forecast a US oil production increase of 124,000 barrels a day in May, suggesting an ongoing supply surplus...that projected surge in U.S. shale output carried into Tuesday trading, and May futures traded down another 24 cents at $52.41 a barrel, their lowest close since April 10th, after a Reuters analysis showed that US financial companies were again investing billions in new production... after inching up on Wednesday morning, the bottom dropped out of oil prices on Wednesday afternoon, after the EIA reported a smaller than expected draw from crude oil supplies and a surprise buildup of US gasoline supplies, with the May contract closing down $1.97 at $50.44 a barrel...with trading in May oil contracts expiring on Thursday, that month's contract closed out down another 17 cents, while the contract for June US light crude, which had fallen $2 a barrel on Wednesday to $50.85 a barrel, shed another 14 cents on Thursday to close at $50.71 a barrel...now quoting June as the front month, oil prices fell another $1.09 a barrel on Friday after Baker Hughes reported another weekly rise in the U.S. oil-rig count, to close the week at $49.62 a barrel, despite word from OPEC of a likely extension of their oil output cut...that left the June oil contract with a 7.4% loss for the week, down $3.98 a barrel from its close of $53.60 the previous Friday....
natural gas prices were lower for the week as well, but not as dramatically...after closing last week down 3.4 cents at $3.227 per mmBTU, natural gas prices for May delivery opened the week down 6 cents, and following a volatile session settled at $3.163 per mmBTU, down 6.4 cents, as weather models showed little likelihood of the northeast US tapping into any cold Canadian air masses...with little change in the forecast, prices drifted 1.8 cents lower on Tuesday, closing at $3.145 per mmBTU...then as usual, traders betting on a surprise in the natural gas storage report bid prices higher, as natural gas closed Wednesday up 4 cents at $3.185 per mmBTU...prices for May then fell back on Thursday, after the EIA's weekly natural gas storage report showed a 54 billion cubic feet addition to US supplies, which was 368 billion cubic feet below last year's total for the same period, but 282 billion cubic feet above the five-year average of 1.833 trillion cubic feet for this time in April...that disappointment carried into Friday, as natural gas prices for May, which will continue trading next week, fell 5.8 cents to close the week at $3.101 per mmBTU...
since we're back on natural gas, i want to clear up the ambiguity i left the last time i addressed the US natural gas production and supply situation...at that time, we showed that our natural gas supplies had been at near seasonal highs over the period from October 2015 through November 2016, with October 2016 being the first time in our history that US stored natural gas supplies topped 4 trillion cubic feet....however, that oversupply did not hold through this past winter, despite an equally warm winter vis a vis the prior one...(recall we showed that demand for heating was 17% below normal in both this past winter and during the El Nino winter before that)....US natural gas supplies have been falling despite this warm winter because both demand for natural gas has increased and production of natural gas has decreased....first, because of near record low prices, natural gas replaced and surpassed coal as the leading electrical generation source during 2016...in addition, natural gas deliveries to the Sabine Pass LNG export facility have more than tripled since mid-2016 and will continue to climb further as more liquefaction capacity ramps up....meanwhile, natural gas production has been down by 3.6% to 3.8% from a year earlier in recent months...and as we've showed many times, new drilling for natural gas is not taking place at these price levels (we've noted that it generally takes natural gas prices over $4 mmBTU to substantially increase the natural gas rig count)
so, while domestic production of natural gas looks like it will continue to be below year ago levels in the near term, users and exporters of natural gas are still expecting greater supplies to materialize in the next few years...recall that when we looked at US LNG export capacity additions 7 weeks ago, we saw that liquefaction and export terminals now under construction would demand about 10% of our total natural gas supplies by the end of 2019...meanwhile, the EIA reported that 13 gigawatts of natural gas-fired generating capacity is scheduled to come online in the US in 2017....if that pace of capacity addition is maintained until the end of 2019, it would represent nearly a 10% increase in demand for natural gas from electric utilities...but during this past winter, despite all time record high supplies of stored natural gas in October, our natural gas supplies have now dropped to a level 14.8% below that of the same week in April a year ago, even as we had an equally warm winter....in other words, over the past 6 months, our great natural gas surplus has been burnt off, and we're now just maintaining a near normal supply....that suggests that as the new gas generating capacity and the new gas liquefaction trains become operational, a shortage of natural gas will develop in the US, and natural gas prices will spike accordingly, as they have many times before...since roughly a third of our natural gas consumption is for residential heating, i would expect that our natural gas shortage will manifest itself as soon as the US sees a normal winter...
The Latest US Oil Data from the EIA
the oil data for the week ending April 14th from the US Energy Information Administration showed another large increase in our oil refining while our supply of crude from net imports and production barely inched up, which meant that we had to take oil out of storage to meet refining needs for the second week in a row, but still only for the 3rd time in the past 15 weeks...our imports of crude oil decreased by an average of 68,000 barrels per day to an average of 7,810,000 barrels per day during the week, while at the same time our exports of crude oil fell by 124,000 barrels per day to an average of 565,000 barrels per day, which meant that our effective imports netted out to 7,245,000 barrels per day during the week, 56,000 barrels per day more than the prior week...at the same time, our crude oil production rose by 17,000 barrels per day to an average of 9,253,000 barrels per day, which means that our daily supply of oil, from net imports and from wells, totaled an average of 16,498,000 barrels per day during the cited week...
at the same time, refineries reportedly used 16,938,000 barrels of crude per day, 241,000 barrels per day more than they used during the prior week, while 176,000 barrels of oil per day were being pulled out of oil storage facilities in the US....thus, this week's EIA oil figures would seem to indicate that refineries used 265,000 more barrels of oil per day than were supplied by what we took out of storage plus our net oil imports and oil well production…therefore, 265,000 barrels of oil per day of "unaccounted for crude oil" is inserted onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the supply and demand data balance out, but no one knows where that oil came from...the reason we follow that weekly fudge factor is because the weekly production and inventory figures often influence the price of oil, and that "unaccounted for crude oil" figure suggests that one or both of those market moving metrics is consistently off by a bunch..
meanwhile, the weekly Petroleum Status Report indicates that the 4 week average of our oil imports fell to an average of 7,941,000 barrels per day, now just 2.0% above the imports of the same four-week period last year, and that the 4 week average of our oil exports inched up to 710,000 barrels per day, 102% higher than the same 4 weeks a year earlier, as we had barely started overseas exports of surplus light crude oil in early 2016....the 176,000 barrel per day decrease in our crude inventories came about on a 148,000 barrel per day withdrawal from our commercial stocks of crude oil and a 28,000 barrel per day sale of oil from our Strategic Petroleum Reserve, part of an ongoing sale of 5 million barrels annually that was planned 19 months ago...
this week's 17,000 barrel per day oil production increase resulted from a 21,000 barrel per day increase in oil output from the lower 48 states, which was partially offset by a 4,000 barrels per day decrease in oil output from Alaska...the 9,252,000 barrels of crude per day that we produced during the week ending April 14th was a 20 month high, up by 5.5% from the 8,770,000 barrels per day we were producing at the end of 2016, and up by 3.3% from the 8,953,000 barrel per day output during the during week ending April 15th a year ago, while it was still 3.7% below the June 5th 2015 record oil production of 9,610,000 barrels per day...
US oil refineries were operating at 92.9% of their capacity in using those 16,938,000 barrels of crude per day, up from 91.0% of capacity the prior week, but still down from the year’s high of 93.6% of capacity in the first week of January, when they were processing 17,107,000 barrels of crude per day...however the quantity of crude oil processed by US refineries was another Spring-time record, beating the 16,697,000 barrel of crude per day record set the prior week by a 241,000 barrel per day margin....it was also 5.2% more than the 16,104,000 barrels of crude per day.that were being processed during week ending April 15th, 2016, when refineries were operating at 89.4% of capacity...
even with the week's refining increase, gasoline production from our refineries decreased by 134,000 barrels per day to 9,794,000 barrels per day during the week ending April 14th, which was still 0.6% more than the 9,738,000 barrels of gasoline that were being produced daily during the comparable week a year ago....on the other hand, refineries' production of distillate fuels (diesel fuel and heat oil) increased by 90,000 barrels per day to 5,150,000 barrels per day, which was 9.3% more than the 4,712,000 barrels per day of distillates that were being produced during the week ending April 15th last year...
however, even with the drop in our gasoline production, the EIA reported that our gasoline inventories increased by 1,542,000 barrels to 237,672,000 barrels as of April 14th, after they had dropped by almost 20 million barrels over the prior 6 weeks....that swing to a surplus came about because our imports of gasoline rose by 355,000 barrels per day to 843,000 barrels per day, while our gasoline exports fell by 62,000 barrels per day to 648,000 barrels per day and as our domestic consumption of gasoline fell by 52,000 barrels per day to 9,223,000 barrels per day....although our gasoline supplies are still down by almost 21.4 million barrels from the record high set 9 weeks earlier, they're still only 2 million barrels lower than last April 15th's inventories of 239,651,000 barrels, and are now 5.3% more than the 225,738,000 barrels of gasoline we had stored on April 17th of 2015...
on the other hand, even with the increase in distillate's production, our supplies of distillate fuels fell by 1,955,000 barrels to 148,266,000 barrels during the week ending April 14th, as our exports of distillates jumped by 568,000 barrels per day to 1,419,000 barrels per day even as our imports of distillates rose by 49,000 barrels per day to 167,000 barrels per day and as the amount of distillates supplied to US markets, a proxy for our consumption, decreased by 458,000 barrels per day to 4,177,000 barrels per day at the same time...while our distillate inventories are now 7.3% below the 159,935,000 barrels that we had stored on April 15th 2016, following last year's warm El Nino winter, they are still 14.6% higher than the distillate inventories of 129,336,000 barrels that we had stored on April 17th of 2015, following a more normal winter…
finally, our commercial inventories of crude oil fell for the 3rd time in the past 15 weeks, decreasing by 1,034,000 barrels to 532,343,000 barrels as of April 14th....however, we still finished the week with 11.1% more crude oil in storage than the 479,012,000 barrels we had stored at the end of 2016, 4.9% more crude oil in storage than what was then a record 507,312,000 barrels of oil in storage on April 15th of 2016, 16.7% more crude than what was also then a record 456,271,000 barrels in storage on April 17th of 2015, and 45.4% more crude than the 365,878,000 barrels of oil we had in storage on April 18th of 2014...
This Week's Rig Count
because last week's rig count data was released on Thursday because of the Friday holiday, this week's rig count change is for eight days...with that caveat, drilling activity still increased for the 24th time in the past 25 weeks, and the week's increase was also the 11th double digit rig increase in the past 14 weeks....Baker Hughes reported that the total count of active rotary rigs running in the US increased by 10 rigs to 857 rigs over the 8 day period ending on Friday April 21st, which was nearly double the 431 rigs that were deployed as of the April 22nd report in 2016, and the most drilling rigs we've had running since September 11th, 2015, but still far from the recent high of 1929 drilling rigs that were in use on November 21st of 2014....
the number of rigs drilling for oil increased by 5 rigs to 688 rigs this week, which was more than double the 343 oil directed rigs that were in use a year ago, and the most oil rigs that were in use since April 24th 2015, while it was still way down from the recent high of 1609 rigs that were drilling for oil on October 10, 2014...at the same time, the count of drilling rigs targeting natural gas formations also rose by 5 rigs to 167 rigs this week, which was up from the 88 natural gas rigs that were drilling a year ago, but down from the recent natural gas rig high of 1,606 rigs that were deployed on August 29th, 2008...in addition, there were also 2 rigs in use that were classified as miscellaneous, compared to a year ago, when there were no such miscellaneous rigs at work...
another drilling platform that had been working offshore from Louisiana in the Gulf of Mexico was shut down this week, which left 20 offshore rigs still drilling in the Gulf, down from the 25 working in the Gulf of Mexico a year earlier....that was also down from the total of 26 offshore rigs that were deployed a year ago, as there was also an drilling platform working in the Cook Inlet offshore from Alaska during the equivalent week last year...
active horizontal drilling rigs increased by 12 rigs to 718 rigs this week, which was well more than double the 332 horizontal rigs that were in use in the US on April 15th of last year, but still down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, a net of 2 vertical rigs were added this week, bringing the vertical rig count up to 79, which was also up from the 51 vertical rigs that were deployed during the same week last year....however, 4 directional rigs were pulled out this week, reducing the directional rig count down to 60 rigs, which was still up from the 48 directional rigs that were deployed during the same week a year ago...
the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of April 21st, the second column shows the change in the number of working rigs between last week's count (April 13th) and this week's (April 21st) count, the third column shows last week's April 13th active rig count, the 4th column shows the change between the number of rigs running on Thursday 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 22nd of April, 2016...
as you can see, there's not much outstanding in the details of this week's count...Texas added 6 rigs during the week, hence accounting for the majority of the additions, and half of those were in the Eagle Ford...otherwise, it's all skinny numbers...however, except for the Marcellus addition in Pennsylvania, where the 5 natural gas rigs were added isn't obvious…one was in the Barnett shale near Ft Worth, where there are now 2 gas rigs and 4 oil rigs operating, while the Haynesville actually dropped a natural gas rig while adding an oil rig...so there were a total of 4 natural gas directed rigs added in the "other" column, in basins which are not named in any of the Baker Hughes summary data...
DUC well report for March
as we mentioned, Monday of this week saw the release of the EIA's Drilling Productivity Report for March, which again showed another increase in uncompleted wells nationally, largely as a result of dozens of newly drilled but uncompleted wells (DUCs) in the two Texas oil basins, the Permian basin of west Texas and the Eagle Ford in the south....although this backlog of unfracked wells has been building for months, US oil prices below $50 a barrel for much of the month likely contributed to the slowdown of completions in March, even as new well drilling continued to increase...this week’s report indicated that the total count of DUC wells in the US rose from 5,401 in February to 5,522 in March, the fifth consecutive monthly increase in uncompleted wells...over the prior 5 months, a period when oil prices were generally higher than the previous year because of the OPEC cuts, the US DUC count in the 7 regions covered by this report still increased by 10.4%, from 4,995 in October to 5,512 in March....those 5,512 wells represent a backlog that will be completed whenever oil or gas prices rise sufficiently, increasing US oil or gas production and hence oil or gas supply, and thus putting a limit on any rapid run-up of prices...
like in previous months, most of the March DUC increases were oil wells; the Permian basin, which includes the Wolfcamp and several other shale plays in that broad basin, saw its total count of uncompleted wells rise by 90, from 1,774 in February to 1,864 in March, as 410 new wells were drilled but only 320 of them were fracked...at the same time, DUC wells in the Eagle Ford of south Texas rose by 26, from 1,259 in February to 1285 in March, as 161 wells were drilled in the Eagle Ford in March but only 135 were completed....in addition, DUC wells in the Haynesville of Louisiana increased by 13 wells to 182, and DUCs in the Bakken of North Dakota increased by 4 to 809...on the other hand, the Niobrara chalk of the Rockies front range saw a 15 well decrease in DUCs (which means more wells were being fracked than were being drilled) as the Niobrara DUC count fell from 638 in February to 623 in March...in addition, the Marcellus DUC count fell by 4 to 662 uncompleted wells, and the Utica shale showed a decrease of 3 uncompleted wells and thus had only 87 DUCs remaining at the end of March, as 18 wells were drilled in the Utica during the month while 21 were completed...for the month, DUCS in the 4 oil basins tracked by in this report (ie the Bakken, Niobrara, Permian, and Eagle Ford) increased by 105 wells, while the DUC count in the natural gas regions (the Marcellus, Utica, and the Haynesville) increased by 6 wells, although as the report notes, once into production, more than half the wells will produce both oil and gas...
Rover Pipeline dumps up to 2 million gallons of 'drilling fluid' south of Navarre - Crews working on the Rover Pipeline dumped drilling fluid on wetlands in Stark and Richland counties, according to papers filed with the Ohio Environmental Protection Agency. The larger spill — estimated between 1.5 million and 2 million gallons — occurred in a wetland adjacent to the Tuscarawas River south of Navarre. The pipeline passes through Bethlehem and Pike townships in Stark County and intersects with the river, according to maps. The second spill is estimated at 50,000 gallons and occurred in Mifflin Township east of Mansfield. Both spills involved drilling fluids — a mud containing bentonite — from horizontal directional drilling tied to construction of a buried pipeline, according to Ohio EPA paperwork. In Bethlehem Township, crews were drilling under the Tuscarawas River to create a path for the pipeline. Drilling has stopped while the company cleans up the spills, Ohio EPA spokesman James Lee said. Vacuum trucks and pumping systems are being used to clear away the mud. The state agency is monitoring the clean up process, he said. The company reported both spills to the Ohio EPA last week, when the incidents occurred. Energy Transfer Partners, based in Houston, is building the $4.2 billion Rover Pipeline to move natural gas produced by wells in the Utica and Marcellus shale formations from southeastern Ohio to distribution points in western Ohio, Michigan and Canada. The company hopes to have the project finished and the pipeline operating late this year. According to the Ohio EPA report, the drilling fluids dumped in Bethlehem Township contained bentonite and cuttings from the dirt and rock formation being drilled. The material covered roughly 500,000 square feet or wetlands with a layer of mud that impacted water quality.
Rover Pipeline work dumps 50,000 gallons of drilling fluid in Mifflin Twp. wetlands | Ashland Source | richlandsource.com An estimated 50,000 gallons of drilling fluids were dumped into wetlands in Mifflin Township in eastern Richland County by crews working on the Rover Pipeline, according to documents filed last week with the Ohio Environmental Protection Agency. The spill involved drilling fluids from horizontal directional drilling related to construction of the buried pipeline being built by Houston-based Energy Transfer Partners. James Lee, spokesman for the Ohio EPA, said the spill took place on Friday, April 14, in the area of Amoy-Pavonia Road and was reported to the EPA by Energy Transfer Partners. According to Ohio EPA paperwork, the drilling fluids accumulated within an estimated 30,000 square foot area of wetlands. The drilling fluids, which included bentonite and cuttings from the natural formation, coated the area with a layer of mud and impacted water quality. Bentonite is a natural clay mud used as a lubricant for drilling. After being informed of the spill, the Ohio EPA issued a notice of violation for the unauthorized discharge to waters of the state, in this case a wetland, Lee said. Lee emphasized that no private wells or public water systems were impacted by the spill. Vacuum trucks and pumping systems are being used by the company to clean up the spill and the Ohio EPA is monitoring the situation. According to Lee, discharges of bentonite mud and other material into waters of the state (including wetlands) can affect water chemistry, and potentially suffocate wildlife, fish and macroinvertebrates. Any affected public water systems would need to apply extensive and costly treatment in order to remove the material from the source water. It’s unknown if the company will receive any fines or further sanctions at this time.
Fracking Pipeline Spilled Millions Of Gallons Of Mud Into Ohio Wetlands – WOSU -- A Texas company building a high-pressure natural gas pipeline has been issued violations notices by the state of Ohio for spilling drilling mud in separate wetlands. An Ohio Environmental Protection Agency notice says Rover Pipeline spilled around 2 million gallons of the mud used as a lubricant into wetlands while drilling beneath the Tuscarawas River in Stark County, about 60 miles south of Cleveland. An EPA spokesman says no mud got into the river. The company spilled 50,000 gallons of the naturally-occurring mud call bentonite the next day in Richland County about 70 miles northeast of Columbus. The $4.3 billion, twin 42-inch pipeline project will transport gas from Appalachian fracking operations. The company says cleanup is finished in Richland County and continuing in Stark County.
Widely-Opposed Pipeline 'Confirms Worst Fears' After Two Spills Into Ohio Wetlands -- Energy Transfer Partners ' new Rover Pipeline has spilled millions of gallons of drilling fluids into Ohio's wetlands. Construction of the $4.2 billion project only began last month. According to regulatory filings obtained by Sierra Club Ohio , on April 13, 2 million gallons of drilling fluids spilled into a wetland adjacent to the Tuscarawas River in Stark County. The next day, another 50,000 gallons of drilling fluids released into a wetland in Richland County in the Mifflin Township. The spills occurred as part of an operation associated with the pipeline's installation. Dallas-based Energy Transfer Partners is the same operator behind the controversial Dakota Access Pipeline . The U.S. Federal Energy Regulatory Commission approved the Rover Pipeline's construction in February. The 713-mile pipeline will carry fracked gas across Pennsylvania, West Virginia, Ohio and Michigan and Canada, and crosses three major rivers, the Maumee, Sandusky and Portage, all of which feed into Lake Erie. The pipeline is designed to transport 3.25 billion cubic feet of domestically produced natural gas per day. Completion of the Rover Pipeline is planned for November 2017. Energy Transfer spokeswoman Alexis Daniel told Bloomberg that the spills will not change the project's in-service date.
Pipeline firm cited for 2M-gallon spill in Ohio wetlands - (AP) — A Texas company building a high-pressure pipeline to carry natural gas from Appalachia has been issued violation notices for spilling a total of about 2 million gallons of drilling fluid into two separate wetlands last week, the Ohio Environmental Protection Agency said. About 2 million gallons of the non-toxic, clay-based lubricant spilled April 13 as Rover Pipeline employees drilled horizontally beneath the Tuscarawas River near Navarre in Stark County, about 60 miles south of Cleveland. EPA spokesman James Lee said Thursday that none of the clay mud, called bentonite, reached the river. The spill, covering 500,000 square feet, was caused by pressure during drilling that allowed mud to rise to the surface, Lee said. The next day, about 50,000 gallons of bentonite spilled in Richland County, about 70 miles northeast of Columbus, after a pump failed. No bentonite has been found in private water wells or public water systems from either spill, Lee said.
Sabal Trail, Marcellus / Utica natural gas supply and Florida's growing power market. - The Florida natural gas market will soon have access to another supply source. In June 2017, the Sabal Trail Transmission natural gas pipeline project is expected to begin service, bringing the market one step closer to connecting Marcellus/Utica natural gas to demand markets on the increasingly gas-thirsty Florida peninsula. The project will increase gas supply options for growing power generation demand in the Sunshine State while effectively also increasing gas-on-gas competition between producers in the Northeast, Gulf Coast and Midcontinent. Today we provide an update on Sabal Trail and its related projects. The Florida peninsula has long been isolated from natural gas supply areas, with minimal in-state production, no gas storage capacity to speak of and just two pipeline options for shipping gas into the state from other supply regions. All that may have been acceptable—or at least manageable—at one point in time, but the state in recent years has added significant amounts of gas-fired power generation capacity. Florida—already one of the biggest consumers of natural gas to generate electricity, second only to Texas—is hugely dependent on natural gas and becoming more so. To meet growing demand for electricity in Florida, NextEra Energy’s Florida Power and Light Company (FPL), the state’s largest electric utility and the largest consumer of natural gas, has undertaken a significant revamp of its generation fleet to replace legacy plants that burn coal and less-efficient natural gas peaker units (see Lady Well Power for more on peaker units). FPL completed its first major plant upgrade at Cape Canaveral in April 2013 – a 1,277-MW combined cycle gas turbine unit consuming about 175 MMcf/d of natural gas. Additional gas-fired generation plant capacity has been added since then. This includes the addition of the 1,250-MW Riviera Beach plant in spring 2014 and the 1,277-MW Port Everglades plant in Fort Lauderdale in April 2016; a 460-MW expansion of Tampa Electric’s Polk County Power Station in January 2017; and a planned new 1,640-MW Duke Energy combined-cycle power plant in Citrus County, FL, and the Okeechobee Clean Energy Center, a 1,600-MW combined-cycle gas-fired power plant in Okeechobee County scheduled to open in 2019.
US shale investment back on the upswing - Charleston Gazette-Mail - Global upstream oil and gas merger and acquisitions reached $136 billion in 2016, according to Evaluate Energy’s global M&A 2016 review. And one area seeing a jump in activity was the U.S. Marcellus shale, where close to eight times more was invested in asset and corporate acquisitions in 2016 than in 2015. The Marcellus formation, which runs through northern Appalachia, primarily in Pennsylvania, West Virginia, New York and Ohio, is considered the second-largest natural gas field in the world, after Northfield in Qatar and Iran. Marcellus spans approximately 60.8 million net acres with an estimated 500 trillion cubic feet of natural gas, about 50 trillion cubic feet of which is recoverable using current technology. In 2015, the U.S. shale industry was one of the main casualties of the oil price downturn, suffering a 75 percent drop in year-on-year merger and acquisition spending to $13 billion. This amount was the lowest annual M&A U.S. shale spend since 2009. A reshuffling of asset portfolios in 2016 redirected investments away from the Permian basin, and toward the Marcellus Shale, which led to resurgence in deals as well as natural gas output. The M&A spend in the shale industry bounced back to $48 billion during 2016, representing a 269 percent increase year on year.Many of the players were eager to take advantage of other companies realizing that their respective Marcellus positions were noncore assets. Mega international players such as Anadarko Petroleum Corp., Statoil ASA and Mitsui & Co. sold significant portions of Marcellus land for sums of more than $100 million. Southwestern Energy Company, in efforts to reduce debt, agreed a large deal to sell Marcellus acreage that had no drilling plans until 2023. The acquirers of these assets included far more Marcellus or Appalachian basin-centric companies.Overall, the Marcellus 2016 deals totaled $7.25 billion. This kind of year-on-year increase usually reflects one or two mega deals but not in 2016, when the total included 13 large deals (over $100 million). Both figures are a significant increase on 2015 activity, when only $920 million was spent and only three large deals took place. In fact, 2016 saw more large deals in the Marcellus than in every year since 2010, the first real M&A boom, when 15 such deals were announced.
Cabot Oil & Gas : New suit alleges fracking polluted Dimock Twp well water --Two weeks after a judge reversed a $4.24 million well contamination verdict against Cabot Oil & Gas Corp., another Dimock Twp. resident filed a federal lawsuit alleging the company's Marcellus shale drilling operations contaminated his well water. Ray Kemble claims Cabot's negligence in drilling natural gas well pads contaminated the well water at his home on Route 3023 with several toxic chemicals and high levels of methane. Kevin Cunningham, a spokesman for Cabot, said Kemble's lawsuit appears to include claims that were resolved by a settlement he reached with Cabot years ago. "Mr. Kemble has been active for years in the media voicing his opposition to development of natural gas in Pennsylvania and this suit appears to be a continuation of that monologue," Cunningham said in a statement. "Cabot intends to vigorously defend the lawsuit." The lawsuit, filed Thursday by attorneys Edward Ciarimboli and Clancy Boylan of Kingston, says Kemble initially noticed problems with his well water in 2008, shortly after Cabot began drilling natural gas wells near his Susquehanna County home. Tests run by state and federal environmental agencies later determined his home and others had high levels of methane. Over the next few years, the water quality problems worsened. By November 2012, his water was "black, like mud, and had a strong chemical odor," the suit says. "Plaintiffs water continues to this day to turn different colors, emit different foul and toxic chemical odors, making it unfit to use for any purpose," the suit says. The suit also alleges a compressor station that transports natural gas to a pipeline disrupts the peace, emitting high decibel screeching and pressure venting noises that can be heard at Kemble's property. It was not clear why Kemble waited nearly a decade to file the lawsuit. Attempts to reach Ciarimboli and Boylan for comment Friday were unsuccessful.
Ship & Shore Environmental Introduces Hydroflare Produced Water Evaporator - Ship & Shore Environmental Inc. today announced the introduction of Hydroflare, a first-to-market technology developed in partnership with Hydrozonix a leading water quality management company. The companies have joined forces in response to recent demand for a viable, efficient and long-term solution for managing water sourcing and wastewater treatment in hydraulic fracturing. This new technology evaporates and treats the “produced water” that oil and gas companies generate in the fracking process. “The number of hydraulic fracturing (fracking) shale oil and gas wells in the US, and worldwide, continues to increase. Discharge of water from the fracking process to the ground creates many environmental problems. In addition, demands on fresh water supplies are mounting, as is the need to process the large volumes of produced wastewater. Companies in the oil and gas industry are under increasing pressure to control the produced water and field gas, so we partnered with Hydrozonix to develop a technology that finally provides a solution. And no solution like Hydroflare exists on the market today,” said Anoosheh Oskouian, President & CEO of Ship & Shore Environmental, Inc. The US has vast reserves of oil and natural gas which now are commercially reachable as a result of advances in horizontal drilling and hydraulic fracturing technologies. But as more hydraulic fracturing wells come into operation, the stress on surface water and groundwater supplies grow more demanding. Withdrawing large volumes of water used in the process requires up to one million gallons (3,780 m3) of fresh water per wellhead to complete the fracking process alone. In addition, the injection of produced water into disposal wells has negatively affected some areas. There have been recent incidents where the injection has induced earthquakes in Oklahoma and Ohio. As a result, some areas have placed restrictions on the injection of produced water into disposal wells. This has led to a lack of capacity and high disposal prices for produced water. Hydroflare alleviates all of these issues. The new technology takes natural gases produced by the fracking process and uses it to provide energy to evaporate this produced wastewater. Ship & Shore Environmental and Hydrozonix have created a revolutionary solution that is long-term and efficient.
Coal, fracking, Amish or what? --Sometimes you can have your cake and eat it, too. But when it comes to energy you cannot! The law of conservation of energy is a fact we must all live by. If you want energy, (the ability to do work, which includes electrical, motion, heating, cooling, building, etc.) you must first have energy. Energy can only come from energy, and our modern society requires vast amounts of it. Currently, we are getting a majority of our energy (electricity) from coal, but there are several others options available and many more possibilities yet to be explored. Coal has been our go-to energy source since the industrial revolution. Without the energy locked up in coal, none of the work required for the industrial revolution would have been possible. . But there are other sources of energy that are powerful, plentiful, and not-as-dirty. Natural gas is one such alternative. Vast amount of natural gas has recently, within the last 20 years, been discovered deep within our nation’s bedrock. Natural gas is powerful and plentiful, the northern great plains of America have been described as the Saudi Arabia of natural gas. When natural gas is burned, instead of coal, far less carbon dioxide (CO2) is released into the atmosphere, reducing the greenhouse effect. Therefore, natural gas has many of the benefits of coal as a suitable national energy source. However, it too has negative side effects when it is used on an industrial scale. The extraction of natural gas is the major problem when compared to coal. The extraction of natural gas requires a modern technique called Hydrological Fracturing, . In times of water shortages, should we be using our fresh water resources for extraction of natural gas? Or we can go Amish. With all respects to the Amish people, their belief in living simple on the earth forbids them to use electricity within their daily lives. I do not know too many people who could carry on their daily lives without the assistance of electricity, which has been generated by the combustion of coal or natural gas. The truth is we need our electricity! Electricity is energy, and coal and natural gas are the two resources we have available to use. You choose: coal or natural gas? You cannot say no to both, energy must come from somewhere.
Vermont Gas Pipeline: Safety Concerns Presented To Governor, Federal Pipeline Safety Administration | Global Justice Ecology Project: Concerned Vermonters have compiled evidence of serious and chronic safety issues surrounding construction of the Vermont Gas pipeline from Colchester to Middlebury. These were detailed and documented in a letter delivered to Governor Scott and a similar letter also delivered to the federal Pipeline Hazardous Material Safety Administration on Monday, April 10th from eight Vermont organizations (listed below). Vermont Gas plans to add flammable gas, under pressure, to the pipeline within the next few weeks. The letters state: “The pipeline has been constructed in haste and without consistent and effective regulatory oversight. Those living near the pipeline are now at risk of harm from a potential pipeline failure, leak or explosion.” Evidence gathered from numerous public records requests and observations show a wide range of problems involving electrical safety, problems with welds and coatings, incorrect placement and handling of pipe and more. Indications are that the company did not even have the essential and required comprehensive written specifications for construction in place. Contractors were therefore left without proper guidelines. Workers were not properly qualified for tasks. Inspectors were not provided with protocols for inspection and required onsite technical experts were not present as required. These problems were raised throughout multiple years of construction and in most cases appear never to have been resolved while construction was allowed to continue. The pipeline now lies buried underground.A prior communication from the groups to the federal Pipeline and Hazardous Material Safety Administration (PHMSA) in October 2016 led to an announcement in January 2017 that the federal agency would open an investigation. Since then, many additional problems have come to light and are presented in detail in documents delivered along with the letters.
Environmental group asks court to block work on Pinelands pipeline until appeals are heard: Citing “imminent environmental harm,” the Pinelands Preservation Alliance on Tuesday asked the Appellate Division of New Jersey Superior Court to block the start of construction of South Jersey Gas’ pipeline through the Pinelands while the court considers several appeals against the project. The motion for a stay further asserts that the Pinelands Commission’s Feb. 24 approval of the project violated its own comprehensive management plan, or charter; that the commission did not conduct proper hearings before the approval; and that two commissioners who voted for the project had potential conflicts of interest. The 22-mile-long pipeline would begin in Maurice River Township in Cumberland County and serve a natural gas-fired electrical-generation plant in Upper Township, Cape May County. Ten miles of the route would run through a protected Pinelands forest where, opponents say, such infrastructure is barred by the Pinelands Commission’s comprehensive management plan. Before a vocal crowd of about 800 at the Crowne Plaza Hotel in Cherry Hill, the Pinelands Commission’s board approved the route by a vote of 9-5 with one abstention. Three years earlier, it had rejected the identical project on a 7-7 vote. “We contend the company [South Jersey Gas] is not substantially harmed by waiting until the appeal is decided before starting construction. In contrast, any construction would cause environmental harm and be entirely unnecessary.”
Don't Call It a Comeback - It's Not Your Father's Haynesville Natural Gas Shale Play - After spending the past few years on the backburner with declining production volumes, the Haynesville Shale natural gas play, which straddles the Northeast Texas-Louisiana border, is back in the headlines. Rig counts in the region have doubled in the Haynesville in the past six months or so. Exco Resources—which has four rigs operating there currently—last week said it is divesting its Eagle Ford assets in favor of boosting drilling investment in the Haynesville. At the same time, there’s a new crop of operators in the play dedicated specifically to drilling in the Haynesville. While total basin production volumes have yet to take off, all signs point to a Haynesville resurrection of sorts. But there are also early clues that much has changed since the first go-round and the drilling profile of today’s Haynesville is likely to look much different than it did nearly 10 years ago. Today we begin a look at RBN’s latest analysis of production economics in the Haynesville Shale. Our blog title today is from the first line of LL Cool J’s tune, “Mama Said Knock You Out,” that pleads: “Don't call it a comeback, I been here for years.” And so it goes for the Haynesville Shale. The mostly pure gas play came on the scene in 2008 and quickly became the darling of the Shale Revolution But when gas prices began falling, drilling economics there were priced out of the market and the play eventually lost favor among producers, hanging on for a time as some wells continued to be drilled to hold leases (for more on HBP, or held-by-production leases, see Hold on Tight). The Haynesville never entirely went away, except perhaps from the headlines, but it’s been largely sidelined in recent years—that is, until now.
Coming soon to the US: more LNG terminals? — If Gary Cohn gets his way, the U.S. could be the biggest exporter of liquefied natural gas in the world. The director of the White House’s National Economic Council — and former Goldman Sachs Group Inc. president — said the administration would step up approvals for LNG export terminals, starting with a project in the Northwest that he didn’t identify. At present, Cheniere Energy Inc. is the nation’s sole LNG exporter from the lower 48 states. “We could be and should be the largest exporter of LNG in the world,” Cohn said at the Institute of International Finance forum in Washington. “We’re going to permit more and more of these LNG plants.” Federal regulators are reviewing about two dozen applications from companies seeking to send America’s gas bonanza overseas. That’s putting the U.S. on course to become a net exporter of natural gas by 2018, the first time that’s happened since the 1950s. Veresen Inc.’s Jordan Cove LNG export project in Oregon has been denied a permit twice by regulators. After Cohn’s comments, shares of the Calgary-based company jumped the most since the beginning of February. The company had no comment on Cohn’s remarks, according to Riley Hicks, a spokesman.
US LNG exports set to tip the gas market scales in 2017 - U.S. LNG exports via Cheniere Energy’s Sabine Pass LNG export facility are poised to be a major demand driver of the domestic natural gas market in 2017. Pipeline deliveries to the terminal have more than tripled since mid-2016 and are set to climb further as more liquefaction capacity ramps up. With two liquefaction trains already operational, the Federal Energy Regulatory Commission last month approved Train 3 to begin operations and also green-lighted the start-up of Train 4 commissioning. Today, we provide an update of Sabine Pass’s export activity and its potential effect on U.S. gas demand this year. Exports are a significant and growing driver of the U.S. natural gas supply/demand balance. As our analysis of gas supply and demand data a few weeks back in You Keep Me Hangin’ On showed, gas exports, including pipeline deliveries to Mexico and Cheniere Energy’s Sabine Pass LNG export facility, soaked up 4.2 Bcf/d of U.S. supplies in 2016, 1.3 Bcf/d (46%) more than in 2015. That incremental demand went a long way toward helping offset the effects of a mild winter (from November 2015 to March 2016) that had led the U.S. gas storage inventory to the highest March-ending level in more than five years. In fact, despite gas demand in the power sector setting records in most months in 2016, the biggest increase in demand in 2016 versus 2015 came from exports. For the full year on average, about 0.8 Bcf/d of the increase came from exports to Mexico and 0.5 Bcf/d from Sabine Pass LNG. But by the end of the year, LNG exports were nearly a third of all U.S. natural gas exports. More recently, they’ve grown to be more than 40% of total average U.S. gas exports. And that is the case in spite of exports to Mexico also growing substantially during the same period. As such, LNG exports are expected to be a major contributor to a tighter gas supply/demand balance this year versus 2016.
Exxon Mobil plans multi-billion dollar plant near Texas — Exxon Mobil Corp. and a Saudi partner plan to build a multi-billion dollar petrochemical plant near the Texas coast, Texas' governor said Wednesday. The project will be a venture involving Exxon and Saudi Arabia Basic Industries Corp. Exxon officials have said it'll be among the largest ethane steam cracker plants in the world, with an opening scheduled for 2024. The plant will be built in Portland, just north of Corpus Christi, on roughly 1,300 acres (526 hectares). Estimated to cost about $10 billion, the plant will produce components used to make polyester, anti-freeze, plastic bottles and other items. In formally announcing the project, Gov. Greg Abbott said the plant "illustrates that our business climate is exactly what leading and growing companies are seeking when investing in their future." Yousef Abdullah Al-Benyan, CEO of SABIC, added: "We are focused on geographic diversification to supply new markets." The project has received state and local tax incentives. The Gregory-Portland Independent School District board voted last month to approve $1.2 billion in tax incentives, and San Patricio County commissioners OK'd a $210 million package. Abbott said Wednesday that more than $6 million was offered in state tax breaks. Officials said the project is expected to create thousands of jobs, an important consideration for leaders in San Patricio County. The Corpus Christer Caller-Times reported the area lost more than 800 jobs in the last three months of 2016 with the closure of a plant and a series of layoffs at a manufacturing company. But the project has also generated criticism. Some residents circulated a petition citing safety and environmental concerns. The plant is set to be built less than 2 miles (3.22 kilometers) from the district high school.
How soaring sand costs and water-disposal expenses threaten producer gains in key shale plays. In the past few years, producers in shale and tight-oil plays have made great strides in reducing their drilling costs and improving the productivity of their wells. But the trends toward much longer laterals and high-intensity well completions have significantly increased the volumes of sand being used—some individual well completions use enough sand to fill 100 railcars or more! An even bigger concern for many producers is the rising cost of disposing of produced water—that is, the water that emerges with hydrocarbons from these supersized wells. Today we begin a surfing-themed series that focuses on how the two key components of any beach vacation—sand and water—are impacting producer profitability. Our initial focus is on sand. We’ll get to water-disposal costs later in this series. Put simply, the Shale Revolution would not have been possible without sand—and large volumes of it. As we said in Tales of the Tight Sand Laterals, freeing the vast amounts of oil, gas and natural gas liquids (NGLs) trapped in shale and tight sands requires horizontal drilling to access the long, horizontal layers where the trapped hydrocarbons reside, and proppant (natural sand, ceramics and resin-coated sand) that, when forced out of the horizontal portion of wells at high pressure (using water and other fluids), fracture openings in the surrounding shale/tight sands. When the pressure is released, the fractures attempt to close but the proppant contained in the fluids keeps them open, making a ready path for oil, gas and NGLs to flow into the well bore.
Sand mining grows in Texas along with faith in energy rebound as 'real deal' - Longview News-Journal — In a deepening pit in this small town southeast of Waco, workers aim a high-pressure water cannon that reduces small hills of clay-like sand into a watery slurry that is filtered, processed, dried into fine particles and loaded onto trucks bound for hydraulic fracturing operations across Texas. It will take as many as 1,000 trucks to haul enough of this sand to frac a single large well. As drilling has recovered in recent months, particularly in West Texas' Permian Basin, the sand mining industry has exploded. It is producing more than ever to meet the demand of an oil and gas sector that is using up to 20 times more sand per well than it did during peak of the last energy boom. Across the state, already home to nearly 10 frac sand mines, operators are moving to expand quickly, setting the stage for Texas to become a bigger player — and competitor — in an industry long dominated by purer Wisconsin and Minnesota sands. At the same time, the growth of sand mining is opening a new front in the battle between the energy industry and environmentalists, who argue the mines despoil pristine land and create health hazards by kicking up silica dust, which has been linked to lung cancer, tuberculosis and other lung diseases when inhaled. "What's more important? Breathing or having water to drink?" Sand companies contend they follow regulations to limit silica air pollution and that they have almost no carbon emissions. They are pressing ahead to take advantage of demand and prices that have doubled in a little over a year. Several new sand mines or expansions, covering thousands of acres are proposed in Texas. Sand is mixed into fracking fluids that crack shale rock to prop open the fissures to allow oil and gas to escape, hence the industry name "proppant" to describe the fine grains. The largest wells now consume up to 25,000 tons — 50 million pounds — of sand each, up from 1,500 tons, or about 3 million pounds, per well during the boom years through 2014.When oil prices crashed and companies sought ways to lower production costs, drillers began experimenting with the idea of using more sand — cheaper than chemicals and ceramic proppants — to increase oil and gas output. Drillers are creating much longer wells that extend a mile or two horizontally and sometimes pumping more than 5,000 pounds of sand per foot, according to energy analysts and executives, including Rick Shearer, the chief executive of sand manufacturer Emerge Energy Services.
Why The Permian Doesn’t Keep OPEC Awake At Night | OilPrice.com: The recent headlines have been eye-popping. “The Permian Basin Keeps On Giving”. “A $900 Billion Oil Treasure Lies Beneath West Texas Desert”. “Shell’s New Permian Play Profitable at $20 A Barrel”. “The World’s Hottest Oil Play”. “Permian Basin Prevails”. “The Permian Basin: An existential Threat To Canadian Oil As The War On Cost Heats Up”. “This Texas Oilfield Is Messing With OPEC”. The articles contain analysis and commentary concluding that no matter what happens in the rest of the world, the future of oil prices will be heavily influenced by U.S. light tight oil (LTO) producers and more specifically, the Permian. This is more of the popular thesis OPEC is dying or dead and the United States has replaced Saudi Arabia as the world’s swing producer. Except it is not true. If you believed every word you would conclude there are only two sources of oil on earth: the Permian Basin and everyone else. While the Permian is a wonderful and significant mass of hydrocarbon-rich formations, its impact on world oil prices in the next few years is overstated. A typical pro-Permian article appeared in Forbes November 21, 2016 under the title “The Permian Keeps On Giving”. It followed a report by the U.S. Geological Survey (USGS) following a new assessment of the Permian including a relatively undeveloped horizon called the Wolfcamp shale. The USGS reported some 20 billion barrels of oil was yet to be discovered and is technically recoverable; Following the USGC report Bloomberg ran a headline reading, “A $900 Billion Oil Treasure Lies Beneath the West Texas Desert”. Expanding on the Wolfcamp assessment, Bloomberg wrote, “That’s almost three times larger than North Dakota’s Bakken play and the single largest U.S. unconventional crude accumulation ever assessed. At current prices, that oil is worth almost US$900 billion”. Of course, that’s if every barrel is discovered and recovered and before any costs.
Why Exxon Is Giving Its Shale Unit a Long Leash - In a matter of weeks, crews working for Exxon’s XTO Energy Inc. unit will begin erecting drilling rigs across a patch of southeast New Mexico to exploit the region’s mile-thick strata of oil-soaked rock. ExxonMobil Corp. paid almost $6 billion for the drilling rights in late February—its biggest acquisition in more than six years—but that’s where the parent company’s involvement ends: Decisions on when and how to harvest the crude fall solely on the shale experts at XTO. Exxon Chief Executive Officer Darren Woods and his top lieutenants at corporate headquarters in suburban Dallas are intentionally staying out of the way of the tightly knit phalanx of XTO engineers, physicists, and geologists leading the oil major’s advance into shale. The top-down and heavily structured approaches they use on megaprojects—building a liquefied gas export complex or pumping crude that lies miles beneath the sea surface—won’t work with shale. Rigs and roughnecks must be hired or moved at a moment’s notice in response to emerging opportunities or volatile crude prices. “Historically, the major operators have been slower-moving beasts,” Barrett says. But in the age of shale, “the ability to be flexible is a huge advantage.”To that end, XTO managers aren’t constrained by the purchasing order system that governs project spending at the rest of Exxon, the people said. The practice, conceived for projects that can take a decade to build and cost $50 billion, is too burdensome for shale’s $6 million wells, which can be up and running within weeks. XTO’s special dispensation means it can hire a bulldozer to clear a drilling site or summon a fracking crew to complete a well without enduring the monthslong wait for signoffs by multiple layers of middle and upper management. XTO planners are also free from the usual Exxon practice of submitting—and strictly adhering to—12-month operating blueprints that undergo arduous vetting and amendment as they make their way through manifold HQ filters.
Tribal Members in Oklahoma Defeat Natural Gas Pipeline Company The U.S. District Court for the Western District of Oklahoma has ordered a natural gas pipeline operator to cease operations and remove the pipeline located on original Kiowa Indian lands Anadarko.The ruling in Davilla v. Enable Midstream Partners,, L.P., issued at the end of March, found that Enable Midstream was continuing to trespass on the land and ordered the company to remove the pipeline within six months.The plaintiffs are 38 enrolled members of the Comanche, Caddo, Apache, Cherokee and Kiowa Tribes of Oklahoma. Additionally, the Kiowa Tribe of Oklahoma has an interest in the land. The interests vary from nearly 30 percent to less than 9/10th of a percent. “It’s very significant,” said plaintiffs’ lawyer David Smith.David Klaassen, a spokesman for Enable, said the company doesn’t comment on active legal issues. The Bureau of Indian Affairs approved an easement across the land in 1980 for Enable’s predecessor, Producer’s Gas Company, to construct and install a natural gas pipeline. The original easement expired in 2000, according to court documents. By 2002, the company had changed to Enogex, Inc., and had submitted a right-of-way offer to the BIA and the plaintiffs for another 20 years. The majority of the landowners rejected the offer.In 2008, the BIA’s interim superintendent of the Anadarko Agency approved Enogex’s application to renew the easement for 20 years. The plaintiffs appealed the decision in 2010, and the BIA vacated the opinion.“The BIA determined that it did not have authority to approve the right-of-way without the consent of plaintiffs or their predecessors in interest and that the price offered by defendants was unreasonable,” according to court documents. “The BIA remanded the case for further negotiation and instructed that if approval of a right-of-way was not timely secured that Enogex should be directed to move the pipeline.” A new right-of-way has not been granted and the natural gas pipeline continued to operate, according to the court documents. The plaintiffs filed a trespassing violation and sought preliminary and permanent injunction in November 2015. Smith said the judge agreed with the tribal members that federal law applies and that there can be an accounting for the money made off the land during the period deemed a trespass, which is 17 years. Smith said there are similar issues all across Indian country.
Trump's EPA to reconsider oil and gas emissions rule | Reuters: The U.S. Environmental Protection Agency will reconsider a rule on greenhouse gas emissions from oil and gas operations and delay its compliance date, the agency said on Wednesday in the Trump administration's latest move to reduce regulations. Oil interest groups, including the American Petroleum Institute and the Texas Oil and Gas Association, had petitioned the EPA a year ago to reconsider the rule limiting emissions of methane and other pollutants from new and revamped oil and gas wells and systems. The EPA said in a statement that it would delay the rule's June 3 compliance date by 90 days and take public comments during that period. Under Democratic President Barack Obama, the EPA released the first methane limits on the facilities in May 2016, saying it would cost energy companies $530 million, but would lead to $690 million in benefits, including lowering medical bills. Scott Pruitt, the EPA chief in the administration of Republican President Donald Trump, joined dozens of other states in challenging the rule when he was attorney general of oil-producing Oklahoma. Pruitt has said he does not believe that greenhouse gas emissions are the main driver of climate change. Energy companies had complained that the methane rule would add costs to wells that were not producing much oil and gas, and that it was duplicative as the sector had already reduced the emissions.
Does methane rule review shut out public input? - Don Nelson estimates he can spot 60 or 70 natural gas flares from his North Dakota ranch — even now that the state has raised its gas capture rate to nearly 90 percent. Ahead of the release of the Bureau of Land Management's final Methane and Waste Prevention Rule, Nelson attended two hearings to testify in support of the regulation to curb gas flaring, venting and leaking from oil extraction operations on federally controlled lands."I think it's the biggest waste I've ever seen in my life," he said. Nelson joins a chorus of Westerners and environmentalists calling on President Trump's Interior Department not to shut out public input on its reconsideration of the BLM rule (Greenwire, April 12). Following the release of Trump's "energy independence" executive order, Interior Secretary Ryan Zinke called for a 21-day review to determine whether the rule — and at least two other department regulations — was fully consistent with the new administration's policies.Zinke handed down his order March 29. The review process isn't unlike efforts by previous administrations to look back at rules introduced by their predecessors, according to an Interior spokeswoman. The executive and secretarial orders simply offer a more formal process, the agency says. Putting a 21-day deadline on the process is not typical, said Alexandra Teitz, who previously served as counselor to former BLM Director Neil Kornze.
Dakota Access, ETCO oil pipelines to start interstate service May 14 - The Dakota Access Pipeline and connected Energy Transfer Crude Oil Co pipeline will start interstate service May 14, opening access for up to 470,000 b/d of Williston Basin crude to move to the Texas Gulf Coast, according to regulatory filings. The pipelines' developers announced the startup timing in separate tariff filings to the US Federal Energy Regulatory Commission posted Thursday. Dakota Access' uncommitted rate is $6/b to move Bakken crude from one of several field points to Patoka, Illinois, and $7.50/b from the field to Nederland, Texas. Shippers that sign a five-year agreement to move at least 5,000 b/d from the field to Illinois would pay $5.25/b.Seven-year committed rates from the Bakken field points to Texas range from $5.60/b for more than 90,000 b/d to $6.50/b for 5,000-29,999 b/d. Ten-year committed rates from the Bakken to Texas range from $5.50/b for more than 90,000 b/d to $6.25/b for 5,000-29,999 b/d. The shipping cost to move crude only on ETCO, from Illinois to Texas, is $1.85/b, according to its tariff filing. Dakota Access received the federal easement it needed to start work at the final unfinished segment in North Dakota on February 8 and has been racing to complete construction and put the delayed project into service.
East Coast refiner shuns Bakken delivery as Dakota Access Pipeline starts | Reuters: Philadelphia Energy Solutions Inc, the largest refiner on the U.S. East Coast, will not be taking any rail deliveries of North Dakota's Bakken crude oil in June, a source familiar with delivery schedules said on Tuesday - a sign that the impending start of the Dakota Access Pipeline is upending trade flows. At its peak, PES would have routinely taken about 3 miles' worth of trains filled with Bakken oil each day. But after the $3.8 billion Dakota Access Pipeline begins interstate crude oil delivery on May 14, it will be more lucrative for producers to transport oil to refineries in the U.S. Gulf Coast. The long-delayed pipeline will provide a boost for Bakken prices and unofficially end the crude-by-rail boom that revived U.S. East Coast refining operations several years ago. "It's the new reality," said Taylor Robinson, president of PLG Consulting. "Unless there's an unforeseen event, like a supply disruption, there will be no economic incentive to rail Bakken to the East Coast." PES declined to comment for this story. The 1,172-mile (1,885-km) Dakota Access line runs from western North Dakota to a transfer point in Patoka, Illinois. From there, the 450,000 barrel per day line will connect to large refineries in the Nederland and Port Arthur, Texas, area.
Montana tribes want Keystone XL away from their drinking Water - In Montana, the Sioux and Assiniboine tribes are working to protect their drinking water from any potential risks the Keystone XL pipeline poses. The Fort Peck Indian Reservation is home to both American Indian nations, and they know firsthand what can happen when oil drilling destroys a water source. Rolling Stone explores this history and the tribe’s ongoing battle in a story published yesterday (April 19).The 1,179-mile long pipeline is set to cross west of the reservation on the Missouri River—the same body of water the Sioux people fought to protect against the Dakota Access Pipeline. The Fort Peck Indian Reservation's only source of fresh water, from an intake plant, sits downstream. People on the reservation used to pull groundwater from their own wells. Then, in the ’90s, tribal members began to notice changes in their tap water: It was salty.As it turned out, the Murphy Oil Corporation dumped 42 million gallons of wastewater brine into unlined pits between 1952 and 1955, a 2013 investigation published in the University of Montana’s graduate journal found. This water contained benzene, a carcinogen, and reservation residents have seen a cluster of cancer cases as a result.Now, they’re worried about what the Keystone XL pipeline can do."Oh, what the hell, just do it to the Indians: I'm afraid that's just a lot of people's attitudes," said Margaret Abbott, who lives on the reservation, to Rolling Stone. Tribal leaders have attempted to meet with TransCanada, the pipeline developer, but the company canceled a March 16 meeting after protestors picketed tribal headquarters. Another meeting is “tentatively planned,” writes Rolling Stone.
Oil Industry Worried About Trump’s “Buy American” -- U.S. President Donald Trump signed an executive order on Tuesday that would promote his “Buy American, Hire American” trade policy, an agenda that is worrying oil pipeline companies.Trump’s executive order is vague in details. The “Buy American” part of the executive order seeks to tighten the standards in U.S. government procurement programs, which essentially means that federally-funded construction projects use more American-made goods. It is not at all clear how this will alter current policy. The administration wants to close what it sees as too many loopholes, such as nearly-finished imported goods being completed in the U.S. and then deemed to be “Made in America.”The “Hire American” agenda calls for a reform of the H-1B visa program, which allows companies to hire skilled foreign workers.The executive order, if carried out, would affect companies building oil pipelines in the U.S., requiring them to use U.S. steel in their projects. But the order is imprecise and incomplete, and fleshing out the specifics of the plan could take more than a year. Crucially, beyond the splashy headlines, Trump’s executive order is the start of a process, not the end of one. Moreover, all the order does is ask federal agencies to review certain rules; it doesn’t require them to necessarily do anything concrete. Trump also made some comments on Tuesday that surely raised some eyebrows in the Canadian oil and gas industry. “And we're going to make some very big changes or we are going to get rid of NAFTA for once and for all. It cannot continue like this, believe me,” he said on Tuesday. Characteristically lacking in specifics, the President’s comments will only add to uncertainty.
US pipeline developers push back on Trump's call for domestic steel - : US oil and gas pipeline developers, including the company behind the newly finished Dakota Access Pipeline, are pushing back on President Donald Trump's call for future pipelines to be built with domestic steel. Energy Transfer Partners -- a major owner of the Dakota Access pipeline that will next month carry Bakken crude from North Dakota to Illinois -- said such a requirement would have a "significant adverse impact." "The impacts of such a restriction are expected to severely delay project schedules, drive up costs, decrease availability and lower quality," ETP said in comments filed to the Commerce Department earlier this month. Days after his inauguration, Trump signed an executive memorandum calling on the Commerce Department to develop a plan "under which all new pipelines, as well as retrofitted, repaired, or expanded pipelines" use US-sourced materials "to the maximum extent possible and to the extent permitted by law." The caveats left considerable wiggle room for any eventual policy, but Trump has nevertheless characterized the memo as a directive to pipeline companies to "buy American." Trump's memo gave Commerce until late July to submit a plan to him.
Undaunted by oil bust, financiers pour billions into U.S. shale | Reuters: Investors who took a hit last year when dozens of U.S. shale producers filed for bankruptcy are already making big new bets on the industry's resurgence. In the first quarter, private equity funds raised $19.8 billion for energy ventures - nearly three times the total in the same period last year, according to financial data provider Preqin. The quickening pace of investments from private equity, along with hedge funds and investment banks, comes even as the recovery in oil prices CLc1 from an 8-year low has stalled at just over $50 per barrel amid a stubborn global supply glut. The shale sector has become increasingly attractive to investors not because of rising oil prices, but rather because producers have achieved startling cost reductions - slashing up to half the cost of pumping a barrel in the past two years. Investors also believe the glut will dissipate as demand for oil steadily rises. That gives financiers confidence that they can squeeze increasing returns from shale fields - without price gains - as technology continues to cut costs. So they are backing shale-oil veterans and assembling companies that can quickly start pumping. "Shale funders look at the economics today and see a lot of projects that work in the $40 to $55 range" per barrel of oil, said Howard Newman, head of private equity fund Pine Brook Road Partners, which last month committed to invest $300 million in startup Admiral Permian Resources LLC to drill in West Texas. Data on investments by hedge funds and other nonpublic investment firms is scant, but the rush of new private equity money indicates broader enthusiasm in shale plays.
Wall Street Is Pouring Money Back Into Shale --With oil prices seemingly on firm footing, Wall Street is pouring money back into the shale sector, expecting profits even at $50 per barrel. The private equity industry raised an estimated $19.8 billion in funds for energy investment in the first quarter of this year, or about three times as much as the same period in 2016. The figures indicate a more aggressive approach from private equity in shale drilling, and rising expectations that the oil market is set to rebound. The data comes from Preqin, and was reported on by Reuters.The optimism comes even as oil prices have languished in the $50 per barrel range since November, after briefly dipping into the $40s last month. The hopes of a stronger rebound by now have been dashed, and oil analysts have steadily revised their expectations, pushing out their projections for stronger price gains. The extraordinary gains in U.S. crude oil inventories in the first quarter caught the market – and OPEC – by surprise, killing off hopes of oil heading north of $60 per barrel. But the new money from Wall Street need not depend on $60+ oil. Lenders are confident that their investments will turn out to be profitable even at the prevailing market price today. That is because shale drillers have dramatically cut their costs, pushing breakeven prices down. "Shale funders look at the economics today and see a lot of projects that work in the $40 to $55 range," Howard Newman, head of private equity fund Pine Brook Road Partners, told Reuters. His firm dumped $300 million in Permian driller Admiral Permian Resources LLC in March. Lenders are already doing much better than they expected. JPMorgan Chase, Wells Fargo and Citigroup announced that they have an additional $370 million from the first quarter to use at their disposal, a collective sum that had been set aside to be used for expected losses on their energy portfolios. A survey from Haynes & Boone of oil companies, banks and private equity found a high degree of confidence that the ongoing credit redetermination period – a twice-a-year review by lenders of their credit lines to drillers – will be favorable to the energy industry. Of the 163 people surveyed, roughly 76 percent said they expect credit lines to either remain unchanged or even increase. In other words, banks are not backing away from the shale industry, and in some cases, they are pouring more money in.
Shale Producers Take the Strain of Lower Prices | Rigzone - As I wrote last week, hedging is one way U.S. oil producers endure the pressures of low prices. And a recent survey by Bloomberg Intelligence found many large E&P firms are locking in pretty low prices for their expected output this year. In particular, producers in the Permian shale basin tend to be hedging at lower prices than rivals centered on less-attractive basins such as the Bakken and Eagle Ford basins. The chart below shows the proportion of 2017 output hedged by these companies at the average price locked in. I've color-coded them according to their main basin exposure, and the bubbles represent the absolute amount of oil covered by hedges: Permian-weighted companies such as Pioneer Natural Resources Inc., Energen Corp. and RSP Permian Inc. tend to dominate that upper-left part of the chart, meaning they have hedged more of their expected production at lower average prices. This is a result of aggressive drilling programs (with hedging providing comfort for the lenders and investors funding it). But the willingness of Permian-weighted firms to take lower prices in general should be noted by anyone who is long of oil. Companies more focused on the Eagle Ford basin are clearly less hedged and generally at higher prices, likely reflecting the tougher economics there. EP Energy Corp. is an outlier in that respect, but this reflects aggressive hedging taken early in 2016, when oil prices rallied, and the company's need to deal with its high leverage, with net debt at 6.1 times Ebitda at the end of 2016, according to data compiled by Bloomberg. The Bakken crowd are also hedged at generally higher prices than those in the Permian basin, but the weighted average is still less than $50 for the five in the chart . Granted, some big Bakken producers, such as Hess Corp. and Continental Resources Inc., haven't hedged any production, according to Bloomberg Intelligence. Yet, with the North Dakota Industrial Commission reporting the state's oil production nudged back above 1 million barrels a day in February, anyone keeping track of U.S. supply trends shouldn't keep their lens focused solely on West Texas.
Many diversified E & Ps in major realignments, shifting toward an oil focus. -- After cutting capital investment 71% between 2014 and 2016, the 13 diversified U.S. exploration and production (E&P) companies examined in our Piranha! market study are planning to increase 2017 capital spending by 30%. While this seems like a lackluster rebound compared to the 47% boost announced by oil-focused E&Ps, the diversified group’s totals are skewed by the pull-back strategy of giant ConocoPhillips. Excluding ConocoPhillips, the 12 other companies are guiding to a 48% increase in 2017 investment—very similar to their oil-weighted peers. Today we continue our Piranha! series on upstream spending in the crude oil and natural gas sector, this time zeroing in on E&Ps with a rough balance of oil and gas assets. U.S. oil and natural gas E&P companies, anticipating continuing low crude oil and natural gas prices, have been reshaping their portfolios to focus on a half-dozen top-notch resource plays whose production economics can hold up even if prices were to soften further. The biggest of these asset purchases and sales grab the headlines, but countless other, smaller-bite deals are having profound effects too. Taken together, this piranha-like devouring of E&P assets in the Permian, the SCOOP/STACK and other key production areas is transforming who owns what in the plays that matter most, and positioning a select group of E&Ps for success. We examine this ongoing transformation in Piranha!, our new market study of 43 representative U.S. E&Ps. Of that universe of companies, 21 focus on oil (60%+ liquids reserves), nine are gas-weighted producers (60%+ natural gas reserves) and 13 are diversified producers. All of the major U.S. shale/unconventional plays are represented in the combined portfolios of these firms.
Prudhoe Bay well continues venting gas - Alaska Dispatch - Natural gas continues to seep from a Prudhoe Bay well that sprayed crude oil and vented gas beginning Friday, a state environmental agency said Sunday. Employees with BP Alaska discovered an "uncontrolled gas release" from the top of a well, as well as what the Alaska Department of Environmental Conservation described as an "initial spray" of crude oil caused by the venting gas, on Friday. On Saturday night, workers were able to enter the wellhouse and bleed off pressure from the well, the DEC said in a Sunday situation report. There are two leaks on the well: one near the top, and one farther down. The top leak was halted with activation of a safety valve; the lower leak "has been reduced but is currently leaking gas," the situation report said.BP was working to plug the top leak, the result of a damaged pressure gauge, according to the situation report."The plan needs to be implemented before well killing operations can take place," the report said. There have been no reports of impact on wildlife, and no evaluation of whether the spraying oil may have reached snow-covered tundra beyond the gravel wellhead pad, the report said. The DEC has not estimated how much crude oil sprayed from the well.
BP Struggles to Control Damaged Well in Alaskan Arctic -- The British oil giant BP worked through the weekend to control a damaged oil well on Alaska’s remote North Slope that had started spewing natural gas vapors on Friday morning, the company and Alaska officials said. There have been no injuries or reports of damage to wildlife, but crews trying to secure the well have failed amid frigid winds gusting to 38 miles an hour. Alaskan and federal officials have identified two leaks venting methane gas, a powerful greenhouse gas linked to climate change. While some crude has sprayed out of the well with the gas, BP said infrared cameras on a flight over the site appeared to confirm that the oil released was contained on the gravel pad surrounding the well head and did not reach the tundra. By Sunday afternoon, crews had shut down one leak with a surface safety valve, but the second leak, although reduced, was still spouting gas, federal and state officials said. Specialists from Boots and Coots, a well control company, were arriving in the area on Sunday to assist in closing down the well. The damaged well is on state land several miles outside Deadhorse, a remote town. “Crews are on the scene and are developing plans to bring the well under control,” said Brett Clanton, a BP spokesman, “and safety will remain our top priority as we move through this process.” He said that it was unknown how much gas had leaked and that the company would investigate the causes of the accident after repairs were made. Oil workers operating near the well were evacuated because of the possibility of an explosion. There are large quantities of gas in the northern Alaskan fields around Prudhoe Bay in part because, without enough pipelines to bring it to market, oil companies have been pumping excess gas back into the ground for decades. “The cause of the discharge is unknown at this time,” federal and state officials said in a statement late on Saturday. The statement said that an effort to secure the well on Friday night “was unsuccessful due to safety concerns and damage to a well pressure gauge.”
Leaking BP Arctic Oil Well: Too Unstable to Shut Down -- BP and U.S. Environmental Protection Agency officials spent the holiday weekend trying to repair a leaking oil well on Alaska's North Slope. Officials said the well is too unstable to shut down because of frigid temps in the high Arctic, but have released the pressure on one of the main leaks. It appears that 1.5 acres of the remote area near Deadhorse, Alaska have been affected by the spill. Native communities were notified and non-essential workers were forced to evacuate. However, no injuries to crew or wildlife have been reported. "Crews are on the scene and are developing plans to bring the well under control," said BP spokesperson Brett Clanton, in a release on Saturday. "Safety will remain our top priority as we move through this process." There were initially two main leaks, one near the top of the rig that was releasing methane and the other down the assembly line spraying crude oil in a mist over the ice. Officials were able to detect both leaks using infrared cameras. "Based on an overflight with infrared cameras, the release appears to be contained to the gravel pad surrounding the wellhead and has not reached the tundra," Clanton said. Crews are still getting the situation under control and no updates have been reported in the last 12 hours. As natural gas operations have begun taking shape in Alaska, reports of leaks have become more frequent. There is an ongoing, and very large leak occurring at Cook Inlet , spewing 210,000 cubic feet of gas per day. Officials said it is too dangerous to repair and letters to the Trump administration have gone unanswered for more than three months as devastation to the pristine landscape is still taking place, threatening critically endangered beluga whales , fish and other wildlife. "Oil companies continue to treat Alaska with reckless abandonment, threatening its pristine waters, wildlife and communities," said Dan Ritzman, director of Sierra Club's Alaska Program.
BP is still struggling to get control of an Alaska North Slope well that has been leaking natural gas since Friday - A damaged BP well on Alaska’s North Slope is no longer spraying crude oil, although workers still haven’t been able to stop the uncontrolled venting of natural gas from the well.The Alaska Department of Environmental Conservation said in an incident report Sunday that the crude oil spray does not appear to have spread beyond the snow-covered drilling pad around the well. But BP, whose public image is still recovering from the 2010 oil spill in the Gulf of Mexico, was still putting together a plan for plugging the well. Experts from Boots and Coots, a well control company, were arriving at the site Sunday to help devise plans to kill and plug the well.“There have been no injuries and no reports of harm to wildlife,” BP spokesman Brett Clanton said Saturday. “Safety will remain our highest priority as we work through this process.”It isn’t clear what caused the leaking well, which is an oil and natural gas production well near the airport for Deadhorse, a town devoted to serving the giant Prudhoe Bay oil fields that began producing 40 years ago. Because there is no pipeline for natural gas from Prudhoe Bay, companies pump oil and inject gas back into the wells.An earlier report by the Alaska DEC said that the pressure in the well had caused the well assembly and equipment to rise three to four feet, hampering efforts to shut off the gas leak.On Saturday night, responders from BP, the Environmental Protection Agency and the Alaska Department of Environmental Conservation were able to connect hoses to valves and bleed pressure from the space surrounding the well’s underground steel pipe.The re sponders were working in tough conditions with temperatures no higher than 14 degrees Fahrenheit; a weather advisory warned of limited visibility and winds that could gust up to 40 miles per hour on Sunday.
Alaska Senators Introduce Bill to Expand Offshore Oil Drilling in Arctic Ocean and Cook Inlet -- Senators Lisa Murkowski and Dan Sullivan, both Republicans from Alaska , have introduced legislation to expand oil and gas drilling in the Arctic Ocean and Cook Inlet, putting fragile ecosystems and endangered wildlife at risk. In December, President Obama permanently protected large areas of U.S. waters in the Arctic from oil and gas drilling. The new bill—Senate Bill 883—would effectively cancel these protections and force the Department of the Interior to quickly approve new oil and gas leasing. "It's not possible to drill safely in the Arctic, as we just saw from the leaking oil and gas well on the North Slope," said Miyoko Sakashita, ocean programs director at the Center for Biological Diversity. "This legislation's nothing more than a giveaway to oil companies. It'll hurt Alaska's healthy habitat and endangered wildlife." S. 883 would require Interior to add at least three leases each in the Beaufort and Chukchi seas and one in Cook Inlet to each five-year leasing plan. The agency would be required to establish a new near-shore Beaufort planning area with annual lease sales for the next three years. The bill would also overturn President Obama's decision to stop exploration and drilling permanently in most of the Chukchi and Beaufort seas under Section 12(a) of the Outer Continental Shelf Lands Act. These areas are home to several endangered species , including polar bears and bowhead whales . "If we let oil companies drill the Arctic, a catastrophic oil spill is just a matter of time," Sakashita said.
Study fortifies link between fracking and earthquakes in British Columbia - -- A new study examining earthquakes in northeastern British Columbia strengthens the link between hydraulic fracturing – or fracking – and increased seismic activity, a research scientist says.The study, published in this month’s Bulletin of the Seismological Society of America, analyzed 676 earthquakes that occurred between October, 2014, and December, 2015.Honn Kao, a Natural Resources Canada seismologist and one of the authors of the study, in an interview said the risks created by such earthquakes should not be ignored just because the magnitudes have been relatively small.“There is essentially no doubt in the research community that injection operations will be able to cause induced earthquakes,” he said. “The question now is whether or not the induced earthquakes can be big enough to have implications.”In fracking, fluids are injected deep underground to shatter rock and release trapped oil and natural gas. The controversial practice created an energy boom in North America but also raised concerns about groundwater contamination and increased seismic activity. In northeastern British Columbia, the number of earthquakes jumped from about 20 a year in 2002 to nearly 200 by 2011. Most have been small and might never have been detected if not for new recording devices placed in the region by government, industry and regulatory bodies.In December, 2015, the B.C. Oil and Gas Commission found a 4.6-magnitude earthquake in northeastern British Columbia earlier that year was caused by fracking. It was the largest induced seismic event ever recorded in the province. The commission has said induced seismicity is “an event resulting from human activity” that “can be caused by industries such as mining and natural gas development.” The study published this month found the earthquakes typically occurred above the area where fracking was taking place. Dr. Kao, who leads Natural Resource Canada’s induced seismicity research, said the study also examined a 4.6-magnitude earthquake that occurred in August, 2015. The study found that quake had an epicentre approximately 1.5 kilometres from a Progress Energy Canada Ltd. fracking operation. “Because most of the earthquakes induced by injection are relatively shallow, compared to tectonic natural earthquakes, given the same size, you would expect larger shaking close to the epicentre area,” he said. “So, in other words, if this kind of event occurred in a populated area, then the level of shaking … can possibly exceed the damage threshold of structures.”
Alberta research shows fracking fluids have ‘detrimental’ effects on fish - The Globe and Mail: Research has found that liquids released from fracked oil and gas wells can harm fish even at low concentrations. “When we put these frack fluids in, the fluids themselves generate chemicals that have detrimental biological effects,” said University of Alberta biologist Greg Goss. It’s long been known that chemicals used in fracking – which uses fluids under high pressure to fracture rock formations and release oil and gas – are environmentally toxic. Prof. Goss and his colleagues conducted a study intended to consider how toxic they are by using water that flowed from an actual fracked well. “The real risk comes from the disposal process, where [companies] have to truck it to a new site or pipeline it to a new site,” Prof. Goss said Tuesday. “If we do have a spill, what are the concerns they have to worry about?” His paper notes that Alberta has experienced more than 2,500 such spills between 2011 and 2014. The researchers exposed rainbow trout to “sub-lethal” levels of such fluids. The levels were intended to simulate exposure fish or other organisms would be subject to from a pipeline leak or a spill near a water body. Even at dilutions as low as 2.5 per cent – 2.5 litres of process water to 100 litres of fresh water – fish showed significant impact on their livers and gills. Prof. Goss calls the effect “oxidative stress.” That means chemicals in the water force liver and gill cells to age and die more quickly. “Oxidative stress is associated with damage to membranes,” he said. Some chemicals in the water, which have been shown to cause hormone disruptions in other studies, were absorbed by the fish.
Exodus From Canada's Oil Sands Continues as Energy Giants Shed Assets -- When ConocoPhillips signed a $13.3 billion deal last month to shed many of its Canadian assets, it became the latest in a growing list of foreign firms to sell tar sands holdings to a Canadian company. A series of recent deals have signaled that multinational energy giants are diverting their money to cheaper and less-polluting resources. But while the message about their investment priorities is clear, the implications for future tar sands production—and climate change—are less so. All told, five American and European companies have sold nearly $25 billion worth of Canadian oil and gas projects over the past 12 months, the vast majority of them in the tar sands. This week, Reuters reported that Chevron is exploring a sale of its major oil sands stake. Tar sands projects are among the most expensive sources of oil, and the extraction produces more greenhouse gas emissions than most conventional drilling. With oil prices remaining low, multinationals are shifting investment to higher-return projects like shale in the United States. When Marathon Oil announced the sale of its tar sands projects for $2.5 billion in March, for example, it also highlighted a $1.1 billion purchase in the Permian Basin of New Mexico and Texas. While economics is the leading factor in the sales, some advocates argue that climate change is playing a role, too. Energy companies—European ones in particular—are facing increasing pressure to lower their carbon footprints, and are doing so by shifting away from heavier fuels like the tar sands and toward more natural gas and renewables. Just as Shell announced the sale of nearly all of its tar sands operations last month, for example, it also disclosed details of a new policy to tie executive bonuses to emissions reductions. Days after itsold its oil sands assets in December, Norway's Statoil announced a $42.5 million winning bid to lease acreage for a wind farm off the coast of New York. With the completion of the five recent sales, about two-thirds of oil sands production will be concentrated in the hands of Canadian companies, That means investment likely will shrink…
Oil demand growth seen slowing for a second year --The International Energy Agency expects growth in the global demand for crude oil to slow for a second consecutive year in 2017.The Paris-based agency expects growth of 1.3 million barrels a day this year, compared with 1.4 million barrels previously forecast, due to stalled demand in the U.S., Middle East, Russia and India.In its monthly report released Thursday, the IEA, a body that advises major oil-consuming nations, says production will grow this year, even when considering pledges by OPEC countries to limit output. The combination of factors could keep a lid on oil prices, which have risen in the past six months after a three-year slump.
Chevron warns of medium-term LNG supply gap - Countering the prevalent LNG market theme of a supply glut, Chevron’s vice chairman Michael Wirth has warned of a supply gap, which is likely to open up in the LNG industry if investor appetite for new projects does not pick up. “In the short term, LNG supply is coming online faster than demand is growing, but with continued demand growth in the next decade the market will rebalance,” Wirth said, speaking at an April 4 gas industry conference in Japan. “So while we expect ample supply in the next few years ... a supply gap could eventually confront us in the years to follow if we don’t eventually sanction new LNG projects,” he said, in comments cited by Reuters. Although Wirth’s message covered the global gas market, it comes at a time when other Chevron executives have pointed to the natural gas supply shortages already faced by Australia’s East Coast following the start-up of Queensland’s LNG export terminals, as well as a low oil price environment and ongoing regulatory uncertainty. Australia is about to become the world’s top exporter of LNG, but faces a gas shortage at home, as producers have focused on supplying gas to overseas plants that have locked in long-term export contracts. However, Chevron has experienced the sharp end of several cost blowouts in Australia’s LNG industry, epitomised by the Chevron-led Gorgon plant at Barrow Island off Western Australia, where the final costs have soared from US$37 billion to US$54 billion. Chevron is also operator at the Wheatstone LNG project, where an 8% cost overrun revealed last October has lifted the overall cost to US$34 billion for the shareholders. The size of the cost overruns announced by several major LNG projects, plus a precipitous drop in LNG prices in Asia in the last three years, have been key drivers in a tailing-off of final investment decisions (FIDs) for large LNG export schemes.
PNG LNG production surges 20% above nameplate capacity in Jan-Mar: Oil Search - Papua New Guinea's LNG project continued to operate well above nameplate capacity during January-March 2017 and has ample feed gas to sustain the strong production levels, while discussions to increase capacity will take place later in the year, project partner Oil Search said Wednesday. PNG LNG operated at an annualized rate of 8.3 million mt/year during the quarter, which is some 20% above the nameplate capacity of 6.9 million mt/year, said Australian-listed Oil Search, which is a 29% equity holder in PNG LNG. "The recent independent recertification of the resources within the PNG LNG project fields has confirmed that there is more than sufficient gas available to support this higher level production and will enable the project to optimally place additional volumes in either term contracts (for uncommitted production above 6.6 million mt/year) and/or the spot market, subject to achieving suitable terms and conditions," Oil Search said. It will be for volumes above 6.6 million mt/year, rather than the current nameplate capacity of 6.9 million mt/year, because that was what the project's capacity was thought to have been when it was first sanctioned in 2009, a spokeswoman for Oil Search said.
NYMEX May gas falls 2.6 cents to settle at $3.159/MMBtu - Natural Gas | Platts News Article & Story: The NYMEX May natural gas futures contract fell 2.6 cents to settle at $3.159/MMBtu Thursday, following Wednesday's 4-cent climb, as the weekly storage report showed a higher injection than expected. The May contract fell after rising a few cents earlier in the day, and traded between $3.134/MMBtu and $3.219/MMBtu. The official weekly gas storage report from the US Energy Information Administration showed a total injection of 54 Bcf in the week that ended Friday, compared with the 47-51 Bcf build estimated by a consensus of analysts surveyed by S&P Global Platts. The most recent reporting week's injection is 48 Bcf above a 6-Bcf build at the same period a year ago, and 19 Bcf above the 35-Bcf five-year average injection.The higher-than-expected build weakened the supply/demand balance, putting storage levels at 2.115 Tcf, some 14.8% below the 2.483 Tcf total at the same time a year ago, but 15.4% above the five-year average of 1.833 Tcf. "While prices have weakened on the news, we note that May natural gas continues to trade above Tuesday's $3.114[/MMBtu] low, a recently confirmed technical support. A break of this level would make a stronger bearish statement," Tim Evans, energy futures specialist at Citi Futures, said in an email. Platts Analytics' Bentek Energy unit projects total US demand will average 68.3 Bcf/d through April 28, before declining to an average of 66.1 Bcf/d through May 5 on weaker residential and commercial consumption. The latest monthly forecast for May from the National Weather Service, posted Thursday, predicted normal temperatures in the northwestern portion of the US, including the western half of the Upper Midwest.
Exxon asks Trump administration for waiver from Russia sanctions | TheHill -- Oil giant Exxon Mobil Corp. is seeking a waiver from the Trump administration to work with Russia’s state oil company on a joint venture, The Wall Street Journal reports. Citing people familiar with the matter, the Journal reports that Exxon asked the Treasury Department in recent months to drill for oil alongside Rosneft. The drilling would take place in the Black Sea, an area covered by sanctions instituted by the United States to prevent certain business dealings in retaliation for Russia’s annexation of Crimea from Ukraine. Secretary of State Rex Tillerson was Exxon’s CEO in 2012 when he struck the joint venture deal, worth hundreds of billions of dollars, with Russian President Vladimir Putin. The State Department is one of the agencies that helps Treasury decide on sanctions waivers. Tillerson promised to recuse himself from matters related to Exxon for his first two years at the State Department. Tillerson was awarded Russia’s Order of Friendship in 2013 due to the deal and his relationship with Putin. That caused numerous senators to question during his confirmation process whether he was too close to Russia and Putin. It is unclear if Exxon applied for the waiver before or after Tillerson was confirmed as Trump’s top diplomat, the Journal said. Treasury does not speak publicly about such waivers or their considerations, and Exxon did not return a request for comment.
The Treasury Department Won’t Give Exxon Mobil a Waiver to Drill in Russia - The Treasury Department said it will not give Exxon Mobil a waiver to drill for oil in Russia despite U.S. sanctions against the country. Treasury Secretary Steven Mnuchin said Friday in a statement that the administration, "will not be issuing waivers to U.S. companies, including Exxon, authorizing drilling prohibited by current Russian sanctions," according to the Associated Press. Exxon was seeking a waiver in order to continue drilling in the Black Sea, the AP reports. The company previously had an agreement with Russian oil company PAO Rosneft. Exxon would not confirm whether or not it was seeking the waiver at all earlier this month, Reuters reports. Exxon's former chief executive Secretary of State Rex Tillerson lobbied against the sanctions in 2014. Sen. John McCain (R-Ariz.) called the request for a waiver "crazy" last week in a tweet linking to a report by the Wall Street Journal. The move comes as the FBI and Congressional intelligence committees are investigating Russian hacking that allegedly attempted to influence the 2016 presidential election, as well as possible contact between Russian officials and members of President Donald Trump's campaign.
Russian oil groups brave cold of western sanctions to explore Arctic - His fur coat heavy with snow and protecting him from temperatures of minus 18C, Igor Sechin, the chief executive of Russian oil company Rosneft, clutched the radio in his thick gloves and relayed to his engineers the simple order he had just been given by Russian President Vladimir Putin: “Start drilling.” A rig operator confirmed his request. Moments later, a drill began its 5,000m journey downwards, in search of oil deposits that the country is banking on to provide more than a quarter of its future output. Perched on the edge of a peninsula deep in the Arctic Circle, Tsentralno- Olginskaya-1 will be Russia’s northernmost oil well. Closer to the North Pole than to any city, it is a feat of engineering that uses equipment shipped 3,600km through icy waters navigable only for two months of the year. The well is one of the most technologically challenging ever attempted in Russia. With the deposits located beneath the icy, frequently frozen waters of the Laptev Sea, cutting-edge horizontal drilling techniques will be used to reach up to 15,000m from the main site. But it was also a moment of triumph for Mr Putin, who was beamed in via video conference from St Petersburg as Mr Sechin braved the frigid elements and who celebrated the start of drilling as an act of homegrown ingenuity. Three years ago, when the US and EU imposed sanctions on the country that restricted companies such as Rosneft from foreign capital and technology, complex wells were exactly the kind of ambitious projects that were supposed to be rendered impossible. Western governments hoped that pressure on Russia’s main energy companies would help change Mr Putin’s political calculations. But as projects like Tsentralno-Olginskaya-1 attest, Russia’s oil and gas majors have found ways to carry on regardless. “Horizontal drilling is a complex and high-tech operation. This is just the first well. There is much more work ahead,” Mr Putin told Mr Sechin in the heavily scripted conversation.
North Sea to see 30 new oil and gas projects by 2020 -- Around 30 new crude oil and natural gas projects are expected to start operating in the North Sea by 2020. That’s according to research and consultancy firm GlobalData, which says the UK will lead the resurgence with 19 projects, followed by Norway with 10 and Denmark with a single installation. A new report from the company suggests the downturn cycle witnessed in the region over the last few years is now easing slightly. It states projects agreed upon in 2016 cost around half as much as projects finalised in 2013 and says this illustrates how companies have made clear improvements in cost efficiency. GlobalData also notes operating costs have halved from nearly $30 per barrel (£24) to just more than $15 per barrel (£12) and production forecasts are on the rise. The projects are expected to contribute around 690,000 barrels of oil per day to global crude production and about 1,255 million cubic feet per day to global gas production.
2017 may give VLCC tankers a wild ride on oil market volatility - video - As the crude oil industry deals with wild cards like the OPEC deal, the narrowing spread between oil benchmarks and shifts in market share between major oil producing countries, VLCC tankers are feeling the waves too. Will the oil market volatility be the hero or the villain for VLCCs in 2017? In this video, Alex Younevitch, Peter Farrell and Gillian Carr explore the dynamics in VLCC freight and ton-mile demand, giving an outlook for the rest of 2017.
Banned at sea: Venezuela's crude-stained oil tankers | Reuters - In the scorching heat of the Caribbean Sea, workers in scuba suits scrub crude oil by hand from the hull of the Caspian Galaxy, a tanker so filthy it can't set sail in international waters. The vessel is among many that are constantly contaminated at two major export terminals where they load crude from Venezuela's state-run oil company, PDVSA. The water here has an oily sheen from leaks in the rusty pipelines under the surface. That means the tankers have to be cleaned before traveling to many foreign ports, which won't admit crude-stained ships for fear of environmental damage to their harbors, port facilities or other vessels. The laborious hand-cleaning operation is one of many causes of chronic delays for dozens of tankers that deliver Venezuela's principle export to customers worldwide, according to three executives of the state-run firm, Neither PDVSA nor Venezuela's Oil Ministry responded to requests for comment about the firm's maritime operations. The tankers sidelined for cleaning provide a vivid example of the firm's downward spiral: Lacking the cash to properly maintain ships, refineries and production operations - or to pay business partners on time - PDVSA can't boost exports, which is its only option for raising more cash. Venezuela's crude exports declined 8 percent to 1.69 million barrels per day (bpd) in the first quarter versus the same period in 2016, according to Thomson Reuters data. When oil prices were high, crude and fuel exports almost entirely financed an elaborate system of government price controls and social subsidies that maintained the popularity of late President Hugo Chavez, the socialist firebrand. Although embattled Venezuelan President Nicolas Maduro insists the government has maintained social programs, he has publicly acknowledged that lower oil prices have left the government with less money to finance them.
Latin America’s Oil-Dependent States Struggle to Repay Chinese Debts --As Chinese loans pour into Latin America, concerns over how the money is spent and how it will be repaid are growing on both sides of the bargaining table. Of most immediate concern for China is whether economically unstable governments such as Venezuela can pay back multi-billion dollar loans amid globally low prices for crude oil.By the close of 2015, China held $53 billion of Venezuelan debt. However, U.S. think tank Inter-American Dialoguesuggests that figure could be as much as $65 billion. Despite Venezuela’s deepening recession, China has continued to lend, offering $2.2 billion in November 2016 alone. “Many thanks for all the support you have given Venezuela in 2014, 2015, and especially 2016. Our older sister China has not left Venezuela alone in moments of difficulty,” said Venezuelan President Nicolás Maduro in a televised speech.But the changing global economic environment means that China cannot continue lending to Latin American countries worry-free. Analysis by Inter-American Dialogue shows that in 2016, 92 percent of China’s loans to Latin America went to Ecuador, Venezuela, and Brazil, nations that are all facing serious economic challenges according to the World Bank.The Brazilian economy has been shrinking since 2011, while the economy in Venezuela also continues to deteriorate. In 2015, 15 years of sustained economic growth came to an end in Ecuador.Experts say the main challenge facing economic cooperation between China and Latin America is whether Chinese investment could better promote sustainable development that is less risky and more environmentally responsible.
Exxon plans to boost shale gas output in Argentina: governor - ExxonMobil plans to ramp up natural gas production from the Vaca Muerta shale play in Neuquen, Argentina, the governor of that province said. Neuquen Governor Omar Gutierrez said he met with senior executives of Exxon and its XTO unit in Houston, Texas, last week during a road show to promote a series of tenders for 56 blocks in the southwestern province, according to a statement Monday. The Irving, Texas-based company "is evaluating the potential of gas development in the Los Toldos 1 Sur block," and is poised to request a 35-year production license for the block, Gutierrez said. Exxon's focus is to be on developing gas from Vaca Muerta, among the world's most promising shale plays, where the company will have invested $750 million by the end of this year, the governor added.
Oil Companies Exploiting Famine And Financial Ruin In South Sudan - South Sudan’s vulnerable financial state is making the civil-war-torn state easy prey for opportunistic oil and gas companies that could be offering Juba a fraction of the energy profits they would earn under stable circumstances.The South Sudanese government and three humanitarian agencies declared a famine in some parts of the country in February, while the newly independent nation is desperately trying to bring its oil back online. A string of deals signed by President Salva Kiir over the past four months has demonstrated the country’s desperation for fresh streams of revenue as the civil war now approaches its four-year anniversary.“The government is working hard to reinvigorate the petroleum industry in South Sudan by creating an enabling environment for international oil and gas companies to invest and operate,” according to Petroleum Minister Ezekiel Lul Gatkuoth. “It is up to the oil companies to come in, explore and produce. Partnership is what fuels the oil industry.” The East African reported this week that oil companies with regional headquarters in Kampala, Nairobi, Addis Ababa, as well as several European cities are setting up meetings with top South Sudanese officials, and Kiir’s administration is happy to oblige the invitations. Toward the end of last year, Suiss Finance Luxembourg AG announced a $10.5 billion deal that could rise to $105 billion in value when joint ventures in infrastructure and transportation are taken into account. While some may view this as a large stepping stone toward bringing back its oil revenues, Kiir’s critics were quick to attack the leader over the deal once news broke, referring to what they called “shadowy” businessmen from Kampala who had brokered the contract. Another recent deal involves Oranto Petroleum, which has committed to a $500 million “comprehensive exploration campaign, starting immediately” to evaluate oil prospects in the 25,150 kilometers that make up Block B3. Juba approved the block a couple of weeks ago, giving Oranto a 90 percent share, while keeping only 10 percent for the government’s Nile Petroleum (Nilepet). The East African said the deal with Oranto has drawn harsh criticism due to a report from technical officials in the Ministry of Petroleum in which claims were made that the company lacked the technical expertise and financial capacity to manage the Block B3 project.
Vietnam's Bach Ho crude likely to flood Asian secondary market: traders - Low sulfur crude suppliers across Southeast Asia and Oceania may have to put in extra effort to clear their June-loading barrels this month as close to 2.5 million barrels of Vietnamese light Bach Ho crude are expected to flood the Asian secondary market, regional traders said Tuesday. Award details of recent spot tenders from Vietnam raised concerns among rival producers in neighboring Malaysia as PetroVietnam Oil Corp. recently sold 82,500 b/d of light Bach Ho for loading in June to Socar Trading Singapore, Gunvor, Vitol and Glencore. Traders said the entire lot being bought by trading companies made other regional producers worried as there was a high chance that most of the medium sweet Vietnamese crude will slip back into the secondary market. "You could say this was possibly the worst-case scenario for [rival] producers [across Asia and Oceania]. The best outcome [for rival suppliers] would have been for a big Chinese end-user to have taken the entire [June barrels offered by PV Oil] ... but it wasn't to be," said a Singapore-based sweet crudes trader.Light Bach Ho, with a gravity of 39-40 API, was rarely offered in the spot market in recent years. However, it was offered via spot tender late last month ahead of the upcoming turnaround at the country's 130,000 b/d Dung Quat refinery, market sources said.
China’s Crude Oil Imports Hit a New Record - China’s General Administration of Customs reported that China’s crude oil imports rose to 9.21 MMbpd (million barrels per day) in March 2017. China’s crude oil imports rose 10.7% month-over-month and 19.4% YoY (year-over-year). Imports rose due to the rise in demand from its teapot refineries. Imports are at the highest level ever. The previous high was in December 2016 when imports were at 8.6 MMbpd. The rise in crude oil imports from China supports crude oil prices. China is the second-largest crude oil consumer after the US. China’s crude oil imports and demand:
- China’s crude imports will rise 5.3% to 8 MMbpd in 2017, according to China National Petroleum. It also added that China’s crude oil consumption will rise 3.4% to 12 MMbpd in 2017.
- China’s crude oil production fell 4.6% YoY to 3.9 MMbpd in March 2017. Slowing Chinese crude oil production due to aging could also increase China’s crude oil imports.
- The EIA estimates that China plans to build 500 million barrels of strategic crude oil reserve space by 2020. It could also add to imports.
- Demand from teapot refineries could support oil imports in 2017.
- China’s fuel exports hit a record high at 1.06 MMbpd in 1Q17—22% higher than the same period in 2016. The rise in Chinese fuel exports will put pressure on refined product margins. To learn more, read How Lower Refinery Margins Impact Crude Oil Prices.
Where Does The World's Biggest Oil Importer Get Its Crude --China is the world’s largest net importer of crude oil, and in recent years, China’s crude oil imports have increasingly come from countries outside the Organization of the Petroleum Exporting Countries (OPEC). As the EIA reports in a recent blog post, while OPEC countries still made up most (57%) of China’s 7.6 million barrels per day (b/d) of crude oil imports in 2016,crude oil from non-OPEC countries made up 65% of the growth in China’s imports between 2012 and 2016. Leading non-OPEC suppliers included Russia (14% of total imports), Oman (9%), and Brazil (5%). On an average annual basis, China’s crude oil imports increased by 2.2 million b/d between 2012 and 2016, and the non-OPEC countries’ share increased from 34% to 43% over the period. Market shares for China’s top three non-OPEC suppliers (Russia, Oman, and Brazil), all increased over these years. While still comparatively small as a share of China’s crude oil imports, imports from Brazil reached a record high of 0.6 million b/d in December 2016, and imports from the United Kingdom reached a high of 0.2 million b/d in February 2017.Growth in China’s total crude oil imports in 2016 reflected both lower domestic crude oil production and continued demand growth. After increasing steadily between 2012 and 2015, China’s crude oil production declined significantly in 2016. Total liquids supply in China averaged 4.9 million b/d in 2016, a year-over-year decline of 0.3 million b/d, the largest drop for any non-OPEC country in 2016. U.S. crude oil production fell by more than 0.5 million b/d in 2016, but total liquids declined by less than 0.3 million b/d because other liquids production increased by less than 0.3 million b/d. Much of Chinese production growth from 2012 through 2015 was driven by more expensive drilling and production techniques, such as enhanced oil recovery (EOR) in older fields. As oil prices declined during 2016, investments in developing new reserves also fell and were not high enough to offset the natural production declines of older fields.
Analysis: China seen moving swiftly to rein in oil blending frenzy - China is inching closer to imposing a consumption tax on mixed aromatics, light cycle oil and bitumen blend, a move that will likely curb inflows of those products and stem surging oil product exports by Asia's biggest oil consumer. The planned policy change will also likely increase China's imports of lighter crudes for gasoline production to offset the squeeze in the blending pool if consumption taxes are imposed, market participants told S&P global Platts. Beijing is widely expected to levy consumption taxes on mixed aromatics and light cycle oil. Although there has been no official confirmation, market participants expect details to be released some time between May 1 and July 1. Sources with knowledge of the matter said the consumption taxes for mixed aromatics, LCO and bitumen blend would use the current consumption taxes on gasoline, gasoil and fuel oil as a reference; these currently stand at Yuan 1.52/liter, Yuan 1.20/liter and Yuan 1.20/liter respectively. "This means importers will have to pay Yuan 1,000-2,000/mt more for importing those products, which is expected to largely curb inflows of these grades, just like what happened to fuel oil a few years ago," a market source said. China's fuel oil imports have fallen dramatically since Beijing imposed the consumption tax in 2008.
Saudi Aramco chief warns of looming oil shortage -- The head of Saudi Arabia’s state energy giant has warned of a looming oil shortage as a $1tn drop in investments into future production takes effect. Amin Nasser, chief executive of Saudi Aramco, the world’s largest oil producing company, said on Friday that 20m barrels a day in future production capacity was required to meet demand growth and offset natural field declines in the coming years. “That is a lot of production capacity, and the investments we now see coming back — which are mostly smaller and shorter term — are not going to be enough to get us there,” he said at the Columbia University Energy Summit in New York. Mr Nasser said that the oil market was getting closer to rebalancing supply and demand, but the short-term market still points to a surplus as US drilling rig levels rise and growth in shale output returns. Even so, he said it was not enough to meet supplies required in the coming years, which were “falling behind substantially”. About $1tn in oil and gas investments had been deferred and cancelled since the oil downturn began in 2014. Riyadh believes its national oil group is worth the money but investors have doubts as IPO nears The remarks come as the kingdom embarks on an ambitious task to sell a 5 per cent stake in Saudi Aramco, its main revenue generator. While the move is the centrepiece of reform plans to overhaul Saudi Arabia’s economy and end reliance on the volatile oil sector, hydrocarbons will remain the backbone of the country’s wealth. Conventional oil discoveries had more than halved over the past four years, Mr Nasser said, compared with the previous four-year period. He added that it should not be assumed that major oil and gas companies would invest in sizeable projects.
Iran Boosts Gas-Output Capacity With New Projects at Giant Field | Rigzone-- Iran, holder of the world’s biggest natural gas reserves, boosted output by inaugurating six projects at the giant South Pars offshore field. The country raised total production capacity at South Pars to 570 million cubic meters a day of gas, putting it almost on par with neighboring Qatar, which produces from an adjacent portion of the same deposit, Oil Minister Bijan Namdar Zanganeh said Sunday at a ceremony in the port city of Assaluyeh. Iran invested $20 billion to complete the six projects, or phases, President Hassan Rouhani said at the event. Iran is on track to out-produce Qatar, the world’s biggest exporter of liquefied natural gas, at the Persian Gulf deposit. Iranian officials want to gain market share for gas shipments and attract foreign investment, even as U.S. President Donald Trump ratchets up confrontational rhetoric against Iran. Even so, Iranians won’t have much gas to export because they are likely to use most of the new production themselves. Half of Iran’s gas goes to warming homes, with the rest used mostly to generate power and for industrial use. New production can barely keep up with domestic demand, and consumption almost doubled to 191.2 billion cubic meters in 2015 from 102.7 billion in 2005, according to BP Plc statistics. Each of the new projects produces 28 million cubic meters a day, Zanganeh told reporters late Saturday. They include phases 17 through 21, with phase 19 having two parts. Qatar announced earlier this month that it was ending a 12-year ban on new projects at its section of the shared field. Qataris call their part of the deposit the North Field, which together with South Pars forms the world’s largest reservoir of non-associated gas. Iran has no plans to interfere with Qatar over its activities at North Field, Zanganeh said. “They can carry out their development projects as we do ours,” he said. “We do our job and let them do theirs.”
Iran would support unanimous OPEC decision to extend output cuts: minister - Iran's petroleum minister believes most OPEC members would endorse an extension of the group's current initiative on production cuts, and Iran would support an extension if unanimously supported by other members, oil ministry news agency Shana quoted the minister as saying Sunday. "OPEC and non-OPEC crude oil producers have displayed a historic esprit de corps in implementation of the organization's output cut plan, which has proved a success, and producers have shown more cooperation month after month," Shana quoted Bijan Zanganeh as saying. Noting that international benchmark crude prices returned last week to around $55/b following a slump, Zanganeh said the recent market reaction showed investors were recognizing that OPEC was living up to its November 2016 decision to cut output by a total of 1.2 million b/d in H1 2017, and that the ensuing decision by other major international producers to join OPEC by contributing additional cuts had been taken in earnest. Iran had honored the initiative and, providing all other OPEC members followed suit, would stick to the plan to cut output, Zanganeh said ahead of the inauguration of several major gas and petrochemicals projects in Iran's southern Assalouyeh region. In the December 2016 agreement, 24 international producers -- including OPEC's 13 members, Russia and Oman -- pledged to deliver nearly 1.8 million b/d of total H1 cuts.Due to the toll that years of international nuclear sanctions had already taken on its oil output, Iran was exempted from making further cuts and was instead permitted under the agreement to raise production by up to 90,000 b/d to match the country's pre-sanctions output of around 4 million b/d, Shana reported.
OPEC’s production cuts aren’t cuts at all -- The OPEC Monthly Oil Market Report is out with OPEC’s crude oil production numbers for March 2017. All data is through March 2017 and is in thousand barrels per day. Looking at the above chart it seems obvious what most OPEC nations were doing. They announced in the summer of 2016 that there would likely be quota cuts beginning in 2017. And those cuts would be a percentage of their current production. So everyone began making heroic attempts to increase production by the end of 2016. Now, after everyone who felt that they should cut, has cut, they are right back to the level that they were at before the cuts were proposed. There is always a considerable difference between what the OPEC nations say they are producing and what the “Secondary Sources” say they are producing. The March MOMR had Saudi producing 9,797,000 bpd in February while Saudi said they were producing 10,011,000 bpd. The April MOMR has revised Saudi’s February production up by 155,000 bpd. This is a snip from one of my Excel spreadsheets. It shows revisions made in the previous two months’ data by “Secondary Sources”. For instance, Saudi Arabia’s January production numbers were revised down by 56,000 bpd while their February production numbers were revised up by 155,000 bp. OPEC 13 Jan. numbers were revised down by 73,000 bpd while their Feb. numbers were revised up by 124,000 bpd. Not much is happening in Algeria. They peaked almost 10 years ago and have been in slow decline ever since. Angola peaked in 2010 but have been holding pretty steady since. Ecuador peaked in 2015. They will be in a slow decline from now on. Any change in Gabon crude oil production is too small to make much difference. Iran has increased production the last three months, though down slightly in March. However, one source says it is a fallacy. We believe Iranian destocking is being misinterpreted as production, and actual production will decline as the year moves forward. Iraq is down 73,000 bpd from their December peak. Kuwait is down 166,000 bpd from their November peak. That is about 5.8%. Libya still has problems, and will likely continue to have problems. Related: Is The Oil Price Rally Running Out Of Steam? Nigeria and Libya are exempt from quota cuts because of rebel problems. Don’t look for those problems to clear up any way soon. Qatar has been in decline since 2008. Her decline will continue albeit at a very slow pace. Saudi Arabia cut in January, then stopped cutting. I think this is where we will be for some time unless there is a real shake up in OPEC.Venezuela’s problems will continue. They ae now below two million barrels per day. They are at 1,972,000 bpd. Last March their production was 2,286,000 bpd. They have dropped 314,000 bpd in 12 months. That’s 13.7 percent in one year. Eyeballing the chart, it looks like World oil production, total liquids, is down about two million barrels per day since peaking in November 2016. OPEC crude production is down 1.45 million barrels per day since November so Non-OPEC liquids, plus OPEC NGLs, would be down just over half a million bpd since then.
OPEC hopes more non-OPEC producers will help manage market: Barkindo - OPEC is hoping to attract other oil producers from outside the bloc to join in its efforts to manage the oil market, Secretary General Mohammed Barkindo said Wednesday. OPEC in December signed a deal with 11 key non-OPEC producers led by Russia to cut a combined 1.8 million b/d to hasten the market's rebalancing, but Barkindo told S&P Global Platts on the sidelines of the GCC Petroleum Media Forum in Abu Dhabi there is still time for other non-OPEC nations to sign on. "We are calling on all non-OPEC producers who are not yet part of the broad platform of the 24 countries that signed the declaration of cooperation," he said. "It is in their interest to join this platform. It's a broad global platform that is in the best interest of the industry as well as the global economy. So if I am a producer who has not signed the declaration of cooperation I would rush to do it now. This is the time to join."No other countries have committed so far, Barkindo acknowledged, but he said he was "using this opportunity to invite them." UAE energy minister Suhail al-Mazrouei said he agreed with Barkindo's call for increased non-OPEC participation in market management efforts. Specifically, with the deal signed in December, he said many of the non-OPEC countries were "hesitant" to cut production and only participated through natural field declines. Should the deal be extended, as OPEC will consider at its May 25 ministerial meeting in Vienna, Mazrouei said he hopes those non-OPEC countries step up their commitments.
Who Holds The Power In Today’s Oil Market? -- Amidst the din of analysts speculating about whether oil prices will rise or fall, observers may well be overlooking some pressing questions about the very nature of the global oil market. The most significant of these questions relates to whether Saudi Arabia is losing its grip on the global oil market and if U.S. oil and gas producers are replacing the Saudis as the key global swing producer. By the mid-70s, the Kingdom of Saudi Arabia wielded the power to swing oil prices at its will by turning on and off the taps. Presently, after 44 years, the scenario is quite different. In fact, the recent Vienna accord where OPEC and NOPEC producers agreed to cut 1.8mbpd of oil, and now its possible extension, is symptomatic of the internal weakness. In 2014 when Saudi Arabia refused to cut production to stabilize prices, and instead increased production to protect market share, an oil price war began. But the strategy to drain out the high cost producers has gone awry. U.S. production continues to rise, while Saudi Arabia’s economy is suffering from lost oil revenue. U.S. Shale producers appear to be recovering market share and have managed to lower breakeven prices through a technological revolution.Welcome to the era of “Fracking 2.0”, where a “company man” 100 miles away from an oil rig can give instructions to his workers via an app called “ISteer.” EOG Resources, one of the largest independent oil and gas companies in U.S. and ranked as Texas’ fifth largest gas producer, is doing wonders as it outperforms its competitors. EOG can now drill horizontal wells in just 20 days, which is down from 38 in 2014. The company has pumped consistent quantities of oil irrespective of the drop in prices. And that is just one example.
Oil end at a 1-week low as traders eye U.S. crude output - Oil prices fell Monday to mark their lowest finish in about a week, pressured by data showing gains in the number of active U.S. oil rigs over the past 13 weeks and expectations for a rise in monthly domestic shale production. May West Texas Intermediate crude fell 53 cents, or 1%, to settle at $52.65 a barrel on the New York Mercantile Exchange. Prices, which posted a gain of roughly 1.8% last week, settled at their worst level since April 7, FactSet data show. In London, June Brent crude on the ICE exchange also fell 53 cents, or 1%, to $55.36 a barrel. On Monday, shortly before the Nymex settlement, a monthly report from the Energy Information Administration forecast a rise of 124,000 barrels a day in May to 5.193 million barrels a day for crude-oil production in seven major U.S. shale-oil plays. New well oil output per rig in the Permian Basin was forecast at 662 barrels a day in May on a rig-weighted average, unchanged from April, according to the EIA. But, according to Curt Taylor, president of Opportune LLP’s Ralph E. Davis Associates, the average productivity of a rig in the Permian before April 2009 was less than 100 barrels a day. “This, along with the increasing rig count and another increase in the [drilled but uncompleted] well count (up another 111 wells), means that U.S. production supply will continue to move up,” he said. Baker Hughes data Thursday showed that the U.S. oil rig count rose for the 13th straight week in the week of April 13. At a total of 683, the current tally is the highest in two years.
Oil prices fall on expected surge in U.S. shale output: (Reuters) - Oil prices fell on Tuesday on news that U.S. shale oil output was expected to post the biggest monthly rise in more than two years, fuelling concerns that U.S. production growth is undermining OPEC-led efforts to rein in oversupply. The latest U.S. government drilling data showed shale production in May was set to rise to 5.19 million barrels per day (bpd), with output from the Permian play, the largest U.S. shale region, expected to reach a record 2.36 million bpd. Global benchmark Brent crude futures were down 26 cents at $55.10 a barrel at 0803 GMT. They touched an intraday low of $54.98, the weakest level in 11 days. U.S. West Texas Intermediate (WTI) crude futures traded down 21 cents at $52.44 a barrel, the lowest since April 10. "EIA (U.S. Energy Information Administration) estimates for a combined 124,000 barrels-per-day growth in U.S. shale production over May have added another bearish element to the market," wrote analysts at JBC Energy, based in Vienna. More barrels could be on their way to market from U.S. shale fields as financial companies are investing billions in production, a Reuters analysis showed. Members of the Organization of the Petroleum Exporting Countries are cutting oil production by 1.2 million bpd from Jan. 1 for six months, the first reduction in eight years. The energy minister of OPEC member the United Arab Emirates said on Tuesday he saw healthy oil demand growth this year and believed inventories would fall. A preliminary Reuters poll showed analysts expected U.S. crude stocks to have fallen in the week to April 14, building on a surprise decline the previous week.
U.S. Shale Surging, But Oil Holds Steady - Oil prices dropped to their lowest levels in nearly two weeks, down slightly on expectations of rising U.S. oil production. The EIA reported in its Drilling Productivity Report that it expects an increase of 124,000 bpd in May, with output gains in the Permian (+76,000 bpd) and the Eagle Ford (+39,000 bpd). Big banks and private equity are stepping up their investment in the U.S. shale patch, so analysts foresee further production gains ahead. . Top OPEC members Saudi Arabia, Iraq and Kuwait are reportedly targeting $60 per barrel, according to the WSJ. At that price level, government finances would stabilize a bit while it would still be low enough to prevent a dramatic resurgence of U.S. shale. “Iraq wants prices to rise to $60. This our aim,” said Iraq’s oil minister Jabbar al-Luaibi in an interview. A move up to $60 per barrel would also bolster the valuation of Saudi Aramco ahead of its IPO. However, the danger is that OPEC is underestimating the ability of shale to ramp up. Indeed U.S. shale output is already rebounding. Nevertheless, the desire from OPEC to reach $60 per barrel bodes well for an extension of the collective production cuts.. Investment banks are growing more bullish on commodities, including crude oil. Citi says it sees oil moving up into the mid-$60s later this year. Even as U.S. shale comes “roaring back,” Citi analysts see OPEC efforts as more than sufficient to tighten the oil market. “With a continuation of the OPEC and non-OPEC producer deal in the second half of 2017 and the expected associated inventory draw-down, we expect oil prices to move above $60 a barrel by the second half of the year,” Citi analysts wrote in a research note. China reported a 6.9 percent annual growth rate in the first quarter, much better than expected. It is also setting new oil import records by the month, dispelling fears that its economy and crude oil demand was slowing down. Imports hit a record high 9.21 million barrels per day in March, an increase of 11 percent from February. That spike is likely temporary, but China no longer appears to be the downside risk to oil prices that many analysts had feared earlier this year.
Drilled and Uncompleted - The Roadblock to Higher Oil Prices -- Beginning in September 2016, the United States Energy Information Administration (EIA) began to include estimates of the number of drilled and uncompleted wells (DUCs) in its monthly Drilling Productivity Report. This data is critical to gaining an understanding of where U.S. oil production may be headed, information that provides us with a measure of whether there will be upward or downward pressure on future oil production, a key factor in future oil prices. Drilled and uncompleted wells are those wells that have been drilled but are standing suspended (i.e. they are not producing hydrocarbons). These wells have production casing in place but potentially productive formations have not been perforated or hydraulically fractured (i.e. completed). Obviously, a high and growing inventory of drilled and uncompleted wells has the potential to impact the domestic supply of oil, a factor which has the potential to impact oil prices, especially in the current market where the balance between oil supply and demand is quite delicate. The drilled and uncompleted wells reported by the EIA fall into one of seven regions; the Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara, Permian and Utica as shown on this map: Here is a bar graph showing the how the number of drilled and uncompleted wells in the lower 48 has grown since the data was first reported in August 2016: In just nine months, the number of drilled and uncompleted wells has grown from 5065 to 5512, an increase of 8.8 percent. Here is a table showing which regions have the most drilled an uncompleted wells in both February and March 2017:As you can see, the two regions with the most drilled and uncompleted wells are located in the Permian Basin and Eagle Ford of Texas. While oil production is down from its peak of 9.627 million BOPD in April 2015, according to the EIA, United States oil production is rebounding from its lows of 8.567 million BOPD in September 2016 to 8.835 million BOPD in January 2017 as shown here: From the EIA data on drilled and uncompleted wells, we can see that it is quite likely that oil prices will be under downward pressure for some time to come unless, of course, OPEC agrees to cut production levels further or a significant number of these wells turn out to be poor producers.
Fracking and horizontal drilling will reduce oil prices to historic lows - Anjli Raval’s perceptive review of Robert McNally’s Crude Volatility (“A refined take on the volatile oil price story”, April 17) correctly states that McNally “argues that price gyrations are an intrinsic feature of the oil industry and that the world should ‘buckle up’ for the perils of another boom-bust era”. McNally crisply sums up his thesis in his final sentence in Crude Volatility: “Welcome back to boom-bust.” Based on his systematic research of crude prices extending back to 1859, McNally concludes his Epilogue with the observation that: “For the first time in over eighty years we appear to have what many have craved and clamoured for: a genuinely free, unmanaged market for crude oil, the world’s most strategic commodity.” Stressing the extreme fluctuations in crude prices for most of the century and a half he has so carefully researched, McNally is confident we shall see similar volatility from low to high in the decades ahead. Another excellent study of the same subject appeared a year earlier, The Price of Oil by Roberto F Aguilera and Marian Radetzki, but reaches a diametrically different conclusion. Having reviewed the “exceptional price changes over the past several decades”, the authors conclude that, nevertheless, “we are likely to experience a turnround from accentuated scarcity and increasing prices into a new era characterised by relative abundance and price falls as two just emerging revolutions mature and spread internationally. The two revolutions are based on recent technological progress perfecting the combination of horizontal drilling and fracking”. These, in combination, will have “an overwhelming impact on global oil supply . . . and a strong price depressing impact”. After weighing the arguments in these two expert studies of the world’s crude markets, this reader is convinced McNally’s view is unduly influenced by his understanding of the past price history and that Aguilera and Radetzki are correct. As fracking and horizontal drilling continue to revolutionise the extraction of oil, I believe crude prices will decline significantly and eventually fall to historically low levels.
Saudi Oil Exports Drop to 2015 Low as Kingdom Sticks to Cuts | Rigzone - Saudi Arabia, the world’s largest crude shipper, trimmed exports to a 21-month low in February as local refineries took advantage of more abundant supplies and processed a record amount of crude. Oil exports fell to 6.95 million barrels a day, the lowest since May 2015, from 7.7 million a day in January, according to data published Tuesday on the Riyadh-based Joint Organisations Data Initiative website. The kingdom boosted production to 10 million barrels a day from 9.7 million a day, the data show. Saudi Arabia is bearing the brunt of the output cuts that members of the Organization of Petroleum Exporting Countries pledged to make in the first six months of this year. It committed to pump no more than 10.058 million barrels a day, as OPEC and other major producers sought to rein in global oversupply and support prices. Saudi refineries increased the amount of crude they processed in the month by 26 percent to 2.67 million barrels a day, the highest in JODI data going back to January 2002. The amount of crude used directly as fuel in power plants and other facilities also rose, as did volume in storage. Stockpiles increased to 264.7 million barrels at the end of February from almost 262 million barrels in January. Saudi Arabian Oil Co. was planning an 80-day maintenance work at its Riyadh refinery starting in late February to last through mid-May, according to two people with knowledge of the situation. The refinery has capacity to process 120,000 barrels of crude a day, according to data compiled by Bloomberg. “It seems that Aramco is preparing for the long shutdown of the Riyadh refinery by increasing production from other refineries as they need to keep some products in stocks while the refinery is closed,” “The amount of crude not being processed at the Riyadh refinery is reflected in the oil stockpiles in February as they increased from January.” The country plans to double refining capacity to as much as 10 million barrels a day within 10 years, Saudi Energy Minister Khalid Al-Falih has said. Saudi Arabian Oil Co., the state producer known as Saudi Aramco, expects to start operating a 400,000 barrel-a-day refinery next year at Jazan on the Red Sea, adding to two other plants of the same size that have come online since 2013. /p>
Oil Slides After Saudis Unexpectedly Cast Doubt On Production Cut Extension - One week after "unnamed sources" reported that Saudi Arabia had backed the proposed 6 month extension to oil production cuts, this morning oil is lower after the world's biggest oil producer appeared to backtrack on its trial balloon from last week, when Saudi Arabia’s energy minister said it is "too early" to decide whether OPEC will extend its crude-production-cutting agreement for the rest of the year. Quoted by the WSJ, Khalid al-Falih, told reporters in Riyadh Monday that “it is premature to talk about extending the cut.” OPEC’s 13 national ministers are scheduled to decide that question on May 25. Falih’s unexpectedly cautious tone "has taken some of the wind out of the bulls’ sails," according JBC analysts. It wasn't just the sudden Saudi retiscence: as the WSJ adds, Falih’s comments were among a range of factors keeping pressure on oil prices, chief among them that U.S. drilling is now set to increase by 123,000 barrels a day in May, according to the U.S. Energy Information Administration, the steepest monthly rise since February 2015. The EIA figures are the latest sign that U.S. companies have been quick to increase production because of higher prices and has “added another bearish element to the market,” said JBC analysts. A surge in U.S. production is a major threat to OPEC’s effort to reset the still-oversupplied global oil market. The U.S. oil rig count has been on the rise 13 weeks and now stands at its highest level in two years, according to oil-field services firm Baker Hughes Inc. The number of U.S. active drilling rigs rose again last week—by 11 to 683.“You have supportive data from Saudi Arabia showing a large drop in exports but on the other hand you have an increase in U.S. production,” said Olivier Jakob from Switzerland-based consultancy Petromatrix. “The prices are going lower,” he said. “Meanwhile, even as data due on Wednesday is expected to show U.S. inventories shrinking for only the 2nd week in 2017, US drillers have continued to add rigs for past 13 week. "At this rate, the U.S. is likely to reach a new recent record level of production by the end of the third quarter” Olivier Jakob added.
WTI/RBOB Tumble After Unexpected Build In Gasoline Inventories -- Despite last week's unexpected crude draw (and product draws) WTI/RBOB has faded since (even with a lower dollar) as OPEC production cut questions trump inventories for now. However, prices tumbled immediately after API report a smaller than expected draw in crude (-840k) and an unexpected build in gasoline (+1.37mm) .API
- Crude -840k (-1.4mm exp)
- Cushing -672k
- Gasoline +1.374mm (-2mm exp)
- Distillates -1.8mm
Smaller than expected draw in crude and unexpected build in gasoline...
Oil Prices Edge Lower As Imports Keep Inventories Buoyed --After a lesser draw than expected to crude inventories, oil is selling off on this third Wednesday in April. As strong imports from the Middle East this week should help to buoy inventories for next week's report, here are five things to consider in oil markets today.
- 1) Much is being made of Saudi Arabia's February exports, which showed a drop to the lowest since mid-2015, according to JODI data. But we can see in our Clipperdatathat this drop is superseded by a solid rebound in March exports. We see exports rebounded to over 7.2 million barrels per day, with flows bound for East Asia (think: Japan, South Korea, China) accounting for 45 percent of loadings.
- 2) It is also interesting to note that Saudi Arabia oil inventories rose in February amid the export lull. We discussed earlier in the month how JODI data showed that oil inventories dropped to 262 million barrels in January, down from a peak of 329 million barrels in October 2015.
- 3) As the Dakota Access Pipeline (DAPL) starts up, the largest refiner on the East Coast - Philadelphia Energy Solutions (PES) - is not expected to take any deliveries of Bakken crude by rail in June. Once DAPL starts up, it is more profitable for oil to be sent by pipe to the U.S. Gulf Coast than it is to send it by rail to the East Coast. As our ClipperData illustrate below, the marginalization of Bakken barrels to the East Coast has been underway for a good while. Waterborne imports bottomed out in early 2015 - at exactly the same time that Bakken shale crude production was peaking out.
- 4) Today's key EIA inventory numbers have been driven in large part by big swings on the US Gulf Coast. While total US refinery runs rose by 241,000 bpd, an increase of 260,000 bpd was seen from Gulf Coast refiners. This uptick in Gulf Coast refining activity, in combination with imports remaining somewhat in check, has meant oil inventories have drawn down on the Gulf Coast by 3 million barrels. Next week's report is set to be impacted by super-strong waterborne imports from the Middle East, but for now, the increase in refining activity is taking center-stage. Crude inputs are now a whopping 958,000 bpd above year-ago levels.
- 5) Finally, the IMF has published its April 2017 World Economic Outlook. It projects world economic growth is going to be at 3.5 percent in 2017, rising to 3.6 percent in 2018. As we know all too well, all paths lead back to energy, hence downward revisions have been made to Latin American and Middle East nations due to the impact of lower oil prices and production cuts.
Barkindo says OPEC, non-OPEC committed to restore market stability | Reuters: OPEC Secretary-General Mohammad Barkindo said on Wednesday that all oil producers taking part in a supply-cut pact are committed to bringing global inventories down to the industry's five year average and restoring stability to the market. Barkindo, speaking in the United Arab Emirates, said compliance data in March is showing better conformity by the oil producers with the agreement than in February. OPEC and non-OPEC producers agreed in December to cut supplies for six months, helping lift oil prices to about $55 a barrel after a two-year slump. OPEC will review policy for the second half of this year at a May 25 meeting. Barkindo would not say whether the agreement will be extended for another six months, but that any decision taken would be in the interest of all producing and consuming countries.
WTI Slides After Smaller-Than-Expected Draw, Production Hits 20-Month Highs --Following API's surprise gasoline build (and small crude draw), DOE dismissed the markets concerns with a sizable draw in both gasoline and distillates. Crude inventories drew down for the 2nd week in a row. WTI prices slipped though as production rose to its highest since Aug 2015. DOE:
- Crude -1.034mm (-1.4mm exp)
- Cushing +276k (+175k exp)
- Gasoline +2.973mm (-2mm exp)
- Distillates -2.153mm (-1mm exp)
Crude inventories dropped for the second week in a row and product inventories continues to trend seasonally lower...
Oil prices just tanked into the close; 4% slide puts crude back near $50: U.S. oil prices fell nearly 4 percent Wednesday, reaching a session low of $50.28 per barrel and marking their biggest daily percentage decline since early March, as inventories posted a less-than-expected decline for the week. U.S. crude futures closed the day down 3.76 percent, trading at $50.44 per barrel and hovering only slightly above the key $50 level, while Brent crude futures dropped nearly $2.30 to trade around $52.70 a barrel. Earlier on Wednesday, the U.S. Energy Information Administration (EIA) said U.S. crude stocks fell 1 million barrels on the week, a bit less than anticipated. A surprise build in gasoline inventories despite heavier refining activity, along with an increase in U.S. crude production, largely pushed prices lower. "[Wednesday's] crude drawdown was not as large as expected," John Kilduff, founding partner at Again Capital, told CNBC in an interview Wednesday. "There was also a large jump in refinery capacity utilization ahead of the peak summer driving season. That's weighing on the perception of the [EIA] report." "In other words, production of these refined products is expected to rise, increasing inventories." Kilduff also noted that U.S. daily production increased to 9.25 million barrels per day. "That's another bearish sign for oil prices." The selling intensified into the close on some maneuvering by traders.U.S. crude for May expires Thursday, and traders are dumping their oil contracts ahead of that, one analyst also noted.
Oil futures fall sharply after data shows US gasoline build - A surprise build in US gasoline stocks last week triggered a sharp sell-off across the oil complex Wednesday, even though weekly US inventory data also showed draws in both crude and distillate inventories. Gasoline stocks rose 1.542 million barrels to 237.672 million barrels in the week ending April 14, Energy Information Administration data showed. Analysts surveyed Monday by S&P Global Platts were looking for a draw of 2 million barrels.On the Atlantic Coast, home to the New York Harbor-delivered NYMEX RBOB futures contract, gasoline stocks fell 1.276 million barrels, but still sit at a 5 million barrel surplus to the five-year average for this time of year. Distillate stocks fell 1.955 million barrels last week, EIA data showed. Analysts were looking for a draw of 1.4 million barrels. Inventories have fallen 10 straight weeks by a total of 22.5 million barrels to 148.266 million barrels, a surplus of 19 million barrels to the five-year average for this time of year. NYMEX May ULSD fell 4.06 cents Wednesday to settle at $1.5813/gal. Crude stocks declined 1.034 million barrels to 532.343 million barrels in the week ended April 14, EIA data showed Wednesday. Analysts were looking for a draw of just 50,000 barrels. NYMEX May RBOB settled 5.20 cents lower at $1.6590/gal.
Why the crude rally has fizzled: Market analysis series --Prices had been trading comfortably above $50/b since late March, with bulls re-trenching on the idea that Saudi-led OPEC supply cut will soon tighten balances. And while today’s price declines could prove temporary, a measure of caution is advised to all bulls, for two key reasons — reasons that we’ve been watching closely since November. First, the expectation that the OPEC supply cuts will tighten global crude supply is overdone. While there is likely a limi to how many OPEC barrels US shale can replace, anyone who thinks the godfathers of the shale revolution are going to sit idly by as prices soar probably wrote a book on peak oil. Second, global refined product stocks are ample and will have to clear — with a noticeable increase in crack spread and differentials — before forecast demand growth can meet expectations. The bulls say given enough time, OPEC-led supply cuts will drive prices higher. A recent S&P Global Platts survey pegged OPEC compliance on stated cuts at around 115% over January to March. That is truly incredible, and clearly part of any bull’s fundamental calculus. But if cuts are actually taking place, what effect are they actually having? The market’s ability to flood Asia and Europe with crude has become entirely unshackled. How long will it be before cut OPEC and Russia volumes are replaced by barrels out of Latin America, the US, Canada, North Sea and West Africa? And isn’t that already happening? Is this not the new normal?
Hedge fund confidence in OPEC starts to fray: Kemp (Reuters) - OPEC and some of the most important hedge funds active in commodities reached an understanding on oil market rebalancing during informal briefings held in the second half of 2016. OPEC committed to implement credible production cuts and reduce global crude stocks while hedge funds responded by establishing bullish long positions in both flat prices and calendar spreads. OPEC effectively underwrote the fund managers’ bullish positions by providing the oil market with detail about output levels and public messaging about high levels of compliance. In return, the funds delivered an early payoff for OPEC through higher oil prices and a shift from contango to backwardation that should have helped drain excess crude stocks. The understanding was initially successful between December 2016 and February 2017, with reports of strong compliance from OPEC, spot prices rising $10 per barrel and calendar spreads moving from contango to flat or, albeit briefly, backwardation. But the understanding started to unravel with the calendar spreads collapsing after Feb. 21 and flat prices dropping from March 8 (http://tmsnrt.rs/2oNQJPq).. The sharp reversal in both spreads and flat prices inflicted substantial losses on many bullish hedge funds in February and March. The correction came amid growing doubts about whether OPEC was really cutting oil supplies to the market by as much as anticipated. Global stocks of crude and refined products showed little sign of drawing down during the first three months of 2017. Bullish fund managers have pushed the time horizon for expected stock draw downs back to the second half of the year. OPEC has come under pressure to reconfirm the faith of hedge fund bulls with an early commitment to extend current output cuts beyond June.
Why The Relationship Between OPEC And Hedge Funds Is On The Verge Of Falling Apart --Following years of acrimony between OPEC and the hedge fund community, which the cartel dismissed simply as "speculators", things suddenly changed in 2016 when the two groups got so close, there were outright reports of collusion between the two on various occasions. We documented this last month in "Why OPEC Is Colluding With Hedge Funds." However, as Reuters' energy analyst John Kemp pointed out on twitter this morning, that relationship may be ending as hedge funds start to lose confidence in OPEC.Taking us to the beginning, Kemp notes that OPEC and some of the most important hedge funds active in commodities reached an understanding on oil market rebalancing during informal briefings held in the second half of 2016. OPEC committed to implement credible production cuts and reduce global crude stocks while hedge funds responded by establishing bullish long positions in both flat prices and calendar spreads.OPEC effectively underwrote the fund managers’ bullish positions by providing the oil market with detail about output levels and public messaging about high levels of compliance. In return, the funds delivered an early payoff for OPEC through higher oil prices and a shift from contango to backwardation that should have helped drain excess crude stocks.The Reuters analyst then notes that the understanding was initially successful between December 2016 and February 2017, with reports of strong compliance from OPEC, spot prices rising $10 per barrel and calendar spreads moving from contango to flat or, albeit briefly, backwardation. But the understanding started to unravel with the calendar spreads collapsing after Feb. 21 and flat prices dropping from March 8.
API: US petroleum demand in March at highest level since 2008 - Oil & Gas Journal: Total petroleum deliveries in March increased 0.2% from March 2016 to average nearly 19.7 million b/d—the highest March deliveries in 9 years, according to data from the American Petroleum Institute. For this year’s first quarter, total US petroleum deliveries, a measure of US petroleum demand, were up 0.4% compared with first-quarter 2016 to average 19.5 million b/d. These were the highest first quarter deliveries since 2008. According to the US Bureau of Labor Statistics report, issued Apr. 7, the US added 98,000 jobs in March. In addition, the unemployment rate at 4.5% and the number of unemployed persons at 7.2 million were both down from a month ago as well as last year. Gasoline deliveries, meanwhile, were up in March from the previous month, but down from the prior year as well as last year’s first quarter. Total motor gasoline deliveries increased 4.3% from February, but were down 1.7% from March 2016 to average 9.2 million b/d. These were the second-highest March deliveries ever recorded. “The strong steady demand for fuel expanded economic activity in the manufacturing sector last month and the overall economy grew for the 94th consecutive month. Good news for workers and the economy,” said Chief Economist Erica Bowman. US crude oil production increased in March for the third straight month, up 1.4%, but posted declines compared with levels in the previous year as well as last year’s first quarter. At an average of 9.2 million b/d, US crude oil production decreased 0.2% from March 2016 and was down 1.8% from first-quarter 2016. Natural gas liquids production was up from the previous month and last year’s first quarter, but was down from the prior year. NGL production in March averaged 3.4 million b/d, which was the second-highest level for the month on record. This was 0.4% above February’s output and 0.8% higher than first-quarter 2016.
RPT-Murky oil inventory picture leaves market grappling for clarity | Reuters: The jury is still out over whether an OPEC-led production cut aimed at tightening oil markets is working, or if the producer club has simply enabled higher prices without making much of a dent in the global fuel supply overhang. Analysts say there are early indications that at least some inventories, key in gauging the health of the market, are starting to draw down. However, inventory levels are hard to judge outside of the United States, as many countries do not release specific figures. Oil shipments show an ongoing excess, while price activity in oil futures suggests sagging optimism the imbalance is being corrected. Over two years into a 50 percent price slump, the Organization of the Petroleum Exporting Countries (OPEC) and some other producers, including Russia, pledged to cut production by almost 1.8 million barrels per day (bpd) during the first half of the year. But more oil than ever is currently traversing the world's oceans. Thomson Reuters Eikon data shows global crude shipments, which monitor tanker movements but exclude pipeline flows, hit a record 47.8 million bpd in April, up 5.8 percent since December, before cuts were implemented. This is in part due to a jump in production and exports from producers who did not agree to cuts, especially the United States. "OPEC seems more like a magician who is keeping the audience's attention fixed firmly on his hands (its production policy) while the actual trick takes place elsewhere (non-OPEC supply)," said Carsten Fritsch, oil analyst with Commerzbank. U.S. production is soaring, jumping by almost 10 percent since mid-2016 to 9.25 million bpd. This brings its output close to the world's top two producers, Saudi Arabia and Russia.
Preliminary agreement reached among some OPEC ministers to extend production cuts: Falih - Saudi energy minister Khalid al-Falih on Thursday said that he saw an extension of the OPEC/non-OPEC production cut agreement likely if global oil inventories do not fall to sufficient levels. "There has been a strong level of commitment in the past three months," Falih said at the GCC Petroleum Media Forum in Abu Dhabi. "Unfortunately we still have not reached our goal." If stocks remained too high, "we will extend this agreement to nine or even 12 months (from January 1) because our target is the level of (inventories), and this will be the indicator of the success of our initiative," he added. OECD stocks remained 336 million barrels above the five-year average at the end of February, the International Energy Agency said in its most recent monthly oil market report. OPEC ministers have said their aim with the production cuts is to bring inventory levels down to the five-year average. Under the six-month deal, which expires in June, OPEC was to cut 1.2 million b/d of crude production from October levels and 11 key non-OPEC producers led by Russia to cut output by 558,000 b/d. OPEC ministers will meet on May 25 in Vienna to decide whether to extend the production cuts, with a monitoring committee composed of Kuwait, Algeria, Venezuela, Russia and Oman to provide a formal recommendation before that.
Saudi Arabia, Kuwait signal likely extension of oil output cut | Reuters: Leading Gulf oil exporters Saudi Arabia and Kuwait gave a clear signal on Thursday that OPEC plans to extend into the second half of the year a deal with non-member producers to curb supplies of crude. Consensus is growing among oil producers that a supply restraint pact that started in January should be prolonged after its initial six-month term, Saudi Energy Minister Khalid al-Falih said. "There is consensus building but it's not done yet," Falih told reporters at a conference in the United Arab Emirates. Kuwait's oil minister Essam al-Marzouq said he expected the agreement to be extended. "Russia is on board preliminarily ... Compliance from Russia is very good," Marzouq said. OPEC Secretary-General Mohammed Barkindo, noting that Marzouq chairs a committee that measures compliance with the cuts, said: "It is significant that the Kuwaiti minister has come out in public and said this." OPEC is keen that non-member producers play their promised part in supporting the group's efforts to lift prices, which have recovered to $53 a barrel from lows last year below $30. The Organization of the Petroleum Exporting Countries and non-OPEC meet on May 25 to discuss extending the curbs that total 1.8 million barrels daily, two-thirds of that from OPEC.
Brent Physical Oil Market Weakens Again Despite OPEC Output Cuts The Brent physical oil market is flashing signs of weakness again as dwindling Asian purchases, an influx of American crude to Europe, and supplies flowing out of storage all combine to recreate a glut in the North Sea. The weakness comes at a time when speculators have started rebuilding bullish positions after a sell-off last month, betting the market will tighten in the second quarter. Yet, Brent physical oil traders say the opposite is happening so far, according to interviews with executives at several trading houses, who asked not to be identified discussing internal views. “We need to see the market going really into deficit for oil prices to rise,” Giovanni Staunovo, commodity analyst at UBS Group AG in Zurich, said. “If this is temporary, it could be weathered, but it needs to be monitored.” The weakness is particularly visible in so-called time-spreads -- the price difference between contracts for delivery at different periods. Reflecting a growing surplus that could force traders to seek tankers as temporary floating storage facilities, the Brent June-July spread this week fell to an unusually weak minus 55 cents per barrel, down from parity just two months earlier. The negative structure is known in the industry as contango. "Keep a wary eye on the Brent contango," said Jan Stuart, energy economist at Credit Suisse Securities LLC in New York. "Bellwether Brent time-spreads have been counter-seasonally widening.”
Oil Stumbles Back To $50 Handle As Saudi/OPEC Jawboning Fails - Oil prices limped higher overnight as desperate jawboning of OPEC production cut deal extensions by the Saudis supported a recovery from yesterday's post-inventories plunge. However, confirming the market's lack of faith in OPEC (and Saudi's ability to hold the deal together), WTI prices are sliding back towards a $50 handle as jawboning half-lives slump. As The FT reports, oil producers are moving closer towards agreement on extending the Opec-led deal to limit output, Saudi Arabia’s energy minister said on Thursday, as the cartel battles excess stockpiles and a resurgent US shale industry that have weighed on prices. Khalid al-Falih said the deal could be run for another three to six months beyond the end of June. Under the terms of the existing accord, Opec members and countries outside the cartel, including Russia, agreed to cut their output by about 1.8m barrels a day throughout the first half of 2017. A preliminary agreement to extend the deal had been reached by most, but not all, producers, he said. “Consensus is building, but it is not done yet,” Mr Falih told reporters on the sidelines of an energy industry event in Abu Dhabi. “We are still in consultations.” But the market is not buying it...
Don't Believe The Hype: Oil Markets Far From Recovery - Arthur Berman - Global oil inventories are falling because of OPEC and non-OPEC production cuts, but the road to market balance will be long. Production cuts have removed approximately 1.8 million barrels per day (mmb/d) of liquids from the world market since November 2016 (Figure 1).Saudi Arabia has cut 619 kb/d (35 percent of total) and the Gulf States Cooperation Council—including Saudi Arabia—has cut 1,159 kb/d (65 percent of the total). Other significant contributors outside the GCC include Iraq (12 percent), Russia (12 percent) and Mexico (9 percent) (Table 1). Nigeria’s cuts are probably involuntary since it was exempted from the OPEC agreement. Iran and Libya–also exempted–and both increased production.OECD inventories began falling in July 2016, four months before the OPEC production cuts were finalized. Stock levels have declined approximately 107 mmb according to recently revised EIA STEO data (Figure 2). That includes the January 2017 increase recently noted in the April IEA Oil Market Report. Although this represents progress toward market balance, stocks must fall at least another 260 mmb to reach the 5-year average level to support oil prices in the $70 per barrel range. Almost three-quarters (73 percent) of OECD decline was from non-U.S. inventories. Perhaps the intent of OPEC’s November cuts was to stimulate a decrease in U.S. inventories (about 45 percent of the OECD total). U.S. stocks and comparative inventories were increasing at the time of the cuts and did not start to fall until February 2017 (Figure 3). Since mid-February, U.S. stocks and comparative inventory have each declined 20 percent. Still, U.S. inventories must fall another ~143 mmb to reach the 5-year average (Figure 4). The immediate results of the OPEC cuts were an increase in oil prices and an important change in the term structure of crude oil futures contracts. Before the cuts were announced, the term structure of the WTI oil futures curve was in contango (prices are higher in the near-future). That favored storing rather than selling oil and contributed to growing inventory levels (Figure 5).In early March 2017, however, oil prices fell as investors lost confidence that the cuts were working. Forward curves moved into weak backwardation (prices are lower in the near-future). Now, prices have increased with outages in Canada and Libya, and the forward curve has moved into stronger backwardation. That favors selling rather than storing crude oil and contributes to decreasing inventory levels.
OilPrice Intelligence Report: Why Oil Prices Are Seeing A Steep Correction -- Oil is heading for its largest weekly drop in over a month as doubts resurfaced over OPEC’s resolve. That comes despite the highly optimistic comments from top officials from Saudi Arabia and Kuwait. There seems to be a growing consensus within OPEC in favor of an extension of the deal. But the one holdout could be Russia, without which an extension is uncertain. Russia’s energy minister Alexander Novak was guarded when asked about Russia’s support for an extension, declining to take a position while citing progress that has already been made in the reduction of oil stocks. "The situation has gradually been improving since the beginning of March," Novak said to reporters.. Oil was down sharply over the past few days, but Goldman Sachs tried to reassure the markets, saying that there is no evidence to justify the price declines. The investment bank tells investors to keep their focus, pointing to ongoing declines in crude oil inventories, drawdowns that are expected to pick up pace this quarter. Goldman says this week’s price declines of about 4 percent were driven more by speculative moves than the fundamentals. As a result, prices should firm up. Goldman says there is nothing to worry about, but the U.S. EIA reported an unexpected increase in gasoline stocks last week, raising fears of softer-than-expected demand. The stock build sent a shudder through the oil market this week. “If there’s too much gasoline, then refineries turn off and that’s bad for crude. This is the first week it has really been a concern,” Sam Margolin, an analyst at Cowen & Co., told the WSJ. The FT reported on Russia’s foray into the Arctic, describing the persistence from the state and the government owned-Rosneft to go it alone on some of the most complex oil projects in the world. International sanctions put on Russia back in 2014 were thought to prevent Russia from accessing the capital, drilling technology and expertise needed to tap oil in the Arctic as well as in Russian shale. But, the FT reports that sanctions have forced Russia to make progress on its own. Oil inventories are declining around the world even as they remain near record highs in the U.S. OPEC compliance is high and the drawdowns are evidence that the OPEC deal is finally bearing fruit. But the market is still uncertain if the cuts will be enough to sufficiently drain stockpiles.
OPEC Rumor-Mill Utterly Fails - Oil Tumbles On Production-Cut Deal Extension Chatter -- Just as Reuters' John Kemp warned, it seems the hedge funds have abandoned OPEC. In the good ol' days (of the last year), one mention of production cut deal extensions, or high production cut compliance rates, would have been enough to see levered buying with both hands and feet, self-reinforcing the 'success' of OPEC's plan. Today - that failed! WTI plunges below $50 and we tweet that OPEC is due any time now... Sure enough seconds later the following headline drop... *OPEC TECH COMMITTEE SAID TO SEE NEED FOR 6-MO CUTS EXTENSION But the reaction was a disaster...As we noted previously, reported stocks need to start falling soon if hedge fund managers’ confidence in rebalancing is to be maintained.Which is why the daily jawboning by OPEC in the form of its recurring messaging about high levels of compliance has lost much of its effectiveness and is no longer enough to justify a bullish position in crude.As a result, reported stock changes now matter more for oil prices and calendar spreads than compliance assessments by OPEC’s secondary sources.Kemp's conclusion: "OPEC’s credibility is on the line: stocks need to show a significant draw during the second and third quarters or many hedge funds are likely to give up on the bullish narrative prevailing since late 2016."
BHI: US rig count adds 10 units, continues onshore drilling spike The US drilling rig count during the week ended Apr. 21 climbed by double-digits for the 10th time in its 14-week streak of increases, Baker Hughes Inc. data indicate (OGJ Online, Apr. 13, 2017). The overall tally of active rigs rose by 10 to 857, up 453 units since the nadir of the drilling downturn on May 20-27, 2016, and its highest point since Sept. 4, 2015. Land-based rigs gained 11 units to 834, with horizontal rigs jumping 12 units to 718, up 404 since May 20-27. Directional drilling rigs lost 4 units to 60. Rigs drilling in inland waters were unchanged at 3, while offshore rigs dropped a unit to 20. Fitch Ratings projects the US Lower 48 land rig count to grow to 850-875 units by yearend, averaging around 800 for the full year, given the expectation of growing production, higher oil and gas prices, and leaner cost structures leading to increased cash flows for producers (OGJ Online, Apr. 21, 2017). “Capital allocation is expected to be weighted toward the highest-return shale plays with growth potential such as the Permian, Eagle Ford, STACK, Haynesville, and Marcellus basins,” Fitch said. Separately, Wood Mackenzie Ltd. said that US Lower 48 onshore operators are beginning to experience cost inflation following a flurry of first-quarter development activity (OGJ Online, Apr. 20, 2017). The research and consulting firm forecasts 15% cost inflation in 2017, with variability across basins. WoodMac noted, however, that horizontal rigs will likely see half the cost inflation rates compared with that of pressure pumping as rigs are operating with greater efficiencies and faster drilling times.“Despite our projections for a 10% cost inflation for horizontal rigs this year, it's unclear how much traction drilling contractors will gain on new long-term rig contracts,” the firm said. “Many producers signed long-term rig contracts at peak prices in 2014, which are now expiring in a spot market that's 40% down, triggering deflation in some cases, and likely influencing contracting activity this year.”The use of longer laterals and fewer wells may limit the amount of rig contracts compared with those of previous years, and with operators electing to hedge oil prices and limit drilling within cash flow, rig growth could moderate during the second half, WoodMac said. The US oil-directed rig count gained 5 units during the week ended Apr. 21 to 588, up 372 since May 27, according to BHI data. Gas-directed rigs rose 5 units to 167, up 86 since last Aug. 26. Two rigs considered unclassified remained operating.
Oil ends below $50 as U.S. rig count continues to climb -- Oil futures fell on Friday, with the U.S. benchmark ending below $50 a barrel and notching a weekly loss of roughly 7%. The latest weekly rise in active U.S. oil rigs offered another sign of further growth in U.S. crude production, casting doubts that the Organization of the Petroleum Exporting Countries will agree to extend its product-cut deal into the second half of the year. June West Texas Intermediate crude fell by $1.09, or 2.2%, to settle at $49.62 a barrel on the New York Mercantile Exchange. The settlement was its lowest since March 29, according to FactSet data. June, which saw its first full day of trading as a front-month contract Friday posted a weekly loss of 7.4%. Based on the most-active contracts, however, prices lost 6.7%. Either way, it was the first weekly loss since the week ended March 24. Declines in WTI accelerated in late morning trading as U.S. equities fell “on France election uncertainty and oil, being in a weak technical position, followed along,” said Phil Flynn, senior market analyst at Price Futures Group. Prices then held on to their losses after Baker Hughes reported another weekly rise in the U.S. oil-rig count.June Brent crude on London’s ICE Futures exchange LCOM7, -2.04% lost $1.03, or 1.9%, to $51.96 a barrel—ending 7% lower for the week. Signs of a possible extension, which would help to offset output increases in the U.S., have provided some support for oil prices in recent weeks. Saudi Arabia Energy Minister Kalid al-Falih said Thursday that a handful of cartel members have reached a tentative agreement to cut more supplies.
Oil dives, sending U.S. crude below $50 for first time in two weeks | Reuters: Oil prices tumbled more than 2 percent on Friday, notching the biggest weekly decline in more than a month on mounting evidence that U.S. production and inventory growth were offsetting OPEC's attempts to reduce the global crude glut. Brent futures LCOc1 settled at $51.96 a barrel, down $1.03, or 2 percent at the market's close. U.S. crude futures CLc1 ended at $49.62 a barrel, down 2.2 percent, or $1.09. Volumes were heavy, with more than 665,000 WTI futures changing hands, surpassing the daily average of 525,000 contracts. For the week, Brent fell 7 percent, while U.S. crude lost 6.7 percent. It was the largest percentage drop for both benchmarks since the week of March 10, when rising concern about the supply glut undermined big bets on an oil rally. Those speculative bets have been on the rise again. On Friday, the U.S. Commodities Future Trading Commission (CFTC) showed total long positions in U.S. crude rose in the week to April 18 to their highest in more than a month at 355,077 contracts. But oil has sagged in recent days, much as it did in March. Many in the market still expect the Organization of the Petroleum Exporting Countries (OPEC) to renew its production cuts for another six months. On Friday an OPEC and non-OPEC member technical committee recommended extending cuts of almost 1.8 million barrels per day (bpd) at the upcoming May 25 meeting. Still, shipment data shows more oil transiting world oceans than when cuts were put in place. “The reason that we’re seeing the selloff today and really for this week has been related to the fact that we’re seeing higher waterborne imports arriving from the Middle East,” said Matt Smith, director of commodity research at Clipperdata. “We should continue to remain well supplied at least over the next few weeks."
Is Aramco IPO Behind Saudi Eagerness For OPEC Cut Extension? - Clear signs emerged this week that the OPEC production cuts in place since November 2016 may be extended past their June 2017 deadline. On Tuesday, Saudi Arabia expressed their willingness to extend the cuts, and the OPEC monthly production report showed the Saudis continuing their over-compliance, cutting production to 9.9 million bpd in March, around 100,000 bpd below the agreed-upon monthly quota. The total fall in OPEC production was 365,000 bpd, sending total production down to 31.68 million bpd. Saudi over-compliance was one factor in the decline, but there were also involuntary losses in Libya and Nigeria. Along with Saudi Arabia, other OPEC members like Kuwait, Iraq, Algeria and Angola have all said that further cuts will be necessary to return markets to a state of balance. The Middle Eastern producers have indicated that their ideal price target is $60, a level which they feel will allow their economies to recover without enabling further American production, according to the Wall Street Journal. Both the announcement of the Saudi position and the OPEC report helped keep prices buoyant this week, as the late-March rally continued, sending the WTI above $53 a barrel. Research from the KLR Group released on Thursday indicated that global inventories would be normalized late in 2017 if the OPEC cuts were extended. A stabilizing supply-demand situation is also the outlook of the IEA, which predicted demand to decline for the second year in a row in 2017. Neither bearish nor bullish, the IEA outlook hedged on the side of caution, noting that declining inventories and OPEC cuts raising prices would spur new growth in U.S. production, partially offsetting the OPEC gains and repeating the trend of early 2017. In January, reports of huge inventory draws and a surge in shale activity saw the price fall back to its pre-November level. Both KLR and the IEA believe that further OPEC cuts would tighten supply, leading to greater stock draws and higher prices in the second half of 2017. But not all OPEC producers are keen on the idea of further cuts. Iran, eager to boost production past its pre-sanctions level, only agreed to cuts in November on the condition it was permitted to continue increasing production to 3.8 million bpd. It reached that level in late 2016 and even neared 4 million bpd according to direct communication to OPEC, but there’s a good chance much of Iran’s impressive increase in exports since January 2016 came from storage facilities on and off shore, and that actual Iranian field production may decline without considerable investment. Iranian production declined somewhat in March, falling 28.7 thousand bpd to 3.79 million bpd according to secondary sources.
Reeling From Low Oil Prices, Saudis Look To Freeze Megaprojects - Saudi Arabia will start reviewing a number of multi-billion-dollar infrastructure and development project—remnants from a better past when crude oil prices were in three-digit territory. Some of these, according to government sources, will be shelved and others will be restructured. The review is part of urgent reforms prompted by the oil price rout from 2014, which saw Saudi Arabia plunge into a budget deficit for the first time in its history. As part of efforts to reform the oil-reliant economy, last year Deputy Crown Prince Mohammed bin Salman removed from their positions the Kingdom’s long-serving oil and finance ministers, Ali al-Naimi and Ibrahim al-Assaf. At the time, the Finance Minister defended these same megaprojects that will now be scrutinized by the Bureau of Capital and Operational Spending Rationalization, saying that when the investment decisions were made, the economic outlook was very different from where it was in 2016. At the end of last year, the Saudi government calculated that the cost of completing all these projects would come in at $370 billion (1.4 trillion riyals). Now, those that are deemed still feasible will be retendered, the unnamed sources told Reuters, to be completed through public-private partnerships under build-operate-transfer contracts. This type of contract allows developers to complete a project and operate it for a set period, aiming to get some profit out of it before transferring ownership to the government. The Deputy Crown Prince who is in charge of turning the oil-dependent Kingdom around seems determined to do his job well, including through diversifying the economy into renewable energy with the extremely ambitious Vision 2030 plan, which stipulates that Saudi Arabia could start generating most of its energy from renewable sources as soon as 2030. Meanwhile, however, sources from OPEC have confirmed that the Kingdom, along with other Gulf producers, are seeking oil prices of $60 to patch up their budgets and set aside some cash for new oil and gas investments.
US seeks political solution to Yemen war: Mattis - US Defense Secretary James Mattis says the conflict in Yemen needs to be resolved "as quickly as possible” through UN-brokered peace negotiations. "Our aim is that this crisis can be handed to a team of negotiators under the aegis of the United Nations that can try to find a political solution as quickly as possible," Mattis told reporters on Tuesday as he flew to Riyadh, Saudi Arabia. "We will work with our allies, with our partners to try to get it to the UN-brokered negotiating table," the Pentagon chief said. Mattis is expected to meet senior Saudi officials, including King Salman bin Abdulaziz Al Saud and Deputy Crown Prince and Defense Minister Mohammed bin Salman. Several UN brokered ceasefires and peace talks have so far failed to end the conflict in Yemen. Mattis gave no details on what additional support, if any, the United States would provide to the Saudi-led coalition. Washington already provides intelligence as well as aerial refueling to coalition warplanes carrying out air strikes in Yemen. Human rights groups have repeatedly criticized the Saudi-led bombing campaign in Yemen for causing civilian casualties. The campaign has claimed the lives of more than 12,000 people, most of them civilians.
BRICS Issues Joint Statement: Illegal Military Intervention in Syria Is Unacceptable -- Brazil, Russia, India, China and South Africa have issued a joint BRICS statement condemning military action in Syria that has not been authorized by the United Nations. The statement also calls for respect of international law, territorial integrity and sovereignty. Some highlights from the statement: BRICS Special Envoys on Middle East expressed their concern about internal crises that have emerged in a number of states in the region in recent years. They firmly advocated that these crises should be resolved in accordance with the international law and UN Charter, without resorting to force or external interference and through establishing broad national dialogue with due respect for independence, territorial integrity and sovereignty of the countries of the region. The participants emphasized the legitimacy of the aspirations of the peoples of the region to enjoy full political and social freedoms and for respect to human rights. They strongly condemned recent several attacks, against some BRICS countries, including that in the Russian Federation. BRICS members stand for consolidating international efforts to combat the global threat of terrorism. They stressed that counter-terrorism measures should be undertaken on the firm basis of international law under the aegis of the UN and its Security Council. In the course of the meeting, the role of the UN Security Council as the international body bearing the primary responsibility for maintaining international peace and security was underlined. It was also stressed that military interventions that have not been authorized by the Security Council are incompatible with the UN Charter and unacceptable. BRICS Special Envoys expressed their deep concern with regard to the continuing violence in Syria, deterioration of humanitarian situation and growing threat of international terrorism and extremism in that country. The participants confirmed their strong support for the sovereignty and territorial integrity of Syria and the need for a peaceful solution, led by the Syrians, to the conflict. They supported all efforts towards a political and diplomatic solution in Syria through talks based on Resolution 2254 of the United Nations Security Council. They welcomed the three rounds of talks held in Astana and the outcome of fifth round of talks in Geneva. They acknowledged that Astana talks paved the way for resumption of Geneva talks. They expressed resolve for renewed and committed efforts to find a political and diplomatic solution in Syria.
Syria Moves Most Of Its Combat Planes Next To Russian Base For Protection -The enemy of my enemy has safe air bases.In a move which either suggests that i) Syria is preparing for more US attacks, ii) really likes Russians, or iii) is simply doing the logical thing, CNN reports that the Syrian government has moved most of its combat planes to a base located in close proximity to the Russian air base in Syria to protect them from potential US strikes. The movement of the aircraft to the air base at Bassel Al-Assad International Airport began shortly after the US's April 6 Tomahawk cruise missile strike on Sharat air base, which destroyed some 24 Syrian warplanes.After the move, the majority of Syria's operation airforce will be located next to Russia's Khmeimim Air Base, where the majority of Russian air forces helping ally Syrian President Bashar al-Assad's regime are based, in Latakia, Syria.The Khmeimim base, along with a naval facility in Tartus, is one of the two of the primary Russian military installations in Syria, and has in the past been shown to be protected by one or more Russian anti-aircraft missile installations.
U.S. says Iran complies with nuke deal but orders review on lifting sanctions | Reuters: The Trump administration said on Tuesday it was launching an inter-agency review of whether the lifting of sanctions against Iran was in the United States' national security interests, while acknowledging that Tehran was complying with a deal to rein in its nuclear program. In a letter to U.S. House of Representatives Speaker Paul Ryan, the top Republican in Congress, on Tuesday U.S. Secretary of State Rex Tillerson said Iran remained compliant with the 2015 deal, but said there were concerns about its role as a state sponsor of terrorism. Under the deal, the State Department must notify Congress every 90 days on Iran's compliance under the so-called Joint Comprehensive Plan of Action (JCPOA). It is the first such notification under U.S. President Donald Trump. "The U.S. Department of State certified to U.S. House Speaker Paul Ryan today that Iran is compliant through April 18 with its commitments under the Joint Comprehensive Plan of Action," Tillerson said in a statement. "President Donald J. Trump has directed a National Security Council-led interagency review of the Joint Comprehensive Plan of Action that will evaluate whether suspension of sanctions related to Iran pursuant to the JCPOA is vital to the national security interests of the United States," Tillerson added. He did not say how long the review would take but said in the letter to Ryan that the administration looked forward to working with Congress on the issue.
Another Flip? Trump Tells Congress Iran Compliant With "Disastrous" Nuclear Deal - On the heels of an apparant avalanche of flip-flops on campaign comments, President Trump has notified Congress that Iran is complying with the "disastrous... worst deal ever negotiated" 2015 nuclear deal negotiated by former President Obama. During his campaign, Trump raised the prospect the United States will pull out of the nuclear pact it signed last year with Iran, alienating Washington from its allies and potentially freeing Iran to act on its ambitions.Trump called the nuclear pact a "disaster" and "the worst deal ever negotiated" during his campaign and said it could lead to a "nuclear holocaust."In a speech to the pro-Israel lobby group AIPAC in March, Trump declared thathis “Number-One priority” would be to “dismantle the disastrous deal with Iran.”All of which makes it fascinating to note that, as AP reports, the Trump administration has notified Congress that Iran is complying with the terms of the 2015 nuclear deal negotiated by former President Barack Obama, a nd says the U.S. has extended the sanctions relief given to the Islamic republic in exchange for curbs on its atomic program. The certification of Iran's compliance, which must be sent to Congress every 90 days, is the first issued by the Trump administration.
Fracking Sweeps Into China - China has turned to hydraulic fracturing to decrease its dependency on foreign natural gas, according to state-run media.China has been trying to use fracking to shifts away from traditional sources of energy such as coal power. Shale gas production has risen by 50.4 percent compared to last year, according to the Chinese National Bureau of Statistics. China produced 3.8 billion cubic feet of shale gas in March. To put this in some perspective, the U.S. currently produces 1,476 billion cubic feet annually.U.S. experts expect China will continue to push fracking, but don’t see the communist country becoming energy independent any time soon.“It makes perfect sense for Beijing to push as hard as it can to rely on new domestic sources of energy wherever possible,” Harry J. Kazianis, director of defense studies at the Center for the National Interest, told The Daily Caller News Foundation. “And increased shale gas output very much fits into such a strategy.”China aims to boost natural gas’s share of the energy supply from 6 to 10 percent by 2020. In March, Beijing became China’s first city to have all natural gas-fired power plants.Fracking hasn’t gone very far in China because its shale reserves, though large, are expensive and technically difficult to extract. China doesn’t have as favorable geology for fracking, so it will rely on imports for the time being. China’s shale oil could be economically recoverable with oil prices at $345 a barrel.“We must keep in mind that China is highly dependent on external energy supplies to power its growing economy,” Kazianis said. “In times of crisis on the high seas or war, if such energy flows were disrupted or cut off, the economic damage that would result could be quite severe.”China is expected to buy roughly 70 percent of its oil from foreign sources over the next few decades, largely from unstable parts of the world. Sudan provides 7 percent of China’s oil imports, and over one-third of Chinese oil imports come from sub-Saharan Africa. Some of China’s largest oil suppliers — Angola, Sudan, Nigeria, and Equatorial Guinea.
Tanker freight rates tank on China’s proposed consumption tax | Hellenic Shipping News Worldwide: China’s plan to impose a consumption tax on mixed aromatics, light cycle oil and bitumen blend has shaken up everyone from the oil industry to the shipping industry. If implemented, the proposed tax will curb inflows of the said products, hit exports of oil products, and in turn hurt demand for oil tankers, says senior editor Sameer C. Mohindru. Clean Tankerwire brings you the latest in tanker freight and fixture rates, giving you a full view of the most important developments, so you can effectively analyze the tanker market. Clean Tankerwire is a daily report that offers extensive listings and clear analysis of the latest tanker freight and fixture rates as a percentage of the Worldscale figure and an additional cost per metric ton conversion. Welcome to the Snapshot, a series that examines the forces shaping and driving global commodity markets today. If China sneezes, the rest of the world catches a cold. And if China coughs, it is rest of the world that has to clear its throat. Such is the whopping appetite of China for all commodities that policy changes effected in Beijing have a significant impact across the globe. It should not then come as a surprise that China’s plan to impose a consumption tax on mixed aromatics, light cycle oil and bitumen blend, has shaken up everyone — ranging from the oil industry to the shipping industry. The proposal, if implemented, will curb inflows of these products and hit exports of oil products – and in turn hurt demand for oil tankers. Freight rates for medium range tankers have already taken a hit.
China Ready To Cut Oil Supplies To North Korea - Beijing’s patience with North Korea is wearing thin as Pyongyang continues to conduct nuclear missile tests. According to a state Chinese media outlet, Huanqui, China is considering a suspension of its crude oil exports to its neighbor should North Korea conduct a sixth nuclear test.North Korea depends on China for 90 percent of its crude oil supply, and stopping these will wreak havoc on the dictatorship, which China has been trying to avoid, since a regime collapse is likely to result in a massive influx of refugees. It has also opposed President Trump’s urging to penalize North Korea for the nuclear tests so far, but now it seems the mood is changing – having another nuclear neighbor is hardly China’s idea of a stable regional environment.Asia’s biggest economy also has other ways to make Kim Jong Un give up nuclear tests, such as stopping or reducing the food aid it sends to the impoverished nation, or cutting North Korean foreign currency transactions that go through Chinese banks.The White House meanwhile has sent “an armada” to the Korean peninsula, and is now mulling over measures such as an oil embargo, a ban on the country’s only airline, and interception of ships carrying cargo to North Korea. Also among the measures being considered is penalizing Chinese banks doing business with Pyongyang.