oil prices fell this week for the first time in seven weeks on fears that a second wave of the coronavirus would damage the embryonic economic recovery....after rising 11% to $39.55 a barrel last week on improving US economic data and on the prospect that OPEC would extend their production cuts, the contract price of US light sweet crude for July delivery initially moved higher on the weekend extension of the OPEC cuts on Monday, but reversed to end $1.38 lower at $38.19 a barrel as the Saudis, the Emirates and Kuwait rescinded the additional voluntary cuts they had undertaken in the wake of the collapse of May oil prices... however, optimism that the announced supply cuts would more than offset demand weakness returned on Tuesday as oil prices regained 75 cents of their Monday loss to close at $38.94 a barrel...oil prices opened lower Wednesday on an API report of crude inventory build, and then tumbled to as low as $37.73 a barrel after the EIA confirmed a big build in U.S. crude oil inventories, as well as an increase in fuel inventories, but then rallied to close 66 cents higher at $39.60 per barrel on a weak dollar and the Fed's plans to keep interest rates at near zero through 2022...however, the bottom dropped out of oil prices on Thursday, as they tumbled more than 10% at one point amid a broader market selloff as fears over second wave of coronavirus cases hit the market and finished $3.26, or 8% lower at $36.34 a barrel after Reuters reported U.S. coronavirus cases had surpassed 2 million, renewing concerns about a new wave of demand destruction...prices continued falling on Friday and were down more than 5% to $34.48 early in the session, but staged a gradual recovery the remainder of the day to finish just 8 cents lower at $36.26 a barrel....still, for the week, prices were down more than 8%, posting their worst week since the week ending April 24th...
natural gas prices also finished lower this week, largely on milder weather that reduced demand for air conditioning....after falling 3.6% lower to $1.782 per mmBTU on lower LNG exports last week, the contract price of natural gas for July delivery edged up seven-tenths of a cent on Monday as a slowdown in natural gas output offset forecasts for lower air conditioning demand and a drop in LNG exports...milder weather and lower LNG exports pushed prices 2.2 cents lower Tuesday, but they moved back up 1.3 cents on Wednesday despite those lower demand concerns on another report of slowing output.... natural gas prices climbed another 3.3 cents to $1.813 mmBTU on Thursday as the weekly natural gas storage report met traders expectations, but then fell 8.2 cents, or 4.5% on Friday to a two-week low of $1.731 per mmBTU, on forecasts for milder weather and weaker cooling demand, and declining LNG exports, thus ending the week 2.9% below the prior Friday's close..
the natural gas storage report from the EIA for the week ending June 5th indicated that the quantity of natural gas held in underground storage in the US rose by 93 billion cubic feet to 2,807 billion cubic feet by the end of the week, which left our gas supplies 748 billion cubic feet, or 36.3% higher than the 2,059 billion cubic feet that were in storage on June 5th of last year, and 421 billion cubic feet, or 17.6% above the five-year average of 2,386 billion cubic feet of natural gas that has been in storage as of the 5th of June in recent years....the 93 billion cubic feet that were added to US natural gas storage this week was just below the consensus forecast from S&P Global Platts' survey of analysts calling for a 95 billion cubic feet increase, while it was near the average of 94 billion cubic feet of natural gas that have been added to natural gas storage during the same week over the past 5 years, but it was well below the 107 billion cubic feet addition of natural gas to storage during the corresponding week of 2019...
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending June 5th showed that due to an increase our oil imports and a decrease in our oil exports, we had surplus oil to add to our stored commercial supplies of crude oil for the 2nd time in five weeks, and for the 28th time in the past thirty-nine weeks....our imports of crude oil rose by an average of 685,000 barrels per day to an average of 6,864,000 barrels per day, after falling by an average of 1,021,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 355,000 barrels per day to an average of 2,439,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 4,425,000 barrels of per day during the week ending June 5th, 1,040,000 more barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells fell by 100,000 barrels per day to 11,100,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 15,525,000 barrels per day during this reporting week..
meanwhile, US oil refineries reported they were processing 13,484,000 barrels of crude per day during the week ending June 5th, 178,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a net of 1,134,000 barrels of oil per day were being added to the supplies of oil stored in the US....so based on that reported & estimated data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 906,000 barrels per day more than what was added to storage plus what our oil refineries reported they used during the week....to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (-906,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed...however, since the media usually treats these weekly EIA figures as gospel and since these figures often drive oil pricing and hence decisions to drill for oil, we'll continue to report them as is, just as they're watched & believed as accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,630,000 barrels per day last week, which was still 13.3% less than the 7,336,000 barrel per day average that we were importing over the same four-week period last year....the 1,134,000 barrel per day net addition to our total crude inventories included 317,000 barrels per day that were added to our Strategic Petroleum Reserve, and 817,000 barrels per day that were being added to our commercially available stocks of crude oil ....this week's crude oil production was reported to be down by 100,000 barrels per day to 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was down by 100,000 barrels per day to 10,700,000 barrels per day, while a 20,000 barrel per day decrease in Alaska's oil production to 360,000 barrels per day was not enough to have an impact on the rounded national total....last year's US crude oil production for the week ending June 7th was rounded to 12,300,000 barrels per day, so this reporting week's rounded oil production figure was about 9.8% below that of a year ago, yet still 31.7% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
meanwhile, US oil refineries were operating at 73.1% of their capacity while using 13,484,000 barrels of crude per day during the week ending June 5th, up from 71.8% of capacity during the prior week, but still among the lowest refinery utilization rates of the last thirty years...hence, the 13,484,000 barrels per day of oil that were refined this week were still 21.0% fewer barrels than the 17,064,000 barrels of crude that were being processed daily during the week ending June 7th, 2019, when US refineries were operating at 93.2% of capacity....
with the increase in the amount of oil being refined, gasoline output from our refineries was also higher, increasing by 360,000 barrels per day to 8,139,000 barrels per day during the week ending June 5th, after our refineries' gasoline output had increased by 608,000 barrels per day over the prior week... however, since our gasoline production is still rebounding from a multi-year low, this week's gasoline output was still 20.8% lower than the 10,276,000 barrels of gasoline that were being produced daily over the same week of last year....meanwhile, our refineries' production of distillate fuels (diesel fuel and heat oil) increased by 48,000 barrels per day to 4,762,000 barrels per day, after our distillates output had decreased by 66,000 barrels per day over the prior week...but even after this week's increase in distillates output, our distillates' production was still 9.1% less than the 5,239,000 barrels of distillates per day that were being produced during the week ending June 7th, 2019....
with the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 3rd time in 7 weeks and for the 7th time in 19 weeks, rising by 866,000 barrels to 258,661,000 barrels during the week ending June 5th, after our gasoline supplies had increased by 2,795,000 barrels over the prior week...our gasoline supplies increased by less this week than last because the amount of gasoline supplied to US markets increased by 351,000 barrels per day to 7,900,000 barrels per day, and because our imports of gasoline fell by 153,000 barrels per day to 629,000 barrels per day, while our exports of gasoline rose by 45,000 barrels per day to 308,000 barrels per day....with this week's inventory increase, our gasoline supplies were 10.1% higher than last June 7th's gasoline inventories of 234,913,000 barrels, and roughly 11% above the five year average of our gasoline supplies for this time of the year...
with the increase in our distillates production, our supplies of distillate fuels increased for the tenth time in 21 weeks and for the 15th time in 36 weeks, rising by 1,568,000 barrels to 175,829,000 barrels during the week ending June 5th, after our distillates supplies had increased by 9,934,000 barrels over the prior week....our distillates supplies rose by much less this week than last because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 584,000 barrels per day to 3,302,000 barrels per day, and because our exports of distillates rose by 673,000 barrels per day to 1,413,000 barrels per day, while our imports of distillates rose by 14,000 barrels per day to 177,000 barrels per day....after this week's inventory increase, our distillate supplies at the end of the week were 37.0% above the 128,372,000 barrels of distillates that we had stored on June 7th, 2019, and about 29% above the five year average of distillates stocks for this time of the year...
finally, with the jump in our oil imports and the drop in our exports, our commercial supplies of crude oil in storage rose for the 17th time in twenty weeks and for the 32nd time in the past 52 weeks, increasing by 5,720,000 barrels, from 532,345,000 barrels on May 29th to an all time high of 538,065,000 barrels on June 5th...that meant our our commercial crude oil inventories were around 14% above the five-year average of crude oil supplies for this time of year, and 52.3% above the prior 5 year (2010 - 2014) average of our crude oil stocks for the first week of June, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first rose above 400 million barrels and continued rising....since our crude oil inventories have generally been rising over the past year and a half, except for during this past summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of June 5th were 10.8% above the 485,470,000 barrels of oil we had in commercial storage on June 7th of 2019, 24.4% above the 432,441,000 barrels of oil that we had in storage on June 8th of 2018, and 5.2% above the 511,546,000 barrels of oil we had in commercial storage on June 9th of 2017...
furthermore, if we check the total of our commercial oil supplies and the stockpiles of all the refined product made from oil, we find those supplies have increased by 9,709,000 barrels this week to a record high of 1,439,638,000 barrels, 9.7% more than the 1,312,314,000 barrel total of the same week a year ago...
This Week's Rig Count
the US rig count fell for the 14th week in a row during the week ending June 12th, and is now down by 64.8% over that fourteen week period....Baker Hughes reported that the total count of rotary rigs running in the US decreased by 5 rigs to 279 rigs this past week, which was the fewest rigs deployed in Baker Hughes records going back to 1940 and 125 fewer rigs than the prior all time low, also down by 690 rigs from the 969 rigs that were in use as of the June 14th report of 2019, and 1,640 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....
the number of rigs drilling for oil decreased by 7 rigs to 199 oil rigs this week, after falling by 16 oil rigs the prior week, leaving oil rig activity at its lowest since June 19, 2009, which was also 589 fewer oil rigs than were running a year ago, and less than an eighth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations rose by 2 to 78 natural gas rigs, which was still down by 103 natural gas rigs from the 181 natural gas rigs that were drilling a year ago, and still less than a twentieth of modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, two rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, and one in Lake County, California... a year ago, there were no such "miscellaneous" rigs deployed..
the Gulf of Mexico rig count was unchanged at 13 rigs this week, with all of those Gulf rigs drilling for oil in Louisiana's offshore waters...that's now 11 fewer rigs than the 24 rigs drilling in the Gulf a year ago, when 22 rigs were drilling offshore from Louisiana and two rigs were operating in Texas waters...there are no rigs operating off other US shores at this time, nor were there a year ago, so the Gulf of Mexico rig count is equal to the national rig count, just as it has been since the onset of this past winter...
the count of active horizontal drilling rigs decreased by 7 rigs to 246 horizontal rigs this week, which was the fewest horizontal rigs active since February 10th, 2006, and hence is a new 14 year low for horizontal drilling...it was also 606 fewer horizontal rigs than the 852 horizontal rigs that were in use in the US on June 14th of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, the directional rig count decreased by 2 to 22 directional rigs this week, and those were also down by 46 from the 68 directional rigs that were operating during the same week of last year...on the other hand, the vertical rig count rose by 4 rigs to 11 vertical rigs this week, but those were still down by 38 from the 49 vertical rigs that were in use on June 14th of 2019....
the details on this week's changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes...the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of June 12th, the second column shows the change in the number of working rigs between last week's count (June 5th) and this week's (June 12th) count, the third column shows last week's June 5th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 14th of June, 2019...
the net of the basin totals shown above is a decrease of 4 rigs, so to have had 7 horizontal rigs removed nationally this week, 3 more horizontal rigs would have had to have been shut down in other basins not tracked separately by Baker Hughes....checking the rig counts in the Texas part of Permian basin, we find that 4 rigs were pulled out of Texas Oil District 8, or the core Permian Delaware, while a rig was added in Texas Oil District 7C, or the southern Permian Midland, at the same time...since the overall Permian rig total was down by 4 rigs, that means that one rigs that was shut down in New Mexico would have been drilling in the western Permian Delaware, and the other had likely been drillng in one of those "other" New Mexico basins not tracked by Baker Hughes, such as the San Juan....elsewhere in Texas, one rig was pulled out of Texas Oil District 1, while a rig was added in Texas Oil District 2, which could represent activity in the Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and touches on both of those Oil Districts...in addition, two rigs started drilling in Texas Oil District 6, which accounts for the 2 rig increase in the Haynesville shale, since the northern Louisiana rig count remained unchanged at 21, while a rig was pulled out of Texas Oil District 10, which would account for the Granite Wash removal...elsewhere, the rig pulled out of North Dakota was the Williston basin rig, but the Oklahoma rig reduction is not accounted for in the basin table and hence it must have been operating in one of those "other basins" not tracked separately by Baker Hughes...the 2 rigs added in the Haynesville this week account for the week's natural gas rig increase, and while two natural gas rigs were also added in Pennsylania's Marcellus, they were offset the removal of two natural gas rigs from West Virginia's Marcellus at the same time...
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CNX to ease production shut-in in Appalachian Basin -- CNX Resources has shut-in 375 million cubic feet per day of natural gas production in the Appalachian Basin, in the wake of the coronavirus pandemic and low commodity prices, Kallanish Energy reports. The volume of natural gas shut-in is expected to decline to about 300 MMcf per day by July, said the company. The company, with headquarters in Pittsburgh, Pennsylvania, said it would adjust as conditions warrant. Shutting-in production began May 1, it said. That action It will result in more than $30 million in incremental free cash flow over the next few years, assuming the wells are turned back online by Nov. 1 and using current forward strip pricing will allow the company to advantage of the large positive spread between summer and winter natural gas prices, CNX said in a statement. It said it has monetized hedges in summer 2020 and added new hedges in winter which locked in a significant portion of the free cash flow improvement. CNX said it saved $2.4 million on diesel fuel costs at the eight-well Marcellus Shale pad, RHL 99, in southwest Pennsylvania. That savings came from contractor Evolution Well Services’ electric fracking fleet using 140,000 Mcf of natural gas to power the fleet in lieu of diesel. It also reported that it drilled two Utica Shales in southwest Pennsylvania at a record high pace and record low cost. The costs decreased from $957 per foot to $447 per foot, or a drop of 53%, with drilling times decreased by 22%, it said. It said the total wells costs for those two Utica wells to be about $1,375 per lateral foot, far below the $1,800 per foot assumed in the company’s plans. It also reported that it has drilled its most successful Utica well, the Bell Point 6, in Central Pennsylvania. Its estimated ultimate recovery is estimated to be 4.5-5.0 Bcfe per thousand feet. The company has about 100,000 acres in its Central Pennsylvania Utica and that area holds great future promise, the company said. The company also reported significant midstream build-out in 1Q 2020 in southwest Pennsylvania’s Marcellus Shale area.
House Speaker Turzai Accepted $11K Flight From Businessman With Fracking-Related Companies -Pennsylvania House Speaker Mike Turzai, an outspoken advocate for the state’s fossil fuel industry, accepted an $11,000 plane ride last year from a Pittsburgh-area businessman involved in two fracking-related companies.In an ethics disclosure, Turzai said he gave a scheduled speech to the Shale Insight Conference in Pittsburgh at 9 a.m. on Oct. 23, but had to make it back to Harrisburg, a four-hour drive, to gavel in the state House at 11 a.m.There were no commercial flights in that time frame, the disclosure said. “Thus so, he had to secure a private flight.”The disclosure said the price for the flight, $10,988.44, was higher than normal because President Donald Trump traveled to Pittsburgh that day to speak at the same shale industry conference. The price was “a result of the security and other logistical concerns related to the arrival of the President that day.” Stephen Frobouck, who paid for the flight, said he made the offer while talking to Turzai’s staff about having the Speaker visit a liquid fuels facility Frobouck is planning to build in Westmoreland County. Frobouck co-founded Reserved Environmental Services, which operates a fracking wastewater treatment plant at the site in New Stanton, Pa., and is president and CEO of another gas-related venture, American GTL, which hopes to create liquid fuel from Marcellus shale gas at the site.
Marcellus LNG Firm Sees Permian and Bakken Opportunities --EXCO Resources has selected Edge Gathering Virtual Pipelines 2 LLC (Edge LNG) to capture and liquefy natural gas from a stranded well in the Marcellus Shale, Edge LNG reported Wednesday.“We are proud to be expanding our footprint in the Marcellus, which we’ve identified as an important region given its large number of stranded wells,” Edge LNG CEO Mark Casaday commented in a written statement emailed to Rigzone. In its deal with EXCO, Edge LNG will deploy its mobile, truck-delivered LNG equipment to the Marcellus site. The firm stated the equipment includes three trailer-based “Cryobox” liquefaction units. It explained the process – created by Galileo Global Technologies and deployed exclusively by Edge LNG in North America – requires minimal investment from the site owner and can be delivered to any site with road access. It also noted the process can start producing LNG within hours and needs no pipeline infrastructure.Under the agreement, Edge LNG will produce the LNG and purchase it from EXCO. The firm noted that it will then sell the LNG and deliver it to customers through its truck-based “virtual pipeline,” providing the fuel for homes and businesses in the Northeast. Each Cryobox unit can convert 1 million British thermal units of gas per day into approximately 10,000 gallons of LNG during the period, the company maintains. “We have a lot of interesting projects underway and we expect to have our technology deployed and producing LNG in the Permian and the Bakken, in addition to the Marcellus, before the end of this year. The environmental and cost efficiencies the Edge LNG solution can bring are considerable and it is great to see producers recognizing this.”
Delaware River Basin Commission faces pressure to reject PennEast pipeline - The PennEast pipeline fight has now entered a new phase, but its old foes — environmentalists and residents from both sides of the Delaware River — are still ready for battle. At the Delaware River Basin Commission’s first virtual session since the coronavirus shutdown began — a second-quarter business meeting open to the public Wednesday morning — the panel covered a report on hydrologic conditions, a COVID-19-related budget resolution, and more. But for environmental advocates and leaders, the topic of the day was a request by PennEast to construct a natural gas line across dozens of waterways and beneath the Delaware River. The $1 billion project would carry Marcellus Shale gas 116 miles from Luzerne County, Pa., to Mercer County, NJ. For an hour after the meeting officially adjourned, public commenters decried the pipeline project and called for the DRBC to reject it. Nearly 20 speakers from the Delaware Riverkeeper Network, the New Jersey Sierra Club, the Clean Air Council, and the New Jersey Forest Services, as well as local residents and a retired Lehigh University chemistry professor, spoke about the environmental threat of pipeline construction and requested a more robust review process. “The decision you render on PennEast is setting the precedent for all future pipelines that pass through the Delaware River watershed,” Maya K. van Rossum, leader of the Delaware Riverkeeper Network, told the commission. The DRBC’s listening session was just the latest episode of public outcry over the PennEast pipeline, which has been pushing for approval for nearly six years. The interstate pipeline gained approval from the Federal Energy Regulatory Commission, as well as Pennsylvania, but ran into trouble with New Jersey regulators. PennEast, a group of five energy corporations, now proposes to build the gas pipeline in two sections, or phases: one in Pennsylvania, and one in New Jersey.
A Powerful Petrochemical Lobbying Group Advanced Anti-Protest Legislation in the Midst of the Pandemic - ONE DAY AFTER West Virginia Gov. Jim Justice’s shelter-in-place orders went into effect, the governor quietly signed into law the Critical Infrastructure Protection Act. In the midst of the coronavirus pandemic, the law created new felony penalties for protest actions targeting oil and gas facilities, as the state continues to confront opposition to two massive natural gas pipelines designed to cut through delicate forests, streams, and farmland. Now, a person who trespasses on a West Virginia property containing “critical infrastructure” with the intention of defacing or inhibiting operations could face a felony charge carrying up to three years in prison and a $3,000 fine. The law creates another new felony and fines of up to $20,000 for any person or organization that conspires with someone to deface or vandalize such properties. “Critical infrastructure” is defined as an array of oil and gas facilities including petroleum refineries, compressor stations, liquid natural gas terminals, and pipelines. West Virginia’s critical infrastructure law mimics a model policy promoted by the American Legislative Exchange Council, known as ALEC, a shadowy group that encourages state lawmakers to pass industry-friendly legislation. Records provided to The Intercept by the Energy and Policy Institute reveal the natural gas industry’s hand in advancing the bill. A network of local lobbyists for Dominion Energy, which owns the Atlantic Coast pipeline; the West Virginia Oil and Natural Gas Association; and the American Fuel and Petrochemical Manufacturers, an industry group representing the refineries and processing plants that are the final destinations for the natural gas pipelines, spent months working behind the scenes to ensure the bill’s passage. West Virginia isn’t the only state to advance such anti-protest measures in the midst of the pandemic. Andy Beshear, Kentucky’s Democratic governor, who has been widely praised for his response to Covid-19,signed a similar critical infrastructure law on March 16, and South Dakota’s governor signed another on March 30. Alabama’s bill passed the state Senate on March 12 and is currently being considered by the House;Mississippi’s passed the House on March 4 and awaits action from the Senate. Particularly striking is a new amendment to Louisiana’s existing critical infrastructure law, now awaiting the governor’s signature, which would prescribe up to 15 years’ imprisonment for entering a critical infrastructure property without authorization during a state of emergency.
During construction hiatus, MVP changes plans for Roanoke River crossing - Builders of the Mountain Valley Pipeline can bore under the Roanoke River to set the pipe at that location instead of an earlier plan to dam the water and dig a trench, energy regulators say. Mountain Valley cannot currently undertake the river crossing in eastern Montgomery County, however, because of a lack of federal authorizations. Construction began in 2018 but has been on hold since fall. On May 20, Mountain Valley asked the Federal Energy Regulatory Commission for approval to change methods for its planned crossing of one of the region’s major rivers. Its application described the creation of pits on opposite sides of the river where the pipeline route and river intersect in Lafayette. One pit would be nearly 31 feet deep, the other nearly 22 feet. A crew would bore horizontally 316 feet and install the 42-inch pipe directly behind the boring machine, passing at least 6 feet beneath the river bottom, the application said. The project could be completed in 90 days, the filing said. Mountain Valley spokeswoman Natalie Cox, asked for the company’s reason for the change, said variances to use boring “for specific crossings” would allow Mountain Valley to “complete final restoration work for larger sections” of the pipeline’s right of way. In giving its consent May 27, FERC said the decision to bore rather than block the river and lay pipe in a trench “will result in a reduction in impacts on aquatic resources by avoiding impacts to the stream bank and channel.” The earth in that location is dominated by shale and limestone with a high percentage of gravel and cobbles, conditions that will require the application of clay solution to lubricate the cutting process, the application said. MVP plans to obtain 500,000 gallons of water from a municipal source and not use river water. MVP said it “does not anticipate conditions” that would cause drilling fluids to be released into the environment. The drilling fluid was described in the application as non-petroleum based, non-hazardous and “non-toxic to fish” at the low concentrations contemplated by MVP’s plan, the application said. David Sligh, a former senior engineer with the Virginia Department of Environmental Quality, warned that the fluid could leak out and damage aquatic life. Environmental safety depends on MVP complying with its plan and government rules, but “MVP’s atrocious record of noncompliance in VA and WV provides no assurance that this will happen,” according to an email written by Sligh, conservation director at Wild Virginia, a litigant in legal challenges designed to stop the project.
EQM Midstream Nears Mountain Valley Pipeline Completion -- EQM Midstream Partners, LP’s EQM Mountain Valley Pipeline project work is around 92% complete. The 303-mile natural gas transmission line is now expected to come online by early 2021. The project has faced delays and cost adjustments due to additional regulatory reviews. The pipeline is expected to meet the rising demand for natural gas in the mid-Atlantic and southeast regions of the country from Marcellus and Utica shale output. The project is waiting for the Biological Opinion and a green signal from the FERC. The project cost is expected to further rise 5% from its present estimate of $5.4 billion. Construction of the pipeline had started in February 2018, with original project cost estimation of $3.5 billion. The long-delayed pipeline’s three compressor stations and three original certificated interconnects are fully complete. Notably, 80% of the pipeline is completed by EQM Midstream that incorporates 264 miles of pipe welding and other major completions. The interstate underground pipeline system connects northwestern West Virginia with southern Virginia. EQM Midstream is the operator of the project with a 45.7% stake. It has NextEra Capital Holdings, Con Edison Transmission, WGL Midstream and RGC Midstream as partners in the project.
Pipeline projects draw criticism for ‘environmental racism’ -- Virginians calling in to the State Corporation Commission on May 12 pulled few punches: “environmental racism,” “sacrifice zone,” an “unfair and unjust project.” Many struggled to get through, repeatedly dropped from the call-in queue for public comment by technical glitches. But they kept calling back, hammering against a proposal to install yet more natural gas infrastructure in the state — 24 miles of 30-inch pipe, three compressor stations and two large gas plants. The $346 million Header Improvement Project (HIP) proposed by Virginia Natural Gas would impact neighborhoods in the city of Chesapeake and several counties — Fauquier, Prince William, Hanover, New Kent, Caroline and Charles City — as well as about 68 streams and rivers, 150 acres of wetlands and 313 acres of forest. It would particularly impact majority-minority communities where residents claim they’re sidelined in the decision-making. They want to know why the infrastructure is being foisted on them and what health and environmental repercussions would be visited on their families because of it. This is the essence of environmental justice, a concept that grew from activism in the 1960s and gained its name in the 1980s. Environmental justice is now at the heart of debates over how pollution, climate change and environmental hazards disproportionately impact the vulnerable and the voiceless. Recent actions in Virginia have emphasized environmental justice, too. In March, Gov. Ralph Northam established a permanent advisory Council on Environmental Justice, and in January a federal appeals court tossed out an air permit to build a compressor station in Union Hill, a historic African-American community in Buckingham County founded by freedmen and freedwomen after the Civil War. Now in the fight over the HIP, the SCC heard the public testimony as well as an evidentiary hearing for industry representatives the next day.Because of the technical difficulties during the hearing, though — held virtually because of COVID-19 restrictions — the SCC extended the public comment period and will schedule another virtual public hearing.
FERC prohibits pipeline construction, allows land seizures as court weighs 'legal purgatory' of rehearing delays - Federal regulators, under scrutiny from the D.C. Circuit Court of Appeals, issued an order Wednesday prohibiting natural gas pipeline developers from beginning construction on a project until regulators act on rehearing requests. The order addresses in part issues raised during the court's April en banc hearing in Allegheny Defense Project v. FERC. The case centers on the Federal Energy Regulatory Commission's (FERC) practice of continuously delaying requests for rehearing under the Natural Gas Act. Petitioners argued in part that the commission has been delaying requests for rehearing indefinitely, while allowing construction on controversial pipeline projects to proceed.FERC Commissioner Richard Glick dissented in part to the order. Though the order is "a step in the right direction," it does not address the concern that pipeline developers can still begin to condemn private land before the landowner is able to challenge the developer's ability to do so, he said. Language in the Federal Power Act (FPA) and the Natural Gas Act (NGA) prevents litigation on an order until the commission makes a ruling on requests for rehearing, but FERC is able to delay those requests through tolling orders. Critics say the practice has led to a legal "purgatory" of opposition to critical orders on wholesale power markets, and favors pipeline developers by allowing projects to move forward dispute despite legal challenges. "Tolling is a Kafkaesque process that should have no place in how FERC operates. It makes no sense to allow land to be seized and construction to proceed before a FERC decision can be challenged in court," John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council, told Utility Dive in an email.Though the Allegheny case focuses on the NGA and pipeline construction in particular, advocates say a favorable interpretation of the gas law would likely lead to a change in policy on the FPA as well.FERC reasoned in its April defense that the commission needs to preserve its ability to address complex requests in longer timeframes if necessary, an argument backed by utility trade group Edison Electric Institute. "The rehearing process serves as a mechanism for the Commission to carefully consider the arguments presented, in order to resolve disputes or bring its expertise to bear on complex, technical matters before they are potentially presented to the courts," according to FERC. But in response to "the serious concerns posed by the possibility of construction proceeding prior to the completion of Commission review" FERC on Wednesday determined developers would not be able to proceed with construction while such a review is pending. "This rule ensures that construction of an approved natural gas project will not commence until the Commission has acted upon the merits of any request for rehearing, regardless of land ownership," the commission wrote in its order.
EPA Water Rule Won’t Speed Up New Oil, Gas Pipeline Projects - A new EPA water rule to curtail state vetoes won’t necessarily ease the path for new oil and gas interstate pipeline projects, energy analysts and lawyers say. They say this is partly due to the sharp decline in oil and gas linked to the coronavirus pandemic. But the hurdles also come from a federal court’s suspension of the Clean Water Act Nationwide Permit 12, or NWP 12, that would allow developers to dredge and fill wetlands and stream crossings in order to lay pipelines. Without a nationwide permit, pipeline builders have no choice to seek the more time-consuming and expensive individual Clean Water Act permits from the U.S. Army Corps of Engineers that apply to each water crossing. Forcing applicants to pursue individual permits—pending the outcome of a months-long Ninth Circuit review of the nationwide injunction—will increase costs and delays in project approvals, according to Sarah Peterman Bell, a Farella Braun + Martel LLP attorney said June 4. A year ago, the Environmental Protection Agency’s water quality certification rule, released June 1 (RIN: 2040-AF86), would have been welcome, said Larry Liebesman, a former Justice Department environmental lawyer. But with the suspension of Nationwide Permit 12, “everything is up in the air,” said Liebesman, now at the environmental and water permitting firm of Dawson & Associates.
Sentencing of utility behind 2018 Mass. gas explosions delayed over probation issue - The sentencing of a NiSource Inc-owned utility company linked to catastrophic gas explosions in Massachusetts in 2018 hit a snag on Monday after a federal judge questioned whether its plea deal called for a term of probation inconsistent with the law. Columbia Gas of Massachusetts had been set to be sentenced by a federal judge in Boston as part of a deal with the U.S. Justice Department in which it would pay a $53 million fine and NiSource would sell its Massachusetts operations. To read the full story on Westlaw Practitioner Insights, click here: bit.ly/2UppoSW
US Natural Gas Permitting in May Falls Most in Decade while Permian Suffers Largest Monthly Decline -The Permian Basin in May reported the largest monthly decline in oil and gas permits ever, down 47% from April, as applications by large-cap operators fell to their lowest levels in history, off by almost three-quarters, Evercore ISI said Tuesday. In Evercore’s monthly permit report covering U.S. activity across the country and in the Gulf of Mexico, analyst James West and his team said domestic activity plummeted to 1,072, off by 53% month/month and 63% year-to-date.Only 102 natural gas permits were issued in May, down by 40% from April and the “lowest count in a decade,” Evercore analysts said. The gas permit decline primarily came from the Marcellus Shale at 52, which was 41 fewer than in April. In the Utica Shale, only 14 permits were issued. The Haynesville Shale’s permit count dropped to 49, driven by a slowdown in Louisiana, down 34 from April, while activity in the Texas portion of the play was flat at 18.Year-to-date, natural gas permits totaled 986 at the end of May, off 47% year/year, driven lower by the Marcellus and the Haynesville Shale. The Marcellus is down 44% year/year at 409, with the Haynesville at 383, a decline of 31%.The sharpest declines were in the West Texas portion of the Permian by large-cap exploration and production (E&P) companies, as well as from lower activity in New Mexico’s Permian, where permitting fell by 125 from April.E&Ps also cut back in the Eagle Ford Shale of Texas, with permit filings at 43, down by 51 from April.The year-to-date oil permit count stood at 8,837 at the end of May, off 65% from a year ago, according to Evercore.While permitting fell back sharply in the Permian, it’s been no picnic in the Rockies, which has suffered the biggest decline since the start of the year. Permits stood at 1,174 through May, or 93% lower year/year. “The collapse in the year-to-date permit count is also related to the downward activity in the Permian,” off 29%, and in the Eagle Ford, down 49% since the end of December, analysts said.Permits granted to private operators represent the 45% of May’s total in the Bakken Shale, which contrasts with the Permian, where privates held around 34% of the applications.Meanwhile, permits for water disposal and well plugging have intensified, analysts sasid.In the Bakken Shale, injection well permits climbed from zero in April to three in May, while well plugging was up by one to 15. Plugging permits also rose month/month in the Haynesville to three from zero.Well plugging permits in Texas jumped to 1,893, up 361 month/month, while wells permitted for water disposal and brine were at seven, down by eight. Through May, year-to-date plugging permits totaled 132, down 59 year/year.
Despite LNG Worries, Natural Gas Futures Gain Ground on Increased Cooling Demand Outlook - Natural gas futures rallied early Wednesday and held in positive territory throughout the trading day on forecasts for a relatively hot June and expectations that rising temperatures will drive seasonally robust energy demand to power air conditioners.The July Nymex contract settled at $1.780/MMBtu, up 1.3 cents day/day. August rose seven-tenths of a cent to $1.870.NGI’s Spot Gas National Avg. rose 2.0 cents to $1.620. “We see a little more heat in today’s medium-range forecast,” said Bespoke Weather Services, noting that models showed higher temperatures taking hold next week.The firm expects a cooler period Friday through Tuesday in the eastern United States before more heat returns in the middle of next week, increasing the likelihood of greater gas-weighted degree day (GWDD) totals for June overall. The current month is “on pace to rival 2018 and 2016 for the highest June GWDD count since June 2011,” and that is “notable given the tendency for hotter summers over the last 10 to 15 years.” Genscape Inc. said Lower 48 power burns have ramped up since late May “as summer begins in earnest.” The firm said burns breached 35 Bcf/d on June 3 and then did so again Tuesday and Wednesday. Though temperatures have fluctuated in some regions this month, cooling degree days (CDD) are expected to increase up to 3.7 average CDDs above normal between June 19 and June 22, Genscape said. By extension, it expects power burns to exceed 37 Bcf/d for the first time on June 18 and sustain that level on ensuing days. On the storage front, EBW Analytics Group said Thursday’s report from the Energy Information Administration (EIA) “could be important” since it may provide “more insight into how the supply/demand balance is shifting at a time when supply and demand are both in flux.” A lower-than-expected build for the week ended June 5 could signal increased industrial demand as factories formerly idled amid the pandemic reopen and drive power usage. A Bloomberg poll of nine analysts found injection estimates ranging from 91 Bcf to 99 Bcf, with a median of 94 Bcf, on par with the five-year average. A Wall Street Journalsurvey produced an average of a 93 Bcf injection. NGI estimated a 96 Bcf build. Last year, the EIA recorded a 107 Bcf increase in storage for the similar week. On Tuesday, the EIA said in its latest Short-Term Energy Outlook that it expects gas demand to increase next winter while production eases, creating upward price momentum and resulting in Henry Hub spot prices averaging $3.08/MMBtu in 2021. Henry Hub prices this year, however, are expected to average just $2.04/MMBtu.
US working natural gas volumes in underground storage increase by 93 Bcf: EIA - — US natural gas storage inventories increased by 93 Bcf for the week ended June 5, the US Energy Information Administration reported June 11, as power burn demand offset continued declines in LNG export demand. The injection was just below an S&P Global Platts' survey of analysts calling for a 95 Bcf build. Responses to the survey ranged from injections of 84 Bcf to 106 Bcf. The injection measured below the 107 Bcf build reported during the same week a year ago and the five-year average build of 94 Bcf, according to EIA data. At 2.807 Tcf, storage volumes now stand 748 Bcf, or 36%, more than the year-ago level of 2.059 Tcf, and 421 Bcf, or 17.6%, more than the five-year average of 2.386 Tcf. The weekly injection total was the first below triple digits since mid-May. US balances trended tighter as small gains across all supply sectors outmatched gains in gas-fired power generation demand, according to S&P Global Platts Analytics data. Total supplies rose by 600 MMcf/d to average 90.9 Bcf/d over the period, led by a combined 300 MMcf/d increase in onshore and offshore production, as well as nominal gains in Canadian imports. Downstream, demand changes were mixed, as LNG feedgas demand continued to slide, falling 900 MMcf/d week on week. Power burn demand increased by 3.1 Bcf/d, lifting total US demand 2.2 Bcf/d higher overall. LNG feedgas demand started out 2020 setting record highs, nearing 9 Bcf/d, but the softened global demand picture has cut feedgas deliveries in half. After the onset of the coronavirus, Platts Analytics' forecast cut 3 Bcf/d of LNG exports between June and October. While exports have provided a new outlet for the abundance of US gas over the last few years, the uncertainty from LNG demand has reflected the trade-offs that come from bursting the North American natural gas bubble, which has opened up domestic markets to new levels of global volatility. The NYMEX Henry Hub July contract rose 1 cent to $1.79/MMBtu in trading following the release of the weekly storage report. Henry Hub balance-of-summer prices were trading mostly flat at an average of $1.90/MMBtu, while the winter strip softened slightly, dipping 1 cent to $2.80/MMBtu from November through March. The massive spreads between summer and winter will likely continue to encourage a high rate of storage injections through the balance of summer. Platts Analytics' supply-and-demand model currently expects an 85 Bcf injection for the week ending June 12, which would be in line with the five-year average. Lower production related to shut-ins in the Gulf of Mexico from Tropical Storm Cristobal looks to help balance supply and demand for the week in progress.
U.S. natgas up as output slows, despite weaker demand forecast - (Reuters) - U.S. natural gas futures rose on Thursday as output continues to slow despite forecasts for demand to decline, lower liquefied natural gas (LNG) exports and a weekly storage build in line with estimates. The U.S. Energy Information Administration (EIA) said utilities injected 93 billion cubic feet of gas into storage during the week ended June 5. That matched analysts' estimates in a Reuters poll and compares with an increase of 107 bcf during the same week last year and a five-year (2015-19) average build of 94 bcf for the period. Front-month gas futures rose 3.3 cents, or 1.9%, to settle at $1.813 per million British thermal units. Looking ahead, futures for the balance of 2020 and calendar 2021 were trading about 24% and 48% over the front month, respectively, on hopes the economy will snap back as state governments lift coronavirus-linked travel restrictions. Refinitiv said production in the Lower 48 U.S. states fell to an average of 88.5 billion cubic feet per day so far in June from a one-year low of 89.2 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With milder weather expected in mid-June, Refinitiv forecast U.S. demand, including exports, would slide from 82.6 bcfd this week to 79.6 bcfd next week. The amount of pipeline gas flowing to U.S. LNG export plants fell to an average of 4.2 bcfd (43% utilization) so far in June, down from an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Utilization was about 90% in 2019. U.S. LNG exports dropped in recent months as buyers canceled dozens of cargoes for the summer with U.S. gas prices trading mostly higher than in Europe since late April due to global demand destruction from the coronavirus and record-high European stockpiles.
US natgas fall to 2-week low on mild weather, falling LNG exports - US natural gas futures fell on Friday to a two-week low on forecasts for milder weather and weaker cooling demand than previously expected, and declining liquefied natural gas (LNG) exports. Front-month gas futures fell 8.2 cents, or 4.5%, to settle at $1.731 per million British thermal units, their lowest since May 27. Refinitiv said production in the Lower 48 US states fell to an average of 88.6 billion cubic feet per day in June from a one-year low of 89.2 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With milder weather expected in mid-June, Refinitiv forecast US demand, including exports, would slide from 82.5 bcfd this week to 79.1 bcfd next week before rising to 85.4 bcfd in two weeks as the weather warms again. The amount of pipeline gas flowing to US LNG export plants fell to an average of 4.1 bcfd (42% utilization) in June, down from an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Utilization was near 90% in 2019. US LNG exports dropped in recent months as buyers canceled dozens of cargoes for the summer with US gas prices trading mostly higher than in Europe since late April due to demand destruction from the coronavirus and record-high European stockpiles. Those higher US prices prompted some energy firms to send LNG to the United States for storage.
In brief: natural gas production in USA – Lexology (legal brief) In contrast to the oil sector, in which some companies are active in all segments, it is more common for companies in the natural gas sector to concentrate on two or three segments (eg, production and gathering or transmission and storage). Ownership of pipeline transportation capacity is separated from ownership of the natural gas transported via pipeline, although some Canadian producers also own pipelines that cross from Canada into the US. The federal government does not participate directly as a party in private natural gas production transactions. However, in fiscal year 2018, approximately 9 per cent of all natural gas and 6 per cent of natural gas liquids produced in the US occurred on federal or native lands. The federal government derives value for gas produced on federal lands through royalties, annual rentals and bonus payments. The Office of Natural Resources Revenue, an agency within the DoI, is responsible for the management of production revenues. Production on state lands is managed by the appropriate state agency. In addition, government agencies impose a variety of taxes and charges. For example, FERC is authorised to recoup its entire budget appropriation through the imposition of annual charges and filing fees. The relevant statutory and regulatory framework for natural gas exploration and production depends largely on whether the activity is conducted on federal, state or private lands, and whether it occurs onshore or offshore. Enforcement generally occurs through administrative processes with the right to seek court review.The BOEM and the BSEE oversee the management of the mineral resources generally located more than three miles from the coast on the outer continental shelf (OCS). The BOEM is responsible for managing development in an environmentally and economically responsible manner, and the BSEE is responsible for enforcing safety and environmental regulations. The DoI prepares a five-year programme that specifies the size, timing and the location of areas to be assessed for federal offshore natural gas leasing. Bids are usually solicited on the basis of a cash bonus and a royalty agreement, with the highest bidder awarded the lease. OCS leases contain decommissioning obligations requiring lessees to return the leased area to the legally required condition, and the BOEM requires lessees to post security to ensure the decommissioning and other lease obligations are met. Additionally, federal regulations require open access to OCS pipelines. The open access rule provides complaint procedures for shippers of oil and gas produced on federal leases on the OCS who believe that they have been denied open and non-discriminatory access to an OCS pipeline.
Trump’s New Clean Water Act Rules Could Affect Embattled Natural Gas Projects on Both Coasts -Just weeks after the state of New York cited climate change among its reasons for blocking a natural gas pipeline to be built beneath New York Harbor, the Trump administration finalized changes to federal regulations aimed at limiting states' ability to stop federally approved pipelines and other infrastructure under the Clean Water Act. The rule change, which Environmental Protection Agency administrator Andrew Wheeler signed on June 1, will restrict states and authorized tribes from citing anything other than a narrow pollution discharge when denying a permit to a federally approved infrastructure project, such as a pipeline or dam. The new rule will also limit the permitting process to a year for states and tribes, which would waive their rights to block a project if they exceeded that time limit. For years, Republicans supporting fossil fuel development have cried foul over states' use of the Clean Water Act's Section 401, which gave state and tribal governments broad authority to block federally approved infrastructure projects that threaten their waters. States like New York and Washington have in recent years used the authority under that section to block high-profile natural gas pipelines, coal terminals or other fossil fuel infrastructure—often in the name of larger environmental goals like tackling climate change. "Now you won't be able to use 401 in the future going forward citing climate change as the reason," Wheeler said in a press call announcing the changes, adding that no longer would states "hold the nation's energy infrastructure hostage." But the changes, which Wheeler first proposed in August 2019, have for months been condemned by environmentalists who see this as the latest move by the Trump administration to disregard environmental law and prop up the fossil fuel industry. State officials, including from New York, California and Washington, also lambasted the move, signaling that legal challenges are soon likely to follow. "With the stroke of a pen, EPA intends to handcuff Washington's ability to protect our waters, our environment and our communities," Laura Watson, director of the Washington State Department of Ecology, said in a statement. "It makes a mockery of the federal-state partnership that has protected our waters for nearly 50 years ... and it will not stand." Many environmental legal scholars see the new rule as highly problematic, going against a past Supreme Court decision and decades of deferring to states to enforce the Clean Water Act. Some believe the new rule could even encourage developers to revive past projects once thought dead.
Federal court upholds Enbridge's Great Lakes spill plans(AP) — Enbridge has produced legally acceptable plans for dealing with a potential spill from oil pipelines that cross a Michigan channel linking two of the Great Lakes, according to a federal appeals court.A panel of the 6th U.S. Circuit Court of Appeals last week overruled a district judge who had agreed with an environmental group that the pipeline company’s plans failed to adequately consider potential harm to fish and wildlife in the Straits of Mackinac.Enbridge, a Canadian company based in Calgary, Alberta, developed the strategy as required under the Clean Water Act in case of failure of its Line 5. The pipeline carries oil and natural gas liquids used in propane from Superior, Wisconsin, to Sarnia, Ontario. A four-mile (6.4 kilometer) segment divides into two pipes that lie across the bottom of the straits, which connect Lakes Huron and Michigan.Enbridge says the 67-year-old segment has never leaked and remains in good condition. But the company plans to build a replacement in a tunnel that would be drilled through bedrock beneath the straits. Michigan Gov. Gretchen Whitmer is a critic of Line 5, which state Attorney General Dana Nessel is seeking to shut down in a lawsuit pending in state court. The National Wildlife Federation sued, contending the agency failed to make sure that approving the plans would not jeopardize fish or wildlife listed under the Endangered Species Act.Nor did the agency prepare an environmental impact statement as required under the National Environmental Policy Act, the wildlife federation said.District Judge Mark Goldsmith in Detroit ordered the pipeline administration to comply with both laws.But in a 2-1 ruling last Friday, the federal appeals panel said the agency could not consider them because the Clean Water Act has specific criteria “by which to evaluate the ‘correctness’ of the plans.” The agency found that Enbridge had met those standards, Judges Amul Thapar and Joan Larsen wrote in their majority opinion. They primarily involve having enough personnel and equipment to respond to a worst-case discharge, as well as testing and drills.
Chesapeake Prepares To File Bankruptcy After Stock Surges 300% - How insane is this "market"? So insane that shale pioneer Chesapeake, which for weeks has been rumored to be on the verge of bankruptcy, exploded by over 300% from Friday's closing print of $25 to $84.75 after the close. Well, the daytrader gambler who bought at $84.75 after hours in hopes of finding an even greater idiot to sell to - such as Jerome Powell perhaps - will be disappointed because as Bloomberg reported shortly after the close, Chesapeake is preparing a bankruptcy filing that could hand control of the oil and gas company to its senior lenders, as in no value to existing equity, which as of the close on Thursday had a market cap of $684 million, an increase of over 425% in the past two days! The timing of these Bloomberg headlines is without doubt the best testament to the absolute idiocy that the moron in charge of the Marriner Eccles buildings has unleashed. According to the Bloomberg report, the shale driller which was once the largest American gas producer before things turned south, including the March 2016 suicide of founder Aubrey McClendon, owes about $9 billion in debt and is debating whether to skip interest payments due on June 15 and invoke a grace period while it talks with creditors. The company has also begun soliciting lenders to provide debtor-in-possession financing to fund its operations during bankruptcy, according to one of the people. The Oklahoma City-based producer is negotiating a restructuring support agreement that could see holders of its so-called FILO term loan take a majority of the equity in bankruptcy, the people said, who asked not to be identified discussing confidential matters. The support agreement remains fluid and the terms could change, the people said.
Chesapeake Energy, a Fracking Pioneer, Is Reeling - The New York Times — Shares of Chesapeake Energy, a pioneer in extracting natural gas from shale rock that came to be known for its excesses, including a scheme to suppress the price of oil and gas leases, went on a wild ride on Tuesday amid reports that it was preparing a bankruptcy filing. Trading was halted for more than three hours in the morning. After buying and selling resumed, the trading was quickly interrupted again by circuit breakers. The company’s shares closed just below $24 for a loss of about 66 percent for the day. Chesapeake’s successes at using hydraulic fracturing to produce gas helped convert the United States from a natural gas importer into a major global exporter. But the company overextended itself by amassing a large debt and has been struggling to survive over the last decade. It is the latest of more than a dozen heavily indebted oil and gas businesses to seek bankruptcy protection since the coronavirus pandemic took hold and Saudi Arabia and Russia flooded the global market with oil this spring. The company hired advisers to explore bankruptcy in recent months after reporting a loss of $8.3 billion in the first quarter, and said it had just $82 million in cash at the end of March. Chesapeake was forced to write down the value of oil and gas assets by roughly $8.5 billion this year. With $9.5 billion in debts at the end of last year, it has bond payments of $192 millions that are due in August. Under its swashbuckling former chief executive Aubrey McClendon, the company drilled across Texas, Oklahoma, Ohio, Wyoming and Louisiana, borrowing billions of dollars along the way. Mr. McClendon was audacious as he aggressively outbid competitors on land leases and explored widely in the early 2000s, although he also drilled many wells that disappointed investors. By 2011, he and others who followed in his footsteps produced a glut of natural gas that sent Chesapeake and other companies to the brink of collapse. But Mr. McClendon was also known to cut corners, which got him and his company in trouble. He was charged in 2016 with conspiring to suppress prices for oil and natural gas leases. The indictment said he had orchestrated a conspiracy in which two oil and gas companies colluded not to bid against each other for several leases in northwestern Oklahoma from late 2007 to early 2012.
IEEFA report: Texas oil producers burned through $749.9 million flaring gas in 2018 - Texas oil producers burned a record $749.9 million by flaring or venting unneeded natural gas into the air, according to a report released today by the Institute for Energy Economics and Financial Analysis (IEEFA). The Texas Railroad Commission, the chief industry regulator in the state, passed up the opportunity to curb flaring last month when it rejected a proposal to cut oil production by 20 percent. The 2-1 vote against taking action occurred even as oil and gas prices plunged because of oversupply conditions exacerbated by the coronavirus pandemic and a price war with Saudi Arabia and Russia. “The Railroad Commission failed to adopt production cuts and closed its eyes to the declining financial conditions of the oil and gas sector and its impact on the Texas economy,” said Tom Sanzillo, IEEFA Director of Finance and a co-author of the report. “Their decision was driven by looking in the rear-view mirror, and they are heading for a crash. The hard issues will haunt them going forward, but the commission is unwilling and unprepared to address them.” Reducing or eliminating flaring would help address oversupply issues that have plagued the oil and gas industry for years. Even so, the report found that the oil and gas regulator failed to fulfill its responsibilities on multiple fronts:
- The commission voted against curbing production, even though state law requires it to take prompt action when the supply of oil and gas exceeds reasonable demand.
- The commission is required to adopt rules and orders to “conserve and prevent the waste of gas,” yet has taken no action directly or indirectly that could reduce the wasteful flaring of gas.
- The commission’s failure to take action flies in the face of U.S. Supreme Court rulings ordering it to consider the impact of the oil industry on the entire state, especially the revenue that it produces for the state’s university, school, general revenue, transportation and rainy-day funds.
Flaring is only one of multiple problems troubling the industry. These troubles include low demand for existing reserves, high debt levels, declining credit ratings, bankruptcies, poor stock performances, market competition and the instability of state-owned enterprises. Removing waste from oil and gas production is not only a legal requirement; it’s also a profit-making proposal.
Natural gas supply from Oklahoma to Upper Midwest plummets over past month | S&P Global Platts— The massive drawdown in active rigs in Oklahoma's SCOOP/STACK plays has prompted pipeline flows out of the region to plummet over the past month, adding upward pressure to Midwest prices. Falling production receipts along the four largest pipelines running through Oklahoma has led to lower natural gas supply from the Midcon Producing region to reach Upper Midwest markets, according to S&P Global Platts Analytics data. Flows between Oklahoma and the Upper Midwest have averaged 2.6 Bcf/d over the past 30 days. This is down 1 Bcf/d from the 30 days prior. The declines are spread among Northern Natural Gas Pipeline, Panhandle Eastern Pipeline, Natural Gas Pipeline and ANR Pipeline. Northern Natural has seen some of the steepest drops. Falling receipts in both Oklahoma and Texas have lowered these flows, with Oklahoma taking slightly more of the losses. Receipts in Oklahoma fell 284 MMcf/d the past 30 days from the thirty days prior, more than the losses seen in Texas which fell 203 MMcf/d. Within Oklahoma, multiple delivery points appear to be splitting the losses, with none losing more than 74 MMcf/d. Texas, however, still provides the bulk of flows on the pipeline, with Texas receipts averaging 1.7 Bcf/d the past thirty days compared to Oklahoma's 78 MMcf/d. The falling supply has helped uplift regional prices. NGPL Midcon basis has averaged 9 cents/MMBtu behind Henry Hub over the last 30 days. That is up from minus 22 cents/MMbtu the thirty days prior. However, as receipts and flows return, this should once again weight down on Midwest prices, according to Platts Analytics. Panhandle Eastern has seen a 268 MMcf/d decline between the last 30 days and the 30 days prior. It is now averaging 589 MMcf/d. Here, however, falling Oklahoma receipts are contributing to virtually all of the declines. Receipts in Oklahoma have averaged 428 MMcf/d, down from 654 MMcf/d the thirty days prior. Receipts from Texas, however, only declined 55 MMcf/d during this time. NGPL has seen slightly lower declines. At Station 106 on the Kansas and Nebraska border flows have declined by 175 Mmcf/d. Again, the bulk of the drop has come from Oklahoma supply. Flows out of the Permian have remained relatively flat at around 350 MMcf/d, while Oklahoma receipts onto the pipeline across the state fell 322 MMcf/d, according to Platts Analytics. Lastly, ANR flows from the Midcon Producing to the Midcon Market have averaged 510 MMcf/d the past 30 days. This is down 146 MMcf/d from the 30 days prior.
Illinois rejects bid to delay decision on Dakota Access Pipeline expansion - (Reuters) - Illinois regulators on Thursday unanimously rejected a request by environmental groups to delay a decision on Energy Transfer LP’s Dakota Access Pipeline expansion due to the coronavirus pandemic. Save Our Illinois Land and Sierra Club, which oppose the expansion, told the Illinois Commerce Commission the oil price downturn caused by the pandemic lessened a need for the expansion, and that market data used to justify the project had become outdated. The ICC still must rule on Energy Transfer’s application to increase capacity on its 570,000 barrel-per-day (bpd) crude oil pipeline by adding a series of pumping stations. The project has received approvals from several other U.S. states. Measures to slow the spread of the coronavirus have cut global fuel demand as much as a third, knocking U.S. crude prices down nearly 40% since the start of the year and spurring widespread production cuts. The environmental groups asked the commission to delay a final decision on the expansion application and order a hearing to introduce new evidence related to oil market conditions. They also cited a recently ordered federal environmental review of a segment of the pipeline. Texas-based Energy Transfer countered that the pandemic’s impact on oil demand would be short-lived and not reduce the future need for the pumping facilities, which are expected to enter service in late 2021.
Cristobal makes USGC landfall as nearly 35% of Gulf crude comes offline | S&P Global Platts — Energy producers shut down almost 35% of the US Gulf of Mexico's crude oil production and more than 32% of natural gas supplies ahead of Tropical Storm Cristobal making a southern Louisiana landfall on June 7. More than 635,000 b/d of crude and 878 MMcf/d of gas were shut in ahead of Cristobal's move onshore, according to the US Bureau of Safety and Environmental Enforcement, as operators evacuated 188 platforms and rigs in the Gulf -- roughly 30% of the US Gulf's total platforms with working personnel. Cristobal battered southern Mexico and shut down ports over the past week, before moving through the Gulf and spreading heavy rainfall from Louisiana to Florida. The storm is hitting just as oil prices are moving up with the OPEC+ group agreeing to extend deeper production cuts at least through July and front-month NYMEX WTI flirting with hitting $40/b for the first time since early March. BP, Occidental Petroleum and other Gulf producers were busy temporarily shutting oil and gas production from their platforms that are near the path of the storm. Total Gulf oil production was nearly 2 million b/d before the coronavirus pandemic cratered global demand and oil prices. BSEE is now estimating Gulf oil production at closer to 1.85 million b/d. However, S&P Global Platts Analytics data estimates that Gulf crude oil production will fall to an estimated 1.62 million b/d average for June as some producers reduced their volumes because of lower prices. After Cristobal passes, offshore oil and gas facilities will be inspected and, once the standard checks are completed, production from undamaged facilities will be brought back online immediately, BSEE said. Facilities sustaining damage may take longer to bring back online. BP said June 3 it was reducing output at its Thunder Horse, Atlantis and Na Kika platforms. Those three BP-operated platforms churn out more than 200,000 boe/d. Royal Dutch Shell has evacuated nonessential workers but hadn't reduced production volumes as of early June 7. "There are currently no impacts to our production, and we expect minimal impacts to our drilling operations," Shell said in a prepared statement. The last major hurricane to significantly interrupt production from the US Gulf of Mexico was Barry, which made landfall last July. Barry caused the shut-in of close to 1.4 million b/d of crude oil, about 73% of the US Gulf crude output, according to BSEE. On a monthly basis, Barry caused US Gulf production to dip by about 330,000 b/d for the month.
Energy firms prepare to resume U.S. Gulf of Mexico output after storm passes - (Reuters) - Energy companies on Monday began preparations to resume oil and gas production in the U.S. Gulf of Mexico, a day after Tropical Storm Cristobal blew through with high winds and heavy rains. Producers had evacuated 182 offshore facilities and shut in about a third of oil and gas production in U.S. Gulf of Mexico wells as of Monday. Royal Dutch Shell Plc, Murphy Oil Corp and BP Plc were among the companies that said on Monday they were starting to resume normal operations and return workers to offshore facilities. Energy companies typically inspect platforms after a storm passes and return evacuated workers once it is safe to do so. U.S. Gulf Coast spot gasoline prices strengthened slightly on Monday, traders said, up 0.25 cent per gallon from Friday. Cristobal has weakened to a tropical depression after making landfall in Louisiana on Sunday with 50 mile-per-hour (80 kph)winds. It led producers to shut 34% of oil and 35% of gas output in the Gulf of Mexico, offshore regulator Bureau of Safety and Environmental Enforcement said. The region provides about 1.93 million bpd of oil. Exxon Mobil Corp, Shell and PBF Energy Inc kept their oil refineries in Louisiana in operation as Cristobal hit over the weekend, people familiar with the operations said. PBF declined to comment. Exxon and Shell were not immediately available to comment.
About 23% of US Gulf oil, gas still offline after Cristobal: BSEE | S&P Global Platts— About 23% of US oil and natural gas production from the Gulf of Mexico remained offline on June 10 after Tropical Storm Cristobal swept through the region during the weekend. Another 140,000 b/d of crude came back online from June 9 to June 10, according to daily updates from the US Bureau of Safety and Environmental Enforcement. Nearly 35% of the US Gulf production was shut-in in advance of the storm. After a peak of 635,781 b/d was shut in, BSEE said 435,767 b/d remained down on June 10, or 23.55% of total US Gulf oil production. BSEE decreased its gas shut-in estimate from 898 MMcf/d down to 619 MMcf/d, keeping 22.84% of the offshore gas volumes offline. BP, Occidental Petroleum and other producers that shuttered some volumes said they are working to resume operations and production volumes. Ahead of Cristobal's move onshore, BSEE said, operators evacuated 188 platforms and rigs in the US Gulf — roughly 30% of the region's total platforms with working personnel — and relocated several drillships. BSEE said 61 platforms remained evacuated on June 10. BP reduced output at its Thunder Horse, Atlantis and Na Kika platforms in the US Gulf. Those three BP-operated platforms churn out more than 200,000 boe/d. BP's Mad Dog platform was not affected. "BP has started to resume normal operations at its four operated platforms in the deepwater Gulf of Mexico," BP said in a June 8 statement, declining to give further updates. Others such as Royal Dutch Shell and Chevron said they had not reduced their US Gulf production volumes during the storm. Cristobal battered southern Mexico and shut down ports over the past week, before moving through the Gulf of Mexico and depositing heavy rainfall from Louisiana to Florida. The storm hit just as oil prices were moving up, with the OPEC+ group agreeing to extend deeper production cuts at least through July and front-month NYMEX WTI flirting with $40/b for the first time since early March. Total US Gulf oil production was nearly 2 million b/d before the coronavirus pandemic cratered global demand and oil prices. BSEE was estimating US Gulf oil production at closer to 1.85 million b/d before Cristobal.
Yearslong lull looms for Louisiana's energy sectors hit by economic slowdown, energy slump - A lull in industrial construction in Louisiana could stretch out several years with some proposed projects likely being postponed or even canceled because of the global economic slowdown and an energy sector slump that could affect producers in the years ahead. David Dismukes, who runs the LSU Center for Energy Studies, told business owners on a call hosted by the Baton Rouge Area Chamber that the outlook is not bright for energy producers and related industries at least until 2025. He said a lull in industrial construction that set in last year after the completion of numerous multibillion-dollar projects will continue until there is more demand for crude oil and petrochemical projects following the economic downturn triggered by the coronavirus pandemic. Dismukes estimates that only about $131 billion may come to fruition out of $195 billion of energy manufacturing and export capital investments that were expected to occur between 2019 and 2029 along the Gulf Coast. In Louisiana alone, during that same period, only about $82 billion of the $116 billion of projected investment is expected to be completed — a big portion of that tied to proposed liquefied natural gas terminals. Of the $88 billion in LNG investments anticipated, only about $55 billion in LNG projects might actually happen, Dismukes said, on top of $27.6 billion in other industrial projects expected to continue. The potential for more than a dozen large-scale LNG projects is much less likely — at least until 2025, he said. Buyers of LNG overseas have already canceled 20 tanker ship loads in June and July. It's expected that 125 tankers from the U.S. might be canceled by the end of the summer. "There's not enough need for natural gas globally; all the cargoes have slowed down pretty dramatically," Dismukes said. "The incremental (capital) investment in 2022 and 2025, that's probably not going to be the case now. I think you are going to see that a lot of these projects are getting canceled or having problems."
In Louisiana, Stepping onto Oil and Gas Industry Land May Soon Get You 3 Years or More in Prison --Sharon Lavigne has spent the last two years fighting a petrochemical complex planned near her community, in St. James, Louisiana. Over the last six months, the 68-year-old-retired teacher has walked onto the property to lay flowers on a burial site that may contain the remains of the slaves she's descended from, and recorded live-stream videos from the levee overlooking the land.But unless Gov. John Bel Edwards, a Democrat, vetoes a bill sitting on his desk this week, those acts could soon be punishable by a mandatory minimum sentence of three years in prison. The bill, which passed the state Legislature in May, amends existing law that already makes it a felony to trespass on "critical infrastructure," a list expanded two years ago to include oil and gas facilities, amid a fight over an oil pipeline that terminates in St. James. The new bill will expand the list to include flood control infrastructure, and further stiffen the penalties for trespassing to three to 15 years if the parish or state is under an emergency order. Louisiana is under multiple such orders, including one for the storm that just roared across the state, and another declared by Edwards in response to the coronavirus pandemic.The bill's author, state Rep. Jerome Zeringue, a Republican, said he introduced the legislation at the request of the Association of Levee Boards of Louisiana, "to put more teeth into current legislation." But civil libertarians and environmental advocates say the bill expands an already vague law that imposes unconstitutional constraints on the rights of residents like Lavigne, who have been fighting petrochemical infrastructure.
Formosa Plastics Opponents Ask Louisiana Governor to Veto Bill Over Harsh Sentencing Concerns | DeSmog -- On Friday, June 12, Louisiana's Democratic governor John Bel Edwards is expected to sign off on a piece of legislation, House Bill 197, that would make it a more serious crime to trespass on Louisiana's so-called “critical infrastructure,” including the state's system of flood-control levees, fossil fuel pipelines, and sprawling network of petrochemical plants and refineries. But if you ask Sharon Lavigne, founder of RISE St. James, a Louisiana community group, what House Bill 197 means to her, the answer that comes back isn’t about floodgates or water pumps or pipelines. It’s about the legacy of slavery in the United States — and how that legacy echoes in criminalization efforts today.“It means that I cannot go and visit the gravesites,” Lavigne told DeSmog on Wednesday, June 10, referring to recently discovered slave cemeteries on former plantations now owned by petrochemical giant Formosa. The Taiwanese company plans to build a massive plastics manufacturing site in St. James Parish where Lavigne lives. “I have to go on the property to go to the gravesite. That affects me because my ancestors are in that grave.”House Bill 197, which was approved by the state’s legislature and is slated for the governor to sign or veto by Friday, would transform some types of trespassing — generally a low-level violation that leads to a small fine — into a felony carrying a minimum sentence of between three and 15 years. And because that sentence would be a mandatory minimum, a judge would have no legal discretion to lower the penalty for anyone convicted under that law, even in the face of compelling extenuating circumstances.“Mandatory sentencing laws disproportionately affect people of color and, because of their severity, destroy families,” a Families Against Mandatory Minimums primer explains. A 2013 Yale Law Journal study found that prosecutors were twice as likely to charge Black defendants under statutes carrying mandatory minimum penalties as white defendants who committed similar crimes. The battle over House Bill 197 and more broadly, the Formosa plastic plant’s construction, touches not only on the legacy of enslavement in the United States, but also on environmental racism, the fossil fuel industry, and how impacted communities are policed and criminalized today. For foreign investors watching events play out, the battle also offers insight into risks associated with the petrochemical projects in the U.S., particularly given the petrochemical industry’s history of pollution both on the Gulf Coast and worldwide.
DNR to hold virtual hearing on Enbridge plans for oil pipeline through northern Wisconsin -- The Wisconsin Department of Natural Resources is planning a virtual public hearing on a Canadian company’s plans to reroute an oil pipeline around a Native American reservation in northern Wisconsin. As a result of a lawsuit filed by the Bad River Band of Lake Superior Chippewa Tribe, Enbridge Energy is planning to remove a 12-mile segment of its Line 5 pipeline from the Bad River Reservation and bypass the reservation with about 42 miles of new pipe. The DNR will hold a hearing at 4 p.m. July 1 -- accessible by telephone or through the online platform Zoom -- on Enbridge’s applications for permits to cross dozens of public waterways and fill wetlands and on the scope of the environmental impact review that will be required of the project. Construction of the proposed pipeline would affect 109 acres of wetlands, resulting in the conversion of 29.5 acres of wooded wetland to non-wooded wetland and the permanent loss of 0.06 acres. Enbridge would use trenching or dredging to install pipe under 87 public waterways and would need to temporarily bridge 185 waterways during construction.
EPA faces lawsuit alleging failure to update flaring requirements - A coalition of environmental groups is taking legal action against the Environmental Protection Agency (EPA) over the agency’s alleged failure to update requirements for an industrial process for burning pollutants. The groups alleged in a notice of intent to sue that the EPA has not updated its requirements for the process, called flaring, since 1986 despite a requirement to do so every eight years. Flaring is a process used in industries such as the oil and gas industry as well as the petrochemical industry in which companies attempt to burn waste gases, which can include some that can harm health and the environment. “The problem is that the current standards for flares are very outdated, they’re 34 years old at this point and they don’t look at certain things that are really necessary to make sure flares are operating properly,” Adam Kron, a lawyer on the case, told The Hill, adding that he would like to see improved monitoring requirements. Data from around the time that the 1986 flaring rule was put forth indicated that flares destroyed about 98 percent of pollutants. More recently, however, the agency found that ethylene flares only destroy about 90.4 percent. The lawyer said that one of the biggest health risks from exposure to flaring is respiratory issues.
Living Near Oil and Gas Wells Linked to Low Birthweight in Babies -Living near active oil and gas wells during pregnancy increases the risk of low-birthweight babies, especially in rural areas, according to the largest study of its kind.Researchers analyzed the records of nearly 3 million births in California to women living within 6.2 miles (10km) of at least one oil or gas well between 2006 and 2015. It is the first such study to look at birth outcomes in rural and urban areas, and to women living near active and inactive oil and gas sites.Proximity to a well and the level of production were found to be significantly associated with poor birth outcomes.Specifically, the study found that in rural areas, pregnant women residing within a mile (1km) of the highest producing wells were 40% more likely to have babies with low birthweights and 20% more likely to have babies who were small for their gestational age compared with people living farther away from wells or near inactive wells only.Even among full-term births, babies born to mothers living close to wells were on average 1.3 ounces (36 grams) smaller than those of their counterparts.Newborns are deemed to have low birthweight when they weigh less than 5lb and 8oz. It can lead to multiple short-term development issues as small babies often struggle to eat, gain weight and fight infections. Studies also suggest small- and low-birthweight babies are more likely to have medical conditions such as diabetes, hypertension, heart disease and intellectual and developmental disabilities in later life.About one in 12 babies in the US have a low birthweight.The study found a link between oil and gas wells and small babies born in urban areas, but it was significantly less marked than in rural communities. Differences in air quality, maternal occupation and housing conditions may have contributed to the urban-rural divide. The findings, published in the journal Environmental Health Perspectives, add to a growing body of evidence linking proximity to oil and gas wells to a variety of adverse birth outcomes, including premature birth, heart defects and low birthweight.
U.S. Oil Drillers Restart Production As Prices Recover - Shale drillers are bringing some shuttered oil production back online as the glut eases. The total amount of shut-in production in the Bakken stood at 475,000 bpd on May 28, a total that was 7 percent smaller than the week before, according to Bloomberg. A couple of high-profile shale companies voiced optimism at the start of June. EOG Resources said it plans to “accelerate” production in the second half of 2020, finding prevailing oil prices sufficient to step up drilling activity. The company also reduced its hedging exposure, a sign that the company is bullish about the trajectory of prices. In addition, in an investor presentation, Parsley Energy also said that it is bringing back the “vast majority” of its curtailed production in June. Parsley shut down around 400 wells in March. Oil prices have shot up from negative territory in April to the mid-$30s by early June. The extreme supply overhang has mostly been corrected by steep production cuts, aided by the bounce back in demand. The three-month slump and the near total halt drilling activity has ratcheted up the pressure on shale drillers. Debt has not gone away, so there is a need for cash flow. Drillers are clearly itchy to begin bringing output back online again. WTI rising to the mid-$30s may be just enough to entice oil back onto the market. “We see more evidence that the horizontal oil rig count is approaching the bottom of this down cycle,” Bjornar Tonhaugen, Head of Oil Markets at Rystad Energy, said in a statement. “However, what will determine the short term trajectory for US oil production is how quickly operators bring back parts of our estimated 1.65 million bpd of shut-in well production.” .
U.S. crude oil inventories increase by 5.7 million barrels - U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) increased by 5.7 million barrels from the previous week. At 538.1 million barrels, U.S. crude oil inventories are about 14% above the five year average for this time of year, according to the EIA crude oil and petroleum weekly storage data, reporting inventories as of June 5, 2020. U.S. crude oil refinery inputs averaged 13.5 million barrels per day during the week ending June 5, 2020, which was 178,000 thousand barrels per day more than the previous week’s average. Refineries operated at 73.1% of their operable capacity last week.
- Gasoline production increased last week, averaging 8.1 million barrels per day.
- Distillate fuel production increased last week, averaging 4.8 million barrels per day.
U.S. crude oil imports averaged 6.9 million barrels per day last week increased by 0.7 million barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.4 million barrels per day, 13.3% less than the same four-week period last year.Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 629,000 barrels per day, and distillate fuel imports averaged 177,000 barrels per day.
- Total motor gasoline inventories increased by 0.9 million barrels last week and are about 11% above the five year average for this time of year.
- Finished gasoline and blending components inventories both increased last week.
- Distillate fuel inventories increased by 1.6 million barrels last week and are about 29% above the five year average for this time of year.
- Propane/propylene inventories decreased by 1.0 million barrels last week and are about 6% above the five year average for this time of year.
- Total commercial petroleum inventories increased last week by 9.7 million barrels last week.
- Motor gasoline product supplied averaged 7.4 million barrels per day, down by 22.7% from the same period last year.
- Distillate fuel product supplied averaged 3.2 million barrels per day over the past four weeks, down by 18.1% from the same period last year.
- Jet fuel product supplied was down 63.8% compared with the same four-week period last year.
EIA Raises Oil Price Forecasts - The U.S. Energy Information Administration (EIA) has raised its oil price forecasts for 2020 and beyond, its latest short term energy outlook (STEO) report has revealed. The EIA now expects the Brent spot price to average $38.02 per barrel this year and $47.88 per barrel in 2021, according to its June STEO. Back in the EIA’s May STEO, the Brent spot price was expected to average $34.13 per barrel this year and $47.81 per barrel next year. West Texas Intermediate (WTI) spot prices are expected to average $35.14 per barrel in 2020 and $43.88 per barrel in 2021, the EIA’s June STEO shows. These prices were forecasted to average $30.10 per barrel this year and $43.31 per barrel next year in the EIA’s previous STEO. “The forecast of rising crude oil prices reflects expected declines in global oil inventories during the second half of 2020 and through 2021,” the EIA stated in its June STEO, which was released on Tuesday. “EIA expects high inventory levels and spare crude oil production capacity will limit upward price pressures in the coming months, but as inventories decline into 2021, those upward price pressures will increase,” the EIA added. The EIA now expects global oil inventories will begin declining in June, a month earlier than previously forecasted. The sooner than expected draws are the result of sharper declines in global oil production during June and higher global oil demand than previously expected, according to the EIA. Global oil inventories at the end of May stood 1.4 billion barrels higher than they were at the end of 2019, the EIA estimates.
What the Data Tells Us: US Oil Needs $70 Per Barrel to Sustain Operations Over the past three weeks, there has been some celebration as oil prices have “recovered” due to oil companies cutting production and some global demand beginning to return. This is normal. The low extremes of April have created a sense of hope in $30 territory. However, while an $70 per barrel gain—from -$37 to $33 per barrel—is great, we are nowhere near a price to sustain US operations. This is a harsh reality for some. I heard this said just last week, “At $50, we had 800 rigs running in the US, right? So if we can get back into the high 40’s, we should be close, right?”Wrong.The fact is, drilling rigs are a real-time indicator of activity. But they are not aleading indicator. For that, drilling permits are a better measure. Now, it is true that permits and drilling rigs do not always move perfectly in sync. But if they are off, it is usually because drilling rigs are being laid down but permits continue to be applied for. After all, it only costs a couple thousand dollars to get a drilling permit, so companies can easily continue to ask for them, even if they may wait a year to drill. In addition, one may not need a new permit if a well is being recompleted. That said, over the past five years, drilling permits have been a relatively consistent leading indicator of rig count and workload, although it can take 3 to 9 months for them to sync up. So, using public data for WTI price, rig count, and drilling permits from the Texas Railroad Commission, we can examine the trends prior to March of 2020 and the demand destruction of COVID-19 lockdown. In doing so, there is a striking correlation: The data PRIOR to coronavirus shows us that even $55 per barrel was going to lead to a downturn. This graph shows the levels correlated to prices: From March to October of 2019, WTI prices were trending up nicely, and averaging right at $69 per barrel. During that time and for a couple of following months, US and TX Rig count hung just above 1,000 and 500 respectively. After October of 2018, oil prices took a hit, but then popped back up in a few months and averaged $56 per barrel from June of 2019 to February of 2020. During this time, US rig count trended down and leveled off at 800, while TX rig count leveled off at 400. In short, an average price drop from $69 to $56 (19%), correlated to a 20% drop in rigs. And while the similarity in these numbers is coincidence, the overall trend makes sense.But now let’s examine drilling permit count. When oil prices averaged $69 per barrel, TX was issuing an average of 317 permits per week, and showing a slight downward trend. But after oil prices dropped, the trend down was substantial, and in the six-month period of Sept 19 to Feb 20, the permits leveled off and averaged 209 per week. Oil prices had lost 19%, rig count lost 20%, and permits dropped by 33%.Unfortunately, it appears that in order to sustain US production and keep people employed, we need to be issuing around 300 permits a week. And this data shows that is questionable, even at $70 per barrel. So, for the hundreds of companies hoping to avoid bankruptcy, and the tens of thousands of workers being furloughed, $35, $45, even $55 per barrel does not signify a return to production.
US Shale Faces Bankruptcy Wave Amid Long And Arduous Global Downturn - The US shale industry could be on the verge of destruction due to the drastic decline in demand and falling energy prices brought on by coronavirus pandemic, a new report says. The Institute for Economics and Peace (IEP) published its 14th edition of the Global Peace Index on Wednesday -- outlining how the virus-induced downturn of the energy market and a price war between Organization of the Petroleum Exporting Countries (OPEC) and Russia -- could result in a "collapse" of US shale."The sharp fall in oil prices will affect political regimes in the Middle East, especially in Saudi Arabia, Iraq and Iran, which may result in the collapse of the shale oil industry in the US, unless oil prices return to their prior levels," IEP warns.The report goes on to say "this global recession will be long and arduous," outlining how weakness in commercial, travel and industrial activity will persist for an extended period, indicating oil prices will remain subdued: "These markets were already effected by an over-supply, emanating from Russia and Saudi Arabia who could not agree on production curbs. On April 20 the price of crude oil turned negative for the first time in history, as seen in Figure 1.9. Demand had collapsed so rapidly that overstocked producers were willing to pay buyers to take away excess inventory. The negative price was a short-lived technicality, due to the way futures contracts are written; with oil prices soon returning to positive territory. Nevertheless, the unprecedented episode highlighted the severity of demand collapsing worldwide." Crude prices stabilized in April after OPEC+ agreed to production cuts. Last weekend, an extension of the 9.7 million barrels per day (bpd) cuts were seen through July. The cuts equal about 10% of global supply, which has led to a 172% rise in Brent crude futures over the last 33 trading sessions. Despite the extension in cuts, Brent crude prices have stalled in the 43-40 level, now at risk of reversing. The oil market only moved into deficit late May and still faces the daunting challenge of normalizing a billion barrels of excess inventories. Yet, the oil relief rally remains unfazed, with prices doubling and exceeding our year-end price target just six weeks after the likely cycles lows.
Report: Oil bust is catching up to pipeline companies - An oil and gas industry bust caused by the coronavirus pandemic is beginning to spill into the pipeline and storage tank business, a new report from New York credit rating firm Moody's shows.Moody's downgraded its outlook for the midstream sector, which includes pipeline and storage terminal operators, to negative from stable. The rating marks the first time that the firm has given a negative outlook for the midstream sector."Although midstream cash flow is largely insulated from the full brunt of commodity price and volumetric instability, the rapid pace and the magnitude of production declines have finally spilled into the midstream sector, compromising its aggregate credit quality," Moody's said. Record low oil prices caused by the pandemic and a price war between Russia and Saudi Arabia prompted producers to slash their budgets while oil field service companies laid off tens of thousands of people.The midstream sector put plans for several new pipeline projects on hold, but earnings largely had been insulated from the downturn as oil companies sought to move and store crude until higher prices return.Moody's now projects that oil production curtailments have been so sharp that pipeline and storage tank operators are expected to see earnings before income tax, depreciation and amortization fall by 5 percent this year.Crude oil pipeline operators are expected to feel the most pain while interstate natural gas pipelines operate with regulated, fee-based contracts have little price or volume risk, Moody's said.
CEOs Bank Big Bonuses As Oil Companies Go Bankrupt -When public oil and gas companies are doing relatively well, many are happy to adopt a pay-for-performance model to reward CEOs and executives. However, the tables are quickly turned when things go to the dogs. When these companies go bankrupt, the misery is shared by employees who lose their jobs; retirees see their benefits and pensions go up in smoke, while shareholders and bondholders get wiped out. In sharp contrast, it’s very common for blue-chip executives who have run their companies to the ground to receive multi-million dollar golden sendoffs. Indeed, top executives of oil and gas companies going through Chapter 11 frequently receive very fat payouts in the form of cash bonuses, stock grants, and other benefits that often exceed payments during the good times.It’s not any different this time around. At a time when hundreds of thousands of employees in the U.S. shale industry have lost their jobs, Bloomberg has reported that some 35 executives at Whiting Petroleum Inc.(NYSE:WLL), Chesapeake Energy Corp.(NYSE:CHK) and Diamond Offshore Drilling Inc.(OTCMKTS: DOFSQ) are set to receive nearly $50 million after their companies declared bankruptcy or are on the verge of doing so. It’s the manner in which these head honchos continue to award themselves fat bonuses despite federal legislation to crack down on the practice that really grates.The board at Whiting, an oil and gas producer that filed for Chapter 11 in April, approved a $6.4M bonus for CEO Brad Holly just days before the company went under, exceeding his previous annual compensation package by nearly a million dollars.In May, California Resources Corp. (NYSE:CRC) warned investors about “…a substantial doubt about the company’s ability to continue as a going concern…” but still went ahead and guaranteed company executives their 2020 bonuses.According to Kelly Mitchell, an analyst at corporate watchdog group Documented, companies do it so as to incentivize these executives to stick around because they understand the company better and, ostensibly, have better odds of pulling them through. Never mind the fact that their decisions are very often to blame for the company’s sad situation in the first place. They also do it in a bid to cut costs and maximize value for creditors using tools such as tax credits or untapped resources. You could argue that this practice is not unique to the energy industry and is, in fact, common in corporate America–and you would be right. Last year, former Equifax CEO Richard Smith, walked away with a very generous ~$19.6 million in stock bonuses, $24-million pension and $50,000 in tax and financial planning services after the credit agency suffered one of the worst data breaches in the history of the U.S.
Energy Industry Jilts Trump as Oil’s Crash Curbs Donations - The oil and gas industry, long one of the most reliable sources of campaign cash for Republican candidates at all levels, is turning a cold shoulder to President Donald Trump. Reeling from the worst oil-price crash on record and wary of Trump at the best of times, energy companies and their employees are donating far less to his re-election campaign than they did to his first run, and also much less than they’ve showered on Republican presidential candidates in the past. As Trump faces widespread criticism of his handling of the coronavirus pandemic and of the protests over police brutality, the slump in donations from a once-reliable ally is more evidence of a troubled re-election campaign. Trump raised $1.1 million from oil and gas company employees between May and November in 2016, the only period he actively raised donations during his first presidential run. But in the 40 months since, when he’s relentlessly been raising re-election cash, they’ve given him $654,103. The reasons vary from slimmer wallets after the oil-price collapse and some of Trump’s rhetoric during Saudi Arabia’s oil price war with Russia, to the Covid-19 lockdown, during which he cheered cheap gasoline as “a tax break for Americans.” Trump’s tariffs on foreign steel, which affect refinery infrastructure, are also unpopular in the industry -- and for some, so was his treatment of Rex Tillerson, the former chief executive officer of Exxon Mobil Corp., who served as Trump’s first secretary of state but was fired in a tweet and later publicly derided by the president as “dumb as a rock.”
North America’s largest pipeline company aims to pivot to natural gas and renewable energy – Enbridge Inc., North America’s largest pipeline company, is shifting its asset mix to reflect the energy transition underway across the world. Al Monaco, chief executive officer of the Calgary-based company, said his company is taking a “gradual” approach to energy transition. While it will continue to invest in oil pipelines, the company will also invest increasingly larger proportions of its capital to natural gas and renewable energy projects as consumers around the world demand lower-emitting forms of energy. “If you look at the energy supply/demand balance globally, we as a company kind of mirror that. We have a meaningful part of our business in renewables — the base is probably 5 per cent of our assets,” Monaco said in an interview with the Financial Post. Currently, 55 per cent of the company’s earnings are generated from its liquids pipeline business, roughly 40 per cent from its gas transmission and storage business and 4 per cent from renewables, which consist primarily of offshore wind projects in the U.K. and Germany. Enbridge has identified offshore wind opportunities in North America as well, but Monaco said the company currently believes there’s a better supply chain and more attractive power-purchase agreements in Europe. “Supply chains are now extremely well developed in (Europe) in terms of engineering, equipment and the sheer know-how of how to deal with offshore wind projects. We also know that from a public policy perspective, Europe is quite advanced and we see very good commercial models there,” Monaco said.
Goldman Made $1 Billion As Oil Plunged Below Zero -Back in late March, Goldman stunned commodity traders when its energy strategist Jeffrey Currie predicted that landlocked oil (such as WTI, and unlike Brent) could trade negative in the very near future as a result of the massive demand plunge in oil and gasoline consumption resulting from the coronavirus shutdowns coupled with the supply surge unleashed by Saudi Arabia as part of its brief market-share war with Russia.This forecast was impressive for two reasons: just 20 days later, the prompt WTI contract indeed plunged into negative territory for the first time ever as those who were set to receive delivery of WTI barrels had no space to store it and ending paying buyers to take it off their hands, sending the price of the maturing contract to as low as negative $40. The second reason, is that Goldman's trading desk actually took Goldman's advice and prepared for oil to crater.As a result, while countless of (most retail) traders suffered massive losses as oil plunged from $15 to -$40 in one session, Goldman made a killing. According to Bloomberg, Goldman's commodities desk generated more than $1 billion in revenue this year through May, benefitting from oil's wild swings for its best start in a decade.The unprecedented mayhem in oil markets sent crude plunging below zero, left corporate risk managers scrambling and forced retail investors to unwind bets. But it presented an opportunity for Wall Street traders to score big gains. The windfall is a redemption for the unit, which less than two years ago faced an uncertain future under new boss David Solomon, who frowned upon a business that wasn’t making enough money. As Bloomberg adds, much of the boost came from oil trading overseen by Anthony Dewell and Qin Xiao, "who correctly positioned their desks for the collapse in prices" by which Bloomberg means they actually read and traded on Goldman's own in house research - which is traditionally meant to lure clients to take positions opposite to the house's own prop positions but in this case actually was spot on - such as this report from March 30 which laid out precisely what would happen.
Exclusive: Oil major BP to cut 15% of workforce - (Reuters) - BP will cut about 15% of its workforce in response to the coronavirus crisis and as part of Chief Executive Bernard Looney’s plan to shift the oil and gas major to renewable energy, it said on Monday. Looney told employees in a global online call that the London-based company will cut 10,000 jobs from the current 70,100. “We will now begin a process that will see close to 10,000 people leaving BP – most by the end of this year,” Looney said in a statement. Reuters had earlier reported the planned job cuts, citing three company sources. The affected roles will be mostly senior office-based positions and not front-line operational staff, the company said. About a fifth of the job cuts will take place in Britain, where BP employs 15,000 people, a company spokesman said. Like all the world’s top energy companies, BP has cut its 2020 spending plans after the coronavirus pandemic brought an unprecedented drop in demand for oil. BP has flagged a 25% cut to $12 billion this year and said it would find $2.5 billion in cost savings by the end of 2021 through the digitalisation and integration of its businesses. On Monday, however, Looney said the company is likely to need to cut costs even further. BP is giving no pay rises to senior employees until March 2021 and said it is unlikely to pay any cash bonuses this year.
Hoard of North Sea Oil Is Starting to Diminish-- A glut of benchmark North Sea oil that’s been sitting on ocean-going tankers for weeks is starting to diminish. Millions of barrels of the region’s unwanted crude have been stashed on oil tankers since the coronavirus caused a demand collapse. But now the volumes are starting to shrink sharply, data compiled by Bloomberg show. Anchored on vessels everywhere from the U.K., to France and the Netherlands, the floating hoard reached 12 million barrels at the end of May. That figure has now dropped by 35%. The decline in the region’s floating storage is important because the grades in question help shape the Dated Brent benchmark that’s used to settle millions of barrels of physical oil transactions between producers and refineries. Nations including Saudi Arabia and Russia are leading a global push to limit output and have cut deliveries into northwest Europe. That’s lifted oil prices and eliminated what traders call a super-contango, a pricing structure that had made it highly lucrative to store. “The incentives to build floating storage have greatly diminished,” said Harry Tchillinguirian, oil strategist at BNP Paribas SA. “The holders of the storage are probably keeping an eye out for opportunistic sales where we see pockets of demand recovery.” While a diminishing floating stockpile of benchmark grades offers producers cause to be optimistic that their cuts are effective, there’s still a lot of work to be done to eliminate a surplus in the global market. There were also 180 million barrels of crude stored at sea worldwide last week, according to data from Vortexa Ltd., a data analytics firm. That’s the highest since at least 2016. On-land stockpiles in Europe’s key storage hub of Amsterdam, Rotterdam and Antwerp, known as ARA, jumped to their highest level in two years last week, according to Genscape Inc. That includes non-benchmark grades from all over the world. Shipments tracked by Bloomberg show that deliveries into ARA from the region’s main supplier regions dropped to 1.28 million barrels a day so far this month, down by about 360,000 barrels a day compared with the average between March and May. While supplies from producers in the North Sea and the Mediterranean jumped so far in June, those from Russia fell sharply, tracking a similar drop in export programs. Just a sliver have reached northwest Europe so far this month from the Persian Gulf.
No source yet identified as oil spill near Postville continues to dissipate - The slick discovered in the waters off Postville, Labrador earlier this week continues to dissipate. That’s according to the Canadian Coast Guard which is in the area with its Environmental Response Team. A recent surveillance flight showed approximately 350 litres of pollution remaining on the surface of the water. Officials say the continued reduction in the size of the sheen indicates a light product that evaporates and disperses relatively quickly—such as diesel. Samples of the product have been collected, and booms have been placed at strategic points to contain the pollution and recover any residual product. Transport Canada and the federal department of Environment and Climate Change are continuing their investigation into the cause of the spill. Residents started noticing a strong smell and a sheen on the water around the time of a fuel delivery to the community. Officials have not yet identified the source of the pollution.
Oil spill Russia - Images captured from space show diesel in Arctic Circle - A major oil spill that took place in Russia and affected the Arctic Circle was spotted from space by two satellites of the European Space Agency (ESA). While the Russian officials claimed that the spill had been stopped, this incident prompted the country's government to declare a state of emergency.The incident took place on May 29 after a power plant's reservoir in the city of Norilsk in Siberia collapsed. In this incident, about 20,000 tons of diesel leaked into an Arctic Circle river. Satellites spot major oil spill in the Arctic Circle (photos) https://t.co/fSYaaFFHQi pic.twitter.com/SfHSc3GWm2 — SPACE.com (@SPACEdotcom) June 5, 2020 According to reports, the ESA was able to monitor the incident from space through its Copernicus Sentinel-2 mission. The mission, consisting of the twin satellites Sentinel-2A and Sentinel-2B, had two separate launches in 2015 and 2017. The goal of the mission is to study Earth by taking images from orbit. The ESA was able to spot the areas affected by the oil spill. As seen in the images obtained by the agency, the red-colored oil traveled down the Ambarnaya River before flowing into Lake Pyasino. Responding to this, Russian President Vladimir Putin declared a state of emergency. He also slammed the power planet known as NTEK, which is a subsidiary of Norilsk Nickel, for the delay in informing the government regarding the incident. Almost a week following the incident, officials from Russia confirmed that the oil spill had been stopped and contained. As of June 5, Russia's Emergencies Ministry confirmed that it has already removed 200 tons of fuel in the affected region.
U.S. offers help in cleaning huge Arctic Circle fuel spill - The United States on Saturday offered to help Russia clean up a vast fuel spill that has fouled an Arctic river in northern Siberia.“Saddened to hear about the fuel spill in Norilsk, Russia,” Secretary of State Mike Pompeo wrote on Twitter. “Despite our disagreements, the United States stands ready to assist Russia to mitigate this environmental disaster and offer our technical expertise.”On May 29, a diesel-fuel tank at a power plant belonging to the giant Norilsk Nickel mining group collapsed near the Siberian industrial city of Norilsk, sending some 15,000 tons of diesel into a nearby waterway and pouring an additional 6,000 tons onto surrounding land.The spill — deemed the worst ecological catastrophe of the sort to ever hit the region — Colorado remote tundra waterways with bright red patches visible from space. President Vladimir Putin declared an emergency and said he expects the company to pay for the clean up, which could take years.Clean up work however has been complicated by marshy ground amid a springtime thaw and the shallow depths of the nearby Ambarnaya River, which prevents boats from reaching the scene. Russian officials said Friday that the spill was probably caused when long-frozen permafrost under the fuel tank melted and gave way, and ordered a review of infrastructure in vulnerable zones.
Disastrous Russian oil spill reaches pristine Arctic lake -A 21,000 tonne (approximately 23,000 U.S. ton) oil spill that prompted Russian President Vladimir Putin to declare an emergency last week has now reached a pristine Arctic lake, and there are concerns it could contaminate the Arctic Ocean.Environmentalists and local officials have raised alarms about the disaster, which they say is the worst of its kind in the Russian Arctic, according to BBC News. So far, the oil has spread 12 miles from the initial spill site, a fuel tank that collapsed May 29. "The fuel has got into Pyasino as well. This is a beautiful lake about 70 kilometres (45 miles) long. Naturally, it has both fish and a good biosphere," Krasnoyarsk region governor Alexander Uss told Interfax news agency Tuesday, as AFP reported.Lake Pyasino flows into the Pyasina river, which in turn flows into the Arctic Ocean's Kara Sea, BBC News explained. Greenpeace Russia director Vladimir Chuprov told AFP it would be a "disaster" if 10,000 tonnes (approximately 11,000 U.S. tons) of fuel or more had reached the lake. He said he feared it would reach the Kara Sea as well, which would have "harmful consequences."Uss, however, was committed to preventing that from happening. "Now it's important to prevent it from getting into the Pyasina river, which flows north. That should be possible," he said, as BBC News reported.But regional officials told a different story."We can see a large concentration of diluted oil products beyond the booms," Krasnoyarsk region deputy environment minister Yulia Gumenyuk said, according to BBC News. Norilsk Nickel, the company that ultimately owns the power plant where the tank collapsed, denied that any oil had reached the lake.The spill has also contaminated rivers and soil. So far, cleanup efforts have removed 812,000 cubic feet of contaminated dirt, according to BBC News. "[The spill] will have a negative effect on the water resources, on the animals that drink that water, on the plants growing on the banks," Vasily Yablokov of Greenpeace Russia said, according to BBC News.The polluted Ambarnaya and Daldykan rivers may take ten years to clean, The Guardian reported.
Siberian oil spill contaminates Arctic lake - An oil spill that sparked a state of emergency has contaminated a freshwater lake in the Russian Arctic, the regional governor said Tuesday, a claim denied by Norilsk Nickel, the metals giant linked to the leak. Russian President Vladimir Putin declared a state of emergency last week after 21,000 tons of diesel leaked from a fuel reservoir that collapsed May 29 outside the Arctic city of Norilsk. The spill has polluted the ground and waterways, triggering a major clean-up effort. Norilsk Nickel owns the power plant where the spill originated and its head Vladimir Potanin told Putin last week his company would pay for clean-up efforts estimated at $146 million. A spokeswoman for the taskforce in charge of the accident clean-up told AFP last week that the spill had been contained. But officials in the Siberian region of Krasnoyarsk this week said that high concentrations of polluted water had been discovered beyond floating barriers set in place to stop the fuel from spreading. "The fuel has got into Pyasino as well. This is a beautiful lake about 70 kilometers (45 miles) long. Naturally, it has both fish and a good biosphere," said Krasnoyarsk region governor Alexander Uss, according to Interfax news agency. He added that it was important to prevent spilled fuel from reaching the Pyasina River, a vital waterway for the region that flows from the lake into the Kara Sea. At a video conference on Tuesday, Norilsk Nickel denied that the diesel had polluted the lake or risked reaching the Kara Sea. "Our samples at the Pyasino Lake show 0.0 percent contamination results," said Sergei Dyachenko, the company's first vice-president and chief operating Officer. "The distance from Pyasino Lake to the Kara Sea is more than 5,000 kilometers," he added.
Concerns oil spill from Siberia could reach Arctic Ocean {sbs.com.au}- video - A Russian environmentalist has warned that a recent oil spill in Siberia could reach the Kara Sea, which forms part of the Arctic Ocean. The spill happened on May 29 at a power plant about 2,900 kilometers northeast of Moscow. An estimated 18,143 tonnes of diesel fuel was spilled from the power plant's storage facility, contaminating waterways.
Russian oil spill leads to charges against plant director - The director of an Arctic power plant faces five years in jail after a major oil spill. Some 20,000 tons of diesel have flowed out of a collapsed storage structure, polluting waterways in Russia's north. Russian investigators have charged the director of an Arctic power plant after a major oil spill, authorities announced on Monday. Investigative Committee spokeswoman Svetlana Petrenko said they had charged Vyacheslav Starostin with violating environmental protection rules. He faces up to five years in jail if found guilty. More than 20,000 tons of diesel has leaked into the ecologically fragile area in the Norilsk region since a storage tank collapsed on May 29, prompting fears for the environment and wildlife. The oil has contaminated local waterways and is threatening to reach the Arctic Ocean. Prosecutors partly blamed thawing permafrost for the collapse. Emergency workers have deployed booms to block the fuel from spreading further into the Ambarnaya River, a tributary of Lake Pyasino. That lake feeds a river that flows into the Kara Sea arm of the Arctic. The head of Russia's natural resources agency Rosprirodnadzor, Svetlana Radionova, denied that any fuel has reached the lake, but local inspectors say the tests being performed aren't adequate, and that fuel has likely poured into the body of water. "If a storm comes, (the fuel) will settle down on the banks and will slowly poison the ecosystem of Norilsk and Pyasino. The consequences won't be immediate. It might also reach the Kara Sea,'' regional inspector Vasily Ryabinin told The Associated Press.
Nigeria records 1,300 oil spills in two years - Over 1,300 oil spill incidents occurred in various parts of Nigeria between 2018 and 2019, latest figures compiled by the National Oil Spill Detection and Response Agency have revealed. It was also gathered that most of the oil spills were caused by the activities of vandals who break pipelines to steal petroleum products. The Director-General, NOSDRA, Idris Musa, said findings by his agency showed that an average of five oil spills was recorded daily in Nigeria. Musa, who spoke to journalists in Abuja, said, “In 2018 we had about 600 oil spill incidents and in 2019, we had over 700 oil spill-impacted sites across the country. “These were oil spill incidents recorded in Nigeria that we’ve compiled and it is based on the fact that by law if there is an oil spill, you must report it. You must report any oil spill, no matter how small.” On the major cause of the spills, the DG said, “Most of the spills that occur are as a result of oil theft by those who go to pipelines to install valves. We had a similar incident about two weeks ago.”Musa observed that it was difficult to record the type of oil spills that were recorded in Nigeria in any other part of Africa. “In fact, aside from Mexico, which is not an African country anyway, you will hardly find such situation anywhere else,” he stated. The NOSDRA boss added, “Whenever we go for international conferences and we say we record over 700 oil spills in Nigeria, people ask how it happened. “When you tell them that people go to oil pipelines to install valves to fetch oil like water, they will ask you if the people who fetch the products are crazy. This is because the pressure inside the pipes is so huge and it can cause severe damage if ruptured.” Musa further noted that the agency had realised that the underground tanks of many filling stations in the downstream oil sector leaked products into their surrounding environment. This, he said, was not healthy for the environment, adding that NOSDRA had started taking inventory of defaulters. He said, “If your tank spills oil as a downstream operator, you will have to clean it up. We have noticed that for some of them who have already spilled products, they find it difficult to clean up.”
Clean-up operations following Barrackpore oil spill - An oil spill in Barrackpore caused by a busted line resulted in the spillage of three barrels of oil on a portion of land and into a watercourse. The discovery was made on Saturday and on Sunday mop-up operations continued at the site near Wilson Road. In a statement, Heritage Petroleum stated that the company received reports of the spill around 1 pm on Saturday. "Upon investigation, it was quickly discovered that the spill was emanating from a 4” pump line. The leak was isolated and clamped by 3:00 PM on the same day. Heritage has estimated that approximately three (3) barrels of oil was spilled." The company stated that it engaged the services of a contractor to clean up the spill and booms have since been reinforced along nearby watercourses to restrict migration of spillage to further downstream. In addition, company officials also visited the owner of nearby agriculture lands which may have been impacted and the parties will continue discussions on Monday. The company has since informed the Ministry of Energy and Energy Industries of the incident and will keep officials appraised of related containment and recovery. Barrackpore West councillor Nicholas Kanhai said he visited the site and observed that clean up operations were being undertaken. He said workers were able to contain the oil in the river from going downstream. He said the spill occurred in an unpopulated area and he has received no reports of damage to agriculture produce or harm to animals.
Put new gas wells on hold until OIL has a disaster plan -- A preliminary report by Wildlife Institute of India (WII) on the environmental damage caused due to Oil India Limited’s (OIL) gas well blowout at Baghjan in Upper Assam’s Tinsukia district, which started on May 27, has found that oil has leaked into adjoining Lohit river, polluting the water and adjoining Maguri-Motapung wetland with toxic pollutants. Maguri-Motapung is located less than 10 km from Dibru-Saikhowa National Park and is a part of the Dibru-Saikhowa Biosphere Reserve (DSBR). The report, which has been submitted to the Union Ministry of Environment, Forest and Climate Change (MoEFCC) and seen by HT, has recommended that the approved new wells and further exploration in the area should be put on hold until OIL authorities put in place their disaster-handling capabilities. The report said a WII team conducted the survey from May 29 to June 4 and found several dead fish and insects that may have died due to oxygen depletion in the water following the oil spill. The survey found the presence of at least five endangered Gangetic dolphins in the 20-kilometre stretch of the Lohit river, a tributary of the Brahmaputra river, indicating that the species will be at grave risk from the ongoing spill. The team has collected samples of tissue and blubber from a Gangetic dolphin carcass found in Maguri beel, which is being analysed for presence of various contaminants. “The toxic fumes and oil coating has universally affected the area’s flora and fauna. The contaminants and oil are continuing to be released in the surrounding areas and immediate steps are needed to contain this spillover. The released toxins are known to have long-term persistence in soils and sediments, which will not only affect current life conditions, but due to sustained release, pose a serious health risk for a longer-term,” the report said. The WII team has also gathered from the local residents that OIL authorities did not have a mitigation plan for such a disaster, and consequently suggested a comprehensive impact assessment of their field operations in the biodiversity-rich Dibru Saikhowa National Park. “It’d be not only prudent but also essential for the well-being of all life forms that the approved new wells and further explorations in this area should be initiated only after a thorough investigation of potential impact, as well as evaluating disaster handling capabilities in place, with appropriate technology and trained manpower,” the report added.
More insurance cover needed for marine oil spills - Maritime NZ has published guidelines about a major increase required in insurance cover or other financial security for marine oil spills from offshore installations. Amendments to the Marine Protection Rules Part 102 now require owners of offshore installations to have insurance or another form of financial security from a third party of up to $1.2 billion. This is an increase from approximately $28 million. Maritime NZ Director Keith Manch says the insurance or other form of financial security is in addition to the unlimited liability imposed by the Maritime Transport Act for spill response costs and compensation for pollution damage to property. The certificate of insurance provides assurance that the money that would be needed is available to meet the costs of clean up and compensation for damage to property in case of an oil spill. Marine Protection Rules Parts 131 and 102 regulate offshore installations. They require an oil spill contingency plan and insurance or another form of financial security to cover the costs of clean up and damage to property. Part 131 requires an offshore installation operating in New Zealand continental waters and in the internal waters of New Zealand have an oil spill contingency plan approved by the Director that will support an efficient and effective response to an oil spill at sea. The amendments to Part 131 require the Director to be satisfied the operator will have the ability to implement the oil spill contingency plan when approving it.
Global gas demand on course for biggest annual fall on record: IEA - (Reuters) - The coronavirus crisis and a very mild winter in the northern hemisphere have put global natural gas demand on course for the biggest annual fall on record, the International Energy Agency said in its annual outlook on Wednesday. Global gas demand is expected to fall by 4%, or 150 billion cubic metres (bcm), to 3,850 bcm this year – twice the size of the drop following the 2008 global financial crisis. Major global gas markets have experienced price falls to record lows as lockdowns and reduced industrial output due to the COVID-19 pandemic have stunted demand. The oil and gas industry is cutting spending and postponing investment decisions. Although a rebound in demand is expected in 2021, the IEA does not expect a quick return to pre-crisis levels. For the full year, more mature markets across Europe, North America and Asia are forecast to see the biggest drops in demand, accounting for 75% of the total fall in 2020. “Global gas demand is expected to gradually recover in the next two years, but this does not mean it will quickly go back to business as usual,” said Fatih Birol, IEA executive director. “The COVID-19 crisis will have a lasting impact on future market developments, dampening growth rates and increasing uncertainties,” he added. The IEA forecasts 75 bcm of lost annual demand by 2025 - the same amount as the increase in global demand in 2019.
Exclusive: Oil tankers turn away from Venezuela as more sanctions loom (Reuters) - Oil tankers that were sailing toward Venezuela have turned around and others have left the country's waters as the United States considers blacklisting dozens of ships for transporting Venezuelan oil, according to shipping data and industry sources. The threat of tighter sanctions is already disrupting the global shipping market. Chinese oil firms are considering whether to decline to charter any tanker that has visited Venezuela in the past year, no matter where the ship is now or for what voyage, four shipping sources told Reuters on Tuesday. Washington is seeking to oust the socialist government of President Nicolas Maduro by choking the oil exports that provide its main source of income. The measures have contributed to a fall in Venezuelan oil exports to a 17-year low and deepened the country's economic crisis, but Maduro has held on - to the frustration of U.S. President Donald Trump's administration. The United States may add dozens more tankers to an existing blacklist, U.S. sources told Reuters last week. That would make it more difficult for state firm PDVSA to deliver oil to refineries abroad. Exports dropped to about 452,000 barrels per day in May, the lowest since a national strike paralyzed the economy and hit exports between 2002 and 2003. Venezuela's Foreign Minister Jorge Arreaza said on Twitter on Tuesday that Washington was attacking Venezuela's economy by blocking foreign revenue that could be used to import humanitarian goods, including food and medicine. The U.S. State Department did not immediately comment.
Country With World's Largest Oil Reserves Has Only One Rig Left - The collapse in oil prices and the tightening U.S. sanctions against Venezuela have accelerated the decline of the oil industry in the country sitting on the largest crude oil reserves in the world. As of May, Venezuela’s rig count plunged to just two, data from Baker Hughes shows, as production slipped by 16 percent to 645,700 barrels per day (bpd), Bloomberg reported on Thursday, citing documents containing production data it has seen. Of the two active rigs in Venezuela last month, one was working at an oilfield and another one was drilling for gas, according to Bloomberg. Those rigs are working in the Orinoco oil belt, where Venezuela’s state oil firm PDVSA operates oilfields in joint ventures with foreign firms, sources familiar with the matter told Bloomberg. Venezuela’s oil industry was collapsing even before the oil price crash and the pandemic, due to the increasingly stricter sanctions in the U.S. maximum pressure campaign against Nicolas Maduro’s regime and its sources of revenues. Oil income is pretty much the only hard currency that Maduro gets, so the U.S. is looking to stifle as much of Venezuela’s oil trade as possible. In addition, PDVSA is severely cash-strapped and hasn’t invested in repair and maintenance of oil facilities and refineries in years. The price crash and the COVID-19 pandemic further exacerbated the crisis in Venezuela’s oil sector and PDVSA started shutting oilfields because of fewer international customers for Venezuelan oil, Bloomberg reports. In March, Venezuela had 25 operational oil and gas rigs, according to the Baker Hughes international rig count data. Venezuela has seen some reprieve recently in its fuel shortage problem, after Iranian tankers shipped gasoline and refining components to the Latin American country in an open defiance of the U.S. sanctions. Maduro’s regime tried to alleviate the fuel shortage in the country home to the world’s biggest oil reserves, but a new scheme of subsidized gasoline failed to put an end to the long lines in which Venezuelans queued to fill their cars with fuel.
The Saudi-Russia oil price war was a 'very big mistake,' Qatar energy minister says -- Qatar's Minister of State for Energy Affairs shared his thoughts on some of the major oil producers' market moves in recent months, shedding disapproval on the March decision by Saudi Arabia and Russia to launch into a price war, which sent oil prices into free fall. "I think it was a very big mistake," Saad al-Kaabi told CNBC's Hadley Gamble from Doha. Al-Kaabi is also CEO of Qatar Petroleum. "You know, flooding the market is what caused us to go to a very low level. And then the pandemic basically took it almost to a very dangerous area where people could not afford to produce anymore. And we saw, you know, negative pricing in (U.S. oil benchmark) WTI." The markets were already being devastated by the crushing drop in demand due to global coronavirus lockdowns. The call to open the taps on oil production pulled the floor from under the market as Saudi Arabia slashed its selling prices and increased production after Russia refused to join its plan to further cut output and boost prices in early March. The hit to producing countries revenue was harsh enough to bring OPEC and its non-OPEC allies — known as OPEC+ — back to the negotiating table. In April, they agreed to the largest production cuts in history at 9.7 million barrels per day. "Now, I think the actions that have been taken by the same group really is to agree what was agreed in the past and keep more sensible … to cater for the supply and demand that we're seeing," al-Kaabi said. Qatar left OPEC in January 2019 after six decades with the organization. The country's state oil producer, Qatar Petroleum, is slashing 30% of its spending this year due to the downturn. But the possibility of a second wave of coronavirus will continue to weigh on the energy outlook, including liquid natural gas prices. S "We may be more prepared for it and have less lockdowns around the world. If that's the case, then we'll see a much quicker recovery, maybe in six months to a year. If there is a second wave, then it could take a little bit longer," he said. Al-Kaabi added, however, that he isn't worried about the long term because it has largely been "short-term events that have affected" prices. Still, he warned the coronavirus could have "some long-lasting effects" on travel and means of doing business. "I think you'll see less people doing business by traveling and more using video conferencing and other means that we got used to now and working from home and so on. So, I think there will be some change in our attitude about whether it's business traveling or working from home," al-Kaabi said.
Why Saudi Arabia Will Lose The Next Oil Price War - Saudi Arabia has instigated two oil price wars in the last decade and has lost both. Given its apparent inability to learn from its mistakes it may well instigate another one but it will lose that as well. In the process, it has created a political and economic strait-jacket for itself in which the only outcome is its eventual effective bankruptcy. OilPrice.com outlines why this is so below. The principal target for Saudi Arabia in both of its recent oil price wars has been the U.S. shale industry. In the first oil price war from 2014 to 2016, the Saudi’s objective was to halt the development of the U.S. shale sector by pushing oil prices so low through overproduction that so many of its companies went bankrupt that the sector no longer posed a threat to the then-Saudi dominance of the global oil markets. In the second oil price war which only just ended, the main Saudi objective was exactly the same, with the added target of stopping U.S. shale producers from scooping up the oil supply contracts that were being unfilled by Saudi Arabia as the Kingdom complied with the oil production cuts mandated by various OPEC and OPEC+ output cut agreements. In the run-up to the first oil price war, the Saudis can be forgiven for thinking that they stood a chance of destroying the then-relatively nascent U.S. shale sector. It was widely assumed that the breakeven price across the U.S. shale sector was US$70 per barrel and that this figure was largely inflexible. Saudi Arabia also held record high foreign assets reserves of US$737 billion at the time of launching the first oil war. As it transpired, of course, the Saudis had disastrously misjudged the ability of the U.S. shale sector to reshape itself into a much meaner, leaner, and lower-cost flexible industry. After two years of attrition, the Saudis caved in, having moved from a budget surplus to a then-record high deficit in late 2015 of US$98 billion. It had also spent at least US$250 billion of its precious foreign exchange reserves over that period that were lost forever.The even more enduring legacy of this first oil price war, though – and part of the reason why the Saudis could never hope to win the last one, or any future oil price war either – is that it created the resilience of the U.S. shale sector as it now stands. This means that the U.S. shale sector as a whole can cope with extremely low oil prices for a lot longer than it takes Saudi Arabia to be bankrupted by them.
Saudi Arabia says 'no room whatsoever' for noncompliance over OPEC+ production cuts - OPEC kingpin Saudi Arabia and non-OPEC leader Russia said Monday that the success of the energy alliance's latest production cuts relies on all members complying with the terms of the deal. The statement comes shortly after OPEC and non-OPEC allies, known as OPEC+, agreed to extend its deepest round of production cuts in history to take roughly 10% of oil supplies off the market through to the end of next month. "We have no room whatsoever for lack of conformity," Saudi Energy Minister Prince Abdulaziz bin Salman said during a virtual press conference on Monday. Those that failed to conform to the OPEC+ deal in May and June should compensate with extra cuts from July through to September, Prince Abdulaziz said. Russian Energy Minister Alexander Novak said via a translator that he fully agreed with his Saudi counterpart. "I can say that overall conformity levels are extremely high, considering the magnitude of the cuts and how bad the situation is." "We have spent a lot of time discussing full conformity and how this will be compensated because the success of the deal and the success of our efforts rests on all countries doing their part," he added. International benchmark Brent crude futures traded at $41.72 a barrel, down around 1.3%, while West Texas Intermediate futures stood at $38.88, over 1.6% lower. Both contracts pared gains after rising to their highest level since March 6 earlier in the session, climbing to $43.41 and $40.44, respectively. What has been agreed? Oil prices have surged since some of the world's most powerful oil producers brought in a production cut of 9.7 million barrels per day from May 1. The move was designed to prop up prices at a time when the coronavirus pandemic had led to an unprecedented demand shock in energy markets. The International Energy Agency estimated that roughly 25% of demand was drained from the market in April as confinement measures brought mobility to a near standstill for billions of people across the globe. The output cuts from OPEC+ were initially scheduled to be scaled back to 7.7 million barrels per day from July 1 through to the end of the year. But the new deal, secured over the weekend, means the group will now cut 9.6 million barrels per day through to the end of July. The figure is 100,000 barrels per day lower than the previous agreement because Mexico said it remained committed to the terms of the original deal and subsequent reduction in cuts.
Iraq Asks Buyers to Forgo Oil Cargoes-- Iraq has asked some Asia refiners to consider forgoing prompt shipments of its Basrah crude, a potential signal the country is trying to meet the output-cut pledges it made to OPEC at the weekend. State-owned marketer SOMO sent requests to several customers asking if they would consider not taking some contracted cargoes for June and July loading, said people with knowledge of the matter. At least one buyer was unwilling to forgo shipments citing downstream commitments, while another will likely agree and seek replacement cargoes in the spot market, the people said. Suppliers such as Iraq and Nigeria that have traditionally been lax at complying with output curbs are coming under increased scrutiny following the latest OPEC+ agreement. The alliance agreed to extend record output cuts for another month on condition that Baghdad doubles down on efforts to rein in production and also makes up for previous non-compliance. Nobody responded to emails and text messages sent to SOMO seeking comment. The company typically sells two grades -- Basrah Light and Basrah Heavy -- to Asian customers in 1 million or 2 million-barrel shipments. Efforts by OPEC+ and involuntary supply cuts in the U.S. have been instrumental in helping oil prices recover from virus-induced lows in April. However, there’s speculation the rally could be stymied as the speed of the rebound entices producers to raise output before demand fully recovers. Iraq will be fully committed to the OPEC+ agreement, the country’s oil ministry said in a statement. The nation produced 4.2 million barrels a day in May, about 15% more than it was meant to under the previous OPEC+ deal struck in April. Iraq is set to release its official selling prices for July-loading crude exports in the coming days. Earlier, Saudi Aramco hiked official selling prices for all grades in a move that shocked buyers across Asia.
Saudi Arabia to end voluntary cuts on top of OPEC+ pact - (Reuters) - Saudi Arabia will boost output in July to match its output OPEC quota while ending deeper, voluntary cuts amid signs of global demand recovering, the Saudi energy minister said on Monday. OPEC, Russia and other producers agreed on Saturday to extend record output cuts of 9.7 million barrels per day (bpd) into July, curbing global supply by almost 10% amid a steep slump in demand due to the coronavirus pandemic. For June, Saudi Arabia, Kuwait and the United Arab Emirates (UAE) had pledged to cut by 1.18 million bpd on top of that, with Riyadh forfeiting 1 million bpd. Saudi Energy Minister Prince Abdulaziz bin Salman said that this would not continue in July, when Saudi Arabia will pump its OPEC quota, amid signs of demand recovery as nations around the world lift strict lockdown measures. “The voluntary cut has served its purpose and we are moving on. A good chunk of what we will increase in July will go into domestic consumption,” Prince Abdulaziz told an OPEC+ virtual news conference. Saudi crude use for power generation typically increases in the hot summer months, the minister noted. Saudi Arabia, OPEC’s de facto leader, and Russia have to perform a balancing act as they push up oil prices to meet their budget needs while not driving them much above $50 a barrel to avoid encouraging a resurgence of rival U.S. shale production. Producers must also weigh the recovery in global demand against a possible return of supply from Libya after months of a blockade that shut off most of its crude production as well as weak compliance with promised cuts from producers such as Iraq and Nigeria. “The market has to absorb millions of barrels of oil that will be released from storage. As prices rise, U.S. production will continue to fall month on month due to steep base declines, but the pace of declines is set to ease markedly,” Energy Aspects analysts said in a note. On Sunday, Saudi state oil company Saudi Aramco hiked its July selling prices for crude grades to all destinations in a move likely to discourage buying for storage but rather could help to lower inventories.
Global Oil Demand Rises - Barkley Rosser - Back on April 20 we saw briefly the bizarre appearance of negative oil prices in certain markets. Today for the first time in many months Brent crude briefly topped $40 per barrel, although it fell back below that level (WTI is tending to be about $3 behind it, despite a single day recently when for the first time in years it nearly matched Brent crude at only 18 cents lower). However, it looks like the recent trend of global oil prices rising will continue some more, with prices likely to go above $40 and stay there. How far beyond that I shall not forecast. But this is a price level where many oil exporting nations can get out of immediate financial crisis, with many of them actually making money, if not as much as they would with still higher prices. One element of this price rise is on the supply side, especially with Saudi Arabia and Russia apparently maintaining a production cut agreement they have. Rumors from OilPrice.com suggest there may be cheating on these agreements to come. But for now these two are holding the line on the supply side. More important has been the increase on the demand side, which looks set to continue rising for at least the near future. I have posted previously on how global carbon emissions appear to have bottomed around April 7, with them rising since, if still well below pre-pandemic levels. Burning fossil fuels is a major source of these emissions, so it is quite possible that oil demand has been rising since around then, even though it was 10 days after then that oil prices did their brief plunge into negative territory. According to OilPrice.com it is China that is leading this increase in oil demand. It was the first economy to drop due to the pandemic, with its oil demand declining about 40% during February. However, it looks that China’s demand has returned as of May to a level 92% of its peak prior to the pandemic. That is substantial, while leaving more room for further growth. Another nation with a large economy making an even sharper turnaround is India. In early April at the beginning of its two month lockdown its demand declined by 60%, but now it is estimated that in June its demand will return fully to its pre-pandemic level.
Brent crude will need to work through oversupply issues despite the OPEC+ output cut, says analyst - Brent crude needs to work through its oversupply issues before it can punch through its current price range of between $40 and $50 per barrel, according to Thom Payne, director at Westwood Global Energy Group. That's despite the latest agreement by the Organization of the Petroleum Exporting Countries and its oil-producing allies to extend a historic oil production cut until the end of July. The alliance cut production by 9.7 million barrels per day at the start of May 1, and the cuts — which have helped push up crude prices in the last two months — was initially set to decline on July 1. "If you take February to May, you've got an average built position, oversupply of 14 million barrels a day. So we've effectively built about 2 billion barrels of additional storage," Payne told CNBC's "Street Signs" on Monday. "We definitely need to drain that before we can see prices move materially above that kind of ($40 to $50) price structure," Payne said. His comments came after the group, known collectively as OPEC+, on Saturday agreed to extend its record oil production cut for another month as it seeks to balance the global oil market. Commenting on the recent OPEC+ agreement, JPMorgan's Head of Asia Pacific Commodities Research, Scott Darling, said: "I'd take some positives out of this — you've got compliance." "I think you've also got now monitoring on a month-by-month basis and it also feels there's not just near-term views on oil but gradually a sort of longer-term vision around where they want oil to go," he added. Oil prices have seen a partial recovery since seeing a plunge in April due to several concerns — ranging from uncertainty over demand due to the coronavirus pandemic that was spreading rapidly, to issues with crude oversupply. In the afternoon of Asian trading hours on Monday, international benchmark Brent rose 1.49% to trade at $42.93 per barrel. Similarly, U.S. crude futures gained 1.34% to trade at $40.08 per barrel. Looking ahead, Payne from Westwood Global said: "What's likely to happen is that the oil markets move to a net draw or undersupply position by around July, August of this year." This would be "very supportive" of the current $40-50 per barrel price range for Brent, he added. For his part, Darling said that JPMorgan sees Brent at $40 dollar per barrel this year and $47 per barrel for next year.
Hedge fund buying dries up after oil prices double - Kemp - (Reuters) - Hedge funds have started to temper their bullishness towards oil after crude futures prices have doubled since late April. Crude prices are nearing levels expected to see some shale production restart and there are concerns the rally is outrunning the recovery in demand.Hedge funds and other money managers purchased the equivalent of just 6 million barrels in the six major petroleum futures and options contracts in the week to June 2.Portfolio managers have bought petroleum derivatives in nine out of the last ten weeks, increasing their bullish position by a total of 324 million barrels since late March (tmsnrt.rs/3cKiMVA).But purchases last week were the smallest for nine weeks (if the single week when funds were actually net sellers is excluded), indicating the buying wave may be fading.Position changes were mostly insignificant with purchases of NYMEX and ICE WTI (+7 million barrels) and European gasoil (+8 million) but sales of Brent (-2 million) and U.S. gasoline (-8 million) and no change in U.S. diesel. But there were some tentative indicators the rally in crude prices may be running out of steam, while funds try to anticipate an improvement in the relative price of distillates, where margins have become uneconomic: Portfolio managers added new short positions in petroleum last week and their ratio of bullish longs to bearish shorts dipped for the first time since the end of March.Fund buying in WTI was some of the smallest since portfolio managers started to accumulate positions in U.S. crude in March. Funds were net sellers of Brent for only the second time in nine weeks.Funds have been net buyers of European gasoil for three weeks running, and last week’s purchases were the largest yet, indicating traders are trying to position themselves ahead of an anticipated improvement in distillate margins.None of these is a strong signal and there is a big risk of over-interpreting them. But taken together they suggest a possible pause or even a future reversal in fund buying.
Saudis Raise Oil Prices by Most in 20 Years-- Saudi Arabia increased prices for some crude exports by the most in at least two decades, doubling down on a strategy to bolster the oil market after OPEC+ producers extended historic output cuts over the weekend. The steepest jump in July exports will hit buyers in Asia, state producer Saudi Aramco’s largest market, according to a pricing list from the company on Sunday. The increases erase almost all of the discounts the kingdom made during its price war with Russia earlier this year. Saudi Arabia is using all the tools at its disposal to turn around the oil market after prices plunged in March and April with the spread of the coronavirus. As the price setter in the Middle East, its increases may be followed by other producers. Unprecedented output cuts led by the Saudis and Russia boosted prices in May, and the OPEC+ group decided Saturday to extend those limits through July. Brent crude has more than doubled since late April, though its still down 35% this year. It rose 1.7% to $43.02 a barrel by 6:55 a.m. in London Monday. Still, oil refiners’ profits are being squeezed by crude’s rally, and the sharp Saudi hikes are likely to exacerbate that problem. Representatives for refineries from Europe and Asia expressed concern and said the new pricing would crush their margins. The month-on-month increase in the official selling price for flagship Arab Light crude to Asia, which accounts for more than half of Saudi oil sales, is the largest in at least 20 years. Aramco raised Asian Arab Light by $6.10 a barrel from June to a premium of 20 cents over the benchmark. The company increased all grades to Asia by between $5.60 and $7.30. That compares with an expected increase of about $4, according to a Bloomberg survey of eight traders and refiners. Buyers in the U.S., the Mediterranean region and northwest Europe will also pay more for oil. Arab Light for northwest Europe was raised to a 30 cent premium over the benchmark from a discount of $3.70. Aramco made the steepest increases in its lighter grades, which are the easiest to process into gasoline. That suggests the company sees good prospects for the fuel’s revival, “though refinery margins remain very weak,” Mills said.
Oil rally and Saudi price spikes could hurt refiners, stifling market recovery - Oil prices pared gains on Monday, despite the weekend announcement by OPEC and its allies, known as OPEC+, that historic production cuts of 9.6 million barrels per day across the group would continue through July as the coronavirus pandemic continues to weigh on demand. The move spurred hopeful talk of a recovery for oil prices, which are down about 30% year-to-date after a 56% recovery for international benchmark Brent crude in the month of May. But data from refineries across several regions shows weak margins, or "crack spreads" — the difference between the price of crude that refiners buy versus the price that the market is paying for the refined products. Higher crude costs without increased returns for the products refineries are selling suggests demand growth isn't in line with the growth in prices, and could force refineries to buy lower crude volumes, translating into lower crude prices. "One word of caution is if we look at the rally we've seen in crude oil prices, it's been amazing, but the big uncertainty is if you look at refinery margins, they are very weak across the board across all regions," Warren Patterson, head of commodities strategy at ING. "And what that suggests is that maybe demand isn't recovering as quickly as many had anticipated, or at least it's not keeping up with the move higher that we've seen in crude oil prices." The crack spread for refined products in the U.S. was at $9 last week, compared to $21 at the same time last year, Reuters reported, citing Refinitiv Eikon data. Margins for European diesel reached a record low of $2.90 per barrel last week. "Very poor refining margins and the recent sharp decline in U.S. crude bases now comfort us in our sequentially bearish outlook," analysts at Goldman Sachs wrote this week. They see Brent pulling back to $35 per barrel in the coming weeks, compared to spot prices at $43. And soon to pressure refineries further is Saudi Aramco's announcement over the weekend that it's raising official selling prices (OSPs) for all of its customers in July, and for some the highest increases in twenty years. Saudi selling prices will spike next month by $5 to $7 per barrel just for Asian buyers, for instance — "again further hitting refining margins," Patterson said. What refineries need is for the demand side to match up with the steady revival of crude prices, expected to gradually improve as economies reopen and lift their lockdowns meant to stem the spread of the coronavirus. "Refiners are facing weak cracks (margins) at the moment and the current pick-up in crude prices will only make them worse,"
Oil falls 3% despite OPEC+ cuts as Gulf ends voluntary curbs - Oil fell more than 3% on Monday after OPEC+ nations agreed to extend output cuts, but Saudi Arabia and two other Gulf producers said they would not maintain supplemental reductions that amount to more than a million barrels of daily supply. Brent crude fell, breaking a seven-day streak of gains. Brent futures fell $1.50, or 3.6%, to settle at $40.80 a barrel. US West Texas Intermediate crude (WTI), meanwhile, fell $1.36, or 3.4%, to $38.19. The Organization of the Petroleum Exporting Countries, Russia and other producers agreed in April to cut supply by 9.7 million barrels per day (bpd) in May and June to support prices as coronavirus lockdowns caused demand to collapse. The group, known as OPEC+, agreed on Saturday to sustain those cuts, equal to about 10% of global supply, through July. However, Saudi Energy Minister Prince Abdulaziz bin Salman said on Monday that the kingdom and Gulf allies Kuwait and the United Arab Emirates would not continue an additional 1.18 million bpd in reductions. "It would be too good to be true to have a total of nearly 11 million bpd in voluntary cuts extended for a month at times when we see supply deficits," said Bjornar Tonhaugen, analyst at Rystad Energy. US shale producers, meanwhile, have started to reopen closed wells as prices have rebounded. Analysts said this could undercut the fragile demand recovery, and undermine OPEC's efforts to shore up prices. Saudi Arabia, in addition, raised prices for its crude, anticipating stronger demand. "US production is returning to the market, and there is speculation that the huge increase in Saudi (prices) will kill already struggling refiner margins in Asia," said Bob Yawger, director of energy futures at Mizuho in New York. China, the world's largest crude importer, said purchases hit a record high of 11.3 million bpd in May.
Why Oil Prices Didn’t Rally After The OPEC+ Extension - OPEC+ agreed to extend the production cuts for another month, but with the extension mostly baked into market expectations, it has done little for oil prices at the start of the week. Meanwhile, the U.S. officially entered an economic recession in February.. Even as OPEC+ agreed to extend the production cuts for another month, Saudi Arabia said that it would end the extra supply cuts that it had imposed in the second quarter. “The voluntary cuts served their purpose and we are moving on,” Prince Abdulaziz said in a press briefing on Monday. Revenues from Saudi oil exports plunged by nearly 22 percent in the second quarter, a decline of $11 billion. Saudi Arabia increased the official selling price for its oil by the most in two decades, with Saudi Aramco raising prices of Arab Light to Asia by $6.10 per barrel. The move is a sign that Saudi Arabia wants to continue to boost the oil market by erasing all the discounts it offered at the start of the price war several months ago. Weak refining margins could kill the oil price recovery, according to a new report from Goldman Sachs. If refiners pull back on processing, crude will pile up, pushing down prices. Other analysts see the same trend. “One word of caution is if we look at the rally we’ve seen in crude oil prices, it’s been amazing, but the big uncertainty is if you look at refinery margins, they are very weak across the board across all regions,” Warren Patterson, head of commodities strategy at ING, told CNBC. The retreat of the Libyan National Army from the siege on Tripoli could pave the way for more Libyan oil to hit the global market. On Saturday, Libya restarted production at its largest oil field, the Sharara, which could bring 300,000 bpd back online. But a day later, the field shutdown after an armed group stormed the facility.. Tropical Depression Cristobal forced 34 percent of U.S. offshore oil production to be temporarily taken offline.
Goldman Sachs says an oil price correction as deep as 20% 'may already be underway' - Goldman Sachs sees a correction in oil prices on the horizon even amid a significant recovery in the last month and the recent decision by OPEC and its allies to extend historically large production cuts through July. "With oil now above $40/bbl, supplies will be incentivized to return, but we believe the risks to the downside have increased substantially and are now looking for a 15-20% correction which may already be underway after Monday's modest sell-off," Goldman Sachs' commodities research team led by Jeffrey Currie wrote in an analyst note on Tuesday. "Despite the rally, we have been hesitant to recommend a long position this early in the cycle for several reasons," the analysts wrote. For one, it's because of surplus inventory that still very much exists — by an estimated 1 billion barrels, piled up as the world's economic activity and travel remains largely at a standstill amid coronavirus fears. Goldman also describes the commodities rally as having gotten "ahead of fundamentals" with metals the only exception, and noted that returns on commodity indexes are still well behind spot price growth — and you can't invest in spot commodity rates. That disparity is exemplified by the fact that fund inflows from retail investors since the start of April "have generated a -20% return despite a 95% rally in spot WTI prices." Some analysts believe it could take until the middle of 2021 to reverse the inventory build, and that's assuming that demand does recover and OPEC sticks to its cutting quotas.
Energy investing is 'speculative gambling,' says pro with 20 years in the industry - Since dropping into negative territory for the first time on record in April,West Texas Intermediate, the U.S. oil benchmark, has staged a record rebound and now trades around the $39 level. But David Ramsden-Wood, who has 20 years of experience in the industry and was previously COO of OneEnergy Partners, said the recent run is nothing to cheer about, and investors should steer clear of the sector. "I have a hard time seeing oil above $40, and I would probably say it averages $30 for the next 12 to 18 months as supply around the world, and in particular in the U.S. and Canada, comes down to match global demand," he said Tuesday in discussion with CNBC's Brian Sullivan during the latest installment of the LIVE PRO Talk series.
Oil Prices Fall As EIA Confirms Crude Inventory Build Crude oil prices accelerated their fall today after the Energy Information Administration reported a rise in U.S. crude oil inventories of 5.7 million barrels for the week to June 5 and an increase in fuel inventories.A day earlier, the American Petroleum Institute reported a crude oil inventory build of 8.42 million barrels, which caused prices to dive after several days of gains. Analysts had expected the EIA to report an inventory decline of 1.45 million barrels for last week. A week earlier, the EIA reported a decline in crude oil inventories, at 2.1 million barrels.In gasoline, the authority reported an inventory increase of 900,000 barrels for the week to June 5, down from a build of 2.8 million barrels a week earlier. Gasoline production last week averaged 8.1 million bpd, compared with 7.8 million bpd a week earlier.In distillate fuels, inventories went up by 1.6 million barrels last week, which compared with a hefty 9.9-million-barrel increase a week earlier. Distillate fuel production averaged 4.8 million barrels daily, compared with 4.7 million bpd a week earlier.Refinery runs rose last week, to average 13.5 million bpd. This compared with 13.3 million bpd a week earlier. Capacity utilization averaged 73.1 percent, compared with 71.8 percent a week earlier.Before the API shocked traders with its estimated inventory build, oil was trendinghigher on hopes the market would soon rebalance. However, there was downward pressure following news that U.S. producers were restarting production and worry that some Middle East producers, notably Iraq, will continue to produce more than their OPEC+ quota calls for. At the time of writing, Brent crude was trading at $40.40 a barrel, with West Texas Intermediate at $38.10 a barrel, both down by about two percentage points from opening today.
US Crude Oil Stockpile Reaches Record High, Production Hits 20-Month Lows - WTI is trading lower this morning after API's report signaled a surprise jump in crude inventories, underscoring the market’s patchy road to rebalancing. All eyes now focused on the official data to see if API's data was right (both crude and distillates which saw a big build - not a good sign in working off the stubborn diesel glut that is holding back the oil market’s broader recovery... DOE:
- Crude +5.72mm (-1.2mm exp)
- Cushing -2.279mm
- Gasoline +866k (-200k exp)
- Distillates +1.568mm (+2.9mm exp)
DOE data confirmed API's reported surprise crude build, but at 5.72mm it was less than API's. Distillates also saw another build - the 10th weekly build in a row)... Notably, as Bloomberg's Julian Lee explains, with space in the Strategic Petroleum Reserve being rented out to producers, it is vital to include movements of crude into and out of the reserve in assessments of stockpile movements at this time. And total crude stockpiles, including commercial and SPR inventories, rose by 8 million barrels last week, that’s the second largest build in the past six weeks. Graphs Source: Bloomberg EIA actually reports that U.S. Crude Oil inventories rise to record highs at 538.1M Bbl.
Oil prices finish higher, with the U.S. dollar weaker on Fed plan to keep interest rates near zero - Oil futures finished higher on Wednesday, buoyed by weakness in the dollar that followed the Federal Reserve’s announcement that it plans to keep interest rates at near zero through 2022.The U.S. dollar got hammered after the Fed’s statement, pushing crude prices toward the highs for the day “after a bearish-tilted EIA report,” said Matt Smith, director of commodity reach at ClipperData.The Fed said that it would do what it takes to support the economy—easing worries about energy demand.The news from the central bank helped to offset earlier pressure from U.S. government data that showed a weekly climb of nearly six million barrels for U.S. crude inventories and a grim forecast from the OECD on the global economic outlook.“The fact that the Fed expects zero interest rates through 2022 supported financial markets including energy futures,” Marshall Steeves, energy markets analyst at IHS Markit, told MarketWatch.Also providing support, in the latest U.S. petroleum data showed that demand is “starting to perk up with refinery utilization recovering to satisfy higher demand for gasoline and distillates,” he said. The revival in demand, combined with an extension of production cuts by major producers through July, “are adding up to a global market rebalancing.” West Texas Intermediate crude for July delivery CL.1, -2.50% CLN20, -2.50%, the U.S. benchmark, rose 66 cents, or 1.7%, at $39.60 a barrel on the New York Mercantile Exchange, after touching an earlier low of $37.73. The settlement was the highest since March 6, according to Dow Jones Market Data.
Record US Crude Stockpiles Reveal Cracks in Oil Market Recovery-- Swelling U.S. oil stockpiles are signaling that a difficult path lies ahead for OPEC and its allies who are trying to stabilize the market with record output cuts. Just weeks after American explorers began shutting in wells in the wake of a slump in demand, a recent recovery in crude is prompting some producers to turn the taps back on at a time when a fresh onslaught of the virus challenges pockets across the country. A month into the state’s reopening, Florida this week reported the most coronavirus cases of any seven-day period. In Texas, hospitalizations on Tuesday jumped to the highest since the pandemic emerged, rising for a third consecutive day. California’s hospitalizations are at their highest since May 13. Those gains in cases are leading to concern that oil’s rebound may unwind if governments implement lockdowns again. The OECD is forecasting a sharp contraction in the global economy this year that could get worse if there’s a second wave of virus infections. “Demand isn’t coming back fast enough, and supply is coming down more slowly than the market needs,” said Rob Haworth, senior investment strategist at U.S. Bank Wealth Management in Seattle. American oil stockpiles reached 538.1 million barrels last week, the highest level in data going back to 1982, according to Energy Information Administration data, even though American production has fallen by at least 2 million barrels a day since mid-March. In the U.S., more excess oil is being sent for storage to the Strategic Petroleum Reserve, which rose by 2.2 million barrels last week to the highest level since November 2018. Rising inbound crude shipments drove stockpiles to a record in the Gulf Coast, with the region accounting for the lion’s share of the inventory increase. Net petroleum imports stand at the highest since August.
Oil Slides After US Crude Stockpiles Expand -- Oil slumped in New York as an increase in American crude stockpiles to a record high raised fresh concerns about excess supply, while the Federal Reserve forecast a long road to recovery for the U.S. economy. Futures lost 4.1% to trade near $38 a barrel, erasing all of the gains from the past two sessions. Crude inventories unexpectedly rose last week, even as oil production fell, while gasoline stockpiles also saw a surprise expansion. Fed Chairman Jerome Powell said the pandemic could inflict longer-lasting damage on the economy and the central bank signaled it would keep rates near zero possibly for years to come. There are also fears that a second wave of infections in the U.S. may derail its fragile recovery. Global supply cuts and the easing of lockdowns in some countries has pushed prices higher after oil plunged below zero in April. However, the recovery is expected to be fragile and uneven, and there are concerns that producers may pump more with crude above $30 a barrel, adding to a glut. A new wave of coronavirus infections pushed the overall count in the U.S. past 2 million cases, with hospitalizations in Texas jumping. “Prices may have run ahead of themselves over the last month or so,” Howie Lee, an economist at Oversea-Chinese Banking Corp. in Singapore, said by phone. “As we approach the second half of the year, there will be some rethinking about how far this rally can continue given the high volume of stockpiles that still exists.” West Texas Intermediate for July delivery fell $1.61 to $37.99 a barrel on the New York Mercantile Exchange as of 7:10 a.m. London time after rising 1.7% on Wednesday Brent crude for August delivery lost 3.5% to $40.26 on the ICE Futures Europe exchange after adding 1.3% in the previous session U.S. crude stockpiles rose by 5.72 million barrels last week to 538.1 million barrels, according to the Energy Information Administration. That’s the highest level in data compiled by Bloomberg since 1982. Still, oil production fell for a 10th week, while supplies at the key storage hub of Cushing, Oklahoma, dropped below 50 million barrels.
Oil drops more than 10% as fears over second wave of coronavirus cases hit the market -- Oil prices dropped more than 8% on Thursday amid a broader market sell-off as fears over a second wave of coronavirus cases led to investors shedding assets. West Texas Intermediate crude futures, the U.S. oil benchmark, fell 10.25%, or $4.00, to trade at $35.60 per barrel. International benchmark Brent crude slid 8.7%, or $3.56, to trade at $38.17 per barrel. Oil has been rallying on the back of an uptick in demand paired with record supply cuts, but data on Wednesday from the U.S. Energy Information Administration showed a surprise build in inventory, suggesting that the demand recovery may have stalled. For the week ending June 5, inventory rose by 5.7 million barrels to a record high of 538.1 million barrels. Another key driver of WTI's recent recovery, which has seen prices jump more than 50% in the last month, has been producers curbing output. Over the weekend, OPEC and its oil-producing allies agreed to extend its record production curb — equivalent to about 10% of pre-coronavirus global demand — through the end of July. In the U.S., production has pulled back from a record of over 13 million barrels per day in March as historically low prices prompted companies to reduce output. But with oil moving higher in recent weeks, some producers have begun to open the taps once again, which could send prices lower. "The higher price levels that we experienced lately have motivated producers to restart some of their shut-down production, in effect reversing a bit the positive price effect that lower production had created," said Paola Rodriguez Masiu, senior oil markets analyst at Rystad Energy. "How prices develop further will depend a lot [on] how much and how quickly this shut production will come back to business," she added. "The global economy is still in a precarious position," noted Cailin Birch, global economist at The Economist Intelligence Unit. "The dip in oil prices in recent days most likely reflects the end of the price boost that came from the initial economic re-opening. The global economy is now settling in for a long, slow recovery process, which we only expect to pick up in late 2021, assuming a Covid-19 vaccine becomes available then," she added.
Oil prices slump 8% as virus-related demand concerns resurface - (Reuters) - Oil prices tumbled about 8% a barrel on Thursday, fuelled by renewed concerns about demand destruction as new cases of coronavirus tick up globally, while crude inventories hit a record in the United States. U.S. coronavirus cases surpassed 2 million on Wednesday, according to a Reuters tally, and new infections are rising slightly after five weeks of declines. While most states have loosened restrictions on movement that shackled demand, fuel consumption remains 20% below typical levels, as consumers remain cautious. The U.S. Federal Reserve has expressed concern that this will continue, limiting demand. “A series of local spikes could have the effect of undermining people’s confidence in travelling, in restaurants, entertainment,” Fed Chair Jerome Powell said on Wednesday. Brent crude LCOc1 futures fell $3.18, or 7.6%, to settle at $38.55 a barrel. U.S. West Texas Intermediate (WTI) crude CLc1 fell $3.26, or 8.2%, to settle at $36.34 a barrel. Brent and WTI posted their worst daily drops since April 21 and 27, respectively. The weakness extended to other asset classes. Equity markets dropped, with the S&P 500 Index down 4% on the day, while U.S. Treasury bonds rallied. Crude futures have gained in recent weeks as government-imposed lockdowns eased, prompting optimism that fuel demand would recover. In parts of Asia and Europe, where the lockdowns were more severe, demand has recovered more sharply.
Oil Falls the Most in Six Weeks, Signaling a Fragile Recovery-- Oil fell the most since late April as economic uneasiness iced U.S. stock markets, threatening to spoil crude’s recovery from a historic drop below zero. The market is grappling with record high U.S. oil inventories and an uneven demand rebound as signs mount that a second wave of the pandemic could be taking hold in some states. U.S. jobless claims remained high, underscoring longer-term macroeconomic challenges a day after the Federal Reserve provided a grim outlook for the economy. Oil’s recovery has been driven by production cuts and the easing of pandemic-related lockdowns. “It was very fast, driven by historically unprecedented OPEC+ cuts and central bank and government support on the demand side,” said Bart Melek, head of commodity strategy at Toronto Dominion Bank. “We should not be surprised to see a pullback, following such a violent rally,” he said. On the supply side, higher prices have pushed some producers to turn on the taps. U.S. crude stockpiles rose last week to 538.1 million barrels, according to the Energy Information Administration. That’s the highest level in data compiled by Bloomberg since 1982. “The surprisingly bearish stats, particularly on crude, the relatively dour comments by the Fed yesterday and fears of a resurgence of the coronavirus have all added to the price weakness today,” said Thomas Finlon, of Houston-based GF International. West Texas Intermediate for July delivery fell $3.26 to settle at $36.34 a barrel in New York, the biggest drop since April 27. Brent crude for August delivery dropped $3.18 to close at $38.55 a barrel, the biggest decline since April 21. Crude’s inability to sustain prices over $40 a barrel is leaving many companies across the industry in dire straits. “A couple months ago, the sector was in complete survivor mode, and it still needs to be, quite frankly,” said Jennifer Rowland, an analyst at Edward Jones & Co. “Even at $45, there will be a lot of companies that can’t survive,” she said. “Companies are still going to be bleeding cash at this level.”
Oil prices extend slump as U.S. coronavirus cases climb - Oil prices slid early on Friday, extending heavy overnight losses on a surge in U.S. coronavirus cases this week that has raised the prospect of a second wave of the outbreak slamming demand in the world's biggest consumer of crude and fuel. West Texas Intermediate was down $1.32, or nearly 4%, at $35.02 a barrel by 0011 GMT, after slumping more than 8% on Thursday. Brent crude was down $1.15, or 3%, at $37.40 a barrel, having dropped nearly 8% the previous session. A rally off April's lows has come to a shuddering halt this week as the market faced the reality that the coronavirus pandemic may be far from over globally, with cases in the United States alone passing 2 million this week. The oil benchmarks are heading for their first weekly decline in seven, with Brent dropping about 12%, while U.S. crude is heading for a loss of more than 10%. "A sustainable rally needs to include improving gasoline demand, reducing inventories, increasing product margins to the point where refiners kickstart runs," RBC Capital Markets said, noting that "U.S. driving patterns are far from normal." While producers have been cutting supply, demand remains constrained by the outbreak, with gasoline stockpiles in the U.S. last week rising more than expected to 258.6 million barrels, according to government data. U.S. crude inventories rose against forecasts by 5.7 million barrels to a record 538.1 million barrels, as cheap imports from Saudi Arabia flowed into the country. In the meantime, states including Texas and Arizona are struggling to cope with a rising number of coronavirus patients filling hospital beds. In Houston, Lina Hidalgo, the senior official for the county that includes the city that is the heart of the U.S. oil industry, warned "we may be approaching the precipice of a disaster". More than 7.43 million people have been infected by the novel coronavirus around the world and more than 400,000 have died, according to a Reuters tally.
Oil prices end slightly lower, post first weekly loss in 7 weeks - Oil futures settled at a modest loss on Friday, with U.S. and global benchmark prices suffering their first weekly decline in seven weeks on worries about oversupply and a resurgence of coronavirus cases in the U.S. Oil is likely to “remain vulnerable and exposed to downside shocks thanks to coronavirus-related concerns,” said Lukman Otunuga, senior research analyst at FXTM. “The possibility of renewed lockdowns and delayed global economic recovery is bad news for oil, which remains one of the biggest causalities of the coronavirus menace,” he told MarketWatch. Although OPEC+ agreed to extend production cuts by another month, in the grand scheme of things this may offer little support to oil, which is in “a losing battle with COVID-19 and world growth fears,” he said. West Texas Intermediate crude for July delivery CL.1, +0.82% CLN20, +0.82%, the U.S. benchmark, fell 8 cents, or 0.2%, to settle at $36.26 a barrel on the New York Mercantile Exchange—the lowest finish for a most-active contract since June 1, according to Dow Jones Market Data. The contract tumbled 8.2% on Thursday to mark the sharpest one-day fall since April 27. Global benchmark Brent oil for August delivery BRNQ20, +0.80%, however, added 18 cents, or 0.5%, to end at $38.73 a barrel on ICE Futures Europe, following a 7.6% plunge Thursday, its steepest such slide since April 21, that took it to its lowest finish since June 1. For the week, WTI marked weekly slide of 8.3%, while Brent saw a decline of 8.4%. That represented the first weekly losses for the two crude benchmarks since the week ended April 24.
OPEC+ mostly met cutting targets in May, but future compliance — and its enforcement — is uncertain - The 23 member states of OPEC+, comprised of OPEC and ten of its oil-producing allies, for the most part delivered on record production cuts agreed to by the alliance through the month of May, a new report shows. "OPEC's 13 members dropped their output to 24.32 million b/d, for a compliance rate of 82% with their prescribed cuts," S&P Global Platts found in a survey released Wednesday. The ten non-OPEC members, which include Russia, pumped a combined 13.89 million barrels per day comprising 91% of their cuts, bringing OPEC+'s collective compliance to 85%, Platts reported. Following the coronavirus pandemic-induced plunge in oil prices, OPEC+ embarked on the largest coordinated oil production cut regime in history in May. They agreed to cut 9.7 million bpd in an effort to support the market, amounting to about 10% of global oil supply. In total, Platts found that the coalition managed to reduce its output by a combined 8.28 million bpd for the month. The OPEC+ alliance agreed over the weekend to extend the cuts through July, with Saudi Energy Minister Abdulaziz bin Salman asserting that this time there would be "no room whatsoever for lack of conformity." But the pacts have traditionally been difficult to enforce, with some members — particularly Iraq and Nigeria — falling behind on their cutting commitments, and OPEC kingpin Saudi Arabia shouldering the overwhelming majority of cuts, often slashing their output by more than their required quota. Iraq, OPEC's second-largest producer, was the group's biggest offender, pumping 4.19 million bpd in May — some 600,000 bpd over its agreed limit. Nigeria, Angola and Gabon, as well as non-OPEC states Kazakhstan and Azerbaijan, were among the other laggards. The group's most recent agreement included a promise by non-compliant countries to compensate for any barrels they didn't cut in May or June by making deeper reductions between July and September. Iraq's oil ministry said this week it is "fully committed" to cutting its production from June onward in accordance with the OPEC+ deal.
Mediterranean Oil Tensions Are Boiling Over - Under pressure in Libya - where it’s gone head-to-head with General Haftar in an ongoing battle to decide who gets to ultimately control the country’s oil revenues - and floundering in Syria, Turkey is once again upping the ante in the Mediterranean, this time preparing to issue new oil and gas exploration licenses in direct confrontation with the European Union. It’s not just about Cyprus, anymore. Turkey’s state-run oil and gas company has been given licenses from the Turkish government to explore for oil and gas in 24 locations in the East Mediterranean. Seven of those locations are just off the coast of key Greek islands. It’s a direct provocation that has Greece infuriated, and experts are worried that this could lead to direct clashes once Turkey starts exploration drilling. Last weekend, Turkey released a draft plan for Turkish Petroleum’s exploration license. On Monday, Greek Foreign Minister Nikos Dendias said in a statement that the country “stands ready to deal with this provocation should Turkey decide to implement this decision”. The draft plan explicitly violates Greek sovereignty, and it is designed to take advantage of a new maritime boundary agreement Erdogan wrangled last year with the Government of National Accord (GNA) in Libya. This was the trade-off for Libya’s aid in fighting back General Haftar in his push to take the Libyan capital, Tripoli. The maritime boundary is meant to perform a pincer movement against Cyprus, which is drilling offshore in its EEZ where Turkey has also provocatively deployed drillships. In the Greek Cypriot EEZ alone, there are an estimated 120 billion cubic meters of natural gas, for which drilling began in 2011. The first license here was granted in 2008 to American Noble Energy (the same company behind the massive Israeli discoveries). Erdogan’s desperation is born out of the fact that Turkey is being squeezed out of a role in the oil and gas riches of the Mediterranean, which is arguably the world’s next biggest, untapped oil and gas hotspot. His latest move to issue more exploration licenses, even encroaching on Greek maritime territory, comes after Israel, Greece and Cyprus signed an agreement to build an underwater pipeline to carry Israeli gas to Europe, cutting out Turkey altogether.
Libya's National Oil Corp declares force majeure on largest oil field after militia shutdown - Libya's National Oil Corporation has declared force majeure on exports from its largest oil field Tuesday, after a militia group shut it down just days after it resumed production following a six-month blockade. "The armed group, which came from Sebha, stormed the Sharara oil field and pulled their guns on civilian unarmed workers, coercing them to stop production at the field at dawn," the state oil company said in a statement. Workers at the massive Sharara oil field have shut it down at the demands of the armed group's leader Mohamed Khalifa, who is linked to the renegade general Khalifa Haftar's Libyan National Army, the instigator of a violent power struggle with Libya's UN-recognized government that's lasted more than a year. Haftar's forces pulled back in May after a prolonged campaign to capture the capital Tripoli failed. Oil prices saw a slight "last-minute injection of upward buying pressures" Tuesday on the Libya news and worries over its stability, Stephen Brennock, an oil analyst at PVM Oil Associates, wrote Wednesday morning. "A few days after returning from a multi-month shutdown, the Sharara field went offline only to restart and suffer a second stoppage in the space of a few hours." "Simply put, a sustained recovery in Libya's oil production is not currently on the cards." Libya's southwestern Sharara field previously had a 300,000 barrel per day output, and was resuming production gradually after reopening on Saturday. It's now in renewed jeopardy after a long period of shutdown that began in January amid fighting that took the majority of the OPEC state's oil production offline. As warring factions within the country attempted to use the key commodity to seize control, output in Africa's third-largest oil producing nation plummeted in late January from around 1.2 million bpd to just over 320,000 bpd and is now estimated to be around a mere 90,000 bpd. The crisis exempted Libya from OPEC's production cut agreement meant to stabilize oil prices. The country's petroleum sector represents 95% of its export earnings and 60% of its GDP.
The purveyors of death cough up loose change for Yemen - A so-called humanitarian aid conference for Yemen last week raised a paltry $1.35 billion, some $1 billion short of the target and less than half the $3.2 billion raised last year. The Saudi monarchy, which has spent $5 to $6 billion per month for the last five years on a criminal war against Yemen, primarily fought from the air, pledged just $500 million. Riyadh insisted $200 million of its donation would be spent through Saudi aid programmes, not those sanctioned by the United Nations (UN). It later emerged that this was not new money but money that had been pledged earlier and not delivered. The US, UK, Norway and Germany contributed most of the remainder, small change compared to the sales value of their weaponry—supplied to the Saudi Arabian military—that has devastated the Arab world’s poorest country. The United Arab Emirates (UAE), the other major participant in the war, made no commitment to the UN’s aid appeal. Dr. Abdullah al-Rabiah, the head of the King Salman Centre for Relief and Humanitarian Aid in Saudi Arabia that co-hosted the virtual conference, ascribed the shortfall to the impact of coronavirus on national budgets, omitting to say that every one of the participants had made billions available to their own corporations and financial institutions, including their arms manufacturers. Unless more money was raised, said Mark Lowcock, head of the United Nations Office for the Coordination of Humanitarian Affairs, Yemen “will face a horrific outcome at the end of the year”. He added, “Yemen is now on the precipice, right on the cliff edge, below which lies a tragedy of historic proportions.” The irony of appealing to the very forces that had produced this “tragedy of historic proportions” seems to have escaped him and the world’s press reporting on a conference that served to absolve the major participants of their crimes. It came as no surprise that the response to the aid appeal was a noxious combination of hypocrisy, indifference and bullying.
Palestinians come out in force to protest US-backed Israel plan -Hundreds of Palestinians have rallied in the city of Hebron in southern West Bank against a United States-backed Israeli plan to annex huge swathes of the occupied territory. The rallies were held on Friday on the anniversary of Israel’s 1967 occupation of the West Bank and the Gaza Strip. Israel occupied the territories during a Western-backed war that year. It was forced to leave Gaza in 2005 but keeps the coastal sliver under a crippling siege. Across the West Bank, Israel has illegally built over 230 settlements that house more than 600,000 Israelis. The rallies that had been called by West Bank-based Palestinian political factions took place in protest against a plan announced by Israel’s prime minister Benjamin Netanyahu to annex the areas where the settlements have been built and the Jordan Valley. The areas that are targeted by the regime’s scheme comprise 30 percent of the West Bank. Netanyahu announced the plan emboldened by a hugely-controversial plot that was detailed and backed by US President Donald Trump on January 28. The protesters on Friday chanted anti-Israeli and anti-Washington slogans, waved Palestinian flags, and held up banners some of which read, “No to the policy of annexation of the West Bank. No to division of Hebron.” “Today is a day for general mobilization in all of the country’s governorates against the annexation deal, which was announced by Netanyahu, and in rejection to Trump’s ‘deal of the century,’” one demonstrator said, referring to the US plot by the ironic name that has been assigned to it by the US president. If you want to continue to read our work and help us produce more news and reports from Palestine, click here for our fundraising campaign The participants, the protester said, were seeking “to send a message to the world, especially Israel, that the people will not accept any solution less than a Palestinian state on the 1967 borders with Jerusalem to be the capital.” Another participant said the protest was one that “rejects and condemns all Israeli measures and is against the American administration’s bias in favor of Israel.” The US plot also re-endorsed Washington’s incendiary recognition of as Israel’s “capital.” The recognition that came during Trump’s presidency flies in the face of Palestinians’ age-old demand that the city’s eastern part serve as the capital of their future state. Since the US’s unveiling of the plot, Palestinians have stopped recognizing any intermediary role by Washington in the Palestinian-Israeli conflict.
China to cut teapot refining capacity as plans for mega complex (Reuters) - China’s oil hub Shandong has embarked on a plan to shut down capacity of half a million barrels per day shared among small, independent refiners to make way for a giant complex that should spur economic recovery from the coronavirus crisis. Reuters exclusively reported last week that China, the world’s largest oil consumer after the United States, was going ahead with the $20 billion Yulong Petrochemical complex. The planned 400,000 barrel-per-day (bpd) refinery and 3 million tonne-per-year ethylene plant in Yantai, Shandong, the country’s hub for independent refineries, sometimes referred to as teapot refineries, had long failed to get approval as China struggled with excess refining capacity. The drop in demand because of coronavirus lockdowns, as well as expectations climate concerns will reduce conventional motor fuel use, is likely to increase over-supply in the near term. But state approval was granted last week for a new mega refining complex, weighted towards petrochemical production whose demand is expected to be relatively robust. That has prompted Shandong to accelerate a plan dating from 2018 to close 500,000 bpd in capacity over the next two-to-three years, Shandong-based industry officials and consultancies said.That amounts to 20% of Shandong’s capacity, made up of more than 60 small plants.
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