oil prices rose for a sixth straight week to close at a 3 month high this week on improving US economic data and on hopes that OPEC would announce an extension of their production cuts at a meeting rescheduled for Saturday....after rising 6.7% to $35.49 a barrel last week on the apparent success of the OPEC+ production cuts, the contract price of US light sweet crude for July delivery opened lower on Monday as oil traders hedged bets in advance of the possible OPEC+ meeting this week to discuss whether to extend production cuts beyond June, but steadied to finish down just 5 cents at $35.44 a barrel as rising U.S.-China tensions weighed on sentiment even in the face of reports that OPEC and Russia were close to a deal on extending output cuts...oil opened higher and continued rising through Tuesday on reports that Saudi Arabia and Russia were close to inking a two-month extension of the current oil production cuts through September 1st and finished $1.37 higher at $36.81 a barrel as economic activity began to recover after the easing of coronavirus lockdowns...oil prices then erased most of Tuesday's gains early on Wednesday on doubts that the OPEC meeting would go ahead as planned, but rallied late iin the session to finish 48 cents higher at $37.29 a barrel as prices were supported by a reported drawdown of U.S. crude inventories...oil prices were little changed on Thursday as investors awaited a decision from crude producers on whether to extend their record output cuts and settled 12 cents higher $37.41 a barrel...oil prices spiked higher early on Friday after an unexpected drop in the US jobless rate and then rallied to a $2.14 increase at $39.55 a barrel on Opec's decision to bring forward to Saturday their discussion of extended output cuts, thus finishing the week more than 11% higher, with both US and international prices finishing at their highest level since March 6th...
Meanwhile, natural gas prices finished the week lower as traders watched the daily changes in natural gas output and US LNG exports for supply & demand clues... after slipping 3.2 cents or 1.7% to $1.849 per mmBTU last week on falling demand for LNG, the contract price of natural gas for July delivery opened lower on Monday despite forecasts for warmer weather and higher air conditioning demand and tumbled to a 4% loss at $1.774 per MMBTU, as US LNG exports continued to drop in the face of record low gas prices in Europe and Asia...natural gas traded in a narrow range on Tuesday and finished three-tenths of a cent higher, and then rose 4.4 cents to $1.821 per mmBTU on Wednesday on improving supply and demand balances, as traders watched a tropical storm that could disrupt Gulf Coast production and as LNG exports edged up with higher gas prices in Europe...natural gas ended little changed at $1.822 per mmBTU on Thursday as rising LNG exports offset a smaller-than-expected weekly storage build and an increase in natural gas output, but then fell back 4 cents to end the week 3.6% lower at $1.782 per mmBTU on forecasts for milder weather and lower air conditioning demand through mid-June....
the natural gas storage report from the EIA for the week ending May 29th indicated that the quantity of natural gas held in underground storage in the US rose by 102 billion cubic feet to 2,714 billion cubic feet by the end of the week, which left our gas supplies 762 billion cubic feet, or 39.0% higher than the 1,952 billion cubic feet that were in storage on May 29th of last year, and 422 billion cubic feet, or 18.4% above the five-year average of 2,292 billion cubic feet of natural gas that has been in storage as of the 29th of May in recent years....the 102 billion cubic feet that were added to US natural gas storage this week was less than the consensus forecast for a 111 billion cubic feet increase from a survey of analysts by S&P Global Platts, while it was close to the average 103 billion cubic feet of natural gas that have been added to natural gas storage during the same week over the past 5 years and was somewhat below the 118 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 May 29th showed that due to a drop our oil imports, a decrease in crude production, an increase in refining, and a big addition to the SPR, we had to withdraw oil from our stored commercial supplies of crude oil for the third time in four weeks, and for the 11th time in the past thirty-eight weeks....our imports of crude oil fell by an average of 1,021,000 barrels per day to an average of 6,179,000 barrels per day, after risng by an average of 2,003,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 382,000 barrels per day to an average of 2,794,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,385,000 barrels of per day during the week ending May 29th, 639,000 fewer 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 200,000 barrels per day to 11,200,000 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 14,585,000 barrels per day during this reporting week..
meanwhile, US oil refineries reported they were processing 13,307,000 barrels of crude per day during the week ending May 29th, 316,000 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 278,000 barrels of oil per day were being added to the supplies of oil stored in the US....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 1,001,000 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 (-1,001,000) 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 numbers often drive oil pricing and hence decisions to drill for oil, we'll continue to report them, 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 5,992,000 barrels per day last week, which was still 18.3% less than the 7,336,000 barrel per day average that we were importing over the same four-week period last year....the 278,000 barrel per day net addition to our total crude inventories included a record 574,000 barrels per day that were added to our Strategic Petroleum Reserve, which was partly offset by a 297,000 barrels per day withdrawal from our commercially available stocks of crude oil ....this week's crude oil production was reported to be down by 200,000 barrels per day to 11,200,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was down by 200,000 barrels per day to 10,800,000 barrels per day, while a 32,000 barrel per day decrease in Alaska's oil production to 380,000 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 May 31st was rounded to 12,400,000 barrels per day, so this reporting week's rounded oil production figure was about 9.7% below that of a year ago, yet still 32.9% 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 71.8% of their capacity while using 13,307,000 barrels of crude per day during the week ending May 29th, up from 71.3% of capacity during the prior week, but still among the lowest refinery utilization rates of the last thirty years...hence, the 13,307,000 barrels per day of oil that were refined this week were 21.4% fewer barrels than the 16,938,000 barrels of crude that were being processed daily during the week ending May 31st, 2019, when US refineries were operating at 91.8% of capacity....
with the increase in the amount of oil being refined, gasoline output from our refineries was quite a bit higher, increasing by 608,000 barrels per day to 7,779,000 barrels per day during the week ending May 29th, after our refineries' gasoline output had increased by 5,000 barrels per day over the prior week... however, since our gasoline production is still recovering from a multi-year low, this week's gasoline output was still 22.6% lower than the 10,049,000 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) decreased by 66,000 barrels per day to 4,714,000 barrels per day, after our distillates output had decreased by 24,000 barrels per day over the prior week...after this week's decrease in distillates output, our distillates' production was 12.8% less than the 5,404,000 barrels of distillates per day that were being produced during the week ending May 31st, 2019....
with the big increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 2nd time in 6 weeks and for the 6th time in 18 weeks, rising by 2,795,000 barrels to 257,795,000 barrels during the week ending May 29th, after our gasoline supplies had decreased by 724,000 barrels over the prior week...our gasoline supplies also increased this week because our imports of gasoline rose by 490,000 barrels per day to 782,000 barrels per day, while our exports of gasoline rose by 53,000 barrels per day to 263,000 barrels per day, while the amount of gasoline supplied to US markets increased by 296,000 barrels per day to 7,549,000 barrels per day ....with this week's inventory increase, our gasoline supplies were 10.1% higher than last May 31st's gasoline inventories of 234,149,000 barrels, and roughly 10% above the five year average of our gasoline supplies for this time of the year...
even with the decrease in our distillates production, our supplies of distillate fuels increased for the ninth time in 20 weeks and for the 14th time in 35 weeks, rising by 9,934,000 barrels to a 37 year high of 174,261,000 barrels during the week ending May 29th, after our distillates supplies had increased by 5,495,000 barrels over the prior week....our distillates supplies rose by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 548,000 barrels per day to a 28 year low of 2,718,000 barrels per day, and because our exports of distillates fell by 135,000 barrels per day to 740,000 barrels per day, while our imports of distillates rose by 8,000 barrels per day to 163,000 barrels per day....after this week's inventory increase, our distillate supplies at the end of the week were 34.7% above the 129,372,000 barrels of distillates that we had stored on May 31st, 2019, and about 28% above the five year average of distillates stocks for this time of the year...
finally, with the big drop our oil imports, the big addition to the SPR, the increase in refining, and the drop in production, our commercial supplies of crude oil in storage fell for the 3rd time in nineteen weeks and for the twentieth time in the past 52 weeks, decreasing by 2,077,000 barrels, from a 38 month high of 534,422,000 barrels on May 22nd to 532,345,000 barrels on May 29th....but with near steady increases this year and three record increases over past 9 weeks, our commercial crude oil inventories are still 12% above the five-year average of crude oil supplies for this time of year, and nearly 50% above the prior 5 year (2010 - 2014) average of crude oil stocks for the end of May, 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 May 29th were 10.2% above the 483,264,000 barrels of oil we had in commercial storage on May 31st of 2019, 21.9% above the 436,584,000 barrels of oil that we had in storage on June 1st of 2018, and 3.7% above the 513,207,000 barrels of oil we had in commercial storage on June 2nd 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 just increased by 15,144,000 barrels to a record high of 1,429,929,000 barrels, 9.7% more than the 1,303,043,000 barrel total of the same week a year ago...
This Week's Rig Count
the US rig count fell for the 13th week in a row during the week ending June 5th, and is now down by 64.2% over that thirteen week period....Baker Hughes reported that the total count of rotary rigs running in the US decreased by 17 rigs to 284 rigs this past week, which was the fewest rigs deployed in Baker Hughes records going back to 1940 and 120 fewer rigs than the prior all time low, also down by 691 rigs from the 975 rigs that were in use as of the June 7th report of 2019, and 1,645 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 16 rigs to 208 oil rigs this week, after falling by 15 oil rigs the prior week, leaving oil rig activity at its lowest since June 19, 2009, which was also 583 fewer oil rigs than were running a year ago, and less than a seventh 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 was down by 1 to 76 natural gas rigs, which was the least natural gas rigs running in at least 80 years, down by 110 natural gas rigs from the 186 natural gas rigs that were drilling a year ago, and 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 up by one to 13 rigs this week, with all of those Gulf rigs drilling for oil in Louisiana's offshore waters...that's still ten fewer rigs than the rig count in the Gulf a year ago, when 21 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 18 rigs to 253 horizontal rigs this week, which was the fewest horizontal rigs active since April 21st, 2006, and hence is a new 14 year low for horizontal drilling...it was also 602 fewer horizontal rigs than the 855 horizontal rigs that were in use in the US on June 7th of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...meanwhile, the vertical rig count was unchanged at 7 vertical rigs this week, but those were down by 39 from the 46 vertical rigs that were operating during the same week of last year...on the other hand, the directional rig count increased by 1 to 24 directional rigs this week, but those were still down by 50 from the 74 directional rigs that were in use on June 7th 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 5th, the second column shows the change in the number of working rigs between last week's count (May 29th) and this week's (June 5th) count, the third column shows last week's May 29th 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 7th of June, 2019...
the basin totals above show a net decrease of 18 rigs, matching the number of horizontal rigs removed nationally this week, so hopefully the above table accounts for all the changes in activity this week has brought us....checking the rig losses 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 the rig count in other Texas Permian basin districts remained unchanged...since the overall Permian rig total was down by 7 rigs, that means that the 3 rigs that were shut down in New Mexico must have been drilling in the western Permian Delaware, to account for the national Permian basin reduction of 7 rigs....elsewhere in Texas, 5 rigs were pulled out of Texas Oil District 1, and 5 rigs were pulled out of Texas Oil District 2, while a rig was added in Texas Oil District 3, and another rig was added in Texas Oil District 4...together, the changes in those districts account for the 9 rig reduction in Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and thus touches on those 4 Oil Districts, and also account for the additon of a rig in that region that doesn't target the Eagle Ford, possibly the directional drilling rig that was added this week...in other states, Oklahoma saw a one rig reduction despite the rig added in the Cana Woodford because rigs were concurrently pulled out of the Ardmore Woodford and the Granite Wash, which borders on the Texas panhandle, while Louisiana saw a one rig reduction despite the addition of the rig in the Gulf of Mexico because rigs were concurrently pulled out of the Haynesville shale in the northwest and from a non-shale basin in the southern part of the state...that Haynesville shale rig, and the rig removed from the Granite Wash basin, were the only natural gas rig reductions this week, while a rig taretting natural gas started drilling in one of those "other" basins not tracked separately by Baker Hughes at the same time...
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Youngstown 'fracking' opponents to file appeal in federal court - Organizers behind an effort to let cities like Youngstown and other voters in Ohio ban fracking in their communities are taking their fight to a federal appeals court. A coalition of activists from Youngstown and other parts of Ohio has filed a notice in the U.S. Sixth Court of Appeals challenging a federal judge's ruling against their claim that state and local elections boards violated their constitutional rights by preventing voters from deciding environmental issues such as fracking.In April, U.S. District Court Judge Benita Pearson dismissed the lawsuit filed by grassroots environmental groups in seven Ohio counties, including Susie Beiersdorfer and Dario Hunter of Frackfree Mahoning Valley, which has been unsuccessful eight times in backing a ballot issue to ban fracking inside Youngstown city limits. Fracking Opponents have expressed concern that fracking could endanger water supplies and pose other environmental hazards.The lawsuit claimed that election boards and the Ohio Secretary of State had violated the groups' constitutional right to free speech and due process by rejecting petitions signed by hundreds and thousands of registered voters seeking ballot space on issues dealing with clean water, fracking, injection wells, and other environmental concerns.The groups say election officials and the Secretary of State should not be allowed to keep questions from the voters based on the content of the issues. Judge Pearson ruled that the plaintiffs failed to show that "local, community self-government" is a constitutional guarantee in this case.
Gulfport updates Utica Shale plans - Gulfport Energy plans to complete three additional Utica Shale wells during the second half of the year The wells would give Gulfport incremental production in the coming months, the Oklahoma City-based driller said in a press release. Gulfport has deferred production until later this year and into early 2021 in the hope that prices for natural gas and oil will rise by then. The company predicted that net production for 2020 would land between 1 billion and 1.075 billion cubic feet equivalent per day. Gulfport’s prior estimate put production in the range of 1.1 billion to 1.15 billion cubic feet equivalent per day. Gulfport has drilled more than 400 wells in Ohio’s Utica Shale, the most of any publicly traded company.
PTTGC, Daelim postpone investment decision on Ohio project -- PTTGC America and Daelim Chemical USA, equal partners in their long-planned PTTDLM petrochemical project in Mead Township, Belmont County, Ohio, have delayed making a final investment decision (FID) on their multi-billion-dollar petrochemical project, originally expected in the middle of 2020. Senior company sources in Bangkok told CW on Monday that the FID is expected to be made either at the end of this year or, more likely, next year and it would take five to six years to complete construction of the facilities. This would take the project’s completion date to around 2027–28. PTT Global Chemical (PTTGC), parent of PTTGC America, first announced plans for the project in 2015. In 2018, Daelim Industrial joined as partner. The companies were hoping to make an FID on the project by the middle of this year. The company tells CW that engineering studies are still being carried out on the project, which would be based on an ethane cracker designed to produce 1.5 million metric tons/year (MMt/y) of ethylene using ethane from the Marcellus and Utica shale deposits. The downstream configuration has not yet been fully decided on but could involve the entire ethylene output being used to make the equivalent amount of high-density and linear low-density polyethylene and/or some of the ethylene also used to make ethylene glycol. Most of the output would be sold on the US market. The company tells CW that the coronavirus disease 2019 (COVID-19) pandemic as well as the latest forecasts in demand are the main reasons for the delay. PTTGC CEO Kongkrapan Intarajang said recently that the company will review its short- and long-term investment plans worldwide based on projects’ costs as well as changes in product demand expected in the post-COVID-19 global economy. President and CEO of PTTGC America, Toasaporn Boonyapipat, said on Monday, "While the pandemic has prevented us from moving as quickly as we would like within our previous timeline, our best estimate is for a final investment decision by end of this year or in the first quarter of next year." PTTGC has spent about $200 million on site preparation and engineering studies so far. Bechtel was last year selected as the engineering, procurement, and construction contractor on the project, of which the initial costs were estimated at $5–6 billion. The complex would be located on a 500-acre site of a former coal-fired power plant. The site is owned by the potential investors. It would also include on-site railcar and truck loading facilities, supporting utilities, infrastructure, storage tanks, and logistics facilities.
Shell Plastics Plant Trump Touted Faces Oversupply Risks: Energy Institute Report - The New York Times — A massive Pennsylvania plastics project that President Donald Trump touted during a visit last year faces risks of oversupply and a low price outlook for the materials, a report by an institute that examines energy issues said on Thursday. The Pennsylvania Petrochemical Complex plant in Beaver County, owned by Shell, has been promoted by some as an economic savior in a region still suffering from the demise of steel industry in the 1980s. But the $6 billion to $10 billion plant, expected to open in 2021 or 2022, faces competition from other major plants owned by companies like Exxon Mobil, expected growth in recycled plastics, and the sluggish global economy, according to the report by the Institute for Energy Economics and Financial Analysis, which supports the transition to green energy. "A lot of people think it's the second coming of the steel industry ... but this is way too weak of a proposition and a questionable economic development choice," Tom Sanzillo, IEEFA director of finance and former first deputy comptroller of New York state, said. Sanzillo hopes local officials and investors will ask questions about the plant. Shell spokesman Curtis Smith said the short-term outlook for the chemicals business is challenging, but long-term demand for petrochemical products will grow. The project is advantaged given its proximity to abundant, inexpensive feedstock, Smith said, referring to the region's natural gas and ethane. Trump won Pennsylvania in the 2016 election by less than 1 percentage point and has visited the state often ahead of the November vote. "This is just the beginning," Trump told thousands of building workers wearing yellow vests at the plant last August. "My administration is clearing the way for other massive, multibillion-dollar investments." He said the project would have never happened without him, although its final permits were issued before he was elected. The White House did not immediately respond to a request for comment.
Shell’s Plastics Plant Outside Pittsburgh Has Suddenly Become a Riskier Bet, a Study Concludes - The same economic forces that are delaying construction of a plastics plant in Ohio will make another one under construction in western Pennsylvania less profitable and riskier to shareholders, an economic think tank warns in a new report.The massive, multibillion-dollar Shell Polymers plant rising from the banks of the Ohio River in Beaver County, Pennsylvania, is expected to make 1.6 million metric tons of plastic pellets annually—the building blocks for such products as bags, bottles, food packaging and toys. But a new study from the Institute for Energy Economics and Financial Analysis warns that Shell will be making less plastic and less money while facing increasingly stiff competition. That means the company won't likely be able to hire as many workers and will contribute less to the local economy, IEEFA concludes. One key factor: the price of plastics has fallen 40 percent since the plant was planned several years ago, as a global petrochemical industry has raced to boost production capacity. These changing economics, made worse by fallout from the coronavirus pandemic, will have significant implications for Shell's investors, local and state governments in Pennsylvania, and the people of Pennsylvania, who have supported the project through tax breaks. IEEFA, a non-profit whose work is aimed at supporting a sustainable energy economy, called on Shell to be transparent with its investors and the public as economic conditions have changed."It will be a distressed asset for years to come," said Tom Sanzillo, director of finance for the energy institute. "Only increased public disclosure by Shell can ensure that problems are faced squarely and with common sense."A Shell spokesman, Curtis Smith, acknowledged "the short-term outlook for this business is challenging given global macro conditions, but it remains our view that long-term demand for the wide variety of products derived from petrochemicals will continue to grow and provide attractive returns."
Report: Fossil fuel industry could see prolonged financial distress - The Institute for Energy Economics and Financial Analysis (IEEFA), an organization largely funded by various anti-fossil fuel agencies, on Thursday released a study that said the risks for Shell’s petrochemical complex indicates less profitability than originally projected, noting that Shell could see prolonged financial distress.The petrochemical industry in Beaver County could face prolonged financial distress, according to a report by an advocate organization for sustainable energy.The Institute for Energy Economics and Financial Analysis (IEEFA), an organization largely funded by various anti-fossil fuel agencies, on Thursday released a study that said the risks for Shell’s petrochemical complex indicates less profitability than originally projected, noting that Shell could see prolonged financial distress.“The current economic climate poses risks for this investment ... This complex will not be as profitable as originally presented. This has significant implications for jobs, taxes and economic spinoffs,” said Tom Sanzillo, IEEFA’s director of finance, in a release. Kathy Hipple, a financial analyst and co-author of IEEFA’s recent report, said the profitability of the complex is due to “a cumulative set of missed revenue and profit targets, as well as an oversupply of plastics, unpredictable costs, lost market share, diminished growth and increased competition.” According to the report, the price of plastics was in the $1 per pound range between 2012 to 2016, while today, plastics are 40 to 60 cents per pound range. Last month, Royal Dutch Shell announced it was selling its Appalachian shale gas holdings in northwestern Pennsylvania for $541 million following steep first-quarter profit hits company leaders attributed to coronavirus shutdowns. But Shell has been slowly shedding its shale assets in the Appalachian Basin for years alongside Chevron Corp., which announced late last year it was looking to sell Marcellus and Utica shale holdings in the region.
Oil, gas and plastics hit by COVID-19; producers await rebound - Ellwood City Ledger - As oil and gas producers wrestle with economic uncertainty and price slumps related to COVID-19, industry supporters expect a swift rebound. Business shutdowns and stay-at-home orders in place to combat the pandemic delayed progress on two Appalachian petrochemical facilities, and a global drop in demand has reduced fracking and drilling activities here and across the United States. The country’s oil prices fell below zero for the first time in history just last month, although prices are climbing again as COVID-19 precautions lift. Shale production in the Appalachian Basin has slowed by less than 2 percent in recent months, but new figures indicate a sharper drop in the average production of new wells. U.S. Energy Information Administration analysts say nationwide natural gas prices will likely remain below average until business activities resume and production slows at the end of the year. Kallanish Energy this week reported a 6.8 percent increase in Pennsylvania’s quarterly natural gas production — the lowest statewide growth rate since 2017. Even pre-pandemic, an abundance of cheap gas produced in the Permian Basin and other shale reserves was flooding the natural gas market and driving prices down. Global energy prices had declined, and Pennsylvania utilities were paying less for natural gas. EQT Corp. and Range Resources, the region’s two largest gas drilling companies, announced plans to lower capital spending by $75 million and $90 million this year, respectively; however, both companies still expect to meet annual production goals. “The outlook for natural gas prices later this year and into 2021 has drastically improved since our year-end call in mid-February,” said Cabot Oil and Gas Corp. CEO Dan Dinges on a recent earnings call, echoing similar statements made by other regional producers. EQT plans to temporarily halt production of nearly one-third of its daily natural gas output in Pennsylvania and Ohio until market conditions improve later this year.
Pa. Supreme Court denies Sunoco pump station appeal - The Pennsylvania Supreme Court has dealt another blow to the Mariner East Pipeline through Lebanon County. The state’s top judicial body on Monday, June 1 denied the company’s petition to appeal a lower court’s decision, putting the future of the Sunoco Pipeline’s pump station in West Cornwall Township in jeopardy. The court upheld an October 2019 ruling by the Commonwealth Court, which said the West Cornwall Township Zoning Hearing Board acted improperly in May 2015 when it issued a permit for construction of a pumping station along Route 322 near Butler Road. The station, according to previous reports, is needed to provide the pressure necessary to maintain the volatile gases in a liquid state while being transported. However, construction was completed in September 2014 and gases began flowing through the station in January 2015, several months before the permit was issued. The Concerned Citizens of Lebanon County (CCLC) brought suit against pipeline owner Energy Transfer Partners, the parent company of Sunoco, in a case that bounced between the township and Court of Common Pleas for several years until a fresh appeal landed it before Commonwealth Court, which decided in CCLC’s favor. Sunoco in January filed a petition with the state Supreme Court to allow them to appeal the Commonwealth Court’s decision. “We are very pleased, after five years of litigation, to finally be vindicated,” CCLC member Pam Bishop said Tuesday. “The permit that was issued has been voided,” she said. “If it was anybody else, and the township found a building that did not have its permit … the township would ask them to take it down. That would be the normal procedure. We’re not sure what the township will do.”
Tensions With China Are Wounding West Virginia — The One State The President Wanted To Save - The political season will enter guns a blazing after Labor Day. But the players are warming up now — something triggered by some states and their attorneys general who are asking that the Chinese government be held to account for the outbreak of COVID-19. It’s a ploy that has an uncommon twist. One of the politicos calling for such action is West Virginia Attorney General Patrick Morrisey, who is struggling to get his footing after getting knocked out of the U.S. Senate race by Joe Manchin in 2016. The reason Morrisey’s signature stands out is that West Virginia is in deep in negotiations with the China Energy Investment Corp. — a deal that would have it invest $84 billion to develop the state’s shale gas fields; China wants to feed its chemical and manufacturing base. The prospective deal would be a game-changer for West Virginia. The three-year investment from China would exceed the state’s annual $75 billion gross economic output. Moreover, China is one of the few countries in the world still buying coal and China paid American coal producers at least $128 million last year. U.S. utilities, meanwhile, are closing their coal-fired units and replacing them with natural gas and renewables. West Virginia sits atop the Marcellus Shale basin, which holds 141 trillion cubic feet of recoverable natural gas. The Utica Shale basin, which is next door, is just as plush. That means China could invest its $84 billion in Pennsylvania or Ohio — states that may value their business and that do not engage in inflammatory political rhetoric. The worst offender is Donald Trump, who said last week at the White House, “They've ripped off the United States like no one has ever done before.” If China Energy does invest in West Virginia, it could trigger an economic boon there: It would attract cracker plants that break apart the “dry gas” used to heat homes from the “wet gas” used in chemical manufacturing. It could also be used as a magnet to attract an ethane storage and distribution hub to harness petrochemicals. Economic developers note that such an investment is worth 100,000 new jobs — chump change, though, for career politicians.
Ballad of a Land Man: Kentucky theatre takes on fracking --On a temporary stage deep in the Appalachian woods of Rockcastle County, Kentucky, the outdoor play Ezell: Ballad of a Land Man was a different kind of production. The five acts—called Welcome, Journey, Performance, Return and Feast—generated an immersive storytelling experience, through which the audience was invited to feel a connection to place and to consider the intricacies of stewardship and belonging. For creator Bob Martin and producer Carrie Brunk, Ezell is an outgrowth of both a passion for locally-engaged theater and their community’s efforts to resist the expansion of fossil fuel extraction. The two, known collectively as Clear Creek Creative, have deep roots in Kentucky and intimately aware of the painful history of resource extraction in Appalachia. A speculator for oil and gas companies knocked on Martin’s and Brunk’s door in 2014, offering a lease for the mineral rights on the land they call home. At the time, oil and gas companies were aggressively positioning themselves for fracking the Rogersville Shale that lies under a great swath of eastern Kentucky. We first meet Ezell as he bounds on to the makeshift stage. His enthusiasm for life is infectious. His character is neither a hero nor a villain. He’s human. Complicated. Real. We see his scars from a hard life of working in coal mines and the military. He returns to his ancestral land, perhaps the last place he felt whole, in an attempt to repair the rifts in his arduous life. The one-man play powerfully wrestles with the personal, financial, generational, and societal barriers Ezell faces to truly going home. As the character says in the play: “Well cousin, to sit on MY porch of MY cabin, I’m gonna have to give up farmin’ these hillside flats and drinkin’ from that spring and trade them for these frackpads and these deep wells. That’s right... And they’re gonna need water, and a lot of it, over 2 million gallons per well. So they’ll tap that spring and they shoot that water down two miles deep and 2 miles across in every direction to break open that shale and bring up that gas. AND, I’ll sit on MY porch, and look out over that holler with these FRACKPADS and all these generators lined up pumping out 24 HOURS A DAY, 7 DAYS A WEEK!” But it’s more complex than that: Ezell also shares tender observations about what has been and will be lost. The majestic chestnut trees that proliferated in the forest. The cold, clear spring with 57 degree water. The family graveyard going back generations. The traditions of the Cherokee people who once lived in the hills and valleys.
NJ Investigates Whether It Has Enough Natural Gas Capacity for the Next Decade - The state is launching an investigation into whether New Jersey has enough natural gas capacity to serve its customers over the next decade, a probe that could alter whether an expansion of new pipelines continues. The proceeding, sought by both gas utilities and conservation groups opposed to the buildout in recent years, aims to answer whether there is enough capacity in the pipeline system and what ‘’nonpipeline’’ solutions can reduce stress on the system during times of peak demand. The bigger-picture issue for critics of the pipeline expansion is how to rein in policies to ensure six million people in New Jersey rely on gas to heat their homes, and align them more with the Murphy administration’s clean-energy agenda and goals to reduce emissions contributing to climate change. “Now, more the ever, we should be vigilant about not wasting precious resources on unneeded projects,’’ said Tom Gilbert, campaign director for energy, climate and natural resources for the New Jersey Conservation Foundation. “Gas experts have shown that New Jersey has a surplus of available natural gas today and at any point in the foreseeable future.’’
NJ tells high court not to bite on 'overstated' impacts in pitch from PennEast — The State of New Jersey has told the US Supreme Court that PennEast Pipeline exaggerated the industrywide harms likely to result from a federal appeals court decision blocking condemnation of property in which the state holds an interest. The June 2 brief from the state comes as PennEast has asked the national's high court to overturn a 3rd US Circuit Court of Appeals decision it contends would enable states to block interstate gas pipelines, threatening the nation's energy markets and likely chilling investments in infrastructure across the country. Oil and gas trade groups and the Federal Energy Regulatory Commission have also warned of far-reaching consequences of the September 2019 3rd Circuit ruling. That decision found state sovereign immunity blocked PennEast from pulling New Jersey into federal court to condemn more than 40 properties in which the state held an interest. The ruling threw into question the route for the 116-mile, 1.1 Bcf/d natural gas project linking Marcellus Shale dry gas production to markets in Pennsylvania, New Jersey, and New York. New Jersey in its brief filed June 2 argued the Supreme Court should not take up the case because there was no circuit court split to resolve and the 3rd Circuit ruling was unanimously decided, reflecting proper application of sovereign immunity and statutory interpretation rules. As such, it said the petition for Supreme Court review rested heavily on overstated warnings of dire consequences. "PennEast is wrong" in asserting the 3rd Circuit created a state veto of interstate natural gas pipelines that will prevent development across the country, New Jersey argued. The decision only identifies which parties can file appropriate condemnation suits, it said. "That is why this question has arisen so infrequently, and why it is not likely to arise frequently in the future," New Jersey said. "The sky has not fallen," since a district court upheld Texas' analogous assertions of sovereign immunity in a condemnation action involving Sabine Pipe Line in 2017, New Jersey argued in the brief. Rather, FERC has received 53 applications for major new natural gas projects and approved 34 with 19 pending and no denials. And, parties have only identified two cases, including PennEast, since the Texas ruling in which states asserted immunity, it said.
Court ruling could delay compressor project — While it could delay the project from coming online and cost the gas company money, a federal appeals court decision to throw out an air permit issued by state regulators will not stop ongoing construction of a natural gas compressor station on the banks of the Fore River, Mayor Robert Hedlund said. The U.S. Court of Appeals for the First Circuit on Wednesday overturned the air permit for the natural gas compressor station Enbridge is building in North Weymouth, ordering the state Department of Environmental Protection to conduct a new analysis of what would be the best available control technology to limit air pollution. In his decision, Judge William Kayatta said the state did not follow its own procedures when it approved a gas turbine, rather than an electric motor, to cut emissions at the station. The state will need to hold proceedings regarding the control technology for the project. Kayatta disagreed with many of the other arguments that petitioners made in their attempts to get the permit tossed, such as the regulators’ failure to consider existing levels of air toxins such as benzene and formaldehyde that already exist in the Fore River Basin. Hedlund praised Town Solicitor Joe Callanan and outside lawyers for their work on the town’s appeal, which raised the issue of using a gas-fired turbine to power the compressor. Hedlund said the state Department of Environmental Protection could either conduct the analysis and still allow the gas turbine, or require Enbridge to modify its plans and use an electric motor. “We have to remain vigilant to protect the health and safety of our residents because this does not stop construction of this facility,” Hedlund said. “It has the potential to delay Enbridge a couple of months, so we remain vigilant to look at all issues to protect the health and safety of residents.” The compressor station is part of the Atlantic Bridge project, which would expand the Houston company’s pipelines from New Jersey into Canada. Enbridge got the final go-ahead from the Federal Energy Regulatory Commission in November and started cleanup of contamination at the site shortly after. The company also needed several state permits, all of which were granted by regulators despite vehement and organized opposition from local officials and residents for several years.
State’s top court wrestles with land seizure for National Fuel pipeline plan – New York State's highest court heard arguments Tuesday on whether an Allegany County widow must surrender land to National Fuel for construction of a natural gas pipeline. The pipeline would move natural gas from Pennsylvania to Canada through Western New York. The Court of Appeals case may turn on which of two bureaucratic findings the court thinks controls the outcome. The Federal Energy Regulatory Commission granted National Fuel a permit for the Northern Access pipeline. But the state Department of Environmental Conservation refused to grant the company a water quality certificate allowing the pipeline to cross streams in Western New York. There are 192 stream crossings along the 97-mile route from the fracking fields of Pennsylvania – 26 miles in Pennsylvania, 71 miles in Western New York. Pennsylvania authorities have granted National Fuel all the permits it sought, but New York has not. FERC officials ruled the DEC's rejection of the stream crossing permit invalid because the decision came 36 days after the expiration of a deadline set in the federal Clean Water Act for the DEC to act on National Fuel's request. The company and the DEC had agreed to an extension of the deadline, but FERC said the Clean Water Act doesn't allow extensions. The DEC and the Sierra Club sued FERC in federal court. The case is pending before the U.S. Second Circuit Court of Appeals, with National Fuel intervening on FERC's side. Tangled up in all the legal and regulatory issues are 200 acres in Clarksville owned by Theresa Schueckler, whose late husband, Joseph, refused to sell a slice to National Fuel for its pipeline. National Fuel took the Schuecklers to court early in 2017, and a State Supreme Court justice in Allegany County granted National Fuel the power to seize their land under the state's eminent domain law. The Schuecklers appealed and in November 2018 won a 3-2 ruling by the Appellate Division, where the majority decided to ignore FERC's decision that the DEC acted too late. The three judges said National Fuel couldn't seize land for a project that hadn't been approved by the DEC.
E.P.A. Limits States’ Power to Oppose Pipelines and Other Energy Projects - The New York Times — The Environmental Protection Agency on Monday announced that it had limited states’ ability to block the construction of energy infrastructure projects, part of the Trump administration’s goal of promoting gas pipelines, coal terminals and other fossil fuel development. The completed rule curtails sections of the U.S. Clean Water Act that New York has used to block an interstate gas pipeline, and Washington employed to oppose a coal export terminal. The move is expected to set up a legal clash with Democratic governors who have sought to block fossil fuel projects. Specifically, it limits to one year the amount of time states and tribes can take to review a project and restricts states to taking water quality only into consideration when judging permits. The Trump administration has accused some states of blocking projects for reasons that go beyond clean water considerations, such as climate change impacts. Andrew Wheeler, the administrator of the E.P.A., said the agency was moving to “curb abuses of the Clean Water Act that have held our nation’s energy infrastructure projects hostage, and to put in place clear guidelines that finally give these projects a path forward.” States, he said, would no longer be allowed to use the law to object to projects “under the auspices of climate change.” The rule was initially proposed in August shortly after President Trump issued an executive order directing agencies to “promote efficient permitting processes and reduce regulatory uncertainties that currently make energy infrastructure projects expensive and that discourage new investment.” Mr. Trump then directed the E.P.A. to revise rules for permits issued under Section 401 of the Clean Water Act, which gives states and tribes the ability to judge the potential impact that energy projects and other construction proposals might have on water quality. He called the current rules “outdated.” The American Gas Association, which represents natural gas distribution and transmission companies, praised the changes and described states’ objections to pipelines and other projects as “abuse.”
Environmental groups open new line of attack at FERC on Atlantic Coast Pipeline | S&P Global Platts — A coalition of environmental groups opened June 1 a new front in their legal war against the 600-mile, 1.5 Bcf/d Atlantic Coast Pipeline project, contending that a supplemental environmental impact statement is needed.The action comes as lead developer Dominion Energy already is laboring to get the project back into construction after a series of legal setbacks. For instance, it is hoping for a positive US Supreme Court decision soon to help reinstate permission vacated by a federal circuit court for the pipeline to cross the Appalachian Trail.The project is intended to move Appalachian gas to mid-Atlantic markets. Should the developer prevail in the Supreme Court, it faces a possible new avenue of litigation in the form of a roughly 4,000-page filing posted on the Federal Energy Regulatory Commission's website June 1 by Southern Environmental Law Center, Appalachian Mountain Advocates and Chesapeake Bay Foundation on behalf of a coalition of conservation groups.The groups argued in the filing that a supplemental EIS is needed in light of new information that has come to light since FERC issued an EIS for the pipeline project in 2017, and given upcoming FERC decisions on key matters such as whether to extend certificate authorization for the project beyond the October expiration date and whether to lift FERC's existing stop-work order on construction. Part of the groups' rationale for a new review is that the region's energy infrastructure has undergone a dramatic shift away from gas-fired power, while the cost of the pipeline has ballooned. "In January 2020, Virginia — the site of over half of the ACP's proposed route — told the Supreme Court that in light of the mounting evidence that the pipeline is not needed, the ACP threatens Virginia's natural resources without clear corresponding benefits," they wrote.
EPA Changes Rule To Limit States' Ability To Oppose Pipelines, Energy Projects - Federal environmental regulators finalized a rule Monday that reduces the time states have to approve federal permits for energy projects. The Environmental Protection Agency finalized changes to a portion of the Clean Water Act called Section 401. For decades, it has given states and tribes the power to review new projects to make sure they don’t harm local waterways. Under the law, states also had the power to withhold approval and set special conditions. In West Virginia, for example, the rule allowed environmental regulators to revoke and then reissue a permit for the Mountain Valley Pipeline. Section 401 has been used by some states, like New York, to prevent new pipelines from being built.In a press release, the EPA said some states abused the law, using it to stall energy projects, and the new rule, which sets a one-year time limit for states to approve or reject projects, is returning the law to its original intention.“EPA is returning the Clean Water Act certification process under Section 401 to its original purpose, which is to review potential impacts that discharges from federally permitted projects may have on water resources, not to indefinitely delay or block critically important infrastructure,” said EPA Administrator Andrew Wheeler.Under the adjusted rule, states are also now only able to consider water quality impacts, not a project's impacts on things like climate change.Environmental groups opposed the rule change.In a statement, Jon Devine, director of federal water policy at the Natural Resources Defense Council said the rule was a mistake and infringes on states' rights. “Enforcing state and federal laws is essential to protecting critical lakes, streams, and wetlands from harmful pollutants and other threats,” he said. “But the Trump administration’s rule guts states' and tribes' authority to safeguard their waters, allowing it to ram through pipelines and other projects that can decimate vital water resources.”
Besieged by Protesters Demanding Racial Justice, Trump Signs Order Waiving Environmental Safeguards --With the nation convulsed by multiple crises, President Donald Trump returned to a favorite stand-by of his presidency—asserting his authority to sweep aside environmental restraints and speed up construction of oil and gas pipelines. But the executive order that he signed Thursday night—the third of his presidency aimed at expediting pipelines—is destined to spur more of the type of litigation that has rendered his previous directives ineffective so far. The White House invoked the same legal authority the president has to expedite hurricane and flood response actions to declare an "economic emergency," that requires the waiving of environmental reviews and other regulations. "This order will be a sitting duck for the sorts of legal challenges that have been so successfully brought against other Trump environmental rollbacks," said Michael Gerrard, founder and faculty director of the Sabin Center for Climate Change Law at Columbia University. "Few developers or lenders will risk millions on starting construction in reliance on this order surviving in court." The White House provided few details on the order before the scheduled signing at 4:30 p.m. "I can tell you it does have to do some of the permitting and energy as it relates to rebuilding this country," said presidential spokesman Hogan Gidley in a brief noon appearance before reporters. Finally, after 6:15 p.m., the White House made copies of the order available. "From the beginning of my Administration, I have focused on reforming and streamlining an outdated regulatory system that has held back our economy with needless paperwork and costly delays," Trump said in the document. "Antiquated regulations and bureaucratic practices have hindered American infrastructure investments, kept America's building trades workers from working, and prevented our citizens from developing and enjoying the benefits of world-class infrastructure. The need for continued progress in this streamlining effort is all the more acute now, due to the ongoing economic crisis." The president's critics were quick to point out that his order was poorly timed, since minority communities would be disproportionately affected by his move to waive the environmental review mandated under the National Environmental Policy Act (NEPA). "Gutting NEPA takes away one of the few tools communities of color have to protect themselves and make their voices heard on federal decisions impacting them."
Natgas flows to U.S. LNG export plants sink to 9-month low due to coronavirus - (Reuters) - The amount of natural gas flowing on pipelines to U.S. liquefied natural gas export plants is at its lowest levels since August, a signal of weak worldwide demand due to government lockdowns to repress the coronavirus. Worldwide gas prices have plunged to record lows in Europe and Asia as lockdowns squeeze demand. Consumption of liquefied natural gas (LNG) has remained stronger than gasoline demand as LNG is used for power generation, but the cash crunch hitting the global economy has cut demand. The amount of gas flowing to U.S. LNG plants was on track to fall to a nine-month low of 4.3 billion cubic feet per day (bcfd), data provider Refinitiv said in a preliminary report Monday that may be revised on Tuesday. U.S. gas at the Henry Hub <0#NG:> in Louisiana has traded higher than European benchmarks <since the end of April and was expected to remain more expensive through September. Most of the feedgas decline was at Cheniere Energy Inc’s (LNG.A) export plants at Sabine Pass in Louisiana and Corpus Christi in Texas. Cheniere said it does not comment on operations. Analysts said U.S. LNG feedgas has declined due to the recent wave of cargo cancellations around the globe, after hitting a record in February before most government-imposed lockdowns. Buyers in Asia and Europe have already canceled over 20 U.S. LNG cargoes for both June and July, and more cancellations are anticipated.
Spot LNG, the worst-performing energy commodity, faces more price pain - (Reuters) - With the recovery in crude oil prices, spot liquefied natural gas (LNG) has assumed the unwanted mantle of the worst-performing major energy commodity this year. Spot LNG for delivery to North Asia in July dropped to $1.85 per million British thermal units (mmBtu) in the week to May 29, down from $1.92 mmBtu the prior week and matching the all-time low this year reached in the seven days to May 1. The price is down by nearly three-quarters from the winter demand peak of $6.80 per mmBtu from mid-October, and is almost two-thirds weaker on a year-to-date basis. In contrast, benchmark Brent crude futures have rallied nearly 150% since hitting the intraday low this year of $15.98 a barrel on April 22, ending at $39.79 on Wednesday. When it hit the April low, Brent was down 78% from its peak so far this year of $71.75 a barrel on Jan. 8, and it is still down by close to half since that high. But Brent’s partial recovery is an example of what happens when some supply discipline is applied to the markets. The Organization of the Petroleum Exporting Countries (OPEC) and its allies, including Russia, in the group known as OPEC+ agreed in April to end their price war and cut output by a combined 9.7 million barrels per day (bpd) for May and June. What crude oil shows is that having a producer organisation willing to prop up prices by cutting supply gives a better outcome price-wise than allowing only market forces to do the job. In LNG, the situation is more complex than crude. LNG trains are difficult to shut down, or even run at substantially reduced rates, meaning that closing down production is usually the very last option a producer will consider. As in crude, it seems the bulk of involuntary supply cuts is coming from the United States, where the rising price of natural gas has rendered U.S. LNG uncompetitive in both the key European and Asian markets.
Magnolia LNG sale falls through to company with ties to Lafayette, new buyer steps up - The Australian parent company behind the Magnolia LNG project near Lake Charles canceled a deal to sell the operation to a British business with a significant presence in Lafayette in late May. Global Energy Megatrend Ltd. was expected to pay $2.25 million to LNG Ltd. by May 15, but on May 25 the deal was terminated due to the buyer's "failure to close the transaction within the required timeframe." One day later, Magnolia LNG Holdings LLC, a Delaware-based entity incorporated on May 7, stepped up and bought Magnolia LNG for $2 million. The new purchase agreement includes an unsecured noninterest bearing promissory note worth $1.3 million if the Magnolia LNG project raises enough capital to begin construction. The new buyer also agreed to work with LNG Ltd. on a potential recapitalization of the company expected to be completed on Nov. 30. The deal includes the permits, land, detailed engineering plans and a contract for development, in addition to the underlying technology related to the LNG project. Former proposed buyer Global Energy Megatrend had described itself as an integrated natural gas company that has been leasing U.S. natural gas fields and investing in pipelines that lead to Louisiana ports and LNG export terminals. Global Energy Megatrend co-founders include Lafayette businessmen Bill Miller of Miller Energy LLC, Ben Blanchet and Eddie Moses of Miller Thomson & Partners LLC. It also has co-founders in London. Before that, LNG Ltd. had expected to be sold in a $75 million deal to Singapore-based LNG9 Ltd., but investors pulled out of that deal after a loan fell through. LNG Ltd. recently appointed administrators who were tasked with dealing with a potential insolvency; the company was on track to run out of money in May. In Australia, where LNG Ltd. is headquartered, administration is akin to Chapter 11 bankruptcy reorganization in the United States. Magnolia LNG was expected to export 8.8 million tons of LNG each year, but has not started construction. The project already has permits from the Federal Energy Regulatory Commission.
U.S. natural gas storage capacity remained relatively unchanged in 2019 - (EIA) Underground natural gas storage capacity in the Lower 48 states has remained relatively flat since 2012. The U.S. Energy Information Administration (EIA) measures working natural gas storage capacity in two ways: design capacity and demonstrated peak capacity. Both measures of capacity were relatively unchanged in 2019; design capacity declined 0.4% and demonstrated peak capacity increased 0.1% compared with 2018. For the sixth year in a row, no new storage fields were completed. Design capacity is calculated as the total of the working gas capacity for all active facilities in the Lower 48 states as of November 2019. Design capacity is an engineering estimate based on the physical characteristics of the reservoir, installed equipment, and operating procedures on the site, which often must be certified by federal or state regulators. Design capacity declined by 19 billion cubic feet (Bcf) in the Lower 48 states during 2019. Most of this decline occurred in the Mountain region, where working design capacity fell by 15 Bcf, or slightly more than 3% of the regional total. Storage operators may reduce design capacity at a storage field following an asset acquisition or reassessment of the operational capabilities. In the Mountain region, Spire Storage West reduced the working design capacity at the Belle Butte (formerly Ryckman Creek) field by 16 Bcf after acquiring the field in 2018. Increases in design capacity occurred primarily in the Pacific and East regions. In the Pacific region, the Northwest Natural Gas Company completed the North Mist capacity expansion project in Oregon, increasing working natural gas capacity by 2.5 Bcf. The North Mist expansion project was the only new natural gas storage reservoir to come online in 2019, increasing capacity at the Mist Underground Natural Gas Storage Facility. The facility provides flexible natural gas storage to Portland General Electric’s Beaver and Port Westward facilities to balance renewable power generation, such as wind and solar, which varies in response to changing weather conditions. Demonstrated peak capacity is calculated as the total of the highest storage levels reached by each storage facility during any month during the most recent five-year period, with the most recent period covering December 2014 to November 2019 (the beginning of each annual heating season). Demonstrated peak reflects how storage facilities were actually used, not just how they were designed. Demonstrated peak capacity remained nearly flat, increasing 3 Bcf, or 0.1%, for the Lower 48 states in 2019 compared with 2018, marking the first time that this metric posted an annual increase since November 2016.
U.S. natural gas falls 4% as LNG exports drop on record low global prices - (Reuters) - U.S. natural gas futures fell over 4% on Monday as liquefied natural gas (LNG) exports continued to drop with record low gas prices in Europe and Asia. The price decline came despite forecasts for warmer U.S. weather and higher air conditioning demand over the next two weeks than previously expected. Front-month gas futures for July delivery fell 7.5 cents, 4.1%, to settle at $1.774 per million British thermal units. Data provider Refinitiv said gas output in the U.S. Lower 48 states was on track to fall to 87.6 billion cubic feet per day (bcfd) on the first day of June, down from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With warmer weather coming, Refinitiv projected demand, including exports, would rise from 80.2 bcfd this week to 81.8 bcfd next week. That is higher than Refinitiv's forecasts on Friday of 78.5 bcfd this week and 79.3 bcfd next week. With U.S. gas prices expected to remain higher than European benchmarks through September, the amount of pipeline gas flowing to U.S. LNG export plants was on track to fall to a nine-month low of 4.3 bcfd on the first day of June as buyers cancel cargoes. That is down from an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Most of the daily decline in LNG exports is expected at Cheniere Energy Inc's exports plants at Sabine Pass in Louisiana and Corpus Christi in Texas, according to early Refinitiv data. Cheniere said it does not comment on its operations. Analysts at Energy Aspects said they expect around 125 U.S. cargoes to be shut-in this summer, potentially slashing LNG deliveries to Europe by up to 424 billion cubic feet compared to what was expected earlier.
U.S. natgas futures gain on storm concerns and rising LNG exports - (Reuters) - U.S. natural gas futures climbed on Wednesday ahead of a storm that could disrupt Gulf Coast production and as liquefied natural gas (LNG) exports edge up with gas prices rocketing higher in Europe. After dropping to record lows last week, major European gas benchmarks soared more than 40% over the past three days, driving forwards for September at the Title Transfer Facility (TTF) in the Netherlands above the U.S. Henry Hub in Louisiana for the first time since late April. In the Gulf of Mexico, meanwhile, Tropical Storm Cristobal is expected to sweep across Louisiana's on- and offshore production areas over the coming weekend. Front-month gas futures rose 4.4 cents, or 2.5%, to settle at $1.821 per million British thermal units. Looking ahead, futures for the balance of 2020 and calendar 2021 were trading about 23% and 47% over the front-month, respectively, on hopes the economy will snap back as governments lift coronavirus-linked travel restrictions. Data provider Refinitiv said average gas output in the U.S. Lower 48 states fell to 88.3 billion cubic feet per day (bcfd) so far in June, down from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With the coming of warmer summer weather, Refinitiv projected U.S. demand, including exports, would rise from 81.0 bcfd this week to 82.0 bcfd next week. The amount of pipeline gas flowing to U.S. LNG export plants was on track to reach 4.5 bcfd on Wednesday up from a 13-month low of 3.8 bcfd earlier in the week. That compares with an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Analysts said U.S. LNG exports dropped in recent months as buyers cancel cargoes due to the collapse in European prices.
US working natural gas volumes in underground storage rise 102 Bcf on week: EIA | S&P Global Platts — US working gas in storage increased by 102 Bcf last week, which was less than the market expected, but Henry Hub futures remained static following the report. The amount of natural gas in US underground storage facilities increased 102 Bcf to 2.714 Tcf in the week that ended May 29, according to the US Energy Information Administration's weekly report, released June 4. The injection was below the consensus expectations of analysts S&P Global Platts surveyed that called for a 111 Bcf build. Responses to the survey ranged from injections of 93 Bcf to 122 Bcf. The injection was 16 Bcf, or 13.6%, below the 118 Bcf build reported in the same week a year ago and 1 Bcf below the five-year average increase of 103 Bcf, according to EIA data. US supply-and-demand balances were largely flat week on week, with large offsetting changes in residential and commercial and power burn demand leaving only a small change, according to S&P Global Platts Analytics. Gas-fired power generation demand rose 2.9 Bcf/d on the week, with gains spread across most regions, with the Midwest, East, and South Central regions adding upward of 800 MMcf/d apiece. At the same time, the Midwest and East regions had residential and commercial demand falling by 1.4 Bcf/d and 800 MMcf/d, respectively. On the US level, declines continued in industrial, LNG feedgas and Mexican exports demand further. Upstream, total supplies held mostly steady, increasing by less than 100 MMcf/d on the week to an average 90.4 Bcf/d. Storage volumes now stand 762 Bcf, or 39%, above the year-ago level of 1.952 Tcf and 422 Bcf, or 18.4%, above the five-year average of 2.292 Tcf, the data show. The NYMEX July futures contract remained unchanged at $1.82/MMBtu in trading following the release of the weekly report and was little changed in the following 30 minutes. Henry Hub NYMEX futures for the balance of summer were trading mostly flat June 4 to the day prior's close of $2.03/MMBtu, and flat to where it was priced a week ago, after some vacillation and a brief dip below $2/MMBtu earlier in the week. Spreads to next winter remain wide, with the July-through-October strip trading nearly 80 cents below the November-through-March window, as the market eyes a bullish 2021 on a tighter market stemming from supply drops from reduced associated gas production.
U.S. natgas flat as rising LNG exports offset small output increase - (Reuters) - U.S. natural gas futures were little changed on Thursday as rising liquefied natural gas (LNG) exports offset a smaller-than-expected weekly storage build and an increase in output. The U.S. Energy Information Administration (EIA) said utilities injected 102 billion cubic feet (bcf) of gas into storage during the week ended May 29. That was less than the 110-bcf build analysts forecast in a Reuters poll and compares with an increase of 118 bcf during the same week last year and a five-year (2015-19) average build of 103 bcf for the period. The increase boosts stockpiles to 2.714 trillion cubic feet (tcf), 18.4% above the five-year average of 2.292 tcf for this time of year. Front-month gas futures rose 0.1 cents, or 0.4%, to settle at $1.822 per million British thermal units. Refinitiv said gas production in the U.S. Lower 48 states fell to an average of 88.5 billion cubic feet per day (bcfd) so far in June from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. Traders, however, noted daily output was up from a one-year low of 87.3 bcfd hit a couple of weeks ago. The amount of pipeline gas flowing to U.S. LNG export plants was on track to reach 5.2 bcfd on Thursday after dropping to a 13-month low of 3.7 bcfd on Monday. That compares with an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Analysts said U.S. LNG exports dropped in recent months after buyers canceled cargoes due to the collapse in European prices. But after collapsing to record lows last week, major European gas benchmarks have soared around 50% this week. That drove forwards for August and September at the Dutch Title Transfer Facility (TTF) above the U.S. Henry Hub for the first time since late April.
U.S. natgas slides on cooler weather and lower mid-June demand – (Reuters) - U.S. natural gas futures slipped 2% on Friday on forecasts for milder weather and lower air conditioning demand in mid-June. The decline came despite an increase in liquefied natural gas (LNG) exports and concerns a tropical storm threatening the Gulf of Mexico could cut output. Front-month gas futures for July delivery on the New York Mercantile Exchange fell 4.0 cents to settle at $1.782 per million British thermal unit. For the week, the front-month was down about 2% after rising almost 7% last week. Tropical Storm Cristobal is expected to sweep across Louisiana's on- and offshore production areas over the weekend. Refinitiv said gas production in the U.S. Lower 48 states fell to an average of 88.6 billion cubic feet per day (bcfd) so far in June from a one-year low of 89.3 bcfd in May and an all-time monthly high of 95.4 bcfd in November. With the coming of milder weather in mid-June, Refinitiv projected U.S. demand, including exports, would rise from 81.2 bcfd this week to 82.2 bcfd next week before sliding to 81.6 bcfd in two weeks. The amount of pipeline gas flowing to U.S. LNG export plants was on track to reach 5.0 bcfd on Friday after dropping to a 13-month low of 3.7 bcfd Monday. That compares with an eight-month low of 6.4 bcfd in May and a monthly record high of 8.7 bcfd in February. Analysts said U.S. LNG exports dropped in recent months after buyers canceled cargoes due to a collapse in European gas prices. Major European benchmarks have soared around 60% this week from record lows last week, boosting forwards at the Dutch Title Transfer Facility (TTF) for all months over the U.S. Henry Hub for the first time since late April.
Is Puerto Rico About to Give Another Terrible Energy Contract to an American Company? - On January 6 and 7, a 6.4-magnitude earthquake and aftershocks struckPuerto Rico, killing at least one person, injuring more, and causing mass blackouts across the island’s already hobbled electrical grid. Citing damage to the Costa Sur power plant, the Puerto Rico Electric Power Authority, or Prepa, said in late January it would need to purchase some 500 megawatts of temporary generating capacity.Now it looks like an American natural gas company could win this contract, flooding the island with fossil fuels rather than investing in the renewable energy that experts say could better withstand both earthquakes and hurricanes. The company’s prior business in Puerto Rico has been conducted with minimal public oversight and a seemingly lax relationship to legal standards governing maritime fuel transport.On its quarterly earnings call in early May, New Fortress Energy announced that it had been shortlisted by Prepa, the island’s sole electric utility, to fill the gap left by damage to Costa Sur. For at least one year, NFE would supply 500 MW worth of generating capacity, reportedly at the cost of some $70 million a month. There’s also a possibility that Prepa could end up permanently purchasing this generating capacity. This would all be a pretty good deal for NFE, which is looking for a place to stash and burn extra fossil fuels that appear to be sourced largely fromthird-party providers, in addition to its liquefaction facility in Miami. As the company’s founder and CEO, Wes Edens, said on the call, “We’ve got a couple of cargoes extra that we have contracted for that we don’t need right now. And I think that what we will do is, either sell those on an outright basis or swap them into cargoes that we can then use in Puerto Rico.” Should NFE win its bid, the Federal Emergency Management Agency might furnish the funds to do just that and could reimburse the cost of the temporary generation per the terms of the Stafford Act. It wouldn’t be a great deal for building a more resilient Puerto Rican energy grid. “They just want to flood Puerto Rico and the Caribbean with fracked gas,” said Ruth Santiago, an attorney with the Environmental Dialogue Committee supporting Queremos Sol (“We Want Sun”), a platform for clean energy development and climate justice backed by a number of environmental and community groups and unions across the island. The coalition has opposed the most recent contractor bidding process, as well as ongoing fossil fuel development on the island.
Equinor planning to shut Gulf production ahead of Cristobal — Equinor is removing workers from its Titan platform in the Gulf of Mexico and is tentatively planning to shut oil production on June 5 ahead of Tropical Depression Cristobal. Cristobal was weakened from a tropical storm to a depression as it hovered over southern Mexico, but the US National Hurricane projects it to regain tropical storm strength as soon as June 5 and make landfall in Louisiana on June 7. The Norwegian energy firm only operates Titan in the Gulf but holds ownership stakes in other facilities. Equinor produces about 120,000 boe/d from the Gulf. Total crude oil production from the US Gulf is nearly 2 million b/d, according to the US Energy Information Administration. "We are currently monitoring the path of the storm and have begun the process of removing non-essential personnel from the Titan facility," Equinor spokesman Erik Haaland said. "If the track of the storm continues along its projected path, we expect to shut in production and remove remaining personnel on Friday." The largest producers in the US Gulf already are taking action to remove non-essential workers or to reduce production volumes temporarily. BP was the first to say it had begun ramping down its output. "With forecasts indicating that Cristobal will begin moving north across the Gulf of Mexico later this week, BP has begun removing offshore personnel and ramping down production at BP's operated facilities Thunder Horse, Atlantis and Na Kika," BP spokesman Jason Ryan said June 3. "Non-essential personnel are being evacuated from BP's operated Mad Dog platform, but production remains unaffected at this time." Murphy Oil said June 4 it began evacuating non-essential personnel from the Gulf, but a spokesman declined to comment on specific locations and on any impacts to production volumes. Talos Energy said it is preparing to evacuate workers. Other producers are beginning to reduce personnel as well.
Plaquemines Parish Faces Service Cuts, Layoffs And A Big Question: Can It Still Rely On Oil? -The people of Plaquemines Parish are experienced in surviving disasters, from floods to hurricanes, but now this community is facing one of the biggest threats yet: the collapsing oil market. The parish’s budget is tied to the price of oil because the parish is in the oil business. It owns about 100,000 acres of land in the Gulf of Mexico that it leases out to oil companies, which pay to drill there.Last year, the parish hired its usual consultants and the finance office worked up estimates for this year’s budget accounting for the price of oil. A barrel of oil then was $59. Now it’s just $30. Because of the coronavirus’ impact on oil prices, the parish faces a $7.5 million budget shortfall, forcing lawmakers to consider whether to raise taxes, lay off staff, cut services, or all of the above. At a recent parish council meeting, held on Zoom, finance manager Tommy Serpas proposed taking out bonds to cover the difference and keep the government operating.“When we run out of money in August or September, how are we going to pay the bills? I mean, everything will have to stop. We won’t be able to pay anything,” he said, sounding exasperated. Councilmember Trudy Newberry agreed: “This pandemic is an eye-opener. We need to get off our butts and we need to do something!”
19 energy companies have filed for bankruptcy in 2020: law firm – Texas-based Gavilan Resources last month filed for Chapter 11 protection, saying it intends to sell its business and assets. It cited the coronavirus pandemic and the oil price rout along with an ongoing dispute with a joint venture partner in the Eagle Ford Shale in South Texas, Kallanish Energy reports. It is among 19 new bankruptcies filed in 2020 through May 31 by U.S. energy companies, according to a list maintained by the Haynes and Boone law firm. The firm with headquarters in Dallas, Texas, said the 19 filings reflected a total debt of $13.1 billion. Other firms filing for federal protection include Whiting Petroleum, Echo Energy Partners, Ultra Petroleum, Skylar Exploration, Diamond Offshore, Freedom Oil and Gas, and Templar Energy. There were 51 bankruptcy filings from Jan. 1 through May 31 in 2016; 14 in 2017, 18 in 2018, and 18 in 2019, the law firm said in its Oil Patch Bankruptcy Monitor. Overall, there are about 225 bankruptcy cases across the country pending in federal bankruptcy courts, as of May 31, it said. There have been predictions that a wave of Chapter 11 filings is coming and that more than 100 U.S. energy companies may be forced to declare bankruptcy this year after the coronavirus pandemic and the oil price rout. According to Haynes and Boone, there have been 13 bankruptcies by oilfield service companies in 2020, through May 31. Those filings had a total debt of $11.6 billion, it said. That compares to 28 bankruptcies from Jan. 1 through May 31 in 2017, eight in 2018 and four in 2019, the law firm said in a separate listing of wellfield service companies.
Stuck with too much diesel, U.S. refiners need to restrict runs - Kemp (Reuters) - U.S. refiners are struggling to manage their production and stocks as the economy’s uneven re-opening leaves demand for some refined fuels recovering much faster than others. Output cuts by OPEC+ and U.S. domestic producers have brought crude inventories under control, but stocks of refined products, especially diesel and other middle distillates, are rising unsustainably. U.S. consumption of gasoline is recovering much faster than diesel, as stay-at-home orders are lifted but much of the manufacturing, freight and distribution system is still operating at reduced rates. By focusing on meeting rising demand for gasoline, their most important product by volume and revenue-generation, refiners have left the market awash with diesel, which is now depressing profit margins. In the week to May 29, refiners boosted crude processing to an average of 13.3 million barrels per day (bpd), up from a recent low of 12.5 million bpd in mid-April (https://tmsnrt.rs/3dvwo8o). Gasoline consumption continued to recover steadily, with the volume supplied to the domestic market reaching an estimated 7.5 million bpd last week, up from a low of just 5.1 million bpd in early April. More than half of the gasoline consumption lost when the country went into lockdown has now returned as stay-at-home orders are lifted and private motoring increases. But distillate consumption is showing a much softer recovery, with supply last week at just 2.7 million bpd, no higher than during the most intense lockdown in early April. Gasoline stocks remain high but appear under control, rising by 3 million barrels last week and up just 11 million barrels since the country went into lockdown in late March. Stocks are around 24 million barrels (10%) higher than year-ago levels and 38 million barrels (17%) above the ten-year seasonal average, which is manageable. By contrast, distillate stocks surged by almost 10 million barrels last week, the ninth weekly increase in a row, with inventories up by 52 million barrels (43%) since the end of March. Distillate stocks are now 45 million barrels (35%) higher than at the same point last year and 43 million barrels (33%) higher than the ten-year seasonal average, and are still trending higher.
20,000 gallons of oil found illegally buried in Crosby, leaking into nearby waterway, officials say - The Harris County Precinct 1 Constable’s Office is investigating what they call a serious crime against the environment in Crosby, Texas.On May 28, environmental investigators were called to 1017 Church Street and discovered tens of thousands of gallons of oil buried illegally at the property.“It was buried here and it is everywhere," said Harris County Precinct 1 Constable Alan Rosen. “You can smell it, you can see it and it is oozing out of the ground as we dig.”Rosen says investigators were tipped off by a citizen who saw oil flowing into a nearby drainage ditch.During the investigation, Rosen says members of his Environmental Crimes division discovered ruptured barrels of oil buried deep in the ground in layers on the property. That oil was then discovered leaking into a nearby drainage ditch.“It stretched at least one-quarter mile west along Church Street and 655 feet to the south along the San Jacinto River Authority’s clean water basin," officials wrote in a press release.Crews are working to try and clean up the leaking oil and prevent it from spreading further into surrounding waterways.“Since last week remediation teams have removed over 20 thousand gallons of contaminated oil/water mix from those ditches.”Investigators said the size and volume of the contamination were among “the largest and most significant they have ever worked.”“This is a very serious environmental case,” Rosen said.The Harris County District Attorney’s Office helped Constable’s deputies obtain a search warrant Friday. Soil samples from the property will undergo chemical analysis and if investigators can prove the chemical on the property did in fact seep into the nearby ditches, they may seek criminal charges, officials wrote.As of Friday night, property owner Wesley Zarsky has not been arrested or charged.A temporary restraining order was obtained to prevent Zarsky from dumping any kind of hazardous waste or oil on the property and force him to begin cleanup.Officials estimate the total cost of cleanup has already surpassed $1 million.
Armed With Eminent Domain, Pipeline Projects Continue to Burden Landowners During the Pandemic -- Pipeline giant Kinder Morgan is cutting a 400-mile line across the middle of Texas, digging up vast swaths of private land for its planned Permian Highway Pipeline. The project is ceaseless, continuing through the coronavirus pandemic. Landowner Heath Frantzen said that dozens of workers have showed up to his ranch in Fredericksburg, even as public health officials urged people to stay at home. “There weren’t wearing masks. They weren’t wearing gloves. They weren’t practicing social distancing,” he said. Frantzen believes the workers pose a danger to him and his 85-year-old father, whom he cares for. While the laborers are confined to the pipeline’s path, he worries they could spread the coronavirus by touching fence railings or gates that he might later handle. In Texas, where the governor exempted pipeline projects from his March stay-at-home order, companies like Kinder Morgan have few checks on their power of eminent domain, which allows them to build pipelines through privately owned farms and ranches that lie in their way. Eminent domain is broadly unpopular and, when used for pipelines, legally contentious. The coronavirus adds a new wrinkle to the debate over the practice as companies like Kinder Morgan continue to work through the pandemic, vexing landowners. “It is wild that people are being forced to accept others onto their land at this time, and if they have an issue with what’s happening, they have to put themselves at risk to address workers directly,” said Erin Zweiner, who represents Blanco County and Hays County in the Texas House of Representatives. “These are workers who hop all over the country, so they’re pretty high-risk spreaders.”
Drilling drought --Monday marked the first day of Hurricane Season and there's already a tropical depression in the Bay of Campeche, but there's a drought of sorts in progress.The Eagle Ford Shale of South Texas is on the verge of entering a drilling permit drought.Houston oil company EP Energy was the only company to file a drilling permit for a project in the region from May 20 to 26. EP Energy, which filed for Chapter 11 bankruptcy in October, is seeking permission to drill a single horizontal well in La Salle County.Record low crude oil prices caused by the coronavirus pandemic continue to take their toll on drilling permits fillings. Only 23 companies filed for 45 drilling permits in Texas from May 20 to 26.
Permian gas pollution halves in upside of oil crash --Natural gas pollution at the world's most prolific oilfield will halve in the coming months, providing an environmental upside to the worst crash in the price of crude in decades.As tumbling demand forces producers to shut in wells across the US, analysts at Rystad Energy estimate the amount of gas flared — where drillers burn off the less valuable gas found alongside the oil — in the Permian Basin will fall from 600m cubic feet a day at the beginning of the year to below 300m cubic feet in the second half.The drop-off is equivalent to the amount of gas required to heat half of all homes in Texas.“In the second quarter we will definitely see a massive decline,” said Artem Abramov, head of shale research at Rystad. “More or less all fracking activities are on hold. Where there is still activity going on it is marginal.” Flaring occurs where gas is recovered as a byproduct of oil drilling. Often a lack of infrastructure makes finding a market for the gas uneconomical, so the easiest option is to set it alight.But the practice is highly polluting. Burning the gas emits carbon dioxide into the atmosphere. And where equipment is not up to scratch, it can also lead to methane — which traps far more heat than CO2 — being vented directly into the air. The shale boom of the past decade has caused US oil production to soar, allowing Donald Trump to boast of “energy independence”. Output surpassed 13m barrels a day earlier this year, with the Permian accounting for more than a third of this.But with the growth in production has come a rise in flaring. The Texas Railroad Commission, which regulates the practice in much of the Permian, issued almost 7,000 licences last year — more than 20 times the figure a decade earlier. Among the basin’s biggest flarers on an absolute basis are ExxonMobil-owned XTO Energy, Diamondback E&P and Encana Oil and Gas, according to the regulator.However, smaller, private equity-backed companies, eager to make quick returns, tend to be the worst offenders, analysts said. The Railroad Commission lists small-time producers including Continental Trend Resources, Siltstone Resources and Mammoth Exploration — which only produce a few hundred barrels of oil a day between them — as having the worst record for flaring relative to output.
State Reopenings Give Oil And Gas Producers A Temporary Boost - podcast - Over the past few months, the pandemic has had a profound impact on almost every aspect of the U.S. and Texas economies. Added to that, huge drops in the oil market have devastated Texas’ most lucrative export industry.But Matt Smith, director of commodity research at ClipperData, told Texas Standard host David Brown that oil and gas producers might get some relief as states reopen and people return to work. He said oil prices are slowly starting to climb.“As oil has rallied in the last month or so … oil prices are dragging gasoline prices higher, even though demand hasn’t necessarily done that ‘V’ rebound by any means,” Smith said.Oil prices will likely continue to climb along with consumer demand, and also if OPEC continues to limit oil production. Earlier this year, OPEC member country Saudi Arabia flooded the market, which contributed to the steep drop in oil prices.But Smith warned that stability in the oil and gas market is still tenuous, especially as Latin America faces its worst phase so far of the COVID-19 pandemic. What you’ll hear in this segment:
- – Why Latin America matters to U.S. oil and gas producers
- – Whether summer travel could bolster the energy sector
- – How the rise in telecommuting could have long-term effects on oil and gas production
Shale Oil Production Bouncing Back With Prices-- Early signs of a shale rebound are becoming evident as crude prices emerge from their dramatic collapse earlier this year. EOG Resources Inc., America’s largest shale-focused producer, plans to “accelerate” output in the second half after shutting in about a quarter of its crude in May, exploration chief Ken Boedeker told an RBC Capital Markets conference Tuesday. Permian producer Parsley Energy Inc. is also turning wells back on just weeks after closing the taps, and producers in the Bakken formation in North Dakota are also easing the rate of shut-ins. After the breakup in the OPEC+ alliance in March and a plunge in demand because of virus-related lockdowns, which pushed the price of West Texas Intermediate to minus $40 a barrel on April 20, oil has been on a steady march upward during the past month. While the U.S. benchmark price is still about 40% below its high point in January, it has jumped to more than $35, above the operating costs of some shale wells that had been closed to save cash. Futures were up 2.3% at $36.24 at 11:50 a.m. in New York. EOG’s strategy “is to really accelerate our production into what we see as a price recovery in the second half of the year,” Boedeker said. The company, which began shutting wells in March and took 125,000 barrels a day off the market in May, recently reduced its hedge position, eliminating some protection against lower prices in a sign of confidence the price recovery will take hold. Parsley will restore the “vast majority” of the 26,000 barrels of daily output it turned off last month, it said in a slide deck for an investor presentation.” Meanwhile, shut-ins in the Bakken totaled 475,000 barrels a day as of May 28, about 7% less than a fortnight earlier. The number of frack crews working in shale fields is believed to have now bottomed at about 80 fleets, with “noticeably higher” completion work in the next three to six months, Based on current budget tweaks announced by explorers, as many as 50 frack crews could still be added by the end of the year, with that number doubling if oil prices move closer to $40 a barrel,
US Production May Be Significantly Less Than EIA Estimate: Bloomberg, Reader -- June 4, 2020 - After the EIA weekly petroleum report was released yesterday, a reader who follows this very, very closely, noted: I haven't even looked at the rest of the report, but the first thing I noticed is that a million barrels of oil per day went missing for the third week in a row, ie, production + imports + storage withdrawal has been 1 mbpd greater than refinery use + exports + the SPR addition... Best guess is that their production number has been wrong... You can see my reply at this post. Overnight, Bloomberg posted an article saying the very same thing: oil traders are asking why US inventory math doesn't add up. “Oil traders and analysts scrutinizing U.S. inventory data for signs of a market recovery are being confronted by an odd situation: the math just doesn’t add up. Various government data sets including stockpiles, production, imports and exports are signaling that current official figures on at least some supplies are excessive.The excess is showing up in the U.S. Energy Information Administration’s so-called crude supply adjustment factor -- the difference between stockpile numbers and those implied by production, refinery demand, imports and exports.That has averaged negative 980,000 barrels daily over the past four weeks -- the largest in records going back to 2001, and equivalent to more than 27 million barrels.”That's nearly exactly what the reader reported: a one-million-bopd discrepancy. The Bloomberg article continues:The adjustment factor tends to swing back and forth ...Some investors lay the blame for the current discrepancy on U.S. oil production numbers. While daily output fell 700,000 barrels to 11.2 million in May, they believe oil’s plunge into negative territory in April should have led to a steeper decline. Just last month, consultancy IHS Markit said that U.S. oil producers are in the process of curtailing 1.75 million barrels a day of existing output by early June...
Lower crude oil prices will mean less exploration and development -According to the financial reports analyzed by the U.S. Energy Information Administration (EIA), global expenditures related to oil and natural gas exploration and development (E&D) increased $42 billion (13%) for 102 publicly traded oil companies in 2019, totaling $361 billion. As a result of significant crude oil price declines in 2020, however, global proved reserves will likely be revised downward, and E&D expenditures will also likely decline. Several companies have already announced large budget reductions.EIA based its analysis and its recently published 2019 Financial Review primarily on the published financial reports of 102 publicly traded companies, so the conclusions do not necessarily represent the sector as a whole because the analysis does not include private companies that do not publish financial reports.According to their financial statements, these 102 companies produced 22.2 billion barrels of oil equivalent (BOE), a measure that reflects their combined production of crude oil and natural gas, and spent $361 billion in E&D. Dividing these companies’ E&D expenditures by their combined production volumes provides a ratio of $16/BOE in 2019, or about one-quarter of the average Brent crude oil price of $64/barrel (b).In its May Short-Term Energy Outlook, EIA forecasts Brent crude oil prices will average $34/b in 2020. If this crude oil price forecast is realized, E&D expenditures per BOE could fall to less than $10/BOE in 2020 if E&D expenditures remain at about one-quarter of the Brent crude oil price.Proved reserves are estimated quantities of oil and natural gas that analysis of geological and engineering data demonstrates with reasonable certainty are recoverable under existing economic and operating conditions. Because crude oil prices directly affect the profitability of E&D projects, changes in the prices companies use to develop their calculation of reserves can significantly affect their proved reserves levels and the volume of reserves they can claim as additions.
Some analysts still bet on Chesapeake going bankrupt this year - Oklahoma City’s Chesapeake Energy continues to be on a list of analysts who predict will be among those firms filing for bankruptcy this year, a move hastened perhaps by the COVID-19 pandemic and the oil crisis.Analyst Travis Hoium, writing for Motley Fool predicted Chesapeake is one of three firms he believes will head to bankruptcy court yet this year.The oil industry has been flipped on its head over the last few months as economic shutdowns around the world have caused demand to plummet by around 20%. For a short time, oil futures prices even went negative in the U.S. because there was more supply than demand.“Producers and suppliers in the oil market are trying to cut costs and adjust finances as quickly as possible, but not everyone will survive. And Occidental Petroleum (NYSE:OXY), Chesapeake Energy (NYSE:CHK), and Transocean (NYSE:RIG) are three that I think might be considering bankruptcy by the end of the year,” wrote Hoium.Chesapeake Energy has always been a company willing to take risks to grow its business, but that’s likely to backfire. The company has $8.9 billion of debt and even before COVID-19 and the resulting drop in oil prices wasn’t able to squeeze out much of a profit.Cash on hand was a meager $82 million as of March 31, 2020, so there isn’t a big financial backstop on the balance sheet either. To shore up the balance sheet and pay off $253 million of debt coming due this year, management had planned to sell $300 million to $500 million of non-core assets, which will likely be difficult in the current energy environment. Oil prices have recovered slightly over the past month but for Chesapeake Energy, the drop in natural gas prices could be offset any oil gains. The company is still a big producer of natural gas and that market has collapsed as well. Chesapeake Energy may have enough hedges and assets to survive for a few more months, but if the weak energy market continues much longer it won’t survive the year.
Enbridge likely to miss prime construction season for new Minnesota pipeline - Enbridge had hoped this month to be building its controversial and much-delayed oil pipeline across northern Minnesota. Instead, the company may miss prime construction season for the second year in a row.Minnesota pollution-control regulators are expected to announce this week whether to make a deeper inquiry into Enbridge’s pipeline construction permits.If they do — and that seems increasingly likely — Enbridge probably won’t be able to start construction until late fall at best.The $2.6 billion proposed pipeline, which is a replacement for its deteriorating Line 3, has been winding through the state’s regulatory process for five years. The Minnesota Public Utilities Commission (PUC) reapproved the new Line 3 in early February.The PUC is the primary regulator of oil pipelines in Minnesota, including determining the risk of oil-spill hazards once they are in operation. But Enbridge must also get more technical approvals from the Minnesota Pollution Control Agency (MPCA) and other agencies.The MPCA in February released “draft permits” for the new Line 3 construction. In April, environmental groups and Ojibwe bands that oppose the new line petitioned the MPCA to conduct a “contested case” on the permits.A contested case usually involves hearings and a review by an administrative law judge. Darin Broton, an MPCA spokesman, said Tuesday that the agency is still reviewing its decision, though he declined to disclose it.“We are looking at the legal guidance set by the [Minnesota] Court of Appeals in the PolyMet case,” he said. “The Court of Appeals made it clear that agencies don’t have unfettered discretion to reject a contested case if issues of fact are unresolved.”
State officials agree to give Line 3 permits additional scrutiny State regulators agreed Wednesday to hold an additional hearing on a key permit for the proposed Line 3 replacement project, a process that is expected to delay construction of the controversial oil pipeline by several months. The Minnesota Pollution Control Agency announced that a contested case hearing will be held later this summer on a draft water quality permit for the project, in which a state administrative law judge will hear additional evidence on the proposed pipeline’s impacts on wetlands and stream crossings. The decision to hold the additional hearing pushes back the MPCA’s deadline to make a decision on the permit — known as a 401 water quality certification — until Nov. 14, three months past the original timeline. “The contested case hearing will help ensure the certification is protective of one of Minnesota’s most important resources,” said MPCA Commissioner Laura Bishop in a statement. State utility regulators have already approved Enbridge’s controversial project. The Canadian company wants to replace an aging, deteriorating pipeline that delivers crude from the Alberta oil sands across northern Minnesota. But the project has been stalled by legal and regulatory delays, which have raised the estimated project cost to $2.9 billion. The company still needs additional construction permits from the MPCA, the state Department of Natural Resources, and the U.S. Army Corps of Engineers. In a statement, Enbridge said it still anticipated starting construction on the project before the end of the year, a process that will take six to nine months to complete. “While the contested case has caused a delay to the permitting process, we believe this additional step will strengthen the MPCA’s decision record,” said Vern Yu, Enbridge’s president of liquids pipelines. The Red Lake Nation and White Earth Band of Ojibwe, along with several individuals and environmental groups — including Friends of the Headwaters, the Sierra Club and Honor the Earth — had asked for the contested case hearing on a number of grounds, including the pipeline’s contribution to climate change and the risk of oil spills. But the hearing the MPCA granted will focus on relatively narrow issues, including the amount of wetlands that will be impacted by the project, and the potential impacts where the proposed pipeline would cross streams and rivers. The Sierra Club’s North Star Chapter Director Margaret Levin welcomed the additional scrutiny on Line 3. “This tar sands pipeline would be a disaster for our waterways and communities, she said.
US states have spent the past 5 years trying to criminalize protest --The Minnesota legislature has spent the last five years preparing for the kind of protests that have rocked the city over the past week in the wake of the police killing of George Floyd — by attempting to criminalize them.From 2016 through 2019, state lawmakers introduced ten bills that either made obstructing traffic on highways a misdemeanor or increased penalties for protesting near oil and gas facilities. Most of these legislative proposals were introduced in response to ongoing protests against a controversial oil pipeline as well as those following the police killing of Philando Castile in a St. Paul suburb in 2016. The bills would have allowed protesters to be jailed for up to a year, fined offenders up to $3,000 each, and allowed cities to sue protesters for the cost of police response. Many of the bills were introduced in 2017 after racial justice activists in the state made headlines shutting down a major highway. A coupleothers were in response to protests in 2016 and 2019 against the energy company Enbridge’s planned replacement of a pipeline running from Alberta to Wisconsin.None of the bills have yet become law, but three failed only because they were vetoed by the governor. Two bills introduced earlier this year are still on the table. One would make trespassing on property with oil and gas facilities punishable by up to three years in prison and a $5,000 fine. The other would make those who assist such activity civilly liable for damages.Over the past half-decade, a wave of bills that criminalize civil disobedience has swept state legislatures across the country — particularly those controlled by Republican lawmakers. According to a new report by PEN America, a nonprofit advocating for First Amendment rights, 116 such bills were proposed in state legislatures between 2015 and 2020. Of those, 23 bills in 15 states became law. While there is no comprehensive count of the number of people arrested and prosecuted under these new laws, activists protesting oil and gas activity have been charged with felonies in Houston and Louisiana. This year alone, four states — Kentucky, South Dakota, West Virginia, and Utah — passed laws that increased penalties and charges for either interfering with oil and gas activity or disturbing meetings of government officials. (Interfering with oil and gas activity may include obstructing the construction or operation of pipelines and other “critical infrastructure.”) As of May, 12 other bills are pending in various state legislatures — all of them introduced before the past week’s unrest. If passed, these bills would increase disciplinary sanctions for campus protesters, classify trespassing on property with oil and gas infrastructure a felony, and expand the definition of rioting, among other things. More bills increasing penalties for protesters may be on their way. In response to the recent protests against George Floyd’s killing, a Tennessee lawmaker has proposed increasing penalties for rioting and South Dakota Governor Kristi Noemhas said that her administration is looking into legislative proposals to respond to the recent unrest.
Old U.S. Oil Refinery to Pursue New Green Life After Crude Crash - HollyFrontier Corp.’s Cheyenne refinery will stop using crude oil and be repurposed to pump out renewable diesel, which is typically made from soybean oil, recycled cooking oil and animal fats. That’s after processing margins plummeted on thecollapse in fuel demand due to Covid-19-related lockdowns. Cheaper renewable energy projects have already led to decreasing coal output across the U.S., and now -- in the wake of oil’s historic crash -- some fuel producers are grappling with diminished returns from turning crude into fuel. The company expects to spend $125 million to $175 million to re-purpose Cheyenne to produce about 90 million gallons per year of renewable diesel by the first quarter of 2022. The plant will stop consuming crude oil at the end of July this year, and 200 workers will be laid off, according to HollyFrontier.The conversion plan comes as dozens of small refineries nationwide brace for a big spike in costs to comply with the Renewable Fuel Standard, which mandates they blend biofuel into gasoline or buy tradable credits to comply. For years, many small refineries have won exemptions from the mandate, but under a federal appeals court ruling in January, only refineries that have continually been granted waivers can count on getting them in the future.HollyFrontier is effectively shedding the Cheyenne refinery’s biofuel-blending obligation under the RFS and transforming it into a plant that stands to benefit from the program.Using the converted plant, HollyFrontier will be able to produce not just renewable diesel encouraged by the RFS but also compliance credits that can be sold separately. However the transition comes with other costs, as fewer workers will be necessary to run the converted plant. The RFS is effectively forcing theclosure of a plant that generated tax revenue and jobs for Wyoming and mandating its replacement be a smaller plant that employs far fewer people to sell fuel to California, said a refining industry official who asked not to be named discussing industry strategy.
How Amazon Is Bringing the Keystone XL Pipeline Online – Steve Horn -Amazon has cemented a partnership with the company that owns the controversial Keystone XL pipeline, recently announcing that TC Energy is “going all-in” on Amazon Web Services. The Canadian pipeline corporation, formerly known as TransCanada, has “migrated almost 90 percent of its corporate and commercial applications” to Amazon Web Services, according to a May 13th statement from Amazon. TC Energy plans to migrate all of its data to Amazon’s cloud, and AWS has already helped the pipeline company develop a suite of workflow automation, data analytics, and machine learning programs.“TC Energy is going all-in on the world’s leading cloud, moving its entire infrastructure to AWS,” the AWS release says. “TC Energy is leveraging the breadth and depth of AWS services, including machine learning, analytics, database, serverless, storage, and compute to deliver energy and generate power more efficiently for millions of homes in North America.”The announcement comes just weeks after TC Energy’s long-contested Keystone XL pipeline, which would carry some of the dirtiest, most carbon-intensive oil on the planet from the Alberta tar sands basin to Nebraska, faced a major legal setback when its permit was vacated by a federal judge. It also comes amid a time of tumult for Amazon, which has, in recent weeks, faced criticism for its treatment of frontline workers during the coronavirus pandemic, and for firing employees calling for more protections. Last year, Amazon tech workers launched a movement calling on CEO Jeff Bezos to adopt a stricter company-wide climate policy and to cancel its contracts with oil and gas companies. Bezos responded by issuing Amazon’s Climate Pledge, which promised to see the company go carbon neutral by 2040. He also stated that the company would continue to do business with the oil and gas industry. This puts Amazon at odds with Google, which recently announced it would not develop custom A.I. tools that enhanced the extraction rate of fossil fuels.“So Amazon is helping build the Keystone pipeline — as plain an example of climatic destruction and human rights abuse as exists on the planet,” said author, activist, and 350.org founder Bill McKibben, who led the opposition to Keystone XL for much of the 2010s, to OneZero in an email. “And for what? So the richest man on earth can be a little richer? The levels of ugliness here just seem endless.”
Trump rule limits states from blocking pipeline projects - The Trump administration gutted a key portion of the Clean Water Act on Monday, limiting states’ ability to block controversial pipeline projects that cross their waterways. The final rule from the Environmental Protection Agency (EPA) targets Section 401 of the law, which lets states halt projects that risk hurting their water quality. It’s been a target of President Trump, who last April ordered the agency to accelerate and promote the construction of pipelines and other important infrastructure. “Today, we are following through on President Trump’s Executive Order to curb abuses of the Clean Water Act that have held our nation’s energy infrastructure projects hostage, and to put in place clear guidelines that finally give these projects a path forward,” EPA Administrator Andrew Wheeler said in a statement. The Clean Water Act essentially gives states veto power over large projects that cut through their rivers and streams, giving them a year to weigh permits and determine how projects would impact their water quality. Environmentalists see it as a way for states to assert their power to block risky projects, but the fossil fuel industry and many Republicans say the section has been abused to stall infrastructure. “This rule is an egregious assault on states’ longstanding authority to safeguard the quality of their own waters. Despite the Trump administration’s professed respect for ‘cooperative federalism,’ it is clearly willing to steamroll states’ rights and greenlight major construction projects with no regard for how they might damage state waters,” Lisa Feldt with the Chesapeake Bay Foundation said in a statement. Two states run by Democrats have recently used the law to sideline major projects: New York denied a certification for the Constitution Pipeline, a 124-mile natural gas pipeline that would have run from Pennsylvania to New York, crossing rivers more than 200 times. Washington state also denied certification for the Millennium Coal Terminal, a shipping port for large stocks of coal.The new policy from the Trump administration would accelerate timelines under the law, limiting what it sees as state power to keep a project in harmful limbo. The need for a 401 certification from the state will be waived if states do not respond within a year. On a call with reporters, Wheeler accused some states of abusing the law, dragging out the certification for years or denying projects for reasons not sufficiently tied to water quality, “wrapping projects in a bureaucratic Groundhog Day in the hopes that investors become frustrated and end development.” States will still be able to block certain projects, but Wheeler warned states risk having their veto power overturned if they stray beyond water quality issues when denying a certification. Climate change or concerns over water scarcity would not be enough for a state to deny certification to a project, he said.
U.S. States Just Lost Pipeline Veto Rights And That’s A Big Deal For Oil --The oil and gas industry in the United States scored a big win this week after the EPA narrowed the focus of a rule that up until now, allowed states to refuse to grant pipeline permits—or stall them indefinitely. But under the Trump Administration’s guidance, the EPA is saying no more shenanigans. The U.S. Environmental Protection Agency (EPA) has issued a final rule narrowing the scope of review for proposed oil and gas pipelines that states should consider under a section of the Clean Water Act for energy infrastructure.Up until now, states have been using Section 401 of the Clean Water Act to deny permits to oil and gas pipeline projects.But this final rule makes it clear: under the Clean Water Act Section 401, states can look at the water issues only—not larger issues such as climate change–when asked to review an energy infrastructure project.States will also be required to complete the review within one year of receiving a certification request—a rule that will surely cramp the styles of the anti-fossil fuel states.The EPA’s actions this week isn’t so much a change in policy or intent of policy, but a clarification of the spirit of the existing Clean Water Act, which the EPA contends was never designed to blanketly oppose oil pipelines on broad climate change grounds, after the FERC had given a project a green light. This keeps the assessment of the broader environmental impact in the hands of the FERC, not each state.“When states look at issues other than the impact on water quality, they go beyond the scope of the Clean Water Act,” EPA said in a statement.“EPA is returning the Clean Water Act certification process under Section 401 to its original purpose, which is to review potential impacts that discharges from federally permitted projects may have on water resources, not to indefinitely delay or block critically important infrastructure,” EPA Administrator Andrew Wheeler said.
Oil and babies don't mix: Wells linked to low birthweight -- Pregnant women in rural California who lived near active oil and gas wells were 40% more likely to give birth to low birthweight babies, according to new research published today.The study led by University of California scientists is the first to investigate what California’s constellation of oil and gas development means for babies born nearby. The finding couldgalvanize efforts in the state Legislature to require buffer zones around oil and gas activities.The researchers found that 6% of women living near rural oil and gas wells that churned out more than 100 barrels a day had low birthweight newborns, compared to 5% of women with no oil and gas production nearby. When the researchers factored in variables like the mother’s age and socioeconomic status, that translates to a 40 percent increased likelihood. Low birthweight babies, who weigh less than 5.5 pounds at birth, may be healthy but often have a higher rate of illnesses, such as respiratory diseases and difficulty fighting infections, as well as developmental delays. The researchers reviewed nearly 3 million birth certificates from 2006 to 2015 in the Sacramento Valley, San Joaquin Valley, South Central Coast and Los Angeles Basin.While the link between oil and gas production and low birthweight babies was found in rural areas, it didn’t hold up in urban areas, such as large parts of the Los Angeles region. But a well churning out oil in a city backyard is not necessarily benign. Morello-Frosch said it’s possible the link to low birthweight babies is there, but it’s just hard to spot because oil and gas might produce a smaller share of the overall pollution in urban areas. In addition, people in rural regions are exposed to pollutants — in groundwater, for instance — that might make them more vulnerable to pollution from oil and gas production. The findings, published in the journal Environmental Health Perspectives, support a handful of studies in other states, including Colorado and Pennsylvania. Those earlier studies reported increased odds of health effects among babies born near oil and gas development, including premature births, heart defects, and low birthweight.
How Should California Wind Down Its Fossil Fuel Industry? - California’s energy past is on a collision course with its future. Think of major oil-producing U.S. states, and Texas, Alaska or North Dakota probably come to mind. Although its position relative to other states has been falling for 20 years, California remains the seventh-largest oil-producing state, with 162 million barrels of crude coming up in 2018, translating to tax revenue and jobs. At the same time, California leads the nation in solar rooftops and electric vehicles on the road by a wide margin and ranking fifth in installed wind capacity. Clean energy is the state’s future. By law, California must have 100 percent carbon-free electricity by 2045, and an executive order signed by former Governor Jerry Brown calls for economywide carbon-neutrality by the same year. So how can the state reconcile its divergent energy path? How should clean-energy-minded lawmakers wind down California’s oil and gas sector in a way that aligns with the state’s long-term climate targets while providing a just transition for the industry’s workforce? Any efforts to reduce fossil fuel supply must run parallel to aggressive demand-reduction measures such as California’s push to have 5 million zero-emission vehicles on the road by 2030, said Ethan Elkind, director of Berkeley Law's climate program. After all, if oil demand in California remains strong, crude from outside the state will simply fill the void. “If we don’t stop using it, then that supply is going to get here, even if it’s not produced in-state,” Elkind said in an interview. Lawmakers have a number of options for policies that would draw down and eventually phase out fossil fuel production in California, according to a new report from the Center for Law, Energy and the Environment at the UC Berkeley School of Law, co-authored by Elkind and Ted Lamm. They could impose a higher price on California's oil production through a "severance" tax or carbon-based fee, with the revenue directed to measures that wean the state from fossil fuels. (California, alone among major oil-producing states, does not have an oil severance tax.) Lawmakers could establish a minimum drilling setback from schools, playgrounds, homes and other sensitive sites. They could push the state's oil and gas regulator, the California Geologic Energy Management Division, to prioritize environmental and climate concerns. A major factor holding lawmakers back is, of course, politics. Given the state’s clean-energy ambitions, it might surprise non-Californians that the oil and gas industry is one of the Golden State’s most powerful special interest groups.
Canada is the largest source of U.S. energy imports - Canada is the largest source of U.S. energy imports and the second-largest destination for U.S. energy exports behind only Mexico. Energy is an important component of trade between Canada and the United States. In 2019, based on the latest annual Standard International Trade Classification (SITC) data from the U.S. Census Bureau, energy accounted for US $85 billion, or 27%, of the value of all U.S. imports from Canada. Crude oil and petroleum products accounted for 91% of the value of U.S. energy imports from Canada and 89% of the value of U.S. energy exports to Canada.The United States exported US $23 billion worth of crude oil, petroleum products, natural gas, and electricity to Canada in 2019, about 8% of the value of all U.S. exports to Canada and the second-highest level recorded after peaking in 2014.U.S. crude oil imports from Canada accounted for 56% of all crude oil imports to the United States in 2019, averaging 3.8 million barrels per day (b/d)—up from 3.7 million b/d in 2018. In 2019, the United States exported 459,000 b/d of crude oil to Canada, which remained the largest destination for U.S. crude oil exports. U.S. crude oil exports to Canada are typically light, sweet grades that are shipped to the eastern part of the country. U.S. crude oil imports from Canada tend to be heavy and are sourced from oil sands in Alberta (Western Canada), and most of these exports flow to U.S. Midwest refineries.Crude oil trade by rail has become more attractive because pipeline capacity in Canada has at times been insufficient to accommodate Canada’s growing crude oil production. Consequently, U.S. imports of Canada’s crude oil by rail have more than tripled from an average of 91,000 b/d in 2016 to an average of 300,000 b/d in 2019. More than half of the crude oil volume imported by rail (171,000 b/d) went to the U.S. Gulf Coast region. Petroleum product trade between the United States and Canada is relatively balanced in both volume and value. Canada is the largest source of U.S. petroleum and refined products imports. In 2019, the United States imported a record 610,000 b/d of petroleum products from Canada, or 26% of all U.S. petroleum product imports last year. These imports were valued at more than US $14 billion. Natural gas trade between the United States and Canada is dominated by pipeline shipments, which accounted for 98% of all U.S. natural gas imports in 2019. Historically, the United States has imported more natural gas than it has exported by pipeline to Canada. Natural gas imports from Canada in 2019 totaled 7.4 billion cubic feet per day (Bcf/d) and were valued at US $6 billion in 2019. Most of the natural gas the United States imported from Canada originated in Western Canada and was shipped to U.S. markets in the West and Midwest regions. U.S. natural gas exports to Canada mainly go into the eastern provinces of Canada.
Push Comes To Shove - Will Crude Shippers Soon Need To Commit To Enbridge's Mainline System? - Up in Canada, there is finally a regulatory timeline for reviewing Enbridge’s long-standing proposal to revamp how it allocates space — and charges for service — on the company’s 2.9-MMb/d Mainline. But the plan to convert the largest crude oil pipeline system out of Western Canada from one whose space is 100% uncommitted and allocated every month to one with 90% of its capacity locked in via long-term contracts remains controversial, especially among producers. Plus, the world has changed in the past few months. Oil sands and other production in Alberta and its provincial neighbors is off sharply in response to pandemic-related demand destruction and low oil prices, and the always-full Mainline has been running at well under 90% of its capacity lately. Further, the Trans Mountain Expansion and Keystone XL projects — competitors to the Mainline in a way — have progressed this year, making shippers wonder whether to lock in capacity on the Mainline if TMX and KXL’s completion may be imminent. Today, we begin a short series on the prospective shift to a contract-carriage approach on the primary conduit for heavy and light crudes from Western Canada to U.S. crude hubs and refineries.
Unknown quantity of oil spilled from refinery into city sewers - An unknown amount of oil from the Co-op Refinery Complex (CRC) spilled into Regina’s sewers sometime last week. According to Brad DeLorey, spokesperson for the CRC, the spill was detected May 22 “late in the morning.” The amount of oil spilled was not known by DeLorey or the City of Regina as of Friday evening. “I don’t know the quantity; the situation has been resolved and they are looking at a long-term solution with the City of Regina,” said DeLorey. The preliminary investigation attributes the spill to high winds. As DeLorey explained, high wind gusts caused waves to form on outdoor ponds located at the CRC where oil is stored. The waves then kicked up sediment sitting on the bottom of the ponds, dislodging the sludge, which then caused a discharge after entering a pump. “Some of that got into the discharge to the city wastewater system,” said DeLorey, quoting an engineer that was familiar with the spill. Normally wastewater from those ponds would discharged to the city for treatment. DeLorey said that since there was no threat posed by the spill, the city and the refinery did not alert the public. An investigation into the cause of the spill and the amount of oil that was spilled is currently underway. When asked if wind has ever caused a similar spill, DeLorey said that he was not aware, saying that it could have been because of the “constant 70 km/h wind.” Wind speeds on May 22 recorded by Environment Canada registered a top speed of 48 km/h. In the days prior to the spill being detected, wind speeds reached 64 km/h on May 20 and 67 km/h on May 21. In an emailed response, a spokesperson for the city said it had been made aware of the spill and quickly contained it. “As a precaution, downstream users are being notified, but no action is required at this time,” said the spokesperson. According to the spokesperson, the city is still conducting tests on the impact of the spill, anticipating test results early this coming week. “The Water Security Agency and the Ministry of Environment indicated that there was low risk to the environment,” said a city spokesperson. The Ministry of Environment will not be investigating the spill at this time according to Wayne Wark, executive director of communications with the ministry. That’s due to an effluent agreement between the city and the refinery. “The discharge was confined to a contained system,” Wark said in an email. He added that the discharge did not affect the natural environment. “It was the City that first identified the incident/impact to its Wastewater Treatment Facility,” said Wark.
Oil spill at Regina Co-op refinery believed to be low risk - An investigation into the May 22 oil spill at the Co-op refinery in Regina is being deemed low risk downstream according to the Water Security Agency (WSA). A statement from Federated Co-op Limited (FCL) on May 30 said an unknown amount of oil spilled into city sewers, eventually showing irregularities when being analyzed by wastewater treatment plant operators. FCL further stated there was no threat to the natural environment. Unifor 594, the union that represents locked out refinery employees during the nearly six-month labour dispute with FCL, is concerned that the City of Regina did not send out a notification about the incident until it was first reported by the media a week later. Patrick Boyle, a spokesperson with the WSA, said it’s being called a spill, but it’s a little different compared to usual oil spills into the environment. When the issue was discovered at the wastewater treatment plant, workers were able to divert what was happening into one of their lagoons. “There’s a treatment system that happens and it is effectively contained within that,” explained Boyle. “What we have asked the city to do is to increase monitoring testing downstream to make sure there are no impacts.” Boyle added that they’ve notified downstream landowners about the issue.“There’s not that many users downstream, but it’s important to get that notification there so they have the same information everyone else has.”Early stages of the investigation show strong winds resulted in a discharge of sludge into the sewage system. The WSA will be working to provide a full assessment of what happened at the refinery that day. Boyle said there are still questions left unanswered at this time.
Fuel oil contaminates Langley salmon-bearing stream - An apparent fuel oil spill that contaminated Fraser Creek near the Langley airport on Saturday afternoon, May 30, may be connected to an upstream leak in Murrayville near Langley Memorial Hospital the day before, said Langley Fire Department deputy chief Bruce Ferguson.“We had a leak [there near LMH] on Friday,” Ferguson told the Langley Advance Times.Ferguson said the exact source of the contamination could not be determined when fire crews and cleanup specialists were called to the area. A company under contract with the Township is handling the cleanup, Ferguson said.Stanley Brown, who lives in the area, reported the contamination Saturday afternoon.Brown said he noticed “a very strong” odor while he was out for a walk around 2 p.m. Saturday in the Derek Doubleday Arboretum at the southwest corner of Langley Airport, near the new hangers.“I smelt it and then I looked and I saw the oil,” Brown related.“The creek was 20 to 25 per cent covered and you could see it roiling up in the current.”When he crossed the Nicomekl River at Fraser Hwy., Brown again encountered a strong smell of fuel and saw “lots of oil visible in the river.”“I could smell it from 50 feet away,” Brown recalled.He said the amount of oil appeared to be spreading Sunday, despite the deployment of containment booms.A Township of Langley Watercourse Classification map ranks Fraser Creek and the Nicomekl River as Class “A” salmon bearing streams, meaning they are inhabited year round or have the potential for a “year round fish presence upon reasonable means of access enhancements.” There have been warnings about the impact of urbanization, pollution, and spills on the salmon population, with the Langley-based Nicomekl Enhancement Society warning salmon populations in the Pacific Coast are under threat, with their numbers dwindling.
Putin orders state of emergency after huge fuel spill inside Arctic Circle - President lambasts power plant owner ‘for not reporting earlier’ incident bigger than Kerch spill. About 20,000 tonnes of diesel fuel has spilled into the Ambarnaya River outside Norilsk. Vladimir Putin has ordered a state of emergency after 20,000 tonnes of diesel fuel spilled into a river inside the Arctic Circle. The spill occurred when a fuel reservoir at a power plant near the city of Norilsk collapsed on Friday. The plant is operated by a division of Nornickel, whose factories in the area have made the city one of the most heavily polluted places on Earth. During a video conference on Wednesday that was broadcasted on television, Putin lambasted the head of the Nornickel subsidiary that owns the power plant, NTEK, after officials said the company failed to report the incident. “Why did government agencies only find out about this two days after the fact? Are we going to learn about emergency situations from social media? Are you quite healthy over there?” the Russian president told Sergei Lipin, the head of NTEK. Nornickel said NTEK had reported what happened in a “timely and proper” way. The governor of the Krasnoyarsk region, where Norilsk is located, told Putin he only learned of the real situation on Sunday after “alarming information appeared in social media”. Putin said he agreed that a national state of emergency was needed in order to call in more resources for the cleanup effort. Russia’s investigative committee, which deals with major crimes, announced it had launched three criminal investigations into the accident and detained a power plant employee. Alexei Knizhnikov of the World Wildlife Fund said the environmental group was the one who alerted cleanup specialists after confirming the accident through its sources. “These are huge volumes,” he said. “It was difficult for them to cover it up.” The volume of the spill is vastly larger than the 2007 Kerch spill, which involved 5,000 tonnes of oil, Knizhnikov said. At the time the spill in the Black Sea strait was the largest of its kind for Russia and required intervention of the military and hundreds of volunteers. Knizhnikov said diesel fuel is lighter than oil, so it was likely to evaporate rather than sink but was also “more toxic to clean up”. The Ambarnaya River that bore the brunt of the spill will be difficult to clean up because it is too shallow to use barges and the remote location has no roads, officials told Putin. Russia’s environment minister, Dmitry Kobylkin, said he thought burning the fuel, which some are suggesting, was too risky. “It’s a very difficult situation. I can’t imagine burning so much fuel in an Arctic territory … such a huge bonfire over such an area will be a big problem.”
Vladimir Putin declares state of emergency in Arctic region over Norilsk fuel spill -- Russian President Vladimir Putin has declared a state of emergency in a region of Siberia after an estimated 21,000 tonnes of diesel fuel spilled from a power plant storage facility, in an accident experts say will take "decades" to clear. The spill took place last week at a power plant in an outlying section of the city of Norilsk, 2,900 kilometres north-east of Moscow. A fuel tank at a power station in the remote, industrial region lost pressure on May 29 and leaked fuel and lubricants into the Ambarnaya River, according to the Investigative Committee, Russia's top criminal investigation body. The Ambarnaya feeds a lake from which springs another river that leads to the environmentally delicate Arctic Ocean. At a televised government meeting to discuss the spill, Mr Putin said he was shocked to find out local authorities had only learned of the incident from social media two days after it happened and scolded the region's governor Alexander Uss on air. "Are we to learn about emergency situations from social networks? Are you alright healthwise over there?" Mr Putin said, waving his hand across his eyes. The state environment watchdog said 15,000 tonnes of oil products had seeped into the river system with another 6,000 into the subsoil. The state fisheries agency says the river will need decades to recover. An expanse of crimson water could be seen stretching from shore to shore down a river and one of its offshoots in aerial footage published by the RIA news agency this week. The environmental impact from the spill could last for "decades", Russia's Greenpeace climate project manager Vasily Yablokov has said. Diesel fuel removed from the river has been placed in temporary reservoirs.(Supplied: Severny Gorod)"We're currently talking about cleaning up the initial pollution from the surface of the water, pumping out the fuel, pumping out the polluted water as far as possible, depending on the reservoirs, cleaning up the polluted ground," he said. "However, there will be enough pollution to poison [the environment] for years to come and it will require recultivation, cleaning, which will take years." Alexei Knizhnikov of the World Wildlife Fund's Russia operation said the damage to fish and other resources could exceed 1 billion rubles ($20.8 million). Over 100 specialists have been dispatched to the area by the emergency services, as well as equipment and experts from Russian state oil corporations.
20,000 Ton Oil Spill in Russian Arctic Has 'Catastrophic Consequences' for Wildlife -- Russian President Vladimir Putin declared an emergency after 20,000 tons of diesel fuel spilled into a river in the Arctic Circle.The accident is the second largest oil spill in terms of volume in modern Russian history, the Word Wildlife Fund (WWF) told AFP, as BBC News reported. The oil spread around 7.5 miles from the fuel site, turning the Ambarnaya river bright red, and contaminated a total of 135 square miles."The incident led to catastrophic consequences and we will be seeing the repercussions for years to come," Sergey Verkhovets, coordinator of Arctic projects for WWF Russia, said in a statement reported by CNN. "We are talking about dead fish, polluted plumage of birds, and poisoned animals."Russia's environmental ministry Rosprirodnadzor is already reporting contaminant levels in the water that are tens of thousands of times higher than the safe limit. "[T]here has never been such an accident in the Arctic zone, " former deputy head of Rosprirodnadzor Oleg Mitvol told BBC News. The spill occurred last Friday when a fuel tank at a power plant near the city of Norilsk in Siberia collapsed. The plant is owned by a subsidiary of Norilsk Nickel, the world's No. 1 producer of nickel and palladium. Its factories are also the reason why Norilsk is one of the most polluted places on Earth, The Guardian reported. The plant initially attempted to clean the spill on their own and did not tell authorities about the incident for two days, Ministry of Emergency Situations head Evgeny Zinichev said, according to CNN. "These are huge volumes," he said. "It was difficult for them to cover it up."The governor of the Krasnoyarsk region, where the spill took place, told Putin he only learned of it Sunday from social media posts. The Russian government has opened three criminal investigations into the incident and detained one plant employee.
Global Gas Market Still Extraordinarily Oversupplied -- The specter of negative prices is hanging over energy markets more than a month after oil’s unforgettable crash below zero. While crude has staged a rapid recovery after a deal by the biggest producers to curb a surplus, the $600 billion global gas market remains extraordinarily oversupplied. Traders and analysts say the worst may be yet to come as demand falls and storage nears capacity, creating the ideal conditions for negative prices in some parts of the world. It shows just how far the global energy industry is from recovering from a pandemic-fueled slide in demand and signals more pain for producers from the shale fields of Texas to Australia’s Curtis Island. Unlike the oil market, there’s been no sign of a coordinated response to address the glut, meaning the fallout could be deeper and longer. “We are in uncharted territory with low demand levels and high storage stocks,” said Guy Smith, head of gas trading at Swedish utility Vattenfall AB. “In the shorter term there is real risk that conditions may be set to allow negative prices in Europe, but only in the very short term.” The fuel, used to generate power and heat and as a feedstock for chemicals and fertilizers, was already slated to have a terrible year after a mild winter exacerbated a glut. But things turned from bad to worse as the pandemic hammered demand, forcing major buyers to reject deliveries. Meanwhile, top sellers haven’t yet throttled back enough output as stockpiles near capacity. Like oil’s brief plunge in April below minus-$40 a barrel, the key factor is the lack of storage to absorb excess supply. Traders and analysts point to Europe as the first market likely to hit that crisis point, which could have ripple effects for buyers and sellers from the U.S. to Asia. While the oil market has a broad, if fragile, alliance of producers to manage production and rescue prices, led by Saudi Arabia and Russia, the gas market lacks a coordinated approach, allowing the current oversupply to drift unchecked.
Oil Tankers Off Chinese Coast Signal Rapid Rebound - Queues of tankers have formed off China’s busiest oil ports as the vessels wait to offload crude for refineries that are quickly ramping up production amid a rapid rebound in fuel demand. Two dozen or more crude-laden tankers are waiting to discharge at terminals on China’s east coast that supply state-owned and independent refiners in the region, according shipbrokers and vessel-tracking data. Asia’s largest economy is leading a recovery in oil consumption, with demand in May almost back to levels seen before the coronavirus triggered stay-at-home orders. Chinese refineries are increasing operations to convert more crude into gasoline and diesel after factories reopened and millions of people returned to work following the easing of restrictions. Government policy dictating that the retail price of fuels won’t be cut in line with sub-$40 a barrel oil has also boosted refining margins in the country. “China’s demand recovery and current low oil prices have prompted refiners, especially the independents, to ramp up crude runs,” said Serena Huang, a Singapore-based analyst at analytics firm Vortexa Ltd. “This crude import momentum could be rolling over to June if refiners’ appetite remain strong.” The fleet of tankers arrived in Chinese waters during the second half of May and the ships have been idling off ports in Shandong and Liaoning provinces, according to data compiled by Bloomberg. Most of the vessels are Suezmaxes and Very-Large Crude Carriers, which are estimated to be collectively carrying about 4 million tons or more of oil from countries including Russia, Colombia, Angola and Brazil. Shandong is home to the Qingdao and Rizhao terminals and China’s independent refiners -- known as teapots -- that have staged a v-shaped recovery. Run rates rose to a record high of about 76% at the end of May, compared with a low of 42% in February, according to industry consultant SCI99. Meanwhile, the queues might get even longer, with the highest number of supertankers since at least the start of 2017 hauling crude to China from almost everywhere across the globe.
Abu Dhabi Mulling Pipeline Stake Sale-- Abu Dhabi’s state-owned energy producer is close to selling a multibillion-dollar stake in its natural gas pipelines to an investor group backed by Global Infrastructure Partners and Brookfield Asset Management Inc., in what is set to be one of the year’s biggest infrastructure deals. The buyers could sign an agreement with Abu Dhabi National Oil Co. for a 49% stake in the pipelines this month, according to people with knowledge of the matter, who asked not to be identified as discussions are private. A deal could value the pipelines at more than $15 billion, including debt, they said said. Equity financing has been arranged and the bidders are negotiating the terms of a debt package with banks, the people said. While discussions are advanced and ongoing, the timing and valuation could still change, according to the people. The GIP consortium also includes Italian infrastructure operator Snam SpA, Ontario Teachers’ Pension Plan, Singapore sovereign fund GIC Pte and South Korea’s NH Investment & Securities Co. Representatives for Adnoc, GIP, Brookfield, Ontario Teachers’, Snam and NH Investment declined to comment. Representatives for GIC did not immediately respond to requests for comment. Infrastructure investors have been defying the dealmaking downturn brought on by the coronavirus pandemic to deploy capital. The Adnoc deal could surpass KKR & Co.’s agreement in March to buy the waste-management arm of U.K. utility owner Pennon Group Plc for 4.2 billion pounds ($5.2 billion). It could also top plans by Portugal’s biggest oil company, Galp Energia SGPS SA, to sell its gas distribution assets for as much as 1.5 billion euros ($1.7 billion). Abu Dhabi has been opening up the operations of its state-owned oil producer to foreign partners as part of a push to diversify its economy and generate additional sources of funding. Adnoc has already sold shares in its distribution unit and brought in international investors to its refining and oil field services business. KKR and BlackRock Inc. agreed last year to invest $4 billion in Adnoc’s oil pipeline network. GIC bought a stake in the business later.
OPEC+ to Discuss Production Cut Extension-- OPEC+ is set to discuss a short extension of its current output cuts, according to a delegate, as the cartel considers bringing forward its next meeting a few days to June 4. The cartel and its allies are considering extending the current cuts for one to three months, the delegate said. As the situation in the oil market is moving fast, the preference is to take short-term measures and not disrupt the rebalancing of the market, the delegate said. The existing deal -- struck in April as energy demand and prices collapsed because of the coronavirus pandemic -- calls for output curbs to ease from July. But that’s up for discussion at the next meeting. Russia wants to start easing from July, people familiar with the situation said last week. Oil prices have rallied as the output curbs coincided with a stronger-than-expected rebound in demand. But with lockdowns easing across the globe, fears that the pandemic could have a second wave make predictions of a recovery perilous. At about $35 a barrel, prices are below what most producers need for government spending. West Texas Intermediate crude and Brent, the global benchmark, edged lower in Asian trading on Monday as the protests in the U.S. damped risk sentiment. The date of the meeting, which will be held by video conference, was still to be confirmed late on Sunday, after people familiar with the situation said OPEC members were close to an agreement to bring it forward to June 4. An earlier date would give the oil cartel more flexibility to change its current production limits. OPEC members usually decide their plans for shipping oil to customers for July in the first week of June, so an earlier meeting would give them more time to react. Algerian Energy Minister Mohamed Arkab, who holds the rotating presidency, proposed June 4, instead of June 9-10. The 23-nation OPEC+ coalition led by Saudi Arabia and Russia is undertaking record oil-production cuts to prop up prices. At the meeting it will decide whether to keep the existing agreement, or extend the current curbs. The Organization of Petroleum Exporting Countries and its partners committed to lowering output by 9.7 million barrels a day, or about 10% of global supply, in May and June. In addition, Saudi Arabia, Kuwait and the United Arab Emirates made further voluntary cuts of about 1.2 million barrels a day for June, bringing the total OPEC+ curbs to almost 11 million barrels a day. Production cuts are meant to be eased to about 7.7 million barrels a day in July.Nigeria and the state oil company of Abu Dhabi, the UAE’s capital, have already announced plans to increase exports in July in line with the OPEC+ deal from April.
Oil Demand Expected to Fall 11.5 Percent - Global oil demand will decrease by 11.5 percent, or 11.4 million barrels per day (MMbpd), year on year in 2020, according to Rystad Energy’s latest demand forecast. Total oil demand is projected to fall to 88.1MMbpd this year from approximately 99.5MMbpd last year, Rystad outlined. May demand is expected to fall by 20.5 percent to 78.5MMbpd and June demand is forecasted to hit 84MMbpd. Rystad believes total global demand for road fuels will fall by 9.9 percent, or 4.7 MMbpd, year on year to 42.7MMbpd. Jet fuel demand is anticipated to decline by almost 40.8 percent, or 2.9MMbpd, year on year to 4.3MMbpd. Rystad forecasts that in 2020, total oil demand in the United States will fall 11.8 percent, or 2.4MMbpd, to 18.1MMbpd and that total oil demand in Europe will drop by 15.6 percent, or 2.2MMbpd, to 12MMbpd. Looking ahead to 2021, Rystad expects total oil demand to rebound to 96.3MMbpd. Road fuel demand is expected to average 46MMbpd and jet fuel demand is expected to average 6.2MMbpd next year. Rystad anticipates total oil demand in the U.S. to average 19.4MMbpd and total oil demand in Europe to average 13.2MMbpd in 2021. Rystad’s newest demand forecast is the latest in a line of weekly predictions that aim to calculate the effect of Covid-19 on oil demand. These are frequently updated as a result of evolving developments around the world. Rystad’s previous demand forecast saw oil demand falling by 10.8 percent, or 10.7MMbpd, in 2020. Road fuel demand was anticipated to fall by 10.8 percent, or 5.1MMbpd, year on year and jet fuel demand was projected to drop by almost 33.6 percent, or 2.4Mmbpd, year on year. There have been 5.9 million confirmed cases of Covid-19 around the world, with 367,166 deaths, as of May 31, according to the latest figures from the World Health Organization.
The Brent crude oil matrix, the linkages that make it work and implications for global markets. Do not try and refine the Brent; that's impossible. Instead, only try to realize the truth...there is no Brent. Then you will see it is not the Brent that gets refined; it is only yourself. For those who are not fans of The Matrix, that sentence may seem a little cryptic, but it makes a point that is little understood outside the rarified world of crude oil trading. The production of North Sea Brent crude oil is down to less than a couple of hundred barrels per day. Soon it will be gone altogether. But 70% of all crude oil in the world is tied either directly or indirectly to the price of Brent. How is that possible? Well, it’s because Brent is no longer simply a grade of crude oil. Over the past two decades, it has evolved into an intricate, multi-layered matrix of trading instruments, pricing benchmarks and standard contracts that is a world unto itself. A world with a huge impact across almost everything in today’s energy markets. Unfortunately, no one can be told what Brent is. You have to see it for yourself. So that’s where we’ll go in this blog series. Warning: To read on is like taking the red pill. When the prompt futures price of West Texas Intermediate (WTI) crude oil plunged to $37.63/bbl below zero on April 20 (see One Way Out), the corresponding price for North Sea crudes, known collectively as Brent, remained positive, and never fell lower than a positive $19/bbl during the late-April meltdown. This relative stability has been touted by some as a justification for crude markets to rely even more on the Brent benchmark, or alternatively for CME WTI at Cushing to morph to a more Brent-like settlement system (more on that distinction later). But simple comparisons between the two benchmarks can be misleading. Brent and WTI are structurally quite different and serve very different markets. Furthermore, Brent has many challenges of its own, not the least of which has been the steady decline of North Sea crude oil production over the past 30 years. As we said above, to understand Brent, you have to see it for yourself. And that means that to understand where Brent is going, we need to review where Brent has been. It has been a long and winding road from the early 1970s until today.
Oil prices slip as wary traders eye upcoming OPEC+ meeting - Oil prices fell nearly 1% on Monday as traders hedged bets with the Organization of the Petroleum Exporting Countries (OPEC) considering meeting as soon as this week to discuss whether to extend record production cuts beyond end-June. Brent crude fell 34 cents to $37.50 a barrel, in the first day of trading in the contract with August as the front month. West Texas Intermediate (WTI) crude futures for July delivery were at $35.17 a barrel, down 32 cents, by 0123 GMT. The price falls come after front-month Brent and WTI prices posted their strongest monthly gains in years in May. Gains were boosted by OPEC crude production dropping to its lowest in two decades with demand is expected to recover as more nations emerge from coronavirus lockdowns. "The focus is very much on OPEC+," OCBC economist Howie Lee said, referring to the grouping of OPEC and its allies including Russia. OPEC+ agreed in April to reduce output by an unprecedented 9.7 million barrels per day (bpd) in May and June after the coronavirus pandemic ravaged demand. "We might see a cautious pullback in (crude) prices given that downstream prices haven't caught up ... but if OPEC+ does come up with a three-month extension, there's a possibility that prices may hit the $40 level," Lee said. Still, tensions between the United States and China weighed on global financial markets while traders are also keeping an eye on riots over the weekend that have engulfed major U.S. cities. Saudi Arabia is proposing to extend record cuts from May and June until the end of the year, but has yet to win support from Russia, sources have told Reuters. Algeria, which currently holds the OPEC presidency, has proposed an OPEC+ meeting planned for June 9-10 be brought forward to facilitate oil sales for countries such as Saudi Arabia, Iraq and Kuwait. Russia has no objection to the meeting being brought forward to June 4. Meanwhile supply in North America is also falling as data from Baker Hughes showed that the U.S. and Canada oil and gas rigs count dropped to a record low in the week to May 29.
Oil Rally Fizzles-- The historic oil-supply curbs by OPEC, Russia and other nations that helped spur May’s record price rally are hanging in the balance as the cartel and its allies dicker over when to hold their next meeting. Oil futures settled slightly lower in New York on Monday amid mixed signals from the Organization of Petroleum Exporting Countries and its confederates about the timing of their next discussions. One idea floated is to bring the meeting forward by several days to Thursday to consider prolonging production limits for as long as three months, according to a delegate. Without an extension, the existing caps begin to wind down next month -- a schedule Russia so far prefers to stick to. Meanwhile, onshore oil exploration in the U.S. shrank for the 11th consecutive week to a level not seen since before the shale revolution kicked off more than a decade ago. Despite well shut-ins across North America, U.S. imports of Saudi crude have surged, swelling supplies held in storage. American stockpiles are “probably heading higher at least in the short term as more imports come in,” said Peter McNally, an analyst at Third Bridge Group Ltd. “The market is oversupplied to begin with. Everyone is looking for more signs of demand firming.” West Texas Intermediate for July delivery settled down 5 cents at $35.44 a barrel on the New York Mercantile Exchange. Brent, the international benchmark, rose 48 cents to $38.32. An earlier OPEC+ meeting would give the producer group more flexibility to change its current production limits. The group’s preference is to take short-term measures on cuts as the situation is volatile, the delegate said. The coalition -- which includes OPEC’s 13 members plus another 10 exporters -- has achieved 92% compliance, according to data analytics firm Kpler. Iraq and Nigeria have been laggards in meeting their pledged targets. Meanwhile, the U.S. Oil Fund ETF begins its monthly roll of futures contracts on Monday. The fund plans to sell its July holdings and buy more November and January futures over the next 10 trading sessions.
Oil Rallies Towards $40 As OPEC+ Nears Deal - Oil prices rose once again on rising odds of an OPEC+ extension. Brent is now nearing $40 per barrel, a remarkable comeback after crashing below $20 per barrel a little more than a month ago.Saudi Arabia and Russia are close to inking a two-month extension of the current oil production cuts, extending the agreement through September 1. Saudi Arabia wants an extension through the end of the year while Russia has favored easing the cuts in July. A two-month extension would be a middle-ground compromise. In the North Sea, almost a third of the oil left on the UK continental shelf is no longer economical to extract. The rig count in the Gulf of Mexico has also fallen by almost half.. After the U.S. downgraded its status with Hong Kong, following Beijing’s new national security law in the territory, China is now threatening to curtail American farm purchases. . In an effort at infrastructure stimulus, China is reviving a $20 billion petrochemical project in Shandong province. “The 400,000 barrel-per-day (bpd) refinery and 3 million tonne-per-year ethylene plant in Yantai, Shandong, the country’s hub for independent oil refineries, was proposed years ago but approval has been slowing in coming because of China’s struggle with excess refining capacity,” Reuters reported.The sharp oil production cuts have led to a decrease in the cost of shipping. Prices for chartering an oil vessel fell 77 percent from the peak in March. Occidental Petroleum cut its quarterly dividend by 91 percent, and shareholders will only receive one penny per share on July 15. In March, Oxy cut its dividend to 11 cents, from 79 cents previously. The rig count fell to 301 rigs last week, the lowest level on record since 1949.
Oil rises nearly 4% ahead of OPEC+ meeting, easing lockdowns - Oil prices were up about $1 a barrel on Tuesday on expectations that major producers will agree to extend output cuts during a video conference likely to be held this week and as countries and U.S. states begin to restart after coronavirus lockdowns. West Texas Intermediate crude climbed $1.37, or 3.87%, to settle at $36.81 per barrel. Brent crude rose 2.7%, or $1.04, to $39.36 a barrel. The Organization of the Petroleum Exporting Countries and others including Russia, a grouping known as OPEC+, are considering extending their production cuts of 9.7 million barrels per day (bpd), or about 10% of global production, into July or August, at a meeting expected to be held on June 4. "Most likely, OPEC+ could extend current cuts until Sept. 1, with a meeting set before then to decide on next steps," said Citi's head of commodities research Edward Morse. Under the original OPEC+ plan, the cuts were due to run through May and June, scaling back to a reduction of 7.7 million bpd from July to December. Saudi Arabia has been pushing to keep the deeper cuts in place for longer, sources said. The gradual reopening of businesses in a growing number of U.S. states and countries around the world after shelter-in-place mandates caused by the coronavirus pandemic also oil boosted prices. "As the economy opens up, there's more and more people on the road. That's going to be good, obviously, for crude oil," said Bob Yawger, director of energy futures at Mizuho in New York. Steadily increasing gasoline demand in the United States and falling crude inventories at the nation's oil storage hub in Cushing, Oklahoma, has also supported prices, Yawger said. Industry group American Petroleum Institute will release its weekly oil inventory report later in the day, with official data following on Wednesday.
Oil falls below $40 on doubts early OPEC+ meeting will go ahead this week - Oil prices erased gains on Wednesday, with Brent crude futures falling back below $40 a barrel, on doubts an early meeting of some of the world's most powerful oil producers will go ahead as planned. OPEC and non-OPEC allies, a group of oil producers sometimes referred to as OPEC+, had been expected to hold their next meeting on Thursday. However, while OPEC kingpin Saudi Arabia and non-OPEC leader Russia were thought to have tentatively agreed on a one-month extension to production cuts, S&P Global Platts reported on Wednesday, citing unnamed sources, the date of a meeting to finalize the deal remains uncertain. OPEC member Algeria, which currently holds the rotating presidency of the group, proposed late last month that the meeting should be brought forward from the original date of June 9-10. Brent crude futures traded at $38.91 a barrel during Wednesday afternoon deals, down over 1.5%. Earlier in the session, the international benchmark had climbed above the $40-a-barrel mark for the first time since March 6. Meanwhile, U.S. West Texas Intermediate (WTI) crude futures stood at $36.26, almost 1.6% lower. The contract had also climbed to its highest level since early March earlier in the trading day, but it has since erased those gains. Oil prices have soared in recent weeks, rebounding from the lows of April amid optimism about an economic recovery in China and as other economies seek to gradually relax lockdown measures. In April, OPEC+ agreed to cut oil production by a record 9.7 million barrels per day (b/d), approximately 10% of global output. The move was designed to prop up prices as the coronavirus pandemic led to an unprecedented collapse in oil demand. The production cuts began on May 1 and are set to run through to the end of June. Under the current deal, the cuts will then be tapered back to 7.7 million b/d from July through to the end of 2020, and 5.8 million b/d from January 2021 through to April 2022.
Oil prices finish at highest in 3 months as traders await next move for OPEC+, digest U.S. supply data - Oil futures Wednesday closed higher, extending a move around the highest level since early March, as uncertainty over whether a meeting of crude producers will be held this week or next raised doubts about a willingness to substantially extend global production cuts that taper after June. Weekly declines in U.S. crude stockpiles and supplies at the Cushing, Okla. storage hub reported by the Energy Information Administration on Wednesday offered little support to oil prices, as petroleum product inventories climbed.West Texas Intermediate crude for July delivery tacked on 48 cents, or 1.3%, to settle at $37.29 a barrel on the New York Mercantile Exchange after surging 3.9% on Tuesday. Global benchmark Brent saw its August contract rise 22 cents, or 0.6%, to end at $39.79 a barrel on the ICE Futures Europe, after gaining 3.3% in the prior session.Prices for WTI and Brent crude marked their highest since March 6, according to Dow Jones Market Data. Amena Bakr, deputy bureau chief at Energy Intelligence, reported that a June 4 meeting of the Organization of the Petroleum Exporting Countries and its allies appeared “unlikely,” via Twitter on Wednesday. She said in a separate tweets that setting the date of next meeting is “contingent on all members of the group sticking to their quotas.” Member states that haven’t achieved their quotas in May will be asked to make up for that in the coming months, Bakr wrote, citing OPEC sources.Reuters reported Wednesday that Saudi Arabia and Russia have reached a preliminary agreement to extend existing cuts by one month. The reductions had been set to taper down to 7.7 million barrels starting in July.Bloomberg News, meanwhile, also reported that Russia and several other producers favor extending the group’s current cuts by one month, citing people familiar with the matter. The report said major producers are cognizant that rising prices of crude benefit U.S. shale production, which is likely to come back on line as futures react to efforts by OPEC+ to stabilize the commodity’s value.U.S. crude inventories, meanwhile, fell in the latest week.The Energy Information Administration reported Wednesday that U.S. crude inventories edged down by 2.1 million barrels for the week ended May 29. That compared with a forecast by analysts polled by S&P Global Platts for an average climb of 3.5 million barrels. The American Petroleum Institute on Tuesday reported a fall of 483,000 barrels, according to sources.A drop in imports led to the fall in crude inventories, as well as an increase in refinery runs and a 4 million-barrel shift of oil from commercial inventories into the Strategic Petroleum Reserve, said Matt Smith, director of commodity research at ClipperData. “Without this transfer, oil inventories would have reached a record high,” he told MarketWatch.
Oil Traders Ask Why U.S. Inventory Math Isn’t Adding Up - Oil traders and analysts scrutinizing U.S. inventory data for signs of a market recovery are being confronted by an odd situation: the math just doesn’t add up. Various government data sets including stockpiles, production, imports and exports are signaling that current official figures on at least some supplies are excessive. While it’s unclear where exactly the discrepancy lies, the difference could potentially signal a more bullish outlook for crude prices as they claw their way back after diving below zero in April. The excess is showing up in the U.S. Energy Information Administration’s so-called crude supply adjustment factor -- the difference between stockpile numbers and those implied by production, refinery demand, imports and exports. That has averaged negative 980,000 barrels daily over the past four weeks -- the largest in records going back to 2001, and equivalent to more than 27 million barrels. The adjustment factor tends to swing back and forth, depending on irregularities in various surveys the EIA pulls from for its reports. For these weekly reports, the EIA is not able to collect domestic crude oil production, instead estimating it from its short-term energy outlook model. Some investors lay the blame for the current discrepancy on U.S. oil production numbers. While daily output fell 700,000 barrels to 11.2 million in May, they believe oil’s plunge into negative territory in April should have led to a steeper decline. “This is a high frequency data series, and so there’s often some smoothening that results from it,” said John Kilduff, a partner at Again Capital, who added the discrepancy may have to do with production figures. “When the numbers are off, you just have to make sure you’re checking everything else independently, like other ways to track import and exports numbers.” Just last month, consultancy IHS Markit said that U.S. oil producers are in the process of curtailing 1.75 million barrels a day of existing output by early June due to operating cash losses, lack of demand and storage capacity and an unwillingness to sell resources at low prices. Some of that lower production is already becoming evident, according to information disclosed in various company announcements and state data.
Saudi Arabia and Russia push for an extension to output cuts, OPEC+ meeting this week still possible - Some of the world's most powerful oil producers had been expected to convene on Thursday, with energy market participants closely monitoring whether the influential group will officially agree to extend their deepest ever round of output cuts. OPEC kingpin Saudi Arabia and non-OPEC leader Russia were thought to support a one-month extension of the current level of supply cuts, Reuters reported on Wednesday, citing unnamed OPEC sources. However, the date of a virtual meeting to finalize an agreement was still unclear on Thursday afternoon. OPEC and non-OPEC allies, sometimes referred to as OPEC+, were originally scheduled to review their production cuts on June 9-10. Late last month, Algeria, which currently holds the rotating OPEC presidency, proposed this meeting should be brought forward to Thursday. An OPEC+ meeting was still possible this week, according to Reuters, citing unnamed OPEC sources, if Iraq and other non-complying members promised to deepen their production cuts. Brent crude futures traded at $39.50 a barrel during early afternoon deals, down more than 0.6%. The international benchmark rose above $40 a barrel for the first time since March 6 in the previous session, before erasing those gains amid OPEC+ uncertainty. U.S. West Texas Intermediate (WTI) crude futures stood at $36.78 a barrel, almost 1.4% lower. The contract also climbed to its highest level since early March on Wednesday. Oil prices have marched higher in recent weeks, recovering from a dramatic fall in April which saw Brent futures hover close to 20-year lows and WTI tumble into negative territory for the first time in history. It comes amid optimism about an economic recovery in China, the world's second-largest economy, and as other countries across the globe seek to gradually lift coronavirus lockdown measures.
Oil rises slightly as traders await clarity on output cuts - Oil prices were little changed on Thursday as investors awaited a decision from top crude producers on whether to extend record output cuts. The Organization of the Petroleum Exporting Countries (OPEC) and allies led by Russia, a group known as OPEC+, are debating when to hold ministerial talks to discuss a possible extension of the existing cuts. Brent crude futures were up 6 cents, or 0.2%, at $39.85 a barrel. West Texas Intermediate crude futures gained 12 cents to settle at $37.41 per barrel. Saudi Arabia and Russia, two of the world's biggest oil producers, want to extend cuts of 9.7 million barrels per day (bpd) that major producers agreed to in April. But a suggestion by OPEC president Algeria to meet on Thursday was delayed amid talks about poor compliance by some producers. Saudi Arabia, Kuwait and the United Arab Emirates are not planning to extend voluntary additional output cuts of 1.18 million bpd after June, indicating that crude supply could rise next month regardless of any OPEC+ decision. "OPEC appears 'damned if they do and damned if they don't' with regard to extended near term production reductions," . "Any decision to forgo any extension of current cuts would easily unleash a near term selling spree while an agreement to extend cuts beyond next month would have longer term bearish implications as upward adjustments to third quarter shale production forecasts would likely be required." Concerns about a resurgence of U.S. shale production, which is already showing signs of revival, was one reason Moscow and Russia only backed prolonging cuts into July rather than agreeing a longer extension, sources briefed on OPEC+ talks have said. Meanwhile, U.S. government data on Wednesday showed large increases in fuel inventories as demand remains impaired due to the coronavirus pandemic. "Large oil inventory builds across the U.S., Europe and Japan last week are weighing on oil prices," Striking a bullish note, however, Russia's Energy Minister said the oil market in July could face a shortage of 3-5 million bpd, Interfax news agency reported.
Oil Prices Surge As OPEC+ Nears Deal - Oil prices jumped yet again on positive news from OPEC+ as well as a far better than expected jobs report. Brent surged by more than $2 per barrel while WTI approached the $40 mark. OPEC+ made a breakthrough in negotiations and the group is slated to meet on Saturday to sign off on the deal, which calls for a one-month extension of the 9.7 mb/d cuts. A sticking point had been the poor compliance rate from Iraq, but the Iraqi government agreed to strict compliance, although there could be a domestic backlash from doing so. The U.S. unemployment rateunexpectedly fell to 13.3 percent in May, with the return of 2.5 million jobs. Economists had expected the unemployment rate to jump to around 20 percent. The numbers led to a wave of optimism around economic recovery. The Libyan National Army (LNA) retreated from Tripoli, ending a 14-month assault on the capital. The civil war has also become a proxy battle between other world powers. The prime minister of the Government of National Accord (GNA) traveled to Ankara to meet with Turkish President Recep Tayyip Erdogan. In a sign of the times, investment bank Tudor, Pickering, Holt & Co., which was an important player in financing the U.S. shale industry, will begin research on clean technologies. The firm will cut back on the number of oil and gas companies it covers, and use an existing equity research team to cover clean tech. GM is developing an electric van for commercial use, a multibillion-dollar segment of the transportation sector, according to Reuters. “It’s going to be similar to what the Model 3 has done for the consumer market,” a UPS executive told Reuters. “Now all of a sudden, we’re off to the races.” The GM van is due to start production in late 2021. Vattenfall AB is going forward with a 1,500-megawatt offshore wind project in the North Sea, and the project carries no government subsidies. When it comes online in 2023, it will be the world’s largest, but won’t carry that title for long as a larger project in the UK is scheduled to come online shortly after. While many of the integrated oil majors have promised larger investments in renewable energy, Norway’s Equinor stands out. The majors are estimated to spend $18 billion combined per year by 2025 on renewables, but Equinor will account for $10 billion of that total, according to Rystad Energy. The Norwegian company will be the only one to invest a majority of its greenfield capex in clean energy.
Crude oil prices climb 5% on US jobless drop, Opec+ meeting hopes - Oil prices rose on Friday after an unexpected fall in the May US jobless rate and Opec's decision to bring forward to Saturday discussions on whether to extend record production cuts. Brent crude futures were up $2.07, or 5.2 per cent, at $42.07 a barrel by 11:05 a.m. EST (1505 GMT). US West Texas Intermediate (WTI) crude futures rose $1.65, or 4.4 per cent, to $39.02 a barrel. The US Labor Department reported a surprise fall in the jobless rate to 13.3 per cent last month from 14.7 per cent in April. Brent has risen 17 per cent since Friday to reach a three-month high, in a range more comfortable for producers like Russia. The contract has more than doubled since crashing as low as $15.98 a barrel on April 22. WTI is up 11 per cent. Both benchmarks were headed for a sixth week of gains, lifted by the output cuts and signs of improving fuel demand as countries ease lockdowns imposed to fight the new coronavirus outbreak.
Oil jumps 5% as traders await OPEC+ meeting on extending supply cuts -- Oil prices rose on Friday after OPEC decided to move up discussions on whether to extend record production cuts to Saturday, indicating that some laggard countries may have agreed to align themselves with the deal. Brent crude futures were up $2.46, or 6.2%, to trade at $43.45 per barrel, while West Texas Intermediate traded $2.06, or 5.5%, higher at $39.48 per barrel. Brent has risen 16% since Friday to reach a three-month high, settling in a range more comfortable for producers like Russia. The contract has more than doubled since it crashed to as little as $15.98 a barrel on April 22. WTI is up nearly 14% from Friday's close, leaving benchmarks on track for a sixth week of gains, lifted by the output cuts and signs of improving fuel demand as countries ease lockdown measures imposed to prevent the spread of the new coronavirus. Russia's energy ministry said on Friday a video conference of a group of leading oil producers, known as OPEC+, would be held on Saturday. OPEC and its allies had said they would bring forward the meeting, which had been scheduled for next week, should Iraq and others agree to boost their adherence to existing supply cuts. "Prices are up with the meeting scheduled for tomorrow. There was lots of confusion... so it looks like they found a way forward," Olivier Jakob at Petromatrix consultancy said. Saudi Arabia and Russia, two of the world's biggest oil producers, want to extend output cuts of 9.7 million barrels per day (bpd) into July. If OPEC+ fails to agree to roll over the current output curbs, that would mean the cut could drop back to 7.7 million bpd from July through December as previously agreed. "The growing fear is that not only will a deal to extend the deep cuts not be reached, but (some) producers may even relax their current over-compliance. This would ultimately see output rise in coming weeks," ANZ Research said in a note. Adding support was the first tropical storm of the season in the U.S. Gulf of Mexico. Storm Cristobal is expected to enter the central Gulf this week, an area rich with offshore platforms, and could see landfall along Louisiana's refinery row on Sunday. U.S. energy companies have already closed some production. "It's not big, but there will be some shut-ins," Jakob said.
Oil prices log over 11% weekly rise, with OPEC+ set to meet Saturday to discuss extension of output cuts - Crude-oil futures ended sharply higher Friday, supported by news that major oil producers will convene Saturday to discuss plans for extended productions cuts, while an unexpected monthly climb in U.S. jobs suggested a recovery in energy demand mat be at hand. The Organization of the Petroleum Exporting Countries and its allies, collectively known as OPEC+, said they would hold meetings via videoconference on Saturday, with the OPEC member conference set to begin at 2 p.m. Central European time, or 8 a.m. Eastern time, and an OPEC+ conference to begin two hours later. The major oil producers are expected to reach an official agreement to extend record oil production cuts of 9.7 million barrels a day through July, according to The Wall Street Journal. The group decided to move forward a meeting that had been planned for June 9-10, after a tentative plan to meet on June 4 fell apart. The weekend meeting is being viewed as a signal to crude investors that the group will deliver substantive near-term measures to stabilize oil’s value. “It’s all about the OPEC+ meeting,” wrote Bjornar Tonhaugen, Rystad Energy’s head of oil markets, in a Friday note. “As it was initially intended to happen on Thursday, when that did not materialize, prices fell because traders sensed a lack of agreement between the extended group’s producing countries.” “Now the mood has changed again and prices rose, following news that a consensus may have been reached and a meeting is across the corner,” he wrote. Meanwhile, U.S. data released Friday showing that the nation regained 2.5 million jobs in May and the unemployment rate fell to 13.3% from 14.7% in April, with that data leading to a rally in the stock market. “The oil price rally went into overdrive after a surprisingly robust U.S. labor market report,” “The economic recovery is already happening and that could do wonders for crude consumption.” West Texas Intermediate crude for July delivery rose $2.14, or 5.7%, to settle at $39.55 a barrel a barrel on the New York Mercantile Exchange. Global benchmark Brent saw its August contract BRNQ20, -0.54% climb $2.31, or 5.8%, to end at $42.30 a barrel on the ICE Futures Europe. For the week, WTI front-month U.S. oil futures were up 11.4%, while Brent climbed 11.8%m according to Dow Jones Market Data. Both benchmarks tallied their sixth consecutive weekly gain and marked a fourth session at their highest settlement since March 6.
Saudi, Russia agree oil cuts extension, raise pressure for compliance - (Reuters) - OPEC leader Saudi Arabia and non-OPEC Russia have agreed a preliminary deal to extend existing record oil output cuts by one month while raising pressure on countries with poor compliance to deepen their cuts, OPEC+ sources told Reuters. However, there was no agreement yet on whether to hold an OPEC+ output policy meeting on Thursday with the main obstacle being how to deal with countries that have failed to make the deep supply cuts required under the existing pact, the sources said. OPEC+ agreed to cut output by a record 9.7 million barrels per day, or about 10% of global output, in May and June to lift prices battered by plunging demand linked to lockdown measures aimed at stopping the spread of the coronavirus. Rather than easing output cuts in July, OPEC and its allies, a group known as OPEC+, were discussing keeping those cuts beyond June. “Saudi Arabia and Russia are aligned on the extension for one month,” one OPEC source said. “Any agreement on extending the cuts is conditional on countries who have not fully complied in May deepening their cuts in upcoming months to offset their overproduction,” the source said.
OPEC+ Extends Oil Cuts in Win for Saudi-Russian Alliance - OPEC+ agreed to a one-month extension of its record output cuts and adopted a stricter approach to ensuring members don’t break their production pledges. The deal will underpin the oil market recovery, easing the financial pain felt by resource-dependent emerging economies, shale explorers in Texas, and blue-chip companies like Royal Dutch Shell Plc. It’s a victory for Saudi Arabia and Russia, who put a destructive price war behind them to successfully cajole Iraq, Nigeria and other laggards to fulfill their promises to cut production. The two leaders of OPEC+ showed that they intend to keep a close watch on the oil market, meeting every month to assess the balance between supply and demand amid an uncertain economic recovery from the global pandemic. “Our collective efforts have borne fruit, and despite many uncertainties, there are encouraging signs that we are over the worst,” said Saudi Energy Minister Prince Abdulaziz bin Salman. “Demand is returning as big oil-consuming economies emerge from pandemic lockdown,” he added. After a video conference lasting several hours on Saturday, delegates said all nations had signed off on a new deal for a production cut of 9.6 million barrels a day next month. That’s 100,000 barrels a day lower than the reduction in June because Mexico will end its supply constraints, but a tighter limit than the 7.7 million barrels a day set for July in the group’s previous agreement. In addition, the communique states that any member that doesn’t implement 100% of its production cuts in May and June will make extra reductions from July to September to compensate for their failings. Those promises are a particular vindication for the Saudi minister, who has consistently pushed fellow members to stop cheating on their quotas since his appointment last year. But they could also add an element of risk. In theory, the entirety of the 23-nation production agreement, which runs until April 2022, is now contingent on every member making 100% of their pledged cuts, according to the communique. That’s something rarely achieved in the 3 1/2 years that OPEC+ has existed, or indeed the decades-long history of the Organization of Petroleum Exporting Countries itself.
OPEC+ keen to keep U.S. shale in check as oil prices rally - (Reuters) - When OPEC, Russia and their allies agreed in April to slash oil production, little did they expect that their initiative to prop up collapsing prices would be helped by a swift drop in U.S. output. Now that crude has rallied on the back of those cuts from below $20 a barrel to $40 or more, the group known as OPEC+ faces a fresh challenge: stopping U.S. shale production delivering another surprise by recovering equally quickly. “The plan is to stick to prices of $40-$50 per barrel because as soon as they rise any further to say $70 per barrel it encourages too much oil production, including U.S. shale,” said a Russian source familiar with OPEC+ talks on the issue. OPEC+ sources told Reuters on Wednesday that Russia and Saudi Arabia had reached a compromise to extend into July the group’s existing output cuts of 9.7 million barrels per day (bpd), the equivalent of 10% of global output. Those deep cuts had been due to be implemented in just May and June, before curbs were to be slowly eased. Concerns about a resurgence of U.S. shale, which is already showing signs of revival, was one reason Moscow and Russia only backed prolonging cuts into July rather than agreeing a longer extension, two sources briefed on OPEC+ talks said.
Trudeau government exploits pandemic to renew $14 billion arms deal with despotic Saudi regime - On April 9, just as Canada was beginning to see a dramatic surge in COVID-19 infections across the country, the Trudeau government lifted its moratorium on the issuing of new export licences for arms shipments to Saudi Arabia. The ban was originally adopted as part of a hypocritical public relations exercise, undertaken by the Trudeau government after the Saudi regime’s grisly murder of journalist Jamal Khashoggi in October 2018 had provoked international anger and revulsion. The Liberals’ “moratorium” was adopted above all to divert attention from revelations that the Saudi army used Canadian-made light armoured vehicles (LAVs) and other military equipment to suppress an uprising in the eastern part of the country in 2014. Canadian military equipment has also played a role in Riyadh’s bloody war on neighboring Yemen, which has led to the deaths of tens of thousands of civilians and left the country in ruins. The Trudeau government launched a year-long “review” of how the Saudis have used LAVs manufactured at a London, Ontario-based General Dynamics’ subsidiary under a $14 billion Canadian government-brokered arms deal. The probe was conducted by Global Affairs, the new name given to Canada’s Foreign Ministry, which plays a central role in advancing Canada’s imperialist interests and ambitions abroad. Predictably, the government review, which will not be made public, concluded that there was “no substantial risk” that the Saudi government, which beheads dozens of people every year and tortures political opponents, would use Canadian-made arms to violate human rights. It even claimed that the exports would “contribute to regional peace and security.” Amnesty International, Project Ploughshares, Oxfam and other groups have condemned the Trudeau government’s decision, which they claim will inevitably cause death and devastation in the entire region. These organizations also criticized the “hypocrisy of the Canadian government” for approving military exports to Saudi Arabia while voicing support, only days later, for a UN call for a global ceasefire during the pandemic.
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