oil prices fell for the first time in 8 weeks this week, as a mutant strain of the coronavirus spreading in the UK prompted a severe lockdown there and new travel restrictions world-wide...after rising more than 5% to $49.10 a barrel last week on a lower dollar and optimism about the vaccine rollouts, the contract price of US light sweet crude for January delivery fell in early trading on Monday as a new, fast-spreading mutant strain of coronavirus in the UK raised concerns that tighter restrictions there and elsewhere would stall the recovery in the need for fuel, and was down nearly $3 or 6% before recovering to close $1.36 lower at $47.74 a barrel despite the rollout of a new vaccine in the US, a congressional deal for a $900 billion coronavirus aid package, and European approval for the use of the COVID-19 vaccine developed by Pfizer, as trading in the January US oil contract expired...now quoting the contract price of US crude for February delivery, which had fallen $1.27 to $47.97 a barrel on Monday, oil prices continued sliding on Tuesday, following new travel bans and lockdowns in Europe and the U.S. to combat the fast-spreading variant of the disease, as February crude settled 95 cents lower at $47.02 a barrel, with losses limited after France's Europe minister said his country would restart freight to the UK by the next day...US oil prices then drifted lower in overseas trading after the American Petroleum Institute reported a surprise gain of 2.7 million barrels in US crude supplies, and then opened lower in New York on Wednesday and were down nearly 2% before the EIA reported withdrawals from U.S. inventories of crude, gasoline and distillate fuels, sparking a turnaround in oil prices which then settled 2.34%, or $1.10, higher at $48.12 per barrel...oil prices again moved higher on Thursday on news that Britain and the European Union had signed a post-Brexit trade deal and finished the shortened pre-holiday session 11 cents higher at $48.24 per barrel, but still finished the week 2.1% lower as traders fretted that a resurgence in the Covid-19 pandemic in the U.S. and Europe would hurt demand for energy, without a sufficient bailout from governments to promote consumer and business activity...
natural gas prices also ended lower this week, as the weather turned milder and inventory withdrawals failed to meet expectations...after rising 4.2% to $2.700 per mmBTU last week as major winter storms moved through the eastern US population centers, the contract price of natural gas for January delivery opened more than 1% higher on Monday as surging LNG exports and forecasts for colder weather in late December outweighed concerns over the new coronavirus strain, but slid from the initial spurt to close just a half cent higher at $2.705 per mmBTU as new UK travel restrictions were imposed by several European countries and Canada...natural gas prices then jumped on Tuesday on forecasts for colder weather and expectations of a large withdrawal of gas from storage and held on to settle 7.5 cents higher at $2.780 per mmBTU....however, natural gas futures plummeted on Wednesday as weather models continued to seesaw, gas production increased, export cargoes were cancelled, and the awaited inventory report fell short of market expectations, and finished 17.2 cents, or over 6% lower, at $2.608 per mmBTU...natural gas prices continued to sink in light Christmas eve trading amid mild temperatures and light heating demand across much of the Lower 48 and settled another 9.0 cents lower at $2.518 per mmBTU, thus closing with a 6.7% loss on the week..
the natural gas storage report from the EIA for the week ending December 18th indicated that the quantity of natural gas held in underground storage in the US decreased by 152 billion cubic feet to 3,574 billion cubic feet by the end of the week, which still left our gas supplies 278 billion cubic feet, or 8.4% higher than the 3,296 billion cubic feet that were in storage on December 18th of last year, and 218 billion cubic feet, or 6.8% above the five-year average of 3,356 billion cubic feet of natural gas that have been in storage as of the 18th of December in recent years....the 152 billion cubic feet that were drawn out of US natural gas storage this week was less than the average forecast from an S&P Global Platts survey of analysts who had expected a 154 billion cubic foot withdrawal, but was higher than the average withdrawal of 127 billion cubic feet of natural gas that have typically been pulled out of natural gas storage during the same week over the past 5 years, and more than the 146 billion cubic feet withdrawal from natural gas storage seen 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 December 18th indicated that because of another big increase in our oil exports, we had to withdraw oil from our stored commercial supplies for the 15th time in the past twenty-two weeks and for the 21st time in the past forty-nine weeks ...our imports of crude oil rose by an average of 140,000 barrels per day to an average of 5,564,000 barrels per day, after falling by an average of 1,055,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 472,000 barrels per day to an average of 3,099,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,465,000 barrels of per day during the week ending December 18th, 322,000 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 was reportedly unchanged at 11,000,000 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 13,465,000 barrels per day during this reporting week...
meanwhile, US oil refineries reported they were processing 14,014,000 barrels of crude per day during the week ending December 18th, 169,000 fewer 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 80,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US....so based on that reported & estimated data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 469,000 barrels per day less than 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 inserted a (+469,000) 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 data for the average daily consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting that there must have been an error or errors of that size in the oil supply & demand figures that we have just transcribed....furthermore, since last week's fudge factor was at -61,000 barrels per day, there was a 530,000 barrel per day balance sheet difference from a week ago, which renders the week over week supply and demand changes we have just transcribed unreliable...(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 5,717,000 barrels per day last week, which was still 12.9% less than the 6,566,000 barrel per day average that we were importing over the same four-week period last year.....the 80,000 barrel per day net withdrawal from our crude inventories was due to a 80,000 barrels per day withdrawal from our commercially available stocks of crude oil, while the oil supplies in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported to be unchanged at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,500,000 barrels per day, while a 13,000 barrels per day increase to 514,000 barrels per day in Alaska's oil production had no impact on the rounded national total...last year's US crude oil production for the week ending December 20th was rounded to 12,900,000 barrels per day, so this reporting week's rounded oil production figure was 14.7% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
meanwhile, US oil refineries were operating at 78.0% of their capacity while using 14,014,000 barrels of crude per day during the week ending December 18th, down from 79.1% of capacity during the prior week, and excluding earlier this year and the 2005, 2008, and 2017 hurricane-related refinery interruptions, one of the lowest refinery utilization rates of the past twenty-eight years....hence, the 14,014,000 barrels per day of oil that were refined this week were still 17.5% fewer barrels than the 16,980,000 barrels of crude that were being processed daily during the week ending December 20th of last year, when US refineries were operating at 93.3% of capacity...
even with the decrease in the amount of oil being refined, gasoline output from our refineries was higher for the 2nd time in six weeks, increasing by 307,000 barrels per day to 8,829,000 barrels per day during the week ending December 18th, after our refineries' gasoline output had increased by 182,000 barrels per day over the prior week...but since our gasoline production is still recovering from a multi-year low in the wake of this Spring's covid lockdown, this week's gasoline output was still 14.0% less than the 10,269,000 barrels of gasoline that were being produced daily over the same week of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) decreased by 14,000 barrels per day to 4,590,000 barrels per day, after our distillates output had decreased by 67,000 barrels per day over the prior week....since it's also just coming off a three year low, our distillates' production was 14.9% less than the 5,394,000 barrels of distillates per day that were being produced during the week ending December 20th, 2019...
even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the first time in six weeks and for 15th time in 25 weeks, falling by 1,125,000 barrels to 237,754,000 barrels during the week ending December 18th, after our gasoline inventories had increased by 1,020,000 barrels over the prior week...our gasoline supplies decreased this week because this week's adjustment to correct for the imbalance created by the blending of fuel ethanol and motor gasoline blending components was at +103,000 barrels per day vs last week's -370,000 barrels per day, and because the amount of gasoline supplied to US markets increased by 47,000 barrels per day to 8,022,000 barrels per day, and because our imports of gasoline fell by 40,000 barrels per day to 571,000 barrels per day while our exports of gasoline fell by 27,000 barrels per day to 757,000 barrels per day....after this week's decrease, our gasoline supplies were 0.6% lower than last December 20th's gasoline inventories of 239,260,000 barrels, but still about 4% above the five year average of our gasoline supplies for this time of the year...
meanwhile, with the modest decrease in our distillates production, our supplies of distillate fuels decreased for the 11th time in 14 weeks, and for the 30th time in the past year, falling by 2,325,000 barrels to 148,934,000 barrels during the week ending December 18th, after our distillates supplies had increased by 167,000 barrels during the prior week....our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 172,000 barrels per day to 4,174,000 barrels per day, and because our exports of distillates rose by 123,000 barrels per day to 1,193,000 barrels per day, and because our imports of distillates fell by 48,000 barrels per day to 444,000 barrels per day....but even after this week's inventory decrease, our distillate supplies at the end of the week were 19.2% above the 124,944,000 barrels of distillates that we had in storage on December 20th, 2019, and about 10% above the five year average of distillates stocks for this time of the year...
finally, with the increase in our oil exports, our commercial supplies of crude oil in storage (not including the commercial oil in the SPR) fell for the 17th time in the past twenty-eight weeks and for the 20th time in the past year, decreasing by 562,000 barrels, from 500,096,000 barrels on December 11th to 499,534,000 barrels on December 18th....but even after that modest decrease, our commercial crude oil inventories rose to 11% above the five-year average of crude oil supplies for this time of year, and rose to 50.8% above the prior 5 year (2010 - 2014) average of our crude oil stocks as of the third weekend of December, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had generally been rising over the past two years, except for this autumn and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of December 18th were 13.2% above the 441,359,000 barrels of oil we had in commercial storage on December 20th of 2019, also 13.2% more than the 441,411,000 barrels of oil that we had in storage on December 21st of 2018, and 14.4% above the 436,491,000 barrels of oil we had in commercial storage on December 15th of 2017...
This Week's Rig Count
note: this week's rig count was released on Wednesday ahead of the Christmas holiday, and hence only covers five days...nonetheless, the US rig count rose for the 14th time in the past fifteen weeks during the period ending December 23rd, but for just the 16th time in the past 41 weeks, and hence it is still down by 56.1% over that thirty-eight week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 2 to 348 rigs this past week, which was still down by 457 rigs from the 805 rigs that were in use as of the December 27th report of 2019, and was also still 56 fewer rigs than the all time low rig count prior to this year, and 1,581 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 increased by 1 rig to 264 oil rigs this week, after rising by 5 oil rigs the prior week, leaving us with 413 fewer oil rigs than were running a year ago, and still less than a sixth 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 increased by 2 to 85 natural gas rigs, which was still down by 42 natural gas rigs from the 125 natural gas rigs that were drilling a year ago, and just 5.3% of the 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 or gas, one rig classified as 'miscellaneous' continue to drill in Lake County, California this week, while a year ago there were three such "miscellaneous" rigs deployed...
The Gulf of Mexico rig count increased by 1 to 17 rigs this week, with 14 of those rigs drilling for oil in Louisiana's offshore waters and three drilling for oil offshore from Texas...that was still 6 fewer Gulf rigs than the 23 rigs drilling in the Gulf a year ago, when 21 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, and one rig was drilling for oil offshore from Texas...since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week's national offshore rig figures are equal to the Gulf rig counts....however, in addition to those rigs offshore, two rigs continue to drill through inland bodies of water this week, one in St Mary parish in southern Louisiana and the other in Chambers County, Texas, just east of Houston, while a year ago there was just one rig drilling on US inland waters..
The count of active horizontal drilling rigs was up by 1 to 309 horizontal rigs this week, which was still 394 fewer horizontal rigs than the 703 horizontal rigs that were in use in the US on December 27th of last year, and less than a quarter of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, the directional rig count was up by 1 to 22 directional rigs this week, but those were also still down by 31 from the 53 directional rigs that were operating during the same week of last year....meanwhile, the vertical rig count was unchanged at 17 vertical rigs this week, and those were still down by 32 from the 49 vertical rigs that were in use on December 27th 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 December 23rd, the second column shows the change in the number of working rigs between last week's count (December 18th) and this week's (December 23rd) count, the third column shows last week's December 18th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running during the count 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 27th of December, 2019...
note that this week saw the first decrease in the Permian basin rig count since September 11th....so, first checking for the details on the Permian in Texas, we find that one rig was added in Texas Oil District 8, which corresponds to the core Permian Delaware, while one rig was pulled out of Texas Oil District 7C, which roughly corresponds to the southern portion of the Permian Midland, which thus means that the net Permian rig count in Texas was unchanged...since the Permian basin rig count was down by 1 rig nationally, that means that the rig that was shut down in New Mexico must have been pulled out of the farthest west reaches of the Permian Delaware, to account for the national Permian decrease...elsewhere in Texas, we have a rig added in Texas Oil District 6, which accounts for one of this week's Haynesville shale rig additions. while the other two Haynesville rigs were added in adjacent northwestern Louisiana....those two Haynesville gas rigs and the oil rig that was added offshore account for Louisiana's 3 rig increase...at the same time, in Oklahoma we had a rig added in the Cana-Woodford while there was a two rig increase in the state, which means that an Oklahoma rig was added in an "other" basin that Baker Hughes does not track...on the other hand, the rig count is down by one in Colorado because there was a rig pulled out of the Denver-Julesburg Niobrara chalk....meanwhile, for rigs targeting natural gas, we have the three rigs that were added in the Haynesville shale, while a natural gas rig was pulled out of West Virginia's Marcellus at the same time..
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'Anti-Protest' Bill Passes Ohio House - People who protest oil and gas pipelines and other infrastructure in Ohio could face stiffer penalties, under a bill passed by the Ohio House late Thursday. The bill creates heavier penalties for trespass and tampering of critical infrastructure like oil, gas, electric, water, telecommunications, and railroads. Tampering with these types of facilities could mean a third degree felony charge, which carries a maximum fine of $10,000 and up to three years in prison, more severe than trespass charges at other locations. This is needed, according to Republican Representative Jamie Callender, who spoke on the House floor Thursday, because of the costly damage that can be done to this type of infrastructure. “Here in Ohio we didn’t have any way to deal with that, other than the normal petty trespass and vandalism,” he said, “which is not enough to cover the damage that is done in these instances.” More than 170 Ohioans previously testified against the measure, many calling it an effort to shut down protests, especially against pipelines and energy development. The bill calls for penalties not just for individuals who trespass, but for groups seen to encourage them. Environmental groups fear that even chanting “stop the pipeline” could be construed as encouraging damage to critical infrastructure, which could lead to fines 10 times those levied against individuals. “SB 33’s purpose is to intimidate individuals, communities, and organizations lawfully exercising their First Amendment and other fundamental rights,” wrote Cheryl Johncox of the Sierra Club in her testimony to an Ohio Senate committee opposing the bill. The Ohio bill has now passed the House and Senate, and would need Governor DeWine’s signature.
Frack waste loading dock permit challenged in court - Martins Ferry Times Leader — A U.S. Army Corps of Engineers permit that would allow a fracking waste loading facility to be constructed on the Ohio River in Martins Ferry is being challenged by an environmental group.The Corps permit was requested March 30 by 4K Industrial “to construct a barge loading and off-loading waterfront facility. The facility will be receiving fluids from the Gas and Oil markets for processing, to reuse the fluids for drilling operations or to be sent to a disposal facility.”People had until April 30 to submit comments or request a public hearing on the permit application. It was approved by the Army Corps in October.The FreshWater Accountability Project, an environmental group concerned about the proposed permit, on Dec. 7 filed a complaint in the U.S. District Court for the Southern District of Ohio against the Army Corps, challenging the permit.“The complaint is seeking declaratory judgment and injunctive relief. No public hearing was held for this permit, violating several federal laws which require public notice and invite public comment. This complaint also highlighted the lack of sufficient environmental review to comply with National Environmental Policy Act requirements,” according to a release from the group.“Rather than allow shipment of yet another potentially deadly product on the river, FreshWater believes the time is now to start cleaning up the river rather than exposing it to the hazardous release of radioactive isotopes and unknown chemicals on such a massive scale that barging would bring,” said Lea Harper, managing director of FreshWater Accountability Project.“We see the agencies continuing to toss the responsibility to each other so that no one agency is accountable for bad decisions, which is what we consider this decision to be between the USACE and the (United States Coast Guard). We believe the (United States Environmental Protection Agency) should be looking into this decision to barge frack waste on such an important drinking water source, especially because of the radioactive and proprietary elements involved, and the fact that it will encourage more toxic frack waste processing plants to proliferate along the river. Policy decisions like this one to allow barging of frack waste have been shown to create more long-term harm than short-term good, so we do not see the public benefit at all.”
For the Ohio River Valley, an Ethane Storage Facility in Texas Is Either a Model or a Cautionary Tale The Trump administration and industry leaders have pointed to a major petrochemical storage complex outside Houston as a model for the upper Ohio River Valley. If only they could find a place like Mont Belvieu, Texas, where geological features allow for large-scale underground storage of the chemicals used to make plastic products, there could be an economic resurgence to follow the collapse of steel and coal. Tens of thousands of jobs would follow.With enough storage of ethane from thousands of existing natural gas fracking wells in the Appalachian region’s Marcellus and Utica shale deposits, the argument goes, several multi-billion-dollar plastic manufacturing plants could be built, lifting economic fortunes across four states: Pennsylvania, West Virginia, Ohio and Kentucky. But if Mont Belvieu—a massive chemical distribution center for what has been a booming Gulf Coast plastics and petrochemical industry—has been a model for those promoting an Appalachian petrochemical renaissance, it also serves as a cautionary tale to those who would rather the Appalachian region reject a boom-or-bust fossil fuel future.An examination of the chemical plants, pipelines and other gas handling equipment that sit atop the massive stores of natural gas liquids at Mont Belvieu reveals a history of fires, explosions, leaks, excess emissions, fines for air and water pollution violations, and an oversized carbon footprint. “We have the evidence that this is harmful, and Mont Belvieu is the prime example of that,” said Dustin White, project coordinator with the Ohio Valley Environmental Coalition, based in West Virginia. “The intention is to have a massive petrochemical buildout, and it’s outlandish they want to build it here, especially in an area that already has major health issues due to existing fossil fuel industries.”A January report meant as a warning to Appalachia, by the Environmental Integrity Project, a Washington-based watchdog group founded by former EPA staff, found that the Mont Belvieu complex was marked by multiple explosions, fires, evacuations and fatalities throughout the 1980s and 1990s, and continues to be a major polluter. The largest Mont Belvieu operator is subject to ongoing federal and state enforcement actions, InsideClimate News found.“Communities in Appalachia are at risk from a plan for an aggressive expansion of the petrochemical and plastics production industry, including construction of a massive new ethane storage hub,” the report concluded. “Area decision makers and residents need to consider the serious hazards that have arisen at a similar development complex in Mont Belvieu, Texas.” Sen. Joe Manchin III (D-West Virginia), among the nation’s leading supporters of the coal industry and also a strong proponent of an Appalachian natural gas buildout, declined to comment on Mont Belvieu’s environmental difficulties but said he remains “committed to the development of the proposed Appalachian Storage Hub, particularly in this moment, for its economic development benefits for rural West Virginia, the greater Appalachian region, and our entire nation.”
Pennsylvania Selects Partner for $2.5M Study on Link Between Cancer and Hydraulic Fracturing -- Pennsylvania Gov. Tom Wolf’s administration has signed a $2.5 million contract with the University of Pittsburgh Graduate School of Public Health to conduct additional research on the potential health effects of hydraulic fracturing (fracking) in the state. The move comes in response to growing concerns in four southwestern Pennsylvania counties where unconventional natural gas development is robust, and high numbers of childhood and young adult cancers have been reported, including more than two dozen cases of the rare bone cancer known as Ewing Sarcoma. Residents from the area have been pushing the state to explore any possible links between the cancer cases and natural gas development. Wolf’s office said late last year that it would select an academic partner to work on two separate studies at a cost for the state of roughly $1 million annually. The administration said this week that the University of Pittsburgh “will be conducting two observational epidemiological studies focusing on known or suspected health effects of hydraulic fracturing.” In one study, the university will investigate the relationship between fracking and the development of childhood cancers in Fayette, Greene, Washington and Westmoreland counties. The other study would aim to replicate earlier research on conditions such as asthma and birth outcomes using data from southwestern Pennsylvania. Researchers hope to finish the studies within the next two years, according to the state Department of Health. The graduate school of public health intends to release quarterly summaries on its work and plans to provide a progress update at the end of the first year. Once the studies are completed, a public meeting would be held to provide information on conclusions, the department said. Oil and gas development, along with other industrial sources, such as a uranium mill tailings site in the region, have been floated as possible causes. The prevalence of cancer, however, makes it difficult to link clusters to any one cause. In a joint statement issued last year by the Marcellus Shale Coalition, Pennsylvania Independent Oil and Gas Association and the American Petroleum Institutes’ Pennsylvania chapter, the industry said it welcomed the studies and was prepared to work closely with the administration.
Equitrans Cuts Guidance as Appalachian Producers Continue to Hunker Down - Equitrans Midstream Corp. has significantly cut its 2021 financial forecast as Appalachian natural gas producers continue to curb spending and output. Equitrans, the third largest natural gas gatherer in the United States with operations in Ohio, Pennsylvania and West Virginia, this month cut its net income guidance for next year to $540-610 million. That’s down from the 2020 forecast that was issued at about the same time last year calling for $1.05-1.10 billion of net income. Appalachian pure-play EQT Corp., Equitrans’ largest upstream customer and the Lower 48’s biggest natural gas producer, renegotiated its midstream contracts for fee relief in the coming years that kicks in beginning in 2021. Meanwhile, producers across the country have continued to curb spending and limit output amid lackluster commodity prices and weak demand during the Covid-19 pandemic. The midpoint of the company’s financial forecast assumes an average of 8 Bcf/d of total gathered volume. The company also said that 70% of its forecasted operating revenue next year is expected to be generated from firm reservation fees. Equitrans is forecasting capital expenditures of $1.04-1.14 billion next year for gathering, transmission and water costs. Also included in that total is the Mountain Valley Pipeline (MVP) project, which has faced repeated regulatory delays and cost overruns. The company expects to spend up to $720 million on MVP this year. The financial forecast assumes MVP will enter service by Dec. 31, 2021. Since receiving its Federal Energy Regulatory Commision certificate in 2017, MVP has faced relentless opposition from environmental advocates. In response to legal challenges spearheaded by these opposition groups, federal courts have issued numerous adverse rulings that have led to construction stoppages and delays. MVP recently obtained new and updated federal approvals related to waterbody crossings and endangered species protections, which have subsequently been subject to further legal challenges, to mixed results thus far. When construction on the system started in 2018, the pipeline was estimated to cost $3.5 billion and be in service by the end of 2018. MVP is now forecasting the 2 Bcf/d system, which would move Appalachian natural gas to the Southeast, to cost up to $6 billion.
Viewpoint: Rising Appalachian gas weighs on 2021 prices –= Natural gas output from the US Appalachian region has proven resilient this year, even as a price slump forced producers to rein in production growth, a trend that could lead to lower prices in the coming year. Gas production from the Appalachian region in 2020 has continued to top year earlier levels, despite the efforts of large regional producers such as EQT, Cabot Oil and Gas and Range Resources to cut costs and return more profits to shareholders. Those companies are facing pressure from investors to stop pursuing seemingly endless production growth. "There is clearly a need for more discipline from all operators" to achieve higher prices, said EQT chief executive Toby Rice in an October earnings call. But Appalachian gas output has continued to climb, underscoring gains in drilling efficiencies that have allowed producers to coax more gas from each new well. Producers have also locked prices on future output through hedging programs which leave them less susceptible to low regional spot prices. "We have seen producers — when pricing gets really bad — curtailing, but by and large, they are a little bit sheltered from some of the most extreme price impacts because of hedging," said Anna Lenzmeier, an energy analyst with BTU Analytics. Dry natural gas production in the Marcellus and Utica shale fields from January to November averaged 31 Bcf/d (878mn m³/d), 4pc higher than a year earlier, according to data from the US Energy Information Administration (EIA). The Marcellus made up the bulk of that output at 23.3 Bcf/d, 6pc higher than year-earlier levels. The formation also had year-over-year gains above 9pc in every month from July to September. Prices may still receive a boost in the coming months as demand for US LNG increases and associated gas production falls because of lower oil prices. At the same time, some producers may be looking to take advantage of typical price spikes that accompany winter demand. Cold weather in the week ended 18 December lifted prices as a winter storm blanketed the northeastern US. Demand-area gas prices surged to an average of $7/mmBtu on 17 December, almost triple the price a week earlier. US gas output was expected to drop to 90.9 Bcf/d this year from an average of 93 Bcf/d in 2019, the EIA said. Spot prices at the Henry Hub, the benchmark price for US gas, in 2021 will average $3.01/mmBtu, according to an EIA forecast. That is down from a November forecast of $3.14/mmBtu. The EIA also revised its forecast average for January down to $3.10/mmBtu from $3.42/mmBtu in the November forecast because of higher expected storage levels.
CenterPoint Energy : seeks recovery following completion of 7-year natural gas pipeline modernization -- CenterPoint Energy's Indiana-based gas utility, Indiana Gas Company, has filed a request with the Indiana Utility Regulatory Commission (IURC) for recovery of investments made within its Indiana natural gas service territory. The filing comes at the completion of the company's 7-year, $725 million gas modernization plan, which was filed in 2013 to comply with federal pipeline safety rules and continue the safe, reliable delivery of natural gas service to its 620,000 north central, central and southeastern Indiana customers. The gas system improvements resulted in upgrades to portions of CenterPoint Energy's 13,000-mile network of distribution mains and transmission pipelines serving north central, central and southeastern Indiana. The work primarily consisted of replacing bare steel and cast-iron distribution mains with new industry-grade plastic mains, as well as inspecting and upgrading natural gas transmission pipelines. This pipeline work has led to a 33% reduction in methane emissions since 2013. Since 2008, nearly 650 miles of gas mains have been replaced in the utility's territory. Using 2013 state laws focused on federal mandates and natural gas infrastructure needs, Indiana utilities submit forward-looking capital investment plans to the IURC for review and cost recovery. The statutes provide utilities the ability for gradual investment recovery as modernization progress is made; otherwise defined as 80% of total capital expenditures and lessening the effect of a larger rate increase through traditional rate recovery. The balance of recovery must be sought through a traditional rate request at the end of the 7-year plan and is a requirement of the law. With the 2013 filing and the IURC's approval and regular review of that plan, the company seeks recovery of the remaining 20% of those investments.
LNG Dip, Pandemic Worries Keep January Natural Gas Futures in Check; Spot Prices Sink -Despite favorable weather news, natural gas futures traded sideways Monday as worries mounted over a still-surging coronavirus pandemic and its potential impacts on economies and energy demand. The January Nymex contract settled at $2.705/MMBtu, up a half-cent day/day. February ticked up eight-tenths of a cent to $2.689. NGI’s Spot Gas National Avg.., meanwhile, declined 19.5 cents to $2.815 amid a warm weather start to the week. NatGasWeather said that while major models swayed back and forth between milder and colder trends over the weekend and into Monday, the American Global Forecast System ultimately settled on a colder outlook beginning around the Christmas holiday and continuing into early January. “There’s still light demand to trudge through the next three days, but after the pattern is much better than it’s been all winter and likely finally cold enough for a bullish lean,” the firm said. Headwinds formed elsewhere, however. Liquefied natural gas (LNG) levels, a catalyst for futures much of December, started the week on a weaker note. NatGasWeather said its estimates for LNG feed gas demand fell over the weekend to around 10.2-10.5 Bcf/d, off around 1 Bcf/d from recent highs. NGI data showed volumes hovering around 10.5 Bcf/d Monday. At the same time, despite a second vaccine being made available this week in the United States, the pandemic continues to surge across the Lower 48, raising concerns about commercial and industrial energy demand. The pandemic also is intensifying overseas, with Great Britain reporting a new strain of the virus and imposing new economic restrictions to curb outbreaks. Several European countries and Canada barred travelers from Britain in hopes of keeping at bay the newly discovered and highly infectious variant of coronavirus that is surging in London. The new strain threatened to throw a wrench into the global economic recovery as well as a rebound in energy demand. Gas futures fell early in the trading day alongside oil prices and major stock indexes in the United States and Europe. Downward pressure on gas prices early Monday was likely “due to a sell-off in equities and oil triggered by new Covid-19 lockdowns in Europe and fears regarding virus mutations,”
Natural Gas Futures Jump on Expectations for Colder Conditions and Lofty Storage Withdrawal - Natural gas futures advanced Tuesday on forecasts for colder weather and a bullish withdrawal from storage. Improved liquefied natural gas (LNG) levels added a dose of optimism. The January Nymex contract climbed 7.5 cents day/day and settled at $2.780/MMBtu. February rose 6.0 cents to $2.749. NGI’s Spot Gas National Avg. rose 5.5 cents to $2.870. Looking to the end of December, colder trends from the European weather model overnight helped drive trading early Tuesday, NatGasWeather said, and futures sustained the momentum throughout the day. While the American model held on to a milder outlook, the European dataset pointed to a substantial stretch of freezing temperatures over the Dec. 29-Jan. 3 timeframe. “Our verification data shows” the European model “performing better over the past 30 days, suggesting” the American dataset “is too warm and needs to add demand,” NatGasWeather said. This “likely has given the natural gas markets hope the cold camp will get a rare victory.” LNG feed gas volumes had hovered just above 10.5 Bcf for several days – below the record levels reached earlier in December – but climbed back above 11 Bcf on Tuesday, according to NGI data, suggesting that export demand remains strong as winter takes hold in Asia and Europe. Traders also took note of optimistic forecasts in this week’s Energy Information Administration (EIA) storage report, which will be released at noon ET on Wednesday. That is a day earlier than normal because of the Christmas holiday. Polls on Tuesday showed widespread expectations for a steep pull for the week ended Dec. 18. A Bloomberg survey showed withdrawal expectations ranging from 146 Bcf to 180 Bcf, with a median of 159 Bcf. A Reuters poll, meanwhile, landed at a median withdrawal of 160 Bcf, with pull estimates spanning from 142 Bcf to 180 Bcf. A Wall Street Journal survey found an average withdrawal expectation of 159 Bcf. Estimates ranged from decreases of 146 Bcf to 179 Bcf. NGI predicted a 159 Bcf withdrawal, above the 146 Bcf pull reported a year earlier and higher than the five-year average 127 Bcf withdrawal. Energy Aspects estimated a 160 Bcf pull and said it modeled a 10% increase in national heating degree days (HDD) during the report week, enough to lift residential/commercial demand by 4.8 Bcf/d week/week. The firm also noted a 0.3 Bcf/d drop in total supply during the week.
US working natural gas volumes in underground storage declines 152 Bcf: EIA - US working natural gas stocks fell well below the five-year average last week, but within expectations, while Henry Hub futures fell following the announcement despite another above-average draw likely for the week in progress. Storage inventories decreased 152 Bcf to 3.574 Tcf for the week-ended Dec. 18 the US Energy Information Administration reported the morning of Dec. 23. The report was issued one day early because of the Christmas holiday. The withdrawal was slightly below an S&P Global Platts' survey of analysts calling for a 154 Bcf pull. Responses to the survey ranged from pulls of 135 to 172 Bcf. The withdrawal was above the 146 Bcf draw reported during the same week last year as well as the five-year average withdrawal of 127 Bcf, according to EIA data. Storage volumes now stand 278 Bcf, or 8.4%, above the year-ago level of 3.356 Tcf and 218 Bcf, or 6.5%, above the five-year average of 3.356 Tcf. In the week ended Dec. 18, US natural gas production dropped to an average 89.8 Bcf/d, according to data S&P Global Platts Analytics compiled. That figure was down about 300 MMcf/d week on week, and more than 2 Bcf/d below a late-November high for US output at over 92 Bcf/d. Recent supply-side weakness has been exacerbated by higher exports and strong domestic heating demand – factors that also contributed to last week's tighter supply balance and large storage withdrawal. In December, feedgas demand from US LNG export terminals is averaging its highest on record at over 11 Bcf/d as import prices in Northeast Asia push the $12/MMBtu level. The NYMEX Henry Hub January contract plummeted 17 cents to $2.61/MMBtu in trading following the release of the weekly storage report at 10:30 am ET. The remaining winter strip, February and March, fell 15 cents to average $2.58/MMBtu, a decline of 5 cents from the week prior. Platts Analytics' supply and demand model currently forecasts a 134 Bcf withdrawal for the week ending Dec. 25, which would shrink the surplus versus the five-year average by an additional 32 Bcf, despite demand being slightly muted by the holiday week. Milder weather has pushed residential and commercial demand down 1.3 Bcf/d. In addition, gas-fired burns in the power sector are on track to fall more than 2 Bcf/d week on week as much higher wind generation lowered gas generation. Warmer weather across the US resulted in lower heating load, and weaker draws in every region except for the East. Lower demand was met with a higher total US supply, led by an 800 MMcf/d boost in US production.
U.S. natgas futures slide over 6% on mild weather, small storage draw - U.S. natural gas futures dropped more than 6% to a near two-week low on Wednesday on forecasts for warmer-than-usual weather and a smaller-than-expected storage draw last week. The U.S. Energy Information Administration (EIA) said utilities pulled 152 billion cubic feet (bcf) of gas from storage during the week ended Dec. 18. That was less than the 160-bcf decline analysts forecast in a Reuters poll and compares with a decrease of 146 bcf during the same week last year and a five-year (2015-19) average withdrawal of 127 bcf. Front-month gas futures fell 17.2 cents, or 6.2%, to settle at $2.608 per million British thermal units, their lowest close since Dec.11. "Near-term prices support has evaporated on a lower than expected, 152 bcf storage withdrawal in this morning's report and variable forecasts for dissipating cold by early January," said Daniel Myers, market analyst at Gelber & Associates in Houston. "More cold (weather) will be needed in upcoming forecasts if the market is going to recover its footing going into the holidays and prevent a collapse to the January contract's prior lows," he added. Data provider Refinitiv estimated 436 heating degree days (HDDs) over the next two weeks in the lower 48 U.S. states, below the 30-year average of 458. HDDs measure the number of degrees a day's average temperature is below 65 degrees Fahrenheit (18 degrees Celsius). The measure is used to estimate demand to heat homes and businesses. Refinitiv projected average demand, including exports, would slip from 124.3 billion cubic feet per day (bcfd) last week to 119.8 bcfd this week as the weather turns milder before rising to 127.9 bcfd next week with the expected arrival of more cold. Output in the Lower 48 U.S. states has averaged 91.0 billion bcfd so far in December. That compares with a seven-month high of 91.0 bcfd in November 2020 and an all-time monthly high of 95.4 bcfd in November 2019. Natural gas futures in Europe and Asia rose to their highest levels in more than a year driven by a sharp increase in demand late in 2020, especially out of China, just as a cold spell in other parts of the region boosts demand for the fuel. China's liquefied natural gas imports hit a fresh peak on rising demand at the start of the heating season, data showed on Wednesday. The amount of gas flowing to U.S. LNG export plants, meanwhile, has averaged 10.7 bcfd so far in December, which would top November's 9.8-bcfd record.
Natural Gas Futures Weighed Down by Weather, Production, LNG and Storage Concerns --Natural gas futures plummeted Wednesday as weather models continued to seesaw, production increased, export cargoes were reportedly cancelled, and the latest government inventory print fell shy of market expectations. The January Nymex contract settled at $2.608/MMBtu, down 17.2 cents day/day. February fell 16.1 cents to $2.588. NGI’s Spot Gas National Avg., meanwhile, dropped 18.0 cents to $2.690. After showing a warmer outlook earlier in the week when compared to the European weather model, the American Global Forecast System (GFS) trended colder overnight into Wednesday and added 15 heating degree days (HDD), according to NatGasWeather. The European model, however, shed eight HDD, bringing it close to the GFS. “Prices gained overnight on the colder-trending GFS, then sold off after the European [model] disappointed on warmer trends,” NatGasWeather said. “The coming pattern is still better than it’s been much of the past two months,” the forecaster added, but with the European data “teasing colder systems yesterday and then backing off today, it’s clearly led to disappointment.” Additionally, the firm noted that trading opened with news that Lower 48 production was up nearly 1 Bcf compared to last week’s 91 Bcf/d. With weather-driven demand dubious, rising output “could be viewed as quite disappointing.” Liquefied natural gas (LNG) levels, meanwhile, remained strong at around 11.4 Bcf Wednesday, according to NGI data. But news media reports of LNG cargo cancellations for February injected some added skepticism for futures traders. Bloomberg reported market rumors of several U.S. cancellations for February, though a lack of shipping availability and aggressively high charter rates were cited as reasons, as opposed to waning demand. The U.S. Energy Information Administration (EIA) then released its latest storage assessment at Noon ET, reporting a withdrawal of 152 Bcf for the week ended Dec. 18. The result was bullish compared to a year earlier, but it fell short of market expectations for a pull of 159-160 Bcf. The prompt month was down about 9.0 cents a few minutes ahead of the storage report and it sunk deeper after EIA’s release. The latest withdrawal was more than the 146 Bcf pull recorded a year earlier and greater than the five-year average 127 Bcf withdrawal, according to EIA. Demand during the covered week was driven by a powerful storm that heaped snow and freezing temperatures on major markets throughout the Northeast. The market, however, was expecting an even steeper pull.
Light Christmas Eve Trading Ends with Natural Gas Futures in Rudolph Red - Natural gas traders on Thursday couldn’t be convinced to go long despite the extended Christmas holiday weekend, especially with the weather data turning milder with every run of the latest models. The January Nymex gas futures contract settled Christmas Eve at $2.518, down 9.0 cents. February slipped 7.6 cents to $2.512. Spot gas prices, which were for gas delivered through Monday, were mostly lower amid the mostly light holiday weekend demand outlook. However, a chilly, wet forecast in the Northeast sparked big gains there. NGI’s Spot Gas National Avg. ultimately climbed 9.0 cents to $2.780. Still digesting the most recent storage data, traders appeared cautious early in Thursday’s Nymex futures session. January prices were slightly lower early in the day but generally stayed within a few cents of Wednesday’s close. However, with yet another warmer turn in the weather models, prices moved decidedly lower ahead of the Christmas Day holiday. “There’s still several days left to go in the latest midday Global Forecast System run, but it’s already lost 14 heating degree days [HDD] for the first 11 days of the new run,” NatGasWeather said. Now, both the American and European models “aren’t quite cold enough overall for the next 15 days.” Any lost demand may keep storage inventories in check in the coming weeks. On Thursday, the few traders that hadn’t quite punched the clock were still digesting the latest storage inventory report. The Energy Information Administration (EIA) reported Wednesday that inventories fell 152 Bcf for the week ending Dec. 18, a pull that came in well short of the near 160 Bcf draw that the market had been expecting.
Weekly Natural Gas Prices Sink Amid Seasonally Mild Weather, Weaker Demand - In an abbreviated four-day trading week ahead of the Christmas holiday, weekly cash prices gave up ground amid mild temperatures and light heating demand across much of the Lower 48. NGI’s Weekly Spot Gas National Avg. for the Dec. 21-24 period fell 45.5 cents to $2.790. Comfortable conditions moved in early and hung around until mid-week across much of the central and eastern half of the United States, with highs of 30s to 50s across northern regions and 60s and 70s over southern areas. As the trading week closed, PNGTS was down $3.145 to $5.240, while Tenn Zone 6 200L was off $4.865 to $3.640, and SoCal Border Avg. was down 50.0 cents to $3.295. While not expected to prove consistently bullish, forecasters anticipated stronger demand in the final days of December and into early January. NatGasWeather looked for a spike in demand in some regions over the long holiday weekend, beginning with subzero Upper Midwest temperatures on Thursday following blasts of snow. Freezing conditions were anticipated across wider swaths of the nation’s midsection and into eastern regions over the course of the weekend, with “frosty lows” ranging from below zero to the 20s over large portions of the country. “Periods of stronger demand are expected” late in December “as a frigid cold shot with rain and snow sweeps across the eastern half of the United States,” NatGasWeather said late Thursday. “Additional systems with stronger demand are expected to follow Dec. 29-30, Jan. 2-4, and again around Jan. 7-8.” However, the firm added, “mild breaks in between is what prevents the coming pattern from being considered more intimidating.” It “is a better pattern with bouts of stronger demand, just without sustained cold that would lead to solidly bullish weather sentiment.” Despite the short week, Nymex futures made a splash, falling sharply across the curve as a milder turn in the most recent weather models and a disappointing storage report hammered prices. Futures had moved higher earlier in the week, with the January contract picking up more than 7.0 cents on Tuesday as weather models pointed to chilly conditions at the end of the month that were seen spilling over into January. However, both the American and European models backed off the intensity of the cold in more recent runs. The warmer trend set the stage for a midweek sell-off along the Nymex strip. Prices on Wednesday already were lower ahead of the Energy Information Administration’s (EIA) weekly storage inventory, which was released a day earlier than usual because of the Christmas Eve federal holiday. With the reported withdrawal coming in several Bcf below what the market had been expecting, the January Nymex contract spiraled even lower. The EIA said that inventories fell 152 Bcf for the week ending Dec. 18, but analysts had pegged the draw closer to 160 Bcf.
Two Natural Gas Rigs Added in U.S. Ahead of Holiday - The U.S. natural gas rig count climbed two units to 83 for the holiday-shortened week ending Wednesday (Dec. 23), while Canada saw a notable drop-off in activity ahead of the Christmas holiday, according to the latest figures from Baker Hughes Co. (BKR). After some shuffling around in the major U.S. onshore plays, the overall domestic rig count added two units to finish at 348, including an increase of one oil-directed unit, offset by the loss of one miscellaneous unit. The combined U.S. tally finished the week more than 450 units below the 805 rigs active at this time last year, according to the BKR numbers, which are based on data provided in part by Enverus. Land drilling increased by one rig, while one rig returned to action in the Gulf of Mexico during the week. One directional unit and one horizontal unit were added, while vertical rigs remained unchanged week/week. The Canadian rig count fell 20 rigs week/week to drop to 82, with the net decline split evenly between oil- and gas-directed units. The Canadian count ended the week 17 rigs behind its year-ago total. The combined North American rig count finished the week at 430, down from 904 in the year-ago period. Among the major plays, the Haynesville Shale turned in a strong week of growth, adding three rigs to up its total to 43. That’s down slightly from 49 a year ago. Elsewhere among plays, the Cana Woodford added one rig, while the Denver Julesburg-Niobrara, Marcellus Shale and Permian Basin each dropped a rig from their respective totals. Broken down by state, Louisiana led with a three-rig increase on the week, while Oklahoma saw a net increase of two rigs for the period. Texas added one rig overall, while Alaska, Colorado, New Mexico and West Virginia each saw one rig depart, according to BKR.
Fossil, Renewable Energy Advocates Alike Applaud Passing of $2.3T Spending Bill -- Proponents of the natural gas, oil and renewable energy sectors all found something to like about a $2.3 trillion omnibus spending and coronavirus relief package passed late Monday by the House and Senate. Infrastructure The American Petroleum Institute (API) praised legislators for including several provisions from Sen. Lisa Murkowski’s (R-AK) American Energy Innovation Act, including parts of two bipartisan bills to promote carbon capture, utilization and storage (CCUS). “We commend the bipartisan group of lawmakers who have moved this legislation one step closer to becoming law and who understand the important role of advancing innovation and technology in addressing the risk of climate change,” said API’s Stephen Comstock, vice president of corporate policy. He added, “We urge the president to swiftly sign this bill into law, and we encourage the next Congress and incoming administration to continue to focus on bipartisan climate solutions like CCUS, which can reduce greenhouse gas (GHG) emissions from multiple industry sectors and sources and that help build on the progress the natural gas and oil industry is making in improving environmental performance.” The spending package also greenlights the bipartisan Protecting our Infrastructure of Pipelines and Enhancing Safety Act (PIPES ACT) of 2020, an update of the PIPES Act of 2016 signed into law by President Obama. The original legislation was championed by Sens. Deb Fischer (R-NE) and Tammy Duckworth (D-IL). The PIPES Act is aimed at improving safety and curbing methane emissions from the U.S. pipeline network through modernization and strengthening of the Pipeline and Hazardous Materials Safety Administration (PHMSA). The PIPES Act “has been years in the making,” said API’s Robin Rorick, vice president of midstream and industry operations, who added that the Act “takes important steps to ensure the safety of our nation’s pipeline system for communities and the environment.” Interstate Natural Gas Association of America (INGAA) CEO Amy Andryszak applauded the PIPES Act passing as well, saying it will “provide PHMSA with the necessary resources to continue its important work overseeing our nation’s pipeline infrastructure. “New funding for our nation’s pipeline safety program and updates to PHMSA’s regulations to reflect the latest technologies and practices will both enhance safety and benefit the environment.” The PIPES Act has been amended since its introduction in order to further reduce methane emissions from transportation infrastructure, and provide PHMSA new rulemaking and inspection resources, INGAA said. Key provisions of the PIPES Act include updates to PHMSA’s methane leak detection and repair regulations; increased funding for state and federal pipeline safety regulatory agencies; modernized safety regulations for liquefied natural gas export facilities; and strengthened safety regulations for local gas distribution systems.
Oil drilling 150 miles off Florida coast prompts dire warning— Exploratory drilling began this week for an offshore oil well just 150 miles from South Florida, prompting a warning from 18 members of Congress, including the entire South Florida delegation, of the potential for “severe, even catastrophic, impact” if a spill occurs. The well, operated by the British-owned Bahamas Petroleum Company under a license from the Bahamian government, will be drilled as deep as 18,000 feet in an area southwest of Andros Island. It is believed to be the only active well in the region, although the status of oil fields nearby in Cuban waters is unclear. The drilling prompted an urgent letter from the 18 Congress members to Hubert Minnis, prime minister of the Bahamas, urging him to reconsider the quest for oil. “It has become clear that oil companies such as BPC have every intention to plow ahead despite red flags, which warn of the grave health, natural disaster, and environmental risks of drilling,” the letter to Minnis said. Even a minor accident that leads to a small oil spill could cost millions of dollars to Florida and disrupt tourism and businesses. Proponents of the drilling say the process is closely regulated and accidents are rare. “The way that they’re drilling today I think it’s perfectly safe,” said Ned Bowman, executive director of the Florida Petroleum Marketers Association. “We’re the most regulated industry in the world and I think you’ve got so many wells that are out there … if you look at that whole concept and how safe the industry is, I don’t have an issue with it.” But Floridians have scarred memories over another exploratory well that led to one of the worst environmental disasters in U.S history. The 2010 Deepwater Horizon spill in the Gulf of Mexico dumped an estimated 164 million gallons of oil into the Gulf of Mexico and caused billions of dollars in economic and environmental damage along the entire Gulf Coast from Louisiana to the Florida Keys.
Settlement calls for Texas oil company to pay for Cimarron River restoration after spill - A Texas oil company that spilled diesel and gasoline into the Cimarron River during a 2016 accident has agreed to pay $150,000 for restoration projects under a proposed settlement with the state. Fronk Oil Co. will pay for restoration to benefit fish, habitat, soil, water and other natural resources that were harmed or lost when a company tanker overturned on U.S. 64 in icy conditions, spilling 1,100 gallons of unleaded gasoline and diesel fuel into the river near the Colin Neblett Wildlife Management Area. “New Mexico residents were directly impacted by the contamination and this settlement will compensate for the losses they have suffered,” state Natural Resources Trustee Maggie Hart Stebbins said in a statement. A 1.5-mile section of the river downstream from the release was closed to public access for several months. The cleanup cost Fronk about $300,000. “Fronk Oil regrets the accident and has taken seriously our corporate responsibility to make things right,” Jerry D. Worsham II, the company’s attorney, said in a statement. “Fortunately, there does not appear to be any long-term impact.”
Permian-Focused Fracking Consolidation Continues With Diamondback Deals -- Big Permian Basin producer Diamondback Energy FANG +0.9% announced a pair of big acquisitions designed to enhance its presence in America’s most active shale oil and gas basin on Monday. Together, the value of the deals totals to more than $3 billion, inclusive of assumed debt, and will rank Diamondback among the basin’s largest producers, along with ExxonMobil XOM -0.4%, Pioneer Natural ResourcesPXD -0.6%, ConocoPhillips COP -1.5% and Oxy. The first deal announced by Diamondback in a release Monday morning details the acquisition of Guidon Operating LLC “in exchange for 10.63 million shares of Diamondback common stock and $375 million of cash,” a total value of about $862 million. Guidon holds about 32,500 acres in the Northern Midland Basin, and had a Q3 2020 estimated daily production of about 17,900 barrels of oil equivalent (boe). Guidon’s holdings include “395 estimated gross (324 net) horizontal locations with an average lateral length of over 10,500 feet.”Diamondback’s second deal involves the acquisition of QEP Resources, a multi-basin independent producer headquartered in Denver, Colorado. Diamondback saidit would purchase 100% of QEP in “an all-stock transaction valued at approximately $2.2 billion, including QEP’s net debt of $1.6 billion as of September 30, 2020.” Diamondback management said that QEP’s holdings in the Williston Basin would be deemed “non-core” assets, and used to either harvest cash flow or be divested, depending on market conditions after the transaction is finalized. QEP’s Permian holdings include “approximately 49,000 net acres in the Midland Basin primarily held by production allowing for capital efficient development,” and “Q3 2020 average Permian production of 30.5 MBO/d (47.6 MBOE/d).” Combined, Diamondback said the two new acquisitions would increase its Midland Basin holdings to 276,000 net surface acres and to a total of 429,000 net acres across the Permian region’s Midland and Delaware Basins. The highly-contiguous acreage positions of the three companies will enable Diamondback to take advantage of the economies of scale and other efficiencies that have become so prized as keys to reducing costs in the Permian and other shale basins across the country. “ Most importantly, the addition of this Tier-1 resource competes for capital right away in Diamondback’s current portfolio, and we will now be able to allocate most of our capital to the high-returning Midland Basin for the foreseeable future.”
US oil, gas rigs fall by one on the week to 413, as Permian at highest level since May— The US oil and gas rig count decreased by one on the week to 413, rig data provider Enverus said Dec. 24, while Permian Basin rigs reached a level not seen in seven months. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up The decrease was from gas-directed rigs, which fell by one to 113 while oil rigs remained at 300 for a second straight week. The oil rig count has not been above 300 since late April 2020. "Typically, the industry experiences weather impact and seasonality around the holidays, but this year the rig count has continued to increase" with the exception of the current week, Evercore ISI analyst James West said in a Dec. 24 investor note. Since the first week in November, the rig count has risen 15% from 359. The Permian Basin of West Texas/New Mexico was the week's clear winner in rig gains, up by three rigs to 184, its highest level since May 2020. Since its late-August 2020 trough of 127, the Permian rig count has added 57 rigs and climbed 45%. But the quieter SCOOP-STACK play in Oklahoma also rose by three rigs on the week to 16, the highest it has been since April 2020. Other basins mostly either shed rigs or were stable week on week. However, the Marcellus Shale sited largely in Pennsylvania and surrounding states, gained one rig, for a total 31. Bakken, DJ, Eagle Ford lose rigs But the Bakken Shale mostly in North Dakota and the DJ Basin in Colorado, lost one rig apiece, for totals of 12 and eight respectively. The Eagle Ford Shale of South Texas lost two rigs, leaving 30. Basins that posted no weekly change were the Haynesville Shale of East Texas/Northwest Louisiana, at 46 rigs, and the Utica Shale mostly in Ohio, at six.
Study: Severe economic hit to Utah with Biden ban on new oil, gas wells - — With climate change a cornerstone of his campaign and central to his proposed Cabinet picks, President-elect Joe Biden has vowed to put an end to any new oil and gas development on federal lands and federal waters.That promise, if enacted, would severely impact Utah and seven other western states with huge chunks of federal land, with a new study predicting staggering economic losses and extreme costs to human lives.Conducted by University of Wyoming professor Tim Considine at the request of the Wyoming Energy Authority, the study lays out these dire predictions of losses to those states over four years under a Biden administration:
- An average of 72,818 fewer jobs annually
- Lost wages totaling $19.6 billion
- Declining economic activity of $43.8 billion
- Tax revenues decreasing by $10.8 billion
These forecasted impacts play out in Utah, Alaska, California, Colorado, Montana, New Mexico, North Dakota and Wyoming.In Utah, the study says such a ban would cost 3,232 jobs on average each year during Biden’s inaugural term, $1.3 billion in oil and natural gas investments, losses in production valued at $650 million, a decrease of $255 million in tax revenue to the state, a drop of $1.4 billion in gross domestic product and $664 million in lost wages.Gov. elect Spencer Cox says such a ban is the wrong move for Utah. “A sudden ban on oil, gas and coal right now could crush Utah’s rural economies and further weaken the oil and gas economy. Plus we’re making progress on reducing carbon emissions through cleaner Tier 3 fuels, which now represent at least 75% of all fuel purchased in Utah,” he said. “ I’m looking forward to working with the Biden Administration to develop a more practical approach to energy policy.”
Scientist Dominic DiGiulio’s Work Illuminated How Fracking Affects People and Environment - - People in communities across the nation have found themselves the participants in a fracking experiment. The practice is controversial because of its potential impacts to public health and the environment, specifically, it can poison drinking water. After years of research, scientist Dominic DiGiulio made this link. He found that people’s groundwater can become contaminated under certain conditions. The pits that store fracking chemicals are one example. Such was the case in Pavillion, Wyoming, a community of roughly 230 people.Back in 2008, residents began complaining their water had a foul taste and smell. So the EPA came in to investigate. Led by DiGiulio, the team’s preliminary findings released three years later suggested fracking was to blame.But officials in Wyoming dismissed the findings as a political move.DiGiulio rejects that claim to this day.DiGiulio: When I worked with EPA, there was no desire with myself and my coworkers to ban fracking. That was never the goal. We were simply conducting an investigation on the impact on groundwater resources and people’s wells. So there was never any kind of goal to have any kind of political objective. Ours was simply a technical objective to better understand the impact of hydraulic fracturing on public health and the environment. But politics still found the scientists, and due to political pressure, EPA backed out of the study. DiGiulio, for his part, knew his work wasn’t done. DiGuilo retired from EPA in 2014 and went on to lead his own study. It was a massive effort with DiGiulio parsing decades of records. DiGiulio: I took about 18 months to actually go through the data once more. So it was a very time intensive process. I mean, there was a lot of data there. It was definitely lots of digging and going back to the beginning, back to the 1960s, and actually looking at every single record, all the well completion records, all the records on cement bond locks for well integrity, all the water well records. We basically did a very comprehensive review of the records out there just to get a much better understanding of what the problems were. DiGiulio’s research made the connection that he had started to draw back in 2011 with EPA, only this time, the investigation made his findings clearer. DiGiulio: Hydraulic fracturing started at the Pavillion field back in the 1960s and so the flowback that came from hydraulic fracturing was disposed in pits. So it was basically Diesel fuel-based fracking fluids that went into the pits, petroleum based fluids. So hydraulic fracturing, the actual process itself, didn’t impact domestic water wells but flowback from hydraulic fracturing was disposed into unlined pits which then contaminated groundwater. The saga in Pavillion, Wyoming, is ongoing. Residents reportedly still can’t drink their water and complain of health problems. DiGiulio says contained within this controversy are lessons for people living in the Mountain West.
Comin' to America, Part 5 - Imports Remain Key to Rockies and West Coast Refiners' Crude Slates - PADDs 4 and 5 — the Rockies and the West Coast regions, respectively — are each outliers in the U.S. refining sector. Refineries in the Rockies, for example, are generally far smaller than those in other PADDs and, due to pipeline flows, source their crude oil from either Western Canada, the Bakken, or in-region production, including the Niobrara and Utah’s Uinta Basin. West Coast refineries, in turn, have no crude oil pipeline links with U.S. points to the east, and depend on a mix of imported crude from Canada, Latin America, and the Middle East, as well as domestic oil from California, Alaska, and rail receipts. Today, we conclude a series on region-by-region crude oil imports and refinery crude slates with a look at PADDs 4 and 5. As we said in Part 1, the Shale Revolution, combined with the development of the oil sands and other hydrocarbon resources in Western Canada, led to a dramatic decline in U.S. oil imports from OPEC countries in particular and, to a lesser extent, from non-OPEC countries (other than Canada) — and a big increase in imports from Canada. In 2005, the U.S. imported an average of 4.8 MMb/d from OPEC, 1.6 MMb/d from Canada, and 3.7 MMb/d from other non-OPEC countries, including 1.6 MMb/d from Mexico, according to the Energy Information Administration (EIA). This situation is far different in 2020. In the first nine months of this year, imports from OPEC averaged about 930 Mb/d, while imports from Canada averaged 3.6 MMb/d, and imports from other non-OPEC countries averaged 1.5 MMb/d — Mexico’s slice of that averaged about 690 Mb/d. Part 2 focused on PADD 1 — the East Coast — which not only produces very little crude oil but has almost no oil pipelines. That means that nearly all of the oil refined in PADD 1 — domestic or imported — needs to be delivered by railroad tank cars or ships. We noted that East Coast refinery demand for oil averaged around 1.1 MMb/d for most of the past decade, but has plummeted by half (to less than 600 Mb/d) this year. PADD 1’s sources of oil supply shifted almost 100% imports in 2010-12 to a mix of imports and railed-in Bakken crude in 2013-15, then back to a preponderance of imports in the latter years of the decade. In Part 3, we looked at the Midwest. PADD 2 refineries for decades depended on a mix of domestic crude and imports from overseas, but since 2010 the region has nearly tripled its imports of Canadian crude — most of it the heavy-sour variety — and invested billions of dollars in cokers and other equipment so they can process that low-API, high-sulfur oil into valuable products like gasoline, low-sulfur diesel, and jet fuel.PADD 3 — the Gulf Coast — was front-and-center in Part 4. The region accounts for more than half of the U.S. refining capacity, and has undergone perhaps the biggest shift in crude-oil sourcing: 15 years ago, it was importing an average of more than 6 MMb/d, but in recent months has been receiving as little as 1.2 MMb/d from abroad. The 80% decline in Gulf Coast oil imports since the mid-2000s was made possible in part by big changes in the crude slates at refineries in Texas, Louisiana, and other PADD 3 states, mostly involving the swapping out of light-sweet crude from overseas with favorably priced light-sweet crude from the Permian and other U.S. shale plays.
BNSF train carrying North Dakota oil derails, starts on fire in Washington state — A Burlington Northern Santa Fe train carrying crude oil from North Dakota's Bakken oil fields derailed and caught fire late Tuesday morning, Dec. 22, in a small town in the far northwest part of the state. BNSF Railway spokesperson Courtney Wallace said in a statement that three of the 10 cars that derailed started on fire in Custer, a town of 370 residents just 25 miles south of the Canadian border, about 11:40 a.m. The train, which originated in North Dakota, was near Interstate 5 about 100 miles north of Seattle, and the Whatcom County Sheriff's Department said they had to evacuate a three-quarter mile radius around the derailment. The train was headed for the nearby town of Ferndale, Wallace said, which is near the Puget Sound. Late in the afternoon, the sheriff's office said in a Facebook post that the fire was under control. However, they said an evacuation order and local road closures were still in place. The sheriff urged town residents to continue to avoid the area, although the interstate was reopened about two hours after the fire started. A photo posted by the sheriff's department showed a huge cloud of black smoke rising into the air and residential homes nearby. Wallace said no injuries were reported to crew members onboard the train. She said the cause of the derailment is under investigation, with BNSF coordinating with authorities. The sheriff's department told the nearby Bellingham (Wash.) Herald that they were unsure if there was any damage to nearby structures or buildings. The number of people evacuated also wasn't available. The department and Wallace said the train was carrying the crude oil from North Dakota. The derailment and fire follows a decision last May in which the U.S. Pipeline and Hazardous Materials Safety Administration sided with North Dakota and Montana against a Washington state law requiring oil unloaded from trains have a vapor pressure under 9 pounds per square inch. The limit would fall below North Dakota's cap of 13.7 pounds per square inch, which the state argued was an industry standard. North Dakota Attorney General Wayne Stenehjem said in a statement that he was “pleased” with the PHMSA decision, according to an article by the Bismarck Tribune.
Train cars carrying crude oil derail and burn north of Seattle - Seven train cars carrying crude oil derailed Tuesday and five caught fire, sending a large black plume of smoke into the sky north of Seattle close to the Canadian border, authorities said. The derailment in the downtown Custer area closed nearby streets and spurred evacuation orders during a large fire response, Whatcom County officials said on Twitter. Interstate 5 was temporarily closed in the area in both directions. Later Tuesday, the Whatcom County Sheriff's Office tweeted that the fires were under control and the evacuation order had been lifted but roadblocks would remain in place. Fires at the site remained active, the Sheriff's Office added, and residents were asked to stay inside once they returned home. "Everyone's in danger at a scene like this, but fortunately there were no injuries," Sheriff Bill Elfo said at a news conference. Home to five oil refineries, Washington state sees millions of gallons of crude oil move by rail through the state each week, coming from North Dakota and Alberta, Canada, according to the state Department of Ecology. The seven cars derailed at about 11:46 a.m. Tuesday, BNSF Railway spokesperson Courtney Wallace said at the news conference. She said two people were on board the 108-car train headed from North Dakota to the Ferndale Refinery, owned by Phillips 66. "BNSF is working with local authorities to assess and mitigate the situation," the railway said on Twitter. "The cause of the incident is under investigation." The state Department of Ecology said a command center had been set up at the scene with the railway and federal Environmental Protection Agency officials. Matt Krogh, director of U.S. Oil & Gas Campaigns for the environmental group Stand.earth, is based in Bellingham near the derailment and told The Associated Press he could see the smoke. He said the incident was another example of how transporting crude oil by train – especially in large numbers of tankers — is "very, very dangerous." He cited the 2013 fiery derailment of a train carrying crude in Lac Megantic, Quebec, which killed 47 people, and a 2016 derailment in Mosier, Oregon, along the Columbia River that caused people to evacuate. Krogh said crude oil is volatile and there are often track maintenance concerns. Among other things, Krogh and his group would like to see a reduction in the number of tank cars allowed per shipment. "I think we got lucky today," he said, referring to the derailment in Custer. Democratic U.S. Rep. Rick Larsen, D-Wash., said in a statement Tuesday he was concerned about the derailment. Larsen is a senior member of the House Transportation and Infrastructure Committee. "I worked closely with the Obama administration to create strong rules to make the transport of oil by rail safer," Larsen said. "Clearly there may be more work to do." Custer, a small town of several hundred people, is about 100 miles (161 kilometers) north of Seattle.
Oil train derailed near site of earlier terrorist attempt, officials say (AP) — Federal and local authorities were investigating a fiery oil car train derailment north of Seattle near where two people were arrested last month and accused of attempting a terrorist attack on train tracks to disrupt plans for a natural gas pipeline. Seven train cars carrying crude oil derailed and five caught fire Tuesday, sending a large plume of black smoke into the sky close to the Canadian border. There were no injuries in the derailment about 100 miles (161 kilometers) north of Seattle Officials were asked about recent attempts to sabotage oil trains, but they said the investigation was just beginning. “We’ve not been able to get close enough to the site to make an evaluation,” Officials with the National Transportation Safety Board along with the FBI and other federal, state and local agencies were on the scene. During a news conference Wednesday, officials spoke about their disaster planning they had done to prepare for incidents similar to what occurred with the train derailment. They also spoke about how the impact of the derailment to the surrounding environment could have been worse. "As far as crude oil derailments and fires, this could not have occurred in a better location with regard to minimizing environmental impact," said David Byers, who manages disaster response for the Washington Department of Ecology. Last month federal authorities in Seattle charged two people with a terrorist attack on train tracks, saying they placed “shunts” on Burlington Northern Santa Fe tracks. “Shunts” consist of a wire strung across the tracks, mimicking the electrical signal of a train. The devices can cause trains to automatically brake and can disable railroad crossing guards. Authorities said the pair were opposed to the construction of a natural gas pipeline across British Columbia when they interfered with the operation of a railroad in Washington state. The FBI’s Joint Terrorism Task Force has said there have been dozens of such cases involving BNSF tracks since January, with a message claiming responsibility posted on an anarchist website early this year. In one, shunts were placed in three locations in northwest Washington on Oct. 11, prompting emergency brakes to engage on a train that was hauling hazardous materials and flammable gas. The braking caused a bar connecting the train’s cars to fail; the cars became separated and could have derailed, authorities said.
BP Divests Stake in Alaska Pipeline -Harvest Alaska has acquired BP Pipelines Inc.’s midstream ownership interests, parent company Harvest Midstream reported late last week.The deal, which received approval from the Regulatory Commission of Alaska on Dec. 14, immediately gives Harvest ownership of BP’s approximately 49-percent interest in the Trans-Alaska Pipeline System (TAPS) and 49 percent of Alyeska Service Co. and other Alaska midstream interests, Harvest Midstream noted in a written statement. The parent firm added that Alyeska will continue to operate TAPS as it has for decades.“The completion of this acquisition is a critical milestone for Harvest,” remarked Harvest Midstream CEO Jason Rebrook. “TAPS is an icon of American ingenuity and has a proven track record of safe and responsible operations with strong relationships in the communities it touches. We are committed to positively building upon this great legacy and we look forward to partnering with Alyeska, other TAPS owners and the State of Alaska for years to come.” The 800-mile (1,287-kilometer) TAPS transports North Slope oil from the Prudhoe Bay oilfield to the Valdez Marine Terminal, boasting a capacity of approximately 1.1 million barrels per day, Harvest Midstream stated.
Shell Marks Another $4.5 Billion in Oil, Gas Assets Up for Write-Down in 4Q -- Royal Dutch Shell plc expects to write down between $3.5 billion to $4.5 billion during the fourth quarter because of impairments, asset restructuring and onerous contracts. It would be the third time this year the Anglo-Dutch supermajor has written down assets. In a fourth quarter update, Shell said it expects to take a partial impairment on the Appomattox asset in the U.S. Gulf of Mexico (GOM) because of sub-surface updates. The project, located about 80 miles south of New Orleans, began production in May 2019. It was the first commercial discovery to ramp up in the Norphlet formation. It also expects charges on oil products related to the previously announced transformation of the refinery portfolio, as well as on onerous contracts in the Integrated Gas (IG) segment. Shell expects IG production to be between 900,000 and 940,000 boe/d in 4Q2020, which is above its previous forecast and higher than output of 820,000-860,000 boe/d in the third quarter. However, the company said the impact to earnings is likely to be “limited” because of its production sharing contracts.Liquefaction volumes are expected to be between 8.0-8.6 million tons, while trading and optimization results are expected to be “below average” in the quarter, according to Shell. Around 80% of the company’s term LNG sales this year have been linked to oil prices, with a price lag of up to six months, management said. Shell is one of the world’s largest LNG traders. The exploration and production giant said “significant margining outflows” have impacted cash flow from operations in the final three months of the year, and the full quarter impact is subject to commodity price changes and forward curves through Dec. 31. Shell in October slashed its workforce by up to 9,000 people, a reduction seen by management as simplifying the organizational structure and helping to deliver “sustainable” annual cost savings of $2-2.5 billion by 2022. Tudor, Pickering, Holt & Co. (TPH) analysts said Shell’s 4Q update pointed to generally weaker results across segments versus their model, with marketing guidance, upstream volumes and higher guided underlying operating expenditures quarter/quarter “key moving pieces.” The TPH team said Shell missed their projections in the upstream and IG segment, but downstream and chemicals operational results fared better versus estimates. Shell in 2Q2020 recorded one-time quarterly impairments totaling $16.4 billion because of withering energy demand and low prices, with charges for QCLNG and Prelude floating LNG in the Browse Basin. It followed that with another nearly $1 billion write-down in October, focused again on Prelude.
Work Suspended on Transmountain Pipeline Following Accidents in Alberta, BC - Work was suspended Friday until Jan. 4, 2021 on the Trans Mountain Pipeline expansion project as a result of construction contractor accidents. Pipeline president Ian Anderson said, “Trans Mountain is proactively taking the step to temporarily stand down construction to review, reset and refocus our efforts, and those of our contractors and their workers.” The work suspension follows accidents at both ends of the 1,150-kilometer (690-mile) oil conduit across Alberta and British Columbia: an October fatality near the Edmonton inlet and a serious injury this week at the outlet in the Burnaby suburb of Vancouver. Construction is about 20% complete on the project that would nearly triple the pipeline’s capacity to 890,000 b/d as an export route for Canada’s top natural gas users, Alberta thermal oil sands plants. “Next year, 2021, will see peak construction for the project, with thousands of people working in hundreds of sites,” said the work suspension announcement. “It is during this time when one of the greatest risks to the project becomes worker safety.” Along with pipeline company and construction contractor reviews, investigations are underway by the Canada Energy Regulator (CER) and workplace safety authorities in Alberta and B.C. Detailed route approval proceedings continue before the CER. The cases include review of a detour that Trans Mountain agreed to build around the Coldwater native tribe, which says the original route endangered the water supply of its southern B.C. reservation.
Mexico Natural Gas Prices Hit 21-Month High in November - Natural gas prices in Mexico reached a 21-month high in November, averaging $3.45/MMBtu, according to the latest IPGN monthly natural gas price index published by Comisión Reguladora de EnergÃa (CRE). CRE compiles the index based on day-ahead spot prices reported anonymously by marketers. CRE used 298 transactions reported by 28 marketers for a total volume of 6.48 Bcf/d to calculate the latest index, up from 238 deals from 24 companies for 6.15 Bcf/d in the similar period last year. Due to Mexico’s growing dependence on pipeline gas imports from the United States, Mexico gas prices are closely tied to prices at liquid trading locations in the United States, namely Henry Hub, Houston Ship Channel and Waha. U.S. prices were boosted in November by surging exports of liquefied natural gas (LNG), which hit a record monthly high after plunging to their lowest levels in more than two years over the summer amid the Covid-19 pandemic, according to the U.S. Energy Information Administration (EIA). A cold start to the winter in Asia combined with fewer pandemic-related restrictions has driven spot LNG prices to their highest level in over two years, researchers said. In its latest Short-Term Energy Outlook, EIA also forecast monthly average spot prices of $3.01/MMBtu for full-year 2021, up from a forecast average of $2.07/MMBtu for 2020. The bullish outlook is driven by higher heating demand, rising LNG exports and domestic production declines.
Private Sector Upstream Industry in Mexico Said Committed to Developing Nation's Oil and Gas Private firms operating in the Mexican upstream oil and gas sector have maintained their commitment to the country despite the impacts of coronavirus and have even upped exploratory activity this year. This is according to a panel of experts who spoke during a virtual event last week organized by the #WeTweetEnergy group, an online community of Mexico energy experts. “Despite the pandemic, this year the effect of coronavirus in Mexico hasn’t been felt as it has been felt on the global level. On the contrary, we’ve seen positive results,” said Selene González, external affairs officer for trade group Asociación Mexicana de Empresas de Hidrocarburos (Amexhi). The year/year increase in private sector upstream investment in the first nine months of this year was $290 million, González said. Even as the Mexican government has suspended exploration and production (E&P) bid rounds, more than 100 contracts from rounds held during the previous administration continue to advance. While there is no sign of new rounds, González said there is over $40 billion committed from private firms in the upstream. Private sector oil production is also expected to close 2020 at 57,000 b/d, up 20% from full-year output in 2019. Energy consultant and former commissioner at upstream regulator Comisión Reguladora de Hidrocarburos (CNH) Gaspar Franco said that part of the reason for the continuation of activity is that most private operators are still in the exploration stage. In Mexico, when the pandemic caused the shutdown of much of the economy back in April, E&P was deemed an essential activity and work continued basically as usual for many firms. “Now it looks like it is strategic for companies to continue exploration,” he said, adding that despite coronavirus and the deep unpredictability of prices, “no one is going to leave, but there will be adjustments in plans.”
Tax Break or No, Mexico's Pemex Likely to Require More Government Support, Fitch Says - Mexican state oil company Petróleos Mexicanos (Pemex) would require more government support over the coming years if it wants to increase capital expenditures (capex) without taking on more debt, even if proposed tax breaks for the firm are passed by legislators, according to Fitch Ratings. Pemex rigs Senator Armando Guadiana, a member of President Andrés Manuel López Obrador’s Morena coalition, has introduced a bill that would see heavily indebted Pemex’s profit-sharing duty reduced to 35% from the current effective rate of 58%. The current rate is scheduled to decrease to 54% in 2021, which would remain the effective rate if Guadiana’s bill fails to pass, said the Fitch analyst team led by Lucas Aristizabal. “Fitch’s base case for the company already incorporates the assumption that Mexico would cover the expected negative free cash flow [FCF] projected for the next few years,” analysts said. They estimated that the proposed tax break would reduce Pemex’s negative FCF by about $3 billion/year on average going forward. If the bill does not pass, Fitch expects Pemex’s negative FCF to be about $15.8 billion on average over the next few years. The proposed legislation also aims to increase Pemex’s tax deductions and remove profit-sharing duties from production used for self-consumption, the Fitch team said. Learn More - LNG Insight The bill, if passed, would allow Pemex to deduct the highest of either 15.5% or $9.80/bbl for most of its oil production, up from 12.5% or $6.10 currently. Pemex’s 2019 average pre-royalties lifting costs of about $10.30 ($14.10 including production taxes in 2019) “are higher than the currently allowed tax deductions, and the proposed amendment would bring the allowed tax deductions closer to the company’s production costs,” Fitch analysts said.
UK to End Support for Natural Gas Export, Other Foreign Fossil Fuel Projects- The UK would end government-funded financial support for overseas oil, natural gas and coal projects under a plan announced this month by Prime Minister Boris Johnson as the country continues to jockey for position in the global fight against climate change. The policy would end taxpayer support for export finance, aid funding and trade promotion of foreign fossil fuel projects. Over the last four years, the government said it has supported 21 billion pounds, or about $28 billion, worth of UK oil and gas exports through trade promotion and export finance. The government has launched a review of the policy with the industry and other stakeholders. The goal is to implement the policy by the start of the United Nations Climate Change Conference in November 2021, which will be held in Glasgow, Scotland. Johnson said the UK Export Finance (UKEF) department, the country’s export credit agency, would continue to consider applications for support in the oil and gas sector as the policy review continues. The UKEF helps UK companies by providing insurance to exporters and guarantees to banks to share the risks of providing export finance. For example, export credit agencies have become increasingly important providers of funding for natural gas liquefaction projects across the world as they have grown in size over the years. Johnson’s announcement, made at the Climate Ambition Summit earlier this month, came just weeks after he laid out a plan to cut the UK’s emissions by at least 68% by 2030 compared to 1990 levels. The prime minister also unveiled last month his “Ten Point Plan” for a so-called green industrial revolution, which aims to support alternative energy and accelerate emissions reductions. Leading groups such as the Organization for Economic Cooperation and Development and the International Energy Agency have called for an end or reduction to government funding for fossil fuel projects.
LNG Could Drive $11 Billion of Australian Natural Gas Project FIDs in 2021, Says Wood Mackenzie -As the pandemic eases and the global economy recovers, $11 billion of Australian natural gas projects could be sanctioned as soon as next year, according to a report released this month by consultancy Wood Mackenzie. The country has helped drive growth in global liquefied natural gas (LNG) supplies in recent years and exports are expected to drive the next wave of Australian final investment decisions (FID) next year. “After doing everything possible to tighten belts this year, Australian operators will open their wallets and start spending,” said Wood Mackenzie senior analyst Daniel Toleman. “The backlog of FIDs will begin to clear as a fresh round of projects are sanctioned. But for this to occur, there has to be continuing improvement in the macro-environment and prices trending up.” The first project expected to be sanctioned next year is Mitsui E&P Australia’s Waitsia natural gas field. The project would export LNG from the North West Shelf with production starting in late 2023. Next, Santos Ltd. is expected to sanction the Barossa gas field in the Northern Territory late in 2Q2021. Barossa would backfill the Darwin LNG terminal when the Bayu-Undan field stops production. [Want to know how global LNG demand impacts North American fundamentals? To find out, subscribe to LNG Insight.] Woodside Petroleum Ltd. is also expected to give the Scarbrough natural gas field the greenlight. The field would feed a second expansion train at the Pluto LNG terminal in Western Australia. Request Information about NGI's Price Index Data “Woodside will sanction the project without contracting any additional LNG, taking on exposure to the spot LNG price,” Toleman said. “This is a bold strategy which allows them to take advantage of strengthening near-term market fundamentals.” Wood Mackenzie also expects Australian Industrial Energy to sanction the Port Kembla natural gas import terminal to supply the East Coast market. FID is expected in 1Q2021, the firm said. LNG imports will become the marginal cost of supply in the country, the firm said, adding that domestic prices would rise as they move towards global LNG prices, including the cost of regasification. “This is positive news for upstream players with uncontracted gas.” Last year marked a record increase in global LNG production, driven primarily by new liquefaction trains and supply ramp-ups in Australia, Russia and the United States, according to the International Group of Liquefied Natural Gas Importers (GIIGNL). The group said LNG production grew by 13% year/year in 2019 to 354.7 million tons (Mt). Australia was the second largest LNG producer in the world with 75.39 Mt of production, behind Qatar, which had 77.80 Mt, according to GIIGNL. The United States was the third largest LNG producer with 33.75 Mt.
Norway supreme court verdict opens Arctic to more oil drilling (Reuters) - Norway’s supreme court upheld government plans for Arctic oil exploration on Tuesday, dismissing a lawsuit by campaigners who said they violated people’s right to a healthy environment. While most of Norway’s oil output flows from south of the Arctic, the government believes the greatest untapped potential lies in the Barents Sea off Europe’s northernmost coast. Tuesday’s verdict upheld rulings by two lower courts, rejecting arguments by Greenpeace and the Nature and Youth group that a 2015-2016 oil licensing round giving awards to Equinor and others had breached Norway’s constitution. While the case was specifically about ten exploration licenses awarded four years ago, the campaigners had hoped that their appeal would set a precedent limiting the oil industry’s Arctic expansion. Norway is western Europe’s largest oil and gas producer, with a daily output of around 4 million barrels of oil equivalent. “The supreme court is rejecting the appeal,” Chief Justice Toril Marie Oeie said as she announced the verdict, which saw 11 of the 15 judge panel rule in favour of the government, while 4 said the environmental groups should have won. “This means today’s youth lacks fundamental legal protection from environmental damage jeopardising our future... This is shocking and we are furious,” the Nature and Youth group said on Twitter in response to the ruling. The plaintiffs said pumping more oil would lead to increased climate-warming carbon dioxide emissions and ultimately violate Norway’s constitution as well as its commitments under the Paris climate agreement and the European Convention on Human Rights. The majority concluded, however, that parliament and the government had broad authority to award new oil acreage. “A broad majority in parliament has repeatedly rejected proposals to end Norwegian oil extraction,” the judges said. The Ministry of Energy and Petroleum has announced plans for another round of Arctic licensing awards, setting an application deadline for early next year.
Russia admits to worlds largest Arctic oil spill - Some 21,000 tons of oil poured into the surrounding ground and waterways after a diesel oil tank belonging to a subsidiary of Russian metals giant Nornickel collapsed on May 29. Kirill Kukhmar / TASS Russian authorities said the fuel spill at an Arctic power station earlier in 2020 was the largest in world history, a top emergencies official said Thursday. Some 21,000 tons of oil poured into the surrounding ground and waterways near the city of Norilsk after a diesel oil tank belonging to a subsidiary of Russian metals giant Nornickel collapsed on May 29. “Such an amount of liquid diesel fuel has never been spilled in the history of mankind,” the state-run RIA Novosti news agency quoted Deputy Emergency Minister Alexander Chupriyan as telling reporters. “We already trapped [the fuel] in the Arctic zone,” he said.A team of Nornickel-funded scientists, meanwhile, struck a more optimistic tone with their discovery of the five polluted rivers’ self-cleaning abilities, according to their final report cited by the state-run TASS news agency Wednesday.“The microflora in the studied waters has adapted to oil products and is able to participate in their decomposition,” said members of the so-called Great Norilsk Expedition organized by the Siberian Branch of the Russian Academy of Sciences in August.Nornickel is currently contesting a $2 billion damages claim with Russia’s state environmental watchdog. A different Nornickel-commissioned report said last month that the oil spill was “inevitable” due to design flaws, management failures and rising temperatures in the region.
Russia's crude oil exports drop 10% in January-October -- Due to lower demand and the OPEC+ deal, Russia’s crude oil exports declined by 10.4 percent in volume year over year in January to October, data from the Russian federal customs, cited by local cargo analytics outlet SeaNews, showed. The value of Russia’s crude oil exports plunged by more than 40 percent in the same period due to the lower oil prices compared to the average price of oil in the first ten months of 2019. The value of Russian crude oil exports plummeted by 40.6 percent between January and October 2020, and stood at US$60.326 billion, according to data from the Russian federal customs service. In October 2020 alone, the amount of Russian crude oil exports fell by 25.3 percent compared to October 2019, and dropped 0.9 percent compared to September 2020. The value of Russian crude exports plunged by 51.9 percent annually in October, in which the exports were worth US$5.13 billion. For most of January through October 2020, Russia was part of the OPEC+ agreement to curtail supply, except in March and early April, when Russia and Saudi Arabia disagreed on how to manage oil supply to the market when demand was crashing due to the pandemic. The current production cuts began in May 2020 and are much deeper than in the previous deal. After nearly a week of debates early this month, the OPEC+ group decided it would ease the current cuts by 500,000 barrels per day (bpd) from January, so the OPEC+ production cuts would stand at 7.2 million bpd, instead of 7.7 million bpd. Ministers of the OPEC+ pact will be meeting monthly to assess the situation on the market and decide on production policy for the following month. The next ministerial meeting is slated for January 4. Despite renewed fears about oil demand due to the new coronavirus strain, the leader of the non-OPEC group in the OPEC+ pact, Russia, is reportedly still in favor of another 500,000 bpd increase in the alliance’s oil production from February.
Iran welcomes Russian investment in oil sector- Zanganeh - Iranian Oil Minister Bijan Namdar Zanganeh said his country welcomes the Russian companies’ investment making in its oil sector, Shana reported. The minister made the remarks after his meeting with the Russia Deputy Prime Minister Alexander Novak and Energy Minister Nikolai Shulginov in Moscow at Monday night. Saying that the expansion of bilateral relations has been one of the major subject discussed during his meeting with the Russian side, the minister reiterated, “We have a good cooperation with the Russian companies, and this cooperation is going to be increased in the fields of oil and gas and related equipment.” "We recognize Russia as a strategic partner, and this partnership is not something that can be changed in a warm or cold atmosphere in the international arena," Zanganeh said, adding, “If the Russian companies want to work in Iran, they must become partner with Iranian companies and make the most use of Iranian capacities through negotiation with their Iranian counterparts to achieve the desired results.” The Iranian oil minister continued: "Iran's ambassador to Russia and his colleagues at the embassy were supposed to follow the agreements. If it were not for the coronavirus pandemic, they could have done it very simply, but in the current situation, we can establish communication by observing the health protocols."
Oil prices fall amid worries over new coronavirus strain Oil prices slid in early trade on Monday as a fast-spreading new coronavirus strain in the United Kingdom raised concerns that tighter restrictions there and in other European countries could stall a recovery in the global economy and its need for fuel. Brent crude dropped 97 cents, or 1.9%, to $51.29 a barrel by 0103 GMT after rising 1.5% and touching its highest since March last Friday. U.S. West Texas Intermediate (WTI) crude was down 83 cents, or 1.7%, to $48.27 a barrel after also climbing 1.5% on Friday to its highest level since February. Monday's declines came after oil prices marked seven straight weeks of gains last week as investors focused on the rollout of Covid-19 vaccines. "A new variant of the coronavirus in Britain and tighter travel restrictions in Europe sparked fears over slower economic recovery, prompting investors to unwind long positions," said Kazuhiko Saito, chief analyst at commodities broker Fujitomi Co. "The oil market has been on a bull trend in the past month or so, ignoring negative factors, amid an optimism that a widening vaccine rollout would revive global growth, but investors' rosy expectations for 2021 have suddenly vanished," Saito said. British Prime Minister Boris Johnson will chair an emergency response meeting on Monday to discuss international travel, in particular the flow of freight in and out of Britain as Covid-19 cases surged by a record number for one day. The headache comes as Johnson also seeks to hammer out a final accord on Brexit. The variant, which officials say is up to 70% more transmissible than the original, also prompted concerns about a wider spread, forcing several European countries to begin closing their doors to travelers from the United Kingdom. The negative sentiment also overshadowed a weekend deal among U.S. congressional leaders for a $900 billion coronavirus aid package. Adding to pressure, the oil and gas rig count, an early indicator of future output, rose by eight to 346 in the week to Dec. 18, the highest since May, Baker Hughes said on Friday, as producers keep returning to the wellpad with crude prices trading above $45 a barrel since late November.
Oil tumbles as new virus strain revives demand fears (Reuters) - Oil prices tumbled nearly 3% on Monday as a fast-spreading new coronavirus strain that has shut down much of Britain and led to tighter restrictions in Europe sparked worries about a slower recovery in fuel demand. Brent crude settled down $1.35, or 2.6%, at $50.91 a barrel, while U.S. West Texas Intermediate (WTI) crude for delivery in January ended the session $1.36, or 2.8%, lower at $47.74 ahead of expiry. The more active February WTI contract fell $1.27, or 2.6%, to settle at $47.97 a barrel. Both contracts had lost as much as $3 earlier in the session, their biggest daily drop in six months. The strength in the U.S. dollar also weighed on oil markets. A strong greenback makes dollar-denominated commodities like crude oil more expensive to holders of other currencies. “Reports of a new strain of the coronavirus have weighed on risk sentiment and oil. New mobility restrictions across Europe are also not helping as European oil demand will suffer,” Brent climbed above $50 last week for the first time since March, buoyed by optimism stemming from COVID-19 vaccines. But a new COVID-19 strain, said to be up to 70% more transmissible than the original, has renewed fears about the virus, which has killed about 1.7 million people worldwide. More countries closed their borders to Britain on Monday, causing travel chaos and raising the prospect of UK food shortages. “The new strain of the coronavirus in the UK has shown us that the vaccine optimism holding Brent above $50 per barrel could be deflated in a fleeting moment,” The new virus strain has already been detected in other countries, including Australia, the Netherlands and Italy. Russian Deputy Prime Minister Alexander Novak said the new strain had an impact on oil prices, adding that recovery of global oil markets was happening more slowly than previously expected and could take two to three years. “Travel restrictions over the next several weeks will complicate OPEC+ plans to gradually raise output,” said Edward Moya, senior market analyst at OANDA in New York. “The monthly meetings will be very tense and keep oil prices volatile until the virus spread is under control across both Europe and the U.S.” The negative sentiment largely overshadowed the rollout of a new vaccine in the United States, a deal among U.S. congressional leaders for a $900 billion coronavirus aid package and European regulatory approval on Monday for the use of the COVID-19 vaccine jointly developed by U.S. company Pfizer Inc and its German partner, BioNTech. The approval by Europe’s medicines regulator puts the region on course to start inoculations within a week.
Oil Rally Unravels On New COVID-19 Lockdowns -Oil sentiment turned negative as near-term problems with demand have finally moved to the front burner after weeks of increasingly bullish sentiment. Dozens of countries cut off travel to the UK over fears of a coronavirus mutation. Lockdowns have also grown tighter in multiple places in December. “The nightmare before Christmas scenario has set in, with a combination of the ‘mutant virus’ compounded by Brexit angst,” saidStephen Innes, chief market strategist at Axi. Goldman sees $65 oil. Despite the current challenges, Goldman is bullish on oil, expecting Brent to average $65 a barrel next year.Congress’ The $900 Covid-19 stimulus, combined with the omnibus spending bill, contained an array of energy-related provisions. The bill authorized $35 billion on a variety of renewable technologies over the next five years, and it extended tax credits. The U.S. Chamber of Commerce called it the most significant energy bill since 2007. The legislation also included a phase out of hydrofluorocarbons (HFCs), a highly potent greenhouse gas found in refrigerants. With little fanfare, the U.S. legislated the most significant action on climate change in years. . Despite renewed fears about oil demand due to the new coronavirus strain, the leader of the non-OPEC group in the OPEC+ pact, Russia, is still in favor of another 500,000 bpd increase in the alliance’s oil production from February. The long-distance Trans Mountain Expansion pipeline project, which would add a twin line to carry oil from Alberta to Canada’s Pacific Coast, has run into some trouble in recent weeks. Several safety mishaps, including the death of a worker, have forced the company to suspend work for the rest of the year.. Enbridge confirmed that a contractor working on Line 3 construction in Minnesota died in an accident on Friday. . Oil inventories at the Cushing hub declined to around 60 million barrels recently, heading towards normal levels.
Oil slides 2% as growing Covid case count weighs on demand projections - Oil dropped towards $50 a barrel on Tuesday, adding to losses from the previous session, as a mutant variant of the coronavirus in Britain revived concerns over demand recovery. Detection of the new variant prompted several countries to close their borders to Britain. The BBC cited France's Europe Minister as saying that the two countries would announce a deal to restart freight by Wednesday. Brent crude fell 83 cents, or 1.63%, to $50.08 per barrel, while West Texas Intermediate (WTI) crude settled 95 cents, or 2%, lower at $47.02 per barrel. Both benchmarks slid nearly 3% on Monday, partly erasing recent gains driven by the rollout of COVID-19 vaccines, seen as key to allowing a return to normal life. The latest rally culminated in Brent hitting $52.48, its highest since March, on Friday. Prices have then come down amid concerns about the virus spreading. Some see potential for prices to fall further. "The holiday malaise has set in on oil," said Phil Flynn, senior analyst at Price Futures Group in Chicago. "Now that we have stimulus done, and we still have concerns about the new strain of virus, people are heading to the sidelines," he said. Oil gained support from U.S. Congress approval of a $892 billion coronavirus aid package after months of inaction. In focus will be the latest U.S. oil inventory reports, expected to show crude stocks fell by 3.3 million barrels. The American Petroleum Institute's report is due at 2130 GMT. The Organization of the Petroleum Exporting Countries and allies, a group known as OPEC+, are set to boost output by 500,000 barrels per day in January. There is no sign yet of any wavering induced by the price drop. Russian Deputy Prime Minister Alexander Novak on Monday said the rise in output should not result in a glut.
Oil Down Again As Covid Mutation Extends Demand Worries - Ship & Bunker --Despite it not affecting the dissemination of the vaccines or their efficacy, a mutation of the Covid virus in Britain once again caused traders to worry about demand recovery and propel two key benchmarks downward for a second session on Tuesday, albeit less severely. Brent declined 83 cents, or 1.6 percent, at $50.08 per barrel, while West Texas Intermediate fell 95 cents, or 2 percent, to settle at $47.02. Stephen Innes, chief market strategist at Axi, said the oil market had been overbought and "The nightmare before Christmas scenario has set in, with a combination of the 'mutant virus' compounded by Brexit angst." Innes was referring to doubts over whether UK prime minister Boris Johnson can secure a post-Brexit trade deal with the European Union. Reuters followed through with a particularly downbeat story suggesting that hope for the end of the pandemic has been oversold and that the current gasoline refining margin of $9.52 per barrel "is lower than all but two of the last 10 years for this time of year." The news agency warned that the current price declines could spur hedge funds to unload positions and that June barrels trading nearly 80 cents per barrel higher than December barrels "suggests oversupply could return by the end of next year." But despite the media hoopla over the Covid mutation (which scientists insist isn't particularly remarkable and won't obstruct the herd immunity that the vaccines will achieve by summer of 2021) and much made of other countries closing travel to Britain, good news on Tuesday came in the form of France's Europe minister saying his country and the UK would announce a deal to restart freight by Wednesday. Also, the U.S. Congress passed the second-biggest economic rescue package in American history as part of a massive $2.3-trillion year-end spending bill, which may support oil prices somewhat until the vaccines produce their desired effect. Still, Tuesday demonstrated the hypersensitivity of the energy community during these Covid crazed times, and Pavel Molchanov, energy research analyst at Raymond James & Associates Inc., also suggested that policy makers have overreacted to the Covid mutation: "This sudden, panicked action by government around the world points to the risk of even more widespread lockdowns and travel restrictions well into the new year."
Oil prices drop amid curb on air travels -Oil prices drifted lower at the mid-week trading session in London. The plunge in crude oil prices is largely due to a surge in U.S. crude oil stockpiles and the travel restrictions put in place to limit a new mutant strain of the COVID-19 virus, putting pressure on already weak fuel demand. At the time of writing this report, Brent oil futures were down by 1.06% to $49.30 thereby dropping below the $50 mark. West Texas Intermediate futures lost over 1.5% to trade at $46.23. Tuesday’s data from the American Petroleum Institute printed a gain of 2.7 million barrels in U.S. crude oil supply for the week ending Dec. 18. The build was larger than the 3.25-million-barrel draw in forecasts prepared by energy experts and the previous week’s build of 1.973 million barrels. In a note to Nairametrics, Stephen Innes, Chief Global Market Strategist at Axi, spoke on recent market fundamentals prevailing in the oil market: “And rubbing salt in the oil market wounds today, oil prices lurched lower, after yet another inventory build that was very much bearish to a consensus to what was penciled in by analysts.Oil traded lower again overnight with worries over the new virus variant and restricted mobility in most of Europe as demand fear resurfaces travel restrictions. And to assume this could be an isolated UK event might be unwise.”The oil cartel is expected to ensure that its crude oil production capacity meets the prevailing energy demand. However, the present situation highlights oil bears having a grip on the black liquid hydrocarbon market, at least for the near term until the COVID-19 caseloads get subdued.
Oil jumps more than 2% after U.S. inventory draw - Oil prices rose more than 2% on Wednesday, boosted by draws in U.S. inventories of crude, gasoline and distillates that lifted investors' hopes for some return in fuel demand. Brent crude futures gained $1.12, or 2.24%, to settle at $51.20 per barrel, while West Texas Intermediate (WTI) crude futures settled 2.34%, or $1.10, higher at $48.12 per barrel. U.S. crude inventories fell by 562,000 barrels in the week to Dec. 18 to 499.5 million barrels, the Energy Information Administration said on Wednesday. Gasoline stocks fell by a surprise 1.1 million barrels in the week to 237.8 million barrels, the EIA said, while distillate stockpiles fell by 2.3 million barrels in the week to 148.9 million barrels, more than expected. "Overall, what this report reflects is that we're starting to see continued improvement in demand," said Phil Flynn, senior analyst at Price Futures Group in Chicago. "It reflects that we're seeing a market that's getting more in balance." A falling U.S. dollar also supported prices. A weak greenback makes dollar-denominated commodities such as crude oil cheaper to holders of other currencies. Investors also kept an eye on Nigeria, where supply disruptions helped lift prices. Exxon Mobil Corp issued a force majeure on the Qua Iboe crude oil export terminal last week after a fire hit the facility and injured two workers. A source told Reuters production is expected to resume in early January. The stream was expected to load about 180,000 barrels per day (bpd) in December and 150,000 bpd in January. Still, oil markets remain jittery about the future recovery of oil demand as a new, highly infectious variant of the novel coronavirus has hit Britain, prompting a slew of countries to shut their borders to the country. The number of Americans filing first-time claims for unemployment benefits unexpectedly fell last week, though remained elevated as more businesses faced restrictions and consumers hunkered down amid rising COVID-19 cases.
Oil jumps more than 2% after U.S. inventory draw - Oil prices rose more than 2% on Wednesday, boosted by draws in U.S. inventories of crude, gasoline and distillates that lifted investors' hopes for some return in fuel demand. Brent crude futures gained $1.12, or 2.24%, to settle at $51.20 per barrel, while West Texas Intermediate (WTI) crude futures settled 2.34%, or $1.10, higher at $48.12 per barrel. U.S. crude inventories fell by 562,000 barrels in the week to Dec. 18 to 499.5 million barrels, the Energy Information Administration said on Wednesday. Gasoline stocks fell by a surprise 1.1 million barrels in the week to 237.8 million barrels, the EIA said, while distillate stockpiles fell by 2.3 million barrels in the week to 148.9 million barrels, more than expected. "Overall, what this report reflects is that we're starting to see continued improvement in demand," "It reflects that we're seeing a market that's getting more in balance." A falling U.S. dollar also supported prices. A weak greenback makes dollar-denominated commodities such as crude oil cheaper to holders of other currencies. Investors also kept an eye on Nigeria, where supply disruptions helped lift prices. Exxon Mobil Corp issued a force majeure on the Qua Iboe crude oil export terminal last week after a fire hit the facility and injured two workers. A source told Reuters production is expected to resume in early January. The stream was expected to load about 180,000 barrels per day (bpd) in December and 150,000 bpd in January. Still, oil markets remain jittery about the future recovery of oil demand as a new, highly infectious variant of the novel coronavirus has hit Britain, prompting a slew of countries to shut their borders to the country. The number of Americans filing first-time claims for unemployment benefits unexpectedly fell last week, though remained elevated as more businesses faced restrictions and consumers hunkered down amid rising COVID-19 cases.
Oil moves higher on Brexit deal, U.S. inventory draw - Oil prices moved higher on Thursday as news that Britain and the European Union had signed a post-Brexit trade deal, as well as a draw in U.S. inventory sparked optimism. U.S West Texas Intermediate (WTI) crude gained 11 cents, or 0.23%, to trade at $48.23 per barrel, while Brent crude futures advanced 10 cents, or 0.2%, to $51.30 per barrel. Volumes were light on the last trading day before the Christmas holiday. Both contracts gained more than 2% on Wednesday. By clinching a Brexit trade deal, Britain avoids a chaotic departure from one of the world's biggest trading blocs, a move many investors warned would have sparked further volatility in financial markets. "While the Brexit deal is supportive, the impact of COVID is the dominant driver in the oil market," said Andrew Lipow, president of Lipow Oil Associates, in Houston, Texas. "Like everyone else the oil market is waiting for the wider distribution of vaccines to get the public back on the road and in the air." U.S. stockpiles fell in the most recent week in what some hoped was a signal that demand would recover after a torrid year in which gasoline and jet fuel consumption plummeted as a result of the pandemic. U.S. crude inventories fell by 562,000 barrels in the week to Dec. 18, according to government data, while gasoline and distillate stockpiles also fell. However, new strains of the coronavirus, which appear to spread the disease more quickly, have hit the United Kingdom, Nigeria, and other countries. "Lingering worries over a new variant of the novel coronavirus capped gains," said Hiroyuki Kikukawa, general manager of research at Nissan Securities. At least four drugmakers expect their COVID-19 vaccines will be effective against the new fast-spreading variant of the virus that is raging in Britain, and are performing tests that should provide confirmation in a few weeks.
Oil prices edge higher, but log first weekly fall in 2 months in Christmas Eve trade -Crude-oil futures settled slightly higher Thursday amid light-trading volumes in the last trading session before Christmas, with investors watching whether a U.S. fiscal package will be signed into law by President Trump. Commodity investors have fretted that a resurgence in the COVID-19 pandemic in the U.S. and Europe in particular will hurt demand for energy without sufficient aid from the government to stem the economic harm from restrictions on consumer and business activity. "We do need to get some kind of stimulus or if the government gets shutdown we could see losses" accelerate, Tariq Zahir, managing member at Tyche Capital Advisors, told MarketWatch, referencing the coronavirus aid package that is rolled into the funding bill for U.S. government that was passed by Congress on Monday but is being held up by President Trump. President Donald Trump has raised the possibility of a veto of a long-sought-after fiscal spending package, after he vetoed a $740.5 billion defense-policy bill on Wednesday and demanded last-minute changes (link) to coronavirus-relief legislation. The president is asking for the increase of direct payments to individuals to $2,000 from $600. However, Republicans in the House defied the president (link)and blocked a bill put forward by Democrats that would have increased those direct payments as part of the coronavirus financial-aid package.Also on Thursday, Britain and the European Union cemented an agreement (link) that would avoid the U.K. leaving the trade bloc without a pact, helping support higher oil prices. On Wednesday, oil markets took a slightly more bullish turn after the Energy Information Administration reported a fall of 562,000 barrels in U.S. crude inventories for the week ended Dec. 18, contrasting with an earlier report from the less closely followed American Petroleum Institute late Tuesday that showed that U.S. crude supplies rose by 2.7 million barrels for the week. Still, the decline in inventories was less than the average of 4.7 million barrels forecast by analysts polled by S&P Global Platts. Meanwhile, Baker Hughes on Wednesday, reporting two days early because of the Christmas holiday, showed that the number of active U.S. rigs drilling for oil rose by 1 to 264 this week, marking a fifth straight weekly rise in oil-rig counts. The total active U.S. rig count, which includes those drilling for natural gas, was also up by 2 to 348. West Texas Intermediate crude for February delivery closed 11 cents, or 0.2%, higher at $48.23 a barrel, after notching a 2.3% gain on Wednesday. February Brent crude finished up 9 cents, or 0.2%, to settle at $51.29 a barrel, after the contract rose 2.2% Wednesday on ICE Futures Europe. For the week, WTI lost 2.1%, while Brent recorded a weekly decline of 1.9%, . Both contracts marked their first weekly loss since the week ended Oct. 30, Dow Jones Market Data show. Natural gas for January delivery settled at $2.5180 per million British thermal units, down 9 cents, on Thursday, or 3.5%, also booking a weekly drop of 6.7%.
US Navy Sails Nuclear Submarine Through Straits of Hormuz - The US Navy nuclear-powered guided-missile submarine USS Georgia transited the Strait of Hormuz Monday accompanied by two additional American warships, the Navy said Monday in a rare public announcement of a nuclear submarine's movements. "The nuclear-power Ohio-class guided-missile submarine USS Georgia (SSGN 729), along with the guided-missile cruisers USS Port Royal (CG 73) and USS Philippine Sea (CG 58), transited the Strait of Hormuz entering the Arabian Gulf, Dec. 21," the Navy said in a statement using an alternative name for the Persian Gulf. The vessels' entrance into the area comes amid heightened tensions with Iran, with Secretary of State Mike Pompeo blaming Iranian backed militias for a rocket attack on the US Embassy compound in Baghdad, on Sunday. Some US officials have expressed concern that Iran may use the anniversary of the killing of General Qasem Solemani to carry out a strike on the US. The US Navy rarely discusses the movement of its submarines, but Monday's announcement also included details on the vessel's capabilities, including its "ability to carry up to 154 Tomahawk land-attack cruise missiles."
Israel's government collapses, not with a bang but a whimper, triggering fourth election in 2 years - The Israeli government collapsed on Tuesday at midnight (17.00 EST) local time after the country's parliament failed to meet a deadline for passage of the 2020 and 2021 budgets. Israel will now head to its fourth elections in two years, probably on March 23 next year. Prime Minister Benjamin Netanyahu and his erstwhile coalition partner, Blue and White leader Benny Gantz, sought to blame one another for the collapse of their seven-month-old government. "Blue and White withdrew from the agreements [to modify the original coalition agreement] and dragged us to unnecessary elections during the corona crisis," said Netanyahu, who on Saturday evening became the first Israeli to receive the Covid-19 vaccine. "We do not want an election and we voted against it ... but we are not afraid of elections -- because we will win!" Gantz, referencing the corruption charges facing Netanyahu, said: "I regret that the Prime Minister is preoccupied with his trial and not the public interest, and is prepared to drag the entire country into a period of uncertainty, instead of ensuring economic stability and a rehabilitation of the economy." After three inconclusive elections, and with the first wave of the coronavirus pandemic underway, Gantz agreed to join Netanyahu in April, in what was described as an "emergency" coalition government - even though he'd campaigned on a platform that ruled out sitting with the Prime Minister while he faced corruption charges. Under the deal, the prime ministership would have been rotated between the two party leaders: Netanyahu would serve first, and then give way to Gantz after 18 months. The only loophole in the complicated deal was if lawmakers failed to agree to a budget before Tuesday's midnight deadline -- a failure that has now come to pass. The fate of the government had appeared sealed after the Knesset failed in the early hours of Tuesday to pass a bill at first reading that would have extended the deadline for reaching a budget agreement. Opposition leader Yair Lapid -- who campaigned with Gantz at the last election, but withdrew his party's support when Gantz joined forces with Netanyahu -- addressed the Israeli leader in the Knesset on Monday evening: "Mr. Prime Minister, who are you kidding? You don't care about the mutation [of coronavirus]. You only care about the rotation [of the prime ministership]." Opinion polls suggest Netanyahu's Likud party is again on track to win the most Knesset seats in the next election. With Blue and White hemorrhaging support, his biggest rivals would appear to come from other right-wing parties, which have been gaining ground on Israel's longest serving leader.
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