record drops in US oil output, US oil exports, & distillates' output; 2nd largest natural gas supply drop on record; oil prices highest since 2019..

natural gas supplies see 2nd largest drop on record as US burns 15% of inventories in one week; oil prices hit highest since 2019 as US oil exports drop most on record, oil production drop matches record; distillates' output drops most on record to an 11 year low; oil refining and distillate exports drop most since Hurricane Harvey; refinery utilization at a 40 month low; gasoline output falls by most in 46 weeks to lowest in 38 weeks; gasoline demand falls most in 43 weeks to a 39 week low...

oil prices moved higher this week as US oil output remained sharply curtailed in the wake of freeze damage to Texas production...after falling fractionally to $59.24 a barrel last week after the Texas freeze shut down US refineries and reduced demand for oil, the contract price of US light sweet crude for March delivery opened higher on Monday, the last day of trading for that contract, as the slow return to normal served as a reminder of the tight supply situation before the deep freeze, and climbed nearly 4% on news that damaged installations on between 2 million to 4 million barrels per day of oil output could be kept offline longer than expected to close $2.25, or 3.8% higher at $61.49 a barrel, while the more widely-traded April oil contract was up $2.44, or 4.1%, at 61.70 a barrel...with the contract price of US light sweet crude for April delivery now being quoted, oil prices jumped by more than $1 early on Tuesday and briefly hit $63 a barrel on reports that southern US shale oil producers would take at least two weeks to restart more than 2 million barrels per day of crude output, as frozen pipes and power supply interruptions slowed their recovery but reversed and settled 3 cents lower at $61.67 a barrel as concerns about the pace of the U.S. economic recover kept gains in check...oil prices then tumbled Tuesday evening after the API reported a surprise increase in US crude and gasoline inventories and thus opened 38 cents lower on Wednesday, but rallied after EIA data showed a big drop in crude output after the freeze had disrupted production last week and closed $1.55 higher at a 13 month high of $63.22 a barrel...oil prices were mixed on Thursday, with U.S. crude edging up while global prices fell as Texas refineries restarted production after last week’s freeze and US prices settled 31 cents higher at $63.53 a barrel, their highest close since 2019, on assurances from the Fed that U.S. interest rates would remain low...but oil prices tumbled on Friday as a collapse in bond prices led to gains in the U.S. dollar, driving oil prices lower and as expectations grew that with oil prices at pre-pandemic highs, more supply would come back to the market, with US crude settling $2.03 lower at $61.50 a barrel, but still posting a 3.8% gain on the week and an 18% increase for the month..

on the other hand, natural gas prices fell every day this week as production resumed and temperatures moderated....after rising 5.4% to $3.069 per mmBTU last week as demand for heating far outstripped the freeze-off curtailed supply, the contract price of natural gas for March delivery opened nearly 6 cents lower on Monday and tumbled to an 11.6 cent loss at $2.953 per mmBTU as production appeared to be quickly recovering from the Arctic blast, and warming weather models provided a headwind to prices...natural gas prices fell another 7.4 cents on Tuesday as warmer weather allowed producers to return more wells to service and restart pipelines that had been frozen during last week’s extreme cold, and then fell another 2.5 cents on warmer weather on Wednesday, as trading in the March contract expired with natural gas priced at a two week low of $2.854 per mmBTU....the natural gas contract for April delivery, which had ended last week priced at $2.991 per mmBTU and fallen to $2.795 per mmBTU by Wednesday close, fell another 1.8 cents to $2.777 per mmBTU on Thursday, as last week's withdrawal of natural gas from storage failed to surpass the record 359 billion cubic feet draw reported by EIA in January 2018...April gas prices held steady through most of Friday on increasingly warm weather outlooks for March, and ended 0.6 cents lower at $2.771 per mmBTU, the seventh lower close in a row, as the April contract finished 7.4% lower on the week, while the benchmark natural gas price still managed to climb 8% for the month ...

the natural gas storage report from the EIA for the week ending February 19th indicated that the amount of natural gas held in underground storage in the US fell by 338 billion cubic feet to 1,943 billion cubic feet by the end of the week, which left our gas supplies 298 billion cubic feet, or 13.3% below the 2,241 billion cubic feet that were in storage on February 19th of last year, and 161 billion cubic feet, or 7.7% below the five-year average of 2,104 billion cubic feet of natural gas that have been in storage as of the 19th of February in recent years....the 338 billion cubic feet that were drawn out of US natural gas storage this week was the 2nd largest withdrawal on record, and was more than the average forecast of a 333 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, and was more than double the 145 billion cubic foot withdrawal from natural gas storage seen during the corresponding week of a year earlier, as well as the average withdrawal of 120 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...  

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending February 19th indicated that because the big drops in our oil exports and our oil refining associated with last week's freeze off were greater than the big drops in our oil production and oil imports, we had a small surplus of oil left to add to our stored commercial crude supplies for the third time in the past fourteen weeks and for the 13th time in the past thirty-seven weeks.... our imports of crude oil fell by an average of 1,299,000 barrels per day to an average of 4,599,000 barrels per day, the largest drop in 32 weeks, after rising by an average of 41,000 barrels per day during the prior week, while our exports of crude oil fell by a record average of 1,548,000 barrels per day to 2,314,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,285,000 barrels of per day during the week ending February 19th, 249,000 more barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells decreased by a record 1,100,000 barrels per day to 9,700,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 11,985,000 barrels per day during this reporting week... 

meanwhile, US oil refineries reported they were processing 12,230,000 barrels of crude per day during the week ending February 19th, 2,589,000 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 184,000 barrels of oil per day were being added to the supplies of oil stored in the US....so looking at that data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 429,000 barrels per day less than what what was added to storage plus what our oil refineries reported they used during the week....to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+429,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed....however, since most everyone treats these weekly EIA figures as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we'll continue to report them as published, just as they're watched & believed to be accurate by most everyone in the industry.....(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,715,000 barrels per day last week, which was 13.3% less than the 6,589,000 barrel per day average that we were importing over the same four-week period last year.....the 184,000 barrel per day addition to our total crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported to be 1,100,000 barrels per day lower at 9,700,000 barrels per day, matching the largest drop on record, because the rounded estimate of the output from wells in the lower 48 states was 1,100,000 barrels per day lower at 9,200,000 barrels per day, while a 17,000 barrel per day decrease to 481,000 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 February 21st was rounded to 13,000,000 barrels per day, so this reporting week's rounded oil production figure was 25.4% below that of a year ago, yet still 15.1% above 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 68.6% of their capacity while using those 12,230,000 barrels of crude per day during the week ending February 19th, down from 83.1% of capacity during the prior week, and among the lowest refinery utilization rates in the last 30 years...hence, the 12,230,000 barrels per day of oil that were refined this week were 23.6% fewer barrels than the 16,008,000 barrels of crude that were being processed daily during the week ending February 21st of last year, when US refineries were operating at an also low 87.9% of capacity...

with the drop in the amount of oil being refined, the gasoline output from our refineries was lower for the 9th time in 14 weeks, decreasing by 1,295,000 barrels per day to 7,736,000 barrels per day during the week ending February 19th, after our gasoline output had increased by 375,000 barrels per day over the prior week...with that drop in production, this week's gasoline output was 21.0% lower than the 9,797,000 barrels of gasoline that were being produced daily over the same week of last year....meanwhile, our refineries' production of distillate fuels (diesel fuel and heat oil) decreased by a record 953,000 barrels per day to an eleven year low of 3,621,000 barrels per day, after our distillates output had decreased by 86,000 barrels per day over the prior week...with distillates' production thus depressed, that output was 25.3% less than the 4,846,000 barrels of distillates that were being produced daily during the week ending February 21st, 2020...

even with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 12th time in fifteen weeks, and for 15th time in 31 weeks, but was up by just 12,000 barrels to 257,096,000 barrels during the week ending February 19th, after our gasoline inventories had increased by 672,000 barrels over the prior week...our gasoline supplies increased this week despite the production drop because the amount of gasoline supplied to US users decreased by 2,200,000 barrels per day to a nine month low of 7,207,000 barrels per day, even as our imports of gasoline fell by 139,000 barrels per day to 531,000 barrels per day, while our exports of gasoline fell by 59,000 barrels per day to 517,000 barrels per day.....after this week's inventory increase, our gasoline supplies were 0.3% higher than last February 21st's gasoline inventories of 256,387,000 barrels, and about 1% above the five year average of our gasoline supplies for this time of the year... 

meanwhile, with the record decrease in our distillates production, our supplies of distillate fuels decreased for the 18th time in 26 weeks and for the 29th time in the past year, falling by 4,969,000 barrels to 152,715,000 barrels during the week ending February 19th, after our distillates supplies had decreased by 3,422,000 barrels during the prior week....our distillates supplies fell by more this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 522,000 barrels per day to 3,932,000 barrels per day, and even though our exports of distillates fell by 270,000 barrels per day to a 41 month low of 701,000 barrels per day, while our imports of distillates fell by 59,000 barrels per day to 303,000 barrels per day...but even after this week's inventory decrease, our distillate supplies at the end of the week were still 10.3% above the 138,472,000 barrels of distillates that we had in storage on February 21st, 2020, and about 3% above the five year average of distillates stocks for this time of the year...

finally, with the the big drops in our oil exports and our refinery throughput, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) ended the week higher for the 9th time in the past thirty-one weeks, and for the 29th time in the past year, increasing by 1,285,000 barrels, from 461,757,000 barrels on February 12th to 463,042,000 barrels on February 19th...after that increase, our commercial crude oil inventories remained near the five-year average of crude oil supplies for this time of year, but were about about 36% above the prior 5 year (2011 - 2015) average of our crude oil stocks as of the third weekend of February, 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 jumped to record highs during the lockdowns this spring after generally rising over the past two years, except for during the 10 weeks prior to this one 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 February 19th were 4.4% more than the 443,335,000 barrels of oil we had in commercial storage on February 21st of 2020, 3.8% above the 445,865,000 barrels of oil that we had in storage on February 22nd of 2019, and also 10.1%  more than the 420,479,000 barrels of oil we had in commercial storage on February 16th of 2018...   

This Week's Rig Count

The US rig count rose for the 22nd time over the past 24 weeks during the week ending February 26th, but it still remains down by 49.3% from what it was 50 weeks ago....Baker Hughes reported that the total count of rotary rigs running in the US was up by 5 to 402 rigs this past week, which was still down by 388 rigs from the 790 rigs that were in use as of the February 28th report of 2020, and was also still 2 fewer rigs than the all time low rig count prior to 2020, and 1,527 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 4 rigs to 309 oil rigs this week, after falling by 1 oil rig the prior week, leaving us with 369 fewer oil rigs than were running a year ago, and still less than a fifth 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 1 rig to 92 natural gas rigs, which was still down by 18 natural gas rigs from the 110 natural gas rigs that were drilling a year ago, and just 5.7% 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' continued to drill in Lake County, California this week, while a year ago there were two such "miscellaneous" rigs deployed...

The Gulf of Mexico rig count increased by 1 to 17 rigs this week, with 15 of those rigs now drilling for oil in Louisiana's offshore waters and 2 drilling for oil in Alaminos Canyon offshore from Texas...that was 5 fewer Gulf of Mexico rigs than the 22 rigs drilling in the Gulf a year ago, when 19 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, another rig was drilling for natural gas in the West Delta field 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....while Gulf rig increased this week, the last rig that had been drilling through an inland body of water in southern Louisiana was concurrently shut down, while a year ago there remained one rig drilling on US inland waters..

The count of active horizontal drilling rigs was up by 3 to 359 horizontal rigs this week, which was just over half of the 708 horizontal rigs that were in use in the US on February 28th of last year, and less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...at the same time, the vertical rig count was up by 1 to 25 vertical rigs this week, but those were still down by 11 from the 36 vertical rigs that were operating during the same week a year ago....in addition, the directional rig count was up by 2 rig to 18 directional rigs this week, but those were also down by 28 from the 46 directional rigs that were in use on February 28th of 2020....

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 February 26th, the second column shows the change in the number of working rigs between last week's count (February 19th) and this week's (February 26th) count, the third column shows last week's February 19th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday 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 28th of February, 2020..    

there were just a few fairly straightforward rig changes again this week....checking the details on the Permian in Texas from the Rigs by State file at Baker Hughes, we find that there were 4 new rigs added in Texas Oil District 7C, which includes the southern counties of the Permian Midland basin, while one rig was pulled out of Texas Oil District 8, which corresponds to the core Permian Delaware, and hence there was a net increase of 3 rigs in the Texas Permian....since the national Permian rig count was up by 4, that means that the rig that was added in New Mexico ​must​ have been added in the farthest west reaches of the Permian Delaware, to account for the national Permian increase...meanwhile, that increase of 3 rigs in the Texas Permian also accounts for the entire Texas increase, since there were no other rig count changes elsewhere in Texas...in Louisiana, the offshore rig addition was offset by the oil rig pulled off an inland lake to net the zero change you see above, and the changes in those three states account for all of this week's oil rig activity....meanwhile, all of this week's natural gas rig changes took place in the Marcellus shale, where two natural gas rigs were added in Pennsylvania while one natural gas rig was pulled out of the Marcellus in West Virginia...

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Rail Is Ready for PetChem Hub No. 2 -- With an increasing number of petrochemical and oil & gas experts and industry observers acknowledging the U.S. Gulf Coast cannot be the sole repository for the U.S.’s two expanding industries, the Appalachian Basin is looking like PetChem Hub No. 2. Not only does the Basin contain the Marcellus and Utica Shale plays and thus abundant natural gas and natural gas liquids, but it also contains one of the building blocks for any region hoping to grow its economy: Transportation infrastructure, including rivers, roadways, airports and railways. What the Tri-State region, which includes Pennsylvania, Ohio and West Virginia, offers certainly from a railroad perspective is 150 years of “Iron Horse” history. Unlike many pockets of the U.S. which lack this storied rail network, the Tri-State is blanketed with rail and rail yards, according to Casey Cathcart. “We have a unique situation in these states in that the land traditionally is covered with rail – and has been for well over 125 years,” said Cathcart, Executive Chairman and co-founder with his father, Thomas, of Cathcart Rail, an Ohio-based freight rail services/transportation company established in 2016. Casey will be part of the Infrastructure Panel presenting at the 2nd annual Appalachian Basin Real Estate Conference, an all-day program slated for March 25, at the Oglebay Resort, in Wheeling, West Virginia. The conference is being presented by Shale Directories. “Casey’s participation will provide important freight rail information for our registrants,” commented Joe Barone, President & Founder, Shale Directories. Cathcart has grown from a single railcar contract shop with 18 employees, to a multi-disciplined, rail platform that employs 800 people across 64 locations in 22 states. Cathcart Rail’s subsidiary companies include Appalachian Railcar Services, operator of the largest independent contract shop network in the U.S.; Bucyrus Railcar Repair, operator of the largest repair agent network; and, the Belpre Industrial Parkersburg Railroad, a short line railroad serving international plastics, petrochemicals and metals customers along the Ohio River Corridor, among others.

A trip down the Ohio River reveals the oil and gas industry’s next big move - Facing falling demand for fossil fuels, companies like Shell are betting big on another polluting commodity: plastic. Hit hard by the coronavirus pandemic, Royal Dutch Shell saw its profits drop 71 percentbetween 2019 and 2020. Its recovery will likely be stymied by the rise of electric cars and renewable energy, which will lead to falling demand for oil and, in the US, natural gas. There is one bright spot for the industry, however. Ethane, a natural gas byproduct used to make plastic, is projected to be a growth market.Plastic will figure prominently in the future of the oil and gas sector. A short trip down the Ohio River in Pennsylvania shows what this will look like, and what it will mean for the environment. In Beaver County, near the Ohio border, a sprawling complex of steel and concrete is rising up on the southern bank of the river. In the next couple of years, Shell will use this $6 billion facility to turn fracked ethane gas produced in the region into polyethylene, a type of plastic. A 98-mile pipeline system will deliver up to 100,000 barrels of ethane per day to the “cracker” plant, which will “crack” ethane molecules apart to produce plastic. The plant will be a lifeline to financially struggling drilling companies in Appalachia. Plants like this may be the last best hope for the oil and gas industry. Beyond buoying drillers in the region, however, the plant may do little to boost the local economy. The construction effort has employed some 7,500 people, though many came from Texas or Canada, and jobs are temporary. The factory will employ only around 600 people full-time.The plant also promises to generate a lot of pollution.An WTAE investigation found the cracker plant will be allowed to churn out more pollution than some of the biggest emitters in the state. Its permit allows the plant to produce more than 2 million tons of carbon dioxide each year, as well as more than 500 tons of volatile organic compounds, which cause headaches, nausea and damage to the nervous system. Locals fear the cracker plant will leave a trail of contamination just like the steel mills that came before.“The pollution we have here was caused by previous plants, and now Shell is coming to add more on top of that,” says Bob Schmetzer, the chairman of the Beaver County Marcellus Awareness Community, a local group opposing fracking. “They will make their money, and then they will pack their bags when the money stops coming in, leaving behind the pollution.” In addition to air pollution, the plant will generate a steady stream of hard-to-recycle plastic, most of which will end up as waste.At the Greenstar Recycling plant, just 20 miles south of Shell’s cracker plant, plastic refuse piles up, but this is the tip of the iceberg. In the US, less than 10 percent of plastic is actually recycled. Another 15 percent or so is burned to generate energy. The rest ends up in landfills. Because plastic is so polluting and so unpopular, oil and gas companies are also looking for ways to manage plastic waste. Shell joined the Alliance to End Plastic Waste, a group made up mostly of petrochemical companies, which plans to invest $1.5 billion in minimizing plastic waste and promoting recycling. But critics say such efforts are far too meager.“It’s a trivial amount compared to the costs that are borne by the communities where fracking occurs, waste disposal takes place, and plastics end up in the environment,” says Patricia DeMarco, a Pittsburgh-based environmental consultant. “It makes no sense to produce a plastic bag that is useful for 12 minutes and then remains in the environment for another 450 years.”

Educators, financial officials dispute data in oil and gas industry report — New information on a report released by the Ohio River Valley Institute on the oil and gas industry. The report claims the oil and gas industry has had very little impact on the Ohio Valley's economic prosperity. However, city and school leaders disagree saying the revenue has enabled them to build new facilities. The Ohio River Valley Institute recently released a report with data up to 2019 from the U.S. Bureau of Economic analysis that shows the oil and gas industry contributed to the country's gross domestic product, but the region is getting less in return. "The output grew at three times the rate of the nation's economy, immense growth, but when we looked at the benefits that would normally accrue from that kind of increase, they weren't there,” said Sean O’Leary, senior researcher with the Ohio River Valley Institute. “While output grew by 60 percent, jobs only grew by 1.6 percent and in the 7 eastern counties in Ohio, they actually declined." O'Leary said the region's population declined as well. Mike Chadsey with the Ohio Oil and Gas Association disagrees saying it invested $86 billion into the region pre-pandemic. "We don't think it paints the complete picture of what has happened here in the Ohio Valley,” Chadsey said. “Some are really cherry-picked, data in there. Certain counties were left out, certain job numbers were left out, certain unemployment numbers were left out.” Monroe County has seen a big impact from the industry regarding tax revenue, according to Treasurer Taylor Abbott. "Five or six years ago now, we were collecting not even half of what we are now,” he said. “Now, we are at $180 million in collections. That's a huge change for this county.” And a large portion of that money is going to the Switzerland of Ohio School District. "The district didn’t have a lot of money to spend on extra things for a long time and it was until this new tax revenue mainly from oil and gas,” Monroe Central High School Principal Joe Semple said. "The Utica Shale play, when it came into our area, we're kind of in the middle of it now,” District Career Coordinator Mark Romick said. “It's brought a lot of tax revenue in, we've been able to do a number of different things." Educators say the tax revenue has allowed the district to build a new athletic complex with additional lab classrooms at the Monroe Central campus. Also, new field houses at Beallsville and River high schools and manufacturing equipment upgrades at Swiss Hills Career Center. "This facility, we’ve got about $1.5 million in,” Director Matthew Unger said. “We had upgrades to our welding facility was about a quarter of a million dollars." Despite the improvements, the Ohio River Valley Institute believes the region has received less than what was promised.

Antero Partnering with Quantum to Fund Some Marcellus Development Through 2024 - Appalachian pure-play Antero Resources Corp. has entered a drilling partnership worth up to $550 million with an affiliate of Quantum Energy Partners to fund a portion of its Marcellus and Utica shale development through 2024. Under the deal, QL Capital Partners would fund 20% of Antero’s development capital spending in 2021 and 15-20% from 2022 to 2024 in exchange for a working interest in each well spud. QL has also agreed to pay a drilling carry each year if certain performance thresholds are met. The drilling partnership would help fund drilling 60 wells over the four-year period. Preliminary plans focus primarily on liquids-rich development in the Marcellus Shale of West Virginia. The partnership is expected to increase Antero’s free cash flow by $400 million through 2025 by cutting expenses related to unutilized firm transportation, capturing midstream fee rebates and lowering interest costs because of lower total debt. Antero, the nation’s third largest gas producer and second largest liquids producer, now expects to achieve an absolute debt target of below $2 billion in 2023 at current strip pricing. Antero also announced last week that it would spend $590 million this year on drilling and completion, a 20% decrease from last year’s levels. “Our 2021 capital budget reflects our shift to a maintenance level capital plan and the benefit from our well cost savings initiatives that we launched in 2019,” said CEO Paul Rady. “ We are targeting total well costs of $635 per lateral foot for the second half of 2021, a 35% reduction from $970 in the initial 2019 budget. “

COVID update: Wolf pushes natural gas tax to boost Pa. economy - As a part of his $37.8 billion proposed budget, Pennsylvania Gov. Tom Wolf is pushing a plan to prop up the pandemic economy by taxing natural gas drilling. Those funds would fuel Back to Work PA, a $3 billion initiative to support workers and small businesses struggling due to restrictions designed to mitigate the spread of COVID-19. Such a plan faces an uphill battle, like failed attempts to tax fracking in years past. Budget brawls are common between the Democratic governor’s administration and the GOP-led state House and Senate, which has shown no appetite for taxing natural gas extraction. Within Wolf’s party, progressives have balked at tying the commonwealth’s long-term financial planning to the fracking industry. Caucus members from the southwestern part of the state, where natural gas prices have a direct impact on the local economy, have also signaled their disapproval. In response to this pattern, Wolf argued that Pennsylvania would merely be joining other states which already tax natural gas production, and pointed out that some companies that would be paying the tax are not based in the commonwealth. “We’re a big producer, and we’re the only major producer without a severance task,” said Wolf. “I’m not sure why it’s been such a heavy lift, but it seems to me to be one of the easiest taxes to impose.” He struck a dire note about the prospects for financial improvement if this possible revenue stream were not tapped, saying, “If we don’t take advantage of it, I’m not sure there is an alternative way to make quality of life better.”

Basin commission to take action on fracking ban near Delaware River --A regulatory agency that’s responsible for the water supply for more than 13 million people is poised to take final action this week on a permanent ban on gas drilling and hydraulic fracturing in the Delaware River watershed.  The Delaware River Basin Commission is scheduled to vote on the proposal at a public meeting on Thursday, Feb. 25.  The commission, which regulates water quality and quantity in the Delaware and its tributaries, first imposed a moratorium on drilling and fracking — the technique that unleashed a U.S. production boom in shale gas and oil — more than a decade ago. It began the process of enacting a permanent ban in 2017. The ban would apply to Wayne and Pike counties in Pennsylvania’s northeastern tip that are part of the nation’s largest gas field, the Marcellus Shale.The agency has representatives including the governors of New Jersey, New York, Pennsylvania, Delaware and the federal government.Republican state lawmakers in Pennsylvania as well as a landowners group are challenging the commission’s right to regulate gas development in court. The Marcellus Shale Coalition, an industry group representing natural gas businesses working in Pennsylvania’s production region, says the DRBC’s proposal“defies common sense, sound science, responsible policymaking” and the authority of the commission. In a 2018 letter to the basin commission, the coalition cites a study by Yale University researchers showing any increase in methane in well water supplies near fracking operations was related to “natural variability, not to shale-related activities.”  The New Jersey Sierra Club, in calling for the DRBC to enact the permanent ban, argues the fracking process is too dangerous a threat. Fracking involves injecting huge amounts of water and chemicals in rock formations that can pollute surrounding aquifers and waterways, the Sierra Club chapter says. “This requires mixing millions of gallons of water with toxic chemicals including volatile organic chemicals like benzene, methyl benzene, formaldehyde and others that are linked to cancer,” according to the chapter. “The process also releases toxic chemicals like arsenic and mercury that are naturally trapped in the shale. The average well uses 2.5 to 4.5 million gallons of water for fracking, (and) many wells are fracked two to three times.” Pennsylvania, New Jersey and Delaware governors Tom Wolf, Phil Murphy and John Carney, respectively, signed a letter in 2018 calling for a full fracking ban in the watershed, the chapter says.

Delaware River Basin Commission votes to make fracking ban permanent | S&P Global Platts — In a move long sought by environmental groups and fought by natural gas producers, the Delaware River Basin Commission on Feb. 25 voted to ban high-volume hydraulic fracturing within the basin's boundaries. The action, which makes permanent a moratorium on fracking in place since 2010, is not expected to impact ongoing production in Pennsylvania, but could preclude development of certain areas in the eastern part of the state, such as Wayne and Pike counties, that fall within basin lines. The ban on high-volume fracking within DRBC boundaries prevailed with four governors on the commission, including Pennsylvania Governor Tom Wolf, voting in favor, and the fifth, federal member, abstaining during a virtual commission meeting. The federal commissioner, Brigadier General Thomas Tickner of the US Army Corps of Engineers, cited the lack of time to coordinate with the new presidential administration. "We respect the outcome of this vote as determined by each respective state commissioner," he said during the meeting. The drilling moratorium narrowly avoids currently productive counties in Northeast Pennsylvania, including Susquehanna and Bradford counties. Dry gas production in Northeast Pennsylvania accounts for roughly one-third of total production in the Appalachian region, with output averaging 11.3 Bcf/d in January, or 33% of the region's total 34.3 Bcf/d of production in January, according to S&P Global Platts Analytics. Separately, the commission acted unanimously to consider later imposing limits on imports of wastewater and exports of basin waters; it approved a resolution that called on the executive director no later than Sept. 30 to formally develop and propose amendments. The DRBC, which oversees management of the Delaware River system, is made up of governors of Delaware, New Jersey, Pennsylvania and New York as well as the division engineer of the North Atlantic division of the Army Corps. It said it imposed the ban by adopting amendments to its comprehensive plan and water code in order to control future pollution, protect public health and preserve waters. Delaware Governor John Carney said the action would "provide the fullest protection to the more than 13 million people who rely upon the Delaware River Basin's waters for their drinking water." Wolf said the action followed careful analysis of unique geographic, geologic and hydrologic characteristics of the basin and came under authority to protect water resources for the basin. The action has been strongly opposed by the Marcellus Shale Coalition. "It may be a good day for those who seek higher energy prices for American consumers and a deeper dependence on foreign nations to fuel our economy, but this vote defies common sense, sound science, and is a grave blow to constitutionally protected private property rights," said MSC President David Callahan. He expressed disappointment with Wolf for aligning with "out-of-state interests," and also faulted President Joe Biden for failing to oppose the ban.

Delaware River Basin Commission Votes to Ban Fracking in Historic Victory - In a historic move, the Delaware River Basin Commission (DRBC) voted Thursday to ban hydraulic fracking in the region. The ban was supported by all four basin states — New Jersey, Delaware, Pennsylvania and New York — putting a permanent end to hydraulic fracking for natural gas along the 13,539-square-mile basin, The Philadelphia Inquirer reported.The vote affirms a 2010 moratorium by the DRBC, an agency that manages the water. Pressured by environmental groups, commissioners used their authority to safeguard public and environmental health and limit future pollution, according to The Philadelphia Inquirer."Today's decision is a historic watershed moment and one that will significantly contribute to a clean energy future," Patrick Grenter, associate director of the Sierra Club's Beyond Dirty Fuels campaign, said in a statement. "Fracking threatens the health of our people, water, climate, and communities and we're relieved to see it outlawed in the Delaware River Basin."Fracking for natural gas involves blasting high volumes of pressurized water and chemicals into rock formations. This has led to contaminated water wells, while wastewater spills have transmitted radioactive materials into surface and groundwater, StateImpact Pennsylvania reported. These pollutants and chemicals are linked to cancers and other health issues in humans and wildlife, NRDC reported.If fracking were to be allowed in the Delaware River Basin, these same impacts could affect the 17 million people that rely on the basin for drinking water, putting 45,000 people who live within a mile of the planned fracking well locations at high risk for those health problems, the NRDC added. The basin is also a critical habitat for one of the most important fisheries in the country, home to diverse species such as native trout, American eels and bald eagles.The debate on fracking in the region began over a decade ago. During Pennsylvania's natural gas boom, commissioners expressed concern over the high quantity of basin water required to support it, StateImpact Pennsylvania found.In response, the DRBC imposed a fracking moratorium in 2010, but never finalized drilling regulations, according to The Philadelphia Inquirer. Despite yesterday's vote, the ban still faces opposition. Pennsylvania Chamber of Business and Industry President and CEO Gene Barr said that the votes by New York, New Jersey and Delaware did not have Pennsylvania's "best interests in mind," StateImpact Pennsylvania reported."There is no support to any claim that drilling results in widespread impacts to drinking water, rivers or groundwater," Barr told AP. "This was a political decision uninformed by science."

Lawmakers push regulators to reexamine compressor approval – Members of Weymouth's congressional delegation want federal regulators to reconsider their decision to allow the compressor station on the banks of the Fore River to go into service. U.S. Rep. Stephen Lynch and U.S. Sens. Edward Markey and Elizabeth Warren recently sent a letter to Richard Glick, chairman of the Federal Energy Regulatory Commission, asking that the commission rescind the in-service authorization issued for the compressor station in September. “The site is located within a half mile of Quincy Point and Germantown – “environmental justice communities” that suffer persistent environmental health disparities due to socioeconomic and other factors – as well as nearly 1,000 homes, a water treatment plant and a public park,” the legislators wrote in the letter. “An estimated 3,100 children live or go to school within a mile of the site, and more than 13,000 children attend school within three miles of the compressor station.” Fore River Residents Against the Compressor Station, the City of Quincy and other petitioners have also asked the commission to revoke the authorization and reconsider its approval of the project. "We urge you to review their concerns fully and fairly, and to swiftly move to rehear the approval of the in-service certificate," the lawmakers wrote in their letter. The commission last week voted to take a look at several issues associated with the compressor station, including whether the station’s expected air emissions and public safety impacts should prompt commissioners to reexamine the project. The compressor station is part of Enbridge’s Atlantic Bridge project, which expands the company’s natural gas pipelines from New Jersey into Canada. Since the station was proposed in 2015, residents have argued it presents serious health and safety problems. Last fall, local, state and federal officials called for a halt of compressor operations when two emergency shutdowns caused hundreds of thousands of cubic feet of natural gas to be released into the air. Max Bergeron, a spokesman for Enbridge, said last week that the in-service authorization remains in place and the company is committed to operating the station “safely and responsibly.” Algonquin Gas Transmission, a subsidiary of Spectra Energy, received initial approval for the compressor station in January 2017 from the Federal Energy Regulatory Commission. Enbridge later acquired Spectra. State regulators also issued several permits for the project despite vehement and organized opposition from local officials and residents. The Town of Weymouth alone filed two dozen lawsuits and spent more than $1.6 million in legal fees attempting to stop the project.

Advocates hold hearing featuring fervent opposition to proposed rollback of oil and gas tank regulation - A virtual public hearing was held Friday on a bill that would exempt about 900 oil and gas waste tanks close to water intake points from regulation. It featured vehement opposition to the measure and frustration that two committees in the House of Delegates have denied official public hearings on the proposal.The “People’s Public Hearing,” conducted via Zoom teleconference, drew about 75 attendees and 25 speakers, all of whom voiced opposition to House Bill 2598, which would rollback the Aboveground Storage Tank Act the Legislature passed in response to the 2014 Elk River chemical spill.The House Energy and Manufacturing Committee voted Tuesday to advance the bill to the full House before Speaker Roger Hanshaw, R-Clay, referred the legislation to the Health and Human Resources Committee on Wednesday.HB 2598 would remove tanks containing 210 barrels or less of “brine water or other fluids produced in connection with hydrocarbon production activities” in zones of critical concern from regulation under the Aboveground Storage Tank Act.The act requires registration and certified inspection of such tanks, as well as the submission of spill-prevention response plans. It also defines zones of critical concern as corridors along streams within a watershed that need close scrutiny because of a nearby surface water intake point and its susceptibility to potential contaminants. The length of zones of critical concern is based on a five-hour water-travel time in streams to the water intake, plus an additional quarter-mile below the intake. A zone’s width is 1,000 feet from each bank of the principal stream and 500 feet from each tributary bank draining into the principal stream.State lawmakers joined conservationists and concerned West Virginians to criticize the bill during the hearing, which advocates said would be recorded and sent to the House.“It’s ridiculous to roll this part of the Aboveground Storage Tank Act back,” said Delegate Mike Pushkin, D-Kanawha, the top-ranking Democrat on the Health and Human Resources Committee. Pushkin said he expects the committee to consider the bill Tuesday or Thursday.“Safe drinking water is not a Democratic issue or Republican issue,” he said. “It’s a human issue.”Delegate Evan Hansen, D-Monongalia, who led an unsuccessful fight against the bill in the House Energy and Manufacturing Committee, and Delegate Larry Rowe, D-Kanawha, also weighed in against the measure during Friday’s hearing. “I just can’t explain why the Legislature would want to create danger zones right at intake areas in our streams,” Rowe said. “It amazes me.”

Court rejects latest effort to stop Mountain Valley Pipeline – An appellate court has declined to stop work on the Mountain Valley Pipeline, dealing the latest blow to arguments that there is no public need for the natural gas that is to be transported by the line. The U.S. Circuit Court of Appeals for the District of Columbia denied a request Friday by a coalition of environmental organizations. The groups had sought an emergency stay of a decision last year by the Federal Energy Regulatory Commission that allowed work on the project, which has been slowed by a slew of lawsuits, to resume. No reasons for the denial were given in a three-paragraph order from the court, which is expected to rule later this year on the underlying legal challenge. But in a brief filed Jan. 29, the Sierra Club and seven other petitioners based their arguments in large part on the assertion that the public’s need for more gas to heat homes, serve businesses and fuel power plants — cited by FERC when it first approved the project in 2017 — no longer exists. Those findings “have not merely grown stale, but fully decayed,” the groups’ law firm, Appalachian Mountain Advocates, stated in the brief. A declining demand and surplus supply in recent years has led EQT Energy, a shipper that holds contracts for about 65% of the pipeline’s capacity, to conclude that it no longer needs the gas, the groups argue. The brief cites a July 2020 conference call with investors in which EQT officials explained their plans to sell their capacity contracts to other energy companies in order to save money and increase returns for shareholders. In a response filed Feb. 8, attorneys for Mountain Valley accused the petitioners of relying on “cherry-picked snippets from an earnings call.” EQT has actually said that long-term capacity from the pipeline has become more valuable in the past year, as utilities scramble to meet customer needs following the cancellation of the Atlantic Coast Pipeline, a similar project which would have run through Central Virginia, Mountain Valley’s brief stated.

Appeals Court Rebuffs Enviro Groups, Keeps MVP Authorizations in Place -The U.S. Court of Appeals for the D.C. Circuit on Friday rebuffed a challenge mounted by environmental groups seeking to stop Mountain Valley Pipeline LLC from restarting construction in areas reauthorized by FERC. A coalition including the Sierra Club, Appalachian Voices and the Chesapeake Climate Action Network late last month filed an emergency motion asking the court to stay recent orders from the Federal Energy Regulatory Commission clearing MVP to resume construction along much of the route outside of a portion near the Jefferson National Forest.The groups also asked the D.C. Circuit to stay FERC’s decision to grant a two-year extension of the original deadline for the project to complete construction.However, the court denied the motion, issuing a one-page order Friday finding that the environmental groups “have not satisfied the stringent requirements for a stay pending court review.”Analysts at ClearView Energy Partners LLC said in a note to clients shortly following Friday’s decision that the “status quo” remains the same for MVP, with the pipeline still cleared to resume work as planned in areas previously authorized by FERC.However, MVP will need further regulatory action before it can resume construction on waterbody crossings — held up over problems with the previously issued Nationwide Permit 12 approvals — and on the portion of the route near the proposed national forest crossing, the ClearView analysts noted. MVP recently laid out a new strategy to obtain the remaining permits and complete construction on the 303-mile, 2 million Dth/d natural gas conduit. Instead of relying on the stayed Nationwide Permit 12 waterbody crossing permits, the developer plans to seek new permitting from the U.S. Army Corps of Engineers under Section 404 of the Clean Water Act. To that end, MVP in a letter filed with FERC Friday said it was submitting its application for the Section 404 approval. The operator asked that its existing Nationwide Permit 12 authorizations be administratively revoked “to avoid unnecessary expenditure of public resources in existing litigation.”

ATC Rejects Mountain Valley Pipeline Opponents' Request to See $19.5 Million Agreement - The Trek -The Appalachian Trail Conservancy this week denied a request to release the full text of its August 2020 “voluntary stewardship agreement” with Mountain Valley Pipeline, LLC, the company overseeing construction of a 303-mile natural-gas pipeline that will cross the Appalachian Trail near Pearisburg, Va.Opponents of the pipeline delivered a petition signed by more than 400 “ATC members, volunteers and/or Trail supporters” to ATC President and CEO Sandra Marra and the board of directors Feb. 16.On Monday, the ATC informed the petitioners that it would not make the agreement public.“As a matter of ATC’s policies, standard philanthropic practice, and for reasons that have been previously discussed, the voluntary stewardship agreement with the Mountain Valley Pipeline and The Conservation Fund is private,” the ATC said in a statement, which included a link to the August announcement of the agreement.Under the agreement, MVP committed up to $19.5 million “for use by the Conservancy to conserve land along the Trail corridor and support outdoor recreation-based economies in Virginia and West Virginia,” according to the ATC.Opponents criticized the ATC’s continued unwillingness to make the agreement public. “The ATC’s actions are a truly grotesque departure from their public ‘Identity Statement,’ which claims the ‘Conservancy’s staff and board embodies honesty, mutual respect, openness, continuous learning and improvement, and excellence,'” ATC member Russell Chisholm said in a statement released Feb. 24. “Instead, the decision to enter into a Voluntary Stewardship Agreement and refuse to provide transparency about the decision inappropriately prioritizes the power of the Board over the wishes of ATC members and the public.”

Mountain Valley Pipeline still on target for completion this year, developers say - Developers of the Mountain Valley Pipeline say it remains on schedule for completion by year’s end, despite a restart in seeking government approval to cross nearly 500 streams and wetlands. All required permits should be in hand by summer, “allowing us to ramp up to full construction,” Diana Charletta, president and chief operations officer of Equitrans Midstream, the lead partner in the joint venture, said during an earnings call Tuesday. Already behind schedule and over-budget, work on the natural gas pipeline hit a major road bump last October, when a federal appeals court issued a stay to a water body crossing permit issued by the U.S. Army Corps of Engineers. Rather than engage in a lengthy court battle over a blanket approval known as a Nationwide Permit 12, Mountain Valley decided to change its method for crossing the streams that remain along the pipeline’s 303-mile path. The company will now seek individual permits, which will require a more detailed analysis of how it plans to dig trenches through temporarily dammed streams to bury the 42-inch diameter pipe. Mountain Valley recently submitted an application to the Army Corps that runs about 6,600 pages long, Charletta said. For water bodies that cannot be forded by the so-called open-cut method, the Federal Energy Regulatory Commission will be asked to approve an alternative method of boring under the streams. Last year, FERC approved such an operation for the Roanoke River, which the pipeline will cross near Elliston on its path through the New River and Roanoke valleys. In addition to getting authorizations from two federal agencies, Mountain Valley must also obtain new water quality certifications from Virginia and West Virginia. Height Capital Markets, an investment banking firm that has been closely following the project, has said it expects the complicated permitting process to push completion of the pipeline well into next year. Meanwhile, opponents continued their sustained assault this week, launching a campaign that attempts to undercut Mountain Valley’s financial backing from banks and investors. In announcing the DivestMVP coalition, organizers said the uncertainty of a project now estimated to cost up to $6 billion has led many industry watchers to openly wonder if it will ever be completed.

Judge rejects Biden request for delay in Trump environmental rollback case --A federal court has rejected the Biden administration's request for a pause before a case on a Trump administration rollback of a key environmental law wraps up. The Biden administration wanted to review the rollback before a ruling, but Judge James Jones, of the Western District of Virginia, on Friday sided with environmentalists who argued that they are currently facing harm because of the Trump administration’s policy and didn’t want to delay a decision that could benefit them. “Adding lengthy additional delay to my decision would not be appropriate, in my judgment,” wrote the judge, who was appointed by former President Clinton. The Biden administration had asked for a 60-day stay on the case, over a rollback of the National Environmental Policy Act (NEPA), to “allow the new administration time to review the challenged agency action.” The Biden administration has also requested pauses on litigation over a number of other Trump-era rules, as it may seek to change its position on them. NEPA requires the government to consider environmental and community concerns before approving pipelines, highways, drilling permits, new factories or any major action on federal lands. The Trump administration sought to reduce the amount of time that environmental reviews under the law take, from about 4 1/2 years to two years. It also removed requirements to consider climate change impacts, complicated the procedure for community input and allowed more industry involvement in environmental reviews. It billed its changes as a move to expedite infrastructure permitting, while environmental groups argued that it’s a move to help industry at communities’ expense.

Piedmont Natural Gas deal not transformative, just profitable, for Duke Energy --Piedmont Natural Gas has proven a valuable acquisition for Duke Energy Corp., even though plans to make it the base to significantly expand commercial and utility natural gas operations fell by the way.   The division is a top performer for Duke. In 2020, it had the highest return on equity of the parent company’s nine gas and electric utility units. Adjusted for book value, Piedmont’s revenue contribution to Duke was $1.3 billion, nearly equaling the revenue of $1.4 billion for its Duke Energy Ohio utility. Its 3% growth in residential customers was the highest for all Duke utilities, well above the 1.2% residential growth at the company’s Midwest gas utilities in Ohio and Kentucky. But Duke’s plans to use Piedmont as a platform to make the company a larger player in natural gas, which Good repeatedly referred to at the time as the “backbone” of the U.S. energy industry, have largely been abandoned.  At the time the deal closed, Duke and Piedmont had three pipeline deals underway. Both were already partners in what eventually became the $8 billion, 600-mile Atlantic Coast Pipeline partnership with Dominion Energy Inc. That project imploded last summer as repeated court and regulatory challenges ground it to a halt. Piedmont had brought to Duke a 24% share of the planned, 124-mile Constitution Pipeline in New York. That $1 billion project with The Williams Cos. was abandoned a year ago, just after it had won victories in some lengthy court challenges. The only interstate pipeline involving Duke that has been completed is the $3.2 billion Sabal Trail Pipeline. That was a project that Duke had been involved with before it bought Piedmont, and it holds just a 7.5% stake in the pipeline.

INVESTIGATION: Giant N.C. spill shows gaps in pipeline safety -- Thursday, February 25, 2021 -- Pipeline companies can find leaks. But they often don't, even as small spills grow bigger over days. (A North Carolina pipeline leaked more than a million gallons of gasoline last summer before anyone noticed it, raising larger questions about pipeline detection technologies that can fail to notice even large-scale spills. E&E News, subscription)

Blackstone-Backed Gas Company Vine Energy Files for IPO -Vine Energy Inc., which focuses on natural gas in the Haynesville and Mid-Bossier shale plays in Louisiana, has filed for an initial public offering. The company, which is backed by Blackstone Group, filed for an IPO in 2017 and withdrew the filing in 2019. Vine Energy said the Vine Oil & Gas business posted 2020 revenue of $378.7 million, compared with $586.5 million in 2019. After a corporate reorganization, Vine Energy Inc. will also include Brix Oil & Gas Holdings LP and Harvest Royalties Holding LP. The company said in the filing that it expects "the Haynesville will be particularly critical to meeting future natural gas demand." It said other sources of natural gas supply "are facing headwinds in the form of reduced activity and infrastructure constraints." While the Marcellus and Utica shales currently account for about 30% of North American natural gas supply, "there is limited pipeline capacity available to transport natural gas out of the area," the company said. "Additionally, the demanding regulatory environment in the Northeast has limited new gas pipeline infrastructure." Vine plans to seek a New York Stock Exchange listing under symbol "VEI."

FERC Reconsidering Approach to Certify Natural Gas Projects = FERC said it would reevaluate the federal government’s approach to certifying natural gas pipelines. Current policy dates to the late 1990s, and key regulators say that, as climate change concerns mount, a re-examination of how infrastructure proposals are approved is overdue.At its monthly meeting Thursday, the Federal Energy Regulatory Commission announced it would examine the 1999 policy statement that guides regulators’ evaluations of proposed natural gas facilities. Critics have long complained that FERC green lights projects without carefully assessing greenhouse gas emissions or other potential environmental concerns of nearby communities and residents.  Former FERC Chairman Kevin McIntyre, a Republican, launched a similar process three years ago, beginning with a request for public input that yielded more than 3,000 comments. McIntyre died in 2019, however, and the review he led stalled.  Richard Glick, the senior Democrat chosen by President Biden in January to lead FERC, said Thursday the Commission is looking to build upon the record already established in response to McIntyre’s 2018 inquiry. FERC called for comments that speak to potential health or environmental effects of FERC’s pipeline certification programs and policies as well as the Commission’s decisions on communities vulnerable to environmental injustice.  FERC said it will also seek comments on how the Commission determines the need for a project, its exercise of eminent domain and assessments of landowner interests, and potential improvements to the efficiency of the Commission’s review process. In its request for comments, FERC noted it would also pay particular attention to input about how projects affect communities of color, Indigenous tribes and low-income rural areas that “are exposed to a disproportionate burden of the negative human health and environmental impacts of pollution or other environmental hazards.”  Both Glick and fellow Commissioner Allison Clements had foreshadowed the review in previous comments, signaling a heightened emphasis on environmental concerns linked to burning natural gas. Though FERC operates independently of the Biden administration, the heads of regulatory arms such as the Commission are named by the president and agendas tend to reflect the administration’s priorities.

NatGas Traders Begged For Cash As Arctic Blast Paralyzed Texas Energy Market - Stories are emerging from veteran gas traders about the events leading up and during one of the worst energy crises in years. As the polar vortex began to dump frigid air into the central U.S. and Texas, "urgent phone calls came over the holiday weekend: traders of natural gas needed more money, and fast," said Bloomberg.As temperatures dove earlier this month and spot prices for natgas skyrocketed 300-fold in a matter of days, traders in the physical gas market realized they had a considerable problem developing: exchanges demanded collateral due to the unprecedented volatility. Readers may recall, on Feb.12, natgas prices across the Great Plains erupted as supply froze in pipes due to Arctic conditions produced by the polar vortex split. By Feb. 13, traders had to come up with collateral by Tuesday (Monday was a market holiday (Presidents' Day/Washington's Birthday)), or they would be forced out of their positions for massive losses. Desperate for cash to meet margin requirements, some traders turned to "European parent companies that could deliver so-called margin payments on their behalf to the exchanges sooner. The cash showed up in different currencies, but it did the trick," said Bloomberg. "I've been through a lot: The '98 and '99 power spikes in the Midwest, the California crisis" of 2000-2001, said Cody Moore, head of gas and power trading at Mercuria Energy America."Nothing was as broadly shocking as this week."With supply frozen in pipes and much of Texas' power generation produced by natgas, the power and gas markets hit record high spot prices last week. While natgas prices in some locations hit $1,250 per million British thermal units, wholesale power for delivery hit its $9,000-per-megawatt-hour price cap as demand exceeded supply leading to one of the worst controlled blackouts in the nation's history.   At one point, Bloomberg calculated that up to 15 million Texans plunged into darkness during the winter blast. ... and of course, there were winners and losers in the energy space during this entire fiasco. Jerry Jones, the billionaire owner of the Dallas Cowboys, was able to sell natgas for extraordinary high premiums. One of the losers, Atmos Energy Corp., a top supplier of gas in the U.S., is in the process of raising cash after it committed to securing $3.5 billion worth of natgas during the chaos.

Natural Gas Prices Continue to Slide on Post-Storm Recovery - Natural gas futures crashed on Monday as production appeared to be making a quick recovery from the unrivaled Arctic blast that rocked the energy industry last week. Warming weather models also provided a headwind to prices, with the March Nymex gas futures contract tumbling 11.6 cents to settle at $2.953. April slid only 5.5 cents to $2.936. Spot gas prices continued to fall too on the much milder weather that settled in over much of the Lower 48. NGI’s Spot Gas National Avg. dropped $1.605 to $2.870. Though likely not at the same level as last week, futures volatility is expected to remain robust in the coming days, with the March contract set to roll off the board Wednesday. Prompt-month prices were down sharply at the open and remained firmly in the red throughout the session. The April-June contracts, meanwhile, moved back to around where they were trading at the beginning of the month. NatGasWeather said the more moderate conditions are expected to shift colder late this week, but the latest weather data paints a less colder picture than in earlier outlooks. The data is colder with a second system forecast to follow March 2-4. Overall, though, the set-up for the 12- to 15-day forecast period is bearish, according to the forecaster. Despite the warmer weather on tap for this week, NatGasWeather said “the damage from the recent Arctic blast has been done.”

US natural gas futures fall on warmer weather -  US natural gas futures slid over 2% to a fresh one-week low on Tuesday as warmer weather allows producers to return to service more wells and pipelines that were frozen during last week’s extreme cold. That small decline comes despite forecasts for higher demand next week as liquefied natural gas (LNG) exports rise. On their second to last day as the front-month, gas futures for March delivery fell 7.4 cents, or 2.5%, to settle at $2.879 per million British thermal units, their lowest close since Feb. 11 for a second day in a row. April futures, which will soon be the front-month, lost 8 cents to $2.86 per mmBtu. Data provider Refinitiv said output in the Lower 48 US states has averaged 85.2 billion cubic feet per day (bcfd) so far in February. Traders noted that was down from 91.1 bcfd in January, due to massive freezing of wells and pipelines last week. Output hit an all-time monthly high of 95.4 bcfd in November 2019. On a daily basis, production was on track to jump to 87.5 bcfd on Tuesday as the weather warms, its highest since Feb. 11 before last week. During last week’s freeze, daily output dropped as low as 72.9 bcfd on Feb. 17, the lowest since August 2017, according to Refinitiv data. Refinitiv projected average gas demand, including exports, would fall from 117.0 bcfd this week to 109.1 bcfd next week as the weather turns milder. That forecast for next week was higher than Refinitiv projected on Monday due mostly to rising LNG exports. The amount of feedgas flowing to US LNG export plants averaged 8.4 bcfd so far in February, down from 10.4 bcfd in January and a monthly record high of 10.7 bcfd in December. Exports dropped this month after several Gulf Coast plants shut or reduced output after the extreme cold cut available power and gas supplies.

US natural gas futures slip to 2-week low -  US natural gas futures slipped to a two-week low on Wednesday as the weather turns milder, heating demand declines and output rises after last week’s freeze. On its last day as the front-month, gas futures for March delivery fell 2.5 cents, or 0.9%, to settle at $2.854 per million British thermal units (mmBtu), their lowest close since Feb. 9. That put the front-month down for a fifth day in a row for the first time since November. April futures, which will soon be the front-month, fell 5 cents to $2.80 per mmBtu. Data provider Refinitiv said output in the Lower 48 US states has averaged 85.5 billion cubic feet per day (bcfd) so far in February. Traders noted that was down from 91.1 bcfd in January, due to massive freezing of wells and pipelines last week. Output hit an all-time monthly high of 95.4 bcfd in November 2019. On a daily basis, production was on track to jump to 89.8 bcfd on Tuesday as the weather warms, its highest since Feb. 8. During last week’s freeze, daily output dropped as low as 72.9 bcfd on Feb. 17, the lowest since August 2017, according to Refinitiv data. Analysts projected last week’s heavy heating demand will erase the long-standing surplus of gas in storage. Stockpiles have remained above the five-year (2016-2020) average since the start of 2020 and were still 2.6% above that average during the week ended Feb. 12. '

Like 'Nothing Happened,' Natural Gas Forward Prices Crumble Below $3.00 --Massive declines spread across natural gas forward markets for the trading period ending Wednesday, fueled primarily by a return to the warm weather pattern that has characterized most of the winter season. A quick ramp in production following last week’s historic winter storm also served as a headwind for prices, with March averaging 34.0 cents lower during the Feb. 18-24 period, according to NGI’s Forward Look. April contracts also took a big hit, falling 19.0 cents on average for the period, while the summer strip (April-October) dropped 13.0 cents on average, Forward Look data showed. Prices for next winter (November-March) posted double-digit losses as well, averaging 10.0 cents lower on the week. The price decreases across U.S. forward curves were expected following the monstrous rally that took place last week amid the prolonged Arctic blast. The unrivaled cold resulted in widespread power outages and surprising moves by the Texas governor to help restore power to the electric grid. The price slide was led by Nymex futures, which fell for five straight days beginning last Thursday (Feb. 18) and ended with the March contract expiring Wednesday at $2.854/MMBtu. April closed the session at $2.795. “It is difficult to argue that nothing happened during the month of February, yet that is what the Nymex curve indicates,” said Mobius Risk Group. Instead, the gas market has been beset by several bearish catalysts over the past week, according to EBW Analytics Group. These include a couple of lower-than-expected storage withdrawals, a much warmer turn in the weather data that has sliced 38 Bcf of demand and a faster-than-expected recovery from record production freeze-offs. “The market remains severely undersupplied, and Nymex futures are significantly undervalued on a fundamental basis,” EBW said. “Last week’s perfect storm and widespread shortages provided the catalyst for the market to move higher, and the lack of upside price action suggests…a likely period of consolidation before a sustained move higher later in late April or May.”

US gas in storage posts second-largest weekly withdrawal on record at 338 Bcf | S&P Global Platts -- The US natural gas storage industry posted its second-largest draw on record last week, but the Henry Hub prompt-month contract continued to slip as the severe, country-wide cold retreated. Storage inventories decreased by 338 Bcf to 1.943 Tcf for the week ended Feb. 19, the US Energy Information Administration reported the morning of Feb. 25. The withdrawal was stronger than the 333 Bcf draw expected by an S&P Global Platts survey of analysts. The pull proved more than 200 Bcf stronger than the the five-year average. It was only the second weekly storage withdrawal to measure more than 300 Bcf. The largest weekly storage decline on record stands at 359 Bcf, which was set for the week ended Jan. 5, 2018. Unprecedented cold in parts of the country led to huge swings in daily supply and demand fundamentals, according to S&P Global Platts Analytics. US production fell about 9 Bcf/d versus the prior week, compared to a 3 Bcf/d decline during the polar vortex of January 2018. Most of the losses were observed within Texas, Oklahoma and the Southeast. Such large losses in US production led to an aggregate increase of 2.6 Bcf/d in net Canadian imports and LNG sendouts week on week. Lower production, massive gains in spot gas prices, loss of power and port closures led to LNG feedgas and exports to Mexico falling by 5.1 Bcf/d and 1.3 Bcf/d, respectively, week on week. Gas prices lost some ground this week, with the now prompt April NYMEX contract falling to near $2.80/MMBtu entering the EIA report -- well off the intraday high of $3.06/MMBtu established last week. A mild outlook over the next two weeks, coupled with a fast return of US production, likely caused some profit-taking. Nevertheless, with the market likely to enter the summer near 1.5 Tcf -- the current summer NYMEX Henry Hub strip appears undervalued, according to Platts Analytics. Indeed, too much demand will be stimulated, and not enough gas will be available to replenish storage to adequate levels. After the EIA report, gas prices were relatively unchanged, with the April contract near $2.79/MMBtu. Storage volumes now stand 298 Bcf, or 13.3%, less than the year-ago level of 2.281 Tcf, and 161 Bcf, or 7.7%, more than the five-year average of 2.104 Tcf. Platts Analytics' supply and demand model currently forecasts a 137 Bcf withdrawal for the week ending Feb. 26, which is about 50 Bcf stronger than the five-year average draw. Rising temperatures aided a quick recovery in US production, increasing 5.6 Bcf/d week over week. Higher production pushed back on other sources of supply, with LNG sendouts and net Canadian imports falling by 1.2 Bcf/d and 1.5 Bcf/d, respectively. More supply availability, the resumption of power and the return to more normalized port operations allowed LNG feedgas volumes to climb 2.4 Bcf/d week on week. In addition, exports to Mexico ticked up 600 MMcf/d week on week.

EIA’s Massive Storage Draw Too Little Too Late; April Natural Gas Prices Fall Again -  The April natural gas futures contract failed to make a big impression on its first day at the front of the Nymex curve. The new prompt month struggled to get off the ground early in Thursday’s session and only reached a $2.855/MMBtu intraday high before settling at $2.777, off 1.8 cents from Wednesday’s close.Spot gas, which traded Thursday for delivery through Sunday, continued to retreat as well, with losses accelerating on the East Coast. NGI’s Spot GasNational Avg. dropped 19.5 cents to $2.555.After five straight days in the red, it would not have been surprising to see the newly prompt April contract make a big splash. Instead, prices languished early in the session, teetering on either side of flat ahead of Thursday’s Energy Information Administration (EIA) report. Analysts had been banking on a steep drawdown, with estimates more or less clustered around a draw near 335 Bcf.However, there was a host of factors that easily could have resulted in much less gas being pulled out of storage during the unparalleled freeze that draped the Midcontinent and Texas last week.The EIA’s monster 338 Bcf withdrawal was near consensus but failed to surpass the record 359 Bcf draw reported by EIA in January 2018. Still, participants on Enelyst were surprised to see the lack of response from futures..Enelyst managing director Het Shah said with the Nymex front month flipping to April, there was not the same level of excitement than if the EIA’s draw would have been posted a week ago.Nevertheless, the draw brought total inventories down to 1,943 Bcf, 298 Bcf lower than year-ago levels and 161 Bcf below the five-year average of 2,104 Bcf, according to EIA.Broken down by region, the South Central region recorded a massive 156 Bcf withdrawal, including an 83 Bcf pull from salt facilities and a 73 Bcf draw from nonsalts, EIA said. The Midwest took out 81 Bcf from storage, and the East withdrew 61 Bcf. Pacific inventories declined by 26 Bcf, while Mountain inventories fell by 14 Bcf.Lefkof questioned the level of demand that would have resulted had it not been for the widespread power outages that affected natural gas production, pipelines, plants, storage facilities and other infrastructure. During the unrivaled Arctic storm, Texas Gov. Greg Abbott also ordered gas producers to not sell gas across state lines in an attempt to help restore power to the grid. Criterion Research LLC analyst James Bevan noted that given the shuffling of supply, South Central supply was actually higher last week. “When you add up the weekly pipeline exports, decreased liquefied natural gas export deliveries, Mexican exports and production freeze-offs, supply actually gained 1.5 Bcf/d,”

LNG tankers pile up in US Gulf as loadings slowly restart - More than 10 tankers were waiting to load in the US Gulf Coast as LNG plants there slowly resumed exports after complications from winter storms prevented tankers from loading and sailing since Feb. 14. Twelve LNG tankers were either waiting to load or in transit to one of the four USGC-based LNG export facilities late Feb. 17, according to S&P Global Platts ship tracking software, cFlow. Exports from the US halted suddenly as the polar vortex affecting much of North America caused operational complications at liquefaction plants and at ship channels. The first US-sourced tankers to set sail since the extreme cold weather set in departed from Freeport LNG late Feb. 17. Since then, another two vessel have left ports in the US Gul Coast: another from Freeport on Feb. 18 and one from Sabine Pass on the same date. Two for the three tankers had been berthed at their respective export facility for a number of days. Ship channels across the gulf had experienced closures or operational complications at the start of the polar vortex, due to essential personnel being unable to access the ports. Tanker loadings and departures have, however, only resumed at two of the four USGC-located facilities. Consequently, the rate of loading from the gulf, and the US as a whole, is significantly lower than just a week ago. The seven-day moving average loading rate for the US as whole fell to 5 Bcf/d on Feb. 19, down by more than half from earlier in the month, data from S&P Platts Analytics showed. As the situation stands, the average export rate for February stands at about 7.4 Bcf/d, below the roughly 9.3 Bcf/d average seen in December and January.

Natural Gas Production in Texas Dropped 45% Amid Historic Freeze --U.S. dry natural gas production plummeted during the Arctic freeze that descended upon Texas last week, hitting a low of 69.7 billion Bcf/d, the U.S. Energy Information Administration (EIA) said in a research note Thursday. The low point, reached on Feb. 17, marked a decline of 21% from the average of the prior week, the agency said. Natural gas production in Texas dropped nearly 45%, falling from 21.3 Bcf/d during the week ended Feb. 13 to a low of 11.8 Bcf/d on Feb. 17, EIA estimated using data from IHS Markit. Temperatures in Texas during the extraordinary cold snap averaged nearly 30 degrees lower than normal for the time of the year. “The decline in natural gas production was mostly a result of freeze-offs, which occur when water and other liquids in the raw natural gas stream freeze at the wellhead or in natural gas gathering lines near production activities,” EIA noted. Unlike natural gas production infrastructure in northern states that is built to withstand frigid conditions, wellheads, gathering lines and processing facilities in Texas are not “weatherized” for prolonged bouts of freezing temperatures. That makes them “susceptible to the effects of extremely cold weather,” researchers said. In a separate report Thursday, EIA said that, with the frosty temperatures and light production, the industry withdrew 338 Bcf from natural gas storage in the week ended Feb. 19, the second-steepest pull on record.

Texas Refineries Released Tons of Pollutants During Storm -  Texas oil refineries released hundreds of thousands of pounds of pollutants including benzene, carbon monoxide, hydrogen sulfide, and sulfur dioxide into the air as they scrambled to shut down during last week's deadly winter storm, Reuters reported Sunday.  Winter storm Uri, which killed dozens of people and cut off power to over four million Texans at its peak, also disrupted supplies needed to keep the state's refineries and petrochemical plants operating. As they shut down, refineries flared — or burned off — gases in order to prevent damage to their processing units.  According to the Texas Commission on Environment Quality, the five largest refiners emitted nearly 337,000 pounds of pollutants in this manner. ExxonMobil's Baytown Olefins plant in Baytown released 68,000 tons of carbon monoxide and nearly a ton of benzene in what it called a "safe utilization of the flare system."  Critics noted, however, that benzene is harmful to bone marrow, red blood cells, and the immune system. "There is no safe amount of benzene for human exposure," Sharon Wilson, a researcher at the advocacy group Earthworks, told Reuters. The five largest U.S. oil refiners emitted tons of pollutants into the skies over Texas this week, including benzen… https://t.co/yZtlbByZ6U   Motiva's Port Arthur refinery released 118,100 pounds of pollutants into the air between Feb. 15 and Feb. 18. This was triple the amount of excess emissions the plant reported to the U.S. Environmental Protection Agency for the entire year of 2019.  Valero's refinery in Port Arthur flared 78,000 pounds of pollutants over 24 hours beginning Feb. 15, while Marathon Petroleum's Galveston Bay refinery released 14,255 pounds in less than five hours that same day. Hilton Kelly, who lives in Port Arthur, told Reuters that there were "six or seven flares going at one time." Wilson said that the flaring "could have been prevented" by winterizing the refineries. "We need someone in the Texas legislature to file a bill requiring the oil and gas industry to thoroughly winterize all their equipment," Wilson told Earther. "The bill probably won't pass in Texas, but that will create some more scrutiny about it."  Earther reports that between Feb. 11 and Feb. 18, there were 174 so-called "emissions events" from fossil fuel facilities in Texas, compared to between 37 and 46 such events in weeks before the storm. In addition to the previously mentioned pollutants, chemicals released from Texas facilities include over 6,500 pounds of the carcinogen isoprene from a Shell plant in Deer Park near Houston, as well as an indeterminate amount of methane, which is 84 times more harmful to the atmosphere than carbon dioxide over the short term. Wilson told Earther that "in Texas we don't count methane" in pollution reports.

Weeks to Restart Damaged Texas Refineries -- Four of the largest refineries in Texas are discovering widespread damage from the deep freeze that crippled the state and expect to be down for weeks of repairs, raising the potential for prolonged fuel shortages that could spread across the country. Exxon Mobil Corp.’s Baytown and Beaumont plants, Marathon Petroleum Corp.’s Galveston Bay refinery and Total SE’s Port Arthur facility all face at least several weeks to resume normal operations, people familiar with the situation said. Gasoline prices at the pump could reach $3 a gallon in May as long outages crimp supply ahead of the driving season, said Patrick DeHaan, head of petroleum analysis for retailer tracker GasBuddy. The cold snap and power outages roiling energy markets affected more than 20 oil refineries in Texas, Louisiana and Oklahoma. Crude-processing capacity fell by about 5.5 million barrels a day, according to Amrita Sen, chief oil analyst for consultant Energy Aspects Ltd. When blackouts that left millions of homes in the dark end and frozen roadways thaw, drivers can take to the road again. But refineries are left with burst pipes, leaks, damaged equipment and, in some cases, petroleum fluids that hardened into a sort of wax because the flow stopped. “It’s going to be a difficult restart for refiners,” said Andy Lipow, president of energy researcher Lipow Oil Associates in Houston. “They are not going to restart until power is restored and they get the go-ahead from the utilities. My guess is the earliest restarts would even begin is this coming weekend.” Restarting a refinery isn’t like flipping a light switch when the power comes back on. In addition to fixing any damage, getting back online involves slowly heating up units, testing all the way, then slowly ramping up so they are running fluid again. And testing and retesting the output until it meets specifications. If a refinery didn’t shut major process equipment like gasoline-making units known as catalytic crackers before a power loss, there will be so-called dead legs, pockets of hydrocarbon and steam that freeze and can burst pipes and cause leaks. An abrupt shutdown could cause any fluids in piping to harden and take days or weeks to remove. Even in the case of a controlled shutdowns ahead of a power loss, plunging temperatures can damage equipment. Below are some details about the four Texas refineries that expect to be down for weeks:

U.S. shale producers reveal extent of hit from Texas freeze (Reuters) - Occidental Petroleum Corp, Diamondback Energy Inc and a host of smaller Permian-focused U.S. shale producers on Monday forecast lower oil output in the first quarter, giving the first indications of the hit to the industry caused by last week’s winter storm. Areas of Texas not used to the cold were hit by sub-zero temperatures and record snow falls last week. While natural gas producers benefited from cold weather forcing closure of wells, shale oil drillers stood on the losing side of the trade as frozen pipes and power supply interruptions were expected to slow an output recovery, operators said. Shale oil producers could take at least two weeks to restart the more than 2 million barrels per day (bpd) of crude output lost during the cold snap and some production may never return because of the cost of restarting marginal wells, analysts said.Diamondback estimated it lost four to five days worth of total production from its current-quarter earnings, sending its shares down nearly 4% to $65.95 in late trading. Oil shares had rallied during the day on higher oil prices. Occidental forecast the storm would cut about 25,000 barrels of oil and gas from its first-quarter production. Its shares also reversed course after the bell and were down about 2%.

Texas freeze helps rival oil exporters like Saudi Arabia ‘tremendously’, may influence OPEC moves  The shock winter storm in Texas that left millions without power and took dozens of lives also froze a major local commodity: the Lone Star State's oil production, slashing some 4 million barrels per day from U.S. output. The consequence will be a boost in revenue and potentially increased exports among rival oil-producing nations, commodities experts say. Analysts estimate the total volume of oil lost to Texas' production freeze at anywhere between 18 million and 40 million barrels and roughly one-fifth of U.S. refining capacity was shut in. And while temperatures are moving upward again and production is expected to mostly recover by the end of this week, the impact of the deficit on oil markets is already visible in the recent jump in crude prices. International benchmark Brent crude is up more than $6 per barrel since the storm began hitting Texan production facilities in mid-February. U.S. benchmark West Texas Intermediate has risen about $3 per barrel. The development, while adding yet another blow to Texas on top of the devastating damage and human suffering wreaked by the once-in-a-decade storm, translates on the global market into a likely boon for other oil producers, like those in the Middle East. "The Texas storm helps Saudi and its partners tremendously because it accelerates the path to inventory normalization," Peter Sutherland, president of Houston-based energy investment firm Henrietta Resources. "Concurrent drawdowns of both crude and refined products are a big tailwind heading into spring," he told CNBC. "It's not just positive sentiment; the roughly 40 million barrels lost due to the storm help tighten the market." The inventory drawdown continues a trend that's seeing oil prices steadily rise from their historic pandemic-induced lows nearly a year ago. Brent crude is up 30% year to date, with Goldman Sachs predicting it could hit $75 by the end of this year, a level not seen since fall of 2018. This could influence decision making among OPEC members in their upcoming meeting on March 4. While the organization had prioritized production cuts during much of the pandemic to keep a floor under oil prices, the more promising outlook for demand — and gradually normalizing global supply — provides incentive for these producers to speed up the rate at which they'll increase their production.

Looks Like We Made It - Propane and the 2021 Deep Freeze; Where Are We Now? --Here in Texas, the snow is melting, the power is back on, and some of us even have drinkable water.  We’ll be dealing with the aftermath of the 2021 Deep Freeze for months, and talking about the insane natural gas and power prices for as long as gas and power markets exist. One thing you have not heard much about during these crazy few days is propane. And given what we’ve been through, no news is good news. Sure, it was impossible to exchange a tank at the local Quickie Mart, and there were sporadic reports of delayed propane deliveries and local shortfalls. But even up in the coldest Midwest states, there were no market meltdowns, no skyrocketing prices. Instead, propane has been the go-to fuel to keep folks warm, to get energy production moving again by defrosting wellheads and pipeline valves, and even to get restaurants back on their feet. It’s always dangerous to declare a winter victory with a few weeks left to go in the season, but today we’ll take that risk.  We started laying the groundwork for our analysis of this season’s propane market late last year in Now You See It, where we warned of the possibility of a coming propane price squeeze. At that point, the big issue was exports, which were running at all-time highs and had the potential to deplete inventories at record rates. We worried that average days-supply, when calculated using both domestic demand and exports, had dropped to a five-year low, and that the market could get very tight. We kept the focus on propane supply and exports in Big Panama With A Purple Hat Band and It's All Over Now, where we looked at how frigid weather in Asia had pulled even more U.S. propane into export markets. By early February the handwriting was on the wall, and we laid out the prospects for a looming deep freeze in Cold As Ice, suggesting that even with super-cold weather just ahead and low inventories in the Midwest (PADD 2), the propane market seemed to be reasonably well prepared for what was to come. So far, that’s how conditions in the propane market seem to be playing out. Prices did increase, but no huge spikes. As shown in the left graph in Figure 1, at the peak (nadir?) of the Deep Freeze on February 18, the Mont Belvieu spot propane price (blue line) was up only 17% over the January average, while the Conway price (green line) was up about 50%. Given that cold temperature records were being set across much of the country, those increases are relatively modest, especially when compared to the chaos in natural gas (right graph in Figure 1). Spot natural gas prices in the same general geographies were up as much as 150 times the average price in January. Most likely the average price for February will be 10 to 20 times the January average. Nothing like that has ever happened before (see Terminal Frost and  Perfect Storm for our analysis of these market conditions).

OKLAHOMA: Injections wells closed or reduced after earthquake -- Monday, February 22, 2021 -- The injection of wastewater into underground wells by oil and natural gas producers has been stopped or reduced in the area where a magnitude 4.2 earthquake struck in northern Oklahoma.

COVID Obscures New Mexico Legislature — But Oil and Gas Still Get In - When state Sen. George Muñoz, the new head of the New Mexico Senate Finance Committee, wants to hold a meeting, he gets to pick who’s invited. That’s how state senate meeting rules are structured. So if he chooses to invite oil and gas industry representatives to dominate a discussion of the financial ramifications of President Joe Biden’s moratorium on federal oil and gas leases, that’s Muñoz’s prerogative. And that’s exactly what he did on Feb. 2. “We want information that’s good and we can rely on,” he said at the start of the virtual meeting.  The unofficial keynoter was Ryan Flynn, president and CEO of the New Mexico Oil and Gas Association (NMOGA), the state’s best-known oil and gas industry advocacy group. Notably absent were any voices from outside government or industry: no one from Gov. Michelle Lujan Grisham’s green energy development task force; no one to comment on industry’s contribution to the climate crisis; and none of the many New Mexican economists who study the oil and gas industry and its fraught future. Consequently, Flynn — whose group’s stated goal is promoting oil and gas development in New Mexico — and a representative from a Texas trade group were given the chance to tell their story of impending economic catastrophe to a gallery of government representatives on a Zoom call.  And while this might have looked like lobbying, don’t call Flynn a lobbyist because — to the surprise of many — he’s not. Not registered, anyway. He hasn’t been since 2019.  Muñoz began the session by introducing Flynn — with a slip of the tongue. “I keep wanting to say ‘Secretary Flynn,’” he chuckled, recalling Flynn’s previous position as New Mexico Environment Department (NMED) secretary under former Gov. Susana Martinez, whose administration vigorously promoted oil and gas development. “Ryan, you wanna go ahead and start out?” The verbal slip, easy familiarity and starring role illustrate how one of the state’s most powerful lobbies is treated within state government. And it’s an example of the soft power that the oil and gas industry holds in New Mexico and of a revolving door between industry and government.

Natural Gas Battles Local Climate Efforts - Facing the rising threat of wildfire and extreme drought, Flagstaff, Ariz., unveiled an ambitious effort two years ago to cut the heat-trapping emissions that drive climate change.A critical part of Flagstaff's climate plan proposed that all new construction get to net-zero greenhouse gas emissions by 2040 and that the city promote "aggressive building electrification" to decrease reliance on fossil fuels. As in many places, buildings are a big source of Flagstaff's greenhouse gases, mainly because many are heated by burning natural gas.But in February 2020, the Arizona Legislature blocked much of Flagstaff's plan for its buildings. With the backing of the state's main gas utility, the Legislature passed a bill that prevents municipalities and counties from banning new gas infrastructure and hookups."It definitely put a huge hurdle in our plans for promoting electrification and fuel switching," says Nicole Antonopoulos, Flagstaff's sustainability director.The Arizona law was a test case for a strategy the natural gas sector is now deploying nationwide. Gas utilities, with help from industry trade groups, have successfully lobbied lawmakers over the past year to introduce similar "preemption" legislation in 12 mostly Republican-controlled state legislatures, according to the Natural Resources Defense Council (NRDC).The speed and scale of the strategy show just how high the stakes are for the gas industry. According to internal reports and hundreds of recent emails obtained through public records requests and shared with NPR, the gas industry sees an existential threat in the efforts of cities, states, businesses — and now the Biden administration — to sharply reduce fossil fuel use."As you're really looking at what's going to come out of the Biden administration, they're really talking about remaking the entire economy through a green lens, and that means eliminating natural gas," Sue Forrester, vice president of advocacy and outreach at the American Gas Association (AGA), said during an industry conference last November. Gas utilities and their powerful lobby, the AGA, are racing on multiple fronts to convince lawmakers and the public that swapping out natural gas with electric would harm consumers and lead to higher bills. They argue that using natural gas is compatible with addressing climate change, despite scientific evidence to the contrary. Pro-gas groups have emerged around the country with names such as "The Empowerment Alliance" and "Partnership for Energy Progress" to sway local and state debates about electrification. The gas industry has launched ad campaigns on Facebook and Instagram touting gas as far better for cooking.

Fond du Lac Band tells outside protesters to respect its sovereignty after bomb scare - – The Fond du Lac Band of Lake Superior Chippewa is telling pipeline protesters who are not band members to respect its sovereignty after a "potential explosive device" prompted an evacuation near an Enbridge pipeline work site on the band's reservation Friday. The band's governing body said in a statement that it recognizes that some people oppose its decision to allow the project within its borders but asked protesters to honor its sovereign authority. A half-mile area around a rural stretch of Ditchbank Road near Cloquet was evacuated for several hours following reports of a package being thrown onto a work site as protesters were dispersing Friday afternoon, according to the Carlton County Sheriff's Office. A bomb squad was called to the site, and state and federal authorities are investigating. "After careful examination, it was determined that the device was not an explosive agent," the Sheriff's Office said in a news release. "Investigators are following up on a number of leads." Forty area residents were evacuated in addition to pipeline workers in an incident the Fond du Lac Band said "created widespread public safety concerns." Emergency alerts were initially send to a large number of northeastern Minnesota residents before another alert clarified the evacuation order affected only residents in the area. Enbridge also briefly shut down its pipelines in the area. The company said two "nonexplosive items" were removed from inside an open pipe. "This incident disrupted not just a pipeline and the delivery of energy, but the lives of real people," Enbridge said in a statement. "This is unacceptable and we will seek to prosecute those involved to the full extent of the law."

PIPELINES: DOJ to court: Biden axing KXL permit rendered suit moot -- Thursday, February 25, 2021 -- A month after President Biden killed the border-crossing permit for the Keystone XL pipeline, his administration asked a federal appeals court yesterday to dismiss litigation over the approval.

Republicans criticizing Haaland's nomination have ties to fossil fuels - Republicans appear eager to derail the cabinet nomination of Deb Haaland, a Native American congresswoman who wants to conserve federal lands and slow climate change as secretary of the interior to Joe Biden. In two days of confirmation hearings before the Senate energy and natural resources committee, Haaland faced hostile questions from a group of GOP senators who attempted to cast her as an extremist and a danger to American jobs.  Haaland, a 35th-generation New Mexican who would be the first Native American cabinet secretary, supports the Green New Deal and opposes fracking on federal land. As secretary of the interior, she would implement Biden’s climate agenda, which, though relatively ambitious, may not go as far as she would prefer. Hostile questioning at her confirmation hearings was led by senators who have taken huge amounts of campaign cash from the oil and gas industry. Some are personally invested in fossil fuels. John Barrasso of Wyoming, the ranking Republican on the committee, said he was “troubled by many of Representative Haaland’s views”, which he characterized as “radical”. “We shouldn’t undermine our energy production and we shouldn’t hurt our own economy,” he said in an opening statement. “Representative Haaland’s positions are squarely at odds with the mission of the Department of [the] Interior.” Barrasso, who has questioned whether humans contribute to the climate crisis, also complained about a tweet in which Haaland said Republicans don’t believe in science. What he didn’t say was that the oil and gas industry has bankrolled his political career and he is personally invested in a company that transports a sizable portion of US natural gas. From 2015 to 2020, Barrasso’s campaign and leadership political action committee, or Pac, took in more than $480,000 from the pacs of oil and gas companies, more than from any other industry, according to data analyzed by OpenSecrets.org.  In 2018, his most recent election year, his campaign got the maximum amount of $10,000 from the pacs of companies such as natural gas driller Chesapeake Energy, which extracts oil from wells in the Powder River Basin in Wyoming; oil giant Chevron, which owns oil and gas properties in Haaland’s state, New Mexico; and fossil fuel conglomerate Koch Industries. In his full federal career, Barrasso has received nearly $1.2m from oil and gas firms and their employees, making him one of the Senate’s top recipients of such money.

Who will clean up the 'billion-dollar mess' of abandoned US oilwells? - Jill Morrison has seen how the bust of oil and gas production can permanently scar a landscape. Near her land in north-east Wyoming’s Powder River Basin, where drilling started in 1889, more than 2,000 abandoned wells are seeping brine into the groundwater and leaking potent greenhouse gasses.  The problem is getting worse. As the oil and gas industry contracts owing to the pandemic, low prices and the rise of renewables, more than 50 major companies have gone bankrupt in the last year. Joe Biden’s recent order to pause drilling on federal land could drive that number higher. Morrison, a rancher and the head of the Powder River Basin resource council, said the crash was exacerbating the abandonment issue. “They drill baby drilled themselves right out of business,” Morrison said. “We’re seeing something we’ve never seen before in the oil and gas industry, in terms of the downturn, and there’s going to be a billion-dollar mess to clean up.” Unplugged wells, either orphaned well, which have no liable party, usually due to bankruptcy, or idle, abandoned ones, where the company has walked away, but could still be liable, cause rampant methane emissions – up to 8% of US total according to a 2014 analysis. They also leak brine, oil and fracking fluid into the groundwater, and carcinogenic gases, like benzine, into the air, and as their numbers increase the impacts grow.“Methane is a strong greenhouse gas, it’s a precursor for ozone, and harmful for human health,” said Mary Kang, a McGill civil engineering professor who conducted the study. “Even just a few wells can be responsible for big emissions, and there are all the other associated risks, and impacts to wildlife and ecosystems.” The impacts aren’t just here in the rangy fields of Wyoming. There are unremediated wells in Los Angeles neighborhoods and Pennsylvania farms. There could be as many as 3.2m abandoned wells in the US, according to a 2018EPA report, but this is probably an undercount because both federal and state programs for regulating and monitoring non-producing wells are incomplete. There are an estimated 2,500 of them in the Powder River Basin alone. So many have been left uncapped because the regulations and bonding requirements, the money that companies pay ahead of time as insurance, for those wells are so minimal that it’s nearly impossible to hold drillers responsible or to pay for cleanup. Some companies simply walk away from wells, meaning they are still liable; when firms go out of business, they are not. The penalties for not cleaning up a well are minimal when there’s nothing but a small bond holding a company responsible. “How do you convince operators to comply when there’s no carrot and no stick?” That means the profits for drilling go to individual companies while the damages, both environmental and financial, are largely borne by the local community and by state and federal taxpayers. “Unplugged wells devalue property, they’re a mess to work around, it can lead to groundwater pollution, and no one is really tracking it,” Morrison said. ... “The heart of the problem is that we have inadequate bonding requirements in places that allow oil and gas companies to walk away and leave taxpayers holding the bag.”

HazMat firefighters respond to 50-foot oil spill in Val Verde - A HazMat response was called Wednesday morning to a 50-foot oil spill following a leak in Val Verde. Los Angeles County Fire Department personnel responded to the scene near Del Valle Road and Hasley Canyon Road at around 9:56 a.m., according to Fire Department Public Information Officer Jonathan Matheny. A 50-foot circle of oil can be seen at the base of a leaking well on Del Valle Road near Hasley Canyon Road in Castaic on Wednesday, 021721. Dan Watson/The Signal “There’s an oil well there and there’s some oil leaking from the wellhead that is coming downhill,” he said. The spill was reportedly 50 feet in diameter on the ground “but the situation is static, meaning it’s not getting any bigger,” Matheny added. The response team, as well as the oil company, were en route as of 10:15 a.m. to investigate, according to Matheny. No injuries or additional incidents related to the spill were reported.

Gavin Newsom Sued for 'Completely Unacceptable' Approval of Oil and Gas Projects in California --Accusing California regulators of "reckless disregard" for public "health and safety," the environmental advocacy group Center for Biological Diversity on Wednesday sued the administration of Gov. Gavin Newsom for approving thousands of oil and gas drilling and fracking projects without the required environmental review.The lawsuit claims that the California Geologic Energy Management Division (CalGEM) failed to adequately analyze environmental and health risks before issuing fossil fuel extraction permits, as required by law. According to the suit, California regulators approved nearly 2,000 new oil and gas permits without proper environmental review.  "CalGEM routinely violates its duty to conduct an initial study and further environmental review for any new oil and gas well drilling, well stimulation, or injection permits and approvals," the suit alleges. "Instead, CalGEM repeatedly and consistently issues permits and approvals for oil and gas drilling, well stimulation, and injection projects without properly disclosing, analyzing, or mitigating the significant environmental impacts of these projects." The center noted that "despite Gov. Newsom's progressive rhetoric on climate change, he has failed to curb California's dirty and carbon-intensive oil and gas production.""His regulators continue to issue thousands of permits without review, and the governor has refused to act on his stated desire to ban fracking," the group said in a statement. "Newsom's regulators also failed to meet the governor's deadline to publish a draft health-and-safety rule after vowing to do so before the end of 2020." Hollin Kretzmann, an attorney at the Center for Biological Diversity's Climate Law Institute, said Wednesday that "it is completely unacceptable for Gov. Newsom to continue to ignore our flagship environmental law that's meant to protect people from oil industry pollution.""Newsom can't protect our health and climate while giving thousands of illegal permits each year to this dirty and dangerous industry," Kretzmann added. "We need the courts to step in and stop this."

Arctic drilling plan in Alaska hits roadblock (Reuters) - Plans for seismic surveys to help find oil in the Arctic National Wildlife Refuge have fizzled due to a lack of protection for polar bears, according to a brief statement Saturday from the Department of the Interior. The Kaktovik Inupiat Corp (KIC), the Native-owned company that applied for permission to conduct the survey, failed to do the required work to identify polar bear dens in the region that would be surveyed, Interior spokeswoman Melissa Schwartz said in an emailed statement. The likely demise of the seismic plan is the latest in a series of setbacks that have deflated the decades-long ambition to convert the refuge into an oil-producing frontier. Alaska’s oil production has been waning since the late 1980s, when the state produced more than 2 million barrels of crude per day. Now its output is roughly 500,000 bpd. Ex-President Donald Trump passed tax legislation in 2017 that would have allowed for drilling in the ANWR, and the federal government held a lease sale in the last days of his presidency. Identification of den sites was needed for the U.S. Fish and Wildlife to grant KIC an incidental harassment authorization, a permit that would allow seismic operations near polar bears, Schwartz said. “The company was advised today that their request is no longer actionable,” she said in her statement. KIC had planned, through contractor SAExploration, to conduct seismic surveys on 352,416 acres within the refuge’s coastal plain. The company missed a Feb. 13 deadline to perform its aerial den-detection work, Schwartz said. The Jan. 6 ANWR lease sale drew qualifying bids for only 11 tracts, most from an Alaska state agency that was participating as a backstop in case oil companies did not submit bids. President Joseph Biden and Interior Secretary-designee Deb Haaland oppose oil development in the refuge.

Big Oil Posts Record Loss in 2020  --Rystad Energy has highlighted that the five integrated supermajors – ExxonMobil, BP, Shell, Chevron, and Total – posted a combined record loss of $76 billion in 2020. Rystad noted that the major chunk of this loss, $69 billion, can be attributed to asset impairments and write-offs as the supermajors re-evaluated their strategy to focus on the energy transition and become less dependent on petroleum. All five majors reported net losses last year, with ExxonMobil reporting the largest at $22.4 billion, followed by Shell and BP which also incurred losses of more than $20 billion, Rystad outlined. The company said Total and Chevron fared better than their peers, relatively speaking, reporting net losses of $5 billion to $6 billion. Rystad highlighted that all the majors had their gearing ratio raised in 2020, with BP and Shell both ending the year with a gearing above the 30 percent mark. ExxonMobil and Chevron raised a record amount of debt during the year, adding $19 billion and $18 billion respectively to their net debt, Rystad outlined, adding that both majors increased their gearing ratio by ten percent in 2020. The combined oil and gas output of the five majors dropped by nearly five percent, or 0.9 million barrels of oil equivalent per day, in 2020, compared from the year before, Rystad revealed. Lower emission targets and demand for cleaner energy have significantly impacted the long-term production outlook for the majors, according to Rystad, which forecasts that the majors’ net production will be around 17.5 million barrels of oil equivalent per day (boepd) in 2025 and peak at around 18 million boepd in 2028. The company’s internal forecast in February 2020 stood at 19 million boepd for 2025 and 20 million boepd in 2028. “Last year has certainly tested oil and gas majors like never before,” Rahul Choudhary, an upstream analyst at Rystad Energy, said in a company statement. “Some recovery can be expected in the near future as demand rebounds and oil prices cross the $60 mark. However, the key to success for the five majors over the next decade will be to strengthen their business in more resilient regions, restructure and resize to match the market needs, and pay back their high debt levels,” he added.

February's Cold Blast Sets New Records for the Canadian Natural Gas Market | RBN Energy -The February 2021 polar vortex will be one for the natural gas record books in the U.S. and Canada — and the month isn’t even over yet! Though no stranger to frigid weather, Canada’s natural gas market has felt the impacts of this month’s extreme cold on both sides of the border. Its own prices, demand, and storage withdrawals have reached multi-year or all-time records as gas buyers have jockeyed for molecules from anywhere they can get them. Gas exports to the U.S. have reached highs not seen for more than a decade, adding emphasis to what has been an emerging turnaround story for Canadian gas into the U.S. market. To top things off, the latest gas market records might be a preview of what is to come in the next few years as Canada’s structural demand for natural gas continues to increase, regardless of how cold it is. Today, we describe all the latest Canadian gas market action and what might be in store for next winter. In the past week, we have been discussing the impacts that the extreme cold snap of February 2021 have had on energy markets. In our coverage last week, the impacts that the deep freeze has wrought on the U.S. natural gas and power markets have been plain to see, with skyrocketing gas prices (East Is East, West Is West) due to wellhead freeze offs (Terminal Frost), surging demand, and storage withdrawals that have struggled to balance both sides of the supply-demand equation (Perfect Storm). Cash prices at ONEOK Gas Transmission (OGT) hub in Oklahoma surged to an unheard of $1,250/MMBtu and some regions literally ran out of gas. However, the U.S. has not been alone in feeling the freakishly cold weather’s effects on demand, supplies, storage, and prices. Canadian natural gas markets have also experienced turmoil due to the February extremes. Prices have swelled, new demand records have been set, supplies have fallen, and storage withdrawals have cranked up to never-seen-before levels to keep supply and demand in balance. With gas needed everywhere all at once it seems, even long-suffering Canadian gas exports to the U.S. have recently surged to levels not seen for more than a decade. Like many a polar vortex, this one was initially felt in Western Canada and steadily expanded south and east from there. The impacts are typically seen first in the Alberta natural gas market, a province and market that is all too familiar with bone-chilling temperatures. Drawing on data from RBN’s Canadian NATGAS Billboard, the demand effects of the cold can be readily seen in the early days of this month (green oval in left graph in Figure 1). Though demand was already seasonally elevated, Alberta’s latest spike in gas demand began on February 5, reaching a new record peak of 7.7 Bcf just four days later on February 9 (green dot in middle graph). So intense was the cold in some parts of Alberta that a string of lofty demand highs were established, with six of the top 10 strongest demand days all occurring on either side of the February 9 record high. Pretty impressive for a gas market that, as we said, is used to extremely cold weather.

Crews respond to diesel spill in B.C. Central Coast - -- Crews continue to try to minimize environmental damage caused by a Feb. 15 diesel fuel spill in the Wannock (Owikeno) River and the Rivers Inlet marine environment in B.C.'s Central Coast. According to the Ministry of Environment and Climate Change Strategy, a report was received that a tanker truck carrying between 7,000 to 8,000 litres of diesel was leaking fluid into the river, due to a crack in a line from one of the trailer units. The ministry says provincial and federal resources were deployed to the community and containment booms and sorbents were placed around the spill. •Traditional knowledge at centre of efforts to protect land from shipwreck's fuel •Oil continues to spill from sunken freighter off Vancouver Island; wildlife affected •New marine oil spill response base to begin construction on Vancouver Island The fuel is used for diesel power generators used by a nearby community and is situated where an old cannery is located, according to the ministry. A release issued by the Wuikinuxv Nation says their administration office was informed of a suspected leak and believes that more than 6,000 litres made it onto the ground and approximately 650 to 700 litres actually reached the inlet. “The spill is close to three culturally and ecologically rich wetland and estuary sites” the release indicates. “The Emergency Operations Centre, Operations and Maintenance and Stewardship Office are working with federal and provincial partners to assess, contain and clean up the spill.” A Transport Canada National Aerial Surveillance Program flight was conducted to map the spill and help identify priorities and sensitive areas around the spill site.

Natural Gas production falls below 3 bcf/d - Natural Gas production averaged less that three billion cubic feet per day (bcf/d) for the first time since the 1990s according to well placed sources at the Ministry of Finance. The Sunday Business Guardian has learnt that for January 2021 natural gas production averaged 2,990 million standard cubic feet per day (mmscf/d) or less than 3bcf/d. This is 1.2 bcf/d less than the installed capacity in T&T and is part of the reason the Minister of Finance Colm Imbert has raised alarm at the low natural gas production. On January 10, Imbert told a news conference that due to depressed oil and gas prices and lower than expected production, revenue from royalties on oil and gas was down by almost half – $806 million or 49.2 per cent. Meanwhile extra ordinary receipts from oil and gas companies also fell by 98.2 per cent or $100 million. The Central Bank in its Economic Bulletin for January reported that natural gas production declined by 23.6 per cent (year-on-year) over the second half of 2020. The bank said Atlantic LNG’s Train 3 was taken down for planned maintenance during the period, which coincided with similar activity at BPTT, the country’s largest natural gas producer. The fourth quarter of 2020 also saw a drop in LNG production at Train 1 amid discussions amongst its shareholders surrounding the future operation of the facility. Natural gas production dropped 29.8 per cent (year-on-year) during October to November 2020 alongside a 46.9 per cent fall in LNG production. The bank noted that the downstream industry also saw declines in output, with methanol production declining 29.4 per cent during the period, while production of ammonia was down by 1.1 per cent.

Israel's beaches blackened by tar after offshore oil spill (Reuters) - Israel is trying to find the ship responsible for an oil spill that drenched much of its Mediterranean shoreline with tar, an environmental blow that will take months or years to clean up, officials said. Thousands of volunteers gathered on Sunday to remove the clumps of sticky black refuse from the pale beaches. Israel’s military said it was deploying thousands of soldiers to help with the effort. Authorities warned everyone else to keep their distance until further notice. Environmental groups called it an disaster. Attesting to the cost to wildlife, they posted pictures of tar-covered turtles. The event began last week during a winter storm, which made it harder to see the tar approaching and deal with it at sea, Israeli officials said. Together with European agencies, Israel was looking as a possible source at a Feb. 11 oil spill from a ship passing about 50 km (21 miles) from shore. Satellite images and modelling of wave movements were helping to narrow the search. Nine ships that were in the area at the time are being looked at, said Environmental Protection Minister Gila Gamliel. “There is a more than reasonable chance that we will be able to locate the specific ship,” she told Ynet TV. If found, Israel could take legal action. One course would be to sue insurance companies for compensation to help deal with the ecological fallout, she said, which could cost tens of millions of shekels. Late last week a 17-metre-long (55ft) fin whale was found washed up on a beach in southern Israel. The Nature and Parks Authority said on Sunday that an autopsy had found oil-based material in the whale’s body, with further tests pending.

Israeli Oil Spill Is a 'Severe Ecological Disaster’ -  A mysterious oil spill began to wash up on Israel's coast last week, closing beaches and harming wildlife. The Israeli government urged people not to visit a wide stretch of beach on Sunday, Haaretz reported. Of Israel's 119 miles of beach, 105 were impacted by the disaster, according to CNN. That's 40 percent of Israel's coastline, Haaretz noted.  "The enormous amounts of tar emitted in recent days to the shores of Israel from south to north caused one of the most severe ecological disasters to hit Israel," the country's Nature and Parks Authority said Sunday, CNN reported.People first noticed the oil last Wednesday, according to Haaretz. It washed up as sticky, dark pieces of tar,NPR reported. As of Monday, it had spread to the beaches of southern Lebanon, Reuters reported.  Animals have also been found covered in tar, including a few birds and nine sea turtles, Haaretz added. Sadly, four of the turtles died. The rest have been taken to the National Sea Turtle Rescue Center to recover. Additionally, a fin whale washed up dead on the Israeli coast on Thursday. Preliminary tests revealed that it did contain oil in its body, Reuters reported. Not least, ecologists are worried about Dendropoma petraeum, a reef-building snail whose population is already declining because of the climate crisis, NPR reported. Volunteers have rallied to help with cleanup efforts, with more than 4,000 people from the non-profit EcoOcean working to remove the tar. However, the Israel Nature and Parks Authority said it would take years to remove all of it, Haaretz reported. Most of the work will have to be done by hand. The government is currently investigating the cause of the spill with the help of European authorities, according to NPR. Israel thinks it likely spilled from a ship about a week ago during stormy weather in the Mediterranean. One candidate is a Feb. 11 oil spill from a ship passing about 21 miles from shore, Reuters reported.Environmental Protection Minister Gila Gamliel said the investigation had pinpointed nine ships as potential culprits.

Israel hit by worst environmental disaster in decades - Although the exact cause of the disaster is still under investigation, the head of the Israel Nature and Parks association said the incident is the country's worst environmental disaster in decades. The cleanup of over 170 km (106 miles) of affected coastline will take a long time and consequences will be felt for years. Dozens of tons of fresh tar lumps began landing on Israeli beaches in Habonim, Maagan Michael, and Neve Yam on Wednesday, February 17, 2021. On Sunday, February 21, Israel's Ministry of Environmental Protection (MoEP) warned people to refrain from going to beaches from Rosh Hanikra, in the north, down to Zikim Beach in the Hof Ashkelon Coastal Council, until further notice. "Do not go to Mediterranean Sea beaches for swimming, sports, or recreational activities until further notice," the ministry said Sunday. "Exposure to tar can be harmful to public health! The Ministries are continuing to monitor the situation and will update the public regarding this matter." It's still unclear what the source of the tar is, landing on the beaches since Wednesday morning, authorities said. Tar is a product of the decomposition and crystallization of oils and oil products. This is usually the result of the illegal dumping of oil into the sea from a passing ship. "The source is not known, but it should be noted that if it's from the dumping of oil from a ship, it may have traveled a great distance," MoEP said. Because the tar that has been landing on the coasts is either semi-solid or completely solid, it must be removed manually, with the oily and sand debris being separated from regular debris as much as possible, the ministry said. "The disaster we are witnessing in recent days on the beaches of Israel is the most serious ecological disaster in recent years, and we'll see its consequences in years ahead," the country's Nature and Parks association said.

Oil spill off Israels coast is its worst maritime pollution in decades --Tar that has washed up along Israel’s coast in recent days represents the country’s worse maritime pollution in decades, with officials blaming dozens of tons of oil spilled at an unknown location at sea. The accident has marred beaches over 170 kilometers (106 miles), 40 percent of Israel’s coast, affecting 16 communities. Air patrols dispatched on Saturday were able to pinpoint oil slicks between 200 to 500 meters from the coast, moving towards the mainland in the north of the country, around the port city of Haifa.  Thousands of volunteers joined major cleaning efforts organized by NGOs and local authorities over the weekend. Officials say much work remains to remove all the tar, and most of it will have to be done by hand. The Israel Nature and Parks Authority believes the cleanup will take years.  "This event will not end in the next few days, we are preparing for long, hard work," said Environmental Protection Minister Gila Gamliel, as she announced that the government had allocated emergency funding to local authorities to deal with damage locally.  The pollution was first noticed Wednesday; the Environmental Protection Ministry says the most likely scenario is an unreported spill from a tanker. On Saturday, Minister Gamliel said information received from the European Maritime Safety Agency points to an area about 50 kilometers off the Israeli coast as the source of the pollution, which occurred about a week ago. "We've identified 10 vessels that passed through that area, and one or more of them could be responsible for this severe incident," she said. Identifiying the source might prove difficult, as officials say the tanker in question likely operated illegally and therefore not monitored. Using the European agency's staellite tracking systems, the search for the source of the spill has been narrowed down. However, officials still await more specific information. Even then, it remains unclear what punitive measures could potentially be taken against the tanker's operators. Wildlife in danger After two days of masses of tar washing up on the shores, particularly in the Haifa area at the Galim, Dor, Habonim and Gedur beaches, cleanup teams reported a decrease on Friday. Since Wednesday, animals have been found covered with tar, including a few birds and nine sea turtles. Four of the turtles died, while the others were taken to the National Sea Turtle Rescue Center at Mikhmoret between Tel Aviv and Haifa. There they were fed in an attempt to increase their metabolism and dilute the oil in their bodies.

Solomon Islands hit by another big oil spill - Two years since authorities were confronted with a major bunker spill, the government of the Solomon Islands is facing another big clean-up, accusing the crew of a 30-year-old bulk carrier of dumping around 1,000 tonnes of heavy fuel oil into local waters.The 1991-built, Panama-flagged Quebec stands accused of deliberately dumping fuel into the sea. The 28,451 dwt handysize ship, which European database Equasis says is managed by Singapore’s Feng Sea Shipping, was carrying out a logging shipment for a Chinese company when it dumped heavy fuel oil into Graciosa Bay in Temotu province in late January, the Solomons government claims.The director of the Solomon Island Maritime Authority, Thierry Nervale, told state media an initial assessment of the Quebec spill indicated about 1,000 tonnes of heavy fuel oil had been discharged, and that the government would pursue legal action against the vessel’s owners.“For us, it is clear that this is deliberate pollution of our seas. It’s not accidental,” Nervale said. The Hong Kong-flagged Solomon Trader ran aground on February 4 in 2019 in Kangava Bay off Rennell Island near the world’s largest raised coral atoll, a UNESCO world heritage site, becoming that year’s most high profile dry bulk casualty. It was loading bauxite in inclement conditions when the accident happened, which led to hundreds of tonnes of bunker fuel spilling and the ship being declared a total constructive loss.

Bolsonaro appoints Army reserve general to head Petrobras  --Brazil's far-right president, Jair Bolsonaro, appointed an Army reserve general to lead state-owned energy giant Petrobras, after criticising several successive increases in the price of fuel. "The government decided to appoint Joaquim Silva e Luna to fulfill a new mission, as... president of Petrobras, after closing the cycle, exceeding two years, of the current president Roberto Castello Branco," said a brief note from the Ministry of Mines and Energy, published by the president on his Facebook account. Silva e Luna, formerly the defence minister under president Michel Temer, had been serving as general director of the Itaipu Binacional dam. His nomination will have to be confirmed by the Petrobras board of directors. Earlier Friday Bolsonaro had announced that there would be "changes" at Petrobras. "We will never interfere in this great company, nor in its pricing policy, but people cannot be surprised with certain increases," Bolsonaro said during a morning event in the northeastern state of Pernambuco. He did not give further details. His statements were followed by a sharp drop in the oil company's share prices. They closed down 7.92 percent Friday, with preferred shares down 6.63 percent.

Iraq decides to freeze oil prepayments deal on rising oil prices(Reuters) - Iraq has decided to freeze its first crude oil prepayment deal, which had aimed to boost its finances, because oil prices are rising, the country’s oil minister told BBC Arabic on Sunday. “We had concerns that oil prices would not rise above $40 when we announced this deal for the first time in the history of Iraq,” Iraq’s Oil Minister Ihsan Abdul Jabbar told the channel. Brent crude has been trading above $60 a barrel recently. Asked about the status of the prepayment crude oil deal, Abdul Jabbar said: “With the start of this year and the economic stability resulted from boosted oil prices, we decided to freeze this option.” Chinese state oil trader Zhenhua Oil Corp had emerged as the frontrunner in a tender to buy Iraqi crude for five years after it submitted the “most competitive bid” in the tender held by Iraq’s state oil marketer SOMO that attracted participation from international oil companies, trading houses and Chinese and Indian refiners. OPEC member Iraq was seeking a five-year prepayment starting January 2021 until December 2025 to be repaid with cargoes of its Basra crude, according to a letter sent by state oil marketer SOMO to its customers and seen by Reuters. Under the prepayment deal, the winner of the tender was to pay SOMO about $2.5 billion in return for 48 million barrels of crude between July 1, 2021 and June 30, 2022.

Oil prices rise with storm-hit U.S. output set for slow return - Oil prices rose on Monday as the slow return of U.S. crude output cut by frigid conditions served as a reminder of the tight supply situation, just as demand recovers from the depths of the COVID-19 pandemic. Brent crude was up $1.78, or 2.85%, at $64.70 per barrel. West Texas Intermediate gained $1.89, or 3.2%, to trade at $61.13 per barrel. Abnormally cold weather in Texas and the Plains states forced the shutdown of up to 4 million barrels per day (bpd) of crude production along with 21 billion cubic feet of natural gas output, analysts estimated. Shale oil producers in the region could take at least two weeks to restart the more than 2 million barrels per day (bpd) of crude output affected, sources said, as frozen pipes and power supply interruptions slow their recovery. "With three-quarters of fracking crews standing down, the likelihood of a fast resumption is low," ANZ Research said in a note. For the first time since November, U.S. drilling companies cut the number of oil rigs operating due to the cold and snow enveloping Texas, New Mexico and other energy-producing centres. OPEC+ oil producers are set to meet on March 4, with sources saying the group is likely to ease curbs on supply after April given a recovery in prices, although any increase in output will likely be modest given lingering uncertainty over the pandemic. "Saudi Arabia is eager to pursue yet higher prices in order to cover its social break-even expenses at around $80 a barrel while Russia is strongly focused on unwinding current cuts and getting back to normal production," said SEB chief commodity analyst Bjarne Schieldrop. 

Oil jumps almost 4% as output slow to recover from Texas storms (Reuters) - Oil prices rose nearly 4% on Monday, boosted by the expected slow return of U.S. crude output after last week’s deep freeze in Texas shut in production. U.S. producers shut anywhere from 2 million to 4 million barrels per day of oil output due to cold weather in Texas and other oil producing states, and the unusually cold conditions may have damaged installations that could keep output offline longer than expected. Brent crude settled at $65.24 a barrel, rising $2.33, or 3.7%, while U.S. oil settled at $61.49 a barrel, jumping $2.25, or 3.8%. The U.S. benchmark crude contract for March delivery expires on Monday, and the more widely-traded April contract was up $2.44, or 4.1%, at 61.70 a barrel.Shale oil producers in the region could take at least two weeks to fully restart normal output, sources said, as damage assessments and power disruptions slow their recovery. “The significant loss of both crude and gasoline production suggests more upside and likelihood of new highs possibly within a one-week time frame,” But he cautioned that with limited refining capacity, price could under pressure if refiners take weeks to return to normal. “The market is behaving as if the refiners are going to come online quicker than the headlines would lead you to believe,” said Yawger. Gasoline crackspreads, an indicator of refiners’ margins have dropped by 5%.For the first time since November, U.S. drilling companies cut the number of oil rigs operating due to the cold and snow enveloping Texas, New Mexico and other energy-producing centres, signalling even tighter supplies ahead. [RIG/U] OPEC+ oil producers are set to meet on March 4, with sources saying the group is likely to ease curbs on supply after April given a recovery in prices, although any increase in output will likely be modest given lingering uncertainty over the pandemic.

Oil prices jump more than $1 on slow U.S. output restart -- Oil prices jumped by more than $1 on Tuesday, as U.S. output was slow to return after a deep freeze in Texas shut in crude production last week. Shale oil producers in the southern United States could take at least two weeks to restart the more than 2 million barrels per day (bpd) of crude output that shut down because of cold weather, as frozen pipes and power supply interruptions slow their recovery, sources said. Brent crude was up $1.06, or 1.6%, at $65.30 a barrel by 0204 GMT, after earlier hitting a high of $66.38. U.S. crude rose 81 cents, or 1.4%, to $62.51 a barrel, after hitting a session high of $62.73. Both benchmarks have risen more than 1% after climbing nearly 4% in the previous session. "The positive momentum continues in the oil complex, with investors unabashedly predisposed to a bullish view," said Stephen Innes, chief global markets strategist at Axi in a note. Goldman Sachs Commodities Research raised its Brent crude oil price forecasts by $10 for the second and third quarters of 2021, citing lower expected inventories, higher marginal costs to restart upstream activity and speculative inflows. The Wall Street bank expects Brent prices to reach $70 per barrel in the second quarter from the $60 it predicted previously and $75 in the third quarter from $65 earlier. Morgan Stanley expects Brent crude prices to climb to $70 per barrel in the third quarter on "signs of a much improved market" including prospects of a pick-up in demand. "It is hard not to be bullish with oil prices now that the deep freeze disruption practically guarantees the summer pickup in crude demand will erase whatever supply glut is left," said Edward Moya, senior market analyst at OANDA in New York. "The global oil demand is looking a lot better now that the Pfizer vaccine shows positive results after one dose, the U.K. sees the end of the pandemic 'in sight', and as hospitalizations and deaths continue to decline after peaking in early January." Stockpiles of U.S. crude oil and refined products likely declined last week, a preliminary Reuters poll showed on Monday, due to the disruption in Texas.

$100 Oil Bets Surge After Texas Turmoil - Amid all the issues ignited in the Texas turmoil, and as oil prices roar to post-COVID highs, analysts across the energy space appear to be outdoing each other with their bullish forecasts. Brent Crude prices could hit $70 a barrel in the second quarter of 2021, while they are set to average $60 this year, Bank of America said this week, raising its average price outlook by $10 a barrel from its previous projection. Echoing Bank of America, Morgan Stanley also sees Brent touching the $70 mark this year, but a bit later - in the third quarter, expecting “a much-improved market,” including on the demand side. On Sunday, Goldman Sachs started the investment banks’ upgrades of oil price forecasts, expecting Brent Crude prices to hit $75 a barrel in the third quarter this year, on the back of faster market rebalancing, lower expected inventories, and traders hedging against inflation. But those forecasts all pale in comparison to Azerbaijan’s Socar Trading SA predicts global benchmark Brent could hit triple digits in the next 18 to 24 months, and Bank of America sees potential spikes above $100 over the next few years on improving fundamentals and global stimulus. And, even with the WTI curve deep in backwardation...Bloomberg reports, speculators are also getting in on the action, increasing bets in the options market that oil will reach the vaunted level by December 2022. As the chart below shows, the open interest in these $100 strike Dec 2022 calls has exploded higher since the turmoil in the Texas energy markets.

WTI Tumbles After Surprise Crude, Gasoline Builds  -- Oil prices held on to gains today, amid equity market chaos, with WTI just losing $62 after hours.“After a $2 rally yesterday,” it was hard to sustain further gains, said Peter McNally, global head for industrials, materials and energy at Third Bridge.Still, “if the combination of seasonal demand, vaccine rollouts and ongoing supply constraints all conspire, it looks like inventories will continue to decline.”We suspect tonight's data will be a mess given the impacts of the Texas storms on demand, refinery capacity, and production. API

• Crude +1.026mm (-5.372mm exp)
• Cushing +2.738mm (-3.034mm exp)
• Gasoline +66k (-3.472mm exp)
• Distillates -4.489mm (-3.905mm exp)

Analysts' expectations were for a 5th weekly draw in a row (10th draw in last 11) but API reports a surprise crude build of just over 1mm barrels and a surprise build in gasoline stocks too...

WTI Surges Above $63 Despite Surprise Crude Build, Plunge In Gasoline Demand --Oil prices have rebounded higher overnight after dropping on a surprise crude build reported by API, as stockpiles at a key European storage hub are at their lowest level since September, according to Genscape. Additionally, the structure of the futures curve continues to indicate tighter supply.“Yesterday’s choppy performance in the oil and equity markets has fueled speculation over how much further the rally in risk assets has to go,” said Stephen Brennock, analyst at PVM Oil Associates.“Oil prices are treading water ahead of what is sure to be a weather-affected EIA update concerning U.S. oil stockpiles.”Pent up demand as the global economy recovers has even got some traders talking about the prospect of returning to $100 crude over the next year or two. DOE

• Crude +1.29mm (-5.372mm exp)
• Cushing +2.807mm (-3.034mm exp)
• Gasoline +12k (-3.472mm exp)
• Distillates -4.969mm (-3.905mm exp)

DOE confirmed API's reports of a modest crude and gasoline build (and large distillates draw)... Overall crude stocks remain near 13 month lows...

Oil rises after data shows slump in U.S. output amid Texas freeze (Reuters) - Oil prices climbed on Wednesday to fresh 13-month highs after U.S. government data showed a drop in crude output after a deep freeze disrupted production last week. U.S. crude oil production dropped last week by more than 10%, or 1 million barrels per day, during the rare winter storm in Texas, equaling the largest weekly fall ever, the Energy Information Administration said. Refinery crude inputs dropped to the lowest since September 2008 as the freeze knocked out power to millions. [EIA/S] “If you’re getting that kind of drop in one week of EIA production, you’re likely to get more after that,” said Phil Flynn, senior analyst at Price Futures in Chicago. “There is some concern that this will be a long-term permanent production drop.” Traffic at the Houston ship channel was slowly coming back to normal but terminals were still facing several issues. After nearly a quarter of national refining capacity was idled by the freeze, refineries have also started to come back online this week. Brent crude futures rose $1.67, or 2.6%, to settle at $67.04 a barrel. The global benchmark hit a session high of $67.30 a barrel, its loftiest since Jan. 8, 2020. U.S. West Texas Intermediate (WTI) crude futures ended $1.55, or 2.5%, higher at $63.22 a barrel, after touching $63.37, also their highest since Jan. 8, 2020. The rally continued oil’s steady march to levels not seen since prior to the coronavirus pandemic as vaccine distribution increases and on forecasts for renewed demand. Oil prices have rallied about 30% since the start of the year, boosted as well by ongoing supply cuts by the Organization of the Petroleum Exporting Countries and its allies. 

Oil mixed, U.S. crude hits highest since 2019 as refineries restart - (Reuters) - Oil prices were mixed on Thursday with U.S. crude edging up to its highest close since 2019 as Texas refineries restarted production after last week’s freeze, while Brent eased on worries that four months of gains will prompt producers to boost output. Earlier in the day, an assurance that U.S. interest rates will stay low and a sharp drop in U.S. crude output last week due to the winter storm in Texas, helped boost both U.S. crude and Brent to their highest intraday prices since January 2020. Brent futures for April delivery fell 16 cents, or 0.2%, to settle at $66.88 a barrel. The April Brent contract expires on Friday. U.S. West Texas Intermediate (WTI) crude, meanwhile, ended 31 cents, or 0.5%, higher at $63.53, its highest close since May 2019. Analysts said WTI increased late in the day as more Texas refineries started to return to service, including Valero Energy Corp’s Port Arthur plant and Citgo Petroleum Corp’s Corpus Christi plant. The freeze caused U.S. crude production to drop by more than 10%, or a record 1 million barrels per day (bpd) last week, while refining runs tumbled to levels not seen since 2008, the Energy Information Administration said. [EIA/S] “The more refineries return to service, the more crude oil they will burn through, and the less crude oil will go to storage,” said Bob Yawger, director of energy futures at Mizuho in New York. Overall, however, analysts noted price gains slowed on Thursday. “With momentum appearing to slow a week before the next OPEC+ meeting, crude may be positioning for a small correction,” said Craig Erlam, senior analyst at OANDA, noting “There’s still plenty of downside risks in the market and one of them is OPEC+ unity coming under strain in the coming months.” The Organization of the Petroleum Exporting Countries and its allies including Russia, a group known as OPEC+, are due to meet on March 4. Analysts noted recent higher oil prices - both Brent and WTI have gained more than 75% over the past four months - could encourage U.S. producers to return to the wellpad and OPEC+ to loosen its production reductions. The group will discuss a modest easing of oil supply curbs from April given a recovery in prices, OPEC+ sources said, although some suggest holding steady for now given the risk of new setbacks in the battle against the pandemic.

Oil prices hit 13-month highs on tighter supplies, Fed assurance on low rates -- Oil prices remained close to 13-month highs on Thursday, with profit-taking limited by an assurance that U.S. interest rates will stay low and a sharp drop in U.S. crude output last week due to the storm in Texas. Brent crude for April slid 0.24% to settle at $66.88 per barrel. Earlier in the session the contract traded as high as $67.70, the highest level since Jan. 2020. U.S. West Texas Intermediate gained 0.49% to settle at $63.53 per barrel, after hitting a high of $63.81 per barrel earlier in the session, the highest level since Jan. 2020. Tamas Varga, analyst at PVM Oil Associates, said the dip was partly due to profit taking after a three-day rally. An assurance from the U.S. Federal Reserve that interest rates would stay low for a while weakened the U.S. dollar, while boosting investors' risk appetite and global equity markets. The winter storm in Texas caused U.S. crude production to drop by more than 10% or 1 million barrels per day (bpd) last week, the Energy Information Administration said. Fuel supplies in the world's largest oil consumer could also tightened as its refinery crude inputs had dropped to the lowest since September 2008, EIA's data showed. ING analysts said U.S. crude stocks could rise in weeks ahead as production has recovered fairly quickly while refinery capacity is expected to take longer to return to normal. Barclays, which raised its oil price forecasts on Thursday, said it oil could rally again on the weaker-than-expected supply response by U.S. oil operators to higher prices. "However, we remain cautious over the near term on easing OPEC+ support, risks from more transmissible COVID-19 variants and elevated positioning," Barclays said. The Organization of the Petroleum Exporting Countries and allies including Russia, a group known as OPEC+, are due to meet on March 4. The group will discuss a modest easing of oil supply curbs from April given a recovery in prices, OPEC+ sources said, although some suggest holding steady for now given the risk of new setbacks in the battle against the pandemic. Extra voluntary cuts by Saudi Arabia in February and March have tightened global supplies and supported prices.

Oil prices fall on rising U.S. dollar, expectations for supply gains Oil dips, but posts gains for the week and month - Oil prices fell on Friday as a collapse in bond prices led to gains in the U.S. dollar and expectations grew that with oil prices back above pre-pandemic levels, more supply is likely to come back to the market. U.S. West Texas Intermediate (WTI) crude futures dipped 3.2% to settle at $61.50 per barrel. For the week the contract gained 3.81%. For February WTI advanced 17.82%. Brent crude futures for April delivery slid 1.12% to $66.13 per barrel. "Bonds are selling off reasonably aggressively and the U.S. dollar has firmed this morning. That's providing a bit of a headwind for crude oil this morning," said Lachlan Shaw, National Australia Bank's head of commodity research. A stronger greenback makes U.S.-dollar priced oil more expensive for those buying crude in other currencies. Despite the drop in prices on Friday, both Brent and WTI are on track for gains of about 20% this month, as markets have grappled with supply disruptions in the United States, while optimism has built for demand to improve with vaccine rollouts. Investors are betting that next week's meeting of the Organization of the Petroleum Exporting Countries (OPEC) and allies, together called OPEC+, will result in more supply coming back to the market, given the recent jump in prices and expectations that demand will improve as pandemic lockdowns ease heading into the northern hemisphere summer. "The stakes at play this time around are particularly large (for OPEC+) insofar as oil prices have more than recovered to pre-pandemic levels, global inventories are continuing to trend down, and vaccine rollouts are accelerating," Shaw said. "The market's probably right to think at this price level and given what the fundamentals are doing, there'll be more supply coming into the market over time." U.S. crude prices also face headwinds from the loss of refinery demand after several Gulf Coast facilities were shuttered during the winter storm last week. There is about 4 million barrels per day of capacity still shut and it may take until March 5 for all of the shut capacity to resume though there is risk of delays, analysts at J.P. Morgan said in a note this week. "The greater concern to U.S. crude oil market participants should be the recovery of refinery demand," the analysts said. "As refiners assessed the damage to their facilities, it became clear that the road to recovery would be weeks rather than days."

Oil Futures Slide As Dollar Gets Stronger  | Rigzone-- Oil fell the most since November with a stronger dollar and concerns surrounding inflation weighing on crude’s best start to the year on record. Futures in New York declined 3.2% on Friday, with a rising dollar reducing the appeal of commodities priced in the currency. Yet, the U.S. crude benchmark still managed to post a nearly 18% gain this month as inventories worldwide tighten and pockets of demand return. Domestic crude production dropped in 2020 for the first time in four years, according to the U.S. government. “Prices have a little bit more risk to the downside from the recent run that we’ve seen,” said Tariq Zahir, managing member of the global macro program at Tyche Capital Advisors LLC. “To continue going higher from here, demand has to come back pretty substantially.” Crude prices have notched the largest year-to-date gain than in any year prior for the same time period, in part due to OPEC+ production curbs helping to deplete global stockpiles. Plus, the unprecedented cold blast that recently halted millions of barrels of U.S. output means oil markets are about 100,000 barrels a day tighter than previously thought, according to JPMorgan Chase & Co. Supply scarcity may worsen in the coming months as North Sea fields undergo major maintenance. The Organization of Petroleum Exporting Countries and its allies will meet next week to decide on output levels. While Russia has signaled it favors a further easing of production cuts, the country’s oil output dipped below its OPEC+ target this month, meaning it failed to take full advantage of the more generous quota it was afforded after January’s OPEC+ meeting. “We all know the OPEC return to production is looming over the market pretty strongly,” said Gary Cunningham, director at Stamford, Connecticut-based Tradition Energy. Continued declines in global supplies will “depend on how much production OPEC brings back and whether or not the sanctions on Iran are lifted.” West Texas Intermediate for April delivery fell $2.03 to settle at $61.50 a barrel. The U.S. crude benchmark rose 3.8% this week. Brent for April settlement, which expires on Friday, declined 75 cents to end the session at $66.13 a barrel. The contract gained 5.1% this week. The more actively traded May contract declined $1.69 to settle at $64.42 a barrel. Soaring bond yields on Thursday were the latest sign that accelerating inflation could trigger a pullback in monetary policy support that has helped fuel gains in risky assets during the pandemic. While global bonds have since stabilized, a less accommodative approach to monetary policy could have ripple effects across commodity markets.

Iran to launch direct shipping line to S. Africa, Latin America --Iran is going to launch a direct shipping line to South Africa and Latin American countries in near future, an official with the Iranian Chamber of Cooperatives (ICC) informed. According to Babak Afghahi, ICC’s head of the non-oil trade and export development committee, the mentioned shipping line will connect southern Iranian ports to the ports of South Africa and then to Latin American countries, specifically Brazil. The said shipping line is going to be launched with the support of the Islamic Republic of Iran Shipping Lines (IRISL) and is aimed to develop Iran’s non-oil trade with the countries in the mentioned regions. “With the support of the Islamic Republic of Iran Shipping Lines, considering the capacity of Iran’s cargo export to the mentioned destinations, the chambers of commerce across the country, the Trade Promotion Organization (TPO) of Iran and other export bodies have been informed about the new development,” Afghahi said. As reported by IRNA, the Islamic Republic’s trade with South Africa reached $43 million in the first six months of the previous Iranian calendar year (March 21-September 22, 2019), while the figure stood at $27 million in the same period of its preceding year. Following a new strategy for boosting non-oil trade and distancing the country’s economy from oil, Iran has been launching several direct shipping lines to its major trade destinations over the past few years Earlier this month, the Head of Iran-Syria Joint Chamber of Commerce Keyvan Kashefi announced the establishment of a direct shipping line between Iran’s southern port of Bandar Abbas and Syria’s Mediterranean port of Latakia. The country has also launched five direct shipping lines to Oman and is planning to establish direct routes to Qatar, India, Turkmenistan, and Russia as well.

Iran wants US to remove sanctions before nuclear talks to clear more crude - — A top Iranian foreign ministry official on Feb. 21 said the US needs to remove its sanctions before talks can begin to revive the nuclear deal with world powers at a time when the Islamic Republic is expected to bring as much as 1 million b/d of crude back to the market by the end of this year. "For us, the criteria is removing the sanctions," Abbas Araghchi, Iran's deputy foreign minister for political affairs, said in a television interview published Feb. 21 by state news agency IRNA. He noted Iran has set a self-imposed Feb. 23 deadline for sanctions to be removed or Tehran will quit additional commitments to the Joint Comprehensive Plan of Action. Araghchi also said Iran is studying a proposal by EU foreign policy chief Josep Borrell to hold an "informal meeting with the US as a guest." China and Russia are aware, he added. "Principally, we think returning the US to the JCPOA doesn't need negotiations. If they want to return to the JCPOA, it's obvious that they should remove the sanctions," he said. The Biden administration on Feb. 18 formally offered to restart negotiations with Tehran, inching the two sides closer to a deal that could see the restoration of Iran's approximately 2.6 million b/d export capacity. President Joe Biden has said the US will rejoin the nuclear deal but only after Tehran resumes full compliance with its terms. In 2018, the US under former president Donald Trump dropped out of the JCPOA signed between Iran and global powers, and imposed tighter sanctions on the country. "I think there is going to be back and forth between the sides in coming weeks/months, but we still think 1 million b/d of additional Iranian oil by year end is more reasonable to assume," Shin Kim, head of supply and production at S&P Global Platts Analytics, said Feb. 21 when asked about Iran's response. Iranian crude production has climbed steadily since the US election in November. In January, Iran pumped 2.14 million b/d of crude, its highest since November 2019, according to the latest Platts survey of OPEC output. More is likely to come, sources have told Platts, particularly in the run-up to the Iranian new year Nowruz celebrations in late March. Platts Analytics said the US and Iran could reach a framework agreement to restore the JCPOA as early as in the next one to three months, with Iranian crude supply to grow by 1 million b/d between February and December. Full sanctions relief may not happen until the fourth quarter, however, assuming Iran would need four months to return its uranium enrichment levels to JCPOA compliance, Platts Analytics said. "Output then grows by 500,000 b/d by June 2022 and 150,000 b/d by end-2022," it said in a recent note.

U.S. launches air strikes on facilities in Syria used by Iran-backed militia - The United States launched airstrikes in Syria on Thursday, targeting facilities near the Iraqi border used by Iranian-backed militia groups. The Pentagon said the strikes were retaliation for a rocket attack in Iraq earlier this month that killed one civilian contractor and wounded a U.S. service member and other coalition troops. The airstrike was the first military action undertaken by the Biden administration, which in its first weeks has emphasized its intent to put more focus on the challenges posed by China, even as Mideast threats persist. Biden’s decision to attack in Syria did not appear to signal an intention to widen U.S. military involvement in the region but rather to demonstrate a will to defend U.S. troops in Iraq. “I’m confident in the target that we went after, we know what we hit,” Defense Secretary Lloyd Austin told reporters flying with him from California to Washington. Speaking shortly after the airstrikes, he added, “We’re confident that that target was being used by the same Shia militants that conducted the strikes,” referring to a Feb. 15 rocket attack in northern Iraq that killed one civilian contractor and wounded a U.S. service member and other coalition personnel. Austin said he recommended the action to Biden. “We said a number of times that we will respond on our timeline,” Austin said. “We wanted to be sure of the connectivity and we wanted to be sure that we had the right targets.” Earlier, Pentagon spokesman John Kirby said the U.S. action was a “proportionate military response” taken together with diplomatic measures, including consultation with coalition partners.

Iran Says S.Korea To Release $1BN Of Its Frozen Funds After Tanker Seizure - Iran and South Korea have been engaged for the past two months in intense crisis meetings triggered by the Jan.4 Iranian seizure of the South Korean-flagged tanker MT Hankuk Chemi off the Islamic Republic's southern waters. From the start of the IRGC's capturing the vessel and detaining its crew, Tehran pointed to $7 billion to $10 billion in Iranian assets in Korean banks previously frozen by Seoul in compliance with US-led sanctions. The clear message has been that the tanker can be released when the funds are released, despite the official Iranian claim that the Hankuk Chemi violated 'environmental protocols'. And now Iran’s Central Bank says Seoul has agreed to release some of these funds. It's expected that $1 billion cash will be unfrozen in the first phase. "In the meeting with the South Korean envoy, we stressed how Iran could use its resources," Governor of the Central Bank of Iran (CBI) Abdolnaser Hemmati told state media on Wednesday. "Great damage has been incurred on the Islamic Republic. It was Koreans themselves who asked and [came] to say that they are seeking to pay Iran’s assets and we showed them how to do so," the Iranian bank official added. Ironically it had been Tehran officials that charged Seoul with "hostage taking" - in the form of badly needed funds at a moment the Iranian economy is being strangled by Washington sanctions. While the release of the 19-person crew was already accomplished in early February, it appears Iran is still holding the oil tanker itself. South Korea’s Ministry of Foreign Affairs had said of the crew's release at the time:  "The two sides... shared the view that the release of the sailors was an important first step to restore trust between the two countries and they will work to resolve the issue of frozen Iranian assets in South Korean banks," according to The Hill.At this point there hasn't been clear confirmation from the South Korean side that it's unfreezing $1 billion as touted in Iranian sources. However, it's clear that intensive talks have been ongoing, with South Korea previously scrambling to send diplomatic teams to Tehran over the tanker issue.

Explosion strikes Israeli-owned ship in Mideast amid tension - -- An explosion struck an Israeli-owned cargo ship sailing out of the Middle East on Friday, an unexplained blast renewing concerns about ship security in the region amid escalating tensions between the U.S. and Iran. The crew and vessel were safe, according to the United Kingdom Maritime Trade Operations, which is run by the British navy. The explosion in the Gulf of Oman forced the vessel to head to the nearest port. The incident recalled the summer of 2019, when the same site saw a series of suspected attacks that the U.S. Navy blamed on Iran, which Tehran denied. Meanwhile, as President Joe Biden tries to revive nuclear negotiations with Iran, he ordered overnight airstrikes on facilities in Syria belonging to a powerful Iranian-backed Iraqi armed group. Dryad Global, a maritime intelligence firm, identified the stricken vessel as the MV Helios Ray, a Bahamian-flagged roll-on, roll-off vehicle cargo ship. Another private security official, who spoke to The Associated Press on condition of anonymity to discuss intelligence matters, similarly identified the ship as the Helios Ray. Satellite-tracking data from website MarineTraffic.com showed the Helios Ray had been nearly entering the Arabian Sea around 0600 GMT Friday before it suddenly turned around and began heading back toward the Strait of Hormuz. It was coming from Dammam, Saudi Arabia, and still listed Singapore as its destination on its tracker. Israel’s Channel 13, in an unsourced report, said the assessment in Israel is that Iran was behind the blast. Israeli officials did not immediately respond to requests for comment. The Iranian government did not comment on the blast Friday. The blast comes as Tehran increasingly breaches its 2015 nuclear accord with world powers to create leverage over Washington. Iran is seeking to pressure Biden to grant the sanctions relief it received under the deal that former President Donald Trump abandoned nearly three years ago. Iran also has blamed Israel for a recent series of attacks, including a mysterious explosion last summer that destroyed an advanced centrifuge assembly plant at its Natanz nuclear facility and the killing of Mohsen Fakhrizadeh, a top Iranian scientist who founded the Islamic Republic’s military nuclear program two decades ago.

Turkey's Eternal Crusade On PKK Continues -Turkey is unrelenting in its crusade against the Kurdistan Worker’s Party and the People’s Protection Units, as two parts of a whole. Ankara’s forces carry out frequent operations within and without the country, targeting both the Kurdistan Worker’s Party’s (PKK) and the People’s Protection Units (YPG)’s interests and members. The Turkish government dubs both groups as terrorists, and does not shy away from invading the sovereign territory of other countries to pursue and “eliminate” their members and positions. As a result, Turkey frequently encroaches on Syrian and Iraqi territory, and even has observation posts set up to target its Kurdish enemy. It strongly opposes the Syrian Democratic Forces, a group whose core is comprised of the YPG, and receives heavy US support. Most recently, between February 10th and the 14th, Turkey began its most recent operation in northern Iraq. In particular, it took place on the Gara Mountain in the Duhok Governorate of the Kurdistan Region. The result was such that both the PKK and the Turkish Armed Forces claimed victory, following the operation. The accounts of what transpired vary. Turkey said it killed 53 PKK members, and captured 2. It admitted to losing 3 soldiers, while 4 of its troops were wounded in battle. According to the PKK, Turkey lost at least 30 soldiers, and dozens more were injured. A sort of collateral damage involved 13 Turkish hostages whose corpses were discovered in a cave network in the mountain area. Turkey and the US claimed that these were largely civilians, and some intelligence officers. The PKK claimed these were 13 Turkish military hostages. Turkey’s Defense Minister claimed many weapons and ammunition, as well as other equipment were seized. In the aftermath, Turkish president Recep Tayyip Erdogan vowed to expand military operations which showed progress to other regions where threats are still significant.

CNOOC Makes Large Oil and Gas Find --CNOOC Limited announced Monday that the company has made a “large sized” oil and gas discovery at the Bozhong 13-2 asset in Bohai Bay. Discovery well BZ13-2-2 was drilled and completed at a depth of 17,135 feet and encountered oil pay zones with a total thickness of approximately 1,135 feet, CNOOC noted. The well was tested to produce an average of approximately 1,980 barrels of crude oil and 5.25 million cubic feet of natural gas per day, the company highlighted. “The successful exploration of Bozhong 13-2 structure is another remarkable exploration achievement for the company to continuously enhancing [sic] its efforts in oil and gas exploration and production in offshore China,” Zhou Xinhuai, the general manager of CNOOC’s exploration department, said in a company statement. “After obtaining Bozhong 19-6 large sized condensate gas field, the company has made significant breakthrough in the exploration of another type of buried hill in Bohai, which not only has important promotion value, but also demonstrates promising exploration prospect in Bohai,” Xinhuai added. The Bozhong find is the first discovery CNOOC has announced in 2021. The company’s last discovery announcement came in March 2020, when it revealed that it had made a “large sized” find at Kenli 6-1 in Bohai Bay. Discovery well KL6-1-3 was drilled and completed at a depth of 5,236 feet and encountered oil pay zones with a total thickness of approximately 65 feet, CNOOC revealed in a company statement at the time, adding that the well was tested to produce around 1,178 barrels of oil per day. The CNOOC Group is the largest producer of offshore crude oil and natural gas in China and one of the largest independent oil and gas exploration and production companies in the world, according to its website..