Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 27 February 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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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…
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…
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.
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