Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 03 April 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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US refinery utilization at a 53 week high, gasoline production at a 25 week high
Oil prices rose for the first time in four weeks, despite an OPEC decision to increase output, as the new US infrastructure plan is expected to increase demand for oil…after falling 0.7% to $61.42 a barrel last week as new Covid infections and lockdowns increased worldwide, the contract price of US light sweet crude for May delivery opened lower on Monday on news that the container ship that had blocked oil traffic for nearly a week in the Suez Canal had been refloated, but reversed to finish 59 cents or 1% higher at $61.56 a barrel after Reuters reported that Russia would support stable oil output ahead of a meeting with the OPEC later in the week…but oil prices fell on Tuesday as the Suez Canal was cleared and traders focused on the upcoming OPEC+ meeting and the impact of Covid-19 on oil demand in Europe, and finished $1.01 or 1.6% lower at $60.55 a barrel, as near-term risks to the demand recovery story emerged with setbacks to economic reopening plans worldwide…oil prices opened lower on Wednesday after the American Petroleum Institute reported surprisingly large crude inventory build, but reversed to show a 1% gain by midday after the EIA reported a modest inventory withdrawal, before reversing again to tank 2% before the close after France announced it would start a month-long lockdown in the face of another Covid surge, as oil prices ended $1.39 lower on the day at $59.16 a barrel….however, oil prices jumped at the open and moved sharply higher on Thursday, despite the news that OPEC+ had reached a deal to gradually ease production cuts from May, as traders took heart in their incremental increases over three months and reacted to the announcement Biden’s vast infrastructure plan that includes investments in roads, railways, and clean energy that would all take copius quantites of oil and asphalt to build, as oil closed $2.29 higher at $61.45 a barrel, and with the markets closed on Good Friday, thus finished the week’s trading with a modest 0.8% gain…
Natural gas prices also rose fractionally this week as LNG exports remained at record levels and the weekly storage report showed a smaller inventory build than had been expeccted…after rising 0.9% to $2.557 per mmBTU last week on strong LNG exports and a bullish storage report, the contract price of natural gas for April delivery opened fractionally higher on its last day of trading on Monday and continued rising to finish trading 2.9 cents higher at $2.586 per mmBTU, on record LNG exports and on forecasts for slightly higher heating demand over the coming week…with the contract price of natural gas for May delivery moving to the top of the board on Tuesday, natural gas quotes fell 3.0 cents to $2.623 per mmBTU, even as exports climbed higher, as a weakening weather outlook and the anticipation of an inventory increase kept natural gas prices in check…natural gas futures fell again on Wednesday, slipping 1.5 cents to $2.608 per mmBTU, as traders mulled domestic demand weakness and the potential for a bearish government inventory report on the next day… however, when Thursday’s natural gas storage report came in a bit below market expectations, natural gas prices bounced 2% and went on to settle 3.1 cents higher at $2.639 per mmBTU, as the initial price momentum faded as traders struggled to make sense of the accompanying revision….thus the daily natural gas quotes saw a 3.2% gain on the week as the front month shifted from April to May, while the May contract itself ended the week 0.8% higher, having closed last week at $2.619 per mmBTU…
The natural gas storage report from the EIA for the week ending March 26th indicated that the amount of natural gas held in underground storage in the US rose by 14 billion cubic feet to 1,764 billion cubic feet by the end of the week, after gas in storage for the week ending March 19th was revised 4 billion cubic feet higher to 1750 billion cubic feet…that left our gas supplies 225 billion cubic feet, or 11.3% below the 1,989 billion cubic feet that were in storage on March 26th of last year, and 36 billion cubic feet, or 2.0% below the five-year average of 1,800 billion cubic feet of natural gas that have been in storage as of the 26th of March in recent years….the 14 billion cubic feet that were added to US natural gas storage this week was less than the average forecast of a 19 billion cubic foot addition from an S&P Global Platts survey of analysts, while it contrasted with the 20 billion cubic foot withdrawal from natural gas storage seen during the corresponding week of a year earlier, as well as the average withdrawal of 24 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 March 26th indicated that after a big increase in our oil exports and another big increase in our oil refining, we finally need to withdraw oil from our stored commercial crude supplies for the first time in six weeks and for the 23rd time in the past thirty-six weeks….our imports of crude oil rose by an average of 523,000 barrels per day to an average of 6,145,000 barrels per day, after rising by an average of 299,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 693,000 barrels per day to an average of 3,174,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,971,000 barrels of per day during the week ending March 26th, 170,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly 100,000 barrels per day higher at 11,100,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 14,071,000 barrels per day during this reporting week…
US oil refineries reported they were processing 14,941,000 barrels of crude per day during the week ending March 26th, 552,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 125,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 745,000 barrels per day less than what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+745,000) 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 there must have been a error or errors of that magnitude in this week’s oil supply & demand figures that 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 they’re 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 5,686,000 barrels per day last week, which was 9.4% less than the 6,279,000 barrel per day average that we were importing over the same four-week period last year… the 125,000 barrel per day net withdrawal from our crude inventories was due to a 125,000 barrel per day withdrawal from our commercially available stocks of crude oil, while the oil supplies in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported to be 100,000 barrels per day higher at 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 200,000 barrels per day higher at 10,700,000 barrels per day, while a 10,000 barrel per day decrease to 445,000 barrels per day in Alaska’s oil production subtracted 100,000 barrels per day the rounded national total (EIA’s math)….last year’s US crude oil production for the week ending March 27th was rounded to 13,000,000 barrels per day, so this reporting week’s rounded oil production figure was 14.6% below that of a year ago, yet still 31.7% 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 83.9% of their capacity while using those 14,941,000 barrels of crude per day during the week ending March 26th, up from 81.6% of capacity during the prior week, and the highest refinery utilization in 53 weeks, which appears to reflect utilization during the last week before the Covid slowdown…however, the 14,941,000 barrels per day of oil that were refined this week were just fractionally higher than the 14,898,000 barrels of crude that were being processed daily during the week ending March 27th of last year, when US refineries were operating at a seasonal low 82.3% of capacity…
With the increase in the amount of oil being refined, the gasoline output from our refineries was higher for the 8th time in 20 weeks, increasing by 762,000 barrels per day to a twenty-five week high of 9,339,000 barrels per day during the week ending March 26th, after our gasoline output had decreased by 300,000 barrels per day over the prior week…as a result, this week’s gasoline production was 25.3% higher than the 7,456,000 barrels of gasoline that were being produced daily over the same week of last year, but still 6.3% lower than the March 13 2020 pre-pandemic high of 9.972,000 barrels per day ….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 137,000 barrels per day to 4,738,000 barrels per day, after our distillates output had increased by 1,703,000 barrels per day from a twenty-six year low of 2,898,000 barrels per day over the prior three weeks…but even after that four week rebound in our distillates’ production, this week’s distillates output was still 4.6% lower than the 4,966,000 barrels of distillates that were being produced daily during the week ending March 27th, 2020…
Despite the big increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the sixth time in twenty weeks, and for 19th time in 37 weeks, falling by 1,735,000 barrels to 230,544,000 barrels during the week ending March 26th, after our gasoline inventories had increased by 204,000 barrels over the prior week...our gasoline supplies decreased this week because the amount of gasoline supplied to US users increased by 275,000 barrels per day to 8,891,000 barrels per day, and because our exports of gasoline rose by 108,000 barrels per day to 541,000 barrels per day, and because our imports of gasoline fell by 320,000 barrels per day to 619,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 6.6% lower than last March 27th’s gasoline inventories of 246,806,000 barrels, and about 4% below the five year average of our gasoline supplies for this time of the year…
With the recovery in our distillates production, our supplies of distillate fuels increased for the 3rd time in 10 weeks and for the 11th time in thirty-one weeks, rising by 2,542,000 barrels to 144,095,000 barrels during the week ending March 26th, after our distillates supplies had increased by 3,806,000 barrels during the prior week….our distillates supplies managed to rise this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 521,000 barrels per day to 4,113,000 barrels per day, because our exports of distillates fell by 426,000 barrels per day to 703,000 barrels per day, while our imports of distillates fell by 223,000 barrels per day to 664,000 barrels per day…after this week’s inventory increase, our distillate supplies at the end of the week were 17.9% above the 122,248,000 barrels of distillates that we had in storage on March 27th, 2020, and rose to about 4% above the five year average of distillates stocks for this time of the year…
Finally, with the increase in our oil exports and the recovery in our refinery throughput, our commercial supplies of crude oil in storage fell for the 12th time in the past twenty weeks and for the 24th time in the past year, decreasing by 876,000 barrels, from 502,711,000 barrels on March 19th to 501,835,000 barrels on March 26th…after this week’s modest decrease, our commercial crude oil inventories remained 6% above the most recent five-year average of crude oil supplies for this time of year, and was still nearly 49% above the average of our crude oil stocks as of the fourth week of March over the 5 years at the beginning of this decade, 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 spring lockdowns of last year, after generally rising over the past two and a half years, except for summers and during the 10 weeks prior to the Texas freeze, after generally falling from a record high over the year and a half prior to September of 2018, our commercial crude oil supplies as of March 26th were 7.0% more than the 469,193,000 barrels of oil we had in commercial storage on March 27th of 2020, 11.6% more than the 449,521,000 barrels of oil that we had in storage on March 29th of 2019, and also 18.0% more than the 425,332,000 barrels of oil we had in commercial storage on March 16th of 2018…
This Week’s Rig Count
Note: this week’s rig count was released on Thursday in advance of the Good Friday market holiday, so it only covers 6 days…nonetheless, the rig count rose for the 26th time over the past 29 weeks, and by the most since January 15th, during the week ending April 1st, but it still remains down by 47.3% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US was up by 13 to 430 rigs this past week, which was still down by 234 rigs from the 664 rigs that were in use as of the April 3rd report of 2020, and was 1,499 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 13 rigs to 331 oil rigs this week, after rising by 9 oil rigs the prior week, still leaving us with 225 fewer oil rigs than were running a year ago, and 20.6% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was down by one to 91 natural gas rigs, which was also down by 9 natural gas rigs from the 100 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, there are now two rigs classified as ‘miscellaneous’ drilling this week, one in the middle of the Permian basin in MIdland county Texas, and the other in Lake County, California, while a year ago there were also two such “miscellaneous” rigs deployed…
The Gulf of Mexico rig count was up by 2 to 14 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and 2 continuing to drill for oil in Alaminos Canyon offshore from Texas…that was 4 fewer Gulf of Mexico rigs than the 18 rigs drilling in the Gulf a year ago, when 17 Gulf rigs were drilling for oil offshore from Louisiana, and one rig was drilling for natural gas in the West Delta field, also offshore from Louisiana…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 totals are equal to the Gulf rig counts….
The count of active horizontal drilling rigs was up by 11 to 391 horizontal rigs this week, which was still down by 202 rigs from the 593 horizontal rigs that were in use in the US on April 3rd 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 directional rig count was up by 4 rigs to 19 directional rigs this week, but those were still down by 22 from the 41 directional rigs that were operating during the same week a year ago….on the other hand, the vertical rig count was down by 2 to 20 vertical rigs this week, and those were down by 10 from the 30 vertical rigs that were in use on April 3rd 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 April 1st, the second column shows the change in the number of working rigs between last week’s count (March 26th) and this week’s (April 1st) count, the third column shows last week’s March 26th 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 3rd of April, 2020..
This is the first week in a while where the new activty has been so widespread, rather than largely limited to the Permian…checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that that one rig was added in Texas Oil District 8A, which encompasses the northernmost counties of the Permian Midland basin, while one rig was pulled out of Texas Oil District 7C, which includes the southernmost counties of the Permian Midland basin, which thus means there was no change in the rig count in the Texas Permian this week…since the national Permian rig count was up by 3, that means that all three rigs that were added in New Mexico must have been added in the farthest west reaches of the Permian Delaware, to account for the national Permian increase….elsewhere in Texas, there was one rig added in Texas Oil District 1, another rig added in Texas Oil District 2, and yet another a rig added in Texas Oil District 3, any two of which could have been the rigs added in the Eagle Ford shale, which stretches in a narrow band through the southeast part of the state…at the same time, there was also a rig added in Texas Oil District 6, which doesn’t appear to have been targeting that region’s Haynesville shale, since the Haynesvile was down by the single rig pulled out in northern Lousiana…Louisiana’s rig count is still up by one, however, because of the two oil rigs added in that state’s offshore waters…elsewhere, two oil rigs were added in Oklahoma, including one in the Granite Wash, two more oil rigs were added in a Utah basin not named by Baker Hughes, more than likely the Uinta, and an oil rig was added in Colorado, which apparently wasn’t targeting the state’s DJ Niobrara chalk…for changes in natural gas rigs, we have the rig that was removed from Louisiana’s Haynesville shale, and another rig that was pulled out of West Virginia’s Marcellus, while a rig was added in Pennsylvania’s Marcellus at the same time…
Eureka Resources expanding operations in northeast Pennsylvania. – Eureka Resources, LLC, an environmental services company operating produced water treatment facilities in the Marcellus Shale region, announced the beginning of construction for phase II of its co-products warehousing and distribution facility in Standing Stone Township, Bradford County, Pa. According to the company, “This high-tech job creation project will allow Eureka Resources to continue to return fresh water to the hydrological cycle, from the hydraulic fracturing process.” The Bradford County facility will streamline and centralize the distribution of extracted valuable minerals such as sodium; calcium, lithium, and chloride from natural gas wastewater from existing operations and a new facility planned in Dimock Township, Susquehanna County, Pa. “By extracting these valuable minerals from wastewater using our innovative and patented technology, we are returning clean freshwater into the hydrological cycle. This reduces water withdrawals from streams and aquifers while eliminating reliance on destructive underground injection disposal used for waste fluids” said Eureka CEO Dan Ertel. “Furthermore, the process we have pioneered in the Marcellus and Utica Shale formations assists the U.S. in reducing dependence on foreign countries for these critical minerals.” The company reports a history of DEP-monitored clean water discharge since 2014 with no violations of any kind.
Appalachian fracking faces financial risks, report warns. Hopes for petrochemical plastics boom ‘unlikely.’ –Developing new shale gas fields in Appalachia “may not end up being profitable” in the years ahead, according to a new report. In addition, the associated petrochemical buildout that the region has pinned its hopes on as the future of natural gas is “unlikely,” the report states.Natural gas drillers need prices to rise in order to turn a profit and continue expanding, a scenario that appears doubtful, according to the report published by the Stockholm Environment Institute’s US Center (SEI) and the Ohio River Valley Institute (ORVI), a Pennsylvania-based economic and sustainability think tank. Volatile market conditions for plastics are also putting the region’s plans for new petrochemical plants in question.Given the poor financial results from the industry over the past decade, “gas prices would need to rebound and increase” if the fortunes of Appalachia’s shale industry are to improve, study co-authors, Peter Erickson, climate policy program director at SEI, and Ploy Achakulwisut, a scientist at SEI, wrote in the report. Appalachia – already suffering from a long drawn out bust in the coal industry – has for much of the past decade seen natural gas prices languish as drillers pumped too much gas out of the ground, which has resulted in persistently low prices. And a renewed price surge appears unlikely as gas faces growing competition from solar and wind.“Now there are signs that gas itself could get passed up for lower-cost renewables, introducing new risks for communities that rely on gas extraction for employment and tax revenue,” the authors wrote.Due to liquefied natural gas (LNG) being a powerful and growing source of climate pollution, LNG’s expansion “would need to be – at best – short-lived,” the SEI/ORVI report’s authors state, noting that global decarbonization efforts could displace much of the gas demand that the industry is anticipating. At the same time, a souring market for petrochemicals – a result of the industry overbuilding capacity and an uncertain plastic consumption outlook in the future – also undercuts the need for developing a major new petrochemical hub in the region. This is much to the disappointment of various business groups, regional politicians, and even the U.S. government who had planned on this being one of the last bastions of hope for the shale gas industry.The financial performance of Appalachian shale gas drillers has been consistently poor, with the industry broadly cash flow negative since its inception in the late 2000s. After a decade-long drilling boom, production ran into a wall in late 2019 and has stagnated since. Production remains high, but the frenetic pace of drilling is long gone.
Environmental groups hail Biden’s plan, but gas industry finds it lacking – Reactions to President Joe Biden’s infrastructure and jobs plan, set to be announced Wednesday afternoon in Pittsburgh, were divided, with environmental groups hailing the clean-energy aspects while energy producers said natural gas and pipelines should be bigger parts of the proposal. The American Jobs Plan, a $2 trillion infrastructure and climate-response program, offers a host of energy- and climate change-related initiatives. Citing last month’s power problems in Texas, Biden’s proposal to Congress will put $100 billion into a more resilient electrical grid and a plan to step up the conversion of the country to carbon-free electricity generation by 2035. That includes tax credits and a leveraging of private investment to construct more than 20 gigawatts of high-voltage power lines and allowing for existing rights of way to have more transmission lines while at the same time putting tax credits and investment into clean energy. It also wants to put $16 billion into plugging old and abandoned oil and gas wells and abandoned coal mines, something that has been advocated by environmentalists and others to address a growing problem in Pennsylvania and around the country. This would, the Biden administration said, put energy employees to work using their existing skills to clean up these hazards. But it was the lack of investment in pipelines that drove the energy industry’s criticism of Biden’s package. Representatives from the natural gas industry say the benefits of the shale revolution aren’t getting the recognition they deserve from Biden’s plan. Natural gas infrastructure – including pipelines, export terminals and power plants – are key parts of job creation and American national security, said Marcellus Shale Coalition President David Callahan. “Pennsylvanians understand the essential role of natural gas and support pragmatic, commonsense market-driven innovations over radical policies that will drive up energy costs, jeopardize grid reliability and eliminate good-paying jobs,” Callahan said. “As the president and Congress work toward a broad infrastructure package, let us be absolutely clear: natural gas is essential to our nation’s future prosperity and continued environmental progress.”
New NJ Bill Would Prompt PennEast Pipeline Review – Two members of Congress from New Jersey have introduced a bill to improve the review process of proposed pipeline projects. This comes after the Biden administration recently backed the PennEast Pipeline in a Supreme Court case. Rep. Bonnie Watson Coleman (D- Mercer) and Tom Malinowski (D-Hunterdon) on Wednesday announced the introduction of the Safe and Accountable Federal Energy Review for Pipelines Act of 2021. According to Watson Coleman and Malinowski, the U.S. Federal Energy Regulatory Commission (FERC) has for years relied on outdated private agreements to determine whether to approve future natural gas pipelines. “The current process for pipeline approval lacks the necessary oversight to protect our natural environment and ensure future generations can live on a safe and clean planet,” Watson Coleman said in a statement. “The SAFER Pipelines Act will ensure the approval of future pipelines consider existing capacity as well as closely monitor the environmental impacts of new construction.” Watson Coleman is a member of the Energy and Water Development Subcommittee of the House Appropriations Committee. Earlier this month, Watson Coleman and Malinowski released a statement expressing “disappointment” after the Department of Justice submitted a brief defending PennEast pipeline’s efforts to seize New Jersey land for a project. Read More Here: NJ Representatives Disappointed As Biden Backs PennEast Pipeline PennEast is planning to build a 120-mile natural gas pipeline from Pennsylvania to New Jersey, cutting through Hunterdon and Mercer Counties. Malinowski said that the current approval process has “failed landowners in New Jersey.”
N.J. Warns of Undermining States in Supreme Court Pipeline Case – Bloomberglaw.com – A win for a pipeline developer in a pending U.S. Supreme Court case would trample state sovereignty, New Jersey lawyers told the high court Wednesday. “Fundamental precepts of sovereign immunity establish that private parties cannot sue nonconsenting States. That rule extends to condemnation suits,” New Jersey Attorney General Gurbir S. Grewal (D) argued in the state’s brief. At issue is the proposed PennEast natural gas pipeline, a $1 billion project that would stretch more than 100 miles from Pennsylvania to New Jersey. PennEast received approval from the Federal Energy Regulatory Commission and began using eminent domain authority to seize…
Hearing on re-powering Hudson Valley gas plant draws lots of speakers – With a ruling expected inside of a year, nearly 300 speakers signed up for a web-based public hearing Wednesday afternoon on a proposal to rebuild and re-activate the Danskammer power plant along the Hudson River near here. A second hearing before the Public Service Commission’s Electric Generation Siting and the Environment also was set for Wednesday evening. Even though, the plan submitted to the Public Service Commission has been deemed to be complete, most of Wednesday’s speakers said they opposed the plant due to the pollution that an expanded larger natural-gas fired facility would emit. “We have clean energy programs on the way,” said Beth Hoeffner, an Orange County resident, referring to the state’s push, under a landmark 2019 law calling for greenhouse gas reductions in the coming decades. “The emissions will worsen climate change,” said Caroline Fenner, with Mothers Out Front, a nearby Dutchess County group. “I’m not the only person that needs clean air,” said Ann Logan, a resident of New York City’s Upper West Side. Like some others who spoke against the plant, she lived outside the plant’s immediate location in the Newburgh area. But like others, she referenced the 2019 Climate Leadership and Community Protection Act, which lays the groundwork for a transition to green energy such as wind and solar to meet future power needs. The law calls for carbon free electricity in the state by 2040. Others noted that the plant would use fracked natural gas from out of state, even though New York has banned drilling for such gas amid fears of harming the water supply. The Danskammer plant isn’t new or closed. Dating to the 1950s and originally built to burn coal, the facility currently operates as a “peaker,” plant which is fired up during periods of peak power need, usually in summer when air conditioning use strains the grid. But owners Danskammer Energy Inc. are proposing a $500 million plan to retire its current equipment and rebuild the plant, user newer cleaner technology for a 600-megwatt capacity plant to operate on an ongoing basis. Part of that could be to fill any energy holes created by the coming shut-down of the last unit at Indian Point nuclear plant near Peekskill. They say the plant would run 60-70 percent of the time but because it would use new equipment, would offset pollution such as nitrogen oxide that older gas plants in the area currently emit.
Pieridae plans to use fracked natural gas from Pennsylvania at its proposed Goldboro LNG plant, and that’s a huge problem – Halifax Examiner –Pieridae US, a Canadian States-Canada corporation, states that the U.S.-sourced natural gas will be exported to Canada at the United border near Baileyville, Maine, at the juncture of the Maritimes & Northeast (M&N) US Pipeline and the M&N Canada Pipeline (collectively, the M&N Pipeline). Pieridae US seeks to export this volume of U.S.-sourced natural gas in the Goldboro LNG Project, where the U.S.-sourced natural gas is liquefied, then re-exported as LNG from Canada by vessel to any other country with which trade is not prohibited by U.S. law or policy (non-FTA countries). “The Pierdae Energy export plan states that it intends to take advantage of the abundance of natural gas from the Marcellus shale fracking fields in Pennsylvania,” reported Tim Faulkner for ecoRI News. “This natural gas is the main source of fuel to meet the project’s goal of exporting up to 800 million cubic feet of domestically produced natural gas per day through a new LNG facility in Nova Scotia.” To bring natural gas from Pennsylvania to Nova Scotia required connecting the Texas Eastern pipeline travelling through Pennsylvania to the M&NP pipeline via a project called “the Atlantic Bridge,” which hinges on a compression plant built in North Weymouth, Massachusetts, just south of Boston. That connection is now complete. On its website, Pieridae has described the source gas for Goldboro in several ways, but so far as I can see, never from the US. In 2018, it said the source fuel was from Quebec and New Brunswick. By 2010, Shell Oil fields in Alberta and British Columbia were added. But again: no mention of Pennsylvania. Moreover, in a PowerPoint presentation before Canadian federal officials in which it was requesting $925 million in financing from the Canadian government, Pieridae made no mention that the money would be used, in part, to enable it to sell gas from Pennsylvania.Nova Scotia bans fracking, as does Germany. Both jurisdictions have determined that fracking simply presents too many environmental and social problems than they’re willing to enable. Joan Baxter asked the German government about its fracking ban in relation to the government’s proposed plan to provide partial financing for the Goldboro plant: Baxter: Although there are moratoriums on hydraulic fracturing in Germany (and in Nova Scotia, where Goldboro is to be built), it appears that at least a portion of the LNG may come from fracked sources. Given these moratoriums, why would the German state provide loan guarantees for a company that will be sourcing fracked gas? Is this not a contradiction and betrayal of German public policy? The German Ministry for Economic Affairs and Energy didn’t really answer the question:
All Eyes on Weymouth as FERC Signals Interest in Environmental Justice – Drilled News – Local activists and legislators have been fighting the Enbridge natural gas compressor in Weymouth for years. It’s too close to residents and businesses, and poses too many health risks to a community that’s already borne the burden of too much pollution, they say. The project was approved by FERC in 2019, built and became operational in 2020. Then it had an emergency shutdown. And another. Now FERC is considering the unprecedented move of re-thinking its permit, a decision that could have broad ramifications.Check out Miriam Wasser’s ongoing reporting on this at WBUR: https://www.wbur.org/earthwhile/2021/03/19/weymouth-compressor-ferc-precedent-enbridge-natural-gas (audio & transcdript)
Stream crossings for Mountain Valley Pipeline become more complicated – Mountain Valley Pipeline’s path across hundreds of streams and wetlands, one of the last unfinished parts of a project long delayed by controversy, could grow even longer and more complicated. The Virginia Department of Environmental Quality recently informed federal officials that it could take nearly a year to issue a water quality certification needed as part of a renewed application for water body crossings. “Based on the complexity of this project and past public controversy, we cannot reasonably issue the VWP [Virginia Water Protection] permit before December 2021 and believe it is quite likely that we could not issue this permit until early 2022,” Melanie Davenport, DEQ’s director of water permitting, wrote Thursday in a letter to the U.S. Army Corps of Engineers. Davenport asked the Army Corps to extend a deadline that normally falls 120 days after an application is submitted, in this case July 2. If the Army Corps were to approve the request, it would make it all but impossible for Mountain Valley to complete construction of the $6 billion project by year’s end, as it has been telling investors and the public since last November. Original plans called for work to be done by 2018, but lawsuits by environmental groups have led to multiple delays. Mountain Valley is disappointed with DEQ’s request and “continues to target a late 2021 in-service date,” spokeswoman Natalie Cox said Monday.
Virginia says it can’t issue stream crossing permit for Mountain Valley Pipeline before winter — Despite developers’ hopes of completing the Mountain Valley Pipeline by the end of 2021, Virginia’s Department of Environmental Quality has told federal officials that it won’t be able to issue a new water quality permit for the project’s stream crossings before December. “Based on the complexity of this project and past public controversy, we cannot reasonably issue the (Virginia Water Protection) permit before December 2021 and we believe it is quite likely that we could not issue this permit until early 2022,” wrote DEQ Water Permitting Division Director Melanie Davenport in a March 25 letter to the U.S. Army Corps of Engineers. While Mountain Valley Pipeline previously sought to use a “blanket permit” known as Nationwide Permit 12 to authorize all stream crossings along its 303-mile length, its developers reversed course in January following legal challenges and broader uncertainty regarding the permit’s future. Under Virginia’s State Water Control Law, any natural gas pipeline that is more than 36 inches in diameter has to obtain a Virginia Water Protection Permit covering “each wetland and stream crossing” from DEQ. Mountain Valley Pipeline is 42 inches in diameter. In her letter to the corps, Davenport said that review, public comment and public hearing procedures laid out in state law would make it “impossible” for Virginia to issue the permit by the July 2 deadline set by the Army Corps. Instead, the state is requesting that it be given until March 3, 2022, to issue the permit. Mountain Valley Pipeline spokesperson Natalie Cox said that the pipeline’s in-service date of late 2021 remains in place. Once scheduled to be completed in 2018, Mountain Valley’s in-service date has been pushed back repeatedly as the project has faced intense public opposition, particularly in Virginia, numerous environmental violations and the loss of numerous permits as a result of court challenges. Another major pipeline intended to transport natural gas from the Marcellus and Utica shale fields to the South Atlantic region, the Atlantic Coast Pipeline, was canceled by developers Dominion Energy and Duke Energy in July 2020 after delays caused costs to balloon.
“This land means a whole lot to me:” Property owners, advocates in Memphis fight to stop pipeline project – CBS News – Clyde Robinson calls a green acre of land in southwest Memphis his legacy. It’s been in his family since the 1930s. “This land means a whole lot to me,” he told CBS News’ Adriana Diaz. The 80-year-old is among several Memphis landowners fighting to keep a crude oil pipeline from cutting through their property. Robinson and others, like Scottie Fitzgerald, said they are being robbed of their land and livelihood. “This, to me, it is hurtful. I am offended,” Fitzgerald said. The two energy companies overseeing the project plan to build a pipeline about 4 feet underground. It would stretch 49 miles in order to connect two existing pipelines transporting crude oil to the Gulf Coast. The company Plains All American said the Byhalia Pipeline is “a safe, responsible way to meet the energy needs of our country” and said they’re paying above market price to homeowners for access to their land. But environmental activists and many locals said the pipeline companies are pressuring mostly Black property owners to build through their land while also putting Memphis’ pristine drinking water at risk of contamination. “We are facing one of the most significant environmental justice and environmentally racist projects in the country’s present and history in Memphis, Tennessee,” said Justin Pearson, co-founder of Memphis Community Against The Pipeline. Pearson said Memphis is the largest municipality in the country to solely rely on groundwater for its drinking water. He said the pipeline would be built in an area where there are known breaches in the clay layer. “And so there are holes where this contamination would more quickly get to our drinking water source than other places in the city or other places where they may operate pipelines. It is not true that this is safe,” Pearson said.
CBS This Morning puts national spotlight on Byhalia Pipeline fight – The proposed Byhalia Pipeline fight in Memphis was featured Thursday on CBS This Morning, where opponents called the project environmental racism. Nearby landowners and activists appeared on the program talking about the impact to properties from the crude oil pipeline and its potential impact on the city’s aquifer. The company behind the controversial Byhalia Pipeline responded to that criticism, saying they’ve chosen the path with the least amount of impact on Memphis residents. They also noted that the vast majority of homeowners living on land slated to be used for the project have agreed to allow the work to happen. As proposed, the Byhalia Pipeline will run 49 miles through parts of Memphis, and Desoto and Marshall counties in Mississippi, connecting two existing crude oil pipelines. Groups in Memphis have taken issue with the project saying it primarily impacts Black neighborhoods like Boxtown and runs over the Memphis water supply. To date, several celebrities have joined the cause, including former Vice Presiden Al Gore. On Thursday, Katie Martin with Plains All American said that they have listened to members of the community and have spoken with researchers on how they can install the pipeline in a responsible way and meet the nation’s energy needs. The route was drawn so it would impact the least amount of people -often taking advantage of vacant lots. They purposefully avoided landmarks and densely populated areas, she said. Those homeowners who will be impacted have been offered a fair market value for access to the land, and to date, 97 percent have accepted their proposal. Martin said the company did not draw the line to specifically target one group or another.
Driftwood Pipeline expansion offers Haynesville enhanced market access – Driftwood Pipeline announced March 29 the start of a binding open season for its proposed Line 200 and Line 300 expansion project intended to serve growing natural gas demand along the US Gulf Coast. The project would significantly expand shippers’ market access to industrial, petrochemical, power generation and LNG export demand along the Gulf Coast with interconnections to 12 existing interstate and intrastate pipelines. The project’s phase 1 development would originate at a proposed interconnect with Texas Eastern Transmission near Ragley, Louisiana, moving gas 37 miles southwest to a termination point at Carlyss, Louisiana. The 42-inch diameter pipeline would transport up to 2.4 Bcf/d with service expected to begin by September 2024. The project’s phase 2 development would offer additional compression, boosting capacity to a maximum 3.2 Bcf/d by its expected completion in June 2026. The final development phase would include construction of an additional 31 miles of 42-inch diameter looped pipeline, expanding the project’s maximum capacity to a total of 4.6 Bcf/d with a targeted in-service date of December 2026. The Driftwood Pipeline itself remains a proposed project that would ship gas 96 miles southwest from Evangeline Parish, Louisiana to the Driftwood LNG terminal. While neither project has been sanctioned by developer, Tellurian, both projects did receive a green light from the Federal Energy Regulatory Commission in April 2019. Tellurian’s proposed Louisiana pipeline promises to improve market access from multiple producing basins across the US but could offer the biggest advantage to producers in the nearby Haynesville shale. Along with the developer’s 2 Bcf/d Haynesville Global Access Pipeline, Tellurian’s proposed midstream projects in Louisiana would give Haynesville producers access to additional interstate and intrastate pipelines capable of reaching end-users across the Gulf Coast. As output from the Louisiana/Texas shale continues rebounding from last year’s drilling slowdown, upcoming midstream expansions are now looking critical to the basin’s future growth. Month to date, gas production from the Haynesville has averaged its highest on record at over 12.7 Bcf/d. With Enverus data showing an estimated 47 rigs currently in operation, the Haynesville is now the only US basin where drilling activity has exceeded its pre-pandemic level. According to recent forecasts from S&P Global Platts Analytics, this year’s acceleration in upstream activity there could see output grow by an incremental 15% or more by late 2021.
U.S. natgas rises on record LNG exports, higher demand views (Reuters) – U.S. natural gas futures rose on Monday on record liquefied natural gas (LNG) exports and forecasts for slightly higher demand this week, while the possibility of an early start to the injection season partly limited gains. On their last day as the front-month, gas futures NGc1 for April delivery on the New York Mercantile Exchange rose 2.9 cents, or 1.1%, to settle at $2.586 per million British thermal units. “Natural gas is getting a bounce partly because of increased demand expectations and concerns over the delay of LNG shipments, because of the Suez Canal,” said Phil Flynn, a senior analyst at Price Futures Group in Chicago. “Some of the power outages we saw from Texas are ending, so we are seeing more electricity demand. So a combination of those factors are giving a little bit of support.” Shipping traffic through Egypt’s Suez Canal has resumed after the refloating of a giant container ship that had been blocking the busy waterway for almost a week. nL1N2LR06I nC6N2J002N Data provider Refinitiv estimated 181 heating degree days (HDDs) over the next two weeks in the Lower 48 U.S. states. The normal number for this time of year is 213 HDDs. HDDs measure the number of degrees a day’s average temperature is below 65 degrees Fahrenheit (18 degrees Celsius) and are used to estimate demand to heat homes and businesses. Refinitiv projected average gas demand, including exports, would rise to 99.2 bcfd this week from 97.5 bcfd in the prior week. The amount of gas flowing to U.S. LNG export plants, meanwhile, has averaged 10.7 bcfd so far in March. That compares with a four-month low of 8.5 bcfd in February, when extreme cold cut power and gas supplies to the facilities, and puts feedgas on track to match the monthly record of 10.7 bcfd in December. nL1N2LH11V Buyers around the world continue to purchase near-record amounts of U.S. gas because prices in Europe TRNLTTFMc1 and Asia JKMc1 remain high enough to cover the cost of buying and transporting the U.S. fuel across the ocean. However, there is “market anticipation of a possible storage injection to be announced this Thursday. If so, then this year’s injection season will start one week earlier than usual, which indicates a somewhat bearish news to the market”, Output in the Lower 48 has averaged 91.1 billion cubic feet per day (bcfd) so far in March, up sharply from a 28-month low of 86.5 bcfd in February. That, however, was still much lower than the record monthly high of 95.4 bcfd in November 2019.
May Natural Gas Futures Falter, Despite LNG Momentum – Natural Gas Intelligence – Robust U.S. export activity held at lofty levels, but natural gas futures fell again on Wednesday as traders mulled domestic demand weakness and the potential for a bearish government inventory report on Thursday. EIA storage March 26 The May Nymex contract settled at $2.608/MMBtu, down 1.5 cents day/day. It declined 3.0 cents a day earlier, its first session as the prompt month. June fell 1.4 cents on Wednesday to $2.667. NGI’s Spot Gas National Avg., however, advanced 12.0 cents to $2.450 amid a brief blast of chilly rains and cool air over the Midwest and eastern Lower 48 ahead of warmth in April. Liquefied natural gas (LNG) levels were strong throughout March, boosted by rising European demand in addition to continued Asian imports. A harsh winter in Europe depleted stockpiles, creating a need to bolster inventories with U.S. LNG ahead of the summer cooling season. LNG feed gas volumes eclipsed 11.7 Bcf on both Tuesday and Wednesday, near record levels, according to NGI data. But forecasters said that, as the weather heats up in April, customary spring maintenance projects would limit capacity at LNG facilities and eat into feed gas volumes. Rising temperatures also could push much of the Lower 48 into a multi-week period of comfortable weather conditions that minimize both heating and cooling needs, dampening demand for natural gas.
US natural gas storage injection season starts early with 14 Bcf build | S&P Global Platts – The first net injection of the year to natural gas stocks came one week earlier than normal because of the arrival of mild weather across much of the US, as the Energy Information Administration also revised the pull for the week prior down 4 Bcf. Storage inventories increased 14 Bcf to 1.764 Tcf for the week ended March 26 EIA reported the morning of April 1. The injection was below the 19 Bcf build an S&P Global Platts’ survey of analysts expected. It stood in contrast to historical draws of 20 Bcf and 24 Bcf reported during the same week a year ago and the five-year average, respectively, according to EIA data. Storage volumes now stand 225 Bcf, or 11%, below the year-ago level of 1.989 Tcf and 36 Bcf, or 2%, below the five-year average of 1.8 Tcf. The report also featured a revision to the week ended March 19 from a 36 Bcf to a 32 Bcf draw because of a discrepancy in the South-Central region’s non-salt storage fields. Gas demand for power generation in the Southeast and Texas averaged 11.1 Bcf/d in March, 2.2 Bcf/d below both February 2021 and March 2020, according to S&P Global Platts Analytics. Despite temperatures in the region averaging 2.5 degrees above normal, the lower burns mainly were driven by a rise in wind and coal to the generation stacks of the Electric Reliability Council of Texas and SERC Reliability Corporation. In March 2020, gas accounted for 41% of ERCOT’s generation stack, with wind at 26% and coal at 30%. This March, gas is down to 36% while wind and coal are up to 38% and 33%, respectively. For SERC, gas made up nearly 60% of total generation in March 2020 while coal was responsible for just 13%. This year, coal generation is up to 20%, while the gas share slid to 50%. While wind generation relies on the weather, prices mainly dictate coal and gas generation and can explain some of the higher coal burns this year versus last year. Prices at the Henry Hub in Louisiana last March averaged $1.75/MMBtu while, this March, they have averaged $2.57/MMBtu, which has encouraged more coal generation. The NYMEX Henry Hub May contract rose 2 cents to $2.63/MMBtu in trading following the release of the weekly storage report. The entire summer strip, May through October, also rose 2 cents to $2.72/MMBtu while the winter 2021-22 strip ticked up 1 cent to average $2.94/MMBtu. Platts Analytics’ supply and demand model currently forecasts a 25 Bcf net injection for the week ending April 2, compared with the five-year average build of 8 Bcf. Total demand has fallen more than 1.8 Bcf/d compared with the prior week. Much of the loss was witnessed within the residential-commercial sector, which fell over 2 Bcf/d. Power burns offset some of the weakness in res-comm – with burns growing about 600 MMcf/d compared with the prior week as coal-to-gas switching accelerated. On the supply side of the ledger, US production was roughly flat The latest Platts Analytics projection has storage peaking at 3.5 Tcf in late October, which would measure more than 200 Bcf below the five-year average.
Natural Gas Futures Hop Ahead of Long Easter Weekend on EIA ‘Neutral’ Print, Lower Production — A couple of minor surprises in the latest government storage report sparked a modest gain for natural gas futures ahead of the long Easter weekend. With a few brief cold snaps on the radar, the May contract finished Thursday’s session 3.1 cents higher day/day at $2.639. Spot gas prices were lower, however, amid weak holiday demand. NGI’s Spot Gas National Avg. fell 10.5 cents to $2.345. NatGasWeather said volatility was expected given the Energy Information Administration (EIA) storage report and players positioning for the three-day holiday weekend. That proved true as prices started off lower day/day, then rallied and continued to ping pong throughout much of the session. “To our view, as long as $2.58 holds on May, bulls are in control,” NatGasWeather said. The latest storage data delivered a couple of surprises and fueled the volatility. The EIA reported a net 14 Bcf injection into natural gas storage for the week ending March 26, coming in slightly below market expectations and prematurely putting an end to the withdrawal season that traditionally runs through the end of March. The EIA figure included a 4 Bcf revision for the week ending March 19 that resulted in a 32 Bcf withdrawal, rather than a 36 Bcf draw. The change occurred in the nonsalt facilities in the South Central region, where inventories reached 519 Bcf for the period. In light of the EIA revision, Bespoke Weather Services said it rated the 14 Bcf injection as a “neutral number.” The firm had projected a 22 Bcf build. Broken down by region, the South Central added a net 15 Bcf into storage, including 11 Bcf into salt facilities and 4 Bcf into nonsalts, according to EIA. Pacific stocks rose by 1 Bcf, while the East and Mountain regions each recorded no change. The Midwest continued to withdraw, pulling 4 Bcf out of inventories.
ENERGY POLICY: Bills would push natural gas exports, restrict solar imports — Monday, March 29, 2021 — — Two Republican senators introduced legislation last week to make it easier for liquid natural gas exports to secure needed permits from the Department of Energy and Federal Energy Regulatory Commission.
Conservation groups ask Haaland to block oil drilling in Florida preserve –A coalition of conservation groups called on Interior Secretary Deb Haaland to deny requests to drill for oil in a section of the Florida Everglades in a letter Tuesday. The Burnett Oil Company has submitted two applications to the state Department of Environmental Protection seeking permits for a new oil well and the construction of an access road near the Big Cypress National Preserve.The company is also proposing a second well in the close vicinity of Miccosukee tribal lands. Although the preserve is part of the National Park System, some of the fossil fuels beneath it are privately owned.“Both proposed well sites are located in wetlands and primary Florida panther habitat. These proposed oil wells and their associated land clearing, equipment storage, wetlands filling, hydrologic alterations, staging areas, access roads, drilling rigs, storage tanks, fuel tanks, water wells, disposal wells, reserve pits, grading, erosion, sedimentation, and potential oil spills – on their face – would be detrimental to the explicit purposes of the Preserve,” the letter states. Signers of the letter include the Center for Biological Diversity, Earth Action, Sierra Club and the South Florida Audubon Society.The wells would also create emissions that threaten the preserve’s status as a vital “carbon sink,” or a reservoir that stores more carbon than it releases, the letter states. The oil company has yet to finish the mitigation process required as part of its National Park Service access permit, the letter states, and it has already done “extensive damage” during the initial phase of oil exploration.“People don’t come to a national park to see oil wells. The constant threat of oil and gas exploration in Big Cypress National Preserve jeopardizes the sensitive habitat this park provides for endangered species like the Florida Panther, as well as the one-of-a-kind park experience Big Cypress offers to so many visitors,” Cara Capp, senior Everglades program manager for National Parks Conservation Association, said in a statement.
US government has returned all the oil it stored for companies when prices crashed last year The U.S. has returned 18.3 million barrels of oil temporarily stored in the Strategic Petroleum Reserve by energy companies that had rented space there when prices were crashing last year. Oil prices briefly turned negative last year in an unprecedented period of volatility after the economy shut down and demand dried up. On April 2, 2020, the Department of Energy said it would offer oil companies 30 million barrels of space. The agency later announced it had rented space to nine companies for 23 million barrels of crude. The government charged them rent in oil. When the announcement was made, oil was trading in the $20s per barrel, but less than three weeks later, West Texas Intermediate futures were negative by more than $37 per barrel. Under the agreement, the oil was to be removed by March 31. An Energy Department spokesperson told CNBC Tuesday that all of the oil was returned except for 1.2 million barrels paid as rent and another 1.5 million being held under a lease deal with the government of Australia. Australia purchased the oil from a company that participated in the storage program. The companies that stored oil in the reserve include Chevron, Exxon Mobil, Energy Transfer, Equinor Marketing and Trading, Mercuria Energy, MVP Holdings, Vitol, Atlantic Trading and Alon USA. The current inventory in the Strategic Petroleum Reserve is 638.1 million barrels. The Energy Department expects the reserve to have 628.1 million barrels at the end of May, following a Congressionally directed sale of 10 million gallons.
Texas upstream oil and natural gas sector added 2,300 jobs in February roughly one year after industry reported ‘bloodbath’ – – The Texas oil and natural gas industry’s upstream sector added 2,300 jobs in February, a record achievement less than nine months after it reported a “bloodbath.” According to data from the Texas Workforce Commission, the sector added 7,400 jobs since the low point in September 2020, bringing the total upstream employment in the state to 164,900 jobs. The upstream sector involves oil and natural gas extraction and excludes other industry sectors like refining, petrochemicals, fuels wholesaling, oilfield equipment manufacturing, pipelines, and gas utilities, which support several hundred thousand additional jobs. Many of those jobs pay among the highest wages in Texas. “The resilience and reliability of the Texas oil and natural gas industry is remarkable and it is the reason this industry will be essential to the energy mix for decades to come,” Todd Staples, president of the Texas Oil & Gas Association, said in a statement. After the state shut down in mid-March last year, wells closed, rigs stopped operating, and tens of thousands of workers were immediately laid off. Texas’ oil output fell in March by an estimated 235,000 barrels per day, the largest monthly decline ever recorded, according to the Texas Alliance of Energy Producers. The Alliance’s benchmark Texas Petro Index (TPI) fell to 172 in April from 181.9 in March, the second largest monthly decline on record (the September to October 2015 11-point drop was the largest on record). “The Texas upstream oil and gas economy was already in a state of decline when COVID-19 came along, with drops in the number of working rigs and industry employment, but the rate of decline has obviously accelerated sharply in March and April,” Karr Ingham, an Alliance economist who created the TPI, told Natural Gas Intel last year. By last March, more than 51,000 jobs were lost after drilling companies and refineries were forced to lay off workers. By April, Philip Jordan, vice president of BW Research Partnership, told Bloomberg News, “We’re looking at anywhere between five and seven years of job growth wiped out in a month.” But by February 2021, after the state’s lockdown had ended, the sector started to show signs of life.
US oil, gas rig count rises 6 to 519 as Permian, Eagle Ford lead growth: Enverus – The US oil and gas rig count rose six to 519 in the week ended March 31, rig data provider Enverus said, as totals in the Permian Basin and Eagle Ford Shale continued to climb. The Permian, sited in West Texas/southeast New Mexico, and Eagle Ford, in South Texas, each picked up four rigs week on week for respective totals of 236 and 41, marking their highest levels in nearly a year. Since the start of 2021, the Permian has added 60 rigs and the Eagle Ford has gained 10. The increase in nationwide rig counts was attributed to the oil side, which grew by six to 393. Gas rigs were static at 126. Weekly changes in rig fleets within the largest US basins were mostly up or down a unit or unchanged, although the Williston Basin of North Dakota and Montana lost two rigs, leaving 14. The Haynesville Shale of East Texas and Northwest Louisiana gained one for a total of 48, while the SCOOP/STACK play in Oklahoma and DJ Basin of Colorado were each down a rig, leaving 18 and 13, respectively. Unchanged on week were the Marcellus Shale of largely Pennsylvania at 33 rigs, and the Utica Shale of Ohio at 12. So far this year, the total oil and gas rig count is up 113, equating to a robust average gain of about nine rigs per week. The count has increased every week save for once in mid-February, when it stood still for a week, before surging by 30.
How A Bill To Prevent Natural Gas Bans In Texas Homes Could Lead To Another Blackout | KUT Radio – The Texas House will vote Tuesday on a handful of bills related to February’s deadly blackouts. The package of legislation has been fast-tracked by lawmakers who say it will safeguard Texas against future blackouts. But among the bills is a proposal that some analysts say would actually make another blackout more likely. House Bill 17 by Beaumont Democratic state Rep. Joe Deshotel would stop Texas cities and towns from banning natural gas hookups in new construction. The law was initially written in response to California cities banning natural gas use in buildings to fight climate change. With the support of the natural gas industry, other states have already preemptively passed laws to “ban” local natural gas “bans.” Deshotel’s legislation got a rebranding when it was included on the list of bills prioritized in response to the blackout. Earlier this month, Deshotel said “gas played an important part in helping a lot of people” during the blackout. “I know in my own home, I was able to keep things going because we had a generator that kicked on and ran on natural gas,” he said in a hearing of the House State Affairs Committee.About one-third of Texas homes use natural gas for heat, so it’s understandable to think increasing that number would keep more people warm when blackouts hit. But the opposite could be true. “This bill absolutely, unequivocally, would make the problem worse,” said Doug Lewin, energy efficiency advocate and president of the consulting firm Stoic Climate and Energy. He said that’s because of the interconnectedness of electricity and natural gas in Texas. One of the causes of February’s blackout was the failure of natural gas to get to gas-fired power plants. Plant owners have testified that that lack of supply forced them to shut down their generators, adding to the power crunch. At the same time, state regulators prioritized gas delivery to residential customers. That helped people with natural gas in their homes, but took fuel away from the plants. Lewin said HB 17 would mean “locking in additional fossil fuel infrastructure [in homes] which will need fossil fuels in the next winter storm.” “Every molecule of gas going to a home is a molecule not going to a power plant,” he said, which could lead to another blackout.
Texas officials responded to the winter storm with propaganda they got from a pro-fossil fuel think tank –In February, Texas experienced an unprecedented winter storm that saw roads shut down from snowfall and millions left without power as the state’s electric grid failed in freezing temperatures. The situation was so bad that the CEO of the state’s grid operator said that the grid was mere minutes away from a total collapse. And yet, while the storm that killed at least 86 peoplecontinued, Texas oil and gas regulators spent their days circulating climate change denialism talking points, according to a report from NBC News.The talking points, which claimed that renewable energy sources like wind and solar power are “often useless when you need them most,” originated from Alex Epstein, author of The Moral Case for Fossil Fuels and the founder of the for-profit think tank the Center for Industrial Progress. Epstein, aclimate skeptic and fossil fuel fanboy, reportedly provided talking points to a number of Texas politicians via email and hosted a briefing on Zoom to which a number of state officials – including Republican Gov. Greg Abbott’s chief of staff Luis Saenz – were invited. According to NBC News, talking points from Epstein landed in the inbox of a number of officials in the governor’s office and at the Railroad Commission, the state’s primary oil and gas industry regulator.It certainly wasn’t hard to find Epstein’s agenda in action. Once Texas leaders got their hands on the messaging, they ran with it. On the same day that Epstein’s email hit inboxes, Railroad Commission member Wayne Christianretweeted Epstein and issued a statement warning of the “dangers of relying too heavily on unreliable, intermittent forms of electric generation like wind and solar” to meet the state’s energy needs. Later that evening, Abbott appeared on Sean Hannity’s Fox News show to use a deadly natural disasterto declare that “the Green New Deal would be a deadly deal for the United States of America.”Texas officials pulled this stunt over and over again, pointing to frozen wind turbines as the supposed reason for the power outage. Despite the fact that wind makes up just 10% of the state’s energy production while natural gas and coal account for 72%, and despite the fact that Texas operates largely independently from any federal regulation, Epstein pushed the following message, per NBC News: “Here’s the bottom line: The root cause of the [Texas] blackouts is a national and state policy that has prioritized the adoption of unreliable wind/solar energy over reliable energy.”Texas officials proved capable of regurgitating that message no problem and did so at every turn – and apparently have been for some time. NBC News reported that Epstein hosts weekly calls that Texas officials can join, and that he regularly sends climate-denying memos as part of an “Energy Talking Points” service, which gets passed around the Texas government regularly. On Feb. 22, an edition of the email with new information and praise for officials who happily spewed the previous messages landed in the inbox of the spokesperson for a Railroad Commission member, who then forwarded the message to three Texas oil and gas lobbying groups with the note, “Talking points from Alex Epstein. Not sure if y’all call in to his calls but wanted to see what he sent out today.”It should come as no surprise that Texas officials are so cozy with someone so heavily invested in promoting fossil fuels. After all, Abbott himself apparently took meetings with a right-wing, anti-science meteorologist as the winter storm was about to hit. Oil is Texas’s primary export, so it has a vested interest in defending the dirty-burning energy source. Still, it’s a little shocking just how brazenly they eat this shit up and how transparent they are about pushing bad information. Epstein provides talking points, officials go repeat them, and then Epstein points to these officials backing what he said as evidence that he was right all along. Wash, rinse, repeat.
Fossil Fuel Companies Took Billions in U.S. Coronavirus Relief Funds but Still Cut Nearly 60,000 Jobs – When Congress looked to prop up a tanking economy and stanch its hemorrhaging of employment as the pandemic spread last year, the oil industry was among those that sought relief. Now, a new analysis shows that dozens of fossil fuel companies received billions of dollars in tax benefits in the coronavirus relief package, but slashed tens of thousands of jobs anyway. While Congress ended up sending billions in direct loans to small and large businesses, a significant portion of CARES Act benefits came in the form of changes to the tax code. At least 77 fossil fuel companies took advantage of those to claim a total of $8.2 billion in benefits last year, even as they cut nearly 60,000 jobs, according to an analysis published Friday by BailoutWatch, a nonprofit supported by Rockefeller Philanthropy Advisors. Chris Kuveke, a BailoutWatch analyst, said the data shows that the aid to the industry failed to deliver the benefits that Congress had intended. “These companies did not use that money they received through the CARES Act to maintain payroll,” he said.As oil prices collapsed last year, some energy companies began lobbying Congress and the federal government for various forms of relief. Occidental Petroleum, for example, enlisted its employees to send letters to members of Congress to ask that they “provide liquidity” to the energy industry,according to Bloomberg News. Among the various forms of stimulus included in the final relief package were changes to the tax code that proved beneficial to the oil industry.For example, companies for years were allowed to “carry back” their losses in one year to offset profits from previous years to get a retroactive tax refund. That allowance helped companies with volatile earnings, but it was eliminated by the 2017 tax cuts signed into law by President Donald Trump. The change was one of the few provisions of the tax overhaul that modestly increased the tax burden for corporations, even as the bill overall drastically reduced corporate taxes, said Thornton Matheson, a senior fellow at Urban-Brookings Tax Policy Center.The CARES Act eliminated that change, and even expanded on the original provision, allowing companies to carry any losses incurred from 2018-2020 back five years, instead of the two years allowed before the 2017 tax bill. Matheson said the oil and gas industry was among a few likely to benefit most from that part of the CARES Act, because its earnings can swing wildly with commodity prices.Thus the change allowed companies to stretch losses from 2018 back to 2013, when oil prices were above $100 a barrel and profits for some of them were sky high (prices fell sharply in late 2014, and have not fully recovered). Marathon Petroleum, a major refiner, benefited the most, the analysis found, claiming $2.1 billion in tax benefits, according to the BailoutWatch analysis. The company cut nearly 2,000 jobs last year, not counting those in its retail business.
Biden infrastructure plan would spend $16 billion to clean up old mines, oil wells – (AP) – President Joe Biden’s $2.3 trillion plan to transform America’s infrastructure includes $16 billion to plug old oil and gas wells and clean up abandoned mines, a longtime priority for Western and rural lawmakers from both parties. Hundreds of thousands of “orphaned” oil and gas wells and abandoned coal and hardrock mines pose serious safety hazards, while causing ongoing environmental damage. The administration sees the longstanding problem as an opportunity to create jobs and remediate pollution, including greenhouse gases that contribute to global warming. Biden said last week he wants to put pipefitters and miners to work capping the wells “at the same price that they would charge to dig those wells.” Many of the old wells and mines are located in rural communities that have been hard-hit by the pandemic. Biden’s plan would not only create jobs, but help reduce methane and brine leaks that pollute the air and groundwater. Methane is a powerful contributor to global warming. The Interior Department has long led efforts to cap orphaned wells – so named because no owner can be found – but does not assess user fees to cover reclamation costs. Bond requirements for well operators, when known, are often inadequate to cover full clean-up costs. Biden’s plan, which needs approval by Congress, would jump-start the well-capping effort and expand it dramatically. Similarly, the White House plan would exponentially boost an Abandoned Mine Land program run by Interior that uses fees paid by coal mining companies to reclaim coal mines abandoned before 1977. About $8 billion has been disbursed to states for mine-reclamation projects in the past four decades, but Biden’s plan would ramp up spending sharply. Sen. Joe Manchin, the West Virginia Democrat who chairs the Senate Energy and Natural Resources Committee, has long pushed to expand the mine-lands program, which he calls crucial to his state. “It cannot be forgotten that West Virginia coal miners powered our country to greatness,” Manchin said. While many mine lands in coal communities have been reclaimed, “there is still much more work to be done to clean up damage to the land and water in those communities,” he said. Wyoming Sen. John Barrasso, the top Republican on the Senate energy panel, ridiculed Biden’s overall plan as “an out-of-control socialist spending spree.” The proposal “starts with the punishing policies of the Green New Deal and builds back worse from there,”
Biden’s Recovery Plan Has an Unforeseen Consequence: More Demand For Oil – When President Biden yesterday unveiled his $2-trillion economic recovery plan, few in his immediate circle likely thought about oil. Yet, the plan will have a positive effect on oil demand because $621 billion of the total would be used for transportation infrastructure, including lots of roads. And roads are built with asphalt. Of this $621 billion, $115 billion would be allocated for road and bridge construction, Bloomberg noted in a report, and another $16 billion has been earmarked for laid-off oilfield workers who would be tasked with plugging abandoned oil wells and securing abandoned coal mines across the country. But the biggest winner from the recovery plan could be Canadian oil sands producers in what could be seen as an ironic twist of fate after Biden canceled the Keystone XL pipeline that might have made life easier for these companies by providing a much needed additional outlet for their growing oil exports to the southern neighbor. Asphalt is made from bitumen, and bitumen is what the oil sands yield. With ambitious targets for new roads and bridges and for large-scale repair works, asphalt demand in the next few years could soar. The employment plans for paid-off oil workers are also good news for the troubled industry. Around 120,000 jobs were lost in the U.S. oil and gas industry last year due to the crash in oil demand and prices and subsequent massive downsizing of staffing levels, Rystad Energy said last month in an industry analysis. The United States, the third-biggest employer in the oil and gas sector globally, saw the number of jobs in the industry decline to around 960,000 last year, down from approximately 1,080,000 employees in 2019.
Biden’s Latest Surprise Boost for Oil Involves Lots of Asphalt – President Joe Biden, who made clean energy a core tenet of his campaign, plans to set off one more oil-sector boom before shadows descend on fossil fuels. In a $2.25 trillion infrastructure proposal unveiled Wednesday, Biden earmarked $115 billion for roads and bridges, and another $16 billion to put laid-off oilfield laborers to work plugging abandoned wells across the nation. Those are in addition to sweeping investments in electric vehicles and renewable power, sectors more in keeping with the administration’s green tinge. Since taking office two months ago, Biden’s been more boon than bane for a fossil-fuel industry that was wary of the ascendance of a politician bent on accelerating the energy transition. Instead, the president’s focus on things like expediting Covid-19 vaccinations and clamping down on reckless environmental practices have had the effect of boosting fuel demand and capping price-killing growth in domestic oil output. In the infrastructure blueprint, the biggest benefit for oil explorers and refiners would come from the expected jump in demand for asphalt to repair crumbling highways and pave new ones. Because asphalt is derived from the heaviest and most-dense material in a barrel of crude, Canada’s oil-sands producers may be the biggest winners, given their status as the source of some of the globe’s thickest petroleum. Plugging old wells and securing defunct coal mines — some of which have been abandoned for more than a century in places like Pennsylvania — would mean paychecks for workers thrown out of high-paying jobs during the back-to-back oil busts that kicked off in 2014. Although details remain scant on how the broad-brush plan will be implemented, the oft-opposing forces of fossil fuels and environmentalism lauded many of the measures laid out in Biden’s plan. The lobbying group that represents more than 700 oilfield service and equipment makers was also pleased with the initial scope of the plan to put hired hands of the shale patch back to work again. North American oil explorers are still recovering from last year’s historic crude crash and pledging to restrain production growth for the sake of investor-friendly measures such as dividends. Canada’s oil-sands industry was among the hardest hit sections of the industry when Covid-19 and a worldwide glut of crude crashed prices last year. Now, assuming some or all of Biden’s wish list is granted, heavy crude from Western Canada may be poised for a rebound. “The asphalt industry should be elated with Biden’s plan to upgrade 20,000 miles of roads in the U.S.,” said Charles Kemp, a senior consultant at Baker & O’Brien Inc. “However, this announcement favors heavier oil production from outside of the U.S., which contains roughly double the amount of asphalt versus the asphalt content in light crudes from U.S. domestic production.”
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