Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 15 August 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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Gasoline supplies at a 42 month low; natural gas supplies still 16.5% lower than a year ago; offshore Alaska drilling resumes
Oil prices ended little changed this week, as concerns about a Covid related slowdown were offset by the passage of the infrastructure spending package in Congress… after falling 7.7% to $68.28 per barrel last week as US crude inventories rose unexpectedly and rising Covid cases prompted global economic restrictions, the contract price of US light sweet crude for September delivery opened lower on Monday after a report on the damaging effects of climate change signalled “code red” for humanity, and extended its losses to over 3% on the back of a firmer U.S. dollar and concerns that new coronavirus-related restrictions in China could slow a global recovery in fuel demand, before settling down $1.80 at $66.48 a barrel, the lowest level in 2½ months, as traders worried that travel restrictions and delayed office reopenings would limit fuel consumption…but oil prices reversed that drop completely on Tuesday, as traders appeared to shrug off worries about the spread of COVID-19, and instead cheered Senate passage of a $1 trillion infrastructure package, with oil recovering all of Mondays losses to close $1.81 higher at $68.29 a barrel, boosted by an IEA forecast that U.S. fuel consumption would grow by 10% this year…oil prices slid early Wednesday after the EIA reported a smaller than expected draw on US crude supplies and a surprise increase in distillates inventories, and after Biden pushed OPEC to boost production faster than their current pace, but recovered to close 96 cents higher at $69.25 a barrel, as the dollar weakened, boosting prices of commodities priced in the currency, and consumer prices increased modestly, reducing concern about an unwinding of the Fed stimulus...however, oil prices turned lower Thursday, after monthly reports from OPEC and the IEA both highlighted demand concerns, and settled 16 cents lower at $69.09 a barrel as both reports also increased their forecasts for 2nd half supplies…oil prices continued lower on Friday as the fast-spreading delta variant continued to cloud the short-term demand outlook, and settled 65 cents lower at $68.44 a barrel after a near record plunge in US consumer confidence readings, but still ended the week with a fractional gain after weathering concerns from banks and the International Energy Agency that the spread of coronavirus variants is slowing oil demand…
Natural gas prices, on the other hand, finished lower as forecasts cooled and inventories rose more than had been expected…after rising 5.8% to $4.140 per mmBTU last week on forecasts for hotter weather and on low gas supplies for this time of year, the contract price of natural gas for September delivery opened higher on Monday but turned lower to close down 8.0 cents at $4.060 per mmBTU after long-range weather forecasts cooled while LNG demand remained well off recent highs… prices rebounded 2.9 cents on Tuesday on increasing heat in the forecast for the current week and modest changes to the supply/demand balance, but fell back 3.0 cents to $4.059 mmBTU on Wednesday as analysts looked for wind generation to curb the bullish effect of peak summer heat in the forecast for the week…natural gas prices fell again on Thursday after the latest EIA storage figure came in on the higher side of expectations, and as much cooler temperatures were expected this weekend…prices then fell 7.2 cents more on Friday as a series of storms was forecast to move in over the weekend, capping temperatures and lowering cooling demand, and thus finished the week off 6.7% at a three week low of $3.861 per mmBTU, despite expectations that LNG exports would rise as Gulf of Mexico plants boosted output after finishing maintenance work...
The natural gas storage report from the EIA for the week ending August 6th indicated that the amount of natural gas held in underground storage in the US rose by 49 billion cubic feet to 2,776 billion cubic feet by the end of the week, which still left our gas supplies 548 billion cubic feet, or 16.5% below the 3,324 billion cubic feet that were in storage on August 6th of last year, and 178 billion cubic feet, or 6.0% below the five-year average of 2,954 billion cubic feet of natural gas that have been in storage as of the 6th of August in recent years…the 49 billion cubic foot increase in US natural gas in storage this week was more than the median forecast for a 44 billion cubic foot addition from a S&P Global Platts survey of analysts, and more than the average addition of 42 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, but less than the 55 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending August 6th indicated that after a sizable increase in our oil exports and a modest increase in our oil refining, we needed to withdraw oil from our stored commercial crude supplies for the tenth time in twelve weeks, and for the 26th time in the past thirty-eight weeks….our imports of crude oil fell by an average of 36,000 barrels per day to an average of 6,396,000 barrels per day, after falling by an average of 75,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 759,000 barrels per day to an average of 2,663,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,732,000 barrels of per day during the week ending August 6th, 795,000 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 reportedly increased by 100,000 barrels per day to 11,300,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to total an average of 15,032,000 barrels per day during this reporting week…
US oil refineries reported they were processing 16,197,000 barrels of crude per day during the week ending August 6th, 277,000 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 average of 64,000 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 and from oilfield production was 1,101,000 barrels per day less than what was added to storage plus what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+1,101,000) 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 omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed….since last week’s EIA fudge factor was at (+711,000) barrels per day, that means there was a 390,000 barrel per day balance sheet difference in the crude oil fudge figure from a week ago, thus rendering the week over week supply and demand changes indicated by this report fairly useless….however, since most everyone treats these weekly EIA reports 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 reasonably accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,608,000 barrels per day last week, which was 16.3% more than the 5,680,000 barrel per day average that we were importing over the same four-week period last year…the 64,000 barrel per day net increase in our 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 100,000 barrels per day higher at 11,300,000 barrels per day because the EIA”s rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at 10.900,000 barrels per day, while a 24,000 barrel per day increase in Alaska’s oil production to 395,000 barrels per day had no impact on the rounded national production total….US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 13.7% below that of our production peak, but 34.1% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016…
US oil refineries were operating at 91.8% of their capacity while using those 16,197,000 barrels of crude per day during the week ending August 6th, up from 91.3% of capacity the prior week, but still somewhat below normal utilization for summertime operations…while the 16,197,000 barrels per day of oil that were refined this week were 10.5% higher than the 14,658,000 barrels of crude that were being processed daily during the pandemic impacted week ending August 7th of last year, they were still 6.4% below the 17,302,000 barrels of crude that were being processed daily during the week ending August 9th, 2019, when US refineries were operating at what was a seasonally normal 94.8% of capacity…
Even with this week’s increase in the amount of oil being refined, the gasoline output from our refineries was somewhat lower, decreasing by 190,000 barrels per day to 9.961,000 barrels per day during the week ending August 6th, after our gasoline output had increased by 1,011,000 barrels per day over the prior two weeks…while this week’s gasoline production was still 3.8% higher than the 9,600,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 2.8% lower than the gasoline production of 10,203,000 barrels per day during the week ending August 9th, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 8,000 barrels per day to 4,885,000 barrels per day, after our distillates output had increased by 138,000 barrels per day over the prior week…with 5 straight decreases before those increases, this week’s distillates output was just 0.2% more than the 4,789,000 barrels of distillates that were being produced daily during the week ending August 7th, 2020, and 3.8% below the 5,077,000 barrels of distillates that were being produced daily during the week ending August 9th, 2019..
With the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the eighth time in nineteen weeks, and for the 18th time in thirty-nine weeks, falling by 1,401,000 barrels to a forty-two week low of 227,469,000 barrels during the week ending August 6th, after our gasoline inventories had decreased by 5,291,000 barrels over the prior week...our total gasoline supplies decreased by less this week because the amount of gasoline supplied to US users decreased by 345,000 barrels per day to 9,430,000 barrels per day, and because our imports of gasoline rose by 84,000 barrels per day to 925,000 barrels per day while our exports of gasoline rose by 121,000 barrels per day to 746,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 7.9% lower than last August 7th’s gasoline inventories of 247,084,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…
Meanwhile, with the modest increase in our distillates production, our supplies of distillate fuels increased for the seventh time in eighteen weeks and for the 19th time in 34 weeks, rising by 1,767,000 barrels to 140,511,000 barrels during the week ending August 6th, after our distillates supplies had increased by 832,000 barrels during the prior week….our distillates supplies rose by more this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 116,000 barrels per day to 3,734,000 barrels per day, because our exports of distillates fell by 218,000 barrels per day to 1,084,000 barrels per day, and because our imports of distillates rose by 23,000 barrels per day to 185,000 barrels per day…but after eleven inventory decreases over the past eighteen weeks, our distillate supplies at the end of the week were still 20.9% below the 177,655,000 barrels of distillates that we had in storage on August 7th, 2020, and about 6% below the five year average of distillates stocks for this time of the year…
Finally, with the big increase in our oil exports and the pickup in refining, our commercial supplies of crude oil in storage fell for the 15th time in the past twenty-five weeks and for the 27th time in the past year, decreasing by 448,000 barrels over the week, from 439,225,000 barrels on July 30th to 438,777,000 barrels on August 6th, after our commercial crude supplies had increased by 3,627,000 barrels the prior week…after this week’s decrease, our commercial crude oil inventories were still about 6% below the most recent five-year average of crude oil supplies for this time of year, but were more than 30% above the average of our crude oil stocks after the first week of August over the 5 years at the beginning of the past 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 Covid lockdowns of last spring and remained elevated thereafter, our commercial crude oil supplies as of this August 6th were still 14.6% less than the 514,084,000 barrels of oil we had in commercial storage on August 7th of 2020, and a bit less than the 440,510,000 barrels of oil that we had in storage on August 9th of 2019, but still 5.9% more than the 414,194,000 barrels of oil we had in commercial storage on August 10th of 2018…
This Week’s Rig Count
The number of drilling rigs active in the US increased for the 40th time out of the past 47 weeks during the week ending August 13th, but was still down by 36.9% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US increased by nine to 500 rigs this past week, which was also up by 256 rigs from the pandemic hit 244 rigs that were in use as of the August 14th report of 2020, but was still 1,429 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, which was a week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 10 to 397 oil rigs this week, after rising by 2 oil rigs the prior week, and it’s now 225 more oil rigs than were running a year ago, while it’s less than a quarter 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 was down by one to 102 natural gas rigs, which was still up by 32 natural gas rigs from the 70 natural gas rigs that were drilling during the same week a year ago, but still just 6.4% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….in addition to oil and gas rigs, a horizontal rig that Baker Hughes classifies as “miscellaneous’ is drilling in Kern county California, while a year ago there were no such “miscellaneous’ rigs reported to be active…
The Gulf of Mexico rig count was down by one to 13 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil in the Alaminos Canyon offshore from Texas….that was the same number of rigs that were drilling in the Gulf a year ago, when 10 Gulf rigs were drilling for oil offshore from Louisiana and three were deployed for oil in Texas waters….in addition to those Gulf of Mexico rigs, this week we also had a vertical rig start drilling for natural gas off the shore of the Kenai peninsula in Alaska, which is the first offshore Alaska drilling in almost two years; as a result, the national offshore rig count is now 14, up from 13 offshore rigs a year ago..
In addition to those rigs offshore, we now have two rigs drilling through inland bodies of water in Louisiana this week. whereas there were no such “inland waters” rigs running a year ago…the new “inland waters” startup is a rig drilling for oil in the Haynesville shale through a lake in DeSoto parish in the northwestern corner of the state, just south of Shreveport, while we also continue to have a rig drilling through an inland body of water in Terrebonne Parish of southern Louisiana…
The count of active horizontal drilling rigs was up by 7 to 456 horizontal rigs this week, which was more than double the 211 horizontal rigs that were in use in the US on August 14th of last year, but was less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…..in addition, the vertical rig count was up by 2 to 17 vertical rigs this week, and those were also up by 4 from the 13 vertical rigs that were operating during the same week a year ago….on the other hand, the directional rig count was unchanged at 27 directional rigs this week, and those were still up by 3 from the 24 directional rigs that that were in use on August 14th 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 August 13th, the second column shows the change in the number of working rigs between last week’s count (August 6th) and this week’s (August 13th) count, the third column shows last week’s August 6th 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 14th of August, 2020…
Since we know there was an offshore natural gas rig startup in Alaska this week, for the state to show the loss of a rig means that two of the oil rigs that had been drilling on the North Slope were apparently shut down at the same time…similarly, since we know we have an inland water oil rig start up in the Haynesville shale this week, the net lost of 1 Haynesville rig means that two of the natural gas rigs that had been operating in that basin were concurrently shut down…since land rigs in northern Louisiana were only down by one, that means that the rig that was pulled out of adjacent Texas Oil District 6 had to have been operating in the Haynesville…but Louisiana’s rig count is still down by one despite the offsetting Haynesville shale activity because the Gulf of Mexico rig that was shut down had been drilling in the state’s offshore waters…
Meanwhile, the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes shows that three rigs were pulled out of Texas Oil District 8, which is the core Permian Delaware, but that two oil rigs were added in Texas Oil District 8A, which encompasses the northern counties of the Permian Midland, while another oil rig was added in Texas Oil District 7C, which includes the southern counties of the Permian Midland…hence, since the Texas Permian count is apparently unchanged, and since the national Permian count was up by two, that means that two of the rigs that were added in New Mexico must have been set up to drill in the far west reaches of the Permian Delaware in that state…
Elsewhere in Texas, we find two rigs were added in Texas Oil District 1 and two more rigs were added in Texas Oil District 2, which together would account for the Eagle Ford shale increase, while at the same time a rig was pulled out of Texas Oil District 3, which had been drilling into a basin not tracked by Baker Hughes…finally, there was also a rig added in Texas Oil District 10, which could have been in the Granite Wash basin if one of the Granite Wash rigs recently added in nearby Oklahoma were shut down at the same time, certainly a possibility since the Oklahoma rig count is down one despite the addition of a Cana Woodford oil rig in the central part of that state…the only other change that shows up on our tables in the addition of four rigs in the Bakken shale of the Williston basin, which included two rigs in North Dakota and two in Montana, the first drilling in Montana since November of last year, and the first time two rigs were deployed in the state in 19 months…
Meanwhile, there were more natural gas rig changes than the aforementioned offshore gas rig added in Alaska and the two gas rigs pulled out of the Haynesville; first, one of this week’s Eagle Ford rig additions was targeting natural gas, which means the Eagle Ford now has four natural gas rigs deployed in addition to 32 oil rigs drilling in that basin…meanwhile, there was also a natural gas rig startup in Oklahoma’s Arkoma Woodford, which was offset by the shutdown of the lone oil rig in that basin at the same time…and lastly, two natural gas rigs were removed from “other basins” that Baker Hughes does not name; which possibly could be the previously unidentifed rigs pulled from Oklahoma and from Texas Oil District 3…
Radioactive loads enter landfills – Republic Services Carbon Limestone Landfill is one of the eight landfills in Ohio currently receiving waste from unconventional oil and gas operations, according to information acquired by Public Herald from the Ohio Environmental Protection Agency. The company is the second-largest provider of nonhazardous solid waste collection, transfer, disposal, recycling and energy services in the United States, as measured by revenue, according to its website. In 2019, the landfill received more than 1.3 million tons of waste – including radioactive fracking waste, according to Public Herald.In Ohio, TENORM (technologically enhanced naturally occurring radioactive material) disposal at landfills falls under the Ohio Revised Code, which states that a solid waste facility cannot accept or transfer TENORM if it contains radium-226, radium-228, or any combination of the two at more than 5 picocuries per gram (pCi/g) over the natural background.Not much testing has been done on TENORM waste in Ohio, but much of the TENORM waste arriving at Ohio landfills is from the Marcellus Shale – the same shale waste that has been tested in a 2016 Pennsylvania TENORM study. In that study, radium levels from fracking waste in the Marcellus were detected as high as 13 pCi/g, more than 2.5 times greater than the Ohio code permits. The average load for combined radium reported in the study from 18 samples was 5.847 pCi/g, again exceeding the Ohio code of 5 pCi/g. But even though Ohio’s TENORM code places a strict standard on radioactive waste disposal, the state hasn’t produced documentation to Public Herald of measurement and enforcement for radium at landfills.“It is an extremely, overwhelmingly strong bet that the waste and disposal practices in Ohio are seeing a great deal of material that exceeds the limits,” Ohio attorney Terry Lodge said.
Disposal of radioactive fracking waste alarms activists – Youngstown Vindicator – Everyone knows that oil and gas wells produce oil and natural gas, but these wells also produce radioactive material being disposed of in communities alongside household trash.The Environmental Protection Agency defines the radioactive portion of this waste as TENORM (technologically enhanced naturally occurring radioactive material). Though Ohio has strict regulations governing radioactive waste that comes across its borders, the state code doesn’t require the kind of extensive testing necessary to adequately measure radioactivity in TENORM waste, Public Herald reports.Surrounding Youngstown are four separate facilities processing radioactive fracking waste. According to Public Herald, they are:
- * Carbon Limestone Landfill, Republic Services, Lowellville;
- * Mahoning Landfill, Waste Management, New Springfield;
- * Wastewater treatment plant in Lowellville;
- * “Chief’s order” facility called Ground Tech Inc. in Youngstown. Chief’s order facilities have special permission to operate outside of existing law, critics say.
Lynn Anderson said she has spent nearly a decade working with FrackFree Mahoning Valley to keep Poland Township and the surrounding area safe from radioactive contamination. But the fight against the industry often seems unwinnable, Anderson said. “People’s lives matter. You can’t sacrifice them for corporate profit,” she said. Never before has the nation undertaken an experiment with radioactive material like the one happening now across the country thanks to technological advances in hydraulic fracturing, a deep, water-intensive, chemical-laden process to extract hard-to-reach fossil fuels.The formations being fracked in Appalachia, including Ohio, from the Marcellus and Utica Shales, happen to be the hottest in the country – as in the most radioactive, researchers have said.In 2020, Harvard scientists revealed that radiation downwind of unconventional fracking development is significantly higher than background levels and moreso in the Marcellus and Utica Shale due to the higher uranium content of those formations.According to the industry, every part of the oil and gas continuum involves radioactivity. A 1982 report commissioned by the American Petroleum Institute stated: “[a]lmost all materials of interest and use to the petroleum industry contain measurable quantities of radionuclides that reside finally in processing equipment, product streams, or waste.”Oil and gas companies drill deep into the earth and blast water and chemicals into bedrock to access minerals. The process produces waste that includes drill cuttings, synthetic drilling muds, fracking chemicals, and naturally occurring radioactive material (NORM) that would otherwise stay locked underground.That waste is taken to facilities across the country, and in Ohio that includes local landfills, where rain filters through trash, carrying contaminants with it.In landfills, the contaminated rainwater called “leachate” is transported to local sewage treatment facilities, which add the liquid to sewage for processing before dumping the leftovers into local waterways. But sewage is not treated for radioactive materials, so whatever TENORM goes into the facility also goes into the river, eventually. Or, TENORM can be lodged in sludge and filters making them radioactive for any material they come into contact with.
Ohio oil and gas waste migrated, but drinking water safe for now, state says – Though oil and gas industry waste fluids migrated in 2019 beyond their original Ohio disposal site, a new report from the Ohio Department of Natural Resources says nearby drinking water wells were not affected. The department previously confirmed hydraulic fracturing waste from a class II injection well in Washington County showed up in 28 nearby gas-producing wells. “Naturally occurring fissures exist between the Ohio shale formation and the Berea sandstone formation, allowing wastewater to migrate between formations and into the production wells,” according to ODNR records. While the state agency has said it’s “unlikely that wastewater will migrate farther – including into underground sources of drinking water due to the composition of the rock layers and other factors,” an expert says it’s possible. The state paid an environmental firm, Groundwater & Environmental Services, Inc. (GES), a little more than $50,000 to test private water wells of those who live near the affected area, according to a report GES issued in June. There were 596 parcels along with 48 private water well locations that were identified within one-half mile radius of nine oilfield wells. The company analyzed samples for chloride and bromide, essentially salt, to detect if the well water contained waste fluids – called “brine” in the industry – that’s present in horizontal hydraulic fracturing, a method that came into widespread use by the oil and gas industry in the 2010s to extract fuel from shale formations deep underground. “GES does not believe that … water wells that were sampled during this investigation were impacted by brine associated with the Redbird injection well,” according to the report. However, waste water from hydraulic fracturing, commonly known as fracking, will continue to migrate, said Amy Townsend-Small, an associate professor of environmental science and geology at the University of Cincinnati who conducts research on hydraulic fracturing and its effects on groundwater. Water samples were taken more than a year after the initial reports of the waste migrating. It’s possible that samples were taken at the wrong location because it’s challenging to determine the location many months after, she said. “Are they going to provide ongoing monitoring? Because one-time sampling may not be sufficient,” Townsend-Small said.
Ascent Res. 2Q: Drilled 23 Wells, Produced 1.95 Bcfe/d, Lost $617M – Ascent Resources, originally founded as American Energy Partners by gas legend Aubrey McClendon, is a privately-held company that focuses 100% on the Ohio Utica Shale. Ascent is Ohio’s largest natural gas producer and the 8th largest natural gas producer in the U.S. The company issued its second quarter 2021 update earlier this week. The company produced 1.95 billion cubic feet equivalent per day (Bcfe/d) during 2Q (91% natural gas). Ascent generated $38 million of free cash flow, but like other M-U drillers, hedging bets on derivatives resulted in a big loss of $617 million for the quarter.During 2Q Ascent operated four drilling rigs and one fracture stimulation crew. The company spud (drilled) 23 wells, hydraulically fractured 17 wells, and turned to sales 26 wells with an average lateral length of 12,247 feet.Of the 26 new wells brought online, 23 were located in the dry gas or lean gas areas, while the other three wells were located in the liquids-rich window.As of June 30, 2021, Ascent had 635 gross operated producing Utica wells.The company is one of the lowest-cost producers in the M-U. Ascent’s well costs averaged approximately $546 per lateral foot during 2Q, a 12% reduction compared to 1Q. Ascent’s official update for 2Q, with an overview of the financials:
Summit Midstream 2Q: Volumes Up Some, Profits Down Some – Summit Midstream Partners, formed in 2009 and headquartered in The Woodlands, Texas, operates natural gas, crude oil, and produced water gathering (pipeline) systems in several unconventional shale plays, including the Marcellus and Utica. Last week Summit issued its second quarter 2021 update. The company’s Utica Shale segment continued to be the star performer. Flows through the company’s pipeline system are up, although revenues were down slightly from the same period a year ago. Summit averaged 1,441 MMcf/d (million cubic feet per day) in natural gas throughput during 2Q, up from 1,391 MMcf/d in the second quarter of 2020, as Utica Shale production remained strong. Operated natural gas volumes increased 7.1% relative to the first quarter of 2021, largely due to continued strong performance from the four Utica Shale wells connected in the first quarter of 2021 and 20 new wells that were turned to sales during the second quarter of 2021 across the Utica Shale, Williston Basin and Marcellus Shale segments. Here’s a chart showing average daily throughput by reportable segment for 2Q21. The Utica and Marcellus segments grew.
First major US hydrogen-burning power plant nears completion in Ohio – Touted as a first-of-its-kind power plant in the United States, the Long Ridge Energy Generation Project, a 485-MW facility being equipped to run on a mix of natural gas and carbon-free hydrogen, is nearing completion at the site of a former aluminum smelter on the banks of the Ohio River.”We are currently in the startup phase,” Bo Wholey, president of Long Ridge Energy Terminal, an affiliate of Fortress Transportation and Infrastructure Investors, said in an Aug. 11 email. The power plant in Hannibal, Ohio, will be “fully operational” in early September, with hydrogen to be introduced in November, Wholey added.The facility first will burn a fuel blend that includes 5% hydrogen in a General Electric Co. H-class gas turbine. The plant is intended to transition to 100% green hydrogen over the next decade by relying increasingly on renewable energy to power electrolysis machines that split water into its hydrogen and oxygen elements.The project has access to industrial byproduct hydrogen for initial testing, according to Long Ridge, but the company is partnering with New Fortress Energy for the green hydrogen transition. It is also exploring underground salt formations for large-scale hydrogen storage.”Having multiple pathways to generating carbon-free energy is a high priority, and we believe, extremely valuable,” Fortress CEO Joseph Adams told investment analysts during a July 29 earnings call. The $600 million project, underpinned by seven- and 10-year fixed-price power sale contracts, is two months ahead of schedule, Adams said.The hydrogen-natural gas generation project is the centerpiece of an intended sweeping makeover of the industrial site, where Long Ridge also plans to develop a 125-acre data center campus with 300 MW of capacity. Advocates hope the project marks the beginning of a new era for hydrogen in helping to decarbonize the power sector and other areas of the economy.Major global equipment suppliers Mitsubishi Corp., Siemens and Wärtsilä Oyj, numerous big U.S. electric and gas utilities and a host of project developers are also placing big bets on hydrogen. Several additional U.S. natural gas-hydrogen hybrid power projects are underway, the largest of which is the Intermountain Power Agency’s planned conversion of an existing coal plant into an 840-MW combined-cycle gas facility by 2025 that would combust up to 30% hydrogen and gradually move to only green hydrogen. Most of the plant’s output is under contract with the Los Angeles Department of Water and Power. But the Union of Concerned Scientists and other clean energy groups have pushed back on burning hydrogen. They have flagged concerns over dangerous nitrogen oxide emissions that occur even with green hydrogen, even though they are supportive of hydrogen fuel cells, which can produce power without combustion.
Study finds blue hydrogen worse than gas or coal — The carbon footprint of creating blue hydrogen is more than 20% greater than using either natural gas or coal directly for heat, or about 60% greater than using diesel oil for heat, according to joint research by Cornell and Stanford universities in the US. The paper, which was published in Energy Science and Engineering, warned that blue hydrogen may be a distraction or something that may delay needed action to truly decarbonise the global energy economy. A research team claimed blue hydrogen requires large amounts of natural gas to produce and said that even with the most advanced carbon capture and storage technology, there are a significant amount of CO2 and methane emissions that won’t be caught. Professors from the universities calculated that these fugitive emissions from producing hydrogen could eclipse those associated with extracting and burning gas when multiplied by the amount of gas required to make an equivalent amount of energy from hydrogen. The paper comes hot on the heels of the United Nations’ Intergovernmental Panel on Climate Change report claiming methane has contributed about two-thirds as much to global warming as CO2 and as many governments are looking to invest in hydrogen production. Robert Howarth, a Cornell University professor and co-author of the study, said: “Political forces may not have caught up with the science yet. Even progressive politicians may not understand for what they’re voting. Blue hydrogen sounds good, sounds modern and sounds like a path to our energy future. It is not.” The UK is high up on the list of countries aiming to put blue hydrogen at the core of its energy transition agenda. UK energy consultancy Xodus recently launched a new report urging a bolder vision to enable the country to become a global leader in the adoption of hydrogen. The researchers, on the other hand, recommended a focus on green hydrogen, which is made using renewable electricity to extract hydrogen from water, leaving only oxygen as a byproduct. “This best-case scenario for producing blue hydrogen, using renewable electricity instead of natural gas to power the processes, suggests to us that there really is no role for blue hydrogen in a carbon-free future. Greenhouse gas emissions remain high, and there would also be a substantial consumption of renewable electricity, which represents an opportunity cost. We believe renewable electricity could be better used by society in other ways, replacing the use of fossil fuels.”
Frackers, Shippers Eye Natural-Gas Leaks as Climate Change Concerns Mount – WSJ – Drones darted in patterns above natural-gas wells in the hills of southwest Pennsylvania, as workers atop water tanks pointed specialized cameras, and a helicopter outfitted with a laser-light detection system swooped in low. All searched for an invisible enemy: methane. The American gas industry faces growing pressure from investors and customers to prove that its fuel has a lower-carbon provenance to sell it around the world. That has led the top U.S. gas producer, EQT Corp. and the top exporter, Cheniere Energy Inc., to team up and track the emissions from wells that feed major shipping terminals. The companies are trying to collect reliable data on releases of methane – a potent greenhouse gas increasingly attracting scrutiny for its contributions to climate change – and demonstrate they can reduce these emissions over time. “What we’re trying to really do is build the trust up to the end user that our measurements are correct,” said David Khani, EQT’s chief financial officer. “Let’s put our money where our mouth is.” Natural gas has boomed world-wide over the past few decades as countries moved to supplant dirtier fossil fuels such as coal and oil. It has long been touted as a bridge to a lower-carbon future. But while gas burns cleaner than coal, gas operations leak methane, which has a more potent effect on atmospheric warming than carbon dioxide, though it makes up a smaller percentage of total greenhouse gas emissions. EQT’s fracking site in Mannington, W.Va., is powered by a turbine rather than conventional diesel engines, which are more typical. The control room at EQT’s field office in Canonsburg, Pa. Oil-and-gas companies use setups like this to remotely monitor – and even run – some operations. Investors, policy makers and buyers of liquefied natural gas, known as LNG, are rethinking the fuel’s role in their energy mix because of concerns about methane emissions, which were highlighted this week as a significant contributor to climate change by a scientific panel working under the auspices of the United Nations. Those concerns, pronounced in Europe and increasingly in Asia, are a problem for LNG shippers, as some of their customers signal plans to ease gas consumption over time. In a policy draft last month, Japanese regulators said the country would have LNG make up 20% of its projected power generation by 2030, down from a prior target of 27%. The European Union has been weighing how to pressure LNG shippers to cut emissions. It could, for example, include LNG among the imports subject to a recently proposed carbon border tax.
PennEast aims to complete first phase of natgas pipe in 2022, despite right-of-way delay (Reuters) – PennEast Pipeline said on Thursday it still expects to complete the first phase of its $1.2 billion natural gas pipe in Pennsylvania in 2022 even though it put off acquiring rights of way for the project due to legal and regulatory hurdles. PennEast, which seeks to complete the pipeline’s second phase from Pennsylvania into New Jersey in 2023, is just one of several long-delayed projects facing opposition from Northeastern states as the region transitions from fossil fuels to cleaner forms of power, like wind and solar. “Given the uncertainty on timing to resolve the remaining legal and regulatory hurdles, PennEast believes it is not prudent to complete the acquisition of the rights of way in the pending actions in Pennsylvania, as it might not be necessary for some time,” PennEast said in a statement. That “uncertainty” caused PennEast partner New Jersey Resources Corp NJR.N last week to announce a $72.7 million after-tax impairment charge related to its investment in the project. In June, the U.S. Supreme Court overturned a Third Circuit decision that blocked PennEast from using federal eminent domain rules to seize New Jersey state-owned or controlled land. That victory cleared one hurdle, but more remain. In addition to completing the rights of way, PennEast still needs permits from environmental Pennsylvania and New Jersey regulators and others before it can start construction. The U.S. Federal Energy Regulatory Commission (FERC) approved PennEast’s request to build the pipeline in January 2018. The company had hoped to complete the project in 2019. The 120-mile (193 kilometer) pipe is designed to deliver 1.1 billion cubic feet per day of gas from the Marcellus shale to customers in Pennsylvania and New Jersey.
Seneca FY3Q: More Drilling to Fill New Pipeline Capacity – Last Friday National Fuel Gas Company (NFG), the parent company for Seneca Resources and Empire Pipeline, issued its latest quarterly update for the quarter ending June 30 (NFG’s third fiscal quarter, everyone else’s second quarter). The exciting news from the update is that with two pipeline projects getting completed this year, Seneca Resources is ramping up its Marcellus/Utica drilling program to take advantage of selling more gas at higher prices.NFG’s FM 100 pipeline project, coming online this year, extends an existing pipeline network in northwestern Pennsylvania to flow an extra 330 million cubic feet per day (MMcf/d) of Marcellus gas to Williams’ mighty Transco Pipeline.A companion project at Williams called the Transco Leidy South expansion is also underway and due to be done this year. Leidy South will carry 600 MMcf/d from Pennsylvania to Atlantic Seaboard markets. Partial capacity on the system was brought online late last year (see Two Williams Projects Online Early: Leidy South & Southeastern Trail). The rest of the Leidy South expansion will be online by the end of this year. All of which means Seneca is ready to drill and complete more wells, to take advantage of their pre-reserved capacity along these pipelines: “For the remainder of the year, we are on track with our plans to ramp up production to fill Leidy South and capture premium winter pricing,” said Seneca President Justin Loweth during a conference call with analysts on Friday. He added: “We have begun the process of accelerating our completion pace and now have two active completion crews, which is a level of activity we expect to continue throughout the first half of fiscal 2022.” NFG/Seneca’s fiscal year (FY) 2022 begins in October.Seneca plans to produce 335-365 Bcfe (billion cubic feet equivalent) in FY 2022, some 25 Bcfe higher than 2021. The new production will come online beginning later this FY (prior to October) and into the beginning of next FY (after October and into early 2022). Seneca produced 83.1 Bcfe during 3Q, a huge increase of 27.1 Bcfe (48%) from the prior year. The improvement was primarily from a 27.3 Bcf increase in natural gas production, largely related to the purchase of Shell’s Marcellus assets last year – 450,000 acres, 350 producing Marcellus and Utica shale wells in Tioga County. During 3Q Seneca drilled 12 new wells.
Activists, Chuck Schumer Protest National Grid’s Brooklyn Pipeline Ahead of Rate Hike Vote – The state’s Department of Public Service is expected to vote Thursday on whether to hike gas rates for National Grid customers in the city – an increase that would help fund a controversial fracked gas pipeline the utility company is constructing in Brooklyn. On Friday afternoon, U.S. Senate Majority Leader Chuck Schumer joined other legislators, community members and environmental activists in Greenpoint to express his opposition to the National Grid North Brooklyn Pipeline Project. “There are a lot of reasons why this is a bad idea,” he said, citing both environmental justice concerns and that the new pipeline is in violation of the state’s progressive climate legislation. The press conference, held in an industrial corner outside the National Grid facility, was in advance of the expected vote Thursday by DPS to increase the utility company’s gas rates. Construction of the seven-mile fracked gas pipeline, which runs from Brownsville up to Greenpoint, was paused in May following multiple protests by environmental justice groups. But the state is still considering rate hikes – which National Grid estimates would increase customers’ monthly bills by $5.56 (or 3.77 percent) in the proposal’s second year and $4.89 (or 3.26 percent) in the third – would fund the work already done on the pipeline. If approved, the company would raise gas prices for its 1.9 million customers in Staten Island, Brooklyn and Southeast Queens, said Lee Ziesche, organizer with the nonprofit Sane Energy. Ziesche learned about the pipeline in 2019 while looking through public records filed with the Department of Public Service. She, along with more than a dozen environmental groups, mobilized to protest its construction. They gained the support of City Comptroller Scott Stringer and Mayor Bill de Blasio, leading National Grid to temporarily halt the project. But by the time the mayor came out against the pipeline in December 2019, four of the five pipeline’s sections had already been completed and begun transporting gas. Schumer declared his opposition to the project while standing among organizers Friday, claiming that the pipeline is in direct defiance of the state’s Climate Leadership and Community Protection Act (CLCPA), ambitious legislation passed in 2019 aimed at transitioning to clean energy and reducing greenhouse gas emissions. “This pipeline violates the precepts of the CLCPA. How can we pass a law and then let them undo the law?” He was joined by Senator Julia Salazar, who told City Limits she’s opposed to both the pipeline and the rate hike. “It’s unhealthy and it’s unnecessary,” she said. “Let’s not grant a rate increase for something nobody wanted in the first place.”
New Yorkers Will Pay for New Gas Pipeline Through Brooklyn With Utility Bill Hike – New York state regulators voted unanimously this morning to increase 1.9-million residents’ utility bills to fund a controversial fracked gas pipeline running through Brooklyn. The New York State Public Service Commission’s (PSC) 7-0 approval of the rate hike comes after years of debate over the funding of National Grid’s Metropolitan Reliability Infrastructure (MRI) project, dubbed the North Brooklyn Pipeline by local activists. The seven-mile long route, construction of which has already been permitted and is nearly completed, runs primarily through Brownsville, Bushwick, Bedford-Stuyvesant, Williamsburg and Greenpoint. Thursday’s vote was over a joint proposal written in May by National Grid, the Long Island Power Authority, and the Department of Public Service, among others, that included rate increases for New Yorkers ($129-million of which will fund pipeline construction); energy efficiency enhancements; limitations on oil and gas marketing; and educational efforts around emissions reductions. “This reflects a solid, creative and responsible work on the part of staff,” said PSC commissioner John Maggiore of the joint proposal before voting yes for its passage in Thursday’s public hearing. “I also think this reflects a point in time and the evolution of this state towards greater reliance on renewable energy sources.” “This case is a gift that will keep on giving,” added PSC Chair John B. Howard following the vote. Though construction on the pipeline began in 2017, New York environmentalists say they were not aware of its existence until 2019, at which point opposition to the project mounted quickly. Over the last year-and-a-half, activists have staged rallies, marches, lock-ups and sit-ins along the pipeline route as the first four phases of its construction were underway. Most recently, the No North Brooklyn Pipeline campaign, apartnership between environmental groups Sane Energy Project, the Brownsville Residents’ Green Committee, Newtown Creek Alliance, and more, launched a gas bill strike across the city, urging New Yorkers to withhold $66 (an estimate of what consumers would be paying over time if the rate hike is approved) from their monthly National Grid payments in opposition to the pipeline.
New York state questions plan to boost capacity at Iroquois pipeline site in Athens – New York environmental officials have some pointed questions for the federal government about plans to upgrade a natural gas pipeline that runs through this Greene County community.The dispute, though, isn’t about plans for a new pipeline. It instead focuses on what might have earlier been an uncontroversial change to an existing line.The proposal by the Iroquois Pipeline Operating Company for adding compressors to their 414-mile eponymously named natural gas line brings into sharp focus the new considerations that state policymakers are weighing regarding energy infrastructure after passage of the 2019 Climate Leadership and Community Protection Act which sets ambitious greenhouse gas reduction goals in New York state.The enhancement by compression project would add a new 12,000-horsepower compressor to the 10,000-horsepower one already in place at the Athens pumping station. Additional compressors are also planned in Dover in Dutchess County and Brookfield, Conn, the latter of which is near company’s headquarters.Iroquois says the expansion would let them increase the flow of gas which runs from the Canadian border through upstate New York and Connecticut to supply New York and Long Island.Iroquois, as well as the utilities that would distribute the gas to customers – ConEd and National Grid’s KeySpan unit – have argued the extra fuel is needed to keep up with demand downstate.It would also offset the need for dirtier oil-burning sources, according to the company.Projected for completion in 2023, the company also says they will use the latest technology to capture methane leaks and use high-efficiency compression equipment.The Federal Energy Regulatory Commission, which oversees most aspects of such pipelines, has been moving the project through its review process.But a number of environmental organizations oppose the upgrade. Rather than making it easier to use natural more gas, they say any new energy initiatives should focus on solar, wind and other carbon-free sources.
West Milford NJ compressor station deal OK’d. What’s next? – Township officials Wednesday approved a deal with Tennessee Gas Pipeline regarding the company’s plan to build a new compressor station near the Monksville Reservoir. The agreement strikes a taxable value of $17.5 million for the property, a former quarry off Greenwood Lake Turnpike. It also requires the pipeline company to fund $10 million in general liability and excess liability insurance, initial and follow-up emergency response training and $20,000 in gas detection equipment for the municipality. In addition to more than $655,000 in expected annual property taxes for 2022, the company agreed to pay the township $200,000. The payment would come in two lump sums: $20,000 within 60 days and $180,000 when the station is federally authorized for service. Mayor Michele Dale said the goal of the agreement is to best position the township in the likelihood that the Federal Energy Regulatory Commission approves the project later this year. The federally regulated project would install a 19,000-horsepower turbine to push more gas through Tennessee Gas Pipeline’s North Jersey infrastructure. Combined with two additional compressor station upgrades, it would provide enough capacity to end Consolidated Edison’s moratorium on natural gas connections in Westchester, New York, records show. West Milford residents and environmental advocates have derided the project for its lack of local benefit. Food & Water Watch organizer Sam DiFalco called the agreement “an abdication of the council’s responsibility to protect their constituents.” “For months, residents have spoken out against this project, out of genuine concern for protecting the health and safety of their communities,” she said. “No amount of money that the town can get from this dirty energy project will make up for a major accident, fire, or a leak of toxins into the Monksville reservoir, a critical source of clean drinking water to millions of New Jersey residents.” Local government officials in Bloomfield, Hamburg, Montague, Ringwood, Wantage and Vernon have adopted resolutions opposing the project.
Environmentalists push FERC on MVP environmental review plans, carbon impacts –A large coalition of environmental groups pressed the Federal Energy Regulatory Commission to pursue a more extensive review of the Mountain Valley Pipeline’s amendment project, days before the commission was scheduled to release its environmental report for the natural gas pipeline. If granted, the lengthy filing backed by 19 groups including Allegheny-Blue Ridge Alliance could add to the timeline for environmental review of the 303-mile, 2 Bcf/d natural gas pipeline project. MVP has been seeking to restore permits and resume construction after legal and regulatory setbacks stalled progress (CP16-10, CP21-57).MVP, which would provide an added outlet for Appalachian gas supplies, in February proposed alternative water crossing methods for about 70 miles of the route. FERC had scheduled release of the environmental assessment for the amendment project for Aug. 13.MVP spokeswoman Natalie Cox, in an Aug. 6 email, said, “The MVP project team continues to expect its [environmental assessment] from the FERC in mid-August.”The environmental groups, however, argued Aug. 3 that FERC erred legally in issuing a scoping notice July 1 that said it had decided on an EA.The supplemental EIS must analyze impacts of the amendment, along with MVP’s requested Clean Water Act Section 404 permit from the US Army Corps of Engineers, they argued.”FERC’s environmental review must examine, on a crossing-by-crossing basis, alternative stream crossing methodologies – including the broader use of trenchless methods,” and must fully consider cumulative effects of hundreds of stream crossings including those in the same stream or watershed, they wrote. The groups also targeted climate impacts, saying FERC must revisit its analysis given new executive orders and the Army Corps’ involvement as a cooperating agency. FERC cannot rely on the “deficient and outdated discussion in its 2017 FEIS,” they contended.
2 Mountain Valley Pipeline protesters locked themselves to drilling equipment (WSET) – Two Mountain Valley Pipeline protesters were arrested Friday morning after reportedly locking themselves to drilling equipment.The incident happened early Friday morning in Lawn, West Virginia, in Greenbrier County, where the Mountain Valley Pipeline crosses underneath Interstate 64. Activist group Appalachians Against Pipelines says the protesters halted work at the site for more than two hours before two protesters were extracted and arrested around 8:30. By 9:30, bail had not been set.”In the expansive timeline of industrial extraction, halting work for a single day might feel molecular, but today’s action is anything but isolated,” stated one of the people locked to the drill. “Today’s action stands in community with all that has transpired, all those that will continue to resist, painting a larger picture of the resiliency of grassroots organizing in Appalachia, the overwhelming value of direct action in rural spaces. As I write and as you read, 303 miles of Appalachian soil is being held captive by the Mountain Valley Pipeline. As pipeline construction intrudes upon the ground under the pads of our feet, we are reminded of the long history of rural communities, of Appalachian flora and fauna reduced to a mere commodity for the sake of bolstering a capitalistic agenda.” The other person who took action today stated: “Today I am taking action against the MVP. For me, the only option is to take direct action against this pipeline which is tearing through the beautiful mountains of Appalachia. I am taking action today not only to oppose this pipeline, but as a part of a broader movement working to abolish the systems of capitalism, white supremacy, cis hetero patriarchy, and all the other systems that are destroying this earth. I am also taking this action in solidarity with Indigenous water protectors and allies fighting Enbridge’s Line 3 up in so-called Minnesota.” Neither protester has been identified, and law enforcement has not yet commented on the arrests. The Mountain Valley Pipeline is a 42-inch diameter, 300-plus mile, fracked gas pipeline that runs from northern West Virginia to southern Virginia, with a 70-mile extension into North Carolina.
Mountain Valley Pipeline protesters arrested after locking themselves to drill tracks – Two people locked themselves to the drill tracks of the Mountain Valley Pipeline in Greenbriar County, West Virginia Friday morning. They are at a construction site 30 minutes outside Beckley, just beyond the intersection of Lawn Road and Route 27. In a press release from Appalachians Against Pipelines, the two protesters issued these statements
- Statement 1: “As I write and as you read, 303 miles of Appalachian soil is being held captive by the Mountain Valley Pipeline. As pipeline construction intrudes upon the ground under the pads of our feet, we are reminded of the long history of rural communities, of Appalachian flora and fauna reduced to a mere commodity for the sake of bolstering a capitalistic agenda.”
- Statement 2: “Today, I am taking action against the MVP. For me, the only option is to take direct action against this pipeline which is tearing through the beautiful mountains of Appalachia.”
There’s also a banner on site that reads “MVP is dead. Doom to the Pipeline.” Work on the pipeline has halted and Greenbriar County Sheriff deputies are on scene. UPDATE: The protesters have been removed and arrested, according to Appalachians Against Pipelines.
Sherriff: Two arrested in Mountain Valley Pipeline protest – Law enforcement officials say two people have been arrested after they were found chained to pipeline construction equipment in Greenbrier County.Local news outlets report that the two were found Friday morning in the Dawson area secured to pipeline equipment with chains and a welded pipe.According to the Greenbrier County Sheriff’s office, local fire department officials helped extract the pair, who were below ground level in a hole. Deputies say one individual voluntarily climbed out, while the other refused and had to be lifted out.The two have both face charges of trespassing, obstructing an officer and conspiracy. It was not immediately known if they had an attorney.Known as the Mountain Valley Pipeline, the project has faced various legal challenges from environmental groups because construction has led to violations of regulations meant to control erosion and sedimentation. The 303-mile pipeline will take natural gas drilled from the Marcellus and Utica shale formations and transport it through West Virginia and Virginia
Environmental Activists Halt Mountain Valley Pipeline Construction – Environmental activists temporarily shut down construction of the already over-budget and behind scheduleMountain Valley Pipeline in southwestern Virginia on Monday. Organizers with the group Appalachians Against Pipelines said 10 people locked themselves to construction equipment to protect native species threatened by the controversial pipeline that would carry fracked gas – primarily methane – more than 300 miles from West Virginia to southern Virginia. “Right now we’re looking at a future with extreme water shortages, accelerating difficulty in growing food, mass human displacement due to natural disasters and manmade disasters caused by pipelines like these,” said Mandy, one of the protesters. The temporary construction comes as activists across the state areramping up pressure to block the pipeline.
Nearly 100 protesters block work on Mountain Valley Pipeline; some are arrested – A crowd of nearly 100 crashed a construction site early Monday morning, loudly voicing their opposition to the Mountain Valley Pipeline. When police arrived at the scene off U.S. 460 in eastern Montgomery County and ordered them to leave, about 80 protesters obeyed, forming a procession as they marched, sang and chanted “Doom to the Pipeline.” About 10 activists remained, chained to heavy equipment and other objects. They were arrested and taken to jail, authorities said. Although human blockades along the construction right of way have become almost routine over the past three years, Monday’s demonstration was the largest of its kind so far to temporarily block work on the natural gas pipeline. Organized by Appalachians Against Pipelines and Arm In Arm, a national organization combating climate change, the protest drew local and out-of-state residents to denounce the project’s environmental damage, use of eminent domain and contribution to global warming. “President Biden, Gov. Northam and Mountain Valley Pipeline officials have been told that clearly the world and civilization as we recognize it cannot survive more conduits of fossil fuels,” said Jim Steitz of Charlotte, North Carolina. “I will not consent to that, and that’s why I’m here,” Steitz said by telephone from the protest site, which was quickly closed off by a large contingent of officers from the Virginia State Police and the Montgomery County Sheriff’s Office.As of 2 p.m., five men and two women had been been taken in a jail van to the magistrate’s office in Christiansburg, according to Lt. Mark Hollandsworth of the sheriff’s office. Appalachians Against Pipelines later said that 10 people had been arrested. After the crowd dispersed, police briefly shut down U.S. 460 in both directions as the procession crossed the highway and formed a support line along the road for the protesters who remained.Many of them waved anti-pipeline signs, drawing honks of support from some motorists and quizzical looks from others.
FERC requests more evidence of reliability impacts as Spire STL pipeline seeks temporary approval —
- Spire STL Pipeline and stakeholders across its Missouri territory are continuing their push for federal regulators to approve temporary operations of the facility while the project assesses its path forward following a potentially detrimental court ruling.
- The pipeline has been in service since 2019, but in June, a federal court of appeals vacated the Federal Energy Regulatory Commission order that allowed the project to move forward, finding the commission did not sufficiently examine evidence of self-dealing and project need. Spire in July requested FERC grant it a temporary certificate of public convenience and necessity while the company sorts out what the court ruling will mean for the pipeline. FERC responded on Friday requesting more information from the company, including on the alleged reliability impacts of closing the pipeline.
- Missouri regulators, the governor, the attorney general and various labor and business groups have echoed Spire’s call for a temporary certificate in comments filed with FERC over the past month. But environmental groups, including the Environmental Defense Fund (EDF) which brought the pipeline company to court in the first place, say the proposal for temporary certification has “serious deficiencies.”
The Spire case has the potential to mark a significant shift in how FERC views the need for new gas infrastructure, according to some environmentalists. In its ruling vacating FERC’s 2018 approval of the pipeline, the D.C. Circuit Court of Appeals found that FERC ignored “plausible evidence of self-dealing” in its assessment of the project. For the pipeline to continue operating, it will need to secure a temporary certificate of public convenience and necessity from FERC, something the company says is necessary to maintain reliable service to the project’s 650,000 customers. FERC, in its response to the request, asked the company to provide more detail on whether the company could meet service requirements without the pipeline, and to back up more thoroughly its claims that the pipeline provided essential reliability services during the February cold snap that led to widespread outages across the Midwest and Texas. Spire, in its comments, had claimed that not allowing the pipeline to remain in service could place “lives at risk.” In comments supporting the company’s bid, Missouri officials, businesses and labor groups agreed that shutting down the pipeline could harm reliability of the local grid. “It is critical that the STL Pipeline be able to continue operations until a long-term, regional solution is established for the citizens and businesses in the St. Louis region,” said Gov. Michael Parson, R, in a comment filed with FERC. “This is particularly important in avoiding gas shortages in the months ahead and throughout this upcoming winter season within the St. Louis area.” But EDF, in comments filed Thursday, argued the company’s application “is fraught with inaccuracies, lacking in key information, and should be scrutinized carefully by the Commission and rejected in part.” Any emergency that may exist if the pipeline is shut down is a problem of Spire’s “own making,” given the pipeline was put into operation in the midst of legal challenges, according to EDF, and therefore the company should not be able to reap any financial benefits if the pipeline does secure temporary authorization.
Chesapeake to buy Haynesville gas producer for $2.2bn – -Chesapeake Energy will acquire natural gas producer Vine Energy through a $2.2bn cash and stock transaction that will expand Chesapeake’s footprint in the prolific Haynesville shale.Under the terms of the deal, Chesapeake will increase its Haynesville net acreage to 348,000, up from 225,000 acres, and its Haynesville output will nearly triple. The combined company will have net Haynesville output of 1.6 Bcf/d (45mn m³/d), the largest of any producer in the field, Chesapeake said.The deal is expected to close in the fourth quarter. Vine shareholders will receive a total of $15/share of consideration, consisting of 0.2486 shares of Chesapeake common stock and $1.20/share of cash.The transaction gives Chesapeake the scale to become the “dominant supplier” of natural gas to the US Gulf coast, Mike Wichterich, Chesapeake’s interim chief executive said.The transaction marks the first major acquisition by Chesapeake since it restructured and emerged from bankruptcy protection in February. Chesapeake has since focused on developing its gas assets in the Haynesville in northern Louisiana and the US Appalachian region, home to the prolific Marcellus and Utica shales.Development of the Haynesville has increased sharply this year as Nymex prompt-month gas prices this summer climbed above $4/mmBtu, rebounding from last year’s sub-$2/mmBtu levels. In addition, the Haynesville is close to key demand centers along the US Gulf coast and to LNG export terminals.The combined company will produce 415,000-435,000 b/d of oil equivalent (boe/d) this year, and 575,000-595,000 boe/d next year, Chesapeake said. Vine had first quarter production of 945mn cf/d and was expecting to increase output to more than 1 Bcf/d during the second quarter.Chesapeake’s second quarter output was 433,000 boe/d, 77pc of which was gas. Output was up by 3pc from a year earlier. Chesapeake plans to operate 10-12 rigs next year, eight or nine of which will develop the company’s gas asset while the others will develop the company’s oil assets. The company operated seven rigs during the second quarter.
Sweeping Infrastructure Bill Goes Big on Energy Transition, Leaves Natural Gas Wanting – The $1 trillion infrastructure bill passed by the U.S. Senate Tuesday with bipartisan support includes a big boost in spending on renewable energy, the power grid and programs to broadly promote lower greenhouse gas emissions to slow climate change. The massive bill contains more than $550 billion in new spending. About $110 billion of that is for physical infrastructure such as roads and bridges, the largest share. But the legislation also invests $73 billion to modernize the nation’s aging electricity grid with new transmission lines that could transport renewable energy from sources such as solar and wind to rural communities in an effort to hasten the adoption of cleaner energy sources, a pillar of President Biden’s agenda.The bill would also invest more than $20 billion in environmental remediation, financing programs to advance the transportation and storage of hydrogen and captured carbon dioxide, among other efforts.Natural gas advocates applauded the legislation’s broad intentions – both the money tagged for traditional infrastructure and to encourage evolution in energy – with one outsized caveat: Gas must have a stated role in the nation’s energy foundation for years to come.The bill “creates new, game-changing programs for deploying low-carbon energy solutions and the pipeline and storage infrastructure that will deliver those solutions,” said Interstate Natural Gas Association of America CEO Amy Andryszak. However, she added, while Biden acknowledged the importance of natural gas during his campaign in 2020, the Senate-passed legislation does not account for the enduring role of gas that most in the energy sector expect would be necessary for decades to come.“Any serious plan to both address global climate change and develop a modern, reliable and affordable energy system must include natural gas as a foundational fuel,” Andryszak said.
U.S. natgas slips on drop in crude prices, lower demand forecasts (Reuters) – U.S. natural gas futures slipped to a near one-week low on Monday due to a drop in oil prices and forecasts for less demand over the next two weeks than previously expected. Traders noted the gas price decline came despite an outlook showing the weather will remain hotter-than-normal through late August. Front-month gas futures NGc1 fell 8.0 cents, or 1.9%, to settle at $4.060 per million British thermal units (mmBtu), their lowest close since Aug. 3. Oil prices dropped 2%, extending last week’s steep losses on the back of a rising U.S. dollar and concerns new coronavirus-related restrictions in Asia, especially China, could slow a global recovery in fuel demand. O/R In the power market, the Electric Reliability Council of Texas (ERCOT), grid operator for most of the state, projected hot weather this week would push peak demand over the current high for the year of 72,856 megawatts (MW) on July 26. The forecast peaks, however, were expected to fall short of the grid’s all-time high of 74,820 MW in August 2019. Data provider Refinitiv said gas output in the U.S. Lower 48 states had risen to an average of 92.0 billion cubic feet per day (bcfd) so far in August from 91.6 bcfd in July. That was still well below the all-time high of 95.4 bcfd in November 2019. With hotter weather expected, Refinitiv last week projected average gas demand, including exports, would rise from 93.4 bcfd this week to 94.4 bcfd next week as power generators burn more fuel to meet rising air conditioning use. Those forecasts, however, were lower than Refinitiv projected on Friday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants has slipped to an average of 10.3 bcfd so far in August due to reductions at the Cameron and Sabine plants in Louisiana, down from 10.8 bcfd in July and a record 11.5 bcfd in April.
Wind Generation Seen Limiting Bullish Impact of Heat as Natural Gas Futures Slide -Natural gas futures fell in early trading Wednesday as analysts looked for wind generation to curb the bullish effect of peak summer heat in the forecast this week. As of around 8:50 a.m. ET, the September Nymex contract was down 5.6 cents to $4.033/MMBtu. From a national gas-weighted degree day standpoint, widespread heat over the eastern half of the country this week will result in the hottest stretch of the summer, according to Bespoke Weather Services. “Muting the bullish effect of the strong heat, however, remains much higher wind versus what we saw last week and the week before, although the wind declines back to low levels by Friday and into the weekend,” Bespoke said. “Heat pulls back into early next week, but into the final third of August, another round of above normal heat is favored in the Midwest and East.” EBW Analytics Group analysts told clients early Wednesday that they expect the peak summer temperatures to help technical support for the September contract hold above $4. Also supporting the front-month is the strength of winter-month contracts bolstered by the storage deficit, according to the firm. “Simultaneously, though, a major dip” in liquefied natural gas (LNG) feed gas demand in the Gulf Coast, which was “partially reversed” in Wednesday’s data, and “very high wind generation (expected to fade soon) have kept prices at Henry Hub in check, limiting the ability of futures to move higher,” the EBW analysts said. “How long this deadlock persists could depend upon this week’s storage report and continued forecast shifts.”
US working natural gas volumes in underground storage rise 49 Bcf: EIA – US working gas storage volumes increased by 49 Bcf for the week ended Aug. 6, slightly more than what the market expected as the NYMEX Henry Hub winter strip declined following the announcement. he build brought the US storage total to 2.776 Tcf, the US Energy Information Administration reported Aug. 12. The injection was more than the 44 Bcf addition expected by an S&P Global Platts’ survey of analysts. Responses to the survey ranged from injections of 38 Bcf to 56 Bcf. The storage build was more than the five-year average build of 42 Bcf but less than the 55 Bcf injection in the corresponding week of last year. The Platts Analytics’ supply and demand model proved closest at 47 Bcf. The analysts’ survey has proved close to the mark over the past four weeks, missing the EIA estimate by an average of 4.5 Bcf. US storage volumes now stand 548 Bcf, or 16.5%, less than the year-ago level of 3.324 Tcf and 178 Bcf, or 6%, below the five-year average of 2.954 Tcf. The injection was much stronger than 13 Bcf added the week prior. Supplies were flat on the week with offsetting changes in production and imports from Canada, according to Platts Analytics. Downstream, however, total demand fell by 4.5 Bcf/d, driven mainly by a 4.3 Bcf/d decline in gas-fired power demand week on week. US power burns tumbled more than 5 Bcf/d year on year in July, because of higher natural gas prices and milder weather. Population-weighted temperatures have come in roughly one degree below the 10-year normal, while prices have tracked $2/MMBtu higher this July versus last. The NYMEX Henry Hub September contract slipped 14 cents to $3.91/MMBtu during trading Aug. 12. The winter strip, November through March, shed 16 cents to averaged $4.03/MMBtu, representing a net decline of 20 cents from one week prior. This kept the seasonal price spread flat at roughly 10 cents, which has been exceedingly small this summer to date. Spreads from this summer to next winter are now trading slightly above 10 cents/MMBtu, still not enough to clear storage cycling costs and prioritizing spot gas over future reliability in the event of a cold winter. Platts Analytics’ supply and demand model currently forecasts a 35 Bcf injection for the week ending Aug. 13, which would measure 7 Bcf less than the five-year average.
U.S. natgas futures slide to 3-week low on forecasts for less hot weather (Reuters) – U.S. natural gas futures fell to a three-week low on Friday on forecasts for less hot weather and lower cooling demand than previously expected and despite expectations U.S. liquefied natural gas (LNG) exports will rise as Gulf of Mexico plants boost output after finishing maintenance work. Demand for U.S. LNG has been growing in Europe and Asia, where gas prices were almost quadruple U.S. prices. Front-month gas futures NGc1 fell 7.2 cents, or 1.8%, to settle at $3.861 per million British thermal units (mmBtu), their lowest close since July 19. For the week, the contract was down about 6%, its biggest weekly percentage loss since February. Last week it gained almost 6%. In the Atlantic basin, Tropical Depression Fred was expected to strengthen into a storm as it marches toward South Florida on Saturday. Traders noted Fred would likely result in cooler weather and power outages that would reduce gas demand but not affect output much since Florida produces almost no gas. Data provider Refinitiv said gas output in the U.S. Lower 48 states rose to an average of 92.0 billion cubic feet per day (bcfd) so far in August from 91.6 bcfd in July. That compares with an all-time high of 95.4 bcfd in November 2019. Refinitiv projected average U.S. gas demand, including exports, would rise from 92.2 bcfd this week to 92.8 bcfd next week as LNG exports increase, before sliding to 92.4 bcfd as the weather turns less hot and air conditioning use declines. The forecast for next week was a little lower than Refinitiv expected on Thursday. The amount of gas flowing to U.S. LNG export plants was expected to jump to a four-week high of 10.9 bcfd on Friday from an eight-week low of 9.3 bcfd on Tuesday as several Gulf Coast plants, including Cameron and Sabine in Louisiana and Freeport in Texas, returned to near full service. That compares with an average for LNG feedgas of 10.2 bcfd so far in August, 10.8 bcfd in July and a record 11.5 bcfd in April. With European and Asian gas both trading over $15 per mmBtu, compared with around $4 for the U.S. fuel, analysts said buyers around the world would keep purchasing all the LNG the United States can produce. Prices at the Title Transfer Facility (TTF) in the Netherlands, the European benchmark, hit a record high on Wednesday. U.S. pipeline exports to Mexico have slipped to an average of 6.3 bcfd so far in August from 6.6 bcfd in July and a record 6.7 bcfd in June.
Oil dispersants used in BP disaster must undergo EPA health, safety review, judge rules — After almost 30 years of delays and a range of health and environmental concerns raised by scientists, a federal judge has ordered the U.S. Environmental Protection Agency to update its rules for the chemical dispersants that were used during BP’s Deepwater Horizon oil disaster.Judge William Orrick of the U.S. District Court in San Franciso agreed Monday with environmental groups that the update is long overdue. “I find that the EPA breached its non-discretionary duty to issue the final rule” and “delayed unreasonably” a process that scientists have been calling for since the mid-1990s, Orrick wrote. Orrick, an appointee of President Barack Obama, gave the EPA a May 31, 2023 deadline to update and finalize its rules. Citing past delays by the agency, Orrick also ordered the agency to file status updates every 180 days.Over the past four years, a flood of new research has blamed dispersants for a host of problems, including lingering human health effects from the BP disaster more than a decade ago.“We are delighted, although not really surprised, with the court’s finding that oil spill response regulations enacted more than 15 years before the BP Deepwater Horizon disaster are no longer aligned with current science and technology,” said Sumona Majumdar, a lawyer for Earth Island Institute, one of the groups that sued the EPA last year. “We urge the EPA to quickly issue a final rule that properly regulates these dangerous chemicals.”
Shreveport City Council approves ordinance calling for moratorium on oil, gas operations – The Shreveport City Council has approved an ordinance similar to one that failed to pass at last week’s Caddo Parish Commission meeting, which called for a moratorium on oil and gas operations and asked the Louisiana Department of Natural Resources to meet with concerned citizens.The ordinance proposed by Tabatha Taylor (District A) was voted 5-2 during a meeting on Tuesday. In late July, Caddo Parish Commissioner Ken Epperson similarly called for a six-month moratorium on drilling activity in his district after numerous complaints about noise and pollution. The resolution asked for meetings between the public and oil & gas operators and called on the Louisiana Department of Natural Resources to enact a six-month moratorium on drilling and fracking until the nuisance issues could be reached. After discussion during Thursday’s meeting, during which a motion by Commissioner John Atkins to take the request for a moratorium out failed, the resolution itself failed to win the necessary majority of the commission’s approval in a 6-6 vote along party lines.
Cheniere Sees Record LNG Exports, but Commodity Price Exposure Leads to Losses -Cheniere Energy Inc. reported record liquefied natural gas (LNG) exports from its terminals in Louisiana and Texas during the second quarter, when demand surpassed expectations as the global market tightened further. The largest U.S. gas exporter loaded 139 cargoes, or 496 TBtu of LNG, in the second quarter. Results shattered a previous record of 133 cargoes set in 1Q2021 and were up from the 78 cargoes exported during the same period last year. An improving outlook for the global gas market prompted Cheniere to revise its 2021 financial guidance upward. The company is now guiding for distributable cash flow of $1.8-2.1 billion, compared with the previous range of $1.6-1.9 billion.“The continued strengthening of the LNG market is yielding higher netbacks on open volumes,” said CEO Jack Fusco. “For context, since our first quarter earnings call in May, spot margins doubled and our portfolio optimization team has been able to capitalize on that with our open volumes.”The company has continued to debottleneck production through maintenance optimization and churn out higher volumes from its trains at the Corpus Christi and Sabine Pass terminals. It anticipates producing extra LNG through the second half of the year. Cheniere has also had success this year signing fixed-fee LNG sales agreements with multiple buyers for its excess volumes. The deals total 12 million metric tons of LNG to be delivered between 2021 and 2032, further underscoring “the strength in the LNG market today,” Fusco said. A cold winter that spilled into the spring and left natural gas inventories tight in Europe and Asia forced buyers to bid up prices for restocking. The trend has continued because of high cooling demand across the Northern Hemisphere this summer. Stronger-than-normal demand in South America amid a drought and global LNG production disruptions have also left the market short of cargoes.
Energy Transfer Says Jump in Gas Prices, Strength in NGL and Refined Products Boost 2Q2021 Results – U.S. midstream giant Energy Transfer LP said its natural gas storage and pipeline operation along with its natural gas liquids (NGL) business helped drive stronger second quarter 2021 earnings.Energy Transfer, whose pipelines held up amid Winter Storm Uri in Texas last winter when others’ did not, said Tuesday in reporting earnings that it continued to collect fee income from natural gas transports to meet demand during the historic deep freeze. It also benefited from rising natural gas prices this summer amid robust domestic cooling demand.Second-quarter earnings in Energy Transfer’s intrastate transportation and storage business rose 20% from a year earlier. It reported an increase of $52 million in transportation fees, with $39 million due to revenue related to Uri.The company also has ramped up its NGL and refined products transportation business to meetmounting global demand amid the recovery from the coronavirus pandemic. It said earnings in the division rose about 9% from a year earlier.Energy Transfer said NGL and refined products terminal volumes rose nearly 60% from a year earlier. In addition to the pandemic recovery and higher throughput volumes, it cited increased export volumes at its Nederland Terminal in Texas due to the initiation of service on its propane and ethane export pipelines late in 2020.“The NGL segment is just unbelievably exciting. We can’t say enough about our team and all the effort we put together at the end of 2020,” co-CEO Marshall McCrea said Tuesday during a call with analysts.Total 2Q2021 revenue more than doubled from a year earlier to $15.1 billion. The company said its net income rose to $908 million from a $292 million loss a year earlier.
Midstream approach to renewables takes shape as more firms announce investments –Under pressure from shareholders and policymakers to reduce greenhouse gas emissions, U.S. pipeline companies are firming up strategies for investing in existing renewable fuels facilities and decarbonizing oil and gas projects already under construction. In terms of acquisitions, the wave of clean energy-oriented M&A that industry experts expected to materialize following Kinder Morgan Inc.’s decision to buy renewable natural gas developer Kinetrex Energy for $310 million is beginning to take shape. Days after U.S. President Joe Biden signed an executive order calling for all-electric cars to make up 50% of new sales in the country by 2030, refiner Phillips 66 announced plans Aug. 9 to purchase a 16% stake in Novonix Ltd., which supplies materials for lithium-ion batteries. Phillips 66 will feed its existing business into Novonix’s synthetic graphite manufacturing facility and expand that asset’s capacity. “[Phillips 66’s] production of specialty coke, which is used to make anode material for batteries, supports the development of a fully domestic supply chain for sales into the rapidly growing U.S. EV market,” analysts at energy investment bank Tudor Pickering Holt & Co. told clients Aug. 10. “The acquisition bolsters PSX’s commitment to pursue lower-carbon solutions.” On Aug. 9, Tallgrass Energy LP closed the acquisition of a 75% membership interest in Escalante H2Power, which is developing a hydrogen-to-power project at the Escalante generating station in New Mexico. The company plans to convert the retired coal-fired power plant, owned by Tri-State Generation and Transmission Association Inc., into a clean hydrogen-fired power generating facility as gas utilities advance hydrogen pilot projects to decarbonize pipeline networks. While many midstream management teams have expressed interest in potentially blending limited amounts of hydrogen into existing gas pipelines, they have also maintained that retrofitting them for that purpose does not necessarily make financial sense. Midstream and end-use infrastructure will be another major challenge for blending, according to S&P Global Platts Analytics, since compressor stations, meters, natural gas turbines, furnaces, water heaters and gas burners would all need to be recalibrated to account for hydrogen’s higher burn speed and lower calorific content.
Permian Basin Gets Vote of Confidence With Infrastructure Plan – The region at the heart of the once-booming U.S. shale industry is signaling confidence in a nascent recovery after the pandemic crushed demand and curtailed oil and gas drilling.The Permian Basin, which straddles West Texas and New Mexico, has grown over the past decade to produce more oil than Iraq. But it has struggled to cope with some of the effects of its expansion over the past decade: roads crumbling from a heavy volume of 18-wheelers, a lack of doctors, skyrocketing house prices and rents, and a lack of qualified workers.A coalition of energy companies, along with state and local partners, plans to spend $844 million on roads, education, workforce development, housing, broadband and health care in the region, according to the Permian Strategic Partnership, which assembled the group. The Texas Department of Transportation is providing most of the funds, while companies including Chevron Corp. and Halliburton Co. are also kicking in.The move gives some much-needed reassurance over the shale industry’s future after a dramatic contraction last year that came as virus shutdowns curtailed travel and sent the U.S. economy into a tailspin. The Permian, which produces more than a third of the crude oil and over a tenth of the natural gas in the U.S., is showing a modest recovery in production and jobs, even as other shale regions flatline and U.S. oil and gas companies focus on returning capital to investors rather than raising output. Texas’s transportation department is providing $675 million for roads and related projects, while the State of New Mexico is contributing $13 million, according to figures provided by the partnership. Companies, which range from multinationals including Chevron and Royal Dutch Shell Plc to large independents such as EOG Resources Inc. and service providers like Halliburton, are spending $48.5 million.
Oxy Looks to Ramp Permian Carbon Capture by Early 2024, Consider More JVs in Lower 48 – The world’s largest direct air capture (DAC) facility, designed to zap up to 1 million metric tons/year of carbon dioxide (CO2) emissions from the Permian Basin, is tracking to start up by early 2024, Occidental Petroleum Corp. CEO Vicki Hollub said Wednesday. Oxy, as it is better known, issued its second quarter results on Wednesday. The Houston-based independent posted solid results across its U.S. and international holdings, with stronger profits and improved efficiencies. Several analysts, though, were keen to hear more about a project that has yet to break ground. Oxy in February pulled the trigger for the first phase offront-end engineering design (FEED) to build what would be the world’s largest DAC, a CO2 capture project set for West Texas. “The FEED study should be done, and we should have final investment decisions in the early part of next year,” Hollub said. “We hope to begin construction by the end of 2022 or beginning of 2023…It should be then online toward the end of 2023 or into 2024. It will be up and running certainly by 2024.”If the project captures 1 mmty of CO2, that would be around 5% of what Oxy sequesters every year through its enhanced oil recovery (EOR) business, also centered in the Permian.Oxy is partnering on the DAC facility with developer 1PointFive Inc. through Oxy Low Carbon Ventures LLC. Initial funding is from Rusheen Capital Management LLC. The unique technology was created by Carbon Engineering Ltd., in which Oxy is an equity owner. Questions still remain about the overall costs to build the facility. Financing overall has not been finalized, but Hollub said “there are multiple ways to fund it. “One is to make investment in the facility itself. Second is to commit to taking the CO2 credits. Third is to commit to purchasing the oil that’s generated from the CO2 that goes into enhanced oil recovery.“We’re working through that now and talking to a lot of interested parties. We should have more information on how we’re going to do that by early next year. But there’s definitely a lot of interest in making this happen.”“It’s for the U.S. and for the world. Direct air capture needs to happen successfully and happen in a big way. And so that’s generating the interest in the parties that want to be contributing to it and then get to participate in the results of it.”
Exxon Accelerates Deleveraging, Targets Sale Of Shale Gas Properties By End Of 2021 -Traditional oil and gas company-turned ESG darling Exxon (we’re only half joking) is heading into the second half of 2021 with momentum. Not only has the oil giant benefitted from the tailwind of increased oil demand and rising prices, but now it is looking to accelerate its deleveraging by selling its shale assets. The company has restarted marking its shale gas properties in an attempt to “reduce debt taken on last year,” according toReuters. Exxon is following through on plans it set three years ago to raise $15 billion from asset sales by December 2021. The pandemic threw a wrench in the gears for most of 2020, as the company had to deal with the dual threat of a demand zap coupled with lower oil prices. On top of that, the company was struggling to address its image as a oil and gas company in the midst of a historic adoption of stock market virtue signaling ESG investing. Exxon lost a record $22.4 billion in 2020, but has committed to making its dividend and deleveraging its priority.So far this year, the company has achieved sales and has pending sales totaling about $2.7 billion. Overall, it has reached about $5 billion of its $15 billion sales goal. The company has paid off more than $7 billion in debt this year. Exxon has about $60 billion in debt it now must deal with as a result. Its XTO Energy shale unit is looking to sell almost 5,000 natural gas wells in the Fayetteville Shale in Arkansas, the report says. Exxon has turned focus from these underperforming assets to newer wells in Guyana, offshore Brazil and – believe it or not – Texas’s Permian Basin.
US oil, gas rig count jumps 14 to 617 on week as companies sound upbeat note – The US oil and gas rig count jumped 14 to 617 on the week, energy analytics and software company Enverus said Aug. 12, the highest activity level since early April 2020 as upstream companies concluded second-quarter earnings calls on an upbeat note. Oil rigs landed at 474, up 11, while natural gas-directed rigs were at 143, up three for the week ended Aug. 11. Horizontal rigs leaped forward by eight to 469 – also the highest that rig classification has been since mid-April 2020. “Looking ahead, we continue to expect relatively modest incremental horizontal activity improvement over the balance of Q3 2021, followed by a stronger ramp-up over the course of Q4,” boutique investment bank Tudor Pickering Holt said in its Aug. 9 daily investor note. Geographically, the basin with the biggest weekly change was the Bakken Shale of North Dakota/Montana, which gained three rigs for a total 25. That is the highest activity level in that play, where the rig count has been fairly rangebound in recent weeks, since late April 2020. The gas-prone Haynesville Shale of East Texas/Northwest Louisiana picked up two rigs in the past week, for a total 57 rigs. And gaining a single rig were the Eagle Ford Shale of South Texas and the SCOOP-STACK play in Oklahoma, making totals of 41 and 30, respectively. In addition, the giant Permian Basin of West Texas/New Mexico lost one rig, as did the Marcellus Shale, mostly sited in Pennsylvania, leaving totals of 257 and 31, respectively. The DJ Basin of mostly Colorado and the Utica Shale were unchanged, at 15 and 13 rigs, respectively. E&P operators’ quarterly earnings calls for Q2, most of which wrapped up over the past week, reflected a growing confidence in continued oil price strength and stability. Producers appeared not to be tempted by higher oil prices in recent months – even though those prices came down a bit in the last week. For example, WTI NYMEX oil prices averaged $68.28/b, down $3.23, while WTI Midland averaged $68.39/b, down $3 and Bakken Composite prices averaged $67.56/b, down $2.93, according to S&P Global Platts. But natural gas prices gained strength, averaging $4.14/MMBtu, up 15 cents, while at Dominion South they weighted in at $3.72/MMBtu, up 55 cents. Overall, E&Ps spent around 25% of their full-year budgets in Q2, or around 47% in the first half of 2021, while completing roughly 30% higher planned onshore wells (about 51% in H1 2021), Credit Suisse analyst William Janela said in an Aug. 11 investor note.
Noble agrees to pay $1 million penalty for oil spills -Noble has reached a settlement with the U.S. Environmental Protection Agency and the U.S. Department of Justice for alleged violations of the Clean Water Act. Noble, which includes Noble Energy, Inc., Noble Midstream Partners LP and Noble Midstream Services, LLC, announced on Tuesday that they have agreed to pay $1 million and take actions to prevent future spills. “EPA will continue to make sure facilities like the State M36 and Wells Ranch Facilities comply with the federal requirements that safeguard our communities and our rivers and streams,” said Suzanne Bohan, director of EPA Region 8’s Enforcement and Compliance Assurance Division. “This agreement will help prevent future oil discharges to Colorado’s waters by requiring Noble to invest in improved spill containment and response measures at all tank battery sites operating in floodplains.” The violations include discharging oil from the State M36 Facility into the Poudre River in 2014 and not following prevention and response regulations for oil spills at the Wells Ranch and State M36 Facilities. The Oil Spill Liability Trust Fund, which pays for the oil and hazardous substances clean up, will receive the $1 million. Required containment and prevention measures include: installation of steel oil-spill containment berms, remote monitoring sensors and anchoring active tank batteries in Colorado floodplains. Response training, drills and exercise programs must be implemented at the Wells Ranch facility.
‘Game changer’? Deal on orphaned wells sparks debate – Lawmakers are poised to make a historic investment to clean up abandoned oil and gas wells, but the $4.7 billion fund tucked into the bipartisan infrastructure proposal is missing a key reform sought by some Democrats. Democratic lawmakers have pushed for increased bonding on federal oil and gas development and for pressure on states to shore up their bonding regulations in return for federal dollars. “This funding is a useful first step, but it is crucial that we continue to work towards passing bonding reform,” said Sen. Michael Bennet (D-Colo.), whose bill, the “Oil and Gas Bonding Reform and Orphaned Well Remediation Act,” S. 2177 would increase bonding rates on federal and tribal lands. He added: “Doing so would ensure we hold companies operating on public lands to the same high standards that responsible operators already follow.” Calls for bonding reform, echoed by many large environmental groups, are part of an attempt to stop abandoned wells from costing taxpayers in the future by ensuring that industry secures the cost of reclamation up front. Risk of abandonment will grow in the coming years, advocates say, especially as the world shifts toward cleaner fuels. “There is a concern, which is valid, that we may have many more orphan wells in the future,” said Adam Peltz, a senior attorney at the Environmental Defense Fund who supported the infrastructure funding as an important step. Orphaned well cleanup has garnered support on both sides of the aisle and proved a popular talking point for Biden officials. They say it addresses methane emissions harmful to the climate, while keeping oil and gas workers employed. But bonding at the national level has fallen along partisan lines, with Republican lawmakers from fossil fuel states saying the high cost of bonding can depress drilling. Rep. Teresa Leger Fernflndez (D-N.M.), acknowledged the exclusion of tougher bonding measures from the infrastructure package.
Republicans ask court to compel Biden administration to sell drilling leases – More than a dozen Republican-led states are asking a court to compel the Biden administration to sell leases for offshore drilling, arguing that the Interior Department is not following a court order requiring it to end a leasing pause. In a court filing on Monday, the states argued that the administration is not following a June injunction that ended its pause on issuing leases on new parcels of land for public lands and offshore drilling. “Defendants have violated the Court’s June 15 Order by their continued application of the Pause to refuse to hold new onshore lease sales or Lease Sale 257,” they wrote, referring to a specific offshore lease sale that was canceled in February. They added that the court should “order Defendants to comply with the law and this Court’s injunction by holding Lease Sale 257.” Under the pause – which was said to be temporary but had no announced end date – ongoing drilling on public land and water continued, and the Interior Department continued to issue permits for new drilling on land that it had already leased. In their filing, the states specifically ask the court to reinstate Lease Sale 257, which would have auctioned off about 78 million acres in the Gulf of Mexico for drilling. A spokesperson for the department declined to comment on this week’s court briefing. In testimony late last month, Interior Secretary Deb Haaland argued that even without having held sales, the administration was in compliance with the court order, citing the work that goes into organizing the sales. “We are complying with the court order right now. As we speak, the department is working. As I mentioned, there’s a lot of work that goes into even having a lease sale and so they are complying with the court order,” Haaland said.
Environmentalists push lawsuits after impact statement released on $3 billion rail project that would quadruple Uinta Basin’s oil output – An oil-hauling railway for the Uinta Basin took a big stride forward Friday with the release of an environmental impact statement (EIS) identifying a preferred route for the 85-mile line that would connect Utah’s oil patch with the national rail network. The Uinta Basin Railway, proposed by a group of energy-producing Utah counties, would move crude from a load-out near Myton west through Indian Canyon to a connection with the Union Pacific line at Kyune near the top of Price Canyon. Four to 11 100-car trains would travel the route each day, enabling the basin’s oil production to quadruple, increasing daily output to 300,000 barrels according to the EIS. The controversial project is under review by the federal Surface Transportation Board, which is expected to issue a final decision in the coming weeks that would allow permitting and construction to begin. The single-track railway would cross stream at 443 places, affecting 61 miles of streams, and could negatively affect 10,000 acres of wildlife habitat. But worse, according to environmentalists, it would promote increased fossil-fuel development at a time when the nation needs to be reducing climate-altering emissions of greenhouse gasses. The EIS takes only a cursory look at the impacts associated with increased drilling in the Uinta Basin, whose airshed already violates federal standards for ozone, according to the Center for Biological Diversity. “This document essentially ignores critical environmental issues by making plans to study them later, behind closed doors,” said Wendy Park, a senior attorney with the group. “Utahns are already choking on wildfire smoke, facing historic drought conditions and suffering sweltering heat waves. This colossal waste of public funds advances a filthy oil train that will only make our climate emergency worse.”
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