Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 29 May 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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Oil prices hit 31 month high; gasoline demand and refinery utilization both at a 14 month highs
Oil prices rose for the fourth week in five as strong US economic data fed optimism on the outlook for fuel demand.. after falling 2.7% to $63.58 a barrel last week on fears of a deal that would lift sanctions on Iranian crude, the contract price of US light sweet crude for July delivery opened higher on Monday, boosted by signs of continuing economic recovery from Covid-19 in the US and an improved outlook for fuel demand. and climbed $2.47, or 3.9%, to settle at $66.05 a barrel, after a U.S. official said there aren’t yet any signs that Iran would comply with the commitments required to lift US sanctions, casting doubts that Iran would soon be able to resume crude exports…however, oil prices eased on Tuesday after Iran and the U.N. nuclear watchdog said they were extending a recently expired monitoring agreement by a month, allowing more time for negotiations, but still finished 2 cents higher at $66.07 a barrel, as rising demand with the approach of the summer driving season and lifting of coronavirus restrictions supported prices…after slipping below $66 early Wednesday, oil prices rebounded after the EIA reported inventory draws from crude supllies and across all major product stores, and settled 14 cents higher at $66.21 a barrel on reinforced expectations of improving demand ahead of the peak summer driving season…oil prices moved lower early Thursday on demand concerns due to the COVID-19 crisis in Asia and on a potential increase in Iranian supplies, but rebounded to finish 64 cents or 1% higher at $66.85 a barrel, the highest daily close since October 2018, bolstered by strong U.S. economic data that offset traders’ concerns about the potential for a rise in Iranian supplies…oil prices opened higher and rose more than 1% early Friday amid hopes that an ongoing economic recovery in the US would have a positive impact on oil demand. but slumped late in the session to finish the day down 53 cents at $66.32 a barrel as traders took profits while awaiting the outcome of next Tuesday’s OPEC+ meeting…nonetheless, oil prices ended with an increase of 4.3% for the week, the biggest weekly gain since the middle of April, and also ended the month of May 4.3% higher, based on front month contract closing prices…
Natural gas prices also finished higher for the seventh time in eight weeks, on higher prices overseas and on a bullish shift the weather forecasts…after falling 1.9% to $2.906 per mmBTU last week as production rose and exports fell, the contract price of natural gas for June delivery opened lower and slumped more than 7 cents early on Monday as production increased and on forecasts for milder weather and less demand over the next two weeks than previously expected, but came back to settle just 2.0 cents lower at $2.886 per mmBTU, still the lowest close since April 27th…the rebound continued into Tuesday as gas prices rose 2.7 cents to $2.913 mmBTU on expectations that rising global prices would boost LNG exports back to record highs in the coming weeks…prices continued rising into Wednesday, the last day of trading for the June contract, as a favorable shift in the weather-demand outlook offset expectations for a triple-digit storage injection, with the EIA’s inventory report pending Thursday, as June natural gas rolled off the board priced 7.1 cents higher at $2.984 per mmBTU, while the more actively traded July contract added 5.3 cents to settle at 3.027 per mmBTU…now quoting the contract price of natural gas for July delivery, prices tumbled more than 9 cents on Thursday after a bearish government inventory report, but recovered to end down 6.9 cents or 2.3% at $2.986 per mmBTU…however, natural gas futures rose again on Friday to their highest in more than a week, buoyed by forecasts for warmer weather in two weeks and a projected increase in liquefied natural gas (LNG) exports, and settled 2.8 cents higher at $2.986 per mmBTU, thus posting an apparent 2.8% increase for the week, even as the July natural gas contract, which had closed the prior week at $2.977 per mmBTU, only gained 0.3% on the week…
The natural gas storage report from the EIA for the week ending May 21st indicated that the amount of natural gas held in underground storage in the US rose by 115 billion cubic feet to 2,215 billion cubic feet by the end of the week, which still left our gas supplies 381 billion cubic feet, or 14.7% below the 2,596 billion cubic feet that were in storage on May 21st of last year, and 63 billion cubic feet, or 2.8% below the five-year average of 2,278 billion cubic feet of natural gas that have been in storage as of the 21st of May in recent years….the 115 billion cubic feet that were added to US natural gas storage this week was above the average forecast of a 107 billion cubic foot addition from an S&P Global Platts survey of analysts, and was also above the average addition of 91 billion cubic feet of natural gas that have typically been injected into natural gas storage during the second week of May over the past 5 years, as well as above the 105 billion cubic feet 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 May 21st showed that because of a modest increase in our oil exports, a modest increase in our oil refininng, and a modest decrease in our oil imports, we needed to withdraw oil from our stored commercial crude supplies for the sixth time in fourteen weeks and for the 28th time in the past forty-four weeks….our imports of crude oil fell by an average of 138,000 barrels per day to an average of 6,273,000 barrels per day, after rising by an average of 923,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 127,000 barrels per day to an average of 3,433,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,840,000 barrels of per day during the week ending May 21st, 265,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly unchanged at 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 13,840,000 barrels per day during this reporting week…
US oil refineries reported they were processing 15,239,000 barrels of crude per day during the week ending May 21st, 123,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 473,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 927,000 barrels per day less than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+927,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or errors of that magnitude in this week’s oil supply & demand figures that we have just transcribed…..however, since most everyone treats these weekly EIA 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 accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,905,000 barrels per day last week, which was 0.5% more than the 5,875,000 barrel per day average that we were importing over the same four-week period last year… the 473,000 barrel per day net withdrawal from our crude inventories included a 235,000 barrel per day withdrawal from our Strategic Petroleum Reserve, space in which has been leased for commerical purposes, and a 237,000 barrel per day withdrawal from our designated commercially available stocks of crude oil….this week’s crude oil production was reported to be unchanged at 11,000,000 barrels per day even though the rounded estimate of the output from wells in the lower 48 states rose by 100,000 barrels per day to 10,500,000 barrels per day, becuase an 8,000 barrel per day decrease in Alaska’s oil production to 448,000 barrels per day caused the subtraction of 100,000 barrels per day from the rounded national total (by the EIA’s math)….our prepandemic record high US crude oil production was at a rounded 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 16.0% below that of our production peak, yet still 30.5% above the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 87.0% of their capacity while using those 15,238,000 barrels of crude per day during the week ending May 21st, up from 86.3% the prior week, and the highest refinery utilization since March 20th of last year…while the 15,239,000 barrels per day of oil that were refined this week were 17.3% higher than the 12,991,000 barrels of crude that were being processed daily during the pandemic impacted week ending May 22nd of last year, they were still 9.1% below the 16,767,000 barrels of crude that were being processed daily during the week ending May 24th, 2019, when US refineries were operating at a still low 91.2% of capacity…
Even with this week’s increase in the amount of oil being refined, the gasoline output from our refineries decreased by 5,000 barrels per day to 9,748,000 barrels per day during the week ending May 21st, after our gasoline output had increased by 165,000 barrels per day over the prior week…while this week’s gasoline production was 35.9% higher than the 7,171,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 2.3% lower than the March 13th 2020 pre-pandemic high of 9,974,000 barrels per day, and 1.2% below the gasoline production of 9,863,000 barrels per day during the week ending May 10th, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 112,000 barrels per day to 4,665,000 barrels per day, after our distillates output had decreased by 102,000 barrels per day over the prior week…but since the pandemic pullback of last year didn’t appear to impact distillates’ production, this week’s distillates output was still 2.4% lower than the 4,780,000 barrels of distillates that were being produced daily during the week ending May 22nd, 2020…
With the decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the second time in eight weeks, and for the eighth time in twenty-eight weeks, falling by 1,745,000 barrels to 232,481,000 barrels during the week ending May 21st, after our gasoline inventories had decreased by 1,963,000 barrels over the prior week...our gasoline supplies decreased this week because the amount of gasoline supplied to US users increased by 255,000 barrels per day to a 14 month high of 9,479,000 barrels per day, even as our exports of gasoline fell by 100,000 barrels per day to 733,000 barrels per day while our imports of gasoline fell by 47,000 barrels per day to 1,034,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 8.8% lower than last May 22nd’s gasoline inventories of 255,000,000 barrels, and about 3% below the five year average of our gasoline supplies for this time of the year…
Even with the increase in our distillates production, our supplies of distillate fuels decreased for the 13th time in 23 weeks and for the 27th time in thirty-nine weeks, falling by 3,013,000 barrels to 129,082,000 barrels during the week ending May 21st, after our distillates supplies had decreased by 2,324,000 barrels during the prior week….our distillates supplies fell by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 403,000 barrels per day to 4,461,000 barrels per day, while our imports of distillates rose by 6,000 barrels per day to 273,000 barrels per day, and while our exports of distillates fell by 186,000 barrels per day to 908,000 barrels per day….after seven consecutive inventory decreases, our distillate supplies at the end of the week were 21.4% below the 164,327,000 barrels of distillates that we had in storage on May 22nd, 2020, and about 8% below the five year average of distillates stocks for this time of the year…
Finally, with the increase in both our refining and in our oil exports, our commercial supplies of crude oil in storage fell for the 17th time in the past twenty-eight weeks and for the 26th time in the past year, decreasing by 1,662,000 barrels, from 486,011,000 barrels on May 14th to 484,349,000 barrels on May 21st, after our crude supplies had increased by 1,320,000 barrels the prior week….after this week’s decrease, our commercial crude oil inventories were about 2% below the most recent five-year average of crude oil supplies for this time of year, but were still about 36% above the average of our crude oil stocks as of the the third week of May over the 5 years at the beginning of this decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring, our commercial crude oil supplies as of May 21st were 9.4% less than the 534,422,000 barrels of oil we had in commercial storage on May 22nd of 2020, but still 1.6% more than the 476,493,000 barrels of oil that we had in storage on May 24th of 2019, and also 11.5% more than the 434,512,000 barrels of oil we had in commercial storage on May 25th of 2018…
This Week’s Rig Count
The US rig count rose for the 33rd time over the past 37 weeks during the week ending May 28th, but it’s still down by 42.4% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US was up by 2 to 457 rigs this past week, which was also up by 156 rigs from the pandemic hit 301 rigs that were in use as of the May 29th report of 2020, but was still 1,472 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 3 to 359 oil rigs this week, after rising by 4 oil rigs the prior week, now giving us 137 more oil rigs than were running a year ago, but still just 22.3% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was down by 1 to 98 natural gas rigs, which was still up by 21 natural gas rigs from the 77 natural gas rigs that were drilling a year ago, but still just 6.1% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….
The Gulf of Mexico rig count was unchanged at 14 rigs this week, with all 14 of those rigs drilling for oil in Louisiana’s offshore waters….that was 2 more Gulf of Mexico rigs than the 12 rigs drilling in the Gulf a year ago, when again all 12 Gulf rigs were drilling for oil offshore from Louisiana….since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig counts…however, in addition to those rigs offshore, a rig continued to drill through an inland lake in St Mary parish Louisiana, while there were no such “inland waters” rigs running a year ago…
The count of active horizontal drilling rigs was up by 3 to 415 horizontal rigs this week, which was also up by 144 rigs from the 271 horizontal rigs that were in use in the US on May 29th of last year, but less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…. on the other hand, the directional rig count was down by 1 to 27 directional rigs this week, which was still up by 4 from the 23 directional rigs that were operating during the same week a year ago….meanwhile, the vertical rig count was unchanged at 15 vertical rigs this week, and those were also up by 8 from the7 vertical rigs that were in use on May 29th 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 May 28th, the second column shows the change in the number of working rigs between last week’s count (May 21st) and this week’s (May 28th) count, the third column shows last week’s May 21st 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 29th of May, 2020..
It appears we have a few more changes than our totals would indicate….checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that that four oil rigs were added in Texas Oil District 8, which is the core Permian Delaware, while a rig was pulled out from Texas Oil District 7C, which encompasses the southern counties of the Permian Midland, which gives us a net increase of three rigs in the Texas Permian…since the Permian basin only saw a two rig increase nationally, that means that the rig that was removed from New Mexico had to have been pulled out of the far west reaches of the Permian Delaware, to account for the national Permian basin change…elsewhere in Texas, we see that three rigs were removed from Texas Oil District 1, and that two rigs were added in Texas Oil District 2, that one rig was removed from Texas Oil District 3, and that three rigs were added in Texas Oil District 4, several combinations of which could have been targeting the Eagle Ford shale, which stretches in a narrow band across the southeast part of the state, to thus account for the one rig increase in that basin…meanwhile, it’s evident that the rig pulled out of Colorado had been drilling in the Denver-Julesburg Niobrara chalk, but since we don’t see evidence of an Oklahoma basin increase in the table above, we have to figure the two rig increase in that state was in basins that Baker Hughes doesn’t track…lastly, we have the two natural gas rigs removed from the Pennsylvania Marcellus, which apparenly were partly offset by a natural gas rig addition in a basin that Baker Hughes doesn’t track, which could have been one of those Oklahoma additions…
Road deicer or radioactive wastewater? Ohio groups face-off over selling AquaSalina to public – The Columbus Dispatch – Drive through Ohio in winter and chances are you’ll see an Ohio Department of Transportation truck spraying the roads with some kind of deicer. Most of the time, it’s a mixture of rock salt and water. But when temperatures dip below 20 degrees Fahrenheit, ODOadds other chemicals to keep the brine from freezing. One of those additives is AquaSalina. It’s made in Brecksville in northeast Ohio by Nature’s Own Source LLC, and owner Dave Mansbery has been singing its praises for years. It’s ancient seawater. It works up to -15 degrees Fahrenheit. It’s 70% less corrosive than traditional deicers and more effective per lane mile, Mansbery told an Ohio House Committee. He wants to take the next step: Selling AquaSalina to all Ohioans for their sidewalks, driveways and porches. But Mansbery can’t do that without removing some existing Ohio laws. That’s where Rep. Bob Young, R-Canton, comes in. He introducedHouse Bill 282, which would end a requirement that AquaSalina users pay a $50 registration fee to the Ohio Department of Natural Resources and report where every gallon gets spread. The Buckeye Environmental Network wants to stop that from happening.Why? Director Teresa Mills said she has three simple reasons: “It’s radioactive. It’s radioactive. It’s radioactive.” AquaSalina is made by refining the salty mixture of water and other chemicals that comes up the pipelines from conventional oil and gas wells. Mansbery claims the radiation emitted by AquaSalina is safe. Bananas emit radioactive particles called potassium-40, and Mansbery, who didn’t respond to a request for comment, says a jug of AquaSalina gives off less radiation.”In principle that is correct,” said Dr. John Stolz, a professor who runs the Center for Environmental Research and Education at Duquesne University in Pittsburgh. He studied AquaSalina in his lab and told the USA TODAY Network Ohio bureau there are critical differences between a banana and this particular deicer. Bananas are beta emitters, which is a kind of radiation that can be blocked by clothing. Radium emits both alpha and gamma radiation.”Gamma has no mass and can go right through your body,” Stolz said. Radium also gets “hotter” as it decays whereas bananas do not.
Oberlin, OH Still Fighting to Shut Down Long-Running NEXUS Pipe –Radical environmentalists continue to use the City of Oberlin, Ohio to try and advance their agenda of ending the use of natural gas pipelines. And Oberlin willingly lets them do it. We’re referring to the latest court filing by Oberlin (actually by Big Green lobbyists using Oberlin) contesting the Federal Energy Regulatory Commission (FERC) decision to approve the NEXUS pipeline, a pipeline from the Utica Shale into Michigan that’s been flowing for years connecting to a pipeline that exports some of the gas into Canada. Oberlin says FERC’s approval of NEXUS is faulty because some gas gets exported and is not “in the public interest.”The case sits before the lefties of the U.S. Court of Appeals for the District of Columbia (DC Circuit). When an interstate pipeline like NEXUS gets built, it has the right under federal law to use eminent domain to “condemn” property owned by landowners who refuse to negotiate and allow it to cross their land, like a tiny strip of land owned by Oberlin. It’s in the law, called “in the public interest.” But the Oberlin lawsuit argues if *some* of the gas flowing through the pipe gets exported, as is the case with *some* (not all) of the gas in NEXUS (flowing to Canada), such a situation is not “in the public interest” because U.S. citizens are not using/benefiting from 100% of the gas.Unfortunately, the judges of the D.C. Circuit left the door open for antis to try and manipulate our laws via the back door of the courts (see DC Circuit Court/Antis Continue to Hassle Long-Done NEXUS Pipe). The court asked FERC to respond to the cockamamie claims in the lawsuit. FERC responded to the court’s demand justifying its decision to approve NEXUS. FERC says in their response that under U.S. law (called the Natual Gas Act) if natural gas is exported by a pipeline to a country that is a free trade partner, as is Canada, such a project IS considered “in the public interest” (see FERC Says NEXUS Approval in Public Interest re Exports to Canada). It’s right there – in the law! (Maybe antis don’t read?)Even if you take all of the gas out of NEXUS that goes to Canada, FERC says enough gas stays right here and is used in the U.S. to justify the NEXUS project anyway, without the exports.Yet the radicals keep pushing:An Ohio city told the D.C. Circuit that gas intended for foreign markets should not be used by the Federal Energy Regulatory Commission as a reason to grant the developer of a $2.1 billion gas pipeline eminent domain authority for its construction under the Natural Gas Act.The D.C. Circuit told FERC in September 2019 that it needed to address questions raised by Oberlin, Ohio, about why shipments to Canada meant the since-completed Nexus pipeline was necessary and worth giving Nexus Gas Transmission LLC power to exercise eminent domain to build it. The commission explained itself in September 2020.*When are the taxpayers in Oberlin going to wise up and stop this nonsense from happening in their name?
Gateway Royalty Sounds Alarm on Ohio’s HB No. 152 — Gateway Royalty, which invests in oil and gas production by buying a portion of the mineral owner’s royalty interest, is sounding the alarm about an industry backed bill that would require unleased mineral owners to accept net proceeds royalties from the well operator. Ohio’s H.B. No. 152 seeks to amend R.C. section 1509.28, which provides for the mandatory pooling of unleased mineral owners in drilling units approved by the Chief of the Ohio Division of Oil and Gas Resources Management. Under the existing statute, an unleased mineral owner can choose to (1) participate in unit operations under lease terms negotiated with the unit operator, (2) participate under the terms of the unit order, or (3) elect to not participate and pay a nonconsenting penalty charge in an amount determined by Chief. H.B. No. 152, if enacted, “would fundamentally alter an unleased mineral owner’s options in ways that would greatly benefit the Unit Operator to the detriment of the mineral owner,” says Chris Oldham, Gateway Royalty’s president. The mineral owner’s first option (which is the default option if the mineral owner declines the other two) requires the mineral owner to accept a royalty of 1/8th of the net proceeds received by the operator. “Net proceeds” is defined in the bill as “proceeds on the sale of production less any and all taxes and fees levied on or as a result of production and less all post production costs incurred between the wellhead and the point of sale.” Based on some of the current operators’ cost deductions, a 12.5% royalty under a net lease is the equivalent of a 6.25% royalty interest or less. According to Oldham, an unleased mineral owner should be permitted to negotiate for a “gross proceeds/no deduct” royalty, as well as for a royalty percentage greater than 12.5%. Oldham says that many oil and gas leases are gross proceeds leases in which the royalty is a negotiated percentage of the gross sale price. Oldham says that this percentage was traditionally 12.5% (1/8th), but with the Utica shale boom the percentage is now “more often between 16 and 20 percent.” H.B. No. 152, Oldham says, “removes the ability of an unleased mineral owner to negotiate for a gross proceeds royalty and for a royalty percentage above 12.5%.”
Ohio HB 152 Forced Pooling Bill Disadvantages Unleased Landowners – Gateway Royalty is sounding the alarm over a new bill that’s quickly advancing in the Ohio legislature. Ohio’s House Bill (HB) 152 allows drillers to force-pool landowners if 65% of a drilling unit is signed to a lease – a pretty low bar if you ask us. But that’s not even the worst part. The reluctant landowner would receive a standard 12.5% royalty, no matter what the royalty is for the rest of the leases in the unit, AND post-production deductions would be taken out. Landowners could realistically see a 6.25% royalty…or less! It’s time to burn up the phone lines to either get this bill changed, or defeated.Gateway Royalty is a royalty owner itself – a company that buys future royalty payments for a one-lump payment now. Some landowners find the arrangement beneficial. Gateway is for all intents a “landowner” in this case. Think of them as a super landowner, with their ear to the ground for issues that affect royalties. Gateway outlines the problems with HB 152 in the press release below: H.B. No. 152, if enacted, “would fundamentally alter an unleased mineral owner’s options in ways that would greatly benefit the Unit Operator to the detriment of the mineral owner,” says Chris Oldham, Gateway Royalty’s president. The mineral owner’s first option (which is the default option if the mineral owner declines the other two) requires the mineral owner to accept a royalty of 1/8th of the net proceeds received by the operator. “Net proceeds” is defined in the bill as “proceeds on the sale of production less any and all taxes and fees levied on or as a result of production and less all post production costs incurred between the wellhead and the point of sale.” Based on some of the current operators’ cost deductions, a 12.5% royalty under a net lease is the equivalent of a 6.25% royalty interest or less. According to Oldham, an unleased mineral owner should be permitted to negotiate for a “gross proceeds/no deduct” royalty, as well as for a royalty percentage greater than 12.5%. Oldham says that many oil and gas leases are gross proceeds leases in which the royalty is a negotiated percentage of the gross sale price. Oldham says that this percentage was traditionally 12.5% (1/8th), but with the Utica shale boom the percentage is now “more often between 16 and 20 percent.” H.B. No. 152, Oldham says, “removes the ability of an unleased mineral owner to negotiate for a gross proceeds royalty and for a royalty percentage above 12.5%.”The mineral owner’s first option (which is the default option under the Bill) requires the operator to pay the unleased mineral owner a bonus of 75% of the current market rate for a bonus payment per acre. This provision is also unacceptable because it does not represent fair market value, according to Oldham. The second option to unleased mineral owners under the Bill is to participate in the unit operations as a consenting party under the terms of the joint operating agreement (“JOA”) attached to the unit operation application. Oldham says this is not a viable option because very few mineral owners, if any, can take the risk and liability of a working interest owner, let alone have the financial ability to join in the drilling, completion and production operations of these Utica horizontal wells, which cost a minimum of $6.0 million to $8.0 million per well. The third option is to participate in the unit operations as a nonconsenting party under the terms of the JOA along with a 300% non-participation charge payable from the nonconsenting owner’s share of production. Oldham says the third option is not viable either because there is a high probability that the mineral owners’ interest will never pay out. Oldham says since neither the second nor third option is viable, the unleased mineral owners “will be stuck with the first option.”
Pennsylvania gas production continues to climb – Pennsylvania gas companies produced a total of 1863 Bcf in Q1 2021, up 5.4% from the same period one year earlier. Not only has gas production climbed, but the rate of growth has accelerated from the previous four quarters, according to recent statistics from the state’s Department of Environmental Protection. Gas producers have consistently put out growing amounts of gas over the last four years, but that rate of growth has fluctuated over time. The growth rate of Pennsylvania’s gas production reached a peak of 18.6% in Q3 2018 and gradually fell from then through 2020. Last year, growth was around 3% for most of the year, but began to climb again at the start of 2021. The state reported the industry spud 133 new horizontal wells in the first quarter of 2021, a decline of 20 wells, or 13.1% from the same period one year earlier. Despite the year-on-year decline in new wells, the trend was up 34 wells from the previous quarter and the first quarterly increase since the first quarter of 2020. New wells slowed dramatically last year because of the decline in prices and weak demand for gas. At the end of March, the state reported a total of 10,438 producing wells. Horizontal wells account for 99% of the production in the state. That total was up 4.9% from the previous year, the smallest year-over-year growth rate on record. The growth rate in producing wells has slowed as producers drill fewer wells and shut in or plug existing wells, the state reported. Without a significant uptick in new wells, new gas production will likely slow or even stagnate, the state reported. Gas wells in Susquehanna, Washington, Green, Bradford counties account for nearly 69% of the state’s production, with Bradford county showing the largest growth in production. Pennsylvania’s total annual production was 7290 Bcf in 2020, second only to Texas, which produced 10,291 Bcf in 2020. The average price for Pennsylvania gas was $2.53/MMBtu in Q1, 2021, a significant discount to the price of gas at Henry Hub, which was $3.44/MMBtu. That average price was the strongest in more than five quarters, and the growth rate was steeper than the growth rate of prices at Henry Hub, the state reported.
Call For Fracking Transparency – Pennsylvania Attorney General Josh Shapiro and other Democratic members of the Senate held a virtual press conference Tuesday to discuss legislation to increase transparency and oversight of management of gas drilling in the fracking industry. Eight recommendations were made based on the report of a two-year investigation that included testimony from homeowners that live within proximity of drilling sites and current and former state employees, according to a news release from PA Senate Democrats. Findings of the report include: numerous families, close to wells or other industrial sites, described unexplained rashes, sudden nosebleeds, and respiratory issues.Senate Democrats aim to usher in reforms through bills that were specifically recommended by the Grand Jury report. The eight reforms detailed in the release include:
- Expanding no-drill zones in Pennsylvania from the required 500 feet to 2,500 feet;
- Requiring fracking companies to publicly disclose all chemicals used in drilling and hydraulic fracturing before they are used on-site;
- Requiring the regulation of gathering lines, used to transport unconventional gas hundreds of miles;
- Adding up all sources of air pollution in a given area to accurately assess air quality;
- Requiring safer transport of the contaminated waste created from fracking sites;
- Conducting a comprehensive health response to the effects of living near unconventional drilling sites;
- Limiting the ability of Pennsylvania Department of Environmental Protection employees to be employed in the private sector immediately after leaving the Department;
- Allowing the Pennsylvania Office of Attorney General original criminal jurisdiction over unconventional oil and gas companies.
“Under this package of bills, citizens and others could report potential environmental crimes directly to the Attorney General’s office for investigation without having to go through other agencies first,” said Sen. Santarsiero. “This would speed up the process for investigations and convictions for environmental crimes and make it clear to potential polluters that damaging our land and water will be met with real consequences.”
Ethane analysis points to severe underestimation of methane emissions in oil and gas production — A new analysis of emissions from ethane, which are tied to methane emissions and largely attributable to oil and gas companies, shows that the U.S. Environmental Protection Agency is underestimating methane generated by the industry by 46% to 76%. Researchers have long suggested that the EPA underestimates the level of methane emissions in the U.S., but pinpointing the sources of these emissions is difficult, given that methane comes from a variety of sources, including agriculture and wetlands. The new study, published May 5 in the Journal of Geophysical Research: Atmospheres, details a method of analyzing ethane emissions that links a previously underestimated share of methane emissions to the oil and gas industry, providing new information that could inform future climate change efforts. “As far as I’m aware, this is the only paper that’s figured out that oil and gas methane emissions [estimates] are too low without actually measuring methane emissions,” said lead author Zachary Barkley, an atmospheric scientist at Pennsylvania State University. “There is clearly an ethane/methane source here – oil and gas wells – which are being underestimated, and it needs to be accounted for.”Methane is an important greenhouse gas that traps heat 28 times more effectively than carbon dioxide over a 100-year span. According to the study, methane emissions stabilized in the early 2000s but have been increasing since 2007. Oil and gas infrastructure is prone to methane leaks through valves and other equipment during production and extraction. Gas flares, a common industry practice, are also common sources of methane emissions. The EPA keeps an inventory of these emissions, but the agency’s calculations tend to be based on old measurements, according to Barkley.”We know CO2 a lot better than we know methane, and so that’s raised a lot of alarm in part because a lot of the climate projections did not account for this methane increase,” Barkley said in an interview with The Academic Times. “We’re doing so much to try and offset CO2, and now we can barely offset the changes we’re seeing to the methane, so there’s this big rush to try and figure out what’s causing it, and one of the big sectors that’s been looked at is oil and gas.”The EPA classifies methane and ethane as “negligibly reactive” volatile organic compounds, or VOCs, which are any organic compounds that react with light in the atmosphere. As a result, the agency exempts methane and ethane from emissions limitations. In April, environmental groups including the Center for Biological Diversity petitioned the EPA to remove methane and ethane from its “negligibly reactive” list. “What happens when you do these studies with methane is you end up reporting your results, and then the oil and gas company will come after you and say, ‘Well, how do you know it wasn’t a cow? How do you know it wasn’t a landfill?'” Barkley said. “When you only use ethane, no methane, and you come up with the same result as all these other papers that show that the EPA inventory is off, it just completely kills that argument, because there’s nothing else it can be coming from.”
Sen. Bob Menendez introduces bill to ban offshore drilling in Atlantic Ocean | Video – U.S. Sen. Bob Menendez announced he would introduce the COAST Act (or Clean Ocean and Safe Tourism Anti-Drilling Act) to keep oil rigs away from the Atlantic Ocean, including the Jersey Shore. The bill would prevent the U.S. Department of the Interior from issuing leases for exploration, development or production of oil or gas in the Atlantic Ocean and the Straits of Florida. In January, President Biden paused drilling in those areas as part of his administration’s effort to combat climate change, blocking a move by the former Trump administration to open most of the coast to drilling.
Bill inspired by South Portland fuel tank emissions earns committee’s endorsement – Petroleum tank farms in Maine would have to continuously monitor emissions and take other steps to reduce off-gassing from aboveground tanks under a bill that received a committee endorsement on Monday. The bill is a response to concerns in South Portland about noxious odors and air pollution emanating from massive tanks located along the city’s waterfront in close proximity to schools, residential neighborhoods and businesses. Although those concerns date back decades, momentum has built since 2019 to tighten monitoring and reporting of emissions from petroleum tanks amid a high-profile dispute between state and federal regulators over emissions levels. The proposal, which faces additional votes in the full Legislature, would direct Maine’s Board of Environmental Protection to develop rules requiring the installation of “fenceline” monitoring stations around facilities with aboveground tanks. The low-cost monitors would then track levels of potentially hazardous emissions drifting into local neighborhoods. The bill also would require use of “floating roofs” – which reduce the accumulation of gases by sitting on the surface of the petroleum – in tanks larger than 39,000 gallons, and insulation in heated, fixed-roof storage tanks to reduce temperature changes that can create additional gases. The bill also would direct the BEP to mandate the collection of emissions created when loading fuels into empty tanker trucks, and the installation of technology capable of monitoring at least monthly for leaks from storage tanks, piping and fittings.
Oil Refineries’ Benzene Pollution a Concern in Eastern KY — A Marathon oil refinery in eastern Kentucky is emitting benzene into the air at levels higher than what the federal Environmental Protection Agency says require action to curb. Benzene is a well-known carcinogen that can cause leukemia. According to a report from the Environmental Integrity Project, benzene readings at the Boyd County refinery jumped 233% between 2019 and 2020. Ilan Levin, associate director at the group, said last year’s levels were 11% above the EPA action level. “These are not necessarily Clean Air Act violations,” said Levin. “But the data indicates clearly that we’ve got a problem at many of these U.S. refineries.” Levin added in 2015, the EPA required all refineries in the U.S. to install benzene pollution monitors. Nationwide, more than 530,000 people live within three miles of a refinery. The EPA estimates 57% are people of color and 43% live at incomes below the poverty line. Levin said he believes lax regulation and oversight of oil refineries threaten public health, and said the EPA should respond more rapidly to short-term spikes in benzene emissions. “Actions often include investigations, requests for information from these refineries,” said Levin. “That’s what EPA needs to do for a handful of these refineries, especially those that are getting worse.” Levin explained benzene often wafts into communities at levels higher than what’s being reported, because refineries can point to other nearby sources and claim the emissions aren’t theirs. He said the data adds to a growing body of evidence about who’s most likely to suffer the consequences of air pollution. “That points to the fact that people of color, and lower-income folks, are disproportionately hit by industrial pollution,” said Levin. He notes the same communities were hit especially hard by COVID-19, where residents lack affordable health care and have higher rates of chronic illness that make them especially vulnerable to air pollution.
More US E&Ps, Utilities and Midstreamers Join Coalition to Reduce Natural Gas Emissions – Since early March, nine oil and natural gas producers, utilities and pipeline and storage operators have joined a coalition that pledges to reduce collective methane emissions to 1% or lower. Our Nation’s Energy Future (ONE Future), with members in the upstream, midstream and downstream sectors, now numbers 45. As members, each company would report methane emissions and hold a seat on the ONE Future board. Privately owned exploration and production (E&P) companies BKV Corp., THQ Appalachia I LLC (THQA) and Jonah Energy LLC, joined in April. Denver-based BKV holds assets in the Marcellus Shale in Pennsylvania, as well as the Barnett Shale in North Texas. According to ONE Future executive director Richard Hyde, BKV “has grown rapidly to become a Top-20 natural gas producer in the United States.” Supported by Tug Hill Operating LLC, THQA also targets the Marcellus, as well as Utica Shale and the Upper Devonian formation in northern West Virginia. “Through the utilization of technology, we strive to improve the efficiency of our operations, minimize our environmental impact, and create lasting partnerships within the communities where we live and work,” said THQA COO Sean Willis. Jonah Energy, based in Sublette County, Wyoming, holds assets within the Jonah Field. The independent produces 550 MMcf/d. Two new utility members, Black Hills Corp. and DTE Energy, plan to report methane intensity associated with distribution operations. Through subsidiaries, Black Hills provides natural gas to customers across Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming. Detroit-based subsidiary DTE Gas delivers gas to 1.3 million customers in Michigan. More midstream companies have also joined ONE Future’s efforts to reduce methane emissions while promoting natural gas. Each company pledged to report results from their gathering, processing, transmission, or storage sectors.Western Midstream Partners LP (WES) joined in March. WES owns properties across Texas, New Mexico, Colorado, Utah, and Wyoming. Blue Racer Midstream LLC, which joined in April, operates processing facilities in the Utica and Marcellus shales. Most recently, Targa Resources Corp. joined in early May. The midstream company operates natural gas pipelines in the Permian Basin and in Oklahoma.
State lawmakers consider bill to preempt local natural gas restrictions — Michigan lawmakers have joined nearly two dozen other states looking to stop local climate change efforts that involve electrifying various building and transportation components to reduce carbon emissions.House lawmakers today debated House Bill 4575 – sponsored by state Rep. Michele Hoitenga, R-Manton – in the House Committee on Regulatory Reform. The co-owner of an oil and gas drilling consulting business with her husband Philip, Hoitenga introduced the largely preemptive bill as an effort to stop local governments from adopting, maintaining or enforcing an ordinance that “prohibits the use of an appliance that uses gas in a new or existing residential building or structure.” The bill, introduced in late March, would amend the Stille-DeRossett-Hale Single State Construction Code Act of 1972. It’s cosponsored by seven other Republicans.Hointenga said during the committee, which she co-chairs, that the bill is meant to “protect consumers from unintended consequences.”“Gas plays a significant role in sustaining a clean energy future,” she said, referring to the broader transition away from coal. “We must be realistic … when undergoing such profound energy usage changes.”Representatives from the Michigan Chamber of Commerce, the Home Builders Association of Michigan, DTE Energy and the Utility Workers Union of America testified in support of the bill. Multiple oil and gas trade groups, Michigan Realtors, the Michigan Restaurant and Lodging Association and the Michigan Licensed Beverage Association also support H.B. 4575.Citing a potential “patchwork” of local ordinances, DTE Gas Director of Sales and Marketing H.J. Decker said the gas utility “supports policies and regulations that expand the use of natural gas.” DTE Gas’ parent company, DTE Energy, has also publicly announced a net zero carbon emissions target by 2050.According to a House Fiscal Agency analysis, more than 20 states have either adopted or introduced bills that would “prohibit local governments from making building code changes that would ban the use of gas appliances in new construction.” The legislation is opposed by the city of Ann Arbor, where officials have adopted the A2Zero Plan that includes strategies to electrify homes and businesses. The plan more broadly calls for the city to reach net zero emissions by 2030 through renewable energy generation and purchases, energy efficiency, weatherization measures and electrifying transportation.
Gas Pipelines: Harming Clean Water, People, and the Planet –Oil and gas pipelines crisscross the United States, and new ones are still being built. It would take volumes to document all the dangers they pose to people, nature, and the planet, but here’s a start: greenhouse gas emissions, violations of indigenous treaty rights and sovereignty, destruction of endangered species habitat, taking of private property without public benefit, contamination of drinking water sources and streams and rivers, ruination of farms and landscapes, deaths and injuries from explosions, damage to wild ecosystems, and environmental injustice.The International Energy Agency has called for an immediate end to new investments in fossil fuel pipelines. With all the cleaner alternatives available, the only benefit of new pipelines is to increase the corporate profits of pipeline owners. Yet while the potential for harm is well known, government agencies keep rubber-stamping permits.FERC has approved dozens of new interstate gas pipelines over the past five years. Here are examples of the worst offenses associated with some of them (stay tuned for more on oil):
- Mariner East 2 pipeline travels 350 miles from Ohio and West Virginia through Pennsylvania. A gas liquids pipeline developed by Energy Transfer Partners (ETP), its construction led to contamination of drinking water sources for dozens of families and farms along the pipeline route. It’s also responsible for 320 spills between 2017 and 2020, reportedly releasing into the environment up to 405,990 gallons of drilling fluid, with more than 260,000 gallons spilled illegally into Pennsylvania waterways. One spill last August released more than 8,000 gallons of drilling fluids into a wetland and stream system that drains into Marsh Creek Lake, a drinking water reservoir near Philadelphia. Building the pipeline has also caused dozens of sinkholes, reportedly endangering some homes and damaging others.
- Also an ETP project, Rover is a 713-mile gas pipeline that travels from West Virginia, through Pennsylvania and Ohio, to Michigan. It’s reported that the company “racked up more than 800 state and federal permit violations while racing to build two of the nation’s largest natural gas pipelines.” One spill alone was more than 2 million gallons. The Federal Energy Regulatory Commission (FERC) denied Rover a so-called “blanket certificate” – the authority to conduct routine construction activities without first seeking permission from FERC – precisely because it concluded Rover “could not be relied upon to comply with the environmental regulations required for all blanket certificate projects.” The full life cycle greenhouse gas emissions generated by the project are estimated to be 145 million metric tons. And FERC recently proposed a $20 million fine for Rover because it allegedly destroyed a historic Ohio property without notifying authorities or obtaining permission.
- Another one of ETP’s greatest hits, the Revolution Pipeline in Pennsylvania is only 40 miles long but in that short distance has caused significant damage. A 2018 explosion on this pipeline destroyed a home and resulted in a civil penalty of $30.6 million. Fortunately, no people were hurt. The Pennsylvania Department of Environmental Protection also determined that Revolution pipeline destroyed at least 23 streams and 17 wetlands and damaged another 120 streams 70 wetlands. There arehundreds of additional allegations related to this project.
- Still under construction, Mountain Valley Pipeline would stretch from West Virginia across the Appalachian Mountains to Virginia. It’s a joint venture of EQM Midstream Partners, NextEra Energy, Con Edison Transmission, AltaGas Ltd., and RGC Midstream. With hundreds of planned water crossings, MVP has already agreed to pay more than $2 million in penalties for more than 350 water quality violations cited by Virginia and West Virginia, and it’s not even close to being completed. No other large pipeline has ever been approved across this many miles of steep slopes and high landslide risk areas – more than 200 miles of “high landslide susceptibility.” Steeper slopes typically mean greater threats to clean rivers and streams as well as increased risks of explosions. The full life cycle greenhouse gas emissions that the project would generate if fully utilized are estimated at almost 90 million metric tons a year – the equivalent of 23 average U.S. coal plants or over 19 million passenger vehicles. MVP faces numerous lawsuits alleging violations of our bedrock environmental laws, including the Endangered Species Act, the Clean Water Act, and the National Environmental Policy Act.
Comment period for key Mountain Valley Pipeline water permits is here – The long-delayed Mountain Valley Pipeline needs water crossing permit approval if it is to ever be completed.The time is now to weigh in on whether the project should get it.Public comments are due Friday to the U.S. Army Corps of Engineers on Mountain Valley Pipeline LLC’s proposal to discharge dredged and/or fill material into wetlands and other waters, while West Virginia environmental regulators are taking comments ahead of a virtual public hearing set for June 22 on whether they should approve a water permit for the project.Mountain Valley Pipeline LLC, the joint venture that owns the pipeline, still has applications pending with West Virginia and Virginia state environmental regulators for about 300 water crossings while it seeks approval from the Federal Energy Regulatory Commission to tunnel under 120 additional waterbodies.The West Virginia Department of Environmental Protection last month asked for an additional 90 days beyond the 120 days the U.S. Army Corps of Engineers gave the agency to review Mountain Valley Pipeline LLC’s water permit request. The Virginia Department of Environmental Quality in March requested an additional year to review the pipeline permit application.Both departments said Monday that they haven’t heard back from the Corps. The Corps could not be reached for comment.The Mountain Valley Pipeline is designed to be a 303-mile natural gas pipeline system traveling from Northwestern West Virginia to Southern Virginia crossing Wetzel, Harrison, Doddridge, Lewis, Braxton, Webster, Nicholas, Greenbrier, Fayette, Summers and Monroe counties in the Mountain State. It is projected to provide up to 2 billion cubic feet per day of natural gas from the Marcellus and Utica shale formations to markets in the mid-Atlantic and Southeastern regions of the U.S. Pipeline developers have proposed a 125-foot-wide temporary right-of-way to construct the pipeline and a 50-feet-wide permanent right-of-way to maintain and operate the pipeline once in service. Mountain Valley anticipates that the project will have temporary impacts to more than 21,000 linear feet of streams and 10 acres of wetlands in West Virginia during the construction phase.
Hurst: Mountain Valley Pipeline is not the future Virginia needs | Columnists –There is no need for the MVP and it should be cancelled. Over the past two years, MVP’s construction has polluted creeks and streams in Virginia and West Virginia, dried wells and ponds, and ruined farms. The company proved it could not prevent massive amounts of sediment from choking our streams, with state officials eventually ordering a fine of over $2 million for over 300 violations of the project permit. This destructive process – conducted on private land, seized for corporate greed – has resulted in the loss of livelihoods for many in the communities I represent. That is why I introduced HB 646 in 2020 which increased penalties for violations. The bill passed and was signed by the governor. The pipeline is now projected to cost $6.2 billion, twice as much as originally estimated, and it is 3-½ years behind its original schedule. If completed, the pipeline could generate greenhouse gas emissions equivalent to 26 coal plants – the last thing we need during this critical time. Unfortunately, Mountain Valley Pipeline and its proposed North Carolina extension, “Southgate,” are not intended to serve the communities they disrupt. Instead, they would link to a national pipeline network that some argue is already overbuilt, at a time when demand for natural gas is in decline. While construction inches forward, the environmental and legal risks continue to mount. As MVP tries to link an incomplete mainline project with the Southgate extension, courts have overturned various permits allowing the pipeline to cross waters, national forests, and the habitats of protected species. The North Carolina Department of Environmental Quality recently rejected, for the second time, a request for a water permit required for construction in the state. MVP also needs new water permits from Virginia, West Virginia, and a federal agency in the wake of litigation. Given all of the observed harms and uncertain future, this project must be cancelled.
U.S. natgas futures fall to near 4-week low on milder weather (Reuters) – U.S. natural gas futures slid to a near four-week low on Monday as production increased and on forecasts for milder weather and less demand over the next two weeks than previously expected. Traders noted cooler weather would cut the amount of gas power generators burn to keep air conditioners humming. Front-month gas futures NGc1 fell 2.0 cents, or 0.7%, to settle at $2.886 per million British thermal units, their lowest close since April 27. That also put the front-month down for a fifth day in a row for the first time since early March. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 90.9 billion cubic feet per day (bcfd) so far in May, up from 90.6 bcfd in April. That is still well below November 2019’s monthly record of 95.4 bcfd. With the milder weather on the horizon, Refinitiv projected average gas demand, including exports, would ease from 85.0 bcfd this week to 84.6 bcfd next week. The forecast for next week was lower than Refinitiv forecasts on Friday. The amount of gas flowing to U.S. LNG export plants averaged 10.9 bcfd so far in May, down from April’s monthly record of 11.5 bcfd. The decline was due to short-term issues and normal spring maintenance at a few Gulf Coast plants and the gas pipelines that supply them. U.S. pipeline exports to Mexico, meanwhile, averaged 6.0 bcfd so far in May, just off April’s monthly record of 6.1 bcfd, Refinitiv data showed.
U.S. natgas edges up as rising global prices seen boosting exports – (Reuters) – U.S. natural gas futures edged up on Tuesday on expectations a rise in global prices will boost U.S. exports back to record highs in the coming weeks. That U.S. price gain came despite forecasts for milder weather, lower demand and a steady increase in output. On their second to last day as the front-month, gas futures NGc1 for June delivery rose 2.7 cents, or 0.9%, to settle at $2.913 per million British thermal units. On Monday, the contract closed at its lowest since April 27 after declining for five days in a row. The July NGN21 contract, which will soon be the front-month, gained about 2 cents to $2.98 per mmBtu. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 90.9 billion cubic feet per day (bcfd) so far in May, up from 90.6 bcfd in April. That is still well below November 2019’s monthly record of 95.4 bcfd. The amount of gas flowing to U.S. LNG export plants averaged 10.9 bcfd so far in May, down from April’s monthly record of 11.5 bcfd. The decline was due to short-term issues and normal spring maintenance at a few Gulf Coast plants and the gas pipelines that supply them. But with European TRNLTTFMc1 gas prices near their highest since September 2018 and Asian JKMc1 prices over $10 per mmBtu, analysts said they expect buyers around the world to keep purchasing near-record amounts of U.S. gas.
June Natural Gas Futures Contract Rolls Off Board Following Robust Gain — Natural gas futures on Wednesday built on the gains of a day earlier as a favorable shift in the weather-demand outlook offset expectations for a triple-digit storage injection with the federal government’s pending inventory report Thursday. eia storage may 21 The June Nymex contract gained 7.1 cents day/day and rolled off the board after settling at $2.984/MMBtu on Wednesday. It had gained 2.7 cents on Tuesday. The June contract hovered near the $3.00 level over much of its span at the front of the curve, but it fell short of breaking through and staying above that threshold. July, which takes over as the prompt month Thursday, gained 5.3 cents to $3.027. NGI’s Spot Gas National Avg. rose a half-cent to $2.700. In terms of demand for natural gas to cool homes and businesses, forecasts on Wednesday improved from earlier in the week, with more intense heat likely next week in the Midwest and East, Bespoke Weather Services said. Both are key regions for natural gas consumption. “The forecast has stepped warmer overall,” Bespoke said Wednesday. While cooler air is still expected in the nation’s midsection and in the Northeast over the looming Memorial Day weekend, any chills “look quite brief before upper level ridging sets up shop once again in the eastern U.S. This keeps total demand over the next 15 days as a whole above normal, even with the cooler period in play.
Larger-than-expected US gas storage build prompts Henry Hub price drop – US natural gas storage fields injected 115 Bcf for the week ended May 21 — much more than expected — prompting Henry Hub futures to decline across the board May 27. Storage inventories increased to 2.215 Tcf over the latest reporting week, US Energy Information Administration data showed. The build proved greater than the 107 Bcf addition expected by an S&P Global Platts’ survey of analysts. It was outside the range of expectations as responses to the survey ranged from a 94 to 112 Bcf injection. It was also above the five-year average of 91 Bcf, according to EIA data. It marked the first time in a month the injection was more than the average. Strong export demand and tepid production levels had resulted in an underwhelming injection season thus far. US supply and demand fundamentals showed significant slackening during the reference week, as the last gasp of heating demand the week earlier finally dissipated, sending demand from the residential-commercial and industrial sectors nearly 6.5 Bcf/d lower, according to S&P Global Platts Analytics. A bump in power burn demand, which rose by 1.7 Bcf/d on the week, was diminished by a 600 MMcf/d drop in LNG feedgas deliveries, leaving total demand 5.2 Bcf/d lower week on week for an average 81.8 Bcf/d. Upstream, supplies were essentially flat. The injection might be the sole triple-digit increase for the entire 2021 injection season, as forecasts for the week in progress and the week ahead point to a tighter market as hotter weather is expected to boost power burn demand, leaving less gas available to inject into storage. Storage volumes now stand 381 Bcf, or 15%, less than the year-ago level of 2.596 Tcf and 63 Bcf, or 3%, less than the five-year average of 2.278 Tcf. On May 27, in its first day holding the prompt-month position, the July NYMEX Henry Hub contract dropped 7 cents/MMBtu, with the balance of summer through October following it lower. The winter contract strip from November-March was less prone, but not by much, as prices tumbled more than 6 cents/MMBtu. This pushed the balance of summer below the $3/MMBtu support level, now trading closer to $2.95/MMBtu, while the winter strip remains firmly above at $3.13/MMBtu, though selling pressure appears to be rising. Platts Analytics’ supply and demand model currently forecasts an 80 Bcf injection for the week ending May 28. This would once again grow the deficit to the five-year average as power burn demand begins to heat up. Total demand is up 1.7 Bcf/d week over week as a decline in residential-commercial and industrial demand pared down the effects of a roughly 3.4 Bcf/d increase in power burn demand.
July Natural Gas Futures, Cash Prices Sink After Bearish Inventory Report – Dragged lower after a bearish government inventory report, natural gas futures plunged on Thursday after rallying more than 7.0 cents into the expiration of the June contract a day earlier. The July Nymex contract, in its debut as the front month, dropped 6.9 cents day/day and settled at $2.958/MMBtu. It had closed above $3.00 on Wednesday. August also lost substantial ground, falling 6.7 cents on Thursday to $2.978. NGI’s Spot Gas National Avg. shed 6.0 cents to $2.640 as temperatures cooled in the Upper Midwest and forecasts called for light demand this coming weekend. Trading on Thursday was for gas delivered Friday through Monday, May 31. Natural gas trading on Friday will be for June gas delivery on Tuesday June 1. Futures traders pulled back after a disappointing U.S. Energy Information Administration (EIA) storage result that eclipsed the high end of analysts’ projections and signaled weaker demand than most had in their models. EIA reported an injection of 115 Bcf natural gas into stockpiles for the week ended May 21. Temperatures during the storage report week were cooler than normal over the southern United States and along the Mid-Atlantic Coast but warmer than normal – and generally comfortable – over the Mountain West and northern portions of the country. The weather minimized demand in key regions, according to NatGasWeather. Still, cooling demand had emerged in the West, and analysts anticipated a lighter build than what EIA delivered. Prior to the report, a Bloomberg poll showed a median estimate of 106 Bcf while a Reuters survey landed at a median build of 106 Bcf. A Wall Street Journal survey found an average build expectation of 101 Bcf. NGI’s model called for a 107 Bcf injection. The estimates compare with a 105 Bcf increase in storage a year earlier and a five-year average injection of 91 Bcf. The build for the May 21 week lifted inventories to 2,215 Bcf. That compared with the year-earlier level of 2,596 Bcf and the five-year average of 2,278 Bcf. But the increase for last week nevertheless signaled some easing in demand. In addition to weather, liquefied natural gas (LNG) export levels last week retreated from recent highs above 11 Bcf. That downward trend, while thought to reflect maintenance interruptions, extended into this week and curbed the influence of a major catalyst for natural gas prices this spring. LNG feed gas volumes hovered just below 10 Bcf on Thursday, NGI data showed.
U.S. natgas futures rise to one-week high on surging global prices (Reuters) – U.S. natural gas futures rose on Friday to their highest in more than a week, buoyed by forecasts for warmer weather in two weeks and a projected increase in liquefied natural gas (LNG) exports. Higher temperatures in two weeks were expected to boost demand for fuel to power generators and keep air conditioners humming. Still, traders said demand next week was likely be similar to this week, kept in check by mild weather and the Memorial Day holiday on Monday. Front-month gas futures NGc1 rose 2.8 cents, or 0.9%, to settle at $2.986 per million British thermal units, their highest close since May 18. For the week, the contract was up about 3% after falling about 2% last week. For the month, the contract was up about 2% after gaining about 12% last month. Data provider Refinitiv said gas output in the Lower 48 U.S. states has averaged 91 billion cubic feet per day (bcfd) in May, up from 90.6 bcfd in April. That, however, was still well below November 2019’s monthly record of 95.4 bcfd. With warmer weather coming after the U.S. Memorial Day holiday week, Refinitiv projected average gas demand, including exports, would rise from 83.6 bcfd this week to 84.1 bcfd next week with a projected increase in LNG exports and 90.1 bcfd in two weeks as warmer weather boosts air conditioning use. The forecast for next week was slightly higher than Refinitiv predicted on Thursday. The amount of gas flowing to U.S. LNG export plants has averaged 10.8 bcfd so far in May, down from April’s monthly record of 11.5 bcfd. The decline was attributable to short-term issues and normal spring maintenance at a few Gulf Coast plants and the gas pipelines that supply them. But with European gas prices near their highest since September 2018 and Asian prices above $10 per mmBtu, analysts said they expect buyers around the world to keep purchasing all the LNG the United States can provide. U.S. pipeline exports to Mexico, meanwhile, have averaged 6.0 bcfd so far in May, just off April’s monthly record of 6.1 bcfd, Refinitiv data showed.
Council approves one-year extension for $542 million liquefied natural gas facility — The Jacksonville City Council approved Houston-based Eagle LNG Partners LLC’s request for another year to start construction on its estimated $542 million liquefied natural gas export facility in North Jacksonville. The Council voted 17-0 to extend Eagle LNG’s deadline to begin construction from May 31 this year to May 31, 2022. The deal is tied to a city incentive of $23 million. Council approved Ordinance 2021-0241, which authorizes the extension, as part of its May 25 consent agenda. An Eagle executive said April 22 that coronavirus-related border closures in some Caribbean and Central American countries over the past year and quarantine orders kept the company from completing customer contracts with the government-owned and private utility companies that would receive the LNG shipping from Jacksonville. “We did lose a year. There’s no question,” said Linda Berndt, Eagle LNG vice president of government and public relations. “We asked for the year extension because of how slow some of these islands will be in recovery but we want to go sooner than a year.” Eagle LNG will have until Dec. 31, 2025, to complete the facility on 200 acres at 1632 Zoo Parkway along the St. Johns River with 12 new full-time jobs in place. Council voted in December 2019 to award Eagle LNG a Recapture Enhanced Value Grant up to $23 million, based on 50% of the incremental increase in ad valorem taxes, according to a legislative summary filed with the bill. Eagle’s investment outside the U.S. could be nearly double what it plans in Jacksonville. Company President Sean Lalani said in November 2019 that Eagle is prepared to spend up to $1 billion for receiving infrastructure in unidentified Central American and Caribbean Island nations. Eagle’s North Jacksonville facility will use lower volume LNG carrier ships to target small, relatively underserved markets that need less supply to operate than utilities in Asian, North American and European counties, according to company executives.
Exports, global demand lift top US producers’ NGL prices, revenues in Q1 – Robust international demand for liquefied petroleum gas drove a sharp spike in realized prices during the first quarter, boosting the NGL revenues of some U.S. shale producers more than 100% above the prior-year period.The 10 largest shale producers covered by S&P Global Market Intelligence recorded year-over-year gains in realized NGL prices of 77% to as much as 180% during the quarter. Both oil and NGL prices improved from the same period a year earlier and even from fourth-quarter 2020 levels. The average Brent crude oil futures prompt month contract gained 22% from the year-ago period, while the average Mont Belvieu NGL spot price grew more than 130%.Executives at Appalachian NGL producer Southwestern Energy Co., which posted the highest year-over-year increases in both NGL prices and revenues, said they expect NGL and oil prices to remain strong.“The 2021 [West Texas Intermediate] strip price has improved over $8 per barrel since we set our guidance in February, with transportation demand improving and OPEC+ compliance shaping supply increases to better match demand recovery,” Southwestern Energy President and CEO William Way said during the company’s quarterly earnings call. “The NGL landscape also remains promising, with low propane storage levels and increased global demand for both ethane and propane.” Antero Resources Corp., the country’s third-largest natural gas producer and Appalachia’s biggest NGL producer, also discussed the “welcomed, but not at all surprising” improved NGL prices on its earnings call. Antero said a major driver of first-quarter free cash flow was increasing commodity prices – particularly C3+ NGL prices, which averaged more than $40/b during the quarter. Analysts from Northland Capital Markets said in a May 12 note that they anticipate Antero’s net realizations will generate $300 million to $400 million of free cash flow through year-end, as Asian and European LPG prices stay high. “Summer exports, fall harvest season and winter weather are all on deck to sustain propane prices above the forward curve,” the analysts said.The second-largest NGL producer in Appalachia, Range Resources Corp., attributed the quarter’s improved NGL and condensate prices to “strong demand in a market that saw decreased supply.” Range posted a pre-hedge NGL price realization of $26.35/b, its highest since late 2018, and an NGL premium of $1.52/b to Mont Belvieu.“Preliminary results for U.S. propane and butane, or LPG, revealed that Q1 2021 domestic demand was 13% higher year on year, while supply decreased by 4%,” Range Senior Vice President and COO Dennis Degner said during an earnings call. “Looking forward, we see propane and butane market prices, as storage balances of these NGLs are much tighter relative to last year.”
Massive LNG export projects along the Louisiana coast could capture 1 million tons of carbon – A company proposing four liquefied natural gas export terminals in south Louisiana plans to capture climate-changing greenhouse gases from at least two of its projects for storage deep underground to prevent carbon from entering the atmosphere. Arlington, Virginia-based Venture Global LNG expects to use advanced technology to capture carbon from the liquefaction process, compress the CO2, then inject it into saline aquifers for permanent storage. The company did not say what percentage of total carbon produced would be captured for storage, and not enough is known from permit documents about its plant emissions to determine how significant the reduction is. The company said it could extend the carbon capture effort beyond the two projects to all four of its proposed terminals in Louisiana. One already is under construction in coastal Cameron Parish, where another project is proposed. Two others are proposed south of New Orleans. “Our location in Louisiana uniquely positions us to pioneer the deployment of this technology due to geology that can support industrial-scale injection and storage of CO2,” Mike Sabel, chief executive officer of Venture Global, said in a news release. “Through this historic carbon capture and sequestration project, we will build upon our existing state-of-the-art technology to develop even cleaner LNG at our facilities to displace coal around the world.” Demand for a cleaner version of LNG is high among countries that have plans to reach net-zero carbon emissions by 2050. Carbon is a greenhouse gas that contributes to climate change by entering the atmosphere and causing the Earth’s protective ozone layer to deteriorate. The company said the 1 million tons of carbon captured each year would equal the emissions of 200,000 cars no longer driving on the road for 20 years. Venture Global LNG said it already has completed “comprehensive engineering and geotechnical analysis” for the carbon sequestration plan for two projects – its Calcasieu Pass site south of Lake Charles and Plaquemines LNG south of New Orleans – and is awaiting regulatory approvals. Between the two export terminals, the company expects to sequester 500,000 tons of carbon each year.
Crews continue to work on cleaning up oil spill along Norfolk creek – The U.S. Coast says it is continuing to respond to an oil spill in Norfolk. Officials say a waste oil tank that was on shore overflowed into Steamboat Creek on Tuesday afternoon. We don’t know how much oil got into the water, but the Coast Guard says the source is secured. About 300 feet of shoreline is said to be affected. The Coast Guard said the “responsible party has been identified and is fully cooperating and participating in all response efforts.” As of Thursday, the Coast Guard said oil spill response teams have collected about 200 gallons of waste oil and water mix, along with 185 bags of oiled debris since cleanup efforts began. The Virginia Department of Health says cleanup is expected to take several weeks and urges people to avoid the area. People should not enter Steamboat Creek to fish or swim. The VDH said nearby residents may smell oil as cleanup continues. A Coast Guard Sector Virginia pollution investigation team, Virginia Department of Environmental Quality, Virginia Department of Emergency Management, and the Norfolk Fire Marshal’s Office are working with local agencies to coordinate cleanup operations and assess any environmental impacts.
Cleanup of oil spill continues off Elizabeth river – A huge operation is underway in Norfolk to stop the damage from an oil spill in Steamboat Creek. The U.S. Coast Guard, several Virginia state agencies, and the city of Norfolk are working to clean up the oil and assess the damage. Discovered Tuesday afternoon, the spill reportedly came from a “waste oil tank overflow incident” on shore. About 300 feet of shoreline was impacted, but the Coast Guard still don’t know just how much oil was discharged into the water. The agency says the source is now secured. Coast Guard Sector Virginia, Virginia Department of Environmental Quality, Virginia Department of Emergency Management, and City of Norfolk Fire-Rescue teams are working with other agencies to get the spill under control. Oil spill response teams deployed one mile of boom and have collected at least 200 gallons of waste oil mixed with water. They’ve cleaned up 130 bags of oiled debris in the first 24 hours since they first responded to the spill. “Our focus is the unity of effort amongst our partner agencies in this ongoing clean up,” says Lt. Savannah Kuntz, the Coast Guard Federal On Scene Coordinator Representative. “Our goal is to minimize impacts to environmentally sensitive areas and species present, and we are so thankful to have state and local partners that are pivotal in our efforts.”
Colonial Pipeline says temporary network disruption resolved (Reuters) -Colonial Pipeline, the largest fuel pipeline in the United States, on Friday said it had resolved a temporary network disruption, just weeks after a ransomware attack crippled fuel delivery for several days in the southeast region. Colonial earlier on Friday experienced a network issue, the company said, but restored service to its network. The issue was not associated with malware, the company said. The company had earlier said shippers were having problems entering and updating nominations for deliveries. The “system functionality has returned to normal,” the company said. The reason for the network issues was not immediately clear. Colonial’s shipping nomination system is operated by a third party, privately-held Transport4, or T4, which handles similar logistics for other pipeline companies. T4 on Friday said its application was working for all customers and carriers. It did not comment on Colonial’s current network issue and said that data between T4 and Colonial was transacting normally. Friday’s network problems are the second occurrence of such issues since the attack earlier in the month. Colonial is the largest fuel system in the United States, accounting for millions of barrels of daily deliveries to the U.S. East Coast and Southeast. Shortly after Colonial restored operations from the hack, it suffered a brief network outage that prevented customers from planning upcoming shipments on the line. At the time, Colonial said the disruption was caused by efforts by the company to harden its system, and was not the result of a reinfection of its network. The southeast United States is still recovering from the six-day line outage from earlier this month and the supply issues it caused in the region. Around 6,000 gas stations were still without fuel this week, according to tracking firm GasBuddy, down from a peak of more than 16,000. Almost 40% of gas stations in the capital, Washington, were without supplies on Thursday, GasBuddy said. More than 20% of stations in North Carolina, Georgia and South Carolina were also empty. The hack also boosted gasoline prices earlier than expected this year. Heading into Memorial Day weekend, the traditional start of the summer driving season, U.S. motorists are seeing the highest gasoline prices in seven years.
Colonial ransomware hack spurs first-ever cybersecurity regulations for pipeline industry – The Department of Homeland Security is moving to regulate cybersecurity in the pipeline industry for the first time in an effort to prevent a repeat of a major computer attack that crippled nearly half the East Coast’s fuel supply this month – an incident that highlighted the vulnerability of critical infrastructure to online attacks.The Transportation Security Administration, a DHS unit, will issue a security directive this week requiring pipeline companies to report cyber incidents to federal authorities, senior DHS officials said. It will follow up in coming weeks with a more robust set of mandatory rules for how pipeline companies must safeguard their systems against cyberattacks and the steps they should take if they are hacked, the officials said. The agency has offered only voluntary guidelines in the past.The ransomware attack that led Colonial Pipeline to shutter its pipeline for 11 days this month prompted gasoline shortages and panic buying in the southeastern United States, including in the nation’s capital. Had it gone on much longer, it could have affected airlines, mass transit and chemical refineries that rely on diesel fuel. Colonial’s chief executive has said the company paid $4.4 million to foreign hackers to release its systems.The cyberattack spurred DHS Secretary Alejandro Mayorkas and other top officials to consider how they could use existing TSA powers to bring change to the industry, said the officials.Gas stations in the Southeastern U.S. saw long lines on May 10, as Colonial Pipeline tries to restore operations following a ransomware attack. (The Washington Post)“The Biden administration is taking further action to better secure our nation’s critical infrastructure,” DHS spokeswoman Sarah Peck said in a statement. “TSA, in close collaboration with [the Cybersecurity and Infrastructure Security Agency], is coordinating with companies in the pipeline sector to ensure they are taking all necessary steps to increase their resilience to cyber threats and secure their systems.”
US pipeline operator reporting hacks to federal government – US pipeline operators need to carry out cybersecurity assessments under the Biden administration’s directives. Ransomware hacking disrupted gas supply in some states this month. The Transportation Security Administration directive issued Thursday will also allow owners and operators of national pipelines to report cyber incidents to the federal government and cyber security coordinators to work with authorities in the event of such attacks. Mandatory to be available at all times Shut down Colonial Pipeline.. Pipeline companies that previously operated on voluntary guidelines followed security directives that reflected the government’s focus on cybersecurity prior to the May attack on Colonial, a senior department of Homeland Security. If you don’t, you may face fines starting at $ 7,000 per day. Officials said. “The progress of ransomware attacks in the last 12-18 months poses national security risks and is concerned about the impact on key functions of the state,” said one official. It was. Anonymity to discuss regulatory details prior to official release. Crime organizations, often based in Russia or elsewhere in Eastern Europe, used encryption to scramble target data and unleash a wave of ransomware attacks demanding ransom. Victims include state governments, local governments, hospitals, medical researchers, and businesses of all sizes, and some victims are unable to even carry out their daily work.
Gas Shortage 2021: Why is Georgia dependent on just one gasoline pipeline? – The six-day shutdown of the Colonial Pipeline, which depleted the fuel supplies of more than two-thirds of metro Atlanta service stations, showed just how vulnerable Georgia is to interruptions to its energy supply. The cyberattack earlier this month made it painfully clear that, in a pinch, there are few practical alternatives to replace the pipeline’s massive capacity. The state is far from alone. The 5,500-mile-long pipeline supplies about 45% of the East Coast’s gasoline, diesel and jet fuel. The Southeast is even more reliant. Colonial delivers more than 70% of transportation fuels to Georgia, South Carolina, North Carolina and Virginia, according to the federal Energy Information Administration, including to crucial arteries such as Hartsfield-Jackson International Airport. Why Georgia’s fuel supply isn’t more diversified is shaped by a confluence of factors – and there are no easy fixes. Unlike many states in the Gulf, Midwest and the Rockies, Georgia doesn’t produce or refine any oil, so all petroleum products must be transported here. Pipelines, which pump fuel from refineries across long distances to customers, are often the most cost-effective option but face increasing opposition from elected officials, property owners and the public. Alternatives are expensive or still years away from widespread adoption. Multiple government reports in recent years warned about the state’s dependency on pipelines. Gulf Coast storms, including hurricanes Katrina and Harvey, and a 2016 pipeline leak in Alabama previewed the havoc that could be wreaked if such systems are impeded. “Georgia is extremely vulnerable to supply interruptions from weather and human interference,” a 2019 report from the state-run Georgia Environmental Finance Authority concluded.While there are alternatives for transporting fuels, none of them comes cheap. Trucking petroleum from the Gulf Coast is inefficient, since the vehicles are limited by how much they can carry. And transportation by rail can be pricey. Meanwhile, the century-old Jones Act requires that all goods transported domestically via ships must be carried on U.S.-built vessels that are owned and operated by Americans. Such tankers can be expensive to build and operate, and it’s sometimes cheaper to import foreign oil. Because of that, Georgia has relied on pipelines for transporting its oil – Colonial, built in the 1960s, and the smaller Products (SE) Pipe Line, built in the 1940s and known, until recently, as the Plantation Pipeline. The latter carries about 720,000 barrels per day compared to its competitor’s 3 million barrels. Both have headquarters in Alpharetta.
Salvors remove diesel fuel from capsized liftboat Seacor Power –Salvage crews have removed all diesel fuel from the tanks of capsized liftboat Seacor Power in the Gulf of Mexico, the U.S. Coast Guard said on Wednesday.Salvors removed approximately 20,363 gallons of diesel fuel from the overturned vessel using the hot tapping method, which involves drilling into the fuel tanks, making a hose connection, and transferring the fuel to portable tanks, the Coast Guard said.Approximately 4,500 gallons of hydraulic fluid still on board will need to be removed after the vessel is raised as the tanks are currently inaccessible, the agency said, adding the tanks have not been compromised.Now that diesel fuel has been removed, salvors will shift their focus toward removing debris and refloating the vessel. The Coast Guard said it expects the vessel will not be raised before June, as the timeline depends on many factors, including primarily the safety of salvage crews, weather conditions and any new structural changes that may occur.The Coast Guard said it continues to monitor for any oil discharges, and the liftboat’s owner Seacor Marine has an oil spill response organization (OSRO) standing by.There were 19 people on board when the U.S.-flagged Seacor Power overturned in extreme weather conditions in the Gulf of Mexico last month. Six people were rescued by the Coast Guard and Good Samaritan vessels, six people died in the accident andseven remain missing. The incident is under investigation by the National Transportation Safety Board (NTSB) and the Coast Guard.
Gas well explodes in St. Mary Parish, burning four people, state says — A natural gas well exploded in St. Mary Parish on Tuesday afternoon following an oil well blowout, causing at least four injuries.The Texas Petroleum Investment Company was in the process of sealing a natural gas well on Little Wax Bayou in Belle Isle on Sunday afternoon when the well blew out for unknown reasons, according to the Louisiana Department of Natural Resources. Wild Well Control, a Houston well control company, responded to the blowout Monday afternoon.However, while working on the uncontrolled spill, the exposed gasoline became ignited and caused an explosion Tuesday. It is unclear what caused the ignition. At least four people – all Wild Well employees – had burns on their hands and faces, according to Wild Well Control. At least one of those injured has been transported by air to Our Lady of Lourdes Regional Medical Center in Lafayette, according to their spokesperson, Elisabeth Arnold.
Four people injured after gas well explosion in Louisiana bayou – Officials confirm four people were wounded in an explosion at a natural gas well in the inland waters of St. Mary Parish on Tuesday. Workers from Wild Well Control, an oil spill response company, were trying to get a blowout under control at a well owned by Texas Petroleum Investment Co. when a spark ignited the natural gas coming from the well, according to Patrick Courreges of the Louisiana Department of Natural Resources. The Wild Well personnel sustained burns to their hands and face, Courreges said. The well is located in the marsh along Big Wax Bayou, west of Belle Isle near the Atchafalaya River delta. A review of state oil and gas data shows the well was first drilled in 1965. TPIC received a permit to plug and abandon the well in March and had been working on that when the blowout began Sunday. “Contractors working to cap a well in the Belle Isle Field were injured when a spark ignited natural gas,” TPIC spokesman David Margulies said in a written statement Wednesday. “The incident began on Sunday while workers were attempting to plug the abandoned well. The gas flow at the well has stopped and the fire is out. The workers are receiving medical treatment and crews are on the scene to protect the environment and bring the well under control.” Margulies updated his statement Wednesday afternoon to add that Tuesday’s fire “was extinguished within two hours and gas flow has been minimized.” The company had called in crews from Houston-based Wild Well Control, which says on its website that it’s the world’s leading provider of emergency well control response services. I TPIC says on its LinkedIn profile that its a Houston-based privately owned company that operates more than 2,000 producing wells along the Texas, Louisiana, Mississippi and Alabama coast. The Louisiana State Police Emergency Response Unit was on the scene Tuesday afternoon around 5:00 p.m. with HAZMAT equipment, Trooper Thomas Gossen said. Randall Mann of Acadian Ambulance said four helicopters and five ground units responded to take four patients to area hospitals. One went to New Orleans by helicopter, two by ambulance and another was taken to a Lafayette hospital by helicopter. Authorities say crews had been working to stop the well blowout since Sunday and the emission of gas seemed to be under control when it ignited. The fire stopped burning after Tuesday’s accident, but Courreges said Wednesday that crews were still working to make sure the well is secure.
$1 billion refinery bid rebuffed by Shell for shuttered Convent site in Louisiana, group says –A group that says it was rebuffed in an effort to buy Royal Dutch Shell’s Convent oil refinery for $1 billion says it is determined to buy and also build a new refinery to process lighter oil piped in from the Bakken shale play in the North Dakota area.”We were trying to take advantage of existing infrastructure at the Convent refinery that was earlier indicated to be for sale,” said Coleman Ferguson, who represents proposed buyer American Clean Energy Refining LLC and had worked at Texaco for more than three decades and is familiar with the Convent refinery. “If they (Shell) don’t want to sell the refinery for some reason we’re still interested in the docks, tanks and infrastructure. We are going to build a refinery we’ve just got to find a site,” he said.The startup company looks to build a second stand-alone refinery for $2 billion, which was planned to be on the Shell site, with capacity of 300,000 barrels of “frack oil” each day, he said.Shell did not directly comment on the group’s effort to buy the Convent refinery.”Despite an extensive marketing process, a viable buyer was not identified,” said Curtis Smith, spokesperson for Shell in an email.”In the marketing process of the Convent Refinery and all other assets globally, we consider a wide range of qualifications and factors, including a prospective buyer’s ability and experience to safely operate a complex manufacturing site.”The company had begun marketing its refinery in July 2020, but moved into shutdown mode several months later, laying off hundreds of workers and hundreds more contractors. Shell said it has found positions within the company for about 60% of the Convent workers.Now the refinery is in the “final steps of the preservation process and will soon be a fully idled and preserved asset,” according to Shell. The company continues to “actively evaluate” its options, including “potential future marketing efforts.”
Valero goes ‘all-in’ on renewable diesel, carbon capture – San Antonio-based Valero Energy Corp. is staking its future on the belief that not all cars and trucks will be powered by electricity in the years to come and the world will still need liquid fuels. The independent refiner is going all in on carbon capture projects and renewable diesel, a fuel produced from animal fats and waste products, such as used cooking oils. Other U.S. firms are doing the same. Houston refiner Phillips 66 said it plans to produce 800 million gallons of renewable diesel annually by 2024, and Ohio-based Marathon Petroleum said in March it would convert a California refinery to produce the fuel. For their part, European oil and gas majors – BP, Shell and Total, all three of which produce and refine oil – are aggressively positioning themselves for a future significantly less dependent on fossil fuels. They’re pouring billions into solar, wind and even hydrogen projects. Once it’s refined, renewable diesel can power any diesel vehicle on the road today. Valero, ranked 32nd on the list of Fortune 500 companies, estimates the fuel reduces emissions by 80 percent compared with regular diesel. Since 2018, Valero has spent hundreds of millions of dollars to expand its renewable diesel business. The company boosted production at its diesel refinery in St. Charles, La., and is building a new production facility at its Port Arthur refinery that will be completed in 2023.
They Wanted to Keep Working. ExxonMobil Locked Them Out. – The lockout began May 1, known in most parts of the world as International Workers’ Day. In a matter of hours, the ExxonMobil Corporation escorted 650 oil refiners in Beaumont, Texas, off the job, replacing experienced members of United Steelworkers (USW) Local 13 – 243 with temporary workers – and hoping to force a vote on Exxon’s latest contract proposal. USW maintains the proposal violates basic principles of seniority, and more than three weeks after the union members were marched out of their facility, they remain locked out. “We would have rather kept everyone working until we reached an agreement,” Bryan Gross, a staff representative for USW, tells In These Times. “That was our goal.” Because strikes and lockouts are often measures taken under more dire circumstances, either when bargaining has completely stalled or is being conducted in bad faith, USW proposed a one-year contract extension. But Exxon rejected the offer, holding out for huge changes to contractual language regarding seniority, safety and layoffs. “It’s a control issue,” Gross adds. “Exxon wants control.” As the oil industry attempts to deskill (and ultimately deunionize) its labor force, refinery workers like those in Beaumont find themselves under siege. Not only is their industry buckling beneath the weight of a global health crisis, but climate change has come to threaten their very livelihoods. Many workers remain skeptical of existing plans for a just transition. Since the coronavirus pandemic began in March 2020, refiners have taken drastic measures to offset steep drops in the price of oil by reducing production, selling assets and even closing some facilities. While the unionization rate in the oil and gas industry is currently higher than the rest of the U.S. workforce (15% compared with nearly 11%, per Reuters), BP, Marathon Petroleum Corporation and Cenovus Energy have cut labor costs by either downsizing or subcontracting to non-union workers. Exxon appears to be following along. Local 13 – 243 member J.T. Coleman, who has worked at the Beaumont refinery for a decade now, fears that hiring so many of these non-union workers to operate the facility could get somebody hurt. “We’re familiar with the equipment,” he says. “They’re not trained like we are.” USW has filed complaints with the National Labor Relations Board accusing Exxon of refusing to bargain, modifying their agreement with the union and coercion. Exxon did not immediately respond to a request for comment from In These Times. The complaints come at a time when the future of oil, in Texas and beyond, has never been more uncertain. In February, three severe winter storms walloped the state, killing 100 people and leaving millions without power. Similar storms hit Texas in both 1989 and 2011, but state lawmakers failed to heed calls from experts to upgrade the power grid at the time. When temperatures plunged below freezing this February, many sources of power in the state failed, including those generated from natural gas.
Bechtel Tapped to Design Natural Gas-to-Gasoline Plant in Texas —Energy developer Nacero Inc. has tapped global engineering and construction contractor Bechtel to design a $6.5 billion to $7 billion plant the firm plans to build in the Permian Basin – a facility Nacero says would be the nation’s first natural-gas-to-gasoline manufacturing facility. Nacero on May 25 awarded a front-end engineering and design (FEED) contract to Bechtel for the 115,000-barrel-per-day facility, which project officials say will incorporate carbon capture, sequestration and 100% renewable power. The Odessa Development Corp. and Houston-based Nacero on April 22 announced plans to build the plant in Penwell, Texas, just outside of Odessa. “This project is truly a game changer,” said Bechtel Energy president Paul Marsden in a release. “Decarbonization is a key to our energy transition here in the U.S. and around the world,” Bechtel Energy president Paul Marsden said in a statement to ENR. “Nacero and their pioneering approach to lower-carbon gasoline are a great fit for these ambitions. Efforts like this also empower everyday people to contribute to the energy transition towards net zero. It is really powerful.” Once Bechtel completes the FEED contract, it will deliver a lump-sum price proposal for engineering, procurement and construction. Project officials say Bechtel will employ sustainable design practices and work toward reducing the project’s carbon footprint, both in the supply chain and during construction. “For America to achieve its domestic energy and climate change mitigation goals, we need big vision and laser-focused execution. Bechtel is center stage in helping us get there,” Nacero president and CEO Jay McKenna said in a release. At its peak, construction of the four-year first phase is expected to employ 3,500 skilled construction workers on site and would produce 70,000 barrels-per-day of gasoline component, ready for blending. The second phase is expected to take two more years and will increase capacity to 100,000 barrels per day. When fully operational, the plant will employ 350 full-time operators and maintenance personnel.
Interior OKs Trump-era drilling leases despite Biden freeze — Monday, May 24, 2021 — The Interior Department has issued dozens of oil leases sold in the final weeks of the Trump administration – and could issue over 200 more – drawing the ire of an environmental group that argues the move is a violation of the Biden administration’s leasing freeze.President Biden ordered a moratorium on new oil and gas leasing shortly after taking office. That pause – which bars the regular auction of drilling rights in federal lands and waters – is in place while the administration conducts a comprehensive review of the federal oil and gas program that considers both the climate impacts and economic benefits of developing the country’s vast stores of fossil fuels.Interior has issued roughly three dozen oil and gas leases since that order. Most are from a Trump administration sale in January in New Mexico, the largest federal oil-producing state, where Biden’s oil lease moratorium has met with mixed reviews from Democratic leadership.Jeremy Nichols, climate campaign director for WildEarth Guardians, said those leases shouldn’t have been finalized. Nichols, whose organization noticed with surprise the issuance of the New Mexico leases this month, said a lawsuit is “definitely on the table.””It’s just unfortunate,” he said in an email. “With [Interior Secretary] Deb Haaland acknowledging that leasing under Trump flouted science, public and Tribal input, and integrity, it’s a shame that there may be a need to litigate more.”The New Mexico leases aren’t the only ones that were auctioned off in the waning days of the Trump administration, conveying 10-year rights to develop minerals in those areas. More than 200 other oil and gas leases were sold about six months ago by the Interior Department.Alyse Sharpe, a Bureau of Land Management spokesperson, said that “the Bureau is actively reviewing the leases from the December 2020 lease sales to ensure they comply with applicable federal laws and regulations and in light of various pending lawsuits.”
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