Oil, Gas, And Fracking News Read 27June 2021 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 26 June 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 at a 32 month high, natural gas prices at a 29 month high; gasoline production at 21 month high

Oil prices set a new 32 monrh high for a fifth consecutive week, as negotiations to lift Iranian sanctions broke off and US crude supplies fell more than was expected for a fifth straight week….after rising 1% to $71.64 a barrel last week on rising demand and falling supplies, the contract price of US light sweet crude for July delivery opened lower on Monday on Fed comments late last week that they might start raising rates by 2023, but then jumped by the most in a month to finish $2.02 higher at a 32 month high of $73.66 a barrel as the US dollar fell from two month highs while US talks with Iran wrapped up without resolution, thus leaving Iranian oil supplies in doubt…however, oil prices fell slightly on Tuesday amid profit taking after Monday’s price surge and settled 60 cents lower, as trading in the July oil contract expired with oil priced at $73.06 a barrel, while the more-actively traded August oil contract fell 27 cents to $72.85 a barrel on expectations that OPEC+ might decide to further boost crude production starting in August.…but oil prices rebounded in after hours trading Tuesday after the American Petroleum Institute reported a much larger than expected withdrawal from crude inventories, and hence the contract price of US light sweet crude for August delivery opened higher on Wednesday, but failed to extend its overnight gains even though the EIA reported an equally large draw, and settled just 23 cents higher at $73.08 a barrel, as traders noted that technical indicators showed that oil was overbought…nonetheless, oil prices continued moving higher Thursday, closing in on their highest in almost three years, on the drawdowns in U.S. inventories and on accelerating German economic activity. and finished the session 22 cents higher at $73.30 a barrel, as positive sentiment over an infrastructure deal announced by the Biden administration overcame concerns about possible additional supply announcements at next week’s OPEC meeting…oil prices pulled back early Friday with all eyes on the OPEC, Russia and other producers meeting next week, but then rallied into the close to settle 75 cents higher at $74.05 a barrel on expectations that demand growth would outstrip supplies, which were continuing to tighten in the U.S. and China….oil prices thus posted their fifth straight weekly gain, the longest winning streak this year, in rising 3.4% to the highest level since early October 2018, while the August oil contract, which had closed at $71.29 a barrel last week, saw its price end this week 3.9% higher..

With oil prices now hitting new 2 1/2 + year highs five weeks in a row, we’ll take a look at a longer term graph so you can get some perspective of where it’s been..

The graphic above is a screenshot of the interactive oil price chart from barchart.com, which i have set to show front month oil prices weekly over the past 5 years, which means you’re seeing prices as they were quoted in the media…this same chart can be reset to show prices of front month or individual monthly oil contracts over time periods ranging from 1 day to 30 years, as the menu bar on the top indicates, and also to show oil prices by the minute, hour, day, week or month for each…each bar in the graph represents the range of oil prices for the week, while the bars across the bottom show trading volume for the weeks in question, with down weeks indicated by red bars and up weeks indicated in green…although it’s a bit hard to see with 5 years all squashed together, there were only two weeks on this graph when prices exceeded this week’s; the week ending July 2nd, 2018, when oil hit a high of $75.27 a barrel. and the week ending October 1st, 20018, when oil prices briefly spurted to $76.90 a barrel….to find higher prices before that, we have to get back to early November 2014, before the Thanksgiving meeting at which OPEC began an attempt to flood the global markets, hoping to put US shale out of business…on the other hand, we can also see how prices briefly dropped to negative $40 during the 3rd week of April last year, when the OPEC agreement broke down during a squabble between Russia and the Saudis, and when oil was again dumped on a world in lockdown, with no place left to store the excess…

Meanwhile, natural gas prices finished higher for the 10th time in twelve weeks in rising to a 29 month high, as exports rose and domestic inventories remained well below normal….after falling 2.5% to $3.215 per mmBTU last week as cooler weather was forecast and utilities began switching to cheaper coal, the contract price of natural gas for July delivery opened lower on Monday and slid 2.4 cents to $3.191 per mmBTU, as less heat was forecast to reach the lower 48 than had previously been expected…but natural gas prices rose 6.7 cents to $3.258 per mmBTU on Tuesday as gas prices in Europe and Asia both topped $10 per mmBTU, leading to expectations US LNG exports would be at record levels this summer...natural gas rallied again on Wednesday as export demand rose sharply following maintenance, and gas production dipped lower for the second straight day, and prices settled 7.5 cents higher at $3.333 natural gas prices were then up another 8.5 cents to $3.418 per mmBTU after opening lower on Thursday, as a very tight government inventory report sparked an initial price rebound, and forecast heat through the first full week of July sent futures surging later in the session.…gas prices opened higher and continued rising on Friday before settling another 7.8 cents higher at $3.496 per mmBTU, as sweltering heat and revived export demand pointed to even tighter balances ahead of the peak summer cooling season, with natural gas thus finishing the week up 8.7% at a fresh 29 month high…

So with natural gas prices also hitting a multi-month high, we’ll include a graph of those as well. to see what it shows..

Like the oil chart earlier above, this is a screenshot of the interactive natural gas price chart from barchart.com, again set to show front month natural gas prices weekly over the past 5 years, which again means you’re seeing natural gas prices as they were quoted daily…again, this chart can also be reset to show prices of front month or individual monthly natural gas contracts over time periods ranging from 1 day to 30 years, and also to show natural gas prices by the minute, hour, day, week or month for each…while this week’s natural gas prices were indeed the highest since January 2019, they come nowhere close to matching the $4.50 to $5 per mmBTU price range we saw in November 2018, when a brutally cold month resulted in an early drawdown of supplies, raising concerns of shortages going into that winter, which persisted until milder weather arrived in late December and January…

The natural gas storage report from the EIA for the week ending June 18th indicated that the amount of natural gas held in underground storage in the US rose by 55 billion cubic feet to 2,482 billion cubic feet by the end of the week, which thus left our gas supplies 513 billion cubic feet, or 17.1% below the 2,995 billion cubic feet that were in storage on June 18th of last year, and 154 billion cubic feet, or 5.8% below the five-year average of 2,636 billion cubic feet of natural gas that have been in storage as of the 18th of June in recent years… the 55 billion cubic feet increase in US natural gas in storage this week was below the average forecast of a 63 billion cubic foot addition from an S&P Global Platts survey of analysts, and was further below the average addition of 83 billion cubic feet of natural gas that have typically been injected into natural gas storage during the second week of June over the past 5 years, as well as far below the 115 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending June 18th showed that despite modest decreases in our oil exports and in our refinery throughput, we still needed to withdraw oil from our stored commercial crude supplies for the seventh time in the past eight weeks, and for the 21st time in the past thirty-two weeks….our imports of crude oil rose by an average of 179,000 barrels per day to an average of 6,943,000 barrels per day, after rising by an average of 108,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 233,000 barrels per day to an average of 3,651,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,292,000 barrels of per day during the week ending June 18th, 430,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells reportedly fell by 100,000 barrels per day to 11,100,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 14,392,000 barrels per day during this reporting week…

US oil refineries reported they were processing 16,112,000 barrels of crude per day during the week ending June 18th, 224,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 1,331,000 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 390,000 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 (+390,000) 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…..furthermore, since last week’s EIA fudge factor was at (+1,097,000) barrels per day, that means there was a 707,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, thus rendering the week over week supply and demand changes that we have just transcribed useless…. however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,489,000 barrels per day last week, which was 1.0% less than the 6,556,000 barrel per day average that we were importing over the same four-week period last year… the 1,331,000 barrel per day net withdrawal from our crude inventories included a 1,088,000 barrel per day withdrawal from our commercially available stocks of crude oil, and a 244,000 barrel per day withdrawal from our Strategic Petroleum Reserve, space in which has been leased for commercial purposes…this week’s crude oil production was reported to be 100,000 barrels per day lower at 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 10,700,000 barrels per day, while an 1,000 barrel per day decrease in Alaska’s oil production to 445,000 barrels per day had no impact on the rounded national total….US crude oil production was at a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 15.3% below that of our production peak, yet still 31.7% above the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 92.2% of their capacity while using those 16,112,000 barrels of crude per day during the week ending June 18th, down from 92.6% of capacity the prior week, and a shade below normal for summertime operations…while the 16,112,000 barrels per day of oil that were refined this week were 16.4% higher than the 13,840,000 barrels of crude that were being processed daily during the pandemic impacted week ending June 19th of last year, they were still 7.1% below the 17,337,000 barrels of crude that were being processed daily during the week ending June 21st, 2019, when US refineries were operating at a close to summertime normal 94.2% of capacity…

Even with this week’s decrease in the amount of oil being refined, the gasoline output from our refineries was higher, increasing by 401,000 barrels per day to a 21 month high of 10,327,000 barrels per day during the week ending June 18th, after our gasoline output had increased by 495,000 barrels per day over the prior week…while this week’s gasoline production was 17.4% higher than the 8,794,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 1.8% lower than the gasoline production of 10,512.000 barrels per day during the week ending June 21st, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 56,000 barrels per day to 5,112,000 barrels per day, after our distillates output had increased by 135,000 barrels per day over the prior week…while this week’s distillates output was 12.1% more than the 4,561,000 barrels of distillates that were being produced daily during the week ending June 19th, 2020, it was still 3.6% below the 5,305,000 barrels of distillates that were being produced daily during the week ending June 21st, 2019..,…

Despite the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the third time in twelve weeks, and for the ninth time in thirty-two weeks, falling by 2,930,000 barrels to 240,050,000 barrels during the week ending June 18th, after our gasoline inventories had increased by 7,046,000 barrels over the prior week...our gasoline supplies decreased this week because our imports of gasoline fell by 210,000 barrels per day to 840,000 barrels per day while our exports of gasoline rose by 60,000 barrels per day to 895,000 barrels per day, and because the amount of gasoline supplied to US users increased by 80,000 barrels per day to 9,440,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 6.0% lower than last June 19th’s gasoline inventories of 255,322,000 barrels, and about 1% below the five year average of our gasoline supplies for this time of the year…

Meanwhile, with the increase in our distillates production, our supplies of distillate fuels increased for the third time in eleven weeks and for the 13th time in 27 weeks, rising by 1,754,000 barrels to 137,945,000 barrels during the week ending June 18th, after our distillates supplies had decreased by 1,023,000 barrels during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 389,000 barrels per day to 3,947,000 barrels per day, even as our imports of distillates fell by 95,000 barrels per day to 276,000 barrels per day while our exports of distillates fell by 47,000 barrels per day to 1,190,000 barrels per day….but with eight inventory decreases over the past eleven weeks, our distillate supplies at the end of the week were still 21.0% below the 174,720,000 barrels of distillates that we had in storage on June 19th, 2020, and about 4% below the five year average of distillates stocks for this time of the year…

Finally, despite the decrease in our oil exports and the slowdown in our oil refining, our commercial supplies of crude oil in storage fell for tenth time in the past eightteen weeks and for the 27th time in the past year, decreasing by 7,614,000 barrels, from 466,674,000 barrels on June 11th to 459,060,000 barrels on June 18th, after our crude supplies had decreased by 7,355,000 barrels the prior week….with this week’s decrease, our commercial crude oil inventories fell to about 6% below the most recent five-year average of crude oil supplies for this time of year, but were still about 31% above the average of our crude oil stocks as of the the third week of June over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring, our commercial crude oil supplies as of this June 18th were 15.1% less than the 540,722,000 barrels of oil we had in commercial storage on June 19th of 2020, and are now 2.2% less than the 469,576,000 barrels of oil that we had in storage on June 21st of 2019, but are still 10.2% more than the 416,636,000 barrels of oil we had in commercial storage on June 22nd of 2018…

This Week’s Rig Count

The US rig count was unchanged during the week ending June 25th, after rising 35 out of the prior 40 weeks, but it’s still down by 40.7% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US remained at 470 rigs this past week, which was still up by 205 rigs from the pandemic hit 265 rigs that were in use as of the June 27th report of 2020, but was still 1,459 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 down by 1 to 372 oil rigs this week, after rising by 8 oil rigs the prior week, but that’s still 184 more oil rigs than were running a year ago, while it’s still just 23.1% 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 up by 1 to 98 natural gas rigs, which was also up by 23 natural gas rigs from the 75 natural gas rigs that were drilling during the same week a year ago, and 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 up by 1 to 14 rigs this week, with 13 of those rigs drilling for oil in Louisiana’s offshore waters and the new one drilling for oil offshore from Texas….that was three more than the 11 rigs that were drilling in the Gulf a year ago, when all 11 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 count… however, in addition to those rigs offshore, a new rig was set up to drill through inland waters in Terrebonne Parish, Louisiana, this week, which with the rig already drilling through an inland lake in St Mary parish, Louisiana, means there are now two inland water rigs running, whereas there were no such “inland waters” rigs running a year ago…

The count of active horizontal drilling rigs was down by 4 to 421 horizontal rigs this week, which was still up by 191 rigs from the 230 horizontal rigs that were in use in the US on June 26th of last year, but less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the vertical rig count was down by 1 to 19 vertical rigs this week, but those were also up by 4 from the 15 vertical rigs that were operating during the same week a year ago….on the other hand, the directional rig count was up by 5 to 30 directional rigs this week, and those were up by 10 from the 20 directional rigs that were in use on June 26th 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 June 25th, the second column shows the change in the number of working rigs between last week’s count (June 18th) and this week’s (June 25th) count, the third column shows last week’s June 18th 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 26th of June, 2020..

Just looking at those tables, it appears there weren’t many changes this week….checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that one oil rig was added in Texas Oil District 7C, which includes the southern counties of the Permian Midland, while two rigs were pulled out from Texas Oil District 8A, which encompasses the northern counties of the Permian Midland, which thus gives us a net decrease of one rig in the Texas Permian…elsewhere in Texas, we find that one rig was added in Texas Oil District 1, while a rig was pulled out of Texas Oil District 2 at the same time, which could have been offsetting rigs in the Eagle Ford shale, which shows no net change regardless….Texas also had an oil rig pulled out of Texas Oil District 5, which apparently had been in the Barnett shale, while a natural gas rig was added in the Haynesville shale in Texas Oil District 6…note that the Haynesville rig count remains unchanged, however, because the lone rig that was drilling for oil in that formation was pulled out in northern Louisiana… meanwhile, the Louisiana rig count remains unchanged because of the addition of the inland waters rig in the southern part of the state, while the Texas rig count remains unchanged because the rig that was added offshore offsets the net loss of one rig on land…at the same time, the Oklahoma rig count was unchanged despite the addition of two oil rigs in the Cana Woodford because offsetting oil rigs were pulled out of the Ardmore Woodford and another oil basin in the state that Baker Hughes doesn’t track….Baker Hughes also doesn’t track any basins in Alaska or California, which also saw offsetting changes this week…

Mahoning County prosecutors called to open criminal investigation into radioactive pollution in waterways – WKBN – On Monday and last Friday, Ohio residents handed letters to nine county prosecuting attorneys and the Ohio Attorney General’s Office.The letters demanded the enforcement of the Ohio Revised Code and the launch of felony investigations into the disposal of radioactive waste in Ohio drinking watersheds.Residents charge that the crime of poisoning is knowingly caused by the spreading of radioactive oil and gas drilling “brine” on public highways as a deicer and dust suppressant.Poisoning is a first-degree felony in violation of O.R.C. ff 2927.24. Letters were delivered to the prosecuting attorneys in Athens, Cuyahoga, Franklin, Lucas, Medina, Portage, Mahoning, Williams and Wood counties as well as Attorney General Dave Yost. Members of the Ohio Community Rights Network (OHCRN) delivered the letters along with packets of information on the toxicity of the brine.The packets support the need for criminal investigations into brine processing companies and the State of Ohio, for the spreading and legalization of radioactive brine throughout the state.“State and private actors are violating Ohio’s criminal code by distributing and depositing radioactive oil and gas waste brine into Ohio watersheds,” said Terry Lodge, CELDF attorney. “State agencies are also guilty of permitting private actors to participate in this practice.”According to tests run by the Ohio Department of Natural Resources (ODNR) in 2017, all tested samples of brine used for these purposes exceeded both federal and state standards of radioactivity limits into the environment. Despite these results, the radioactive substance is being spread in drinking water basins and ecosystems, according to CELDF.Other tests run by independent researchers at Penn State, the National Resources Defense Council and Duquesne University have shown similar results. According to a 2020 investigation published in Rolling Stone Magazine, the oil/gas industry is fully aware of these radiation issues and has been for decades. The Ohio Legislature is currently considering bills (HB 282 and SB 171) that would further encourage the spreading of radioactive brine by reclassifying it as a commodity in the state. However, even without passage of these bills, the Ohio Department of Transportation and ODNR have both permitted and utilized this brine for several years throughout the state as a road deicer and dust suppressant. The letters handed to the county prosecuting attorneys and Ohio Attorney General state:“These concentrations of Ra-228 and Ra-226 are dangerous. Once oil and gas brine is applied to roadways, it will ultimately be washed into every surface water source in the state. The decay of Ra-226 to safe levels will take more than 11,000 years. Radium is very mobile in water and will come to pervade the water table everywhere throughout Ohio. It is misidentified by our bodies as calcium, and so would be deposited in bones and teeth, from whence it would bombard and mutate surrounding cells into cancers.” Former Youngstown Fire Chief Silverio Caggiano stated in the Rolling Stone article on radioactive brine: “If we caught some ISIS terrorist cells dumping this into our waterways, they would be tried for terrorism. . . . However, the frac industry is given a pass on all of this.”

Still no Ohio rules for oil and gas drilling waste six years after facility opens – Despite calls from state inspectors to clean up its act, an oil and gas waste facility continues to operate in eastern Ohio without any formal sanctions, potentially leaking radioactive waste near the Ohio River and just 2,500 feet from a high school stadium and hospital. The Austin Master Services facility in Martins Ferry, situated in a 100-year floodplain in Belmont County, handles waste from the hydraulic fracturing business, records show.Problems cited in quarterly inspections of the aging warehouse since 2017 by the Ohio Department of Natural Resources include radioactive waste being stored directly on the floor and not in a container; a leaking roof that resulted in pools of rainwater collecting on the warehouse floor in the same facility with overflowing bins of radioactive waste; and waste seen by inspectors being tracked by trucks outside the facility. Despite repeated documentation of such problems in state inspection reports, the state has not taken any action against the facility.A detailed interview request was left June 10 with a staff member at Pennsylvania-based Austin Master Services. The company had not responded to the request as of June 22. Austin Master is one of multiple oil and gas waste facilities in the state. During an interview, state officials noted there are “a couple of others.”The Ohio Department of Natural Resources is charged with monitoring the facilities, but no rules for bringing sanctions for violations have been finalized, six years after the Martins Ferry facility opened in 2015.”I don’t see where any agency in the state of Ohio has regulatory control over this facility, and facilities like them,” said Teresa Mills, executive director of the Buckeye Environmental Network, who called together a group of environmental organizations in hopes of prompting action on this issue. “We have the citizens in these communities who have no say about what goes on in their communities. There’s no opportunity for citizens’ input.” Mills said in addition to waste being tracked when it leaves the facility, there are concerns about worker exposure to chemicals.

Muskingum Watershed Joins Fight Against Ohio Forced Pooling Bill – In May MDN brought you the news that landowner Gateway Royalty was sounding the alarm over a new bill quickly advancing in the Ohio legislature. House Bill (HB) 152 would use forced pooling if 65% of a proposed unit’s landowners are leased (too low a bar) and also would force the landowner to accept a 12.5% royalty and force them to accept post-production deductions with royalties in some cases potentially going down to nothing (see Ohio HB 152 Forced Pooling Bill Disadvantages Unleased Landowners). Another major Ohio landowner with considerable acreage leased to the Utica Shale industry, the Muskingum Watershed Conservancy District (MWCD), is adding its voice of opposition to HB 152.MWCD was organized in 1933 to reduce the effects of flooding and conserve water for beneficial public uses. MWCD oversees 16 dams and reservoirs across 22 counties in Ohio, covering 20% of the state. It is a massive area, some 8,000 square miles, under the oversight and control of the MWCD.We’ve previously covered MWCD deals with Antero Resources to lease District property for drilling. We’ve also covered District deals to sell water to Antero and other shale drillers. MWCD has protected the land under its oversight while benefiting from shale drilling and water sales to shale drillers. The best of both worlds.After Gateway Royalty’s initial alarm, the bill’s sponsors backed away from it. However, they came back with a substitute bill which Gateway also opposes (see Rights Owner Says Changes to OH Forced Pooling Bill Not Enough).MDN received the following op-ed from Craig Butler, Executive Director of MWCD, expressing his concerns with the HB 152 substitute bill. The bill does not pass muster with MWCD. The new bill would gut provisions MWCD includes in its lease deals – provisions that protect the land under MWCD’s oversight. “…The Ohio General Assembly is considering a bill (HB 152) to make changes to how oil and gas leasing is managed when a landowner does not choose to lease their lands. This process, called “unitization,” has long existed but through this bill the industry is now trying to change this process. Unfortunately, the newly accepted substitute bill fails to protect the public interest and erodes our commitment to ensure a responsible oil and gas exploration program. Specifically, this bill eliminates our ability to include our hard-fought operational and environmental lease provisions. This is especially important if our lands are “unitized” by an operator not of our choosing and one that may not have the track record and financial stability that we demand as a partner at MWCD…”

Shell begins ‘steam blowing’ at Beaver County cracker plant – Beaver Countians can expect to see clouds of white water vapor emerging from Shell Chemicals’ ethane cracker plant site this month. The company began “first fire” activities last week to prepare piping on its cogeneration unit for eventual operation. It’s one of many milestones on the project’s path to startup; steam blows are the final cleanliness check of the plant’s steam piping. Passersby will see large clouds of vapor and may hear intermittent noise that differs from typical construction-related activity. This will last through the end of June, according to company leaders. A video on the process can be found on the Shell Pennsylvania Chemicals Facebook page. The multi-billion dollar complex is expected to be completed and operational by next year. The company in March said it was in the early stages of commissioning and start-up activities. Once power plant startup is complete, workers can launch processing units – including an ethane cracking unit and the three polyethylene units

Ferrari Energy Explains Whether the Extraction of Natural Gas is More Costly Than Oil – Whenever natural gas is extracted in the oil and gas industry, it is either wet or dry. The difference between wet and dry natural gas is that dry natural gas is at least eighty-five percent methane or more. Wet natural gas consists of some methane and other liquid features like butane, ethane, or propane. Essentially, the more methane present in natural gas, the dryer it is considered.When taking a closer look at how dry gas is extracted compared to wet gas, the cost for retrieving dry gas tends to come at a higher price. The cost is elevated due to the use of more advanced metallurgy and equipment. Ferrari Energy, a private, family-owned oil and gas company that offers mineral and leasehold acquisitions services is familiar with the debate around dry gas extractions. Below, experts at Ferrari Energy debunk myths related to gas and oil extraction costs and provide facts explaining whether or not gas and oil extraction prices are that much different. A common feature that natural gas and crude oil share is that they both are energy commodities. These fossil fuels are utilized to power society’s energy needs like transportation or heating and cooling homes. The prices of natural gas and oil relate as they are an inter-commodity spread. That means that the cost of these two energy resources changes in relation to one another. When looking at the history of cost fluctuation between the two, when one of the two raises in price, the latter elevates in consumer demand due to the nature of a lower price along with increased supply. When it comes to the businesses in the oil and gas industry, it is common for companies to produce both crude oil and natural gas. Oil and gas exploration usually goes hand in hand with production as the oil drilling process often involves natural gas’ release and capture. After more natural gas reserves were discovered in the United States, the connection between natural gas and crude oil prices changed. Massive gas reserves found in the United States’ Marcellus and Utica shale regions resulted in a price decrease of natural gas while, at the same time, oil prices proceeded to elevate from 2000 to 2014. Towards the end of 2014 and into 2016, the cost of crude oil reduced immensely due to the economy’s decelerated growth and less demand for oil. However, by 2018, the oil price climbed again until the coronavirus pandemic altered the global economy and society, putting a pause on oil demand. The pandemic forced a drastic fall in the cost of crude oil, so much so that the prices reached historic lows. On the other end, natural gas decreased a bit but mainly stayed at a consistent price. When comparing the refining process of crude oil and natural gas, the difference in their molecular makeup makes crude oil’s refining process a bit more profound compared to natural gas in preparation for commercial use.

Proposed Peabody Power Plant Defended, Challenged At Public Forum – – The first major public forum in the six-year history of the planned Peabody peaker power plant Tuesday night included more than four hours of utility officials laying out the benefits and necessity of the proposed fossil fuel-powered facility, while those concerned about the environmental and health impacts of the plant called for additional community input before a decision is made on the project’s future. Massachusetts Municipal Wholesale Electric Company officials delivered an extensive presentation on the cost-effectiveness of owning the plant to meet surge-capacity requirements in case of extreme heat and cold compared to buying that energy off the greater grid or using less-reliable sources such as wind, solar or battery power. Officials argued having the 55-megawatt oil and gas peaker plant – which they say will only run about 239 hours per year and produce fewer emissions than 94 percent of similar resources in the region – will actually help the 13 municipalities that draw energy from the plant use more renewable energy sources because having the reliable backup will allow it to use more clean sources for primary energy needs. “While we certainly pledge to continue adding renewable resources to our power portfolio in compliance with de-carbonization thresholds put forward by the Commonwealth,” Peabody Municipal Power Plant Chairman Tom D’Amato said, “Our Board firmly believes at this point in time that Project 2015A is fundamentally sound, well-grounded and, frankly, vital to serving our statutory obligation as a load-serving entity.” The project entered a “pause” of at least 30 days on May 11 amid a growing outcry from public officials and climate advocatesabout a lack of transparency in the proposal, which moved along the planning stages for years in relative obscurity until recent months.

Oil spill settlement to fund loon conservation projects (AP) – A half-dozen projects in New England and New York are slated to receive more than $3.5 million in funding to help protect common loons. Loons have been the focus of conservation efforts throughout the country, and they have slowly come back in some states, including Maine. The U.S. Fish and Wildlife Service said state and federal regulators have picked six projects to receive money via a settlement stemming from an oil spill. The Bouchard B-120 oil spill in 2003 in Buzzards Bay off Massachusetts killed more than 500 loons and resulted in a $13.3 million settlement. One of the grants is an award of nearly $800,000 to the Adirondack Center for Loon Conservation to restore breeding common loons in Adirondack Park in New York. Another grant, awarded to the Vermont Center for Ecostudies for more than $440,000, is designed to increase loon populations in Vermont with strategies such as management and monitoring. The remaining projects are in New Hampshire, Maine, Massachusetts and Rhode Island. Hunting, habitat loss and pollution reduced loon populations around the country, but environmental protections have helped the birds recover somewhat. Protections have included bans on lead tackle, which can poison the birds; “no wake zones,” which require boaters to travel slowly, have also helped the birds successfully nest.

Public comment hearing on Mountain Valley Pipeline water permit focuses on past water violations, economic impact – The Mountain Valley Pipeline drew ire from opponents for its history of water quality violations and erosion control issues and praise from supporters for generating jobs during a hearing Tuesday evening on a crucial water permit for the project.The West Virginia Department of Environmental Protection held the hearing via Zoom teleconference to gather input at the end of a public comment period on Mountain Valley’s request to cross waterbodies throughout the state.Mountain Valley Pipeline LLC, the joint venture that owns the pipeline, still has applications pending with West Virginia and Virginia environmental regulators for about 300 water crossings while it seeks approval from the Federal Energy Regulatory Commission to tunnel under 120 additional waterbodies.Of the two-dozen commenters who addressed the DEP, 17 spoke out against the Mountain Valley Pipeline, arguing that past pipeline water quality violations found by West Virginia and Virginia environmental regulators show the project, long delayed by legal and regulatory challenges, is not fit for permit approval.West Virginia Rivers Coalition staff scientist Autumn Crowe recalled the nonprofit warning the DEP in 2016 that proposed erosion controls would be ineffective on steep slopes and that construction would damage streams and rivers. “Now, five years later, I feel like a broken record,” Crowe said. “And I hate to have to say we told you so.”Crowe predicted that allowing Mountain Valley the permit could result in muddy water causing boil-water advisories, buried trout eggs and clogged fish gills. Lewis County landowner Susie Vance said flooding earlier this month washed out a base of decomposed timber mats and devastated an area where Mountain Valley is planning to tunnel under to construct the pipeline. The flooding had destroyed the pipeline’s silt barriers and fencing.“I’m still devastated from the whole thing,” Vance said.Vicki Pierson reported that the pipeline crosses her Northern Braxton County property and that Mountain Valley was directing water onto her property, causing erosion of streambeds downstream and significant discharge into a Burnsville reservoir.The DEP proposed a consent order earlier this year requiring Mountain Valley to pay a $303,000 fine for violating permits by failing to control erosion and sediment-laden water. That penalty followed a $266,000 fine from the same regulators in 2019 for similar erosion and water contamination issues.

OIL AND GAS: Feds falling short on pipeline safety – watchdog — Thursday, June 24, 2021 — The country’s pipeline safety agency needs to develop performance measures to gauge whether previous regulatory changes are achieving their desired results, according to a new report from the Government Accountability Office.

U.S. natgas climbs to 1-week high on rising global gas prices (Reuters) – U.S. natural gas futures rose over 2% to a one-week high on Tuesday on expectations the increase in global gas prices to their highest in years would boost U.S. liquefied natural gas (LNG) exports to fresh records this summer. Front-month gas futures NGc1 for July delivery on the New York Mercantile Exchange (NYMEX) rose 6.7 cents, or 2.1%, to settle at $3.258 per million British thermal units (mmBtu), their highest since June 14. Last week, U.S. speculators boosted their long futures and options positions on the NYMEX 3023651MLNG by the most since June 2020 to their highest since November 2018 as soaring global gas prices prompt buyers around the world to keep purchasing all the LNG the United States can produce. Gas prices in Europe and Asia both traded over $10 per mmBtu, with the Title Transfer Facility (TTF) in the Netherlands reaching its highest since January 2014. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 91.6 billion cubic feet per day (bcfd) so far in June, up from 91.0 bcfd in May but still well below the monthly record high of 95.4 bcfd in November 2019. With the coming of seasonally hotter summer weather, Refinitiv projected average gas demand, including exports, would rise from 87.3 bcfd this week to 91.9 bcfd next week. Those forecasts were lower than Refinitiv projected on Monday.

Natural Gas Futures Rally on Returning LNG Demand, Production Revisions – Natural gas futures roared back midweek as export demand rose sharply following maintenance and production dipped lower for the second straight day. The July Nymex gas futures contract surged 7.5 cents day/day to $3.333. The August contract picked up 7.5 cents to $3.352. Spot gas increases also became more widespread ahead of warmer weather on the East Coast. However, big losses in California left NGI’s Spot GasNational Avg. unchanged at $3.095.There continued to be small changes to the long-range weather outlook on Wednesday. However, the pattern was still expected to result in relatively light demand east of the Plains for the next few days, according to NatGasWeather.Still, the overall U.S. pattern is set to become hotter for the five- to 15-day forecast and is likely viewed as having a “bullish lean” for Saturday (June 26) through July 5. National cooling degree days are forecast to be above normal.“Sure, the pattern could be more intimidating, but there’s still enough coverage of highs reaching the upper 80s to 100s to result in smaller-than-normal weekly builds the last week of June and the first week of July,” NatGasWeather said. “And the upper pattern does favor widespread above-normal temperatures holding into the second week of July to keep strong national demand going for the 15- to 20-day period.”

US natural gas storage deficit grows as South Central region reports net withdrawal | S&P Global Platts — US natural gas inventories increased by a margin well below the five-year average for the week ended June 18 as the Henry Hub balance-of-summer reached $3.40/MMBtu. Storage inventories increased 55 Bcf to 2.482 Tcf for the week-ended June 18 the US Energy Information Administration reported June 24. The build was less than the 63 Bcf addition expected by an S&P Global Platts’ survey of analysts, as well as the five-year average build of 83 Bcf, according to EIA data. Storage volumes now stand at 513 Bcf, or 17%, less than the year-ago level of 2.995 Tcf, and 154 Bcf, or 6%, less than the five-year average of 2.636 Tcf. The injection was less than half the 115 Bcf build reported for the same week in 2020. Markets remained notably tight in the South Central region as temperatures there surged, driving up power demand. The region posted a net withdrawal of 4 Bcf. Over the past five years, the region has added an average of 19 Bcf in the corresponding week, according to EIA data. Platts Analytics’ base case forecast expects net storage withdrawals across the Gulf Coast region the next two months due to higher burns as well as slower-than-anticipated production growth from the Haynesville and Permian. Gulf Coast inventories are forecast to exit the summer at 950 Bcf, 250 Bcf less than the five-year average and the lowest end to the summer since October 2018, when total US stocks entered the winter with just 3.2 Tcf in the ground. The NYMEX Henry Hub July contract added 7 cents to $3.40/MMBtu in trading on June 24. Spreads from summer to winter now stand at just 10 cents/MMBtu, disincentivizing economic storage cycling and positioning the winter for potentially even more bullish price moves. Henry Hub is also being boosted by rebounding LNG demand. Total US LNG feedgas broke back above 11 Bcf/d on June 23 for the first time since June 1 as multiple export facilities and feedgas delivery pipelines have gone down for maintenance work. The 1.6 Bcf/d increase in LNG demand since June 21 has caused spot prices at Henry Hub to strengthen from $3.15/MMBtu to $3.33/MMBtu for flow date June 24, the strongest daily cash price for Henry Hub since mid-February. US LNG feedgas is forecast to average 10.9 Bcf/d in July. Further declines in Gulf inventory projections could see prices move well above $3-$4/MMBtu (perhaps as high as $9-$10/MMBtu to cut LNG demand) given the limited elasticities in the power sector at higher loads/prices as witnessed this month, according to Platts Analytics. Platts Analytics’ supply and demand model currently forecasts a 67 Bcf injection for the week ending June 25, which would measure only 2 Bcf more than the five-year average.

Natural Gas Futures Soar Past $3.40 on ‘Crazy Tight’ EIA Storage Figure, Hot July Forecast — A very tight government inventory report sparked an initial rebound in natural gas futures on Thursday. But it was heat seen through the first full week of July and some technical drivers that sent futures surging later in the session. The July Nymex gas futures contract shot up 8.5 cents to settle at $3.418. August closed at $3.437, also up 8.5 cents on the day. Spot gas prices also strengthened as hotter weather began to expand across more of the country. With potentially record-breaking temperatures in the Pacific Northwest and across the border in Canada, NGI’s Spot Gas National Avg. climbed 5.5 cents to $3.150. Though still a couple of weeks shy of the core of summer, some early bouts of heat have provided enough momentum to move Nymex gas prices comfortably above $3.00. The latest storage data confirmed the stronger demand, as the Energy Information Administration (EIA) reported a modest 55 Bcf injection into storage. The latest EIA figure was well below historical levels, coming in 60 Bcf below last year’s injection and 28 Bcf below the five-year average. It also was a tick below the lowest estimate in major surveys ahead of the report. Bespoke Weather Services said the figure reflected “crazy tight” supply/demand balances, which it had expected. “How tight was the question.” NGI’S ‘HUB & FLOW’ PODCAST Latest Episode: Brighter Days Ahead – Natural Gas Poised for Growth after Historic Winter Freeze Grips Market Listen & Subscribe Now As it turned out, the combination of low wind and low nuclear output last week accounted for more than Bespoke estimated. The EIA figure would promote end-of-season storage levels under 3 Tcf if extrapolated forward, according to the firm. “Obviously, that is not going to happen, as next week’s number will not be nearly as tight, thanks to higher wind and more nuclear output. But it is easier now to see why prices have been on such a march higher.”

Why Did NYMEX Gas Futures Price Hit a 29-Month High Yesterday? | Marcellus Drilling News – Yesterday the July NYMEX gas futures contract (the current contract) went up by 8.5 cents to settle at $3.42. The August NYMEX futures contract closed at $3.44, also up 8.5 cents on the day. The big question is why? The short answer is that less gas was put into storage than expected for this time of year. The slightly longer answer is that less gas went into storage because of the hot weather and all those air conditioners whirling using all that electricity and all that electricity gets generated in big part by burning natural gas. So the bottom line is this: Natural gas futures prices popped yesterday because of the weather. The following story from Reuters does a good job of connecting all the dots, but was written before the closing bell (at midday), so it shows a slightly lower price increase (7.5 cents instead of the closing 8.5 cents on the day): Front-month gas futures rose 7.5 cents, or 2.3%, to $3.408 per million British thermal units by 12:02 p.m. EDT (1602 GMT), putting the contract on track for its highest close since January 2019. U.S. natural gas futures rose over 2% to a 29-month high on Thursday on a smaller-than-expected storage build, forecasts for hotter weather over the next two weeks, rising exports and projections for power demand in Texas to reach record highs for June. The U.S. Energy Information Administration (EIA) said utilities added 55 billion cubic feet (bcf) of gas into storage during the week ended June 18. That is lower than the 66-bcf build analysts forecast in a Reuters poll and compares with an increase of 115 bcf in the same week last year and a five-year (2016-2020) average increase of 83 bcf. Analysts expected a low storage build last week because power generators burned lots of gas to keep air conditioners humming during heat waves in the Southwest. Last week’s build boosted U.S. stockpiles to 2.482 trillion cubic feet (tcf), or 5.8% below the five-year average of 2.636 tcf for this time of year. Front-month gas futures rose 7.5 cents, or 2.3%, to $3.408 per million British thermal units by 12:02 p.m. EDT (1602 GMT), putting the contract on track for its highest close since January 2019. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 91.6 billion cubic feet per day (bcfd) so far in June, up from 91.0 bcfd in May but still well below the monthly record high of 95.4 bcfd in November 2019. With the coming of hotter summer weather, Refinitiv projected average gas demand, including exports, would rise from 88.2 bcfd this week to 93.1 bcfd next week. Those forecasts were similar to Refinitiv’s projections on Wednesday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants fell to 9.9 bcfd so far in June due mostly to short-term maintenance outages at Gulf Coast facilities and the pipelines that supply them with fuel. That compares with averages of 10.8 bcfd in May and a record 11.5 bcfd in April. But with European and Asian gas both trading over $11 per mmBtu, analysts said they expect buyers around the world to keep purchasing all the LNG the United States can produce.

U.S. natgas gains over 2% to 29-month high on hot forecasts (Reuters) – U.S. natural gas futures rose over 2% to a fresh 29-month high on Friday on forecasts for hotter weather and higher air conditioning and export demand next week than previously expected. Traders noted prices were up even though the weather was expected to turn milder in two weeks, which should cut air conditioning demand a bit. On their second to last day as the front-month, gas futures NGc1 for July delivery rose 7.8 cents, or 2.3%, to settle at $3.496 per million British thermal units, their highest close since January 2019 for a second day in a row. The August NGQ21 futures, which will soon be the front-month, were up about 7 cents to $3.51 per mmBtu. For the week, the front-month was up over 8%, its biggest weekly increase since early February. Last week, the contract slid over 2%. In the power market, the Texas power grid operator said peak electric demand broke the June record on Thursday and was expected to do so again on Friday. But unlike last week, this week’s record breaking was a non-event for the Electric Reliability Council of Texas (ERCOT), which operates the grid in most of the state. In the West, meanwhile, a heatwave forecast to hit over the weekend boosted power prices at some hubs to their highest in years with the Mid Columbia hub W-MIDCP-IDX in Washington State up to $334 per megawatt hour for Monday, its highest since March 2019 when it hit a record high of $891. High temperatures in Seattle, the biggest city in the U.S. Pacific Northwest, were forecast to reach a record 111 degrees Fahrenheit (44 Celsius) on Monday, according to AccuWeather. That compares with a normal high of 73 F at this time of year. Data provider Refinitiv said gas output in the Lower 48 U.S. states has averaged 91.6 billion cubic feet per day (bcfd) so far in June, up from 91.0 bcfd in May but still well below the monthly record high of 95.4 bcfd in November 2019. Refinitiv projected average gas demand, including exports, would rise from 87.9 bcfd this week to 93.7 bcfd next week with the coming of hotter weather before sliding to 92.4 bcfd in two weeks as temperatures ease. The forecast for next week was higher than Refinitiv’s projection on Thursday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants has fallen to 9.9 bcfd so far in June due mostly to short-term maintenance at Gulf Coast facilities and the pipelines that supply them with fuel. That compares with averages of 10.8 bcfd in May and a record 11.5 bcfd in April.

USA Regulator Adds Hurdle for Enbridge Project— Enbridge Inc.’s embattled plan to build a tunnel under the Straits of Mackinac for its Line 5 oil pipeline will need a more thorough review from the U.S. Army Corps of Engineers, the latest setback for the project opposed by Michigan Governor Gretchen Whitmer. The Army Corps said Wednesday that the project will require an environmental impact statement, which is lengthier than a simple environmental assessment. The EIS is appropriate because it could “significantly” affect the quality of the “human environment,” Jaime Pinkham, acting assistant secretary for the Army for Civil Works, said on the agency’s website. The requirement is a victory for environmentalists and indigenous groups that now will gain more time to oppose Line 5. The Canadian pipeline giant is facing mounting opposition and hurdles for its two key projects to upgrade conduits that haul crude from the oil sands to U.S. refineries. They are crucial for producers in Alberta that have struggled for years with a shortage of export pipelines, and have seen projects such as TC Energy Corp.’s Keystone XL get scrapped. The decision “will lead to a delay in the start of construction on this important project. Enbridge will continue to work with the USACE on its review of our application and towards a successful conclusion to this process which began when we filed our permit application in April 2020,” Calgary-based Enbridge said in a statement. Earlier this month, more than 200 protesters were arrested in Minnesota after they clashed with law enforcement at a pump station for Enbridge’s Line 3, which the company is expanding. For Line 5, Enbridge is seeking to construct a tunnel under the lake bed as it fights off an order from Whitmer to shut down the pipeline entirely. The governor says that the line is a threat to the Great Lakes, but Enbridge and the government of Canada argue that Line 5 is an essential conduit of light crude for refineries in the U.S. Midwest, as well Ontario and Quebec. Last year, Whitmer revoked an easement for the line and ordered it shut by May 12, which Enbridge defied, arguing that the governor didn’t have the authority to shut the line. The dispute is currently before a federal judge and in court-ordered mediation. The fight has soured relations between the U.S. and Canada months after President Joe Biden, a Whitmer ally, angered Canadians by revoking a permit to the build cross-border Keystone XL pipeline. While the Keystone decision was disappointing, the continued operation of Line 5 is “nonnegotiable,” Canada’s Natural Resources Minister Seamus O’Regan has said. “Governor Whitmer stood with the people as she raised the alarm on the risks associated with the Line 5 pipeline,” Jane Kleeb, chair of the Nebraska Democratic Party and founder of the Bold Alliance, said in an email. “It is our hope Pres. Biden applies the same standard to reviewing and ending the KXL pipeline to other pipelines that are all risk and no reward.”

Enbridge says tougher environmental review will delay Line 5 tunnel project (Reuters) -Enbridge Inc said on Wednesday construction on its Line 5 oil pipeline tunnel under the Great Lakes will be delayed, after the U.S. Army Corps of Engineers announced the project will undergo a tougher environmental review. Calgary-based Enbridge had planned to start building the $500 million tunnel beneath the Straits of Mackinac, connecting Lake Huron and Lake Michigan, this year. The proposed tunnel would rehouse a four-mile (6.44 km)section of the aging Line 5 oil pipeline, which currently runs along the lake bed. Line 5 ships 540,000 barrels per day of oil and refined products from Superior, Wisconsin, to Sarnia, Ontario, and is a key link in Enbridge’s crude export network. “The decision by the U.S. Army Corps of Engineers (USACE) to complete an environmental impact statement (EIS) instead of an environmental assessment (EA) for the Great Lakes Tunnel project will lead to a delay in the start of construction on this important project,” The company had expected the tunnel to be operational by 2024, but environmental impact statements can take years. Duffy said Enbridge was still evaluating the impact on its timeline. Environmental campaigners have argued for years that there is a risk Line 5, built in 1953, could rupture in the Straits. The pipeline is the subject of an ongoing legal battle between Enbridge and the state of Michigan that has also embroiled the Canadian government. Michigan ordered the pipeline to shut down in May over concerns it could leak into the Great Lakes, an order that Enbridge ignored. The company first announced in 2018 plans to build a tunnel that would be buried more than 100 feet (30.5 m) below the lake bed which it said would virtually eliminate any chance of a spill, but environmentalists remain opposed to the project. “This announcement comes after tens of thousands of citizens voiced concern over Enbridge’s Line 5 tunnel permitting application because it lacked critical details,” said Beth Wallace of the National Wildlife Federation. The U.S. Army Corps of Engineers said it received more than 15,000 comments on the project after holding a public hearing in December 2020. “I have concluded that an EIS is the most appropriate level of review because of the potential for impacts significantly affecting the quality of the human environment,” said Jaime Pinkham, the Army’s acting assistant secretary for Civil Works.

UP Republican representatives say fuel tanker spill ‘will become more frequent’ without security of Line 5 pipeline – On Thursday night, three Republican State Representatives issued a statement about Line 5 following a fuel tanker spill in Hancock Thursday morning.Representatives John Damoose, of the 107th House District (R-Harbor Springs), Beau LaFave, of the 108th District (R-Iron Mountain) and Greg Markkanen, of the 110th District (R-Hancock) criticized the Biden Administration’s review of the Line 5 pipeline plan, which has previously gained approval from the Michigan Department of Environment, Great Lakes and Energy (EGLE), the state Legislature, and former Gov. Rick Snyder.Thursday, a fuel tanker truck overturned resulting in a fuel spill that discharged into Portage Canal in Houghton County, causing an environmental incident and unfortunate situation for the nearby residents and Great Lakes.Public access to beaches and boat launches has been shut down temporarily, and the public has been asked to avoid the affected area for the foreseeable future. As of Friday morning, clean-up continues in Hancock.In a release, the three representatives said, “This unfortunate incident in Houghton County earlier [Thursday] will become more frequent if Governor Whitmer and President Biden get their way and shut down the safest means of transporting life-sustaining fuels, Line 5. “It is quite ironic, and sad, that this accident occurred within hours of the Biden Administration announcing their intention to investigate the pipeline. If today’s events do not highlight the inherent dangers that vehicular transportation of fuels poses, we don’t know what will.

PIPELINES: Colonial hit with class-action lawsuit over ransomware hack — Wednesday, June 23, 2021 — Colonial Pipeline Co. is facing a class-action lawsuit for allegedly “grossly negligent” cybersecurity practices leading up to a May hack that shut down its 5,500-mile fuel system.

DC Circuit moves to vacate Spire STL certificate; finds FERC scrutiny lacking – Agreeing with the Environmental Defense Fund, a panel of the US Court of Appeals for the District of Columbia Circuit June 22 decided to vacate the certificate for the Spire STL Pipeline, finding FERC refused to seriously engage arguments challenging the weight of an affiliate precedent agreement in establishing the need for the project. At issue is the 65-mile Spire STL project, designed to move 400,000 Dt/d of gas from the Rockies Express Pipeline system into the St. Louis Area. FERC approved the project in a split vote August 2018 and placed it into service in November 2019. The decision comes as the debate has been ongoing for several years over the degree to which FERC must look beyond precedent agreements in assessing the market need for projects, but the ruling distinguishes the facts in this case from others in which the court found in FERC’s favor. The ruling does not immediately affect the Spire pipeline operations because the court withheld issuance of the mandate in the case for seven days after disposition of a petition for hearing or rehearing en banc, should Spire seek rehearing. But the ruling could ultimately force a shutdown, once the court’s mandate issues, said Gary Kruse of ArboIQ, with timing potentially contingent on efforts, stay the court’s mandate and further appeals. Spire STL in an emailed statement June 22 said it was disappointed, calling the ruling “a decision that would be detrimental to communities throughout eastern Missouri,” while adding that Spire was “currently reviewing the order and considering next steps.” “We have trusted and relied upon the established FERC process and precedent to build and operate the STL Pipeline, but three years after approval was granted by the FERC, it appears that reliable and critical energy access to 650,000 homes and businesses throughout the St. Louis region now could be in jeopardy,” Spire said. According to S&P Global Platts Analytics, deliveries on Spire STL to local distribution companies have averaged 95 MMcf/d this year and reached as high as 312 MMcf/d only once so far in 2021, February 21, during the record cold snap across the Midwest. EDF petitioned for a review of FERC’s August 2018 certificate authorization of the project and its November 2019 decision to deny rehearing. The group contended FERC relied on information presented by Spire, about a contract between the company and its affiliate covering 87.5% of the output, as sufficient evidence of project need when FERC should have rigorously assessed whether market conditions warranted approving the project. Enable Mississippi River Transmission and the Missouri Public Service Commission also raised objections during the FERC review that the project was unneeded and would negatively impact St. Louis gas market competition.

OIL AND GAS: Court’s ‘historic’ FERC slap-down shifts pipeline war — Wednesday, June 23, 2021 – A federal court ruling yesterday could influence how the Federal Energy Regulatory Commission reviews and approves pipelines, with major implications for the gas industry and legal cases around the country, analysts say. The U.S. Court of Appeals for the District of Columbia Circuit axed a certificate for the Spire STL pipeline in a forceful opinion that criticized FERC for failing to follow its own policies and delve into whether there was a need for the 65-mile natural gas pipeline from Illinois to Missouri. Instead, the court found that FERC had relied too heavily on Spire’s precedent agreement with shipper Spire Missouri, a retail utility that was affiliated with the pipeline developer (E&E News PM, June 22). The fate of the operational pipeline is now in the hands of the agency. Analysts said the ruling could influence FERC’s ongoing review of its Certificate Policy Statement, which dictates the process for determining whether a proposed pipeline is in the public interest and should therefore be approved. FERC Chairman Richard Glick reopened the review this year but has not indicated when it will end. The agency has historically greenlit proposals as long as they included one or more precedent agreements, which indicate that customers are willing to reserve capacity on the pipeline, but that practice could change depending on the outcome of the FERC review (Energywire, May 28). “I don’t think it can be overstated how important this decision is today,” said Gillian Giannetti, an attorney with the Natural Resources Defense Council’s Sustainable FERC Project. “This is a historic opinion that could change the landscape of how FERC assesses pipeline need.”

Tellurian Looking to Build Natural Gas Pipeline System to Serve Demand in Southwestern Louisiana -Tellurian Inc. is looking for approval from FERC to build a 37-mile, dual 42-inch pipeline system in Louisiana to meet natural gas demand in the Lake Charles area and potentially serve its proposed export terminal. The Line 200 and 300 project would pair supplies from various production regions with growing industrial, petrochemical, manufacturing, power generation, residential and liquefied natural gas (LNG) demand. The system would plug a supply gap between Lake Charles and a pipeline network about 30 miles north. Subsidiary Driftwood Pipeline LLC launched a binding open season earlier this year to secure firm transportation on Line 200 and 300. In its Federal Energy Regulatory Commission filing, Tellurian said it signed a 20-year transportation agreement for 4.6 million Dth/d with an undisclosed foundation shipper. The dual system would pick up supplies from existing pipeline infrastructure in the state near Ragley in Beauregard Parish and terminate near Carlyss in Calcasieu Parish at a new meter station near Tellurian’s proposed Driftwood LNG export terminal.

Offshore oil and its Democratic allies are greenwashing Gulf drilling – When President Biden took office in January, a peculiar idea about oil and gas started to make the political rounds: that certain parts of the industry are more environmentally responsible and can actually reduce emissions, compared to other parts of the industry that are worse for the Earth. “If you want to reduce emissions, the offshore arena is better,” Scott Angelle, who was the top environmental regulator of offshore energy under the Trump administration, told the trade publication Offshore in late January. Questionable claims about the climate might be expected from a Trump administration official who rolled back oil and gas regulations, but the same argument has also seeped into Democratic politics. “Gulf of Mexico oil and gas production produces substantially fewer greenhouse gas emissions than oil and gas production in any other region of the world,” Louisiana Gov. John Bel Edwards, a Democrat, testified to the Senate Energy Committee in May. Documents show that these claims originated with a little-known lobbying group that advocates for offshore oil – and experts told Vox that they’re dubious at best. By focusing on the emissions of oil and gas production, the industry is ignoring the much larger share of pollution that comes from the burning of fossil fuels. This is a clear attempt at greenwashing: Parts of the oil industry are arguing, perversely, that more fossil fuels can help solve the climate crisis. Yet these tactics also suggest that fossil fuel companies foresee a fight for survival in a shrinking market for oil and gas – and one emerging industry tactic is pointing fingers to claim that a particular source of oil and gas isn’t as dirty as the next person’s. “They’re falling over themselves” to claim “their oil is cleaner than someone else,” Lorne Stockman, a research analyst at Oil Change International, a nonprofit advocacy group, told Vox. What’s worrying is that attempts to rebrand some oil and gas as sustainable has gained traction even among prominent Democrats, and could influence an administration that has pledged to slash emissions by half within the decade in the hope of preventing catastrophic climate change.

As the Gulf of Mexico Heals from the Deepwater Horizon Oil Spill, Stringent Safety Proposals Remain Elusive – Obama put forth a tough new standard for offshore drilling that Trump rolled back, prompting a lawsuit by environmentalists. They’re now looking to Biden for help. Over a three-month period beginning on April 20, 2010, over 200 million gallons of oil spilled into the Gulf of Mexico because of a catastrophic blowout and explosion that rocked the Deepwater Horizon, an offshore oil rig 41 miles off the Louisiana coast operated by British Petroleum, killing 11 workers and injuring 17 others.In Biloxi, the effects of the disaster on seabirds and sea fronts are mostly gone except in the memories of residents. But the measures designed to prevent a similar disaster lay in the hands of a federal court in Louisiana, Interior Department officials in Washington and lawmakers on Capitol Hill. Former President Donald Trump’s administration weakened many of the drilling safety measures adopted under Obama after the disaster. Most notably, Trump partially repealed a federal regulation that required increased testing and monitoring of underwater drilling equipment and well-control operations. As over 80 operators continue to drill and pump oil in the Gulf today under the weakened regulation, environmental activists are in federal court in New Orleans trying to get Trump’s partial repeal thrown out. Although President Joe Biden has put the partial repeal on a long list of Trump administration actions to review, it’s unclear whether his administration will simply try to revert to the Obama well safety regulation, or try to strengthen it. There’s always the potential for something catastrophic to happen like “another Deepwater Horizon spill,” said Chris Eaton, a senior attorney with Earthjustice and a lead counsel in the case challenging Trump’s partial repeal, which remains in effect. “It’s important to make sure that to the extent that there is oil and gas development still happening, that it’s done safely.”

U.S. infrastructure deal includes $6 billion sale from oil reserve -document (Reuters) -The infrastructure deal struck by a group of bipartisan senators and President Joe Biden on Thursday includes partial funding by a proposed $6 billion sale from the U.S. emergency oil reserve, according to a document circulated by Republican lawmakers. A sale of that size equals a drawdown of about 82 million barrels, based on Thursday’s price of $73 a barrel for West Texas Intermediate crude. That represents about 13% of the reserve’s current holdings of nearly 624 million barrels of oil, though if prices rise, the volume of oil would shrink. The deal was a step forward for the $1.2 trillion bipartisan Senate package, but the battle is not over. Biden’s fellow Democrats are also working on a companion bill to include more money to address climate change, but could only be passed on a party line vote in a process called reconciliation. The effort to pass the bills could extend into September and beyond. A document released by the White House also confirmed that the deal calls for partial financing by a sale from the Strategic Petroleum Reserve (SPR), but did not say how much money would be raised. The Republican document did not detail the time period over which the sale would take place. The White House said the deal includes $73 billion for electricity grid improvements, including the building of thousands of miles of transmission lines to deliver power from renewable energy projects, and a new Grid Authority. The investments could help boost use of electric vehicles, reducing demand for fuels refined from crude oil while curbing carbon emissions. The deal also includes $21 billion for environmental remediation, much of which could go toward cleaning up abandoned coal and hardrock mines and oil and gas wells, while providing jobs in communities that have long relied on work producing fossil fuels. The SPR, held in several salt caverns on the Texas and Louisiana coasts, has been tapped before to fund the federal government, medical research and a modernization of the facility under laws passed in 2015 and 2016. In 2015, the government agreed to sell 58 million barrels between 2018 and 2025.

USA Crude Hub Stocks Seen Falling to Historic Lows– Crude oil inventories in America’s largest storage hub could fall to historically low levels by the end of September as the demand rebound continues to outpace production. Stockpiles in Cushing, Oklahoma, the delivery point for West Texas Intermediate oil futures fell nearly 4 million barrels in the last two weeks, bringing inventories to the lowest since March of 2020 when the pandemic forced the country into lockdown. Analysts are estimating and traders are betting that supplies could dwindle to seasonal levels not seen since 2018 by the end of September. Inventory levels at the massive complex, which houses crude oil produced across West Texas, the Midwest and western Canada, arguably has more sway over oil prices than anywhere else in world. With U.S. shale production still 15% off of its pre-pandemic peak and imports from Canada running low there is a growing consensus among trading house and Big Oil executives that prices are set to surge as supplies tighten. Stockpiles at Cushing, currently at 41.7 million barrels, could drop to the lowest in almost 3 years as refineries ramp up fuel-making and oil production is still lagging, said Chris Sloan, a Houston-based analyst with BB Energy Trading Ltd. Inventories could fall to the 30-million-barrel range in the next three months, he said. It’s a stark reversal from a year ago when a market price crash devastated the oil industry as demand slid from pandemic-fueled restrictions. It forced traders to stuff unwanted crude into storage globally until consumption improved, shifting the market to a steep contango where oil for immediate delivery trades at a discount to forward supply. At the heart of the decline is a lack of a type of oil called Domestic Sweet or DSW that is produced by blending a cocktail of crudes, including supplies from the Permian and the Midwest, according to market participants. Output recovery in the Midwest, where Cushing tanks sit, has been the slowest among all producing regions. “The lack of available DSW is undoubtedly tightening WTI – spec balances at the hub,” according to a note from consultants Energy Aspects. This and strong exit flows could push Cushing stocks in August and September to around 27 million barrels and 24 million barrels, respectively, they said.

Empty Oil Tanks at Key Storage Hub Show Speedy Demand Rebound –Crude storage tanks that were brimming a year ago when the pandemic grounded flights and kept drivers at home are beginning to empty in the main U.S. distribution hub, the latest sign of strengthening demand in the world’s biggest oil-consuming country. For the first time since before the pandemic, empty tanks are being offered for lease at Cushing, Oklahoma, the delivery point for West Texas Intermediate oil futures. At least 1.4 million barrels of storage is up for rental starting in July, for roughly 12 cents per barrel a month, said Steven Barsamian, chief operating officer at storage brokerage Tank Tiger. That’s a stark contrast to at least 60 cents charged when there was little space left about a year ago. Americans are taking to the roads and skies at increasing numbers as the summer nears and the country emerges from months of lockdowns, with oil refiners speeding up fuel making to meet the rising demand. This week, California, America’s most populous state, re-opened its economy, while New York ended most of its curbs. It’s a dramatic turnaround from a market crash that saw traders storing unwanted crude in tankers at sea, and U.S. producers at one point having to pay for customers to take their oil last year. Meanwhile, shale producers are sticking to their pledges to focus on balancing their books and boosting returns to shareholders, rather than increasing output. U.S. production is 15% below its peak last year, limiting flows to the storage center. So, traders are rapidly draining their storage tanks to supply refineries with every barrel of crude feedstock they need. Empty tanks are typical of a market where demand is outpacing supplies and traders are getting a premium on the nearest deliveries, making it unprofitable to keep oil in storage — a pattern known as backwardation. A year ago, when traders were storing as much oil as possible to wait for better prices, the nearest deliveries for WTI were selling at a discount to longer-dated ones. That structure is known as contango. These patterns affect especially the commercial storages used in speculative trading, such as the ones in Cushing. “Typically, in a backwardated market, its the storage that isn’t being used for operational purpose like the ones in Cushing, Oklahoma, that get emptied out first,” Barsamian said. “Storage at most other locations such as in Houston and Midland in Texas are used for operational purposes and get emptied out later.”

Cash gushes freely in shale oil bonanza –Cash is flowing faster than oil in the US shale patch as the threat of Opec’s spare capacity continues to cap investment to boost production.Surging oil prices are fuelling an unexpected bonanza for investors in the US shale sector. Output remains stalled in the lower 48 US states this year but benchmark WTI is up by two-thirds at over $70/bl. The shale industry is expected to earn record revenues this year before taking hedging into account, consultancy Rystad Energy says. Yet firms are unwilling to spend more to boost output until oil market fundamentals tighten – especially the overhang of shut-in capacity held by Opec+ producers, estimated at 5.5mn-8mn b/d.Shale producers are determined to shake off the image of their profligate past, when they spent more than they earned while chasing rapid output growth. They are now focusing on rewarding shareholders and paying down debt, despite the doubling of prices since last year. “It is not the price of oil that is going to trigger whether we are growing or not growing,” EOG Resources chief executive Bill Thomas says. And this view is echoed across the industry.Most shale firms are just spending enough to keep output flat and using excess cash to accelerate debt repayments and increase shareholder dividends. Breakeven prices have fallen sharply as operators continue to improve well productivity and cut development costs. EOG says it needs WTI at $50/bl for a 10pc return on capital employed, down from $57/bl last year and $81/bl in 2016. The firm says it aims to bring this down to $40/bl in the future.US oil production is expected to rebound in the second half of this year as shale drilling and completion activity picks up onshore in the lower 48 states, the EIA’s Short-Term Energy Outlook (STEO) says. Output will be down by 2pc for 2021 as a whole, thanks to deep spending cuts brought on by the pandemic. But year-on-year growth will rise to 4pc for the remainder of 2021 and to 7pc in 2022, STEO projections show (see graph). It will still take until late 2023 to regain pre-pandemic output, even at these higher growth rates. Oil production is projected to rise modestly in June-July from the seven major shale formations covered by the EIA’s Drilling Productivity Report (DPR). Output from new wells exceeds legacy declines from existing wells – estimated at 425,000 b/d. About 50pc more wells are being completed each month than drilled as operators draw on their large backlog of drilled-but-uncompleted (DUC) wells. These cost 40pc less to bring on line than drilling and completing a well. Operators completed 779 wells last month, of which 247 were DUC wells (see graph).

Shale oil and gas fraud: A sign of a peak in oil supplies? – Those of us who watched incredulously as investors shovelled more and more money into what we were sure were money-losing shale oil and gas drillers do not find the current spate of fraud lawsuits against these drillers surprising. The gargantuan claims about shale hydrocarbon reserves – which were compared more than once to those in Saudi Arabia – were clearly designed to woo investors into bidding up the stock price and/or hoovering up the constant stream of junk bonds emitted by the shale oil and gas drillers. The hype succeeded for a long time, even during the crash in oil prices in 2015 and beyond when investors convinced themselves that they were picking up “bargains.” It wasn’t until the pandemic-induced plunge in oil prices that the reality of those outlandish claims was revealed, and many companies disappeared. But this story of fraud and exaggerated claims is much more than a legal story. The large production gains that did take place in American oil fields had people believing America would be or already was “energy-independent,” a phrase that meant the country would not be a net importer of energy resources. Though U.S. dependence on imported energy resources did decline, it didn’t reach zero until the pandemic dramatically crashed U.S. oil demand below U.S. production. But as the world and U.S. economies rebound, that dependence is almost certain to return as the so-called “shale miracle” turns out to be something less than miraculous, bankruptcies continue and reserve estimates come back into line with reality. But the fallout extends even further. The U.S. shale boom was the principal source of increased world production for most of the last 15 years. Without that boom and the boom in the Canadian tar sands, world oil production would have grown little or even declined. Now that U.S. shale oil production is receding – from an estimated 8.3 million barrels per day (mbpd) in November 2019 to 6.9 mbpd as of February 2021 – it is unlikely that U.S. producers could pull off a similar feat again. The recent rise in oil prices against a backdrop of a still recovering economy suggests that the shale miracle is not returning any time soon, if ever. For those who scoffed at the idea that world oil production would peak in the near term, the test is just ahead. World production of crude oil including lease condensate (which is the definition of oil) peaked at 84.6 mbpd in November 2018 (well before the pandemic) and has yet to touch that peak again. In fact, the latest monthly production figures available from the U.S. Energy Information Administration show oil production in February still more than 10 million barrels below its November 2018 peak.

War of Words Over New Mexico’s Oil Fields -In mid-June, a federal judge in Louisiana blocked the Biden administration’s 5-month-old pause on new oil and gas lease sales on federal lands and waters. But in New Mexico, where the state’s Democratic governor had requested an exemption to the pause, the tension over leases highlights how tricky it is for petroleum-dependent states to transition away from the historically rich revenue stream.It’s not yet clear how the judge’s order will play out, but the pause had already led to a dustup among state legislators and an unusual alliance across the upper levels of the state’s deeply polarized political parties.“There’s not a whole lot of common ground, at least with myself and the governor,” says state Sen. Greg Baca, the Republican minority floor leader. “But on this one thing, I can agree that we need to continue these leases.” He is the lead signatory on a letter fired off earlier in June to the Biden administration and signed by all of the state’s Republican legislators. In it, they denounced an earlier letter two dozen state Democrats sent to the president.State Democrats asked that the lease moratorium be kept in place to protect the environment and allow for further review of the leasing process on federal lands, crossing the state’s most prominent Democrat, Gov. Michelle Lujan Grisham.“Just as our Democratic Governor requested in March 2021,” the Republicans wrote to Biden, “we respectfully ask that New Mexico’s fossil fuel production and any associated federal permitting and leasing activities be exempt from all future regulatory moratoriums.”This put them squarely in line with the governor, an uncommon position for both.

Plugging New Mexico’s oil and gas wells could create thousands of jobs – Plugging thousands of abandoned oil and gas wells in New Mexico could generate billions in wages and more than 65,000 jobs while generating state revenue, per a recent study. A report published Tuesday by New Mexico-based O’Donnell Economics pointed to the economic boost well plugging could create but also contended federal funds were needed for the State to reap the benefits. When an operator is permitted to drill a well, they often pay bonding to assist with cleanup should the well be abandoned or orphaned – usually when its profitability declines. The State of New Mexico often foots the bill for shutting in the well and remediating the land as required by state law, officials said. State officials, environmental groups and iPlugging thousands of abandoned oil and gas wells in New Mexico could generate billions in wages and more than 65,000 jobs while generating state revenue, per a recent study.A report published Tuesday by New Mexico-based O’Donnell Economics pointed to the economic boost well plugging could create but also contended federal funds were needed for the State to reap the benefits.When an operator is permitted to drill a well, they often pay bonding to assist with cleanup should the well be abandoned or orphaned – usually when its profitability declines.The State of New Mexico often foots the bill for shutting in the well and remediating the land as required by state law, officials said. State officials, environmental groups and industry groups pushed the federal government to provide financial assistance to states for well plugging to protect the environment and stimulate the economy. Industry groups pushed the federal government to provide financial assistance to states for well plugging to protect the environment and stimulate the economy. Remediation of the facilities would support 65,337 jobs and $4.1 billion in wages, the study ready, providing jobs to energy workers displaced during the COVID-19 health crisis and the state’s transition away from fossil fuels, or whose jobs fluctuate with future busts in oil and gas.

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